EPA 440/1-74 029-a
Group I
i
Development Document for
Effluent Limitations Guidelines
and New Source Performance Standards
for the
STEAM ELECTRIC POWER GENERATING
Point Source Category
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UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
October 1974
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ABSTRACT
This document presents the findings of an extensive study of
the steam electric power generating point source category
for the purpose of developing effluent limitations,
guidelines, standards of performance for new sources, and
pretreatment standards for the industry in compliance with
and to implement Sections 30U, 306 and 307 of the Federal
Water Pollution Control Act Amendments of 1972.
Effluent limitations guidelines contained herein set forth
as mandated by the "Act":
(1) The degree of effluent reduction attainable through
the application of the "best practicable control
technology currently available" which must be achieved
by nonnew point sources by no later than July 1, 1977.
(2) The degree of effluent reduction attainable through
the application of the "best available technology
economically achievable" which must be achieved by
nonnew point sources by no later than July 1, 1983.
The standards of performance for new sources contained
herein set forth the degree of effluent reduction which is
achievable through the application of the "best available
demonstrated control technology, process, operating methods,
or other alternatives."
This report contains findings, conclusions and
recommendations on control and treatment technology relating
to chemical wastes and thermal discharges from steam
electric powerplants. Supporting data and rationale for
development of the effluent limitations, guidelines and
standards of performance are contained herein.
iii
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CONTENTS
Section
I CONCLUSIONS
II RECOMMENDATIONS 3
III INTRODUCTION 7
Gener al Background 7
Purpose and Authority 8
Scope of Work and Technical Approach 11
Industry Description 14
Process Description 24
Alternate Processes 26
Presently Available Alternate Processes 26
Hydroelectric Power 26
Combination Turbines and Diesel Engines 28
Alternate Processes Under Active Development 29
Future Nuclear Types 29
Coal Gasification 31
Combined Cycles 31
Future Generating Systems 32
Magnetohydr©dynamics 33
Electrogasdynamics 33
Fuel Cells 34
Geothermal Generation 34
Industry Regulation 35
Construction Schedules 3 6
Reliability,Reserve Generating_Capacitv and 36
Scheduling of Outages
Methods of Determining Reserve Requirements 39
Reserves for Scheduled Outages 40
Coordination for Reliability 42
Coordinating Techniques 46
Small Systems 47
IV INDUSTRY CATEGORIZATION 51
Process Considerations 51
Fuel Storage and Handling 51
Steam Production 55
Steam Expansion 59
Steam Condensation 60
Generation of Electricity 63
Raw Materials 63
Coal 63
Natural Gas 64
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CONTENTS (continued)
Section Page
Fuel Oil 65
Refuse 66
Information on U.S. Generating^Facilities(Size and Age^ 67
~Size of Units 72
Age of Facilities 72
Mode of Operation (Utilization) 79
Annual Hours of Operation 84
Performance Indices 84
Load Factor 86
Operating Load Factor 86
Capacity Factor 87
Operating Capacity Factor 87
Use Factor 87
Site Characteristics 8 8
Categorization 91
Chemical"wastes 93
Thermal Discharges 96
Summary 100
PART A: CHEMICAL WASTES 107
A-V WASTE CHARACTERIZATION 107
%
Introduction 107
Once-Through Cooling Systems 114
Recirculating Systems 114
Water Treatment 120
Clarification 122
Softening 122
Ion Exchange 124
Evaporator 128
Character of Water Treatment Wastes 129
Boiler or PWR Steam Generator Slowdown 133
Eguipment Cleaning 136
Chemical Cleaning Boiler or PWR Steam Generator Tubes 135
Preoperational Boiler Cleaning Wastes 137
Operational Boiler Cleaning Wastes 142
Composition of Scale 143
Frequency of Boiler Cleanings 143
Types of Boiler Cleaning Processes 143
Alkaline Cleaning Mixtures with 143
Oxidizing Agents for Copper Removal
Acid Cleaning Mixtures 144
Alkaline Chelating Rinses 144
and Alkaline Passivating Rinses
vi
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CONTENTS (continued)
Section Page
Methods Using Organic Solvents 145
Proprietary Processes 145
Condenser Cleaning 145
Boiler Fireside Cleaning 146
Air Preheater Cleaning 146
Feedwater Heaters Cleaning 147
Miscellaneous Small Equipment Cleaning 148
Stack Cleaning 148
Cooling Tower Basin Cleaning 148
Ash Handling 148
Coal 149
Oil 160
Coalpile Runoff 160
Floor and Yard Drains 164
Air Pollution Control Devices 167
Sanitary Wastes 170
Plant Laboratory and Sampling Streams 171
Intake Screen Wash 172
Service Water Systems 172
Low Level Rad Wastes 173
Construction Activity 179
Chemical Discharges in General 180
Summary of Chemical Usage 182
Classification of Waste Water Sources 182
A-VI SELECTION OF POLLUTANT PARAMETERS 189
Definition of Pollutants 189
Introduct ion 189
Common Pollutants 192
pH Value 192
Total Dissolved Solids 192
Total Suspended Solids 192
Pollutants from Specific waste Streams 193
Biochemical Oxygen Demand (BOD) 193
Chemical Oxygen Demand (COD) 193
Oil and Grease 193
Ammonia 193
Total Phosphorus 194
Chlorine Residuals 194
Metals 194
Phenols 196
Sulfate 196
Sulfite 196
Boron 197
vii
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CONTENTS (continued)
Section Page
Fluoride 197
Alkaline and Acidity 197
Total Solids 197
Fecal Coliform 197
Total Hardness 197
Chloride and Magnesium 198
Bromide 198
Nitrate and Manganese 198
Surfactants 198
Algicides 198
Other Potentially Significant Pollutants 198
Selection of Pollutant Parameters 199
Environmental Significance of Selected Pollutant 202
Parameters
Iron -~Total 204
Polychlorinated Biphenyls 206
Chlorine - Free Available, - Total Residual 209
Chromium - Total 211
Copper - Total 212
Oil and Grease 213
pH, Acidity and Alkalinity 213
Phosphorus - Total 214
Total Suspended Solids 215
Zinc - Total 216
A-VII CONTBOL AND TREATMENT TECHNOLOGY 219
General Methodology 219
Pollutant - Specific Treatment Technology 220
Aluminum • 220
Ammonia 220
Antimony 220
Arsenic 220
Barium 220
Beryllium 220
Boron 221
Cadmium 221
Calcium 221
Chlorine Residuals 221
Chromium 222
Cobalt 223
Copper 223
Iron 224
Lead 224
Magnesium 224
viii
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CONTENTS (continued)
Section Page
Manganese 224
Molybdenum 224
Mercury 225
Nickel 225
Oil and Grease 225
Total Phosphorus (as P) 225
Potassium 226
Polychlorinated Biphenyls (PCB's) 226
Selenium 226
Silver 226
Sodium 226
Sulfate . 226
Thallium 226
Tin 227
Titanium 228
Total Dissolved Solids 228
Total Suspended Solids 228
Vanadium 228
Zinc 228
Combined Chemical Treatment 229
Precipitation 229
Alkali Selection 235
Aeration 236
Solids Separation 238
Evaporation and Other Processes 238
Technology Specific to Powerplant Waste Waters (General)^ 239
Continous Waste Streams 243
Cooling Water Systems 243
Chemical Conditioning 244
Chemical Conditioning of Once-Through 244
Systems
Chemical Conditioning of Recirculating 256
Systems
Mechanical Cleaning of condenser Tubes 267
On-Line Mechanical Cleaning 270
Mechanical Cleaning During Scheduled 274
Outages
Economics of Condenser Cleanliness 275
Design for Corrosion Protection 278
Corrosion Resistant Materials in Condensers 279
Corrosion Resistant Materials in Cooling Towers 279
Resistant Pretreatments and Coatings 280
Saltwater Cooling Towers 280
Cooling Tower Blowdown Treatment 281
Clarification, Softening and Filtration 287
ix
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CONTENTS (continued)
section Page
Ion Exchange Wastes 290
Evaporator Slowdown 294
Boiler or PWR Steam Generator Slowdown 294
Periodic Wastes 295
Maintenance Cleaning Wastes 295
Ash Handling Wastes 296
Coal Pile Runoff 312
Floor and Yard Drains 318
Air Pollution Control Devices 318
Sanitary Wastes 323
Ohter Wastes 323
Various Waste Streams - Concentration and Recycle 324
Sludge Disposal 329
Powerplant Wastewater Treatment^Systeins 336
Wastewater Management 336
Effluent Reduction Benefits of Waste Water Treatment 343
to Remove Chemical Pollutants
Summary 346
A-VIII COST, ENERGY AND NON-WATER QUALITY ASPECTS 355
Introduction 355
Central Treatment plant Costs 356
Costs for Wastes Not Treated at Central Treatment 373
Plant
Cooling Water - Once Through Systems 373
Cooling water Blowdown - Closed Systems 377
Sanitary Wastes 379
Materials Storage and construction Runoff 383
Intake Screen Backwash 387
Radwaste 387
Ash Sluicing Systems 387
Costs of Complete Treatment of Chemical Wastes 400
for Re-use
Energy 404
Non-Water Quality Environmental Impacts 405
Intermediate Dewatering Devices 405
Evaporation Ponds (Lagoons) 406
Landfill 406
Conveyance to Off-Site Disposal 407
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CONTENTS (continued)
Section .Pa3§
A-IX,X,XI BEST PRACTICABLE CONTROL TECHNOLOGY CURRENTLY 409
AVAILABLE, GUIDELINES AND LIMITATIONS
BEST AVAILABLE TECHNOLOGY ECONOMICALLY 409
ACHIEVABLE, GUIDELINES AND LIMITATIONS
NEW SOURCE PERFORMANCE STANDARDS AND 409
PRETREATMENT STANDARDS
Best Practicable Control Technology Currently Available 409
Cooling Systems . 409
Low-Volume waste Waters 410
Once-Through Ash and Air Pollution Control Systems 412
Rainfall Runoff Waste Water Sources 412
Best Available Technology Economically Achievable 412
New Source Performance Standards 413
Application of Effluent Limitations Guidelines 414
and Standards
Costs 418
Energy and Other Ngn-Water^guality 419
Environmental Impacts
PART B: THERMAL DISCHARGES 421
B-V WASTE CHARACTERIZATION 421
General 421
Quantification of Waste Stream Characteristics 421
Industry-wide variations ~ 426
Variations with Industry Grouping 430
Effluent Heat Characteristics from Systems 439
Other Than Main Condenser Cooling Water
Environmental Risks of Powerplant Heat Discharges 439
B-VI SELECTION OF POLLUTANT PARAMETERS 443
Rationale 443
Environmental Significance of Effluent Heat 445
B-VII CONTROL AND TREATMENT TECHNOLOGY 447
Introduction 447
Process Change 449
Background 449
History of Steam Electric Powerplant Cycle 457
Rankine Cycle 460
Rankine Cycle with Superheat 460
xi
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CONTENTS (continued)
Section gage
Regenerative Cycle 460
Reheat Cycle 463
Historical Process Changes 465
Process Changes for Existing Plants 467
Feedwater Heater Additions 467
Reduce Backpressure (Condensing Pressure) 467
Increase Steam Temperature 469
Increase Steam Pressure 469
Reheat 469
Increase Cooling Gas Pressure 469
Drain coolers 469
Drains Pumped Forward 469
Superposed Plants 469
Complete Plant Upgrading 472
Future Improvement in Present Cycles 474
Gas Cycles 474
Gas Cycle Plants-Base Power 477
Gas Cycle Plants-Peaking Power 477
Combined Gas-Steam Plants 477
Future Generation Processes 479
Binary Topping Cycles 479
Geothermal Steam 430
MHD 480
Fuel Cells 480
Waste Heat Utilization 480
Agricultural Uses 482
Aquaculture 482
Utilization of Extraction Steam 433
Total Energy Systems 435
Cooling Water Treatment 486
General 486
Once-Through (Nonrecirculating Systems) 487
Once-Through Systems with Supplemental 489
Heat Removal (Helper Systems) 489
Closed or Recirculating Systems 496
Cooling Ponds 497
Spray Ponds 508
Wet-Type Cooling Towers 520
Wet Mechanical Draft Towers 523
Induced Draft - Crossflow 525
Induced Draft - Counterflow 532
Forced Draft 533
Wet-Dry Cooling Towers 533
Natural Draft Cooling Towers 535
Dry-Type Cooling Towers 543
Other Tower Types Used Outside the U.S. 550
xii
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CONTENTS (continued)
Section Page
Survey of Existing Cooling Water Systems 555
Effluent Heat Reduction for Closed-Cycle Systems 562
B-VIII COST, ENERGY AND NON-WATER QUALITY ASPECTS 565
Cost and Energy 565
Cost Data-Plant Visits 569
Cost Studies for Specific Plants 573
Other Cost Estimates 578
Cost Analyses 587
Energy (Fuel) Requirements 611
Loss of Generating Capacity 614
Site-Dependent Factors 614
Age * 615
Size 621
Site-Dependent Factors in General 621
Flow Rate 626
Intake Temperature 626
Wet-Bulb Temperature 627
Back-End Loading 627
Aircraft Safety 627
Miscellaneous Factors 628
Relative Humidity 628
Land Requirements 628
Non-Water Quality Environmental Impact 636
of Control and Treatment Technology
Drift 636
Fogging 643
Noise 652
Height « 655
Consumptive Water Use 655
Slowdown 665
Aesthetic Appearance 666
Icing Control 668
Non-Water Quality Environmental Aspects 669
of Spray Cooling Systems
Non-Water Quality Environmental Aspects 672
of Surface Cooling
Comparison of Control Technologies 673
Costs Versus Effluent Reduction Benefits 673
Considerations of Section 316 (a) 679
xiii
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CONTENTS (continued)
Section Pagg
B-IX,X,XI BEST PRACTICABLE CONTROL TECHNOLOGY CURRENTLY 681
AVAILABLE, GUIDELINES AND LIMITATIONS
BEST AVAILABLE TECHNOLOGY ECONOMICALLY 681
ACHIEVABLE, GUIDELINES AND LIMITATIONS 681
NEW SOURCE PERFORMANCE STANDARDS AND
PRETREATMENT STANDARDS
Limitations 681
Factors 683
XII ACKNOWLEDGMENTS 701
XIII REFERENCES 711
XIV GLOSSARY 753
Appendix 1 Industry Inventory
Appendix 2 Reliability Coordination Organizations
xiv
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FIGURES
Number Title Page
III-1 Projected Total U.S. Energy Flow 22
Pattern (1980)
III-2 Condensed Construction Schedule, 37
200 Mw Oil-Fired Unit
•
III-3 Typical LWR Nuclear Plant Project 38
Schedule, Highlights Only
III-'* Regional Reliability Versus Percent Reserve 41
IV-1 Schematic Flow Diagram, Typical Steam 52
Electric Generating Plant
IV-2 Power Cycle Diagram, Fossil Fuel 53
IV-3 Power Cyle Diagram, Nuclear Fuel 54
IV-1 ' Typical Boiler for a Coal-Fired Furnace 57
IV-5 Schematic Cooling Water Circuit 62
IV-6 Cumulative Frequency Distribution of Entire 69
Powerplant Inventory for All EPA Regions
IV-7 Cumulative Frequency Distribution of Fossil- 70
Steam Powerplants for All EPA Regions
IV-8 Cumulative Frequency Distribution of Nuclear- 71
Steam Powerplants for All EPA Regions
IV-9 Largest Fossil-Fueled -Steam Electric 73
Turbine-Generators in Service (1900-1990)
IV-10 Heat Rates of Fossil-Fueled Steam 76
Electric Plants
IV-11 Heat Rate vs Unit Capacity 77
IV-12 Heat Rate vs Unit Age 78
A-V-1 Typical Flow Diagram, Steam Electric 109
Powerplant (Fossil-Fueled)
A-V-2 Simplified Water System Flow Diagram 110
for a Nuclear Unit
XV
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FIGURES (continued)
Number Title Page
A-V-3 Nomogram to Determine Langelier 118
Saturation Index
A-V-1 Clarification Process 123
A-V-5 Filtration Process 123
A-V-6 Ion Exchange Process, Cationic and i25
Anionic Type
A-V-7 Ion Exchange Process, Mixed Resin Type 126
A-V-8 Evaporation Process 130
A-V-9 Typical Ash Pond 150
A-V-10 Flow Diagram - Air Pollution Control 169
Scrubbing Device at Plant 4216
A-V-11 Liquid Radioactive Waste Handling 176
System PWR Nuclear Plants
A-V-12 Liquid Radioactive Waste Handling System 178
1100 Mw BWR Nuclear Plant
A-VTI-1 Effect of pH on Phosphorus Concentration 227
of Effluent from Filters Following Lime
Clarifier
A-VII-2 Solubility of Copper, Nickel, chromium, 230
and Zinc as a Function of pH
A-VII-3 Theoretical Solubilities of Metal Ions 231
as a Function of pH
A-VII-4 Experimental Values - Solubility of 232
Metal Ions as a Function of pH
A-VII-5 Experimentally Determined Solubilities 233
of Metal Ions as a Function of pH
A-VII-6 Change in the Solubilities of Zinc, 234
Cadmium, Copper, and Nickel
Precipitates (Produced with Lime
Additions) as a Function of Standing
Time and pH Value
A-VII-7 Brine Concentrator 240
xvi
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FIGURES (continued)
Number Title Page
A-VII-8 Typical Powerplant Cooling Water Circuit 246
A-VII-9 Concentration of Residual Chlorine in Cooling 248
Tower Slowdown Versus Time
A-VII-10 Chlorine Peed Control, Once-Through 251
Condenser Cooling Water
A-VII-11 Typical Powerplant Once-Through Fresh 253
or Saltwater Cooling Systems, Points
of Chlorine Application
A-VII-12 Recirculated Powerplant Cooling Water 259
Systems, Points of Chlorine Application
A-VII-13 Recirculating Condenser Cooling 265
System, pH Control of Slowdown
A-VII-1U Schematic Arrangement 271
Amertap Tube Cleaning System
A-VII-15 Reverse Flow Piping 273
A-VII-16 Tube Cleanliness Versus Cost of 277
Reduced Generating Efficiency
A-VII-17 Cooling Tower Blowdown Chromate 285
Reduction System
A-VII-18 Typical Process Flow Diagram, 286
Chromate Removal System
A-VII-19 Flow Diagram of the Primary Water 288
Treatment Plant, Mohave Generating
Station
A-VII-20 Possible Combinations of Concentration 289
and Evaporation-Crystallization Processes
For Complete Treatment of Cooling
Tower Blowdown
A-VII-21 Clarification Waste Treatment Process 291
A-VII-22 Ion Exchange Waste Treatment Process 292
A-VII-23 Neutralization Pond 293
A-VII-2U Tube Settler for Ash Sluice Water 302
xvii
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FIGURES (continued)
Number Title Page
A-VII-25 Flow Diagram, Recirculating Bottom Ash 306
System at Plant No. 3630
A-VII-26 Flow Diagram, Recirculating Bottom Ash 307
System at Plant No. 5305
A-VII-27 Ash Sedimentation System - Plant No. 5305 308
A-VII-28 Ash Handling System - Plant No. 3626 309
A-VII-29 Ash Handling System, Oil Fuel Plant 311
- Plant No. 2512
A-VII-30 Cost of Neutralization Chemicals 314
A-VII-31 Comparison of Lime, Limestone, and 315
Soda Ash Reactivities
A-VII-32 Comparison of Settling Rate 316
A-VII-33 Coal Pile - Plant No. 5305 317
A-VII-3a Cylindrical Air Flotation Unit 319
A-VII-35 Typical A.P.I. Oil-Water Separator 319
A-VII-36 Oil Separator and Air Flotation Unit 320
- Plant No. 0610
A-VII-37 Corrugated Plate Type Oil Water 321
Separator
A-VII-38 Oil Water Separator 322
A-VII-39 Vapor - Compression Evaporation 325
System (Case I)
A-VII-40 Vapor - Compression Evaporation 327
System (Case II)
A-VII-U1 Sewage and Waste Water Disposal for a 337
Typical Coal-Fired Unit, 600 Mw
A-VII-42 Recycle of Sewage and Waste Water for a 338
Typical Coal-Fired Unit, 600 Mw
A-VII-U3 Recycle Water System, Plant No. 2750 340
A-VIII-1 Flow Sheet, Coal Fired Plant 357
Central Treatment Plant
xviii
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FIGURES (continued)
Number Title Page
A-VIII-2 Cost of Equalization Tanks and 358
Oil Removal Tanks
A-VIII-3 Costs of Clarifier, Reactor System, 359
and Filters
A-VIII-U Estimated Total Capital Costs of 368
Central Treatment Plants
A-VTII-5 Annual Costs of Labor, Chemicals and 374
Power for Chemical Treatment
A-VIII-6 Cost for Coal Pile Run-off Collection 384
A-VIII-7 Materials Storage Area Runoff Treatment 335
A-VIII-8 Flow Sheet, Recalculating Bottom Ash 390
Sluicing Slowdown Treatment
A-VIII-9 Treatment of Combined Ash Overflow 39 ]_
A-VIII-10 Estimated Total Capital Costs for Materials 395
Storage and Construction Activities Rainfall
Runoff Treatment, Recirculating Bottom Ash
Systems with Slowdown Treatment and Recirculating
Bottom Ash Systems with Treatment of combined
Ash Pond Overflow, All for Coal-Fired Plants
A-VIII-11 100 Mw Coal-Fired Steam Electric 402
Powerpiant. Recycle and Reuse of
Chemical Wastes
A-VIII-12 100 Mw Oil-Fired Steam Electric 403
Powerplant, Recycle and Reuse of
Chemical Wastes
A-X-1 Hypothetical Powerplant Water Flows 4^5
B-V-1 Onit Condenser Delta (T) 422
B-V-2 Unit Heat Rate Distribution 424
B-V-3 Maximum Summer Outfall Temperature 427
B-V-4 Delta (T) vs Onit Age 431
B-V-5 Base Unit Heat Rates 433
B-V-6 Cycling Unit Heat Rates 434
xix
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FIGURES (continued)
Number Title
B-V-7 Peaking Unit Heat Rates
B-V-8 Base Unit Condenser Delta (T)
B-V-9 Cycling Unit Condenser Delta (T)
B-V-10 Peaking Dnit Condenser Delta (T)
B-VII-1 Energy Flow for a Powerplant
B-VII-2 Energy Balance for a Powerplant
B-VII-3 Powerplant Violating Second Law
B-VII-4 Powerplant Violating First Law
B-VII-5 Powerplant Conforming to First
and Second Law
B-VII-6 Carnot Cycle Steam Powerplant
B-VII-7 Rankine Cycle Powerplant
B-VII-8 Rankine Cycle with Superheat
Powerplant
B-VII-9 Regenerative Cycle Powerplant
B-VII-10 Reheat Cycle Powerplant
B-VII-11 Drain Cooler Addition to Powerplant
B-VII-12 Drains Pumped Forward in Powerplant
B-VII-13 Superposed Plant Addition
B-VII-1U Simple Brayton Cycle Gas Turbine
Powerplant
B-VII-15 Brayton Cycle with Regenerator Gas
Turbine Powerplant
B-VII-16 Combined Gas-Steam Powerplant
B-VII-17 Once-Through (Open) Circulating
Water System
B-VII-18 Once-Through (Open) System with
Helper Cooling System Installed
Page
435
436
437
438
452
452
454
454
455
456
461
462
464
466
470
471
473
475
476
478
488
491
xx
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FIGURES (continued)
Number Title Page
B-VII-19 Cooling System Capable of Both 492
Open and Closed Mode Operation
B-VII-20 Plant Layout at Plant No. 2119 493
B-VII-21 Seasonal Variation of Helper Cooling 495
Tower
B-VII-22 Cooling Canal - Plant No. 1209 499
B-VII-23 Chart for Estimating Cooling Pond 502
Surface Heat Exchange Coefficient
B-VII-24 Cooling Pond Surface Area vs Heat 504
Exchange Coefficient
B-VII-25 Determination of Surface Temperature 505
Increase Resulting From Thermal
Discharge of Station
B-VII-26 Determination of Average Surface 506
Temperature Increase Resulting
From Thermal Discharge of Station
B-VII-27 Estimation of Capital Cost of 507
Cooling Pond
B-VII-28 Dnitized Spray Module 510
B-VII-29 Four Spray Module 511
B-VII-30 Spray Canal - Plant No. 0610 512
B-VII-31 Spray Modules - Plant No. 0610 513
B-VII-32 Graphic Representation of Design 515
of Spray Augmented Cooling Pond
B-VII-33 Thermal Rotor System 516
B-VII-34 Double Spray Fixed Thermal Rotor 517
B-VII-35 Graphic Representation of Preliminary 518
Cost Data on Rotating Disc Device
B-VII-36 Determination of Required Flow per 519
Disc for Rotating Disc Device
B-VII-37 Counterflow Mechanical Draft Tower 521
xxi
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FIGURES (continued)
Number Title Page
B-VII-38 Crossflow Mechanical Draft Tower 521
B-VII-39 Crossflow Natural Draft Tower 522
B-VII-HO Counterflow Natural Draft Cooling 522
Tower
B-VII-41 Typical Chart for Determining 527
Fating Factor
B-VII-42 Cost Vs Rating Factor, 528
Mechanical Draft Tower
B-VII-43 Cooling Tower Performance Curves 529
B-VII-UU Comparison of K-Factor and Rating 530
Factor for the Performance of
Mechanical Draft Cooling Towers
B-VII-45 Graph Showing Variation of Cost of 531
Mechanical Draft Cooling Towers
with Water Flow
B-VII-U6 Mechanical Forced Draft Cooling 534
B-VII-U7 Parallel Path Wet-Dry Cooling 534
Tower Psychrometrics
B-VII-U8 Parallel Path Wet-Dry Cooling 536
Tower for Plume Abatement
B-VII-U9 Parallel Path Wet-Dry Cooling 537
Tower (Enlarged Dry Section)
B-VII-50 Typical Natural Draft Cooling 539
Towers - Plant No. 4217
B-VII-51 Hyperbolic Natural Draft Crossflow 540
Water Cooling Towers, Typical Cost
Performance Curves for Budget
Estimates
B-VII-52 Hyperbolic Natural Draft Crossflow 541
Water Cooling Towers, Typical Cost
Performance Curves for Budget
Estimates
B-VII-53 Fan-Assisted Natural Draft Cooling 542
Tower
xxii
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FIGURES (continued)
Number Title Page
B-VII-54 Direct, Dry-Type Cooling Tower 544
Condensing System with Mechanical
Draft Tower
B-VII-55 Indirect, Dry-Type Cooling Tower 545
Condensing System with Natural-
Draft Tower
B-VXI-56 Temperature Diagram of Indirect Dry 546
Cooling Tower Heat-Transfer System
B-VII-57 Representative Cost of Heat Removal 543
With Dry Tower Systems for Nuclear
Plants
B-VII-58 Steam Type Direct Contact Condenser 549
B-VII-59 Effect of Turbine Exhaust Pressure on 551
Fuel Consumption and Power Output
B-VII-60 Section Across a Circular Mechanical 552
Draft Cooling Tower
B-VII-61 Frimmersdorf Power Station 553
B-VII-62 Cable Tower 554
B-VII-63 Cooling Tower with Noise Control 555
at Lichterfelde Plant
B-VIII-1 Example of Optimization of Net Unit 570
Power Output by Reduction of Cooling
Tower Fans
B-VlII-la Salinity Effects on Cooling Tower 583
Size and Costs
B-VIII-2 Additional Generating Costs for 601
Mechanical Draft Towers, Base-Load
Unit, 300 Mw, 6 Year Remaining Life
B-VIII-3 Additional Generating Costs for 601
Mechanical Draft Towers, Base-Load
Unit, 300 Mw, 18 Year Remaining Life
B-VIII-U Additional Generating Costs for 601
Mechanical Draft Towers, Base-Load
Unit, 300 Mw, 30 Year Remaining Life
xxiii
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FIGURES (continued)
Number Title Page
B-VIII-5 Additional Generating Costs for 601
Mechanical Draft Towers, Base-Load
Unit, 300 Mw, 18 Year Remaining Life
B-VIII-6 Additional Generating Costs for 601
Mechanical Draft Towers, Base-Load
Unit, 300 Mw, 30 Year Remaining Life
B-VIII-7 Additional Generating Costs for 603
300 Mw Cyclic Unit, Mechanical
Draft Towers, 6 Year Remaining Life
B-VIII-8 Additional Generating Costs for 603
300 Mw Cyclic Unit, Mechanical
Draft Towers, 18 Year Remaining Life
B-VIII-9 Additional Generating Costs for 603
300 Mw Cyclic Unit, Mechanical
Draft Towers, 30 Year Remaining Life
B-VIII-10 Additional Generating Costs for 603
300 Mw Peaking Unit, Mechanical
Draft Towers, 6 Year Remaining Life
B-VIII-11 Additional Generating Costs for 603
300 Mw Peaking Unit, Mechanical
Draft Towers, 18 Year Remaining Life
B-VIII-12 Additional Generating Costs for 603
300 Mw Peaking Unit, Mechanical
Draft Towers, 30 Year Remaining Life
B-VIII-13 Variation of Additional Generation 604
Cost with Capacity Factor
B-VIII-1** Additional Generating Costs for 800 Mw 606
Nuclear Unit, Mechanical
Draft Cooling Towers, 18 Year
Remaining Life
B-VIII-15 Additional Generating Costs for 800 Mw 606
Nuclear Unit, Mechanical
Draft Cooling Towers, 30 Year
Remaining Life
B-VIII-16 Turbine Exhaust Pressure Correction 612
Factors (Example, Plant No. 3713)
B-VIII-17 Costs/Benefits of Retrofitting Versus 620
Age of Unit
xxiv
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FIGURES (continued)
Number Title Page
B-VIII-18 Percentage Distribution of 1983 622
Generation By Annual Cost of
Closed-Cycle Cooling
B-VIII-19 Capital Costs of Retrofitting Mechanical 623
Draft Cooling Towers to Units Placed into
Service After 1970 Versus Size of Unit
B-VIII-20 Broadside Multiple Tower Orientation 632
B-VIII-21 Longitudinal Multiple Tower Orientation 633
B-VIII-22 Ground-Level Salt Deposition Rate from 641
a Natural-Draft Tower as a Function of
the Distance Downwind: A comparison
Between various Prediction Methods
B-VIII-23 Modified Psychrometric Chart 644
B-VIII-24 Graphical Distribution of Potential 646
Adverse Effects From cooling Towers
Based on Fog, Low-Level Inversion and
Low Mixing Depth Frequency
B-VIII-25 Location of Natural Draft Cooling 649
Towers Through 1977
B-VIII-26 Fan Cost Versus Noise Reduction 654
B-VIII-27 Heat Transfer Mechanisms With 657
Alternative Cooling Systems
B-VIII-28 Water Consumption versus 660
Meteorology and Cooling Range
B-VIII-29 Regions Upon Which Water Consumption 662
Studies Have Been Based
B-VIII-30 Additional Cost Versus Heat Discharged 675
A-2-1 Formal Coordinating Organizations or A2-1
Power Pools
A-2-2 Informal Coordinating Groups A2-2
A-2-3 National Electric Reliability Council A2-3
Regions
XXV
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TABLES
Number Title Page
I1-1 Summary of Effluent Limitations Guidelines 4
and Standards for Pollutants Other Than Heat
II-2 Summary of Effluent Limitations Guidelines 5
and Standards for Heat
III-1 Principal Statutory Considerations 10
III-2 Summary Description Electrical Power 16
Generating Industry (Year 1970)
III-3 Projected Growth of Utility Electric 18
Generating Capacity
III-U FPC Projection of Fuel Use 19
in Steam Electric Powerplants
III-5 FPC Projected Annual Fuel Requirements 21
for Steam Electric Powerplants
IV-1 Industry Inventory Summary 68
IV-2 Distribution of Installed Generating 74
Capacity in the U.S. By Size for Various
Years When Equipment Was First Placed
In Service
IV-3 Urban Steam Electric Powerplants 85
IV-4 Characteristics of Units Based on 89
Annual Hours of Operation
IV-5 Chemical Waste Categories 94
IV-6 Applicability of Chemical Waste 95
Categories by Fuel Type
IV-7 General Subcategorization Rationale 101
IV-8 Subcategorization Rationale for Heat 102
IV-9 Subcategorization Rationale for Pollutants 103
Other Than Heat
IV-10 Distribution of U.S. Generating Capacity by 105
Age and Capacity Factor
xxvi
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TABLES (continued)
Number Title page
A-V-1 Recirculating Water Quality Limitations 117
A-V-2 Typical Characteristics of Powerplant Water 121
Supplies
A-V-3 Typical Water Treatment Waste Water Flows 131
A-V-U Arithmetic Mean and Deviation of 134
Selected Water Treatment Waste Para-
meters
A-V-5 Chemical Waste Characterization, 138
Boiler Tubes* Cleaning
A-V-6 Chemical Waste Characterization, 141
Air Preheater Cleaning, Boiler
Fireside Cleaning
A-V-7 Constituents of Coal Ash 152
A-V-8 Time of Flow for Ash Handling Systems 153
A-V-9 Chemical Waste Characterization, 154
Ash Pond Overflow - Net Discharge
A-V-10 Coal Pile Drainage 162
A-V-11 Chemical Waste Characterization 165
Coal Pile Drainage
A-V-12 Equipment Drainage, Leakage 166
A-V-13 Total Metals Discharged from Powerplants 181
in the U.S. (1973) Compared to Other
Industrial Sources
A-V-1U Total Iron and Copper Discharges from 181
Coal-Fired Powerplants in the U.S. (1973)
A-V-15 Chemicals Used in Steam Electric Powerplants 183
A-V-16 Chemicals Associated with Nuclear 184
Power Plants
A-V-17 Use of High Tonnage Chemical Additives 185
by Steam Electric Powerplants (1970)
A-V-18 Chemical Composition of Trade-Name 186
Microorganism Control Chemicals
xxvii
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TABLES (continued)
Number Title Page
A-V-19 Class of Various Waste Water Sources 187
A-V-20 Typical Chemical Wastes from a Coal- 188
Fired Powerplant
A-VI-1 Applicability of Parameters to Chem- 190
ical Waste Streams
A-VI-2 Chemical Wastes - Number of Plants 191
with Recorded Data
A-VI-3 Selection of Pollutant Parameters 200
A-VI-1* Selected Pollutant Parameters 203
A-VII-1 Comparison of Alkaline Agents 237
for Chemical Treatment
A-VII-2 Operating Data, Typical Powerplant 246
Cooling Water Chlorination, Open
Once-Through Cooling Systems
A-VII-3 Chemical Conditioning of a Cooling Tower 257
System Using CrOJJ - PO.4
A-VII-H Chemical Conditioning of a Cooling Tower 257
System Using Organic Phosphate
A-VII-6 No Chemical Conditioning of Cooling Tower 268
System Except for Alkalinity Control, But
Using On-Line Mechanical Cleaning Condenser
Tubes
A-VII-7 Complete Chemical Conditioning of Cooling 268
Tower System At "Zero" Discharge with
Sidestream Treatment of Tower Waste and
On-Line Mechanical Cleaning Condenser Tubes
A-VII-8 Comparitive Capital Costs of Condenser 276
Cleaning Systems
A-VII-9 Comparative Annual Costs 276
A-VII-10 Recommended Construction Materials for 282
Cooling Tower Operating with Salt Water
A-VII-11 Waste Disposal Characteristics of Typical 283
Cooling Tower Inhibitor Systems
A-VII-12 Ash Pond Performance 297
xxviii
-------
TABLES (continued)
Number Title Page
A-VII-13 Summary of EPA Data Verifying 298
Ash Pond Performance, Plant No. 0107
A-VII-1<» Ash Pond Effluent Total 300
Suspended Solids
A-VII-15 Performance of Tube settlers for Ash 304
Sluice Water
A-VII-16 RCC Brine concentrator System Chemistry 325
(Case I)
A-VII-17 RCC Brine Concentrator System Chemistry 323
(Case II)
A-VII-18 Ash Collection and Utilization, 1971 330
A-VII-19 Known Uses for Ash Removal From Plant 330
at No Cost to Utility
A-VII-20 Extent of Present Use of Chemical Waste 344
Disposal Methods in Coal-Fired Powerplants
(1973)
A-VII-21 Chemical Wastes - Control and 347
Treatment Technology
A-VII-22 Flow Rates - Chemical Wastes 349
A-VII-23 Costs/Effluent Reduction Benefits, 350
Control and Treatment Technology for
Pollutants Other Than Heat, High
Volume Waste Streams
A-VII-2U Costs/Effluent Reduction Benefits, 351
Control and Treatment Technology for
Pollutants Other Than Heat,
Intermediate Volume Waste Streams
A-VII-25 Costs/Effluent Reduction Benefits, 352
Control and Treatment Technology for
Pollutants Other Than Heat,
Low volume waste Streams
A-VII-26 Costs/Effluent Reduction Benefits, 353
Control and Treatment Technology for
Pollutants Other Than Heat,
Rainfall Runoff Waste Streams
xxix
-------
TABLES (continued)
Number Title Page
A-VIII-1 Estimated Equipment Costs, Central 360
Treatment Plant for Coal-Fired Powerplants
A-VIII-2 Estimated Equipment Costs, Central 361
Treatment Plant for Oil-Fired Powerplants
A-VIII-3 Estimated Equipment Costs, Central 362
Treatment Plant for Gas-Fired Powerplants
A-VIII-U Estimated Equipment Costs, Central 363
Treatment Plant for Nuclear Powerplants
A-VIII-5 Estimated Total Capital Costs, Central 364
Treatment Plant for Coal-Fired Powerplants
A-VIII-6 Estimated Total Capital Costs, Central 365
Treatment Plant for Oil-Fired Powerplants
A-VIII-7 Estimated Total Capital Costs, Central 356
Treatment Plant for Gas-Fired Powerplants
A-VIII-8 Estimated Total Capital Costs, Central 357
Treatment Plant for Nuclear Powerplants
A-VIII-9 Estimated Annual Costs, Central Treatment 369
Plant for Coal-Fired Powerplants
A-VIII-10 Estimated Annual Costs, Central Treatment 370
Plant for Oil-Fired Powerplants
A-VIII-11 Estimated Annual Costs, Central Treatment 371
Plant for Gas-Fired Powerplants
A-VIII-12 Estimated Annual Costs, Central Treatment 372
Plant for Nuclear Powerplants
A-VIII-13 Capital and Operating Costs for On-Line 375
Tube Cleaning Equipment
A-VIII-14 Typical Sponge Rubber Ball Tube Cleaning 375
System Costs
A-VIII-15 Costs Comparison of Alternative Tube 373
Material
A-VIII-16 Capital Investment Costs for Chromate 390
Reduction Systems
A-VIII-17 Variable Operating Costs for Materials 330
and Supplies, Chromate Reduction Systems
XXX
-------
TABLES (continued)
Number Title
A-VI1I-18 Units Costs of Chrornate Reduction Systems 381
A-VIII-19 Slowdown Treatment System Costs • 382
A-VIII-20 Estimated Costs, Materials Storage and 338
Construction Activities Runoff Treatment
(Coal-Fired Plant)
A-VIII-21 Estimated Equipment Costs, Recirculating 392
Bottom Ash Systems and Treatment of Bottom
Ash Slowdown
A-VIII-22 Estimated Equipment Costs, Recirculating 393
Bottom Ash Systems and Treatment of
Combined Ash Pond Overflow
A-VIII-23 Estimated Capital Costs, Recirculating 394
Bottom Ash Systems and Treatment of
Bottom Ash Slowdown
A-VIII-24 Estimated Capital Costs, Recirculating 395
Bottom Ash Systems and Treatment of
Combined Ash Pond Overflow
A-VIII-25 Estimated Annual Costs, Recirculating 397
Bottom Ash Systems and Treatment of
Bottom Ash Slowdown
A-VIII-26 Estimated Annual Costs, Recirculating 393
Bottom Ash Systems and Treatment of
Combined Ash Pond Overflow
A-X-1 Effluent Limitations for Hypothetical Plant 415
B-V-1 Efficiencies, Heat Rates, and Heat 425
Rejected by Cooling Water
B-V-2 Plant Visit Thermal Data 428
B-V-3 Typical Characteristics of Waste 440
Heat Rejection
B-V-1 Total Plant Thermal Discharges 441
B-VII-1 Efficiency Improvements 468
B-VII-2 Energy Demand by Heat Using 434
Applications (1970)
xxxi
-------
TABLES (continued)
Number Title Page
B-VII-3 Oses of Various Types of 557
Cooling Systems
B-VII-4 Extent to Which Steam Electric 558
Powerplants are Already Committed
to the Application of Thermal
Control Technologies
B-VII-5 Cooling Systems for Plants 300 Mw and 559
Larger Under Contruction
B-VII-6 cooling Water Systems Data, Plants 551
Visited
B-VII-7 Effects of Cycles of Concentration on 553
Cooling System Losses, Makeup Required,
Reduction in Effluent Heat
B-VII-8 Effects of Cycles of Concentration on 554
Heat Discharged From a 1000 Mw Power Station
B-VIII-1 Cooling Water Systems - Cost Data, 572
Plants Visited
B-VIII-2 Estimated Costs of Typical Installations of 577
Backfitting Closed-Cycle cooling Systems to
Once-Through Cycle Plants
B-VIII-3 Comparative Cost Estimates of New 579
Nuclear-Fueled Plant Cooling Systems
B-VIII-U Comparative Costs Estimates for New 580
Fossil-Fueled Plant Cooling Systems
B-VIII-5 Cost Estimates of Retrofitted Cooling 581
Systems for Specific Generating Stations
B-VIII-6 Cost Estimates of New Plant Cooling 582
Systems for Specific Generating Stations
B-VIII-7 Capital Costs of selected Cooling Ponds 584
B-VIII-8 Thermal Control Costs for New Plants 586
B-VIII-9 Cost of Cooling System Equipment 589
B-VI11-10 Hypothetical Plant Operating Parameters 591
B-VIII-11 Revised Plant Operation Parameters 591
xxxii
-------
TABLES (continued)
Number Tide
B-VIII-12 Typical Plant Characteristics 593
B-VIII-13 Assumed Increase in Heat Rate Compared 595
to Base Heat Rate as a Function of the
Turbine Exhaust Pressure
B-VIII-14 Cost Assumptions 597
B-VIII-15 Cooling Tower Economic Analysis gOO
B-VIII-16 Comparison of Burns and Roe Economic Analyses of 507
Retrofitting Cooling Towers Wtih Sargent
and Lundy Analysis
B-VIII-17 Comparison of Utility Survey of Retrofitting
Costs With EPA Cost Curves
B-VIII-18 Energy (Fuel) Consumption Penalty
Due to Increased Turbine Backpressure
from Closed-Cycle cooling System
B-VIII-19 Computer Simulation of Costs of
Retrofitting Cooling Towers,Mechanical
Draft, 411 Mw Units, 72X Capacity Factor
B-VIII-20 Computer Simulation of Costs of Retrofitting 617
Cooling Towers, Mechanical Draft, 535 Mw
Units, 44% Capacity Factor
B-VIII-21 Computer Simulation of Costs of Retrofitting 618
Cooling Towers Natural Draft, 411 Mw Units,
72% Capacity Factor
B-VIII-22 Computer Simulation of Costs of Retrofitting 619
Cooling Towers, Mechanical Draft, 82°F Wet
Bulb, 78° Stream Temperature, 600 gpm/Mw
B-VIII-23 Summary of Selected Utilities Capital Costs, 625
Capability Losses and Energy Losses for
Mechanical Draft and Natural Draft Cooling
Towers (1973 Dollars)
B-VIII-24 Effluent Heat, Applicability of 629
Control and Treatment Technology
B-VIII-25 Solids in Drift From Cooling Towers 638
xxxiii
-------
TABLES (continued)
Number Title Page
B-VIII-26 Factors Affecting Dispersion and 640
Deposition of Drift from Natural-Draft
and Mechanical-Draft Cooling Towers
B-VIII-27 Energy Production of Some Natural 551
and Artificial Processes at Various
Scales
B-VIII-28 Evaporation Rates for Various Cooling 658
Systems
B-VIII-29 comparative Utilization of Natural 559
Resources With Alternative Cooling
Systems for Fossil-Fuel Plant with
680 Mw Net Plant Output
B-VIII-30 Control and Treatment Technologies 674
for Heat: Costs, Effluent Reduction
Benefits, and Non-Water Quality
Environmental Impacts
B-VIII-31 Cost Versus Effluent Reduction Benefits, 676
0-100* Removal of Heat
B-VIII-32 Incremental Cost of Application of 677
Mechanical Draft Evaporative Cooling
Towers to Nonnew Units (Basis 1970 Dollars)
B-VIII-33 Incremental Cost of Application of 678
Mechanical Draft Evaporative Cooling
Towers to New Units (Basis 1970 Dollars)
B-VIII-34 Timing for Cases Leading to Significant 680
Thermal Controls
A-2-1 Members of Formal Coordinating A2-4
Organizations or Power Pools (1970)
A-2-2 Informal Coordinating Organizations A2-5
or Power Pools (1970)
A-2-3 Multiple Memberships in Informal A2-6
Coordinating Organizations or Power Pools
A-2-4 Individual Members of Regional Reliability A2-7
Councils
xxxiv
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SECTION I
CONCLUSIONS
For the purpose of establishing effluent limitations,
guidelines and standards of performance for steam electric
powerplants, it has been found that separate consideration
must be given to effluent heat and to pollutants other than
heat, and these are therefore discussed in separate parts of
this report.
The framework for establishing limitations for pollutants
other than heat (chemical-type wastes) has been based on the
types of waste streams generated in each plant, which in
turn are dependent on fuels used, processes employed, plant
site characteristics and waste control technologies.
Chemical-type wastes include wastes from the water treatment
system, power cycle system, ash handling system, air
pollution control system, coal pile, yard and floor
drainage,, condenser cooling system and miscellaneous wastes.
Significant factors for limitations for effluent heat
(thermal discharges) are utilization, age, and size of
facilities.
A survey of current industry practices has indicated that
many plants provide only minimal treatment of chemical type
wastes at the present time, although some of the more
recently constructed plants employ elaborate re-use and
recycle systems as a means of water management. Current
industry practice as far as thermal discharges are concerned
is that they have been successfully controlled where
required by environmental considerations or at sites where
the lack of sufficient naturally available cooling water
made once-through cooling systems impractical.
Current treatment and control technology in the general
field of waste treatment includes many processes which could
be applied by powerplants to reduce the discharge of
chemical pollutants. It is therefore concluded that best
practicable control technology currently available to be
applied no later than July 1, 1977, consists of the control
and treatment of chemical-type wastes to achieve significant
reductions in the level of pollutants discharged from
existing sources. It is also concluded that best available
technology economically achievable to be applied no later
than July 1, 1983, for chemical-type wastes is reflected in
addition by recycle of bottom ash transport water and by
chemical treatment of cooling tower blowdown to remove
-------
chromium, phosphorus and zinc. Standards of performance for
new sources will provide for essentially the same effluent
levels as best available technology, however, limitations on
cooling tower blowdown are based on design for corrosion
prevention rather than the addition of chemicals for
corrosion inhibition.
For thermal effluents, it is concluded that technology is
currently available and is widely utilized in the industry
to achieve any desired or necessary degree of reduction of
the thermal component of powerplant discharges, including
essentially the complete elimination of thermal discharges.
The technological basis for best available technology
economically achievable, and new source performance
standards consists of closed-cycle evaporative cooling
systems such as mechanical and natural draft cooling towers
and cooling ponds, lakes and canals.
The designation of specific control and treatment as best
practicable control technology currently available, best
available technology economically achievable, or as the
basis for new source standards for both chemical and thermal
discharges is intended to satisfy sections 304 and 306 of
the Act. Technology so designated provides the basis for
establishment of thermal and chemical effluent limitations,
guidelines and standards, in that the technology selected is
available and capable of meeting the recommended
limitations. However, the designation of specific
technology as "best practicable", etc., does not mean that
it alone must be utilized to meet the effluent limitations.
Any technology capable of meeting the limitations may be
employed by any powerplant so long as the effluent
limitations are achieved.
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SECTION II
RECOMMENDATIONS
As a result of the findings and conclusions contained in
this report, the effluent limitations, guidelines and
standards of performance recommended for the steam electric
power generating point source category, in compliance with
the mandates of the Federal Water Pollution Control Act
Amendments of 1972, are summarized in Tables II-1 and II-2.
-------
Table II-2
#
SUMMARY OF EFFLUENT LIMITATIONS GUIDELINES AND STANDARDS FOR HEAT
All no discharge limitations allow for blowdown to be discharged at a temperature not
to exceed the cold-side temperature, except where a unit has existing closed-cycle
cooling blowdown may exceed the cold-side temperature. All limitations for existing
units to be achieved by no later than July 1, 1981, except where system reliability
would be seriously impacted the compliance date can be extended to no later than July 1, 1983.
EXISTING GENERATING UNITS
Capacity 500 Mw and greater
Placed into service prior to January 1, 1970
Placed into service January 1, 1970 or thereafter
Capacity 25 Mw to 499 MW
Placed into service prior to January 1, 1974
Placed into service January 1, 1974 or thereafter
Capacity less than 25 Mw
NO LIMITATION,
NO DISCHARGE
NO LIMITATION,
NO DISCHARGE
NO LIMITATION
* Note: Exceptions prescribed on a case-by-case basis for units in systems of
less than 150 Mw capacity, units with cooling ponds or cooling lakes,
units without sufficient land available, units with blowdown TDS 30,000
mg/1 or greater and neighboring land within 500 ft of cooling tower(s),
and units where FAA finds a hazard to commercial aviation would exist.
NEW SOURCES
NO DISCHARGE
# Note: No effluent limitations on heat from sources other than main condenser
cooling water
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SECTION III
INTRODUCTION
General Background
The involvement of the Federal Government in water pollution
control dates back to 1948, when Congress enacted the first
comprehensive measure aimed specifically at this problem.
At that time the Surgeon General, through the U. S. Public
Health Service, was authorized to assist states in various
ways to attack the problem. The emergence of a national
water pollution control program came about with the enact-
ment of the Water Pollution Control Act of 1956 (Public Law
84-660) which to this date remains the basic law governing
water pollution. This law set up the basic system of tech-
nical and financial assistance to states and municipalities,
and established enforcement procedures by which the Federal
Government could initiate legal steps against polluters.
The present program dates back to the Water Quality Act of
1965 and the Clean Water Restoration Act of 1966. Under the
1965 Act, the states were required to adopt water quality
standards for interstate waters, and to submit to the
Federal Government, for approval, plans to implement and
enforce these standards. The 1966 Act authorized massive
Federal participation in the construction of sewage
treatment plants. An amendment, the Water Quality Act of
1970, extended Federal activities into such areas as
pollution by oil, hazardous substances, sewage from vessels,
and mine drainage.
Originally, pollution control activities were the responsi-
bility of the U. S. Public Health Service. In 1961, the
Federal water Pollution Control Administration (FWPCA) was
created in the Department of Health, Education, and Welfare,
and in 1966, the FWPCA was transferred to the Department of
the Interior. The name was changed in early 1970 to the
Federal Water Quality Administration and in December 1970,
the Environmental Protection Agency (EPA) was created by Ex-
ecutive Order as an independent agency outside the Depart-
ment of the Interior. Also by Executive Order 11574 on
December 23, 1970, President Richard M. Nixon established
the Permit Program, requiring all industries to obtain
permits for the discharge of wastes into navigable waters or
their tributaries under the provisions of the 1899 River and
Harbor Act (Refuse Act). The permit program immediately
became involved in legal problems resulting eventually in a
ruling by a Federal court that effectively stopped the
-------
issuance of a significant number of permits, but it did
result in the filing with EPA, through the U.S. Army Corps
of Engineers, of applications for permits which, without
doubt, represent the irost complete inventory of industrial
waste discharges yet compiled. The granting of a permit
under the Refuse Act was dependent on the discharge being
able to meet applicable water quality standards. Although
EPA could not specify methods of treatment, they could
require minimum effluent levels necessary to meet water
quality standards.
The Federal Water Pollution Control Act Amendments of 1972
(the "Act") made a number of fundamental changes in the
approach to achieving clean water. One of the most signifi-
cant changes was from a reliance on water quantity related
effluent limitations to a direct control of effluents
through the establishment of technology-based effluent
limitations to form an additional basis, as a minimum, for
issuance of discharge permits. The permit program under the
1899 Refuse Act was placed under full control of EPA, with
much of the responsibility to be delegated to the States.
Purpose and Authority
The Act requires the EPA to establish guidelines for
technology-based effluent limitations which must be achieved
by point sources of discharges into the navigable waters of
the United States. Section 301(b) of the Act requires the
achievement by not later than July 1, 1977, of effluent
limitations for point sources, other than publicly owned
treatment works, which are based on the application of the
best practicable control technology currently available as
defined by the Administrator pursuant to Section 304(b) of
the Act. Section 301 (b) also requires the achievement by
not later than July 1, 1983, of effluent limitations for
point sources, other than publicly owned treatment works,
which are based on the application of the best available
technology economically achievable which will result in
reasonable further progress toward the national goal of
eliminating the discharge of all pollutants, as determined
in accordance with regulations issued by the Administrator
pursuant to Section 304(b) of the Act. Section 306 of the
Act requires the achievement by new sources of a Federal
standard of performance providing for the control of the
discharge of pollutants which reflects the greatest degree
of effluent reduction which the Administrator determines to
be achievable through the application of the best available
demonstrated control technology, processes, operating
methods, or other alternatives, including, where
practicable, a standard permitting no discharge of
-------
pollutants. Section 304(b) of the Act requires the Adminis-
trator to publish within one year of enactment of the Act,
regulations providing guidelines for effluent limitations
setting forth the degree of effluent reduction attainable
through the application of the best practicable control
technology currently available and the degree of effluent
reduction attainable through the application of the best
control measures and practices achievable including treat-
ment techniques, process and procedure innovations,
operation methods and other alternatives. The regulations
proposed herein set forth effluent limitations, guidelines
pursuant to Section SOU (b) of the Act for the steam electric
powerplant industry.
Section 306 of the Act requires the Administrator, within
one year after a category of sources is included in a list
published pursuant to Section 306 (b) (1) (A) of the Act, to
propose regulations establishing Federal standards of
performances for new sources within such categories. The
Administrator published in the Federal Register of January
16, 1973 (38 F.R. 1624), a list of 27 source categories.
Publication of the list constituted announcement of the
Administrator's intention of establishing, under Section
306, standards of performance applicable to new sources
within the steam electric powerplants industry category,
which was included within the list published January 16,
1973. See Table III-1 for a summary of the principal
statutory considerations.
Section 304 (c) of the Act requires the Administrator to
issue informaton on the processes, procedures or operating
methods which result in the elimination or reduction in the
discharge of pollutants to iirplement standards of
performance under section 306 of the Act. Such information
is to include technical and other data, including costs, as
are available on alternative methods of elimination or
reduction of the discharge of pollutants.
Section 316 (a) of the Act provides that whenever the owner
or operator of any point source can demonstrate to the
satisfaction of the Administrator that any effluent limita-
tion proposed for the control of the thermal component of
any discharge will require more stringent control measures
than are necessary to assure the protection and propagation
of a balanced, indigenous population of shellfish, fish and
wildlife in and on the body of water into which the
discharge is to be made the Administrator may impose less
stringent limitations with respect to the thermal component,
(taking into account the interaction of such thermal
component with other pollutants) that will assure the
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Table III-l
PRINCIPAL STATUTORY CONSIDERATIONS
STATUTORY
BASIS' General Description Process Changes Cost
Process
Employed, Age
& Size of Equip-
ment & Facilities.
Non Water Quality
Environmental
Impact & Energy
Control Technology
Currently Available
304(b)(l)(A)
[Existing Sources]
1. Achieve by 1977
2. Generally average
of best existing per-
formance; high con'
fidence in engineering
viability.
3. Where treatment
uniformly inadequate
a higher degree of
treatment may be
required if practic-
able [compare exist-
ing treatment of
similar wastes].
Normally does not
emphasize in-process
controls, except
where presently
commonly practiced.
Balancing of
total cost of
treatment against
effluent reduc-
tion benefits.
Age, size &
process employed
may require
variations in
discharge limits
(taking into account
compatibility of costs
and process technology)
Assess impact of
alternative controls
on air, solid waste,
noise, radiation
and energy require-
ments.
Best Available
Technology
Economically
Achievable
304 (b> (1KB)
[Existing Sources]
1. Achieve by 1983.
2. Generally best
existing performance
but may include tech-
nology which is capable
of being designed,
though not yet in
place; further
development work could
be required,
Emphasizes both
in-process and end-
of-process control.
Costs considered
relative to broad
test of reason? •
ableness.
Age, size &
process employed
may require
variations in
discharge limits
(taking into account
compatibility of costs
and process technology)
Assess impact of
alternative controls
on air, solid waste
noise, radiation and
energy requirements.
Standards of
Performance Best
Available
Demonstrated Con*
trol Technology
306
[New Sources]
1. Achieved by sources
for which "construc-
tion" commences after
proposal of regula-
tions.
2. Generally same
considerations as for 1983;
more critical analysis
of present availability.
Emphasizes process
changes.
Cost considered
relative to broad
test of reasonable-
ness.
N/A
Assess impact of
alternative controls
on air, solid waste,
noise, radiation
and energy require-
ments.
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protection and propagation of a balanced, indigenous
population of shellfish, fish, and wildlife in and on that
body of water.
The Act defines a new source to mean any source, the
construction of which is commenced after the publication of
proposed regulations prescribing a standard of performance.
Construction means any placement, assembly, or installation
of facilities or equipment (including contractual
obligations to purchase such facilities or equipment) at the
premises where such equipment will be used, including
preparation work at such premises.
Scope of Work and Technical Approach
This document was developed, specifically, for effluent dis-
charge from steam electric powerplants covered under
Standard Industrial Classification (SIC) 1972 Industry Nos.
4911 and 4931, relating to liquid discharges to navigable
waters of the United States.
Industry No. 4911 encompasses establishments engaged in the
generation, transmission and/or distribution of electric
energy for sale. Industry No. 4931 encompasses
establishments primarily engaged in providing electric
service in combination with other services, with electric
services as the major part though less than 95 percent of
the total. The S.I.C. Manual (1972) recommends that, when
available, the value of receipts or revenues be used in
assigning industry codes for transportation, communication,
electric, gas, and sanitary services.
The study was limited to powerplants comprising the electric
utility industry, and did not include steam electric
powerplants in industrial, commercial or other facilities.
Electric generating facilities other than steam electric,
such as combustion gas turbines, diesel engines, etc. are
included to the extent that power generated by the
establishment in question is primarily through steam
electric processes.
This report covers effluents from both fossil-fueled and
nuclear plants and excludes the radiological aspects of
effluents.
The Act requires that in developing effluent limitations,
guidelines and standards of performance for a given
industry, certain factors must be considered, such as the
total cost of the application of technology in relation to
the effluent reduction benefits to be achieved, age of
11
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equipment and facilities, processes employed, engineering
aspects of the application of various types of control
techniques, process changes, non-water quality environmental
impact (including energy requirements) and other factors.
For steam electric powerplants, formal segmentation of the
industry based on all the factors mentioned in the Act has
been found to be inapplicable. However, the two basic
aspects of the effluents produced by the industry, chemical
aspects and thermal aspects, were found to involve such
divergent considerations that a basic distinction between
guidelines for chemical wastes and thermal discharges was
determined to be most useful in achieving the objectives of
the Act. Accordingly, this report covers waste
categorization, control and treatment technology and
recommendations for effluent limitations for chemical and
other nonthermal aspects of waste discharge in Part A and
similar subjects for thermal aspects of discharges in Part B
of this report considering the factors cited in the Act.
Section 502 (6) of the Act defines the term pollutant in
relation to the discharge into water of certain materials,
substances and other constituents of discharge. The
inclusion of heat in the list cf pollutants indicates the
clear intention on the part of Congress to have this
pollutant included in the same manner as other pollutants in
the establishment of effluent limitation guidelines and
standards of performance. Other recognition of heat in
special provisions of the Act is in Sections 104 (t) and 316.
Section 104 (t) requires the EPA Administrator in cooperation
with other agencies and organizations to conduct continuing
comprehensive studies of the effects and methods of control
of thermal discharges. The studies are to include cost-
effectiveness analysis and total impact on the environment.
The Act states that they are to be used by EPA in carrying
out Section 316 of the Act, and by the States in
establishing water quality standards. However it does not
indicate that the studies are to be utilized in establishing
effluent limitation guidelines and standards of performance.
Section 316 (a) does provide for individual variances to be
granted from effluent guidelines for thermal discharges,
where such a variance will assure the protection and
propogation of a balanced, indigenous population of
shellfish, fish and wildlife in and on that body of water.
Consequently, the Act requires effluent guidelines and
standards of performance for heat to be developed in the
same manner as for other pollutants, but also allows for
individual relief from the guidelines and standards under
Section 316. In this context, this report only contains an
12
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evaluation of control and treatment technology for thermal
discharges which reduces or eliminates the amounts of heat
discharged. Consideration of mixing zone technology is
therefore not included, since mixing zones do not reduce the
effluent heat but rely in part upon the dilution effect of
the receiving water to decrease the overall receiving water
temperatures to meet applicable limitations based on
environmental criteria. Therefore they do not qualify as a
control or treatment technology for the establishment of
technology-based effluent limitations guidelines or
standards of performance.
The effluent limitations and standards of performance
recommended herein have been developed from a detailed
review of current practices in the steam electric powerplant
industry. A critical examination was made of treatment
methods now in use in the industry and methods used in other
industries to achieve solutions to problems similar to those
encountered in steam electric powerplants. As part of the
review of current practices, applications for discharge
permits filed in accordance with other provisions of the Act
were examined. There is also a volumuous literature base
and on-going reseach development and demonstration programs
in this and related technical areas. Also as part of this
effort visits were made to 35 plants, with at least one
plant visit to each of the ten EPA regions. Six plants were
visited outside the U.S. Sampling programs were conducted
at plants where it was felt that sufficient information
could be obtained to document treatment practices. The
plants visited are listed below:
Beznau, Dottingen,Switzerland
B.F. Cleary, Taunton, Massachusetts
Big Brown, Fairfield, Texas
Brayton Point, Somerset, Massachusetts
Canal, Sandwich, Massachusetts
Centralia, Centralia, Washington
Cherokee, Denver, Colorado
Chesterfield, Chester, Virginia
Dresden, Morris, Illinois
Dunkirk, Dunkirk, New York
Fremont No. 1, Fremont, Nebraska
Fremont No. 2, Fremont, Nebraska
Fort Calhoun, Fort Calhoun, Nebraska
Greene county, Demopolis, Alabama
Holtwood, Holtwood, Pennsylvania
Keystone, Shelocta, Pennsylvania
Lichterfelde, West Berlin
Marshall, Terrell, North Carolina
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Milliken, Ludlowville, New York
Mohave, Davis Dam, Nevada
Morgantown, Newburg, Maryland
North Omaha, Omaha, Nebraska
Palisades, Benton Harbor, Michigan
Paradise, Drakesboro, Kentucky
Pittsburg, Pittsburg, California
Preussag, Ibbenburen, West Germany
Quad Cities, Cordova, Illinois
Rancho Seco, Rancho Seco, California
Roseten, Roseton, New York
Rugeley, Town of Rugeley, England
Sanford, Sanford, Florida
Turkey Point, Florida City, Florida
Valmont, Valmont, Colorado
Volkswagenwerk, Wolfsburg, West Germany
Westfalen, Schmehausen, west Germany
Will County, Joliet, Illinois
The economic analyses contained in this report pertain only
to costs related to control and treatment technology for the
reduction and elimination of the discharge of pollutants
from steam electric powerplants. Benefits derived from
associated costs are simply the reduction and/or elimination
of pollutant discharges. Cost-benefit analysis which
consider environmental effects, benefits to society,
economic impact, etc. are beyond the scope of this report.
In arriving at recommendations fcr effluent limitations
guidelines and standards of performance, extensive use has
been made of prior studies in this area made for EPA, in-
house information developed by EPA, information developed
by industry sources, and comments submitted by numerous
Federal and State agencies, industrial and other groups, and
others.
Industry Description
Steam electric powerplants are the production facilities of
the electric power industry. The industry also provides for
the transmission and distribution of electric energy. The
industry is made up of two basically distinct ownership
categories, investor-owned and publicly-owned, with the
latter further divided into Federal agencies, non-Federal
agencies, and cooperatives. About two-thirds of the 3400
systems in the United States perform only the distribution
function, but many perform all three functions, production
(generally referred to as generation), transmission, and
distribution. In general, the larger systems are vertically
integrated, while the smaller systems, largely in the
14
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municipal and cooperative categories, rely on firm purchases
to meet all or part of their requirements. Many of the
systems are interconnected, and can, under emergency
conditions, obtain power from other systems.
Historically, the industry started around 1880 with the con-
struction of Edison's steam electric plant in New York City.
For the next sixty years, growth was continuous, but
unspectacular, due to the fairly limited demand for power.
However, since 1940 the annual per capita production of
electric energy has grown at a rate of about six percent per
year, and the total energy consumption by about seven
percent. In 1970, there were about one thousand generating
systems in the United States. These systems had a combined
generating capacity of 340,000 megawatts (Mw) and produced
1,530,000,000 megawatt hours (Mwh) of energy. A breakdown
of the capacity and production by ownership categories is
given in Table III-2.
The industry produces, transmits and distributes a single
product, electric energy. The product is distinguished from
other products of the American industry by the fact that it
cannot be economically stored, and that the industry must be
ready to produce at any give time all the product the
consumer desires to utilize. While some industrial power is
sold on a so-called "interruptible" basis, the total amount
sold on this basis is insignificant compared to the overall
power consumption. The ability of the industry to meet any
instantaneous demand is the criterium for what constitutes
satisfactory performance in the industry and is the single
most significant factor in determining the need for new gen-
erating facilities.
Other special considerations involved in a discussion of the
industry relate to its role as a public utility, a monopoly,
and a regulated industry. As a public utility, its major
objective is to provide a public service. It must supply
its product to all customers within its assigned service
area, but it cannot discriminate between customers, and it
must supply its product to all customers within a given
class at equal cost. As a monopoly, the industry is
generally assigned a service area, but within that area is
exempt from competition except perhaps for competition with
other sources of energy, particularly in the industrial
area. However, in return for the granting of a monopoly,
the industry is required to furnish service. Thus it cannot
cease to service a certain area when such service appears to
be unprofitable. Finally, in view of its position as a
public utility and a monopoly, both the quality of service
it must provide and the rates it may charge for its service
15
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Table III-2
SUMMARY DESCRIPTION
ELECTRICAL POWER GENERATING INDUSTRY (YEAR 1970)
Number of plants (stations). approx. 1000
Number of generating units. approx. 3000
OWNERSHIP
Investor
Federal
Public (non-Fed)
Cooperative
NUMBER OF SYSTEMS*
250
2
700
65
GENERATING CAPACITY, Mw*
265,000
40,000
35,000
5,000
GENERATION, 10 Mwh*
1,180
190
140
22
CUSTOMERS
Residential
Commercial
Industrial
Other
NUMBER
55,000,000
8,000,000
400,000
ENERGY SOLD, Mwh
450,000,000
325,000,000
575,000,000
60,000,000
PROJECTED GROWTH
1970
1980
1990
INSTALLED CAPACITY, Mw
266,000
540,000
1.057.000
FUEL USED
Coal
Natural Gas
Oil
Nuclear
PERCENT HEAT INPUT
54
29
15
2
COST (YEAR 1968)
Production
To Customers
rnills/^
7.7
15.4
* Note: Includes some hydroelectric and internal combustion.
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are regulated by both State and Federal regulatory agencies.
Since the rates it is allowed to charge are a function of
the cost of providing service, any prudent costs imposed on
the industry by regulatory agencies will eventually be
passed on to the electricity consumer. And since the
consumer, particularly at the retail residential level, has
very few options to the use of electricity, the relationship
between costs and consumption is generally considered to be
"inelastic" in the short time, that is, an increase in cost
has little effect on the level of consumption.
The use of electric energy can be divided into three major
categories: industrial, residential and commercial. In
1965, industrial use accounted for 41% of all energy
generated. Residential use accounted for 24% and commercial
use for 18*. Another 17% of the energy generated was used
by miscellaneous users for auxiliary operations within the
industry or lost in transmissions. Studies by the Federal
Power Commission (FPC) indicate no change in this basic use
pattern over the next two decades.
On the other hand, the total amount of electric energy that
will be used is expected to increase significantly over the
next two decades. Again, based on studies by the FPC, it is
believed that the required generating capacity will increase
from 340,000 Mw in 1970 to 665,000 Mw in 1980 and 1,260,000
Mw in 1990. The industry's 1970 generating facilities would
therefore have to be almost doubled by 1980 and again
doubled by 1990.
At the present time, steam electric powerplants, including
both fossil-fueled and nuclear-fueled plants, account for
about 79% of total generating capacity and 83% of the total
power generated. The remainder is accounted for by hydro-
electric generation, both of the once-through and pumped-
storage types, and by direct combustion-generation processes
such as gas turbines and diesel engine driven generators.
Table III-3, taken from reports of the FPC, shows the
projected growth of generating capacity over the next two
decades.
Four basic fuels are used in steam electric powerplants,
three fossil fuels-coal, natural gas and oil - and uranium,
presently the basic fuel of nuclear power. A potential
fuel, reclaimed refuse, is being burned at one experimental
facility, but is not likely to have a major impact on the
industry within the foreseeable future. Table III-U, again
from FPC reports, shows the projected distribution of fuel
use for steam electric power generation for the next two
decades.
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TABLE III- 3
PROJECTED GROWTH OF UTILITY ELECTRIC GENERATING CAPACITY
(Figures in thousands of megawatts)
oo
Type of Plant
Fossil Steam
Nuclear Steam
Subtotal Steam
Hydroelectric-
conventional
Hydroelectric-
pumped storage
Gas-Turbine and Diesel
TOTALS
1970 (actual)
% of
Capacity Total
260 76
6 2
266 78
52 15
4 1
19 6
341 100
1980
% of
Capacity Total
393 59
147 22
540 81
68 10
27 4
31 5
666 100
1990
% of
Capacity Total
557 44
500 40
1,057 84
82 6
71 6
51 4
1,261 100
Notes: (1) These projections are keyed to the electrical energy demand projections made
by Regional Advisory Committee studies carried out in the 1966-1969 period.
(2) The projections are premised on an average gross reserve margin of 20%.
(3) Since different types of plants are operated at different capacity factors,
this capacity breakdown is not directly representative of share of kilowatt-hours
production. For example, since nuclear plants are customarily used in base-load
service and therefore operate at comparatively high capacity factors, nuclear
power's contribution to total electricity production would be higher than its
capacity share.
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Table III-4
FPC PROJECTION OF FUEL USE IN STEAM ELECTRIC
POWERPIANTS
Fuel
Coal
Natural Gas
Fuel Oil
Nuclear
1970
54%
29
15
2
1980
41%
14
14
31
1990
30%
8
9
53
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Table III-5 shows the projected annual fuel requirements for
steam electric powerplants over the next two decades. See
also Figure III-1 for a graphical presentation of the
projection, by the Joint Committee on Atomic Energy, of the
U.S. energy flow pattern for 1980. Although their share of
the total fuel use is declining, the actual use of all three
fossil fuels is projected to continue to increase. Most
significant is the fact that utility consumption of coal
will more than double although coal's share of the total use
will decrease from 5H* to 31%. These projections assume no
major slippages in the construction of nuclear generating
plants. Should such slippages occur, it is possible that
coal will be called upon to assume an even greater role in
meeting the nation's energy needs.
Coal is the most abundant of the fossil fuels. Nationwide
it is estimated that proven recoverable reserves are
sufficient to supply our needs for the next 200 to 300
years. A problem with coal is that it varies in chemical
properties and its geographic distribution does not coincide
with the geographic distribution of the demand for electric
energy. A primary concern is the sulfur content of the
coal. Most of the Eastern coal is too high in sulfur
content to meet the increasingly stringent limits on sulfur
dioxide in stack gases.
Sulfur dioxide removal systems are being employed at a
number of powerplants. All indications are that limitations
on sulfur dioxide emissions will substantially increase
production costs in coal-burning powerplants. In the West,
there are large deposits of low sulfur coal, but here the
cost of either shipping the coal or transmitting electric
energy are substantial. The possibilities of further
environmental restrictions as much as the actual
environmental regulations now in force has possibly resulted
in the conversion of a large number of coal burning plants
to other forms of fossil fuel, and the construction of new
generating facilities using less abundant but more
environmentally acceptable fuels.
Both natural gas and low sulfur residual oils are in short
supply. The natural gas situation was initially felt to be
more critical and some generating plants were being
converted from natural gas to fuel oil. The 1970 FPC
projections indicated that natural gas utilization would
remain fairly constant and that the use of fuel oil would
increase at approximately the same rate as the use of coal.
All of these projections were based on the assumption that
there would be no additional governmental actions regulating
the utilization of fuels and that nothing would happen to
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Table III- 5
FPC PROJECTED ANNUAL FUEL REQUIREMENTS FOR
STEAM ELECTRIC POWERPLANTS
Fuel
Coal
Natural Gas
Fuel Oil
u^o^
3 8
Measure
10 tons
12
10 cubic feet
10 barrels
10 tons to diffusion
plants without re-
cycle of plutoniutn
1970
332
3.6
331
7.5
1980
500
3.8
640
41
1990
500
3.8
800
127
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Figure III-l
PROJECTED TOTAL U0S0 ENERGY FLOW PATTERN (1980)
234
HYDROELECTRIC
GEOTHERMAL
NUCLEAR
GAS
(IMPORTS)
GAS
(DOMESTIC)
ro
ro
COAL
OIL
(IMPORTS)
OIL
(DOMESTIC)
(UNITS: MILLION BBLS/DAY OIL EQUIVALENT)
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affect our present heavy reliance on foreign sources for
fuel oil. Subsequently, the fuel oil problem became
critical, projections were altered and certain plants were
considered for reconversion to coal.
Finally, the projected growth of nuclear generating capacity
is dependent in the short run on the discovery of additional
deposits of low-cost uranium and the construction of
additional ore processing facilities. In the long run, it
is dependent on the successful development and use of
breeder reactor systems. The United States may have a full-
scale breeder plant in operation in the 1980's.
In summary, this report deals with the setting of effluent
guidelines for an industry with many complex aspects. It is
a public utility and therefore is regulated both as to the
quality of its service and the rates it can charge for the
service. While regulation limits the rates it can charge,
it also insures that any prudently increased costs will
eventually be passed on to the retail customer. Except for
some competition in the industrial use of electricity, there
is little competition for the use of its product. On the
other hand, the industry itself has little mobility. A
powerplant generally cannot be moved and a generating unit
can be shut down only when an equivalent unit has been
provided. Since its product cannot be stored and must be
produced to meet a fluctuating demand, much of its capacity
is used only part time. With suitable sites near the
centers of demand largely used up, it has to go further and
further from its demand to obtain satisfactory generating
sites, and even then is often encountering pressure from
environmental groups opposed to the construction of the new
facilities. In addition, because of planning, construction
and design problems with regard to a number of plants
already sited, delays are resulting for some major power
plant installations. Generally, the slippage in the
schedules for new powerplants is requiring the industry to
continue to operate some of the older, less efficient, and
perhaps less environmentally acceptable plants.
Amplification of the "energy crisis" has evoked considerable
attention, constraints, and changes in the industry. In
addition to some shifts in fuel and fuel costs, reduced
projections for the demand for electricity and possibly
other factors have caused at least one major system to
announce a slowdown in planned expansion resulting in the
delay in construction of generating units.
The setting of effluent standards for steam electric power-
plants has therefore involved a large number of complex
factors, many of which do not apply to a conventional
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manufacturing industry producing a non-perishable,
transportable product in a competitive market.
Process Description
The "production" of electrical energy always involves the
utilization and conversion of seme ether form of energy.
The three most important sources of energy which are
converted to electric energy are the gravitational potential
energy of water, the atomic energy of nuclear fuels, and the
chemical energy of fossil fuels. The utilization of water
power involves the transformation of one form of mechanical
energy into another prior to conversion to electrical
energy, and can be accomplished at greater than 90 percent
of theoretical efficiency. Therefore, hydroelectric power
generation involves only a minimal amount of waste heat
production due to conversion inefficiencies. Present day
methods of utilizing the energy of fossil fuels, on the
other hand, are based on a combustion process, followed by
steam generation to convert the heat first into mechanical
energy and then to convert the mechanical energy into
electrical energy. Nuclear processes as generally utilized
also depend on the conversion of thermal energy (heat) to
mechanical energy via a steam cycle. Although progress in
powerplant development has been rapid, a large part of the
energy released by the fuel as heat at a high temperature
level, in even the most efficient plants, is not converted
to useful electrical energy, but is exhausted as heat at a
lower temperature level. This is due to the limitations of
the second law of thermodynamics which can be stated as
follows: A reversible heat - engine can generate work from
high-temperature heat only at the expense of rejecting a
part of this heat to a lower-temperature reservoir. The
fraction of the high-temperature heat which is converted to
work is (T-t)/T, where T is the absolute temperature of the
high-temperature heat source and t is the absolute
temperature of the lower-temperature heat sink.
Where a water-steam cycle is used to convert heat to work,
the maximum theoretical efficiency that can be obtained is
limited by the temperatures at which the heat can be
absorbed by the steam and discarded to the environment. The
upper temperature is limited by the temperature of the fuel
bed and the structural strength and other aspects of the
boiler. The lower temperature is ideally the ambient
temperature of the environment, although for practical
purposes the reject temperature must be set by design
significantly above the highest anticipated ambient
temperature. Within these temperatures it can be shown that
24
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the conversion of heat into any other form of energy is
limited to efficiencies of about 40 percent regardless of
any improvements to the present day machines employed. The
limited boiler temperature utilized by present day light
water nuclear powerplants is the major reason of the lower
efficiency of these plants compared to fossil-fueled plants.
For any steam electric power generation scheme, therefore, a
minimum of about 60 percent of the energy contained in the
fuel must be rejected to the environment as waste heat. The
extent to which existing and future steam electric
powerplants approach this theoretical limit will be
discussed later in this report, as will alternate methods of
converting fuel energy to electric energy which do not
employ a steam cycle and therefore are not limited to steam
cycle efficiencies.
Fossil-fueled steam electric powerplants produce electric
energy in a four stage process. The first operation
consists of the burning of the fuel in a boiler and the
conversion of water into steam by the heat of combustion.
The second operation consists of the conversion of the
high-temperature high-pressure steam into mechanical energy
in a steam turbine. The steam leaving the turbine is
condensed to water, transferring heat to the cooling medium,
which is normally water. The turbine output is conveyed
mechanically to a generator, which converts the mechanical
energy into electrical energy. The condensed steam is
reintroduced into the boiler to complete the cycle.
Nuclear powerplants utilize a similar cycle except that the
source of heat is atomic interactions due to nuclear fuel
rather than combustion of fossil fuel. Water serves as both
moderator and coolant as it passes through the nuclear
reactor core. In a pressurized water reactor, the heated
water then passes through a separate heat exchanger, where
steam is produced on the secondary side. This steam, which
contains no radioactive materials, drives the turb' ie. In a
boiling water reactor, steam is generated directl, in the
reactor core and is then piped directly to the turbine.
This arrangement results in some radioactivity in the steam
and therefore requires some shielding of the turbine. Long
term fuel performance and thermal efficiencies are .milar
for the two types of nuclear systems.
The theoretical water-^steam cycle employed in steam electric
powerplants is known as the Rankine cycle. Actual cycles in
powerplants only approach the performance of the Rankine
cycle because of practical considerations. Thus, the heat
absorption does not occur at constant temperature, but
consists of heating of the liquid to the boiling point.
25
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converting of liquid to vapor and superheating (heating
above the saturation equilibrium temperature) the steam.
Superheating is necessary to prevent excess condensation in
the turbines and results in an increase in cycle efficiency.
Reheating, the raising of the temperature above saturation
of the partially expanded steam, is. used to obtain
improvements in efficiency and again to prevent excess
condensation. Preheating, bringing of condensate to near
boiling temperatures with waste heat, is also used for this
purpose. Condensers cannot be designed to operate at
theoretically optimum values because it would require
infinitely large equipment. All of these divergences from
the optimum theoretical conditions cause a decrease in
efficiency and an increase in the amount of heat rejected
per unit of production. As a result, only a few of the
larger and newer plants approach even the efficiencies
possible under the ideal Rankine cycle. Also as a result of
second law limitations, modifications of the steam cycle of
an existing plant are not likely to result in significant
reductions in heat rejection.
Alternate Processes
Alternate processes for generating electric energy can be
divided into three distinct groups. The first group
includes those processes that are presently being used to
generate significant amounts of electrical energy. This
group includes hydroelectric power generation, combustion
gas turbines, and diesel engines. The second group includes
processes that seek to improve on the steam electric cycle
by utilizing new fuels or new energy technology. This group
includes liquid metal fast breeder reactors, geothermal
generation, utilization of solar energy, and various forms
of combining cycles to obtain greater thermal efficiency.
The last group includes those systems, also mostly still
under development, that seek to eliminate the inherent
limitations of the conventional Rankine cycle by providing
for some alternative type of conversion of chemical energy
into electrical energy. This group includes
magnetonydrodynamics, electrogasdynamics and fuel cells.
Presently Available Alternate Processes
Hydroelectric Power
Hydroelectric developments harness the energy of falling
water to produce electric power, and have a number of
distinct advantages over steam electric plants. Operation
and maintenance costs are generally lower. Although the
initial capital cost may be higher, hydroelectric develop-
26
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ments have longer life and lower rates of depreciation, and
capital charges may therefore be less. The cost of fuel is
not an item of operating cost. Both availability and
reliability are greater than for steam electric units.
Hydroelectric plants are well suited for rapid start and
rapid changes in power output and are therefore particularly
well adapted to serve peak loads. Best of all,
hydroelectric plants do not consume natural fuel resources,
produce no emissions that affect air quality and discharge
no significant amounts of heat to receiving waters.
Unfortunately, the availability of hydroelectric power is
limited to locations where nature has created the
opportunity by providing both the stream and the difference
in elevation to make the energy extractable. In many
instances this means generation far away from load centers
with long transmission lines required to bring the energy to
its point of use. At the present time, hydroelectric
generation in the United States is a major factor only in
the Far West, in New York State, and in some areas of the
Appalachian Region. Total hydroelectric capacity installed
at the end of 1970 amounted to 52,300 Mw, amounting to about
15% of the total installed U. S. generating capacity. In
spite of a projected growth of about 30,000 Mw by 1990, the
share of once-through hydroelectric power is expected to
decline to about 7% by 1990. The primary reason for this
decline is that the best available sites for hydroelectric
power have already been developed and that the remaining
sites are either too far from load centers or too costly to
develop. Development of some sites may be prohibited by
legislation such as the Colorado River Basin Project Act (P.
L. 90-537) and the Wild and Scenic Rivers Act (P. L. 90-
5U2). Development of the maximum potential at other sites
may be limited by the Federal Power Act which requires that
a project to be licensed or relicensed be best adapted to a
comprehensive plan for the use of the basin's resources.
There is a possibility of importing substantial blocks of
hydroelectric power from eastern Canada, but the rapid rate
of growth in Canada has possibly been a factor in the
inability of that country and the United States to enter
into long-term contracts for the sale of power. As much as
5,000 Mw might be available on a short-term basis of about
twenty years and could be transmitted to load centers in the
Northeastern United States at economically feasible costs.
One form of hydroelectric power, pumped storage projects, is
expected to play an increasing role in electric power
generation. In a pumped storage project water is pumped, by
electricity generated by thermal units, into an elevated
27
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reservoir site during off-peak hours and electricity is then
generated by conventional hydro means during the periods of
peak usage. Pumped storage plants retain the same favorable
operating characteristics as once-through hydroelectric
plants. Their ability to accept or reject large blocks of
energy very quickly make them much more flexible than either
fossil-fueled or nuclear plants. Of course, the power
required to pump the water into the reservoir must be
generated by some other generating facility. Efficiencies
of pumping and of hydroelectric generation are such that
about 3 kwh of .energy must be generated for each 2 kwh
recovered, but on many systems the loss of 1 kwh of non-peak
fuel consumption in lieu of 2 kwh (equivalent) of capital
expenditure for additional peak generating capacity is
favorable in the light of overall system economics.
Although the earliest pumped storage project dates back to
1929, total pumped storage capacity at the end of 1970
amounted to only 3,700 Mw. FPC estimates indicate that
pumped storage capacity may reach 70,000 Mw by 1990. This
would represent a higher rate of growth than the projected
growth of the entire industry.
Although hydroelectric plants produce neither air emissions
nor thermal discharges, some proposed projects have drawn
opposition from environmental groups because of the large
volumes of water being drawn through the turbine-pump units,
with the associated potential for damage to marine life, and
the relatively large areas of uncertainty surrounding the
effect of artificial reservoirs on groundwater regimen.
Several of the pumped storage project reservoirs have
required remedial measures to reduce leakage of water from
the reservoir.
In general, hydroelectric power represents a viable
alternative to fossil-fueled or nuclear steam cycle
generation where geographic, environmental and economic
conditions are favorable. Pumped storage additionally
offers an opportunity to improve overall system performance
and reliability, particularly for rapid startup and
maintenance of reserves ready to be loaded on very short
notice.
Combustion Gas Turbines and Diesel Engines
Combustion gas turbines and diesel engines are devices for
converting the chemical energy of fuels into mechanical
energy by using the Brayton and Diesel thermal cycles as
opposed to the Rankine cycle used with steam. As with the
Rankine cycle, the second law of thermodynamics imposes
28
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upper limits as their ideal energy conversion efficiencies
based on the maximum combustion temperature and the heat
sink temperature (ambient air). The actual conversion
efficiencies of combustion gas turbines and diesel engines
are lower than those of the better steam cycle plants.
Diesel engines are used in small and isolated systems as a
principal generator of electrical energy and in larger
systems for emergency or standby service. Combustion gas
turbines are used increasingly as peaking units and in some
instances as part of combined cycle plants, where the hot
exhaust gases from a combustion gas turbine are passed
through a boiler to generate steam for a steam turbine.
Both types of units are relatively low in capital cost
($/kw), require little operating labor, are capable of
remote controlled operation, and are able to start quickly.
Since these units typically operate less than 1,000 hours
per year, fuel costs are generally not a deciding factor.
In a combustion gas turbine, fuel is injected into
compressed air in a combustion chamber. The fuel ignites,
generating heat and combustion gases, and the gas mixture
expands to drive a turbine, which is usually located on the
same axle as the compressor. Various heat recovery and
staged compression and combustion schemes are in use in
order to increase overall efficiency. Aircraft jet engines
have been used to drive turbines which in turn are connected
to electric generators. In such units, the entire jet
engine may be removed for maintenance and a spare installed
with a minimum of outage time. Combustion gas turbines
require little or no cooling water and therefore produce no
significant thermal effluent.
Diesel engines can be operated at partial or full loads, are
capable of being started in a very short time, and are
ideally suited for peaking use. Many large steam electric
plants contain diesel generators for emergency shutdown and
startup power if the plant is isolated from outside sources
of power.
In 1970, combustion gas turbine and diesel engines
represented 6% of the total United States generating
capacity. This represented 15,000 Mw of combustion gas
turbines and 4,000 Mw of diesel engines.
Alternate Processes Under Active Development
Future Nuclear Types
At the present time almost all of the nuclear powerplants in
operation in the United States are of the boiling water
29
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reactor (BWR) or pressurized water reactor (PWR) type. As
previously discussed some technical aspects of these types
of reactors limit their thermal efficiency to about 30X.
There are potential problems in the area of fuel
availability if the entire future nuclear capacity is to be
met with these types of reactors. In order to overcome
these problems, a number of other types of nuclear reactors
are in various stages of development. The objective of
developing these reactors is two-fold, to improve overall
efficiency by being able to produce steam under temperature
and pressure conditions similar to those being achieved in
fossil fuel plants, and to assure an adequate supply of
nuclear fuel at a minimum cost. Included in this group are
the high temperature gas-cooled reactor (HTGR), the seed
blanket light water breeder reactor (LWBR), the liquid metal
fast breeder reactor (LMFBR), and the gas-cooled fast
breeder reactor (GCFBR). All of these utilize a steam cycle
as the last stage before generation of electric energy.
Both the HTGR and the LMFBR have advanced sufficiently to be
considered as potentially viable alternate processes.
The HTGR is a graphite-moderated reactor which uses helium
as a primary coolant. The helium is heated to about 750
degrees centigrade (1400 degrees Fahrenheit), and then gives
up its heat to a steam cycle which operates at a maximum
temperature of about 550 degrees centigrade (1,000 degrees
Fahrenheit). As a result, the HTGR can be expected to
produce electric energy at an overall thermal efficiency of
about 40JS. One HTGR is operating in the United States at
this time, with another expected to be operating in 1974.
The thermal effects of its discharges should be similar to
those of an equivalent capacity of fossil-fueled plants.
Its chemical wastes will be provided with essentially
similar treatment systems that are presently being provided
for BWR and PWR plants.
The LMFBR will have a primary and secondary loop cooled with
sodium, and a tertiary power producing loop utilizing a
conventional steam system. Present estimates are that the
LMFBR will operate at an overall thermal efficiency of about
36*, although higher efficiencies are deemed to be
ultimately possible. The circulating water thermal
discharges of the LMFBR will initially be about halfway
between those of the best fossil-fueled plants and the
current generation of nuclear plants. Chemical wastes will
be similar to those of current nuclear plants.
30
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Coal Gasification
The technology for producing from coal a low Btu gas
suitable for combustion in a utility powerplant has long
been available. Thus far, the economics of processing the
coal at the mine and transporting gas to the point of use
have not been sufficiently favorable to lead to the
construction of large scale facilities based on this
process.
The attractiveness of the concept lies in its potential for
utilizing the most abundant of the fossil fuels, coal,
without the problems usually associated with coal, sulfur
and particulates in the stack gases and ash and slag
problems in the boiler. The drawbacks are that coal
gasification only returns 2 Jew for each 3 kw of coal
processed, large capital investments are required, and the
resulting cost per Btu is high.
The Federal Government and a number of private organizations
are supporting research and development seeking to reduce
the cost of coal gasification. There are at least eight
process alternates in various stages of development with
different by-products or energy requirements. Best current
estimates are that low Btu gas could be produced from coal
for about twice the average price currently (1973) paid by
electric utilities for natural gas. With an increasing
shortage of natural gas and fuel oil and increasing pressure
on the utilities for environmentally "clean" generation of
electric energy, coal gasification could well turn into a
significant factor in the steam electric powerplant
industry.
Combined Cycles
One possible avenue toward greater overall thermal
efficiency lies in first utilizing the hot gases generated
by combustion of the fuel in a combustion gas turbine and
then passing the exhaust of the turbine through a steam
boiler. A small number of plants based on this concept have
been constructed. One problem lies in the fact that
present-day turbine technology requires a relatively clean
gas or light oil (natural gas or refined oil) fuel. Gas
turbines are used primarily as peaking units due to the
shortage of natural gas supplies, its high cost per unit of
heating value, and the relatively high maintenance cost of
the equipment. Thermal efficiency is a primary
consideration only for base loaded units and experience
with gas turbines used as base- load units is limited.
A major advantage of the combustion gas turbine is the fact
that it requires no cooling water. Conversion of existing
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units or plants to combined cycle offers, at least in
theory, the potential for reducing the thermal effects
associated with a given production of electrical energy. In
practice, the modification of existing equipment is
generally likely to be technically difficult, if not
impossible, and of doubtful economic viability.
One form of combining cycles that holds special attraction
is the utilization of municipal refuse as a source of energy
for the production of steam and electrical power. Municipal
refuse has an average heating value of about 12,000 J/g
(5000 Btu/lb). Many municipalities have been forced to
incineration of their refuse by the growing scarcity of
available and environmentally acceptable sites for landfill
operations. In European countries, higher fuel costs and
lower wages have resulted in economics favorable to the
recovery of heat from the incineration of refuse. In the
United States, general practice has been to incinerate
refuse in refractory furnaces without attempt at heat
recovery, although several large municipal incinerators now
generate steam.
Plant No. 2913 has been converted to accept a mixture of 10
to 20X shredded refuse and 80 to 90% powdered coal. The
refuse has previously been processed to remove a portion of
the ferrous metals. The operation appears to be reasonably
successful. However, the modifications to both the refuse
disposal operations and the production of electric energy
are such that the economics must be carefully evaluated in
each individual case.
Future Generating Systems
Magnetonydrodynamics
Magnetohydrodynamic (MHD) power generation consists of
passing a hot ionized gas or liquid metal through a magnetic
field to generate direct current. The concept has been
known for many years, although specific research directed
towards the development of viable systems for generating
significant quantities of electric energy has only been in
progress for the past ten years.
The promise of MHD lies in its potential for high overall
system efficiencies, particularly if applied as a "topping"
unit in conjunction with a conventional steam turbine. The
exhaust from a MHD generator is still at a sufficiently high
temperature to be utilized in a waste heat boiler. The
combined MHD-steam cycle could result in overall system
32
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efficiencies of 50 to 60% and would require substantially
less cooling water than presently available systems.
The problems with MHD lie in the development of suitable
materials that can withstand temperatures in the 2200-2800°C
(UOOO-5000°F) range. This includes electrodes, channels,
and auxiliary components. There are also problems in the
burning of commercial fuels containing various impurities
(such as sulfur-containing coal) and problems resulting from
the fixation of nitrogen and the lack of satisfactory
methods to remove nitrous oxides from the stack gases.
Although the Soviet Union and Japan are actively engaged in
MHD research and development, including the construction of
a commercial size MHD plant in Moscow, experimental
generators in the United States have produced only moderate
outputs for short periods of time or small outputs for
periods of up to hundreds of hours. In spite of substantial
interest in and support of MHD research by the Office of
Coal Research of the U. S. Department of the Interior, and
the Edison Electric Institute, it does not seem likely that
MHD will reach commercial operations in the United States
within the next several years.
Electrogasdynamics
Electrogasdynamics (EGD) produces power by passing an
electrically charged gas through an electric field. The
process converts the kinetic energy of the moving gas to
high voltage direct current electricity.
The promise of EGD is similar to the promise of MHD. Units
would be smaller, with a minimum of moving parts, would not
be limited by thermal cycle efficiencies and would not
require cooling water. The system could also be adapted to
any source of fuel or energy including coal, gas, oil or
nuclear reactors.
Unfortunately, the problems of developing commercially
practical units are also similar to those associated with
MHD. A pilot plant was constructed in the United States in
1966, but tests on the pilot model uncovered major technical
problems and resulted in a termination of the project. In
view of these difficulties and the relatively small current
effort toward further work on this process, it seems
unlikely that EGD will have an impact on the national energy
picture within the next twenty years.
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Fuel Cells
Fuel cells are electrochemical devices, similar to storage
batteries, in which the chemical energy of a fuel such as
hydrogen is converted continuously into low voltage electric
current. Fuel cells presently under development produce
less that 2 volts per cell. In order to create a usable
potential, many cells have to be arranged in series and many
of these series arrangements must be paralleled in order to
produce a significant current. Converters would be required
to convert the direct current produced by the cells into
alternating current.
The main attractiveness of the fuel cell lies in its modular
capability and the possibility of tailoring power output to
the immediate needs. Fuel can be stored and used when
needed. Losses in transporting fuel are also less that the
corresponding losses incurred in transmitting electricity.
The efficiency of the direct conversion from chemical to
electric energy is high and the heat losses are minimal.
Main problem areas at the present time lie in developing low
cost materials of construction and low cost fuels. The most
effective electrodes presently available are platinum
electrodes, which can be used in military and space applica-
tions, but are not economically competitive for commercial
use. Presently used fuels include hydrogen, hydrazine and
methyl alcohol. The use of relatively low cost fuels such
as coal, natural gas or petroleum is not feasible at this
time. Unfortunately, the manufacture of the usable fuels
also involves the utilization of significant quantities of
electric and other energy, so that the overall benefits are
que stionable.
A strong effort is being made in the United States to
develop the fuel cell for residential and commercial
service. A number of prototype units have been installed
'and are operating successfully. However the fuel cell is
not expected to replace a significant portion of the central
plant power generation within the next ten years.
Geothermal Generation
Geothermal generation utilizes natural steam or hot water
trapped in the earth1s crust to produce electrical energy.
At the present time, geothermal generation is limited to
areas of geothermal activity such as fumaroles, geysers and
hot springs, if steam is obtained directly from the earth,
it can be used to drive a turbine. Hot water must first be
flashed to steam or used to evaporate some other type of
working fluid.
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Advantages of this type of power generation are that the
source of energy is essentially free, although the costs of
drilling are not insignificant. Disadvantages are that the
steam must first be cleaned and that, at the current state
of the art, this scheme is practical only where there is
geothermal activity near the surface of the earth. With the
advances being made in deep drilling for locating oil, it
would seem possible to tap energy sources almost anywhere on
earth. However, economic considerations appear to lead to
the conclusion that geothermal generation will be feasible
only under specially favorable geologic conditions.
Industry Regulation
At the Federal level, .numerous agencies have regulatory
authority or direct responsibility for certain aspects of
the industry. These include the Atomic Energy Commission
(AEC) , Department of Agriculture, Department of the
Interior, Federal Power Commission, the Department of the
Treasury, Securities and Exchange Commission, Tennessee
Valley Authority, Environmental Protection Agency, U.S. Army
Corps of Engineers and the Department of Labor.
The Federal Power Commission (FPC) is authorized to provide
certain types of economic regulation over certain investor-
owned electric utilities and administrative supervision over
certain publicly-owned systems. It licenses all non-Federal
hydroelectric projects, regulates all interstate rates and
services, and requires systems to keep a specific system of
accounts and submit reports on their activities. The annual
report FPC Form 67; Steam Electric Plant Air and Water
Quality Control Data, with responses from 654 plants, and
the Summary Report for the year ended December 31, 1969,
formed one of the major sources of data for this report.
The 654 plants reporting represented steam electric plants
of 25 Mw or greater capacity which were part of a power
supply system of 150 Mw or greater and plants of 25 Mw or
greater capacity operating in one of the Air Quality Control
Regions.
The Atomic Energy Commission (AEC) has the responsibility
for licensing construction and operation of nuclear plants
(stations). A utility proposing to build a nuclear plant
must first apply for a construction permit. With this
application the utility must file a Preliminary Safety
Analysis Report and an Environmental Impact Statement.
After the major design details have been completed, and
while construction is under way, the utility has to submit a
Final Safety Analysis Report which then becomes the basis
for an operating license. In conformance with a recent
35
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decision by the United States Court of Appeals, AEC
licensing procedures now include consideration of all
environmental factors, non-nuclear as well as nuclear, as
required by the National Environmental Policy Act (NEPA) of
1969.
At the state level, all states except Minnesota, Nebraska,
Texas and South Dakota have regulatory commissions with
authority over investor owned utilities. In less than half
the states the commissions also have the power to regulate
publicly-owned utilities. The degrees of authority vary,
but generally include territorial rights, quality of
service, safety, and rate-setting. The rate-setting power
generally requires a utility to demonstrate to the
regulatory authority that a proposed rate structure is
necessary in order to permit the utility to earn a return on
its equity investment, also known as a rate base. The rate
base may be determined from historical cost or fair market
value or some other valuation formula, but in most cases,
commissions in effect assure the utility of a minimum return
on capital invested in its system.
Construction Schedules
Construction schedules for nuclear plants and fossil-fueled
plants are significantly different in the total time span
required from the concept study stage to commercial
operation. For example, the condensed construction schedule
for a 200 Mw oil-fired unit shown in Figure III-2
encompasses a span of about three years from initiation of
the concept study to commercial operation. In contrast.
Figure III-3 shows excerpts from a typical LWR nuclear plant
project schedule. The time span shown from the initiation
of the preliminary design until commercial operation is
about 8-9 years.
Reliability, Reserve Generating Capacity,
and Scheduling of Outages
According to the Federal Power Commission and the National
Electrical Reliability Council (References 292, 392 and
396) , in order to maintain the uninterrupted service that
customers expect and rely upon, all power systems must
maintain or have access to more generating capacity than the
expected annual peak load. This spare capacity, known as
required reserves, changes from time to time and varies
widely from system to system, depending on the system size,
the sizes and types of generating units in the system, the
forced outage rates for these units, maintenance
requirements, and system load characteristics.
36
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Figure III-2
CONDENSED CONSTRUCTION SCHEDULE, 200 MW OIL-FIRED UNIT* (Reference No. 187)
Years
Months
Concept Study Begun
Grading and Excavation
Piling
Substructure
Structural Steel
Superstructure
Gallery Work
Steam Generator
Steam Turbine-Generator
Condensing Equipment '
Cooling Tower**
Equipment Erection
Flues, Ducts and Stack
Misc. Field Erection
Piping System
Thermal Insulation
Electrical
1972
JFMAMJJASONI
-
1973
JFMAMJJASOND
Initi
___ Commerci
.
1974
JFMAMJJASQND
Boil out — ^
al Steam
M
1975
JFMAMJ
»
fc
* Note: Base-load type unit with provisions for cycling duty. Major items of
equipment include one main transformer, one generator, one steam turbine,
one steam condenser, two condensate pumps, five closed feedwater heaters,
one deaerating heater, two boiler feedwater pumps, one steam generator,
one combustion burner group, and two combustion air fans and compressors.
** Note: Cooling tower is mechanical draft.
-------
GO
00
Figure III-3
TYPICAL LWR NUCLEAR PLANT PROJECT SCHEDULE (HIGHLIGHTS ONLY)*
Task
\Year
8
10
Site Selection and Acquisition
Environmental Studies
Prepare NSSS and Fuel Specifications
Vendor Bid Preparation
Bid Evaluation and Negotiation
Contract Awards
Preliminary Design
Detailed Design
Site Clearance and Excavation
Foundations and Buildings
Containment Erection
NSSS Equipment Installation
Turbine-Generator Erection
NSSS and T-G Auxiliary Equipment
Fuel Loading
Testing
Commercial Operation
* Note: Excerpts from Reference No. 186,
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Methods of Determining Reserve Requirements
The planning techniques used by electric utility systems to
establish required reserve levels can be divided into two
broad categories:
1. Non-probabilistic methods
2. Probabilistic methods
Generating capacity requirements based on a non-
probabilistic method have generally been determined by
establishing minimum reserve requirements over the annual
peak load period based on:
1. A fixed percentage of peak load, or
2. A fixed multiple of the system's largest
generating unit, as for example the largest unit
plus an average-sized unit.
In the use of these non-probabilistic methods, judgment
plays a predominant role. Their only advantage is
simplicity, since reserve requirements can easily be
calculated once an annual peak load has been projected and
the capacity of the largest unit is known. This simplicity
of application, however, is offset by the inherent inability
of such methods to measure, in a quantitative manner, the
system reliability associated with such ' reserve
determinations. In this approach, little consideration is
given to the daily, monthly, and seasonal load patterns, or
to the characteristics of generating equipment peculiar to
the individual system, such as unit availabilities and the
mix of unit types and sizes.
Probabilistic methods, although complex, provide an
analytical means for evaluating the relative risk associated
with supplying system load requirements by various means.
This is generally accomplished by interrelating the load and
capacity models developed for the particular system and time
period under study. The load model usually consists of a
series cf load levels representing the full range of daily
or monthly peak loads anticipated throughout the given
p'eriod. The model is usually developed from historical
records of daily peaks, with adjustments to reflect expected
changes in load characteristics of future loads. It may
also inclu'de provision for the probability of load changes
because of deviations from normal conditions of weather or
expected economic activity.
The capacity models used in probabilistic method usually
involve calculating the likelihood of availability of
various levels of system generating capacity, based on
39
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assumed forced outage rates for the individual units. The
study period is usually divided into uniform maintenance
intervals so that units that would not be available for
service due to scheduled maintenance would be excluded from
the calculations for that particular interval. In effect,
this results in a number of capacity models. The
interrelation of such capacity models with load models forms
the basis for evaluating the risk of capacity not being able
to satisfy the load requirements. Sample calculations and
more detailed explanations are given in some of the Regional
Advisory Committee reports published in Parts II and III of
the 1970 National Power Survey.
To illustrate the relationship between reliability and
reserve generating capacity consider the two curves in
Figure III-4 which are based on studies made by two groups
of systems. Assuming an equivalent level of reliability,
e.g., one occasion in ten years when, on a probability
basis, insufficent generation will be available to cover
load, the New England systems require a reserve of about 21%
compared with 12% for the MARCA systems. This reflects the
differences in type, number, and size of generating units as
well as the diversity and composition of load in each
instance - all factors, which affect generation reserves.
Furthermore, the percent reserve requirements can be
expected to change with time, reflecting varying conditions.
Reserves for Scheduled Outages
Generating units are taken out of service at fairly regular
intervals for inspection, overhaul, and repair as required.
This practice accounts for the relatively high reliability
of generating capacity. When conditions are such on an
electric system that generating capacity needed to supply
load must be taken out of service, generating capacity from
reserves must be provided to take its place. The amount of
reserves needed at time of peak load depends on the duration
of maintenance outages and whether the work can be scheduled
during offpeak months.
There are variations from year to year in the amount of
scheduled maintenance that a generating unit requires, and
some types of inspection and repair are needed only at two
or three year intervals. There are also variations in
intervals between scheduled outages and in downtime for
maintenance because of such factors as age, size and type of
unit. On the average, baseload boiler-turbine-generator
units require about one month of scheduled maintenance per
year.
40
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ONE OCCASION
IN 10 YEARS
10 15 20
PERCENT RESERVE
Figure 111-4
Regional Reliability Versus
Percent Reserve
41
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In general, the relatively large generating units will be
operated at higher use factors and will require more time
for maintenance than the smaller units. For the purpose of
the Federal Power Commission analysis of 1980 reserve for
scheduled outages, the large size thermal units, 600
megawatt or over, were assumed to require 600 hours of
scheduled maintenance annually while units of 200 megawatt
to 599 megawatt size were assumed to require 500 hours, and
units under 200 megawatt, 400 hours.
In estimating the amount of reserve required for scheduled
maintenance, it is necessary to determine whether there is
enough time and spare capacity to take all units out of
service for their scheduled overhaul during off-peak months.
In actual practice, such a determination would involve
extensive calculation if there were many units in the system
and the scheduling were tight. Various combinations would
be explored to determine the optimum schedule in terms of
utilizing the spare capacity available in generating units
of different sizes for each interval.3«* Reference 395 gives
an example of a model for the optimization of outage costs.
At the same time the maintenance schedule should provide for
reasonable use of the crews and not result in excessive
loading on parts of the transmission system. A further
factor is that the generating capacity of a system may
change month by month because of retirements, additions,
cooling water limitations, and seasonal changes in the
output capability of installed hydro-electric units.
Coordination for Reliability
Most of the text of this discussion is exerpted from
Reference 292, from the Federal Power Commission.
Nearly every major electric utility system in the United
States is connected with neighboring systems to form large
interconnected networks. Financial benefits are thereby
often realized from staggered construction of large
generating units, short-term capacity transactions, and
interchanges of economy energy. Reduction of installed
reserve capacity is made possible by mutual emergency
assistance arrangements and associated coordinated
transmission planning. Bulk power supply reliability is
enhanced by interconnection agreements covering spinning
reserves, reactive kilovolt-ampere requirements, emergency
service, coordination of day-to-day operations, and
coordination of maintenance. The satisfactory performance
of a power supply network requires close cooperation among
component systems for accurate control of frequency, sharing
42
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of load regulating responsibilities and maintenance of power
system stability.
There are thousands of arrangements among systems from all
segments of the industry providing for various degrees and
methods of electrical coordination. These variations
reflect differences in load density, characteristics of
generating sources, geography, and climate. They are also a
product of managerial views with respect to planning,
marketing, competition, and retention of prerogatives.
Because of these differences, no single definition of
coordination has been established by the electric utility
industry. As used in this discussion "coordination" is
joint planning and operation of bulk power facilities by two
or more electric systems for improved reliability and
increased efficiency which would not be attainable if each
system acted independently. "Full coordination" involves
coordination of all systems within an area, to the extent
technologically and economically feasible to permit the
serving of their combined loads with a minimum of resources
and to exploit opportunities for coordination with adjacent
areas.
Managements of various electric systems have developed a
wide variety of formal and informal coordinating
organizations or power pools. Some merely provide members
with a mechanism for the exchange of information; others
deal primarily with day-to-day interconnected operations
under normal and abnormal system conditions; many engage in
coordinated planning and operation for increased economies;
and still others are dedicated to improving reliability over
broad geographic areas encompassing otherwise unaffiliated
electric systems. All of these organizations contribute in
varying degrees to the reliability and economy of electric
power supply.
The term "formal power pool" as used here means two or more
electric systems which coordinate the planning and/or
operation of their bulk power facilities for the purpose of
achieving greater economy and reliability in accordance with
a contractual agreement that establishes each member1s
responsibilities. Individual members usually are able to
obtain the economies and other advantages available to much
larger systems while retaining their separate corporate
identities.
Table A-2-1 of Appendix 2 lists the individual members of
each formal power pool in the contiguous United States. The
areas served by formal power pools cover most of the United
States as shown in Figure A-2-1 of Appendix 2.
43
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A power pool must have sufficient generating capacity to
meet the combined pool load plus reserve to cover equipment
outages, frequency, regulation, load swings, errors in
forecasting loads, and slippage in planning and construction
schedules. The various pools make specific provision for
sharing among the pool participants the burden of providing
this reserve margin. There are, in general, two different
methods of accomplishing this objective. Under one, each
member is required to maintain a specified minimum capacity
reserve, usually stated in percent of peak load. Under the
other, existing installed generating capacity is shared on
an equalized reserve basis. That is, rather than each
member being responsible for maintaining some minimum amount
of reserve, the reserve capacity of the pool is shared
proportionally among the members. Reserve responsibility is
satisfied by capacity transactions so that members with
excess capacity resources are compensated by members having
capacity deficiencies.
There are at least 13 informal organizations of utilities in
the contiguous United States which are structured to
emphasize some limited aspects of inter-system coordination.
These coordinating groups are informal in the sense that no
member is contractually obligated to undertake any specific
course of action or to provide any kind of service to other
members. The groups are usually concerned primarily either
with planning or operation, although some are active in
both. The geographic areas covered by these groups are
shown in Figure A-2-2 of Appendix 2. Table A-2-2 of
Appendix 2 lists each group, its acronym, and the individual
members. Twenty-four individual systems, as shown in Table
A-2-3 of Appendix'2, are members of two or more informal
coordinating groups.
The National Electric Reliability Council (NERC) was formed
in 1968 for the purpose of further augmenting the
reliability and adequacy of bulk power supply by the
electric systems of North America. It consists of nine
regional reliability councils whose membership comprises
essentially all of the power systems in the United States
and the Canadian systems in the provinces of Ontario,
British Columbia, Manitoba, and New Brunswick.
Each council has established a mechanism to provide for
direct or indirect participation by the smaller electric
utilities within its boundaries. The approximate geographic
boundaries of the councils are shown on Figure A-2-3 of
Appendix 2, and the individual members of each council are
shown in Table A-2-4 of Appendix 2.
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None of the reliability councils has authority to make
decisions involving the planning or installation of new bulk
power facilities, but most have a formal review and approval
role. Seven reliability councils have adopted criteria for
testing the design and operation of existing and proposed
bulk power facilities and the other two have established
committees to formulate such criteria. Several councils
have adopted procedures for reporting by members of uniform
compatible data on load estimates, scheduled maintenance,
power exchanges, and installed reserve margins. A few have
developed guides and regionally coordinated programs
covering daily operating reserve margins, emergencies on the
interconnected system, uniform rating of generating
equipment, and principles of relaying. Some regional
councils have established environmental committees to
encourage more effective consideration of environmental
matters in the siting, construction, and operation of major
facilities.
The Federal Power Commission's Statement of Policy on
Reliability and Adequacy of Electric Service, Order No. 383-
2 (Docket No. R-362), issued April 10, 1970, is intended to
implement fully the voluntary aspects of Section 202(a) of
the Federal Power Act, and to encourage utilities throughout
the Nation to continue to strengthen the reliability
councils and develop more effective bulk power supply
programs. The Commission Order requested participation by
the staffs of the Commission and appropriate State
commissions as non-voting participants in the principal
meetings of NERC and the regional councils, and requested
regional councils to report the projection of loads and
coordinated bulk power supply programs on a ten-year basis.
It also requested reports on the status of consultations
with affected groups and appropriate local. State, and
Federal authorities regarding the environmental impact of
proposed major facilities, and information on load flow
studies, network stability analyses, principal communication
and control systems, and coordinated regional programs
pertaining to provisions for emergencies, scheduled
maintenance outages of major facilities, and other matters
which affect the overall reliability of the interconnected
network. Initial reports were filed as of September 1,
1970. Future reports to be filed on April 1 of each year
provide opportunity for updating the power supply programs
in the ten-year framework to reflect revisions in load
estimates, new developments and resources, and the
resolution of environmental issues.
In April 1962, representatives of interconnected systems
throughout the United States and eastern Canada met at
45
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Omaha, Nebraska, and laid the groundwork for an
international organization to coordinate the operation of a
looming coast-to-coast interconnected network. This led to
formation of the North American Power Systems
Interconnection Committee (NAPSIC) which held its first
meeting in January, 1963. NAPSIC is a voluntary
organization of operating personnel representing ten
interconnected Operating Areas. The scope of the
organization has expanded so that by 1971 it included
consideration of the following:
1. Operating reliability criteria,
2. Frequency regulation,
3. Time control,
t. Tie-line frequency bias,
5. Operating reserves,
6. Time error correction procedures,
7. Emergency operating procedures
(a) Load shedding and restoration
(b) Tie separation and restoration
(c) Generating unit security,
8. Scheduled maintenance outages of major facilities
9. Interchange scheduling procedures,
10. Procedures, for handling inadvertent interchange,
11. Any other operating matters that required
coordination to effect reliable inter-
connected operation.
NAPSIC's contribution to reliable system performance is
enhanced by its close liaison with planning entities,
regional reliability councils, and the National Electric
Reliability Council. Much of the reliability council work
overlaps activities which are the concern of the Operating
Areas within NAPSIC. Close working relationships which have
been established between these different organizational
units provide the opportunity for very effective
coordination between planning and operating functions.
Coordinating Techniques
Over the years electric utilities have developed a wide
variety of coordinating techniques to achieve increased
reliability and improved economies. Some of the major
coordinating techniques are described below.
Staggered construction is a technique which involves
construction of excess capacity by one utility for the use
of one or more other utilities with the supplier-buyer
arrangement being reversed or modified with each succedding
46
-------
unit. Several variations of this practice are widely used.
Sometimes adjacent systems informally coordinate their
capacity additions over a period of several years so that
the total installed capacity reserve approximates the amount
required by the entire geographic area. Another form of
staggered construction which has gained widespread
acceptance in recent years is the unit-sale concept. This
entails arrangements whereby a system installs a larger unit
than it otherwise normally would, and sells a specified
amount of excess capacity from that unit to one or more
neighboring systems. The purchaser's entitlement is limited
to the availablity of capacity from the specific unit. In
the event of an outage of such unit, the buyer is not
entitled to any portion of the supplier's other capacity
resources.
Seasonal capacity exchanges can usually be made when the
annual peak loads of two utilities, areas, or regions occur
in different seasons of the year. However, individual
systems within the same power pool having annual peak
demands which occur in different months do not normally
participate in seasonal capacity exchanges because, in a
pool, savings from intrapool diversity are automatically
achieved by the decreased total installed reserve
requirements resulting from the pool operation.
Small Systems
For the purpose of providing a statistical frame of
reference, small electric systems were defined in the 1964
National Power Survey as those having annual peak-hour
demands of less than 25 megawatts. By this definition there
were 3,190 small systems in 1962, of which 899 generated all
or part of their requirements and 2,291 purchased their
entire requirements. By 1968 the total number of small
systems decreased to 2,812, a reduction of 348, principally
as the result of acquisitions and mergers. More than 800 of
the remaining small systems owned generating facilities, and
243 were electrically isolated from major transmission
networks.
The total cost of generation at the bus bar for the sizes of
plants usually installed by small systems is relatively high
because such plants cost more per kilowatt to build, burn
more fuel per kilowatt-hour, and cost more per kilowatt-hour
to operate. The ability to take full advantage of modern
generation and transmission technology is often limited to
the larger systems. Only 31 systems with generating
capacity of less than 500 megawatts are members of formal
power pools.
47
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Since the cost gap between small scale and large scale
generation and transmission has been progressively widened
by technological improvement, most of the smaller electric
systems which generate the bulk of their electric
requirements are at a relatively greater economic
disadvantage than they were during the 1950's and the early
IseO's. Benefits from coordinated planning are being
realized by some of these smaller system through joint
ownership, or entitlements in large, more efficient
generating units sized to meet area needs, and through
associate or affiliate membership in regional councils.
Systems which serve their growing needs by power purchases
receive reliability and economic benefits when their power
suppliers participate in area-wide and regional
coordination.
Many small systems buy all of their power requirements at
wholesale, although they have the option to plan, install,
and operate bulk power facilities. A heavy concentration of
these distribution systems within a specific geographic area
increases the chances of economic feasibility for them
jointly to plan and construct their own bulk power system,
but such endeavors may result in duplication of faciities
unless suitable wheeling arrangements can be worked out with
neighboring, and generally competing, systems.
Small systems having generating facilities, but with
sufficient capacity to meet their total electric
requirements, include: (1) those having only a small amount
of generation (often, hydro) which is supplemented with
purchases from a neighboring supplier (2) systems which plan
gradually to phase themselves"out of the generating business
but still have one or more units in serviceable condition;
and (3) systems that use small units for peak shaving to
reduce average purchased power costs. There is a wide
variety of bilateral arrangements covering such situations
This type of system will continue to be a part of the
overall supply, primarily because it provides an
intermediate step in moving to or from full within-system
generation.
Some small systems have sufficient generation to meet their
own requirements and operate in complete electric isolation,
or with interconnection facilities normally open. Others
are connected to and operate in parallel with major power
networks, under a wide variety of agreements. In recent
years, some small systems have been able to negotiate lower
reserve requirements through coordination of their
operations with neighboring systems, and a few have gained
access to large scale generation.
48
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At the beginning of 1968, 243 systems were electrically
isolated from power supply networks. Approximately 82 1/2
percent of the total generating capacity of the isolated
systems was located in eight states (Florida, Illinois,
Kansas, Louisiana, Massachusetts, Mississippi, Ohio and
Texas) .
Isolated systems typically experience relatively high power
supply costs and inferior bulk power reliability. About 75
percent of the isolated systems in 1966 carried reserve
capacity greater than 50 percent of their annual system peak
demands. On such systems the forced outage of a generating
unit may represent loss of such a large portion of on-line
capacity that partial or total power failure may result
before other units can respond to meet the increased load
placed upon them. Also, an isolated system is vulnerable to
extended service interruption if fire, natural disaster, or
other catastrophe destroys one or more of its major
generating plants.
49
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SECTION IV
INDUSTRY CATEGORIZATION
The purpose of this section is to establish a framework for
the orderly development of effluent limitations guidelines
and standards in consideration of waste water
characteristics, pollutant parameters, control and treatment
technology, cost, energy, non-water quality aspects, and
other factors as presented in subsequent sections. The
rationale supporting the recommended industry
subcategorization and effluent limitations guidelines and
standards is presented in Sections IX, X, and XI of this
document.
Steam electric powerplants are characterized by many diverse
aspects, and at the same time by many similarities.
Categorization of the industry into discrete segments for
the purpose of establishing effluent limitations guidelines
requires consideration of the various factors causing both
this diversity and similarity. Specific factors which
require detailed analysis in order to categorize the
industry include the processes employed, raw materials
utilized, the number and size of generating facilities,
their age, site characteristics and mode of operation^
Process Considerations
There are five major unit processes involved in the
generation of electric power - the storage and handling of.
fuel related materials both before and after usage, the
production of high-pressure steam, the expansion of the
steam in a turbine which drives the generator, the
condensation of the steam leaving the turbine and its return
to the boiler, and the generation of electric energy from
the rotating mechanical energy. Figure IV-1 shows a
schematic flow diagram of a typical steam electric
powerplant. Power cycle diagrams for typical fossil fuel
units and nuclear units are shown in Figures IV-2, and IV-3,
respectively.
Fuel Storage and Handling
All fuels must be delivered to the plant site, stored until
•usage, and the spent fuel materials stored on the premises
or removed. Fossil-fueled plants require off-loading
facilities and fuel storage in quantities based on the size
of the plant and the limited reliability of delivery.
Fossil-fuels are transported to the furnace where combustion
51
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cn
tv>
VENT
X
BOILER
SLOWDOWN
DRUM
FIGURE IV-I
SCHEMATIC FLOW DIAGRAM
BOILER FEED
PUMP
CONDENSATE
PUMP
TYPICAL STEAM ELECTRIC GENERATING PLANT
-------
Table II-l
SUMMARY OF EFFLUENT LIMITATIONS GUIDELINES AND STANDARDS FOR POLLUTANTS OTHER THAN HEAT
SOURCE
Nonrecirculating cooling water
Cooling tower blowdown
Ash transport
Bottom ash transport
Fly ash transport
Low-volume wastes
Boiler blowdown
Metal equipment cleaning wastes
Other sf except sanitary wastes
and radwastes
Rainfall runoff from materials stor-
age piles and construction activities
Rainfall runoff from other sources ***
Sanitary wastes and radwastes
All sources
POLLUTANT PARAMETER
Free available chlorine
Total residual chlorine
Free available chlorine
Total residual chlorine
Chromium, total
Zinc, total
Total phosphorus ( as P )
Corrosion inhibiting materials
other than Cr, Zn, and P
All corrosion inhibiting materials
Total suspended solids
Oil and grease
Total suspended solids
Oil and grease
Total suspended solids
Oil and grease
Total suspended solids
Oil and grease
Copper, total
Iron, total
Total suspended solids
Oil and grease
Copper, total
iron, total
Oil and grease
Total suspended solids
All pollutant parameters
All pollutant parameters
Polychlorinated biphenyls
pH value ****
EF
BPCTCA (1977)
--"
"^.
"I
>- No limitation
\
J
30 (100 max)
15 ( 20 max)
-
-
-
-
^
LUEOT LIMITATIONS*
BATEA (1983)
0.2 (0.5 max) **
**
0.2 (0.5 max) **
**
0.2 (0.2 max)
1.0 (1.0 max)
5.0 (5.0 max)
Case-by-case
-
-
-
2.4 (8.0 max)
1.2 (1.6 max)
30 (100 max)
15 ( 20 max)
30 (100 max)
15 ( 20 max)
1.0 '(1.0 max)
1.0 (1.0 max)
30 (100 max)
15 ( 20 max)
1.0 (1.0 max)
1.0 (1.0 max)
30 ( 100 max )
15 ( 20 max)
Not to exceed 50mg/l
No limitation
No limitation
No discharge
Within the range 6.0-9.0
_ at all times
New Sources
_
_
_
_
No discharge
-
-
1.5 (5.0 max)
0.75(1.0 max)
No discharge
No discharge
* Note: Numbers are concentrations, mg/1, except for pH values. Effluent limitations, except for pH and rainfall runoff, are quantities of pollutants
to be determined by multiplying the concentration indicated times the flow of water from the corresponding source. Effluent limitations are
averages of daily values for 30 consecutive days ( maximum values for any one day are determined from the numbers in parentheses), except for
pH and rainfall runoff. In the event that waste streams from various sources are combined for treatment or discharge, the quantity of each
pollutant attributable to each waste water source shall not exceed the limitation for that source. No limitations are prescribed for
sources/pollutants not specified in this table.
** Note: Neither free available chlorine nor total residual chlorine may be discharged from any unit for more than two hours ( aggregate ) in any one
day and not more than one unit in any plant may discharge free available chlorine or total residual chlorine at any one time. Exceptions to be
made, on a case—by—case basis, if discharger demonstrates that limitations must be exceeded in order for the cooling system to operate
efficiently.
*** Note: ...and from facilities designed, constructed, and operated to treat the volume of material storage runoff and runoff from construction activit-
ies that is associated with a 10 year, 24 hour rainfall event.
**** Note: From all sources except nonrecirculating cooling water, rainfall runoff from sources other than materials storage piles and construction activ-
ities ***, sanitary wastes and radwastes.
-------
CT1
CO
Stack Loss Air In
Net Power Loss
Net Power
Net
Generator
& Mechanical
Loss
fit—
High Pressure Bleed Heaters
\
Low Pressure Bleed Heaters
Boiler Feed Pump
Figure IV—2 Power cycle diagram, fossil fuel — single reheat, 8 stage regenerative feed heating — 3515 psia, 1000F/1000F steam.
278
-------
en
Auxiliary
Loss
Figure
Steam
Generator
Feed Pump
Turbine
Low Pressure Bleed Healers
& Internal Moisture Separator Receivers
Power cycle diagram, nuclear fuel — reheat by bleed and high pressure steam, moisture separation, and 6-stage regenera-
te feed heating — 900 psia, 566F/503F steam. 278
-------
takes place. The combustion of fossil fuels results in
gaseous products of combustion and non-gaseous non-
combustible residues called ash. A portion of the ash is
carried along with the hot gases. This portion is referred
to as fly ash. The remainder of the ash settles to the
bottom of the furnace in the combustion zone and is called
bottom ash. The amount and characteristics of each type of
ash is dependent on the fuel and the type of boiler
employed. Coal produces a relatively large amount of bottom
ash and fly ash. Oil produces little bottom ash but
substantial fly ash. Gas produces little ash of any type.
Coal-fired steam generators can be categorized as wet or dry
bottom according to ash characteristics. Gas-fired and oil-
fired steam generators are generally run with dry bottoms.
In one type of wet bottom steam generator the coal is burned
in such a manner as to form a molten slag which is collected
in the bottom and is tapped off similar to the tapping of a
blast furnace. In dry bottom steam generators, where ash is
removed hydraulically, it is customary to pump the ash
slurry to a pond or settling tank, where the water and ash
are separated.
Many modern powerplants remove fly ash from the gaseous
products of combustion by means of electrostatic
precipitators, although scrubbers may be required on plants
burning fossil fuels containing more than a minimal amount
of sulfur. The removal of fly ash collected in an
electrostatic precipitator depends on the method of ultimate
disposal. if the fly ash is to be used in the manufacture
of cement or bricks or otherwise used commercially, it is
generally collected dry and handled with an air conveyor.
If it is to be disposed of in an ash pond or settling basin,
it is sluiced out hydraulically.
Many of the operations involving fossil-fuels are potential
sources of water pollutants. The storage and handling of
nuclear fuels in comparison is not a continuous operation,
requires little space, is highly sophisticated from the
standpoint of engineering precision and attention to
details, and is not considered to be a potential source of
nonradiation water pollutants.
Steam Production
The production of high-pressure steam from water involves
the combustion of fuel with air and the transfer of the heat
of combustion from the hot gases produced by the combustion
to the water and steam by radiation and convection. In
order to obtain the highest thermal efficiency, as much of
55
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the heat of combustion as possible must be transferred from
the gases to the steam and the gases discharged at the
lowest possible temperature. This requires the transfer to
be accomplished in a series of steps, each designed for
optimum efficiency of the overall process. Not every boiler
provides each of the steps outlined in this section, but
most of the boilers supplying steam to larger and newer
generating units (over 200 Mw and built in the last twenty
years) provide these steps as a minimum. A typical boiler
for a coal-fired furnace is shown in Figure IV-U.
Feedwater is introduced into the boiler by the boiler feed
pump and first enters a series of tubes (regenerative
feedwater heater) near the point where the gases exit from
the boiler. There it is heated to near the boiling point.
The water then flows to one or more drums connected by a
number of tubes. The tubes are arranged in vertical rows
along the walls of the combustion zone of the boiler. In
this zone, the water in the tubes is vaporized to saturated
steam primarily by the radiant heat of combustion. The
saturated steam is then further heated to higher
temperatures primarily by convection of the hot gases in the
superheater section of the boiler. In some boilers, the
steam is reheated after passage through the initial sections
of the turbine. Finally, the flue gases are passed through
a heat exchanger (air heater) in order to transfer heat at a
low temperature to the air being blown into the boiler.
As far as steam production is concerned, the efficiencies
possible from the conversion of the chemical energy of the
fuel to electric energy depend on the maximum steam
temperatures and pressures and on the extent of the
utilization of regeneration feedwater heaters, reheat and
air heating. For a simple cycle using saturated steam with
a maximum pressure of 6.3 MN/sq m (900 psi) expanded in the
turbine to atmospheric pressure and using exhaust steam to
heat the feedwater, the total cycle efficiency would be
about 20%. If the saturated steam is superheated to 530°C
(1,000°F), the efficiency is increased by an increment of 5
to 6%. The addition of a high-vacuum (863 kg/sq m (2-1/2
in. of Hg abs)) condenser and the addition of feedwater
heating will increase possible efficiencies by an increment
of 12 - 13% to about 38%. By increasing the maximum
pressure still further and reheating the steam, the
efficiency can be increased to about U5%. These are turbine
cycle efficiencies and do not reflect various losses in the
boiler and auxiliary power requirements. Indications are
that these efficiencies represent the limit obtainable from
the processes presently in use. Higher efficiencies which
require higher steam pressures and temperatures would
56
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ZJ
Coal
Tripper
-=¥R!J
•••^IM—,
•i" .•• _ .
Cyclone " ;!•
"223J~furnac.es ii
Gas
Outlet
Universal-Pressure boiler with opposed Cyclone Furnaces and bin system for coal preparation and feeding.
Figure IV-4 Typical Boiler for a Coal-Fired Furnace
57
-------
present material problems that do not seem to be near
solution. The alternate of lower terminal temperatures is
not possible since the waste heat must be rejected to the
environment under ambient conditions, unless economical
techniques could be developed to reject waste heat to the
low temperature of outer space.
In the effort to improve the efficiency of the steam cycle,
designers have attempted to resort to higher temperatures
and pressures. Maximum turbine operating pressures
increased from about 1,000 psi in the early 1930's to 5,000
psi in the early 1960's. Since then, turbine design
pressures for new units have receded slightly to a maximum
of 3500 psi. Similarly, maximum operating temperatures
increased from 800°F to 1200°F for a brief period and then
receded to a maximum of 1050°F, as designers looked to more
sophisticated reheat cycles and turbine designs to optimize
plant performance.
Nuclear generators presently in operation fall into two
classes, pressurized water reactors (PWR) and boiling water
reactors (BWR). In a PWR, water under a pressure of about
1U MN/sq m (2,000 psig) is heated as it circulates past the
nuclear fuel rods in a closed loop. This hot water then
exchanges heat with a secondary water system which is
allowed to vaporize to steam. In the BWR, water heated in
the reactor core under a pressure of about 7 MN/sq m (1,000
psig) is allowed to vaporize to steam directly. Neither of
these processes produce steam with significant amounts of
superheat and this limits their thermal cycle efficiencies
to about 30%.
The size or rating of boilers is in terms of thousands of
pounds of steam supplied per hour. According to the FPC the
increase in boiler capacity was rather slow until 1955, when
the maximum capacity of boilers installed began to rise from
a level of about 1,500 thousand pounds per hour to the
present level of about 10,000 thousand pounds per hour.
Prior to 1950, individual boilers were kept small, in large
part because boiler outages were rather numerous, so that it
was common design practice to provide multiple boilers and
steam header systems to supply a turbine-generator. Some
plants report to the FPC that the steam headers are
connected to multiple turbine-generators. Advances in metal
technology since 1950, with associated lower costs of larger
units, have made it economical and reliable to have one
boiler per turbine-generator.
58
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Steam Expansion
The conversion of the pressure energy of the steam into
mechanical energy occurs in the steam turbine. In the
turbine the steam flows through a succession of passages
made up of blades mounted on alternately moving and
stationary discs. Each set of moving and stationary discs
is called a stage. The moving discs are mounted on a
rotating shaft while the stationary discs are attached to
the turbine casing. As the steam passes from disc to disc,
it gives up its energy to the rotating blades and in the
process loses pressure and increases in volume. If the
steam enters the turbine in a saturated condition, a small
portion of the steam will condense as it passes through the
turbine. One reason for superheating or reheating steam is
to reduce this condensation and the mechanical problems
associated with it.
There are. many different types of turbines and turbine
arrangements in use in steam electric powerplants. Almost
all turbines in use in central generating plants are of the
condensing type, discharging the steam from the last stage
at below atmospheric pressure. The efficiency of the
turbine is highly sensitive to the exhaust pressure
(backpressure). A turbine designed optimally for one level
of backpressure will not operate as efficiently at the other
levels of backpressure. Some turbines designed for 863
kg/sq m (2-1/2 in. of Hg abs) backpressure cannot operate at
1,730 kg/sq m (5 in. of Hg abs) because of high temperature
in the last stages. In general, turbines designed for once-
through cooling systems will generally be operated at lower
backpressures than those designed for closed cooling
systems. Moreover, if a turbine designed for the low
backpressures corresponding to once-through cooling system
is operated instead with a closed cooling system, an
incremental decrease in turbine efficiency will result
during times when the back pressure is higher than it would
have been for once-through cooling.
In most turbine arrangements a portion of the steam leaves
the casing before the final stage. This type of turbine is
called an extraction turbine. The extracted steam is used
for feedwater heating purposes. In some turbines, a portion
of the steam is extracted, reheated in the boiler, and
returned to the turbine or to another turbine as a means of
improving overall efficiency. Many different mechanical
arrangements of high pressure and low pressure turbines on
one or more shafts are possible, and have been utilized.
While there are no major effluents associated with the steam
expansion phase other than those resulting from housekeeping
operations, the significance of the steam expansion lies in
59
-------
its effect on plant efficiency and therefore on the thermal
discharge. In many plants, turbine design will be a key
factor determining the extent of the feasibility of convert-
ing a once-through cooling system to a closed system.
Steam Condensation
Steam electric powerplants use a condenser to maintain a low
turbine exhaust pressure by condensing the steam leaving the
turbine at a temperature corresponding to vacuum conditions,
thus providing a high cycle efficiency and recovering the
condensate for return to the cycle. Alternatively, the
spent steam could be exhausted directly to the atmosphere
thus avoiding the requirement for condensers or condenser
cooling water, but with poor cycle efficiency and a
requirement for large quantities of high purity water.
There are two basic types of condensers, surface and direct
contact. Nearly all powerplants use surface condensers of
the shell and tube heat exchanger type. The condenser
consists of a shell with a chamber at each end, connected by
banks of tubes. If all of the water flows through the
condenser tubes in one direction, it is called a single-pass
condenser. If the water passes through one half of the
tubes in one direction and the other half in the opposite
direction, it is called a two-pass condenser. Steam passed
into the shell condenses on the outer surface of the cooled
tubes.
A single-pass condenser tends to require a larger water
supply than a two-pass condenser and will generally result
in a lower temperature rise in the cooling water. In most
instances it will also produce a lower turbine backpressure.
A two-pass condenser is utilized where the cooling water
supply is limited or in a closed system where it is desired
to reduce the size of the cooling device, and improve its
efficiency by raising the temperatures of operation.
Many condensers at the more-recently built powerplants have
divided water boxes so that half the condenser can be taken
out of service for cleaning while the unit is kept running
under reduced loads. Since cleanliness of the condenser is
essential to maintaining maximum heat transfer efficiency,
it is common practice to add some type of biocide to the
cooling water to control the growth of algae or slimes in
the condenser. In spite of these biocides most powerplants
clean condensers mechanically as part of regularly scheduled
maintenance procedures. Some plants employ continuous on-
line mechanical cleaning systems.
60
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Operation of the condenser requires large quantities of
cooling water. Wherever adequate supplies of cooling water
are available, it has been common practice to take cooling
water from a natural source, pump it through the condenser,
and discharge it to the same body of water from which it was
obtained. This is known as a "once-through" system. One of
the major considerations in siting powerplants is the
availability of an adequate source of high-quality once-
through cooling water. If sufficient water for a once-
through system is not available and other considerations
prevail in determining the location of the plant, cooling
water must be recirculated within the plant. In this case
some form of cooling device, an artificial pond with or
without sprays, or a cooling tower must be provided to keep
the temperature from rising above the maximum level
permissible or desirable for turbine operation. Figure IV-5
shows a schematic flow diagram of a typical recirculating
(closed) system utilizing cooling towers. For reasons of
economy closed systems typically operate at higher
temperature differentials across the condenser than once-
through systems, balancing the somewhat reduced efficiency
of the turbine against the lower quantity of cooling water
required, and therefore the smaller size and lower cost of
the cooling device. However, since nearly all cooling
devices currently in use obtain their cooling effect from
evaporation, the dissolved solids concentration of closed
cooling systems tends to increase, eventually reaching, if
uncontrolled, a point where scaling of the condenser would
interfere with heat transfer. A portion of the concentrated
circulating water must therefore be discharged continually
as blowdown to remove dissolved solids, and purer fresh
water must be provided to make up for losses due to
evaporation, blowdown, liquid carryover (drift), and leaks.
Flow rates of cooling water vary with the type of plant, its
heat rate and the temperature rise across the condenser. A
fossil plant with a heat rate of 10,000 kJ/kwh (9,500 Btu
per kwh) and a 6.7°c (12°F) rise across the condenser
(values typical of plants in the industry using
once-through cooling systems) will require about 0.5 x 10-*
cu m/sec (0.8 gpn) of cooling water for every kw of
generating capacity. A nuclear plant with a heat rate of
11,100 kJ/kwh (10,500 Btu per kwh) and a 11°C (20«F) rise
across the condenser, (typical of plants using closed
cooling systems) will require about 0.46 x 10-* cu m/sec
(0.73 gpm). Because of differences in thermal efficiencies,
nuclear plants under identical conditions require about SOX
more cooling capacity than comparible fossil plants.
61
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EVAPORATION
LOSS
FRESH
WATER
MAKE-UP
AUXILARY
COOLERS
&
CONDENSERS
SPRAY &
WINDAGE LOSS
COOLING
TOWER
CHLORINE &
TREATING
CHEMICALS
$\
V
SURFACE
CONDENSERS
PUMP BEARING COOLING
SLOWDOWN
PUMP GLAND COOLING
FIGURE IV-5 SCHEMATIC COOLING WATER CIRCUIT
62
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While both once-through and closed cooling systems are
currently in use in the industry, the use of closed systems
has generally been dictated by lack of sufficient water
supplies to operate a once-through system and not generally
by considerations of the thermal effects of the cooling
water discharge. A few plants have installed cooling
devices on their effluents to meet receiving water quality
standards and a few others have installed or are planning to
install cooling devices or to convert to closed systems in
order to meet receiving water temperature requirements.
Generating of Electricity
The actual generation of electric energy is accomplished in
a generator, usually directly connected to the turbine. The
generator .consists of a rotating element called a rotor
revolving in a stationary frame called a stator. The
process converts mechanical energy into electric energy at
almost 100% of theoretical efficiency and therefore produces
little waste heat.
Raw Materials
General aspects of the four basic fuels in use in the
industry have been discussed in the previous section. In
this section some of the characteristics of each of the
fuels will be discussed as they affect the process and the
wastewater effluents produced.
Coal
Coals are ranked according to their geological age which
determines their fuel value and other characteristics. The
oldest coals are the anthracites, which contain in excess of
92% fixed carbon. Most anthracite lies in a limited region
of eastern Pennsylvania and is not a major factor in the
nationwide generation of electric energy. Most of the power
is produced from bituminous coal (the next lower rank) which
contains between 50 and 92% fixed carbon and varies in fuel
value between 19,300 and 32,600 J/g (8,300 and 14,000 Btu
per Ib). A substantial amount of power is also produced
from lignite containing less than 50% carbon and having an
average heating value of 15,600 J/g (6,700 Btu per Ib).
Three major characteristics of coal that affect its use in
powerplants are the percentages of volatile combustible
matter, sulfur and ash. The sulfur content of coal is
particularly critical since air pollution limitations
restrict the emission of sulfur dioxide. The sulfur content
of U. S. coals varies from 0.2 to 7.0 percent by weight.
63
-------
Most of the low sulfur coal deposits are located west of the
Mississippi River. In the East, a large portion of the low
sulfur coal has been dedicated to metallurgical and export
uses.
The ash content of coal varies from 5 to 20% by weight. Ash
can create problems of air pollution, slagging, abrasion and
generally reduced efficiency. One problem of substituting
low sulfur coal for coal with a higher sulfur content is
that low sulfur coals tend to have higher ash fusion
temperatures, which may cause problems in boiler operation.
The fly ash produced by low sulfur coal tends to have higher
electrical resistivity which reduces the efficiency of
electrostatic precipitators.
Several other aspects of coal as a fuel for steam electric
powerplants should be noted. The first is the increased
popularity of mine-mouth plants, that is plants built for
the purpose of using coal from a specific mine and located
in the immediate vicinity of that mine. Much of the current
construction of coal-fired units consists of mine-mouth
plants. These plants in effect trade off the cost of trans-
porting coal against the cost of transmitting the electrical
energy generated. Their major advantages are that in most
cases that they are not located in or near urban centers and
therefore do not arouse public opposition or have the same
type of environmental impact as plants located within those
centers. Most mine-mouth plants are base-load operated and
many use cooling towers because of the absence of adequate
cooling water supplies. They compete favorably on a unit
cost basis with nuclear plants and in many instances can be
constructed with a substantially shorter lead time.
A second aspect consists of the potential impact on the
industry of the successful development of a commercial-scale
coal gasification process. A number of processes are
currently under development. The potential of coal
gasification lies in its ability to produce a storable
product that can be transported economically by pipeline and
can be burned without ash or sulfur problems. At the
present, the estimated cost of synthetic gas is still
substantially higher than the cost of alternate fuels, but
upward pressures on natural gas and residual oil prices may
make coal gasification economically attractive.
Natural Gas
The use of natural gas as a fuel for generating electricity
is a fairly recent development, dating back to about 1930.
In 1970 0.1 trillion cu m (3.9 trillion cu ft) of natural
64
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gas were burned to generate electricity, placing natural gas
second among the fossil fuels and accounting for almost 30%
of the energy generated from fossil fuels.
The original attractions of natural gas were its
availability and its economics. For a long time natural gas
was considered almost a by-product. At the same time, its
use in utility powerpiants resulted in simpler and less
costly fuel handling, burning facilities and a marked
reduction in ash handling and air pollution problems.
However, the availability of natural gas has declined
sharply in the last few years, and utilities are finding it
increasingly difficult to conclude long-term agreements for
natural gas supplied for central generating plants. The
future availability of natural /gas is uncertain. Present
reserves of natural gas amount to an estimated twelve times
our current annual production, and the annual discovery of
new sources is less than the current rate of consumption.
Estimates by the FPC project a fairly stable level of
natural gas consumption by the electric utility industry
over the next twenty years. However, in view of the
projected growth of the industry as a whole, the share of
the total electricity generated is expected to decrease to
6% by 1990. This trend could be affected by several
technological developments. One of these is the successful
commercial application of coal gasification. Another is an
AEC program to increase the yield of natural gas from
underground formations by the underground explosion of
nuclear devices. In the meantime, some existing plants
using natural gas as a fuel were being converted to oil in
spite of the advantages of natural gas in the ash and air
pollution areas.
Fuel Oil
Fuel oil is presently the third most significant source of
fossil fuel for generating electricity, accounting for 15X
of the total generation in 1970. However, in the New
England- Middle Atlantic area it accounted for 82* of the
thermal generation, primarily as a result of the conversion
of coal-burning plants to residual fuel oil in order to meet
air pollution standards.
Three types of fuel oil are used in utility powerplants:
crude oil, distillate oil, and residual oil. A key problem
with the use of fuel oil, as with the use of coal, is the
sulfur content. At the present time, powerplants in the
Northeast are burning oil containing less than 1% sulfur by
weight. Domestic supplies of low sulfur crudes are quite
65
-------
limited and will not be improved significantly when Alaskan
oil is available in the contiguous United States. As a
result, utilities have been highly dependent on foreign
sources of supply. Major foreign sources include Venezuela,
and the Middle East. Venezuelan sources must be, and are,
desulfurized at the source, while Middle Eastern crudes are
low in sulfur in their original state.
With the future availability of petroleum products of all
types in question, it appears doubtful that the recent trend
toward increased burning of oil in powerplants will continue
in the future. FPC projections (1970) indicated a slight
increase in the percentage share of oil compared to total
use of fossil fuels over the next five years, with a
leveling off thereafter. The price of fuel oil, which had
remained fairly constant during the early 1960's has
increased in recent years, and will possibly increase
further in the future.
A possible technological development which might affect the
supply of fuel oil is the extraction of oil from oil shales.
Certain areas of Colorado, Utah and Wyoming contain large
reserves of oil shale, with unfavorable economics being the
major obstruction to the development of an oil shale
industry. If crude oil prices continue to escalate and oil
supplies continue to dwindle, the development of this source
may become economically viable.
Fuel oil use in powerplants minimizes bottom ash problems,
although fly ash can continue to be troublesome. Some fuel
oils also contain vanadium and may contain other unusual
components which may or may not wind up in a powerplant
effluent.
Refuse
Emphasis on recycling waste products has increased interest
in use of another fuel - solid waste. Refuse and garbage
are not confined to kitchen wastes, but include a mixture of
all household wastes with commercial and industrial wastes.
Large-scale inorganic industrial wastes are generally not
included. The average American domestic refuse has many
combustibles which raise its heating value to approximately
HQ% of that of coal. Incineration coupled with steam
generation has been practiced for a considerable period in
Europe, where household garbage as collected is mixed,
especially during the winter months, with the ashes of
household coal furnaces. Garbage is generally shredded and
most non-combustibles are removed by magnetic and
centrifugal separators before firing to the furnace.
66
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However, furnaces must still be designed for non-combustible
loadings. Garbage is essentially sulfur-free but can
generate moderate quantities of hydrogen chloride from the
combustion of polyvinyl chloride and other chlorinated
polymers. Because of the presence of these materials,
studies of the removal of acid gases from the furnace stack
gases, and the disposal of the effluents resulting from
these operations should continue.
At the present time there is one powerplant in the United
States that burns refuse as part of its fuel. The plant has
the capability of using as much as 20% refuse with at least
80% coal, although operation to date has been limited to 10%
refuse and 90% coal.
Information on U. S. Generating Facilities (Size and Age)
An inventory of operating steam electric powerplants in the
United States is presented in Appendix 1 of this report.
The list has been divided into ten sections to conform to
the ten EPA regions of the country. The inventory shows the
operating utilities by states, plants, and their specific
geographic location. It also shows the total plant capacity
in megawatts, with an indication of whether the plant is
nuclear or fossil-fueled, and a designation of plants that
are under construction. Gas combustion turbine facilities
operating within fossil-fueled generating plants have been
indicated on a separate line.
The inventory shows a total of 1,037 operating generating
plants in the United States as of January !=•/ 1972, consist-
ing of 1011 fossil-fired plants and 26 nuclear plants. -A
total of 59 plants were under construction as of the date
indicated. Of this total, 42 are nuclear plants and 17 are
.fossil-fueled plants. Table IV-1 provides a summary of the
industry inventory by EPA region and individual states.
Figures IV-6 through IV-8 provide a cumulative frequency
distribution plot of plant size within the steam electric
powerplant industry. It can be seen from Figure IV-6 that
approximately 50 percent of the plants in the industry are
100 Mw or larger, and that 25 percent of all plants are
larger than 400 Mw. Figure IV-7 shows that the size
distribution of fossil-fueled plants roughly corresponds to
the industry profile. However, Figure IV-8 illustrates the
large size of nuclear plants, showing that 50 percent of
these plants are larger than 800 Mw, and that 25 percent are
larger than 1,500 Mw.
67
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TABLE IV-1
INDUSTRY INVENTORY SUMMARY
OPERATING PLANTS
STATE
EPA Region 1
Connecticut
New Hampshire
Rhode Island
Vermont
Maine
Massachusetts
EPA Region 2
New Jersey
New York
Puerto Rico
Virgin Islands
EPA Region 3
Delaware
Maryland
Pennsylvania
Virginia
West Virginia
District of Columbia
EPA Region 4
Alabama
Florida
Georgia
Kentucky
Mississippi
North Carolina
South Carolina
Tennessee
EPA Region 5
Illinois
Indiana
Michigan
Minnesota
Ohio
Wisconsin
EPA Region 6
Arkansas
Louisiana
New Mexico
Texas
Oklahoma
EPA Region 7
Iowa
Kansas
Missouri
Nebraska
EPA Region 8
Colorado
Montana
North Dakota
South Dakota
Utah
Wyoming
EPA Region 9
Arizona
California
Hawaii
Nevada
EPA Region 10
Alaska
Idaho
Oregon
Washington
TOTAL
16
5
5
4
6
29
18
39
4
2
5
14
48
15
12
2
10
43
13
19
9
12
16
7
45
29
40
48
54
33
10
27
16
91
19
37
32
31
15
23
8
9
9
6
8
12
39
7
6
14
1
6
9
FOSSIL
13
5
5
3
6
28
17
36
4
2
5
14
45
15
12
2
10
43
13
19
9
12
15
7
43
29
38
45
54
31
10
27
16
91
19
37
32
31
15
23
8
9
8
6
8
12
37
7
6
13
1
6
9
NUCLEAR
3
0
0
1
0
1
1
3
0
0
0
0
3
0
0
0
0
0
0
0
0
0
1
0
2
0
2
3
0
2
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
2
0
0
1
0
0
0
FOSSIL
0
0
0
0
0
0
0
1
0
0
0
0
0
0
1
0
0
0
3
2
0
1
1
1
1
1
2
0
0
0
0
1
0
1
0
0
0
0
0
0
0
0
0
0
0
1
0 •
0
0
0
0
0
0
NUCLEAR
0
0
0
0
1
1
1
2
0
0
0
1
2
2
0
0
3
4
1
0
0
2
1
1
3
0
4
1
3
1
1
1
0
0
0
1
0
0
2
1
0
0
0
0
0
0
2
0
0
0
0
0
0
TOTAL
1037 1011
68
26
17
42
-------
o
o.
o
o
CUMULRTIVE FREQUENCY DISTRIBUTION OF
ENTIRE POWER PLflNT INVENTORY
FOR RLL EPR REGIONS
o
o
o
rj_
o
o
o
CO-
12.50 25.00 37.50 50.00 62.50 75.00 87.50 100.OC
PERCENT OF PLRNTS EQURL TO OR LRRGER THRN STRTED SIZE
FIGURE IV-6
69
-------
o
O-
O
o
o
CD-
CO
o
o
o
CM-
PI
O
O
CUMULATIVE FREQUENCY DISTRIBUTION OF
FOSSIL-STEflM POWER PLflNTS
FOR flLL EPfl REGIONS
0 12.50 25.00 37.50 50.00 62.50 75.00 87.50 100.OQ
PERCENT OF PLflNTS EQUflL TO OR LflRGER THflN STflTEO SIZE
FIGURE IV- 7
70
-------
O
O
00
.—zr.
~ c\j
5°
ro'
uLj
rvj
•-S.
o
C\J.
o.
CD
O
o
o.
Of
o
o
CUMULflTIVE FREQUENCY DISTRIBUTION OF
NUCLERR-STERM POWER PLRNTS
FOR RLL EPR REGIONS
0 12.50 25.00 37.50 50.00 62.50 75.00 87.50
PERCENT OF PLRNTS EQURL TO OR LRRGER THRN STRTED SIZE
100. OC
FIGURE IV- 8
71
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The Federal Power Commission Form 67, "Steam-Electric Plant
Air and Water Quality Control Data for the Year Ended
December 31, 1969" provides data on the capacity
utilization, age, etc., of generating units. This form must
be filed annually by plants with a generating capacity of 25
Mw or greater, provided the plant is part of a system with a
total capacity of 150 Mw or more.
Size of Units
According to the Federal Power Commission (FPC) 1970
National Power Survey, in 1930, the largest steam-electric
unit in the United States was about 200 megawatts, and the
average size of all units was 20 megawatts. Over 95 percent
of all units in operation at that time had capacities of 50
megawatts or less. By 1955, when the swing to larger units
began to be significant, the largest unit size had increased
to about 300 megawatts, and the average size had increased
to 35 megawatts, (see Figure IV-9). There were then 31
units of 200 megawatts or larger. By 1968, the largest unit
in operation was 1,000 megawatts; there were 65 units in the
400 to 1,000 megawatt range; and the average size for all
operating units had increased to 66 megawatts. In 1970, the
largest unit in service was 1,150 megawatts; three
1,300-megawatt units were under construction; and three
additional 1,300-megawatt units were on order. The average
size of all units under construction was about U50
megawatts. As the smaller and older units are retired, the
average size of units is expected to increase to about 160
megawatts by 1980 and 370 megawatts by 1990.
The distribution of U.S. generating capacity by size, as a
percentage of the generating capacity installed in
particular years, is given in Table IV-2.
Age of Facilities
In the steam electric powerplant industry, age of generating
facilities must be discussed on the basis of units rather
than on a plant basis. Generally, the units comprising a
generating plant have been installed at different times over
a period of years, so that the age of equipment within a
given plant is likely to be distributed over a range of
years. In addition, age may play a peculiar role in
assigning a unit to a particular type of operation as out-
lined below.
In general, the thermal efficiency of newly designed power
generation plants has increased as operating experience and
design technology have progressed. Early plants generated
72
-------
Figure IV- 9
LARGEST FOSSIL-FUELED STEAM-ELECTRIC
TURBINE-GENERATORS IN SERVICE
1900 - 1990
2500 r
2000
1500
1000
500
292
1900
1930
YEAR
1960
1990
73
-------
Table IV-2
DISTRIBUTION OF INSTALLED GENERATING CAPACITY IN THE U.S. BY SIZE
FOR VARIOUS YEARS WHEN EQUIPMENT WAS FIRST PLACED IN SERVICE
Generating
megawe
0 -
25 -
100 -
300 -
500 -
Capacity,
itts
24
99
299
499
Year
1945
18
58
24
0
0
in Which
Equipment
1955 1960
8
26
66
0
0
4
13
56
27
0
1965
0
12
55
25
8
was First
1970
1
4
32
32
31
Placed
1972
0
1
13
13
73
in Service
1974
0
3
3
10
84
1970-1974
0
1
13
15
71
-------
saturated steam at low pressures and consumed large
quantities of fuel to produce a unit of electrical energy.
One electrical kilowatt hour of energy is equivalent to 860
k cal (3,413 Btu) of heat energy. Steam pressures and
temperatures increased from about 1.17 MN/sq m (170 psig) at
the turn of the century to 1.72 - 1.90 MN/sq m (250 - 275
psig) and 293°C (560°F) by World War I, and to 3.10 - 4.48
MN/sq m (450-640 psig) and 370-400<»C (700-750°F) by 1924.
«»• In 1924 and 1925 there was a surge to 8.27 MN/sq m
(1,200 psig) and 370°C (700°F) and it has steadily increased
since then, until by 1953 pressures had reached the critical
pressure of steam (22.11 MN/sq m (3,206 psia) and
temperatures of 540-565°C (1,000-1,05p°F).*»• Above the
critical pressure the liquid and vapor phases are
indistinguishable and there is no need for a steam drum
(separator). The economic justification of the
supercritical cycle has resulted in a limited number of this
type of unit to date.
These changes have had the effect of reducing the amount of
fuel required to generate a kilowatt hour, as shown in
Figure IV-10, taken from Reference No. 292. In 1900 it
required 2.72 kg (6 pounds) of coal, (41,700 k cal (75,000
Btu) to generate one kwh. Today a supercritical,
double-reheat unit of Plant no. 3927 has established an
annual heat rate of 2197 k cal/kwh (8,717 Btu/kwh). "°
This amounts to 0.318 kg (seven-tenths of a pound) of coal
per kwh. The heat economies of the newer facilities
generally make it desirable to keep them in full-time
base-load operation. The older units with their higher fuel
consumption are therefore generally relegated to cycling or
peaking service. In spite of this general trend, there are
indications that heat rates have been increasing since 1972
as a result of pressures to reduce capital cost in relation
to fuel prices, and increasing use of air and water
pollution control equipment which tend to reduce generating
efficiency.
A computer plot of heat rate in Btu/kwh vs unit capacity in
megawatts (x 10) is shown in Figure IV-11. The plot is a
print-out . of data obtained from FPC Form 67 for the year
1969. In the plot, data obtained from newer plants (under
10 years old) are represented by squares, those 10-20 years
old by triangles, and those over 20 years by X's.
Similarly, Figure IV-12 is a printout of the same
information replotted with Btu/kwh as the ordinate and unit
age as the abscissa. The data from both plots represent
over 1,000 operating units, and are not conclusive, but do
show general trends. The newer plants, of larger size,
generally are more efficient. Thus the data illustrates the
-------
30,000 p
25,000 -
20,000 -
1
-------
LEGEND
m UNITS UNDER 10 TERRS OLD
* 10 TO 20 TERRS OLD
X OVER 20 TEflRS OLD
"tToo
20.00 10.00 60.00 80.00
UN'IT CflPflCITT (MW)
100.00 120.00 140.00 160.00
*10'
HEflT RRTE VS UNIT CflPRCITT
Figure IV-1
77
-------
o
o
LEGEND
D UNITS UNDER 100 MW
A 100 TO 300 MW
X OVER 300 MW
o
OJ_
o
o
o
tn.
o
o
O
a a
a
a a
o
o
CC
:co
a
a
CD
o
o
a
a
cr-
oc
o
o
O
O.
X X
X
an *
a *
x
x B a
a
a
3 H a a
a _ m a
a a a
8 m a 1 R
8-;:!§lis
m " * * * I * 8
5 * a
Q
. n
a a D
1§
a 9
a a
*
B °
a a n a a
a a Q
I
4
B
a
a a
a
a
n
a
"b.OO
5.00
10.00 15.00 20.00 25.00 30.00 35.00 40.00
UNIT flGE IN TERRS
HERT RflTE VS0 UNIT RGE
Figure IV-12
78
-------
improvement in efficiency achieved as the industry has
progressed to newer and larger generating facilities.
Mode of Operation (Utilization^
The need for considering a subcategorization of the industry
based on utilization arises because of the costs and
economics associated with the installation of supplemental
cooling facilities. The unit cost increment (mills/kwh)
required to amortize the capital costs of the cooling system
is dependent on the remaining kwh's that individual units
will generate. The remaining generation is a function of
both the manner in which the individual unit is utilized and
the number of years that the unit will operate prior to
retirement. These two factors are not fully independent
variables. In general, utilities will employ their most
efficient, usually newest equipment most intensively. This
equipment will also generally have the longest remaining
useful life. The cost of installing supplemental cooling
water equipment for these units relative to the remaining
generation will therefore be relatively low. Therefore,
these more modern, highly-utilized units, which also would
reject relatively large amounts of the waste heat, are
better able to carry the costs associated with thermal
effluent control.
Less efficient, usually older equipment will be utilized to
a lesser degree to meet daily and seasonal peak loads. This
lower annual utilization is compounded by the fact that this
equipment has relatively fewer remaining years of service
prior to retirement. Therefore, the cost of amortizing
supplemental cooling equipment for these units will be
substantially higher than for the newer, more highly
utilized units. Because of their low utilization, these
units will reject considerably less heat per unit of
capacity than the newer equipment. Also, because of the
higher costs associated with this equipment, utilities might
consider early retirement of much of this equipment rather
than the installion of costly treatment equipment. Since
these units provide an important function as peaking or
standby capacity, retirement prior to the installation of
replacement capacity would have associated penalties.
According to the FPC National Power Survey (1970), all of
the high-pressure, high-temperature, fossil-fueled
steam-electric generating units, 500 megawatts and larger,
have been designed as "base load" units and built for con-
tinuous operation at or near full load. Daily or frequent
"stops" and "starts" are not consistent with their design
and construction and so-called "cycling" or part-time
79
-------
variable generation was not originally comtemplated for
these units. However, by the time units having lower
incremental production costs become available for base load
operation, it is believed that the earlier "base load" units
can be adapted and used as "intermediate" peaking units.
The units placed in service during the 1960•s still have 15
or more years of base load service ahead of them, but
eventually the installation of more economical base load
equipment may make it desirable to convert to peaking
service those units which are suitable for such conversion.
New steam-electric peaking units, sometimes referred to as
mid-range peaking units, are designed for minimum capital
cost and to operate at low capacity factor. They are oil-
or gas-fired, with a minimum of duplicate auxiliaries, and
operate at relatively low pressures, temperatures, and
efficiencies. They are capable of quick startups and stops
and variable loading, without jeopardizing the integrity of
the facilities. Such units are economical because low
capital costs and low annual fixed charges offset low
efficiency and operation at low capacity factors. The units
can, however, be operated for extended periods, if needed,
to meet emergency situations.
The first of such fossil-fueled steam-electric units
designed for peaking service, a 100-megawatt, 1,450 psi,
1000°F, non-reheat, gas-fired unit, was installed in 1960,
Two earlier low capital cost fossil-fueled steam-electric
plants—a 69-megawatt, single-unit plant (1952), and a 313-
megawatt, two-unit plant (1954)—were generally classified
as hydro standby; they were not straight peaking
installations. The 313-megawatt plant was later modified
for base load operation.
With increasing loads and the accompanying need for
additional peaking capacity, at least 27 peaking units of
this general type were on order or under construction at the
end of 1970. All are either oil- or gas-fired, because the
added costs of coal and ash handling facilities for peaking
units are not justified by the small fuel cost saving that
might be realized by using coal. Eight of the 27 units are
in the 250 to 350-megawatt class, fifteen in the
400-megawatt class, and four in the 600-megawatt class.
Most of the units are designed for steam conditions of 1,800
psi and 950°/950°F.
The use of the nuclear power plant in conjunction with other
forms of generation in order to provide energy to meet the
daily requirements of a power system will probably not be
vastly different from the use of a fossil-fueled plant of
80
-------
the same capacity. There are some differences, however,
that may affect the operation of the nuclear plant, such as
relative operating costs, refueling time and inspections.
Because an economic loading schedule for a power system will
tend to favor operation of units with the lowest incremental
production cost, the capacity factor of a nuclear fueled
plant is expected to be relatively high when it is added to
a system consisting of fossil-fueled plants. However, when
newer, more efficient nuclear plants are added to the
system, which can operate with even lower production costs,
the first nuclear plants will begin to have decreasing
capacity factors. Most of the plants that have been ordered
during the past three years will probably have annual
capacity factors of 80 percent or better for a period of ten
to fifteen years, depending on the operating requirements
and makeup of the system.
The limited operating experience to date with the
comparatively small nuclear plants indicates that they are
able to handle load swings without difficulty. It is
expected that the larger units now on order will perform
similarly, but it may develop that they will not be amenable
to load regulation. In that event, fossil units,
pumped-storage units, conventional hydro units, or other
types of peaking units will be installed to carry peak load
with nuclear units being maintained at base load for
substantially all of their useful lives. If nuclear units
are to be utilized with very low annual capacity factors,
substantial research and engineering effort must go into the
determination of core designs to economically accomplish
this type of operation.
Base-load units are responsible for the bulk of the thermal
discharges, will continue to operate for many more years,
and are able to support the required technology with
relatively small increases in the bus-bar cost of power.
The balance of the steam-electric power generation inventory
is made up of older equipment, which reject considerably
less heat and for which the cost of installing control and
treatment technology would be considerably higher relative
to the effluent reduction benefits obtained. It is
understood that considerable abatement will take place in
time in this older portion of the inventory due to normal
attrition.
Traditionally, the power industry has employed two
categories for generating equipment. Units that are
continuously connected to load, with the exception of
scheduled and unscheduled maintenance periods, have been
81
-------
termed base-loaded units. Units which are operated to meet
seasonal peak loads have been termed peaking units. Daily
load swings have usually been met by modulation of the base-
loaded units. More recently, the increased cycle
sophistication built into the newer base-loaded equipment
has made them less efficient in accommodating large daily
load swings. Therefore, a third type of capacity called
cyclic or intermediate generation unit has come into general
acceptance within the industry. This third type of unit is
usually a downgraded base-loaded unit which can be adapted
to the intermittent operation with fairly rapid load swings.
The progression of individual units of capacity through the
three types of duty assignments generally follows the
sequence given below:
1. New steam electric capacity has historically been
added as base-load units. All but a few existing steam
electric generating units were at one time base-loaded
units. Beginning in the middle 1960's some new peaking
units, both steam electric and gas turbine types have been
constructed. More recently (late 1960's early 1970»s)
several units of the combined (gas turbine/steam turbine)
cycle design have been designed specifically for cyclic or
intermittent duty. The aggregate existing capacity of units
or. inally built for peaking or cyclic service is
considerably less than 151 of the total steam electric
inventory.
2. Cycling capacity and peaking capacity has been
obtained by downgrading the older less efficient base-loaded
equipment as more efficient replacement capacity has been
built. The manner in which a unit is downgraded depends
upon the needs of the individual utility and the
requirements of its system load curve. Toward the end of
its usefx\ life, the unit may be held in standby duty to be
used only in the event of an outage to the other units.
3. Units have been retired from the bottom level of
utilization. Therefore, retirements of steam electric
capacity have generally been made from the peaking
inventory. While the annual retirement of steam electric
powerplant capacity have been significantly less than 1% of
the total capacity, this amount constitutes a significant
portion of the present peaking inventory.
The typical utility makes duty assignments by comparing the
capability of its available generating units against the
requirements of its system load curve. Efficient system
operation dictates that the most efficient equipment be
82
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operated continuously. These are the base-loaded units. In
descending order, the less efficient equipment is assigned
lower utilization duty to meet daily and seasonal variations
in the load curve. The process of matching capacity to load
is different for each utility. The system load curve will
be different for each utility as will the capability of its
individual generating units.
Large systems will have sufficient diversity of load which
will dampen extreme peaks and valleys in the characteristic
load curve. They will also have multiple units serving each
of the load segments and considerable flexibility in making
duty assignments. Individual large industrial loads may
dominate the system load curve for smaller utilities and
highs and lows of load may be more exaggerated. Duty
assignments for smaller systems will be more constrained by
the lack of multiple units and single units may be found
which service all three load segments. Duty assignments are
also influenced by the needs of the regional power grid in
which most utilities participate through a series of
agreements governing interconnections.
The diversity in both load and available capacity com-
plicates the process of establishing concrete limits between
the three types of generating equipment. The following
bases of establishing definitions of base-load, cyclic and
peaking units have been considered.
1. Qualitative descriptions of the three types of
operation.
2. Annual hours of operation.
3. Plant index numbers such as load factor, capacity
factor, utilization factor, etc.
The relative merits of definitions based on these systems
are discussed below. The ideal definition should be
relatively easy to employ, allow effective separation of the
three types of generation, and be understood and accepted.
Definitions Based on Qualitative Description of the Three
Types of Generation
This would rely on a description of the three types of
generation as the basis of separation. Suggested
definitions of the three types of generation are as follows:
83
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A base-loaded unit is one which is continuously connected to
load except for periods of scheduled or unscheduled
maintenance.
A cycling unit is one which services daily load variations
above the base-load. This type of unit is typically
connected to load some 250 days per year for a typical
period of about 12 hours. When not connected to load the
boiler is kept warm to allow rapid return to the system.
A peaking unit is one which is operated to meet peak loads
only. During periods when the unit is not generating power
it is held in standby or is shut down.
Annual Hours of Operation
It is clear that a basic difference between the three types
of generation is the amount of time that the different units
operate.
Reference 292, Part II suggests that steam peaking units are
designed to operate less than 2,000 hours per year.
Reference 256 indicates that base-load units operate in
excess of 6,000 hours per year. Units which operate between
these two limits would be defined as cycling units. The
hours of operation referred to in this system are hours that
the unit is connected to load. Hours of boiler operation
are not satisfactory. There is considerable difference in
hours of boiler operation and hours connected to load for
cycling and peaking units. Hours of condenser operation
could be used as a substitute since it is equivalent to
hours connected to load. See Table IV-3 for the heat rate,
service life, and capacity factors characteristic of units
within the above groupings based on hours of operation.
Historical records of annual hours of operation are required
to employ this sytem. There will be instances where base-
loaded units will have been operated less than 6,000 hours
per year because of extended maintenance requirements. On
the other hand there will be cases of stretching out the
operating schedules of peaking and cycling units because of
capacity shortage in particular systems. This system does
have the advantage of a basic simplicity in discriminating
between the different categories of generation.
Performance Indices
This would require relating the utilization of a unit to
indices of its performance. Several of these indices are
described below.
84
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Table IV-3
CHARACTERISTICS OF UNITS BASED ON ANNUAL
HOURS OF OPERATION
oo
en
Annual Hours of
Operation
0 - 2000
2000 - 6000
6000 - 8760
Heat
Min.
8727
8735
8706
Rate,
Mean
15793
12493
10636
Btu/kwhr
Max.
27315
27748
26741
Remaining Service? yr
Min. Mean Max.
1
1
1
11 26
15 26
19 32
Capacity Factor
Min. Mean Max.
.01 .07 .17
.03 .35 .71
.15 .67 1.12
Note: Based on a total service life of 36 years.
-------
Load Factor
Load factor is the ratio of the average demand for power
(kilowatts) over a designated period to the maximum demand
for power occurring in that period. The average demand is
the total (kilowatt-hours) for the period divided by the
total time span (hours). For example, in the twelve months
ended December 31, 1971, the electric energy generated and
purchased less sales to other electric utilities amounted to
35,720,253,101 kilowatt-hours. The one-hour net maximum
demand was 7,719,000 kw. The average hourly demand was,
consequently, 35,720,253,101 / 8760 = 4,078,000 kw. The
annual system load factor is, therefore, 4,078,000 /
7,719,000 = 0.528 or 52.8*. The load factor may be regarded
as providing some measure of the variation of demand during
a given period. Thus, if the load factor is 100* over a
period of 21 hours, the demand has been maintained constant
for the duration of the period.
Operating Load Factor
If the maximum demand varies from day to day, then the
operating load factor is the ratio of the average demand to
the average value of the maximum demands for the period.
For example, the daily maximum demands for a ten-day period
and the corresponding kilowatt-hours are as follows:
Maximum Demand Kilowatt Hours
Day kw Per day
1 1,000 19,200
2 950 13,700
3 800 14,400
4 980 9,700
5 700 10,900
6 850 18,000
7 500 7,000
8 750 10,000
9 820 9,100
10 900 12.000
Totals 8,250 124,000
Maximum Demand 1,000 kw
Average Maximum Demand = 8,250 / 10 = 825 kw
Average Demand = 124,000 / (10 x 24) = 517 kw
Load Factor = (517 / 1000) x 100 = 51.7%
Operating Load Factor = (517 / 825) x 100 = 62.6%
86
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Thus the operating load factor takes into account the varia-
tion of the daily maximum demand.
Capacity Factor
Capacity factor defines the relation between energy output
over a given time span and the capacity for energy
production over the same time span, and normally provides
measure of the utilization of the generating equipment
relative to investment. This factor is also a ratio of the
average load to the total rating of the installed generating
equipment for a given period. For example, in the twelve
months ended December 31, 1970, one unit generated
4,465,175,600 kilowatt-hours (exclusive of gas turbine
generation). The maximum unit capacity (winter rating) was
878,000 kw. The average hourly load was 4,465,175,600 /
8760 = 509,723 kw. The annual capacity factor is therefore,
509,723 / 878,000 = 0.5806 or 58.1%.
Operating Capacity Factor
Although a plant may have installed equipment of a certain
amount of generating capacity, only part of this may be in
actual operation for the given period. Suppose for a
certain generating plant the capacity of the installed
equipment is 770,000 kw and for some particular month only
600,000 kw of boiler capacity is actually operating. This
means that the maximum demand that can be imposed on the
plant is limited to 600,000 kw. The operating capacity
factor for the month would then be in the ratio of the
average demand for power to 600,000 kw, the maximum capacity
utilized. This factor therefore, determines the relation
between average output and the peak demand for power which
the plant is prepared to meet.
Use Factor
This term is generally used in connection with the
performance of turbo-generators. It is the ratio of the
actual energy output of a machine during a certain period to
the energy generation which could have been obtained during
the actual operating hours in that period by operating the
machine at rated capacity. A turbo-generator operating for
7,000 hours generated 350,000,000 kilowatt-hours. The rated
capacity of the unit is 100,000 kw. The use factor was
350,000,000 / (100,000 x 7,000) = 0.5 or 50%.
87
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Section 301 (b) of the Act requires the Administrator to take
into account, in determining the applicable control measures
and practices, the total cost of application of technology
in relation to the effluent reduction benefits to be
achieved from such application. Among the above factors,
the capacity factor alone would determine, for otherwise
similar circumstances, the incremental production cost
associated with the application of pollution control
technology in relation to the effluent reduction benefits to
be achieved.
The 1970 National Power Survey by the Federal Power
Commission (FPC) describes base-load, intermediate, and
peaking units as follows. Base-load units are designed to
run more or less continuously near full capacity, except for
periodic maintenance shutdowns. Peaking units are designed
to supply electricity principally during times of maximum
system demand and characteristically run only a few hours a
day. Units used for intermediate service between the
extremes of base-load and peaking service |inust be able to
respond readily to swings in systems demand, or cycling.
Units used for base-load service produce 60 percent, or
more, of their intended maximum output during any given
year, i.e., 60 percent, or more, capacity factor; peaking
units less than 20 percent; and cycling units 20 to 60
percent. The FPC Form 67, which must be submitted annually
by all steam electric plants (except small plants or plants
in small systems) reports annual boiler capacity factors for
each boiler. The boiler capacity factor is indicative of
the gross generation of the associated generating unit.
Site Characteristics
Engineering criteria require an adequate supply of cooling
water, adequacy of fuel supply, fuel delivery and handling
facilities, and proximity of load centers. These have
always been important factors in the selection of powerplant
sites. 29« Traditionally, plants have been located in or
near population centers to reduce transmission costs and
satisfy the other key site factors mentioned. Table IV-4
shows a total of 153 plants located in the 50 largest cities
of the country. This total represents approximately 15
percent of all plants in the industry, and does not include
suburban plants near the cities in question, or urban plants
in smaller population centers. Clearly, a significant
number of existing plants in the steam electric generating
industry are situated in locations which interface with a
reasonable percentage of the country's population.
88
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Table IV-4
URBAN STEAM ELECTRIC POWER PLANTS
NO.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
CITY
New York
Chicago
Los Angeles
Philadelphia
Detroit
Houston
Baltimore
Dallas
Washington
Cleveland
Indianapolis
Milwaukee
San Francisco
San Diego
San Antonio
Boston
Memphis
St. Louis
New Orleans
Phoenix
Columbus
Seattle
Jacksonville
Pittsburgh
Denver
Kansas City
Atlanta
Buffalo
Cincinnati
San Jose
Minneapolis
Fort worth
Toledo
Newark
Portland
Oklahoma City
Louisville
Oakland
Long Beach
Omaha
Miami
Tulsa
Honolulu
El Paso
St. Paul
Norfolk
Birmingham
Rochester
Tampa
Wichita
STATE
New York
Illinois
California
Pennsylvania
Michigan
Texas
Maryland
Texas
D.C.
Ohio
Indiana
Wisconsin
California
California
, Texas
Massachusetts
Tennessee
Missouri
Louisiana
Arizona
Ohio
Washington
Florida
Pennsylvania
Colorado
Missouri
Georgia
New York
Ohio
California
Minnesota
Texas
Ohio
New Jersey
Oregon
Oklahoma
Kentucky
California
California
Nebraska
Florida
Oklahoma
Hawa i i
Texas
Minnesota
Virginia
Alabama
New York
Florida
Kansas
POPULATION
7,894,862
3,369.359
2,809,596
1,950,098
1,513,601
1,232,802
905,759
844,401
756,510
750,879
744,743
717,372
715,674
697,027
654,153
641,071
623,530
622,236
593,471
581,562
540,025
530,831
528,865
520,117
514,678
507,330
497,421
462,768
452,524
445,779
434,400
393,476
383,818
382,288
380,555
368,856
361,958
361,561
358,633
346,929
334,859
330,350
324,871
322,261
309,828
307,951
300,910
296,233
277,767
276,554
NUMBER OF
PLANTS
12
4
4
4
6
7
6
6
2
3
3
3
2
3
7
2
1
3
4
1
3
2
3
5
3
3
1
1
2
0
2
3
2
1
2
2
4
1
2
4
1
1
1
2
2
3
2
3
4
4
Total 152
89
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The trend in recent years toward larger units, combined with
the advent of commercial nuclear power generation and the
institution of mine-mouth coal-fired plants has resulted in
a greater number of plants being constructed in rural areas.
Site selection for new generating facilities is not only
governed by the factors cited, but increasingly by
environmental considerations. The prevention and control of
air and water pollution is undoubtedly as important as many
of the traditional factors involved in the selection of new
plant sites. Factors generally considered in decisions on
plant location include land requirements, water supply, fuel
supply and delivery, etc.
Land requirements are quite variable. For plants situated
near population centers, land cost is a prime consideration.
The largest consumers of land are the fuel storage area, ash
disposal area and water cooling ponds, lakes etc. if
utilized. Since they are public utilities, power generating
plants must have sufficient fuel storage capacity to allow
uninterrupted operation for the duration of a major
transportation strike. This means that unless the plant is
very near its source of supply, it must have a storage
capability up to approximately three month1s fuel. Even
mine-mouth plants must have fuel storage to allow them to
withstand a miners' strike.
Most steam plants require water for two main purposes -
boiler feed water make-up and steam condensation. The cost
of preparation of the high purity boiler feed water required
by modern boilers is a function of the purity of the source
water. It is possible to use saline water for cooling
purposes, but it cannot be used in a boiler. Preparation of
boiler feed from saline water by evaporation or reverse
osmosis is generally quite expensive. The availability of
large quantities of cooling water has traditionally affected
the decisions made regarding plant location. In areas where
water is critically short, recirculation of cooling water
using cooling towers or ponds has been widely practiced.
This subject is discussed in detail in subsequent sections
of this report.
Plant location may also be influenced by energy transporta-
tion costs. The cost of transmission of energy as
electricity must be weighed against the cost of transporting
fuel. Generally, fuel availability and economic factors
will be the major considerations regarding the relationship
between fuel and plant siting.
The trend in siting of generating plants using open-cycle
cooling is toward locations on oceans, estuaries and lakes.
90
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Of the plants installed near 1960, approximately 80% are on
rivers, 10% on lakes, 10% on estuaries and 2% used municipal
water. For the plants installed in the 1970's,
approximately 50-6OX are on rivers, 20-30% on lakes, 15% on
estuaries, 2% on municipal water and 2% on oceans.
The methods used to control atmospheric pollution by stack
gases vary. With plants burning solid fuel, a particulate
emission problem may exist. The usual control system is the
electrostatic precipitator. Finely divided solid particles
suspended in a gas stream will accept an electrostatic
charge when they pass through an electrical field. If they
are then passed between two oppositely charged plates, they
are attracted to one of the plates, depending on the
polarity of the charges. On the plates they agglomerate and
may be removed by rapping the plates. This operation is
usually carried out at temperatures between 121° and 177°C
(250-350°F). Finely divided solids may also be removed from
the vent gases by using bag filters or by intimately
contacting them with water in a venturi scrubber or similiar
device.
Sulfur dioxide in stack gases can present another air
pollution problem. This, of course, is most easily
controlled by firing low sulfur fuel, which is not always
readily available. Many alternatives have been proposed to
remove the SQ2, and several are being used on a commercial
scale. Most involve neutralization of the acid SO2 with
alkaline materials such as soda ash, lime, limestone,
magnesia or dolomite, and ammonia. The processes developed
to date consist of both once-through and recycle systems. A
detailed analysis of air pollution control systems which
produce a liquid waste stream is presented in another
section of this report.
Categorization
The Act requires, for the purposes of assessment of the best
practicable control technology currently available, that the
toal cost of application of technology in relation to the
effluent reduction benefits to be achieved from such
application be considered. Other factors to be considered
are the age of equipment and facilities involved, the
process employed, the engineering aspects of the application
of various types of control techniques, process changes,
nonwater quality environmental impact (including energy
requirements) and other factors as deemed appropriate. For
best available technology economically achievable the Act
substitutes "cost of achieving such effluent reduction" for
91
-------
'•total cost ... in relation to effluent reduction
benefits...11 For new source standards which reflect the
greatest degree of effluent reduction achievable through the
application of the best available demonstrated control
technology, processes, operating. methods, or other
alternatives, the Act requires only the consideration of the
cost of achieving such effluent reduction and any nonwater
quality environmental impact and energy requirements.
There are two radically different types of waste produced by
steam electric powerplants. The first type consists of the
essentially chemical wastes which originate from different
processes and operations within a plant. These wastes are
highly variable from plant to plant, depending on fuel, raw
water quality, processes used in the plant and other
factors. Some waste streams are not directly related to in-
dividual generating units but result from auxiliary process
systems such as water treatment, ash disposal, housekeeping
operations, and air pollution control. However, all of
these waste streams are at least in a qualitive way
comparable to waste streams produced by other manufacturing
operations.
The second type of waste consists of the waste heat produced
by the plant and disposed to the environment through the
cooling water system. As previously indicated, waste heat
is an integral part of the process of producing electric
energy. As long as electric energy is produced by the use
of thermal energy from fuels to produce steam, waste heat
will be produced, and will ultimately have to be dissipated
to the environment. Under present day technology, the
atmosphere is the final recipient for this heat, but water
is generally used as an intermediate recipient. The choices
available in the control of thermal discharges therefore in
most cases are limited to accelerating the transfer of the
waste heat from water to the atmosphere. There is no
available means of significantly reducing the waste heat
itself.
Furthermore, while the technology for affecting this trans-
fer is available, its application is dependent on many fac-
tors not directly associated with the production process.
The effectiveness of heat transfer devices is to some degree
governed by atmospheric conditions. The achievement of any
specific level of reduction does not follow the type of cost
- effectiveness curve associated with the removal of more
conventional pollutions.
The basic categorization in this report therefore is to
separate consideration of the chemical wastes from the ef-
92
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fects of thermal discharges. Within the chemical waste
category, each plant is considered as a whole and sub-
elements have been established according to the type of
wastes produced by each plant. In the consideration of
thermal discharges, each generating unit is considered
separately.
Chemical Wastes
The origin and character of chemical wastes within a power-
plant is dependent upon the factors indicated above. Plants
utilizing different fuels will produce different wastes to
the degree that certain waste streams are completely absent
in plants employing one type of fuel. Coal pile runoff is
not a problem in oil-fired plants, and similarly ash
sluicing is not necessary in gas-fired plants. Nuclear
plants have closed waste systems to contain any waste which
is, or may be, radioactive. These wastes are handled in a
manner prescribed by the Atomic Energy Commission, and are
not relevant to the categorization of the industry for the
purposes of this project. As a result, many of the waste
streams present in fossil-fired plants are not normally
present, or of concern in a nuclear plant.
Another factor, such as raw water quality, will determine
the type of water treatment employed within a specific
plant, and in turn the wastes produced from water treatment
processes. Although these wastes are extremely variable,
depending upon the treatment employed (clarification,
softening, ion exchange, evaporation, etc.), they are wastes
which are common to all powerplants regardless of fuel or
other factors. Other waste streams depend upon the specific
characteristics of the particular plant in question.
As a result, the industry has been categorized for chemical
waste characteristics by individual waste sources. The
basis of evaluation of plants in the industry will be a
combination of the appropriate waste sources for a
particular powerplant. Guidelines will be established for
each waste source, and can then be applied and utilized in
the manner of a building-block concept. Waste streams may
be combined, and in many cases this would have obvious
advantages, and the appropriate guidelines would then also
be combined for application to the new waste stream.
Subcategories have been based on distinguishing factors
within groups of plants. Table IV-5 provides the informal
categorization for the purposes of the development of
effluent limitations guidelines and standards for chemical
wastes, and Table IV-6 shows the applicability of the
93
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TABLi IV-5
CHKi'ilCAL WASTE CATEGORIES
I. Condenser Cooling System
A. Once-through
B. Recirculat irig
II. Water Treatment
A. Clarification
B. Softening
C. Ion Exchange
D. Evaporator
E. Filtration
F. Other Treatment
ILL Boiler or PWR. Steam Generator
A. Slowdown
IV. Maintenance Cleaning
A. Boiler or PWR Steam Generator Tubes
B. Boiler Fireside
C. Air Preheater
D. Misc. Small Equipment
E. Stack
F. Cooling Tower Basin
V. Ash Handling
A. Oil-Fired Plants
1. fly ash
2. bottom ash
3. Coal-Fired Plants
1. fly ash
2. bottom ash
VI. Drainage
A. Coal Pile
B. Contaminated Floor and Yard Drains
VII. Air Pollution Control Devices
A. SO 2 Removal
VIII. Miscellaneous waste ."Streams
A. Sanitary Wastes
B. Plant Laboratory and Sampling Systems
C. Intake screen Backwash
D. Closed Cooling Water Systems
E. Low-Level Had Wastes
F. Construction Activity
94
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TABLE IV-6
APPLICABILITY OF CHEMICAL WASTE CATEGORIES
BY TYPE OF FUEL
Process_or_Oggration
I. Condenser Cooling System
A. Once-through
B. Recirculating
II. Water Treatment
A. Clarification
B. Softening
C. Ion Exchange
D. Evaporator
E. Filtration
F. Other Treatment
III. Boiler or Generator Slowdown
IV. Maintenance Cleaning
A. Boiler or Generator Tabes
B. Boiler Fireside
C. Air Preheater
D. Misc. Small Equipment
E. Stack
F. Cooling Tower Basin
V. Ash
A. Bottom Ash
B. Fly Ash
VI. Drainage
A. Coal Pile
B. Floor and Yard Drains
VII. Air Pollution (SO^) Control Devices
Nuclear Coal Oil Gas
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X'
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
VIII. Miscellaneous
A. Sanitary Wastes
B. Plant Laboratory and
Sampling Streams
C. Intake Screen Backwash
D. Closed Cooling Water Systems
E. Low-Level Rad Wastes
F. Construction Activity
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
95
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categories to plants utilizing the four basic fuels for
producing electricity.
Thermal Discharges
The most obvious factor influencing the rejection of waste
heat to navigable waterbodies is the type of condenser cool-
ing system utilized within a plant. Powerplants which re-
cycle cooling water through a cooling device only affect the
receiving water by way of the relatively small blowdown
stream from the cooling tower, pond, etc. On the other
hand, plants operating with once-through cooling systems are
primarily responsible for the discharge of waste heat to
receiving waters. Consequently, the basic subcategorization
for thermal discharge characteristics divides the generating
units by type of cooling system utilized, into plants having
recirculating cooling systems, or once-through cooling
systems.
As indicated above, the primary factor in consideration of
waste heat rejection is the generating unit in question.
Therefore, subcategorization of once-through cooling systems
has been made on a unit, rather than a plant basis. The
evaluation of generating units to further sub-divide the
industry considered in detail the various factors described
in this section of the report; namely, fuel, size, age, and
site characteristics and mode of operation utilized. The
evaluation of these factors will be described below to
provide the rationale for the subcategorization developed.
The consideration of fuel as a factor in waste heat
rejection from a powerplant essentially focuses on the
differences between present nuclear and fossil-fueled units.
In general, the inherent characteristics of a light water
nuclear unit make it less efficient than fossil-fired units.
This difference in efficiency results in the rejection of
more waste heat to receiving waters from nuclear units than
from comparable fossil units. Subsequent sections of the
report will discuss the technical factors which cause this
difference.
Nuclear units generally have basic similarities with regard
to age, size, location and utilization which also tend to
differentiate them from fossil-fueled units. Nuclear units
can be generally classified as being relatively new,
relatively large, located in rural or semi-rural areas, and
operated as base-load facilities.
These factors are extremely variable when applied to
fossil-fueled units on a broad basis. Also, the thermal
96
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waste characteristics of units burning different fossil
fuels indicate that there is no basis for distinguishing
between fossil fuels for the thermal categorization of the
industry. Consequently, the basic subcategorization of
once-through cooling systems divides the industry between
nuclear and fossil-fueled units.
A major factor of concern with regard to fossil-fueled
generating facilities is the utilization of individual
units. An earlier portion of this section of the report
described the relationship of this factor with age and with
efficiency or heat rate of a generating unit. In addition
to this aspect of utilization, another point of concern is
the relationship between utilization and the cost of
installing facilities to treat waste heat. Utilization is
significant in economic analysis, as it provides the
operating time against which capital costs may be applied.
Furthermore, utilization reflects the effluent heat
reduction benefit to be achieved by the application of
control technology. As defined earlier, the utilization
aspect of power generation is defined by peaking, cycling
and base load generating facilities. Peaking units are
defined as facilities which have annual capacity factors
less than 0.20, while cycling units have annual capacity
factors between 0.20 and 0.60 and base-load units have
annual capacity factors in excess of 0.60.
Some difficulty could be encountered, for the purpose of
effluent limitations, in determining the level of
utilization that a generating unit will achieve in the years
to come. It is known, however, that all of the nuclear
steam-electric generating units and all of the
high-pressure, high-temperature, fossil-fueled units 500
megawatts (Mw) and larger have been designed as base-load
units. Almost all nuclear units are 500 Mw and larger.
All of these units presently operating were placed into
service since 1960 (excepting only one small nuclear unit
initially operated in 1957). The units placed in service
during the 1960*s had 15 or more years of base-load service
ahead of them as of 1970, and would thus have 8 or more
years of base-load life as of 1977.
A further difficulty that could be . encountered in
determining the level of utilization of a generating unit
relates to the fact that the only official record of the
utilization of individual generating units is the Form 67
"Steam-Electric Plant Air and Water Quality Control Data",
which must be filed annually with the Federal Power
Commission. Utilities are required to report the capacity
97
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and average annual capacity factor (level of utilization)
for each boiler, but not the turbine-generator.
Furthermore, prior to 1950, individual boilers were kept
small, in large part because boiler outages were rather
numerous, so that it was common design practice to provide
multiple boilers and steam header systems to supply a
turbine-generator. Some stations have the headers connected
to multiple turbine-generators. Hence, the problem could
arise in these cases as to what comprises a generating unit
(boiler(s) plus turbine-generator) and what is its level of
utilization. Furthermore, the problem of applying a
closed-loop cooling system could be more difficult where
multiple boilers supply single or multiple
turbine-generators due to the physical and operating
problems arising from the multiple connections involved.
However, advances in metal technology since 1950, with
associated lower costs of larger units, have made it
economical and reliable to have one boiler per
turbine-generator. The trend to the larger, one boiler per
turbine-generator units began to be significant when the
first 300 Mw unit was placed into service in 1955. From
1930 until that time the largest steam electric unit in the
U.S. was about 200 Mw. Hence, for units 300 Mw and larger,
the unit itself and its level of utilization are clearly
defined and the physical and operating problems associated
with a closed-loop cooling system and arising from the
multiple connections involved are not encountered.
Age was identified in the Act as a factor to be taken into
account in the establishment of effluent limitation
guidelines and performance standards. As indicated above,
the interrelationship between age, utilization and
efficiency, has generally been well documented in the steam
electric generating industry. Age is also important because
the remaining life of equipment provides the basis for the
economic write-off of capital investment. Consequently, age
is of significance in subcategorizing steam electric
generating units not only for technical reasons, but also
for economic considerations.
Federal Power Commission depreciation practices indicate the
estimated average service life of equipment for steam elec-
electric production to be 36 years •*. Figure IV-10, which
shows the improvement of efficiency in the generation of
electricity since 1920, indicates a sudden dip in the curve
in approximately 1949, or 24 years ago. Based on this
process factor and the anticipated service life of
equipment, it was decided, for the purposes of the cost
analysis, to segment fossil-fueled units by age, with 6
98
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(six-year) segments defining the range of age with regard to
generating units.
Site characteristics were considered as a possibility for
subcategorization of the industry for thermal discharges.
The basic consideration involving location related to the
situation of a plant with regard to its cooling water source
(ocean, river, estuary, lake, etc.). However, categoriza-
tion along these lines would in reality violate the intent
of the Act, which stresses national uniformity of
application and is technology oriented. The control and
treatment of waste heat is essentially an internal matter
within a powerplant. Absolute location will influence the
cost of such control and treatment, but will not generally
determine its feasibility. This type of location factor is
primarily related to environmental considerations, which are
taken into account under Sections 303 and 316 of the Act.
Consequently, it was decided not to establish any
subcategories for thermal waste characteristics based on
location.
Size was another factor which conceivably could form the
basis for thermal waste subcategorization of the steam
electric powerplant industry. Among those technical and
economic factors considered relative to the size of a unit
were availability and degree of practicability of control
and treatment technology, unit costs of control and
treatment technology and their relation to other generating
costs, and system reliability. A basis for a size
subcategorization would be the precedent established by the
Federal Power Commission with regard to the requirements for
filing Form 67, "Steam Electric Plant Air and Water Quality
Control Data". The FPC does not require filing of this form
by powerpiants smaller than 25 megawatts, or plants larger
than 25 megawatts which do not belong to a utility system
with a capacity equal to, or greater than 150 megawatts.
Consequently, the data available from this source would not
cover the numerous small generating plants under 25
megawatts.
As a result of evaluation of the factors outlined above,
informal segmentation for the purposes of the development of
effluent limitations guidelines and standards for heat
includes a division between nuclear and fossil units and
further division of fossil units based on utilization, all
followed by age considerations, and finally segmentation by
size of unit as defined by cost and other considerations.
99
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Summary
In summary, the most significant of the basic components of
all steam electric powerplants which relate to waste water
characteristics are the fuel storage and handling
facilities, water treatment equipment, boiler, condenser,
type of cooling system, and auxiliary facilities. Steam
electric powerplants (plants) are comprised of one or more
generating units. A generating unit consists of a discrete
boiler, turbine-generator and condenser system. Fuel
storage and handling facilities, water treatment equipment,
electrical transmission facilities, and auxiliary components
may be a part of a discrete generating unit or may service
more than one generating unit. The characteristic quantity
and intensity of the waste heat transferred in the condenser
from the expended steam to the cooling water is related to
the combined characteristics of the plant components that
are its source.
The general subcategorization rationale is summarized in
Table IV-7 the subcategorization rationale for heat is
summarized in Table IV-8 and the subcategorization rationale
for pollutants other than heat is summarized in Table IV-9.
The degree of nonthermal effluent reductions that can be
achieved by the application of specific control and treat-
ment technologies are related to the type of source
components involved, and further to water use and quality
and other considerations peculiar to individual plants.
Both unit and plant related characteristics affect the
degree of practicability of applying nonthermal waste water
control and treatment technology.
Accordingly, the general categorization scheme developed was
approached from the basis that separate subcategorizations
would be constructed for thermal characteristics and for
nonthermal characteristics so that the rationale supporting
the one would not necessarily be supportive of the other,
and candidate approaches to either could be utilized or
discarded on their own merits. Numerous factors were
considered as candidates for further subcategorization and
are as follows: the age of equipment and facilities, the
process employed, waste source (nonthermal characteristics),
nonwater quality environmental impact (including energy
requirements), site characteristics, size of plant, type, of
thermal control employed, fuel utilized, and utilization
characteristics of the plant, with only the age of unit, its
utilization,, its generating capacity (size) and type of
thermal control employed qualifying as further bases for
subcategorization of thermal discharges, and waste source
for nonthermal discharges. Many of the above factors are
TOO
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Table IV-7
GENERAL SUBCATEGORIZATION RATIONALE
Subcategorization for heat, is approached separately
from Subcategorization for other pollutants because:
• Control and treatment technology for heat relate
primarily to the characteristics of generating units,
while nonthermal control and treatment technologies
relate primarily to characteristics of stations.
• Control and treatment technologies are dissimilar; and
• The costs of thermal control and treatment technology
are much greater than nonthermal control and treatment
technologies.
-------
Table IV- 8
SUBCATEGORIZATION RATIONALE FOR POLLUTANTS OTHER THAN HEAT
Characteristic
of Plant
Need for Sub-
categorization
Rationale
o
ro
Utilization (base—load,
cyclic, or peaking)
Age
Fuel
Size
Land Availability
Water Consumption
Non-Water Quality Envir-
onmental Impact (inclu-
ding energy consumption)
Process Employed
No
No
Yes
No
No
No
No
No
Yes
Climate
No
Costs versus effluent reduction benefits
vary significantly but are small in all cases
Costs versus effluent reduction benefits
vary significantly but are small in all cases
Certain technologies are practicable for new
sources but not for others
Effects on costs versus effluent reduction
benefits are not significant
Costs versus effluent reduction benefits are
greater for small plants but still
relatively small
Treatment technology includes small-sized
configured equipment as well as lagoon-type
facilities
Negligible consumption
Not significant
Practicability of treatment technology
is related to the volumes of waste water
treated, therefore subcategories should
be based on the specific waste water streams,
especially those of significant volume
Not significant except for effect on rainfall
runoff treatment costs, but costs versus
effluent reduction benefits are approximately
the same and costs are relatively small
-------
Table IV-9
SUBCATEGORIZATION RATIONALE FOR HEAT
Characteristic of Unit
Need for
Subcategorization
Rationale
o
GO
Utilization(Base-load,
cyclic, or peaking)
Age
Fuel
Size
Yes
Yes
Yes
Yes
Process Employed
Land Availability
Water Consumption
Climate
Non-Water Quality
Environmental Impacts
•Saltwater Drift
•Fogging
•Noise
•Aesthetics
No
Yes
No
No
Yes
No
NO
No
Coupled with age, this factor determines the
incremental cost of production versus the effluent
reduction benefits related to the thermal control
technology.
Coupled with utilization, this factor determines
the incremental cost of production versus the
effluent reduction benefits related to the thermal
control technology.
Nuclear-fueled units reject significantly more
heat to cooling water than do comparible
fossil-fueled units.
Retrofit outages in small plants (typically older
peaking plants) and small systems would be more
likely to cause reliability problems. Size may
affect retrofit costs. Size is generally
related to age and utilization. Counterbalancing
of cost variations is not as likely for small
plants and systems.
All significant differences already accounted
for by factors of utilization, age, fuel, and size.
Numerous units, due to urban locations, have
insufficient land available to implement the
control technology.
Where required water consumption rights can add an
incremental but insignificant cost over the cost
of water use rights otherwise required.
Variabilities are primarily cost related and
taken into account in the cost analysis
While technology is available to limit drift
to very low levels, significant impacts could
occur for units in urban areas on saltwater
bodies.
Technology is available to abate fogging in
the few cases where it might otherwise have
a significant impact.
Technology is available to abate noise in
the few cases where it might otherwise have
a significant impact.
Would only be a problem in a case-by-case
evaluation of alternatives.
-------
related as previously discussed. A further example is the
relation between age of generating units and their capacity
factor, as shown in Table IV-10.
Certain further factors can be identified each of which are
not sufficiently significant to warrant their inclusion in
the general subcategorization framework but which will be
examined in detail in subsequent sections of this document.
Some of these factors are the following: available land
characteristics, size of the unit, accessibility of existing
cooling system, ability of existing structures to
accommodate a new recirculating cooling system, requirements
imposed by nearby land uses (drift, fogging, noise,
structure height), climatic considerations (wind, relative
humidity), soil strengths, significance of consumptive use
of water, main condenser cooling water flow rate, unit heat
rate, wet-bulb temperature, back-end loading, cooling tower
plume abatement, noise abatement, aircraft safety, system
reliability requirements, and characteristics of intake
water (temperature, concentrations of constituents).
104
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Table IV-10
DISTRIBUTION OF U.S. GENERATING CAPACITY BY AGE AND CAPACITY FACTOR*
Year Installed
Before 1956
1956-1960
.1961-1971
1972-1978
Capacity Factor
0 - 0.2
11,000 Mw
2,000
1,000
0
0.2 - 0.4
7,000 Mw
5,000
10,000
0
0.4 - 0.6
13,000 Mw
15,000
36,000
8,000
0.6 +
20,000 Mw
10,000
36,000
81,000
o
en
* Source: FPC data
-------
PART A
CHEMICAL WASTES
SECTION V
WASTE CHARACTERIZATION
Introduction
In this part of the study (Part A) only the nonthermal, or
chemical wastes are dealt with. Part B of the report deals
with thermal discharges.
Chemical wastes produced by a steam electric powerplant can
result from a number of operations at the site. Some wastes
are discharged more or less continuously as long as the
plant is operating. Some wastes are produced inter-
mittently, but on a fairly regularly scheduled basis such as
daily or weekly, but which are still associated with the
production of electrical energy. Other wastes are also
produced intermittently, but at less frequent intervals and
are generally associated with either the shutdown or startup
of a boiler or generating unit. Additional wastes exist
that are essentially unrelated to production but depend on
meteorological or other factors.
Waste waters are produced relatively continously from the
following sources (where applicable): cooling water
systems, ash handling systems, wet-scrubber air pollution
control systems, boiler blowdown.
Waste water is produced intermittently, on a regular basis,
by water treatment operations which utilize a cleaning or
regenerative step as part of their cycle (ion exchange,
filtration, clarification, evaporation).
Waste water produced by the maintenance cleaning of major
units of equipment on a scheduled basis either during
maintenance shutdown or during startup of a new unit may
result from boiler cleaning (water side), boiler cleaning
(fire side), air preheater cleaning, stack cleaning, cooling
tower basin cleaning and cleaning of miscellaneous small
equipment. The efficiency of a powerplant depends largely
on the cleanliness of its heat transfer surfaces. Internal
cleaning of this equipment is usually done by chemical
means, and requires strong chemicals to remove deposits
formed on these surfaces. Actually the cleaning is not
successful unless the surfaces are cleaned to bare metal.
107
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and this means in turn that some metal has to be dissolved
in the cleaning solution. Cleaning of other facilities is
accomplished by use of a water jet only.
Rainfall runoff results in drainage from coal piles, floor
and yard drains, and from construction activity.
A diagram indicating sources of chemical wastes in a fossil-
fueled steam electric powerplant is shown in Figure A-V-1.
A simplified flow diagram for a nuclear plant is shown in
Figure A-V-2. Heat input to the boiler comes from the fuel.
Recycled condensate water, with some .pretreated make-up
water, is supplied to the boiler for producing steam. Make-
up requirements depend upon boiler operations such as
blowdown, steam soot blowing and steam losses. The quality
of this make-up water is dependant upon raw water quality
and boiler operating pressure. For example, in boilers
where operating pressure is below 2.8 MN/sq m (400 psi),
good quality municipal water may be used without
pretreatment. On the other hand, modern high-pressure,
high-temperature boilers need a controlled high-quality
water. The water treatment includes such operations as
lime-soda softening, clarification, ion exchange, etc.
These water treatment operations produce chemical wastes.
According to the FPC23*, the principal chemical additives
reported for boiler water treatment are phosphate, caustic
soda, lime and alum.
As a result of evaporation, there is a build-up of total
dissolved solids (TDS) in the boiler water. To maintain TDS
below allowable limits for bciler operation, a controlled
amount of boiler water is sometimes bled off (boiler
blowdown) .
The steam produced in the boiler is expanded in the turbine
generator to produce electricity. The spent steam proceeds
to a condenser where the heat of vaporization of the steam
is transferred to the condenser cooling system. The
condensed steam (condensate) is recycled to the boiler after
pretreatment (condensate polishing) if necessary, depending
upon water quality requirements for the boiler. As a result
of condensate polishing (filtration and ion exchange), waste
water streams are created.
In a nonrecirculating (once-through) condenser cooling
system, warm water is discharged without recycle after
cooling. The cool water withdrawn from an ocean, lake,
river, estuary or groundwater source may generate biological
growth and accumulation in the condenser thereby reducing
its efficiency. Chlorine is usually added to once-through
108
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EAW WATSfe
S
TYPICAL PLOW DIAGRAM - STEAM ELECTRIC POWER PLANT (POSSILp-FUELED)
SOURCES OF CHEMICAL riASTES
FIGURE A-V-1
-------
RECENERANT
CHEMICALS
DEMORALIZED
700 GPM
10,000-14. HOC CPM
MAKE-UP
SYSTEM
no GPM
6GPM
440 GPM
,
0
RAW WATER
OEMINERA'JZER
SANITARY
SYSTEMS
PLANT RAW
SERVICE
WATER SYSTEM
MINERALIZES
WATER
REGENERA
AND
SECONDARY
SYSTEMS
NT WASTE
blU(A(jt MIJX
CO
- — UtM
SEWAGE
TREATMENT
i_
NOENSATE
NERAHZERS
REGENERAM
l WASTE
Ul REGENERAM
1 HOLDUP UNK
1 1
fr.ni iwr.
*-
•
NEUIRtLlZATION
CHEMICALS
RECENERAta
CHEMICALS
CONDE\SATE
STORAGE
TA,\K
/oo-iooncpM
1
'
ulLUTIO's
0000-11.400 GPM
0-32 00 GPM
SUMP
» ATMOSPHERE
Figure A-V- 2
SIMPLIFIED WATER SYSTEM FLOW DIAGRAM FOR A NUCLEAR UNIT
108r
-------
condenser cooling systems -to minimize this fouling of heat
transfer surfaces. Chlorine is therefore a parameter which
must be considered for nonrecirculating cooling water
systems.
Cooling devices such as cooling towers are employed in the
recirculating cooling systems. Bleed streams (blowdown)
must generally be provided to control the build-up of
certain dissolved solids or total dissolved solids within
the recirculating evaporative cooling systems. These
streams may also contain chlorine and other chemical
additives. According to the FPC23*, the principal chemical
additives reported for cooling water treatment are
phosphate, lime, alum and chlorine.
As a result of fossil-fuel combustion in the boiler, flue
*jases are produced which are vented to the atmosphere.
Depending upon the type of fossil fuel, the flue gases carry
certain amounts of entrained particulate matter (fly ash)
which are removed in mechanical dust collectors,
electrostatic precipitators or wet scrubbing or collector
devices. Thus fly ash removal may create another waste
water stream in a powerplant.
A portion of the noncombustible matter of the fuel is left
in the boiler. This bottom ash is usually transported as a
slurry in a water sluicing operation. This ash handling
operation presents another possible source of waste water
within a powerplant.
Depending upon the sulfur content of the fossil fuel, SO2
scrubbing may be carried out to remove sulfur emissions in
the flue gases. Such operations generally create liquid
waste streams. Note that SO2 scrubbing is not required for
gas-fired plants, or facilities burning oil with a low
sulfur content. Nuclear plants, of course, have no ash or
flue gas scrubbing waste streams.
As a result of combustion processes in the boiler, residue
accumulates on the boiler sections and air preheater. To
maintain efficient heat transfer rates, these accumulated
residues are removed by washing with water. The resulting
wastes represent periodic (intermittent) waste streams.
In spite of the high quality water used in boilers, there is
a build-up of scale and corrosion products on the heat
transfer surfaces over a period of time. This build-up is
usually due to condenser leaks, oxygen leaks into the water
and occasional erosion of metallic parts by boiler water.
Periodically, this scale build-up is removed by cleaning the
111
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boiler tubes with different chemicals - such as acids,
alkali, and chelating compounds. These cleaning wastes,
though occuring only periodically, contain metalic species
such as copper, iron, etc. which may require treatment prior
to discharge.
The build-up of scale in cooling tower basins and soot
build-up in stacks require periodic washings and these
operations also give rise to waste streams.
For coal-fired generating units, outside storage of coal at
or near the site is necessary to assure continuous plant
operation. Normally, a supply of 90 days is maintained.
Coal is stored either in "active" piles or "storage" piles.
As coal storage piles are normally open, contact of coal
with air and moisture results in oxidation of metal
sulfides, present in the coal, to sulfuric acid. The pre-
cipitate trickles or seeps through the coal. When rain
falls on these piles, the acid is washed out and eventually
winds up in coal pile runoff, creating another waste stream.
Similarly, contaminated floor and yard drains are another
source of pollution within the powerplant.
Besides these major waste streams, there are other miscel-
laneous waste streams in a powerplant such as sanitary
wastes, laboratory and sampling wastes, etc. which are also
shown in Figure No. A-V-1.
In a nuclear-fueled powerplant, high quality water is used
in the steam generating section. Conventional water
treatment operations give rise to chemical waste streams
similar to those in fossil-fueled powerplants. Similarly,
the cooling tower blowdown is another waste stream common to
both fossil-fueled and nuclear fueled powerplants. Some
wastes in a nuclear plant contain radioactive material. The
discharge of such wastes is strictly controlled and is
beyond the scope of this project. However, the steam
generator in a PWR plant is a secondary system, having a
blowdown and periodic cleaning wastes which are not
radioactive. Some of the disposal problems associated with
low-level radiation wastes from nuclear fuel powerplants are
briefly described in this report.
Data was accumulated from different sources to characterize
the various chemical wastes described above. The sources of
data include:
a. Plants visits and collection of samples for analysis
112
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b. Permit applications submitted by powerplants to the U.S.
Army Corps of Engineers.
c. Tennessee Valley Authority (TVA) reports of operating
plants
d. EPA Region II - questionnaire
e. EPA Region V - summary of permit applications data by
National Environmental Research Center, Corvallis
f. Southwest Energy Study - Appendices
g. U.S. Atomic Energy Commission, Environmental Impact
Statements
h. In-house data at Burns and Roe, Inc.
These data were included in Appendix 2 of the Development
Document supporting the proposed effluent limitations
guidelines and standards for steam electric powerplants,
which was issued in March, 1974. A code system was used for
individual plant identification.
Based on these data and other industrial and governmental
literature, recommended effluent limitations guidelines
proposed are developed for chemical wastes from the
following operations in steam electric powerplants.
I. Condenser Cooling System
A. Once-Through
B. Recirculating
II. Water Treatment
A. Clarification
B. Softening
C. Ion Exchange
D. Evaporator
E. Filtration
F. Other Treatment
III. Boiler or PWR Steam Generator Slowdown
IV. Maintenance Cleaning
A. Boiler or PWR Steam Generator Tubes
B. Boiler Fireside
C. Air Preheater
D. Misc. Small Equipment
E. Stack
F. Cooling Tower Basin
113
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V. Ash Handling
A. Oil-Fired Plants Fly Ash
B. Coal-Fired Plants
1. fly ash
2. bottom ash
VI. Rainfall Runoff
A. Materials Storage (Coal Pile)
B. Construction Activity
VII. Air Pollution Control Devices
VIII. Miscellaneous Waste Streams
A. Sanitary Wastes
B. Plant Laboratory and Sampling Streams
C. Intake Screen Backwash
D. Closed Cooling water Systems
E. Low-Level Rad Wastes
F. Floor Drains
G. Others
Once-Through Cooling Systems
The common biocides used are chlorine or hypochlorites. The
amount of chlorine dosage varies from site to site and
depends upon the source of cooling water and ambient
conditions. For example, in winter the biological growth is
normally not as pronounced as in spring or summer.
Consequently, chlorine demand is less in winter. Normally,
the chlorine is supplied as a slug rather than by continuous
injection. The frequency of chlorine dosage differs in each
plant, and may vary from once a day to ten times a day.
Treatment duration varies between 5 minutes and 2 hours.
Chlorination results in residual chlorine concentrations in
the range of 0.1 to 1 mg/1 (ppm). Higher concentrations can
be found in cases where higher level organisms, such as
jellyfish, or eels, tend to accumulate on condenser
surfaces.
Since the waste characteristics of once-through cooling
systems designed for economical operation and the control
technology for the reduction of the discharge of pollutants
from this source reflect in many instances the same or
similar technologies, these aspects are discussed in more
detail in Section A-VII of the Development Document.
114
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Recirculating Cooling Systems
In the operation of a closed, evaporative cooling system,
the bulk of the warm circulating water returning to the
cooling tower, pond, etc. is cooled by the evaporation of a
small fraction of it. During this evaporation only water
vapor is lost, except for leakage and some net entrainment
of droplets in the air draft (drift loss), and the salts
dissolved in the remaining liquid become more concentrated.
Most natural waters contain calcium (Ca-H-) , magnesium
(Mg-f-f) , sodium (Na+), and other metallic ions, and carbonate
(CO3—), bicarbonate (HCO3-), sulfate (SO4—), chloride
(C1-) and other acidic ions~in solution. All combinations
of these ions are possible. When the concentration of ions
in any possible combination exceeds the solubility limits
under the existing conditions, the corresponding salt will
precipitate, some of these salts are characterized by
reverse solubility, that is, their solubility decreases when
the temperature rises. If water saturated with such a salt
leaves the cooling tower at the cool water temperature, as
the water is heated in passing thru the condenser the
solubility will decrease and the salt will deposit as a
scale on the condenser tube walls and hinder heat transfer
thru the tubes.
According to Reference 141, the formation of scale may be
controlled in several ways. The most common is to blowdown
a portion of the circulating water stream and replace that
quantity with fresh water so that the circulating water does
not reach saturation at any time. Blowdown therefore is the
constant or intermittent discharge of a small portion of the
circulating water in a closed cooling system to prevent a
buildup of high concentrations of dissolved solids. The
blowdown (B) is a function of the available makeup (B+D+Ev)
water quality and is related to evaporation (Ev) and drift
(D) in the following manner:
C = (B + Ev + D)/(B + D)
In this equation, C equals cycles of concentration, a
dimensionless number which expresses the number of times the
concentration of any constituent is multiplied from its
original value in the makeup water. (It does not represent
the number of passes through the system). B, Ev, and D are
expressed in consistent units (e.g. percent of circulating
water flow rate or actual flow rate).
For average makeup water quality, conventional practice sets
the value of C between U and 6. For extremely high quality
makeup water (or-treated water) C values of 15 and above are
possible. For salt or saline water, C values as low as 1.2
to 1.5 may be required. This is usually not a materials or
115
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operating limit, but rather a means of preventing biological
damage from blowdcwn salinity.
The chemical characteristics of the recirculating water
(treated or untreated) determine the maximum C value. Table
A-V-1 provides some "rules of thumb" to be used in
establishing the maximum C value. Note that the C subscript
designations used in the table represent individual
constituent concentrations and should not be confused with
C, cycles of concentration used above.
The "Limitation" column in Table A-V-1 indicates the maximum
value allowed in the recirculating water for each chemical
characteristic given. The maximum C value would be
established when any one of the "Limitations" is exceeded.
Note that this table provides "rule of thumb" estimates,
which may not be applicable to unique water quality
problems.
The equation for C can be rewritten for blowdown (B):
B * Ev-D(C-1)
C - 1
In order to minimize the total amount of makeup water and
blowdown the cooling tower should be operated at as high a C
value as possible. The following data were computed using
the above equation and illustrate the effect of C on the
blowdown and makeup flow rates:
C Blowdown Makeup
(cycles of concentration) (cf si (cfsi
1.2 107 128
1.5 42.8 64.2
2.0 21.4 42.8
5.0 5.3 26.7
10.0 2.3 23.7
20.0 1.1 22.5
This table was developed assuming an evaporation rate (Ev)
of 21.4 cfs and a drift rate (D) of 0.05 cfs (0.005* of 950
cf s) .
There are several advantages to maintaining a high C value:
a. Minimizing the makeup water requirement, thus
reducing the number of organisms entrained in the cooling
water.
116
-------
Table A-V-1
RECIRCULATING WATER.QUALITY LIMITATIONS
461
Characteristic
Limitation
Comment
pH and Hardness
pH and Hardness
with addition of
proprietory chemicals
for deposit control.
Sulfate and Calcium
Langelier Saturation
Index = 1.0
Langelier Saturation
Index = 2.5
Langelier Saturation
Index = pH-pHs
where
pH = measured pH
pHs = pH at saturation
with CaCO,
See Figure A-V-3 for
nomograph solution.
(CSQ ) x (CCa) = 500,000
p
= concentration of
S04 in mg/1
= concentration of
Ca in mg/1 as CaCO,
Silica
CSi0
= concentration of
Si02 in mg/1
Magnesium and Silica
x(CSi02} = 35'000
C.. = concentration of
Mg in mg/1 as CaC03
Suspended Solids
Css = 400 mg/1
C = concentration of
" ss in mg/1
117
-------
Figure A-V-3
228
NOMOGRAM TO DETERMINE LANGELIER SATURATION INDEX
Courtesy Power Engineering
P.l.=VrS PC3 ',"LL :0'-l
J; 3000
i-vooo
1
- 40
-'• 50
pALK AVO
pCoSCALE
-2000 4.0-
7.6-
-'000
t jt i \— 6U
— 800 2A | ~r
- 600 "1 I- 70
(- %&J"'C* zzJ{ •'•" 'r
'. • »* i» • t v* _J
.
300
Ml/
I ^1~
L I00 /^
L !~'~ \ J"'40
t 6o /.4 -A /.S-4--
r "c"jC4/^ i i
I M -\ t
£- 3O ~\ i 0 ;_
i no
Example: Water at 124 F has a pH
-' 7 ?. fr.fA! buii'-s ;.;f '100 ppm. C3|-
tium iiara'ness as CaCU.-, of 240 ppm,
and alkalinity as CaCO:; of 196 ppm.
Fiiiri rhe Langeiier saiurcjtion inde*..
ioiution: (i) join 400 ppm nn thp
ir>i'thand scale with 1 ?.'i F nn th.-. *sm.
C- .•• •.!•; liuie vsiiiP of i./. /v) j.^jj.
"•'0 f'Jirn with nr'a r^JorvrCC OCInt
and extend to pC;i scale. K-.cd pCd =
2.62. (3) Join 1S6. ppm with pALK
rc-ference point, extend to pALX scale
and read pALK = 2.40. Add the three
V3k;3s:
pHs=C + pCa + pALK=6.72
pH-pHs = 7.2-6.72=+0.48
118
-------
b. Minimizing the volume of biowdown water to be
discharged.
c. Reducing the size and cost of makeup and blowdown
handling facilities (i.e., pumps, pipes, screens, etc.).
Values for evaporation from cooling systems average about
0.75X of cooling water flow for every 10°F of condenser
delta T for cooling towers and approximately 50% higher for
cooling ponds. This is equivalent to a range of 15.0 to
30.0 gpm/Mw for cooling towers and 22.5 to 45.0 gpm/Mw for
cooling ponds. Drift constitutes a relatively small portion
of the required makeup water. For new cooling towers, drift
losses can be kept as low as 0.005% of the cooling water
flow for mechanical draft towers and 0.002X for natural
draft towers. Drift losses for ponds are negligible.
Estimates of the allowable blowdown flow based on these
factors can be made once the cooling water flow, condenser
delta T, and allowable concentration factors are known.
The heat content of the blowdown as a percent of condenser
heat rejection can be quite variable. The heat content of
the blowdown can vary from a fraction of 1% of the total
condenser heat rejection to as high as 7 to 8% of this
value. Higher rates of heat rejection in the blowdown are
due to larger blowdown flows (smaller C values) required in
salt water systems and systems that blowdown from the hot
side of the system. Systems that blowdown from the cold
side of the cooling system should contain no more than 1 to
2% of the condenser heat rejection.
Scale formation may be controlled by chemical means such as
softening or ion exchange to substitute more soluble ions
for the scale formers, such as Na+ substitution for Ca-H- and
Mg-H-. Advantage may be taken of the greater solubility of
some ions. For instance SOU— may be substituted for CO3—
or HCO3-, as: ~
Ca CO3 + H2 SOU = CaSOU + H2O + CO2 (g)
Mg(HCO3)2 * H2SO* = MqSOU +2H2O +2CO2(g)
In these reactions, CO2 is released as a gas. Sulfates have
a much greater solubility than carbonates and bicarbonates,
and scale formation is reduced. Organic "sequestering"
agents are used to tie up the insoluble metallic ions so
that they cannot combine with the carbonates and
bicarbonates to form scale. Many of these agents are
proprietary compounds and their compositions are not
generally known. The use of chemical dispersants and makeup
119
-------
water softening to reduce or eliminate blowdovm at certain
powerplants is discussed in Reference 22. Eventually the
limit is reached and there must be some bleed through drift
or blowdovm although its quantity may be greatly reduced,
resulting in higher concentrations. Data obtained from the
study of fifteen plants reveals an extremely large variation
in the parameters listed. Generally, the important
pollutant parameters are: total suspended solids (TSS), pH,
hardness, alkalinity, total dissolved solids and phosphorus.
In general, condenser materials are chosen so as to resist
corrosion by the recirculating water. Consequently,
chemicals are generally not required in the recirculating
water for corrosion resistance, except in cases where the
recirculating water (because of the make-up water quality)
has high chloride concentrations chromates or other
chemicals are added as corrosion inhibitors.
In recirculating systems, growth organisms such as algae,
fungi and slimes occur because of the warm and moist
environment. Such biological growth will affect condenser
efficiencies and chlorine is commonly used as a biocide.
The chlorine dosage is usually in slugs. The residual
chlorine is generally in the range of 1 mg/liter. Higher
residual chlorine concentrations may cause corrosion
problems. In cooling towers with wood filling, sodium
pentachlorophenate is sometimes added to inhibit fungi
attack on wood. The chemicals are generally added to the
cooling tower basin to ensure adequate mixing. Depending
upon the chlorine dosage frequency (one to three times a
day) and sodium salt addition, the concentration of these
pollutants in the blowdown will vary for each case.
Since the waste characteristics of recirculating cooling
systems designed for economical operation and the control
technology for the reduction of the discharge of pollutants
from this source reflect in many instances, the same or
similar technologies, these aspects are discussed in more
detail in Section A-VII of the Development Document.
Water Treatment
All water supplies contain varying amounts of suspended
solid matter and dissolved chemical salts. Table A-V-2
gives typical characteristics of powerplant water supplies.
Salts are dissolved from rock and mineral formations by
water as it flows into rivers and lakes. In the boiler, as
water evaporates to steam, mineral salts deposit on metal
surfaces as scale. Scale reduces transfer of heat through
the metal tubes, and if allowed to accumulate reduces the
120
-------
Table A-V-2
TYPICAL CHARACTERISTICnOF
POWERPLANT WATER SUPPLIES
Constituent
Calcium, as CaC00
Magnesium, as CaCO~
* *J
M Alkalinity, as CaC03
Sulfate, as S04
Chloride, as Cl
Silica, as StOp
Iron, as Fe
Manganese, as Mn
Oil
Suspended Solids
Concentrati
40 -
10 -
5 -
20 -
10 -
2 -
0.2 -
0.1 -
<1 -
10 -
pH 5.5 -
Specific Conductance, ymhos (18°C) 100 -
on (mg/1)
200
50
50
140
150
15
2.0
1.0
5.0
200
7.5
500
121
-------
flow area, eventually causing failure of the tubes. To
prevent scaling, water is treated for removal of mineral
salts before its use as boiler feed water.
Removal of the dissolved mineral salts can be accomplished
by evaporation, chemical precipitation or by ion exchange.
Evaporation produces a distilled-water-quality product but
is not always economical and results in a stream of brine
waste. Chemical precipitation is of limited use in the re-
moval of dissolved solids, as the product water of the
process contains soluble quantities of mineral salt. To
produce a boiler feed water, chemical precipitation followed
by evaporation is used occasionally, but cost is not always
economical.
Clarification
Chemical precipitates and naturally occurring suspended
solids are very fine and light. Clarification is a process
of agglomerating the solids and separating them from the
water by settling. Suspended solids are coagulated, made to
join together into larger, heavier particles and then
allowed to settle. Clarified water is drawn off and fil-
tered to remove the last traces of turbidity. Settled
solids, more commonly called sludge, are withdrawn from the
clarifier basin, continuously or intermittently and
discharged to waste. Figures A-V-4 and A-V-5 show
simplified flow diagrams for clarification and filtration
processes respectively. Surface water, in addition to
dissolved impurities, may contain suspended matter, causing
turbidity or objectionable color. Removal of turbidity by
coagulation is an electro-chemical phenomenon. Iron and
aluminum ions of positive charge form a bridge with the
negative charge of the sediments, causing an agglomeration
of the particles. Most commonly used coagulants are
aluminum sulfate (alum, filter alum, A12(SOU)3 . 18 H2O),
ferrous sulfate (copperas, FeSO.fl . 2 H2_O) , ferric sulfate
(ferrifloc, Fe2 (SOj»)3), and sodium aluminate (soda alum,
Na2 A12 OU). Polyelectrolytes and other coagulant aids are
frequently used in the process.
Softening
In the softening process, chemical precipitation is applied
to hardness and alkalinity. Principal chemicals used are
calcium hydroxide (hydrated lime - Ca (OH) 2) and sodium car-
bonate (soda ash-Na2CO3). Calcium is precipitated as cal-
cium carbonate (CaCO3) and magnesium as magnesium hydroxide
(Mg (OH) 2) .
122
-------
TREATMENT
CHEMICALS
RAW WATER
CLARIFIER
CLEAR WATER
SLUDGE
FIGURE A-V-4 CLARIFICATION PROCESS
RAW WATER
WASH
1
FILTER
WASTE
FILTERED
WATER
FIGURE A-V-5 FILTRATION PROCESS
123
-------
Chemical precipitation of calcium and magnesium can be car-
ried out at ambient temperatures, which is known as cold
process softening, or may be carried out at elevated
temperatures, 100°C (212°F), known as hot process softening.
Hot process softening is generally employed for boiler feed
water in steam electric powerplants when steam is generated
for heating purposes as well as electric power generation.
The hot process accelerates the reactions and reduces the
solubility of calcium carbonate and magnesium hydroxide.
Since there is always some carryover of fine particles from
the clarifiers, these are generally followed by filters.
Filters may contain graded sizes of sand, anthracite coal or
other filter media. Filters are also required in case
clarifiers have an upset and precipitates are carried over
into the clear water overflow.
Ion Exchange
Ion exchange processes can be designed to remove all mineral
salts in one unit process operation. These processes
produce high-quality water suitable for boiler feed
purposes. All of the mineral constituents are removed in
one process. The ion exchange material is an organic
resinous type material manufactured in granular bead form.
Resin beads contain pores that make them similiar to a
sponge. The surface area is electrically charged and
attracts to the surface chemical ions of opposite charge.
Basically there are two major types of resin, cation and
anion. Cation resin attracts the positively charged ions
and anion resin attracts the negatively charged ions. When
the charded sites on the resin surface are filled with ions
exchanged from the water, the resin ceases to function and
must be regenerated. (Figure A-V-6)
The regeneration process is a three-step operation for all
ion exchange units except mixed resin units. Mixed resin
units (Figure A-V-7) contain a mixture of cation and anion
resin in a single vessel. The resin is in a mixed form
during the service run and is separated during the regenera-
tion.
During the service run, water flow in an ion exchanger is
generally downflow through the resin bed. This downward
flow of water causes a compaction of the bed which in turn
causes an increase in resistance to flow through the bed.
In addition, the raw water being treated always contains
some micro-size particles which collect at the top surface
of the bed and add to the resistance to flow. To alleviate
124
-------
RAW WATER.
ACID
CATION
L I
DEGASI-
FIER
CASUTIC
ANION
DEIONIZED WATER
WASTE
WASTE
FIGURE A-V-6 ION EXCHANGE PROCESS CATIONIC AND ANIONIC TYPE
125
-------
RAW WATER
CAUSTIC
ACID
MIXED
RESIN
WASTE
DEIONIZED WATER
FIGURE A-V-7 ION EXCHANGE PROCESS MIXED RESIN TYPE
126
-------
this resistance, normal water flow to the bed is stopped and
direction of flow through the bed is reversed, causing the
bed to erupt, and wash the solids out. Ion exchange beds
are usually washed for a period of 10 to 15 minutes. Flow
rates vary with the size of vessel and the type of resin.
The flow rate is adjusted to expand the resin bed 80 to 100%
of its settled bed depth. Flow rates of 3.4-U.1 10~3 cu
m/s/sq m (5-6 gallons per minute per square foot) are
typical. The second stage of regeneration is the contacting
step. Chemical solution is passed through the bed at a
controlled flow rate such that resin is contacted with the
chemical solution for a certain time. Cation resins are
contacted for approximately 30 minutes while anion resins
are contacted for approximately 90 minutes. Immediately
after this chemical contact, the bed is given a slow rinse.
The normal volume of rinse is two bed volumes. The purpose
of the rinse is to wash the regenerant solution remaining in
the voids of the bed after the regenerant flow is stopped.
The bed is then rinsed until effluent quality reaches de-
ionized water specification. Quantity of rinse water
depends on the resin. Cation rinse water is approximately 8
cu m water per cu m resin. Anion rinse water is
approximately 10 cu m water per cu m resin. With mixed
resin units, there are two additional steps in the re-
generation process. After rinsing, the water level is
drained until it is just above the settled resin bed level.
Air is injected into the bottom of the vessel causing the
two stratified layers of resin to mix. After this mixing,
the vessel is filled with water and the resin bed is given a
short final rinse.
Chemical characteristic of the spent regenerant depend, on
the type of service that an ion-exchanger is performing.
Cation exchange in hydrogen cycle absorbs calcium, mag-
nesium, potassium, and sodium ions from the water. The
cation unit is regenerated with sulfuric acid. The acid
concentration is maintained low to prevent calcium sulfate
precipitation. The spent regenerant solution contains the
eluted ions with excess acid.
In order for the regeneration process to proceed there must
be a driving force. The driving force is excess chemical
quantity. The quantity of acid required for regeneration,
on a weight basis, is 2-4 times the stoichiometric exchange
capacity of the resin. On a weight basis, the waste sul-
furic acid will consist of 1/4-1/3 part mixed cations and
2/3-3/4 part of excess sulfuric acid. Concentration of
cations in the waste depends on their distribution in the
water supply.
127
-------
Occasionally, hydrochloric acid is used for hydrogen cycle
regeneration. Hydrochloric acid yields a greater regenera-
tion efficiency than sulfuric acid. The cost of hydro-
chloric acid is generally higher than sulfuric acid,
therefore, it is used only when the economics justify it.
Anion exchange units are regenerated with sodium hydroxide.
The concentration is approximately UX. The spent regenerant
will contain the eluted anions. These are sulfate,
chloride, nitrate, phosphate, alkalinity, bicarbonate, car-
bonate, and hydroxide. Silica in the form of HSio3~ is also
absorbed by anion exchangers and may be present in the spent
regenerant.
In high-pressure steam electric plants, condensate is
deionized to prevent dissolved salts from condenser tube
leaks from entering the boiler system, and eliminate minute
quantities of iron and copper formed as a result of
corrosion. The condensate is then polished in mixed resin
units. The ion exchange resin is regenerated with sulfuric
acid and sodium hydroxide. Sometimes, ammonium hydroxide is
used in place of sodium hydroxide. The quantity of iron and
copper found in the spent regenerants is usually negligible.
Sodium cycle ion exchange is the exchange of calcium and
magnesium ions for sodium ions. Hard water is often
softened by this process, but the content of dissolved
solids is not appreciably changed. The exchange resin is
regenerated with 10% sodium chloride solution. The waste
regenerant consists of approximately 1/3 part calcium
chloride and magnesium chloride and 2/3 part sodium
chloride.
Evaporator
Evaporation is a process of purifying water for boiler feed
by vaporizing it with a heat source and then condensing the
water vapor on a cool surface, and collecting it externally
of the evaporator unit. In the process, a portion of the
boiling water is drawn off as blowdown.
The evaporator consists of a vessel, usually in a horizontal
position in order to provide a large surface area for
boiling. In steam electric plants, evaporators are usually
heated by a waste source of heat, such as extraction steam
from the turbine cycle. The water evaporates into the upper
surface of the vessel and is ducted to an external con-
denser. In the lower portion of the vessel, a pool of the
boiling water is maintained at a constant level to keep the
steam tubes immersed in liquid. As water evaporates from
128
-------
•the pool, the raw water salts in the pool become concen-
trated. If allowed to concentrate too much, the salts will
scale the heating surfaces and the heat transfer rate di-
minishes. To prevent scaling, a portion of the pool water
is drawn off as blowdown. A simplified flow diagram of the
process is shown in Figure A-V-8.
Chemical composition of the blowdown is similar to that 'of
the raw water feed except that it is concentrated several
times. The blowdown is alkaline, with a pH in the range of
9-11. This is due to decomposition of bicarbonate ion to
carbon dioxide and carbonate ion. The carbon dioxide is
degassed from the evaporator leaving carbonate in solution
and yielding an alkaline pH. If the concentration of
calcium sulfate is high enough, it will precipitate out of
solution. Some steam electric power plants feed phosphate
to the raw water feed. This phosphate reacts with calcium
and lessens the precipitation of calcium carbonate and
calcium sulfate.
Evaporators are usually found in older low-pressure steam
electric plants. Ultra pure water required in the modern
high pressure units may generally be obtained more
economically by the ion exchange processes.
A typical powerplant may employ a combination of the dif-
ferent water treatment operations described above. However,
the waste streams from all these water treatment operations
are generally similar in pollutant characteristics.
Consequently, a description of the combined pollutants found
in the waste streams is given below.
Character of Water Treatment Wastes
Water treatment waste streams should be described by three
parameters: 1) pH, 2) suspended solids concentration, and 3)
concentration parameters typical of processes involved or
toxic elements involved in the process. Reference 21
reports waste water flows as shown in Table A-V-3.
Clarification wastes consist of clarifier sludge and filter
washes. Clarifier sludge could be either alum or iron salt
sludge, from coagulant chemicals. If the clarifier is lime
softening, then the sludge would be a calcium carbonate-
magnesium hydroxide sludge. Filter washes would contain
suspended solids either as light carry-over floe from the
clarifier or as naturally contained in unclarified raw
water. Activated carbon absorber wash would contain light
suspended particles or very fine activated carbon particles
due to attrition of the carbon.
129
-------
FEED
WATER
CONDENSER
CONDENSED
BOILER FEED
STEAM
COND*
EVAPORATOR
EVAPORATOR
SLOWDOWN
FIGURE A-V-8 EVAPORATION PROCESS
130
-------
Table A-V- 3
TYPICAL WATER TREATMENT WASTE
WATER FLOWS (Ref. 21)
PROCESS
RANGE OF FLOWS
. gal/ 1000 Ib water
treated
Clarifier blowdown
Lime-soda
Raw water filtration backwash
Feed water filter
Sodium zeolite regeneration
Cation exchange regeneration
Anion exchange regeneration
Evaporator blowdown
Condensate filtration and
ion exchange
Condensate powdex
1-4
1-4
0-6
0-6
0.5 - 3
0.5 - 3
0.5 - 3
12 -40
0.02 - 0.6
0.01 - 0.06
131
-------
Various attempts have been made to classify clarifier
sludges. Although these vary from plant to plant, the basic
characteristics are quite similar. Alum sludge is a non-
Newtonian, bulky gelatinous substance composed of aluminium
hydroxide, inorganic-particles, such as clay or sand, color
colloids, micro-organisms including plankton and other
organic matter removed from water.
The major constituent in sludge from lime soda softening is
calcium carbonate. Other consituents which may be present
are magnesium hydroxide, hydroxides of aluminum or iron,
insoluble matter such as clay, silt or sand, and organic
matter such as algae or other plankton removed from the
water.
The American Water Works Association Research Foundation has
conducted a study among its members to gather information on
the nature of waste disposal problems in water treatment
plant to assist the utilities. **
Waste sludges from clarifiers generally have a solids
content in the range of 3,000 - 15,000 mg/1. Suspended
solids amount to approximately 75 - 80* of total solids with
the quantity of volatile solids being 20 - 25% of total
solids. The BOD level usually is 30 - 100 mg/1. A large
corresponding COD level of 500 - 10,000 mg/1 shows that the
sludge is not biodegradable, but that it is readily
oxidizable. The sludge has a pH of about 5-9.
Filter backwash is more dilute than the wastes from clari-
fiers. Generally, it is not a large volume of waste.
Turbidity of wash water is usually less than 5 mg per liter
and the COD is about 160 mg per liter. The total solids
existing in filter backwash from plants producing an alum
sludge is about 400 mg per liter with only 40 - 100 mg/1
suspended solids.
All ion exchange wastes are either acidic or alkaline except
sodium chloride solutions which are neutral. While ion ex-
change wastes do not naturally have any significant amount
of suspended solids, certain chemicals such as calcium
sulfate and calcium carbonate have extremely low
solubilities and are often precipitated because of common
ion effects. Calcium sulfate precipitation is common in ion
exchange systems because of excess quantities of sulfuric
acid.
Evaporator blowdown consists of concentrated salts from the
feed water. Evaporators are usually operated to a point
where the blowdown is three to five times the concentration
132
-------
of the feed water. Due to the low solubility of calcium
carbonate and calcium sulfate, it is possible that there
will be precipitation of calcium carbonate and sulfate, if
present in the feed water. While the concentrated salts of
the feed water are neutral, decomposition of bicarbonate to
carbon dioxide and calcium carbonate, creates an alkaline
waste stream from the evaporator.
Table A-V-U shows the arithemetic mean and standard devi-
ation for a number of parameters for water treatment wastes.
These data were gathered from many different sources and
reported in various ways. Therefore they show wide varia-
tions. As can be seen, the standard deviation of each
parameter chosen, is two to three times greater than the
mean value of the parameter.
Undoubtedly, other factors that do not appear in the data
caused this variation. Under the sub-heading of clarifi-
cation wastes, the reported data do not indicate whether the
waste stream is a sludge from a clarifier removing suspended
solids, a sludge from a lime softener for hard water, or a
wash-water from a filter. Obviously, waste stream
composition will vary depending upon its origin.
Similarly, data listed under ion-exchange wastes do not
indicate whether the waste is acid, caustic or brine waste.
There are no indicators of what source the waste originated
from, or if the waste was neutralized before reporting. In
summary, data collected on water treating wastes is of
limited value because of the process variations which were
not reported, and because of the limited quantity of
information available on these waste streams.
Boiler or PWR Steam Generator Slowdown
Except for zero solid treatment systems, no external water
treatment regardless how efficient, is in itself protection
against bciler scale without the use of supplementary
internal chemical treatment of the boiler water.
The primary cause of scale formation is that the
solubilities of scale forming salts decrease with an
increase in temperature. The higher the temperature and
pressure of boiler operation, the more insoluble the scale
forming salts become. No method of external chemical
treatment operates at a temperature as high as that of the
boiler water. Consequently, when the boiler feed water is
heated to the boiler operating temperatures, the solubility
of the scale forming salts is exceeded and they crystallize
from solution as scale on the boiler heating surfaces.
133
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TABLK A-V-4
. ARITHMETIC MEAN AND DEVIATION OF
SELECTED WATER TREATMENT WASTE PARAMETERS
ARITHMETIC STANDARD 0~
MEAN DEVIATION m
m 0-
CLAHIFICATION^WASTES
Flow - M* per day
Turbidity - J.T.U.
Total Suspended Solids - mq TSS per
Total Suspended Solids - kg TSS per day
Total Hardness - mq CaCO_3 per 1
Total Hardness - kq CaCD3_ per day
Iron - mq Fe per 1
Iron - kg Fe per day
Aluminum
Flow - M3 ner day
Total Dissolved Solids - mg TDS per 1
Total Dissolved Solids - kg TDS per day
Sultate - mg SO4per 1
Sulfate - kg SO4 per day
Chloride - mg Cl per 1
Chloride - kq Cl per day
Sodium - mg Na per 1
Sodium - kq Na per day
Ammonia - mg NHj - N per 1
Ammonia - kg NH_3 - N per day
EVAPORATOR_BLOWDOWN
Flow - MJ per day
Total Dissolved Solids - mg TDS per
Total Dissolved Solids - kg TDS per day
Total Suspended Solids - mg TSS per
Total Suspended Solids - kg TSS per day
sulfate - mg SOj* per 1
Sulfate - kg SO4 per day
chloride - mg Cl per 1
Chloride - kg Cl per day
1
day
1
day
0
1
day
1
day
316
1,088
25,213
2,673
3,215
27
352
212
1 Piece
74,515
7,408
1,311
2,085
1,100
1,708
124
3. 112
558
46
1
-------
Calcium and magnesium salts are the most common source of
difficulty with boiler scale. Internal chemical treatment
is required to prevent deposit scale formation from the
residual hardness concentration remaining in the feed water.
One of the most common sources of scale is the decomposition
by heat of calcium bicarbonate to calcium carbonate and
carbon dioxide.
Ca(HCO3)2 + Heat = CaCO3(s) + H2O + CO2(g)
Deposits cf iron oxide, metalic copper and copper oxide are
frequently found in boilers operating with very pure
feedwater. The source of deposits is corrosion. Causes of
the corrosive action are dissolved oxygen and carbon
dioxide.
To prevent calcium and magnesium salts from scaling on
boiler evaporative surfaces, internal treatment consists of
precipitating the calcium and magnesium salts as a sludge
and maintaining the sludge in a fluid form so that it may be
removed by boiler blowdown. The blowdown can be continuous
or intermittent and the operation involves controlled
discharge of a certain quantity of boiler water. The most
common chemicals used for precipitation of calcium salts are
the sodium phosphates.
Chelating or complexing agents are sometimes applied.
Tetrasodium salt of ethylenediaminetetracetic acid (Na<»-
EDTA) and trisodium salt of nitrilotriacetic acid (Na3-NTA)
are the most commonly used chelating agents. The chelating
agents complex the calcium, magnesium, iron and copper in
exchange for the sodium.
The solubility of iron in water increases as the pH de-
creases below the neutral point. To prevent corrosion,
neutralization of the acid with an alkali is necessary.
Sodium carbonate, sodium hydroxide and/or ammonia are
commonly employed for this purpose.
Dissolved oxygen present in boiler water causes corrosion of
metallic surfaces. Dissolved oxygen is introduced into the
boiler, not only by the makeup water, but by air infil-
tration in the condensate system. In addition to mechanical
deaeration, sodium sulfite is employed for chemical
deaeration.
2 Na2SO3 + 02 = 2Na2SOU
It is common practice to maintain an excess of the sulfite
to assure complete oxygen removal. The use of sodium
135
-------
sulfite is restricted to low pressure boilers because the
reaction products are sulfate and dissolved solids which are
undesirable in high pressure boilers.
Hydrazine is a reducing agent which does not possess these
disadvantages for high pressure operation. Hydrazine reacts
with oxygen to form water.
N2H4+ O2 = 2H2O + N2
The excess hydrazine is decomposed by heat to ammonia and
nitrogen.
The characteristics of boiler blowdown are an alkaline waste
with pH from 9.5-10.0 for boilers treated with hydrazine and
pH from 10-11 for boilers treated with phosphates.
Blowdown from medium pressure boiler has a total dissolved
solids (TDS) in the range of 100-500 mg/1. High-pressure
boiler blowdown has a total dissolved solids in the range of
10-100 mg/1. Blowdown frcm boiler plants using phosphate
treatment contain 5-50 mg/1 phosphate and 10-100 mg/1
hydroxide alkalinity. Boiler plants with hydrazine
treatment produce a blowdown containing 0-2 mg/1 ammonia.
In PWR nuclear-fueled powerplants, the steam generator
employs ultrafine quality water. Consequently the blowdown
frequency and the impurities are much less than that in
fossil fuel plants.
The blowdown frequency is commonly once a day. Most of the
data also confirm the typical alkaline nature of the
blowdown. The data do not show completely the type of
treatment and the raw water treatment efficiency. Con-
sequently, the data have greatly varying parameters.
Reference 21 reports waste water flows from boiler blowdown
ranging from 0-U gal/1000 Ib steam generated.
Equipment Cleaning
Chemical Cleaning Boiler or PWR Steam Generator Tubes
Boilers are subject to two major chemical problems,
corrosion and scale formation. Proper operation and main-
tenance involves the pretreatment of boiler makeup water,
and the addition of various corrosion and scale control
additives to the feed water. Boilers operating at high
pressures (and temperatures) require more critical control
of boiler water chemistry than low pressure boilers.
136
-------
Even with the best preventive maintenance, occasional boiler
cleaning is a necessary operation for proper performance of
steam boilers. Condenser leaks, oxygen leaks in the boiler
water and corrosion/erosion of metallic parts by boiler
water may increase the frequency of boiler cleanings.
The data in Table A-V-5 shows pollutant concentrations for
specific cases. Inasmuch as boiler cleaning is tailored for
individual requirements, generalization about pollutant
concentration is not possible. However, the data does
indicate generally observed high amounts of metallic species
and COD requirements.
In this study, boiler tube cleaning was not categorized on
the basis of once-through or drum-type. However, it is to
be noted that similar cleaning as described earlier is fol-
lowed for once-through type boilers.
In nuclear powerplants of the PWR type, strict control on
the quality of steam generator water is maintained. Clean-
ing frequently varies with plant characteristics, as in
fossil-fuel power plants, but the cleaning methods are the
same.
Chemical cleaning of boilers can be of two types - 1) Pre-
operational—necessary for new boilers before going on-
stream and 2) Operational-necessary for scale and corrosion
products removal to maintain normal boiler operating
performance.
Preoperational Boiler Cleaning Wastes
During the manufacture and assembly of boiler steel
components, a black iron oxide scale (mill scale) is formed
on metal surfaces. The removal of mill scale is necessary
to eliminate potential galvanic corrosion and erosion of
turbine blades which can occur because of trapped mill scale
in the steam path. Similarly, the presence of oil, grease
(used during fabrication and assembly) and construction
debris can be detrimental to boilers. Consequently,
preoperational cleaning of boilers is an important aspect of
powerplant start-up procedures.
Typical steps for preoperational cleaning involve:
(i) an alkaline boilout using a solution containing caustic
or soda ash, phosphates, wetting or emulsifying agents and
sodium nitrite as an inhibitor to protect against caustic
embrittlement.
137
-------
TABLE A-V-5
CHEMICAL HASTE CHARACTERIZATION
A
Site"
3409
3409
3410
3412
3414
3416
3404
3603
3603
3604
3604
3604
3604
3604
3605
3605
3605
3605
3605
3605
3606
3606
3609
3609
3609
3607
3610
3610
3610
3610
3611
3611
3612
3612
3612
3612
3612
3612
3612
3612
3612
3612
3614
3614
3614
3614
3614
3614
3613
3613
3613
B
Cleaning
months
24
24
12
24
12
22
23
15
20
13
7
20
50
60
SO
12
24
24
36
22
48
100
74
15
12
9
18
15
50
100
60
30
50
40
24
30
36
40
40
30
40
24
20
36
14
12
30
24
24
C
Boiler
n,3
174
174
106
215
303
190
571
314.58
117.1
278.8
163.4
163.4
261.19
261.19
261.19
143.45
143.45
189.3
183.1
183.1
108.95
108.95
108.95
148.903
136.18
136.18
136.18
136.18
129.6
129.6
52.65
52.65
52.65
52.65
77.17
77.17
77.17
77.17
137.54
137.54
59.9
74.4
74.4
74.4
74.4
74.4
74.9
74.9
74.9
INCREASE IN POLLUTANT QUAN .'ITY PER CLEANING CYCLE
BOILER TUBES' CLEANING
D EF GHIJKLMNOP
Volume Alkalinity (CaCOi) BOD ' COD Total Solids Dissolved Solids Suspended Solids
(1000 gal.) (Ib) Kg (Ib) kg (Ib) kg (Ib) kg (Ib) kg (Ib) kg
46 1380 626 104 47.2 4017 1823 11816 5369 8588 3899 176 80
46 1380 626 104 47.2 4017 1823 11816 5369 8588 3899 176 80
28 181 82 -9.8 -4.45 5091 2311 12024 5458 10684 4850 9.8 4.45
57 -158 -72 -8.3 -3.8 8302 3769 11972 5435 11225 5096 75 34
80 3770 1711.9 121.4 55 11101 5040 34817 15807 1983 900.4 505.2 229.4
50 158.4 71.94 -1.65 -0.75 9169 4163 39698 18023 37196 16887 246 111.7
150.8 -23.8 -10.84 0 0 -14.07 -6.39 99.34 45.1 99.34 45.1 0 0
83.09 -- -- -__ -----
30.93 -- -- _-_ -----
43.165 -- - - --- -- --
43.165 -- -- --- -----
92.92 -_- - - - - - --
35.97 -- -- --- -----
35.97 -- -- -_- -----
69.18 -- -- _-- -----
69.18 -- -- -_- -----
69.18 -- - - -_- -- --
37.89 -- -- --- -----
37.89 -- - - -_- -- --
50.0 -- -- --- -----
48.37 -- -- --- -----
48.37 -- -- -_- --___
28.78 -- - - -_- -- --
28.78 -- -- --_ -----
28.78 -- -- --- -----
39.33 -- -- --- -----
35.97 -- -- -__ _.---
35.97 -- -- --- -----
35.97 -- •- --- -----
35.97 -- -- -_- -----
34.23 -- -- --- -----
34.23 -- -- --- -----
13.9 -- -- -_- -----
13.9 -- -- --- -.---
13.9 -- -- -_- -----
13.9 -- -- --- -----
20.38 -- -- .-- -----
20.38 -- -- -_- -----
20.38 -- -- --- -----
20.38 -- -- --- -----
36.33 -- - - --- -- --
36.33 -- -- --- -----
15.82 -- -- _-- -----
19.66 -- -- --- -----
19.66 -- -- --- -----
19.66 --'- - --- -- --
19.66 -- -- --- -----
19.66 -- -- -_- -----
19.78 -- -- --- -----
19.78 -- -- _-- -----
19.78 -- -- -_.
Q R
Ammonia
(Ib) kg
16.7 7.58
16.7 7.58
1.2 0.54
9.8 4.45
52.86 24.0
3.2 1.454
0 0
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
.
-------
TABLE A-V-5
CHEMICAL WASTE CHARACTERIZATION
A
Plant
Code
3409
3409
3410
3412
3414
3416
3404
3603
3603
3604
3604
3604
3604
3604
3605
3605
3605
3605
3605
3605
3606
3606
3609
3609
3609
3607
3610
3610
3610
3610
3611
3611
3612
3612
3612
3612
3612
3612
3612
3612
3612
3612
3614
3614
3614
3614
3614
3614
3613
3613
3613
B C
Nickel
(Ib)
95.8
95.8
-
—
294
108.4
-
Ill
-
-
-
100
-
-
81.9
-
-
-
-
-
577
-
33
-
-
46.2
-
-
44
-
41.8
-
-
-
-
-
-
-
-
-
44.0
-
-
-
-
-
24.23
-
24.23
-
-
kg
43.5
43.5
-
—
133.88
49.22
-
50.4
-
-
-
45.4
-
-
37.2
-
-
-
-
-
262
-
15
-
-
21
-
-
20
-
19
-
-
-
-
-
-
-
-
-
20
-
-
-
-
-
11
-
11
-
-
D E
Zinc
(Ib)
5.99
5.99
10.3
-0.045
169.6
91.56
0.00018
141
-
-
-
126
-
-
106
-
-
-
-
-
74.89
-
44 •
-
-
59.4
-
-
55
-
52.8
-
-
-
-
-
-
-
-
-
55
-
-
-
-
-
30.8
-
30.8
-
-
kg
2.72
2.72
4.67
-0.02
77
41.57
0.00008
64
-
-
-
57.2
-
-
48.1
-
-
-
-
-
34
-
20
-
-
27
-
-
25
-
24
-
-
-
-
-
-
-
-
-
25
-
-
-
-
-
14
-
14
-
-
INCREASE IN POLLUTANT O.UABTITY PER CLEANING CYCLE
BOILER TUBES' CLEANING (continued)
F GHIJKLH
Sodium Nitrate Hardness Bromide
(Ib)
1076
1076
2018
-
4885
12378
-55.9
-
-
2569
2569
3504
1902
2742
3363
3363
5007
2200
1515
2031
132
243
128
-
-
-
2603
1301
2603
-
3500
5374
1144
573
1144
573
3027
3027
-
-
-
-
201
-
55.7
-
1440
2161
2105
810
2105
kg (Ib) kg
488 0.56 0.25
488 0.56 0.25
916 -5.6 -2.54
-0.542 -0.25
2218 2.9 1.32
5620 0.817 0.371
-25.46
_
-
1166
1166
1590
863
1244
1526
1526 - ' -
2273
998
687
922
82
110.3
58
_
-
_
1181
590.6
1244
_
1589
2441
519
260
519
260
1374
1374
- - -
-
-
_
91.4
-
25.28
_
653
981
955
367
955
(Ib) kg (Ib)
I'll 550
1M1 550
•i-
-29.19 -13.25
89.86 40.8
-
1.25 0.57
-
_
484
484
492
582
484
-
-
_
503
503
773
635
847
444
- -
- -
-
476
635
476
476
465
465
481
243
481
243
270
270
- -
- -
- -
-
698
- -
193
-
-
-
201
328
201
kg
_
-
-
-
-
-
-
-
-
219.7
219.7
223
264
219.7
-
-
-
928
228
350.9
288
384
201
-
-
-
216
288
216
216
211
211
218
110
218
110
122
122
-
-
-
-
317
-
87.6
-
-
-
91.2
148.9
91.2
N O
Manganese
(Ib) kg
_ _
-
-
•>
-
-
0.0059 0.0027
30.8 14
-
-
-
27.9 12.7
-
- .
48.9 22.2
-
-
-
-
-
15.4 7
-
11 5
-
-
13.2 6
-
-
11 5
-
11 5
-
-
-
-
-
-
-
-
-
11 5
-
-
-
-
-
6.6 3
-
6.6 3
-
-
idity, Oil and Grease,
rcurj, Sulfite. Lead-
ileniOni, Pnenolgj Surfactant
370
370
276
23
387
100
0
-------
TABLE A-V- 5
A
3409
3406
34 IS
3412
3414
3416
3404
3603
3603
3604
3604
3604
3604
3604
3605
3605
3605
3605
3605
3605
3606
3606
3609
3609
3609
3607
3610
3610
3610
3610
3611
3611
3612
3612
3612
3612
3612
3612
3612
3612
3612
3612
3614
3614
3614
3614
3614
3614
3613
3613
3613
B C D E
Phosphorus Sulfate
(Ib) kg (Ib) kg
4.07 1.84 11.26 5.11
4.07 1.84 11.26 5.11
0.4 0.18 -40 -18.6
-O.O8 -0.036
7.26 3.3 73.37 33.31
-0.001674 -0.00076 0.33 0.15
-0.0125 -0.0057 2.24 1.02
74 33.6
-
-
_
78.9 35.82
-
-
58.72 26.66
-
-
-
_
_
40.97 18.6
-
24.45 11.1
- - - -
-
33.76 15.33
- - - -
-
30.1 13.7
-
28.7 13.05
-
-
-
- . -
-
-
-
-
-
30.9 14.03
-
-
-
-
-
17.24 7.83
-
17.24 7.83
-
-
F
(1C)
7772
7772
19100
6142
25898
32191
6.03
40361
15052
21006
21006
45224
14588
14588
42085
38290
42085
18440
18440
24332
29422
29422
13167
13167
13167
19140
14588
17506
14588
14588
19477
16696
6768
8460
6768
8460
8266
8266
12398
11572
17101
14733
9625
11962
9568
11962
11962
11962
8022
8022
8022
G
kg
3528
3528
8671
2788
11758
14615
2.74
18324
6834
9537
9537
20532
6623
6623
19107
17834
19107
8372
8372
11047
13358
13358
597B
5978
5978
8690
6623
7948
6623
6623
8843
7580
3073
3841
3073
3841
3753
3753
5629
5254
7764
6689
4370
5431
4344
5431
5431
5431
3642
3642
3642
INCREASE
IN POLLUTANT QUANTIFY PEE CLEANING CYCLE
BOILER TUBES' CLEANING (continued)
H I
Fluoride
(Ib)
-
-
-
-
-
-
-
870
-
478
478
2509
514.7
514.7
3837
3837
3837
1050
1050
1385
-
-
1596
-
399
-
514.7
997
514.7
514.7
864.5
864.5
192.8
192.8
192.8
192.8
282
282
1130
1130
504
504
253
1092
546
546
552
829
549
362.3
275
kg
_
-
-
-
-
-
-
395
-
217
217
1139
233
233
• 1742
1742
1742
477
477
628
-
-
724
-
181
-
233.6
452.6
233.6
233.6
392.4
392.4
87.53
87.53
87.53
87.53
128
128
513
513
228.8
228.8
114.86
495
247.88
247.88
250.6
376.3
249.2
164.5
124.8
J K
Aluminum
(Ib)
_
-
-
-
-
-
-
18.94
-
-
-
17
-
-
13.87
-
-
-
-
-
11.0
-
28.6
-
-
8.8
-
-
8.8
-
6.6
-
-
-
-
-
-
-
-
-
8.8
-
-
-
-
-
4.4
-
4.4
-
-
kg
-
-
-
-
-
-
-
8.6
-
-
-
7.7
-
-
6.3
-
-
-
-
-
5
-
13
-
-
4
-
-
4
-
3
-
-
-
-
-
-
-
-
-
4
-
-
-
-
-
2
-
2
-
-
L M
Chromium
(Ib)
6.91
6.91
1.4
1.21
23.17
0.0832
0.035
-
-
-
-
16.9
-
-
13.87
-
-
-
-
-
11.01
-
6.6
-
-
8.8
-
-
—
-
6.6
-
-
-
-
-
-
-
-
-
8.8
-
-
-
-
-
13.2
-
4.4
-
-
kg
3.13
3.13
0.63
0.55
10.52
0.0378
0.0160
-
-
-
-
7.7
-
-
6.3
-
-
-
-
-
5
-
3
-
-
4
-
-
-
-
3
-
-
-
-
--
-
-
-
-
4
-
-
-
-
-
6
-
2
-
-
N 0
Copper
(Ib)
251.6
251.6
245.5
-
718
325
0.00006
800
800
900
800
500
300
600
200
100
25
500
600
600
200
300
400
200
300
300
500
400
500
500
600
400
200
100
200
300
300
400
100
100
300
200
500
100
100
100
50
50
200
200
200
kg
114.2
114.2
111.4
-
326
147.7
0.00003
363
363
408.6
363
227
136.2
272
90.8
45.4
11.35
227
272
272
90.8
136.2
181.6
90.8
136.2
136.2
227 '
181.6
227
227
272
181.6
90.8
45.4
90.8
136.2
136.2
181.6
45.4
45.4
136.2
90.8
227
45.4
45.4
45.4
22.7
22.7
90.8
90.8
90.8
P Q
Iron
(Ib)
599
599
1571
1668
1841
5491
0.001
3100
3100
2400
4900
3800
2200
2100
4000
3000
3000
1100
1100
5000
3500
4500
1500
2500
3000
3000
100
1000
1000
900
2000
2500
900
800
700
500
1000
1000
1500
1000
3000
1500
1600
1400
1200
1000
1000
500
1000
1000
1000'
kg
271.8
271.9 •
713.2
757.2
836
2493
0.00045
1407
1407
1089
2224
1725
999
953
1816
1362
1362
499
499
2270
1816
2043
681
1135
1362
1362
45.4
454
454
408
908
1135
408
363
318
227
454
454
681
454
1362
681
726
635
545
454
454
227
454
454
454
R S
Maqnesium
(Ib) kg
224 101.7
224 101.7
-
-
13.83 6.28
-
-
66 29.9
-
-
-
59.0 26.8
-
-
48.9 22.2
-
-
-
-
-
33 15
-
22 10
-
-
28.6 13
-
-
26.43. 12
-
24.23 11
-
-
-
-
-
-
-
-
-
26.43 12
-
-
-
-
-
13.22 6
-
13.22 6
-
-
-------
TABLE A-V-; 6
CHEMICAL HASTE CHARACTBRIZATIOH
INCREASE IN POLLUTANT QUANT 17K PBR CLEANING CYCIZ
AIR PREHEATER CLEANING
Line
1)
2)
3)
4)
5)
6)
7)
A
Plant
3409
3410
3411
3412
3413
3414
3415
»
C
D
E
P
frISSinc'v Batch VoluM Alkalinity
eycl»/yr
12
12
8
12
5
6
4
»
409
852
1363
2272
265
162.8
378.6
(1000 gal.)
108
225
360
600
70
43
100
(Ib)
-72.02
-76.65
-90.08
-530.39
189.73
-19.71
-25.02
kg
-32.7
-34.8
-40.9
-240.8
86.14
-8.95
-11.36
G
COD
(Ib)
14.4
16.87
14.98
35.02
116.7
5.72
9.16
B
kg
6.54
7.66
6.8
15.9
53
2.6
4.16
I
Total
(Ib)
11951
24964
40528
65515
2616
4768
11257
J
Solids
kg
5426
11334
18400
29744
1188
2165
5111
K
Dissolve*
(Ib)
7907
16605
27022
44264
4467
3189
8249
L
Solids
kg
3590
7539
12268
20096
2028
1448
3745
M
Total
Suspended
(Ib)
1975
4008
6603
10788
477.9
785.24
1834
N
Solids
kg
897
1820
2998
4898
217
356.5
833
O
P
Sulzata
(Ib)
1066
2231
3601
6114
692
423.8
979
kg
484
1013
1635
2776
314.2
192.4
444.5
g
Chic
(Ib)
1.801
0
0
9989
0
-8.96
-14.16
*
arid*
kg
0.8178
0
0
4534
0
-4.07
-6.43
BOILER FIRESIDE CLEANING
8)
9>
3410
3411
2
8
2626
90.8
720
24
-240
5.99
-109
-2.72
1134
19
515
8.63
40861
4002
18551
1817
35127
3002
15948
1363
3823
119.09
1736
54.07
11949
299.4
5425
135.9
0
18.01
0
8.18
AIR PREHEATER CLEANING (continued)
Line
1)
2)
3)
4)
5)
6)
7)
8)
9)
fi**
3409
3410
3411
3412
3413
3414
3415
3410
3411
B C
Aamonia
(Ib)
2.378
4.49
8.1
12
0.722
0.925
2.176
1.49
0.039
kg
1.08
2.04
3.68
5.45
0.328
0.42
0.988
0.68
0.018
D E
Nitrate
(Ib)
3.414
5.06
11.25
5.48
0.471
1.074
3.37
14.75
0.7
kg
1.55
2.3
5.11
2.49
0.214
0.488
1.53
6.7
0.318
F G
Phosphorus
(Ib)
0.513
2.66
4.67
5.86
0.035
0.559
1.32
11.1
0.257
kg
0.233
1.21
2.12
2.66
0.016
0.254
0.6
5.04
0.117
H I
Hardness
(Ib)
3949
8255
13372
22196
476.8
1577
3709
35409
791.41
kg
1793
3748
6071
10077
216.5
716
1684
BOILER
16076
359.3
J K
Chromium
(Ib)
1.1.,'
24.25
39.03
59.19
0.749
0.458
0.533
FIRESIDE
0.0299
0.998
kg
0.529
11.01
17.72
26.875
0.34
0.208
0.242
CLEANING
0.0136
0.453
L H NO
Copper Iron
(Ib)
4.434
-
-
0
2.907
1.788
1.86
(continued)
_
0.249
kg (Ib)
2.018 1531
3189
5103
0 8506
1.32 3.495
0.812 2.13
0.848 2.379
900
0.113 30
kg
695.1
1448
2317
3862
1.587
0.967
1.08
408.9
13.63
P Q
Magnesium
(Ib)
874.45
1850
2986
4812
107.4
352.4
828
11949
190.35
kg
397
840
1356
2185
48.76
160
376
5425
86.42
R S
Nickel
(Ib)
67.55
140.72
225
375.3
28.63
17.93
20.83
30.02
-
kg
30.67
63.89
102.2
170.38
13
8.14
9.46
13.63
-
AIR PREHEATER CLEANING (continued)
Line,
1)
2)
3)
4)
5)
6)
7)
8)
9)
*
sas*
3409
3410
3411
3412
3413
3414
3415
3410
3411
B C
804 lull
(Ib)
1.799
0
0
8630
552
-0.35
1.66
0
9
kg
0.818
0
0
3918
251
-0.16
O.757
0
4.09
D
Zinc
(Ib)
4.43
8.97
14.93
25.02
0.283
1.788
2.07
28.72
2
E
kg
2.011
4.075
6.78
11.36
0.1285
0.812
0.942
13.042
0.908
P
BOD
(Ib)
3.6
0
0
15.01
2.335
1.793
1.668
0
0
G
kg
1.635
0
0
6.815
1.06
0.814
0.757
0
0
H
Turbidity
JTU
495
476
497
478
500
500
498
476
98
BOILER FIRE3IDB CLEANING (continued)
-------
(ii) draining of the solution after achieving satisfactory
removal of oil, grease, silica, loose scale, dirt and
construction debris etc.
(iii) rinsing of the boiler
(iv) acid cleaning of the boiler to remove mill scale using
corrosion inhibited hydrochloric acid or organic acids, such
as citric and formic acids or patented chelating scale
removers.
(v) draining of the acid solution using nitrogen to prevent
metal rusting
(vi) second rinsing of the boiler with demineralized water
(vii) an alkaline boilout to neutralize trapped acid and to
remove trapped hydrogen gas molecules (which if left in the
boiler can cause metal embrittlement over a period of time)
(viii) and finally followed by a passivation rinse using
sodium nitrite and phosphate solution.
These typical preoperational cleaning steps are followed for
drum type boilers. For once-through boilers, process steps
are similar except that instead of boilout, continuous
flushing is carried out.
The pollution parameters associated with preoperational
boiler cleanings are extreme pH values (acidic or alkaline
solutions), phosphates,, nitrates, BOD from the organic
emulsifying agents, oil and grease and suspended solids.
The quantity of these wastes and the pollutant
concentrations vary for each specific case.
Reference U68 describes the preoperational chemical cleaning
program for a nuclear powerpiant.
Operational Boiler Cleaning Wastes
A variety of cleaning formulations are used to chemically
clean boilers whose operation has deteriorated due to build
up of scale and corrosion products. Analyses of scale de-
posits are made on sample sections of tubes cut from the
boiler. Based on the composition of scale discovered in
these samples, a cleaning program is selected. Some pro-
cedures are more effective for copper removal, others for
iron removal, and still ethers for silica removal. The
composition of boiler scale and corrosion products is brief-
142
-------
ly described. This is followed by a description of methods
used to renovate boilers.
Composition of Scale
Boiler scale contains precipitated salts and corrosion
products. Precipitation occurs because of local
supersaturation of their solution concentration near the
heated tube surfaces. These salts include calcium carbonate
and sulfate, calcium and magnesium phosphates and silicates,
and magnesium hydroxide as principal constituents. Iron and
copper oxides are present as corrosion byproducts and
various trace metals as zinc, nickel, aluminum may be
present either as constituents of the feed water, or as
corrosion products. In addition, mud, silt, dirt or other
debris introduced via condenser leaks are also present. Oil
contamination of boiler water results in carbonation of this
waste and this is incorporated into the boiler scale. The
composition of boiler scale is dependent on the composition
of boiler feed water, materials of construction, boiler
chemical additives, and contaminants leaked into the boiler
water, and therefore will differ with each successive
cleaning of the boiler.
Frequency cf Boiler Cleanings
There are many factors which affect the cleaning schedule
for power utility steam boilers. High pressure boilers
require more critical control cf feed water purity and
consequently usually require less frequent cleanings. A
review of boiler cleaning data in Table A-V-5 shows that
cleaning frequency varies from once in seven months to once
in one hundred months. The mean time between boiler clean-
ings is estimated from these data as thirty months with a
standard deviation of eighteen months.
Reference 469, prepared by the ASME Research Committee Task
Force on Boiler Feedwater Studies, is a report of an
investigation of current practices regarding factors
influencing the need (frequency) for chemical cleaning of
boilers.
Types of Boiler Tube Cleaning Processes
Alkaline Cleaning Mixtures with Oxidizing Agents for Copper
Removal
These formulations may contain free ammonia and ammonium
salts, (sulfate or carbonate), an oxidizing agent such as
potassium or sodium bromate or chlorate, or ammonium
143
-------
persulfate, nitrates or nitrites, and sometimes caustic
soda. Air is sometimes used as the oxidant. These mixtures
clean by the following mechanism: Oxidizing agents convert
metallic copper deposits to copper oxide. Ammonia reacts
with the copper oxide to solubilize it as the copper
ammonium blue complex.
Since metallic copper interferes with the conventional acid
cleaning process described below, this cleaning formulation
is frequently used to precede acid cleaning when high copper
levels are present in the boiler scale.
The pollutants introduced by these cleaning formulations are
as follows: ammonium ion, oxidizing agents, high al-
kalinity, and high levels of iron and copper ion dissolved
from the boiler scale.
Acid Cleaning Mixtures
These mixtures are usually based on inhibited hydrochloric
acid as solvent, although sulfuric, sulfamic, phosphoric,
nitric, citric, formic and hydroxyacetic acids are also
used. Hydrofluoric acid or fluoride salts are added for
silica removal. Corrosion inhibitors, wetting agents, and
complexing agents to solubilize copper may also be included.
These mixtures are effective in removal of scale due to
water hardness, iron oxides, and copper oxide, but not
metallic copper.
The principal pollutants introduced to the waste stream from
these cleaning chemicals are acidity, phosphates, fluorides,
and organic compounds (BOD). In addition large quantities
of copper, iron, hardness, phosphates and turbidity are
released as a result of loosening and dissolving the boiler
scale.
Alkaline Chelating Rinses and Alkaline Passivating Rinses
These formulations contain ammonia, caustic soda or soda
ash, EDTA, NTA, citrates, gluconates, or other chelating
agents, and may contain certain phosphates, chromates, ni-
trates or nitrites as corrosion inhibitors. These cleaning
mixtures may be used alone, or after acid cleaning to
neutralize residual acidity and to remove additional amounts
of iron, copper, alkaline earth scale compounds, and silica.
Their use introduces the following pollutants to the
discharged wastes: alkalinity, organic compounds (BOD),
phosphates, and scale components such as iron, copper and
hardness.
144
-------
Methods Using Organic Solvents
Organic solvents are also widely used to remove iron/copper
scales from boiler tubes. Two common methods, described in
Reference 444, are:
1. Vertan 675 (R) (Dow trademark). This is an
ammoniated salt of ethylenediaminetetraacetic acid. In this
process the boiler is first protected by injecting a
corrosion inhibitor, then sufficient Verton 675 or EDTA is
pumped in to achieve a 5-10% solution. The boiler is then
fired to 75-100 psi (about 300-325°F) until the iron has
been picked up, the boiler is cooled to 200°F, the chelant
strength is restored to about 5* and air is introduced into
the unit. This oxidizes the copper to the cupric form which
is readily complexed. The boiler is drained, rinsed and is
made ready for service. The pH of this solvent is about
9.5.
2. Citrosolv Process. This is another two-step
process. It starts with a 3% citric acid solution
ammoniated to a pH of 3.5. The solution is circulated at a
temperature of 200°F for 6-8 hours or until all of the iron
has been picked up. The second step calls for raising the
pH to 9.2 - 9.5 by addition of anhydrous or aqueous ammonia
after cooling the boiler to 150°F. Air is then injected to
oxidize the copper and finally sodium nitrite is injected to
assist in rendering passive surfaces. A final demineralized
water or condensate rinse completes the job.
Proprietary Processes
Frequently boiler tubes are cleaned by specialized companies
using proprietary processes and cleaning chemicals. Most of
these chemicals are similar to those described earlier and
the resulting wastes contain: alkalinity, organic compounds
(BOD), phosphate, ammonium compounds, and scale compounds
such as iron, copper and hardness.
Condenser Cleaning
The other major heat transfer component in a boiler system
is the condenser. The spent steam from the turbine is
liquefied in the condenser by the condenser cooling water
system. Condenser tubes are made out of stainless steel,
titanium or copper alloys. Preoperational cleaning of the
condensers is done with alkaline solutions, with emphasis on
the steam side of the condenser because of high quality
water circulation. Operational cleaning on the steam side
depends upon boiler water quality and is not done
145
-------
frequently. The water side of the condenser is cleaned with
inhibited hydrochloric acid.
Boiler Fireside Cleaning
The fireside of boiler tubes collects fuel ash, corrosion
products and airborne dust. Gas-fired boilers have the
cleanest combustion process.
In order to maintain an efficient heat transfer, boiler
firesides are cleaned with high pressure fire hoses, while
the boilers are hot. Soda ash or other alkaline materials
may be used to enhance the cleaning. Depending upon the
sulfur content of the fuel, the cleaning wastes are more or
less acid.
Data was available from only two plants for boiler fireside
cleaning. These data are shown in Table A-V-6. The pol-
lutants in the waste stream may reveal extreme values of pH,
hardness and suspended solids as well as some metals.
Air Preheater Cleaning
Air preheaters are an integral part of the steam generating
system. They are used to preheat the ambient air required
for combustion and thus economize thermal energy. Two types
of preheaters are used — tubular or regenerative. In
either case, part of the sensible heat of the combustion
flue gases is transferred to the incoming fresh air.
In tubular air preheaters, cold fresh air is forced through
a heat exchanger tube bundle using a forced-draft-fan. The
flue gases leaving the economizer flow around the tubes and
heat is transferred through the metal interface.
Regenerative type preheaters are used more frequently in
large powerplants. In this type, heat is regenerated by
using metallic elements in a rotor. The rotor revolves
between two ducts — outlet duct carrying hot flue gases to
the stack and intake duct carrying fresh air to the boiler
windbox. Heat is transferred to the metallic elements which
in turn transfer it to the fresh air by convection.
Soot and fly ash accumulate on the preheater surfaces and
the deposits must be removed periodically to maintain good
heat transfer rates as well as to avoid plugging of the
tubes or metallic elements. Preheaters are cleaned by
hosing them down with high-pressure water from fire hoses.
Depending upon the sulfur content of the fuel, the cleaning
wastes are more or less acidic in nature. The washing fluid
146
-------
may contain soda ash and phosphates or detergents which have
been added to neutralize excess acidity or alkaline de-
pending on the cleaning product used. Fly ash and soot,
rust, magnesium salts, and metallic ions leached from the
ash and soot are normal constituents of the cleaning wastes.
Copper, iron, nickel, and chromium are usually prevalent in
this discharge, and in oil-fired installations vanadium may
also be present at significant levels.
Cleaning frequency is usually about once a month, but
frequencies of H to 180 cleanings per year are reported in
Table A-V-5.
Chemical data for air preheater cleaning are also shown in
Table A-V-5. Data for plant number 3412 appears to deviate
considerably from the other plants, and much of the data
reported varies considerably from other plants, by as much
as an order of magnitude.
Feedwater Heaters Cleaning
According to Reference 4U4, the number of closed feedwater
heaters in the preboiler cycle ranges from H to 10. Tubes
may be formed from admiralty brass; 90/10, 80/20, 70/30
cupro-nickel; monel and arsenical copper in the nonferrous
group and carbon steel and stainless steel in the ferrous
family. Tube sizes are 5/8" or 3/4" O.D. by 15 to 80 feet
long. They may be straight or hairpin bent tubes.
Feedwater flows through the tubes, extracting heat from the
steam which surrounds the tubes.
Pre-operationally both sides of the heaters may be cleaned
to remove oils, grease, dirt and preservative coatings put
on by the manufacturer. The cleaning solvent is generally a
solution of O.OX to l.OX tri-sodium phosphate containing
wetting agents. Recirculation at 180°F is maintained for 6-
12 hours. Draining and rinsing with demineralized water
completes the job. In some cases the water side of the
heaters are also acid cleaned using an organic acid such as
3% solution of citric, ammoniated citric or hydroxyacetic-
formic acids at 190°F. Sometimes these jobs are done
simultaneously with the cleaning of the boiler. Again there
is a reluctance to acid clean the steam side of the heater
for fear of acid "hanging up" in crevices.
Operational cleaning in general has not been required on the
ferrous alloy tubes. Deposits found on the water side of
the copper alloy tubing have been predominantly copper and
iron oxides. The common solvent used has been 5-20%
hydrochloric acid, circulated for 6-8 hours at a temperature
147
-------
of 150°F. Neutralization of the system has been
accomplished by circulating a 0.5 - 1.0* soda ash or caustic
soda solution for 2-3 hours at 120-150°F. Rinsing with
demineralized water completes the cleaning process.
Miscellaneous Small Equipment Cleaning
At infrequent intervals, other plant components such as con-
densate coolers, hydrogen coolers, air compressor coolers,
stator oil coolers, etc. are cleaned chemically. Inhibited
hydrochloric acid is a common chemical used for cleaning.
Detergents and wetting agents are also added when necessary.
The waste volume is, of course, smaller than that
encountered in other type of chemical cleanings. Pollutant
parameters are low-high pH, total suspended solids (TSS)
metallic components, oil, etc.
Stack Cleaning
Depending upon the fossil fuel used, the stack may have
deposits of fly ash, and soot. Acidity in these deposits
can be imparted by the sulfur oxides in the flue gases. If a
wet scrubber is used to clean the flue gas, process or
equipment upsets can result in additional scaling on the
stack interior. Normally, high-pressure water is used to
clean the deposits on stack walls. These wastes may contain
total suspended solids (1SS) , high or low pH values,
metallic species, oil, etc.
Cooling Tower Basin Cleaning,
Depending upon the quality of the make-up water used in the
cooling tower, carbonates can be deposited in the tower
basin. Similarly, depending upon the inefficiency of
chlorine dosages, some algae growth may occur on basin
walls. Seme debris carried in the atmosphere may also
collect in the basin. Consequently, periodic basin washings
with water is carried out. The waste water primarily
contains total suspended solids (TSS) as a pollutant.
Ash Handling
Steam-electric powerpiants which utilize oil or coal as a
fuel produce ash as a waste product of combustion. The
total ash is of two sorts: bottom ash and fly ash. Bottom
ash is the residue which accumulates in the furnace bottom,
and fly ash is the material which is carried over in the
flue gas stream.
148
-------
Ash-handling or transport is the conveyance of the
accumulated waste products to a disposal system. The method
of conveyance may be either wet (sluicing) or dry
(pneumatic). This section discusses the wet ash handling
system and in particular* the waste water which it produces.
The chemical characteristics of ash handling waste water is
basically a function of the fuel burned. The following
table from Reference 278 lists commercial fuels for power
production.
»
Fuels Containing Fuels Containing
Ash Little or No Ash
All coals Natural gas
Fuel oil-"Bunker C" Manufactured gas
Refinery sludge Coke-oven gas (clean)
Tank residues Refinery gas
Refinery Coke Distillates (most)
Most tars Combustion-turbine exhaust
Wood and wood products
Other products of vege-
table
Waste-heat gases (most)
Blast-furnace gas
Cement-kiln gases
Of the fuels containing ash, coals and fuel oil are mostly
used in the power industry.
Coal
Coal is the most widely used fossil fuel in United Stated
powexplants. In 1972, 335 million tons of coal were con-
sumed in the U.S. for power generation. The average ash
content of coal is 11% for the nation, Z3B with a range from
6 to 20%. It may, therefore be estimated that roughly
37,000,000 tons of ash were produced in 1972 by U.S. power-
plants. Disposal of this quantity of solids from the waste
water stream has prompted most utilities to install some
sedimentation facility. In many cases, ash settling ponds
are used. A typical ash pond is illustrated in Figure A-V-
9, which is located in plant no. 4217. However, in some
cases, because of unavailability of land, aesthetics, or
some other reason, utilities have installed more
sophisticated materials-handling systems based on the
sedimentation process.
The characteristics of the water handling coal ash is re-
lated to the physico-chemical properties of that ash and to
149
-------
"*£:>JL'
rZ£3?^m%&:
TYPICAL ASH POND
PLANT NO. 4217
Figure A-V-9
150
-------
the volume and initial quality of the water used. Table A-
V-7 lists some of the constituents of coal ash.23a Table A-
V-8 shows the volume and time variabilities of water flow in
an ash handling system. Reference 21 reports that water
requirements for ash handling are as follows:
fly ash 1,200-40,000 gal/ton ash conveyed
bottom ash 2,400-40,000 gal/ton ash conveyed
Data obtained from discharge permit applications on ash pond
overflows for 33 plants burning coal indicates a wide range
in the overflow quantities, from about 0.2 MGD per 1000 Mw
of generating capacity to about 50 MGD per 1000 Mw of
capacity. The data, as MGD per 1000 Mw, approximate a log-
normal distribution, with 50 percent of the ash pond
overflows being less than 5 MGD per 1000 Mw and 60 percent
less than 10 MGD per 1000 Mw. Based on the annual coal
consumption reported for these plants (Ref.: Steam Electric
Plant Factors/1971), the overflows range from about 0.1 MGD
per million tons coal burned per year to about 16 MGD per
million tons coal burned per year, with a median value of
about 4 MGD per million tons coal burned per year.
The relative percentages of bottom ash and fly ash depend
upon the mode of firing and the type of combustion chamber.
Following figures are satisfactory averages, for a coal of
13,000 Btu/lb.
Type of operation Fly ash (% of total ash)
Pulverized coal burners
Dry bottom, regardless of type 85
of burner
Wet bottom 65
(without fly ash reinjection)
Cyclone furnaces 20
Spreader stokers
(without fly ash reinjection) 65
The number of variables involved in characterizing the water
used for ash handling is such that it is not probable that
any two plants would exhibit the same waste stream charac-
teristics. The approach taken in this report is to examine
a cross section of plant data. There are no data available
on the actual ash sluicing waste water. However, since most
plants now employ a settling pond, the ash pond overflow
data can be used to evaluate associated waste water
characteristics. These data are summarized in Table A-V-9.
151
-------
Table A-V- 7
CONSTITUENTS OF COAL ASH
238
Constituent
Si°2
A12°3
Fe2°3
CaO
MgO
so3
C and volatiles
P
B
U and Th
Cu
Mn
Ni
Pb
Zn
Sr
Ba
Zr
Percent
30-50
20-30
10-30
0.4-1.3
1.5-4.7
0.5-1.1
0.4 1.5
1.0-3.0
0.2-3.2
0.1-4.0
0.1-0o3
0.1-0.6
O.O-Ool
trace
trace
trace
trace
trace
trace
trace
trace
152
-------
Table A-V- 8
TIME OF FLOW FOR ASH HANDLING SYSTEMS
Plant No. 0110, a 952 Mw unit fueled by pulverized coal
- basis is one 8-hr cycle —
Duty
H. E. #1
Flushing
H. E. #2
Flushing
H. E. #3
Flushing
Purge
Fill
Pyrites Tank
Purge
Grlder Seal
Mill Rejects
Pressure Transfer
Hydrovac*
Bubblers
Cool Weirs
Pyrites Tank Make-up
Flow Rate, gpm
1,960
600
1,960
600
1,960
600
1,960
1,500
2,660
2,660
8
515
1
4,604
4
540
640
Duration, minutes
73
15
60
20
47
15
3x8 each
3 x 15 each
12
8
180
7x6 each
210
270
continuous
continuous
12
*NOTE: Only significant Hem pertaining to fly ash handling.
other Items pertain to bottom ash handling.
All
153
-------
TABLE A-V- 9
CHEMICAL WASTE CHARACTERIZATION
ASH POND OVERFLOW -i NET DISCHARGE
CHANGE IN PARAMETER LEVEL .FROM INTAKE TO DISCHARGE
Code Plant Capacity £s>el_ . .
3412
3416
3404
3402
34O1
3405
1703
1720
1710
1722
1709
1711
1711
*1711
3936
3936
*3936
3927
2616
1808
1729
1718
393O
3930
•393O
1825
1825
1825
1825
•1825
3920
1816
2608
0111
4704
2119
2119
•2119
0107
3514
1716
1716
*1716
MM
1114.5
740
300
308
31
116.2
766
1178
1162
1232
690
1179
1086
1469
933
732
186
1042
500
1304
544
600
510
1300
823
2558
568
2152
676
MWHr/day
13205
10525
5420
4965
865
1629
6288
16155
3164
15563
0706
21872
18908
21705
14276
12050
2978
13856
3816
24813
7695
10149
7550
18169
9874
31458
5741
11315
11092
C - Coal
0 - Oil
C/0
C
C/0
C/0
C
C/0
C
C
C/0
C
0
C
C
C
C
C
C
C/0
C
C
C
C
C
C
C
C
C
C
C
Flow
n>3/day
19574
13100
2556
2726
9132
18.17
22716
49218
2726
98436
3786
32560
2650
35210
3786
22716
26502
5300
15901
15144
1817
53000
15144
3786
18930
37103
12115
6058
114
55390
27259
3786
5679
27782
15434
40694
82252
122946
2726
10865
1893
568
2461
(lOOOgpd)
5170
3460
675
720
2412
4.8
6000
13000
720
26000
1000
8600
700
9300
1000
6000
7000
1400
4200
4000
480
14000
4000
1000
5000
9800
3200
1600
30
14630
7200
1000
1500
7338
4076
10748
21725
32473
720
2870
500
150
650
mg/1
3560
-23
1879
54
-1338
-18509
-240
362
0
112
309
509
506
387
680
647
0
121
670
79
1124
1084
626
525
500
1000
300
1290
230
295.5
-1
475
61
182
-
414
324
Total solids
(Ib/day)
153490
-663
10577
324
-26914
-745
-12008
39247
0
24284
2574.9
36506
2954
39460
3227
34026
37253
7552
0
4035
2680
9222
37491
9013
46504
51163
14011
6669
250.2
72093
18614
10757
2876
18084
- 34
42578
11052
53630
1093
-
1724.7
40S.32
2129.39
kg/day
69688
-301
4802
147
-12219
-338
-5452
17818
0
11025
1169
16574
1341
17915
1465
15448
16913
3429
0
1832
1217
4187
17021
4092
21213
23228
6361
3028
113.6
32730
8451
4884
1306
8210
-15
19330
5017
24347
496.16
-
783
184.01
967
(Ib/MWHr)
11.621''
-0.064
1.952
0.065
-31.1
-0.457
-1.91
2.423
0
1.54
0.295
1.652
0.135
1.787
0.169
1.799
1.968
0.345
0
0.334
0.9
0.665
9.82
2.356
12.176
2.06
0.564
0.268
0.01
2.9031
2.41
1.06
0.362
0.9953
-.0034
1.SS35
.1513
1J7048
OJ1904
-
.X553
.0365
0.1928
kg/MWHr
5.272
-0.0292
0.886
0.0296
-14.12
-0.207
-0.867
1.1
0
0.7
0.134
0.075
0.061
0.0811
0.077
0.816
0.893
0.157
0
0.152
0.408
0.302
4.46
1.07
5.53
0.936
0.256
0.122
0.0045
1.319
1.098
0.481
0.164
0.4518
-.0016
.6145
.1595
0.7740
0.0864
-
.0705
.0166
0.0871
mg/1
3328
-110
1852
40
-1309
-18520
-129
330
108
106
328
486
499
447
650
620
0
364
646
75
1059
1081
611
435
460
500
-320
1210
225
-
-
-
-
193
844
445
277
Total
(Ib/day)
143495
-3174
10423
240.2
-26323
-741.41
-6453
35777
648.45
22984
2735
34856
2912
37768
2892
32524
35416
7237
0
12143
2586
8755
35328
9013
44341
49934
11608
6136
125.11
67803
-18614
10090
2812
-
-
-
-
-
1159
20201
1854
346.52
2200
Dissolved Solids
kg/day
65147
-1441
4732
109.04
-11951
-336.6
-2930
16243
294.4
10435
12417
15825
1322
17147
1313
14766
16079
3286
0
5513
1174
3975
16039
4092
20131
22670
5270
2786
56.8
30782
-8451
4581
1277
-
-
-
_
-
526
9171
842
157.32
999
(Ib/MWHr)
10.87
-0.308
1.92
0.483
-30.41
-0.455
-1.026
2.12
0.2048
1.475
0.3127
1.586
0.133
1.719
0.153
1.719
1.873
0.3326
0
1.006
0.868
0.632
9.25
2.356
11.606
2
0.467
0.247
.00504
2.72
-2.398
0.994
0.354
-
-
-
-
-
0.2019
1.785
.1672
.0312
0.1984
kg/MWHr
4.929
-0.14
0.873
0.219
-13.81
-0.206
-0.465
1
0.093
0.67
0.142
0.72
0.06
0.78
0.069
0.78
0.85
0.151
0
0.457
0.394
0.287
4.2
1.07
5.27
0.91
0.212
0.112
0.00229
1.237
-1.098
0.4513
0.1607
-
-
-
_
-
0.0917
0.8098
.0759
.0142
0.0891
mg/1
91
40
27
14
1
11
-111
32
0
-1
-13
23
7
17
94
17
0
-243
51
1
65
3
15
85
35
100
-4
36
5
-
-
-
-
-11
-337
-7
69
Total Suspended Solids
(Ib/day)
3923
1154
152
84.05
20.11
0.44
-5552
3469
0
-216.7
-108.3
1647
40.86
1687.86
141.76
4702
4843.76
198.45
0
-8105
203 . 96
116.74
2167.4
25
2192.4
1224.67
2268
4669
25.02
8186
-300
300
62.53
-
-
_
_
-
-66.05
-8066
-29.07
86.319
57.25
kg/day
1781
524
69
38.16
9.13
0.20
-2521
1575
0
-98.4
-49.2
748
18.55
766.55
64.36
2135
2199.36
90.1
0
-3680
92.6
53
984
11.35
995.35
556
1030
212
11.36
1809
-136.3
136.3
28.39
-
-
-
_
-
-29.98
-17767
-13.2
39.188
26
(Ib/MWHr)
x 106
2 97 J 00
112066
28044
16931
2323
270
-89867
213656
0
-13920
-12445
75110
1868
76978
7467
248678
256145
9141
0
-671800
68491
8266
567841
6555
574396
49339
91418
18819
1008
160584
-39017
29581
7868
-
_
_
_
-
-11504
-712900
-2621
7782
5161
kg/MWHr
x 106
134800
50878
12732
7687
1055
123
-40800
97000
0
-6320
-5650
34100
848
34948
3390
112900
116290
4150
0
-305000
31095
3753
257800
2976
260776
22400
41504
8544
458
72906
-17714
13430
3572
-
-
_
_
-
-5223
-323400
-1190
3533
2343
•total of more than one waste stream for plant
-------
TABLE A-V-9
CHEMICAL HASTE CHARACTERIZATION
ASH Dnun nupppiiw;.-
Plant
Code
3412
3416
3404
3402
3401
3405
1703
1720
1710
1722
1709
1711
1711
*1711
3936
3936
*3936
3927
2616
1808
1729
1718
3930
3930
*3930
1825
1825
1825
1825
•1825
3920
1816
2608
0111
4704
2119
2119
-2119
0107
3514
1716
1716
•1716
Total Hardness ICaCCb )
mg/1
736
25
-
-12
-
-252
-
99
255
357
220
110
207
335
275
-
-
388
51
340
350
406
250
200
270
-
-
0
283
-134.8
272.3
31.3
-
-
83
74
(Ib/day)
31733
1010
-
-72.04
-
-10.04
-
10731
55293
2975
15777
642
16419
1724
16762
18486
3209
-
-
1552
5953
11341
2918
14259
33182
6671
2668
67.55
42588
-
-
0
17319
-4582
24408
5671
30079
-
-
346
92.57
438
kg/day
14407
458.5
-
-32.71
-
-4.56
-
4872
25103
1351
7163
291.55
7454
783
7610
8393
1457
-
-
705
2703
5149
1325
6474
15065
3029
1211.5
30.67
19336
-
-
0
7863
-2078
11081
2574
13655
-
-
157.1
42.02
199
(lb/MWHr)
x 106
2403000
98057
-
-14513
-
-6165
-
662995
3.546xl06
341409
720264
29361
749625
90969
886249
977218
147577
-
-
521445
429687
2970000
764860
3735000
1320000
268881
107541
2722
1699000
-
-
0
953233
-464000
775892
180278
956170
-
-
31057
8346
39403
kg/MWHr
x 106
1090000
44518
-
-6589
-
-2799
-
301000
1610000
155000
327000
13330
340330
41300
402357
443657
67000
-
-
236736
195078
1349000
347248
1696000
600000
122072
48824
1236
772132
-
-
0
432768
-210500
352255
81846
434101
-
-
14100
3789
17889
mg/1
152
2.2
120
8
-240
-996
45
-18
43
63
34
286
-26
158
201
60
123
128
527
98
220
300
180
225
314
132
-
200
28
93
61.5
-
-
-
129.9
446
230
-49
MPT* n Td~*HAR<7F (continuGd )
CHANGE IN PARAMETER LEVEL FROM INTAKE TO DISCHARGE
(Ib/day)
6554
63.48
675.5
48.01
-4826
-42.5
2251
-1951
258.19
13658
258.37
20513
-151.78
20665
1317
10057
11374
700
4308
4268
2109
11440
7339
2501
9840
14709
60044
4189
33.01
78975
-
1667
350.22
5691.5
2090.6
-
-
-
840.07
10675
959
-61.3
897.3
kg/day
2973
28.82
306.68
21.8
-2191
-19.3
1022
-886
117.22
6201
117.3
9313
-68.91
9244
598
4566
5164
318
1956
1938
957.5
5194
3332
1135.8
4467.8
6678
2726
1902
14.99
11321
-
757
159
2584
949
-
-
-
381.1
4846
435.4
-27.83
407.6
(Ib, MWHr)
x 106
496300
6163
124378
9676
-5570000
-26165
357929
-120704
81497
876651
29515
936123
-6940
929183
69603
531749
601352
32158
301762
352420
708205
825674
1922907
655599
2578506
592511
241993
168841
1330
1004675
-
164097
44057
313253
211730
-
-
-
146328
943400
86343
-5526
80817
kg/MWHr mg/1 (Ib/day)
x 106
225100 0.075 3.233
2798
56468
4393
-253000O
-11879
16250O
-5480O 0.011 1.19
3700O
3980OO 0.15 32.51
13400 0.1 0.722
42500O 6 0
-3151 -0.145 -0.8326
421849 -0.8326
31600 . -
241414
273014
14600 0.153 1.784
13700O 1.67 58.48
16000O
321525
374856 1.350 157.62
873000 0.021 0.7
297642 0.021 0.175
1070642 0.875
269000
109865
76654
604
456123
_
74500 6 50
20002
142217
96125
-
-
-
66433 5.30 32.12
4283OO -
39200 -0.22 -0.916
-2509 0.1 0.125
36691 -0.12 -0.791
kg/day
1.468
-
-
-
-
-
-
0.541
14.76
0.378
0
-0.384
-0.384
-
-
-
0.81
26.55
-
-
71.56
0.318
0.0795
0.3975
-
-
-
-
-
-
22.72
-
-
-
-
-
-
14.58
-
-0.4160
0.0568
-0.3592
(Ib/MWHr)
x 106
244
-
-
-
-
-
-
72.68
2070
94.71
0
-39.6
-39.6
-
-
-
81.49
4097
-
-
11376
182.82
46.25
229.07
-
-
-
-
-
-
4912
-
-
-
-
-
-
5597
-
-81.49
11
-70.49
kg/MWHr mg/1
x 106
111 -0.113
0
-
0.01
-
0.139
0.00001
33 -0.014
940
43
0 0
-18 -0.03
-18
0.0005
0.007
-
37 0.011
1860
-
-
5165 0.001
83
21
104
0.080
0.004
0.007
0.005
-
-
2230
-
-
-
-
-
-
2541 0
-
-37
5
-28
(Ib/day)
-4.86
0
-
0.059
-
0.0055
0.0005
-1.515
_
-
0
-0.174
-0.17
0.0044
0.35
0.354
0.1277
-
-
-
0.116
-
-
-
6.54
0.105
0.092
0.001251
6.738
-
-
-
-
-
-
-
-
0
-
-
-
-
kg/day
-2.21
O
-
0.027
-
0.0025
0.00023
-0.688
_
-
0
-0.079
-0.079
0.0019
0.159
0.1609
0.058
-
-
-
0.053
-
-
-
2.97
0.048
0.042
0.000568
3.06
-
-
-
-
-
-
-
-
0
-
-
-
-
(lb/MWHr)
x 106
-368
0
-
11
-
3.407
0.079
-92.5
_
-
0
-8.8
-8.8
0.218
17.6
17.81
5.88
-
-
-
8.81
-
-
-
262
4.4
4.4
0.005
270.85
-
-
-
-
-
-
-
-
0
-
-
-
-
kg/MWHr
x 10s
-167
0
-
5
-
1.547
0.036
-42
-
-
0
-4
-4
0.099
8
8.099
2.67
-
-
-
4
-
-
-
119
2
2
0.023
123.03
-
-
-
-
-
-
-
-
0
-
-
-
-
*total of more than one waste stream for plant
-------
TABLE A-V- 9
CHEMICAL WASTE CHARACTERIZATION
ASH POND OVERFLOW t- MIT DISCHARGE
Plant
Code
3412
3416
3404
3402
3401
3405
1703
1720
1710
1722
1709
1711
1711
•1711
3936
3936
•3936
3927
2616
1808
1729
1718
393O
3930
*393O
182S
1825
1825
1825
•1829
382O
1816
2608
0111
4704
2119
2119
*2119
0101
3514
1716
1716
*1716
•9/1
0
-4
-
-
52
-1609
982
-
26
-
-3
173
30
32
73
14
-
-
3
92
88
27
23
ia
37
—
21
-
-
-
-
-
-
-49
-1M
(Ib/day)
0
-115.4
-
.
1046
-63.43
106467
-
5638
-
-215.63
10O8
793
250.22
1601
1851.22
852.4
489
-
-
350.2
3068
733.83
3801
2204
613.6
240.15
9.25
3067
_
287.7
-
-
-
-
-
-
-
-U7.66
-170
-397.6
Sodium
kg/day
0
-52.4
-
-
56.07
-28.8
48336
-
2560
-
-97.9
458
361
113.60
726.98
840.58
387
222
-
-
159
1393
333.16
1726.16
1001
278.6
109.03
4.2
1392.83
-
130.5
-
-
-
-
-
-
-
-85.2
-77.24
-162.4
- (continued )
CHANGE IN PARAMETER I£VED FROM INTAKE TO DISCHARGE
Alkalinity (CaCCh )
(Ib/MWHr)
x 106
0
-11204
-
-
1209000
-38940
6.58xl06
-
361233
-
-9845
46176
36331
13200
84656
97856
39207
34350
-
-
25275
B03964
192308
996272
88100
24737
9678
372.2
122887
_
37600
-
-
-
-
-
-
-
-16916
-15339
-32255
kg/MHHr
X 106
0
-5087
-
-
548500
-17679
2.99xl06
-
1640OO
-
-4470
20964
16494
6000
38434
44434
178OO
15595
-
-
11475
365000
873 OS
4423O8
40000
11231
4394
169
55794
-
171OO
-
-
-
-
-
-
-
-7680
-6964
-13644
mg/1
-19
-6
0
160
-
-
-110
10
0
2
7
-67
64
13
13
69
-67
28
-94
-15
120
95
75
48
70
65
-38
216
-63
226.4
-6.2
-93.6
-13.7
-16
443.7
-22
15
(Ib/day)
-819.2
-173.1
0
960
-
-
-5504
1084
0
433.7
58.37
-4804
373
-4431
108.37
650.50
758.87
805.5
-2345
934
-376.2
-1751
4002
792.2
4792.2
6130
12810
934
16.25
19890
-2282
1799
-787174
13855
-210.7
-8390
-24R4
-10854
-96.07
10620
-91.74
18.76
-72.98
kg/day
-371.6
-78.6
0
436
-
-
-2499
492.2
0
196.9
26.5
-2181
169.6
-2010.4
49.20
295.33
344.53
365.7
-1065
424
-170.8
-795
1817
359.67
2176
2783
581.6
424
7.38
3786
-1035
817
-357.77
6235
-95.68
-3809
-1118
-4927
-43.61
4821
-41.65
8.51
-33.14
(Ib/MHHr)
x 106
-62000
-16808
0
193508
-
-
-875110
66960
0
27753
6696
-218061
17083
-200978
5726
34392
40118
37004
-162995
77312
-126330
-126378
1048458
207605
1256063
24669
51625
37638
656
114588
-296600
177482
- 99125
755868
-21346
-266709
-77985
-344694
-16736
938600
-8260
' 1692
-6568
kg/MHHr
x 106
-28100
-7631
0
87853
-
-
-397300
30400
0
12600
3040
-99000
7756
-91244
2600
15614
18214
16800
-74000
35100
-57354
-57376
476000
94253
570253
11200
23438
17088
298
52024
-134500
80577
- 45033
343164
-9691
-121086
-35405
-156491
-7598
426100
-3750
768
-2782
mg/1
-0.03
0
-2.4
-
0.66
-3
-5
0
0.1
-5
0
-4.5
-
0.83
1.01
0.51
0
0.38
0.12
-0.04
3.4
1.2
0.55
0.12
1.1
0.5
0.6
-0.13
-
-
-
-
-
-
.
0.4
-5
(Ib/day)
-
-0.859
0
-14.4
-
0.026
-150
-541
0
21.67
-41.69
0
-
-
6.91
50.52
57.43
5.94
0
12.68
0.48
-4.67
113.43
10
123.43
44.9
3.2
14.67
0.1233
62.89
30.02
-1.083
-
-
-
-
-
-
-
-
1.670
-6.255
-4.585
Ammonia (N)
kg/day
-
-0.39
0
-6.54
-
0.012
-68.1
-246
0
9.84
-18.93
0
-
-
3.14
22.94
26.08
2.7
0
5.75
0.218
-2.12
51.5
4.54
56.04
20.4
1.454
6.66
0.056
28.57
13.63
-0.492
-
-
-
-
-
-
-
-
0.76
-2.84
-2.08
(Ib/MHHr)
x 106
-
-83.39
0
-2903
-
16.21
-23852
-33480
0
13.92
-4790
0
-
-
365.68
2671
3036
273.12
0
1000
160.8
-337
29713
2623
32336
1806
129.9
592.5
5.044
kg/MHHr
x 106
-
-37.86
0
-1318
-
7.36
-10829
-15200
0
6.32
-2175
0
-
-
166
1213
1379
124
0
500
73
-153
13490
1191
14681
820
59
269
2.29
mg/1
-
-
0
0.24
-
-0.33
-0.73
0.12
0
1.3
0.04
1.0
0.16
0.8
0.6
0.33
0
0.72
1.19
0.09
4.2
0.97
6.1
2.6
0.07
4.6
2533 1150.3
3900
-105.72
-
-
-
-
-
-
-
-
149.78
-564
415.78
1771
-48
-
-
-
-
-
-
-
-
68
-256
-188
-0.8
-1.35
-0.19
-
-
-
-
-
—
0.09
0.23
(Ib/day)
-
-
0
1.44
-
-0.01
-36.52
13
0
282
0.33
71.7
1.51
73.21
6.87
30.02
36.89
3.85
0
24
4.75
10.5
140
8.08
148.08
498
69.38
0.934
1.149
569.46
-48.04
-11.25
-2.37
-
-
-
-
-
-
-
0.374
0.287
0.661
Nitrate (Ml
kg/day
-
-
0
.65
-
-0.005
-16.58
5.9
0
128
0.15
32.560
0.689
33.249
3.12
13.63
16.75
1.75
0
10.9
2.16
4.77
63.6
3.67
67.27
226.3
31.5
0.424
0.522
258.74
-21.79
-5.11
-1.08
-
-
-
-
-
-
-
0.17
0.13
0.3
(Ib/NNHr)
x 10*
.
-
0
290
-
-6
-5806
804
0
18061
37.45
3260
70.48
3330
361
1588
1949
176.2
0
1982
1597
757
36696
2119
38815
20044
2797
37.44
46.25
22924
-6000
-1110
-299.6
-
-
-
-
-
-
-
33
26
59
kg/MWHr
x 106
-
-
0
132
-
-3
-2636
365
0
8200
. 17
1480
32
1512
164
721
885
80
0
900
725
344
16660
962
17622
9100
1270
17
21
10408
- 2700
-504
-136
-
-
-
-
-
-
-
15
12
27
•total of
one waste stream for plant
-------
TABU: Arv- 9
CHEMICAL WAS1E CHARACTERIZATION
ASH POND OVERFLOW! - NET DISCHARGE (contlnuted)
CHANGE IN PARAMETER I£VEL PROM INTAKE TO DISCHARGE
tode Chloride
3412
3416
3404
3402
3401
3405
1703
1720
1710
1722
1709
1711
1711
*1711
3936
3936
•3936
3927
2616
1808
1729
1718
3930
3930
*3930
1825
1825
1825
1825
*1825
3920
1816
2608
Olll
4704
2119
2119
*2119
0107
3514
1716 '
1716
*1716
mg/1
2415
-1
1700
13.5
-140
-
15
75
1
34
81
21
-16
35
51
161
2
1
41
8
120
120
30
29
32
152
-
41
-
-2.5
-43.7
-13.4
-16.4
-
73
163
26
(Ib/day)
104121
-28.85
9570
81.01
-2815
-
750.5
8130
6
7372
675.3
1506
-93.4
1412.6
291.85
2551
2842
1879
70.04
33.35
164.1
934
4002
1000
5002
2451
773.78
426.8
38.01
3689
-
341.4
-
-153
-1485
-1201
-2971
-4172
-
1747
679.6
32.52
712.1
kg/day
47271
-13.1
4345
36.78
-1278
-
340.74
3691
2.726
3347
306.6
683.7
. -42.4
641.3
132.5
1158.5
1291
853.3
31.8
15.144
74.5
424
1817
454.3
2271
1113
351.3
193.8
17.26
1675
-
155
-
-69.46
-674
-545.3
-1349
-1894
-
793.2
308.56
14.76
323.32
(Ib/MWHr)
x 106
7885000
-3215
1765918
16319
-3230000
-
119350
503295
1898
473678
77588
68859
-4271
64588
15431
134909
150340
86594
4907
2768
55101
67400
1049000
262240
1311000
98804
31189
17207
1533
148733
-
33480
-
-8421
-150449
-38183
-94458
-132641
-
-
61273
2932
64105
Copper
kg/MWHr mg/1 (Ib/day) kg/day (Ib/MWHr) kg/MWHr
x 106 x 106 x 106
3577000 -0.001 -0.043 -0.0196 -3 -1
-1460 00 00 0
801727 -
7409 -0.006 -0.0359 -0.0163 -6.6 -3
-1470000 - - - ...
_
54185 - - - -
228496 - - - -
862 - - - -
215050 - - - -
35225 0.02 0.166 0.075 18.94 8.6
31262 ' -
-1939 -
29323 ...
7006 - - - -
61249 -
68255 -
39314 0.005 0.0573 0.026 2.62 1.19
2228 -. - - -
1257 -
25016 -0.037 -0.148 -0.0672 -50.66 -23
30600 - - - -
476226 - - - -
119057 -
595283 -
44857 - - - -
14160 -
7812 -
696 - - - -
67525 -
-
15200 -
-
-3823 -
-68303 - - - -
-17335 -
-42884 - - - -
-60219 ...
0.06 0.36 0.1635 62 28
_
27818 - - - -
1331 -
29149 -
mg/1
-0.479
0.045
-
-4.6
-
-
-
0.6
-
0.28
0.001
0
-0.252
0.034
0.040
0.099
1.770
-
-0.593
-0.387
-
-
0.02
0.09
0.032
0.098
0.141
-
-
-
0.44
2.894
_
0.15
-
-
-
(Ib/day)
-20.65
1.297
-
-27.62
-
-
-
65
-
60.7
0.008326
0
-1.4978
-1.4978
0.2819
2.0
2.2819
1.15
61.98
-
-2.37
-45.8
-
-
-
1.634
2.4
0.4270
0.0245
4.4855
-
-
-
26.92
98.37
_
-
0.9
-
-
-
-
Iron
kg/day
-9.376
0.589
-
-12.54
-
-
-
29.53
-
27.56
0.00378
0
-0.68
-0.68
0.128
0.908
1.208
0.524
28.14
-
-1.077
-20.8
-
-
-
0.742
1.09
0.194
0.0111
2.037
-
-
-
12.22
44.66
— t
-
0.409
-
-
.-
-
(Ib/MWHr)
x 106
-1600
125.55
-
-5563
-
-
-
4008
-
3898
0.9559
0
-68.28
-68.28
14.98
105.72
120.70
52.86
4341
-
-797
-3306
-
-
-
63.87
96.9
17.6
0.984
179.35
-
-
-
1482
9963
_
-
32
-
-
-
-
Manqanese
kg/MWHr mg/1 (Ib/day) kg/day (Ib/MWHr)
x 106 x 106
-726 -
57
-
-2626 -
-
_
-
1820 -
- - -
1770 0.02 4.34 1.97 277.5
0.434 0.0002 0.001652 0.0
-------
s
Plant
TABIE A-V- 9
CHEMICAL HASTE CHARACTERIZATION
ASH POND OVERFLOW - NET DISCHARGE (continued)
CHANGE IN PARAMETER USVEL FROM INTAKE TO DISCHARGE
Zinc
~"""- —
3412
3416
3404
3402
3401
3405
1703
1720
1710
1722
1709
1711
1711
*1711
3936
3936
*3936
3927
2616
1808
1729
1718
3930
3930
*3930
1825
1825
1825
1825
^825
3920
1816
2608
0111
4704
2119
2119
•2119
0107
3514
1716
1716
•1716
mg/1
156
-
-
-11
-
-
-
18
-
25
-
-3
10
15
14
21
0.1
-
-
-2
-
-
0
12
11
12
-
-
-
-3.8
-1.9
-
-
-
10
6
18
(Ib/day)
6724
-
-
-54.03
-
-
-
1951
-
5420
-
-215.6
58.37
-157.23
125.11
700
825.11
244.5
3.50
-
-
-233.48
-
-
-
0
320.26
146.76
2.99
470
-
-
-
-232.55
-64 . 58
-
-
-
-
239.36
25.02
22.52
47.54
kg/day
3053
-
-
-24.53
-
-
-
886
-
2461
-
-97.9
26.5
-71.4
56.8
318
374.8
111
1.59
-
-
-106
-
-
-
0
145.4
66.63
1.36
213.4
-
-
-
-105.58
-29.32
-
-
-
-
108.67
11.36
10.22
21.58
(Ib/MWHr)
x 106
509200
-
-
-10885
-
-
-
120704
-
348017
-
-9846
2669
-7177
6608
37037
43645
11233
3898
-
-
-16850
-
-
-
0
12907
5914
121.1
13942
-
-
-
-12800
-6542
-
-
-
-
21100
2247
2031
4278
kg/MWHr
x 106
231000
-
-
-4942
-
-
-
54800
-
158000
-
-4470
1212
-3258
3000
16815
19815
5100
1770
-
-
-7650
-
-
0
5860
2685
55
8600
-
-
-
-5811
-2970
-
-
-
-
9600
1020
, 922
1942
mg/1 (Ib/day) kg/day (Ib/MWHr) kg/MWHr mg/1 (Ib/day) kg/day (Ib/MWHr) kg/Mifflr mq/1
x 106 ' x 106 x 106 x 106
- - - - - -0.054 -2.32 -1.057 -175 -80 -0.014
----- 0.162
0.00013
-. -_ - -----
----- 0.17
- - - - 0.117
-- -- - _---_0
----- -0.073
-_ -_ - -----
0.0002 0.044 0.0197 2.77 1.26 0.01 2.167 0.984 139.2 63.2 0.03
-- - ----- 0.011
-. _- - -----
- - -- - _____
-- - -----
-- - ----- 0.009
-- -- - ----- 0.009
__ _ -_-_
0.011 0.1277 0.058 5.88 2.67 0.003
_- -- - -----
-0.01
-0.002 -0.00793 -0.0036 -0.44 -0.2 -----
-- -- - ----- o.03
- - - 0.015 0.5 0.227 130.83 59.4 0.003
- - - - - 0.008 0.066 0.0302 17.62 8 0.013
- - - 0.566 0.257 148.45 67.4
-- -- - ----- o.07
-- -- - --- - - -0.007
-- -- - ----- -0.006
-- - ----- 0.001
--_- ----
_- _- _ -----
-- -- - -----
-- -- - --___
-- -- - -----
-- _- - -----
-- -- - -----
-- -- - -----
.-_- -----
oo oo o _-_-- 0.05
-- - -----
-- -- - ----- 0.12
-- -- - ----- -0.02
.--- ----
(Ib/day)
-0.603
4.67
0.00073
-
3.41
0.00467
0
-7.9
-
6.5
0.09
-
-
-
0.0749
0.45
0.5249
0.035
-
-0.332
-
3.5
0.099
0.108
0.207
5.7
-0.185
-0.079
0.000251
5.436
-
-
-
-
-
-
-
-
0.30
-
0.5
-0.025
0.475
kq/day
-0.274
2.12
0.00032
-
1.552
0.00212
0
-3.59
-
2.953
0.041
-
-
-
0.034
0.2044
0.2384
0.0159
-
-0.151
-
1.59
0.0450
0.0492
0.0942
2.59
-0.084
-0.036
0.000114
2.47
-
-
-
-
-
-
-
-
0.14
-
0.227
-0.0113
0.216
llb/MWHr)
X 106
-45
453.7
0.134
-
3951
2.86
0
-489
-
416.23
10.35
-
-
-
3.94
24.23
28.17
1.6
-
-2.75
-
253.3
24.229
28.63
52.959
231.27
-6.6
-2.2
0.011
222.48
-
-
-
-
-
-
-
-
50
-
44
-2.2
41.8
kg/MWHr
x 106
-20
206
0.061
-
1794
1.301
0
-222
-
189
4.7
-
-
-
1.79
11
12.79 •
0.73
-
-1.25
-
115
11
13
24
105
-3
-1
0.005
101
-
-
-
-
-
-
-
-
24
-
20
-1
19
•Total of more than one waste stream for plant
-------
TABI£ A-V- 9
CHEMICAL WASTE CHARACTERIZATION
A3H POND OVERFLOW - NET DISCHARGE (continued)
CHANGE IN PARAMETER I£VEL FROM INTAKE TO DISCHARGE
Plant
Code
3412
3416
3404
3402
3401
3405
1703
1720
1710
1722
1709
1711
1711
*1711
3936
3936
*3936
3927
2616
1808
1729
1718
3930
3930
*3930
1825
1825
1825
1825
*1825
3920
1816
2608
0111
4704
2119
2119
*2119
0107
3514
1716
1716
*1716
Phosphorus ^p'
mg/1
-
-
0
0
-
-0.5
-0.33
-0.7
-
-0.09
-1.19
-0.7
~
0.1
0.2
0.14
0
0.26
0.08
-0.05
-
-
-
-
-
-
-0.09
0.41
-0.06
-
-
-
-
-
-
-0.23
-0.23
(Ib/day)
-
-
0
0
-
-0.02
16.5
-75.88
-
-19.51
-9.91
-50.22
-
-50.22
0.815
10
10.815
1.63
0
8.65
0.319
-5.83
-
-
-
-
-
-
-
-
-5.4
3.41
-0.749
-
-
-
-
-
-
-
-0.958
-0.280
-1.238
kg/day
-
-
0
0
-
-0.01
-7.49
-34.45
-
-8.86
-4.5
-22.8
-
-22.8
0.37
4:54
4.91
0.74
0
3.93
0.145
-2.65
-
-
-
-
-
-
-
-
-2.45
1.55
-0.34
-
-
-
-
-
-
-
-0.435
-0.13
-0.565
(lb/l*mr)
x 106
-
-
0
0
-
-10
-2623
-33480
-
-1253
-1136
-2290
-
-2290
41.8
528
569.8
74.89
0
718
107.93
-420
-
-
-
-
-
-
-
-
-702.6
337
-94.7
-
-
-
-
-
-
-
-85.9
26
-59.9
kg/MWHr
x 106
-
-
0
0
-
-5
-1191
-15200
-
-569
-516
-1040
-
-1040
19
240
259
34
0
326
49
-191
-
-
-
-
-
-
-
-
-319
153
-43
-
-
-
-
-
-
-
-39
12
-27
Sulfite, Lead, Oil and Grease,
Phenols, Surfactants. Alqicldes
-5
13
-29
183
8
0
10
27
-14
1
-2
-22
-2.2
16.3
-13
-13
*total of more than one waste stream for plant
-------
In that table, plant capacities range from 31 Mw to 2,533 Mw
and the ash pond overflow varies between 1,817 cu m/day
(480,000 gpd) and 122,946 cu m/day (32,473,000 gpd).
Because of the large variation in quality of coal used in
powerplants, the data also show a wide variation in
concentration of trace metals in the effluent. Some of the
metals discharged may be harmful to aquatic life.
Oil
The ash content of fuel oils is low (about 1% of the amount
commonly found in coal). 27a It is generally 0.10 to 0.15%
by weight, although it may be as high as 0.2%.
The quantity of ash produced in an oil-fired plant is very
small, but the settling characteristics of oil ash are not
as favorable as those of coal ash. It has been found that
in some cases recycling oil fly into the furnance increases
efficiency and eliminates the fly ash disposal problem. De-
pending on the vanadium content of the oil, the dry bottom
ash can actually be a saleable by-product.
Most oil ash deposits are partially soluble and can be re-
moved by water washing. Generally the washing is done while
the unit is out of service. In-service water washing at re-
duced loads has been practiced to some extent, using the
hot, high-pH boiler water in carefully regulated amounts.
Limited data are available on the characteristics of oil ash
handling waste water. Table A-V-9 lists 6 plants which use
both coal and oil, but only one plant is listed using oil
alone. No data are reported for vanadium in waste streams.
In certain cases, however, when other means of collecting
the vanadium are not available, the content of vanadium in
waste water should be evaluated, because of its possibly
toxic effect on aquatic life.
Coal Pile Runoff \
For coal-fired generating plants, outside storage of coal at
or near the site is necessary to assure continuous plant
operation. Normally, a supply of 90 days is maintained.
These storage piles are typically 8 to 12 meters (25-40 ft)
high spread over an area of several square meters (or
acres). Typically from 600 to 1,800 cubic meters (780 to
2340 cu yd) are required for coal storage for every Mw of
rated capacity. As such a 1000 Mw plant would require from
600,000 to 1,800,000 cubic meters (78,000 to 2,340,000 cu
yd) of storage. Depending on coal pile height, this
160
-------
represents between 60,000 to 300,000 square meters (15-75
acres) of coal storage area.
Coal is stored either in active piles or storage piles. Ac-
tive piles are open and contact of active coal with air and
moisture results in oxidation of metal sulfides, present in
the coal, to sulfuric acid. The precipitation trickles or
seeps into coal piles. When rain falls on these piles, the
acid is washed out and eventually winds up in coal pile
runoff. Storage piles are sometimes sprayed with a tar to
seal their outer surface. In such cases, the precipitation
runs down the side of the pile.
Based on typical rainfall rates, pile runoff may range from
64,000 to over 32,0000 cubic meters (17 to 85 million gal-
lons) per year with average figures around 75,000 to 100,000
cubic meters (20 to 26 million gallons) per year. Table A-
V-10 presents the amount of coal consumed per day, area and
height of coal pile, average rainfall and runoff from
various coal-fired generating plants across the country.
Liquid drainage from coal storage piles presents a potential
danger of stream contamination, if it is allowed to drain
into waterways or to seep into useful aquifers. Ground
seepage can be minimized by storing the coal on an
imprevious base. Vinyl liners of various thicknesses have
been used for that purpose. To prevent the sharp edges of
coal particles from puncturing the liner, a 15 cm(6") bed of
sand or earth is placed on top of a liner before forming the
coal pile.
Water pollution associated with coal pile runoff is due to
the chemical pollutants and suspended solids usually trans-
ported in coal pile drainage. Drainage quality and quantity
is variable, depending on the meteorological condition, area
of pile and type of coal used. Areas of high average rain-
fall have much higher drainage than those of low average
rainfall. Contact of coal with air and moisture results in
oxidation of metal sulfides to sulfuric acid and precipita-
tion of ferric compounds. High humidity areas have higher
precipitation and produce larger runoffs.
Coal pile runoff is commonly characterized as having a low
pH (high acidity) and a high concentration of total dis-
solved solids including iron, magnesium and sulfate. Unde-
sirable concentrations of aluminum, sodium, manganese and
other metals may also be present. Contact of coal with air
and moisture results in oxidation of the metal sulfides
present in the coal to sulfuric acid. Pyrites are also oxi-
dized by ferric ion to produce ferrous sulfate. When rain
161
-------
TABLE A-V-10
COAL PILE DRAINAGE
PLANT
ID
4701
4706
4702
4705
4703
2120
4704
2119
0112
5305
COAL CONSUMED/DAY
Ibs Kgs
xlflS xlO6
15 6.81
31 14.07
15 6.81
27.6 12.53
20.6 9.35 '
25.4 11.53
14.34 6.51
47.6 21.6
35.8 16.25
-
AREA OF PILE
Acres M^
x!03
25 101.85
58 236.29
75 305.55
28 114.07
18 73.33
61 248.5
21 85.55
25 101.85
25 101.85
120 488.8
HEIGHT OF PILE
Ft. Meters
40 12.19
25 7.62
17 5.18
25 7.62
40 12.19
22 6.7
25 7.62
-
40 12.19
AVERAGE ANNUAL
RAINFALL
Inches Meters
44 1.117
-
54.7 1.389
-
45.84 1.164
-
43.1 1.094
44.4 1.1277
: -
60 1.524
RUN -OFF PER YEAR
Million M3
Gallons xlO3
20 75.7
-
25 94.62
-
25 94.62
-
17 64.34
22 83.27
26.5 100.3
-
CTl
ro
-------
falls on these piles, the acid is washed out and eventually
winds up in the coal pile drainage. At the low pH produced,
other metals such as aluminum, copper, manganese, zinc, etc.
are dissolved to further degrade the water.
Coal pile runoff, like coal mine drainage, can be classified
into three distinct types according to chemical
characteristics. The first type of drainage will usually
have a pH of 6.5 to 7.5 or greater, very little or no acid-
ity, and contain iron, usually in the ferrous state. Alka-
line drainage may occur where no acid-producing material is
associated with the mineral seam or where the acid is
neutralized by alkaline material present in the coal. Some
alkaline waters have high concentration of ferrous ion, and,
upon oxidation and hydrolysis, precipitate large amounts of
iron. .
A second type of drainage is highly acidic. This water con-
tains large amount of iron, mostly in ferrous state, and
aluminum.
Although the exact reaction process is still not fully
understood, the formation of acid coal pile drainage can be
illustrated by the following equations. Initial reaction
that occurs when iron sulfate and sulfuric acid
2 F6S2+7 02 +2 H2O = 2 FeSOU+2 H2SOU
Subsequent oxidation of ferrous sulfate produces ferric sul-
fate:
4 FeSOtt+2 H2SOU+O2 = 2Fe2 (SO4) 3+ 2 H2O
Depending on physical and chemical conditions, the reaction
may then proceed to form ferric hydroxide or basic ferric
sulfate:
Fe2(S04)3+6H20 = 2Fe (OH) 3+3H2SOU
Fe2(S04)3 + 2H20 = 2Fe (OH) (SOU) +H2SO4
Pyrites can also be oxidized to ferric ions as shown below:
FeS2+lU Fe+'+8H2O = 15
Regardless of the reaction mechanism, the oxidation of one
mole of pyrite ultimately leads to the release of two moles
of sulfuric acid (acidity) .
163
-------
Other constitutents found in coal pile drainage are produced
by secondary reactions of sulfuric acid with minerals and
organic compounds present in the coal. Such secondary reac-
tions are dependent upon type of coal and physico-chemical
conditions of the pile.
The pollution of streams by coal-pile runoff may be at-
tributed to higher concentration of dissolved solids,
mineral acid, iron, and sulfate present in the runoff. In
addition, aluminum, copper, zinc and manganese may be
present. The degree of harm caused by these elements is
compounded by synergisir amcng several of them; for example
zinc with copper. The harmful effects of iron, copper and
zinc solutions can be greater in the acid water polluted by
coal pile drainage than in neutral or alkaline water. Data
reported from various plants are shown in Table A-V-11. An
inspection of these data reveals an extremely large
variation in the pollutant parameters listed. The
concentration of runoff is dependent on the type of coal
used, history of the pile and rate of flow. Plant nos.
1729, 3626, and 0107 using high sulfur coal are highly
acidic (low pH), and have high sulfate and metallic
concentrations.
The acidity, sulfate and metal concentrations of plant no.
3505 which uses very low sulfur coal are very small. The
concentration of pollutants during heavy rainfall will be
very small after an initial removal of precipitated material
from coal, while during low flow conditions the retention
time may be high enough to complete oxidation, resulting in
higher runoff concentrations.
Floor and Yard Drains
A steam electric powerplant contains a number of potential
sources of wastewater in the nature of piping and equipment
drainage and leakage. The list in Table A-V-12 is a
representative compilation of sources, showing major
contaminants, the likely frequency, potential severity of
discharges, and control technologies that might be
considered.
The floor drains within a powerplant which collect equipment
drainage and leakage generally include dust, fly ash, coal
dust (coal-fired plants) and floor scrubbing detergent.
This waste stream also contains lubricating oil or other
oils which are washed away during equipment cleaning, oil
from leakage of pump seals, etc., and oil collected from
spillage around storage tank area.
164
-------
TABLE A-VT11
CHEMICAL WASTE CHARACTERIZATION
COAL PILE DRAINAGE
Line
1)
2)
3)
4)
5)
6)
7)
8)
9)
10)
11)
Plant
Code
3402
3401
3936
1825
1726
1729
3626
0107
5305
5305
5305
B
AlXalinitv
mg/1
6
0
0
-
82
-
-
0
21.36
14.32
36.41
C
mg/1
0
0
10
-
3
-
-
-
-
-
-
D
mg/1
1080
1080
806
85
1099
-
-
-
-
-
-
E
rag/1
1330
1330
9999
6000
3549
-
-
45000
-
-
-
P
mg/1
720
720
7743
5800
247
-
28970
44050
-
-
-
G
mg/1
610
610
22
200
3302
-
100
950
-
-
-
H
Ammonia
mg/1
0
0
1.77
1.35
0.35
-
-
-
-
-
-
Discharge Concentrat
Nitrate Phosphorus
mg/1
0.3
0.3
1.9
1.8
2.25
-
-
-
-
-
-
mg/1
_
-
1.2
-
0.23
-
-
-
-
-
-
ions.
mg/1
505
505
-
-
-
-
-
-
8.37
2.77
6.13
L
Acidity
mg/1
_
-
-
-
-
-
21700
27810
8.68
10.25
8.84
M
Total
Hardneaa
• mg/1
130
130
1109
1850
-
-
-
-
-
-
-
N
Sulfate
mg/1
525
525
5231
861
133
6837
19000
21920
-
-
-
O
Chloride
mg/1
3.6
3.6
481
-
23
-
-
-
-
-
-
P
Aluminum
mg/1
_
-
-
-
-
-
1200
825
-
-
-
Q
Chromium
mg/1
0
0
0.37
0.05
-
-
15.7
0.3
-
-
-
Discharge Concentrations
Plant
Line Code Copper
1)
2)
3)
4)
5)
6)
7)
10)
11)
3402
3401
3936
1825
1726
1729
3626
8) 0107
9) 5305
5305
5305
mg/i
1.6
1.6
1.8
3.4
C
Iron
mg/1
0.168
0.168
-
0.06
-
0.368
4700
93000
1.0
1.05
0.9
D E
Haqnesium Zinc
mg/1 mg/1
1.
1.
89 2.
174 0.
0.
-
12.
23
-
-
-
6
6
43
006
08
5
P G
Sodium pH
mg/1
1260 2
1260 2
160 3
4
7
2
2
2
6
6
6
pH
.8
.8
.4
.8
.7
.1
.8
.7
.6
.6
-------
Table A-V-12
Equipment Drainage, Leakage 444
Source Major Contaminants
Oil-water Heat
Exchangers
Oil Tank, Lines &
Transformer Rupture
Floor spills
Oil Drips and
Tank Leakage
Sump Discharges from
Service Bldg. & Yard
Chemical Tank
Rupture
Chemical Tank
Leakage
Oil
Oil
Suspended Solids
or Oil
Oil
Oil and
Suspended Solids
Regenerant and
cleaning chemicals
Regenerant and
cleaning chemicals
Frequency
Remote
Possibility
Remote
Possibility
Daily
Daily
Often
Remote
Possibility
Occasional
Potential Severity Potential Control Techniques
Severe
Severe
Slight
Slight
Slight
Severe
Slight
1. Continuous Gravity Separation
2. Detection and Batch Gravity
Separation
3. Detection & Mechanical Separation
A.' Maintain pressure of water
greater than oil
1. Isolation from Drains
2. Containment of Drainage
1. Plug Floor Drain
2. Route Floor Drainage Throut .
Clarif ier & gravity or meet anical
separation
1. Isolate from Floor Drains
2. Route to Gravity or Mechanical
Separation
1. Isolate and route through clarified
and gravity or mechanical
separation
1. Containment of Drainage
2, Isolation from Drains
3. Route Drains to Ash Pond or Hold-
ing Pond for neutralization
1, Isolate from Floor Drains
2, Route Drains to Ash Pond or
Holding Pond
NOTE: oil Spill Contingency Plans would apply to significant oil releases.
-------
No data regarding the flow and composition of this waste
stream have been reported, however, oil, suspended solids,
and phosphate from floor scrubbing detergent may be present
in the floor drains. The discharge stream will be acidic if
any wash water from air preheater or fireside of the boiler
winds up in floor drains.
Air Pollution Control Devices
A number of processes have been proposed for removing
particulate and SO2 emissions from stack gases. Some of
these processes have been suggested for potential
application in fossil-fuel powerpiants. In general the SO2
removal processes can be categorized, according to Reference
123, as follows:
(1) Alkali scrubbing using calcium carbonate or lime
with no recovery of SO2.
(2) Alkali scrubbing with recovery of SO2 to produce
elemental sulfur or sulfuric acid.
(3) Catalytic oxidation of SO2 in hot flue gases to
sulfur trioxide for sulfuric acid formation.
(4) Dry-bed absorption of SO2 from hot flue gases
with regeneration and recovery of elemental sul-
fur.
(5) Dry injection of limestone into the boiler furnace
for removal of SO2 by gas-solid reaction.
The removal of particulates from stack gases can also be
carried out separately - using an electrostatic precipitator
or a dry mechanical collector, wet scrubbing for SO2_ removal
can be applied subsequently.
The waste water problems are mainly concerned with wet
processes (first three types mentioned above). Wastewater
problems associated with particulate (fly-ash) removal de-
vices are described in an earlier portion of this section of
the report.
At present three wet processes are under development or in
use: alkali scrubbing with and without SO2 recovery, and
oxidation of SO2 for sulfuric acid production. Of the three
processes, data is available mainly for the alkali scrubbing
process without S02 recovery, s and consequently only this
process is described briefly in the following paragraph.
Flue gas from electrostatic precipitators (optional equip-
ment) is cooled and saturated by water spray. It then
167
-------
passes through a contacting (scrubbing) device where SO2 is
removed by an aqueous stream of lime absorbent. The clean
gas is then reheated (optional step) and vented to the at-
mosphere through an induced draft fan if necessary. The
lime absorbent necessary for scrubbing is produced by
slaking and diluting quicklime in commercial equipment and
passing it to the delay tank for recycle as a slurry through
the absorber column (s). Use of the delay tank provides
sufficient residence time for the reaction of dissolved SO2
and alkali to produce calcium sulfite and sulfate. The
waste sulfite/sulfate is them pumped as a slurry to a lined
settling pond or mechanical system where sulfite is oxidized
to sulfate. The clear supernatent liquid is returned to the
process for reuse. The waste sludge containing fly ash (if
electrostatic precipitator is not employed) and calcium
sulfate is sent f,or disposal (as a landfill).
The process described above has the potential for scaling
problems. The calcium salts tend to form a deposit, which
may cause equipment shutdown and maintenance.
The process is a closed loop type and consequently there is
no net liquid discharge from the process. The disposal of
sludge has been covered in the literature. However,
depending upon the solids separation efficiency in a pond or
mechanical equipment, there may be excess free water as-
sociated with the sludge. To dewater this sludge,
mechanical filtration equipment may be necessary.
To date eleven or more utilities have committed themselves
to full-scale installation of the alkaliscrubbing process
without SO 2 recovery. During the course of the present
study, visits were made to two plants for observing the
scrubbing devices. However, in plant no. 1720, the scrubber
was not running because of operational problems. The pro-
cess for the other plant (no. 4216) is described below.
Plant no. 1216 of 79 Mw capacity burns 0.7X sulfur coal.
The boiler gases are split into two streams - approximately
7556 going to a scrubber and the remaining 25% going to an
electrostatic precipitator. The exhaust gases from the two
are then recombined and vented to atmosphere at 210°F. This
splitting of the boiler gases is done to reheat the scrubber
exhaust gases which are at 12U°F (saturated). This stack gas
reheating is achieved to minimize scaling problems from
moist gases. The scrubber is not specifically used for SO2
removal. Rather, the primary function is to remove
particulates. On the other hand, seme SO2 pick-up may be
achieved based on Figure A-V-30 where the net output from the
process (thickener underflow) is richer in sulfate than the
168
-------
.STACK GASES
@~210°F
, LIME SLURRY .
-450 GPM
•
pH 5.6
FLYASH FROM
PRECIPITATOR
AND SERVICE
WATER DISCHARGES
~ 90.000 SCFM
STEAM TO TURBINES
1
BOILER
(79 MW PLANT)
.~ 270.000 SCFM ,
• FLUE GASES •
•~ 360.000 SCFM ^
INLET ^-*
SCRUBBER LIQUOR
NOTE: IN THIS PLANT 25% OF THE
FLUE GASES GO THROUGH
THE ELECTROSTATIC PRECIPITATOH
AND NOT THROUGH THE SCRUBBER
~3500 GPM
OVERFLOW
~ 2500 GPM
/ UNDERFLOW.
800-1000 GPM '
OVERFLOW
750 GPM
RIVER WATER MAKEUP
~ 160 GPM
p
^
\
^r
T r
1 v
?)
| ~65 GPM
M
MAX
STREAM #:
PARAMETER
pH
ACIDITY PP
ALKALINITY MO
HARDNESS
SULFATE
SULFITE
TDS DRY 103°C
TSS
ECTROLY
I
ICKENER
^
TE
©
UNIT
IN PPM
_
CaCO3
CaCOj
CsCOj
S°4
S03
PPM
PPM
11
HOLDING
SUMP
1 vO
/TN1
SETTLING
POND
C-Lc OVERFLOW
• '* 'TO RIVER
^ LOSS TO SOIL
i
I J -500 GPM
1
INLET
SCRUBBER
WATER
2.0
3900
0
1950
4095
cl
7910
8480
2
THICKENER
UNDERFLOW
2.7
3600
0
1950
4067
<1
7665
176.680
3
LIMED
WATER
9.2
0
68
1800
1287
<1
2390
318.800
4
DISCHARGE
TO POND
6.7
5
80
696
520
<1
1095
70,780
5
DISCHARGE
TO RIVER
7.2
5
32
484
377
<1
750
5
R
RIVER
WATER
6.7
3.7
22
58
25
<1
130
130
i
UNDERFLOW f_"\
. 36-60 GPM
FIGURE A-V-10 FLOW DIAGRAM AIR POLLUTION CONTROL SCRUBBING SYSTEM AT PLANT NO. 4216
-------
process input (river water). However, some of the increase
in sulfate may be due to chemicals added to enhance
particulate removal. The flow diagram and the different
stream compositions are shown in Figure No. A-V-10.
For a more complete review of the status of air pollution
control technology for steam electric powerplants, see
References 470-473.
Sanitary Wastes
The amount of sanitary waste depends upon the number of
employees. This in turn is dependent upon the type of
plant-rcoal, oil, or gas, its size and its age. A power-
plant employs administrative personnel and plant personnel
(plant crews and maintenance personnel). Coal-fired plants
require more operational personnel then others. For a coal-
fired plant, the breakdown in types of employees is
typically as follows:
operational personnel: 1 per 20-40 Mw
maintenance personnel: 1 per. 10-15 Mw
administrative personnel: 1 per 15-25 Mw
A typical three boiler 1,000 Mw coal-fired plant may employ
150-300 people. Whereas, in a oil plant of similar size,
the total number of employees may be in the range of 80-150.
The typical parameters which define the pollutional
characteristics of sanitary wastes are BOD-5 and suspended
solids. The following table lists per capita design esti-
mates for the waste stream:
Office-Admin. 0.095cu m/day 30 g 70 g
(25 gpd) (0.07 Ib) (0.15 Ib)
Plant 0.133 cu m/day 40 g 85 g
(35 gpd) (0.09 Ib) (0.19 Ib)
Knowing the number of personnel in the office-administrative
and plant categories, the characteristics of the raw sewage
waste stream can be estimated. Typically, for an oil-fired
plant generating 1,000 Mw the personnel required might be 20
office and administrative, and 85 plant personnel. The raw
sewage characteristics for this plant can be estimated on
the basis presented above as follows:
170
-------
FLOW
BOP-5
Office-Admin.
Plant
Total
1.890 cu m/day
(500 gpd)
1.125 cu m/day
(2975 gpd)
3.015 cu m/day
(3475 gpd)
635 g
(1.40 Ib)
3480 g
(7.65 Ib)
4115 g
(9.05 Ib)
1360 g
(3.00 Ib)
7330 g
(16.15
8690 g
(19.15 Ib)
The sanitary waste from steam electric powerplants is
generally similar to municipal sanitary wastes with the
exception that powerplant wastes do not normally contain
laundry or kitchen wastes. Moreoverf the per capita
hydraulic loading for powerpiant personnel is relatively
small (25 to 35 gallons) in comparision to domestic usage
(100 to 150 gallons). Normally the local health agencies
dictate requirements for treating sanitary wastes. In
metropolitan areas, the raw sewage may be discharged to a
municipal treatment plant. In rural areas, packaged
treatment plants for sanitary wastes may be employed.
Plant Laboratory and Sampling Streams
Laboratory facilities are maintained in many steam electric
powerplants to carry out chemical analysis for checking dif-
ferent operations such as ion exchange, water treatment,
boiler tube cleaning requirements, etc. The size of the
laboratory depends upon the size, type, and age of the
plant. Modern high pressure steam plants require closer
control on the operations and consequently increased
laboratory activity. In nuclear plants the use of a
laboratory is extensive.
The waste from laboratories vary in quantity and
constituents, depending upon the use of the facilities and
the type of powerplant.
Laboratory facilities for steam electric powerplants also
vary considerably depending on the age of the plant and the
extent to which different companies rely on plant labs for
their chemical analysis needs. For some plants,
particularly small and older plants, no laboratory work is
done on site and samples are shipped to central laboratories
for analysis. In others, and especially modern, high-
pressure steam plants and nuclear facilities, much more
laboratory support is required.
171
-------
Laboratory wastewater can contain a wide array of chemicals,
although they are usually present in extremely small
amounts. Chrarcteristics are also highly variable and could
entail a wide range of pH. It has been common practice to
combine laboratory drains with other plant plumbing and
consequently data on representative analysis, flows or
special treatment procedures are not available. In general,
it would appear that a toxic materials inventory approach to
account for chemicals that might be discharged to laboratory
drains would be more practical than conducting an analysis
on the wastewater.
If a problem is shown to exist because of contamination
through a laboratory drain, approaches to control would
involve a wide range of alternatives ranging from a revision
of the specific test procedure causing the difficulty to a
batch analysis, containment and separate treatment of the
waste or removal from the site.
Intake Screen Wash
Powerplants require water for various operations. Plants
using once-through type condenser cooling systems draw the
cooling water from a waterbody such as an ocean, a lake, a
river, etc. On the other hand, plants using a recirculating
condenser cooling system need less water intake than the
once-through types. Depending upon the water requirements
and the source of intake water, traveling screens are used
to prevent river debris, fish, leaves, etc. from entering
the intake system. The accumulated debris is collected and
the screens hosed down to prevent plugging.
Service Water System
Service water systems supply water which is used for such
house services as bearing and gland cooling for pumps and
fans, auxiliary cooling and heat exchangers, hydrogen cooler
and fire pumps. In many cases toilet and potable water is
included in this category.
According to Reference 21, there are basically two types of
service water systems. Once-through service water systems
are most common. In these types raw water with no treatment
chemical is added. These types of systems are operated in
parallel to the condenser cooling water system. Raw water
is used and no continuous treatment is practiced.
Occasional shock chlorination is given to similar levels as
with condenser cooling water. Chlorination treatment is,
however, much less frequent. Many nuclear plants integrate
172
-------
•the emergency core cooling system with a once-through
service water system. Once-through service water systems
can be used exclusively or in conjunction with closed-loop
recirculatory systems. With recirculatory systems the
makeup can be supplied from either raw or city water. This
makeup is pretreated to a high degree of purity. This
closed loop recirculatory water is treated to a high degree
to prevent: corrosion within the system. In general,
chromates are used in conjunction with caustic soda for
control of pH at 9.5 to 10 up to levels of 250 ppm. Borate-
nitrate corrosion inhibition treatment is also used to
levels of between 500 to 2,000 ppm. Generally, there is
little or no loss from these closed-loop systems. The only
occasions when water loss can occur are during maintenance
or occasionally if the system has to be drained for
cleaning, which although infrequent can occur at a three
year frequency.
Service water requirements cover a wide range. For once-
through systems water flows range from 0.5 to 35 gpm per Mw
of rated plant capacity. Typically, the flow is 10 to 11
gpm per Mw of rated capacity. Where closed-loop systems are
operated a figure of 22 to 23 gpm per Mw of rated capacity
is typical. On this basis, closed-loop blowdown can
typically be 5 gallons per day with a settleable solids
content of 1 to 2 ppm. Service water requirements of plant
no. 4251, a nuclear unit of 851 Mw using 480,000 gpm of main
condenser cooling water, are as follows:
Primary plant component cooling water 5,800 gpm
Secondary plant component cooling water 16,000 gpm
Centrifugal water chiller 3,000 gpm
Control room air conditioner 210 gpm
Low Level Rad Wastes
The radioactive waste handling system is beyond the scope of
this study. Some of the low level rad wastes from a nuclear
powerplant contain boron and •therefore can also be
considered as chemical wastes. Consequently, a brief de-
scription of the waste handling systems in a nuclear power-
plant is included. The sources of radioactive wastes are
the reactor coolant and spent fuel coolant and the various
systems with which these coolants come into contact. In
general, the radioactive fluids are treated by filtration,
ion exchange, and distillation. The fluids are then either
recycled for use in the plant or diluted with condenser
cooling water for discharge to the environment.
173
-------
Most commercial nuclear powerplants in the country are
either pressurized water reactors (PWRs) or boiling water
reactors (BWRs). In a pressurized water reactor, the
primary coolant is maintained at a pressure (2,200 psi)
sufficient to keep it from boiling. After the primary
coolant is heated in the reactor, it flows through the tube
side of large heat exchangers generating steam on the
shellside. This steam is used to drive the turbine and is
then condensed and returned to the steam generator through a
series of preheaters. Thus, in a PWR, the primary coolant
is isolated from the steanb-condensate system. However, some
leakage through defects in steam-generator tubes may occur
resulting in contamination of the steam-condensate system.
There are several other fluid systems which may be
contaminated. In a PWR, boron is used in the primary
coolant to help control reactivity. As the fuel burn-up
progresses, the boron concentration is lowered by feed and
bleed of reactor coolant.
Two systems are associated with this process. The first
system, which is sometimes called the chemical and volume
control system (CVCS), is on stream at all times and is used
to control the radioactivity chemistry and volume of reactor
coolant. Reactor coolant is continously bled from the
primary system into the CVCS where it usually passes through
filters and ion exchangers. The coolant can then be
returned to the reactor or diverted to the second system to
allow addition of water with a different boron concentration
to the reactor through the CVCS. The second system can be
labeled the boron management system (BMS). It processes the
reactor coolant letdown after it has passed through the CVCS
ion exchangers. Processing in the BMS usually includes gas
stripping to remove hydrogen and the radioactive noble
gases, ion exchange, and distillation. The distillate may
be recycled for use as reactor coolant or diluted with
condenser cooling water for discharge to the environment.
The concentrated bottoms from the distillation process are
either recycled as boric acid for use in the reactor coolant
or mixed with cement and placed in drums or larger
containers for shipment to a solid radioactive waste burial
site.
Provisions are made so that after reactor shutdown it is
possible to cycle reactor coolant through ion exchangers
prior to flooding the reactor area and fuel transfer canal
with water from the refueling water tank. However, there is
still some residual activity in both the refueling water
tank and the fuel storage pools. Thus, it is possible that
refueling water, spent fuel coolant, new fuel pool water and
secondary coolant are contaminated as well as reactor
174
-------
coolant and letdown. Also, the fluids used to transfer or
regenerate resins in any of the systems mentioned above may
be contaminated. Therefore, all leaks and resin-handling
and regeneration fluids from these systems are collected and
processed in a radioactive waste management system (WMS).
This WMS also uses filtration, ion exchange, or distillation
or a combination of the three to produce very low activity
water suitable in most cases for discharge to the
environment. Because the WMS processes a wide variety of
liquids, some of which may be contaminated with oil or other
undesirable substances, the WMS effluent is generally not
recycled. Figure A-V-11 shows a block diagram of the liquid
radioactive waste management system for a PWR.
In BWRs, the reactor coolant is itself boiled and thus flows
through the steam condensate system. The condensate is
usually heated and returned to the reactor. The solutions
produced in handling or regenerating the ion exchange resins
constitute the major radioactive liquid waste in a BWR. In
addition to the equipment for "polishing condensate" a
system is provided for filtering and demineralizing the
reactor coolant. This system, called the reactor water
cleanup system (RWCS), takes coolant from the reactor
vessel, cools it, filters and demineralizes it and returns
it to the reactor coolant system, thus controlling
nonvolatile corrosion products and impurities in the reactor
water. Because no boric acid is used in the reactor water
under normal circumstances there is no feed and bleed
operation for boron concentration control and consequently
no boron management system.
As in the PWR, the water for refueling also becomes con-
taminated and any leakage of refueling water as well as any
leakage and resin regenerating or transporting fluids and
filter backwash (from any of the contaminated systems
discussed above) is collected and treated. Treatment of
wastes in a BWR also includes filtration, ion exchange, and
distillation. The exact design of the systems vary from
plant to plant; however, from the liquid radioactive waste
point of view, BWRs may be placed in two categories: (1)
those which use disposable ground resin in filter de-
mineralizers for condensate polishing, and (2) those which
use resin regenerable in deep bed demineralizers. In
general, it appears that the former system is favored except
where saline cooling water is used.
The use of regenerable resin means that large volumes of
regenerant solutions have to be processed every day. The
processing usually involves the use of large evaporators
with total through-put capacity on the order of 0.0025 cu
175
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m/s (HO gpn) or more for some plants. The distillate from
these evaporators is generally sent to high-purity waste
system for further treatment by ion exchange. About 90% of
the effluent of this high-purity waste system is recycled
for use in the reactor and 10* discharged.
In those plants which use ground resin units for condensate
polishing, no regeneration takes place since water is used
only to transport the powder. Thus, considerably less fluid
has to be treated and, since the radionuclides are not
dissolved into the water, only mechanical separation such as
settling, filtration and centrifuging is used for initial
treatment of the water. Again the water is sent to a high-
purity waste system where it is treated by ion exchange and
the bulk of the water is recycled for use in the reactor
with the remainder discharged into the cooling water.
BWRs usually use ground resin filter demineralizers in the
RWCS. The liquid from transporting ground resin in the RWCS
is treated in the same way as that used for ground resin
condensate polishers.
Other liquid wastes from BWRs are treated by ion exchange,
evaporation, and filtration. Other sources of wastes are
floor drains and laundry drains (including personnel
decontamination and cask cleaning). Distillates from
evaporation of these waste are generally discharged to the
environment. Concentrated bottoms from evaporators and
solids from dewatering equipment are drummed for off-site
shipment. Figure A-V-12 shows a block diagram of the liquid
radioactive waste handling systems of a BWR of 1,100 Mw
capacity.
It is difficult to establish the exact amount of liquid
which will be released by the radioactive waste handling
systems of a power reactor. The number and type of
shutdowns and load changes the amount of leakage from
various systems, and the degree of recycle of processed
waste all affect the quantities of liquid discharged.
However, in the process of obtaining licenses for
construction and operation of a nuclear powerplant,
estimates are made of these releases based on expected
operating conditions. A review of several Environmental
Impact Statements for PWRs and BWRs indicates a range of
effluent quantities which are expected to be discharged.
PWR wastes processed in the BMS are usually of high enough
quality to be recycled. In general, the distillate from
BMS's contains concentrations much lower than 1 mg/1 of all
chemicals other than boric acid which is present at a maxi-
177
-------
oa
CONDENSATE
DEMjNERALIZERS (6)
LOW CONDUCTIVITY WASTE
EQUIPMENT DRAINS FROM
DRY WELL. REACTOR BUILOIN6
AND TURBINE BUILDIN6 ETC.
HIGH CONDUCTIVITY WASTE
FLOOR DRAINS FROM
DRYWELL AND REACTOR.
TURBINE. AND RADWASTE
BUILDINGS. ETC.
CHEMICAL WASTE
LABORATORY DRAINS
SAMPLE DRAINS. ETC
DECONTAMINATION
DETERGENT WASTE
CASK CLEANING
PERSONNEL DECONTAMINATION
TANK
20.000 gal.
COLLECTOR
TANK
20.000 gal.
" J v
I
DISTILLATE
JEMINEKALIifcRI | 20,000 g
. J ho*
L
I J FLOOR DRAIN SAMPLE
[ "DEMINF.RALIZER 2o'oo"o"
1
a 1.
%
DRAIN
gal,
RADIATION
MONITOR ~
DETERGENT""!
DRAIN TANKS
SOLID WASTE
DISPOSAL SYSTEM
SPENT RESIN AND
FILTER SLUDGE TANKS
CENTRIFUGE AND
DRUMMING STATION
DRUMMED
WASTC TO
' OFF - SITE
DISPOSAL
4.000 gpm
DISCHARGE
STRUCTURE
J INTAKE
r51 STRUCTURE
"• — ' COLUMBIA RIVEN -_ -. _-ir~" .-_•..-.
LIQUID RADIOACTIVE WASTE HANDLING SYSTEM
1100 Mw BWR NUCLEAR PLANT
FIGURE A-V-12
-------
mum concentration of 60 mg/1. The anticipated quantities of
BMS discharge for a sampling of PWRs ranges from 0 to over
5,000,000 gal/year. The quantity of distillate discharged
from the BMS depends on the operating mode of the plant
(i.e. base loaded or load following), number of shutdowns
and the degree of distillate recycling.
Distillate from the WMS can generally be expected to have
the same chemical purity as that from the BMS although it
may occasionally contain a few mg/1 of sulfates and
chlorides resulting from processing condensate polisher
regenerants during primary to secondary leaks.
•.
Some of the fluids routed to the WMS are not necessarily
treated by the radwaste evaporator. These wastes are ex-
pected to be of such low activity that they will be
filtered, monitored, and then treated as conventional
wastes. The quantity of liquid discharged from the WMS of a
PWR can vary widely. For example, during a primary to
secondary leak, plant condensate polishers may process the
polisher regenerants through the WMS. While this means that
millions of gallons of distillate may be discharged from the
WMS, it doesn't add to overall plant waste discharged since
the regenerants would have to be processed and discharged at
nearly the same rate by chemical treatment system in the
event there were no primary to secondary leak.
As discussed above, the nature and quantity of liquid
discharged by the radioactive waste systems of a BWR differ
greatly between units which use ground resin condensate
polishing and those which use conventional ion exchangers.
Even within a given type of plant there is a large variation
in techniques for handling the various wastes and the
anticipated discharge quantities vary considerably. For
example one plant using ground resin condensate polishers is
expected to discharge approximately 1.5 million gallons per
year while another also using similar polishers may
discharge five times that amount.
Because of the treatment requirements for removing radio-
isotopes from waste streams, it is expected that most
discharges from radioactive waste systems in BWRs will con-
tain extremely low concentrations of chemical pollutants.
Construction Activity
There are liquid wastes associated with on-site construction
activities. Such wastes will depend upon the type and size
of construction and the location.
179
-------
Generally, waste water resulting from construction activity
will consist Of storm water runoff from the site during the
course of construction. This stream can be characterized by
suspended solids and turbidity resulting from the errosion
of soil disturbed by the construction activity.
Construction activity referred to here concerns buildings
and equipment immediately related to powerplants and does
not address the construction of cooling ponds or cooling
lakes, visitor centers, access roads, etc.
Chemical Discharges in General
Effluents from steam electric powerplants contribute a
significant portion (14%) of the total national discharge of
metals from major industrial point sources. According to
information filed by point source dischargers under the
National Pollution Discharge Elimination System (NPDES)
permit program, steam electric powerplants contribute 50% of
the chromium, !<*% of the copper, 10% of the iron, 21% of the
zinc, and 14% of all metals as a whole, found in the
discharges of U.S. industries designated as major
dischargers by EPA.
Data from NPDES permit applications stored in the computer
file were analyzed in order to determine the percentage of
total heavy metal pollutants contributed by the steam
electric power industry. The analysis was done for four
specific metals: chromium, copper, iron, and zinc.
Data were available for 67% of all major dischargers and for
66% of the major steam electric powerplants. The other 33-
3<*% were not entered into the computer file. The figures
include in most cases the contribution from cooling water
discharge.
Table A-V-13 shows the relative contribution of metals from
powerplants compared to other major industrial sources.
Extrapolating this data to all major and minor dischargers
caused little variation in the percentage contribution of
powerplants regardless of the assumptions made concerning
the relative contributions of major to minor dischargers.
A study by an EPA contractor (ERGO) of coal-fired
powerplants showed the following estimates of daily
discharge from existing (1973) coal-fired powerplants, in
pounds. This study covered only the coal-fired plants and
did not include cooling water discharge. The results are
given in Table A-V-14
180
-------
Table A-V-13
Total Metals Discharged from Powerplants
in the U.S, (1973) Compared to Other Industrial
Sources ( Includes cooling water discharges)
Pollutant
Chromium
Copper
Iron
Zinc
Total
Discharges by Major
Steam Electric Power-
plants, Ib/day
15,365
2,739
20,683
20,099
58,886
Percentage of
All Major
Dischargers
50
14
10
21
14
Table A-V-14
Total Iron and Copper Discharges from
Coal-Fired Powerplants in the U0S,
, (1973)
Source
Ash Ponds
Boiler Cleaning
Condenser Cleaning
Total
Iron, Ib/day
10,200
1,500
-
11,700
Copper, Ib/day
180
150
40
370
181
-------
Total suspended solids in waste water streams from a typical
1,000 megawatt coal-fired plant are as follows:
Low-volume wastes 500 Ib/day
Coal-pile runoff 500 Ib/day
Ash sluicing 1,240,000 Ib/day
A conventional ash pond for a 1,000 megawatt coal-fired
plant achieving an average effluent total suspended solids
concentrations of 30 mg/1 and using 10,000,000 gallons per
day of sluice water would discharge 2,650 Ib/day of total
suspended solids.
Summary of Ch lieal Usage
Table A-V-15 lists chemicals used in steam electric
powerplants corresponding to various classes of uses. Table
A-V-16, from the U.S. Atomic Energy commission document,
"Toxicity of Power Plant Chemicals to Aquatic Life," lists
chemicals specifically associated with nuclear powerplants
and includes some chemicals not included in Table A-V-15.**2
Table A-V-17 gives the annual use of high tonnage chemical
additives by powerplants. Table A-V-18 gives chemical
compositions of trade-name microorganism control chemicals.
Classification of Waste Waters Sources
Waste water sources can be classified as high-volume,
intermediate-volume, ... ^-volume, or rainfall run-off. Table
A-V-19 lists the individual waste water sources according to
the above classification.
The available da\.a on waste water flow rates corresponding
to the various waste water sources in steam electric
powerplants are summarized in Table A-V-20 along with
typical concentrations of major pollutants.
182
-------
Table A-V-15
CHEMICALS USED IN STEAM ELECTRIC I U./ERIIANTS
Major source is Reference 21.
Use
Coagulant in clarification
water treatment
Regeneration of ion ex-
change water treatment
Lime soda softening
water treatment
Corrosion inhibition or scale
prevention in boilers
pH control in boilers
Sludge conditioning
Oxygen scavengers in boilers
Boiler cleaning
Regenerants of ion exchange
for condensate treatment
Chemical
Aluminum sulfate
Sodium aluminate
Ferrous sulfate
Ferric chloride
Calcium carbonate
Sulfuric acid
Caustic soda
Hydrochloric acid
Common salt
Soda ash
Ammonium hydroxide
Soda ash
Lime
Activated magnesia
Ferric coagulate
Dolomitic lime
Disodium phosphate
Trisodium phosphate
Sodium nitrate
Ammonia
Cyclohexylamine
Tannins
Lignins
Chelates such as EDTA,NTA
Hydrazine
Morphaline
Hydrochloric acid
Citric acid
Formic acid
Hydroxyacetic acid
Potassium bromate
Phosphates
Thiourea
Hydrazine
Ammonium hydroxide
Sodium hydroxide
Sodium carbonate
Nitrates
Caustic soda
Sulfuric acid
Ammonex
Use
Corrosion inhibition or scale
prevention in cooling towers
Biocides in cooling towers
pH control in cooling towers
Dispersing agents in
cooling towers
Biocides in condenser cooling
water systems
Additives to house service
water systems
Additives to primary coolant
in nuclear units
Numerous uses
Chemical
Organic phosphates
Sodium phosphate
Chromates
Zinc salts
Synthetic organics
Chlorine
Hydrochlorous acid
Sodium hypochlorite
Calcium hypochlorite
Organic chromates
Organic zinc compounds
Chlorophenates
Thiocyanates
Organic sulfurs
Sulfuric acid
Hydiochloric acid
Lignins
Tannins
Polyacrylonitrile
Polyacrylamide
Polyacrylic acids
Polyacrylic acid salts
Chlorine
Hypochlorites
Chlorine
Chromates
Caustic soda
Borates
Nitrates
Boric acid
Lithium hydroxide
Hydrazine
Numerous.proprietary
chemicals
-------
Table A-V-16
CHEMICALS ASSOCIATED WITH NUCLEAR POWER PLANTS Aauatic Life-
Reference: U.S. Atomic Energy Cocomisaion report "Toxicity of Power Plant Chemicals to Aquatic Lire
CORROSION & SCALE INHIBITORS
Chroraates
Sodium chronate
Sodium dlchromate
Zinc chrornate
Zinc dichroaste
Potassium chroeute
Potassium dlchroaate
Phoaphates and Polyphosphates
Calcium oet*pho«phate
Sodium phosphate
Sodium metaphosphate
Sodium hexametaphoephate
Sodium cripolyphosphate
Sodium pyrophoaphate
Zinc phosphate
Sodium orthophosphate
Calcium phoaphace
Organic polyphosphates
| Glassy Silicates
Sodium silicate
Nitrites and Hitratea
Sodium nitrite
Sodium altrate
Potassium nitrate
CTanatea
Sodium ferrocyanate
Fluorides
Sodium fluoride
Amines (alao used as biocldea)
Octadecylamina
Ethylenedlaaine
Cyclohexy1amlne
Benzylamina
Horphln*
Che 1 at ing Agents
Ethylenedlaaine Tetraacetic acid (EOTA)
Nitrilotrlacetlc acid (NTA)
LTSR - "low temperature scale remover"
(a proprietary compound produced by Dow
Chemical)
CLEANING & NEUTRALIZING COMPOUNDS BIOCIDES (particularly cooling tower use)
Alkaline Cleaning Stage
Sodium hydroxide
Calcium hydroxide
Sodium phosphate
Sodiua sulfate
Sodium trlphosphate
Aamonlum hydroxide
Acid Cleaning Stage
Citric acid
SulCurie acid
Neutralising (paaslvating) Stage
Sodium carbonate
Sodium sulfate
Sodium phosphate
Sodium dlphosphate
Sulfurlc acid
Lithium hydroxide
Mnrphollne
Sodium lignosulfonate
Cyclohexy1amlne
Ammonium sulfate
Ammonium hydroxide
Ammonia
Oxygen Rjeducejra
llydrazine
Morphollne
Sodium aulflte
Cobalt sulfate
Cobalt
Reactivity Control
Boric acid
Boron
Oxidizing Biocides
Chlorine
Bromine
Sodium hypochlorlte
Calcium hypochlorite
Potassium permanganate
Chlorinated cyanurates and inocyanuratea
Persulfate Compounda
Potassium hydrogen peraulfate
Hon - oxidising Biocides
A. CatIonic Surftee Active Agent*
Sulfonium
Phoaphonium
Araonium
lodonlum
5. Dithlocarbaaic Acid Salts
1. Chlorinated and/or phenylated phenols:
Chloro-0-phenylphenol
2-Tert-flutyl-4-chloro-5-methylphenol 6.
0-Benzyl-p-chlorophenol
t> ,6-Dlchlorophenol
2,4-Dinltrochlorobenzene
2,6-Dlnltrochlorobenzene
2,4,5-Trichlorophenol
l,3-Dlchloro-5,5-Dlmethylhydranotln
Trlchloromethyl sufone (Bis)
Sodlun salts (atea) of:
0-Phenylphenol
2,4,5-Trichlorophenol
(flodium 2,4,5-Trlchlorophenate)
' Chloro-2,phenylphenol
2-Chloro-4-phenylphenol
2-Bromo-4-phenylphenol
2.3.4.6-Tetrachloroohenol
Pentachlorophenol
Potassium salts (ates) of:
2,4,S-Trichlorophenol
2. Quaternary Amines (quaternary ammonium compounds)
Dllauryl dimethyl ammonium chloride
Dilauryl dimethly ammonium oleate
Dodecyl trlmethyl aamonlum chloride
Trimethyl ammonium chloride
Octadecyl trlmethyl ammonium chloride
N-Alkyl benzyl-N.N.N.-trisethyl
annonlum chloride
Alkyl-9-oethyl benzyl ammonium chloride
Lactory mercuriphenyl annonlum lactate
Atkvl dlraethvl benzvl ammonium chloride
3,4-Dlchloro benzyl ammonium chloride
Fbenylmercuric trlhydroxyet^yl
aamonlum lactate
Plienyloercuric trlethanol annonium lactate
Alkyl (Ciz to Cifl) dimethyl benzyl-aanwniuni
chlorides
1-Alkyl (C& co C.g) amino-3 anInopropane monoacetate
Sodium dimethyl dlethyl dlthiocarbamate
Ulsodium ethylene bladlthiocarbamate
Organic Amines (often used with pentachlorophenol)
Primary Rosin Amines
Sodium carboxethyl rosin amlne
Rosin amine acetate
Other Amines (primary beta-amloes and
beta-dlamlnes )
Chloramlne
Benzylamlne
Cyc lohexy 1 ami ne
E thy lenedi amine
Polyethyleneamlne
Zinc and Copper Salts
Zinc sulfate
Copper sulfate
Copper citrate
Arsenates
Arsenic acid
Sodium srsenite
CORROSION PRODUCTS
3. Organo-metalllc Compounds
Organotlns
Bis (Tributyl Tin) oxide
Orgenosulfurs
Disulfldes
Organothlocyanates
Methylene bisthiocyanate
Copper Ions
Zinc ions
Inorganic Scale and Precipitates
Calcium carbonate
Calcium phoaphate
Calcium sulfate
Calcium hydroxide
Magnesium carbonate
Magnesium hydroxide
Magnesium phosohat*
Iron oxides
-------
Table A-V-17
Use of High Tonnage Chemical
Additives by Steam Electric Powerplants
(1970) 4bi
Chemical
Alum
Caustic Soda
Chlorine
Lime
Phosphate
Total
Cooling Water
Additive,
tons
2,470
-
24,642
13,324
865
41,301
Boiler Water
Additive,
tons
1,751
37,998
985
7,824
1,100
49,658
Total,
tons
3,221
37,998
25,627
21,148
1,965
90,959
185
-------
Table A-V-18
Chemical composition of d
nucruofgannm control chemicals
Composition
Usage
NALCO21-S
Sodium pentachlorophrnale 21.3
Sodium 2,4.5-trichlorophenale 11-9
Sodium tall* of olhei chlorophenoh 3.0
Inert ingredients 63.8
NALCO 25-L or NALCO 42S-L
1 -Alkyl (C6 to C, j)-3mino-3-aminopropane
propioiule -copper acetate complex 15.0
liopropyl alcohol 30.0
Copper expressed as metallic 0.55
Inert ingredients 55.0
NALCO 201
Potassium pentachtoropherute 15.7
Pol.mium 2,4,5-trichlorophenate 9.0
Potassium said of other chlorophenob 1.8
Inert ingredienti 70.3
NALCO 202
Meth)-l-l,2-dibromopropionat« 29.7
Inert ingredienti 70.3
NALCO 207
MclhylenebisthiocyanaU 10.0
Inert ingredienti 90.0
NALCO 209
l,3-Diehloro-5.5-dimetriy!hydanloin 25.0
Inert ingredients " 75.5
NALCO 321
I -A Iky I (Cj to C| i)a amino-3-aminopropane monoacebte 20.0
liopropyl alcohol 30.0
Inert ingredients 50.0
NALCO 322
I • Alkyl (C$ toC]()tf amino-3-aminopropane monoacetate 19.8
2,4.5-Trichlorophenol 9.5
Iiopropyl alcohol 27.0
Inert ingredients 43.7
NA LCO 405
2,4-L)initrochlorobenzene 22.2
J,b-I)initroch!orobenzene 2.8
Inert ingredients 75.0
Betz A-9
Sodium penlachlorophenate 24.7
Sodium 2,4,$-trtchlorophenate 9.1
Sodium salts of other chlorophe nates • 2.9
Sodium dimethyl dithiocarbamale 4.0
N-Alkyl(Ci) - 4%,C,4 - 50%.C,» - 10^)
dtmelhylbenzylammomum chloride 5.0
Inert ingredients (including solubilizinf and
dispersing agents) 54.3
Bet! C-5
1.3-Uichloro-S,5-dimethylhydantoin 50
Inert ingredients (including solubiliiing and
dispersing agents) 50
Retz C-30
Buftrichloromethyl) tulfone 20.0
Methylenc billhiocyanate 5.0
Inert ingredients (including solubilizinf and
dispersing agents) .75.0
Betz C-34
Sodium dimethyl dithiocarbamale 15.0
Nabam (disodium cthylene bisdithiocarbamaie) 15.3
Inert ingredients (including solubiliztng and
dispersing agend) 69.7
beuJ-12
N Alkyl (d i - 5%. C| 4 - 60%. C,« - 30%, C,» - 5%)
dimethylbcnzybmmonium chloride 24.0
BiMtributyltin) oxide 5.0
Inert ingtcdients (including solubilizing and
dispersing agents) . 71.0
B«lzF-14
Sodium pentachtorophrnale 20.0
Sodium 2,4,5-trtchlorophenala 7.3 '
Sodium salts of chlorophenilc 2.5
Dehydroabutyl ammonium phenoxide 2.0
Inert ingredients, including dispersants 68.0
Periodically, as needed,
25-400 ppm of continuously
Weekly. 20- 300 ppra
Periodically, as needed.
300 - 400 ppm or 12 60 ppm
continuously
5-200 ppm periodically or
continuously
Weekly, 25 -50 ppm
As needed, 50-100 ppra
Weekly, 5-200 ppm
As needed, 10- 200 ppm
As needed. 100-200 ppm
JAs-in fatty acids of coconut oil.
From company \ourcei and Environmental Protection Agency.
186
-------
Table A-V-19
CLASS OF VARIOUS WASTE WATER SOURCES
Class
Source
High Volume
Nonrecirculating main condenser
cooling water
Intermediate Volume
Nonrecirculating house service water
Blowdown from recirculating main
cooling water system
Nonrecirculating ash sluicing systems
Nonrecirculating wet-scrubber air
pollution control systems
Low Volume
Clarifier water treatment
Softening water treatment
Evaporator water treatment
Ion exchange water treatment
Reverse osmosis water treatment
Condensate treatment
Boiler blowdown
Boiler tube cleaning
Boiler fireside cleaning
Air preheater cleaning
Stack cleaning
Miscellaneous equipment cleaning
Recirculating ash sluicing systems
Recirculating wet-scrubber air
pollution control systems
Intake screen backwash
Laboratory and sampling streams
Cooling tower basin cleaning
Rad wastes
Sanitary system
Recirculating house service water
Floor drainage
Miscellaneous streams
Rainfall Runoff
Coal pile drainage
Yard and roof drainage
Construction activities
187
-------
Table A-V-20
TYPICAL CHEMICAL WASTES FROM A COAL-FIRED POWERPLANT
Waste Stream
Ion exchange
Boiler blowdown
Boiler cleaning
Boiler fireside cleaning
Air preheater cleaning
Miscellaneous cleaning
Laboratory operations
Floor drains
Recirculating bottom
ash sluicing blowdown
Ash pond overflow (once-
through fly ash)
Coal pile drainage
Flow, 1
GPD/MW
88
52
0.25
4.44
11.7
1.11
10
30
400
5000
3
•J
Typical Concentrations of Major Pollutants /mg/1
TSS
46
25
127
582
1882
1000^
100^
100^
1000
60
864
Iron
—
—
2100
142
1610
-
-
'_
_
—
—
Copper
w
-.
380
—
-
-
-
_
_
—
—
Sulfate
2085
_
—
1650
1130
-
-
—
_
. 510
6880
Hardness
_
—
520
4661
3700
-
-
_
_
244
1025
Notes: 1. Based on the average of available data
2. Assumed values
3. Based on 0.02 acres/Mw coal pile and 40 inches of rainfall per year;
the f-low is calculated to be 59,500 GPD for a 1000 Mw plant
-------
PART A
CHEMICAL WASTES
SECTION VI
SELECTION OF POLLUTANT PARAMETERS
Definition of Pollutants
Section 502(6) defines the term "pollutant" to mean dredged
spoil, solid waste, incinerator residue, sewage, garbage,
radioactive materials, heat, wrecked or discarded equipment,
rock, sand, cellar dirt and industrial, municipal and
agricultural waste discharged into water. This report
addresses all pollutants discharged from steam electric
powerplants with the exception of both high-level and
low-level radioactive wastes of nuclear powerplants. The
exclusion is made for two reasons: (1) administratively,
the permiting or licensing authority for nuclear plants,
from the standpoint of radiation safety resides with the
U.S. Atomic Energy Commission; and (2) it is not known that
the application of conventional waste water treatment
technology for the control of non-radiation aspects of
radioactive waste will not result in the creation of a
radiation hazard (e.g. due to the concentration of the
suspended solids removed).
Introduction
Section A-V describes various operations in a steam electric
powerplant which give rise to chemical wastes. Reported
data were included for each waste stream wherever available.
The waste streams are specific to each powerplant and depend
upon factors such as raw water quality, type and size of
plant, age of plant, ambient conditions and operator
preferences. Table A-VI-1 summarizes the pollutants present
in the various chemical waste streams based on data recorded
in Section A-V, Waste Characterization, and knowledge of the
respective processes. The data in many cases show a wide
variation from plant to plant. This wide variation in data
and the presence of many pollutants in a single waste stream
makes the selection of characteristic pollutants a difficult
task. Table A-VI-2 summarizes the number of plants for
which data was recorded in Section A-V for each waste
stream.
189
-------
TABLE A-VI-1
APPLICABILITY OF PARAMETERS TO CHEMICAL WASTE STREAMS
PARAMETER
ALKALINITY
BOD
COD
TS
TDS
TSS
AMMONIA
NITRATE
PHOSPHOROUS
TURBIDITY
FECAL COLIFORM
ACIDITY
HARDNESS, TOTAL
SULFATE
SULFITE
BROMIDE
CHLORIDE
FLUORIDE
ALUMINUM
BORON
CHROMIUM
COPPER
IRON
LEAD
MAGNESIUM
MERCURY
NICKEL
SELENIUM
VANADIUM
ZINC
OIL & GREASE
PHENOLS
SURFACTANTS
ALG 1C IDES
CHLORINE
MANGANESE
Condenser
Cooling
System
Once
Through
X
X
rRecircu-
latinq
X
X
X
X
V
X
X
Water
Treatment
Clarifi-
cation Wastes
x
x
X
0)
3
I
X 0)
H tT>
ll
X
X
X
Evaporator
X
x
x
Boiler
Blowdown
X
x
X
!
x x
x
x
|
i
X x
V V
x x | x : x
x ! x x x
V
x
X
X XX X X
X
X
' X
X
Jf
X
y
X
X
X
X
1
X , X
x x
X X
y
X
V
X
X
X
X
X
Chemical
Cleaning
Boiler
Tubes
x
X
X
X
X
X
X
V
X
X
X
X
X
X
X
X
X
X
[Air Pre-
heater
x
X
X
X
X
J£
X
X
X
X
Boiler
Fireside
x
X
X
X
x
V
X
X
X
X
X
X
Ash Pond
Overflow
x
x
x
x
x
X
X
X
X
X
V
X
X
X
X
X
X
X
V
X
X
X
X
X
Icoal Pile 1
Drainage j
x
x
X
x
Floor 1
Drains |
Air Pollution
Devices
S<->2 Removal
V
X | X
X
X
y
X
' X
v -
X '
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
V
X
X
1 X
X
Y-
X
X
X
,
Sanitary
Wastes
x
X
X
X
X
X
W
II
X
t
1
X
X
1
Miscellaneous streams such as laboratory sampling, stack chemical cleanings, etc.
are not included since the species are accounted for in other streams. .
190
-------
TABLE A-VI-2
CHEMICAL WASTES-
NUMBER OF PLANTS WITH RECORDED DATA
PARAMETER
ALKALINITY
BOD
COD
TS
TDS
TSS
AMMONIA
NITRATE
PHOSPHOROUS
TURBIDITY
FECAL COLIFORM
ACIDITY
HARDNESS, TOTAL
SULFATE
SULFITE
BROMIDE
CHLORIDE
FLUORIDE
ALUMINUM
BORON
CHROMIUM
COPPER
IRON
LEAD
MAGNESIUM
MERCURY
NICKEL
SELENIUM
VANADIUM
ZINC
OIL & GREASE
PHENOLS
SURFACTANTS
ALGICIDES
CHLORINE
MANGANESE
Condenser
Cooling
System
Dnce
Through
_
-
-
_
_
—
-
-
-
—
-
—
-
1
-
2
-
-
—
-
-
-
-
-
_
-
-
-
-
-
-
-
-
-
-
Recircu-
lating
6
4
4
4
6
5
5
6
9
-
-
6
11
-
10
2
1
-
4
1
5
6
_
1
5
-
2
-
-
-
3
Water
Treatment
Clarification
Wastes
5
4
5
6
6
6
5
6
6
6
-
6
6
-
6
-
1
-
5
4
5
5
—
2
5
-
-
-
-
-
-
Ion Exchange
Wastes
12
12
12
16
18
16
15
17
20
7
-
15
23
-
21
-
-
-
14
8
13
17
2
5
16
2
5
-
_
_
4
Evaporator
5
7
7
8
9
8
7
7
9
5
-
7
7
-
8
-
-
-
8
5
5
6
2
2
8
3
2
_
-
2
Boiler
Slowdown
17
18
17
17
18
17
15
14
19
10
-
11
16
-
17
-
-
-
11
7
8
6
_
5
13
-
5
-
-
-
-
Chemical
Cleaning
Boiler
Tubes
6
6
6
6
6
6
6
5
17
6
-
4
5
-
17
10
11
-
15
17
17
13
_
14
17
-
-
-
-
-
12
Air Pre-
heater
7
7
7
7
6
7
7
7
7
7
-
7
7
-
7
-
-
-
7
5
7
7
_
7
7
-
-
-
-
-
-
Boiler
Fireside
2
2
2
2 I
2
2
2
2
2
2
-
2
2
-
2
-
-
-
2
1
2
2
-
1
2
-
-
-
-
-
-
Ash Pond
Overflow
27
-
-
28
26
26
21
21
18
12
-
19
27
-
25
-
12
-
12
7
16
15
2
4
16
-
-
-
-
-
5
Coal Pile 1
Drainage
9
4
5
6
7
7
5
5
2
3
3
4
8
-
4
-
2
-
6
4
7
2
-
7
-
-
-
-
-
-
Floor
Drains
3
3
3
3
3
3
3
3
3
3
_
-
1
_
3
_
_
_
1
-
_
_
—
1
1
1
-
—
—
—
Air Pollution
Devices
SOj Removal
1
-
-
-
1
1
-
1
1
M
_
_
1
2
2
—
_
1
_
1
1
_
i
1
1
-
-
_
-
-
_
-
Sanitary
Wastes
-
—
-
-
-
-
-
_
_
—
_
_
_
H
_
^
_
_
_
_
-
_
—
_
—
_
_
—
-
_
-
•0
nj tn
K i
II
-
—
-
-
-
-
-
_
_
_
_
_
—
_
_
—
_
_
_
—
-
_
-
_
—
-
_
-
-
_
'-
191
-------
Common Pollutants
Since powerplant waste effluents are primarily due to in-
organic chemicals, the common pollutants reflect the general
level of inorganic chemical concentration.
pH Value
pH value indicates the general alkaline or acidic nature of
a waste stream, and represents perhaps the most significant
single criteria for the assessment of its pollutional
potential. While a pH in the neutral range between 6.0 and
9.0 does not by itself assure that the waste stream does not
contain detrimental pollutants, a pH outside of this range
is an immediate indication of the presence of potential
pollutants.
Total Dissolved Solids
Total dissolved solids represents the residue (exclusive of
total suspended solids) after evaporation and includes
soluble salts such as sulfates, nitrates, chlorides, and
bromides. Total dissolved solids are particularly
significant as a pollutant in discharges from closed systems
which involve recirculation and re-use. These systems tend
to concentrate dissolved solids as a result of evaporation
and require blowdown to maintain dissolved solids within
ranges established by process requirements. The blowdown
may contain specific pollutants in detrimental amounts
depending on the number of cycles of concentration.
Total Suspended Solids
Total suspended solids is another pollutant which is a
characteristic of all the waste streams. Suspended solids
are significant as an indicator of the effectiveness of
solids separation devices such as mechanical clarifiers, ash
ponds, etc. One of the functions of water use in a
powerplant is to convey solids from one stage of the process
to another or to a point of final disposal. Some processes
used in a powerplant create suspended solids by chemically
treating compounds in solution so that they become insoluble
and precipitate. Turbidity is related to suspended solids
but is a function of particle size and not an independent
pollutant.
Having established the three common pollutants, the
characteristic pollutants of individual waste streams are
outlined below.
192
-------
Pollutants from Specific Waste Streams
Biochemical Oxygen Demand (BOD)
BOD is a significant pollutant only for sanitary waste water
originating from the use of sanitary facilities by plant
personnel.
Chemical Oxygen Demand (COD)
COD is a pollutant usually attributed to the organic
fraction of industrial waste waters. Since steam electric
powerplants do not have a significant volume of organic
wastes, COD is generally not a significant pollutant in
powerplant effluents, but may be used as gross indicator for
certain combined wastes.
Oil and Grease
Oil and grease enter the plant drainage system primarily as
a result of spillage and subsequent washdown during
housekeeping operations or following natural precipitation.
Oil and grease are also removed from equipment during pre-
operational cleaning. Oil and grease is normally present in
the following waste streams:
Chemical cleaning - boiler tubes;
- boiler fireside;
- air preheater;
- miscellaneous small equipment;
Ash handling
wastes - oil fired plants;
- coal fired plants;
Drainage and .misc.
waste streams - floor and yard drains;
- closed cooling water systems; and
- construction activity.
Ammonia
Ammonia is a significant pollutant in plants that use
ammonia compounds in their operations. Ammonia may be used
to control the pH in the boiler feedwater. It may also be
used for ion exchange regeneration in condensate polishing
and in boiler cleaning. An ammonia derivative, hydrazine,
is used as an oxygen scavenger, but is used only in small
quantities. Because of its instability, it is not likely to
be a component of a waste stream. Ammonia will therefore be
a component of those waste streams which emanate from the
operations during which ammonia is added to the system, such
193
-------
as ion exchange wastes, boiler blowdown, boiler tube
cleaning and closed cooling water systems.
Total Phosphorus
Phosphates are used by some powerplants in recirculating
systems to prevent scaling on heat transfer surfaces. To
the extent that they are used, they will be a component of
any blowdown from such systems. These include primarily
boiler and PWR steam generator blowdown and blowdown from
closed cooling water systems but could also include a number
of minor auxiliary systems. In some cases, phosphorus
compounds are also used in boiler cleaning operations and
would therefore be a possible component of cleaning wastes.
Chlorine Residuals
Many condenser cooling water systems use chlorine or
hypochlorites to control biological growth on the inside
surface of condenser tubes. The biological growth, if left
uncontrolled, causes excessive tube blockages, poor heat
transfer, and accelerated system corrosion—all of which
reduce plant efficiency. For any cooling tower system the
length of time of the chlorine feed period and the number of
chlorine feed periods per day, week, or month change as the
biological growth situation changes. In most cooling
systems, the chlorine is added at or near the condenser
inlet in sufficient quantity to produce a free available
chlorine level of 0.1-0.6 mg/1 in the water leaving the
condenser. The amounts of chlorine added to maintain the
free available chlorine depend upon the amount of chlorine
demand agents and ammonia in the water.
Chlorine and ammonia react to form chloramines. Chioramines
contribute to the combined residual chlorine of the water.
The combined residual chlorine is less efficient and slower
in providing biological control than is the free available
chlorine. Total residual chlorine is the sum of the free
available chlorine and the combined residual chlorine.
Although chlorination is effective for slime control in
condenser tubes of cooling system, its application may
result in the discharge of total residual chlorine to the
receiving water. The effects of total residual chlorine on
aquatic life are of great concern.
Metals
Various metals may be contained in some of the waste streams
as a result of corrosion and erosion of metal surfaces and
194
-------
as soluble components of the residues of combustion where
such residues have been handled hydraulically.
Slowdown from boiler feedwater systems and from closed
cooling water systems will contain trace amounts of the
metals making up the heat exchanger surfaces with which they
have been in contact. Treatment of these waters generally
minimizes the amount of corrosion. However, cleaning
operations of these systems are designed specifically to
restore the heat transfer surfaces to bare metal. In this
process significant amounts of metal and metal oxide are
dissolved and are conveyed with the waste streams. The two
most common metals likely to be present in cleaning wastes
are iron and copper.
Metals present in wastes from fuel storage and from ash
handling operations will depend on the metals present in the
fuel. Generalization is difficult because of the wide
variation in fuel composition, but iron and aluminum are
typically present in significant quantities in ash from
coal. Mercury may be present if the coal used contained
mercury. Vanadium is present in sufficient quantities in
ash resulting from the burning of some types of residual
fuel oil, notably of Venezuelan origin.
If chromates and/or zinc compounds are used for the
treatment of closed cooling water systems, chromium and/or
zinc will be significant pollutants for any blowdown or
leakage from these systems.
Thesfc metals are likely to occur in the following waste
streams:
1. Iron
water treatment - clarification;
maintenance cleaning - boiler tubes;
- boiler fireside;
- air preheater;
ash handling - coal fired plants;
and coal pile drainage.
2. Copper
boiler and steam generator (PWR) blowdown;
chemical cleaning - boiler tubes;
- air preheater;
- boiler fireside
condenser cooling
water systems - once through; and recirculating
195
-------
3. Mercury
ash handling - coal fired plants; and coal
pile drainage.
J». Vanadium (oil-fired plants only)
ash handling;
chemical cleaning - boiler fireside; and
- air preheater.
5. Chromium and Zinc
recirculating condenser cooling system; and
closed cooling water system.
6. Aluminum and Zinc
coal pile drainage;
ash handling - coal fired plants;
water treatment - clarification;
chemical cleaning - boiler fireside; and
- air preheater.
Phenols
Polychlorinated biphenyls (PCB's) are sometimes used as
coolants in large transformers. PCBfs may also be used as
heat transfer fluids and for other purposes. In case of
leaks or spills, these materials could find their way into
the yard drainage system. Materials showing up as phenols
are also possible in drainage from coal piles, floor and
yard drainage, ash handling streams, and cooling tower
blowdown.
Sulfate
Sulfates in powerplant effluents arise primarily from the
regenerant wastes of ion exchange processes. Sulfate may
occur in ion exchange and evaporator wastes, boiler fireside
and air preheater cleaning, ash handling and coal pile
drainage.
Sulfite
Sulfite is used as an oxygen scavenger in the boiler
feedwater system in some plants. Plants using sulfite may
discharge the sulfite with their boiler blowdown. Because
196
-------
of its high oxygen demand, sulfite in significant quantities
is considered undesirable in a plant discharge.
Sulfite may occur in the following waste streams:
maintenance cleaning - boiler fireside;
- air preheater;
- stack;
- cooling tower basin;
ash handling - oil fired plants;
- coal fired plants;
coal pile drainage; and
air pollution control
devices for SO2 removal.
Boron
Oxidizing agents such as potassium or sodium borate may be
contained in cleaning mixtures used for copper removal in
the chemical cleaning of boiler and steam generator (PWR)
tubes.
Fluoride
Hydrofluoric acid or fluoride salts are added for silica
removal in the chemiaaA cleaning of boiler and steam
generator (PWR) tubes.
Alkalinity and Acidity
Both alkalinity, and acidity are parameters which are closely
related to the pH of a waste stream.
Total Solids
Total solids is the sum of the total suspended solids and
the total dissolved solids.
Fecal Coliform
Fecal coliform is only significant in sanitary waste.
Total Hardness
Hardness is a constitutent of natural waters, and as such is
not generally considered as a pollutant in effluents from
industrial processes. Also, hardness is not harmful in the
concentrations recorded in Section A-V.
197
-------
Chloride and Magnesium
Both chloride and magnesium are not practicably treatable at
the levels recorded, and also are not harmful at the levels
present in the various waste streams.
Bromide
Bromide may result from boiler cleaning operations, but is
not considered harmful at the levels present. Moreover, it
is not practicably treatable at these levels.
Nitrate and Manganese
Nitrate and manganese are also not harmful nor practicably
treatable at the levels present in the various waste
streams.
Surfactants
Surfactants are not practicably treatable at the recorded
levels.
Algicides
Very little data was found for algicides (exclusive of
chlorine) although various algicides may be utilized in
cooling water systems. Most utilities requiring algicides
utilize chlorine.
Other Potentially Significant Pollutants
The following are potentially significant pollutants, which
may be present in effluents from steam electric powerplants,
but for which little data are available at this time.
Cadmium
Lead
Nickel
Selenium
Complete analyses of the fossil fuel used by a particular
plant can be used as a basis for determining which
pollutants, in addition to those covered by effluent
limitations guidelines and standards, are likely to be
present in effluents in quantities justifying monitoring and
the establishment of effluent limitations.
198
-------
Selection of Pollutant Parameters
The U. S. Environmental Protection Agency published (Federal
Register, Volume 38, No. 199, pp. 28758-28670, October 16,
1973) HO CFR 136 "Guidelines Establishing Test Procedures
for the Analysis of Pollutants." Seventy-one pollutant
parameters were covered. This list with the addition of
free available chlorine, polychlorinated biphenyls, chemical
additives, debris and pH, which were not included, provides
the basis for the selection of pollutant parameters for the
purpose of developing effluent limitations guidelines and
standards. All listed parameters are selected except for
these excluded for one or more of the following reasons:
1. Not harmful when selected parameters are controlled
2. Not present in significant units
3. Not controllable
U. Control substitutes more harmful pollutant
5. Insufficient data available
6. Indirectly controlled when selected parameters are
controlled.
7. Indirectly measured by another parameter
8. Radiological pollutants not within the scope of
effluent limitations guidelines and standards.
Table A-VI-3 presents a breakdown of the methodology for
selection of parameters for the following waste water stream
(except for sanitary wastes) which comprise the entire waste
water discharged from steam electric powerplants:
High Volume
nonrecirculating (once-through) condenser cooling
systems
Intermediate Volume
blowdown from recirculating condenser cooling water
systems
nonrecirculating ash sluicing systems;
nonreciruclating service water systems
199
-------
Table A-VI-3
SELECTION OP POLLUTANT PARAMETERS*
POLLUTANT PARAMETER
General
Acidity (as CaCO )
Alkalinity (as CaCO3)
Ammonia (as N)
Biochemical oxygen demand (5-day)
Chemical oxvqen demand
Hardness-total
Kjeldahl nitrogen (as N)
Nitrate (as N)
Nitrite (as N)
pH value
Total dissolved (filterable) solids
Total organic carbon
Total phosphorus (as P)
Total solids
Total suspended (nonf ilterable) solids
Total volatile solids
Nutrients, Anions. and Orqanics
Algicides
Benzidine
Bromide
Chloride
Chlorinated organic compounds
Chlorine-free available
Chlorine— total residual
Cyanide-total
Debris
Flouride
Oil and grease
Organic nitrogen (as N)
Ortho-phosphate (as P)
Pesticides
Phenols
Polychlorinated biphenyls
Sulfate (as SO )
Sulfide (as S)
Sulfite (as SO )
Surfactants
Chemical additives (biocide,corr. inhib. )
CLA
High-Volume
1
1
2
2
2
3
2
2
2
2
3
2
2
3
3
2
6
2
2
3
2
•
6 **
2
•
2
2
2
2
2
2
2
3
3
3
2
6**
SS OF WASTE WATER STREAMS
Intermediate- Volume
1
1
2
2
2
4
2
2
2
•
3
2
•
6
•
2
6
2
3
3
5
•
6**
2
2
2
•
2
6
5
2
2
3
3
3
6
6**
Low-Volume
'l
1
2
2
?
4
2
2
2
6
2
6
6
•
2
5
2
3
3
5
2
2
2
2
6
•
2
6
2
2
2
3
3
3
6
6 •
Rainfall Runoff
1
1
2
2
2
4
2
2
2
•
3
2
2
6
•
2
2
5
3
3
5
2
2
2
2
2
•
2
2
5
2
•
3
3
3
2
2
*Keyi • =Selected 5 =Rejected because insufficient data available
1 =Rejected because not harmful when selected parameters are controlled 6 =Rejected because indirectly controlled when selected parameters
2 =Rejected because not present in significant amounts are controlled
3 =Rejected because not controllable
4 =Rejected because control substitutes a more harmful pollutant
Selected where technology is available to achieve no discharge
7 =Rejected because indirectly measured by another parameter
8 =Rejected because radiological pollutants are not within the
scope of EoP.Ao guidelines and standards
-------
Table A-VI-3 (continued)
SELECTION OF POLLUTANT PARAMETERS *
POLLUTANT PARAMETER CLASS OF WASTE WATER STREAMS
Trace Metals
Aluminum-total
Antimony-total
Arsenic-total
Barium-total
Beryllium-total
Boron-total
Cadmi urn- tota 1
Calcium- total
Chromium- VI
Chromium-total
Cobalt-total
Copper-total
Iron-total
Lead-total
Magnes ium— total
Manganese-total
Mercury-total
Molybdenum-total
Nickel-total
Potassium-total
Selenium-total
Silver-total
Sodium-total
Thallium-total
Tin-total
Titanium-total
Vanadium-total
Zinc-total
Physical and Biological
Coliform bacteria (fecal)
Coliform bacteria (total)
Color
Fecal streptococci
Specific conductance
Turbidity
Radiological
Alpha— counting error
Alpha-total
Beta-counting error
Beta-total
Radium-total
High-Volume
2
2
2
2
2
2
2
1
2
2
2
3
3
2
1
2
2
2
3
1
2
2
1
2
2
2
2
2
2
2
2
2
2
3
8
e
8
8
8
Intermediate- Volume
6
2
2
2
2
3
3
1
6
•
2
6
6
2
1
2
2
2
6
1
2
2
1
2
2
2
2
•
2
2
6
2
7
6
8
8
8
8
8
Low— Volume
6
2
2
2
2
3
2
1
6
6
2
•
•
2
1
2
2
2
6
1
2
2
1
2
2
2
2
6
2
2
6
2
7
6
8
8
8
8
8
Rainfall Runoff
6
2
2
2
2
3
2
1
2
2
2
2
2
2
1
2
2
2
6
1
2
2
1
2
2
2
2
2
2
2 '
6
2
7
6
8
8
8
8
8
*Key • =Selected
1 =Rejected because not harmful when selected parameters are controlled
2 =Rejected because not present in significant amounts
3 =Rejected because not controllable
4 =Rejected because control substitutes a more harmful pollutant
5 =Rejected because insufficient data avialable
6 =Rejected because indirectly controlled when selected parameters
are controlled
7 =Rejected because indirectly measured by another parameter
8 =Rejected because radiological pollutants are not within the
scope of E.P.A. guidelines and standards
-------
nonrecirculating wet-scrubbing air pollution
control systems
Low Volume
blowdown from recirculating ash sluicing systems
blowdown from, recirculating wet-scrubber air
pollution control systems
boiler blowdown
equipment cleaning (air preheater, boiler fireside,
boiler tubes, stack, etc.)
evaporator blowdown
flow drains
intake screen backwash
recirculating service water systems
water treatment system
Rainfall Runoff
coal pile drainage
road and yard drains
construction activities
Sanitary System
The selected parameters for the various classes of waste
water streams are shown in Table A-VI-4.
Environmental Sicrnificance of Selected Pollutant Parameters
The environmental significance of many of the pollutant
parameters evaluated in this section are discussed in detail
in "Water Quality Criteria 1972,'• a report of the Committee
on Water Quality Criteria, Environmental Studies Board,
National Academy of Sciences/National Academy of
Engineering, published in 1972 at the request of and funded
by the U.S. Environmental Protection Agency. The report
addresses the several parameters individually in the light
of water quality needs for recreation and aesthetics, public
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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.
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water supplies, freshwater and aquatic life and wildlife,
agricultural uses, and industrial water supplies.
Briefly summarized below are factors concerning the
environmental significance of the pollutant parameters
selected in this section.
Iron-Total
Iron is the fourth most abundant, by weight, of the elements
that make up the earth1s crust. It is common in many rocks
and is an important component of many soils, especially the
clays where usually it is a major constituent. Iron in
water may be present in varying quantities dependent upon
the geology of the area and other chemical components of the
waterway.
The ferrous, or bivalent (Fe ++), and the ferric, or
trivalent (Fe +++) irons, are the primary forms of concern
in the aquatic environment, although other forms may be in
organic and inorganic wastewater streams. The ferrous (Fe
*+) form can persist only in waters void of dissolved oxygen
and originates usually from ground waters or mines when
these are pumped or drained. For practical purposes the
ferric (Fe ++) form is insoluble. Iron can exist in natural
organomettallic or humic compounds and colloidal forms.
Black or brown swamp waters may contain several parts per
million of iron in the presence or absence of dissolved
oxygen, but this iron form has little effect on aquatic life
because it is ccmplexed or relatively inactive chemically or
physiologically.
In stratified lakes with anaerobic hypolimnia, soluble
ferrous iron occurs in the deep anaerobic waters. During
the autumnal or vernal overturns and with aeration of these
lakes, it is oxidized rapidly to the ferric ion that
precipitates to the bottom sediments as a hydroxide, Fe(OH)3
or with ether anions. If hydrogen sulfide (H2S) is present
in anaerobic bottom waters or muds, ferrous sulfide (FeS)
may be formed. Ferrous sulfide is a black compound and
results in the production of dark mineral muds.
Prime iron pollution sources are industrial wastes, mine
drainage waters, and ironbearing ground waters. In the
presence of dissolved oxygen, waters from mine drainage are
rapidly precipitated as a hydroxide (Fe(OH)3). These
yellowish or ochre precipitates produce "yellow boy"
deposits found in many streams draining coal mining regions
of Appalachia. Occasionally ferric oxide (Fe203) is
precipitated, which forms red waters. Both of these
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precipitates form as gels or floes that may be detrimental
when suspended in water to fishes and other aquatic life.
They can settle to form flocculant materials that cover
stream bottoms thereby destroying bottom-dwelling
invertebrates, plants or incubating fish eggs. With time
these floes can consolidate to form cement-like materials,
thus consolidating bottom gravels into pavement-like areas
that are unsuitable as spawning sites for nest building
fishes; particularly this is detrimental to trout and salmon
populations whose eggs are protected in the interstices of
gravel and incubated with oxygen bearing waters passing
through the gravel.
Iron is an objectionable constituent in water supplies for
either domestic dr industrial use. Iron appreciably affects
the taste of beverages and can stain laundered clothes and
plumbing fixtures. A study by the Public Health Service
indicates that the taste of iron may be readily detected at
1.8 mg/1 in spring water and 3.H mg/1 in distilled water.
96 hour LC50 values of 0.32 mg/1 of iron have been obtained
for mayflies, stoneflies, and caddisflies; all are important
fish food organisms. Iron has been found toxic to carp
(Cyprinus carpio) at concentrations of 0.9 mg/1 when the pH
of the waters was 5.5. Pile (Esox lucius) and trout
(species not known) died at concentrations of 1-2 mg/1. In
an iron polluted Colorado stream, trout or other fish were
not found until the waters were diluted or the iron had
precipitated to effect a concentration of less than 1.0 mg/1
even though other water quality constituents measured were
suitable fcr the presence of trout.
Ferric hydroxide floes have been observed to coat the gills
of white perch (Roccus americanus), minnows and silversides
(Menidia sp. ?) The smothering effects of settled iron
precipitates may be particularly detrimental to fish eggs
and bottom-dwelling fish food organisms. Iron deposits in
the Brule River, Michigan and Wisconsin were found to have a
residual long term adverse effect on fish food organisms
even after the pumping of iron bearing waters from deep
shaft iron mines had ceased. Settling iron floes have also
been reported to trap and carry diatoms down from waters.
The effects of iron on marine life have not been
investigated adequately to determine a water quality
criterion. Soluble iron readily precipitates in alkaline
sea waters. Fears have been expressed that these settled
iron floes may have adverse effects on important benthic
commercial mussel and other shellfish resources.
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Iron has not been reported to have a direct effect on the
recreational uses of water other than its effects on aquatic
life. Suspended iron precipitates may interfere with
swimming and be aesthetically objectionable. Deposits of
yellow ochre or reddish iron oxides can be aesthetically
objectionable.
Iron at exceedingly high concentrations has been reported to
be toxic to livestock and interfere with the metabolism of
phosphorus. In aerated soils, iron in irrigation waters are
not toxic. Precipitated iron may complex phosphorus and
molybdenum making them less available as plant nutrients.
In alkaline soils, iron may be so insoluble as to be
deficient as a trace element and result in chlorosis, an
objectionable plant nutrient deficiency disease.
Polychlorinated Biphenyls
Polychlorinated biphenyls (PCB's) are a class of compounds
produced by the chlorination of biphenyls and are known in
the United States commercially as Aroclors (R). The degree
of chlorination determines their chemical properties and
generally their composition can be identified by the
numerical nomenclature, e.g., Aroclor 1242, Aroclor 1254,
etc. The first two digits represent the molecular type and
the last two digits the average percentage by weight of
chlorine. Gas-liquid chromatography with highly sensitive
and selective detectors has been employed successfully in
their detection at low levels. PCB compounds are slightly
soluble in water; soluble in fats, oils, and organic
solvents, and resistant to both heat and biological
degradation. Typically, the specific gravity, boiling
point, and melting point of PCB's increase with their
chlorine content. PCB's are relatively non-flammable have
useful cooling, insulating, and dielectric properties, and
principally are used in the electrical industry in
capacitors and transformers.
Exposure to PCB is known to cause skin lesions and to
increase liver enzyme activity that may have a secondary
effect on reproductive processes. It is not clear whether
the effects are due to the PCB's or their contaminants, the
chlorinated dibenzofurans, that are very harmful, while
chlorinated dibenzofurans are a byproduct of PCB production,
it is not known whether they are also produced by the
degradation of PCB's.
Analyses of 40 fish, in one program, indicated only one fish
to contain less than 1 ug/g PCB with the ten highest
residues ranging from 19 ug/g to 213 ug/g whole body weight.
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Studies of the Milwaukee River revealed ambient water
concentrations of 2.0 to 2.8 ug/1 and residues in fish as
high as 105 ug/g. Open water Lake Michigan concentrations
have been reported to be less than 0.01 ug/1 with mean
residues in coho salmon of about 15 ug/g. The Food and Drug
Administration guideline for protecting the health of human
consumers of fish is 5 ug/g in tissue residues of fish.
Based on Lake Michigan data, which indicate that at a
concentration of 0.01 ug/1 the fish tissue residues exceed a
level found to be non-hazardous to man, a criterion of 0.001
ug/1 in freshwater is warranted.
Bluegill sunfish exposed to Aroclors 1248 and 1254,
exhibited a bioaccumulation factor of 7.1 x 10*. The
bioaccumulation factor for gizzard shad in the Saginaw River
(Michigan) varied between 0.6 x 10 9 and 1.5 x 10 s for
Aroclor 1254. A residue level of 2 ug/g in fish consumed by
commercial ranch mink has been shown to prevent survival of
offspring. Reproduction was almost totally eliminated in
ranch mink fed a beef diet containing 0.64 ug/g of Aroclor
1254. This suggests that a mink-food tissue level of not
more than 0.5 ug/g would be required to protect the wildlife
consumer.
Median PCB concentrations in whole fish of eight species
from Long Island Sound obtained in 1970 were reported to be
in the order of 1 ug/g, as were comparable concentrations
off the coast of Southern California. Generally, residues
in ocean fish have been below 1 ug/g.
Surveys of Escatnbia Bay (Florida) have produced data on the
pathways and effects of PCB's in the estuarine and marine
environments. Although the major PCB source, accidental
leakage from a PCB manufacturing plant has been terminated,
residues continue to be observed in aquatic organisms of the
bay. The sediment reservoir of Aroclor 1254 is thought to
be a continuing source of PCB to biota. The initial survey
of Escambia Bay biota revealed fish, shrimp, and crabs with
levels as high as 12 ug/g. Higher levels were detected in
higher trophic levels than shrimp, which could implicate a
chain transfer from sediment to large animals.
From the Escambia Bay data, which include flow-through
bioassays with residue analyses where possible, the
following conclusions were reached: (1) all of the Aroclors
tested are acutely toxic for certain estuarine organisms;
(2) bioassays lasting longer than 96 hours demonstrated
that Aroclor 1254 is toxic to commercial shrimp at less than
1 ug/1; (3) fish, particularly sheephead minnows, are
extremely sensitive to Aroclor 1254 with 0.1 ug/1 being
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lethal to fry; and (4) acute toxicity of Aroclor 1016 to
estuarine organisms is similar to the toxicity of other
Aroclors but appears less toxic to fish in long-term
exposures than does Aroclor 1254.
Oysters were sensitive to Aroclor 1260 with growth
diminished by 44 percent in 10 ug/1 and by 52 percent in 100
ug/1. Approximately 10 percent of the pink shrimp died in
100 ug/1, but no apparent effects on pinfish were noted at
100 ug/1. Aroclor 1254 had no apparent effect on juvenile
pinfish at 100 ug/1 in 48-hour flow-through tests, but
killed 100 percent of the pink shrimp. At 100 ug/1 of
Aroclor 1254 for 96 hours, shell growth of oysters was
inhibited and decreased only 41 percent at levels of 10
ug/1. The toxicity of Aroclor 1248 and 1242 to shrimp and
pinfish was similar to that of Aroclor 1254. Aroclor 1242
was toxic to oysters at 100 ug/1. Killfish exposed to 25
mg/1 of Aroclor 1221 suffered an 85 percent mortality. In
96-hour bioassays, Aroclor 1016 was toxic to an estimated 50
percent of the oysters, brown shrimp, and grass shrimp at 10
ug/1; it was toxic to 18 percent of the pinfish at 100 ug/1.
Young oysters exposed to Aroclor 1254 in flowing sea water
for 24 weeks experienced reduction in growth rates at 4.0
ug/1, but apparently were not affected by 1.0 ug/1/ Oysters
accumulated as much as 100,000 times the testwater
concentration of 1.0 ug/1. Tissue alterations were noted in
the oysters exposed to 5.0 ug/1. No significant mortality
was observed in oysters exposed continuously to 0.01 ug/1 of
Aroclor 1254 for 56 weeks.
Blue crabs apparently were not affected by a 20 day exposure
to 5.0 ug/1 of Aroclor 1254. Fink shrimp exposed under
similar conditions experienced a 72 percent mortality. 'In
subsequent flow-through bioassays, 51 percent of the
juvenile shrimp were killed by Aroclor. 1254 in 15 days and
50 percent of the adult shrimp were killed at 3.0 ug/1 in 35
days. From pathological examinations of the exposed pink
shrimp, it appears that Aroclor 1254 facilitates or enhances
the expression of latent viral infections. Aroclor 1254 was
lethal to grass shrimp at 4.0 ug/1 in 16 days, to amphipods
at 10 ug/1 in 30 days, and to juvenile spot at 5.0 ug/1
after 20 to 45 days. Sheephead minnows were the most
sensitive estuarine organisms to Aroclor 1254 with 0.3 ug/1
being lethal to the fy within 2 weeks. Aroclor 1016 in two
different 42- day flow-through bioassays caused significant
mortalities of pinfish at 32 ug/1 and 21 ug/1. Pathological
examination of those exposed to 32 ug/1 revealed several
liver and pancreatic alterations. Sheephead minnows in 28
day Aroclor 1016 flow-through bioassays were not affected by
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concentrations of 10 ug/1 or less, but died at 32 and 100
ug/1. The bioaccumulation factors for the different flow-
through bioassays ranged from .2.5 x 103 for sheephead
minnows to 1.0 x 10s for oysters.
Based upon an accumlation factor of 100,000 in the oyster,
it may be necessary to limit the marine water concentration
of PCB's to a maximum of 0.01 ug/1 to protect the human
consumer.
Evidence is accumlating that PCB1s do not contribute to
shell thinning of bird eggs. Dietary PCB's produced no
shell thinning in eggs of Mallard ducks. PCB's may increase
susceptibility to infectous agents such as viral diseases,
and increase the activity of liver enzymes that degrade
steroids, including sex hormones. Laboratory studies have
indicated that PCB with its derivatives or metabolites,
causes enbryonic death of birds.
Chlorine-Free Available, - Total Residual
Elemental chlorine is a greenish-yellow gas that is highly
soluble in water. It reacts readily with mandy inorganic
substances and all animal and plant tissues.
The denaturing effect of chlorine on animal and plant
tissues forms the basis for its use as an effective water or
wastewater disinfectant. When chlorine dissolves in water,
it hydrolyzes according to the reaction: C12 «• H2O = HOCl +
H+ + Cl~. Unless the concentration of the chlorine solution
is above 1,000 mg/1, all chlorine will be in the form of
HOCl or its disassociated ions H+ and OC1-. The HOCl is a
weak acid and disassociates according to the equation HOCl =
H+ + OC1-.
The ratio between HOCl and OC1 - is a function of the pH,
with 96 percent HOCl remaining at pH 6, 75 percent at pH 7,
22 percent at pH 8 and 3 percent at pH 9. The relationship
of HOCl and pH is significant as the undisassociated form
appears to be the bactericidal agent in the use of chlorine
for disinfection.
Chlorine is not a natural constituent of 'water. Free
available chlorine (HOCl and OCl) and combined available
chlorine (mono- and di-chloramines) appear transiently in
surface or ground waters as a result of disinfection of
domestic sewage or from industrial processes that use
chlorine for bleaching operations or to control organisms
that grow in cooling water systems. Chlorine in the free
available form reacts readily with nitrogenous organic
209
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materials to form chloramines. These compounds are harmful
to fish. Chloramines have been shown to be slightly less
harmful to fish than free chlorine, but their toxicity is
considered to be close enough to free chlorine that
differentiation is not warranted. Since the addition of
chlorine or hypochlorites to water containing nitrogenous
materials rapidly forms chloramines, toxicity in most waters
is related to the chloramine concentration. The toxicity to
aquatic life of chlorine will depend upon the concentration
of total residual chlorine, which is the relative amount of
free chlcrine plus chloramines. The persistence of
chloramines is dependent on the availability of material
with a lower oxidation-reduction potential. In most
receiving water, chloramines will combine with such
materials within a few days to form other compounds that may
have toxic effects on fish.
In field studies in Maryland and Virginia it was observed
that, downstream from plants discharging chlorinated sewage
effluents, the total numbers of fish species were
drastically reduced with the stream bottom clear of the
wastewater organisms characteristically present in
unchlorinated wastewater discharges. No fish were found in
water with a chlorine residual above 0.37 mg/1 and the
species diversity index reaches zero at 0.25 mg/1. A 50
percent reduction in the species diversity index occured at
0.10 mg/1. Of the 45 species of fish observed in the study
areas, the brook trout and brown trout were the most
sensitive and were not found at residual chlorine levels
above about 0.02 mg/1. In studies of caged fish placed in
waters downstream from chlorinated wastewater discharge, it
has been reported that 50 percent of the rainbow trout died
within 96 hours at residual chlorine concentrations of 0.014
to 0.029 mg/1. Some fish died as far as 0.8 miles (1.3 km)
downstream from the outfall. Studies indicate that
salmonids are the most sensitive fish to chlorine. A
residual chlorine concentration of 0.006 mg/1 was lethal to
trout fry in two days. The 7-day LC50 for rainbow trout was
0.08 mg/1 with an estimated median period of survival of one
year at 0.004 mg/1. Rainbow trout were shown to avoid a
concentration of 0.001 mg/1. it has been demonstrated that
brook trout had a mean survival time of 9 hours at 0.35 mg/1
18 hours at 0.08 mg/1 and 48 hours at 0.04 mg/1, with
mortality of 67 percent after 4 days at 0.01 mg/1, A 50
percent brcwn trout mortality has been observed at 0.02 mg/1
within 10.5 hours and at 0.01 mg/1 within 43.5 hours.
The range of acutely lethal residual chlorine concentrations
is narrow for various species of warm water fish. 96 - hour
LC50 values have been determined for the walleye, black
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bullhead, white sucker, yellow perch, largemouth bass, and
fathead minnow. The observed concentration range was 0.09
to 0.30 ing/I.
Using fathead minnows in a continuous bioassay technique, it
has been found that an average concentration of 0.16 to 0.21
mg/1 killed all of the test fish and that concentrations as
low as 0.07 mg/1 caused partial kills. A 50 percent
mortality has been demonstrated of smallmouth bass exposed
to 0.5 mg/1 within fifteen hours. The mean 96-hour LC50
value for golden shiners was 0.19 mg/1. It has been found
for fathead minnows and the freshwater crustacean Gammarus
pseudolimnaeus in dilute wastewater that the 96-hour LC50 of
total residual chlorine for Gammarus was 0.22 mg/1 and that
all fathead minnows were dead after 72 hours at 0.15 mg/1.
At concentrations of 0.9 mg/1, all fish survived for seven
days, when the first death occurred. In exposure to 0.05
mg/1 residual chlorine, investigators found reduced survival
of Gammarus and at 0.0034 mg/1 ther was reduced
repreduction. Growth and survival of fathead minnows after
21 weeks were not affected by continuous exposure to O.OU3
mg/1 residual chlorine. The highest level showing no
significant effect was 0.016 mg/1. With secondary waste
water effluent, reproduction by Gammarus was reduced by
residual concentrations above 0.012 mg/1 residual chlorine.
In marine water, 0.05 mg/1 was the critical chlorine level
for young Pacific salmon exposed for 23 days. The lethal
threshold for chinhook salmon and coho salmon for a 72-hour
exposure was noted to be less than 0.01 mg/1 chlorine.
Studies on the effect of residual chlorine to marine
phytoplankton indicate that exposure to 0.10 mg/1 reduced
primary production by 70 percent while 0.2 mg/1 for 1.5
hours resulted in 25 percent of primary production;,
Labortory studies on ten species of marine phytoplankton
indicate tht a 50 percent reduction in growth rate occurred
at chlorine concentrations of 0.075 to 0.250 mg/1 during a
24-hour exposure period. Oysters are sensitive to chlorine
concentrations of 0.01 to 0.05 mg/1 and react by reducing
pumping activity. At chlorine concentrations of 1.0 mg/1,
effective pumping could not be maintained.
Chromium-Total
Chromium, in its various valence states, is hazardous to
man. It can produce lung tumors when inhaled and induces
skin sensitizations. Large doses of chromates have
corrosive effects on the intestinal tract and can cause
inflammation of the kidneys. Levels of chromate ions that
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have no effect on man appear to be so low as to prohibit
determination to date.
The toxicity of chromium salts toward aquatic life varies
widely with the species, temperature, pH, valence of the
chromium, and synergistic or antagonistic effects,
especially that of hardness. Fish are relatively tolerant
of chromium salts, but fish focd organisms and other lower
forms of aquatic life are extremely sensitive. Chromium
also inhibits the growth of algae.
In some agricultural crops, chromium can cause reduced
growth or death of the crop. Adverse effects of low
concentrations of chromium on corn, tobacco and sugar beets
have been documented.
Copper-Total
Copper salts occur in natural surface waters only in trace
amounts, up to about 0.05 mg/1, so that their presence
generally is the result of pollution. This is attributable
to the corrosive action of the water on copper and brass
tubing, to industrial effluents, and frequently to the use
of copper compounds for the control of undesirable plankton
organisms.
Copper is not considered to be a cumulative systemic poison
for humans, but it can cause symptoms of gastroenteritis,
with nausea and intestinal irritations, at relatively low
dosages. The limiting factor in domestic water supplies is
taste. Threshold concentrations for taste have been
generally reported in the range of 1.0-2.0 mg/1 of copper,
while as much as 5-7.5 mg/1 makes the water completely
unpalatable.
The toxicity of copper to aquatic organisms varies
significantly, not only with the species, but also with the
physical and chemical characteristics of the water,
including temperature, hardness, turbidity, and carbon
dioxide content. In hard water, the toxicity of copper
salts is reduced by the precipitation of copper carbonate or
other insoluble compounds. The sulfates of copper and zinc,
and of copper and cadmium are synergistic in their toxic
effect on fish.
Copper concentrations less than 1 mg/1 have been reported to
be toxic, particularly in soft water, to many kinds of fish,
crustaceans, mo Husks, insects, phytoplankton and
zooplankton. Concentrations of copper, for example, are
detrimental to some oysters above 0.1 ppm. Oysters cultured
212
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in sea water containing 0.13-0.5 ppm of copper deposited the
metal in their bodies and became unfit as a food substance.
Oil and Grease
Oil and grease exhibit an oxygen demand. Oil emulsions may
adhere to the gills of fish or coat and destroy algae or
other plankton. Deposition of oil in the bottom sediments
can serve to exhibit normal benthic growths, thus
interrupting the aquatic food chain. Soluble and emulsified
material ingested by fish may taint the flavor of the fish
flesh. Water soluble components may exert toxic action on
fish. Floating oil may reduce the re-aeration of the water
surface and in conjunction with emulsified oil may interfere
with photosynthesis. Water insoluble components damage the
plumage and costs of water animals and fowls. Oil and
grease in a water can result in the formation of
objectionable surface slicks preventing the full aesthetic
enjoyment of the water.
Oil spills can damage the surface of boats and can destroy
the aesthetic characteristics of beaches and shorelines.
pH, Acidity and Alkalinity
Acidity and alkalinity are reciprocal terms. Acidity is
produced by substances that yield hydrogen ions upon
hydrolysis and alkalinity is produced by substances that
yield hydroxyl ions. The terms "total acidity11 and "total
alkalinity" are often used to express the buffering capacity
of a solution. Acidity in natural waters is caused by
carbon dioxide, mineral acids, weakly dissociated acids, and
the salts of strong acids and weak bases. Alkalinity is
caused by strong bases and the salts of strong alkalies and
weak acids.
The term pH is a logarithmic expression of the concentration
of hydrogen ions. At a pH of 7, the hydrogen and hydroxyl
ion concentrations are essentially equal and the water is
neutral. Lower pH values indicate acidity while higher
values indicate alkalinity. The relationship between pH and
acidity or alkalinity is not necessarily linear or direct.
Waters with a pH below 6.0 are corrosive to water works
structures, distribution lines, and household plumbing
fixtures and can thus add such constituents to drinking
water as iron, copper, zinc, cadmium and lead. The hydrogen
ion concentration can affect the "taste" of the water. At a
low pH water tastes "sour". The bactericidal effect of
chlorine is weakened as the pH increases, and it is
213
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advantageous to keep the pH close to 7. This is very
significant for providing safe drinking water.
Extremes of pH or rapid pH changes can exert stress
conditions or kill aquatic life outright. Dead fish,
associated algal blooms, and foul stenches are aesthetic
liabilities of any waterway. Even moderate changes from
"acceptable" criteria limits of pH are deleterious to some
species. The relative toxicity to aquatic life of many
materials is increased by changes in the water pH.
Metalocyanide complexes can increase a thousand-fold in
toxicity with a drop of 1.5 pH units. The availability of
many nutrient substances varies with the alkalinity and
acidity. Ammonia is more lethal with a higher pH.
The lacrimal fluid of the human eye has a pH of
approximately 7.0 and a deviation of 0.1 pH unit from the
norm may result in eye irritation for the swimmer.
Appreciable irritation will cause severe pain.
Phosphorus-Total
During the past 30 years, a formidable case has developed
for the belief that increasing standing crops of aquatic
plant growths, which often interfere with water uses and are
nuisances to man, frequently are caused by increasing
supplies of phosphorus. Such phenomena are associated with
a condition of accelerated eutrophication or aging of
waters. It is generally recognized that phosphorus is not
the sole cause of eutrophication, but there is evidence to
substantiate that it is frequently the key element in all of
the elements required by fresh water plants and is generally
present in the least amount relative to need. Therefore, an
increase in phosphorus allows use of other, already present,
nutrients for plant growths. Phosphorus is usually
described, for this reasons, as a "limiting factor."
When a plant population is stimulated in production and
attains a nuisance status, a large number of associated
liabilities are immediately apparent. Dense populations of
pond weeds make swimming dangerous. Boating and water
skiing and sometimes fishing may be eliminated because of
the mass of vegetation that serves as an physical impediment
to such activities. Plant populations have been associated
with stunted fish populations and with poor fishing. Plant
nuisances emit vile stenches, impart tastes and odors to
water supplies, reduce the efficiency of industrial and
municipal water treatment, impair aesthetic beauty, reduce
or restrict resort trade, lower waterfront property values.
214
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cause skin rashes to man during water contact, and serve as
a desired substrate and breeding ground for flies.
Phosphorus in the elemental form is particularly toxic, and
subject to bioaccumulation in much the same way as mercury.
Colloidal elemental phosphorus will poison marine fish
(causing skin tissue breakdown and discoloration). Also,
phosphorus is capable of being concentrated and will
accumulate in organs and soft tissues. Experiments have
shown that marine fish will concentrate phosphorus from
water containing as little as 1 ug/1.
Total Suspended Solids
Suspended solids include both organic and inorganic
materials. The inorganic components include sand, silt, and
clay. The organic fraction includes such materials as
grease, oil, tar, animal and vegetable fats, various fibers,
sawdust, hair, and various materials from sewers. These
solids may settle out rapidly and bottom deposits are often
a mixture of both organic and inorganic solids. They
adversely affect fisheries by covering the bottom of the
stream or lake with a blanket of material that destroys the
fish-food bottom fauna or the spawning ground of fish.
Deposits containing organic materials may deplete bottom
oxygen supplies and produce hydrogen sulfide, carbon
dioxide, methane, and other noxious gases.
In raw water sources for domestic use, state and regional
agencies generally specify that suspended solids in streams
shall not be present in sufficient concentration to be
objectionable or to interfere with normal treatment
processes. Suspended solids in water may interfere with
many industrial processes, and cause foaming in boilers, or
encrustations on equipment exposed to water, especially as
the temperature rises. Suspended solids are undesirable in
water for textile industries; paper and pulp; beverages;
dairy products; laundries; dyeing; photography; cooling
systems, and power plants. Suspended particles also serve
as a transport mechanism for pesticides, and other substances
which are readily sorbed into or onto clay particles.
Solids may be suspended in water for a time, and then settle
to the bed of the stream or lake. These settleable solids
discharged with man's wastes may be inert, slowly
biodegradable materials, or rapidly decomposable substances.
While in suspension, they increase the turbidity of the
water, reduce light penetration and impair the
photosynthetic activity of aquatic plants.
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Solids in suspension are aesthetically displeasing. When
they settle to form sludge deposits on the stream or lake
bed, they are often much more damaging to the life in water,
and they retain the capacity to displease the senses.
Solids, when transformed to sludge deposits, may do a
variety of damaging things, including blanketing the stream
or lake bed and thereby destroying the living spaces for
those benthic organisms that would otherwise occupy the
habitat. When of an organic and therefore decomposable
nature, solids use a portion or all of the dissolved oxygen
available in the area. Organic materials also serve as a
seemingly inexhaustible fcod source for sludgeworms and
associated organisms.
Turbidity is principally a measure of the light absorbing
properties of suspended solids. It is frequently used as a
substitute method of quickly estimating the total suspended
solids when the concentration is relatively low.
Zinc-Total
Occurring abundantly in rocks and ores, zinc is readily
refined into a stable pure metal and is used extensively for
galvanizing, in alloys, for electrical purposes, in printing
plates, for dye-manufacture and for dyeing processes, and
for many other industrial purposes. Zinc salts are used in
paint pigments, cosmetics, Pharmaceuticals, dyes,
insecticides, and other products too numerous to list
herein. Many of these salts (e.g., zinc chloride and zinc
sulfate) are highly soluble in water; hence it is to be
expected that zinc might occur in many industrial wastes.
On the other hand, some zinc salts (zinc carbonate, zinc
oxide, zinc sulfide) are insoluble in water and consequently
it is to be expected that some zinc will precipitate and be
removed readily in most natural waters.
In zinc-mining areas, zinc has been found in waters in
concentrations as high as 50 mg/1 and in effluents from
metal-plating works and small-arms ammunition plants it may
occur in significant concentrations. In most surface and
ground waters, it is present only in trace amounts. There
is some evidence that zinc ions are adsorbed strongly and
permanently on silt, resulting in inactivation of the zinc.
Concentrations of zinc in excess of 5 mg/1 in raw water used
for drinking water supplies cause an undesirable taste which
persists through conventional treatment. Zinc can have an
adverse effect on man and animals at high concentrations.
216
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In soft water, concentrations of zinc ranging from 0.1 to
1.0 mg/1 have been reported to be lethal to fish. Zinc is
thought to exert its toxic action by forming insoluble
compounds with the mucous that covers the gills, by damage
to the gill epithelium, or possibly by acting as an internal
poison. The sensitivity of fish to zinc varies with
species, age and condition, as well as with the physical and
chemical characteristics of the water. Some acclimatization
to the presence of zinc is possible. It has also been
observed that the effects of zinc poisoning may not become
apparent immediately, so that fish removed from zinc-
contaminated to zinc-free water (after 4-6 hours of exposure
to zinc) may die U8 hours later. The presence of copper in
water may increase the toxicity of zinc to aquatic
organisms, but the presence of calcium or hardness may
decrease the relative toxicity.
Observed values for the distribution of zinc in ocean waters
vary widely. The major concern with zinc compounds in
marine waters is not one of acute toxicity, but rather of
the long-term sub-lethal effects of the metallic compounds
and complexes. From an acute toxicity point of view,
invertebrate marine animals seem to be the most sensitive
organisms tested. The growth of the sea urchin, for
example, has been retarded by as little as 30 ug/1 of zinc.
Zinc sulfate has also been found to be lethal to many
plants, and it could impair agricultural uses.
217
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PART A
CHEMICAL WASTES
SECTION VII
CONTROL AND TREATMENT TECHNOLOGY
General Methodology
Curry371 presents a general methodology for metallic waste
treatment. Some of the principles are also applicable,
however, to other types of wastes. The following outline
conveys, with some modifications, the general principles of
Curry's work:
I. Omit flows with a pollutant concentration lower
than the concentration in equilibrium with the
precipitate formed
II. Reduce the waste water volumes requiring treatment
III. Minimize the solubility cf the pollutant
A. Eliminate compounds that form soluble
complexes
B. Reduce concentration of interfering ions that
increase pollutants solubilities
C. Maintain conditions that minimize total
solubility
IV. Control conditions to increase the proportion of
the pollutants in the ionic form required for its
precipitation or adsorbent reaction
V. Avoid conditions that will form harmful amounts of
gases during treatment
VI. Select a process that will give the lowest
practicable or economically achievable amounts of
pollutants in the effluent, up to and including no
discharge of pollutants
VII. Select a process that produces a sludge that can be
disposed of in accordance with environmental
considerations.
219
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Pollutant-Specific Treatment Technology
Applicable control and treatment technology relevant to
specific pollutants is discussed in the J.W. Patterson, et
al, report "Wastewater Treatment Technology".208 Based on
the data of that report and other sources, the following
information is given on pollutant-specific treatment
technology.
Aluminum
Precipitates as the hydroxide at pH 5.5-7.371, *62 The
minimum solubility is at pH 6.0. Some halides may increase
the solubility of aluminum by complexation reactions and
thus change the conditions.**«
Ammonia
Ammonia can be removed from waste waters by stripping with
steam or air. Steam stripping systems are capable of
achieving effluent ammonia concentrations of from 5 to 30
mg/1. Cooling towers could be considered as air strippers
of ammonia from contaminated waters. However, the reverse
effect can occur, i.e. air-borne ammonia is absorbed.375
Antimony
Solubility data indicates a potential removal of about 90
percent by lime coagulation treatment.18
Arsenic
Treatment processes employed involve coagulation at pH 6.0
to produce ferric hydroxide floe to tie up the arsenic and
carry it from solution. This process has consistently
yielded arsenic levels of 0.05 mg/1 or less.
Barium
Precipitation as barium sulfate after addition of ferric or
sodium sulfate at pH 6.0 yields effluent levels of 0.03-0.27
mg/1.
Beryllium
No information was found concerning treatment methods for
the removal of beryllium from industrial waste waters.
However, precipitation of insoluble sulfate, carbonate or
hydroxide may be possible.
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Boron
No practicable treatment is reported. Borate-nitrate
corrosion inhibition treatment is used in closed-loop house
service water systems. Boron from this source could be
reduced by minimizing the use of boron-containing chemicals.
However, some boron chemicals could discharge from ash
sluicing operations as a result of boron content in raw coal
used for firing.
Cadmium
Cadmium precipitates as the hydroxide at elevated pH. Its
solubility at pH 10 is 0.1 mg/1. The presence of iron
hydroxide can enhance removal due to co-precipitation with,
or adsorption on the iron floe. Complexing agents in the
waste stream can reduce the effectiveness of precipitative
removal.
Calcium
The lime-soda process precipitates calcium as calcium
carbonate.
Chlorine Residuals
An end-of-pipe treatment for reducing chlorine levels is the
addition of reducing agents such as sodium bisulfite
(NaHS03). Chlorine being an oxidizing agent will oxidize
these chemicals. Dechlorinaticn with sulfur dioxide has
been practiced for many years in water treatment 43° and,
more recently, on wastewater.431 Sulfur dioxide is favored
for its low cost and ease of handling. It is fed by
equipment identical to that used in chlorination systems.
The reaction in dechlorination is instantenous, the
resulting products being chloride and sulfate ions. The
theoretical requirements is 0.9 mg/1 of sulfur dioxide per
mg/1 of residual chlorine (not chlorine dosage). Actual
practice indicates the requirement to be nearer 1:1. It is
equally effective for combined or free residual.418 One mole
of bisulfite is required per mole of chlorine or 1.47 mg/1
per mg/1 of chlorine. By maintaining a 10% excess of sodium
bisulfite in the discharge stream, chlorine can be
eliminated. However, the excess sodium sulfite creates an
oxygen demand, thus substituting one pollutant problem for
another.
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Chromium
The most common method of chromium removal is chemical
reduction of hexavalent chromium to the trivalent ion and
subsequent chemical precipitation. The standard reduction
technique is to lower the waste stream pH to 3 or below by
addition of sulfuric acid, and to add sulfur dioxide, sodium
bisulfite (or metabisulfite or hydrosulfite), or ferrous
sulfate as reducing agent. Trivalent chromium is then
removed by precipitation with lime at pH 8.5-9.5.
The residual of hexavalent chromium after the reduction step
depends on the pH, retention time, and the concentration and
type of reducin.g agent employed. The following effluent
levels are reported for treatment of industrial wastes:
metal finishing wastes,
using sulfure dioxide -------- 1 mg/1
metal finishing wastes,
using sulfur dioxide -------- "zero"
wood preserving wastes,
using sulfur dioxide -------- 0.1 mg/1
electroplating wastes,
using sodium bisulfite ------- 0.7-1.0 mg/1
cooling tower blowdown,
using metabisulfite ------ below 0.5 mg/1
cooling tower blowdcwn,
using metabisulfite --------- 0.025-0.05 mg/1
metal plating wastes,
using metabisulfite --------- o.l mg/1 or less
chrome plating wastes,
using metabisulfite --------- 0.05-0.1 mg/1
Ion exchange treatment of metal finishing wastes has
successfully met chrome effluent standards equivalent to a
hexavalent chromium concentration of 0.023 mg/1.
The solubility of trivalent chromium is less than
approximately 0.1 mg/1 in the pH range 8-9.5. Effluent
levels, after precipitation of industrial wastes with lime,
are reported as follows:
electroplating wastes,
using coagulant aid ------------- 0.06 mg/1
metal finishing wastes,
using settling ------------- below 3 mg/1
wood preserving wastes,
using settling ---------------- o.02 mg/1
metal finishing wastes,
using an anionic polyelectrolyte ------- 0.75 mg/1
222
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Ion exchange removal can effect complete removal of
trivalent chromium.
The U.S. Atomic Energy Commission reports total chrornate
effluents of 0.1-0.2 mg/1 after either chemical treatment or
ion exchange.372"373
Cobalt
No information was found concerning treatment methods for
the removal of cobalt from industrial waste waters.
Copper
Effluent concentrations of 0.5 mg/1 can be consistently
achieved by precipitation with lime employing proper pH
control and proper settler design and operation. The
maximum solubility of the metal hydroxide is in the range pH
8.5-9.5. In a powerplant, copper can appear in the waste
water effluent as a result of corrosion of copper-containing
components of the necessary plant hydraulic systems.
Normally, every practicable effort is made, as a part of
standard design and operating practices, to reduce corrosion
of plant components. However, copper is not used in once-
through boilers and, consequently, is not found in
corresponding spent cleaning solutions. Excessively
stringent effluent limitations on copper may necessitate
complete redesign and alteration of condenser cooling and
other systems. The following effluent levels of copper are
reported for full-scale treatment of industrial wastes by
lime precipitation followed by sedimentation (except as
noted):
metal processing wastes --------0.5 mg/1
metal processing wastes -------- 0.2-2.5 mg/1
metal processing wastes, using
sand filtration -- - - - 0.2-0.5 mg/1
metal fabrication wastes,
using coagulant -----------2.2 mg/1
metal finishing wastes ------ avg. 0.2 mg/1
metal mill wastes ----------- 1-2 mg/1
wood preserving wastes -------- 0.1-O.U mg/1
A significant problem in achieving a low residual
concentration of copper can result if complexing agents are
present, especially cyanide and ammonia.
223
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Iron
In general, acidic and/or anaerobic conditions are necessary
for appreciable concentrations of soluble iron to exist.
"Complete11 iron removal with lime addition, aeration, and
settling followed by sand filtration has been reported.
Existing technology is capable of soluble iron removals to
levels well below 0.3 mg/1. Failure to achieve these levels
would be the result of improper pH control. The minimum
solubility of ferric hydroxide is at pH 7. In some cases,
apparently soluble iron may actually be present as finely
divided solids due to inefficient settling of ferric
hydroxide. Polishing treatment such as rapid sand filters
will remove these solids. In a powerplant, iron, as with
copper, can appear in the waste water effluent as a result
of corrosion to iron-containing components of the necessary
plant hydraulic systems. Normally, every practicable effort
is made, as a part of standard design and operating
procedures, to reduce corrosion of plant components.
Excessively stringent effluent limitations on iron, as with
copper, may necessitate complete redesign and alteration of
condenser cooling and other systems.
Lead
Precipitation by lime and sedimentation has been reported.
Little data is available on effluent lead after treatment;
however, the extreme insolubility of lead hydroxide
indicates that good conversion of soluble lead to insoluble
lead can be achieved, with subsequent removal by settling or
filtration.
Magnesium
The lime-soda process precipitates magnesium as the
hydroxide.
Manganese
Precipitates upon lime addition. Significant removals
during water treatment are achieved at pH 9.4 and above.
Molybdenum
No information was found concerning treatment methods for
the removal of molybdenum from industrial waste waters.
However, precipitation as chloride or sulfide may be
possible.
224
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Mercury
General treatment methods exist which are applicable to
mercury-bearing waste streams. One of the most common,
simplest, and most effective methods to remove mercury from
solution is precipitation of an insoluble mercury compound.
Sodium sulfide (Na2S) and sodium hydro-sulfide (NaHS) are
effective in forming the extremely insoluble HgS. This
method is not favored, however, when recovery of mercury is
desired, since offensive and poisonous hydrogen sulfide
(H2S) gas is formed in the reduction process. By keeping
the pH about 10 the H2S problem can be avoided while
enhancing the production of sulfide ion for
precipitation.462 Other methods include filtration with
adsorptive compounds such as activated carbon, graphite
powder and powdered zinc, chemical flocculation, and ion
exchange.
Nickel
Nickel forms insoluble nickel hydroxide upon addition of
lime. Little efficiency is gained above a pH of 10, where
the minimum theoretical solubility is 0.01 mg/1. Removal by
adsorption on an iron or manganese hydroxide floe is
possible.*«2
Oil and Grease
Flotation is efficient in removing emulsified oil and
requires minimum space. It can be used without chemical
addition, but demulsifiers and coagulants can improve
performance in some cases. Whenever possible, primary
separation facilities should be employed to remove free oil
and solids before the water enters the flotation unit.
Multi-stage units are more effective than single-stage
units.. Partial-recycle units are more effective than full-
pressure units. Oil removal facilities including single-
cell flotation can achieve effluent oil and grease levels
from 10-20 mg/1, while multi-stage units can achieve 2-10
mg/1. Reference 398 gives data on oil and grease levels
attained by a number of petroleum refineries using primary
gravity separation, flotation (with and without chemicals),
chemical flotation, and filtration. Reference 399 presents
data on oil and grease levels achieved by dissolved air
flotation. Levels ranging from 2-20 mg/1 were indicated.
Total Phosphorus(as P)
Phosphorus concentrations of less than 0.1 mg/1 can be
routinely obtained using two-stage lime clarification at pH
11, followed by multi-media pressure filters. Single-stage
lime clarification at pH 9-11 with cr without filtration can
225
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achieve phosphorus concentrations of 2 mg/1 or less. Figure
A-VII-1 shows the effect of pH on phosphorus concentration
of effluent after filtration. The average concentration for
a clarifier pH of 9.5, and prior to filtration was 0.75
mg/1.37* Precipitation using ferric or aluminum salts has
been used.*62
Potassium
No information was found concerning treatment methods for
the removal of potassium from industrial waste waters.
Polychlorinated Biphenyls (PCBs)
PCBs are commonly used as coolants in large transformers.
Special care should be taken to prevent leaks and spills and
to contain possible spills of these fluids in order to
prevent their discharge to water bodies.
Selenium
Under conditions of moderate reduction, selenium may be
removed from solution by reduction to the insoluble
elemental form.*62
Silver
Precipitation with chloride ion can remove silver to the
mg/1 level. However, co-precipitation with other metal
hydroxides under alkaline conditions improves silver removal
to less than 0.1 mg/1.
Sodium
No information was found concerning treatment methods for
the removal of sodium from industrial waste waters.
Sulfate
Use of lime (calcium carbonate) in place of dolomite
(mixture of calcium carbonate and magnesium carbonate) in
lime treatment will minimize the presence of soluble
sulfates, due to insolubility of calcium sulfate and
solubility of magnesium sulfate.
Thallium
No information was found concerning treatment methods for
the removal of thallium from industrial waste waters.
226
-------
2.0
3.5
ca
E
Tf.
a
o
o
C£
p
n:
CL.
O
a.
0.5
•• .^r-t
00 «•"
e
T*-
*
B.5
9.0
.J ______ ! __ ;
9.5 10.0
CLARIFIER pH
10.5
11.0
11.5
Figure A-VII-1
Effect of pH on Phosphorus Concentration
of Effluent from Filters Following
374
Lime Clarifier
227
-------
However, the trivalent hydroxide is insoluble and may be
removed by lime addition.
Tin
No information was found concerning treatment methods for
the removal of tin from industrial waste waters. However,
precipitation as hydroxide or sulfite may occur.
Titanium
No information was found concerning treatment methods for
the removal of titanium from industrial waste water.
Total Dissolved Solids
Removal of total dissolved solids (TDS) from waste waters is
one of the more difficult and more expensive waste treatment
procedures. Where TDS result from heavy metal or hardness
ions, reduction can be achieved by chemical precipitation
methods; however, where dissolved solids are present as
sodium, calcium, or potassium compounds, then TDS reduction
requires more specialized treatment, such as reverse
osmosis, electrodialysis, distillation, and ion exchange.
Total Suspended Solids
Suspended solids removal can be achieved by sedimentation
and filtration operations employing, in some cases,
flocculaticn-coagulation technology to improve the clarity
of the effluent or to speed up the process.
Vanadium
No information was found concerning treatment methods for
the removal of vanadium from industrial waste waters.
However, precipitation as the insoluble hydroxides may
occur. However, vanadium recovery operations discussed
elsewhere in this section may include technology for
preventing vanadium from dissolving, thus increasing the
amount in the reclaimable solid.
Zinc
Lime addition for pH adjustment can result in precipitation
of zinc hydroxide. Operational data indicate that levels
below 1 mg/1 zinc are readily obtainable with lime
precipitation. The use of zinc can be minimized since other
treatment chemicals are available to reduce corrosion in
closed cooling-water cycle. Zinc removals have been
228
-------
reported for a range of industrial systems and, generally,
treatment is not for zinc alone. Lime addition with
hydroxide precipitation followed by sedimentation (except as
indicated) has yielded the following effluent zinc levels:
plating wastes ------------ 0.2-0.5 mg/1
plating wastes ------------ 2 mg/1
plating wastes, using
sand filtration -----------0.6 mg/1
plating wastes ------------ less than 1 mg/1
fiber manufacturing wastes ------ less than 1 mg/1
tableware manufacturing wastes,
using sand filtration -------- 0.02-0.23 mg/1
fiber manufacturing wastes ------ 0.9-1.5 mg/1
fiber manufacturing wastes ------ 1 mg/1
metal fabrication wastes ------- 0.5-1.2 mg/1
metal fabrication wastes, using
sand filtration ----------- 0.1-0.5 mg/1
Combined Chemical Treatment
Precipitat ion
The effluent levels of metal ions attainable by combined
chemical treatment depend upon the insolubility of metal
hydroxides in the treated water and upon the ability to
mechanically separate the hydroxides from the process
stream. Reference 379 presents data on the solubilities and
other aspects of chemical treatment for the removal of metal
ions from waste waters. The theoretical solubilities of
copper, nickel, chromium, zinc, silver, lead, cadmium,
tellurium and ferric and ferrous iron as a function of pH
are shown in Figures A-VII-2, 3. At a pH of 9.5 the
solubility of copper, zinc, chrcmium, nickel and iron is of
the order of 0.1 mg/1, or less. Experimental values plotted
in Figures A-VII-U, 5 vary somewhat from the theoretical
values. Nevertheless, the need for fairly close pH control
in order to avoid high concentrations of dissolved metal in
the effluent is evident. A pH of 8.5 to 9.0 is best for
minimizing the solubility of copper, chromium and zinc, but
a pH of 10.0 is optimum for minimizing the solubility of
nickel and iron. To limit the solubility of all of these
metals in a mixed solution, an intermediate pH level would
be selected.
A further aspect related to solubility is the time for
reaction. Figure A-VII-6 shows the change in solubilities
of zinc, cadmium, copper and nickel with time for various
levels of pH.
229
-------
io cr
i.o
O.I
XI
"o
in
0.01
OOOI
7
10
II
12
Solution, pH
Figure A-VII-2
SOLUBILITY OF COPPER, NICKEL,
AND ZINC AS A FUNCTION OF pH
230
-------
0>
9? O.I
.0
_3
O
0.0001
O.Of
0.001
Figure A-VII-3 THEORETICAL SOLUBILITIES OF METAL IONS
AS A FUNCTION OF pH
231
-------
0.
Legend
O Nickel
D Chromium
X Zinc
A Copper
Note: Values plotted as O.I mg/i
were reported as zero.The
O.lmg/jt value is assumed
to be the detectable limit.
8 9 10 II
Solution , pH
12
13
14
Figure A-VII-4
EXPERIMENTAL VALUES - SOLUBILITY OF METAL IONS AS
A FUNCTION OF pH
379
232
-------
0.01
7 8 9 10
pH (After 2-hr Standing)
Figure A-VII-5 EXPERIMENTALLY DETERMINED SOLUBILITIES
OF METAL IONS AS A FUNCTION OF pH
Reference No0 236
233
-------
ou
70
60
/
u 20 n
c
0
— pH =
T~\ \ III I
*
- pH =
pH =
7- \ 1 1 1 1 1
7.5
1 ,
,
8.0
8.5
1 J
* i.e'
o
w 1.2
S;0.8
E0.4
0
pH =
^_ pH =
9,0
9.5
10.-
1 1 1 1 1 1 1
0 1234 567 8
Standing time, hours
ZINC
e
3
•H
e
nj
u
t-i
X)
3
O
W
-H
1
1UU
80
60
20'
10
i
4.0,
3.0
2.0
1.0'
f
0.4
0.2
(
pH = 8
—
.5
^~ pH = 9.0
L_ I 1 1 1 1 I
.
j,
>
- pH = 9.5
—
u_ 1 I 1 1 1 1
,
t
— ^_-- • ' ' pH = 10.i
—
._ .1 1 J I.I 1 .
' .
••-,
/
~ ^ — pir =~TO .
-^^^^
i i i i i i
i i 2 3 4 5 6
fc
Standing time, hours
CADMIUM
|
04
a
o
o
o
o
(O
Cr>
e
16
14
12
10
8J
2.4
2.0
1.6
1.2
0.8
0.4
0
I I
7.5
I I I I
0)
X.
u
•H
2
a)
r-t
JQ
3
i-H
o
w
20
16
12
8
4
= 9.0
=9.5
I I I I I I „
01234
678
Standing time, hours
NICKEL
012345678
Standing time, hours
COPPER
Values for pH = 8.0 are_ 0_._2 _ _ _ __ _ _ ___
Figure A-VII- 6' CHANGE IN THE SOLUBILITIES OF ZINC, CADMIUM, COPPER, AND
AND NICKEL PRECIPITATES (PRODUCED WIT!! LIME
ADDITIONS) AT- A FUNCTION' OF STANDING TIME AMD
pH VALUE. Reference No. 236.
234
-------
The theoretical and experimental results do not always agree
well with results obtained in practice. Concentrations can
be obtained that are lower than the above experimental
values., often at pH values that are not optimum on the basis
of the above considerations. Effects of co-precipitation
and adsorption on the flocculating agents added to aid in
settling the precipitate play a significant role in reducing
the concentration of the metal ions. Dissolved solids made
up of noncommon ions can increase the solubility of the
metal hydroxides according to the Debye-Huckel Theory. In a
treated solution from a typical electroplating plant* which
contained 230 mg/1 of sodium sulfate and 1,060 mg/1 of
sodium chloride, the concentration of nickel was 1.63 times
its theoretical' solubility in pure water. Therefore, salt
concentrations up to approximately 1,000 ppm should not
increase the solubility more than 100 percent as compared.to
the solubility in pure water. However, dissolved solids
concentrations of several thousand ppm could have a marked
effect upon the solubility of the hydroxide.
When solubilizing complexing agents are present, the
equilibrium constant of the complexing reaction has to be
taken into account in determining theoretical solubility
with the result that the solubility of the metal is
generally increased. Complexing agents such as EDTA
(ethylene-diamine-tetraacetic acid) , could .have serious
consequences upon the removal of metal ions by
precipitation.
Superposed on the situation presented above for chemical
treatment for the removal of iron, copper, chromium and
nickel could be requirements for removal of other heavy
metals and phosphorus. Phosphorus effluents of 2 mg/1 are
achievable with or without filtration at pH 9-11, therefore,
no problem of phosphorus removal is anticipated at pH values
which are optimum for the removal of iron, copper, chromium
and nickel. Reference 380 presents minimum pH values for
complete (effluent generally 1 mg/1) precipitation of metal
ions as hydroxides as follows: Sn*«(pH 4.2), Fe+3 (pH 4.3),
A1+'(PH 5.2), Pb+2(pH 6.3), Cu*« (pH 7.2), Zn+« (pH 8.4),
Ni+2(pH 9.3), Fe*2(9.5), Cd+* (pH 9.7)r, Mn+* (pH 10.6). In
the case of amphoteric metals such as aluminum and zinc,
resolubilization will occur if the solution becomes too
alkaline. . .
Alkali Selection
Several alkaline materials are available for use in chemical
treatment, e.g. lime, hydrated lime, limestone, caustic
soda, soda ash. The choice among these may depend on
235
-------
availability, cost, desired effluent quality, ease of
handling, reactivity, or characteristics of sludge produced.
A comparison of these materials is given in Table A-VTI-1.
When cost and effluent quality are the most important
factors, lime, hydrated lime and limestone would be the more
commonly used alkalis.
Lime is readily available and relatively simple to use. In
acid (coal) mine drainage applications, it consistently
neutralizes the acidity and removes the iron and other
metals present in mine drainage at a reasonable cost, if not
the least cost. For these reasons, lime is used in most of
the estimated 300 plants that treat mine drainage.380 The
relative disadvantages of lime are: an increase in the
hardness of the treated water, problems of scale (gypsum)
formation on plant equipment, and the difficulties in
dewatering or disposal of the sludge volumes produced.
There are four basic steps in lime treatment. First, waste
waters are neutralized by addition of slurried lime with
vigorous mixing for 1-2 minutes. Aeration is provided for
15-30 minutes to oxidize ferrous iron to the ferric state.
Solids separation is provided in either mechanical
clarifiers, or large earthen settling basins. The treated
water is discharged and the sludge is disposed of. Capital
costs range from about $40/cu m processed/day for a 40,000
cu m/day process to about $100/cu m/day for a 2,000 cu m/day
process to about $1,000/cu m/day for a 400 cu m/day process
for treatment of acid mine drainage. Operating costs vary
from 3 to 12 cents per 1,000 cu m (11 to 45 cents per
million gallons) per mg/1 of acidity but are generally in
the range 4 to 7 cents/1,000 cu m/mg/1 (15 to 27
cents/million gallons/mg/1) . 38<> sludge disposal costs can be
as much as 50 percent of the total operating costs.
Limestone has several advantages over other alkaline agents.
The sludge produced settles more rapidly and occupies a
smaller volume. The pH of the treatment is not so sensitive
to feed rate. Limestone is easier to handle than the other
alkaline materials. Disadvantages center around its slow
reactivity which requires larger detention times and larger
treatment vessels. As a result of its disadvantages few
actual operating systems have been installed.
Aeration
The oxidation of ferrous iron to ferric iron can be
accomplished by either diffused or mechanical aeration
equipment. Capital costs range from about $2,000 for a 100
cu m flow/day process to about $50,000 for a 10,000 cu m
236
-------
Table A-VII-1
COMPARISON OF ALKALINE AGENTS FOR CHEMICAL TREATMENT
380
Agent
Cost, $/ unit of CaCO equiv,
ro
to
Limestone, Rock (calcium carbonate)
Limestone, Dust (calcium carbonate)
Quick Lime (calcium oxide)
Hydrated Lime (calcium hydroxide)
Magnesite (magnesium carbonate)
Soda Ash (sodium carbonate, 50%)
Dolomite (calcium-magnesium carbonate)
Ammonium Hydroxide
Caustic Soda (sodium hydroxide,50%)
8.82
11.02
14.19
20.40
23.24
42.08
47.70
50.14
67.02
-------
flow/day process. Operating costs will vary from 10-20
percent of the total plant operating costs.3a«
Solids Separation
The first step in separating the precipitated metals is
settling, which is very slow for gellike zinc hydroxide, but
accelerated by co-precipitation with the hydroxides of
copper and chromium. Coagulation can also be aided by
adding metal ions such as ferric iron which forms ferric
hydroxide and absorbs some of the other hydroxide, forming a
floe that will settle. Ferric iron has been used for this
purpose in sewage treatment for many years as has aluminum
sulfate. Ferric chloride is frequently added to the
clarifier of chemical waste-treatment plants in plating
installations. Flocculaticn and settling are further
improved by use of polyelectrolytes, which are high
molecular weight polymers containing several ionizable ions.
Due to their ionic character they are capable of swelling in
water and adsorbing the metal hydroxide which they carry
down during settling.
Settling is accomplished in the batch process in mechanical
clarifier or a stagnant tank, and after a time the sludge
may be emptied through the bottom and the clear effluent
drawn off through the side or top. The continuous system
uses a baffled tank such that the stream flows first to the
bottom but rises with a decreasing vertical velocity until
the floe can settle in a practically stagnant fluid.
Although the design of the clarifiers has been improved
through many years of experience, no settling technique or
clarifier is 100 percent effective; some of the floe is
found in the effluent - typically 10 to 20 mg/1. This floe
could contain 2 to 10 mg/1 of metal. Polishing filters or
sand filters can be used on the effluent following
clarification. The general effectiveness of such filtering
has not been ascertained.
Evaporation and Other Processes
Basic processes, in addition to evaporation ponds, include
multi-stage flash evaporation, multi-effect long-tube
(vertical) evaporation, and vapor compression evaporation.
The multi-stage flash evaporation process has been
considered potentially applicable to the production of
potable water from acid mine drainage.380 Major problems
which have confronted this process are calcium sulfite
scaling and brine deposit. The product water at 50 mg/1 TDS
238
-------
is suitable for recycle to almost all water uses in steam
electric powerplants.
Vapor-compression evaporation systems are being offered on a
guaranteed performance basis by a company specialized in
their applications. These systems can be used to recover
and recycle most of the water contained in the typical blow-
down from recirculating process streams. A schematic flow
diagram of a typical vapor-compression evaporation system is
shown in Figure A-VII-7. The system works as follows:
The brine to be treated is initially fed into a feed tank
for a 5-to-10 minute residence during acid treatment. The
acidified feed is then pumped through a heat exchanger: (1)
which raises the temperature of the incoming flow to the
boiling point. After the water passes through a
noncondensible gas scrubber (2), it enters the evaporator
sump (3). Brine from the sump is pumped to the top of the
heat-transfer tubes (H), where it is released to fall as a
film inside of the tubes. A portion of this falling film is
vaporized. In a vapor-compression thermodynamic cycle, the
vapor is then compressed (5) and introduced to the shell
side of the tube bundle. (6). The temperature differential
between the vapor and the brine film causes the vapor to
condense as pure water (7). The concentraton brine slurry
is continuously withdrawn (8) from the sump for final
dehydration in a solar pond, mechanical dryer, or separator.
The total energy consumption is in the range of 30 to HO Btu
per pound of feed water.
Membrane processes are capable of acceptably high levels of
brine concentration. However, flux-rate reduction with
increasing brine concentration, and membrane fouling are
problems which have not been satisfactorily overcome.
Insufficient information is available to judge the
performance, reliability, costs of membrane electrodiaiysis,
ion exchange, freezing, electrochemical oxidation (of
ferrous iron), ozone oxidization or any other process for
the treatment of steam electric powerplant waste waters.
Technology Specific to Powerplant Waste Waters (General)
The control and treatment technology for the discharge of
chemical wastes from a steam electric powerplant involves
one or more combinations of the following techniques:
(1) Elimination of pollutants by:
a) process modifications
239
-------
ro
-p»
o
CONDENSATE
[ | COMPRESSED VAPOR
WATER VAPOR
[ | CONDENSATE
STEAM
COMPRESSOR
PRODUCT
WATER
PUMP
CONCENTRATED BRINE
Figure A-VII-7 Brine Concentrator, Resources Conservation Co.
452
-------
b) material substitutions
c) good housekeeping practices
(2) Control of waste streams by maximum reuse
and conservation of water
(3) Removal of pollutant from waste stream
The following is a summary,exerpted from reference 4<»4, of
the principal methods of powerplant waste disposal which are
currently available:
1. Controlled Release to a Waterway. A common
practice is to neutralize the acid or alkaline waste and
release it via the circulating water discharge so that
dilution of 5,000 or 10,000: 1 is realized.
2. Collection of Spent Solvent in a Retention Basin
for Neutralization and Sedimentation Before Controlled
Release. This method has the advantage at some sites that
acidic wastes can be reacted with alkaline wastes so that no
additional chemicals are required for neutralization; but
the applicability of this method is affected by site
characteristics such as availability of space and the nature
of other wastes generated at the site.
3. Impoundment on Company Property. Some utilities
particularly in the Southwest impound their waste in lagoons
on site. These lagoons or holding basins are suitably
constructed so as to prevent the escape of the liquid by any
means other than evaporation. This method is of course
possible only at locations where sufficient land is
available and where climate conditions are suitable.
3. Off-Site Disposal. In some cases chemical wastes
have been trucked off-site to a commercial waste disposal
firm. Costs range up to 12 cents per gallon depending on
waste compositions and distance. Barging to deep sea is
another method which has been used by utilities along the
coast. This method is costly and generally cannot be
economically justified for volumes under 200,000 gallons.
In general, economic and environmental considerations limit
the usefulness of off-site disposal to special situations.
5. Solidification of Hastes. Some utilities have
experimented with solidifying the spent solvents. This
entails engaging an outside vendor who transports a van
equipped with solidifying reagents, pumps and other
paraphernalia; scheduling is important and costs range from
5 to 17 cents per gallon. This method can be used where
solid disposal is possible in a landfill area, gully,
abandoned mine, etc. Final solid volume is about 5% more
241
-------
than starting volume of the waste due to the solidfying
chemicals added.
6. Combustion or Incineration of Wastes. Within the
last year or two, one utility has introduced a new means of
disposal of certain spent solvents. A small number of jobs
have not been performed by several utilities in which Vertan
675 or the ammoniated citric acid from the CitroSolv
process, both at pH of 9.2 - 9.5, have been drained from the
boiler and combusted in an adjoining boiler. The method has
been to spray the spent solvent into the furnace of an
operating boiler at a rate of 50-100 gallons per minute.
Interestingly, no deleterious air pollution effects have
been associated with this procedure. In fact there appears
to be some reduction in emissions of nitrogen oxides and
dulfur dioxide. It is questionable whether this method
could be used on neutralized hydrochloric acid or ammonium
solutions. There is a distinct possiblity that the halogen
ions could attack the austentite steel alloy tubes in the
superheater and reheater.
In order to select and implement an efficient waste
management program, it is necessary to evaluate the control
and treatment techniques corresponding to specific factors
applicable in each case.
In this section alternate control and treatment techniques
and their limitations are evaluated for different chemical
waste streams. Advantages and disadvantages are presented.
Based on the reported data, industry-wide practices and
exemplary facilities are indicated.
Chemical wastes can be discussed in three general groups
(continuous wastes, periodic wastes, and wastes whose
characteristics are unrelated to the powerplant operations)
even though, for the purposes of guideline development, a
classification by volume would be appropriate. The
continuous wastes are those directly associated with the
continuous production of electrical energy. They include
condenser cooling water discharge (for once-through systems)
or blowdcwn (for closed systems), water treatment plant
wastes, boiler or PWR steam generator blowdown, discharges
from house service water systems, laboratory, ash handling
systems, air pollution control devices, and floor drains.
The periodic wastes are those associated with the regularly
scheduled cleaning of major units of equipment, usually at a
time of plant cr unit shutdown. Those include spent
cleaning solutions from the cleaning of the boiler or PWR
steam generator tubes, boiler fireside, air preheater and
condenser cooling system, and other miscellaneous equipment
242
-------
cleaning wastes. The final group of wastes includes
drainage from coal piles of coal fueled plants, drainage
from roof and yard drains, run-off from on-site construction
and sanitary wastes. Control and treatment of discharges
from systems involving high-level or low-level rad wastes
are not known to be practicable due to the possible adverse
affects which might arise from concentrating the radioactive
materials in the treatment operation.
Continuous Waste Streams
Cooling Water Systems
References 357, 387-389, «»18 and others are a source of
considerable information en control technology for cooling
water systems.
Maintaining condenser tubes or other heat exchange equipment
with an inherent new-tube cleanliness is most important to
keep the efficiency and economics of the process at its
designed level. The cost penalty of tube fouling increases
porportionately as the cleanliness decreases. If allowed to
continue, an unscheduled outage may be rquired to clean the
tubes, thereby losing production and further compounding
additional costs. The objective is to maintain the
cleanliness factor at an acceptable level by one or more
methods that can be:
1. Continuous and complete chemical conditioning of the
cooling system while operating
2. Chemical cleaning of the heat exchanger tubes at the
scheduled outage
3. Mechanical cleaning of the tubes while operating with
equipment utilizing either sponge rubber balls or brushes,
slightly over-sized to pass through the tubes
4. Mechanical cleaning of the tubes at a scheduled otuage
5. Mechanical cleaning as in Item 3 but without extensive
chemical conditioning as intended in Item 1.
To discuss methods of cleaning condenser systems might imply
that condenser tubes become fouled quite often either from
chemical or biological deposits or in combination. In some
instances this is true; there are electric generating plants
that consider it necessary to clean condenser tubes on a
weekly basis. Others do so less frequently, such as semi-
annual ly or annually. Yet other plants can operate and
243
-------
maintain the designed cleanliness factor without having to
clean tubes but once in 10 to 15 years. For many plants the
elementary difference may lie in the attitude toward
maintaining a proper quality program for the cleanliness of
circulating water systems, whether once-through or
recirculating incorporating a cooling tower.
Chemical Conditioning
Chemical Conditioning of Once-Through Systems
At those generating plants where once-through cooling is
used, chemical conditioning of the circulating water for
corrosion and scale control is never practiced. The costs
would be prohibitive considering the large volume of water
to be treated. Mainly the only chemical needed is a biocide
to minimize fouling of the condenser tubes, tube sheets, and
water boxes by bacterial slime or other growths. Generally
the biocide is predissolved chlorine gas, applied one or
more times a day over a period of 15 to 30 minutes to
produce a residual of about 1 mg/1 or more at the condenser
inlet. Chlorine is the only biocide that has proved to be
effective and most economical at many plants.
Frequency, dose, and duration of the chlorination cycle is
variable, depending on water quality and temperature. Four
30 minute periods a day is not an unusual program. Dosage
is controlled by maintaining a residual level at the
condenser outlet at a level of about 0.5 mg/1. Time
interval between application and sampling may be in the
range of 20-30 seconds when chlorine is applied just ahead
of the condensers to 3-5 minutes when it is applied at the
intake.
Water quality has a two-fold effect on this operation. The
poorer the quality, the greater the chlorine demand thus
increasing dosage requirements. The food supply in poor
quality water accelerates the growth of organisms in the
condenser tubes between chlorination programs thus
increasing the duration of the chlorination cycle and/or
frequency to maintain satisfactory control. The popular
definition of the term "chlorine demand" is that it is the
defference between dose and residual. To be of meaning, it
must be properly .expressed in terms of type of residual,
temperature, pH, and time of contact between dosing and
residual measurement. It is the time element that is so
frequently overlooked and which poses a problem in very
short time-of-contact situations.
244
-------
Consider, for instance, that demand figures tinder otherwise
identical conditons were compared for 30 seconds vs 30
minutes in water containing ammonia nitrogen. Assuming 80%
of the 30 minute demand will be satisfied in the first 5
minutes, much of this will occur in the reaction with
hypochlorous acid before the formation of the slower
reacting chloramines. When this occurs, the rate of
satisfaction of the demand falls off rapidly. When demand
results are based on the addition of preformed chloramines,
the difference is so drastic that chlorine demand figures
require the added dimension of type of available chlorine
being used. Misunderstood by many is that ammonia does not
constitute chlorine demand until the ratio of chlorine to
ammonia exceeds approximately 10:1.
Further complicating this issue in the case of short contact
times is that sampling and accurate residual determination
may consume much more time than the actual contact time.
This error probably accounts for many powerplants using a
larger dosage than necessary in their cooling water.
The preparation of environmental impact statements for
operating systems for new power stations led to the study of
existing plants for probable operating results. Some
multiple units employing once-through cooling water systems
were found to seldom discharge any appreciable residual
chlorine to the receiving water where the station
configuration was similar to that shown in Figure A-VII-8
Procedure provides for chlorination of one unit at a time on
a program similar to that described below. The discharge
from each unit is diluted by that from the three not being,
chlorinated. The effect of dilution and exertion of
chlorine demand by the unchlorinated water occurs almost
simultaneously.
Data from several power plants are illustrated by Table A-
VII-2 The data were collected by trained technicians
familiar with powerplant chlorination practices, using
amperometric titrators. The scope of the test work did not
include complete analysis of the water but, based on the
foregoing comments regarding chlorine dosage, ammonia, and
time of contact, the differences in water "quality" are
evident. Stations A and B are nearly idential in layout to
that shown by Figure A-VII-8, but located on two different
rivers. The points of application are close to the
condenser water boxes in both power plants. Plant C has a
common discharge canal and several units were running at the
time of the test. All points of chlorine application are at
the intakes serving the units and one unit is treated at a
time. Plants D, E, and F are included to illustrate the
245
-------
Figure A-VII-8 Typical Powerplant Cooling Water
Circuit
S.AMPI.ING POINT
fO.T CONTROL
SAMl'-LifJG POIi.T
FOR MOXItQfllNG.
^^^
~^v
U.MIT N'O. 1
UNI r f-.:o. ?
IJi-IIT .\'O. 3
\J:M! I rJO. 4
/ /
I
/
" "V
/
V
/
\
\
r\
V
HIVER
Table A-VII-2
OPERATING DATA
TYPICAL POWER_ P.LA-NT_COOLI^ V..vrF.R CHLORINATICN
OF E.'< ,' O.'.'C i- -THSCUCiH , CObL L'.'G SYSTEMS
ClL\RCH-H?i; 197~3)
Reference 418
PUNT
A
B
C
D
E
F
TIME OF
(SECO
Thru Cond.
30
61
SZ
115
44
63
CONTACT
^;DS)
To River
180
174
78
624
225
591
DILU-
TION
RATIO
3:1
3:1
4:1
4:1
1:1
5:1
"2
DOSE
0"g/D
1.52
1.76
2.00
3.80
7.00
7.00
CMLQIUK'i Rl:5ir
Cond. "liiicli
Free
0.6S
O.C5
0.03
0.50
1.20
1.10
Tot.il
0.84
0.82
l.SO
1.60
2.20
2.00
J'JAL (F^A)*
1 Ht:fluf/.t
Free
0.06
0.07
0.00
0.00
0.70
0.00
Total
0.19
0.10
0.20
0.20
1.20
O.OS
CHLORINE T.IC.'.TJ.F.OT
(X/D.iy)| (Mia.)
1
1
3
3
5
1
30
30
20
120
i
30
45
•Chlorine residuals by amperomctric titrator.
246
-------
differences which can be encountered on the same river -over
a distance of less than 3 miles. Plant D is the upstream
plant and Plant F is the farthest downstream. The points of
chlorine application are at the intakes in all cases and the
plants supervisory and operating personnel have many years
of experience with chlorination. The purpose of Table A-
VII-2 is to illustrate, as accurately as possible, actual
operating conditions in power plants where organic growths
in condensers are being successfully controlled, and to show
the effects of dilution and added "chlorine demand" on the
total residual chlorine in the plant effluents.
The data were collected in plants having individual units
varying in age from 5 to 30 years, and unit sizes from 60 Mw
to 750 Mw. After one studies the data one may reach
conclusions such as (a) Plant D is overchlorinating in terms
of either frequency or duration; (b) Plant E is
overchlorinating in terms of residual level and frequency.
Extensive test work is being conducted at both plants to
determine the optimum chlorine treatment required.
It is not unusual to observe two units in a single power
plant requiring different chlorination schedules. The
geometry of \he cooling water system; size and design of
condensers; physical condition of the tube surfaces; as well
as water quality have an influence on the chlorine residual
levels and schedules of operation required to maintain
comparable unit performance. Obviously, the condition of a
river can change substantially within a few miles as
indicated by Plants D, E, and F.
A conclusion is that substantial savings in chlorine dosage
can be achieved by application as near the condenser inlet
as possible while still maintaining control levels necessary
to maintain cleanliness. This in turn results in residual
chlorine consisting to some major degree of hypochlorous
acid, a form most easily reduced to chloride by chlorine
demand of water from adjacent units.
Another study was made on the blowdown of a cooling tower
serving a power plant employing intermittent chlorination of
recirculated water for slime control of the condensers.
Blowdown was continuous. Chlorination of the unit served by
this tower is programmed for four times a day. Residual in
the blowdown for one cycle (typical of the other three) is
shown in Figure A-VII-9. Makeup to this tower is discharge
from a cooler using water from another system in the plant,
also being chlorinated with a similar program but staggered
from the tower under study. This accounts for the momentary
increase close to the end of the cycle. This curve shows
247
-------
080
070
0.60
ICO 120 KO 160
TIME IN MINUTES
200 220 2JO 260 280 200
Figure A-VII-9
Concentration of Residual Chlorine
in Cooling Tower Slowdown Versus Time
418
248
-------
only total residual chlorine. Other data on this tower
indicated that at peak values as much as 65% of the total
was free available chlorine, declining gradually and
disappearing when the total dropped to approximately 0.2
mg/1.
Draley,425 in developing data for an equation to predict
decay rate, plotted the residual values during two
chlorination cycles and beyond in a power plant with a
natural draft tower. The shape of the curves for the
cooling tower basin return was nearly identical to Figure A-
VII-9. Peak value for one run was about 0.3 mg/1 total
residual. No free available chlorine was found. A second
run with a peak value of about 0.5 mg/1 total yielded less
than 0.1 mg/1 free available chlorine.
The similarity of the shape of the curves is noteworthy in
view of the differences in the syterns. The data in Figure
A-VII-9 represents a cooling water which (1) has some
residual remaining from the previous cycle, (2) the total
value was higher, (3) sampling was in the tower blowdown
instead of the cold water return, and (U) the tower was of
the induced draft instead of natural draft (hyperbolic)
type.
In another study. Nelson32* in developing a mathematical
model to predict residual chlorine levels in cooling tower
blowdown streams, expressed residual as negative chlorine
demand. When the plot of the resulting curve is simply
inverted, it closely resembles those mentioned above. The
point is that the reliability of predictability seems firmly
established. The factors involved in the decay rate of the
recirculated cooling water after the chlorination cycle is
ended are: (1) blowdown; (2) evaporative losses; (3) light
catalyzed decomposition of free chlorine; (1) chlorine
demand of the system; (5) cooling system volume; (6)
recirculation rate; (7) chlorine demand of the makeup; (8)
atmospheric contamination; and (9) decomposition products of
basin sediment deposits.
Since all of these effects occur simultaneously, it seems
impossible to segregate and identify them individually.
Fortunately, from the results cited above it also seems
unnecessary. One of these, evaporate losses, has been cited
as a possible air pollution problem. The volatitity of
chloramines has long been known to exceed that of free
available chlorine. This is particularly true of nitrogen
trichloride and, to a slightly lesser degree, dichloramine.
In fact, aeration is frequently used to remove these
compounds following ammonia nitrogen oxidation (breakpoint
249
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chlorination). The most predominant species,
monochloramine, is much less subject to loss. In studying
waste treatment plant effluents, where the residual usually
consists of all chloramine, Kothandaraman and Lin42*
reported no loss of residual chlorine due to air agitation
of 5600 cfm/1000 cu ft for 30 minutes at residual levels
above 2 mg/1. Thus it would appear that evaporative losses
of combined chlorine which could be expected to be nearly
all monochloramine in a cooling tower and subsequent air
contamination are not factors of consequence. Free
available chlorine is subject to reduction by sunlight but
not by volitilization.
Excess total residual chlorine discharge can be minimized by
monitoring free available chlorine concentrations in the
discharge stream and providing feed-back control on chlorine
addition. Commercial monitoring and controlling instruments
are available from at least two major suppliers. The
analyzers furnished by both of these firms involve an
amperometric analytical method which utilizes two electrodes
to measure the current generated by the presence of
chlorine. One of these firms advises that the reliability
of this type of analyzer and control system is generally
concluded to be approximately 0.1 mg/1. However, the
analyzer must be calibrated in the field at least once per
week by using a titrator, and consequently the ultimate
reliability of the system depends upon the conscientiousness
of the operating and/or maintenance personnel. These
analyzers can be used to monitor either total residual
chlorine or free available chlorine by making a change in
the chemical composition of the buffer solution.
As shown in Figure A-VII-10, chlorine can be regulated by
feedback instrumentation. The chlorine feeder is activated
manually or by a timer. Chlorine is then added to the
cooling water before it goes to the condenser. Cooling
water leaving the condenser flows to the cooling pond or to
the receiving water body. Chlorine level in the discharge
is monitored by chlorine analyzer AC-1. When chlorine
reaches 0.1 mg/1 the analyzer opens ACS-1 which shuts down
the feeder until it is restarted manually or by timer KS-1.
This type *ot system is not in general use in the industry at
this time, but is common practice in municipal sewage
treatment plants. Intermittent programs of chlorine or
hypochlorite addition can be employed to reduce to total
chlorine residual discharged. A further technique to reduce
the total residual chlorine discharged is to employ
chlorination at periods of low condenser flow for a unit.
If only one unit at a time at a multiunit station is
chlorinated, the concentration of total residual chlorine in
250
-------
RIVER
WATER
SUPPLY
AC-1
CONDENSER
KS-1
RIVER
WATER
RETURN
CHLORINATOR
-o
ACS-1
CHLORINE
CYLINDER
LEGEND:
AC-1:
ACS1:
KS-1:
CHLORINE ANALYZER
CHLORINE FEEDER CONTACTS
CONTROLLER (TIMER OPTIONAL)
FLOW PATH
OPTIONAL FLOW PATH
INSTRUMENT SIGNAL
FIGURE A-VII-10CHLORINE FEED CONTROL ONCE-THRU CONDENSER COOLING SYSTEM
251
-------
the combined effluent from the station is reduced.
Chlorination can further be employed at times in harmony
with more favorable receiving water conditions.
Controlled addition of chlorine can also be achieved without
the daily use of monitoring instruments. Sampling and
laboratory analysis can be employed for a number of days
until a correlation is established between chlorine addition
characteristics (schedule, rate, duration) and the effluent
total residual chlorine concentrations. Subsequent use of
the correlation with no effluent sampling, except for
occasional checks, may be satisfactory in many cases.
Figure A-VII-11 illustrates, in simplified form, a typical
once-through system for a nuclear or fossil-fueled plant.
It is impossible to cover the many variations in layout
which are being developed by engineers to accommodate the
rapidly changing technology, power plant equipment design,
and growth in unit size. However, regardless of the
complexity of the system, all of the cooling water must be
chlorinated.
To minize the level of residual chlorine in the effluent, it
is logical to select points of chlorine appM.cation and
design the control system to take maximum advantage of
dilution effects in the discharge canal(s). This requires
revisions in what has been considered standard practice.
Referring to Figure A-VII-11, it has become a common
practice in recent years to chlorinate the plant service
water and or auxiliary cooling water as separate systems tor
two reasons which remain valid: (1) Chlorination of the
service water often requires a schedule of treatment and
chlorine dosage level different than needed for the main
condensers; and (2) modern intake designs and pump locations
make it very difficult to design and locate a single set of
diffusors to chlorinate all the water entering the plant.
Therefore, chlorination of the station service water,
auxiliary cooling water, and emergency cooling water (if
any) remain as separate functons which may be controlled to
take advantage of dilution in the water return system.
For the past twenty-five years, with few exceptions,
condenser cooling water has been chlorinated at the intake
structure. Again, with few exceptions, chlorination was
programmed on a unit basis as indicated by the plants listed
on Table A-VII-2 There are several sound reasons for this
practice: (1) The chlorine solution piping system is short
and of simple design for most applications; (2) The
electrical control system is the least complicated possible.
252
-------
Figure A-VII-11 Typical Power Plant Once-Through
Fresh or Salt Water Cooling System-
Points of Chlorine Application
( Reference 418)
253
-------
often being limited to one or two program clocks and simple
chlorine feed step rate controls; (3) If marine growths and
shelled organisms are anticipated as a problem the diffusors
are located ahead of the bar racks instead of in the screen
wells 428 and the controls remain essentially the same as
indicated above; and (4) The chlorination equipment and
chlorine handling system are located near the water intake
structure which is generally several hundred feet from the
power station proper.
Generally new condensers are served by at least two cooling
water flows and six are not uncommon. Therefore, if the
points of chlorine application are located in the piping
system just ahead of the inlet water boxes as illustrated on
Figure A-VII-11 and the chlorine control system designed to
treat the unit flows (four illustrated) one at a time in
sequence, the chlorine residual in the treated water will be
diluted by a factor of one, three or five depending on the
system design.
The auxiliary cooling systems are treated on a separate
program which is timed to operated when the main condenser
flows are not being treated. The ratio of auxiliary water
flow to the total main condenser flow is on the order of one
to ten or more and it is unlikely that a measurable chlorine
residual from this source would be detected in the plant
effluent.
There are existing powerplants which have been using this
type of control for over 15 years though the original
designers had no thoughts regarding dilution of chlorine
residual in the effluents at the time the plants were built.
Experience with chlorination in these plants has been
excellent. Based on work done several years ago and recent
test data presented herein, there are several advantages
which should fce self-evident: (1) The short time of contact
minimizes both the chlorine dose required and the level of
the combined chlorine residual in the water as it passes
through the condenser; (2) Since a large percentage of the
total chlorine residual in the condenser during treatment is
free (HOCl) the duration of each treatment can also be
reduced. However, duration of treatment and frequency are
both dependent on the rate of growth of the fouling
organisms and frequency, in particular, may require change
with the season of the year; and (3) The effect of dilution
on the total chlorine residual in the plant effluent is
obvious.
Mechanically and electrically, the chlorination system
becomes more complicated but with compensations. The size
254
-------
of the chlorination system in terms of chlorine feed rate is
reduced by a factor of two, four or six. This saving in
cost is probably offset by the additional solution piping
and controls which are required. The chlorine control
equipment and handling system may still be located remotely
with respect to the power plant. The total amount of
chlorine used will be reduced to the practical minimum for
the particular plant and units.
There are three points which should not be overlooked
though, in most cases, they would not be considered
disadvantages: (1) Long cooling water lines ahead of the
condensers are unprotected in terms of organic fouling: (2)
The intake structure and cooling water system up to the
points of application are subject to fouling by Bryozoa and
shelled organisms if brackish water or sea water is the
source of cooling water, and (3) Service water and/or
auxiliary cooling water must be treated in its entirety,
usually at the intake, because of the relatively complicated
cooling systems involved.
The current trend in the U.S. is away from large, open,
once-through cooling water system except those involving
man-made lakes built for the purpose of sea water cooled
projects. For practical purposes, the modern spray canal
can also be considered as an open system in terms of
chlorination though actual experience is limited to very few
installations at this time. One spray canal user reported
during August, 1971, that no detectable chlorine residual
returned to the point of chlorine application. The blowdown
connection is on the cold water end of the canal and ahead
of the point of chlorine application. No measurable
residual chlorine is in the blowdown water at any time. The
constants for this particular system are:
Recirculating rate -29 185,000 gpm treated one at a time
(2 Program Control)
Chlorine Treatment - 20 minutes once per day - each point
Chlorine Dosage - 2.7 mg/1
Total Chlorine Residual - 0.5 to 1.0 mg/1 at condenser inlet
Points of Application - Ahead of circulating pumps
Dilution Ratio - 1:1
Contact Time in Canal - 5 hours
Makeup Water Flow - 20,000 gpm
255
-------
One plant, on once-through circulation with sea water,
changed to acrolein from chlorine primarily because acrolein
(CH2CHCHO) was more effective in controlling grass growth
that matted the screens at the intake canal. After some
months it was noted that condenser tube fouling had
increased; an inspection disclosed that the acrolein was
more effective than anticipated for biological fouling; the
tubes and the tube sheet were free of slimes. The foulant
in heat transfer was found to be a paper thin layer of
carbonate scale that previously had been kept under control
by the slight depression of pH when chlorine was used. The
acrolein was incapable of reacting with the carbonate. The
plant then changed back to chlorine. Of incidental
interest, acrolein in the amount needed as a biocide has
zero toxicity to fish. Typical of many others, this plant
has not had to clean condenser tubes either manually or
chemically after 10 years operation. The biocide quality
control program has been adhered to and has maintained to
desired cleanliness factor. The related program of
reversing flow through the condenser was incorporated in the
original design and is routinely utilized to dislodge some
of the potential foulants.
Chemical Conditioning in Recirculating Systems
In an evaporative cooling tower system the dissolved solids
will become increasingly concentrated above the amount of
dissolved solids in the makeup water to the system because
of evaporative cooling losses. By blowdown from the system
the concentrated solids are maintained at a prescribed level
to prevent chemical precipitation and scaling. Chemical
conditioning is used supplementally to minimize any scaling
or corrosive tendency. Shock treatment with a biocide
completes the conditioning program. Chemical conditioning
with proper quality control will maintain the designed
terminal temperature difference at the condenser for many
years. Corrosion rates will be less than 1.0 mil per year.
Tables A-VII-3 and A-VII-U show the average operational
values for two types of chemical conditioning of cooling
tower systems that are operated without on-line mechanical
tube cleaning equipment.
The monitoring of chlorine in the blowdown stream can be
achieved in a manner similar to that described for the
once-through system.
256
-------
Table A-VII-3
CHEMICAL CONDITIONING OF COOLING TOWER SYSTEM
USING CrO4 - 387
Untreated River Makeup to Tower
Cooling Tower System
Ca as CaCO3
Mg as CaCOs
HC03 as CaCOs
ClasCI"
S04 as SO4
mg/l
200
66
129
455
60
Ca as CaCO3
MgasCa(X>3
HCOs as Ca(X>3
Cl as CC
804 as 804
CrO4 as Cr
' P04 as P
pH
mg/l
800
264
15
1,820
712
12
4
6.5
Controllable limits in tower system: pH 6.4 to 6.6; total alkalinity 15 to 20 mg/l;
calcium as CaCOs 1000 mg/l max; hexametaphosphate'6 to 10 mg/l; CrC>4
25 to 30 mg/l.
Table A-VII-4
CHEMICAL CONDITIONING OF COOLING TOWER SYSTEM
USING ORGANIC PHOSPHATE 387
Untreated Well Water Makeup to Tower
mg/l
Ca as CaC03 232
Mg as CaCC>3 40
HCO3asCaCO3 216
SiC>2 as Si02 28
Cooling Tower System
Ca as
Mg as
HCO3 as
SiO2 as
mg/l
968
212
196
150
Controllable limits in tower system: pH 8.4 to 8.6; total alkalinity 175 to 225
mg/l; calcium as CaCOs 1000 mg/l max; silica as SiO2 180 mg/l max; organic
phosphate 20 to 30 mg/l.
257
-------
Further potential methods of reducing or eliminating
residual chlorine levels in the blowdown are as follows:376
a) Installing residual data feedback equipment into
the chlorine feed system.
b) Practicing split stream chlorination (splitting the
condenser flow into separate streams which are
chlorinated one at a time) .
c) Reducing the chlorine feed period, if possible.
d) Reducing the initial residual chlorine level in the
condenser effluent.
e) Increasing the water volume of the cooling tower.
This alternative may not apply to existing cooling
towers because it involves the system design. The
alternative can apply to systems on the engineering
drawing boards. This alternative may have other
advantages—such as an extra supply of water for fire
protection.
f) Cutting off the blowdown when residual chlorine
appears in the sump. The blowdown flow can resume after
the residual is dissipated by the flashing effect and
the makeup water chlorine demand. The length of time
during which the blowdown can be eliminated is a
function of the system's upper limit on dissolved
solids.
g) Mixing the blowdown with another stream which has a
high chlorine demand.
Figure A-VII-12 illustrates a typical recirculated fresh
water cooling system and a few of the ancillary systems or
variations which are often encountered. The total residual
chlorine curve with respect to time (decay) is predictable
for a cooling tower system. Location of the points of
chlorine application is traditionally in the tower basin
discharge canal or ahead of the recirculating pumps in a
sump. The several sets of data in the references were
collected from tower systems intermittently chlorinated
using the traditional points of application. At this time
a recommendation cannot be made that the location of the
point of application be changed since dilution or lowering
of the chlorine residual returning to the tower would
undoubtedly result in accelerated fouling of the tower fill.
If the makeup water is first used to cool auxiliaries, it
should be chlorinated following the same principles as used
for an open system but with the program set so that it does
not coincide with treatment of the recirculating water.
The blowdown should be taken from the tower basin ahead of
the point of chlorine application but it has been found that
258
-------
/ i
'•-->
....y ..._,,
"TSi
v-; <>
n
r J
.„..
L
K-
•-•• i
\ l_.
I ccx..i.iiVu
RrcM-y;i;i.ATto r :•,':> ~;..A.riT cot'.: .:•-.; v..vi;%r? SYSTEM
Figure A-VII-1.2
259
-------
•this is not the case for many existing cooling tower
Systems. If the blowdown is used to sluice ash, the
chlorine residual is lost in the ash pond. Similarly, a
holding pond could accomplish the same result if the time of
retention is long enough. At the very least, a holding pond
smooths out the peak levels of residual chlorine and reduces
the level to one which can be easily eliminated by
controlled chemical dechlorination.
If the blowdown is returned to the receiving body of water
direct, there are two alternatives: (1) Close the blowdown
valve during the chlorination cycles with suitable time
delay controls set to match the time-residual
characteristics of the system; and (2) Controlled chemical
dechlorination of the blowdown in synchronism with the
chlorination program controls and with time delay as
described above.
Experience indicates that a successful chlorination cycle
for the average fresh water power plant cooling tower system
is two treatments per day; each treatment approximately ten
minutes longer than the turnover time; and with the chlorine
feed rate set to build up a total residual chlorine level of
0.5 mg/1 in the water returning to the tower at the end of
the chlorination period. Note that this statement is based
on current experience; not on tests designed to determine
the minimum treatment which will produce the desired
results; viz., a clean system. For example, it should
follow that a lower residual maintained for a longer time
would give a similar result, or carried to the logical
conclusion, a very low total chlorine residual carried in
the system continuously would be equally effective.
There are several power companies in the U.S. which use
continuous chlorination of cooling tower systems but at
residual levels on the order of 0.3 to 0.5 mg/1. No
experiments have been performed to determine the
practicability of variations in the chlorine treatment of
cooling tower systems; largely because no one wishes to risk
the need for removing a large unit from the line to manually
clean both the condenser and the cooling tower.
Experience with recirculated salt water systems is
practically nil but the makeup water to a cooling tower
system should be chlorinated continuously if the water
supply is either brackish or salt. The total residual
chlorine level should be the minimum which can be realiably
controlled, i.e., between 0.1 and 0.2 mg/1. The treatment
will prevent infection of the recirculated water system by
260
-------
Bryozoa and shelled marine organisms such as barnacles and
mussels.
Controlling the usual organic slime growths in once-through
salt or brackish, water-cooled heat exchangers requres the
same chlorine treatments as needed for fresh water.
Variations in residual chlorine level, length, and duration
of treatment are caused by pollution factors, the same as
for fresh water, and the need to control the accumulation of
more resistant marine growths.
Using the open system, salt water experience as a reference,
it follows that continuous low level chlorination of the
makeup water will eliminate the marine organisms as a
problem and certainly reduce the bacterial infection and
chlorine demand added to the recirculating water via the
makeup water. However, it is doubtful that it would be
practical to chlorinate the makeup water heavily enough for
the chlorine residual to be effective in the condensers or
on the tower structure.
The standard intermittent chlorination of the recirculating
water will be the same as described for a fresh water system
but undoubtedly the total amount of chlorine used will be
reduced. The cooling water is an excellent air scrubber and
algae as well as "chlorine demand" removed from the air
remain as fouling sources to be contolled by chlorination of
the recirculating water.
The amounts of pollutants discharged in blowdown can be
reduced by reducing the blowdcwn flow. This reduction in
flow can be achieved by substituting more soluble ions for
scale formers. Similarly, the use of organic sequestering
agents such as polyolesters and phosphonates can be used to
reduce blowdown flow rates. 336 These then become
pollutants in the blowdown.
Water treatment chemicals are used to control several
problem areas. The use of these chemicals has been greatly
reduced by the substitution of plastic or plastic-coated
cooling tower components. The plastic shows considerable
resistance to microbiological attack, corrosion, and
erosion. Many new installations using cooling towers are
going this route. Where water treatment is necessary,
several chemicals are being used to control the various
problem areas associated with the cooling towers.
Of the commonly used biocides, chlorine or hypochlorite or
nonoxidizing organic compounds such as chlorophenols,
quaternary amines, and organo-metallics such as organotin
261
-------
compounds, organosulfur, and organothiocyanate Table A-V-18
are most frequently employed. They are all used to prevent
deterioration of tower wood, loss of heat transfer
efficiency, general fouling or plugging arising from
microbial growths, and corrosion that results from microbial
attack, Organotin must be formulated with quaternary
ammonium and other complex amines to produce a synergistic
effect and to be dispersible. Chlorophenols, as soluble
potassium and sodium salts, are more persistent than free
chlorine and remain in systems longer. Common Chlorophenols
include: 2,4,5-trichlorophenate; 2,4,6-T; 2,3,4,6-T;
tetrachlorophenol; and pentachlorophenol. Organosulfurs are
noted for low toxicity to animals, yet effective action
against bacteria, fungi, and especially sulfate-reducing
bacteria. Quarternary and complex amines are effective
wetting agents and destroy microbial agents by surface-
active properties; these are the least toxic of all
antimicrobial compounds to animals, although they may form
and so cause anesthetic problems. The organothiocynates,
the most modern of the nonoxidizing biocides, are widely
effective. Oils, organic chemicals, water hardness, and
other materials seem to cause little reduction in their
effectiveness, especially if they are combined with
Chlorophenols. The nonoxidizing biocides are used whenever
the problems are rather severe and where the use of free
chlorine is not acceptable. Typical concentrations for
continuous use are 1 to 25 ppm; higher (200 ppm or so) if
applied in periodic treatments. Elemental chlorine is an
oxidizing agent and can cause rapid deteroriation of
wood.10See
The use of biocides that contain mercury, arsenic, lead, or
boron may be limited by more stringent regulations on their
release to the environment than most of the compounds
previously discussed. These are rarely if ever used now;
however, a review of label names in Table A-V-18 reveals
that the potentially harmful materials, copper and
thiocyanate ions, are present in some commercial compounds.
Tin is probably also questionable as far as environmental
harm is concerned. All of the chemical labels note that
precautions should be used in handling of the proudct, and
two indicate that the product may be harmful or fatal if
absorbed through the skin. Only two, however, cautioned
against dumping them directly into lakes, streams, or ponds.
Some of the products containing 2,t,5-T listed no such
precautions; yet the compound is now expressely banned in
waterways.
Scale and corrosion inhibitors and biocides require the
addition of acid or alkali to makeup water to keep the pH at
262
-------
an optimum level, usually a range from 5.5 to 7.5. Silt
controls polymers may be used if makeup is raw water from a
nearby lake or river. Lignin-tannin dispersives such as 1
to 50 ppm sodium lignosulfonate may be employed.
Antifoulants such as 0.1 to 5 ppm of acrylamids,
polyacrylate, polyethyleneimine, or other high molecular
synethic organic polyelectrolytes may also be used.lOSee
Wood deterioration includes three types of attack; chemical,
biological, and physical. Chemical deterioration, which
removes the lignin, is especially severe with the combined
presence of high chlorine residual and high alkalinity
(chlorine should be less than 1 ppm). This deterioration
can be checked by maintaining the pH below 8.0. Biological
attack on wood is caused by cellulolytic fungi. The
application of chlorinated phenolic compounds in a
controlled foam form has been found to be highly effective
in promoting prolonged protection of cooling tower wood.
Physical attack on wood is caused by high-temperature
waters, high solids concentration, and freezing and thawing
conditions.
Oxidizing biocides effectively kill the organisms, but their
activity is short-lived. (Requires frequent or continuous
feeding). Chemicals which are used include chlorine and
calcium and sodium hydrochlorites. One method is to dose to
a free available chlorine concentration of 0.3 - 0.6 ppm for
a period of four hours daily. The chlorinated cyanurates
and inocyanurates and other chlorinated organic materials
are also used to introduce chlorine to water. Persulfate
compounds, which are odorless, are also often used
(potassium hydrogen persulfate). Ozone, another oxidizing
biocide, is undergoing experiment for use in various
systems. It is a very powerful oxidizing agent and is twice
as potent as chlorine for destroying bacteria and organic
matter. It also oxidizes undesirable metals such as iron
and manganese. Several nonoxidizing biocides are also being
used. Some of these compounds include: chlorinated phenolic
compounds - chlorinated and phenylated phenols and their
sodium or potassium salts; organotin - complex amine
combinations; surface-active agents such as quartenary
ammonium groups; organo-sulphur compounds such as
dithocarbamate salts and the thiuram mono - and disulfides;
rosin amine salts formed by reaction with carboxylic acids
and acidic phenols such as the salts of acetic acid and
pentachlorophenol; copper salts such as copper sulfate;
thiocyanates such as methylene thiocyanates and
bisthiocyanate; and acrolein which is highly flammable and
may be toxic to warm-blooded animals.
263
-------
In cooling water systems, two types of corrosion inhibitors
can be used - anodic and cathodic. Chromates,
orthophosphates and nitrite - based products are examples of
anodic corrosion inhibitors, polyphosphate , silicate, and
metal salts which form sparingly soluble hydroxides, oxides
and carbonates (such as zinc) act as cathodic inhibitors.
Chromates and other heavy metals may be harmful to aquatic
organisms. Phosphates can serve as a nutrient to aquatic
life. Inorganic, nonchromate corrosion inhibitors consist
of various combinations of poly phosphates, silicates,
borates, f errocyanides, nitrates, and metal ions such as
zinc and copper (straight polyphosphate, zinc
polyphosphate, and ferro cyanide - polyphosphate) . Work is
being done to develop nonpolluting corrosion inhibiting
components. Two such compounds are sodium and
mercaptobenzothiazole and derivatives of organo-phosphorus.
Dearborn Chemical Division of W. R. Grace and Company has
developed a nonchromate, nonphosphate corrosion inhibitor.
The synthetic-organic corrosion inhibitor which is
hydroly tic ally stable and possibly nontoxic. This compound
is designed to reduce scaling and fouling on heat transfer
surfaces. It is not as effective as zinc and chromates, but
is at least as effective as other comparative nonchromate
and zinc polyphosphate compounds.
A film-forming sulfophosphated organic corrosion inhibitor
is put out by the Tretolite Division of Petrolite
Corporation. Tretolite states that it is effective in both
fresh and high brine waters and is less toxic to fish and
other aquatic life than metal salts such as chromate. Its
toxicity compares to that of methanol, gasoline, and xylene.
It is said that the inhibitor also performs well in the
presence of H2S or
Scale deposits are prevented by controlling the hardness and
alkalinity of the water system. This is normally done by
feeding an acid to the water to neutralize the bicarbonate
alkalinity. An acid which is widely used is sulfuric acid.
Most cooling tower systems are controlled in the pH range of
six to seven. This range depends on the balance between
corrosion inhibition and deposit control. Organic phosphate
compounds such as aminimethylenephosphonate are used in
concentrations up to 3 ppm. Phosphonates and
polyelect roli tes are used as deposit-control agents. A
possible arrangement for pH control is shown in Figure A-
VII-13.
264
-------
ro
en
in
'^J~
RIVER
WATER
TURBINE
\
CONDENSER
COOLING TOWER
COOLING
WATER
--' PUMP
SLOWDOWN
A ACID OR \
LKALI TANK^/
• \JA
SOLUTION FEEDER
LEGEND:
AC-1: PH SENSOR & TRANSMITTER
E/P-1: ELECTROPNEUMATIC TRANSDUCER
FC-1: FLOW CONTROL VALVE
: FLOW PATH
: CONTROL SIGNAL (ELECTRICAL)
// // : CONTROL SIGNAL (PNEUMATIC)
FIGURE A-VII-13RECIRCULATING CONDENSER COOLING SYSTEM pH CONTROL OF SLOWDOWN
-------
The following corrosion and scale inhibitary chemicals may
be employed at the concentrations given.108ee
1. Chromate plus zinc 5 to 30 mg/1 CrOU
1 to 15 mg/1 Zn
2. Chromate plus zinc plus phosphate 5 to 30 mg/1 CrOU
1 to 15 mg/1 Zn
1 to 5 mg/1 PCW
(inorganic)
1 to 5 mg/1 (organic)
3. Zinc plus inorganic phosphate 10 to 30 mg/1 PO4
2 to 10 mg/1 Zn
4. Zinc plus organic phosphate 1 to 10 mg/1 Zn
3 to 15 mg/1 POU
(organic)
5. Organic phosphate scale inhibitor 1 to 18 mg/1 POU
(organic)
6. Specific copper corrosion inhibitors 1 to 5 mg/1 sodium
mercaptobenzothiazole
or benzotriazole
Consider the problem of trying to maintain condenser
cleanliness in the situation where the discharge is
permitted of the mildly concentrated and untreated tower
system blowdown to a receiving stream but the plant is not
permitted to discharge any inhibiting chemicals that might
be used normally for scale or corrosion control. Such
inhibitors might include individual or combined compounds of
zinc, chromate, hexametaphosphate, phosphonate, polyol
esters, etc. In essence, the tower system would have no
chemical conditioning except for shock application of a
biocide to control slime and algae and the use of an acid to
adjust alkalinity.
This method of minimum chemical treatment involves
controlling the stability index of the system water, by acid
feed, to a point where it is in a slightly scaling condition
plus shock chlorination. The objectives in operation is to
produce a water with a slight scaling tendency thereby
eliminating the basic requirement of a corrosion inhibitor.
Nor is the scaling tendency to be viewed with alarm if the
tower system is equipped with on-line condenser tube
cleaning equipment such as that supplied by Amertap or
M.A.N. Mild descaling also cart be accomplished by depression
of the pH in the tower system to 5.0 for about 8 hours once
weekly. Mild descaling does not increase the overall rate
of corrosion. In this regard the installation of corrosion
266
-------
probes in the system may be required for monitoring
corrosion rates either periodically or continuously.
Shock chlorination of the condenser cooling water for about
20 minutes daily, or one complete cycle, will be adequate to
control the growth of bacterial slimes and algae under the
usual conditions. If not, a second application some 8 hours
later would be indicated. The free available chlorine in
the water returning to the tower must be limited to 1.0 to
1.5 mg/1 in order not to delignify the wood components of
the tower. If the cooling tower is all wood the components
should have been specified for chemical pretreatment to
prevent fungal attack and to withstand any excess alkalinity
in the cooling water.
The manufacturers of on-line condenser cleaning equipment
suggest that chlorine is not needed when their equipment is
used; the tubes supposedly are kept free of bacterial
growth. Chlorine, or an equivalent biocide, however, is
certainly needed to prevent excessive growths on the tower
deck and tower fill. If the growths are allowed to
proliferage on the decks the distribution orifices may
become plugged and cause flooding. Excessive growths on the
fill decrease tower efficiency.
Tables A-VII-6 and A-VII-7 shows the average operational
values for a cooling tower system without any chemical
conditioning other than acid for the control of alkalinity;
and with complete chemical conditioning. The condenser is
provided with on-line mechanical cleaning equipment.
Chemical Cleaning of Condenser Tubes During Scheduled
Outages
Condensers are by far the largest heat exchanger in the
condensate-feedwater cycle. They contain from 5,000 to
50,000 tubes, 7/8 or lw O.D. by 20 to 60 feet long. Tube
materials may be stainless steel or brass alloys such as
admiralty brass, aluminum brass, aluminum bronze, arsenical
copper, 90/10 or 70/30 cupro-nickel. The tubes may be
contained in one housing or shell or because of size may be
arranged in from 2 to 6 shells for very large units. Each
shell may be considered a condenser in itself.
In function the condenser serves to re-liquefy the steam
which exhausts from the last row of blades of the turbine
and flows around the tubes. Cooling water flows through the
tubes extracting heat from the tube walls which interface
with the steam. The overall cleanliness of the tube
267
-------
Table A-VII-6
NO CHEMICAL CONDITIONING OF COOLING TOWER SYSTEM
EXCEPT FOR ALKALINITY CONTROL. BUT USING ON-LINE
MECHANICAL CLEANING CONDENSER TUBES 387
Untreated River Makeup to Tower Cooling Tower System
mg/l mg/l
Ca as CaC03
Mg as Ca(X>3
HC03 as CaCOa
ci as cr
804 as SO 4
SIO2 as Si02
pH
100
64
148
4
10
6
7.5
Ca as CaCC>3
Mg as CaCOs
HCOs as CaC03
CI as CI'
804 as SO4
Si02 as Si02
PH
500
320
136
18
645
27
8.0
Table A-VII-7
COMPLETE CHEMICAL CONDITIONING OF COOLING TOWER
SYSTEM AT "ZERO" DISCHARGE WITH SIDESTREAM TREAT-
MENT OF TOWER WATER AND ON-LINE MECHANICAL CLEANING
CONDENSER TUBES 387
Untreated River Makeup to Tower Cooling Tower System
mg/l mg/l
Ca as Ca(X>3 230 Ca as CaCOs 260
MgasCaCOs 172 Mg as CaCOs 175
HCOsasCaCOs 263 HC03 as CaCOs 300
Na as Na 24 Na as Na 7,740
CI as CI- 12 CI as CT 1.030
SO4asSO4 174 80435804 14.800
SiO2 as SK>2 20 SK)2 as S£>2 20
pH 7.5 Organic P04 25
pH 8.5
268
-------
surfaces is critically important to the efficiency of the
condenser, to the degree of vacuum placed in the turbine,
and hence to the efficiency of the plant.
Chemical cleaning of condenser tubes is usually performed
during a scheduled outage of the unit, unless the fouling
has reached a magnitude that warrants a separate outage
beforehand. The chemical cleaning is relatively simple,
using either the acid foaming technique or the soak method.
The condenser can be cleaned within 12 hours if all
preliminary operations have been organized. Of the two
methods, soaking has proved to be more thorough than
foaming.
The foaming method consists of a foam generator, with a
mixing tank to produce an acid foam that is then pumped to
specified sections of the water box. The foamed mixture
flows by gravity through the condenser tubes and then to
waste. Since there is no pressure involved, the top rows of
tubes, or a condenser tube that is partially blocked, will
receive hardly any foam and remain uncleaned.. It is
important before cleaning that all of the tubes should be
inspected and any potential blockage removed. It is not
uncommon to find numerous tubes partially blocked with
pieces of wood, particularly after icing conditions cause
damage to tower fill. Wind blown grass and similar debris
will also cause blockage. The efficiency of foam cleaning
in a relatively short contact time is attributed to the
strength of acid used, in this case about 15 percent
compared to the usual 5 to 7 percent acid in soaking.
Either inhibited sulfuric acid or mixed organic acids may be
used when foaming austenitic stainless steel tubes. At the
strength of 15 percent it would not be prudent to use
hydrochloric in contact with this steel. Neutralization
with an alkali is not needed following the acid foam or soak
cleaning. The usual practice is to start the circulating
pumps and flush the condenser for about 30 minutes to remove
any residual acid. Then, the water boxes can be reopened
for inspection.
Chemical cleaning by the soak method is merely filling the
water boxes to the top rows of condenser tubes with
inhibited acid plus 0.5 percent ammonium bifluoride at
ambient temperature. The acid strenght is 5.0 to 7.5
percent. Circulation is used when practical by repumping
the acid solution from the condenser to the acid delivery
tank truck and then back to the condenser. Although the
acid recirculation rate is relatively low, the reaction rate
is increased by circulating fresh acid over the deposition.
The choice of acid for the soak method is generally
269
-------
hydrochloric because of its rapid reaction with carbonate
scale without forming an insoluble by-product. Other
deposits also are more easily solubilized. The addition of
ammonium bifluoride intensifies the solubility of silicate
and iron deposition. Sulfuric acid also will react with
calcium carbonate deposition, but produces an insoluble
calcium sulfate precipitate that may settle out and adhere
to the tubes in quiescent soaking. Therefore, the choice of
acid is usually hydrochloric even if the condenser tube
material is austenitic stainless steel. Corrosion tests
show essentially the same rates for stainless with sulfuric
or hydrochloric under soaking conditions; neither stress nor
crevice corrosion has occured with hydrochloric as used at
ambient temperature.
Mechanical Cleaning of Condenser Tubes
On-Line Mechanical Cleaning
Equipment for on-line mechanical cleaning of condenser tubes
is manufactured primarily by the Amertap Corporation and by
the M.A.N. Corporation of West Germany. By far, most of the
installations at electric generating plants in the United
States have been supplied by Amertap. In principle, each of
the two systems has the same objectives; that is, to
maintain condenser tube cleanliness continuously while in
operation by mechanical means instead of chemical.
The basic principle of the Amertap system is to circulate
oversize sponge rubber balls through the condenser tubes
with the cooling water. These balls, after the original
charge, are injected into the inlet pipe, collected at the
discharge piping in a basket arrangement and then repumped
continually to the inlet. The number of balls in the system
is approximately 10 percent of the number of tubes in the
condenser. Amertap estimates that each tube receives a ball
on the average of every 5 minutes with a normal circulation
time per ball of 20 to 30 seconds. However, any tube that
becomes partially blocked at the entrance or within its
length will not become unblocked by the ball. The
effectiveness of the sponge balls is for removing soft
chemical precipitates or bacterial slimes before then can
become adherent. Because the balls are porous a certain
amount of water flows through the balls and loosens the
accumulated deposits retained on the balls. The balls are
also furnished with an abrasive band, to be used only where
older deposition needs to be removed by the scouring action
of the abrasive. A schematic arrangement of the Amertap
system is shown is Figure A-VII-14.
270
-------
OUTLET WATER
BOX
COOLING
WATER
OUTLET
STRAINER
SECTION
1
TURBINE EXHAUST
STEAH
CONDENSER
DOME
HATCH FOR INSERTING
OR REMOVING BALLS
BALL COLLECTING
BASKET
BASKET SHUTOFF
FLAP ""
//pxE
BALL
COLLECTOR
,INLET MATER
BOX
A. 1
•
1
1
1
1
* 1
1
I
•
r
•^
^
SPONGE RUBBER
BALLS (TYPICAL)
COOLING WATER
INLET
Figure A-VII-14
SCHEMATIC ARRANGEMENT AMERTAP TUBE CLEANING SYSTEM
387
-------
The M.A.N. system for on-line mechanical cleaning uses a
brush device about 50 mm long sized to pass through the
condenser tubes intermittently. The M.A.N. system has to be
incorporated in the original design of a condenser in order
to provide additional tube length for attachment of a
plastic cage on each end of each tube to hold the brush
device. The plastic cage length is about 75 mm. To attach
the plastic cage to the tube ends, the tubes have to extend
10 mm beyond the tube sheet. Therefore, inlet tube ends
have to be straight instead of flared as would be the usual
practice to avoid inlet end erosion. The tube sheets do not
have to be machined for flaring with the M.A.N. system.
Provisions for reversing the flow of condenser cooling water
have to be incorporated in the original design of the
auxiliary equipment. To clean the tubes the cooling water
flow is reversed, which forces the brushes through the tubes
to the plastic cage at the opposite end. Then the cooling
water flow is returned to the normal direction, the brushes
would be forced to their normal resting position in the
cages at the outlet ends of the tubes. Recycling can be set
up automatically for whatever frequency of backwash is
desired. Twice daily is normal. The schematic arrangement
of the reverse flow piping for the M.A.N. system is shown in
Figure A-VII-15.
A current Edison Electric Institute survey conducted among
member companies comparing chlorination versus mechanical
cleaning of condenser tubes may be indicative of the degree
to which mechanical devices for maintaining tube cleanliness
have been successful and the degree to which the
supplemental use of chlorine is required. As of May 24,
1974, fourteen (14) respondents had supplied answers
covering two types of in-service mechanical cleaning
installations on the condenser cooling water systems for 54
powerplant units.
1. Three of the reported units have had the M.A.N.
system, which is the system that uses bristle
brushes; and the other 51 units had or have the
Amertap System, which is the system that uses
sponge balls.
2. None of the three M.A.N. systems is still in
service. One of these systems tended to become
fouled by leaves and twigs - and even a few fish.
On another, severe grooving of tubes was found.
3. Of the 51 Amertap units reported, 46 units are
still in service.
272
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NORMAL FLOW PIPING
BACKWASH PI OW PIPING
ro
«vi
CO
o OPEN
c CLOSED
SECTION OF
CONDENSER BEING
BACKWASHED
J
/<
J
t
\
J
'o /
< c
1
L
( c
(
>
( L.
i
s
1
J
^
< c
i
L
^ 0
— 1
J
/<
1
J
^ c >
1 (
p
L
'c
'
J
/
1
J
^
1
^ o
1
L
^ 0
«
''I-
1
^
1
J
/
1
( 0
•
1
L
^ 0
'— 1
J
>
1
^
\
< c
'
1
1
Figure A-VII-15 Reverse Plow Piping 387
-------
4. Of the 46 Amertap units now in service 25 also use
chlorination, and 21 do not use chlorine.
5. For the 21 Amertap Systems in service without
chlorination the cooling water systems are:
Acid mine-water, once-through, 9 systems
Closed cycle cooling towers or ponds, 6 systems
Brackish water once-through, 2 systems
Sea water once-through, 2 systems
Fresh water once-through, 2 systems
6. Of the 51 Amertap units reported by respondents, 7
reported that they thought good heat transfer could
be maintained without chlorination and 6 reported
they think chlorination is necessary.
7. For the 46 Amertap units now in service, it was
reported that the primary purpose of the mechnical
cleaning system was for the control of:
a. sediment, sludge or scale, for 41 units
b. slime for 5 units
8. Of the five (5) systems that are reported to be in
service for the purpose cf controlling slime, only one
(1) uses once-through cooling with fresh water, and the
other four (4) use once-through cooling with brackish
water.
9. Of these five (5) systems that are reported to be in
service for the purpose of controlling slime, two (2)
also use chlorination, and one of the others has had
only limited operation.
Mechanical Cleaning During Scheduled Outages
Manual mechanical cleaning of condenser tubes is
accomplished with short bristle brushes, rubber balls, or
scraper devices shot through the tubes individually by water
pressure or combined with air pressure. High pressure
water lancing alone has been used. The procees is
laborious, time-comsuming, extremely monotonous, and often
uneconomical.
If the deposition in the tubes is loose, or in thin curls,
after the tubes become dry, the brushes or balls will do a
fairly satisfactory job. Brushes or balls are used by
plants that need to clean tubes at repeated intervals to
maintain cleanliness. When the desposition is adherent the
274
-------
short metal scraper-type devices will be more effective;
they are shot through the tubes with water and air pressure.
The overall shooting time will be longer with scrapers than
with brushes. Regardless of the device used it is a good
idea to keep an inventory of the number before and after
cleaning. The mechanical cleaning time will range from 50
tubes to 300 tubes per man-hour depending on whether
scrapers or brushes are used and on the attitude of the
crew.
As a rule, mechanical cleaning is practiced at small
generating plants where the labor may be readily available
and economical. It may also be a plant where quality
control for the cooling system is continuously disregarded
by the operating personnel, requiring that the condenser
tubes be mechanically cleaned fairly regularly. In this
case, plant labor would be used instead of using outside
services for chemical cleaning which would require
management appropriation of capital.
Economics of Condenser Cleanliness
Comparative capital costs of the Amertap system and the
M.A.N. system are shown in Table A-VII-8 As noted on the
table, the costs shown are additional costs to those that
would be required for conventional chemical conditioning.
The costs are for a 675 Mw generating unit to be installed
in 1979 which will be equipped with an open recirculating
cooling system using mechanical draft cooling towers.
Table A-VII-9 shows comparative costs of operation and total
annual costs for the same 675 Mw generating unit. The
demand and energy costs reflect increased circulating water
pumping costs for the mechanical systems due to friction of
the plastic cages of the M.A.N. system, and of the strainers
of the Amertap system. For the Amertap system they also
reflect the cost of operating the small pumps that
recirculate the balls. The annual fixed charge rate is
assumed to be 15.0 percent.
As tube cleanliness decreases, the condenser pressure
increases which causes the turbine heat rate to increase and
generating cpability to decrease. Figure A-VII-16 shows
tube cleanliness factor plotted against the annual cost of
increased fuel and reduced capability for the same 675 Mw
unit. The unit is assumed to operate at an annual capacity
factor of 86.5 percent, fuel is evaluated at a price of 45
cents per million Btu, and generating capacity is evaluated
at an annual cost of $20.80 per kw. The costs plotted in
Figure A-VII-16 are additional costs as the cleanliness
275
-------
Taole A-VII-8
COMPARATIVE CAPITAL COSTS* OF CONDENSER
CLEANING SYSTEMS 387
Table A-VII-9
COMPARATIVE ANNUAL COSTS* 387
ro
^i
en
M.A.N System, Baskets and Brushes
Amertap System
Tubing
Tube Sheet Machining
Backwash Piping and Valves
Miscellaneous Piping and Valves
Controls
Mechanical Construction
Electrical Construction
General Construction
Subtotal
Indirect Costs at 16 Percent
Comparative Capital Costs*
Amertap
System
$
-
160,000
Base
Base
Base
10,000
35,000
34,000
22,000
8.000
269,000
43.000
312,000
M.A.N.
System
$
72,000
1,000
(37,000)
107,000
Base
6,000
12,000
3,000
Base
164,000
26,000
190,000
Annual Costs of Operation*
Manual Brush Cleaning of Tubes
Chemicals
M.A.N. System Brushes
Amertap Balls
Demand and Energy Costs
Comparative Costs of Operation
Total Annual Costs*
Fixed Charges
Costs of Operation
Comparative Total Annual Costs
Differential Total Annual Costs
Conventional
Chemical
Treatment
$
5,000
23,000
-
-
Base
28,000
Base
28,000
28,000
Base
Amertap
System
$
-
20,000
-
19,000
6,500
45,500
46,800
45,500
92,300
64,300
M.A.N.
System
$
-
20,000
16,000
-
12,100
48,100
28,500
48.100
76,600
48,600
'Costs shown are increases or (decreases) from capital costs of a conventional 'Costs are for a 675 MW generating unit to be installed in 1979, operating with an open
chemical cleaning system. Costs are for a 675 MW generating unit to be recirculating cooling system using mechanical draft cooling towers. Annual fixed charge
installed in 1979, operating with an open recirculating cooling system using rate is 15.0 percent.
mechanical draft cooling towers.
-------
GENERATING UNIT - 675 HW
FUEL COST - $ 0.45 PER I06 BTU
CAPACITY COST - $21.80/KW/YEAR
ANNUAL CAPACITY FACTOR -86.5*
70 80
CLEANLINESS FACTOR IN PERCENT
Figure A-VII-16
TUBE CLEANLINESS VERSUS COST OF REDUCED
GENERATING EFFICIENCY 387
277
-------
factor decreases from 100 percent (which reflects the
cleanliness of new clean tubes).
Costs of operation shown in Table A-VII-9 are based on all
cleaning systems maintaining the same degree of cleanliness.
It is expected that the Amertap system can maintain tube
cleanliness at about 95 percent, if placed in service when
the condenser tubes are new, and that the M.A.N. system can
maintain tube cleanliness at about 90 percent. The reason
that the M.A.N. system would not be able to maintain the
cleanliness level as high as the Amertap system is that the
M.A.N. system operates intermittently, while the Amertap
system is a continuous cleaning system.
The comparative annual costs shown in Table A-VII-9 and on
Figure A-VII-16 can be used to determine whether or not a
mechanical cleaning system such as the M.A.N. system or the
Amertap system can be economically justified. For the 675
Mw unit, neither a M.A.N. system with a cleanliness factor
of 90 percent nor an Amertap system with a cleanilness of 95
percent could be justified unless the cleanliness factor
with conventional chemical conditioning is less than 80
percent. This conclusion applies only to the case studied
since it is dependent on such parameters as generator size,
capacity factor, and the fuel cost. However, it serves as a
general indication of the amount of improvement in
cleanliness factor that must be achieved in order to justify
an on-line mechanial cleaning system.
Design for Corrosion Protection
The use of corrosion resistant materials is standard
practice in the electric utility industry. Unlike most
other industries, power plants are -built for service lives
of thirty years or more. Thus, corrosion prevention is a
necessary consideration in power plant cooling systems.
Although corrosion resistant materials are more costly,
their use is justified by less maintenance, improved heat
transfer, and reduced water treatment costs, corrosion and
scale inhibiting chemical usage can be minimized in large
cooling water systems through the proper selection of
construction materials and protective coatings. In fact,
there are a few power plants where the existence of
corrosion resistant materials plus the use of on-line
condenser tube cleaning equipment has eliminated the need
for chlorine and other biocides, thus allowing operation
without any chemical treatment.
In addition, corrosion resistant materials generally help
prevent water pollution. By minimizing corrosion and scale
278
-------
inhibiting chemical usage, the anrounts of harmful materials
such as zinc and chromate discharged into lakes and streams
are reduced. Corrosion products in blowdown streams can
also be maintained at low levels.
Corrosion Resistant Materials in Condensers
The use of corrosion resistant materials in steam condenser
tubes is standard practice. A wide variety of materials are
in use or are available including admiralty, 304 and 316
stainless steel and copper-nickel alloys.
Cold water boxes are normally made of carbon steel.
Occasionally, phenolic or epoxy coatings are applied.
Corrosion Resistant Materials in Cooling Towers
Although redwood or Douglas fir are still the normal
structural elements used in mechanical draft cooling towers,
concrete towers are now being built. All the hyperbolic
natural draft cooling towers built in the United States to
date have been of concrete construction. Concrete towers
should last longer, are structurally superior to wood and
can save utility companies on fire insurance preminums. A
cooling tower manufacturing recently mentioned that a client
could save $100,000/year on insurance premiums by using
concrete induced-draft cooling towers instead of wood.
Type 2 concrete is normally used for cooling towers, but
where waters containing 1,000 ppm or more of sulfate ion
(SO£—) are encountered such as in the West and Southwest,
Type 5 must be specified.
The use of wood in the internals of large cooling towers is
also diminishing. Plastics such as polyvinyl chloride (PVC)
are now being used for splash-type tower fill, drift
eliminators, and fill hangers. Film-type fill is normally
made from asbestos concrete board (ACB). Air louvers and
some drift eliminators are also made of ACB. When ACB is
used in a tower, it is important to maintain cooling system
pH at more than 6.0 to avoid deterioration.
Hardware used in cooling tower construction is normally
stainless steel, although hot dipped galvanized steel, naval
brass, copper alloys and silicon-bronze can also be used.
Stacks in mechanical draft towers are generally made from
fiberglass reinforced plastic (FRP).
279
-------
Redwood stave piping is being used less frequently since
redwood is becoming more scarce. Risers and headers, which
are large pipes located at the cooling towers, are made of
concrete or redwood staves, and less frequently of vinyl
painted carbon steel. Where brackish or salt water is used
for tower makeup, 316 stainless steel and coated carbon
steel are commonly specified for piping systems.
Concrete and stainless steel cost 2-3 times more than carbon
steel. Cost differences between stainless steel and
prestressed reinforced concrete will depend on differences
in material grade, freight charges and installation costs.
Most power companies do not make detailed cost comparisons
between piping materials, but one Ohio utility determined
that for a new power plant, concrete recirculation lines
would cost about $300,000 more than coated carbon steel.
Spray cooling apparatus is normally constructed with 301 or
316 stainless steel. Cathodic protection devices have been
installed en some floating spray aerator-coolers.
Resistant Pretreatments and Coatings
Redwood and Douglas fir construction materials used in
mechanical draft cooling towers are always pressure treated
with either acid copper chromate or chromated copper
arsenate to prevent fungus attack. Tower suppliers have
indicated that this pretreatment is effective and that
leaching of the treatment chemical does not occur after the
initial few weeks of tower operation.
Since chemical pretreatment of cooling tower lumber is a
necessary process, its costs has not been separated from the
total purchased cost of tower systems.
Carbon steel pipe and hardware are sometimes coated with
epoxy, phenolic, or vinyl paints to reduce corrosion rates.
Steel piping is occassionally given a coal tar bitumastic
coating on the inside to prevent corrosion. Bitumastic
coatings may also be applied to the outside of pipes to
prevent leakage and corrosions. These coatings normally
cost $20 - $UO/ft of pipe length.
Saltwater Cooling Towers
Reference 390, a state of the art report on saltwater
cooling towers, addresses, as a major topic, design
consideration related to the corrosive action of salt water
280
-------
on cooling system equipment. The incremental deterioration
due to corrosion effects of salt water being used in a
cooling tower is of the same nature as those expected
elsewhere in the plant where this water is being circulated.
With well-designed and constructed components where
coatings, lubricants and when possible inert materials are
used, most of the problem associated with the use of salt
water can be reduced to make the average life the components
equivalent to those exposed to fresh water.
Table A-VII-10 gives recommended construction materials for
cooling towers operating with salt water. Chemicals added
to reduce chemical and biological attack in saltwater
cooling towers include the following: sulfuric acid,
chromate, zinc compounds, organic non-chromates including
polyphosphates, silicates, ferrocyanides, nitrates, and
metal ions (e.g., straight polyphosphates, zinc-
polyphosphates, ferrocyanide-polyphosphates, zinc-
ferrocyanide-polyphosphates), organics (starch derivations,
lignosulfonates, tannins, glucosates, glyceride derivations
and many proprietary formulations), chlorine and bromine.
Reference 390 lists 20 saltwater cooling towers in operation
as of February, 1973, and <* proposed towers. Of the 15
towers associated with electric generating station 10 are
mechanical draft, 4 are natural draft, and 2 are wet-dry
mechanical draft. Circulating water flow rates for the 15
towers range from 4,900 gpm to 578,000 gpm per tower.
Cooling Tower Blowdown Treatment
A system for the chemical treatment of residual chlorine in
cooling tower blowdown is currently being installed in a
nuclear plant employing cooling towers, which is currently
under construction. Whenever residual chlorine is present
in the combined wastes flowing from the discharge channel,
sodium bisulfite will be added in the last chamber of the
dilution structure in sufficient quantity to react
completely with the chlorine. The addition of bisulfite
will be controlled automatically, using a chlorine analyzer
in the discharge stream with a proposed sensitivity of about
0.01 ppm residual chlorine.
Specific methods exist for treating other individual
contaminants that may occur in fclowdown wastes. Table A-
VII-11 lists typical levels of concentration of corrosion
inhibitors used in recirculating cooling water systems, with
these same concentrations existing in the blowdown from
these systems.
281
-------
Table A-VII-10
RECOMMENDED CONSTRUCTION MATERIALS FOR COOLING TOWERS
OPERATING WITH SALT WATER
Reference 390
Component
Asbestos
Cement
Plastics
(Including
Coating reinforced
Concrete Paint or fiberglass
No. 2 or 5* Epoxy and PVC)
Stainless
Steel
Silicon
Bronze
Pressure-
Treated
Wood
Structure
framework x
Water distri-
bution system x
Fill x
Drift eliminators x
Louvers x
Fan stack
Fans
Gear housing
Drive shaft
Coupling
Motor and gear
support
Bolting for
mechanical
support
Joint connectors
Anchor castings
Bolts, nuts,
washers & nails
x
X
X
X
X
X**
X**
X
X
X
X
X
X
X
* Used by cooling tower manufacturers
**Uaed successfully when tower is in continuous operation.
282
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Table A-VII-11
Waste Disposal Characteristics
of Typical Cooling Tower Inhibitor Systems
Inhibitor
System
Organic only
Concentration in
recirculating
water
Chromate only
Zinc
Chromate
Chromate
Phosphate
Zinc
Phosphate
Zinc
Phosphate
Phosphate
Organic
200-500
8-35
17-65
10-15
30-45
8-35
15-60
8-35
15-60
15-60
3-10
as
as
as
as
as
as
as
as
as
as
as
Cr04
Zn
Cr04
Cr04
P°4
.Zn
P04
Zn
P°4
P°4
organic
100-200 as organic
10 est. as BOD
100 est. as COD
50 est. as CCl
extract
5 est. as MBAS
Organic
Biocide
30 as chl'or9phenol
5 as sulfone
1 as thiocyanate
283
-------
There are four methods which can be used to treat the
blowdown wastes containing chromate as the only inhibitor.
One basic method that has worked in the past and has been
proven effective is called the reduction method. This
process consists of adjusting the pH of the blowdown water
containing the chromium to approximately 2 with the addition
of acid, usually sulfuric acid, and then the addition of a
reducing agent, either sulfur dioxide or sodium
metabisulfite, which releases sulfur dioxide into the
solution to reduce the hexavalent chromium to the trivalent
state. Then the addition of caustic or lime to raise the pH
to approximately 8.5 and form insoluble chromic hydroxide
precipitate. A treatment system using the reduction method
is shown in Figure A-VII-17. The treated water from this
system is anticipated to contain less than 0.05 ppm of
chromium. ion exchange methods have also been reported for
chromate recovery from blowdown wastes.*33-436 These
methods require a prefiltration step to remove suspended
solids from the blowdown wastes and also require a close
control on the inlet pH and salt concentration for maximum
recovery. The advantage of the ion exchange methods is that
the recovered chromate can be reused. Another method for
chromate removal is the ANDCO proprietary process. This
patented process is an electrochemical method (Figure A-VTI-
18) and is claimed to reduce chromate concentration to less
than 0.05 ppm. Finally, a vapor-compression evaporation
system is also commercially available to recover and reuse
water from blowdown wastes. The concentrated brine from
this system can be sent to a spray-dryer for the final salt
recovery.
All the methods mentioned above are also applicable for zinc
removal from blowdown wastes. Thus it is possible to
coprecipitate zinc as an insoluble hydroxide by chemical
precipitation.
Similarly, it is possible to use an acid regenerated zinc
cation exchange process so effect a reduction in volume so
that the concentrated solution can be "hauled away or
rendered harmless by precipitation11*3*. The ANDCO process
is also claimed to reduce zinc from blowdown wastes.
Phosphate can also be removed by chemical precipitation.
Addition of alum is required for higher efficiency. An
adsorption process that apparently is applicable to crudely
filtered or undiltered blowdown containing phosphate, only,
has been reported in the literature.
Depending upon the make-up water quality and the plant
specifics, it is possible to investigate various.
284
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r\j
CD
01
BX-OWDOVS/tO PUMPS
R.EDUCT\OK1
TA.VJK.
A.CID WMX.
K>
VACUUVA FILTER,
COWV.
II
Figure A-VII-17 Cooling Tower Slowdown Chromate Reduction System
457
-------
POWER
SOURCE
-©
© © ©
SLUDGE
AM AMMETER
VM VOLTMETER
Fl FLOW INDICATOR
TI TEMPERATURE INDICATOR
PI PRESSURE INDICATOR
MTENTJ .SSIM .NO «.*.!» «>
TYPICAL PROCESS FLOW DIAGRAM
ANDCO CHROMATE REMOVAL SYSTEM
cinclco<&
andco environmental processes, inc.
buffalo, new york
Made under U.S. and foreign patents and patents pending.
Figure A-VII-18
Typical Process Flow Diagram
Chromate Removal System 453
286
-------
alternatives methods to select the most practical and
economic method to minimize blowdown flow. The Southern
California Edison company has achieved a 31X reduction in
the cooling tower blowdown at the Etiwanda generating
station by modifying the treatment technique.4*0 Similarly,
the company has included facilities in a new plant design
for cold lime-soda as makeup softening to achieve zero
blowdown operation (Figure A-VII-19). This will reduce
total pondage requirements from 240 acres to 3U acres.
(Pondage is required for softening sludge disposal, other
plant liquid wastes and for periods of softening equipment
outages when blowdown from cooling towers will be
necessary) .
Reference UU5 analyzed four basic approaches for the
concentration of cooling tower blowdown to a dry or almost
dry, solid as follows:
Evaporation, in a conventional multi-effect evaporator-
crystallizer, to a slurry from which mother liquor is
finally removed by a centrifuge, yielding damp crystals.
Preliminary distillation in a multi-stage flash (MSF)
plant, followed by an evaporator-crystallizer somewhat
smaller than in the first approach.
Passage of the tower blowdown through a cation exhanger,
plus reverse osmosis (R.O.), followed by an evaporator-
crystallizer of larger size than in the second approach.
Identical with the third approach but with an MSF plant
after the R.O. unit, resulting in a small evaporator-
crystallizer of only one effect.
In each of the cases involving MSF, two types of MSF plants
were studied: (1) a high-capital cost plant, very efficient
in energy utilization, and (2) a less efficient but less
costly plant.
The various combinations of processes are shown in Figure A-
VII-20.
Water Treatment Wastes
Clarification, Softening and Filtration
The waste streams from these operations are sludges, whose
composition will vary depending on the raw water quality and
the method of treatment. Sludges from plain sedimentation
are essentially silty in character. If alum is used as a
287
-------
ro
oo
CO
C.O C.O »;,C%4l,fci
P P t P P P
cotL stuter
CLAeirLOlCULATOg.
TB tiona. 440
-------
ro
00
COOIINC TOWU t
IDENIICAl foil All CASES.
PRODUCES INSOLUBLE SOLIDS
(OR DISPOSAL
CONCENTIATION
IWOUTKHI • CITSTAUIZATIOR
TWO POSSIILE PROCESSES AVAILABLE.
witn sotws
TO ttsrosu
THREE POSSIBLE ALTERNATIVES. PLUS DIRECT
FEED TO EVAPORATOR • CRVSTALLIZER.
Figure A-VII-20 Possible Combinations of Concentration and Evaporation-
Crystallization Processes for Complete Treatment of
Cooling Tower Slowdown
-------
coagulant, the sludges will contain aluminum hydroxide
together with whatever organic or inorganic colloids have
been coagulated by the alum. Sludges from lime softening
contain primarily calcium and magnesium carbonates and
hydroxides. Sludges from filter backwash operations reflect
the processes that preceded the filter and differ only to
the extent that filter backwash is generally a periodic
operation, whereas sludges from setting basins are withdrawn
more or less continuously.
Sludges will generally contain between 0.5 and 5.0% of sus-
pended solids. Accepted treatment techniques in the water
and wastewater treatment industry consist of hydraulically
thickening these sludges to about 10 to 15% solids content.
Following thickening, the sludges can be further dewatered
by land disposal, centrification, filtration, or
incineration. Figure A-VII-21 shows three clarifier waste
systems. The supernatent from sludge thickening is
generally returned to the original solids separation unit.
Ion Exchange Wastes
Ion exchange resin beds must be regenerated periodically in
order to maintain their exchange capacity. For cation
resins, the most common regenerant is sulfuric acid. For
anion resins, the common regenerant is sodium hydroxide, al-
though ammonium hydroxide is used in some plants. Since
powerplant practice is to use excess amounts of regenerants,
the waste streams contain primarily sulfuric acid and sodium
hydroxide, together with the ions removed from the water
during the exhaustion cycle. The waste stream also includes
rinse water, that is water passed through the resin beds to
remove all traces of regenerant. Typical practice is to
regenerate ion exchange units whenever a specified
exhaustion has been reached while the units are in service.
Figure A-VII-22 shows a simplified flow system.
Waste regenerants and rinses from both the cation and anion
resins are normally collected in a neutralization tank and
the pH is then adjusted to within the range of 6.0 to 9.0 on
a batch basis by the addition of sulfuric acid or sodium
hydroxide as required. If any precipitates are formed after
neutralization, they are separated from the liquid by
settling or by filtration. Figure A-VII-23 shows a
neutralization pond.
The neutralized wastes are high in TDS and would require
further treatment before they could be used for other water
uses requiring low TDS water. However, they are suitable
for use as makeup for closed condenser cooling systems or
290
-------
CLEAR WATER OVERFLOW TO RECYCLE
RAW
WATER ,
CLARIFIER
WASH
'', *
FI.LTE'R
SYSTEM
n
WATER TO
PROCESS
"
SLUDGE
THICK-
ENER
SLUDGE
MECHANICAL
DEWATERING
OVERFLOW TO RECYCLE
RAW
WATER
CLARIFIER
WMj>n
I
i f
FILTER
SYSTEM
i
WATER T(
, PROCESS
SLUDGE DISCHARGE
MOIST SOLIDS
DISPOSAL
SLUDGE SETTLING
POND
OVERFLOW TO RECYCLE
RAW
WATER
CLARIFIER
WATER TO PROCESS
SLUDGE DISCHARGE
SLUDGE SETTLING
POND
MECHANICAL
SOLIDS REMOVAL
MECHANICAL SOLIDS
REMOVER
FIGURE A-VII-21CLARIFICATION WASTE TREATMENT PROCESSES
291
-------
AC ID ADJUSTMENT
CAUSTIC ADJUSTMENT
ION EXCHANGE WASTE
RECIRCULATE
DISCHARGE
NEUTRALIZATION
TANK
FIGURE A-VII-22 ION EXCHANGE WASTE TREATMENT PROCESS
292
-------
NEUTRALIZATION POND
Figure A-VII-23
293
-------
for such uses as ash sluicing or gas scrubbing, which do not
require high quality sources of supply. It may be desirable
for some uses in the powerplant to use ion exchange wastes
without neutralization. Closed cooling water systems
generally require some acid treatment to reduce the buildup
of alkalinity and air pollution control devices may require
an alkaline source of water. Ion exchange waste therefore
can often form an economical source of low grade acid or
caustic for other uses in the plant.
Substantial reductions in the volume of demineralizer wastes
can be achieved by the use of systems which substitute
reverse osmosis (RO) or electrodialysis combined with ion
exchange (IE) for systems using ion exchange alone. One
study shows that RO plus IE systems are less costly than IE
systems alone for total dissolved solids of 500 mg/1 as
CaCO.3 in the natural water available. The study is based on
100,000 gallons/day product capacity, no labor costs, and a
waste disposal cost of $5/1000 gallons.383 A 250. gpm product
capacity RO system has been recently installed at plant no.
5405. The available water total dissolved solids level is
750 mg/1 as CaCO.3. The system is designed to reduce the
dissolved solids level of pretreated river water to the
range for which the conventional resin-bed deionizers are
designed.38*
Evaporator Slowdown
In those plants still utilizing evaporators to produce
boiler feedwater makeup, the blcwdcwn from the evaporator
contains the salts of the original water supply in
concentrated form, but generally still in the solution
phase. Treatment is similar to the treatment of ion
exchange wastes by adjusting the pH to the neutral range of
6.0 to 9.0 with sulfuric acid or sodium hydroxide. If
precipitates are formed during neutralization, these are
removed by sedimentation and filtration.
As for ion exchange wastes, the most desirable method of
disposal is by reuse within the plant for applications not
requiring low TDS sources of supply.
Boiler or PWR steam Generator Slowdown
Since the quality of the boiler feedwater must be maintained
at very high levels of purity, the blcwdown from these units
is generally of high quality also. Boiler blowdown seldom
exceeds 100 mg/1 TDS and in most cases is as low as 20 mg/1.
For most plants, the quality of the boiler blowdown is
better than the quality of the raw water supply, whether it
294
-------
be from a natural source or a municipal water system. The
most desirable reuse of boiler blowdown is therefore as
makeup to the demineralization system.
Boiler blowdown is usually slightly alkaline, but because of
the low TDS level, the pH changes very readily.
Neutralization is generally not necessary for any of the
forms of reuse previously discussed in this section.
Periodic Wastes
Maintenance Cleaning Wastes
All heat transfer surfaces require periodic cleaning and the
usual method of cleaning boiler tube internals is to contact
these surfaces with solutions containing chemicals which
will dissolve any scale or other deposits on these surfaces.
Cleaning operations utilizing water include cleaning of the
fire side of boiler tubes, the air preheater, the cooling
water side of the condenser, and other miscellaneous heat
exchange equipment.
Modern steam generators do not permit inspection of areas
most likely to be in distress due to internal deposits, nor
can they be cleaned mechanically. Hence, the only practical
and generally accepted method of cleaning is by chemical
means.377
Boiler cleaning wastes pose special problems of disposal.
In order to be effective, the chemicals used for cleaning
must form soluble compounds with the scale and deposits on
the surfaces to be cleaned. Since scale is evidence of the
precipitation of an insoluble compound, the cleaning
solution must somehow change that solubility. The most
common means of accomplishing this objective is by extremes
of pH and strong oxidation potential. Where acids are
utilized as cleaning agent, there is the additional problem
of metals being dissolved into the cleaning solution.
Cleaning of heat transfer surfaces is a relatively
infrequent operation. The rate of deposition determines the
frequency. However, no.general agreement exists as to how
to determine when the point has been reached which calls for
cleaning. Most operators clean on a time schedule,
frequently established by trial and error. A majority of
those that do not clean on a time schedule remove tube
sections to gauge the amount of deposition.377 Boilers are
usually cleaned not more than once per year. Some of the
auxiliary units may be cleaned twice a year. Cleaning
operations are scheduled in advance in order to minimize the
295
-------
effect of the outage on the ability of the utility to meet
the demands for electric power.
Powerplants use essentially two types of cleaning solutions.
One type is an acid solution, usuallly hot hydrochloric
acid, used to clean the water side of the boiler tubes.
Hydrochloric acid cleaning is the cheapest and most
effective of the cleaning methods, but requires a larger
volume of water and takes longer than methods employing
other chemicals. Citric and phosphoric acids are also used,
primarily because they involve less outage time than
hydrochloric acid. Fireside cleaning of boilers and
cleaning of air preheaters is accomplished using alkaline
solutions, primarily containing soda ash.
Many utilities discharge their cleaning wastes with once-
through condenser cooling water, relying on the high
dilution ratio to minimize adverse effects of the discharge.
some utilities collect spent cleaning solutions in storage
basins or ash ponds and adjust the pH to the neutral range.
This causes the precipitation of some of the less soluble
compounds. The supernatent is discharged to the receiving
water and the solids are removed from the basin when this
becomes necessary. This technique is followed at plant no.
2525, which neutralizes its cleaning wastes before discharge
to a large settling pond. Plant no, 3601 also collects
cleaning wastes in a storage basin, applies lime or caustic
for neutralization, and then discharges the supernatent.
Current control and treatment technology for cleaning wastes
involves segregation of the waste, chemical treatment to
bring the pH into the neutral range, and separation of any
precipitates resulting from the neutralization.
Ash Handling Wastes
Most of the coal-fired plants use ash ponds. The data from
existing ash settling ponds was reviewed in Part A Section V
of this report. Of the plants for which useful data was
obtained, 28% have a negative or zero net discharge of total
suspended solids from the ash pond. For example. Federal
discharge permit applications for four of these stations are
given in Table A-VII-12. The data of one of these, plant
no. 0107, were verified by analyses of samples taken at the
site by EPA personnel. These data are summarized in Table
A-VII-13.
Sedimentation lagoons are commonly used at steam electric
powerplants, however, some plants employ configured tanks.
296
-------
Table A-VII-12
ASH POND PERFORMANCE
Source: Federal discharge permit applications
Plant No.
0104
0105
0106
0107
Concentration
Plant Intake
31
35
10
13
Total Suspended Solids, mg/1
Effluent
22
6
3
10
ro
10
-------
Table A-VII-13
SUMMARY OF E.P.A. DATA VERIFYING ASH POND PERFORMANCE, PLANT NO0 0107
Location
Intake
Inlet to Ash Pond
• from fly ash
• from bottom ash
Ash Pond Discharge
TSS
mg/1
22
76,440
4,110
14
pH
6.3
4.4
5.6
4.3
Aluminum*
mg/1
0.7
1100
56
6.0
Chromium*
mg/1
<0.04
1.3
0.1
< 0.04
Copper*
mg/1
< 0.04
501
0,3
0.1
Iron*
mg/1
0.5
2500
112
0.6
Mercury*
mg/1
<0.04
0.1
< 0.04
< 0.1
Zinc*
mg/1
<0.05
2.8
0.1
0.1
ro
10
oo
* Note: Total
-------
Tanks can be used where space limitations are important.
Tanks constructed for solids removal usually have built-in
facilities for continuous or intermittent sludge removal.
Designs based on maximum flow anticipated can provide the
best performance. Equalization can be provided to regulate
flow. The retention time required is related to the
particle characteristics. Plant No. 3905 employs a settling
basin 250,000 sq ft x 5 ft deep to provide a minimum
retention time of 24 hours for a waste stream of normally
1,800 gpm (3,300 gpm maximum). The ash pond is 600 acres in
area and will contain 6,700 acre ft. coal used at the plant
is pulverized to a size passing 80 percent through a 200
mesh screen. Approximately 80 percent of the ash is
discharged as fly ash. No cooling water is discharged to
the ash pond. The distance from inlet to outfall is about
one mile. The narrow water stream in the pond meanders
through the settled ash piles. The reported flow is about
500 gpm.
Nine out of the ten fossil-fueled steam electric powerpiants
operated by the Tennessee Valley Authority use ash ponds for
both fly ash and bottom ash, as well as for other plant
wastes such as from boiler cleaning. Effluent samples from
these ponds have been taken quarterly over a period of
several years. Analyses were performed and reported on
numerous parameters including total solids, total dissolved
solids and turbidity. Total suspended solids values can be
inferred as the difference between total solids and total
dissolved solids. A total of 1297 effluent suspended solids
sample values were tabulated for 10 plants in the system.
Of tnis total, 1,151 values were less than 100 mg/1, 4
samples were exactly 100 mg/1 and only 146 values exceeded
100 mg/1. On a percentage basis, values equal to, or less
than, 100 mg/1 represented approximately 89% of the total
number of values reported. The 951 value for the total of
the 1,297 samples was 165 mg/1. Table A-VII-14 summarizes
the data from the 10 plants in the system.
An analysis of the data indicates that the effluent
suspended solids values reported for Plant No. 2119 were
generally higher than the results reported for the other 9
powerplants in the system. of the total number of 146
samples which were equal to, or exceeded 100 mg/1, 106 were
reported by plant No. 2119. Consequently, it was decided to
analyze the data, omitting the results from this plant, to
determine the percentage of values exceeding 100 mg/1 and
the 95X value for the other 9 plants. This analysis yielded
299
-------
Table A-VII-14
ASH POND EFFLUENT, TOTAL
SUSPENDED i'OLID'J, MG/L
Plant No.
and Ash
Pond
2119-P1
4701
4704
4704
4703
4705,-North
0111
2119-P1
4701
2119-P1 -
4702
4705-South
6, 4702
2119-P1
2119-P2
2120
4706, 0111
& 0112
2119-P2
2119-P2
2119-P2
Flow
Rate
in GPM
1,500
1,700
3,000
3,300
4,000
4,500
5,000
6,000
6,500
7,000
7,200
7,500
9,000
12,000
13,000
14,000
15,000
20,000
25,000
Suspended
Solids for
95ti of
Samples ng/1
899 or lower
65 or lower
39 or lower
36 or lower
38 or lower
71 or lower
86 or lower
195 or lower
87 or lower
184 or lower
222 or lower
56 or lower
309 or lower
305 or lower
22 or lower
61 or lower.
205 or lower
72 or lower
205 or lower
No. of
Samples
Considered
48
45
41
48
31
37
36
41
45
12
47
41
47
41
49
47
47
12
48
Median
Value
in r,'.q/l
128
41
14
13
10
15
31
62
42
106
57
13
64
70
16
15
53
22
51
Aver;u;e Value
of 95% of
Samples
176
23
16
14
14 '
20
40
72
42
109
66
16
167
88
21
19
76
30
74
360
-------
the following results:
A. Total number of samples = 985
B. 2 values = 100 mg/1
C. 38 values > 100 mg/1
D. Percentage of values > 100 mg/1 = 3.96% to
U.06% of the total of 985 samples
E. 95% value = 93 mg/1
It was generally concluded that this analysis may be more
representative of the entire system, since the results from
plant No. 2119 appear to be atypical of the data provided by
the other 9 plants.
Data on ash pond overflow for 38 plants obtained from
discharge permit applications, plant visits, a regional
office survey, and other sources indicate that 50 percent of
the ash ponds are achieving effluent total suspended solids
levels of 30 mg/1. For this same sample, 50 percent of the
ash ponds are achieving less than 15 mg/1 total suspended
solids after allowances are made in the data to exclude
total suspended solids in the make-up water. On this net
basis, 30 mg/1 is being achieved by approximately 75 percent
of the ash ponds in the sample.
The Henderson, Kentucky, Municipal Powerplant No. 1 uses a
tube settler to achieve over 99 percent removal of total
suspended solids from fly ash and bottom ash sluice water.
Some details on this systems are presented in Reference U51.
Land was not available for constructing conventional removal
facilities (an effective surface area of 3,000 square feet
would have been required to provide adequate treatment at
1,200 gpm). See Figure A-VII-24.
Tube settlers, manufactured under several proprietary
names, consist of numerous plastic tubes about one inch in
depth and 24 inches long, mounted in modules and placed in a
basin. The tubes, as manufactured, are installed in an
inclined position and each tube acts as an individual
settling^ device. With a length of travel of one inch the
settleable particles can be removed at a much faster rate
than in conventional settling arrangements. The angle of
incline allows the sludge to slide downward to the basin
scrapers. Thus, the tubes are self-cleaning when operating
under design conditions.
Preliminary testing indicated that a hydraulic loading rate
of 1.75 gpm per sq ft would produce a good quality effluent.
Consequently this method of ash removal was recommended for
the project. In the final design, a hydraulic loading rate
of 1.6 gpm per sq ft was used. Accordingly, an effective
surface area of 750 square feet was required. Modules made
by Permutit Co., Division of Sybron Corp. were selected.
301
-------
LJ
3-<•"""•'
* ,/
A !"?'„. "' R*I.IH1<
I;'..1,..'..,.? \
r 'A
/i
*
[
I..-.J
.. .-..^__,
"""~"""';~'">^FT'?g'"7/:^".'""'J
J
Figure A-VII-24 Tube Settler for Ash Sluice Water
at Henderson, Kentucky Municipal
Power Plant No. 1
302
-------
Two basins were designed, each capable of treating one-half
the design flow. However, all piping and launders of each
basin were designed to carry the entire flow in case one
basin is out of service. Each basin has an influent baffle
which serves two purposes: distributing the flow across the
basin and trapping all floatable particles. The settled ash
is removed with mechanical sludge scrapers furnished by
Envirex, Inc., a Kexnord Co. The scraper travels up a 30
degree inclined plane at the effluent end of each basin. As
the sludge is moved up the incline, it continues to dewater
until it discharges into a sludge storage area. Any
drainage from the ash storage area is pumped back to the
basin influent. Although the sludge is quite wet, it is
easily handled with a high-loader. Ultimate ash disposal is
by haul to a landfill as before.
After the settling basins were placed in operation,
composite samples were collected during several cycles of
operation to determine the efficiency of the new system.
The results of the sampling program are shown in Table A-
VII-15 and reflect the performance of the new basins only.
The turbidity and suspended solids concentrations of the
river during the sampling program were 64 JTU and U2 mg/1
respectively.
Maintenance requirements for the system have averaged about
16 manhours per week. The normal duties of the maintenance
personnel include hauling of the removed fly ash, preventive
maintenance and general clean-up of the facilities. The
power requirements include two 2-hp scraper drives and one
1/4-hp sump pump. The total construction cost was $179,000.
pH adjustment has been discussed earlier for other waste
streams. Some plants provide pH control on ash pond
effluent. In pH adjustment, addition of chemicals (such as
lime) to the pond should be carried out such that adequate
mixing and settling is provided in the pond. This can be
achieved by separating the pond in two areas by use of
overflow weirs.
In most of the existing plants, a combined once-through
sluicing system is used to transport both the fly ash and
the bottom ash. Specific data was obtained for five plants
which utilize recirculating ash sluicing systems. In all
the cases, blowdown of the system is practiced to minimize
deposition of dissolved solids as well as to minimize
corrosive effects on the distribution pipes.
303
-------
Table A-VII-15
Performance of Tube Settlers for Ash Sluice Water
(Results of Composite Sampling)
454
to
Sample Number
1
2
3
4
Average
Turbidity, JTU
Influent
1300
360
750
750
790
Effluent
2.1
6.2
19
10
9.5
Total Suspended Solids, mg/1
Influent
7910
1175
2815
5200
4275
Effluent
4
4
26
18
13
% Removal
99.9
99.7
99.1
99.7
99.7
-------
At plant No. 3626 the fly ash is handled dry by a
pressurized collection system, and the bottom ash is
collected hydraulically. Once per shift the bottom ash is
sluiced from the furnace bcttom for settling. Water for the
next sluice is recycled from the effluent of the
sedimentation unit. The settled solids are periodically
drained for disposal. The system is designed for complete
recycle, with blowdown achieved by water retained in the
settled solids. The recycle stream concentrations have
equilibrated and the system has operated successfully for a
number of years. The total makeup to the recirculating
system has been reported as 230 gpd/Mw. A similar system in
operation at plant no. 3630 was installed as a retrofit.
Bottom ash from the combustion of pulverized coal at plant
no. 3630 is trucked from the plant site by a purchaser. The
make-up water rate is about 20 gpd/Mw.
Figure A-VII-25 shows the flew diagram for the system at
plant No. 3630. The blowdown flow has been reported as 198
gpd/Mw. Figure A-VII-26 shows the flow diagram for the
recirculating system at plant No. 5305. The blowdown flow
is 165 gpd/Mw. The recirculating systems at plant Nos. 5305
and 3626 are shown in Figures A-VII-27 and A-VII-28,
respectively.
In two plants within the companies represented on the UWAG
Chemical Cost Task Group which have recycling ash sluicing
systems, blowdown flows of 600 gpd/Mw and 960 gpd/Mw are
used.
Utilizing the data from these five plants (20,165,230,600
and 960 gpd/Mw), the three lowest values of which
conservatively include water lost in evaporation and water
removed with the ash solids, the average blowdown for a
recirculating ash system is about 400 gpd/Mw. If it is
assumed that 5000 gpd/Mw is the recirculating flow
requirement for handling bottom ash, the average blowdown
flow of approximately 400 gpd/Mw represents an 8X blowdown
flow. Three of the plants are achieving a blowdown flow of
less than 250 gpm/Mw which would represent, based on a
recirculating flow requirement of 5000 gpd/Mw, a 555 blowdown
flow.
Most oil fired plants use dry ash handling, although closed-
looped wet systems are also in use. At plant No. 2512, the
fly ash sluicing system was designed to be a closed system.
The ash collected by the precipitators is sluiced from the
hoppers to two concrete ponds. Suspended solids settle out
in the ponds and a relatively clear liquor is returned to
305
-------
Recycle
2470 gpm
(4450 GPD/Mw)
ASH HANDLING
SYSTEM
c
Evaporation Loss
45 gpm
2425 gpm
SETTLING POND
Make-up
56 gpm
Ash Sludge for Disposal
(^20% moisture)
gpm water loss
( 19.8 GPD/Mw)
Figure A-VII-25
FLOW DIAGRAM
RECIRCULATING BOTTOM ASH SYSTEM AT PLANT NO* 3630
306
-------
Cooling Tower
Slowdown as
Make-up
(160 gpm)
ASH HANDLING
SYSTEM
Evaporation Loss
(assumed zero)
1960 gpm
(2000
Recycle
1800 gpm
ASH
SEDIMENTATION
SYSTEM
Ash Sludge for Disposal
160 gpm water loss
(/v/165 GPD/Mw)
Figure A-VII-26
FLOW DIAGRAM •
RECIRCULATING BOTTOM ASH SYSTEM AT PLANT NO. 5305
307
-------
ASH SEDIMENTATION SYSTEM
PLANT NO. 5305
Figure A-VII-27
308
-------
OVER-
FLOW
1. ASH HOPPER ^'
2. SLIDE GATE
3. ASH SUMP WITH CLINKER GRINDER
4. ASH PUMP
5. ASH PUMP DISCHARGE TO HYDROBIN
6. HYDROBIN - THIS IS WHERE ASH IS SEPARATED FROM WATER.
7. UNLOADING OF ASHES INTO TRUCK
8. HYDROBIN OVERFLOW TROUGH
9. UPPER DECANT LINE
10. LOWER DECANT LINE
11. HYDROBIN DRAIN
12. SURGE TANK
13. LET DOWN LINE - THE REGULATING VALVE IS NOT IN USE. THIS IS NOW A HAND
OPERATION TO LET WATER INTO LOWER COMPARTMENT OF SURGE TANK.
14. HOUSE SERVICE SUPPLY LINE - NOT NORMAL MAKEUP.
15. LINE FROM SURGE TANK TO ASH SUMPS
16. HOUSE SERVICE SUPPLY LINE - AT PRESENT DATE IS SOURCE OF MAKEUP - HAND OPERATION
17. REGULATING VALVE TO ASH SUMP
18. HOUSE SERVICE SUPPLY LINE - NO LONGER IN USE.
19. HOPPER WASH DOWN LINE - A MEANS OF PUTTING WATER INTO ASH HOPPERS
FROM MAIN CYCLE.
20. ASH HOPPER OVERFLOW
21. BOILER SEAL TROUGH - WATER OVERFLOWS FROM HERE TO ASH HOPPER THUS ANOTHER
SOURCE OF MAKEUP WATER.
22. BOILER FEED PUMP HYDRAULIC COUPLING COOLING WATER
23. DRAIN BACK LINE - DRAINS ASH PUMP DISCHARGE LINE.
24. OVERFLOW TROUGH - DISCHARGES INTO CIRCULATING WATER DISCHARGE.
FIGURE A-VII-28ASH HANDLING SYSTEM (PLANT NO. 3626)
309
-------
the precipitators to sluice additional ash to the ponds on a
continuous basis. Due to excessive rainfall and leakage of
pump sealing water, the system requires a blowdown of
approximately 132.5 cu m (35,000 gal) per week. The
blowdown is treated in another clarification pond where the
solids are allowed to settle. The effluent from this pond
goes to a neutralizing tank for pH adjustment, and is
settled prior to discharge. The system is shown on Figure
A-VII-29.
The settled solids are intermittently dug out and sold to
reclaiming companies for vanadium recovery. The cost of the
ash handling system is estimated at $461,000.
The above plant is presently investigating a vacuum filter
system for continuous withdrawal and treatment of settled
solids, to replace the intermittent withdrawal system now
used.
At plant No. 1209 fly ash from the mechanical collectors is
recirculated to the boilers for reburning. Accumulated
bottom ash is periodically removed during maintenance and
sold for the vanadium content. The utility representatives
indicate that other plants in their system utilize similar
ash handling techniques.
Plant No. 3621 employs the same type of dry bottom ash
handling and reinjection of fly ash as mentioned above. The
oil burned is Bunker "C" - Venezuela oil, with an ash
content of 0.1X, a sulphur content of 3X, and a vanadium
content of 300-400 ppm, A magnesium oxide fuel additive is
used and it is estimated that bottom ash is 3016, and fly ash
is 70X, of the total ash and additives residue. The
following factors influenced the utility's choice of ash
handling system: in a wet ash handling system it is
estimated that 74.6% of the oil ash is soluble in water, and
30-40% of this ash remains in solution upon settling unless
the detention time is very great - hence a large settling
area requirement; oil ash sluice is expected to be acidic
(pH 3.5- 4) and may cause corrosion and maintenance
problems; the dry bottom ash collection system would allow a
credit for the sale of this ash for its vanadium content of
about $ 0.001 per g ($0.50 per Ib).
Plant nos. 5509 and 5511 employ completely recirculating wet
fly ash handling systems. Dry bottom ash systems are in use
a£ a few plants.
310
-------
CHEMICAL CLEANING WASTES
1. BOILER TUBES
2. BOILER FIRESIDE
3. ASH POND
WASTE TO DISCHARGE -
FLUME OVERFLOW
WASTE
NEUTRALIZING
TANK
WASTE
SUMP
2,500 GAL
WASTE POND
350,000 GAL.
(CONCRETE)
FLOATING SUCTION
WASTE POND PUMP
TAKES CLEAR LIQUOR
FROM POND TO NEUTRALIZATION
TANK PRIOR TO DISCHARGE
ACID CAUSTIC
NEUTRALIZATION PUMPS
FIGURE A-VII-29ASH HANDLING SYSTEM OIL FUEL PLANT (PLANT NO. 2512)
-------
Coal Pile Runoff
In areas where water evaporation rates are higher than pre-
cipitation rates, it is possible to direct coal pile runoff
to a storage pond. These ponds may be provided with an
impervious liner to avoid leakage that may contaminate a
ground water aquifer. Since the amount of runoff depends on
rainfall, for an average annual rainfall of 100 cm (40") a
flow rate of 100,000 cubic meter (26.4 million gallons) per
year could be expected for a one hundred thousand square
meter (25 acres) storage pile. However, a precipitation of
5 cm (2") in one hour is also possible resulting in 5000 cu
m (1.32 million gallons) runoff. Inasmuch as the
evaporation of water is dependent on the surface area of
pond, large pond areas will be required for these runoff
flows. Furthermore, a leaping weir or similar device can be
used to retain the potentially significantly polluting
portions of storm rainfall and to divert the remaining
relatively nonpolluting portions of the storm.
Storage ponds for retention and treatment of coal pile
runoff should be designed for local weather conditions. The
design basis of the pond should be complete retention of
runoff resulting from a storm which occurs once in ten
years. Piping and/or open channels used for collection of
runoff from the coal pile should be designed to bypass all
flow which exceeds the design basis of the storage pond.
Weirs, baffles and regulators such as utilized in combined
municipal sewer systems may be employed to bypass excess
flow and avoid overloading of the storage pond.
The runoff flows are also critically dependent upon the coal
pile area in a plant. For example, the area required for a
90 day coal supply and for other storage functions, such as
alkali for electrostatic precipitators, etc., has been
estimated to be 0.02 acres per Mw of generating capacity
(Ref: "Considerations Affecting Steam Power Plant Site
Selection", Report by the Energy Policy Staff, Office of
Science and Technology, US GPO No. 0-325-261 1968). Data
were compiled for coal pile area encountered in 10 plants
comprising one particluar utility system. The average coal
pile area was approximately 0.02 acres per Mw of generating
capacity with the full range extending from 0.004 to 0.035
acres/Mw.
Coal pile drainage with pH from 6 to 9 and low dissolved
solids can be pumped to an ash pond along with other waste
streams, depending upon available area of the pond.
Runoff from coal pile with high acid and sulfate content can
be neutralized by lime, limestone or soda ash. Any of these
312
-------
chemicals used for the neutralization process involves
essentially the same unit operation. A typical sequence of
unit operation is (a) holding (b) adding the neutralizing
agent and mixing (c) sludge settling and disposal. The
major difference between soda ash neutralization and lime or
limestone neutralization is that soda ash produces a water
low in hardness and calcium, but high in sodium. Other
chemical parameters are comparable between the three
neutralizing agent. Figure A-VII-30 presents the chemical
cost for these three chemicals.
Limestone handling is easier than that of lime because of
its low reactivity. Limestone reaction is not very sensi-
tive quantitatively: i.e. small changes in limestone feed
rate or runoff quality do not cause large changes in product
water quality so that the accuracy of limestone feeding need
not be controlled with the precision required for lime.
Unlike lime, accidental over treatment is not a pollution
problem with limestone because of its low solubility.
A major disadvantage in limestone neutralization can be
attributed to the slow oxidation rate of ferrous iron and
consequently lower rate of settling. The rate of settling
can be increased by the addition of coagulant aids. Figure
A-VII-31 and Figure A-VII-32 present a comparison of lime,
limestone and soda ash reactivities and settling rates
respectively. For a coal pile runoff containing ferrous
iron (FesoU) and free acid (H2SOU), the overall
neutralization reaction using limestone (CaCO3_) can be
represented in the following simplified manner:
3CaC03 + 2FeSO4 + H2SO4 + 0.5 O2 * 2H2O = 3CaSOU «• 2Fe (OH) 3
+ 3C02
A method of collecting and neutralizing coal pile drainage
is to excavate a channel around the coal pile large enough
to have a 10 minute detention time. The bottom of the
channel should contain a limestone bed for neutralizing the
acid content of the runoff. The channel should be sloped so
as to have the runoff drain to a sump from where it can be
pumped or gravity fed to a holding pond prior to discharge.
Insoluble material or precipitated products from
neutralization can be separated by sedimentation or
filtration. The removal of solids by sedimentation has been
described earlier. Figure A-VII-33 shows a, typical coal
pile, with a runoff collection ditch around the perimeter.
Plant no. 3630 has a retrofit system for collecting and
filtering coal pile drainage. The coal pile trench is
designed to handle a 15-hour, once-in-36-years rainfall (3.9
313
-------
1.2
1.1
1.0
0.9
W
C
O
3 0.8
id
O
§ 0.7
o
to-
•H
-P
(0
O
u
rt
u
e
0)
0-5
0.4
0.3
o.i
o
6 7 8 9 10
ACIDITY IN 1000 mg/1
11 12
13 14 15 16 17
COST OF NEUTRALIZATION CHEMICALS
(From Reference 313)
FIGURE A-VI.I-30
-------
en
pH 10 -
pH 8
-,V---;rN
TT f
pH 6
c
pH 4 -
pH
O SODA ASH
A LIME
H LIMESTONE
0 GRAMS 0.2
0 2.0
0.8
8.0
1.0 (LIME, SODA ASH)
10.0 (LIMESTONE)
GRAMS ADDED TO ONE LITER OF RUNOFF (From Reference 313)
(INITIAL HOT ACIDITY = 619 nig/1)
COMPARISON OF LIME, LIMESTONE, AND SODA ASH REACTIVITIES
FIGURE A-VII-31
-------
O LIME
A LIMESTONE
DSODA ASH
INITIAL HOT ACIDITY 586 mg/1
J_
j_
30 min. 60 min. 4 hrs. 8 hrs. 12 hrs. 16 hrs. 20 hrs. 24 hrs,
TIME
COMPARISON OF SETTLING RATE (From Reference 313)
FIGURE A-VII-32
-------
•
COAL PILE
PLANT NO. 5305
Figure A-VII-33
317
-------
inches) . The inflow to the coal pile is gradually
transferred to a collecting basin, which also receives yard
and building drains. The maximum flow to the 100 ft
diameter filtering pond is 2,400 gpm. The filter medium is
a 4 ft deep layer of 0.4 mm sand. The loading is 3.5 gpm/sq
ft and is designed to achieve 35 mg/1 total suspended solids
in the effluent. A design for lower effluent total
suspended solids would involve a deeper bed, a better filter
media, or a larger bed area. This filter has achieved
effluent total suspended solids levels of 15 mg/1 or less
over approximately 75 percent of the storm events to date.
The trench and collecting basin construction costs were
about $750,000 and the filtering pond about $150,000.
Floor and Yard Drains
Floor drains from a coal-fired generating station can be
collected and pumped directly on to the coal pile so that
the oil present in the drainage stream is absorbed by the
coal and burned with it. The water will serve the purpose
of keeping the pile wet in order to avoid spontaneous com-
bustion. Floor drains from plants using a fuel mixture or
fuel other than coal, can be neutralized (if necessary) by
lime or acid to bring the pH between 6 and 9.0. Oil will be
removed by passing the stream through an air flotation unit
or an oil-water separator (Figures A-VTI-34, 35). If the
drains contain high levels of TSS, sedimentation techniques
described earlier can be used. An air flotation unit used
for floor and yard drains is shown in Figure A-VII-36.
Contaminated stormwater runoff can be treated in a similiar
manner. Stormwater collected in oil storage tank basins is
generally held for controlled discharge to an oil-water
separator (Figures A-VII-37, 38).
API - type oil - water separators are being used at plant
nos. 3626, 5105, 1209, and 3702 to reduce oil content down
to 15-20. mg/1. A dissolved air flotation unit is used at
plant no. 0610. Certain preventative measures can be
applied to prevent spillage of oil and the entrance of oil
into the plant drainage system. For example, plant No. 1201
employs inflatable "stoppers" in the entrance to plant floor
drains to trap spilled oil and so that it may be removed
before entering the floor drain system.
Air Pollution Control Devices
The nonrecovery alkali scrubbing process is a closed-loop
type, and the process employs recycle lime scrubbing liquor.
The process requires a make-up water for saturating the
boiler gases. Consequently, the liquid effluent associated
318
-------
_. SKIMMINGS
\ HOPPER
MOTOR &
COMPRESSED
AIR
Vat/
CLEAN WATER
DISCHARGE J^-> i
OIL/,"* J-
SKIMMEDOIL / c c<
DISCHARGE | / ;^
o .1
WATER
SLUDGE , """""" l
*« r ROTATING
=-> I SKIMMER BLADE r-A
1 ^DCPVr*l C /^
net/ T oi_c
1 1 WATER x
k'^1?**.^.^-" L. ' ^y * » x
j •,," ^ ? • •• — ^-^ . l
-1 - •-. ; , H,-*,.r*y!, „<$!,
s\ o RECYCLE
•'A PUMP ^^-
.°.PL_. L_ ^^T • mi
L, ^ao^; ^ IN
±^--~~^ ^ RISING AIR
<^"^ BUBBLES WITH
I ATTACHED OIL
ERATION TANK
*""*VAERATED RECYCLE
WATER
j
.- FLASH VALVE
-- (RELEASES
. ' BUBBLES)
Y WATER
FLUENT
ROTATING \ ^-Dl^y,ScER '
SCRAPER ARM J CONE
FIGURE A-VII-34 CYLINDRICAL AIR FLOTATION UNIT
OIL COLLECTING -r
PIPE
DISTRIBUTION '
BOX 1
WEIR—, BAFFL
j
INLET ^ ri'll A
r^" 0U; » =
\n v^.1 __
r
^ - (
"1-U R^J^ - ~~ c c
7 ':.l I -*• i;"
//~^ /' / /.// 77~/7~/7/X/7/~^ / r^rr-Tx. /'•-*/!""' /"7~r/ —
[
INLET PRIMARY
CHANNEL CHAMBER
^£l X^z^/ 1
rLICjHT CLEANER
SLUDGE SECONDARY
SUMPS CHAMBER
OIL COLLECTING
PIPE
r BAFFLE
pWEIR
\S^ YA OUTLET
JzzJ
OUTLET
CHANNEL
FIGURE A-VII-35 TYPICAL A. P. I. OIL-WATER SEPARATOR
31S
-------
OIL SEPARATOR AND AIR FLOATATION UNIT
PLANT NO. 0610
Figure A-VII-36
320
-------
INTERCEPTOR
BAY
PLATE
ASSEMBLY "
GRATING
OUTLET CHANNEL
r- POLYURETHANE FOAM
SKIM PIPE
INLET CHANNEL
SLUDGE
COMPARTMENT
BAFFLE
SAND
STORAGE
FIGURE A-VII-37 CORRUGATED PLATE TYPE OIL WATER SEPARATOR
321
-------
OIL/WATER MIXTURE IN
VENT
WATER
DRAIN
OIL
FIGURE A-VM-38 OIL WATER SEPARATOR
322
-------
with the sludge removal step should be kept to a minimum to
minimize make-up water requirements. This can be achieved
by providing adequately sized ponds and adding flocculants
for efficient settling. Use of mechanical filtration
equipment will further dewater the sludge and thus minimize
liquid effluent discharge. Oxidation of the scrubber
discharge effluent will ensure that sulfite level in the
sludge is minimal. Lime/limestone addition is necessary to
eliminate acidity. If the process employs a pond in the
scrubber liquor recycle loop, the pond should be lined to
minimize ground seepage.
Sanitary Wastes
Sanitary wastes can be discharged to municipal sewerage
systems where possible. In rural areas, packaged sewage
treatment plants are commonly used for treating this waste.
Most of these plants are based on the biological principle
of aerobic decomposition of the organic wastes and are able
to reduce the raw sewage concentrations of BOD-5 and TSS to
meet effluent standards applicable to publicly-owned
treatment works.
Other Wastes
Intake screen backwash can be collected, viable organisms
returned to the waterway, and the collected debris removed
before discharging the effluent to the receiving waters.
Collected debris can be disposed of in a landfill or other
solid waste disposal facility.
For other miscellaneous wastes, such as those from
laboratory and sampling activities, etc., pH adjustment and
TSS removal is similar to that followed in other waste
streams. Technology for the control of pollution from
construction activities is 'treated comprehensively in
Reference 382.
Oil spillage from transformers can be absorbed in slag-
filled pits under and around the transformers. Curbing of
the pits prevents flooding by surface water and floating off
the oil.
Waste water from the primary coolant loop of nuclear plants
may contain boron; however, no treatment is known for boron
removal. As explained in Part A Section V, nuclear plants
follow a radioactive waste management system. Any treatment
or recycle concept applied to remove non-radioactive
pollutants from these wastes would have to consider the
radioactive components of this waste.
323
-------
Various Waste Streams - Concentration and Recycle
Vapor-compression evaporation systems can be used to recover
and recycle water from various waste streams encountered
normally in a steam electric generating plant. These
streams include boiler blowdown, demineralizer blow-down,
ash sluicing water blowdown, coal pile runoff, SO^ scrubber
blowdown, treated sewage effluent, boiler cleaning waste and
cooling tower blowdown. Two case histories in which the
vapor-compression evaporation systems (brine concentrator)
have been installed in steam electric generating plants are
described below.
Case I (See Figure A-VII-39 and Table A-VII-16) is an
application of the brine concentrator that was placed in
operation on June 14, 1974. This application will
ultimately employ several brine concentrators to completely
eliminate wastewater blowdown from the ash sluice system.
The ash sluice water is provided by the cooling tower
blowdown where it is recycled to the boiler and ash is
sluiced to the ash separator. The supernatant from the ash
separator is recycled to the ash sluice water storage tank
for reuse. The blowdown from the ash sluice water storage
tank is processed in the brine concentrator where the
concentration of total solids is increased to over 100,000
ppm. It is contemplated that as additional generating units
are placed on line, additional brine concentrtors will be
installed so that eventually the only feed to the pond will
be the waste from the brine concentrators.
Case II (See Figure A-VII-40 and Table A-VII-17) is an
application of the brine concentrator that was placed in
operation on June 28, 1974. This installation will
eventually be used to process a blowdown from various
generating plant waste streams. However, the brine
concentrator is currently being utilized to concentrate only
cooling tower blowdown. The blowdown will be concentrated
approximately 40 times such that the feed of 156 gpm is
reduced to 3.7 gpm of concentrate. At this installation,
the client anticipates a wide variation in the feedwater
chemistry to the brine concentrator. On the chemistry data
sheet are shown the maximum TDS design conditions and the
normal value TDS conditions.
Evaporation ponds are in use at a number of steam electric
powerplants to reduce waste streams to dryness. Plant No.
4883 uses 101,000 sq ft of lined evaporation pond to
evaporate a maximum flow of 43,000 gal/day of waste water to
324
-------
TCV.'Ef! EVAPWnP'l TraEP. ni'T .'•
2 GP" UIIIL'AC!: LI S3
OJ
ro
tn
cnpLi;:; ;(".jci< *
::AKE'JP «iri r,p:;
COOLING TOWER
Figure A-VII-39 Vapor-Compression Evaporation System (Case I)
System commissioned on June 14, 1974
452
-------
Table A-VII-16
RCC BRINE CONCENTRATOR SYSTEM CHEMISTRY (Case I)
452
COMPONENT
CALCIUM (As Ca^)
MAGNESIUM (As Mg^)
SODIUM (As Na+)
BICARBONATE (As HCOg" )
SULFATE (As S04= )
CHLORIDE (As C1")
SILICA (As Si02)
*30 CONCENTRATION FACTORS
TDS (PPM)
SS (PPM)
FLOW RATE (GPM)
PH
CONCENTRATOR
FEED (TDS)
529 PPM
276
55
488
2,002
62
55
3,467
-
156
8.0-8.5
CONCENTRATOR
WASTE BRINE (TDS)*
520 PPM
7,800
2,850
-
36,528
1,800
250
49,748
54,862
5.2
7.0-7.6
PRODUCT
WATER
< 10
-
148
6.0-7.0
co
ro
on
-------
POWER PLANT
CONDENSER
RCC BRINE
PRODUCT
WATER
1So PPM CONCENTRATOR}*-
152.3 GPM V SYSTEM
10 PPM CF = 40
EVAPORATION
4 LOSSES
I
COOLING
TOWER
COOLING TOWER
MAKEUP
COOLING TOWER
SLOWDOWN
156 GPM
5,000 - 8.000 PPM
3.7 GPM
94,300 - 165,600 TDS PPM
103,400 - 139,500 SS PPM
EVAPORATION
POND
Figure A-VII-.40 Vapor-Compression Evaporation System
( Case II)
327
-------
Table A-VII- 17
RCC BRINE CONCENTRATOR SYSTEM CHEMISTRY (Case II) 452
COMPONENT
CALCIUM (As Cd**)
MAGNESIUM (As Mg"*"*")
SODIUM (As Na+)
BICARBONATE (As HCOj")
SULFATE (As S04=)
CHLORIDE (As Cl")
SILICA (As S102)
*40 CONCENTRATION FACTORS
TDS (PPM
SS (PPM)
FLOW RATE (GPM)
PH
CONCEN'
FEED
NORMAL
748 PPM
166
496
360
2,964
172
110
5,016
-
156
8.0
FRATOR
(TDS)
HIGH
1,000 PPM
149
1,182
360
4,963
199
134
7,987
-
156
8.0
CONCENTRATOR
WASTE BRINE (TDS)*
NORMAL
720 PPM
6,640
19,840
-
60,000
6,880
250
94,330
103,430
3.7
7.0-7.6
HIGH
480 PPM
5,960
47,280
-
103,680
7,960
250
165,610
139,470
3.7
7.0-7.6
PRODUCT
WATER
< 10
-
152.3
6.0-7.0
CO
ro
oo
-------
dryness. Configured systems are being installed at three
steam electric powerplants (plant nos. 0413, 3517 and 4907).
The configured systems use brine concentrators which recycle
the distillate to the demineralizer system or to the cooling
tower. All process 156 gpm of cooling tower blowdown.
However, water treatment wastes, etc., are combined with the
recirculation cooling water. The plants involved are
designed to achieve no discharge of pollutants through
recycle of waste water streams. Therefore, the concentrated
brine ultimately contains all plant wastes. The costs of
the units are approximately $2-4/kw with about 18 months
required for installation. The application of evaporative
brine concentrators to low-volume waste stream effluents
after chemical treatment is not known to have been achieved.
Therefore, some technical risks may be involved in applying
this technology directly to lew-volume waste water of
powerplants.
Sludge Disposal
The major solid wastes from powerplants can be classified
into three categories:
1. Fuel related wastes (ash) - flyash, bottom ash and
boiler slag
2. Scrubber sludges - from non-regenerable (throwaway)
flue gas desulfurization systems
3. Chemical sludges - from water and effluent treatment
systems
Of the three wastes, partial utilization of ash has been
commonly practiced. Tables A-VII-18 and A-VII-19 indicate
ash collection and utilization data (Ref. 33). Estimated
1976 ash production is also shown in Table A-VII-18. It can
be seen that the largest usage has been, and continues to
be, as fill material for roads, construction sites, etc.
However, new commercial processes are being developed and
the trend seems to be to increase ash utilization for other
applications. Some recent developments which offer
potential high-tonnage ash utilization are as follows:
(Ref. 33).
1. A material composed of lime, flyash and sulfate or
sulfite sludges was used to pave some access roads and
parking areas at Dulles International Airport (Washington,
D.C.) for the Transpo *72 exhibition. 2. Two cement
companies announced new plants and programs to market for
general construction purposes a portland pozzolan cement
that is a blend of portland cement and flyash. 3. A new
project in northern West Virginia will use 250,000 tons of
329
-------
Table A-VII-18
Ash Collection and Utilization, 1971 (Tons)
33
Fly Ash Bottom Ash
Ash uses:
1. Mixed with raw material before
forming cement clinker 104,222 —
2. Mixed with cement clinker or mixed
with pozzolan cement 16,536 —
3. Partial replacement of cement in:
a. Concrete products 177,166
b. Structural concrete 185.467
c. Dams and other mass concrete 71,411
4. Lightweight aggregate 178,895
5. Fill material for roads, construction
sites, etc. , 363.385
6. Stabilizer for road bases, parking
areas, etc. 36,939
7. Filler in asphalt mix 147,655
8. Miscellaneous 98.802
Subtotal 1,380.478
Ash removed from plant site lat no cost
to utility, but not covered in
categories listed above, see Table II
below) 1,872.728 542.895
ilies. which account lor 60% of Hie bituminous coal
and 80% ol the ash-producing oil that is consumed
in the U.S.
Boiler Slag
91.975
76.563
35.377
13,942
533,682 2.628.885
7,880 49,564
2,833 81,700
475.417 428,026
1.069,131 3.356.713
381.775
Total ash utilized
Ash removed to disposal areas (at
company expense)
Total ash collected, 1971 *
Estimated 1976 ash production
•These ash production ligu'es .ve lor eiecincai uln-
3,253.206
24.497.848
27,751,054
36.994.436
1,612,026
8,446.941
10.058367
117.411,603
3.738.488
1,232.298
4,970,786
2,517.703
Table A-VII-19
Known Uses for Ash Removed From Plant at No Cost to
Utility (Tons) 33'
Cement manufacture
Mine-fire control
Anti-skid winter roads
Building blocks and fill material
Experimental soil conditioner
Misc. fill material
Airport pavement
Soil stabilization
Fertilizer tiller
Rubber filler
Vanadium recovery
Oust control
Asphaltic wear-course aggregate
Total
Fly Ash Bottom Ash Boiler Slag
51,697
129,258
82,948
25
477,918
16,200
5,035
1,321
296
200
38,940
178.323
14,741
34.760
200
11.284
166.131
229,393
2.130
764,898
278,248
397,654
330
-------
bottom ash and boiler slag as aggregate for a new portion of
West Virginia1s Route 2. Besides conserving dwindling
supplies of local natural aggregates, this use of ash is
expected to save $500,000 in material costs, 4. Ontario
Hydro commenced operation of its flyash processing plant at
Mississauga, Ontario, to make pozzolan, aggregate, magnetite
and carbon products. Also, International Brick and Tyle's
flyash brick plant near Edmonton, Alta., has started
production; it is designed to initially provide 6.25 million
units annually to the face-brick and paving-tile market in
western Canada. The process being used was developed by the
Coal Research Bureau of West Virginia University. This
process will also be used in Czechoslovakia in a plant that
will consume about 100,000 tons/year of flyash. 5.
Specifications for "lime-flyash-aggregate" base material are
anticipated to become part to the Federal Aviation
Administration1s construction guidelines. Newark and JFK
Airports have already utilized this type of material in the
construction of runways for new, heavier aircraft. Similar
pavements are being designed for airports at other
locations.
Besides these commercial applications, extensive research is
being conducted to utilize ash in agriculture as fertilizer,
in brick manufacturing, for land and water reclamation, and
for fire control purposes.
The traditional ash disposal methods - namely ponding and
landfill - are expected to remain in widespread practice.
These methods have been described in the literature (Ref.
417).
Dewatering and fixation aspects related to the disposal of
scrubber sludges from non-regenerable (throwaway) flue gas
desulfurization systems have been described in the
literature (Ref. 117).
Chemical sludges resulting from water and effluent treatment
systems in a powerplant can be disposed in landfill or
ponding operations. Table A-V-20 indicates typical chemical
wastes originated in a coal-fired powerplant. Based on this
tabulation, it is possible to estimate the annual volume of
sludges resulting from the treatment of these waste streams.
For example, for a 1,000 Mw coal-fired powerplant chemical
sludges will require an additional land area of
approximately 2-7X for pondage. This is based on the waste
characterization shown in Table A-V-20 and the following
assumptions:
331
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1. A 1,000 Mw coal-fired powerplant requires an ash
disposal area of 120 acres piled to an average depth of 25
feet over a 35 year plant life and assuming an average
capacity factor of 50% (Ref. 370). 2, Chemical treatment
results in a precipitate of twice the weight of pollutant.
3. Suspended solids removal system is designed for an
outlet concentration of 30 mg/1. 4. Chemical treatment
removes all of the chemical pollutant parameters listed in
Table A-V-20 completely and the weight of precipitate is
twice the weight of the pollutant parameter. This is a
conservative assumption. For example, if the ash pond
overflow is treated only for these suspended solids removal
(and no pH adjustments is required) then sulfate and
hardness will not be precipitated. Consequently, the 1,000
Mw plant will require an additional land area of 251 for
pondage based on these considerations.
Clarifier underflow (sludge) contains typically 1 to 2
percent solids and can be carried to a lagoon. Run-off
through porous soil to ground-water can be objectionable
since precipitated metal hydroxides tend to get into
adjacent streams or lakes. Impervious lagoons require
evaporation into the atmosphere; however, the average annual
rainfall in many locations balances atmospheric evaporation.
Additionally, heavy rainfalls can fill and overflow the
lagoon. Lagooning can be avoided by dewatering the sludge
to a semi-dry or dry condition.
Several devices are available for dewatering sludge. Rotary
vacuum filters will concentrate sludge containing t to 8
percent solids to 20 to 25 percent solids. Since the
effluent concentration of solids is generally less than 4
percent, a thickening tank is generally employed between the
clarifier and the filter. The filtrate will contain more
than the allowed amount of suspended solids, and must,
therefore, be sent back to the clarifier.
Centrifuges will also thicken sludges to the above range of
consistency and have the advantage of using less floor
space. The effluent contains at least 10 percent solids and
is returned to the clarifier.
Pressure filters may be used. In contrast to rotary filters
and centrifuges, pressure filters will produce a filtrate
with less than 3 mg/1 of suspended solids. The filter cake
contains approximately 20 to 25 percent solids. Pressure
filters are usually designed for a filtration rate of 2.0t
to 2.<*4 liters/min/sq m (0.05 to 0.06 gpm/sq ft) of
clarifier sludge.
332
-------
Solids contents from 25 to 35 percent in filter cakes can be
achieved with semi-continuous tank filters rated at 10.19 to
13.4U liters/min/sq m (0.25 to 0.33 gpm/sq ft) surface. A
solids content of less than 3 mg/1 is normally accepted for
direct effluent discharge. The units require minimum floor
space.
Plate and frame presses produce filter cakes with UO to 50
percent dry solids and a filtrate with less than 5 mg/1
total suspended solids. Because automation of these presses
is difficult, labor costs tend to be high. The operating
costs are partially off-set by low capital equipment costs.
Automated tank-type pressure filters produce a cake the
solids content of which can reach as high as 60 percent
while the filtrate may have up to 5 mg/1 of total suspended
solids. The filtration rate is approximately 2.0U
liters/min/sq m (0.05 gpm/sq ft) filter surface area.
Pressure filters can also be used directly for neutralized
wastes containing from 300 to 500 mg/1 suspended solids at
design rates of a.88 to 6.52 liters/min/sq m (0.12 to 0.16
gpm/sq ft) and still maintain a low solids content in the
filtrate. Filter cakes can easily be collected in solid
waste containers and hauled tc land fills.
Several companies have developed proprietary chemical
fixation processes which are being used to solidify sludges
prior to land disposal. In contrast to filtration, the
amount of dried sludge to be hauled is increased. Claims
are that the process produces insoluble metal ions so that
in leaching tests only a fraction of a part per million is
found in solution. However, much information is lacking on
the long term behavior of the "fixed" product, and potential
leachate problems which might arise. The leachate test data
and historical information to date indicate that the process
has been successfully applied in the disposal of polyvalent
metal ions and it apparently does have advantages in
producing easier to handle materials and in eliminating free
water. Utilization of the chemical fixation process is felt
to be an improvement over many of the environmentally
unacceptable disposal methods now in common usage by
industry. Nevertheless, chemically fixed wastes should be
regarded as easier-to-handle equivalents of the raw wastes
and the same precautions and requirements required for
proper landfilling of raw waste sludges should be applied.
Powerplant Wastewater Treatment Systems
Previous sections of this report have discussed the signi-
ficant parameters of chemical pollution present in various
333
-------
waste streams and the control and treatment technology
available to reduce these parameters to acceptable limits.
It would generally not be practicable for powerplants to
provide separate treatment facilities for each of the waste
streams described. However, segregation and treatment of
boiler cleaning waste water and ion exchange water treatment
waste water is practiced in a relatively few stations, but
is potentially practicable for all stations. Oily waste
waters are segregated from nonoily waste streams at some
stations and the oil and grease removed by gravity
separators and flotation units. Combined treatment of waste
water streams is practiced in numerous plants. However, in
most cases treatment is accomplished only to extent that
self-neutralization, coprecipitation and sedimentation occur
because of the joining and detention of the waste water
streams. Chemicals are added during combined treatment at
some plants for pH control. Most of these stations employ
lagcons, or ash ponds, while a few plants employ configured
settling tanks. It would be generally practicable, from the
standpoint cf costs versus effluent reduction benefits, for
powerplants to treat separately certain low-volume waste
streams, certain intermediate-volume waste streams, the
high-volume waste streams, and the waste stream caused by
rainfall runoff.
A major problem in providing a central treatment facility is
the variability of the flow characteristics of the waste
streams generated in a powerplant. As previously indicated,
some of the flows are either continuous or daily batch dis-
charges, while others only occur a few times per year and
others depend on meteorological conditions. The provision
of adequate storage to retain the maximum anticipated single
batch discharge is therefore a critical aspect of the design
of a centralized treatment facility. For purposes of this
report it has been conservatively assumed that sufficient
storage would be provided to store all of the batch
discharges as if they would occur simultaneously and deliver
them to the treatment units at an essentially uniform rate.
A small, highly efficient central treatment facility would
be primarily designed to handle low volume wastes with
relatively high concentrations of heavy metals, suspended
solids, acidity, or alkalinity, etc. The addition of
intermediate-volume wastes such as cooling tower blowdown
and nonrecirculating ash sluice water to this facility would
require a significantly more costly investment and would not
with the same practices be able to affect as high a degree
of effluent reduction (pounds) due to the dilution factors
involved. The capital investment required for inclusion of
cooling tower blowdown in the central facility may be
334
-------
significant. The benefit derived from including this stream
in terms of suspended solids removal is questionable when
compared to the added cost involved. Cooling tower blowdown
and nonrecirculating ash sluice water was not considered in
development of the model treatment facility because the
characteristics of these streams are not necessarily com-
patible with the treatment objectives of the central
facility.
Cooling tower blowdown generally can be characterized by a
relatively high concentration of the total dissolved solids
present in the water source and a somewhat lower con-
centration of the suspended sclids present in the water
source. In addition, tower blowdown generally contains
small concentrations of chlorine and other additives from
the closed cooling system. The objective of directing
cooling tower blowdown to a central treatment facility would
most likely be for the removal of suspended solids.
However, in general treatment for removal of suspended
solids prior to the use of water as make up to a cooling
tower would be practiced if the suspended solids level is at
all significant. In any event, some concentration of the
suspended solids level will occur in the tower due to
evaporation and, in some cases, due to contact with airborne
particulates. However, the cooling tower basin also acts as
a settling basin to some degree, so that suspended solids in
many cases will settle out in the cooling tower basin. In
any case, the objective of suspended solids removal from
these intermediate-volume waste streams can best be achieved
by the commonly employed practice of using sedimentation
lagoons.
In some cases in both fossil-fueled (plant no. 2119) and
nuclear plants (plant no. 3905) cooling tower blowdown is
combined with low volume wastes in the sedimentation pond.
Better results can be obtained by segregation of these low-
volume and intermediate-volume waste streams. In plant no.
3905 the pond is designed for 24 hours detention and is
divided by a dike to provide settled solids accumulation in
the forepond to facilitate removal, and further to prevent
short-channeling of waste water flows. Segregation could
have been provided at an incremental cost for the additional
piping required.
Where sufficient land is not available for effective ash
ponds and/or where no discharge of heavy metals, etc., would
be required, closed-loop recirculating systems can be
employed which require much less available land.
Recirculating ash sluicing systems of this type are capable
of achieving significant removals of pollutants up to no
33b
-------
discharge of ash in waste water effluents. An example of
such a system is the upgraded waste treatment facility now
operating at plant No. 3630. In this system, bottom ash is
sluiced from the ash hoppers and collected in the hydrobins.
The sluicing water is recirculated back to the hoppers thus
making a closed loop system.
Wastewater Management
Because of the varied uses that are made of water in a
powerplant and the wide range of water quality required for
those uses, powerplants present unusual opportunities for
wastewater management and water reuse. The highest water
quality requirements are for the bciler feedwater supply.
Makeup to this system must be demineralized to TDS
concentrations of the order of 50 mg/1 for intermediate
pressure plants and 2 mg/1 for high pressure plants. Boiler
blowdown is generally of higher purity than the original
source of supply, and can be recycled for any other use in
the plant, including makeup to the demineralizers. In
plants using closed cooling water systems, the blowdown from
the cooling system is of the same chemical quality as the
water circulating in the condenser cooling system. Limits
on the water quality in that system is governed by the need
to remain below concentrations at which scale forms in the
condenser. However, if calcium is the limiting component,
the introduction of a softening step in the blowdown stream
would restore the waste to a quality suitable for reuse.
Even without softening, the blowdown from the condenser
cooling water system is suitable for makeup to the ash
sluicing system, or for plants using alkaline scrubbers for
control of sulfur dioxide in stack gases, as makeup to that
system. Plants located adjacent to mines (mine-mouth
plants) often have additional requirements for low quality
water for ore processing at the mine.
With these cascading water uses it is frequently possible to
devise water management systems in which there is no
effluent as such from the powerplant. These plants still
have significant overall water requirements, but the water
is used consumptively for evaporation and drift in cooling
towers, for sulfur dioxide removal, or for ash handling and
ore preparation. Figures A-VII-U1, 42 show flow diagrams,
taken from Reference 378, for a typical 600 Mw coal-fired
plant, with and without waste water management to achieve no
discharge of pollutants. An equalization basin is usually
provided for temporary large waste discharges such as result
from cleaning operations, but even these wastes can be
reintroduced into the system at a later time. Several
336
-------
EVAPORATION & DRIFT LOSS
ALUM
DISCHARGE
BOILER SLOWDOWN
20 GPM
Figure A-VII- 41 Sewage and Waste Water Disposal for a Typical Coal-Fired Unit, 600 Mw
378
-------
EVAPORATION & DRIFT LOSS
0-0
4,980 GPM
HAW WATER ^
7.400 GPM *
SURGE
POND
k~
1
t
ALUM DISPERSANTS
1 —.LIME CORROSION IN
Y * CHIOHINF —
SOFTENER
AND
CLARIFIER
7,250 GPM
HIBITORS -,
1
rwi
r
1 |
BACKWASH FMTFB
WET /
COOLING /
TOWER /
/
r '•
r
SURFACE
CONDENSERS
-M )—— ^-TO CONDENSATE TANK
vqv
SLOWDOWN
2.ISO GPM
EVAPORATOR > BOILER SLOWDOWN 220 GPM
Figure A-VII-42 Recycle of Sewage and Waste Water for a Typical Coal-Fired Unit, 600 MH
378
-------
plants visited during this study were using water management
schemes of this type without economic penalties. Water
management may be the most economical mode for operating a
powerplant in a water short area. There can be no doubt
that the concept of no discharge of pollutants is feasible
for many steam electric pcwerplants. A number of plants
within the industry currently practice recycle and reuse in
varying degrees and in a number of different ways. Several
plants constructed within the last few years were designed
for minimal or no discharge. See Figure A-VII-43.
Plant No. 3206 was intended to be a no discharge facility
and is achieving that goal although some operating problems
have been encountered. The plant receives slurried coal by
pipeline and after dewatering reuses the water in its
service system. Makeup to the cooling towers is softened to
obtain 16-17 concentrations in the system and therby
minimize blowdown. Ash sluicing water is also recycled and
blowdown from this system along with other blowdown streams
are sent to evaporation ponds for final disposal.
Plant No. 5305 is a mine-mouth facility which also was
designed to produce no discharge other than that resulting
from coal pile drainage and the effluent from the sewage
treatment plant. Discharges from plant operations,
including cooling tower blowdown, water treatment wastes,
boiler blowdown, floor drains and blowdown from a closed ash
sluicing system are collected in effluent storage ponds.
Makeup to the ash sluicing operation is taken from these
ponds, but the major portion of the water is transported to
the mine and coal preparation plant. The plant is an
excellent example of cascading water reuse to usages
requiring successively lower water quality. A large amount
of the water withdrawn from the river is lost through
evaporation in the cooling towers. The remainder is either
ultimately tied up with filter cake at'the coal preparation
plant or disposed of with wet ash. Both the filter cake and
the ash are returned to the mine for use as fill.
Plant No. 0801 utilizes a series of ponds to achieve
intermittent controlled discharge for use in irrigation.
The ponds provide the water required for condenser cooling,
boiler feed, flue gas scrubbing and ash sluicing. Ash
sluice, boiler blowdown and scrubber wash water are
discharged to two alternately used ash ponds. Overflew from
these ponds and condenser cooling water are discharged to a
series of three ponds or lakes. The third in the series of
ponds serves as the water source, thus providing a
completely closed system.
339
-------
CO
-e»
CD
HOPPER JETTING NOZZLES
EVAPORATION
RIVER
Figure A-VII-43
RECYCLE WATER SYSTEM, PLANT NO. 2750
254
-------
Several generating stations are utilizing closed-loop
recirculating systems for ash sluicing operations. Systems
of this type are capable of achieving effluent reductions up
to no discharge of pollutants in wastewater effluents.
Examples of such systems include plants 3630 (a retrofit)
and 3626. Both of these installations collect sluiced
bottom ash in hydrobins, and recirculate the water back to
the ash hoppers for sluicing. This type of system is
particularly suited to plants where sufficient land is not
available for effective ash ponds. Plant No. 4846 also
utilizes a closed-loop ash sluicing system, but employs an
ash pond with discharge from the pond being pumped back to
the plant.
Plant No. 3630 has a retrofit system for achieving no
discharge of pollutants from bottom ash . sluicing, boiler
cleaning wastes, floor drainage, boiler blowdown, evaporator
blowdown, and demineralizer wastes. This is achieved
through the re-use of neutralized demineralizer waste water,
boiler cleaning effluents, floor drainage, boiler blowdown,
and evaporation blowdown in the ash sluicing operation.
Ultimate blowdown is achieved through the moisture content
(15-20 percent) of the bottom ash discharged to trucks for
off-site use. Fly ash, handled dry, is also trucked to off-
site uses. The plant capacity is 600 Mw and operates in the
base-load mode. The bottom ash recycle and handling system
occupies a space approximately 200 ft square. The entire
system cost about $2 million including equipment,
foundations, re-piping, pumps, and instrumentation and took
approximately two years to install including engineering,
purchasing, delivery, and installation. The same plant
retrofit a system for collecting and filtering coal-pile
drainage and road and building drainage. The coal pile
trench is designed to handle drainage from a Monce-in-30-
years" rainfall (3.9 inches). The filtering pond is 100 ft
in diameter and the filter bed is sand. Trash from the bar
screens of the intake is buried on-site. The demineralizer
neutralization system cost about $80,000, the boiler
cleaning effluent tanks about $100,000, re-piping about
$250,000, and the intake screen washing system about
$35,000.
Other plants employ various recycle and reuse techniques
depending upon their water needs, environmental effects,
plant layout, etc. Plants 2119 and 4217 utilize cooling
tower blowdown as makeup to the ash sluicing system. Plant
No. 3713 discharges treated chemical wastes from the ash
pond into the intake to the condenser cooling water stream.
Plant No. 4216 utilizes a closed-loop wet scrubbing device
for air pollution control, and plant 2512 sluices fly ash
341
-------
from an electrostatic precipitator to a pond and reuses the
water in the sluicing system.
A number of plants, including Nos. 2512, 2525, 3601A, and
4217 utilize central treatment facilities or ponds to treat
chemical type wastes to acceptable levels for discharge.
The effluents produced could be reused, but the availability
of an adequate, cheap water supply has not made this
necessary in these instances.
Recycling in nuclear plants and plants with no ash sluicing
will depend primarily upon treatment of cooling tower blow-
down and re-use of the blowdown as make up to the tower.
The wastes resulting from water treatment could be recycled
to the influent of the water treatment plant. Blowdown from
these internal recycling schemes would be treated by
desalination techniques to remove total dissolved solids,
and as a result, water produced by this treatment could also
be recycled. In plants where a water surplus would occur,
the intent would be complete treatment for removal of all
pollutants and discharge of clean water to the receiving
stream. This interpretation of "no discharge" is meant to
be no discharge of pollutants, rather than no discharge of
any liquid stream. Generally, however, it is anticipated
that even nuclear plants and plants with no ash sluicing
would not have a water surplus, but would require makeup to
the various internal recycling schemes.
In any case the degree of practicability of recycle and
re-use systems would be favored in cases where; a) Tower
construction is corrosion resistant to water high in TDS,
sulfates and chlorides, b) Piping systems and equipment are
lined or resistant to corrosion. c) Condenser leakage
affecting feedwater quality for sustained power operation is
minimized or compensated for. d) Sludge handling and
disposal facilities are adequately designed and available.
e) Designs for tower operation at a high number of cycles of
concentration could be feasible if windage and drift losses
are minimized to eliminate heavy carryover of solids to the
surrounding areas.
The extent to which wastewater management can be practiced
depends on the chemical constituents of the original water
supply. Table A-V-2 , adapted from an unpublished paper by
G.R. Nelson, shows the typical raw water characteristics of
a water supply for powerplant water systems, A water supply
falling within the range of concentrations shown on Table A-
V-2 could probably be used for a once-through cooling system
without treatment. However, if this source of supply were
used for recirculating cooling, certain constituents might
342
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limit the number of cycles of concentration possible without
precipitation and resultant loss of heat transfer capacity.
Since the number of cycles of concentration determines the
quantity of circulating water that can be maintained with a
given quantity of makeup, it is generally desirable to
achieve the largest number of cycles possible for any given
raw water analysis. The factors limiting the number of
cycles are shown in Table A-V-1.
If the number of cycles of concentration limited by the
hardness of the water supply, the plant has several options
to increase the number of cycles and thereby reduce both the
makeup and discharge water quantitites. These include:
1. Makeup water treatment programs (makeup programs)
where all or a portion of the makeup is treated prior to
entering the system. The treatment results in a net
reduction in the makeup and discharge water quantities.
2. Recirculating water treatment programs (recirculating
programs) where all or a portion of the recirculating water
is treated and recycled back to the cooling system. The
treatment results in a net reduction in the makeup and
discharge water quantitities.
3. Slowdown water treatment programs (blowdown programs) -
where all or a portion of the blowdown is treated and
recycled back to the cooling system. Again, the net result
is a reduction in the makeup and discharge water quantities.
In summary, the concept of recyle or re-use is not new to
the steam electric powerplant industry. Many plants utilize
a variety of recycle schemes to satisfy particular needs,
and these systems have the potential for broad application
in the industry to meet effluent limitations guidelines.
Effluent Reduction Benefits of Waste Water Treatment
to Remove Chemical Pollutants
The use of a conventional ash pond at a 1,000 megawatt coal-
fired plant (capacity factor = 0.6) typically achieves the
removal of over 1,200,000 Ib/day of total suspended solids,
with an overflow of 1,<*00 Ib/day of total suspended solids.
This is based on 1970 data for the Bull Run plant of
T.V.A.Z7» and an assumed 11% of ash solids in coal. It is
estimated that about 70-75 percent of the U.S. coal-fired
generating capacity uses ash ponds, as indicated by the data
sample summarized in Table A-VII-20. For a pulverized coal
burner about 15% of the ash generated is fly ash. However,
the overflow discharge of total suspended solids from
343
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Table A-VII-20
Extent of Present Use of
Chemical Waste Disposal Methods
in Coal-Fired Powerplants 467
(1973)
Method of
Disposal
Number of Plants,
Generating Capacity
of Plants, %
Ash Ponds
Direct to
Receiving Waters
Sewers
61
24
15
72
26
344
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combined ash ponds would most likely be mainly the fines
from fly ash, which are the most difficult to remove in ash
ponds. Therefore, the use of dry fly ash sluicing in place
of ash ponds would remove an increment of about 1,400 Ib/day
of total suspended solids that would otherwise be discharged
from the ash pond. In addition to removal of total
suspended solids the dry fly ash system would have the
further benefit of removing aluminum, chromium, copper,
iron, manganese, mercury, nickel, selenium, zinc, and other
pollutant parameters that might otherwise be discharged.
Recognizing that the removal of suspended solids by
sedimentation is limited by the effluent concentrations that
are achievable, reduction in pond overflow discharge (at the
same effluent concentration) would proportionally reduce the
discharge of suspended solids in the overflow discharge.
Recirculating bottom ash sluicing systems, by reducing the
waste water discharge from sedimentation facilities such as
ash ponds, therby result in the reduction of bottom ash
total suspended solids in the discharge. In some cases,
where both bottom ash and fly ash are settled in the same
ash pond and water is recirculated for bottom ash sluicing,
further clarification treatment of the final combined
overflow from the pond to achieve effluent limitations based
as a model on separate ash ponds, would result in suspended
solids removals comparable to these attained by separate
recirculating bottom ash systems.
Chemical treatment of metal equipment cleaning waste waters
would result in significant removals of copper, iron, and
other metals. Average concentrations of copper and iron in
boiler tube cleaning waste water, where these data were
available and where chemical treatment would be needed to
achieve effluent concentrations of 1 mg/1 each for copper
and iron were as follows: 206 mg/1 copper and 1,286 mg/1
iron. Chemical treatment to achieve the above effluent
limitations would remove virtually of the copper and iron in
the untreated boiler tube cleaning waste water, in these
cases.
In It cases where data on cooling tower blowdown were
available, chemical treatment for chromium, phosphorus, and
zinc removal would not be required in all but 2 cases. In
one case, a zinc concentration of 3 mg/1 was reported and a
phosphorus (as P) concentration of 17.7 mg/1 was reported.
This is reflective of the general adequacy of simple pH
adjustment rather than the use of corrosion inhibitors to
control corrosion rate below 3 mils per year. Generally
corrosion inhibitors would be needed only for cooling tower
service with high chloride concentrations in the
345
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recirculating water.389,***. In cases where chemical
addition of chromium, phosphorus, or zinc would be employed
for corrosion inhibition, typical maximum concentrations in
cooling tower blowdown would be as follows:
30 mg/1 CrOU
15 mg/1 Zn
30 mg/1 PO4
Substantial reduction in the discharge of these pollutant
parameters would be obtained in cases where effluent
treatment were needed.
Effluent reduction benefits of the control of free available
chlorine and total residual chlorine in cooling water would
be significant due to the large volume of cooling water used
by this industry, about HQ trillion gallons per year which
is roughly 10 percent of the total flow of water in U.S.
rivers and streams per year, **3 and because of the
widespread use of chlorine addition to cooling water (24,642
tons in 1970233) used by this industry.
Summary
Table A-VII-21 provides a summary of the control and
treatment technology for the various waste streams. The
table includes the effluent reduction achievable with each
alternative, the usage in the steam electric powerplant
industry and approximately capital and operating costs.
Table A-VII-22 summarizes flow data for chemical wastes,
indicating the range of values from reported data and
typical flows or volumes for each chemical waste stream.
The costs of the application of various control and
treatment technologies in relation to the effluent reduction
benefits to be achieved are given in Table A-VII-23 for
large volume waste streams. Table A-VII-2U for intermediate
volume waste streams. Table A-VII-25 for low volume waste
streams, and Table A-VII-26 for rainfall waste streams.
346
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TABLE M-VII-21
CHEMICAL WASTES
CONTROL & TREATMENT TECHNOLOGY
Control and/or
Treatment
Pollutant Parameter Technology
Common:
pH Neutralization
with chemicals
Dissolved Solids 1.
2.
3.
Suspended Solids 1.
2.
3.
Specific:
Phosphate 1 .
(Slowdown, Chemical
Cleaning, Floor &
Yard Drains, Plant
Laboratory s Sampling)
2.
Iron 1 .
Chemical Cleaning
Coal Ash Handling,
Coal Pile Drainage) 2.
Copper 1.
(Once-through
Condenser Cooling)
Copper 1 .
(Slowdown, Chemical
Cleaning)
2.
3.
Mercury 1.
(Coal Ash Handling
s Coal Pile Drainage)
2.
3.
Vanadium !•
(Chemical Cleaning)
2.
Vanadium 1.
(Oil Ash Handling)
2.
Concentration and
evaporation
Reverse Osmosis
Distillation
Sedimentation
Chemical Coagulation
and Precipitation
Filtration
Chemical coagulation
and Precipitation
Deep Well Disposal
Oxidation, chemical
coagulation &
precipitation
Deep Well Disposal
Replace condenser
tubes with stain-
less steel or
Titanium.
Chemical Coagulation
and Precipitation
Ion Exchange
Deep Well Disposal
Reduction & Precip-
itation
Ion Exchange
Adsorption
H S Treatment & .
Precipitation ^ •
Ion Exchange /
Convert to Dry
Collection
Total Recycle with
Slowdown s Pre-
Effluent
Reduction
Achievable
Neutral pH
Complete Removal
50-95*
60-90%
90-95%
95-99%
95%
Industry Costs
Usage Capital Operating
Common 510-20,000 (tanks, • $3-30,000 (Chemicals,
feeder, etc.) labor, etc.)
Not generally $250,000-51,660,000 $150,000-$450,000
in use - De- from Table A-VIII-5 ; from Table A-VIII-6;
salinization costs are signifir costs are significantly
technology cantly less in areas less in areas where
where evaporation evaporation ponds are
ponds are feasible, feasible.
Not in use - SO-SO C/1000 gal.
Desalinization total cost.
technology.
Not in use - 80-150 C/1000 gal.
Desalinization total cost.
technology.
Extensive $1000-S20,000 1-20C/1000 gallons
Mw
based on 500 gpd /Mw
Moderate 5 10, 000-$ 35 ,000 1-20C/1000 gallons
Mw
based on 500 gpd /Mw
Not generally $7 ,000-$30,000 1-20C/1000 gallons
practiced-water Mw
treatment based on 500 gpd / Mw
technology.
Not generally $io,000-$35 ,000 1-200/1000 gallons
practiced-water j.;w
treatment ^sea on 500 gpd /f;w
technology.
Ultimate Disposal Not practiced Costs extremely variable-dependent
primarily on geologic conditions.
removal to
0.1 mg/1
Elimination of
discharge .
Removal to
0.1 mg/1
Removal to
0.1 mg/1
Removal to
0.3 mg/1
Removal to
0.1 mg/1
Removal to
50 Mg/1
Removal of low
concentrations
difficult to
achieve
Ultimate
Disposal
Complete recycle
of liquid
Limited usage $150-4, OOOxlOJ 10-lOOc/lOOO gal.
Done in several Prohibitively No incremental
plants where tubes expensive-would operating cost.
have erroded or not be done except
corroded-not done where retubing is
for environmental required for process
reasons. reasons.
Limited usage $100-$9, 000/1000 10-350C/1000 gal.
gpd capacity
Not Practiced $400-$1200/1000 31-81C/1000 gal.
gpd capacity
s escri e a ove
Limited usage $700/1000 gpd 7«-27*/1000 gal.
Not practiced $18,000-$22,000/ $1/1000 gal.
1000 gpd
Not practiced $5000-$50,000/ $0.50-$2/lb.
1000 gpd mercury removed
Not practiced Cost Data Not Available
Not practiced Cost Data Not Available
Practiced in Cost Data Not Available
several plants
Not generally Cost Data Not Available
practiced
cipitation
347
-------
Table A-VII-21
CHEMICAL WASTES
CONTROL & TREATMENT TECHNOLOGY (continued)
Pollutant Parameter
Chlorine
(Once-through Con-
denser Cooling)
Control and/or
Treatment
Technology
1. Control of Residual
Cl with automatic
instrumentat ion
2. utilize mechanical
Effluent
Redact ion
Achievable
Control to
0.2 mg/1
Eliminates
Industry
Usage
Limited usage in
the industry-
Technology from
sewage treatment
practiced in some
Costs
Capital
$5,000
No Cost Data
Operating
Negligible
Available
cleaning
Cl discharge plants-all systems
are not capable of
being converted to
mechanical cleaning.
Chlorine
(Recirculating)
1. Control of Residual
Cl with automatic
instrumentat ion
-As described above-
2. Reduction of Cl
with sodium
bisulfite
Below detect- Being installed in
able limits a new nuclear
facility,-however
Data Available
Aluminum/Zinc 1.
(Water Treatment,
Chemical cleaning,
Coal Ash Handling, 2.
Coal Pile Drainage)
3.
Oil 1.
(Chemical cleaning,
Ash Handling, Floor
s Yard Drains)
2.
Phenols 1.
(Ssh Handling, Coal
Pile Drainage, Floor
s Yard Drains) 2.
3.
Chemical Precip-
itation
Ion Exchange
Deep Well Disposal -
Oil-water Separator
(Sedimentation
with skimming)
Air Flotation
Biological
Treatment
Ozone Treatment
Activated Carbon
Removal to
1.0 mg/1
Similar to
excess NaHSO is
discharged.
Limited usage $500-53000/1000 gpd 10-180C/1000 gal.
Copper
As described above .
Removal to
15 mg/1
Removal to
10 mg/1
Removal to
1 mg/1
Removal to
< 0.01 mg/1
Removal to
< 0.01 mg/1
Common usage $1,500-$ 15 ,000 No data
based on 500 gal/Mw
25-400 Mw range
Limited usage $5,000-$50,000 No data
N-^t practical $130- $2800/1000 gpd 22C/1009 gal.
in the industry.
Not practiced No data No data
in the industry.
Not practiced $50-$350/1000 gpd 4C-15«/1000 gal.
in the industry.
Sulfate/Sulfite
(Water Treatment,
Chemical cleaning.
Ash Handling, Coal
Pile Drainage, SO
Remova 1)
Ion Exchange(Sulfate)
Oxidation s Ion
Exchange (Sulfite)
75-95%
Not practiced Total cost of $2.00/1000 gal.
in the industry.
Ammonia
(Water Treatment,
Slowdown, chemical
Cleaning, Closed
1. Stripping
50-90%
Not practiced;
several installa-
tions in sewage
treatment
Total cost
- 3C/1000 gal.
Cooling Water Systems)
Oxidizing Agents
(Chemical Cleaning)
BOD/COD
(Sanitary Wastes)
COD (Water Treatment
Chemical cleaning)
Fluoride
(Chemical Cleaning)
2. Biological
Nitrification
3. Ion Exchange
Neutralization with
reducing agent and
precipitation where
necessary.
Biological Treatment
,1. chemical Oxidation
2. Aeration
3. Biological Treat.
Chemical Precipitation
Removal to
2 mg/1
80-95%
Neutral pH &
>95% removal
85-95%
85-95%
85-95%
85-95%
Removal to
1 mg/1
Not practiced for
these waste streams
Not practiced
Limited usage
Common practice
Limited usage
Not practiced
Not practiced
Limited usage
No
Total cost.
No
$25,000-$35
No
No
No
Total cost
Data
- IOC/1000
Data
,000
Data
Data
Data
Available
gal.
Available
Negligible
Available
Ava ilable
Available
- 10-50C/1000 gal.
Boron Ion Exchange
(Low Level Radwastes)
Removal to Not generally
1 mg/1 practiced-radio-
active material would
concentrate on ion
exchange resin requir-
ing inclusion in solid
348 radwaste disposal
system.
Available
-------
TABLE A-VII-22
FLOW RATES-CHEMICAL WASTES
Waste Stream
Reported Data
Waste Flow or Volume
Frequency
Typical
Flow or Volume
Basis
Remarks
Condenser Cooling Water
Once-Through
Recirculating
Water Treatment
Clarification
Softening
Ion Exchange
20-7200 x 10 GPD
No Discharge
No Discharge,
1-533,00 x 10 GPD
Evaporator
Boiler Slowdown
Chemical Cleaning
Boiler Tubes
Boiler Fireside
Air Preheater
Misc. Small Equip.
Stack
Cooling Tower Basin
Ash Handling
Dra*inage
Coal pile
0.1-1060 X 10J GPD
0.05-1120 X 10 GPD
3-5 Boiler Volumes
24-720 x 10J GAL.
43-600 x 103 GAL.
No reported data
No reported data
No reported data
5-32,000 x 103 GPD
17-27 x 10 GAL/YR.
Floor & Yard Drains No reported data
Air Pollution Control No Discharge
Devices
Misc. Haste Streams
Sanitary Wastes No reported data
Plant Laboratory and No reported data
Sampling
Intake Screen Backwash No reported data
Closed Cooling Systems No reported data
Low Level Rad Wastes Mo reported data
Construction Activity No reported data
500-1500 GPM/Hu
Varies from 0.3% to 4% of
curculatlng water flow.
52-365
cycles/yr.
300-365
cycles/yr.
25-365
cycles/yr.
once/7 mos.- 1 boiler vol.per
once/100 mos. 1-2 hrs.-Boiler
draindown time.
2-8/yr. 300,000 GAL.
Flow reported in PPC
Form 67.
Slowdown depends on water
quality and varies from
2-20 concentrations.
Extremely variable-
depending on raw water
quality.
Extremely variable-
depending on raw water
quality.
Flow reported in FPC
Form 67.
4-12/yr.
200,000 GAL.
Frequency-once
per 24-30 mos.
5/yr.
6-12/yr.
Dependent
on rainfall
Reported data
based on 43-60
inches of rain
year.
Cleaned infrequently
Cleaned infrequently
Overflow from as!; ponds
reported in FPC Form 67.
Flow dependent upon
frequency, duration and
intensity of rainfall
Flow dependent upon fre-
quency & duration of
cleaning and stormwater
runoff.
25-35 gal/capita/ Personnel:
day operators-1 per 20-40 N"
maintenance-1 per 10-15 M»
administrative-1 per 15-25
5 gal./day
Nominal, variable flow
Guideline requires col-
lection S removal of
debris-flow data not
significant.
Flow extremely vari-
able depending on treat-
ment techniques, leakage,
etc.
Flow depends primarily
on rainfall.
-------
Table A-VII-Z3
COSTS/EFFLUENT REDUCTION BENEFITS
CONTROL AND TREATMENT TECHNOLOGY FOR POLLUTANTS OTHER THAN HEAT
HIGH VOLUME WASTE STREAMS-
Waste Stream: Nonrecirculating main condenser cooling water
Pollutant / Technology
Cost / Effluent Reduction Benefit,
concentration
CO
en
o
Chlorine-free available
Uncontrolled addition(S)
Controlled addition(S) less than
Shutdown mechanical cleaning(S)
On-line mechanical cleaning (S)
Chemical addition treatment*(N)
Alternative biocide use*(N)
Copper
Present system(C)
Alternative condenser
tubs material(S)*
One-stage chemical treatment (N)
Base
0.01/2
0.01/approaching 0
0.01/approaching 0
for existing units
less than 0.01/approaching 0
for new units
Prohibitive
Unknown
Base
Prohibitive for existing
units
0.01/0 for new units
Prohibitive
Meaning of C = commonly employed
Symbols CT = currently transferrable
PT = potentially transferrable
N
S
*
net luiown to be practiced
sonm usage
i:,ay substitute one pollutant
for another
-------
Table A-VII-24
COSTS/EFFLUENT REDUCTION BENEFITS
CONTROL AND TREATMENT TECHNOLOGY FOR POLLUTANTS OTHER THAN HEAT
-INTERMEDIATE VOLUME WASTE STREAMS-
Waste Streamsi Slowdown from recirculating main condenser cooling water systems
Nonrecirculating ash sluicing water
Nonrecirculating wet-scrubber air pollution control systems
Nonrecirculating house service water
Pollutant / Technology
Chlorine-free available
Uncontrolled addition(S)
Controlled addition(S)
Shutdown mechanical cleaning(S)
On-line mechanical cleaning(S)
Chemical addition treatment*(S)
Alternative biocide use*(N)
Copper-total
Present system(C)
Alternative condenser
tube material(S)*
One-stage chemical treatment(N)
Chemical Additives
Uncontrolled addition(S)
Controlled addition(S)
Chemical substitution*(S)
Design for corrosion protection(C)
Mercury-total
Present system(C)
One-stage chemical treatment(CT)
Fuel substitution(N)
Oil and Grease
Present system(C)
One-stage separation(S)
Two-stage separation(CT)
Total Phosphorus (as P)
Present system (S)
One-stage chemical treatment(CT)
Chemical treatment
with filtration(CT)
Chemical substitution (PT)
pH Value
Present system(C)
Coneutralization(C)
Chemical addition (6)
Total Suspended Solids
Present system(C)
Conventional solids separation(C)
Fine solids separation(CT)
Dry ash handling system(S)
Total Dissolved Solids
Present system(N)
Brine concentration(CT)
ChromiUM-total
^"Present system (S)
Chemical treatment (CT)
Chemical substitution (PT)
Zinc-total
Present system (S)
Chemical treatment (CT)
Chemical substitution (PT)
Cost / Effluent Reduction Benefit,
[mill/** j / C«g/i]ef£luflnt concentratio:
Base
less than 0.01/2
0.01/approaching 0
0.01/approaching 0
for existing units
less than 0.01/approaching 0
for new units
0.01/approaching 0
Unknown
Base
Prohibitive
for existing units
0.01/0 for new units
0.03/1
Base
Better than base
Unknown
Costly for existing
closed coaling
systems
less than 0.01/approaching 0
for new systems
Base
Unknown/0.3
Unknown
Base
0.01/10
0.02/8
Base
0.03/5
0.05/less than 5
Unknown
Base
less than 0.01
less than 0.01
Base
0.01/15
Prohibitive
0.01/sign. red.
Base
Prohibitive
Base
(?1/1000 gal)/0.2
Unknown
Base
0.05/1
Unknown
Meaning of C = commonly employed N
Symbols CT = currently transferrable S
PT = potentially transferrable *
not known to be practiced
some usage
may substitute one pollutant
for another
351
-------
Table A-Vtl- 25
COSTS/EFFLUENT REDUCTION BENEFITS
CONTROL AND TREATMENT TECHNOLOGY FOR POLLUTANTS OTHER THAN HEAT
-LOW VOLUME WASTE STREAMS-
Waste Streamsi Blowdown from recirculating ash-sluicing systems
Slowdown form recirculating wet-scrubber air
pollution control systems
Boiler blowdown
Cooling tower basin cleanings
Floor drainage
Intake screen backwash
Laboratory and sampling streams
Low-level radwastes*
Miscellaneous equipment cleaning
- Air preheater
- Boiler fireside
- Boiler tubes
- Small equipment
- Stack, etc.
Sanitary system
Service and small cooling water systems blowdown, etc.
Water treatment
Technology / Pollutant
Cost / Effluent Reduction Benefit,
[mill/kwh] , [mg/1] „, ,_ .
' y effluent concentration
Present System(C)
One-Stage Chemical Treatment(S)
Copper-total
Iron-total
Heavy metals in general
Oil and grease
pH value
Numerous misc. parameters
Two-Stage Chemical Treatment(CT)
Chromium-total
Copper-total
Iron-total
Heavy metals in general
Oil and grease
pH value
Total suspended solids
Numerous misc. parameters
Brine Concentration and Recycle(PT)
All parameters
Biological Treatment(C)
BOD, etc.
Base
0.05 mill/kwh
10 mg/1
10 mg/1
10 mg/1
1.0 IK-/'
6.0 tc -. . 0
13 uiy/1
significant reductions
0.1 mill/kwh
0.5
0.2 mg/1
1 mg/1
1 mg/1
1 mg/1
< 10 mg/1
6.0 to 9.0
15 mg/1
significant reductions
mill/ kwh
no discharge
0.01 mill/kwh
municipal stds.
Meaning of C = commonly employed
Symbols CT = currently transferrable
PT = potentially transferrable
N = not known to be practiced
S = some usage
* = no applicable technology due to
possible radiation hazards
352
-------
Table A-VII- 26
COSTS/EFFLUENT REDUCTION BENEFITS
CONTROL AND TREATMENT TECHNOLOGY FOR POLLUTANTS OTHER THAN HEAT
-RAINFALL RUNOFF WASTE STREAMS-
Waste Streams:
Coal-pile drainage
Yard and roof drainage
Construction activities
Technology / Pollutant
Cost / Effluent Reduction Benefit,
[mill/kwh ] , [mg/1 ] ,..- . . . .
' ' ^ effluent concentration
CO
Ul
CO
Present System(C)
Conventional Solids Separation(S)
Oil and grease
pH value /
Total suspended solids.
One-Stage Chemical Treatment of
Polluted Portions of Runoff (CT)
Oil and grease
pH value
Total suspended solids
Numerous misc. parameters
One-Stage Chemical Treatment of
Entire Runoff(N)
Two-Stage Chemical Treatment(N)
Base
OoOl mill/kwh
no reduction
no change
15 mg/1
0.01 mill/kvrti
10 mg/1
6.0 to 9.0
15 mg/1
significant reductions
unknown
unknown
Meaning of
Symbols
C = commonly employed
CT = currently transferrable
PT = potentially transferrable
N = not known to be practiced
S = some usage
-------
PART A
CHEMICAL WASTES
SECTION VIII
COST, ENERGY AND NON-WATER QUALITY ASPECTS
Irvtroduct ion
This section discusses cost estimates for the control and
treatment technology discussed in the previous section,
energy requirements for this treatment technology and non-
water quality related aspects of this technology such as
recovery of byproducts, ultimate disposal of brines and
sludges, and effects on the overall energy situation.
The estimates contained herein assume ample availability of
land. It is recognized that powerplants located in highly
developed urban areas may incur costs several times in
excess of those shown, other assumptions include no unusual
foundation or site preparation problems. Estimates do not
consider regional differences in construction costs.
Due to the wide range of water volumes required from plant
to plant for the individual unit operations involved, and
further, due to the wide range (frcm plant to plant) of
costs per unit volume of water treated, which are further
related to the effluent reductions obtained, the costs vary
widely for the removal of specific pollutants to various
degrees. For example, boiler fireside chemical cleaning
volumes vary from 24,000 gal to 720,000 gal per cleaning,
with cleaning frequencies ranging from 2 to 8 times per
year. The operating costs of chemical precipitation
treatment for copper and iron removal to 1 mg/1 effluent
concentration and for chromium removal to an effluent of 0.2
mg/1 range from $0.10 to $1.30/1000 gal. Furthermore, there
are approximately 10 or more separate unit operations which
are sources of waste water at power generating plants, each
with its station-specific flow rate and waste water
characteristics, as well as cost peculiarities.
Site-related factors concerning the practicability of
various re-use practices make these .practices even more
difficult to cost, due to the added complexities involved.
355
-------
Central Treatment Plant Costs
Although powerplants produce many different wastewater
streams with different pollutants and different flow
characteristics, the most feasible concept of treatment
consists of the combination of all compatible wastewater
streams, with equalization or holding tanks to equalize the
flow through the treatment units. Figure A-VIII-1 shows a
typical flow diagram for a possible central treatment plant
for coal-fired powerplants.
Wastewater treatment facilities for treating chemical wastes
therefore consist essentially of a series of tanks and
pumps, and interconnecting piping: special equipment such
as pressure filters, vacuum filters, centrifuges, or
incinerators as may be required. Tanks serve for several
purposes, as equalization tanks to permit the following
units to operate under constant flow conditions, as
neutralization tanks to adjust acidity or alkalinity, or as
coagulation and precipitation tanks to provide for mixing of
a coagulant, the formation of the precipitates and the
separation of the precipitates from the treated flow. In
most cases, the mechanical equipment inside the tank is a
minor cost consideration, although in the case of certain
types of tanks used for softening and similar reactions the
equipment cost may be significant. Chemical feeders may be
of the dry volumetric type or of the solution type. In
either case, the cost of the feeder is likely to be minor,
although costs of associated equipment for the storage of
chemicals is often significant. A substantial amount of
data is available on chemical feeders.
Cost curves are given in Figures A-VIII-2, 3 for the
principle items of equipment required for the treatment of
chemical type waste water.
A cost analysis is based on a central treatment plant as
shown in Figure A-VIII-1 for all low-'-olume waste waters
containing chemical pollutants. The design flows assumed
for this plant are given in the figure. The estimated
equipment sizes and costs for central treatment plants
corresponding to 100 Mw and 1,000 Mw coal-fired plants, oil-
fired plants, gas-fired plants and nuclear plants are given
in Tables A-VIII-1, 2, 3 and 4 respectively. Total capital
costs for these plants, including equipment, installation,
construction, engineering and contingency costs, are given
in Tables A-VIII-5, 6, 7 and 8 respectively. Capital costs
for plants of capacities other than 100 and 1,000 Mw can be
estimated from Figure A-VIII-U. Annual costs, including
fixed changes against capital and operating and maintenance
costs are given in Tables A-VIII-9, 10, 11 and 12. Cost for
labor, chemicals and power are based on the cost versus
356
-------
CO
CP
—I
Figure A-VIII-1
FLOW SHEET - COAL FIRED PLANT CENTRAL TREATMENT PLANT
BOILER TUBE
EQUIPMENT CLEANINGS
90 gal/mw
(0.25 gpd/mw)
BOILER FIRESIDE
800 gal/mw
(4.44 gpd/mw)
AIR PREHEATER
700 gal/mw
(11. 7 gpd/mw)
MISC, 210 gal/mw
EQUALIZATION
TANK41
1800 gal/mw
(1.17 gpd/mw)
ION EXCHANGE
88 gpd/mw
LABORATORY WASTES
10 gpd/mw
COOLING TOWER
BASIN WASHING
(210 gal/mw)
1.17 gpd/mw
RECIRCULATING
SCRUBBER 20 gpd/mw
BOILER BLOWDOWN
52 gpd/mw
FLOOR DRAINS
30 gpd/mw
LIME 7.2 x 10~4-!-b
gal
(0.013 Ib/day/mw)
18 gal/mw
pH=3 (assume)
REACTOR
(0.8 gal/mw)
1 HR. DETENTION
pH 8.5
172 gpd/mw
FLOCCULANTS
1lb/1000 gal
(0.13lb/day/mw)
DISCHARGE TO
RECEIVING WATERS
1% SLURRY
20LB/DAY/MW
(3.0 gpd/mw)
30 gpd/mw
SLUDGE
(0.2 Ib/day/mw)
-------
1,000
oo
en
en
M
m
rH
O
W
•g
fl
(0
3
O
^
+J
-P
CO
O
U
3
s
100
10
1 10 100 1,000 10,000
Capacity, thousands of gallons
Figure A-VIII-2 Costs of Equalization Tanks and Oil Removal Tanks
-------
1,000
10
en
10
n
CTl
iH
05
to
•H
H
O
Tf
4-1
O
w
'O
n)
0)
CO
O
O
-P
C
I
•H
w
100 •--
10
,- ";-..- "i ij i"r'" •; n~T~i'"
r-^jT-ir-iTi!-! :n-
Figure A-VIII-3
1 10 100 1,000
Capacity, thousands of gallons per day
Costs of Clarifiers, Reactor Systems, and Filters
-------
Table A-VIII-1
Estimated Equipment Costs
Central Treatment Plant for Coal-Fired Powerplants
Description
Equalization Tank No.l (gal)
No. 2
No. 3
Oil Removal- Tank No.l (gal)
No. 2
Reactor System (GPD)
Clarifier (GPD)
' Filter* (GPD)
Pumps and Piping
Major Equipment Cost
100 Mw
Size/Capacity
180,000
38,000
3,000
1,800
3,000
1,800
22,000
300
-
$ (1000)
38
12
1.7
3.5
4.5
2.7
7
1
10.9
81.3
1000 Mw
Size/Capacity
1,800,000
380,000
30,000
18,000
30,000
18,000
220,000
3,000
-
$ (1000)
111
65
10
9.5
12.5
4.5
22
10
20.2
264.7
co
-------
Table A-VIII-2
Estimated Equipment Costs
Central Treatment Plant for Oil-Fired Powerplants
Description
Equalization Tank No.l (gal)
No. 2
No. 3
Oil Removal Tank No.l (gal)
No. 2
Reactor System (GPD)
Clarifier (GPD)
Filter* (GPD)
Pumps and Piping
Major Equipment Cost
100 Mw
Size/Capacity
180,000
38,000
1,500
1,800
1,500
1,800
20,500
300
$(1000)
38
12
1
3.5
3.3
2.7
6.8
1
10.9
79.2
1000 Hw
Size/Capacity
1,800,000
380,000
15,000
18,000
15,000
18,000
205,000
3,000
i
$(1000)
111
65
5.8
9.5
8.6
4.5
21
10
20.2
255.6
oo
en
* Note: 5 gpm/ft2 and $265/ft2 (UWAG study page 11-24)
-------
Table A-VIII-3
Estimated Equipment Costs
Central Treatment Plant for Gas-Fired Powerplants
Description
Equalization Tank No.l (gal)
No. 2
Reactor System (GPD)
Clarifier (GPD)
Filter* (GPD)
Pumps and Piping **
Major Equipment Cost
100 Mw
Size/Capacity
30,000
36,000
142
15,300
210
$ (1000)
10
11
1.5
5.8
1
5.5
34.8
1000 1'iw
Size/Capacity
300,000
360,000
1,420
153,000
2,100
,
$ (1000)
55
62
2.6
18
7
10.1
154.7
co
cr>
ro
* Note: 5 gpm/ft2 and $265/ft2 (UWAG study page 11-24)
** Note: Assumed to be 50% of the size for the corresponding coal-fired case
-------
Table A-VIII-4
Estimated Equipment Costs
Central Treatment Plant for Nuclear Powerplants
Description
Equalization Tank No.l (gal)
Reactor System (GPD)
Clarifier (GPD)
Filter* (GPD)
Pumps and Piping **
Major Equipment Cost
100 Mw
Size/Capacity
21,000
36,000
142
15,300
210
$(1000)
7.2
11
1.5
5.8
1
5.5
32
1000 Mw
Size/Capacity
210,000
360,000
1,420
153,000
2,100
.
$(1000)
41
62
2.6
18
7
10.1
140.7
co
01
co
* Note: 5 gpm/ft2 and $265/ft2 (IWAG study page 11-24)
** Note: Assumed to be 50% of the size for the corresponding coal-fired case
-------
Table A-VIII-5
Estimated Total Capital Costs
Central Treatment Plant for Coal-Fired Powerplants
Item
Major Equipment Cost
Installation Cost
@ 50% for new sources
@ 100% for retrofit
Instrumentation
d> 20%
Construction Cost
Engineering
@ 15%
Contingency
@> 15%
Total Capital Cost
($/kw)
100 Mw
Retrofit
$(1000)
81,3
81.3
16.3
178.9
26.8
26.8
232.5
(2.33)
New Sources
$(1000)
81.3
40.7
16,3
138.3
20.8
20.8
179.9
(1.80)
1000 Mw
Retrofit
$(1000)
264.7
264.7
52.9
582.3
87.3
87.3
756.9
(0.76)
New Sources
$(1000)
264.7
132.4
52.9
450.0
67.5
76.5
585.0
(0.59)
CO
O!
-------
Table A-VIII-6
Estimated Total Capital Costs
Central Treatment Plant for Oil-Fired Powerplants
Item
Major Equipment Cost
Installation Cost
@ 50% for new sources
@ 100% for retrofit
Instrumentation
d> 20%
Construction Cost
Engineering
@ 15%
Contingency
@ 15%
Total Capital Cost
(£/kw)
loor-v
Retrofit
$ (1000)
79.2
79.2
15.8
174,2 '
26.2
26.2
226,6
(2.27)
New Sources
$ (1000)
79.2
39.6
15.8
134.5
20,2
20.2
175.0
(1.75)
1000 Mw
Retrofit
$(1000)
255.6
255.6
51.2
562.4
84,4
84.4
731.2
(0.73)
New Sources
$(1000)
255.6
127.8
51.2
434.6
65.3
65.3
565.2
(0.57)
CO
-------
Table A-VIII-7
Estimated Total Capital Costs
Central Treatment Plant for Gas-Fired Powerplants
Item
Major Equipment Cost
Installation Cost
@ 50% for new sources
f> 100% for retrofit
Instrumentation
@ 20%
Construction Cost
Engineering
d> 15%
Contingency
@ 15%
Total Capital Cost
($Aw)
100 IV
Retrofit
$ (1000)
34.8
34.8
7.0
76.6
15.3
15.3
107.2
(1.07)
New Sources
$(1000)
34.8
• 17.4
7.0
59.2
8.9
8.9
77.0
(0.77)
1000 MM
Retrofit
$(1000)
154.7
154.7
30.9
340.3
51.1
51.1
442.5
(0.44)
New Source^
$(1000)
154.7
77.4
30.9
263.0
39.5
39.5
342.0
(0.34)
er>
-------
Table A-VIII-8
Estimated Total Capital Costs
Central Treatment Plant for Nuclear Powerplants
Item
Major Equipment Cost
Installation Cost
d> 50% for new sources
@ 100% for retrofit
Instrumentation
@ 20%
Construction Cost
Engineering
@ 15%
Contingency
@ 15%
Total Capital Cost
($/ kw)
100 Mw
Retrofit
$(1000)
32.0
32.0
6.4
70.4
10.6
10.6
91.6
(0.92)
New Sources
$ (1000)
32.0
16.0
6.4
54.4
8.1
8.1
70.6
(0.71)
1000 Mw
Retrofit
$(1000)
140.7
140.7
28.1
309.5
46.5
46.5
402.5
(0.40)
New Sources
$(1000)
140.7
70.4
28.1
239.2
35.8
35.8
310.8
(0.31)
co
er>
-------
n
r»
CTi
CO
M
<0
H
H
O
T>
M-l
O
CO
•a
m
CO
3
O
CO
O
U
m
.p
-H
ft
(0
n)
4J
O
0)
-P
-H
-P
CO
W
10,000
1,000
100
10
-.--•
ii:_i RaKk- " ! i ;! :H' i-:. i
_'_—;--Goai-f:iried:-- ' '
Ex i st i ng Pi a nt s
Plants
10,000
10 100 1,000
Plant Generating Capacity, megawatts
Figure A-VIII-4 Estimated Total Capital Costs of Central
Treatment Plants
368
-------
Table A- VIII-9
Estimated Annual Costs
Central Treatment Plant for Coal-Fired Powerplants*
Item
Construction Cost (CC)
Total Capital Cost (TCC)
Maintenance @ 3% of CC
Fixed Charges @ 15% of TCC
Chemicals and Power '
Labor
Total Annual Cost
Unit Cost, mills/kwh
Base-load (0.77 capacity factor)^
Cyclic (0.44 capacity f actor )#
Peaking (0.09 capacity f actor )#
100 jy
Retrofit
.5 (1000)
178.9
232.5
5.4
34.9
4.2
100.0
144.5
0.214
0.375
1.84
Iw
New Sources
$ (1000)
138.3
179.9
4.1
27.0
4.2
100.0
135.3
0.201
0.353
1.72
1000 i
Retrofit
$ (1000)
582.3
756.9
17.5
113.5
38.0
190.0
359.0
0.055
0.096
0.467
4W
New Sources
$ (1000)
450.0
585.0
13.5
87.7
38.0
190.0
329.2
0.049
0.086
0.422
CO
vo
* Note: Flow basis is 220
# Note: Assumes full costs of maintenance, chemicals, power, and labor.
These costs would actually be less than shown and would reflect the
extent of utilization of the plant.
-------
Table A-VIII-10
Estimated Annual Costs
Central Treatment Plant for Oil-Fired Powerplants*
Item
i
! Construction Cost (CC)
!
1 Total Capital Cost (TCC)
i Maintenance @ 3% of CC
; Fixed Charges @ 15% of TCC
Chemicals and Power
Labor
Total Annual Cost
Unit Cost, mills/kwh-
Base-load (0.77 capacity factor)*
Cyclic (0.44 capacity factor) #
Peaking (0.09 capacity factor) #
100 1
Retrofit
$ (1000)
174.2
226.6
5.3
34.0
4.0
98.0
141.3
0.211
0.369
1.80
^w
New Sources
$ (1000)
134.5
175.0
4.0
27.2
4.0
98.0
133.2
0.198
0.346
1.69
1000
Retrofit
$ (1000)
562.4
731.2
16.9
109.7
36.0
185.0
347.6
0.052
0.091
0.445
DJw
New Sources
$ (1000)
434.6
565.2
13.0
84.8
36.0
185.0
318.8
0.047
0.082
0.400
CO
•>J
o
* Note: Flow basis is 205 GPD/Mw
# Note: Assumes full costs of maintenance, chemicals, power, and labor.
These costs would actually be less than shown and would reflect the
extent of utilization of the plant.
-------
Table A-VIII-11
Estimated Annual Costs
Central.Treatment Plant for Gas-Fired Powerplants*
CO
•~J
Item
Construction Cost (CC)
Total Capital Cost (TCC)
Maintenance @ 3% of CC
Fixed Charges @ 15% of TCC
Chemicals and Power
Labor
. .
Total Annual Cost
Unit Cost, mills/kwh
Base-load (0.77 capacity factor) #
Cyclic (0.44 capacity factor) #
Peaking (0.09 capacity factor) #
100 rte
Retrofit
$ (1000)
76.6
107.2
2.3
16.1
3.0
90.9
111.4
0.165
0.289
1.41
New Sources
$ (1000)
59.2
77.0
1.8
11.5
3.0
90.0
106.3
0.159
0.277
1.36
1000 IV
Retrofit
$ (1000)
340.3
442.5
10.2
66.4
28.0
175.0
279.6
0.042
0.073
0.356
New Sources
$ (1000)
263.0
342.0
7.9
51.3
28.0
175.0
262.2
0.039
0.068
0.335
* Note: Flow basis is 155 GPD/Mw.
# Note: Assumes full annual costs of maintenance, chemicals, power, and labor.
These costs would actually be less than shown and would reflect the
extent of utilization of the plant.
-------
CO
^J
ro
Table A-VIII-12
Estimated Annual Costs
Central Treatment Plant for Nuclear Powerplants*
Item
Construction Cost (CC)
Total Capital Cost (TCC)
Maintenance @ 3% of CC
Fixed Charges @ 15% of TCC
Chemicals and Power
Labor
Total Annual Cost
Unit Cost, mills/kwh
Base-load (0.77 capacity factor )H=
Cyclic (0.44 capacity factor) #
Peaking (0.09 capacity factor) #
100 I
Retrofit
$ (1000)
70.4
91.6
2.1
13.8
3.0
90.0
108.9
0.162
0.284
1.39
8-.'
New Sources
$ (1000)
54.4
70.6
1.6
10.6
3.0
90.0
105.2
0.156
0.273
1.33
100C f.
Retrofit
$ (1000)
309.5
402.5
9.3
60.4
28.0
175.0
272.7
0.040
0.070
0.345
IW
New Sources
$ (1000)
239.2
310.8
7.2
46.7
28.0
175.0
256.9
0.038
0.066
0.322
* Note: Flow basis is 155 GPD/Mw
# Note: Assumes full annual costs of maintenance/ chemicals, power, and labor.
These costs would actually be less than shown and would reflect the
extent of utilization of the plant.
-------
capacity functions shown in Figure A-VIII-5, which in turn
are based on the following units cost:
Operations Labor $20,000/man-year
Lime $27/ton
Flocculant $0.05/lb
Electricity 12 mills/kwh
Costs for Wastes Not Treated at Central Treatment Plant
The following wastes are not considered suitable for treat-
ment at a central treatment plant for chemical wastes:
Cooling water (once-through system), cooling water blowdown
(closed system), sanitary wastes, roof and yard drains, coal
pile runoff, intake screen backwash, radwastes,
nonrecirculating ash sluice water, nonrecirculating wet-
scrubbing air pollution control waste water, once-through
(nonrecirculating) house service water. Recirculating
bottom ash sluicing water blowdown is considered separately
although incorporation in the central treatment plant may be
feasible in some instances.
Cooling Water-Once Through Systems
The treatment technology for once-through condenser cooling
water systems consists of maintaining the residual chlorine
in the effluent below an established limit by controlling
the chlorine added to the system. The capital costs
involved consist of the cost of a residual chlorine analyzer
and feedback controls to adjust the feed rate. The
installed cost of a residual chlorine analyzer and control
equipment is estimated to be about $5,000 regardless of size
of unit. This cost is easily amortized through savings
realized by reduced consumption of chlorine.
Costs of on-line mechanical cleaning of condenser tubes are
given in Tables A-VIII-13 and A-VTII-14.
There are several alternative materials available which can
replace copper based alloys as condenser tube materials.
The most widely used copper alloys are admiralty, with a
copper content of 70% and Cupro-nickel alloys with a copper
content of from 70 to 90 percent. Replacement materials
consist of stainless steel which provides a good option in
inland fresh water locations and titanium which finds
373
-------
1,000
CO
CO
m
o
T3
o
CO
3
rd
CO
3
O
£
-P
-P
CO
O
O
m
§
c
100
10
1 10 100 1/000
Capacity/ thousands of gallons per day
FIGURE A-VIII-5
Annual Costs of Labor/ Chemicals and Power
for Chemical Treatment
-------
Table A-VIII-13
Capital and Operating Costs for On-Line Tube Cleaning Equipment
389
System
Recirculating
Sponge Balls
Plastic Brushes
Caoital Costs
S/106 Btu/hr $/kw
Rejected
120-290
38-125
0.48-1.16
0.15-.50
Annualized Capital
Mills/kwh(")
.008-. 020
.003-. 009
_____ Operati ng i
$10° Btu/hr1
Rejecte.d
2.85-5.15
3.07-6.12
ind Maintenance
Costs
Mills/kwh
(a 1
0013-.00241 '
fc)
,0014-.0028V
Total Ar.r.ual
Costs
Mills/kwh
.009-. 022
.004-. 01 2
CO
^J
01
a. Power costs estimated at 4 mills/kwh. Maintenance labor estimated at $7.00/hr
b. Based on 15% per year
c. Includes allowance for replacing brushes every five years.
-------
Table A-VIII-14
Typical Sponge Rubber Ball Tube Cleaning System Costs ^a^ 389
Unit Capacity
Mw
900
1,190
680
950
Cooline Water
Kecirculation Rate
gpm
405 . 000
440,000
220 OOO
882 , 000
Equipment Cost * '
S
$229,000
312,000
165,000
556,000
$/Mw
$254
284
243
585
Additional Power
Required to Operate
System, kw
70
76
46
166
Replacement Ball
Costs ,$/yr
$6 , 400
15,000
6,000
11,000
Maintenance
Labor Rqd ,
hrs/wk
1
1
1
2
CO
-J
(a) Data provided by Mr. W. I. Kern, Amertap Corporation
(b) Estimated total installed cost of system, including capital equipment for new installation
2 x equipment cost.
-------
greater applicability in coastal plants operating on sea
water. Both stainless and titanium are highly resistant to
corrosion which allows the use of thinner tube thicknesses
in most applications. The overall heat transfer coefficient
for both of these materials is somewhat less, at normal
operating conditions, than the copper based alloys, thus
requiring a greater tube length. In addition, the cost of
titanium is considerably more than copper and these two
factors have combined to limit the use of titanium to a
relatively few coastal applications. However, several
plants have retubed with this material based on economical
analysis which showed that reduced tube failures lowered
overall maintenance costs. Stainless steel, on the other
hand is competitive with the copper based alloys in terms of
price and its greater tolerance to both erosion and
corrosion has led to a dramatic growth in its use over the
last 10 years.
Table A-VIII-15, shows a cost comparison of the use of these
alternatives tube materials for typical condenser conditions
(7.5 ft/sec and 1.0" diameter tubes) and recent (197U)
materials prices. The table shows that the use of titanium
to retube an existing condenser might add as much as 90% to
the retubing cost. The use of stainless steel is competitve
with the cost of both admiralty and copper-nickel tubing.
Installation of alternate tube material at existing plants
can be done at the time of normal condenser retubing. Major
condensers can be completely retubed in approximately one
month.
Cooling Water Blowdown - Closed Systems
The treatment technology is essentially the same as for a
once-through system. Residual chlorine is monitored in the
effluent, and blowdown is permitted only when the residual
chlorine is below the established limit. It is possible to
schedule blowdown only at such times when the residual
chlorine level meets the effluent limitation. Additional
costs would occur in cases where sedimentation would be
provided for suspended solids removal, and where chemical
treatment would be required for removal of chromium,
phosphorus, or zinc. Sedimentation costs, where needed,
would be approximately 7 cents/1000 gallons treated and
chemical treatment costs, where needed, would be about
$1/1000 gallons.
Capital investment and operating costs were estimated for
various chrornate reduction systems, based on the flow
diagram shown on Figure A-VII-17 and the wastewater
377
-------
Table A-VIII-15
COST COMPARISON OF ALTERNATIVE TUBE MATERIAL
(1"0 tubes; velocity 7.5 ft/sec)
CO
-«J
00
Manorial
Admiralty
90/10 Cupro-Nickel
Titanium
Stainless Steel (316)
Copper
Content (%)
20
90
0
0
BWG
18
20
22
22
Overall
Heat Transfer
Coefficient
(Btu/hr/ftZ/F)
600
570
535
520
Heat
Transfer
Multiplier
1.00
1.05
1.12
1.15
Unit
Cost
$/ft
0.74
0.96
1.26
0.76
Cost
Multi-
plier
1.00
1.29
1.70
1.02
Total
Multi-
plier
1.00
1.36
1.90
1.17
-------
characteristics shown in Table A-VII-11. Estimates were
based on a 1,000 Mw fossil-fuel plant operating at a heat
rate of 10,UOO Btu/Kwh (Efficiency = 33X) and having a
circulating water flow rate of 600,000 gpm at a temperature
differential of 20°F. For such a system, the amount of
blowdown required depends on the characteristics of the
makeup water supply, in particular, the number of cycles of
concentration possible before scaling occurs. The capital
cost of a chromate reduction system is in turn a function of
the blowdown rate. Table A-VIII-16 shows the capital
investment costs for chromate reduction systems for various
blowdown rates and the corresponding number of cycles of
concentration.
The maximum number of cycles of concentration can be
increased ty pretreatment of the makeup supply to reduce the
specific parameter limiting the number of cycles of
concentration. Thus there are obvious tradeoff
possibilities between pretreatment of makeup water and post-
treatment of blowdcwn.
Operating costs of chromate reduction systems consist of
capital charges, maintenance, labor, and materials and
supplies. The first three items are essentially fixed, but
materials and supplies vary with the hours of operation of
the system and the level of chromate carried in the system.
Table A-VIII-17 shows the various costs as a function of the
chromate concentration.
Unit costs for chromate reduction systems are developed in
Table A-VIII-18
Typical automatic blowdown control equipment costs are
estimated to be $7,300 including installation.389. The
installation of conventional pH controlling equipment is
estimated to be about $3,000.3«»
Table A-VIII-19 taken from Reference 389 gives costs for
sedimentation ponds, cooling towers and chemical recovery
for blowdown treatment.
Sanitary Wastes
Sanitary wastes are generally discharged to municipal
sewerage systems, or if municipal sewers are not available,
treated in biological process treatment plants. The volume
of sanitary wastes is primarily a function of the size of
the labor force. For most powerplants in isolated
locations, a minimum size factory preassembled activated
sludge type treatment plant will provide adequate treatment.
379
-------
Table A-VIII-16
CAPITAL INVESTMENT COSTS FOR
CKROMATE REDUCTION SYSTEMS
Slowdown Rare
rl /s gpm
5,400
2,400
720
Assumptions :
Cycles of
Concentration
3
5
10
1,000 Mw fossil-fuel
Heat rate 10,400 Btu/kwh
600,000 gpm at 20°F AT
Evap. - 2%
Capital Cost
$780,000
537,000
364,000
(Efficiency = 33%)
Table A-VIII-17
VARIABLE OPERATING COSTS FOR MATERIALS AND SUPPLIES
CKROMATE REDUCTION SYSTEMS
Item
S02
H2S04
NaOH
Polymer
Power
Unit Cost
$0.17/lb.
$0.02/lb.
$0.04Vlb.
$2.00/lb.
$0.03/kwh
Cost per 1000 gal, processed
Chromate Concentration, mg/1
10 50 100 200
$.05
.08
.145
.02
.0075
$.11
.12
.20
.02
.0075
.4575
$.175
.16
.29
.02
.0075
.6525
$.317
.20
.40
.02
.0075
.9345
380
-------
Table A-V1II-1B
UNIT COSTS OF
CHROMATE REDUCTION SYSTEMS
Capital Investment Costs
Construction Cost $413 000
Engineering 62^000
Contingencies 62,000
Total $537,000
Annual Costs
Capital Cnarges @15% x Total $ 80,500
Maintenance @3% x Constr. Cost 12,400
Labor 23,700
Fixed $116,600
Materials and Supplies 394,400
$511,000
Unit Costs, mills/kwh
Capacity Factor 1.00 0.67 0.35
Fixed Costs 0.013 0.020 0.038
Materials and Supplies 0.045 0.045 0.045
Total 0.058 0.065 0.083
Note; 1000 Mw fossil-fuel plant, 5 cycles, 10 mg/1 Chromate
381
-------
Table A-VIII-19 slowdown Treatment System Costs 389
System
sediment 'it i (.••••. Pond
Mechanical Draft
Evaporative
Cooling Tower
Chr ornate Recovery
Installation
Costs
S/m3/hr fed
3-6
20-30
8400
Annualized , ,
Capital Costs
$/l,000 m3 fed
0.05-0.10
0.34-0.51
144
Operating and .
Maintenance Costs3'
5/1,000 m3 fed
0.01-0.02(c)
2.20-2.75
37
Total Costs
S/1,000 m3 fed
0.06-0.12
2.54-3.26
181
Principal System
Characteristics
1. Provides solids settling
chlorine dissipation, and
usually some cooling
2. Costs dependent on land
values and climate.
1. Allows positive control of
blowdown temperature.
2. May require biocide treatment.
CJ
00
NJ
(a) Based on 15 percent per year
(c) Maintenance estimated at 3 percent per year of capital investment
-------
The installed cost of these plants is estimated to be
$25,000 - $35,000 depending on geographic location.
Materials Storage and Construction Runoff
The cost of materials storage and construction runoff
treatment is a function of the meteorological conditions at
each particular site. Capital costs of lined retention
ponds capable of holding various volumes of runoff are shown
in Figure A-VIII-6. Costs for neutralizing chemicals will
vary with pH and frequency of treatment.
Systems to collect coal pile run-off installed in recent
years vary considerably, in complexity and costs. Elaborate
collection systems would be required at some plants where
unusual terrain conditions and space limitations exist. At
one midwestern plant of about 1,000 Mw capability a new
system collects run-off by gravity in a concrete basin from
which it is pumped to an adjacent ash settling basin. The
collection and treatment systems cost about $500,000 to
install. On the other hand, at one eastern plant such
collection can be accomplished merely by grading of adjacent
areas to route run-off by gravity to an existing ash pond.
This particular system cost about $20,000 to install.444
The assumptions made for estimating the cost of constructing
facilities for containment of the runoff from a one acre
area for the storage of coal and other materials are given
below:458
1. The estimates of cost are based on a 10-year, 2U
hour event in which 0.114 m (4.5 in) of rain falls.
2. The surface of the land to be used as a storage
area has a 3 degree grade.
3. The soil is permeable so that an impermeable
subbase must be prepared. The impermeable base is
prepared by grading 0.6 m (2 ft) from the edge of
the square storage area. This graded surface is
backfilled, graded level, and compacted to a depth
of 0.15 m (5 in). Polyethylene sheeting is placed
on the dikes described later. Overlaps of 0.3 m
(12 in) at the seams of the sheeting are used. A
0.45 m (1.5 ft) layer of earth is than graded and
compacted over the polyethylene, including the face
of the dikes described later.
4. Dikes are constructed across the downhill end of
the square storage area, and for about one-third
383
-------
140
120
'j'lOO
CO
o
Q
O
o
o
c
•H
O
U
80
60
m
•U
•H
04
-------
the distance up each side. The dikes will be 2.5 m
(8.2 ft) high at the crest. The crest will be 1.5
m (5 ft) wide, and the total width of the base of
the dikes, which are trapezoidal in cross-section,
will be 12 m (40 ft). The dike at the downhill end
of the storage area is provided with a concrete
sluiceway so that water can overflow in the event
of a catastrophic rainfall. The crest of the
sluiceway is 1.5 m (5 ft) above the grade level of
the base of the dike. The dikes are constructed
prior to placement of the polyethylene sheets so
that the upstream faces of the dikes can be covered
with polyethylene, and then earth, and compacted.
5. Trenches are dug across the uphill end of the
storage area and along each side to divert runoff
into the diked area.
6. Neutralization facilities are used to maintain
within proper limits the pH of any overflow from
the diked area at a rate of up to 4.5 acre-inches
averaged over one day, as controlled by the weir.
Any flow in excess of this level is allowed to
bypass the treatment facility. These facilities
include a storage hopper and feeder for lime and a
pH sensor and controller along with necessary
wiring. Mixing of the lime with overflow from the
containment pond, when overflow occurs, is
accomplished by the use of a mixer in the
downstream trough of the sluiceway. The lime
feeder is controlled by a pH controller with the
sensor downstream from the sluiceway. The pH
controller will activate the feeder in proportion
to the amount the pH is lower than a pre-selected
point.
7. A settling basin, created by excavation to build
the dike, is sized to provide a detention time of
24 hours (taking into account the build-up of
sediment for the volume of the 10-year 24 hour
event. An overflow is provided. The settling
basin is not lined. See Figure A-VTII-7 which is a
sketch of the runoff treatment system.
The unit costs used in estimating the above cost are
$1.18/cu m ($0.90/cu yd) for grading, filling and
compacting; $0.27/sq m ($0.025/sq ft) for purchasing 10-mil
polyethylene film (quoted price); and $1.65/lineal meter
($0.50/lineal ft) for machine trenching.*sa
385
-------
TRENCH
DIKE
CO
CD
MATERIALS
STORAGE
AREA SLUICEWAY •'
WEIR
LIME STORAGE
LIME FEEDER
pH SENSOR/CONTROLLER
MIXER
SETTLING
BASIN
Overflow
River
Bypass
Figure A-VIII-7 Materials Storage Area Runoff Treatment
-------
The total cost of the O.U04 hectare (1 acre) area for
storing coal and other materials is estimated to be $17,000,
including the cost for preparing impermeable sub-base
($3,300), trenches and dikes ($1,100), and the sluiceway and
neutralization facilities including installation
($8,500) .*»«
For a larger facility, the cost of trenches and dikes are
estimated to be proportional to the square root of the size
of the storage area, since their length is proportional to
the square root of the enclosed area. The cost of the
sluiceway and neutralization facilities are estimated to be
proportional to the 0.6 power of the size of the storage
area, since the cost versus size characteristics of the
components involved can be approximated using this scale
factor.*6* Estimated cost for treatment of runoff from
materials storage areas and construction activities for a
100 Mw and a 1,000 Mw coal-fired plant is given in Table A-
VIII-20. Estimated costs for plants of other sizes are
shown in Figure A-VIII-10. The controlled area is assumed
to be 0.03 acresAMw in each case, which is comprised almost
entirely cf the area of the coal pile. Costs for oil-fired,
gas-fired, and nuclear plants would therefore be relatively
insignificant.
Intake Screen Backwash
The incremental cost of land disposal of debris removed from
intake screens would be insignificant in most cases.
Floor and Yard Drains
The installed cost of two API-type oil-water separators at
plant no. 3702 (400 Mw) is $70,000, or $0.18/kw, to treat
about 56 I/sec (900 gpm) of a floor and yard drain waste
water stream.
Radwaste
No treatment is assumed due to possible hazardous effects of
concentrating radioactive wastes.
Ash Sluicing Systems
In cases where sedimentation would be required for suspended
solids removal from ash sluice water, the costs would be
about 7 cents/1000 gallons. Having achieved adequate
suspended solids removal, the effluent is suitable for
recycle for ash sluicing, which would involve an incremental
cost for pumps, piping and blowdown controls. Flow sheets
387
-------
Table A-VIII-20
Estimated Costs
Materials Storage and Construction Activities Runoff Treatment
(Coal-Fired Plant)
Item
Area Controlled @ 0.03 acre/Mw
Trenches, dikes, and settling basin
Sluiceway, diversion, and
neutralization facilities
Major Component Cost
Installation Cost*
Instrumentation Cost*
Construction Cost
Engineering @ 15%
Contingency @ 15%
Total Capital Cost
( $Aw )
Model
1 acre
$ 1,100
8,500 .
$ 9,600
0
0
$ 9,600
1,440
1,440
$12,480
100 Mw
3 acres
$ 1,910
16,430
$18,430
0
0
$18,340
2,750
2,750
$23,840
( 0.24 )
1000 Mw
30 acres
$ 6,030
65,400
$71,430
0
0
$71,430
10,700
10,700
$92,830
( 0.09 ) |
co
00
CO
*Note : Included in major component cost
-------
for the adaption of recirculating bottom ash sluicing
systems where ash pond sedimentation is already employed are
given in Figures A-VIII-8, 9, one of which applies where a
combined ash pond is used for both fly ash and bottom ash
and the other applies where the ash pond handles only
bottom ash. Equipment costs are determined from Figure A-
VIII-2, 3. It is assumed, based on site plans of all TVA
coal-fired plants that 6,000 ft of return pipe would be
needed for a 1,000 Mw plant and further, that the length of
return pipe required for plants of other capacities would be
proportional to the plant capacity to the 0.6 power.
Equipment costs for 100 Mw and 1,000 Mw coal-fired plants
are given in Tables A-VIII-21, 22, respectively, for
adaptation of recirculating bottom ash systems for the two
types of ash pond usage. Corresponding capital costs are
given in Tables A-VIII-23, 24. The estimated relation of
capital costs to plant generating capacity is given in
Figure A-VIII-10. Estimated annual costs are shown in
Tables A-VIII-25, 26.
The backfitted configured recirculating ash sluicing system
at plant No. 3630, which utilizes no ash pond for
sedimentation, cost approximately 3 million dollars to
handle the bottom ash from coal turned at a rate of 3,000
tons/day. However, the costs for this system include
modification of floor and yard drainage, neutralization and
disposal of demineralizer and boiler cleaning wastes and
modification of trash screens as well as the configured ash
water recycle system. System components include a coal pile
trench, collecting basin, filtering pond, neutralizing
tanks, pumps, piping, hydrobins, settling tank and
recirculating tank. The system is designed to achieve no
discharge of pollutants except for those contained in the
moisture removed with the settled ash. The plant uses once-
through cooling systems.
The capital cost of the configured recirculating bottom ash
system at plant No. 5305 was $2,100,000. Dnit 1, with a
capacity of 700 Mw, was installed in late 1971 and Unit 2,
with the same capacity, was installed in late 1972.
Assuming the costs to be approximately the same for both
units and a 5 percent increase in costs between 1972 and
1973, the 1973 cost for a 700 Mw recirculating bottom ash
system would be about $1,100,000. Using this as a base and
assuming a 0.6 scale factor on costs versus size (Mw
capacity) the capital costs for a 100 Mw unit would be
approximately $420,000 or 4.20 $/kw, and $1,360,000 or 1.36
$/kw for a 1,000 Mw unit. Costs would vary from case-to-
case.
389
-------
CO
10
O
Figure A-VIII-8
FLOW SHEET - RECIRCULATING BOTTOM ASH
SLUICING SYSTEM SLOWDOWN TREATMENT
WATER
(9 gpd/mw)
RECIRCULATING BOTTOM ASH
SLUICING WATER
5000 gpd/mw
BOTTOM ASH
POND
pH 3
(ASSUME)
RECYCLE FOR BOTTOM
ASH SLUICING
5000 gpd/mw)
400 gpd/mw MAKEUP
FLOCCULANTS
1 LB/1000GAL
(0.4 Ib/day/mw)
DISCHARGE TO
RECEIVING
WATER
^ PH 7.
r
5000 gpd/mw)
TSS 1000 mg/J? (ASSUME)
SLOWDOWN
400 gpd/mw
TSS 1000PPM
CLARIFIER
-0
1% SLURRY
45 gpd/mw
DISCHARGE TO
RECEIVING WATER
SLUDGE
LIME
7.2 x 10"4 Ib/gal
(3.6 Ib/day/mw)
LIME
5% LIME SLURRY
-------
Figure A-VIII-9 TREATMENT OF COMBINED ASH OVERFLOW
RECYCLE FOR BOTTOM ASH SLUICING
5000 gpd/mw)
RECIRCULATING BOTTOM ASH
SLUICING WATER 5000 GPO/MW
FLY ASH SLUICING WATER
6000 gpd/mw
Co
10
COMBINED
ASH POND
FLOCCULANTS
1 Ib/IOOOgal
(5.5 Ib/day/mw)
DISCHARGE TO
RECEIVING WATERS
—'5400 gpd/mw
OVERFLOW
10,000 gpd/mw
TSS 60 mg/J
SO4 510 malt
HARDNESS 244 mg/7 AS CaCO3
LIME OR ACID
SLUDGE
-MAKEUP
400 gpd/mw
6000 gpd/mw)
REACTOR
(pH ADJUSTMENT)
208 gal/mw (1 HR. DETENTION)
FILTER
1% SLURRY'
8000 Ib/day/mw
(1000 gpd/mw)
(•ASSUMES THAT THE WEIGHT OF PRECIPITATE IS TWICE THE WEIGHT OF POLLUTANTS)
-------
Table A-VIII-21
Estimated Equipment Costs
Recirculating Bottom Ash System
and Treatment of Bottom Ash Slowdown
Component
Lime Mixing System (Ib/day)
Clarifier (gpd)
Filter (gpd)
Pumps and Piping
Major Equipment Cost
100 Mw
Size/Capacity
360
40,000
4,500
$
2,000
9,400
16,000
21,500
48,900
1000 Mw
Size/Capacity
3,600
400,000
45,000
$
3,500
30,000
34,000
87,000
154,500
CO
«-O
ro
-------
00
to
co
Table A-VIII-22
Estimated Equipment Costs
Recirculating Bottom Ash System
and Treatment of Combined Ash Pond Overflow
Component
Reactor (gpd)
Clarifier (gpd)
Filter (gpd)
Pumps and Piping
Major Equipment Cost
100 Mw
Size/Capacity $
540,000
540,000
100,000
9,200
36,000
44,000
21,500
110,700
1000 Mw
Size/Capacity
5,400,000
5,400,000
1,000,000
$
16,000
210,000
94,000
87,000
407,000
-------
Table A-VIII-23
Estimated Capital Costs
Recirculating Bottom Ash System
and Treatment of Bottom Ash Slowdown
Item
Major Equipment Cost
Installation Cost
@50% for new sources
@100% for retrofit
Instrumentation
@20%
Construction Cost
Engineering
@15%
C ont i ng enc y
d>15%
Total Capital Cost
($Aw)
100 Mw
Retrofit
($1000)
48.9
48.9
9.8
107.6
16.1
16.1
139.8
(1.40)
New Sources
($1000)
48.9
24.5
9.8
83.2
12.5
12.5
108.2
(1.08)
1000 Mw
Retrofit
($1000)
154.5
154.5
30.9
339.9
50.9
50.9
441.7
(0.44)
New Sources
($1000)
154.5
77.3
30.9
262.7
39.4
39.4
341.5
(0.34)
co
-------
Table A-VIII-24
Estimated Capital Costs
Recirculating Bottom Ash System
and Treatment of Combined Ash Pond Overflow
Item
«
Major Equipment Cost
Installation Cost
d> 50% for new sources
@ 100% for retrofit
Instrumentation
@ 20%
Construction Cost
Engineering
® 15%
Contingency
@ 15%
Total Capital Cost
($Aw).
100 Mw
Retrofit
($1000)
110.7
110.7
22.1
243.5
36.5
36.5
316.5
(3.17)
New Sources
($1000)
110.7
55.4
22.1
188 o 2
28.2
28.2
244.6
(2.45)
1000 M"
Retrofit
($1000)
407.0
407.0
81.3
895.3
134.4
134.4
1,164.1
(1.16)
New Sources
($1000)
407.0
203.5
81.3
691.8
103.9
103.9
899.6
(0.90)
<*>
to
en
-------
n
r-
en
s-i
m
rH
H
O
o
CO
fl
en
3
O
-P
en
0
U
-P
•H
a
ro
O
rH
a
-P
o
13
. •...; . '• !. . ' • :...
*:I '• '• •• I i Hi!'
~ Existing Plants
- -"New 'Plant's " ~"~
•-rrrBoth _Ebcis-ting
i_ .and.J3ew. .Plants.
10 100 1,000
Plant Generating Capacity, megawatts
10,000
Figure A-VIII-10
Estimated Total.Capital Costs for Materials Storage and
Construction Activities Rainfall Runoff Treatment,
Recirculating Bottom Ash Systems with Slowdown Treatment,
and Recirculating Bottom Ash Systems with Treatment of
Combined Ash Pond Overflow,All for Coal-Fired Plants
396
-------
Table A-VIII-25
Estimated Annual Costs
Recirculating Bottom Ash System
and Treatment of Bottom Ash Slowdown*
Item
Construction Cost (CC)
Total Capital Cost (TCC)
Maintenance @ 3% of CC
Fixed Charges @ 15% of TCC
Chemicals and Power
Labor
Total Annual Cost
Unit Cost, mills/kwh.
Base-load ( 0.77 capacity f actor )#
Cyclic ( 0.44 capacity f actor )#
Peaking ( 0.09 capacity f actor )#
;_ 100
Retrofit
($1000)
107.6
139.8
3.2
22.0
7.5
120.0
152.7
0.228
0.398
1.95
Mb.'
New Sources
($1000)
83.2
108.2
2.5
16.2
4.8
100.4
123.9
0.183
0.321
1.57
I
1000
Retrofit
($1000)
399.9
441.7
10.2
66.3
70.0
230.0
466.5
0.069
• 0.121
0.590
Mw
New Sources
($1000)
262.7
341.5
7.9
51.3
4.4
200.0
263.6
0.039
0.068
0.334
CO
-------
CO
«£>
00
Table A-VIII-26
Estimated Annual Costs
Recirculating Bottom Ash System
and Treatment of Combined Ash Pond Overflow*
( Retrofit Only)
Item
Construction Cost (CC)
Total Capital Cost (TCC)
Maintenance @ 3% of CC
Fixed Charges @ 15% of TCC
Chemicals and Power
Labor
Total Annual Cost
Unit Cost
Base-load ( 0.77 capacity factor )#
Cyclic ( 0.44 capacity factor)#
Peaking ( 0.09 capacity f actor )#
100 Mw
($1000)
243.5
316.5
7.3
47.5
90.0
250.0
394.8
0.587
1.03
5.02
1000: Mw
($1000)
895.3
1,164.1
26.9
175.0
870.0
480.0
1,559.9
0.108
0.189
0.923
* Note: Flow basis is 5,400
# Note: Assumes full annual costs of maintenance, chemicals, power, and labor.
These costs would actually be less than shown and would reflect the
extent of utilization of the plant.
-------
Reference U60 estimates the costs of settling ponds at
$5,000/acre for 100 acre ponds and $l,000/acre for a pond of
2,400 acres. Reference 370 estimates that 300-UOO acres of
ash ponds (fly ash and bottom ash) would be required for a
3,000 Mw coal-fired plant. Assuming the above costs (0.5
scale factor on costs versus size) and a pond size of 12
acres/100 Mw and 120 acres/1000 Mw, the capital cost of an
ash pond (fly ash and bottom ash) for a 100 Mw coal-fired
plant would be $180,000 or $1.80/kw and $550,000 or $0.55/kw
for a 1,000 Mw coal-fired plant. Assuming acreage for ponds
handling only bottom ash to be 25% of the above and for fly
ash 75% of the above, bottom ash ponds would cost $90,000 or
$0.90/kw for a 100 Mw plant and $280,000 or $0.28/kw for a
1,000 Mw plant; and fly ash ponds would cost $150,000 or
$1.50/kw for a 100 Mw plant and $U80,000 or $O.U8/kw for a
1,000 Mw plant.
Dry fly ash systems costs would vary from case to case
depending on the quantities of ash transported and other
factors. Cost have been reported of $150,000 for a 100-600
Mw plant handling 80 tons/hour and $500,000 for a 700 Mw
plant handling 150 tons/hour.**9 Both costs do not include
storage silos which may cost approximately as much as the
other parts of the system. Both costs are for retrofitted
systems and include equipment only. For the 700 Mw case
above, the total capital costs is estimated to be $2,210,000
including 50* installation; 20% instrumentation, 15%
engineering, and 15 % contingency costs. Applying a 0.6
scale factor, total capital costs for a new 100 Mw unit
would be about $550,000 or $5.50/kw and $2,600,000 or
$0.26/kw for a new 1,000 Mw unit. Estimated costs for
retrofit systems would be more if a 100% factor for
installation costs were used.
The use of recalculation bottom ash systems for all sources,
dry fly ash systems for new sources, and primary
sedimentation of fly ash for existing sources is estimated
to achieve the removal cf approximately 28,000,000,000
Ib/year, by 1990, of total suspended solids that would have
otherwise been discharged (over 99* removal) . This estimate
is based on the following assumptions:
33% of coal-fired generation would have used dry fly ash
systems (base-line)
72% of coal-fired generation would have used ash ponds
(base-line)
399
-------
26% of coal-fired generation would have discharged
directly (base-line)
2% of coal-fired generation would have discharged to
sewers (base-line)
1990 coal-fired generation is 330,000 Mw
Capacity factor 1990 coal-fired generation is 0.6
In 1990, 67% of coal-fired generation will use dry fly
ash systems
In 1990, 1% of coal-fired generation will discharge to
sewers
In 1990, 0% of coal-fired generation will discharge
directly
Ash generated by a 1,000 Mw coal-fired plant (0.6
capacity factor) is 900,000 Ib/day fly ash and 300,000
Ib/day bottom ash
Overflow from primary sedimentation of fly ash at a
1,000 Mw coal-fired plant (0.6 capacity factor) contains
700 Ib/day of solids
Discharges of solids from a treated recirculating bottom
ash system at a 1,000 Mw coal-fired plant (0.6 capacity
factor) are about 60 Ib/day.
Costs for Complete Treatment of Chemical Wastes for Reuse
Because of the wide range of opportunities and associated
incremental costs of achieving no discharge of pollutants
from waste water sources other than cooling water systems
and rainfall run-off (based on the technology of maximum
recycle with evaporation of the final effluent) a model
plant is employed as a basis for considerations of this
higher level of technology. The features of the model plant
are selected to produce conservatively high incremental
costs of applying this technology, i.e. the determined costs
would be at a level higher than would be expected for almost
all other plants. The model plant would have such adverse
characteristics that recycle of all water (except that used
in ash sluicing systems or in wet-scrubber air pollution
control systems) would not be practicable except after
distillation. Distillation is much more costly than the
chemical addition and sedimentation treatments which would
400
-------
be used in most cases. Ash sluicing water and wet-scrubber
water would be recycled after sedimentation (or filtration)
for solids removal. The model plant would have to distill
blowdown from ash sluicing for recycle to other processes,
however, the quantities of water distilled would be less
than the feed intake to the system of low quality waste
waters from other sources by the amount of evaporation
during sluicing and the amount cf moisture removed in the
ash. Therefore, the assumption of the presence of wet ash
sluicing is consistent with the conservative approach of the
cost analysis. Similar considerations pertain to
wet-scrubber air pollution control systems. Non-solar
evaporation is further assumed.
Conceptual flow diagrams have been developed for such plans
for coal-fired and oil-fired powerplants. These flow
diagrams are shown in Figures A-VIII-11 and A-VIII-12. Cost
estimates were then prepared based on these flow diagrams.
.The three major process units required to provide a complete
treatment of chemical wastes for reuse within a powerplant
include a softener and chemical feed system to reduce the
hardness of the cooling tower blowdown, a brine concentrator
to preconcentrate the blowdown brines resulting from the
recirculating of ash sluicing water, and an evaporator-dryer
to finally reduce the sludge to a solid cake for disposal by
landfill.
The capital costs, operating costs, and annual and unit
costs for a complete treatment system for chemical wastes
exclusive of once-through cooling water and rainfall runoff
are estimated to be as follows:
Capital cost, 3-6 $/kw
Operating costs, 1 $/yr-kw
Annual costs, 1-3 $/yr-kw
Unit costs, 0.2-0.5 mill/kwh (base-load)
This system will produce no discharge of pollutants while
returning the water to the process for reuse. The costs
represent upper limits of cost. At some plants it may not
be necessary to concentrate brine and evaporate to dryness.
For example, plants in the southwestern United States would
probably be able to utilize evaporation ponds at a
substantial saving in cost. Mine-mouth plants will
frequently have requirements for large volumes of low
quality water for coal processing with ultimate disposal to
401
-------
COOL-
ING
TOWER
MAKE-UP
890
GPM
LIQUID
WASTES
FROM ION
EXCHANGE
& EVAP. ONLY
14,3000 GPD
Il6 GPM)
COAL 80,800 LB/HR
AIR 788,000 LB/HR
OUTPUT HEAT BALANCE:-
POWER-3.42 X 108 BTU/HR
FLUE GAS-1.58 X 108
BTU/HRT. 7
COOLING TOWER-
ASSUMPTIONS
INPUT:-10.5 X 106 BTU PER MW
FOR COAL -13,000 BTU/LB.
AIR REO'D-7.5 LB/10.000 BTU
WATER PRODUCED IN FLUE GASES-0.4 LB/10,000 BTU
15% OF INPUT IS LOST TO FLUE GASES
FLUE GASES
184,000 SCFM (b.d.l®
~400°F & 105°F D. P.
INPUT:- „
HEAT-10.5 X 108 BTU/HR
DRY FLY ASH
FOR DISPOSAL
| 254,000 SCFM |b.d.|@ 135°F (SAT.) * R_EHEAT (II
SLUDGE FOR
DISPOSAL (CaSO4)
•^*^fc^fe*^M - T)
FLUE GASES TO
ATMOS. AFTER
REHEAT (IF REQ'D.)
COOLING TOWER
EVAPORATE 1000 GPM
(ASSUME NEGLIGIBLE
DRIFT LOSS)
MAKE-UP-1.1 X 1000 GPM
-100 CONCENTRATION
OPERATION
CONTROLLED
DOSAGE(S) OF
CHLORINE
BASIN CLEANING
5300 GPY
410,000 GPD.
ASH
SLUICING
SYSTEM
LOSS BY
EVAPOR-
ATION
ASH SLUICING
SYSTEM
NEUTRALIZATION pH ADJUSTMENT
& SEDIMENTATION (IF REO'D) OIL
SEPARATION &
TSS REMOVAL
SLUDGE
TO CITY
SEWERS (IF
ALLOWED)
NET SLOWDOWN @10%,
OF CENTRAL TREAT
MENT PLANT FLOW
LEGEND
- WATER
NET BLOW- I-
IDOWN 11.6 GPMl
JBRINE
ICONCENTRATORl"
CONCENTRATED .
SLUDGE
SLUDGE TO
ASH POND
CITY SEWERS
(I FALLOWED)
MOIST SOLIDS
FOR DISPOSAL
FLUE GASES
-OIL
>• SLUDGE
-OPTIONAL ARR'GT.
FIGURE A-VIII-11100 MW COAL-FIRED STEAM ELECTRIC POWERPLANT RECYCLE AND REUSE OF CHEMICAL WASTES 1
-------
ASSUMPTIONS
INPUT; - 10.5 « 106 BTU PER MW FOR
NO.6 6lL: • 18.000 BTU/LB., 8 LB/GAL
AIR REQ'D. • 13.5 LB/LB of OIL
WATER PRODUCED IN FLUE GASES - 0.849 LB/LB
15% OF INPUT OF OIL IS LOST TO FLUE GASES
FLUE GASES TO
ATMOSPHERE AFTER
REHEAT (IF REO-D)
CLOSED WATER
COOLING SYSTEMS
CONDENSATE
AS MAKE-UP
MAKE-UP WATER -138 GPM
FLUE GASES
170,000 SCFMIb.d.)
e 490°F &
113°F D. P.
BOILER
MAKE-UP
108,000 GPD
(~74 GPM)
INPUT: 10.5 X 108 BTU/HR.
MOIST SOLIDS
FOR DISPOSAL
OUTPUT: . .
POWER-3.42 X 108 BTU/HR
NO. SOIL
58.300 LB/HR.
(7ioOGPH)
FLUE GASES-
1.58 X~108 BTU/HR.
COOLING'TOWER:
5.5 X 108 BTU/HR.
(BY DIFFERENCE)
AJ240.000 ACFM€»140°F (SAT'D)..
COMBUSTION AIR
758.000 LB/HR
DRY FLY ASH
, FOR REBURN
AND/OR DISPOSAL
BOILER
SLOWDOWN
5200 GPD
l~3.7 GPMI
20°FATRISE
(ASSUME)
COOLING TOWER
EVAPORATE -1000 GPM
; (ASSUME NEGLIBLE DRIFT
' LOSS)
JMAKE UP:~1.1 X 1000GPM
-100 CONCENTRATION
OPERATION
CONTROLLED
DOSAGE IS) OF CHLORINE
MOIST SOLIDS
FOR DISPOSAL
SLOWDOWN
@10%*1.6GPM
SLOWDOWN 0 10%=10 GPM
FLOOR AND
YARD
DRAINAGE
BASIN CLEANING ~ 5300 GPY .
NET BLOW DOWN |
11.6G
CITY SEWERS
(IF ALLOWED)
BRINE
CONCENTRATOR
SLUDGE FOR
DISPOSAL
TO
CITY SEWERS
(IF ALLOWED)
SLUDGE FOR
DEWATERING
pH ADJUSTMENT
JlFREO'DIOIL
SEPARATION &
TSS REMOVAL
WATER
FLUE GASES
OIL
SLUDGE
OPTIONAL ARRGT
CONCENTRATED
SLUDGE
•" MOIST SOLIDS
FOR DISPOSAL
FIGURE A-VIII- 12100 MW OIL-FIRED STEAM ELECTRIC POWERPLANT RECYCLE AND REUSE OF CHEMICAL WASTES
-------
the mine. The estimates assume that no alternate ultimate
disposal methods for the brines are available and that
evaporation to dryness is the only feasible method of
ultimate disposal. Under these assumptions, the cost of
complete treatment is estimated to be 0.30 mills per kwh for
a 100 Mw plant and 0.11 mills per kwh for a 1,000 Mw plant
assuming a unity capacity factor. For a typical base load
plant operating at a capacity factor of 0.67, these costs
increase to 0.45 mills per kwh for a 100 Mw plant and 0.17
mills per kwh for a 1,000 Mw plant. Costs for plants
operated in the cycling mode at a capacity factor of 0.35
are about 0.86 mills per kwh for a 1000 Mw plant and 0.32
mills per kwh for a 100 Mw plant. Costs for a 100 Mw
peaking plant are about 1.5 mills per kilwatt hour. These
costs are about 5, 6, and 12 percent of production costs,
respectively. The above costs assume the full capacity
costs of maintenance, labor, chemicals, and power. The
actual costs for these items would be lower than shown and
would reflect the degree of utilization of the plant. Costs
for smaller plants would be generally higher and costs for
larger plants would be generally lower. Costs would be less
for plants in climates suitable for solar evaporation. Cost
would be generally less for nuclear plants and for gas-fired
plants because there is no requirement for water related to
ash handling. From an overall standpoint, costs would be
generally lower than the costs for the model plant due to
the conservative assumptions employed in the model. Full
recycle of blowdown from evaporative recirculating cooling
water systems would be significantly more costly. The costs
of achieving no discharge of pollutants other than heat by
complete chemical treatment and recycle provide a
conservatively high estimate of achieving no discharge of
pollutants from low-volume waste sources only.
Energy
Energy requirements for the treatment of chemical wastes are
not a significant consideration. Most of the processes
utilized for the treatment of chemical wastes require no
input of energy other than that required for conveying the
liquid. Some of the processes involved in the technology
for achieving no discharge of pollutants involve a change of
state from the liquid phase to the vapor phase, and others
such as vacuum filters and reverse osmosis require
substantial mechanical energy. However, these processes are
generally applied to only a small portion of the total
wastes, so that again the overall effect is negligible.
Based on the flow diagrams for a central chemical wastes
treatment plant and for complete treatment facilities
designed to achieve no discharge of pollutants, the
404
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estimated energy requirements for central waste treatment
are less than 10 kw per 100,000 kw of plant capacity, or
less than 0.01% of the plant output. For complete treatment
and reuse, including steam evaporation to dry material for
ultimate disposal, the energy requirements are less than
0.2% of the plant output. For plants capable of achieving
no discharge by utilizing evaporation ponds, energy
requirements are about 0.04X of the plant output.
Non-Water Quality Environmental Impacts
The waste treatment processes previously discussed are
essentially separation techniques which produce a liquid
fraction suitable for discharge or reuse and a liquid-solid
residue which requires ultimate disposal. The residues from
ion exchange, evaporation, and reverse osmosis processes are
concentrated brines, which carry the solids in solution
form. The residues from other waste treatment processes are
sludges of various types and concentration, which may
contain from 0.5 to 5.0 % solids in the suspended form. The
ease with which these sludges can be further dewatered
depends on the type of sludge. At one end of the scale are
sludges which contain a high propcrtion of mineral solids,
and which dewater readily to about 20% solids. At the other
end of the scale are gelatinous sludges such as those
resulting from alum coagulation which are very difficult to
dewater. The following paragraphs describe some of the
dewatering and ultimate disposal techniques applicable to
steam electric powerplants.
Intermediate Dewatering Devices
A number of devices are available for the intermediate de-
watering of sludges from their original concentration of 1-
5% solids to about 15-30% solids. These devices include
vacuum filters, pressure filters and centrifuges.
Vacuum filters are devices consisting of a drum covered by a
filter media and rotating slowly while partially submerged
in a reservoir containing the sludge to be dewatered. A
vacuum of 40 to 80 kN/sq m (12 to 25 in. of Hg) is applied
to the inside of the drum, causing a layer of sludge to
adhere to the surface of the media. As the layer emerges
from the reservoir, it is further dried by air being drawn
through the layer and into the interior of the drum. Just
prior to resubmerging into the reservoir, the dewatered
sludge is removed from the drum by a scraper and conveyed to
disposal.
405
-------
Some sludges contain very fine or filamentous solids that
clog the filter media and prevent the flow of liquid and air
through the media. Such sludges must be treated to increase
the porosity of the filter cake. Treatments prior to
filtration may consist of the addition of ferric chloride to
colloidal sludges or diatomaceous earth to sludges
containing a high proportion of silty material. 18Z
Pressure filters are similar to vacuum filters except that
the sludge or suspension is forced through the filter media
by pressure rather than by vacuum. The most common filter
media arrangement consists of a series of vertical frames
covered by a cloth media. The sludge is applied through a
header to the outside of the filter media, while the
filtrate is collected from the inside. A filter aid is
commonly used to increase the filterability of the sludges.
Neither vacuum filters nor pressure filters have been used
for pollution control in steam electric powerplants to any
significant extent, although certain types of pressure
filters are used in some forms of condensate polishing.
Centrifuges are intermediate dewatering devices which make
use of the gravitational forces in liquids rotating at high
speeds to separate particulate matter from suspensions.
There are no known instances of centrifuges being used by
steam electric powerplants for pollution control, but the
technology is available and should be considered as a means
of concentrating and dewatering sludges.
Evaporation Ponds (Lagoons)
Evaporation ponds are a feasible method of ultimate disposal
for plants having the necessary land area available and
having climatic conditions favorable to this method. In
general, annual evaporation should exceed annual rainfall by
over 50 cm (20 in). This would restrict uncovered
evaporation ponds to the southwestern portion of the United
States.
Ponds are generally lined to prevent seepage into the
ground. Multiple ponds are usually provided to allow
evaporation from one pond while ether ponds are receiving
wastes. Facilities must also be provided to remove solids
accumulated in the pond.
Landfill
Landfills are the most common method of disposal of solid
residues. However, leachate from chemical wastes deposited
406
-------
in landfills may cause groundwater problems. If the wastes
contain soluble components, fill areas must be lined and
leachate and runoff collected and treated as for coal pile
runoff.
Conveyance to Off-Site Disposal
Conveying brines and sludges to off-site disposal facilities
is a method of ultimate disposal provided that the washes
have been concentrated to make conveying economically
attractive and provided there is a facility to which the
wastes can be delivered. Alternate methods of conveyance
are by trucks, railroad cars or pipeline. Pipeline
conveyance is the most economical means for quantities in
excess of 100 cu m (26,000 gal) per day. For smaller
quantities, truck or rail hauling is more economical, with
distance the deciding factor. Trucking is more economical
for distances below 50 km (35 miles) with rail haul more
economical for longer distances. In any case, costs are of
the order of $0.01 - 0.10 per cu m-km ($0.05 - $0.50 per
1000 gal - mile) exclusive of disposal charges by the
receiving agency. 369 These costs are sufficiently high to
make conveyance economically unattractive except at sites
having no alternate means of disposal.
407
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PART A
CHEMICAL WASTES
SECTIONS IX, X, XI
BEST PRACTICABLE CONTROL TECHNOLOGY CURRENTLY AVAILABLE,
GUIDELINES AND LIMITATIONS
BEST AVAILABLE TECHNOLOGY ECONOMICALLY
ACHIEVABLE, GUIDELINES AND LIMITATIONS
NEW SOURCE PERFORMANCE STANDARDS AND
PRETREATMENT STANDARDS
Best Practicable Control Technology Currently Available
Cooling Systems
Free available chlorine discharges in both recirculating and
nonrecirculating cooling water systems are to be limited to
average quantities reflecting concentrations of 0.2 mg/1
during a maximum of 2-hours a day (aggregate) and maximum
quantities, during these periods, reflecting concentrations
of 0.5 mg/1. These limitations can be achieved by means of
available feedback control systems presently in wide use in
other applications. Chlorination for biological control can
be applied intermittently and thus should not be applied on
two or more units at the same plant simultaneously in order
to minimize the maximum concentration of total residual
chlorine at any time in the combined cooling water
discharged from the plant. Generally Chlorination is not
required at higher chlorine levels or for more than two
hours each day for each unit. However, additional
Chlorination may be allowed in specific cases to maintain
tube cleanliness. Alternative methods of reducing the total
residual chlorine in condenser cooling water systems
include chemical treatment, substitution of other less
harmful chemicals, and use of mechanical means of cleaning
condenser tubes. Mechanical cleaning is employed in some
plants but its practicability depends on the configuration
of the process piping and structures involved at the
particular unit. Moreover, chlorine may still be discharged
even with mechanical cleaning of condenser tubes, because of
its continued use in maintaining biological control in other
parts of the cooling system. Further removal of residual
chlorine in nonrecirculating condenser cooling water systems
by chemical treatment is available but is not generally
practicable because of the additional costs involved to
treat the large volumes of water involved.
409
-------
Chemical treatment of recirculating cooling water systems
would be less costly and the pollution potential of residual
bisulfide chemicals added would be less significant than
with nonrecirculating cooling water systems due to the
smaller wastes water volumes requiring treatment.
Experience in this technology is highly limited in the
powerplant field; however, this is a well established
technology in the water supply industry. Other technologies
potentially available for recirculating cooling water
systems are split stream chlorination, blowdown retention,
and intermittent discharge programmed with intermittent
chlorination.
The use of chemicals for control of biological growth,
scaling and corrosion in evaporative cooling towers is
commonplace. The types and amounts of chemicals required is
highly site-dependent. Chromate addition is not generally
required for corrosion control. Phosphates and zinc salts
are employed in some cases. Insufficient data exists to
judge what alternative chemicals for control of corrosion,
etc., would be generally practicable from a cost versus
effluent reduction benefit, standpoint. Minimum discharge of
added chemicals can be achieved by employing the best
practicable technology for water treatment and water
chemistry to minimize the quantities of blowdown flow
required. In cases of new sources, design for corrosion
protection can eliminate the need for chemical additives for
corrosion protection. Treatment of cooling tower blowdown
by chemical addition for effluent pH control, and by
sedimentation for reduction of effluent total suspended
solids is achievable, however, essentially all total
suspended solids that would be removed would come from
sources other than the process (intake water and air).
Low-Volume Waste Waters
Low-volume waste water sources include boiler blowdown, ion
exchange water treatment, water treatment evaporative
blowdown, boiler and air heater cleaning, other equipment
cleaning, laboratory and sampling streams, floor drainage,
cooling tower basin cleaning, blowdown from recirculating
ash sluicing systems, blowdown from recirculating
wet-scrubber air pollution control systems, and other
relatively low volume streams. These wastes, where by the
specific waste water parameters of the untreated waste, can
be practicably treated collectively by segregation from
higher volume wastes, equalization, oil separation, chemical
addition, solids separation, and pH adjustment.
410
-------
Oily streams such as waste waters from boiler fireside
cleaning, air preheater cleaning and miscellaneous equipment
and stack cleaning would be practicably treated for
separation of oil and grease, if needed, to a daily average
level of 15 mg/1. Addition of sufficient chemicals to
attain a pH level in the range 9 to 10 and total suspended
solids of 30 mg/1 in the effluent of this treatment stage
would be generally practicable considering the pH levels of
the untreated waste streams and the waste water flow volumes
involved. Generally, the higher the pH level, with total
suspended solids of 30 mg/1, the greater the effluent
reduction benefits attained for the numerous chemicals
removed by treatment. Examples of pollutants significantly
reduced by this treatment are the following: acidity,
aluminum, biochemical oxygen demand, copper, fluoride, iron,
zinc, lead, magnesium, manganese, mercury, oil and grease,
total chromates, total phosphorous, total suspended solids,
and turbidity. Some waste water characteristics, such as
alkalinity, total dissolved solids, and total hardness are
increased, however. Following the above treatment it would
be practicable, in a second stage, to adjust the effluent pH
to a level in the range 6.0 to 9.0 in compliance with stream
standards, with sedimentation to attain final daily average
effluent total suspended solids levels of 30 mg/1. Effluent
daily average concentrations of levels of 1 mg/1 total
copper and 1 mg/1 total iron are achievable by the
application of this technology to segregated metal equipment
cleaning waste waters and to segregated boiler blowdown.
The effluent limitations in mass units, in any particular
plant, would be the products of the collective flow of the
affected low-volume waste sources times the respective
concentration levels.
Segregation and treatment of boiler cleaning waste water and
ion exchange water treatment waste water is practiced in a
relatively few plants, but some degree of segregation is
potentially practicable for all plants. Oily waste waters
are segregated from non-oily waste streams at some plants
and the oil and grease removed by gravity separators and
flotation units.
Combined treatment of waste water streams is practiced in
numerous plants. However, in most cases treatment is
accomplished only to the extent that self-neutralization,
coprecipitation and sedimentation occur because of the
joining and detention of the waste water streams. Chemicals
are added during combined treatment at some plants for pH
control. Most of these plants employ lagoons, or ash ponds,
while a few plants employ configured settling tanks.
411
-------
Separate regulations are now being formulated by EPA to set
forth effluent limitations for sanitary waste waters from
privately-owned treatment works such as would be the case
for sanitary waste treatment for steam electric powerplants.
Once-Through Ash and Air Pollution Control Systems
Daily average effluent total suspended solids levels of 30
mg/1 are practicably attainable as are oil and grease levels
of 15 mg/ and pH values in the range 6.0 to 9.0. Due to the
fact that intake water to ash sluicing and air pollution
control systems is often well in excess of this level, an
effluent limitation of 30 mg/1 total suspended solids times
the waste water flow would, in many of those cases, require
the removal of quantities of suspended solids not added by
the plant. In the light of this, in cases where it is
authorized to take account of suspended solids not added by
the plant, it should be practicable for an effluent total
suspended solids level for these streams to be limited to a
greater number of pounds per day but not in excess of the
total intake to the plant for these systems.
Dry processes are used by most oil-fired plants for ash
handling, while only fly ash is handled dry at some coal-
fired plants. Gas-fired plants have little or no ash. The
extent of the practicability of employing dry processes for
bottom ash'handling at coal-fired plants is not known.
Rainfall Runoff Waste Water Sources
Rainfall run-off waste water sources include materials
storage drainage and.run-off from construction activities.
Construction activities include only those in the
immediately vicinity of the generating unit (s) and related
equipment. Runoff from other parts of the site ( land for
future generating units, construction of access roads,
cooling ponds and lakes, visitor centers, etc.) is not
intended to be covered by this limitation. Effluent
limitations of 50 mg/1 total suspended solids and a pH value
in the range 6.0 to 9.0 reflect the technology of diking,
neutralization, and solids separation.
Best Available Technology Economically Achievable
The technology of re-use and recycle of all waste water to
the maximum practicable extent, with distillation to
concentrate all lew-volume water wastes and to recycle water
to the process, and with evaporation to dryness of the
concentrated waste followed by suitable land disposal is not
41:
-------
judged to be generally warranted due to the finding that the
technology has not been fully demonstrated.
Re-use of waste water streams is practiced at relatively few
plants, but some employ recycle of ash sluice water.
Distillation concentration with recycle is currently planned
for at least three plants. Some stations plan to employ
re-use of cooling tower blowdown in wet-scrubber air
pollution control systems. Since water quality requirements
for bottom ash sluicing operations and are relatively low,
some degree of re-use should be practicable for all plants
where these operations are employed. Best available
technology economically achievable is reflected by retrofit
systems for the recycle of bottom ash transport water with a
resulting blowdown flow of 8 percent of the volume of ash
transport water treated by sedimentation to a total
suspended solids level of 30 mg/1, an oil and grease level
of 15 mg/1 and a pH value in the range 6.0 to 9.0.
Universal retrofitting of dry fly ash systems would not be
economically achievable. The concept of cascading water
use, i.e., recycle and re-use of water from applications
requiring high quality water to applications requiring
successively lower water quality, to reduce to the volume of
waste water, if any, ultimately requiring evaporation or
other treatment, while practicable in all cases, would
generally be subject to a case-by-case analysis to determine
the optimum among the various candidate systems.
Chemical treatment of blowdown from recirculating cooling
water system for removal of total chromium, total phosphorus
(as P) and zinc, while not currently demonstrated in
powerplant applications, could be achieved by 1983, in the
relatively small number of cases where it would be needed.
Corresponding effluent limitations, based on the application
of this technology, are 0.2 mg/1 total chromium, 5 mg/1
total phosphorus (as P), and 1 mg/1 zinc-total, all times
the waste water flow.
Chlorination programs to achieve no discharge of total
residual chlorine from recirculating cooling water systems
have been determined to be not fully demonstrated and
therefore cannot be generally applied by 1983.
Rainfall runoff limitations are the same as best practicable
control technology currently available.
New Source Performance Standards
In view of the current technical risks associated with the
application of distillation technology to waste water
413
-------
recycle and chlorinaticn programs to achieve no discharge of
total residual chlorine from recirculating cooling water
systems, new source performance standards have been
determined to be identical to the limitations prescribed for
best available control technology economically acheivable
with the following exceptions. Recirculating bottom ash
transport systems designed for new sources can reasonably
achieve effluent limitations based on a blowdown flow of 5
percent of the ash transport flow volume. No discharge is
allowed of corrosion inhibitors in blowdown from
recirculating evaporative cooling water system, based on the
availability of design technology for corrosion prevention.
No discharge of pollutants from nonrecirculating ash
sluicing system, based on the general availability of dry
fly ash systems and of recirculating wet bottom ash systems.
Rainfall runoff limitations are the same as best practicable
control technology currently available.
Application of Effluent Limitations Guidelines and Standards
The effluent limitations for a powerplant are determined
based on the existing or planned flow rates of the
individual waste sources at the plant and the effluent
limitations corresponding to each of the waste sources. An
example is given in Figure A-X-1 and Table A-X-1 of the
determination of the effluent limitation for a simplified
hypothetical case. The extent of the feasibility of the
flow arrangement shown is not known and is presented solely
as an example of the application of the effluent limitations
guidelines and standards. For the plant shown, the
determination of the limitations, for the metal equipment
cleaning wastes is straight-forward since there is no reuse
or combination with other wastes prior to treatment, except
that the waste waters are combined with other wastes waters
immediately prior to discharge. Boiler blowdown, however,
is combined with other waste waters prior to treatment, as
is ash transport water and seme of the waste water from
other low-volume wastes sources. Some of the cooling tower
blowdown and some of the waste waters from other low-volume
waste sources are reused directly for ash transport. A
portion of the overflow of the first stage (ash pond) of the
combined treatment of ash transport water, boiler blowdown,
and wastes from other low-volume waste sources is recycled
for use in bottom ash transport. The remainder of the ash
pond overflow receives final treatment prior to being
combined with treated metal equipment cleaning waste waters
and some of the cooling tower blowdown prior to discharge.
414
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Intake 62,890
(Jl
70
40
660
400
5,000
METAL
EQUIPMENT
CLEANING
CENTRAL TREATMENT
Slowdown
62,120
BOILER
Slowdown 40
OTHER
LOW-VOLUME
SOURCES
BOTTOM
ASH
TRANSPORT
FLY
ASH
TRANSPORT
COOLING
TOWER
4.600
5,000
5,000
ASH POND
Slowdown 7,000
Drift 120
Evaporation 50,000
OVERFLOW
TREATMENT
, f Discharge
^.
12,770
Figure A-X-T Hypothetical Powerplant Water Flows
( Flows shown in units of 1000 liters/day)
-------
Table A-X-1
Effluent Limitations for Hypothetical Powerplant
Source
Metal Equipment
Cleaning
Boiler Slowdown
Other Low-Volume
Sources
Bottom Ash
Transport
Fly Ash Transport
Cooling Tower
Blowdown
Flow,
1000 I/day
70
40
660
5,000
5,000
12,000
Total
Effluent Limitations, kg/day
TSS
2.1
(30)*
1.2
(30)
19.8
(30)
12.0
(30/12.5]
150.0
(30)
K
185.1+
Fe
0.07
(1)
0.04
(1)
N
N
N
N
0.11+
Cu
0.07
(1>
0.04
(1)
N
N
N
N
0.11+
Zn
N
N
N
N
N
12.0
(1)
12.0+
Cr
N
N
N
N
N
2.4
(0.2)
2.4+
P
N
N
N
N
N
60.0
(5)
60.0+
O&G
1.05
(15)
0.60
(15)
9.9
(15)
6.0
(15)
75.0
(15)
N
92.55+
* Note: Concentration bases, mg/1, shown in parentheses
+ Note: Plus effluent from sources with no limitation
-------
In each case, the effluent limitations for a particular
waste water source are based on the wastewater flow
emanating from that source, regardless of the subsequent
reuse, recycling, or combination of the wastewater with
other streams, and regardless of the source of the water
used by that source. A discharger may find that the reuse
of certain waste streams results in a less costly pollutant
removal scheme than one employing no reuse due to the
reduction in the final flow volume requiring treatment.
Water reuse may also be employed to reduce the volume of
water required by the plant or to reduce the cost of
influent water treatment.
In no case, however, should the effluent limitations
computed for a plant which combines waste water streams
reflect effluent reductions (mass units) less than would be
achieved by the same plant in the case that the individual
limited waste water streams are not combined with other
waste water streams that are cr are not limited. Within the
context of the above, effluent limitations computed for the
plant should not reflect the transfer from individual
limited waste water streams, whose limitations are based on
chemical precipitation and sedimentation technology, of
pollutants (other than pH) that would otherwise be removed
by chemical precipitation and sedimentation to other waste
water streams that have no limitations which reflect
chemical precipitation and sedimentation technology.
If other regulations permit allowances to be made for
pollutants brought into the plant in make-up waters, no
distinction should be made in the effluent limitations
between inert suspended solids brought into the plant and
inert suspended solids added by the plant. Suspended solids
that are not inert, such as precipitated metals, should not
be discharged in exchange for inert suspended solids in
make-up water. The requirements can generally be met by the
technology that provides the basis for the effluent
limitations developed in this document since the limits
developed are assumed to apply as gross limits.
For the purposes of estimating the costs of the application
of available technology for the reduction of pollutants
discharged from both continuous and intermittent waste
sources, it is assumed that waste waters are discharged
after treatment on a continuous and uniform basis year
round. A discharger may find, however, that an alternative
discharge schedule would be less costly or otherwise more
desireable, in which case the effluent limitations should
reflect the discharge flow volume program proposed by the
discharger.
417
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Costs
The incremental costs of controlled additions of chlorine,
in the cases where chlorine is required for biological
control, are less than 0.01 mill/kwh. In the relatively few
cases where chromates are added for corrosion control and
where other less harmful chemicals and methods can provide
effective corrosion control the incremental costs are less
than 0.01 mill per kilowatt hour. The incremental cost of
mechanical cleaning to replace some fraction of the total
required chlorine additives is approximately 0.01 mill/kwh
for existing stations and considerably less for new units
whether at new or existing plants.
Cost estimates based on the combined treatment of selected
low-volume streams for oil and grease separation, equaliza-
tion, chemical precipitation, solids separation, and further
based on generalizations with respect to the cost of land,
construction, site preparation and with respect to the waste
water volume, indicate an approximate cost of 0.1 mill per
kilowatt-hour depending upon the plant1s generating capacity
and utilization. The highest costs are associated with the
smaller plants and peaking plants which generally have the
highest basic generating cost. In general, the entire
incremental cost should be felt by individual plants since
this type of complete chemical treatment is not generally
employed.
Sedimentation of ash sluicing water, etc., would cost
typically about 7 cents/1000 gal, with the incremental cost
in mills/kwh being related to the quantitites of water
treated. Since many plants already have some type of
sedimentation facility, the incremental costs of improved
sedimentation performance if required will be some fraction
of the cost cited.
In the few cases where it would be required chemical
treatment for removal of phosphorus, total chromium or zinc
from cooling tower blowdown would cost about 0.1 mill per
kilowatt-hour. Incremental costs of dry ash handling
systems for new sources are estimated to be less than 0.01
mill/kwh and would largely depend on the economics of dry
ash disposal or sale versus wet ash disposal in specific
cases.
Recirculating ash sluicing systems require sedimentation
discussed above plus pumps, piping and a blowdown system.
Incremental costs above sedimentation are approximately 0.1
mill/kwh for existing plants and considerably less for new
plants.
418
-------
The incremental costs of equipment design for corrosion
protection are normally largely offset by other cost
benefits such as reduced costs of chemicals. The net
incremental costs for both lined cooling tower components
and stainless steel or titanium condenser tubes would be
less than 0.1 mill/kwh total. Replacement of existing
cooling tower components might be more expensive however.
Enercrv and Other Non-Water Quality Environmental Impacts
Energy requirements for technologies reflecting the
application of the best available technology economically
achievable for pollutants other than heat are less than 0.2
percent of the total plant output.
The non-water quality impacts of technologies available to
achieve limitations on pollutants other than heat are
negligible with respect to air quality, noise, water
consumption and aesthetics. Solid waste disposal problems
associated with achieving the limits required by best
practicable control technology currently available are
similarly insignificant. Systems with evaporation and
recycle of waste water will not generally create significant
amounts of solid waste. If recycle of blowdown from
evaporative recirculating cooling systems were to be
employed, however, considerable volumes of solid waste may
be generated. In most cases these are nonhazardous
substances requiring only minimal custodial care. However,
some constituents may be hazardous and may require special
consideration. In order to ensure long term protection of
the environment from these hazardous or harmful
constituents, special consideration of disposal sites may be
made. All landfill sites where such hazardous wastes are
disposed should be selected so as to prevent horizontal and
vertical migration of these contaminants to ground or
surface waters. In cases where geologic conditions may not
reasonably ensure this, adequate legal and mechanical
precautions (e.g. impervious liners) should be taken to
ensure long term protection to the environment from
hazardous materials. Where appropriate the location of
solid hazardous materials disposal sites should be
permanently recorded in the appropriate office of legal
jurisdiction.
419
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PART B
THERMAL DISCHARGES
SECTION V
WASTE CHARACTERIZATION
General
Significant thermal discharges from steam electric
powerplants occur when a powerplant utilizes a once-through
circulating water system to reject the heat not converted
into electric energy. The amount of heat energy discharged
with the circulating water is equal to the heat value of the
fuel less the heat value converted into electric energy and
miscellaneous station losses. The heat energy discharged is
therefore directly related to the efficiency of the plant.
According to industry practices, the efficiency of a gen-
erating unit is expressed as its heat rate, in units of
Joules per kwh (Btu per kwh). A new fossil-fired generating
unit may be designed for a heat rate of 9.5 million Joules
per kwh (9,000 Btu/kwh). Since one kwh is equivalent to 3.6
million J/kwh (3,413 Btu), such a plant would have an
efficiency of 38%.
The transfer of heat from the condensing steam to the cool-
ing water results in a temperature rise of the cooling
water. For a given amount of heat transfer, the temperature
rise of the cooling water is inversely proportional to its
flow. That is, one may either heat a small quantity of
water a great deal, or a large quantity of water a small
amount. On the average, temperature rises have been
centered about 9 degrees C (16 degrees F) for economic and
process considerations (Figure B-V-1). It is clear,
however, that almost any lower limit on temperature rise can
be achieved given a sufficiently large source of cooling
water and no economic constraints. It is also clear,
however, that a temperature difference reduction does not
limit the amount of heat rejection.
Quantification of Waste Stream Characteristics
The data presented below were obtained from the Federal
Power Commission and represent a summary of the data col-
lected on "FPC Form 67" for the year 1969.28° These data
have been screened to eliminate obvious inconsistancies.
The statistical analyses have been performed using standard
subroutines available from IBM in their scientific
subroutine package (1000) operating units. All units in
421
-------
MINIMUM=1
MRXIMUM=38
MEflN=15
STflNDRRO OEV = 5
o
o
o
o
o
o
o
C\J_
=2-
o
o
o
o
o
o,
r\j
5.00 10.00 15.00 . 20.00 25.00 30.00 35.00 HO.00
CONDENSER DELTR T (DEC. F)
UNIT CONDENSER DELTfl T
FIGURE B-V-1
422
-------
this sample are fossilfueled. Heat rates for the industry
are profiled in Figure B-V-2. This figure shows the mean
unit heat rate to be approximately 11.8 million Joules/kwh
(11,200 Btu/kwh) with a standard deviation of approximately
2.86 million Joules/ kwh (2,700 Btu/kwh). These statistics
are not weighted by generation. Weighted figures show the
national average heat rate to be about seven (7) percent
lower.281 Given the heat rate, one may calculate the cooling
water heat rejection for fossil plants in the following
manner:
1. Multiply the heat rate by the boiler efficiency (0.8-0.9
are reasonable efficiencies to use for this calculation)
2. Subtract from that number the energy of one (1) kwh
(3,600,000 Joules or 3,413 Btu).
3. The result is the heat rejected to the cooling water
stream.
The result obtained from this calculation is slightly higher
than the real requirement in most cases. This analysis
ignores the difference between the lower and higher heating
values of the fuel. Heat rates can be reported using high
heating values although all this energy is not available to
do work. The difference is lost forming water vapor from
the hydrogen in the fuel and oxygen in the air. Various in-
plant heat and steam losses, and the power requirements of
the plant's auxilliary equipment are also ignored. Using
this analysis, the mean plant in our sample rejects about
seven (7) million Joules (6,640 Btu) per net kwh generated.
Table B-V-1 lists heat rates, efficiencies, and waste heat
produced for a range of plants typical of the industry. The
heat rejection requirements calculated above are satisfied
by the heating of the circulating water. Figure B-V-1
indicates that the mean temperature rise (unit basis, not
weighted) of the cooling water is between eight and nine
degrees C (about 15 degrees F) with a standard deviation of
about three degrees C (5 degrees F).
Flow rates range from, about 1,100 liter/min (300 gpm) to
4,000 liter/min (1,100 gpm) for each megawatt of load.2»o
Thus a 100 Mw unit operating at capacity may discharge up to
400,000 liter/min (110,000 gpm) of water heated to nine
degrees C (15-16 degrees F) above ambient. (A more typical
number would be about two-thirds of this example based on
national heat rates).
The maximum summertime temperature of the heated effluent
varies with location, but is strongly centered (Figure B-V-
423
-------
MINIMUM=8706
MflXIMUM=27748
MERN=11216
§ STflNDflRD DEV=2710
0
CM'
o
o
o
o.
t\j
o
U3-
o
IT-
o
C\J_
o
m
^0.00 120.00 160.00 200.00 240.00 280.00 320.00 360.00 400.00
UNIT HEflT RflTE (BTU/KW-HR) *102
UNIT HEflT RflTE DISTRIBUTION
FIGURE B-V-2
424
-------
Table B-V-1
EFFICIENCIES, HEAT RATES AND HEAT REJECTED BY COOLING WATER
Plant
Efficiency,
%
38
34
29
23
17
34
29
Plant
Heat Rate
Heat Converted
to Electricity
Stack and Plant
Heat Losses
Heat Rejected
to Cooling Water
Joules per Jcwh x 10~ (Btu/kwh )
Fossil-Fueled Units
9.5 ( 9,000)
10.5 (10,000)
12.5 (12,000)
15.5 (15,000)
21.0 (20,000)
3.6 (3,400)
3.6 (3,400)
3.6 (3,400)
3.6 (3,400)
3.6 (3,400)
0.95 ( 900)
1.05 (1,000)
1.25 (1,200)
1.55 (1,500)
2.1 (2,000)
4.95 ( 4,700)
5.85 ( 5,600)
7.65 ( 7,400)
10.35 (11,100)
15.3 (14,600)
Nuclear Units
10.5 (10,000)
12.5 (12,000)
3.6 (3,400)
3.6 (3,400)
0.5 ( 500)
0.6 ( 600)
6.4 ( 6,100)
8.3 ( 8,000)
in
-------
3) about 35 degrees C (95 degrees F). It is interesting to
note the large number of plants operating at or above a
maximum summertime outfall temperature of 39 degrees C (102
degrees F). At elevated temperatures turbine efficiency
frequently begins to suffer.
Table B-V-2 summarizes data received from powerplants vis-
ited under this contract. Many of the plants visited were
among the most efficient in the nation.
The visits were, in general, made to examine unique features
in control or efficiency incorporated in the plant. These
data, therefore, represent typical values for newer modern
plants rather than an industry-wide cross section. Of some
interest, however, are the data from the nuclear plants
visited. Since all nuclear plants in utility service are
relatively new, these plants may be considered typical of
nuclear plants. It is observed that the heat rejection is
considerably higher for nuclear plants (by a factor of more
than 1.5) than for the fossil-fueled plants studied. In
addition, the temperature rise for the nuclear plants is
generally higher.
Industry-wide Variations
Heat rate varies about thirteen percent regionally.zel This
variation is due to relative equipment age, availability of
high quality fuel, and economic and other factors. For
example, the northeastern section of the country has many
old, relatively inefficient units which must be operated to
meet loading requirements. On the other hand, the western
section of the country uses a great deal of lower
heating-value lignite which contributes to its higher
average heat rate. The southeastern section of the country
can attribute its lower average heat rate to many new,
large, efficient units burning high-quality fuel. The net
effect of the regional heat rate variation on heat rejection
requirements may be as high as twenty percent (see previous
section for calculations). This number may be considered
conservative, however, since some of the regional heat rate
variation is fuel quality dependent.
Temperature 'rise varies with both heat rate and cooling
water availability. In addition, considerations such as
economics, ambient water temperature, and water quality
requirements weigh heavily upon the design cooling water
temperature rise. Thus, temperature rise requires a plant
by plant evaluation.
426
-------
MINIMUM=1
MRXIMUM=1 18
MERN=95
° STRNDRRD DEV=13
o
qin
2c.cc 40.00 eo.cc so.oo 100.00 :ao.oo mo.oo ISU.OD
MflX. OUTFRLL TEMP. (DEC. F)
MRX, SUMMER GUTFniL TEMP0
FIGURE B-V-3
427
-------
TABLE B-V-2
PLANT VISIT THERMAL DATA
Plant
0640
1209
2612
1723
3117
1201
1201
5105
2525
0801
1209
4217
4846
3713
2512
3115
2527
0610
2119
ID Fuel
Nuclear
Nuclear
Nuclear
Nuclear
Nuclear
Oil & Gas
Oil & Gas
Oil
Oil
Coal & Gas
Coal & Gas
Coal
Coal
Coal
Oil
Oil & Gas
Oil
Oil & Gas
Coal
Capacity
MM
916
1456
700
1618
457
139.8
792
1157
1165
300
820
1640
1150
2137
542.5
644.7
28
750
2534
Nuclear Averages
Fossil
Averages
Heat Rate
Joules/kwh
x 10-'
N.A.
1.1
1.1
N.A.
1.07
1.02
N.A.
1.09
.95
1.12
.99
1.03
1.05
.92
.94
1.06
1.02
1.15
N.A.
1.09
1.03
Cooling Temp.
Water Flow Rise
M3/min °C
1688
4735
1476
3564
1362
439
2002
1851
2346
1056
2078
2120
2838
3883
632
1429
94.6
1332
2937
N/A
N/A
15.6
8.9
13.9
13.3
10.0
5.7
8.5
13.2
8.2
N.A.
7.3
14.4
7.5
10.0
16.1
9.3
N.A.
10.0
13.9
12.34
10.34
Discharge Temp.
°C
Summer
30.0
40.6
N.A.
36.7
28.6
34.0
39.6
45.4
31.0
N.A.
38.9
31.7
N.A.
28.3
33.4
28.2
N.A.
36.7
N.A.
N/A
N/A
Winter
27.0
28.9
N.A.
14.4
13.9
22.3
29.1
18.2
12.7
N.A.
27.3
17.8
N.A.
17.8
22.6
13.2
N.A.
20.0
N.A.
N/A
N/A
Average
28.3
35.6
N.A.
N.A.
21.7
26.8
32.4
36.3
21.4
N.A.
33.9
26.7
N.A.
N.A.
28.0
21.0
N.A.
26.7
N.A.
N/A
N/A
Heat Dissipation
roules/Hr
X 10-9
6580
10588
5135
11916
3417
624.3
4271
6116
4840
N.A.
3786
7676
5336
9744
2552
3343
N.A.
3343
10229
N/A
N/A
Joules/kwh
X 10-6
7,194
7.27
7.349
7.37
7.48
4.466
5.39
5.285
4.156
N.A.
4.626
4.68
4.645
4.56
4.71
5.196
N.A.
4.46
4.04
7.33
4.68
N.A. - Not Available
H/A - Not Applicable
-------
Maximum temperature of the outfall varies with both ambient
temperatures and temperature rise. Thus higher temperatures
should be expected in the southern section of the country.
This expectation is somewhat mitigated by the fact that the
steam cycle has efficiency limitations beyond certain tem-
peratures. Thus, utilities economically optimize tempera-
ture rise (a lower temperature rise requires more pumping
power and/or a larger condenser) and final temperature (a
higher final temperature reduces turbine efficiency).
Therefore, regional variations in maximum summertime outfall
temperature are not as large as regional variations in
ambient water temperatures.
Seasonal variations in heat rate, temperature rise and out-
fall temperature may be significant but move in opposing
directions. That is, when the ambient temperature, the max-
imum outfall temperature and the heat rate increase, the
temperature rise, in general, falls. In many sections of
the country, the summer heat rate is higher than the winter
heat rate because many inefficient peaking plants are run
only in the summer months. This effect is in addition to
the efficiency loss created by ambient conditions. The ef-
ficiency loss is of particular concern since peak demand
usually coincides with the worst (for power generation)
ambient conditions, which can cause power shortages. Con-
versely, the wintertime heat rate (usually better than sum-
mer) occurs at a time when demand is below peak. Therefore,
the heat rejected per kwh, the total heat rejected, and the
maximum outfall temperature are all lower. While the tem-
perature rise may be higher in the winter, it can be con-
trolled by increasing the cooling water flow (which was cut
back for economic reasons to cause the higher rise in the
first place) .
Age is a frequently mentioned parameter for the thermal ef-
fluent of powerplants. Historically, plant aging has been a
double edged sword. The aging process included material and
equipment deterioration (turbine blade erosion, etc.) which
is an absolute loss over a period of time, and obsolescence
which is a relative deterioration. Recent history
indicates281, however, that there has .been no heat rate
improvement on a national basis for over a decade. There-
fore, heat rate deterioration with age is only a function of
material deterioration which is much less dramatic than the
historic cycle improvements. Furthermore, older plants are
traditionally smaller than newer plants. With the demand
for electricity increasing exponentially, the capacity
required for peaking and cycling in a system approaches the
capacity of their older plants. Therefore, the older plants
are usually derated to peaking and cycling service while the
429
-------
larger new units are base loaded. Temperature rise is not
significantly affected by age (Figure B-V-4). While the
trend has been slightly upward over the years, the increase
has been slight (largely for thermodynamic reasons).
Maximum outfall temperature has not changed materially over
the years because the two determining factors (other than
natural conditions) have changed in offsetting directions.
Unit capacity has a small effect on heat rate and virtually
no effect on temperature rise. The effect on heat rate is
due largely to engineering and capital cost considerations
and to the fact that small plants are not usually base
loaded.
Variation with Industry Grouping
Nuclear plants reject about 5051 more heat to the cooling
water per kwh than fossil plants. Fossil-fueled plants re-
ject from 10% to 20% of the available fuel energy to the
atmosphere through the stack. This energy leaves the plant
in the form of water vapor (heat of vaporization) created by
burning hydrogenous fuel and heated exhaust gases.
Nuclear plants reject virtually all their heat to the
cooling water. If this were the only factor, nuclear plants
of the same efficiency as fossil plants would reject from
18% to 43% more heat per kwh than fossil plants. However,
nuclear plants of current design (PWR, BWR) cannot produce
superheated steam for the generation cycle. For this
reason, a well-designed nuclear plant can seldom be expected
to exceed a thermal efficiency of 3U% under even ideal
conditions while well-designed, well-run fossil plants have
achieved thermal efficiencies of up to 39% as an average for
an entire year's operation (plant no. 3713) 29». Thus,
nuclear plants can be expected to reject more heat than
fossil plants for thermodynamic reasons. The sum of these
two effects yields cooling water heat rejection requirements
in the range of 50% higher for nuclear plants than for
fossil plants. The higher heat rejection requirements for
nuclear plants are usually met by increasing the cooling
water flow and slightly raising the temperature difference
across the condenser. This method is practiced to avoid the
additional thermodynamic inefficiencies associated with
higher outfall temperatures.
Nuclear plants, then, closely approximate new fossil plants
in temperature rise and maximum outfall temperature and are
significantly higher in cooling water requirements. Fossil-
fueled units can be divided into three categories, based on
hours operated per year. The lowest group are operated less
430
-------
cc
EJ
z"
o
CJ
• LEGEND
HI RLL UNITS IN INVENTORY
B r! ,; H r- = 3 B c T.
n KJ n a ?:Ssnn
H g _, E
E a
B § = K !5aB T, n
^ffi-r, m "naif
s a
g a
KB a nE23^aaaa
"
9aSaa"aciaa
-a a
D
-j ---j a tj LJ- 4J a—C3 ts ip -i_; u t_i ifj i_r (_i u u ] ti j cs cj 1 a—(
TKOO 5.00 10.00 15.00 20.00 25.00 30.00 3CJ.OO UC.OO
UNIT RGE IN YEflRS
DELTfl T VS UNIT RGE
FIGURE B-V-4
431
-------
than two thousand (2,000) hours per year. The intermediate
group are operated more than two thousand (2,000) and less
than six thousand (6,000) hours per year, while the highest
groups are operated more than six thousand (6,000) hours per
year.
The highest group heat rates average 11.25 million Joules
per kwh (10,636 Btu/kwh, see Figure B-V-5) with a standard
deviation of about 3.1 million Joules per kwh (2,100
Btu/kwh). Intermediate group heat rates average about 13.3
million Joules per kwh (12,U9U Btu/kwh, see Figure B-V-6)
with a standard deviation of about 3.1 million Joules per
kwh (2,950 Btu/kwh), while the lowest group averages about
16.6 million Joules per kwh (15,793 Btu/kwh, see Figure B-V-
7) with a standard deviation of U.72 million Joules per kwh
(4,U80 Btu/kwh). The variation in the heat rate mean is
over forty-seven percent, with heat rate varying inversely
with utilization. The variation in cooling water heat
rejection requirements is clearly higher than the variation
in heat rate since the major portion of the additional heat
must be rejected to the cooling water. This is only true
when the plant is on-line. If a plant is on hot standby,
the heat is rejected to the atmosphere through the stack.
The impact of the increased heat rate is reduced sharply by
two factors. The units with the higher heat rates are on-
line less than the most utilized units and produce far less
electric power. As a result, the total heat rejection per
year is far less than for the most utilized units.
Furthermore, a significant contribution to the high heat
rates of the less utilized units is the practice of keeping
these units on hot standby during periods when the
probability of peaking demands is high. During these
periods, these units produce no electricity and, therefore,
have an infinite heat rate but reject little or no heat to
•the cooling water. Thus, the heat rate figures for the
least utilized plants tend to be misleading (on the high
side) as well as less important than those for the most
utilized.
(It should again be noted that all statistics in this
section are unweighted arithmetic means. Weighing averages
by generation would produce lower heat rates, and,
therefore, lower cooling water heat rejection requirements).
Condenser temperature rise does not vary with industry
categorization (for fossil units). The mean for all three
groups (based en hours operated per year) is about eight to
nine degrees C (15-16 degrees F) with a standard deviation
of a little under tnree degrees C (5 degrees F). (See
figures B-V-8, B-V-9, and B-V-10).
432
-------
o
o
a
="0
MINIMUM-8705
MERN-1CS36
STRNDRRD DEV-2095
,
^"o.OO 120.00 16b7ob"~"20oTbo" "2140.00 280.00 320.00 ""'36cT.LoT'J""4'ooTob
HERT RflTE (BTU/KW-HR)- *1C~
BflSE UNIT HEflT RflTES
FIGURE B-V-5
433
-------
MINIMUM=8735
MRXIMUM=27748
MEflN=12493
STRNORRD DEV=2951
aa aa
nguaanmBEi
-T$ , 1 ta—| unmaiLj—iMUjijjmjmumjmij ipumi^uji^m^iumMmjm^ujm^iijujujiiJuiuuLjLLmjijR^uJUJ^JUJUium
^0.00 120.00 160.00 200.00 240.00 280.00 320.00 360.00 400.00
HERT RRTE IBTU/KW-HR) xlO'
CYCLING UNIT HERT' RflTES
FIGURE B-V-6
434
-------
CD
I—
20
==:
<\j'
o
do
LjjO
o-wH
O
UJtC
2:"
z
3 3
MINIMUM=87?7
MHXIMUM=27315
MERN=15793
STRNDRRD
33 33 3 £33 3 333
^0.00 120.00 160.00 200.00 240.00 280.00 320.00 360.00 400.00
HEflT RflTE (BTU/KW-HR) «102
PERKING UNIT HERT RRTES
FIGURE B-V-7
435
-------
0
oj
o
o
CO
cc°
o
° I
o
o
MINIMUM=1
MRXIMUM=32
MERN=15
STflNDflRO DEV=5
a a
a
4'.00 S'.OO 12.00 16.00 20.00 24.00 28.00 32.00
CONDENSER DELTfl T (DEC. F)
BflSE UNIT CONDENSER DELTfl T
FIGURE B-V-8
436
-------
MINIMUM=1
r\j
O
-"O
CJO
O
erg
UJ •
CD10-
MERN=15
STRNDRRD DEV=--5
an
o
o
4.00 8.00 12.00 16.00 .OO >4.00 28.00 2.00
CONDENSER DELTR T (DEC. F)
CYCLING UNIT CONDENSER DEL T
FIGURE B-V-9
437
-------
MINIMUM=9
MRXIMUM=38
MERN=16
STflNDRRD DEV
do
O
o
o
o
o
o
o
12.00 16.00 20.00 24.00 28.00 32.00 36.00 UO.OO
CONDENSER DELTfl T (DEC. F)
PERKING UNIT CONDENSER DEL T
FIGURE B-V-10
433
-------
Maximum outfall temperature will not vary with industry
grouping since it is the sum of ambient water temperature
(which is unrelated to grouping) and temperature rise across
the condenser (which does not vary with grouping).
In summary, the only waste stream characteristic which
varies with industry grouping is the quantity of heat
rejected to the cooling water. The other characteristics
vary with locale, season, etc., and require site-by-site
evaluation to draw any reasonable conclusion.
Finally, Table B-V-3 summarizes typical waste stream charac-
teristic ranges for each grouping.
Effluent Heat Characteristics from Systems Other Than Main
Condenser Cooling Water
Waste heat from house service water systems and other
smaller sources can contribute about 1X of the total
effluent heat discharged from a generating plant. For
example, the thermal discharges of one nuclear plant (no.
4251) are shown in Table B-V-4. House service water systems
can be either once-through (nonrecirculatory) or
recirculating. Nuclear plants have emergency core cooling
systems connected to the house service water system. Where
closed house service water systems are used for nuclear
plants, U.S. Atomic Energy Commission Safety Guide 27
requires (indirectly) that sufficient water be stored on-
site (storage pond) to assure an ultimate heat sink for
safety purposes.
Environmental Risks of Powerplants Heat Discharges
Reference U46 reports the results of analyses of the
environmental risks associated with thermal discharges from
powerplants by age, size, etc. based on a random sample of
180 plants with 455 units. The sample represents one-
seventh of the U.S. generating capacity through 1978.
439
-------
it*
£t
O
Table B-V-3
TYPICAL CHARACTERISTICS OF WASTE HEAT REJECTION
_— — _— — !
Grouping
Nuclear
Fossil (Nat-
ional Average)
Reference 281
High Utilization
Intermediate
Utilization
Low Utilization
r
Heat Rate,
Joules/ kwh
x 10~7
1.02 - 1.16
1.11
0.92 - 1.32
1.05 - 1.69
1.05 - 2.1
Heat Rejection to Water*
Joules /kwh
x 10
0.72 - 0.80
0.58
0.42 - 0.80
0.53 - 1.07
0.53 - 1.43
Temperature Rise,
°C
10 - 16
8.6
4.5-13
4.5-13
4.5-11
* Note: Calculated by method discussed in this section for fossil-fueled plants
and from Table B-V-2 for nuclear plants,,
-------
Table B-V-4
TOTAL PLANT THERMAL DISCHARGES
Plant No. 4251 (nuclear)
Cooling Water System
Main Condenser
Primary Plant Components
Secondary Plant Components
Centrifugal Water Chiller
Control Room Air Conditioner
Steam Generator Blowdown
(Discharged 1 hr out of
every 100 hr)
Flowrate, gpm
480,400
5,800
11,000
3,000
200
50 max
AT, °F
26
22
10
9
10
120
Heat, Btu/hr x 10~6
6,290
66*
55
13
1
3 max
* Note: 175 x 10 Btu/hr during plant cooldown once a year.
-------
PART B
THERMAL DISCHARGES
SECTION VI
SELECTION OF POLLUTANT PARAMETER
Rationale
The Act, Section 502(6), defines heat as a pollutant.
The purpose of this analysis is to suggest a functional
parameter reflecting the level of effluent heat reductions
achievable by the application of available control and
treatment technology for steam electric powerplants. The
determination of a suitable parameter for measuring the
thermal component of the effluent is an essential part of
the work in developing effluent limitation guidelines for
thermal discharges.
The change that has occurred in the cooling water passing
through the condenser is an increase in its internal energy.
This term is also called "heat content". The change in
internal energy or heat content is a product of the mass
rate of water flow, its temperature increase, and its
average specific heat.
Both the temperature increase of the cooling water and its
discharge temperature do not include the quantity of water
discharged at this temperature level, and thus do not
reflect the total energy or heat discharged. A parameter
based on temperature alone, therefore, would not be a
reflection of the effluent heat in the discharge. To
adequately evaluate the heat rejection to a receiving water-
body, a parameter reflecting total internal energy of the
discharge is required.
The parameter that has been chosen in this report to
represent the effluent thermal characteristics is the total
increase in internal energy or heat content of the cooling
water. This parameter directly reflects that change in the
effluent which results in thermal effects.
The increase in internal energy or heat content of the
cooling water is a function of the size of the powerplant.
In order to compare different size plants, the increase in
internal energy must be determined per kilowatt hour of
plant output for each case. The increase in internal energy
443
-------
or heat content of the condenser cooling water is determined
as follows:
U = m x ex T
kw
Where 0 = increase in internal energy of
condenser cooling water
m = mass flow rate of cooling water
c = specific heat of cooling water
T = temperature increase of cooling water
kw = unit power output
With commonly used sets of units U would be expressed in
J/kwh (Btu/kwh) . Dimensionally, m is expressed kg/hr
(Ibs/hr) cf cooling water, c = 4.186 J/kg/°C (1 Btu/lb/°F)
and T is expressed in °C (°F)
For example, consider a powerplant with the following
conditions:
Power output: kw = 225 x 10 kilowatts
Cooling water flowrate: m = 2.72 x 10 kg/hr (6.0 x 10 Ibs/hr)
Temperature increase of cooling water: T = 11.1°C (20°F)
Specific heat of cooling water: C = U.186 x 10 J/kg/°C (1 Btu/lb/°F)
The resultant internal energy increase is:
U = 2.72 x 10 fU.186 x 10 1 (11.U = 5626 x 10 J/kwh
225~x 10
or in English units:
U = 6.10_x_10 111_J[201 = 533 Etu/kwh
~225~x 10
This parameter provides a measure of the heat rejected to
the receiving waterhody in a manner which can be readily
monitored. The only quantities in the equation requiring
measurement are the cooling water flow and temperature rise
and power output of the unit. Each of these can be
monitored directly without difficulty and utilized in a
444
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straightforward manner to compute the increase in internal
energy or heat content.
Environmental Significance of Effluent Heat
The effects of effluent heat on the environment are
generally correlated with water temperature.
Temperature is one of the most important and influential
water quality characteristics. Temperature determines those
species that may be present; it activates the hatching of
young, regulates their activity, and stimulates or
suppresses their growth and development; it attracts, and
may kill when the water becomes tco hot or becomes chilled
too suddenly. Colder water generally suppresses
development. Warmer water generally accelerates activity
and may be a primary cause of aquatic plant nuisances when
other environmental factors are suitable.
Temperature is a prime regulator of natural processes within
the water environment. It governs physiological functions
in organisms and, acting directly or indirectly in
combination with other water quality constituents, it
affects aquatic life with each change. These effects
include chemical reaction rates, enzymatic functions,
molecular movements, and molecular exchanges between
membranes within and between the physiological systems and
the organs of an animal.
Chemical reaction rates vary with temperature and generally
increase as the temperature is increased. The solubility of
gases in water varies with temperature. Dissolved oxygen is
decreased by the decay or decomposition of dissolved organic
substances and the decay rate increases as the temperature
of the water increases reaching a maximum at about 30°C
(86°F). The temperature of stream water, even during
summer, is below the optimum for pollution-associated
bacteria. Increasing the water temperature increases the
bacterial multiplication rate when the environment is
favorable and the food supply is abundant.
Reproduction cycles may be changed significantly by
increased temperature because this function takes place
under restricted temperature ranges. Spawning may not occur
at all because temperatures are too high. Thus, a fish
population may exist in a heated area only by continued
immigration. Disregarding the decreased reproductive
potential, water temperatures need not reach lethal levels
to decimate a species, temperatures that favor competitors,
445
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predators, parasites, and disease can destroy a species at
levels far below those that are lethal.
Fish food organisms are altered severely when temperatures
approach or exceed 90°F. Predominant algal species change,
primary production is decreased, and bottom associated
organisms may be depleted or altered drastically in numbers
and distribution. Increased water temperatures may cause
aquatic plant nuisances when other environmental factors are
favorable.
Synergistic actions of pollutants are more severe at higher
water temperatures. Given amounts of domestic sewage,
refinery wastes, oils, tars, insecticides, detergents, and
fertilizers more rapidly deplete oxygen in water at higher
temperatures, and the respective toxicities are likewise
increased.
When water temperatures increase, the predominant algal
species may change from diatoms to green algae, and finally
at high temperatures to blue-green algae, because of species
temperature preferentials. Blue-green algae can cause
serious odor problems. The number and distribution of
benthic organisms decreases as water temperatures increase
above 90°F, which is close to the tolerance limit for the
population. This could seriously affect certain fish that
depend on benthic organisms as a food source.
The cost of fish being attracted to heated water in winter
months may be considerable, due to fish mortalities that may
result when the fish return to the cooler water.
Rising temperatures stimulate the decomposition of sludge,
formation of sludge gas, multiplication of saprophytic
bacteria and fungi (particularly in the presence of organic
wastes), and the consumption of oxygen by putrefactive
processes, thus affecting the esthetic value of a water
course.
In general, marine water temperatures do not change as
rapidly or range as widely as those of freshwaters. Marine
and estuarine fishes, therefore, are less tolerant of
temperature variation. Although this limited tolerance is
greater in estuarine than in open water marine species,
temperature changes are more important to those fishes in
estuaries and bays than to those in open marine areas,
because of the nursery and replenishment functions of the
estuary that can be adversely affected by extreme
temperature changes.
446
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PART B
THERMAL DISCHARGES
SECTION VII
CONTROL AND TREATMENT TECHNOLOGY
Introduction
This section contains a general discussion of the various
methods for controlling thermal discharge from steam
electric power stations. There are three methods available
to reduce the gross amount of heat rejected to receiving
waters from the steam electric power generation process.
These methods are:
. process change
. waste heat utilization
. cooling water treatment
Various process changes can be made to the basic Rankine
cycle to increase its thermal efficiency. These process
changes include increasing boiler temperature and pressure
rating, the addition of reheat and regenerative cycles and
reducing turbine exhaust pressure. In addition, the Rankine
cycle can be replaced with other forms of generation which
are inherently non-polluting. Several of these new forms of
generation are already available, such as the gas turbine
Brayton cycle and the combined cycle plant. Looking to the
future, transfer of gas turbine technology from the
aerospace industry offers the promise of gross plant thermal
efficiencies approaching 50% in the latter part of the
decade. Since the gas turbine is air cooled, its increased
use can significantly reduce heat rejection to receiving
waters.
The replacement of the conventional Rankine steam plant with
other forms of power generation is also receiving increased
attention. It is anticipated that conservation of available
energy resources will require larger expenditures in coal
research and in the development of new power generation
technologies which do not require fluid fossil fuel. These
new generation technologies include solar generation, fuel
cells, MHD and geothermal power. In the nuclear power
field, the production of a demonstrator breeder reactor by
the end of the decade will lead to higher thermal
efficiencies in nuclear power generation.
447
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The utilization of portions of heat contained in the
discharge of condenser cooling water can reduce the amount
of heat rejected from steam electric powerplants. There are
two different ways in which power station waste heat can be
beneficially employed by others. This first is to use the
low grade heat contained in the condenser cooling water
itself. Several small-scale projects for utilizing low-
grade heat (mostly for agriculture and aquaculture purposes)
will be described, other uses for partially expanded steam
(extraction steam utilization) for industrial process steam,
space heating and cooling, and water desalting have been
practiced at several locations in conjunction with electric
power generation. The use of extraction steam methods
generally involves a degradation of the power cycle since
the steam at the extraction point has significant enthalpy
remaining. Because of this loss of cycle efficiency,
extraction steam utilization tends to raise the heat dis-
charged as measured in Joules/kwh. It is necessary in
evaluating this type of alternate use of steam to combine
both the powerplant and the alternate use to determine the
benefits derived.
The major weakness of most programs of low-grade heat
utilization and single-purpose extraction steam utilization
is that many of the alternate uses of the available heat are
seasonal. This means that the additional costs associated
with providing the steam distribution systems must be
written off over relatively few hours during the year. It
also means that the full amount of heat must be discharged
to the waterway during those periods when the secondary heat
consumers are not operating. This weakness largely defeats
the purpose of employing low-grade heat utilization systems.
The total energy concept seeks to overcome this shortcoming
by aggregating all uses of heat in a region to fully utilize
available energy on a year-round basis. Most total energy
systems in this country are small, consisting of individual
shopping centers, educational complexes and commercial
developments. Larger total energy systems exist in Europe.
It is felt that the rapidly increasing cost of energy
brought about by greater worldwide competition for the
earth's remaining fossil-fuel resources will make the total
energy concept more attractive in the future. Several
different waste heat utilization projects will be described.
A number of different technologies have been applied to
condenser cooling water discharges to reduce heat rejected
to the waterways. Three basic treatment options are
available; open cooling systems, closed cooling systems, and
combinations of the two. Open cooling systems discharge the
full condenser flow following supplemental cooling. Closed
448
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systems recycle the bulk of the circulating water flow back
to the condenser following supplemental cooling and
discharge a small fraction as blowdown to control salinity
buildup in the system.
Open cooling systems employing evaporative cooling have the
basic disadvantage of not being able to maintain a desired
level of treatment year-round due to seasonal variations in
wet bulb temperature. Open cooling systems have a distinct
advantage over closed systems in that they do not affect the
turbine backpressure. A closed cooling system can produce a
low-level heat discharge year-round at the expense of
increased turbine backpressures. Increasing turbine
backpressure entails increased station cost above the cost
associated with the cooling system. These additional costs
are incurred to buy replacement power for those periods when
the station (because of high backpressures) cannot produce
its rated capacity (capacity penalty) and also to pay for
increased fuel cost for less efficient turbine performance
(energy penalty). Both open systems and closed systems
require additional power to operate pumps, fans, etc., which
affects station capacity and fuel cost to some degree.
Incremental capacity and fuel costs are higher for
backfitting existing units than for new units.
Most existing treatment of condenser cooling water has been
designed to operate in a recycle mode. These systems have
generally teen installed where sufficient water for once-
through cooling was unavailable. Some closed systems are
designed to allow open system operation for a portion of the
year. All of the available cooling water treatment tech-
nologies will be described in this section.
Process Change
Background
In order to properly understand both the problems and
possible solutions regarding thermal discharges from power-
plants, it is necessary to review a few essential thermo-
dynamic principles. Only those principles that directly
relate to the situation being investigated will be
discussed. They will be presented in simplified terms,
allowing a small relaxation cf rigorous scientific
exactitude.
The discussion is presented in three steps. First presented
are principles, and then shown how they affect the steam
electric powerplant cycle. Next, historic developments are
reviewed, relating them to the principles. This is
449
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important to understanding some approaches to improving
plants in regard to thermal effects. Finally, we have
related principles as guides to possible new types of power
generating systems with improved thermal effects
characteristics.
Thermodynamics is the study of the conversion of energy from
one form to another, particularly the forms of energy called
"heat" and "work". The purpose of a steam electric
powerplant is to convert heat into work or power, which is
the rate of work. Thus, steam electric powerplants are
directly concerned with thermodynamics. Important questions
to pose about this process of getting work from heat are:
1. How can we increase the amount of work obtainable from a
given amount of heat?
2. Is there a limit to how much work obtainable from a
given amount of heat?
3. What happens to the heat that is not converted into
work?
Thermodynamics is based largely on two laws. These are
called the "First Law" and "Second Law". Before stating
these laws, it is necessary to include a few definitions of
words or phrases used in the statements of these laws, or in
explaining them.
Keat engine {powerplant) - a device or plant used to convert
heat into work.
Energy - the ability to do work. Heat and work are both
forms of energy. Work may appear as mechanical energy (such
as the rotation of a wheel) or electrical energy.
Cycle - the processes or changes which the working fluid of
heat engine (powerplant) goes through.
\
Efficiency - the proportion of energy input (heat) to a
powerplant which is converted to energy output (work).
Reservoir - an energy source or an energy receiver.
There are a number of ways of stating the laws of thermo-
dynamics. We have chosen a special phrasing that seems most
applicable to this study. It should be remembered that this
is a restricted non-rigorous statement.
450
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First Law - the total energy supplied to a powerplant must
be removed from the plant.
This statement is akin to the conservation of energy
interpretation of the First Law, i.e., there must be a
budget or accounting of the energy, and this budget must
balance.
Figure E-VII-1 shows a simplified example of the energy flow
for a power producing engine or plant.
The powerplant receives energy in the form of heat from
combustion of fossil fuels, or from nuclear reaction. Some
of this energy is converted to a useful output in the form
of work (electricity). There is also heat energy output
from the plant. This is mainly the energy associated with
thermal discharge to receiving waters.
The First Law, which requires an energy balance, thus can be
stated in equational form for this example as:
Energy In (Heat) = Energy Out (Work) + Energy Out (Heat)
or rearranging Energy Out (Heat) = Energy In (Heat) -
Energy Out (Work)
The importance of this for thermal discharges is that once
the proportion of Heat Energy In that is converted to Work
Energy Out is determined, the remainder is a source of
thermal discharge. For example, in Figure B-VII-2 relative
values of energy are indicated for a hypothetical
powerplant. For this plant, for every 100 units of energy
input, HO units are converted to useful work. The First Law
reveals that inexorably there are 60 units of energy that
must be rejected to the surroundings. (The relative values
in this example- are close to those typical of modern steam
electric powerplants).
Note however, that the First Law does not require that any
heat be rejected from the powerplant. It only says that we
cannot produce more energy in the form of work than the
quantity of energy (in the form of heat) supplied. At this
point, the following might be asked:
"Does the energy rejected have to be in the form of
heat?" "Can we build a plant with a better efficiency
than in the example cited, which seems pretty
inefficient (40X)?" "Is there any limit on efficiency,
other than economic considerations? This is, can we
reduce the heat rejected to the environment, without
limit?"
451
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ENERGY IN
(HEAT)
POWER
PLANT
ENERGY OUT
(WORK)
ENERGY OUT
(HEAT)
FIGURE B-VII-1 ENERGY FLOW FOR A POWER PLANT
100 ENERGY UNITS IN
(HEAT)
POWER
PLANT
40 ENERGY UNITS OUT
(WORK)
60 ENERGY UNITS OUT
(HEAT)
FIGURE B-VII-2 ENERGY BALANCE FOR A POWER PLANT (FIRST LAW)
452
-------
Such questions have important implications. They lead to a
statement of the Second Law of Thermodynamics:
"It is impossible for a powerplant to receive heat
energy from a source and to produce the same amount of
energy as work."
It might be noted at this point that the Second Law of
Thermodynamics cannot be proven from other principles. It
is a conclusion reached by experience: observation and
experimentation. We can picture a powerplant that . would
violate the Second Law as stated in Figure B-VII-3. Note
that it does not violate the First Law. In order to bring
this powerplant into conformity with the Second Law, we try
to rearrange its operation as shown in Figure B-VII-U. We
are not producing the same amount of energy as work, as was
supplied in the form of heat. But now we are violating the
First Law, as there is an energy unbalance.
In order to make this plant conform to both laws, we must
rearrange its operation as shown in Figure B-VII-5.
The remaining 60 energy units in the form of heat must be
rejected tc the receiver, which is the environment.
Based on our senses and experience, we are usually
psychologically comfortable with the First Law. It
expresses a principle that a budget must balance. Yet the
Second Law may seem irrational. There seems to be nothing
unnatural in having a powerplant receive heat energy and, as
a result, produce some power with no other results or
effects occurring. Nevertheless, evidence indicates that
such a powerplant cannot be built. Some heat must be
rejected. But how much? Could we build a powerplant that
is 99% efficient, if we considered it financially feasible,
thus rejecting a negligible quantity of heat to the
environment?
There is an upper limit on the efficiency of any powerplant.
This limit is that provided by a powerplant that operates on
a completely reversible cycle. In this type of cycle, the
plant receives heat only at a constant temperature and
rejects heat only at a constant temperature. In addition,
there are no losses such as friction in any of the processes
taking place. The efficiency of such a powerplant depends
only on the temperature at which the plant receives heat
from the source, and the temperature at which it rejects
heat to the surroundings.
453
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100 ENERGY
UNITS IN
POWER
PLANT
100 ENERGY UNITS
OUT (WORK)
FIGURE B-VII-3 POWER PLANT VIOLATING SECOND LAW
100 ENERGY
UNITS IN
POWER
PLANT
40 ENERGY UNIT3
OUT (WORK)
FIGURE B-VII-4 POWER PLANT VIOLATING FIRST LAW
454
-------
100 ENERGY
UNITS IN
POWER
PLANT
40 ENERGY UNITS
OUT (WORK)
60 ENERGY
UNITS OUT
m
FIGURE B-VII-5 POWER PLANT CONFORMING TO FIRST AND SECOND LAW
-------
The efficiency of this type of plant can be determined from
the following equation:
Ere = 100 (1-T2) (1)
Tl
where Ere = efficiency of reversible cycle powerplant
Tl = temperature at which plant receives heat
from heat source, expressed in absolute units
T2 = temperature at which plant rejects heat to
surroundings expressed in absolute units
This equation'can be derived from the Second Law of Thermo-
dynamics, in a somewhat lengthy procedure. There are a
number of these completely reversible cycles that have been
conceived of. The best known is called the Carnot cycle.
For this reason, the above efficiency is often called the
Carnot Efficiency, although any cycle that meets the
specified conditions will have the same efficiency.
It will be instructive to determine what the efficiency of a
completely reversible cycle would be for temperatures
representative of modern steam electric powerplants. The
maximum temperature at which a plant receives heat is about
600°C (1,000°F). This is a limit resulting from the
decreasing strength of metals at elevated temperatures. The
minimum temperature at which a plant rejects heat is about
32°C (90°F). This is a limit resulting from the available
temperature of normal surroundings, unless a plant could
reject heat to outer space at absolute zero, -273°C (-
«460°F) .
Converting these temperatures to their absolute values,
(degrees Rankine), and calculating the efficiency:
Tl = 1000 + 460 = 1460°R
T2 = 90 + 460 = 550°R
Ere = 100 (1-550) =62%
1460
This is the highest efficiency that can be reached by any
powerplant operating within these temperature limits. The
efficiency of the most modern powerplants incorporating the
best technology features, operating within these temperature
limits, reaches 40fl. These modern powerplants achieve a
quite high efficiency, relative to the maximum. If one does
456
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not consider the Second Law limitations, 40% seems a low
figure, and we might conclude that great increases in
efficiency could be made with reasonable research
investment. But in reality, the "perfect" powerplant under
these conditions is itself only 62% efficient. Thus, an
actual modern powerplant has an efficiency relative to the
theoretical possible of:
Relative Efficiency = 40 x 100 = 65%
64
Considering additionally, the minimum practical losses in
each of the components in a powerplant, even the relative
efficiency of 65% is low as an indicator of the likelihood
of further improvements in the existing steam electric
powerplant cycle. In any case, even with the best
theoretical cycle, the same basic problem would exist of
discharging large amounts of waste heat to the surroundings,
since only about a 33% reduction in present thermal
discharges would be accomplished.
Referring to Equation (1), note that the efficiency of the
completely reversible cycle is increased by raising Tl or
lowering T2, and that 100% efficiency can be achieved only
with an absolute zero temperature T2, or approached with an
infinite temperature Tl.
History of the Steam Electric Power Plant Cycle
In this section, we will outline the chronological
development of the thermodynamic cycle of the steam electric
powerplant. The purpose of this approach is to indicate
what methods have been developed to improve cycle
efficiency, and indirectly reduce the heat discharged to the
environment. This will aid in understanding problems and
possible directions for future cycle improvements.
The discussion should begin with a description of a
completely reversible cycle, as it is the best theoretically
achievable. In this way, each actual powerplant development
may be compared to the paragon.
The Carnot cycle is chosen as the completely reversible
cycle to describe. Figure B-VII-6 shows the basic
components of the Carnot steam powerplant cycle: boiler,
turbine, condenser and compressor. The components are
connected by piping as shown, with the direction of flow of
the fluid between them as indicated.
457
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POWER OUT
m
00
BOILER
POWER IN
FIGURE B-VII-6 CARNOT CYCLE STEAM POWER PLANT
-------
The heat source may be combustion of fossil fuel or nuclear
reaction (or recently geothermal heat). Heat is transferred
from the source to water in the boiler. The water enters
the boiler in a saturated liquid condition. This means that
it is at a temperature where it will begin to boil when
heated. It does not need to be heated up to boiling
temperature. The water is completely evaporated, and it
leaves as saturated steam. This means that it has been
completely converted to vapor, but its temperature has not
increased. (Further heating of the vapor to a higher
temperature produces superheated steam).
The steam then flows to a steam turbine, where its energy is
used to rotate a shaft and generate power. In so doing, the
steam temperature and pressure drop considerably in the
turbine. Steam leaving the turbine flows to the condenser,
where heat is removed from it.
The condenser removes enough heat to partially condense the
steam entering. Thus a mixture of liquid and vapor leaves
the condenser. The temperature of the condensing steam does
not change during the process. This mixture is then com-
pressed in a compressor. This compression process raises
the temperature and pressure of the fluid, and also causes
the condensation of the remaining vapor. The result is that
the fluid leaves the compressor at the pre-determined con-
ditions set for the boiler, as a saturated liquid. Note
that power is required to operate the compressor.
As heat is added in the boiler at a constant temperature and
removed in the condenser at a constant temperature, and
assuming no losses in any equipment, the cycle will be a
completely reversible one, with the maximum efficiency
possible for the temperatures specified.
With this paragon continually in mind as a reference
standard, let us now turn to the historical development of
tne actual cycles used in the steam electric powerplant. We
have observed that the cycle modifications and developments
improved efficiency, usually however, at the expense of
increased plant complexity. We also note that the
developments brought the actual cycle closer to some of the
features of the Carnot cycle, which being the best possible,
is not a surprising development. Yet the Carnot cycle
itself has great practical deficiencies.
It. is worth noting that the development of the cycle was
largely accomplished by inventive-minded engineers, and to a
areat extent at a time before thermodynamics was a fully
understood or applied science.
459
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Rankine Cycle
Named after the engineer W. J. M. Rankine (1820-1872) ,
Professor at the University of Glasgow, the components and
flow for this cycle are shown in Figure B-VII-7.
The cycle has four basic components: boiler, turbine, con-
denser and pump. A heat source furnishes heat to the
boiler, water entering the boiler is first heated up to its
saturation temperature and then evaporated completely. The
steam flows
to the turbine where its energy is used to rotate a shaft
and generate power. The steam leaves the turbine at a lower
temperature and pressure, and flows to the condenser. Here
the steam is completely condensed to liquid water by remov-
ing heat. A pump delivers the feedwater to the boiler at
the boiler pressure. Some of the heat is added in the
boiler to the water, which is at a temperature lower than it
would be in the boiler in a Carnot cycle at the same maximum
temperature. Thus the efficiency of the Rankine cycle will
be lower than that of the Carnot cycle.
Rankine Cycle with Superheat
Even at very high pressures, the boiling temperature of
water is considerably lower than can be achieved in the
boiler, with present technology. Recalling the fact that
the higher the temperature at which heat is added to the
plant, the greater the efficiency, this means that with the
Rankine cycle, efficiency is unnecessarily restricted.
A relatively simple means of improving this situation is to
superheat the steam. A schematic flow diagram of the
Rankine cycle with superheat is shown in Figure B-VI1-8.
After the water has been completely evaporated, the steam is
superheated to a higher temperature, within metallurgical
limits. AS the average temperature at which heat is
supplied to the plant is higher than with the simple Rankine
cycle, a higher efficiency will result.
Regenerative Cycle
Kith the Rankine cycle, water entering the boiler is at a
relatively low temperature, i.e. the temperature at which it
is condensed in the condenser. As with the Carnot cycle,
the lower the condensing temperature, the greater the
efficiency. However, with the Rankine cycle, having this
cool water entering the boiler means that a good part of the
heat is added to the working fluid at an average temperature
considerably below the iraximum.
460
-------
cr>
IN
'POWER
OUT
BOILER
POWER
IN
FIGURE B-VII-7 RANKINE CYCLE POWER PLANT
-------
a\
ro
SUPERHEATER
V
I HEAT
SOURCE
HEAT
IN
BOILER
POWER
OUT
TURBINE
CONDENSER / HEAT
OUT
POWER
IN
FIGURE B-VII-8 RANKINE CYCLE WITH SUPERHEAT POWER PLANT
-------
If the average temperature at which heat is added could be
increased, the cycle efficiency would improve. This is the
basis for the regenerative cycle. A schematic flow diagram
with components for one version of the regenerative cycle
shown in Figure B-VII-9.
In this cycle, the boiler feed water is preheated in a
heater before entering the boiler, by means of steam at an
intermediate temperature and pressure bled from the steam
turbine. The water entering the boiler is therefore at a
higher temperature than it would be with the Rankine cycle.
The heat added from the external source will now be added in
the boiler at a higher average temperature, and the cycle
efficiency will be higher.
To increase the efficiency still further, a few heaters in
series can be used, with steam bled from the turbine at
progressively different conditions. of course, the
complexity and cost of the plant increases with more
heaters.
As the number of feedwater heating stages increases, the
regenerative cycle more closely approaches the Carnot cycle,
because less of the heat is added externally at lower than
maximum temperatures (more is being added internally - hence
the word regenerative). The question naturally arises as to
why the Carnot cycle itself is not used, as it has a greater
efficiency, and would avoid the complexity and expense of
the feedwater heating stages.
In actual conditions, the Carnot cycle applied to real
equipment would have a poor efficiency. The turbines, pumps
and compressors have losses due to mechanical friction,
fluid turbulence and similar phenomenae. Thus the pump and
compressor will require more power to operate than under
ideal conditions. It is the nature of the Carnot cycle that
the compressor is a very large power consuming device. In a
real plant, the actual power to operate this compressor
would reduce the actual plant efficiency considerably. The
Rankine cycle does not suffer from this shortcoming, as the
pump requires relatively only a small amount of power.
Reheat Cycle
As the steam expands in the turbine, in addition to its
temperature and pressure dropping, it begins to condense.
The result is that in the latter stages of the turbine
liquid water droplets form. Only a small amount of moisture
can be tolerated, due to possible erosion of the turbine
blades and reduction of turbine efficiency. Depending on
463
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HEAT IN
CTl
POWER IN
POWER OUT
. HEAT OUT
CONDENSER/ _ / HEAT >
RESERVOIR/
FIGURE B-VII-9 REGENERATIVE CYCLE POWER PLANT
-------
the inlet temperature and pressure, if the designer attempts
to use the minimum condensing temperature available, the
moisture content in the turbine might be excessive. In that
case, he would have to design the Rankine or regenerative
cycle with a higher condensing temperature and suffer a loss
of efficiency.
A method of overcoming this difficulty is with the reheat
cycle. Figure B-VII-10 is a flow diagram of a typical
reheat cycle.
Steam leaving the superheater enters a high pressure
turbine. The steam does not expand in this turbine to a
temperature low enough to create excess moisture. The steam
leaving the turbine is reheated at the lower pressure back
to a high temperature. It then flows to a low pressure
turbine where it can be expanded down to the minimum
condensing temperature without excess moisture being created
in the turbine. The reheat cycle can be combined with the
regenerative cycle also, in a similar manner.
Historical Process Changes
Changes in existing processes or their conditions may be
considered as a possible way to improve plant heat rate and
thus reduce heat rejection. It is worthwhile to see how the
plant heat rate has already been improved by such changes up
to the present time, and then to view the progress for
further improvements.
By the 1920's typical plants used steam pressures and
temperatures reaching about 1,900 kN/sq m (275 psi) and
293°C (560°F). The improved equipment and materials that
became available in the decade enabled pressures and
temperatures to be increased to the neighborhood of 3,792
kN/sq m (550 psi) and 343°C (650°F), resulting in increased
efficiency. Expansion in the turbine from these conditions,
however, resulted in excessive moisture in the turbine, and
as a result these plants adopted the reheat cycle.
By the 1930's further material improvements resulted in the
availability of steam pressures and temperatures of about
6205 kN/sq m (900 psi) and 482°C (900°F). Under these
conditions, expansion in the turbine occurs down to minimum
condensing pressure without excessive moisture, and as a
result plants were typically designed without reheat.
Further material improvements since the 1930*s resulted in
higher available steam pressures. A pressure of 17,200
kN/sq m (2,500 psi) and temperature of 538°C (1,000°F) might
465
-------
H. P.
TURBINE
L. P.
TURBINE
FIGURE B-VII-10 REHEAT CYCLE POWER PLANT
466
-------
be typical today. This increase in pressure with corres-
pondingly little increase in temperature would result in a
condition of excessive moisture if full expansion were taken
in the turbine in one pass. Because of this, reheat has
been adopted again in recent decades. In addition, higher
fuel costs justify the increase in efficiency gained from
reheat. Generally only one stage (single) reheat is
economical. For plants that are designed to operate at
supercritical pressures 2,400 kN/sq m (3,500 psi), however,
double reheat may be justifiable. Triple reheat has not
been found economically feasible under any conditions.
Along with these developments, adoption of the regenerative
cycle had become standard due to its increased efficiency
over the Rankine cycle. The efficiency increases with the
number (stages) of feedwater heaters used, but of course the
plant initial ccst increases correspondingly. For large
plants, present costs justify 7 or 8 stages of heating.
Process Changes for Existing Plants
A summary of possible individual changes in existing plants
is shown in Table B-VII-1, Efficiency Improvements.
Included in this table are approximate estimates of the
improvement resulting from the change, the work required to
effect it, estimates of outage time that the plant will be
down to make changes, and approximate capital costs. These
figures are quite approximate, because they actually vary
with existing plant conditions.
Feedwater Heater Additions
Addition of one heater improves the heat rate about 285 kJ/
kwh (270 Btu/kwh), perhaps 2%. Further heaters would
improve the heat rate by a succeedingly smaller amount.
Turbine modifications would probably be required.
Reduce Backpressure (Condensing Pressure)
This is accomplished by increasing the velocity of water in
the condenser tubes, which results in better heat transfer
and thus lower condensing temperature and pressure. The
degree to which this improvement can be effected is small.
Tubes must be changed to take the higher velocities without
erosion, but this is limited. In any case, the increased
pumping power would offset part, if not all, of the gain in
efficiency.
467
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TABLE: B-VII-1
EFFICIENCY IMPROVEMENTS
Modification
Add Feedwater
Heaters
Lower Back
Pressure
(Pump more
C.W.)
Increase
Steam
Temperature
c.
Ti
X>
Increase
Steam
Temperature
Add
Reheat
Improvement
in Heat Rate
270 Btu/Htr.
l%/0.5"Hg
0.8%/50°
1450-1800psig
=1.7%; 1800-
2400psig=2.0%;
2400-3500 psig
=1.7%
3-4% for units
operating at
Outage
Work Required Time Cost
Replace turbine, add 8 mos. $25/kw
heater and piping
Change condenser tubes for 2 mos. $6-8/kw
higher velocity. Add new
circulating water pumps
with new intake bays and
piping as required.
Possibility of boiler 3 mos. $6-8/kw
modification to obtain
-25°F. Some modification
.of turbine will be required.
Main steam piping will have
to be replaced.
For 50-100°F increase 8-16 mos. $35-50/kw
make extensive modifi-
cation to boiler (or replace)
and replace turbine plus
steam piping. Turbine
pedestal modifications will
also be required.
Replace boiler, turbine, 16 mos. $60-80/kw
steam and feedwater piping,
some changes to feedwater
heaters. Modify turbine
pedestal and install new
feedwater pumps .
Replace boiler, turbine 24 mos. $100/kw
and hot reheat piping,
Remarks
For same steam flow the unit output
would be reduced by 5%. Charge
required for replacement energy.
Limit of improvement is in the order
0.25"Hg and any gain would probably
be lost to increase pump power.
Practical limit for steam temperature
is 1000 F. Limitation primarily due
to boiler, however turbine also poses
problems
Increases of 3-5% possible without
modification. However, this will not
increase cycle efficiency because the
turbine is designed for maximum
efficiency at rated pressure.
Typical new reheat unit would be 75MV^
or less in size and would operate at
1800 psi and
above.
2-3% for units
operating at
1200-1450 psi
rebuild turbine pedestal,
modify boiler controls,
modify condenser and make
changes to feedwater
heating system.
1450 psi and 950°F.
-------
Increase Steam Temperature
Small increases might be accomplished with boiler and main
steam piping modifications. Larger increases require
turbine replacement also. In any case, the maximum steam
temperature practical at the present level of technology is
about 540°C (1000 °F) .
Increase Steam Pressure
Improvements in efficiency of the order shown may be
accomplished by increasing steam pressures. However,
extensive replacement of much of the plant is required.
Reheat
On lower pressure units, 10,000 kN/sq m (1150 psi and less) ,
the efficiency gain from reheat is less than for higher
pressure units, 12,400 kN/sq m (1800 psi and higher). The
gains and work required are as shown in Table B-VII-1. The
extent of work approaches a complete replacement of the
plant.
Increase Cooling Gas Pressure
Py increasing the pressure of the hydrogen gas used for
cooling the generator, it would be possible to produce
slightly more power from the generator, with higher input.
Drain Coolers
Cycle efficiency may be improved slightly by the addition of
drain coolers to the existing feedwater heating system, if
not already included. Figure B-VII-11 shows this arrange-
ment. The drain cooler takes the hot condensate from the
feedwater heater and uses it to preheat the feedwater
leaving the condenser. In this way the cycle efficiency is
increased slightly.
Drains Pumped Forward
Cycle efficiency may be improved slightly by pumping the
feedwater drains forward, instead of draining it back to the
condenser. Figure B-VII-12 shows this arrangement. Note
that an additional pump is required for pumping the drains.
Superposed Plants
A method of improving the efficiency of older plants that
has met with some success is the superposition of a higher
pressure and temperature system on top of the existing
plant. A new boiler, turbine, feedwater heaters and pumps
469
-------
-J
o
AAAA
HEATER
FIGURE B-VII-11 DRAIN COOLER ADDITION TO POWER PLANT
-------
CONDENSER
FIGURE B-VII-12 DRAINS PUMPED FORWARD IN POWER PLANT
-------
are added to the plant, exhausting steam to the old turbine
at its design conditions (Figure B-VII-13). The new boiler
may replace the old boiler or supplement it. The advantage
of this procedure is that the existing turbine and condenser
are retained, and made use of. Economical upgrades of a
number of plants were carried out in this way in the 1930•s.
It is doubtful that this approach would be economically
justifiacl= under existing capital cost conditions.
Complete Plant Upgrading
Consider a typical non-reheat unit, rated at 75 Mw, to be
upgraded to get a turbine cycle heat rate of approximately
8,U50 kJ/kwh (8,000 Btu/kwh). The following changes would
be required:
1. Raise pressure to 16,500 kN/sq m (2,UOO psi)
2. Increase superheat temperature to 537°C (1,000°F)
3. Add reheat to 537° (1,000°F)
U. Modify the regenerative feedwater heating cycle
To make these changes, the following work is required:
1. New boiler, turbine and boiler feed pumps
2. New steam and feedwater piping
3. New boiler controls
U. New feedwater heaters
5. Add cold and hot reheat piping
6. Rebuild the turbine pedestal
7. Modify the condenser
8. Modify parts of the turbine building and rebuild the
boiler building
The cost of all this work would be at least as much as that
of a new plant, as that is what it involves. It is
estimated that a 2-3 year plant outage would be required for
the work.
472
-------
NEW PLANT ADDITION
ORIGINAL PLANT
FIGURE B-VII-13 SUPERPOSED PLANT ADDITION
473
-------
Future Improvements in Present Cycles
At the present time, maximum steam temperatures are limited
to about 537°C (1,000°F). Temperatures above this requires
changes in the type of steel used in boiler tubing, piping
and in turbines that greatly increase plant costs. There is
a general consensus in the utility industry that significant
increases in steam temperature are not forthcoming in the
immediate future.
Most of the average size units being installed at the
present time, in the 300 to 600 Mw size range, are at a
pressure level of around 17,200 kN/sq m (2,500 psi). A
significant increase to supercritical pressures, around
2U,100 kN/sq m (3,500 psi) is being used for some of the
larger units. A cycle efficiency improvement of about 1.5
to 2.0% occurs with this pressure increase.
Gas Cycles
In addition to the steam vapor powerplant cycle, gas cycles
may be considered for generating electric power. These
plants usually operate on the Brayton (Joule) cycle or some
modification of this cycle. Figure B-VII-1U indicates an
arrangement of components, and the gas flow.
Air is drawn into the compressor. After compression the air
flows to a combustor where a gaseous or liquid fuel is
burned in the air. The products of . combustion at high
temperature and pressure flow through the turbine and
generate power. This cycle may have a relatively low
thermal efficiency, even though heat is added at a
relatively high temperature. This is because the gases
discharged from the turbine are still at a quite high
temperature. To overcome this a regenerative heat exchanger
is added to the cycle, as shown in Figure B-VII-15.
The effect is to preheat the compressed air before
combustion, utilizing the waste gas, thus increasing cycle
efficiency.
Further refinements can be made by adding intercooling
between compressor stages and by reheating, using a second
combustion chamber. With these refinements the efficiency
of the cycle may increase further.
Gas cycle power generation precludes any significant thermal
wastewater, as the main effluent is a gas.
474
-------
FUEL IN
POWER IN
COMBUSTOR
POWER OUT
TURBINE
AIR IN
COMBUSTION
GAS OUT
FIGURE B-VII-14 SIMPLE BRAYTON CYCLE GAS TURBINE POWER PLANT
-------
FUEL
POWER IN
AIR
COMBUSTION
GASES
COMBUSTOR
POWER OUT
FIGURE B VII-15 BRAYTON CYCLE WITH REGENERATOR GAS TURBINE POWER PLANT
-------
Gas Cycle Plants - Base Power
Plants using gas cycles are used for base power today only
in special applications. The cycle efficiency does not
equal that of the steam vapor cycles. Gas turbines are not
available in sizes adequate for the larger units of present
powerplant design.
Present development of turbines and other plant components
to withstand higher temperatures may make the gas cycle more
attractive in future decades.
Gas Cycle Plants - Peaking Power
The gas turbine cycle is used today for purposes of peaking
power. The structure of some power system loads is such
that there is a base load plus short term requirements for
peaks above that load. A gas turbine plant addition is a
natural consideration for this use. A relatively
inefficient cycle can be used, because of the short periods
of use. The incremental capital cost of the plant addition
is low.
The result of this arrangement is no increase in the thermal
wastewater discharge for the additional power generated.
However this holds only for the incremental power and only
during the short time period that the peaking equipment pro-
duces this power.
Combined Gas - Steam Plants
An efficient combination can be obtained by utilizing the
high temperature at which heat is added to the plant in the
gas cycle and the low temperature at which heat is rejected
from the plant in the steam cycle. An example of the plant
component arrangement is shown in Figure B-VII-16.
The combined cycle has proven advantageous as a method of
up-grading existing older steam plants. Usually the situa-
tion is one where the existing boilers need replacement or
very extensive rebuilding. The efficiency of the existing
plant is usually not high, as the steam temperatures and
pressure are considerably lower than those possible today.
The modernization procedure usually consists of replacing
existing boilers with gas turbine exhaust heat boilers which
supply steam to the existing steam turbines. The overall
plant efficiency of such an arrangement might increase 5 to
10%, thereby reducing the thermal discharge correspondingly.
Plant No. 3708 has up-graded part of its plant with such a
combined system. The result has been to reduce the heat
477
-------
TO
STACK
-J
00
~l
r
EXHAUST
HEAT
BOILER
COMBUSTOR
STEAM
TURBINE
HEATERS
COMPRESSOR
AIR IN
GAS FLOW
STEAM FLOW
FIGURE B-VII-16 COMBINED GAS-STEAM POWER PLANT
-------
rate on that part of the plant from 14,770 kJ/kwh (14,000
Btu/kwh) to 11,610 kJ/kwh (11,000 Btu/kwh).
The combined gas-steam cycle has also been chosen in some
new plants recently. The overall plant efficiency is
approximately the same as that which would be achieved with
a modern steam plant. However, gas turbines that will
withstand significantly greater temperatures are expected to
be available within a few years. Higher temperatures are
already in use in aircraft gas turbines, and the spin-off in
technology should follow as it has previously. This is
estimated to result in cycle efficiency improvements of 5 to
10* for the next generation of combined gas-steam plants
over the best steam plants today. The present design of
steam plants is not expected to improve by a similar
increase of temperature. Technological improvements in
boilers to match those of gas turbines are not expected. If
such developments occured,
it seems likely that the resultant steam plant would not
economically compete with the combined plant.
Future Generation Processes
Binary Topping Cycles
With steam vapor cycles, much of the heat is added to the
plant at lower temperatures than the maximum possible. This
heat is largely used to evaporate the water. Vaporization
of water cannot take place above 374°C (705°F), therefore
this inefficient heat addition process cannot be avoided.
To overcome this defect, plants using two fluids, each in a
separate cycle, have been conceived. An example is the
mercury-steam binary cycle. Mercury is used in the topping
cycle, steam in the bottom (lower temperature) cycle. Heat
can be added to the mercury at practically the highest tem-
perature metallurgically permissible. A few powerplants
have been constructed using this arrangement.
Although this cycle has an inherently higher efficiency than
with the steam cycle alone, serious disadvantages have led
to its demise. Mercury is extremely expensive and highly
toxic. Seme operating problems were not satisfactorily re-
solved in the plants built. Theoretical interest has been
shown in using other fluids for the topping cycle (e.g.,
potassium) but developmental work has been limited.
479
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Geothermal Steam
Geological conditions in certain locations provide a natural
source of steam from the earth's heat. The steam can be
used in a conventional power turbine. The thermal discharge
rejected from the plant has less internal energy than the
steam, so there is a net negative thermal discharge.
However, the disposed waste heat could still be in an
objectionable form and location. The use of this power
source is practicably confined to only a few locations on
the earth, and thus does not affect thermal discharges
generally.
KHD
Magnetohydrodynamics (MHD) is a principle of producing power
quite different from the steam cycle. An electrically con-
ducting hot gas is moved at high velocity through a magnetic
field, a procedure that directly generates electricity in a
surrounding coil. The present status of this phenomenon for
power production is in experimental development stages only.
Fuel Cells
The efficiency of a fuel cell is not limited to that of the
Carnot cycle, as it does not receive its energy by means of
conversion of heat energy to work. Energy is converted
directly from chemical to electrical energy. Fuel cells
have been commercially developed for certain applications in
small power requirements, but at the present time there is
no prospect for large units on the scale of steam power-
plants.
Waste Heat Utilization
There are three ways in which heat produced by powerplants
might be utilized in an alternate manner to reduce the
amount of heat rejected to receiving waters. These
alternate heat consuming methods are as follows:
- utilization of low-grade heat
- utilization ot extraction steam
- *-otal anergy systems
Utilization of low grade heat
This process means the use of the condenser cooling water in
the condition it is in as it leaves the condenser. Using
low-qrade heat in this manner is desirable because no
modification to plant performance is required. The
480
-------
disadvantage of this type of system is that the heat content
of the condenser water that is useable is small and large
volumes of water must be transported to get a significant
quantity of heat. Of the several systems of low-grade heat
utilization in operation or in various stages of
development, most are agriculturally or aquaculturally
oriented. The findings of some of these programs are dis-
cussed below.
Agricultural Uses
A considerable amount of related work has been planned by
the Tennessee Valley Authority. TVA has set aside 72.8 ha
(180 acres) of land at a major nuclear installation (Plant
No. 0113) for the testing of various ways of using waste
heat.
The initial effort at the TVA plant will be concentrated on
the development of greenhouse technology for the production
of high value horticultural crops utilizing the condenser
discharge water for both heating and cooling. The
information on these programs has been taken from Reference
353. Initial tests will include conventional greenhouse
crops such as lettuce, tomatoes, cucumbers, and radishes.
Later work will include such crops as strawberries for the
fresh out-of-season market. Eventually, a mix of crops
which fits well in sequence during the year with production
and marketing conditions and which grow well in the
greenhouse climate will be determined.
Preliminary calculations have been made of several crop com-
binations to obtain an estimate of the potential sale value
per acre of greenhouse. The data indicate gross sale poten-
tial of from $40,000 to $60,000 per 0.405 ha (acre) per year
is obtainable depending on crop mix. The savings in fuel
cost alone in utilizing the waste heat in this manner may be
upwards of $10,000 per 0.405 ha (acre) per year.
Calculations show that the development of 13.0 ha (32 acres)
of greenhouse tomato production and 23.5 ha (58 acres) of
lettuce would utilize about 6% of the available condenser
water at the plant, and provide about 1.4* of the total re-
quirements for these products in the Southeast. The lettuce
production would amount to 30 percent of that now shipped
into the combined Atlanta, Memphis, Nashville, and
Birmingham markets. TVA is also planning other projects for
agricultural use of waste heat for subsurface heating of the
ground, and also utilizing the greenhouse concept for the
raising of pork and poultry. These programs are not very
far advanced at this point.
481
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A similar study of greenhouse use of waste heat has been
performed by the AEC and is reported in Reference 351. This
study centered on the use of waste heat from a new high-
temperature gas-cooled reactor located in the Denver
vicinity. The study concluded that the cost of equipment
required to utilize the warm water was in the range of the
cost of heating systems for conventional greenhouses. Since
the cost of heating greenhouses in the Denver area is over
$5,000 per year, the potential value of the heat being
wasted is greater than $1,000,000 per year.
Aquaculture
The use of low-grade heat to improve the yields and produc-
tivity for fish and seafood species is called aquaculture.
Basic data indicate that catfish grow three times faster at
28.3°C (83°F) than at 24.4°C (76°F). Similarly, shrimp
growth is increased by about 8031 when water is maintained at
26.6°C (80°F) instead of 21.1«C (70°F).
Several commercial operations of this type are in existence
in the U.S. utilizing waste heat from powerplants. A com-
mercial oyster farming operation is in existance on Long
Island, N.Y. using the thermal effluent from powerplant No.
3621. Normal growing periods of four years have been
reduced to 2.5 years by selective breeding, spawning, larvae
growth and seeding oysters in the hatchery. This avoids
reliance on variable natural conditions and permits acceler-
ated growth in the thermal effluent discharge lagoon over a
period of about 4-6 months when the water would otherwise be
too cold for maximum growth. The product is marketed for
$15-20/bushel (1971) which is the upper end of the wholesale
price range.
Catfish have been cultured in cages set into the thermal
discharge canal of a fossil-fueled plant (plant No. 4815)
located in Texas. During the winter of 1969-70 growth rates
achieved were equivalent to 200,000 Ib/acre-year. This is
comparable to the yields of rainbow trout culture in moving
water. The Texas operation is now on a commercial basis.
TVA also operates a small-scale catfish raising facility at
its waste heat complex. Results from the first year's
operation confirmed that the growth rate of the catfish was
significantly enhanced by the addition of the heated water
and that the growing season was significantly lengthened.
However, several problems prevented expansion to a
commercial scale operation. Feed loss and mortality rates
were high. Water quality studies showed that high intensity
production of catfish generated substantial quantities of
482
-------
waste material and that the equivalent of secondary
treatment would be necessary before the facilities could be
expanded.
The major weaknesses of low-grade heat utilization are the
following:
1. Inability to utilize large quantities of total waste
heat available. This is due not only to the capital
requirement but also to the fact that the product is
produced in such quantities that it may exceed market
demand.
2. Uses are seasonal which require either the dumping of
waste heat in the off season or the building of a cooling
tower in addition to the waste heat utilization systems.
3. Inability to provide needed heat when plant is shut down
and unadaptability of the cultured organisms to rapid
temperature change.
Utilization of Extraction Steam
Extraction steam utilization increases both the number and
the size of the potential heat users. Table B-VII-2 follow-
ing shows the total annual energy demand by several types of
heat using processes in the United States. The table is
taken from Reference 24.
The most notable extraction steam heating system is located
in downtown Manhattan, in which approximately•300 Mw of heat
is supplied from extraction and back pressure turbines.
This system has been in operation for many years. District
heating systems of this type are expected to increase in
usage in those places where it can be marketed successfully
for operation of large tonnage air conditioning loads.
Extraction steam heat utilization is also used to supply
industrial process steam. The classic case of extraction
steam utilization for industrial process steam takes place
at powerplant No. 3414 located in the Northeast. This plant
supplies the bulk of the process steam to an adjacent oil
refinery. The plant was designed with this capability in
"mind. The alternate utilization scheme increases the effi-
ciency of the generation cycle from 3451 to 54%. This is
equivalent to reducing the waste heat rejected to the en-
vironment by 25%.
483
-------
Table B-VII-2
ENERGY DEMAND BY HEAT USING APPLICATIONS (1970)
24
Application
Electricity
Space Heat
Domestic Hot Water
Industrial Steam
Supply Temperature, F
-
200
200
300-400
Energy Used, trillion Btu
4,000
6,000
1,000
5,000
00
-------
Another form of extraction steam utilization is the use of
steam to desalt saline or sea water. This type of use is
common in arid locations and also in many of the small
islands in the Caribbean. Unfortunately, the quantities of
heat consumed by water desalting processes are relatively
small. The largest water desalting plant in operation today
has a capacity of only 5.0 million gallons of water per day.
This would require much less than 1% of the waste heat from
a new 1,000 Mw nuclear plant.
The major disadvantage of extraction steam methods is the
necessity of combining the plant and the adjacent steam
utilizing process to determine the overall performance of
the system. In addition, it is difficult to balance the
often variable steam requirements with the power production
process.
Total Energy Systems
The total energy concept seeks to overcome some of the
obvious shortcomings of the low-grade and extraction steam
utilization concepts by aggregation of all energy consuming
interests in a well defined area. Most total energy systems
in the United States are relatively small, consisting of
individual shopping centers, educational complexes and in-
dustrial complexes. The total energy concept is practiced
more intensively in Europe.
A major study conducted by the Oak Ridge National
Laboratory, Reference No. 350, tested the economic
feasibility of a large energy system serving a hypothetical
new town of 389,000 people. The climate of the new town was
similar to that of Philadelphia, Pa. The system provided in
addition to electricity, heat for space heating, hot water,
and air conditioning for the commercial buildings and
portions of the apartment buildings. Heat was also
available for manufacturing processes and desalting of
sewage plant effluent for reuse. The study concluded that
it would be possible in the 1975-1980 period and beyond to
supply low cost thermal energy from steam electric
powerplants to new cities, especially those in the
population range of 200,000 to 400,000. With respect to
climate, the cities could be located anywhere in the
continental United States except perhaps in the most
southern portions.
The use of thermal energy extracted for the turbines of the
generating plants would be economically attractive. For
example, in one configuration of a 1980 city with a popu-
lation of 389,000 people and a climate similar to that of
485
-------
Philadelphia, Pennsylvania, the cost of heat for space heat-
ing and domestic hot water was estimated to be approximately
$1.98/MBtu.355 This system was considered to be competitive
in that its use would result in an approximately equal cost
compared with other systems. It is anticipated that
interest in total energy systems will increase as the
rapidly increasing cost of fuel will require corresponding
increases in the efficiency of fuel consumption.
Cooling Water Treatment
General
Steam electric powerplants employ four types of circulating
water systems to reject the waste heat represented by the
difference between the energy released by the fuel and the
electric energy produced by the generators. These systems
are the once-through system, once-through with supplemental
cooling of the discharge, closed systems, and combinations
of the three systems. In a once-through system, the entire
waste heat is discharged to the receiving body of water.
The applicability of this system is dependent on the
availability of an adequate supply of water to carry off the
waste heat and the ability of the receiving body of water to
absorb the energy. There is no reduction of total waste
heat energy being discharged by the plant in a once-through
system.
A. once-through system with supplemental cooling removes a
portion of heat energy discharged by the plant from the
plant effluent and transfers this energy directly to the
atmosphere. Various devices are used to achieve this
transfer. A long discharge canal could be a cooling device.
If a sufficient surface area is not available, the rate of
evaporation per unit area may be increased by installing
sprays in the discharge canal. If sprays do not provide
sufficient evaporative capacity, cooling towers may be
utilized in the supplemental cooling mode. The amount of
heat that can be removed from the circulating water dis-
charge is a function of atmosphere conditions and the type
and size of the cooling device provided.
Recirculating cooling water systems provide a certain type
of design and operational flexibility leading to lower costs
that is not available with helper systems. The costs of
cooling devices are related to their size. The use of
higher cooling water temperatures allows for the use of
smaller, less costly cooling devices to transfer the same
amount of waste heat to the environment. The recirculation
to the condensers of all, or a part, of the cooling water
486
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leaving a cooling device (if its temperature exceeds intake
cooling water temperature) would elevate all temperatures in
the system. The result would be that, for a fixed system,
more waste heat would be transferred to the atmosphere, or,
for a fixed waste heat load, a smaller and less costly
cooling device could be used. In any case, the added or
reduced costs due to changes in the energy conversion
efficiency brought about by the changed recirculation
temperatures would become significant in relation to the
extent of the temperature changes involved. A further cost
savings of recirculating cooling water systems would be
attributable to the small intake and discharge structures.
A further characteristic of helper systems is that they are
designed primarily to reduce the temperature of the water
discharged and not the amount of heat discharged. When
recirculation of a portion or all of the cooling water is
practiced, the temperature of the discharged water is
actually increased (compared to operating in the helper
mode) but the effluent heat is reduced (compared to the
helper mode) because of the reduction in discharge volume.
Closed circulating water systems are currently in common use
in the industry, although in the past the reason for
employing closed systems has seldom been the elimination of
thermal effects, but rather the lack of a source of water
supply adequate for a nonrecirculating system.
The following section describes each of these systems in
further detail.
Once-Through (Nonrecirculating) Systems
These are defined as those systems in which the water is
removed from the water source, pumped through the condenser
in one or more passes to pick up the rejected heat, and then
returned to the water source. These systems are arranged so
that the warm water discharged to the receiving body of
water does not recirculate directly to the intake point.
Oncethrough systems have been the most prevalent in the
United States to date.. In general, other systems have been
used only when sufficient water for once-through operation
has not been available. The trend has been away from the
use of once-through systems. Only about one-half of all new
units are committed to once-through systems, whereas about
80% of all existing systems are once-through.
The basic design of the once-through, or open, system is
shown in Figure B-VII-17. The purpose of the intake
structure has generally been to prevent trash, fish, grass
487
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STEAM
FLOW
DISCHARGE
CANAL OR
PIPING
COOLING
WATER
PUMPS
OO
INTAKE
PIPING
OO
INTAKE
STRUCTURE
GENERAL WATER FLOW
LAKE
RIVER
ESTUARY
OCEAN
FIGURE B-VII-17 ONCE THROUGH (OPEN) CIRCULATING WATER SYSTEM
488
-------
and other materials from entering the condenser and either
plugging or damaging the condenser tubes, resulting in
decreased performance or shut down of the unit for repair of
condenser tubes. In some cases skimmer walls are used to
insure drawing cooling water from deep in the supply source,
where the water is colder. The pumps required to circulate
the water through the condenser are normally located at the
intake structure. Normally there are several pumps for each
unit, due to the large flows involved and due to the
requirement of providing a higher degree of flexibility and
safety in the operation of the cooling water system. Flows
for a single unit can exceed 30 cu m/sec (500,000 gpm), and
some of the large stations require over 60 cu m/sec
(1,000,000 gpm). The total annual use of cooling water by
steam electric powerplants is an amount equivalent to about
15* of the total flow of all rivers and streams in the U.S.
The cooling water flow rates in some plants is comparable to
the flow rates cf some rivers.
The discharge from the condenser can be returned to the
source via a canal or pipe, depending on the local condi-
tions. The discharge structure serves two purposes. The
first is to return the water in such a manner that damage to
the stream bank and bottom in the immediate vicinity is
minimized. The second is to promote the type of thermal
mixing required. On lakes or estuaries where water veloci-
ties are low, considerable separation between the intake and
outlet structures is required to prevent warm water from
recirculating directly into the intake.
When compared to closed systems, the water temperature of
the circulating water in the open system tends to be lower,
thereby sometimes allowing a higher generating efficiency
for the plant with the open system. Plant No. 3713 has one
of the best heat rates in the country, due, in part, to the
low inlet water temperature, which does not exceed 2«J°C
(75°F), during the summer months. This is discussed in more
detail under closed systems. As a result of the above, the
best
plant efficiencies are generally obtained with once-through
systems.
Once-Through Systems with Supplemental Heat Removal (Helper
Systems)
With the development of the larger generating stations, it
has been determined in some cases that the large amount of
heat rejected to the environment by cooling water discharged
from these stations could seriously affect the water
environment. Consequently, in those cases, the utilities
489
-------
have been required to re-evaluate their thermal discharge
systems. One consideration short of recycling condenser
cooling water would be to remove heat from the
nonrecirculating system prior to discharge to the
environment. This would be accomplished by a cooling device
placed in the circuit between the condenser and the
discharge point, as shown in Figure B-VII-18 to divert some
heat directly to the atmosphere. The amount of heat that
could be removed by such a device operating at full capacity
would be dependent upon the atmospheric or climatic
conditions, principally wet bulb and dry bulb temperatures,
or even wind velocity, solar intensity, and cloud cover,
depending on the type of device used.
Since these heat removal systems are also applicable to
closed systems, they will be discussed here in general terms
only. The design and operation of each of the systems is
covered in detail under the closed systems section. Special
considerations only are covered in this section. In
general, limiting climatic conditions are such that while a
majority of the heat can be removed, the discharge stream
temperature will always be higher than the receiving water
at the discharge point.
The systems considered for this end of pipe, or helper mode
of thermal discharge control are cooling towers, both
natural draft and mechanical draft, and ponds or canals
which can contain floating powered spray modules to augment
the natural cooling process. The known installations tend
to be designed for operation in any one of several
alternative modes. For example. Plant No. 2708 (Ref. No*
108dd) employs a mechanical draft evaporative cooling tower
system capable of (a) off-line, (b) helper, (c) partial
recirculating and (d) closed-cycle modes of operation that
is expected to be capable of meeting water quality
standards.
Diagrams of two systems presently in use are shown in
Figures B-VII-19 and B-VII-20. The system in Figure B-VII-
19 can be operated in both open and closed modes. The
system shown in Figure B-VII-20 is much more complex. Units
1 and 2 were originally once-through. When Unit 3 was
added, a once-through system could not be used due to low
water availability in the summmer.3*' In- designing the
closed cooling tower system for Unit 3, it was decided to
add one additional tower, which would permit operation of
all three units on an almost closed system during the summer
when the temperature of the discharge to the river is se-
verely limited by environmental protection considerations.
The systems illustrated indicate the degree of flexibility
490
-------
BOILER
STEAM
TURBINE
CONDENSATE
INTAKE
PIPING
PUMPING
STATION
INTAKE
STRUCTURE
00
GENERATOR
J
CONDENSER
DISCHARGE PIPING
OR CANAL
00
HEAT
REMOVAL
SYSTEM
DISCHARGE
STRUCUTRE
GENERAL WATER FLOW
LAKE
RIVER
ESTUARY
OCEAN
FIGURE B-VII-18 ONCE THROUGH (OPEN) SYSTEM WITH HELPER COOLING SYSTEM INSTALLED
491
-------
10
K)
COOLING SYSTEM CAPABLE OP BOTH OPEN
AND CLOSED MODE OPERATION
'(Ref. 108z) *
FIGURE B-VII-19
-------
• ^&—"\—V"
.CONDENSER^n^ \ \
PLANT LAYOUT AT PLANT No. 2119
'From Refei-fijico 359)
FT'.URE B--Vri-20
493
-------
which can be built into a once-through system by using
supplemental heat removal systems.
The seasonal variability of the performance of a helper
system is shown in Figure B-VII-21. This curve shows the
average monthly performance of a tower located in the East,
and designed to remove 100% of the heat in September. The
circulating water temperature rise was assumed to be 11°C
(20°F). With a stream temperature of 27.2°C (81°F), the
approach was U.5°C (8°F). During the month of March, with a
stream temperature of 5.6°C (42°F) and a wet bulb of 7.8°C
(46°F) the same tower removes only 22.5% of the heat, even
though the approach has increased to 6.U°C (11.5°F).
This decrease is due to the variation in relationship be-
tween stream temperature and wet bulb temperature. In the
summer the stream temperature is well above the wet bulb
temperature. In winter, in this location, the stream tem-
perature drops below the wet bulb temperature. In addition,
tower performance is lower at the lower winter temperatures.
This obviously poses a problem in the design of towers for
"helper" use. In the case shown, a tower designed to remove
100% of effluent heat under the worst winter condition
(March) would be over-sized by a factor of 4 during most of
the summer.
There is a relatively simple solution to this dilema, and
that is to partially close the system during the winter
months. Part of the warm circulating water would be recir-
culated into the intake stream, increasing its temperature.
This would increase the discharge temperature, and
consequently the water temperatures in the tower. This in
turn would increase the difference between the water and the
wet bulb temperature and increase the amount of heat
removed. The water not recirculated would be discharged. A
problem then arises in that the water discharged would have
a temperature significantly above the stream temperature.
This temperature might not meet applicable stream standards,
which . would mean operation of the tower in two modes: open
in summer and closed in winter. The tower would be designed
to handle the heat load under the more difficult of the two
operating conditions.
All evaporative type cooling systems would have this
decrease in heat removal performance during winter months
when operated in the "helper" mode.
One other system should be mentioned in this section. This
is the dilution system to limit the temperature effect of
494
-------
100
90
80
70
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LU
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,60
50
40
TO TOWER
JANUARY
FEBRUAR
MARCH
APRIL
>
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LU
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£
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00
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0
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in
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FIGURE B-VII-21 SEASONAL VARIATION OF "HELPER" COOLING TOWER (FROM REFERENCE 74)
495
-------
the discharge on the water to which it is discharged. In
this method an excess of water, above the quantity required
in the condenser is pumped through the intake system, with
the excess being mixed with the hot condenser effluent prior
to discharge into the receiving water. While this dilution
reduces the combined discharge water temperature, the amount
of total heat discharged to the water is slightly greater
due to the added generation (and heat rejection) required to
power the dilution pumps.
Closed or Recirculating Systems
Closed systems recirculate water first through the condenser
for heat removal, and then through a cooling device where
this heat is released to the atmosphere, and finally back to
the condenser. Three basic methods of heat rejection are
used. The one of most commercial significance in the power
industry is wet, or evaporative cooling using cooling
towers, or spray augmented ponds. Evaporation at 5 x 10s
j/kg (1,000 Btu/lb) is the principal means of heat transfer.
There is also some sensible heat transfer. A second method
of closed system cooling commonly employed is the use of
cooling lakes, which are similar in principal to open, once-
through systems, but which are closed inasmuch as no
significant thermal discharge occurs beyond the confines of
the lake. Dry cooling towers, in which heat is transferred
by conduction and convection, have found very limited use.
The following subsections describe the available technology
for achieving waste heat removal in closed or recirculation
cooling systems.
1. Cooling ponds or lakes
2. Spray augmented ponds
3. Canals with powered spray modules
4. Rotating spray system
5. Wet tower, natural draft - crossflow
6. Wet tower, natural draft - counterflow
7. Wet tower, mechanical forced draft
8. Wet tower, mechanical induced draft, crossflow
9. Wet tower, mechanical induced draft, counterflow
496
-------
10. Dry tower, direct
11. Dry tower, indirect
12. Combined wet-dry mechanical draft tower
The effects of the number of cycles cf concentration in the
operation of closed-cycle (recirculating) cooling towers on
the percentage reduction of effluent heat compared to once-
through cooling is given in Table B-VII-7 and compared to
once-through "helper" assisted systems in Table B-VII-8.
Cooling Ponds
Cooling ponds are normally artificial lakes constructed for
the purpose of rejecting the waste heat from a powerplant.
A secondary purpose for which the pond is utilized is the
storage of water for plant operation during periods of low
natural availability of water. This dual usage makes cool-
ing ponds economical in the more arid areas of the country.
There are also a significant number of cooling ponds in use
in the southern part of the United States. While cooling
towers could be used to provide cooling in conjunction with
a storage pond, the consumptive use of water in the cooling
tower, plus the losses from the water storage pond, is gen-
erally greater than the losses from a dual purpose pond.
Two distinct types of ponds can be identified, based on the
legal means in which discharge is defined. The first is a
pond located where there is little or no natural drainage,
or where the water rights on the watershed belong solely to
the utility company, and there is no thermal discharge from
the pond. In this case, the cooling pond is considered to
be completely under the control of the utility company, and
the pond is operated solely to give the best plant perfor-
mance. The cooling pond at plant No. 3514 is an example of
this type. While the pond itself may not come under thermal
discharge regulations, any chemical discharges (blowdown)
from the pond will. In addition, any other effects of the
cooling lake on the environment would also have to be taken
into account.
The second case is where the pond is constructed on a water-
shed having significant runoff, and where the utility does
not own the pond and the total water rights on the
watershed. In this case, the pond is legally considered to
be external to the plant, and control of the thermal
discharge is subject to state and federal regulations.
Plant No. 3713 in North Carolina is an example of this type.
497
-------
Cooling ponds are normally formed by construction of a dam
at a suitable location in a natural watershed. Soil under
the pond must be relatively impervious to avoid excessive
loss of water. Ponds may be constructed by excavation, but
generally the cost would be much higher than for a dammed
watershed. The size of the pond is primarily related to the
plant generating capacity, and rough approximations of 4000-
8000 sq m (1 to 2 acres) per Mw, are found in the liter-
ature. At 0.8 ha (2 acres) per Mw, the pond for a 1,000 Mw
plant would be 800 ha (2,000 acres) in size. Thus, the pond
size for such a plant would normally be large enough to
serve as a recreational site in addition to its primary
function.
When a watershed is dammed to form a cooling pond, the shape
is determined by the topography of the area. The station
intake and discharge structures are placed on the cooling
pond so that maximum use is derived from the pond, i.e.
widely separated, if not at opposite ends of the pond. With
excavated ponds, the shape is not totally limited by the
topography. One station currently uses a pond with a dike
separating the intake and outfall structures, and extending
almost across the lake to provide a U-shaped pond. Another
station, plant No. 1209, utilizes a series of canals as a
"cooling pond" as shown in Figure B-VTI-22. The land is
flat, and the dikes between the canals provide a convenient
place to pile the material dredged from the canal.
Considerable research on thermal aspects of cooling ponds
has been undertaken. Likewise some of the research on the
discharge of condenser water into lakes and rivers may be
applicable. References 32, 84, and 120 are part of a series
of five reports dealing with cooling ponds, and a more
comprehensive study is described in Reference 246.
The performance of a cooling pond is dependent to a large
extent on its physical features, as indicated below.
1. Ponds have been arbitrarily categorized in a number of
ways, such as shallow or deep, stratified or non-
stratified, and plug flow or completely mixed ponds. In
terms of the above, the ideal pond is a deep, stratified
pond in which the hot water flows through the pond on
the pond surface with no longitudinal mixing, and the
cool water is removed from a deep portion of the lake.
2. The configuration of the discharge structure for
discharging the hot water from the plant, particularly
in the case of shallow ponds, greatly affects pond
performance. The discharge structure should be designed
498
-------
I
iSPS**-'1*
-
COOLING CANAL
PLANT NO. 1209
Figure B-VII-22
499
-------
to spread the hot water in a thin layer over the lake
surface thus preventing mixing with the cooler
subsurface water, and sustaining a high pond surface
temperature to promote rapid heat transfer to the
atmosphere. The suitability of the discharge structure
is sometimes evaluated in terms of the Froude No., a
ratio of the fluid momentum forces to the fluid
gravitational forces and which relates the velocity of
discharge to a characteristic length of the structure,
normally the width of the channel.
Froude No. = V*/Lg
where V = Velocity of discharge, m/s (ft/sec)
L = Width of discharge channel, m (ft)
g = Gravitational constant, 9.82 m/sec* (32.2 ft/
sec 2)
Discharge structures are generally considered adequate
for use in relation to cooling ponds when the Froude No.
is less than 1.0.
3. The intake structure is normally located well beneath
the pond surface, if not at the bottom. Its position in
relation to the discharge structure is important.
Currents within the pond, particularly wind currents,
must be considered in placing the structure to get the
best performance out of the pond.
H. The pond shape has some effect on performance. The
extent of the effect is dependent on the degree to which
density currents exist within the pond. For those ponds
with strong density currents, the pond shape is usually
insignificant.
5. The temperature of the discharge into the pond sets the
driving forces for loss of heat to the atmosphere.
Other important considerations include climatic factors,
particularly wind speed, gross solar radiation, dewpoint
temperature, and other factors which affect the equilib-
rium temperature of the pcnd. The pond size required
for a particular plant depends on the climatic condi-
tions in the immediate vicinity of the pond. Pond
design is usually based on conditions which approach the
most unfavorable conditions expected. The more
accurate, reliable, and extensive the available data is,
the more confidence can be placed in a design based on
these data. The importance of the climatic factors
500
-------
outlined above is demonstrated in the following
equations which describe the relationships among the
principal factors involved in sizing a cooling pond. At
steady state conditions, the net heat loss from the pond
is equal to the waste heat from the powerplant. The
steady net heat loss from the lake surface is normally
expressed as:
Heat loss = KA (Ts -TE)
where K = Heat Exchange Coefficient, J/sq m-day-°C
(Btu/sq ft-day-°F)
A = Area of Lake, sq m (sq ft)
Ts = Average Surface Temperature, °C (°F)
TE = Equilibrium Temperature, °C (°F)
The equilibrium temperature (TE) can be estimated by
the following equation:
TE = Td + Hs/K
where Td = Dewpoint Temperature, °C (°F)
Hs = Gross Solar Radiation, J/sq m-day (Btu/sq ft-day)
K = Heat Exchange Coefficient, J/sq m-day-°C
(Btu/sq ft-day-°F)
The heat exchange coefficient (K) is closely related to
windspeed as shown in Figure B-VTI-23, which permits
determination cf K in terms of windspeed and the temper-
ature T = Td * Ts where an initiate value of Ts must be
2
assumed.
The estimation of the average pond surface temperature
is an important part of the analysis. Parameters
necessary for this determination are the expected
temperature rise and circulating water flow rate. The
degree of mixing in the pond must be estimated. Where
there is little mixing (slug flow), the temperature
decrease occurs during the entire transit of the pond by
a typical slug of circulating water. The other extreme
is where complete mixing occurs, and the temperature
throughout the pond is the same. The actual degree of
mixing in any particular case would lie between these
two extremes.
501
-------
35
\
in
+ cv
C-1 Q)
•P
(0
t-l
0)
0)
en
a)
30
25
20
15
10
\
v :\. -\_..
4 5
Windspeed (m/s)
CHART FOR ESTIMATING COOLING POND SURFACE HEAT EXCHANGE COEFFICIENT
(From Reference 32)
FIGURE B-VII-23
-------
The first step in the procedure for estimating the average
pond surface temperature is to determine the discharge tem-
perature to the cooling pond. This is done by first deter-
mining the quantity:
where K = Heat exchange coefficient estimated from Figure
B-VII-23, J/sq m-day-°C (Btu/sq ft-day-°F)
A = Assumed pond area, sq m (sq ft)
p = Density water, kg/cu m (lb/ft3)
C£ = Heat capacity, J/kg-°C (Btu/lb-°F)
Qg = condenser flow, cu m/day (ft3/day)
Figure B-VII-2'J can be used to determine the approximate
area A. With the condenser rise, from Figure B-VII-25, 9
(excess of discharge temperature, TE, over the equilibrium
temperature, TE) is determined. Note that curves for slug
flow and complete mixing are given. Then the discharge tem-
perature, TJD, and the inlet temperature, Tc, can be deter-
mined.
Tp = TE + 9r
Tc = TJD - Condenser rise
From Figure B-VII-26, using 9 and KA/pcQjD, 9 average is
determined, since 9 is Ts_ - TE, Ts is determined. This
value of Ts will normally not correspond to the assumed
value used to determine K. The correct value is then
determined by iteration, i.e., new values for Ts are assumed
and the process repeated until the two values of Ts agree to
the degree of accuracy desired.
Once Ts has been estimated, the pond area can be determined
from Figure B-VII-24, which determines the area required for
each million kJ (million Btu) of heat to be rejected. If
the cost per acre of pond surface is known, the cost per
million kJ (million Btu) of heat rejected can be determined
from Figure B-VII-27.
Costs for cooling ponds are very dependent on local terrain.
In general, costs would include the following:
503
-------
3.0 _
o
,H
X
o
rH
2.5
2.0
1.5
m
0)
S-l
o i.o
Cn
C
•H
•H
0
o
o
0.5
T = Surface Temperature ( C)
s
T- = Equilibrium Temperature ( C)
e
180200220240260280300320340360380400
Heat Exchange Coefficient, k, J/m - C,-day
COOLING POND SURFACE AREA VERSUS HEAT EXCHANGE COEFFICIENT
FIGURF B-VII-24 504
-------
35
30
25
20 L
u
-------
25
20
-l
3
en
0)
15
10
T - T
P e
27.5 J
22
16.5
Completely Mixed Pond
Once Through Pond
1.0
1.5
2.0
K A/ P C Q (dimensionless)
P P
DETERMINATION OF AVERAGE SURFACE TEMPERATURE INCREASE, 8,
RESULTING FROM THERMAL DISCHARGE OF STATION
FIGURE B-VII-26
2.5
-------
3.0
Cost per Hectare of Pond Surface
$2,500
$7,500
n
I
X
%
»•-*•
,C
b
o
%
<
2.5
2.0
1.5
1.0
0.5
000
j_
200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600
Capital Cost ($/10 kJ/hr)
ESTIMATION OF CAPITAL COST OF COOLING POND
FIGURE B-VII-27
507
-------
I. Preliminary
1. Soil surveys
2. Topographical mapping
II. Construction
1. Dam or basin
2. Discharge structure
3. Intake structure
4. Canals or pipelines associated with 2 and 3
5. Makeup water system (pipelines, canals, pumps, etc.),
if required.
6. Auxiliary equipment for above, roads, fencing, etc.
III. Maintenance
1. Canal, pipeline maintenance
2. Intake and discharge structures
Spray Ponds
The total use of spray cooling in power generation in not
easily compiled. Ceramic Cooling Tower Company reports 645
modules in operation, shipped or in manufacture. Richards
of Rockford Inc., has 365 units in similar stages for large
and small applications. Cherne Industrial reports small
volume sales to three customers, primarily for testing.
Ashbrook Corporation has supplied 14 units to ten
customers.40S
Spray systems can be utilized to reduce the large area re-
quired by cooling ponds by up to a factor of ten. Two types
of spray systems are available. In a fixed system, which
essentially operates in a once-through mode, the hot water
is pumped through a grid of piping, into which nozzles have
been placed at regular intervals. The water is sprayed out,
and cools by evaporation and sensible heat transfer to the
air as it falls to the pond below, water from the pond is
pumped directly to the condenser. To obtain adequate cool-
ing on this once-through basis, the spray must be fine.
This factor, coupled with wind factors, can lead to large
drift losses and associated problems in the vicinity of the
pond. The relatively high pumping losses and lengthy piping
required for such a fixed system would make this type of
design relatively costly for a medium-sized power station.
The second type of spray pond is commonly called a spray
canal due to its flow-through hydraulics and shape which
makes full use of prevailing winds to enhance cooling per-
formance. The spray is produced by modules moored at inter-
vals in the canal and floating on the water surface. Two
503
-------
types currently in use are illustrated in Figures B-VII-28
and B-VII-29. The module in Figure B-VII-28 is a unitized
pump and spray module. The module in Figure B-VII-29 has a
central pump supplying four nozzles. Both units are powered
by 56,000 watt (75 hp) motors and spray 0.631 cu m/sec to
0.789 cu m/sec (10,000 to 12,500 gpm). Two characteristics
of this system are important. The first is that each slug
of water can be sprayed in repetitive steps, thus minimizing
the need for small droplets required by the fixed system.
The droplet size can be larger, reducing the drift problem.
Secondly, not all the water need be sprayed, but enough to
provide the required cooling. This permits adjustment of
the number of modules operating to. the climatic conditions
and generating level of the plant.
The use of these modules in the utility industry is
relatively new, although tests have been underway for some
years. Plant No. 330U and Plant No. 5105 are using, or are
installing powered spray modules. The largest installation
in use is at Plant No. 0610. The canal of plant no. 0610 is
U-shaped as shown in Figure B-VII-30. The intake and
discharge structures are at the same end of the pond. The
power and control systems for the modules are located on the
central dike. Figure B-VII-31 shows the modules in
operation. The diameter of the spray pattern is about 15
meters (50 feet).
Plant No. 1723 is installing a large number of each design.
Spray modules are being used primarily for helper systems on
existing plants when additional units are added to a plant.
The design of the cooling canal is more complex than that of
a cooling tower, and computer programs are often used. To
make the best use of climatic conditions, these systems are
designed as canals where all the modules are exposed insofar
as possible to the ambient air conditions, reducing adverse
interference of performance due to proximity to other
modules. The canals can be circular in shape, or straight,
as required. The canals should be aligned perpendicular to
the prevailing winds for maximum ambient air exposure, and
therefore maximum module efficiency.
Design of the system involves determining the incremental
contribution to cooling of each set of modules in series.
The first module's inlet temperature is the condenser dis-
charge temperature. The cooled spray from the first module
remixes with the water in the canal, and the resulting tem-
perature of the canal is the temperature at the inlet to the
second set of modules. This procedure is continued until
the desired temperature is reached, or the increase in over-
-.09
-------
c->
~^
->
->
in
r"
O
UNITIZED SPRAY MODULE
(From Reference 365)
FIGURE B-VII-28
-------
40 H MMIM1L
FOUR SPRAY MODULE
(From Reference 366)
FIGURE B-VII-29
-------
SPRAY CANAL
PLANT NO. 0610
Figure B-VH-30
512
-------
•
II- .
£"
' r
SPRAY MODULES
PLANT NO. 0610
Figure B-VII-31
513
-------
all performance with additional modules is not cost
effective. Using seme general data on one manufacturer's
units. Figure B-VII-32 was developed to give a pictorial
representation of the process. The initial temperature is
the inlet temperature to the first set of modules (condenser
discharge temperature). The wet bulb temperature is then
used to determine the expected temperature decrease of the
sprayed water. From the percentage of water sprayed, the
change in canal temperature can be determined, and this
translated into a new exit temperature from the modules.
This then becomes the initial temperature for the second set
of modules. The number of modules in parallel at any point
in the canal can also be optimized.
The retrofit installation at plant no. 1723 is
representative. The two generating units at the plant are
rated at 809 Mw each. The cooling canal will encircle the
plant and will be 4.1 km (2.5 miles) long. The canal will
contain 176 units from one manufacturer, and 152 units from
another manufacturer. The number of modules, or blocks of
them operating at any one time will be adjusted to give the
amount of cooling required. The installed power for the 328
units is 18,300 kw (2U,600 hp). At 90% efficiency, this
amounts to 20.4 megawatts, or 1.26% of the plant's previous
output using once-through cooling. Since higher cooling
water temperatures are expected, thereby reducing the plants
gross generating capacity, the combined reduction in plant
generating capacity will be greater than 1.26%.
For the past several years, another manufacturer has been
testing a rotating disc design for producing sprays. Their
current design is shown in Figure B-VII-33. This design is
currently undergoing field evaluation at a station in the
United States. A cross section of a proposed installation
is shown in Figure B-VII-34. The spray droplets produced by
these rotating discs are about 1 mm in size. As with the
fixed spray systems, this size is required to get adequate
cooling performance. With this size drop, drift is a
problem, and adequate provision to minimize drift losses
must be made.
Insufficient data has been published to make reliable
performance or cost estimates. From some of the limited
performance data the curves in Figures B-VTI-35 and B-VTI-36
were developed.
514
-------
100 90 80 70 60 50 40 30 20 10 8
Initial Temperature
Wet Bulb Temp.
17.8°C
Initial Temperature ( C)
GRAPHIC REPRESENTATION OF DESIGN OF SPRAY AUGMENTED COOLING POND
Figure B-VII-32
-------
Ul
M
CTi
THERMAL ROTOR SYSTEM
FIGURE B-VII-33
(From Reference 389)
-------
r
COOLED WATER CHANNEL
tOTORS
^
SPRAY
\U*>~r- —/-'-
-T-J•---' 24 INLET PIPE y
PLAN
~~~~~~"
—S~
HOT WATER CHANNEL
.ROIOJS
COOLED WATER ^-HOI WATER
SECTION THaU ROTORS
--S--
^6 G7.V'«l
~6" SAND
-POLTVINTi
SECTION THRU CHANNELS
HOT WATER
Stale: 1/16 =1'-0
DOUBLE SPRAY FIXED THERMAL ROTOR
(From Reference 360)
FIGURE B-VII-34
-------
+J
c
-------
X
cn
-------
Wet Type Cooling Towers
A number of different types of evaporative cooling towers
have been, and are currently, in use. The basic types are
as follows:
Natural Draft
Mechanical Draft: (Hyperbolic): Dry Type:
Counterflow-Induced Draft Counterflow Direct
Crossflow-Induced Draft Crossflow Indirect
Counterflow-Forced Draft Counterflow-
Crossflow-Forced Draft Fan Assisted
wet-Dry—Any of the above
The terms crossflow and counterflow refer to the relation-
ship between the air flow and the water flow. In counter-
flow, the water flows downward through the packing and the
air flows upward (Figure B-VII-37). In crossflow, the water
still flows downward, but the air flows horizontally (or
perpendicularly to the water) from outside to inside as
shown in Figure B-VII-38. Induced draft refers to the means
for developing the air flow by a fan mounted on top of the
tower which pulls the air through the tower (Figures B-VII-
37 and B-VII-38). In the older, and little used today,
forced draft system fans are mounted around the periphery of
the tower at ground level and force the air upward through
the tower.
Drift eliminators, common to all towers except the dry-type,
are used to remove most of the entrained water droplets from
the air stream prior to its leaving the tower.
The wet-dry tower is a relatively new development. It con-
sists of an upper section of dry tower emitting warm air
heated solely by conduction, and a lower wet section emit-
ting the nearly saturated air which has a high fogging
potential. These two air streams are mixed in the tower,
significantly reducing the fogging potential.
Natural draft towers are commonly known as hyperbolic
towers, since the chimneys are hyperbolic in shape to take
advantage of the excellent stress characteristics of this
shape. The chimneys are normally constructed of reinforced
concrete. A crossflow tower is shown in Figure B-VTI-39.
The tower shown in Figure B-VII-40, takes up less land space
than the crossflow tower. The chimneys on these towers are
tall, ranging from 90 to over 150 m (300 to over 500 feet).
The tower height has the advantage that the plume is emitted
high enough above the ground that if fog develops, it will
normally not create a ground level hazard.
520
-------
I AIR I
I OUTLET I
-FAN
COUNTERFLOW MECHANTCAL DRAF1 TCWER
FIGURE B-VII-37
AIR
OUTLET
FAN
lll'IV WATER
INLET\
CROSSFLOW MECHANICAL DR^JT TOWER
FIGURE B-VII-38
-------
WATER OUTLET
CROSSFLOW NATURAL DRAFT TOWER
FIGURE B-VII-39
DRIFT / HOT-WATER
ELIMINATOR / DISTRIBUTION
•^•* COLD-WATER BASIN
COUNTERFLOW NATURAL-DRAFT COOLING TOWER
FIGURE E-VII-40
522
-------
A recent modification to the natural draft tower is the fan-
assisted hyperbolic. In this design, fans are placed at the
periphery of the tower, along the bottom to force the air
through the tower. The required tower height is diminished,
since air flow does not depend solely on the difference in
air density inside and outside the tower as in the
unassisted tower. Several of these fan-assisted towers are
in use in Europe, and have been proposed for use in specific
cases in this country.
The dry-type cooling towers rely solely upon conductive and
convective heat transfer for their cooling effect. Two
types of systems are used. In the "direct" system, the
steam condenses directly in the tubes of the heat exchanger
in the tower. This type is restricted to relatively small
plants due to the size of the steam piping required to
circulate the relatively low density steam. In the
"indirect" sytem, cold water from the tower is used to
condense the steam from the turbine and the warmed water is
circulated through the tower. Since the system is
completely closed, a direct contact condenser can be used,
greatly reducing the condenser terminal temperature
difference (TTD) . With the direct contact condenser, the
circulating water must be of the same quality as the boiler
makeup water, however direct contact condensers are less ex-
pensive than shell and tube condensers. The air system for
the tower may be either induced, forced, or natural draft.
Wet Mechanical Draft Towers
The wet tower cools the water by bringing it into contact
with unsaturated air and allowing evaporation to occur.
Heat is removed from the water as latent heat required to
evaporate part of the water. Approximately 7538 of the total
heat transferred is by evaporation, the remainder by
sensible heat transfer to the air.
In addition to the thermodynamic potentials, several other
factors influence the actual rate of heat transfer, and
ultimately, the temperatrue range of the tower. A large
water surface area promotes evaporation, and sensible heat
transfer rates are proportional to the water surface area
provided. Packing (an internal lattice work) is often used
to produce small droplets of water and thus increasing the
total surface area per unit of throughput. For a given
water flow, increasing the air flow increases the amount of
heat removed by maintaining higher thermodynamic potentials.
The packing height in the tower should be high enough so
that the air leaving the tower is close to saturation.
523
-------
The mechanical draft tower consists of the following essen-
tial functional components:
1. Inlet (hot) water distribution
2. Packing (film)
3. Air moving fans
H. Inlet-air louvers
5. Drift or carry over eliminators
6. Cooled water storage basin
Although the principal construction material in mechanical
draft towers is wood, other materials are used extensively.
In the interest of long life and minimum maintance, wood is
generally pressure treated with a water-borne preservative.
Although the tower structure is still generally treated
redwood, a reasonable amount of treated fir has been used in
this and other portions of the tower in recent years.
Sheathing and louvers are generally of asbestos cement, and
fan stacks of fiber glass. The trend in fill is to fire-
resistant extruded PVC which, at little or no increase in
cost, offers the advantage of unlimited life to its fire-
resistant properties. Some asbestos cement is also used for
fill. Even the trend in drift eliminators is away from wood
to either PVC or asbestos cement.
Two problems arise from the use of wood: decay, and its sus-
ceptibility to fire. On multi-celled towers, the cost of
fire prevention system can run into several hundred thousand
dollars or more, constant exposure to water results in
leaching of the lignin from the wood, reducing its strength.
Steel construction is occasionally used, but not
extensively, if at all, for units in the powerplant
industry.
Concrete construction, never popular because of relatively
high labor costs, is actively being considered for large
units of the type used in steam electric generating
stations. The savings in fire protection costs and extended
life make this alternative attractive in many cases.
Inlet water distribution systems are operated at low pres-
sure and wood stave pipe, plastic and metallic pipe have
been used. The blades on the fans must be reasonably light-
weight, and corrosion resistant. Both cast aluminum and GRP
524
-------
(glass reinforced plastic), are generally used -today. For
large towers mounted on the ground, concrete cooled-water
storage basins are used almost exclusively. For other
applications, both wood and sheet metal basins have been
used.
Reference 6 discusses the primary advantages and
disadvantages of various types of wet mechanical draft
cooling towers as described below.
Wet Mechanical Draft Tower - Induced Draft - Crossflow
Currently one of the most widely used wet mechanical draft
towers in the larger sizes is the induced draft crossflow
tower illustrated in Figure B-VII-38. Primary advantages
for this tower are:
1. Lower pumping head as a result of lower packing.
2. Lower pressure drop through the packing.
3. Higher water loadings for a given height.
U. Lesser overall tower height.
Compared to the counterflow tower, crossflow towers have the
following disadvantages:
1. A substantial correction factor must be applied to the
driving force to take into account the reduced thermo-
dynamic potentials in parts of the fill. This is par-
ticularly true at wide ranges and close approaches.
More ground area and more fan horsepower may be required
in some cases.
2. The packing is not as efficient, and more air flow is
required for an equivalent capacity tower.
Despite these disadvantages, the crossflow tower is widely
used. With proper louver design, ice buildup is minimal.
The design is much more versatile, with a tower available to
meet almost every need.
Sizing and costing of mechanical draft towers are dependent
on climatic or operating conditions. Basic parameters
controlling size and cost include:
1. Climatic conditions, particularly wet bulb temperatures
525
-------
during the summer months.
2. Heat load from the powerplant.
3. Cooling water flow rate (or temperature range).
4. Approach temperature.
Two of the major cooling tower manufacturers use proprietary
factors for estimating the cost of cooling towers. Wet bulb
temperature, approach temperature and cooling tower range
are used to determine the factor. Then, the factor and the
circulating water flow are used to determine the tower cost.
Tables illustrating use of the factor by one of the manufac-
turers are shown in Figure B-VTI-41. The rating factor ob-
tained from these curves is inserted into the following
equation:
Tower Units = Rating Factor x Cooling Flow (gpm)
A set of simple calculations then provides Figure B-VII-42;
where cost/10* Btu is shown as a function of Rating Factor
and cooling tower range. The cost factor used was $8.11 for
the cost of a tower unit.
The other manufacturer mentioned uses a slightly different
technique. Using the cooling range, wet bulb temperature,
and approach temperature, a "K" factor is determined. (Fig-
ure B-VTI-43). The "K" factor is multiplied by the cooling
water flow rate. Another chart gives a "C" factor, which
multiplied by the flow through the tower gives an estimated
capital cost. The graph for the "C" factor also has curves
for determining fan horsepower and basin area. A comparison
between the rating factor of Manufacturer A and the K-Factor
of Manufacturer B is shown in Figure B-VTI-44. The rela-
tionship between the two factors is essentially linear.
The curves in Figure B-VTI-43 take into account a size fac-
tor, something that the other procedure omits. Some costs
for various K-Factors and ranges are shown in Figure B-VII-
45.
In addition to water lost by evaporation, a small percentage
of the water is lost as drift, or small droplets carried out
of the tower with the air flow. Drift eliminators are
generally used in the tower to reduce this to a minimum.
Current designs reduce these losses to a small percentage of
the throughput. This drift contains salts and chemicals
added to the water for treatment. These droplets fall out
526
-------
70° WET BULB
40
30
20
• 5 0-6 0-7 0-6 0-9 1-0 1-1 1-2 1»3 1-4 1-5 1-6
RATING FACTOR
TYPICAL CHART FOR DETERMINING RATING FACTOR
(From Reference 74)
Figure B-VII-41
527
-------
3000
2500
cc
I
2000
cc
Ul
o
H 1500
CC
O
u
z
I 1000
u
UJ
5
u.
O
CO
8
500
COST BASIS $8.11/TOWER UNIT
COST INCLUDES TOWER AND BASIN
RANGE 10°F
0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3 1.4 1.5
RATING FACTOR
FIGURE B-VII-42 COST VS RATING FACTOR MECHANICAL DRAFT TOWER (FROM REFERENCE 74)
528
-------
APPROACH 5 6 7 8 910 12
COST = CX$100,000
BASIN AREA = CX 100 FT2
FAN HORSEPOWER =C X 100
PUMP HORSEPOWER = GPM X
0.012
/ 10.0
/
9.0
8.0
7.0
6-°«
O
5.0 §
LL
O
,1.0
10.5
0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0
K X GPM X 106
FIGURE B-VII-43 COOLING TOWER PERFORMANCE CURVES
(57)
529
-------
150
140
J 30
120
1.10
100
90
10
.5
.7 .8
.° .1.0 1.1 1.2 1.3 1.4 1.5 1.6
Rating Factor
57 74
COMPARISON OF K-FACTOR AND RATING FACTOR
FOR THE PERFORMANCE OF MECHANICAL DRAFT COOLING TOWERS
FIGURE B-VII-44
530
-------
A!
kO
o
4J
U)
O
U
m
-P
•H
ft
m
u
1400
1300
1200
1100
1000
900
800
700
600
500
400
300
200
100
16.7°C
0.1
0.2
0.3
0.4
0.5
0.6
0.7
3
Water Flow Through Tower (m"/s)
0.8
GRAPH SHOWING VARIATION OF COST OF MECHANICAL DRAFT COOLING TOWERS
WITH WATER FLOW (from Reference 57)
FIGURE B-VI1-45
531
-------
in the surrounding area and could result in problems of
corrosion to equipment or damage to plants and trees.
In addition to losses from drift, a certain amount of the
water is intentionally removed from the system as blowdown
to control the concentration of salts and chemical additives
in the cooling water. The amount of blowdown varies with
the quality of the makeup water. The amount of heat in this
blowdown stream is relatively small.
Aside from the appearance of the physical structure, an
additional visual result of usage of cooling towers is the
formation of visible plumes of condensed water vapor under
appropriate weather conditions. These plumes are formed
when the temperature of the moisture-laden air leaving the
tower drops below the dew point. With mechanical draft
cooling towers, these plumes are close to the ground due to
the low tower height, and will drop to the ground under
certain wind conditions. With their tall chimneys, natural
draft towers produce plumes at 300-500 feet above the
ground. Further discussion of plumes is provided in a
subsequent section of the report.
Wet Mechanical Draft Towers - Induced Draft - Counterflow
This type of tower, pictured in Figure B-VII-37 is only
slightly different from the crossflow type. The air flow is
counter to the water flow. This makes the tower taller than
the crossflow tower, because additional space must be
allowed at the bottom of the tower for the air to enter.
Some advantages of this system are:
1. The coldest water contacts the driest air. The air, as
it travels up through the water, contacts progressively
warmer water, maintaining the potential for evaporation.
2. The fan forces the air straight up, minimizing air recir-
culation.
3. Larger fans can be used (up to 18.3 meters (60 feet)).
U. Closer approaches and large cooling ranges are possible.
There are a number of disadvantages also:
1. The small air opening at the bottom of the tower leads
to high pressure drops, and subsequently, higher fan
horsepower requirements.
532
-------
2. A more sophisticated air distribution system is required
to maintain uniform air flow through the packing.
3. Since the top of the packing is higher above the ground,
the required pumping head is higher.
Wet Mechanical Draft Tower - Forced Draft
This tower design, pictured in Figure B-VII-46, is not cur-
rently being used to any extent, particularly in the steam
electric utility industry. Its principal advantages are:
1. Noise levels and vibration are reduced, since fans are
mounted at the base of the tower.
2. Blade erosion is non-existent and condensation in gear
boxes is greatly reduced.
3. Fan units are slightly more efficient than induced draft
type, since development of static pressure in tower per-
mits some recovery of work.
Disadvantages of the forced draft tower:
1. Fan size is limited to about 3.6 m (12 ft), necessitating
multiple fan installations.
2. Baffles are necessary for air distribution.
3. Recirculation of the hot, humid discharge air is a prob-
lem, as it can flow back to the low pressure intake.
4. During cold weather, ice may form on the fan blades,
causing damage and reducing air flow.
A modern adaptation of the type of tower is the fan-assisted
natural draft tower, which is discussed under the section on
natural draft towers.
Wet-Dry Cooling Towers
A fairly recent development in the mechanical draft cooling
tower is the wet-dry system. This design combines the wet
and dry tower principles, as shown in Figure B-VII-47. The
concept was originally developed to reduce or eliminate the
plumes from mechanical draft towers.
The principles of operation are shown in the psychrometric
chart in Figure B-VII-U7. The air passing through the dry
section is heated along line 1-3. The air passing through
533
-------
MECHANICAL-FORCED DRAFT COOLING
FIGURE B-VII-46
\ !-* -DPV S£CTION
O
tt
O
s
3
Z
u
ui
Q.
SUPER SATURATION
(Fog) AREA
SUPER HEAT
(Nan-Fog) AREA
'DRY STREAM —•
DRY BULB TEMPERATURE (°F)
PARALLEL PATH WET DRY COOLING TOWER PSYCHROMETRICS
. FIGURE B-VII-47
(From Reference 128)
534
-------
the wet section is heated and humidified along line 1-2.
When the air from these two sections is mixed in the fan
plenum, the condition of the mixture lies along line 2-3, at
some point U. The position of this point is dependent on
the relative amount of the two air streams mixed. The
relative size of the dry section is dependent on the local
climatic conditions as related to the probability of fog
formation.
The details of construction of the tower for plume abatement
are shown in Figure B-VII-48. Note the summer damper door
used to shut off most of the air flow through the dry
section during the summer when plume abatement is not
required. This shunts the air flow to the wet section
during the summer when increased cooling is necessary.
While plume reduction itself can be beneficial, the concept
of combining the wet and dry sections opens up possibilities
for applications where water consumption considerations are
important. By enlarging the dry section, as shown in Figure
B-VII-U9, the principal cooling occurs in the dry system,
with the wet section used only as required. The tower per-
formance in such a situation is indicated on the psychro-
metric chart in Figure B-VII-49. A contract has been signed
for the installation of four wet-dry towers at plant No.
2416. The towers will cool 472,000 gpm of brackish water.
Details are given in Reference 391.
Natural Draft Cooling Towers
The natural draft tower, or hyperbolic tower, as it is com-
monly known, has the advantage that no mechanical energy is
required to circulate the air through the tower. The tall
chimney is used to develop sufficient driving force between
the hot, humid air from the fill and the cooler air outside
the chimney. This force difference must overcome the
internal resistance to air flow.
(pa - pt) g X h = Pressure drop through packing +
go tower friction loss + kinetic energy
of air leaving the tower.
where pa = density of air entering the tower
pt = density of humid air in the tower
g = gravitational constant at elevation of tower
go * reference gravitational constant
h = height of tower
535
-------
SUB-SATURATED AIR MIXTURE
AIR COOLED
HEAT
EXCHANGERS
HINGED SUMMER
DAMPER DOOR
SUMMER
HOT WATER FUOWONLY
INLET PIPE
INTERMEDIATE
WATER
NORMAL
AMBIENT
AIR INLET
COLD WATER
BASIN
PARALLEL-PATH WET DRY COOLING TOWER FOR PLUME ABATEMENT
FIGURE B-VII-48
(Froi? Reference 128)
536
-------
StCTION
o
en
mJ
ei
O
D
X
u
ui
O.
SUPER SATURATION
(Fog) AREA
STUEAM
DIMENSIONS INDICATE
RELATIVE FlOW RATE
SUPER HEAT
(Non-Fog) AREA '
WET STIEAM MASS HOW
DRY BULB TEMPERATURE (=F)
COlO WATER
PARALLEL-PATH WET DRY COOLING TOWER (ENLARGED DRY SECTION)
FIGURE B-VII-49 (Fr°m Reference 128>
-------
Approximately a tenth of the tower height is utilized for
the air-water contact section, the remaining 90S is used
solely to develop the required driving force for adequate
air circulation. A typical installation, in plant No. 4217,
is shown in Figure B-VII-50.
The economical use of natural draft towers is restricted to
regions with moderate temperatures and average humidities.
In areas such as the Southwest, with high temperatures and
low humidities, the potentials for favorable density dif-
ferences are decreased, resulting in an impractically high
chimney to provide circulation for the cooling tower.
Climatic conditions in the Southeast and Gulf Coast areas do
not favor natural draft towers because of the high wind
design loadings.
One of the benefits of the natural draft tower, and perhaps
the reason it has become so popular, is that the fog plume
is released several hundred feet in the air, and does not
create any local hazards due to fogging. However, care
should be taken to assure that the stack gases and the tower
plume do not intermix, as any SO2 that may be present in the
stack gases may tend to combine with the water in the plume
to form damaging acids.
The tower may be constructed for crossflow or for
counterflow, with both types in use. The crossflow takes
slightly more area, as the fill is located outside the tower
proper. Both types may utilize fireproof construction. The
fill material employed is asbestos cement.
One manufacturer gives some curves for budget estimates of
the capital costs of their crossflow towers (see Figures B-
VII-51 and B-VII-52). The costs are shown in 1970 dollars,
and correspond to the relative humidity, range, approach and
wet bulb temperature.
The fan-assisted tower, pictured in Figure B-VTI-53 is a
modification of the basic natural draft tower which makes it
more versatile by combining some features of natural draft
towers and mechanical draft towers. The tower looks like a
truncated natural draft tower. Forced draft fans are
installed in place of the normally large openings for the
entrance of air around the bottom of the tower. with the
forced draft fans, dependence on the natural chimney effect
is removed, considerably increasing the versatility of the
tower. The shortened natural draft chimney retains some of
538
-------
j$0*f
TYPICAL NATURAL DRAFT
COOLING TOWERS
PLANT NO. 4217
Figure B-VII-50
-------
15° RANGE
10096 RH
APPROACHES
0123
TOWER COST - DOLLARS PER THOUSAND BTU/HR.
25° RANGE
100% RH
APPROACHES
50 -
0123
TOWER COST - DOLLARS PER THOUSAND BTU/HR
15° RANGE.
50% RH APPROACHES
0123
TOWER COST - DOLLARS PER THOUSAND BTU/HR.
25° RANGE
50?6 RH
APPROACHES
0 23
TOWER COST - DOLLARS PER THOUSAND BTU/HR.
15° RANGE
25 96RH APPROACHES
I 2 .3
TOWER COST - DOLLARS PER THOUSAND BTU/HR
25°RANGE
2556 RH APPROACHES
TOWER COST - DOLLARS PER THOUSAND BTU/HR.
HYPERBOLIC NATURAL DRAFT CROSSFLOW WATER COOLING TOWERS
TYPICAL COST-PERFORMANCE CURVES FOR BUDGET ESTIMATES
(From Reference 74)
Figure B-VII-51
-------
35° RANGE
10096 RH
APDRCACHES
0123
TOWER COST - DOLLARS PER THOUSAND 8TU/HR
45° RANGE
10096 RH
APPROACHES
I 2 3
TOWER COST - DOLLARS PER THOUSAND BTU/HR
35° RANGE
5036 RH
0123
TOWER COST - DOLLARS PER THOUSAND BTU/HR
45° RANGE
5096 RH „
I 2 3
TOWER COST - DOLLARS PER THOUSAND BTU/HR
35°RANGE
35% RH
ACPP CiC HE S
80 | 1
60
I 2
TOWER COST - DOLLARS PER THOUSAND BTU/HR
45° RANGE
35% RH
APPROACHES
1111
I 2 3
TOWER COST - DOLLARS PER THOUSAND BTU/HR
HYPERBOLIC NATURAL DRAFT CROSSFLOTC WATER COOLING TOWERS
TYPICAL COST-PERFORMANCE CURVES FOR BUDGET ESTIMATES
(From Reference 74)
Fiaure B-VII-52
-------
Reinforced-concrete veil
based on same design prin-
ciples as Research-Cottrell
hyperbolic natural draft
towers. Creates natural
draft, reducing fan power
requirement. No need for
orientation with respect to
prevailing wind, or wide
spacing between multiple
units.
Forced-draft fans assist
natural draft, reducing
required tower height.
Tower height can be
just enough to avoid
problems of vapor
plume downdraft to
ground level, and of
moist air reclrcula-
tlon.
Counterflow design
locates the fill inside the
tower, minimizing pump-
ing head. Fill can with-
stand ice load, if it should
ever accidentally occur,
without destruction. Veil
and-fill are constructed
entirely of fireproof, rot-
proof materials—essen-
tially maintenance free.
FAN-ASSISTED NATURAL DRAFT COOLING TOWER
FIGURE B-VII-53
(From Reference 358)
542
-------
the driving force, reducing fan requirements. The height,
intermediate between the mechanical draft and natural draft
tower, reduces the chance of local hazards from fog. The
possibility of recalculation is also reduced. While no fan-
assisted natural draft towers are currently operating in the
U.S., several towers are operating in Europe.
Dry-Type Cooling Towers
The dry-type cooling tower is used more in the petroleum
processing industry than the electric utility industry.
Being a closed system, the bulk of the heat is transferred
from the petroleum products to air directly, with the final
cooling to ambient temperatures being accomplished with
evaporative-type towers. The temperatures obtainable with
dry-type cooling towers are higher than those economically
useful in the electric utility industry. Since no
evaporation is involved, the dry bulb temperature governs,
not the wet bulb temperature. In spite of this, the utility
industry is considering this type of system for specific
installations where insufficient water is available for wet
towers. There are approximately six electric generating
stations using dry-type cooling towers, principally in
Europe. The one operating facility in the U.S. is a 20 Mw
unit. This is a "direct" unit, with the steam condensing
directly in the coils. Construction of a 330 Mw unit at the
same site utilizing a dry tower -is contemplated. The two
types of dry towers, direct and indirect, are shown in
Figures B-VTI-54 and B-VII-55.
The principal drawback to the use of this type of tower is
the higher turbine exhaust pressures which result. Current
turbine designs would have to *be changed, as most turbines
are designed for a maximum turbine exhaust pressure of 127
mm Hg (5 in. of Hg abs) whereas with dry-type cooling
towers, the maximum turbine exhaust pressure would range
from 200 to 380 mm Hg (8 to 15 in. of Hg) . Dry bulb
temperatures range from 5.5° to 20°C (10° to 35°F) above the
wet bulb temperature. Due to the higher heat transfer
equipment costs, dry-type towers optimize at higher
approaches than wet towers, additionally increasing the
turbine exhaust pressure.
A temperature diagram for an indirect, dry cooling tower is
shown in Figure B-VII-56. In dry cooling towers the initial
temperature difference (ITD) is used as a design parameter.
The ITD is the difference between the saturated steam
temperature of the turbine exhaust and the temperature of
ambient air entering the cooling tower. The corresponding
543
-------
CONDENSATE
HEADER
TO FEEDWATER
CIRCUIT
EXHAUST STEAM
STEAM
HEADER
AIR FLOW
\ /
X
FAN
-*-
CONDENSATE
HEADER
STEAM TURBINE
STEAM SUPPLY
CONDENSATE
RECEIVER
CONDENSATE
PUMP
EXHAUST
STEAM
TRUNK
I
EXHAUST
STEAM
CONDENSATE
POLISHERS
Figure B-VII-54
DIRECT, DRY-TYPE COOLING TOWER CONDENSING SYSTEM
WITH MECHANICAL DRAFT TOWER
241
-------
ui
DRAFT TOWER
STEAM
TURBINE
EXHAUST
STEAM
t COOLING COILS
DIRECT-CONTACT
CONDENSER
WATER RECOVERY
TURBINE
STEAM SUPPLY
CONDENSATE POLISHERS
CIRCULATING PUMP
•MOTOR
CIRCULATING
VMTER PUMP
CONDENSATE TO
REACTOR FEEDWATER
CIRCUIT
Figure B-VII-55
INDIRECT, DRY-TYPE COOLING TOWER
CONDENSING SYSTEM WITH NATURAL-DRAFT TOWER 241
-------
DIRECT-CONTACT
CONDENSER
TURBINE EXHAUST
STEAM
COOLING COILS
Tsl
r
TRANSFER OF HOT CIRCULATING
WATER FROM CONDENSER
TO TOWER
1
u
cr
ui
(L
UJ
^-TRANSFER OF COLD CIRCULATING WATER
FROM TOWER TO CONDENSER
(I)
I
AMBIENT
tu
(2)
I
(3)
I
(4)
I
AIR
(I) WATER AND STEAM ENTERING CONDENSER
(2) WATER LEAVING CONDENSER
(3) WATER ENTERING TOWER AND AIR LEAVING TOWER
(4) AIR ENTERING TOWER AND WATER LEAVING TOWER
Figure B-VII-56
TEMPERATURE DIAGRAM OF
INDIRECT DRY COOLING TOWER
HEAT-TRANSFER SYSTEM 24°
546
-------
temperature difference in the wet tower system is the sum of
the approach to wet bulb, cooling range and terminal
temperature difference (TTD).
Assuming the design parameters typical of an eastern U.S.
location (dry bulb temperature equal to 32°C (90°F) and wet
bulb temperature of 25°C (76°F)), the turbine exhaust pres-
sures corresponding to a wet system and corresponding to a
dry system can be compared. For the wet tower, typical
values of the cooling range, approach, and terminal
temperature difference are 12, 11 and 5.5°C, respectively.
The sum of these is 29°C (52°F), which yields a condensing
temperature of 53.5°C (128°F) with a corresponding pressure
of 14.5 kN/sq m (4.3 in. of Hg abs) in the wet system.
A corresponding dry-type tower with an ITD of 29°C (52°F)
with the ambient temperature of 32.2°C (90°F), gives a con-
densing temperature of 61.1°C (142°F) with a corresponding
pressure of 20.4 kN/sq m (6.2 in. of Hg abs). This is
almost 50% higher than the condensing pressure in the wet
system.
A number of economic studies have been made comparing the
cost and benefits of dry-type towers with wet towers. Some
data from one of these has been used to calculate the cost
curves shown in Figure B-VII-57. The curves are for the
cooling tower only. The variation in cost shown is due
primarily to the variation in construction costs in the
different locations. Northeast, West, and Southeast rather
than to variations in the design dry bulb temperature
indicated on the figure.
The direct contact condenser is considerably cheaper than
the normal shell and tube condenser, as it does not require
expensive alloy tubes. A typical direct contact condenser
is shown in Figure B-VII-58. The lower condenser costs par-
ticularly make up for the greatly increased cost of the
cooling tower.
There are a number of other benefits from the dry-type cool-
ing tower.
1. No water usage, thus no large makeup requirements and no
buildup of solids, chemicals, etc., in the water as in
an evaporative tower.
2. There is no possibility of fogging and there are no
drift losses to deposit minerals on the surrounding
territory.
547
-------
10,000 _
o
.-!
\
4-1
in
0
O
ro
•P
•H
0-
flj
CJ
9,000 _
8,000
7,000
5,000
5,000
4,000
3,000
2,000
1,000
Natural Draft
Towers
ir
Average Design
Dry Bulb Temperature
18
20
25 30
ITD (°C)
35
40
45
REPRESENTATIVE COST OF HEAT REMOVAL WITH DRY TOWER SYSTEMS
(from Ref. 240) FOR NUCLEAR PLANTS
FIGURE B-VII-57
548
-------
Ul
it*
WATER INLET
AIR VAPOR
•OFFTAKE
CASCADE
PLATES
CONOENSATE
OUTLETS
STEAM INLET
EXPANSION JOINT
STEAM INLET FROM
TURBINE EXHAUST
WATER DISTRIBUTION
PLATE
Figure B-VII-58
STREAM TYPE
DIRECT CONTACT CONDENSER240
-------
On the other side of the ledger, there is a significant loss
in plant efficiency due to the higher turbine exhaust pres-
sures. Figure B-VII-59 gives the expected increases in fuel
consumption and decrease in power output for a nuclear and
fossil-fueled plant, provided the turbine could operate at
the higher pressures indicated. Not only is there a loss in
efficiency, but the maximum plant capacity is also reduced.
Other Tower Types Used Outside the D.S.
Conventional multicell evaporative mechanical draft cooling
towers and evaporative natural draft cooling towers are used
outside the U.S., as are several types of dry cooling
towers. Another type of tower widely used outside the U.S.
is the circular base evaporative mechanical draft cooling
towers. The basic design of this type of tower is shown is
Figure B-VII-60. One firm has supplied hundreds of these
towers, in sizes up to approximately 40,000 metric tons per
hour circulating water rate. A tower at the Staudinger
plant handing 40,000 metric tons/per hour has a base
diameter of 61 meters and a height of 50 meters. This firm
has supplied one circular based mechanical draft tower to a
U.S. utility for plant no.'4210.*°° Figure B-VII-61 shows
the use of 34 circular mechanical draft towers with fan
diameter up to 21 meters and one natural draft cooling tower
of 115 meters height for units sized between 100 and 300
megawatts at the Frimmersdorf plant.*o»
Mechanical draft cooling towers of circular base with forced
draft fans have been supplied by the firm discussed above
for 5 powerplants. The largest of these are 2 towers at the
Biblis plant where 105,000 metric tons per hour of cooling
water is circulated in each tower. The towers are 80.5
meters in diameter and 80 meters in height.*00
A novel cooling tower is being constructed under financing
of the West German government. This tower, shown in Figure
B-VII-62, consists of a center mast 575 feet tall, with an
upper ring 290 feet in diameter and a lower ring 490 feet in
diameter. These rings are connected by cables to give a
hyperbolic shape as shown, with a minimum diameter of 260
feet. The network of cables will be covered with aluminum
panels to complete the tower. It is hoped that this method
of construction will eliminate the size constraints imposed
by the present reinforced-concrete construction. The first
tower is being designed and constructed by two large German
cooling tower firms, Balke-Durr and GEA, working together.
The unit will be at the Schmehausen station, cooling a 300
Mw unit, but will be designed to accommodate a 500 Mw
unit.3««
550
-------
15
20
10
la
•" f n
If
9r in
in
ro
ui
^
O
CO
^
•*"*
z
2 15
£
5
0
O
_l
UJ
2 10
z
LU
CO
111
DC
0
£ 5
UJ
O
DC
UJ
a.
~
CO
' <
i UJ
5 £
LU
Q
u.
! *^
LU
u
cc
LU
p-***
^x*
^
CO
<
w /
s! /X
>^
^^9
-^7
x^
w
z
2
/
4 5 6 7 8 9 10 11
TURBINE EXHAUST PRESSURE - INCHES Hg ABS
12 13 14
FIGURE B-VII-59 EFFECT OF TURBINE EXHAUST PRESSURE ON FUEL CONSUMPTION AND POWER OUTPUT
(FROM REFERENCE 269)
551
-------
1 Fan
2 Tower shell
. 3 Central shaft concrete housing
4 Water distribution system and
drift eliminator
5 Cooling fill material
6 Vertical driving shaft
7 Dry chamber for mechanical
equipment
8 Drive gear with motor and
turbo coupling
Figure B-VII-60 Section Across a Circular
Mechanical Draft Cooling Tower
400
552
-------
Ul
LTI
L-J
Nr. 1B/BO/173J Met) -Pras Dusselciorl
Figure E-VII-61 Frimmersdorf Power Station
401
-------
\ /. \ •.
. V v" \' "'•'
" '
- ^ ••" ^ x
. . / - - 'v /••: \/\ .'
.-••• • i- ••• •. "',-.->
Figure B-VII-62 Cable Tower
554
-------
Balcke-Durr has also supplied large cooling towers with
noise suppression. At Bewag's Lichterfelde plant in Berlin,
3 circular forced draft towers circulating 12,000 metric
tons per hour (150 megawatts) each of water were built from
1972 to 1974. Noise level guarantees were 60, 55, and 50
db(A) at 5 meters, respectively, for the first, second and
third towers constructed. The towers are 35 meters in
diameter and 50 meters in height. See Figure B-VTI-63. At
Kkw's Biblis plant, 2 circular forced-draft towers
circulating 105,000 metric tons per hour each of cooling
water are planned for installation in 1975 to 1976. A noise
level is guaranteed of 19 db(A) at 1,000 meters. The towers
are 65 meters in diameter and 80 meters in height. At
Stadtw.*s Duisburg plant, 1 circular forced-draft tower
circulating 48,000 metric tons per hour of cooling water is
plannned for installation in 1975/1976. A noise level is
guaranteed of 25 db(A) at 500 meters. The tower is 55
meters in diameter and 48 meters in height.
In the case of the Lichterfelde plant in Berlin, the noise
levels of the towers were based on a noise regulation which
limited noise to 35 db(A) at night at a distance of 130
meters from the plant. This plant was constructed at a site
in close proximity to a high-density residential area. Site
selection was limited by the unique territorial constraints
of West Berlin.*o«
Survey of Existing Cooling Water Systems
The FPC Form 67 Summary Report for 1970 summarizes the use
of once-through cooling, cooling ponds, cooling towers, and
combined systems by number of plants and by installed
capacity (Table B-VII-3). In 1970 about 23% of the plants
(1851) of installed capacity) used cooling ponds or towers.
Data submitted to the FPC by Regional Reliability Councils
indicates that cooling ponds or cooling towers are already
committed for over 50* of the total capacity of units to be
installed 1974 through 1980. See Table B-VII-4. Table B-
VII-5 gives the total installed capacity, fossil-fueled and
nuclear, which is committed to cooling towers, supplemental
cooling, or once-through cooling, for plants 300 Mw and
larger under construction as of April 1, 1974.
Site visits were made to a number of steam electric genera-
ting plants. One purpose of these visits was to observe
actual operations of cooling water systems and to discuss
operating experiences with plant personnel. Design and
operating data were obtained for these plants, including
basic plant information, type of cooling system,
555
-------
Figure B-VII-63 Cooling Tower with
Lichterfelde Plant
Control at
556
-------
Table B-VII-3
USES OF VARIOUS TYPES OF COOLING SYSTEMS 233
Based on FPC Form 67 for 1969, 1970
Type of Cooling
Once-through, fresh
Once- through, saline
Cooling ponds
Cooling towers
Combined systems
Number
% t
1969
49.8
18.9
5.4
17.2
8.7
of Plants,
otal
1970
49.4
18.5
5.7
17.5
8.9
Installe
% 0
1969
50.5
23.5
5.9
10.9
9.2
d Capacity,
f total
1970
50.!
22.8
6.7
11.2
9.2
Ui
-------
Table B-VII-4
EXTENT TO WHICH STEAM ELECTRIC POWERPLANTS ARE
ALREADY COMMITTED TO THE APPLICATION OF
THERMAL CONTROL TECHNOLOGIES 61
CONTROL TECHNOLOGY
ASSOCIATED GENERATING CAPACITY, THOUS, MW
IN ACTUAL USE
IN 1973
COMMITTED FOR UNITS INSTALLED
1974 THROUGH 1980
ui
Ul
00
No Control (Once-Through)
Controlled
• Cooling Towers
• Cooling Ponds
• Combinations
Unknown
230
110
60
130
50
30
30
80
40
10
30
-------
Table B-VII-5
COOLING SYSTEMS FOR PLANTS 300 Mw AND LARGER UNDER CONSTRUCTION
(April 1, 1974)*
TYPE OF COOLING
Cooling Towers
Supplemental Cooling
Once-Through
Total
FOSSIL-FUELED
MW
46,276
6,466
56,334
109,076
NUCLEAR
Mw
30,428
8,518
52,587
91,533
TOTAL
Mw
76,704
14,984
108,921
200,609
% Total
38.3
7.5
54.2
Ul
Ul
VD
* Source: May, 1972 FPC printout of utility responses to FPC Order No. 303-2
-------
quantitative data such as flow rate, temperatures, and
approximate cost data.
Plants visited were chosen to result in a spectrum of
fossil-fueled and nuclear units, geographical locations,
sizes, and types of cooling systems. Table B-VII-6 presents
a list of plants visited in the U.S. and the basic cooling
water data collected. A few plants that were visited are
not included in this list as a result of incomplete data.
Many of these plants have once-through or open condenser
cooling water systems. Sources of cooling water for plants
visited include lakes, wells, rivers, and estuaries.
Generally, the water in these plants is discharged at the
temperature at which it leaves the condenser. However,
several "helper" systems were observed, where the water is
cooled before being returned to the source, using a cooling
tower or other device. One plant discharged cooling water
to a municipal water system.
Some of the plants that have been designed with or have used
once-through cooling systems are installing closed cooling
systems as a result of environmental regulations. In most
instances, a small loss of plant capacity and efficiency has
resulted when this change has been made.
Other plants visited have closed condenser cooling water
systems, where the cooling water is not discharged to the
receiving water, in order to avoid a thermal impact, but is
recirculated utilizing cooling ponds and cooling towers.
A number of plants use cooling ponds. These may be artifi-
cially constructed lakes, or may be canal shaped. If avail-
able land is limited, a smaller pond may be constructed by
utilizing spray modules. Among the plants visited with con-
ventional cooling ponds, operation generally appeared satis-
factory, and as predicted. Some plants using spray ponds,
however, seem to be having difficulties in maintaining
satisfactory operation with these units.
Cooling towers are also used in a number of cases for
cooling the condenser cooling water in closed recirculating
systems. Both mechanical draft and natural draft wet towers
were observed. Natural draft towers seem to have been
specified in cases where there was concern over possible
fogging effects from mechanical draft towers. Performance
of plants with cooling towers appears to have been
satisfactory in all cases.
560
-------
Table B-VII- 6
COOLING WATER SYSTEMS DATA
PLANTS VISITED
Plant ID
Code Ho.
0640
Type Of
Fuel
NUCLEAR
Plant
Capacity Type
Mw
Hafjral
916 Draft
Coolinq
He idh t
Ft. Meters
425 129.5
Tower
Diameter
Ft. M
325 99.6
Water _,
BF of Pond
28
Cooliii'j Pond
Surface Area
Acres H* (10J )
or Like
Volume
Acre Ft. MJ(10J)
Ave rage
Time
Once -Throuql
Length of Pipe
Ft. M
System
Diameter of Pipe
Ft. M
Discharge
Type Comments
1201
1201
5105
2525
0801
1209
1209
2612
4217
4B46
3713
3626
1723
2512
3115
3117
2527
0610
2119
.OIL & GAS
OIL S GAS
OIL
OIL
COAL & GAS
COAL S GAS
NUCLEAR
' NUCLEAR
•I
COAL
COAL
COAL
COAL
NUCLEAR
OIL
OIL S, GAS
NUCLEAR
OIL
OIL 6 GAS
COAL
139.8
792
1386
1165
300
820
1456
Mechanical
700 Draft 62
Natural
1640 Draft 323
1150
2137
290
1618
542.5
644.7
457
28
750
Natural
2534 Draft 437
Artifical 1100 4460 9350 11556
Spray
Canal 7.35 29.8
SSnal 14'1 57'17 132 163"'5
Natural
Lakes 536.63 2176 11234.3 13885
Artif ical
Canal 3a60 15652 20,000 24719
18.89 48 14.63 30
98.45 247 75.28 28
Artif ical
Lake 2353 9541 50600 62541
Art if ical
Reservoir 32510 131830 1093600 135167
.Natural
Lake
Spray
Pond 2S 113.54 171 211.35
133.2 311 94.8 27.7
850 250 4 1.22 Gravity
100
6(Inlet) 1.828 9 mos.once thr
2 lO(Outlet) 3.048 wavity 3 mos .spr .canal
Gravity once through
units 162
canal will be
100 useunttsa|11 4
Length of tower
3300 1005 11 3.352 Gravity 650 ft.
two towers
are used
356 108.5 0.75 0.228 Gravity
Hultiple spr canal will
Ditruser Be installed
3619 1103 16 4.876 Systems to replace dlf
250(Inlet) 76.2 5.5IIN) 1.676 plujrietv SyS '
235(Outlet) 71.62 7.5(OUT) 2.28 OutTall
40(Inlet) 12.19 5.5UN) 1.676 Gravity Concrete
IS(OUT) 4.57 7.5(OUT) 2.28 Type Tunnel
80 24.38 4.5 1.51
3 such towers
for 3 Units
-------
Effluent Heat Reduction for Closed-Cycle Systems
The effluent heat reduction achievable by closed-cycle
evaporative cooling systems, as a fuction of the cycles of
concentration is given in Tables B-VII-7, 8, compared to a
once-through system and a helper tower system, respectively.
562
-------
Table B-VII-7
EFFECT OF CYCLES OF CONCENTRATION ON COOLING SYSTEM LOSSES, MAKEUP REQUIRED,
REDUCTION IN EFFLUENT HEAT Reference 389( 1,000 megawatt unit)
Cycles of
Concentration
(a)
1.5
2.0
3.0
4oO
6.0
8.0
10.0
Evaporation
Rate, m /hour
n rate is 86,260 mVliv. ' Heat duty is 3.81 bill I.on .RTU/lir and
U-capei-rtUirc ranj;e is ll.l°C (20.0°F).
(:>) Ar,t;i.iir.j-.! hoai; t r
-------
Table B-VII-8
liffcet of Cycles ol Concentration
on Heat IHscliarge Kate
From ;i 1,000 raw Power Station 389
Cycles of
Concent rat i on^a'
1.5
-i.U
3.0
4 . 0
d.il
8.0
10. 0
li 1 owdown
Rate, m3/hr(t>,c)
2460
1230
615
410
246
176
137
Heat Discharge for Temperature
Differences Between Receiving
and 1U owdown, million BTU/hr
AT=1°C AT=5°C £1=10° C
9.37 48.66 97.33
4.87 24.33 48.66
2.43 12.16 24.33
1.62 8.11 16.22
0.97 4.87 9.73
0.70 3.48 6.95
0.54 2.70 5.41
Percent Reduction Over
Helper Tower Assisted
Once-Through System* i: '
96.2
98.1
99.0
99.3
99.6
99.7
99.8
(a) Power plant thermal efficiency assumed to be 40 percent. Heat duty
is :).H1 billion IViT/hr and cooling tower temperature range is 11.1°C (20"F)
(h; Assumed lieal transfer is 75 percent evaporative
(<•) ni'/lir x 4.4 = gpm
(d) Based on the operation of a 65,150 m3/hr "helper tower" in which warm water
from the coiulenser(s) passes through the cooling tower and then directly to
a renei vi iij', body.
564
-------
PART B
THERMAL DISCHARGES
SECTION VIII
COST, ENERGY AND NON-WATER QUALITY ASPECT
Cost and Energy
The evaluation of the additional costs to be assessed
against the power generated in a unit to which a helper or
closed cooling system has been added are of prime importance
to a utility. This provides a basis for determining the re-
quired rate increases. In addition, the capacity of a unit
is reduced by the amount of power used in the cooling system
plus any penalties that iray be incurred by required shifting
of unit operating parameters, primarily, the increase in the
turbine exhaust pressure. This lost capacity must be
replaced, either by new capacity, or operation of other
units more intensively.
The cost of installation of cooling towers can be signifi-
cantly higher at sites with adverse local conditions. Land
with insufficient bearing strength would require piling, or
use of mechanical draft towers instead of natural draft, or
both. conversely, in hilly terrain, extensive, and
expensive, excavation into hard rock might be required.
Even if only piping has to be excavated into rock, the cost
is increased significantly. Reference 250 contains a
detailed study of tower installations at such a site.
Proximity of stations to earthquake faults means additional
structural strength will be required, particularly in
natural-draft towers. Towers in Florida and the Southeast
require hurricane-resistant design. Other factors of a
specific local nature at other sites will increase the cost
of installation of cooling towers.
Addition of a cooling system to an existing plant will re-
quire breaking into existing structures, piping or tunnels.
Suitability of existing structures used in the new system
will have to be evaluated. Will the structures withstand
the new pressures? Will it be easier to modify the con-
densers for increased pressures, and connect directly to
them, or should the cooling system be connected at the
present intake and outfall? These are questions that must
be answered during design of the cooling system. The
current layout, pump size, and location of intake and
outfall structures will influence the required decisions.
565
-------
The plant or unit will be shut down during the final period
of installation when the new system is connected to the
unit. The unit's generating capacity is lost during this
period. In some cases the connections can be made during
the annual scheduled overhaul. In other cases extended
downtime may be required, maybe as much as three or four
months. Costs would vary accordingly. The dollar value of
these costs will vary from plant to plant.
The economic analysis of adding a supplemental cooling
system to an existing unit consists of evaluating the costs
of the following:
1. Installing the cooling system
2. Operating and maintenance costs of cooling systems
3. Providing additional generation capacity to replace
power used or capacity lost
4. Operating and maintenance costs for replacement capacity
5. Additional cost of generation of remaining power due to
a decrease in plant heat rate
Once these individual costs are determined, the total cost
for the addition of a cooling system to an existing plant
can be developed.
There are a number of methods in which the costs can be
evaluated. These methods include annual costs, present
worth, and capitalized cost.
Probably the most popular method of comparing investment
alternatives for return on capital is the present worth
method. The result of this type of analysis, and the
capitalized cost method, is a dollar value for each
alternative.
In this study, the interest is primarily in incremental
costs, i.e., how many mills/kwh will the addition of a
cooling system add to the cost of generation of each fcwh?
Since generation costs are normally expressed in mills per
kilowatt hour, this was chosen as the cost basis for the
addition of cooling systems. This cost was developed using
the method of annual costs. The additional costs for the
year were totaled and divided by the power generated to give
an additional generation cost.
566
-------
The capital investment involved in the addition of a new
cooling system to a once-through plant can be split into two
parts. The first is the installed cost of the tower and its
necessary auxiliaries. These include new pumps, controls,
power system, motor starters, and modifications to the ex-
isting condenser and piping system. The second part is the
capital cost of the replacement generation capability. It
is normally assumed that gas turbine units will be installed
to provide the power to replace that no longer available due
to installation of the cooling system. Once these costs
have been determined, the annual cost is determined by use
of the fixed charge rate. The fixed charge rate is a
percentage, which when multiplied by the capital investment,
gives the annual expenses incurred for the capital invested.
Included in the fixed charge rate are interest on this
capital, depreciation or amortization, taxes, and insurance.
The actual fixed charge rates vary for each utility, but
generally they average around 15% for investor-owned
utilities. The fixed charge rate for publicly-owned
utilities is normally several percent lower, with a 11% rate
corresponding to the 15% for the investor-owned utility.
Of the four items included in the fixed charge rate, in-
terest on the capital and depreciation or amortization
account for the largest portion of the total. Interest on
the capital varies with the current cost of money. Depreci-
ation or amortization rates depend primarily on the life of
the equipment to be built. An installation with a life of
25 years would be depreciated at U%, while an installation
with a life of 5 years would be depreciated at 20%.
When the complete plant is built at the same time, one rate
is normally used to cover the entire installation. When
adding a cooling system onto an existing unit, the period
over which the cooling system is depreciated is the
remaining life of the unit, not the life of the cooling
system. Whether the cooling system will have any salvage
value when the unit is shut down depends on the location and
type of system used. Obviously, if the cooling system can
be switched to another unit, it will have salvage value.
For evaporative type towers, switching to another unit is
generally not possible, and the tower will therefore have no
salvage value. It will usually be uneconomical to move the
tower due to the high construction costs involved. Powered
spray modules will have salvage value, as they could be
moved to other sites. If the cooling system will have a
salvage value when the unit is retired, the amount upon
which the depreciation is figured is the difference between
the installed cost and the salvage value.
567
-------
The operating and maintenance costs for a cooling system
include the incremental power required by the pumps and fans
(if mechanical draft is used), maintenance and annual
overhaul labor and parts and associated overhead. Both the
pumps and fans are low maintenance items, so the major cost
is the energy to operate the system. One cooling tower
manufacturer gives a figure of about $200 per year per fan
cell as a tower maintenance cost. The circulating pumps
would normally be overhauled once a year, which is a two
week job en the average.
The amount of replacement generation capacity required is
determined by adding the capacity penalty on the unit due to
increased turbine backpressures to the power required by the
cooling system. The unit capacity rating is normally given
for a stated steam inlet condition and flow, and
corresponding turbine exhaust pressure. If the cooling
system can be added without changing the turbine exhaust
pressure, there is no backpressure penalty. However, if the
turbine exhaust pressure is increased, which normally occurs
with a closed cooling system, the output of the unit is de-
creased by up to several percent, depending on the increase
in turbine backpressure. Turbine manufacturers supply the
curves necessary to determine this decrease in capacity with
the turbine. The backpressure cannot be increased without
limit, without necessitating redesigns of the turbine. For
current condensing turbines, the maximum turbine exhaust
pressures are 17 to 18.5 kN/sq m(5.0 to 5.5 in. of Hg abs).
The limiting factor is the design of the last stages in the
turbine. Once the amount of replacement capacity is deter-
mined, its cost can be calculated. If new capacity is in-
stalled, it would be completely separate from the unit, and
would be depreciated independently of the unit for which the
capacity was required.
The operating cost of this replacement power must be charged
against the cooling system. The total operating cost would
depend upon how many hours a year the additional generation
was required. Throughout most of the United States, peak
loads - come during the summer months. Thus the replacement
power would probably only be required during the summer.
The remainder of the year, the units with backfitted cooling
systems should be capable of handling the demand, even at
the reduced capacity. The annual operating hours for which
replacement power would be required and the associated cost
would depend on the particular utility involved.
Associated with any capacity penalty is an increase in unit
heat rate. The Joules (Btu) heat input to the unit is
changed by adding the cooling system, but less power is
568
-------
generated due to the higher turbine exhaust pressure. This
means that more Joules (Btu) are being used per Kwhr
generated. Again, by making use of the turbine curve, the
corresponding magnitude of the change in generation cost can
be determined. Here again, the penalty will apply only part
of the year. Only when the climatic conditions are such
that the design turbine exhaust pressure is exceeded will
this increased generation cost exist. Furthermore, the
operation of the fans in mechanical draft towers need not be
continuous throughout the year. Figure B-VIII-1 is an
example of how the net power output of a unit can be
optimized by reducing fan power. This is again dependent on
the specific unit in question.
Once the annual cos»ts for the above items have been deter-
mined, they can be totaled to give an annual cost for the
addition of the cooling system for the unit. The total
generation expected to be delivered to the bus bar is then
determined, and the additional generation cost due to addi-
tion of the cooling system can then be determined directly.
Cost Data - Plant Visits
Cost data 'were obtained from the U.S. steam electric
generating plants which were visited during the course of
this study. The utilities involved were very helpful, with
seventeen providing the requested information.
Nuclear plants and all three types of fossil-fueled plants
(coal, oil, and gas) were visited. The size of the plants
visited ranged from 28 Mw to the largest in the country at
approximately 2,500 Mw. One plant had a unit constructed in
192U. In the remaining plants, all units were constructed
after 1952, with 12 plants being constructed after 1960. Of
the total number of plants visited, 5 were nuclear. Seven
of the plants had once-through cooling systems, the
remaining were on, or in the process of installing, closed
or helper cooling systems.
The types of closed systems involved were mechanical and
natural draft cooling towers, spray canals, and man-made
cooling ponds. One of the two helper systems inspected
utilized natural draft cooling towers, the other spray
modules in the discharge canal.
Two types of information were requested, the first involved
the physical description of the plant and its operation.
The second was concerned with the cost of the plant, and the
cooling system in particular. In addition, by visiting
569
-------
100%
OPTIMUM COOLING
TOWER FAN
CAPACITY IN
SERVICE
50%
WET BULB TEMPERATURE
Figure B-VIII-1
EXAMPLE OF OPTIMIZATION OF NET UNIT POWER OUTPUT BY REDUCTION OF
COOLING TOWER FANS
362
-------
plants throughout the country, a great deal of information
about regional problems and their solutions was collected.
A compilation of the cost data is shown in Table B-VIII-1.
Probably the most important feature of this table is the
great variation of costs involved. The land for plant No.
5105, a 1,157 Mw station, cost $172,000. The land at plant
No. 0610, for a 750 Mw unit, cost $3,335,000, most of which
was for a spray canal. In the table, the unit cost ($/kw)
varies from a low of $68/kw to a high of $387/kw, with the
higher values being those for the nuclear plants. The costs
also vary with year of installation, with the older units
having lower costs. The highest unit cost for a fossil-
fueled plant is plant No. 2527 at $155/Jcw, for a 28 Mw
plant. Larger plants tend to have lower unit costs. Plant
No. 2525 at 1,165 Mw and a unit cost of $142/kw, seems to be
an exception.
Operating and maintenance cost data for cooling systems are
sketchy. In general, operating and maintenance costs appear
to be a small part of the total operating cost for a
station. In only one case was the reported operation and
maintenance cost of the cooling system greater than 1% of
the capital cost of the cooling system (Plant no. 3626).
Energy required to operate the cooling systems, as reported,
was 2% or less of the rated station capacity. Loss in
capacity due to higher turbine exhaust pressures varied from
O.tt% to 2.5%.
Of the five plants reporting increases in heat rate, three
reported increases of 105 kJ/kwh (100 Btu/kwh)(roughly IX of
gross plant heat rate) or greater, fthen a specific plant is
considered for a cooling system other than once-through, the
plant cooling system design is normally optimized. This
means some increase in turbine exhaust pressure, and conse-
quently higher circulating water temperatures. This permits
use of smaller cooling towers, and the savings realized on
smaller towers more than offset the increase in costs due to
the higher turbine exhaust pressure. Thus part of the heat
rate increase is intentional, and results in lower overall
costs.
The last two columns of the table describe the-cooling
system currently in use or being installed and the reason
for its installation. Stations employing different types of
closed cooling systems were included in the plants visited.
In the table, a lake is differentiated from a cooling pond
in that the lake in question was created by damming a stream
in which the water rights did not belong to the power
571
-------
TABLE B-VIII-1
COOLINC rfATER SYSTEMS - COST DATA
PLANTS VISITED
Plant Cost Data
ID
Olj.'.O
1201
1201
5105
2525
0801
1209
1209
2612
4217
u,
M 3713
3626
1723
2512
3115
•117
2527
U610
2119
Type of capacity
Fue 1 Mw
HUCLEAR
OIL & GAS
OIL & GAS
OIL
OIL
COrtL f. GAS
COAL & GAS
NUCLEAR
NUCLEAR
COAL
COAL
COAL
NUCLEAR
OIL & GAS
NUCLEAR
OIL
OIL & GAS
COAL
'1C
139.8
792
1157
1165
300
820
1486
700
1640
2137
290
1618
644.7
457
28
750
2534
Date of
Const.
:-,-is-7.:
1956T59
1969-72
1958-69
1961-69
1924-64
1964-67
1967-73
1966-70
1965-68
1962-70
1952-55
1966-72
1954
1967-73
1964-66
1968-72
1969
Land structure Equip.
(1000) (1000) (1000)
-
1960
1958 26000
172 8638
605 20915
408 5858
2213
2393 37735
3692 19502
781 30163
69.58 4609
1062 34833
844 13806
213 165480
45 1072
3335 4036
-
12130
85000
116255
138127
29288
106856
158783
174913
18511
110542
55283
71233
3283
97681
Co<
slino System Cost Energy Cost
•rotalCap- unit Date of Land StructureEquip. Total Cap-% of MPerating^ooiing
italcost Cost Const. , $ $ ital Cost plant ^ Main. System
Rcquiro-
$ (1000) g/fc,., (1000) (1000) (1000) 5(1000) Cost $(1000) Bents
355,
14,
112
125
159
35
59
252
146
181
205
23
146
63
85
165
4
105
003
090
,958
,065
,648
,554
,175
,381
,984
,977
,857
,190
,437
, 513
,883
,693
,400
,052
(1)
125,000
.1Q7 ly69-7L 111
88.06 1956-59
134.8 1969-72 1544
110.29 1970-71 109
142 1971-74
118.5 1924-64 (3)
68.5 1964-67 (3)
170.0 1971-74
210 1972-74
105 196S-68
(2)
102.9 11524
153.12 1952-55
118
117 1963-68 20
143
344
155
143 1971-72 2496
109 1969
13,021 205 11,337 3.76 - -
3i6 825 1,141 B.I 11
6,^50 4,045 11,939 10.6 13
I,o82 1,349 2,540 - -
8,000 .. 4Mrf
1,K20 261 2,081 7.04
1, 62 2,146 3,908 4.5 10
37,858
19,600 14Mrf
15,750 36
(2) (2) (2)
25, .17 16,243 53,284
.;58 585 844 3.67 48.5
23,~)00 16.0 28.5
;68 568 856 1.35
4818 8.03 4.632
6975 9471 9
8036 - - 12
IncreasedLoss of
Heat capacity
Rate TyP6 °* Cooling
jlCU/Kwn *^W System
Natural Draft W«t
Tower
Once Through Flow
89 6-8 Cooling Pond
Helper Spray Canal1
Helper Spray Canal
31 4 Closed Spray Canal
Cooling Ponds
(three)
Once Through Flow
vfhen Installed
in Station
Original Design
Original Design
1 unit
Oricinal Design
2 units
Backfitted to
neet stream stds
3 units
Bckfttd to meet
Str Stds launits )
Orig.Des.llunit}
Orininal Design
Or iainal Design
(to pe added tO
cooling canal)
Backfitted to
Cooling Canal close system
Mechanical Draft '
10o 9 "et Tower
Natural Draft Wet
Cooling Lake
Once Through Flow
Spray Canal
267 41.4 (in process)
Once Through Flow
(seawater)
Once Through Flow
Or.ce Through Flow
Once Through Flow
Spray Canal
Nat.Prf "-."flt Twr
Bckfttd to close
cooling system
Original Design
Oriyinal Design
Original Design
Bckfttd to close
cooling system
Original Design
Original Design
Original Design
Original Design
Change from once
throdtjh during
constr.
Bckfttd on 2 uniti
156 42 Hlpr&Closed Modes0^'008 • * unit
(1) for Unit 3 only
(2) Only fraction of this cost allocatable
to station 3713, breakdown not given in date.
(3) Not given included in plant cost
-------
company. In a cooling pond the water rights belong to the
utility involved.
The last column designates whether the current cooling
system is the original design or has been backfitted. Of
the twenty stations visited, six are backfitted. Two of the
stations visited were backfitting for the second time to
meet increasingly stringent stream water quality standards.
Several of the plants backfitting with closed systems are
doing so as a result of legal action. In these cases the
trend has been to go to a closed system. The necessity of
getting additional generating capacity "on line" has been an
important factor in determining the course of action taken.
It was evident from the visits that the spray canal with the
powered spray modules is used primarily as a helper system
to cool the circulating water to meet stream standards.
This technology is relatively new, and some ancilliary
problems remain to be solved before this technology becomes
sufficiently reliable for extensive utility use.
Cost Studies for Specific Plants
Preliminary studies ***, 46S have been completed to indicate
the feasibility, cost, and time required for construction of
facilities to bring Pacific Gas and Electric Company's Moss
Landing and Pittsburgh power plants into compliance with
EPA*S proposed effluent guidelines and standards for steam
electric power plants (Federal Register March 4, 1974). All
units at both plants would have been required to retrofit
closed-cycle cooling systems by the proposed effluent
limitations on heat.
Generating units at Moss Landing are as follows:
Unit No. Capacity. Mw Utilization Initial Service Year
1 114 Peaking 1950
2 113 Peaking 1950
3 115 Peaking 1952
4 122 Cyclic 1952
5 122 Cyclic 1952
6 750 Baseload 1968
7 750 Baseload 1968
All units are fossil-fueled.
Conclusions of the study are as follows. It was shown that
wet mechanical draft saltwater cooling towers could be
retrofit to the Moss Landing Power Plant without the
573
-------
production of prohibitively high turbine backpressures for
most of the anticipated operation. It should be noted that
installation of these cooling towers would require the
acquisition of additional property. The plant site property
currently owned by PG6E is not adequate for the placement of
the cooling towers required. The area selected for the
installation of cooling towers is not well suited to the
existing plant because of the length of the circulating
water lines. This area is well suited, however, in terms of
its effect on plant operation because the cooling tower
plume would be carried away from the plant for most periods
of operation. The increase in any operating cost of the
units at the Moss Landing Power Plant would be consistent
with the increase normally associated with the. addition of
cooling towers. The capital costs of these cooling towers
and the associated equipment are higher than normal, which
is usually the case with retrofit designs. Special
considerations or design problems particular to this plant
(i.e., the long circulating water lines required) induce
even higher capital costs. The overall capital costs are
estimated to be $28,186,000 at current prices (approximately
$14/kilowatt). Allowance for engineering, taxes, and
interest during construction, etc., and providing for
reasonable contingency, increase these costs to $42,520,000
or $21/kilowatt. One of the largest cost items is the
escalation, for serious inflation can be anticipated during
the intervening years. The final escalated costs are
$63,260,000 or $31/kilowatt.
Generating units at Pittsburg are as follows:
Initial Service
Unit No. Capacity, Mw Utilization Year
1 160 Cyclic 1956
2 170 Cyclic 1956
3 160 Cyclic 1956
4 170 Cyclic 1956
5 330 Baseload 1961
6 330 Baseload 1961
7 740 Baseload 1966
All units are fossil-fueled.
Conclusions of the study are as follows. It has been shown
that wet mechanical draft cooling towers could be fitted to
the Pittsburg Power Plant without the acquisition of
additional land, and without the production of prohibitively
high turbine backpressures for most of the anticipated
574
-------
operation. It should be noted, however, that the available
land is net well suited for towers because of its location
with respect to the plant and that no other suitable lands
are available because of other facilities and nearby
residential patterns. The annual operating costs of the
units at the Pittsburg Power Plant would be increased by a
normal amount due to the addition of cooling towers, but the
capital costs of these cooling towers and the associated
equipment are abnormally high. Higher-than-normal capital
costs are always associated with retrofit designs. Special
considerations at this site, such as the length of the
circulating water lines, result in capital cost of
approximately $32 million at current prices (approximately
$24/kw). Allowance for engineering, interest during
construction, taxes, etc., and providing for a reasonable
contingency increase this cost to approximately $19 million
or $37/kw. One of the largest cost items, however, is
escalation, for serious inflation can be anticipated during
the intervening years. The final escalated cost is over $75
million or $57/kw.
A number of problems were encountered in the layout and
preliminary design of the mechanical draft cooling system
for the Pittsburg Power Plant. Basically, most of these
problems can be attributed to the lack of space at an
appropriate loaction for the layout of the cooling towers
systems. These problems include:
• Distance and routing of the circulating water lines
to the cooling towers.
• Access to the existing pumphouse.
• Placement of the towers with respect to downwind
effects on the plant and switchyard.
• Placement of the towers with respect ot the
subsurface conditions encountered in the foundation
design.
There is adequate space on the property owned by PG&E for
the cooling towers required for Units 1-6, as well as for
towers for a proposed Unit 8 and for towers for replacement
of the spray canal of Unit 7 should this replacement be
desired. All of these towers would fit in the available
area with sufficient spacing to minimize the mutual
interference caused by placing such a large number of towers
in one location. The major problem is that this space is a
considerable distance from the plant itself, especially from
Dnits 1-6. In addition, layout of the existing equipment
575
-------
and facilities in the area between the plant and the
available space for locating the towers was made without any
allowance for the later addition of closed-cycle cooling
towers. Thus, the routing of circulating water lines would
be extremely long, difficult to construct, and expensive.
When cooling towers are retrofitted to existing stations
based on once-through cooling, certain difficulties are
normally encountered. Problems associated with the
interface between the existing circulating water system and
the new equipment required for the cooling towers vary
considerably from plant to plant. In the case of the
Pittsburg Power Plant, access to the circulating water
pumphouse has proven to be extremely difficult.
Construction of offshore diking or sheet piling jetties
might resolve this problem. However, this study has assumed
that such construction would not be allowed. Therefore,
construction of a new forebay behind the existing pumphouse
would be required. This construction would prove to be
extremely slow, inefficient, and costly because of the
difficulty in avoiding damage to the surrounding structures.
The only available space for the installation of cooling
towers on PG6E property at the Pittsburg Power Plant is near
the existing spray canal to the west of the plant. This
location is not good with respect to the power plant
operations because prevailing winds would carry the tower
plume back over the plant and switchyard during much of the
year. Although damage due to drift is expected to be
considerably less than past experience because of the
improved performance of cooling tower drift eliminators, the
highly humid plume in the transmission corridor and
switchyard area is still likely to cause some operating
difficulties. The space available for the cooling towers is
in an area of very poor soil condition and high groundwater.
The porous nature of the peat soil causes the water table to
be frequently at or near the surface. Special designs to
prevent flotation and special designs for foundation in this
type of peat material would be required, leading to extra
costs. **5
Sargent and Lundy **7 presented a summary of previous
estimates they had made of the cost of backfitting some of
their clients* units. The summary, shown in Table B-VIII-2,
also describes the cost influencing items for each of the 13
plants covered.
A preliminary study 23Z has been completed to assess the
feasibility of backfitting closed-cycle cooling system with
natural draft cooling towers at two TVA powerplants. Plant
No. U704 has four units with a total capacity of 823 Mw, has
576
-------
Table B-VIII-2
Batiaatrt Coat* of Typical Installation* of Backflttlaf
ClOMd Cycla Coolln* Sy»t«M to One* Ttaw Cycle Plant* 447
(Eatiaatcd Coat* Arc Adjusted to Mid-1973 LercU)
STATJCW
-1
2
3
U
5
6
7
8
9
10
11
12
13
•0. OF
OBITS
b
2
b
b
b
2
b
1
2
b
b
3
2
TOTAL
m
i.tti
1,160
905
90b
630
b*
Itf
107
2.260
90S
901.
6b9
52b
TTfl
FURL
Co»l
CoU
Coal
Coal
Oil
Coal
Coal
Coal
•ttelaar
Coal
Coal
Coal
Coal
BO. A
TTfl
Towns
3-H.D.
3-H.D.
>«.D.
b-H.D.
Bybrld
2-M.D.
1-H.D.
i-H.r.
^Hybrid
1-*.D.
2-I.B.
1-B.D.
1-V.D. •
TOTAL tO.
COLS Oil
Dmxsion
27
27
JO
10
21)'B z b7$'Dla.
12
S
b
250-1 z 390'nu.
SOO'I z SOO'BU.
bSO'B z bSO'Bla.
370'B z bbO'Dla.
350'H z 350'W«.
sravm
FUN
900,000
916,000
720,000
JUS, ooo
(00,000
390,000
95,600
110,000
1.U53.000
720,000
914,000
570,000
376,000
.% Of
FUN TO
TOV^KS
66%
66%
loan
vx>H
66%
66%
66%
100%
100%
100%
100%
66%
66%
BACOTT
COST
*Aw
120.50
lib. 37
118.21
t3b.68
130.58
$17.78
131.90
137.62
$36.65
|2b.98
Ib9.f*\
118.09
•27.95
KSCRIPTIOII or COST ufuiPtuu rrots
CRIB BOOSE ALTEBATIOIS AID EADTB WORK FOB CUCTUTPS UA7E> tO
BTPASS PIPUC.
COST OF CIRCULATDC WATER PIPIK m COOLIBC VMOG OD EAE! TEX
Dl IXTAKE CBAJfflEL.
COPFERDAK, EARTH FILL, AID RIP UP SLOPES RNPIRED Di COOLm tM-X
AREA.
tmXWK COFFERDAM WORK AKD EAJTH FTU FOR CODING TWER AHEA
REQUIRED.
TOmXHC BELOW SAITTART D13TSICT SMX, CITT SEVER, AID iAUJtOAD
TUCKS.
COST OF CDtOIUTDC WATER PIPDC FOR COOLIBC TOWERS.
COST OP COOLDB TOWER IKSTALLATIOB FOR LOW GEIEUTIBC OOTPVT.
COST Or COOLDC TCUER DIS7ALUTIOH FOR C5LT 1 OTTT Or CEffiSATSIC
OOTFOT.
NODinCATIOH OF CIRCOLATIRG WATER ATO SEH7IC1 WATER STSTDS AROTOB
TEE PLAIT SITE.
COFFERDAM, EABTH FILL, ABD RIP KAP SLOPES BEQUBD IB COOLDB TOVER
AREA.
EXTUSHt COFFERDAM WORK AID EABTH PILL FOB COOLIBC TOWER ABU
REQUIRED.
TDKBELIBC BELOW CITT STREET IBTO BOCK STRATA ABD CORLKCTE LDB TBS
ROCK SURFACE.
COST OF CIRCULATDIC WATER TOBBELS ABD TEBTICAL SBAFTS.
U1
-------
a capacity factor between 0.2 and 0.6, and will have 12
years useful service life after 1983. Plant No. 0112 has
eight units with a total capacity of 1978 Mw. Units 1-6
have a capacity factor between 0.2 and 0.6, and a useful
life of 9 years after 1983. Units 7 and 8 have a capacity
factor near 0.6 and a useful life of 29 years after 1977.
The pertinent results of the study are as follows:
1) the conversions are feasible
2) cost for plant No. 4704 is $16,5 million;
cost for units 1-6 of plant No. 0112 is $18.6 million;
and
cost for units 7, 8 of plant No. 0112 is $15.0 million
3) scheduled plant outage for any of the three is 2-3
months
In each case the cost of the towet including foundations is
about 40% of the total cost, civil work (dikes, pump
station, earthwork, etc.) about 40-50%, electrical work less
than 3%, and mechanical work (pump, piping, etc.) about 10-
15%.
Other Cost Estimates
Reference 385 collected estimates from other sources of the
incremental costs of various alternative cooling systems
compared to once-through fresh water systems for new plants.
These cost estimates are summarized in Tables B-VIII-3
(fossil-fueled plants) and B-VIII-4 (nuclear plants). Also
given in Reference 385 are estimates of the incremental
costs of retrofit cooling systems for specific plants (See
Table B-VIII-5) and new cooling systems for specific plants
(See Table B-VIII-6).
Reference 385 estimated the effect of salinity on cooling
tower costs. See Figure B-VTII-la.
Reference 389 collected data on the capital costs of cooling
ponds. See Table B-VIII-7. The cost of the cooling system
as a percentage of total plant cost varied from 1.35% for a
once-through system to 9% for a spray canal system. The
costs depend a great deal on local conditions. In addition
to varying land costs, foundation problems vary as well as
length of intake and discharge channels, etc. Of the data
collected, costs for cooling systems averaged less than 10%
of the plant cost.
578
-------
Table B-VIIX-3
COMPARATIVE COST ESTIMATES OF NEW NUCLEAR-FUELED
PLANT COOLING SYSTEMS
385
(Cost Estimates in Excess of Once-Through Fresh Water Systems)
Cooling .Pond
Spray Canal
Wet Towers
Mechanical Draft
Natural Draft
Dry Towers
Mechanical Draft
Natural Draft
Once-Through
Salt
Unit Capacity
**WOODSON
$ mills
kW kWh
3.4 0.07
4.7 0.10
10.6 0.22
31.0 0,96
61.4 1.57
800 MWe
**ORNL
$ mills
. kW kWh
5.6
0.02
11.9(a>
14.3
0.27
1.37
59.5*«>
71.4
1.57
Not Available
^ROSSIE
$ mills
kW kWh
25.8
"30.2
800 MWfi
JAMISON &
«.*ADKINS
$ mills
kW kWh
3.4-4.5
5.6-6.7
6.7-9.0
25.8 '
28.0-
30.2
600 MW
and larger
OLESON &
BOYLE
$ mills
kW kWh
0.11
0.22 (a)
0.90(a3
1132 MWfi
^BATTELLE
$ mills
kW kWh
5.9 0.17
7.0 0.37
12.8 0.43
24.1 0.95
37.3 1.10
6.6 0.14
1000 MWC
FRANKLIN
^INSTITUTE
$ mills $
kW kWh kW
6.3
6.9
9.5
25.2
1000 MWe
**FWQA
mills
kWh
0.02-0.07
0.10-0.17
0.17-0.26
000 MWe
,AAEC
$ mills
kW kWh
33.4- 0.87-
34.3 1.25
0.92-
42.2 1.32
860-928 MWe
(Jl
Expressed in 1973 dollars. The dollar base year
for each study was inflated or deflated, depending
on the base year of the study, using a 67. per year
inflation rate.
Includes capability replacement costs.
^a'Costs for mechanical and natural draft
-------
Table B-VIII- 4
COMPARATIVE COST ESTIMATES OF. NEW FOSSIL-FUELED PLANT
COOuING SYSTEMS* 385
(Cost Estimates in Excess of Once-Through Fresh Water Systems)
Cooling Pond
Spray Car.ui
Wet Towers
Mechanical Draft
Natural Draft
Dry Towers
Mechanical Draft
Natural D-aft
Unit Capacity
^WOODSON
$/KW mills /kWh
2.6 0.07
2.8 0.09
6.2 0.16
17.6 0.76
37.3 1.10
800 MWe
**ORNL
$/kW mills/kWh
3.6-
6.0
0.05
8.3
17.9
0.24
41.7- 1.13
59.5 1.42
Not Available
^OSSIE
$/kW mills/kWh
1.12x
19.0 1.12x+
0.54
22.4
eOO MWe
JAMISON &
**ADKINS
$/kW mills/kWh
2.2-
3.6
3.6-
6.0
4.5-
6.7
17.9-
19.0
20.2-
23.5
600 MW
on<4 1 a^»*kt»
FRANKLIN
^INSTITUTE
$/kW mills/kWh
_4_.4 _
3.8
5.7
20.2
1000 MW
**FWQ*
S/kW mills/kWh
1.9- 0.01-
3.0_ 0.05
3.8- 0.06-
ft.O 0.08
4.2- 0.10-
4.5 0.14
8.1- 0.17-
8.2 0.26
22.6- 0.55-
23.0 0.83
24.8- 0.51-
25.0 0.76
1000 MWe '
00
o
(a)
Expressed in 1973 dollars. The dollar base year
for each study was inflated or deflated, depend-
ing on the base year of the study, using a 67. per
year inflation rate.
Includes capability replacement costs.
Costs for mechanical and natural draft towers.
-------
Table B-vril-5
COST ESTIMATES OF RETROFITTED PLANT COOLING SYSTEMS FOR SPECIFIC
GENERATING STATIONS 385
(Cost Estimates In Excess of Once-Through Cooling System-1973 Dollar Value)
Nuclear Fossil
Plant
San Onofre
01
Zlon 1 & 2
Quad-Cities
1 & 2
Dresden
2 & 3
Slze-MW
1-450
1-450
1-650
1-450
i
1-450
2-1100
2-1100
2-1100
2-1100
2-809
2-809
2-809
2-809
2-809
2-809
Cooling System
Evaluated
Dlffuser
Mechanical Draft Tower
Saltwater-Open Cycle
Mechanical Draft Tower
Saltwater-Closed Cycle
Mechanical Draft Tower.
Freshwater-Closed Cycle
Spray Pond Cooling
Saltwater-Open Cycle
High Velocity Jet Dlschg.
Off-Shore Intake
Round Mechanical Draft
Tower-Closed Cycle
Natural Draft Cooling
Tower-Closed Cycle
Dry Mechanical Draft
Cooling Tower-Closed
Cycle
Dlffuser
Spray Canal Cooling
Tower-Closed Cycle
Mechanical Draft Tower
Closed Cycle
Natural Draft Cooling
Tc..^r-Closed Cycle
Cooling Pond
Closed Cycle
Cooling Pond and Spray
System-Closed Cycle
Capacity
Factor
80*
80T.
sen
607.
em.
72%
111
721
721
72%
721
721
721
727.
72%
Cost
S/kW Imllls/ktfh5
15l
26l
391
100 l
44l
82
543
643
\
2083
6.3*
28*
26*
36*
30*
2i4
0.48
1.14
1.17
2.22
V.34
0.20
1.53
1.73
5.75
0.16
0.78
0.72
0.97
0.78
0.64
Plant
Jollet (Old)
Units 566
Jollet (New)
Units 7 & 8
Slze-MW
461
461
461
461
1,234
1,234
1,234
Cooling System
Evaluated
Natural Draft Cool-
Ing Towers-Closed
Cycle
Mechanical Draft
Towers-Closed Cycle
Cooling Pond
Closed Cycle
Spray Canal
Closed Cycle
Natural Draft Cool-
Ing Towers-Closed
Cycle
Mechanical Draft
Towers-Closed Cycle
Spray Canal
Closed Cycle
Capacity
Factor
351
357.
35%
351
55%
55%
55%
Cost
$/kW
304
214
7 16
604
23*
IS4
236
mllls/kWh'
l.SJ
1.36
4.67
3.82
0.81
0.64
0.81
NOTES :
1. Base Is considered as once-through single point ocean.
2. Base Is considered as once- through on shore Intake-discharge lake.
3. Base Is considered as once-through with high velocity Jet discharge
off shore Intake lake.
4. Base Is considered as once- through river.
5. Includes Investment, capability loss charges, and operating and
maintenance costs.
Ul
00
-------
Table B-VIII- 6
COST ESTIMATES OF NEW PLANT COOLING SYSTEMS FOR
SPECIFIC GENERATING STATIONS
385
(Cost Estimates in Excess of Once-Through Cooling Systems»-1973 Dollar Value)
?!ent
San Onofre,
2&3
Perry
1&2
Davis-Besse
Notes: 1 - Base Is (
Slze-MW
2-1140
2-1140
2-1140
2-1200
2-1200
2-1200
1-872
1-872
:onsldered as ocean-(deei
Coollnq System Evaluated
Mechanical Draft Cooling Towers - Saltwater
Closed Cycle
Mechanical Draft Cooling Towers - Salt Water
Open Cycle
Multi-Point Dlffusor
Natural Draft Cooling Towers - Fresh Water
Closed Cycle
Mechanical Draft Cooling Towers - Fresh Water
Closed Cycle
Spray Canal Cooling - Fresh Water
Closed Cycle
Natural Draft Cooling Towers - Fresh Water
Closed Cycle
Mechanical Draft Cooling Towers - Fresh Water
Open Cycle
Spray Canal Cooling - Fresh Water
Open Cycle
) Intake - deep discharge)
Capacity
Factor
80%
80%
80%
80%
80%
80%
80%
80%
80%
•
, Cost ...
$ mills
kW )c\Vh 3
231 0.75
i
32 1.01
6 0.17
11..32 0.2S
IS. I2 0.33
12. 72 0.58
25. 22 0.62
32. 82 0.81
1S.62 0.38
2 - Sase Is considered as once-through lake
3 - Includes Investment, capability losses, and operating •
and maintenance costs
01
00
to
-------
O HEIGHT
A DIAMETER
O COST
20
SALT CONCENTRATION, (ports/million)x 10
-3
F:;.gure B-VIII-la Salinity Effects pn Cooling Tower
Size and Costs
583
-------
Table B-VIII-7
Capital Costs of Selected Cooling Ponds (c) 389
PLANT
H. B. ROBINSON
ROXBORO (a>
BRAUNIG
KINCAID
MT. CREEK
NORTH LAKE
BALDWIN (a>
VALLEY
YT. STORM (a)
1970
CAPACITY
(MW)
906
1067
885
1319
99O
7O9
584 •
725
1140
SURFACE. AREA
( ACRES )(b)
2145
3750
1250
2400
2710
800
1000
1120
CAPITAL COST
OF COOLING POND ($)
4,800,000
4,831,000
4,717,000
3,819,000
4,333,000
3 , 555 , 000
3,000,000
918,209
6,523,000
UNIT COST
$/M»
5,298
4,528
5,330
2,895
4,377
5,014
5,137
.1,266
5,722
$/ACRE
2238
1288
.3774
1591
1599
4444
918
5824
COMMENTS
1971 Capacity
Ul
CO
u Future expansion at site contemplated.
b One acre equals 4047m2.
c Covers land and land rights costs only.
-------
Based on the FPC Form 67 data for the year 1970 ««,. the
capital costs reported for once-through (fresh) cooling is
$4.03 per kw, once-through (saline) is $4.63 per kw, cooling
ponds is $5.43 per kw, and cooling towers is $6/25 per kw.
The incremental cost shown of cooling towers ' over
once-through systems is about $1.6 - $2.2 per kw.
Sargent and Lundy Engineers444 estimated costs of mechanical
and natural draft cooling towers compared to once-through
cooling for new plants as shown in Table' B-VIII-8.
Incremental capital costs of mechanical draft cooling towers
over the cost of once-through system capital costs are
$3.09/kw for a 1150 Mw nuclear unit and $4.46/kw for a 550
Mw fossil-fired unit based on 1974 dollars.
Reference 368 presents nomographs which permit the
estimation of cooling system.performance and costs. » .
In general, it seems possible to distinguish three groups of
economic factors that could affect the relative costs of
open and closed cycle cooling systems. The first group
consists of the cost elements of the plant cooling water
system itself. These include the intake structure, screens,
pumps, piping, condenser, discharge facilities, and water
and wastewater treatment 'plant.
The second group of-cost factors concerns itself with the
limitations on the location of the plant imposed by the
once-through cooling system. A once-through cooling system
plant must be located at or near the level of the water
supply. This frequently results in high costs for
dewatering the site, and high foundation costs for piling or"
concrete mats to protect the plant against settlement,
flotation during periods of high groundwater, or flooding.
Even if a site has already been committed, there may be
alternate locations, on the site or alternate foundation
arrangements and floor elevations which are less costly than
those dictated by the limitations imposed by the orice-
trhough circulating water system.
The third group of cost factors apply only if the site has
not been selected, and generally only to coal-fueled plants.
These relate to the fact that it is generally more
economical to transmit electricity than to ship coal and the
location of the source of the fuel has a greater impact on
economics of generating electricity than availability of
sufficient quantity of water than once-trhough cooling.
There are also cost savings which result from generally
better foundation conditions and lower requirements for
architectural and other aesthetic aspects. The magnitude of
585
-------
Table B-VIII-3
Thermal Control Costs for New Plants
448
Cooling System
Capital Cost, 1974 (exclusive of escalation,
allowance for funds used during construction,
or allowance for indirect costs
550 Mw
Fossil-Fired
1150 Mw
Nuclear
Once-through
Mechanical-draft
cooling tower
Natural-draft
cooling tower
$2,646,000
5,096,000
8,047,000
$10,052,000
13,599,000
17,458,000
Incremental
(mechanical draft
less once-through)
$2,450,000
($4.46/kw)
$ 3,547,000
($3.09/kw)
586
-------
•this factor may be approximated by the cost of shipping
coal, which is of the order of $10 per ton for a haul of 250
miles. This is equivalent to 0.5* per Ib. of coal or per
kwh of electricity generated.
»
Costs Analyses
The initial part of this work consisted of preparing cost
estimates for placing the various types of evaporative
cooling in a number of hypothetical plants in various
representative locations in the United States.
Four typical plants were chosen:
100 Mw fossil-fueled unit
300 Mw fossil-fueled unit
600 Mw fossil-fueled unit
1,000 Mw nuclear-fueled unit
Two condenser temperature rises were chosen, 6.7°C (12°F)
and 11.1°C (20°F). These represent the lower and upper
design averages in plants currently operating in the once-
through mode, or plants that would be considered for
backfitting with closed cooling systems. A turbine exhaust
pressure of 8.45 kN/sq m (2.5 in. of Hg) abs. was chosen as
being an average of the units in this group. This pressure,
plus the climatic conditions, permitted design of a closed
cooling system.
The four locations chosen for this analysis were Seattle,
Washington (cool), Phoenix, Arizona (hot and dry), Richmond,
Virginia (average), and Pensacola, Florida (hot and humid).
The wet bulb temperatures used were those listed as being
equaled or exceeded only 5% of the time, on the average
during the four months of June through September. ** This
amounts to 110 hours for this period.
The necessary information was submitted to three cooling
tower manufacturers and two powered spray module
manufacturers for cost estimates. These conditions assumed
100% heat removal in the tower and no change to the
generating unit, i.e., cooling water temperature was the
same. Of the total of 32 separate plants resulting from the
matrix of conditions, 20 were capable of being backfitted
with mechanical draft cooling towers, and 16 with natural
draft cooling towers. Use of natural draft towers in
Phoenix were not practical due to low humidity.
587
-------
One powered spray module manufacturer proposed systems for
28 of the 32 cases, while the other proposed for 16 of the
32 cases. The costs of the equipment only is shown in Table
B-VIII-9. The mechanical draft tower (wood construction) ,
and the natural draft tower (concrete construction), are the
two types of cooling towers most widely used in this
industry. These are considered available technology.
Powered spray modules are being used for backfitting to
reduce circulating water temperatures to meet stream
standards. As such, they are available technology. At one
major plant the powered spray modules are being installed in
a closed system.
Table B-VIII-9 illustrates a number of points. The first is
that under the conditions specified, natural draft cooling
towers are considerably more expensive to buy than the other
types. .This is particularly true for smaller plant sizes in
which the natural draft tower would not be expected to be
competitive. However, operating costs are less, which makes
their overall cost lower than the tower cost would seem to
indicate. For mechanical draft towers, it appears that
concrete construction is more expensive than wood by a
factor of l.U. The cost of all the systems, exclusive of
the natural draft tower is about the same. Thus if
mechanical tcwers are used as a technology to investigate
the costs of their application, use of the other systems
would result in similar costs. This leaves a number of
options open to utilities for about the same cost. Each
plant would have to be evaluated on an individual basis to
determine the most economical system for that station.
Cooling pcnds were not covered in detail since their use is
not dependent upon equipment supplied by a manufacturer.
Their cost is almost entirely composed of land cost and the
cost of the retrofit. This option is available for use and
considered as a lower cost available technology for those
plants where suitable land is available.
For the overall costs' analysis, the additional cost (in
mills/kwh) to install and operate a mechanical draft cooling
tower as a function of the percent of heat removed from the
circulating water is generally representative of the overall
cost of the application of effluent heat reduction
technology, due to general similarity of costs among
available technologies. Due to the broad spectrum of unit
sizes and conditions throughout the United States, the
number of cases studied had to be strictly limited to
provide a manageable number of analyses. The first
restrictions were made on the basis of the categorization of
the industry. Fossil-fueled plants only were considered, as
these make up the bulk of existing facilities at present.
588
-------
TABLE B-VIII- 9
COST OF COOLING SYSTEM EQUIPMENT
Unit
Size
(MW)
100
.
300
600
1000
Unit
Location
Seattle
Phoenix
Richmond
Pensacola
Seattle
Phoenix
Richmond
Pensacola
Seattle
Phoenix
Richmond
Pensacola
Seattle
Phoenix
Richmond
Pensacola
Circulating
Water Rise (F)
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
Mech. Draft
Wood Constr .
.400
.459
.612
.567
.728
1.050
1.195
1.768
1.640
2.025
1.815
2.154
3.102
2.648
3.497
4.275
4.840
7.281
6.765
8.337
Cost For Systam (.$ x 10 ~
. Mech. Draft
Concrete Contr.
Mfr. A (Mfr. B
.550 •
.648 ' .650
.857 : .825
.798 ' 0.800
1.019 i 0.955
1.442
1.665 • 1.490
2.478 • 2.232
2.300 ' 2.010
2.835 • 2.530
2.491
'3.014 . 2.640
4.332 > 3.825
3.705 ; 3.525
4.897 ; 4.470
5.867
6.780 ' 6.000
10.191 9.050
9.465 ! 8.250
11.677 9.900
Natural
Draft
2.5
2.8
*
4.1
4.3
3.9
4.7
8.0
8.3
5.5
6.8
14.6
15.1
10.1
14.7
30.8
31.9
&•)
Powered Spray
Module
Mfr. A
.380
.532
.684
1.596
.684
1.293
.836
1.064
1.293
1.824
4.180
1.748
3.345
2.05
1.748
2.200
3.118
7.22
2.965
5.700
3.57
4.180
4.940
7-. 3 80
16.040
6.920
12.700
8.51
Mfr. B
.364
.401
.765
.656
.875
1.130
1.933
1.695
1.531
1.763
3.390
2.984
3.255
3.933
8.070
6.984
589
-------
The next break came on the basis of unit use. A statistical
analysis of the plants reporting to FPC on Form 67 resulted
in the statistics shown in Table B-VTII-10. Based on these
figures, the figures shown in Table B-VIII-11 were used in
the analysis. The only adjustment, other than rounding off,
were made in the heat rate. These heat rates are based on
total fuel burned and total kwh's generated during the year.
Since by definition a base unit is operating at or near
capacity most of the year, this heat rate is fairly
representative of the actual heat rate while operating at
near full capacity. The same is not true of the other two
cases. The cyclic unit, operates for longer periods of time
at lower loads, where efficiency is lower. This unit may
act as spinning or standby reserve where the boiler is up to
pressure, but little power is being generated. Thus the
heat rate is higher than that actually existing when the
plant is operating at near full capacity, the heat rate
desired for this analysis. The cyclic unit heat rate was
reduced to 12,000 kJ/kwh (11,500 Btu/kwh), considered to be
more truly representative of the actual unit heat rate. The
same factors influence the heat rate of the peaking unit,
even to a greater degree. The heat rate of peaking units
was reduced to 13,200 kJ/kwh (12,500 Btu/kwh) as being a
more realistic figure. Mote that when a unit is being held
in a warm standby condition it is normally not connected to
the circulating water system. Thus, most of the increased
heat is discharged to the stack and not to the receiving
water. Since the purpose of the analysis was to determine
the range of costs involved in installing wet cooling towers
on existing units, three wet bulb temperatures were chosen
as the worst, near average and best wet bulb temperatures,
for cooling tower design purposes, in the United States.
The worst, or highest wet bulb temperature was 28°C (83°F).
This was at the IX level, exceeded only one percent of the
time during June through September. An average chosen was
2H°C (75°F), and the lowest summer wet bulb at the 1% level
was 1U0C (57°F).
The remaining factor was unit age, and this was taken into
consideration as unit remaining life, assuming a unit life
of 36 years. The median ages of the three age categories,
6, Id, and 30 years, were used. This gives a total of 27
cases, 3 types of units multiplied by 3 wet bulb tempera-
tures multiplied by 3 ages.
Some additional information on the unit must be specified.
The plant size chosen was 300 Mw. By using a 300 Mw unit,
some idea of the magnitude of the various costs could be
made. Since parameters and costs used varied linearly with
unit size, the costs, in terms of mills/per kwh, will be
590
-------
TABLE B-VIII- 10
HYPOTHETICAL PLANT OPERATING PARAMETERS
Type
of Unit
Base
Cyclic
Peaking
Hours Up
per Year
7685
4475
1155
Heat Rate
kJ/kwh
11,231
13,192
16,677
Btu/kwh
10,636
12,493
15,793
Capacity
Factor
0.77
0.44
0.09
Bus Bar Cost
miUsVkwh
6.24
8.35
12.50
TABLE B-VIII-11
REVISED PLANT OPERATION PARAMETERS
Type
of Unit
Base
Cyclic
Peaking
Hours Up
per Year
7690
4500
1200
Heat Rate
kJ/kwh
11,088
12,144
13,200
Btn/kwh
10,500
11,500
12,500
Capacity
Factor
0.77
0 . 4<
0.09
Bus Bar Cost
mills /kwh
6.34
8.35
12.50
591
-------
applicable to any unit for which the basic assumptions are
valid and operating parameters fall within the range
indicated. It was further assumed that operation of the
unit at a turbine exhaust pressure of 8.45 kN/sq m (2,5 in.
of Hg abs) would incur no operating penalty other than the
power requirements of the tower and pumps. Any increase in
pressure above this would result in both an additional
capacity penalty and a fuel penalty.
A circulating water temperature rise of 16.7°C (30°F) was
chosen as being the highest to be found in the units being
considered for backfitting. Due to the restrictions on
approach and cold water temperature to the condenser, this
is the most restrictive set of temperature criteria for
tower design. The other extreme of circulating water rise
is about 6.7°C (12°F). For the same size plant, the cooling
water flow would be increased by a factor of 2.5. This has
a significant effect on tower cost, but the temperature
criteria are much less restrictive. This permits, as will
be explained later, modification of the cooling system to
significantly reduce the cost for the case with a 6.7°C
(12°F) temperature rise.
Two additional parameters were chosen, the first was a
terminal temperature difference of 5.5°C (10°F) in the
condenser. The second was to establish 6.7°C (12°F) as the
minimum approach to be used in tower design. This value was
determined through conferences with cooling tower
manufacturers.
The above plant characteristics are summarized in table B-
VII-12.
A number of additional assumptions related to the economics
of the utility industry were necessary to complete the
analysis. Since the pumps required to circulate water
through the cooling tower are not included in the cost of
the tower, these were priced using a total dynamic head of
24 meters (80») , of this 24 meters (80»), 18 meters (60«)
was required in the tower, and the remaining 6 meters (20')
was for pipe losses and additional lift required. Since
most once-through condensers make use of the siphon effect
to lower pumping requirements, the original pumps are low
head, and would not be suitable for cooling tower service.
There are a number of ways in which the cooling tower could
be connected, but all include new pumps, either to handle
the entire system or to be placed in series with current
pumps. The cost of the pumps was estimated at $100/hp, and
an overall pump-motor efficiency of 80% was assumed. The
592
-------
TABLE B-VIII- 12
TYPICAL PLANT CHARACTERISTICS
Unit Size - 300 Mw
Unit Types - Base, Cyclic, and Peaking
Wet Bulb Temperatures - 83°F, 75°F, 57°F
Median Remaining Unit Life - 6, 18, and 30 years
Circulating Water Rise - 30°F (Upper Limit)
Condenser TTD - 10°F
Cooling Tower Approach - 12°F minimum
593
-------
cost of connecting the cooling tower into the existing
circulating water system is site dependent and is therefore
extremely variable. Factors that influence the cost of the
tower installation include the relative locations of tower
and plant, the type of terrain and soil conditions, and the
site, type and locations of connections that must be broken
into. Indirect costs for engineering, legal, and
contingencies must also be included.
Table B-VIII-1 shows the cost of installing the cooling
systems at the plants visited during the study. The average
value for retrofitted closed cooling systems was
approximately $17/kw. For a 300 Mw unit, this amounts to
approximately $5 million for the complete installation
including tower, pumps, installation and indirect costs.
The cost of the tower and pumps alone for this installation
would be approximately $1.25 million. Therefore, the tptal
installed cost is approximately 400% of the cost of the
major equipment involved. The basis for this estimate of
the costs of tower and pumps was a base-load unit installed
at a location where the design wet bulb temperature was
75°F. The cost will vary for other wet bulb temperatures
with a range of about $13/kw to $25/kw.
For the purposes of the economic analysis a markup of 300
percent above the the base cost of the major equipment items
was allowed to cover the installation costs and indirect
costs mentioned above. This allowance is considered to be
conservative for most cases.
To determine the tower costs, the cost information on
mechanical draft towers from Table E-VIII-9 was used to
develop a linear relationship between the tower parameters
(approach, range, flow, and wet bulb) and cost. The vari-
ation in cost was less than 5% at the 28°C (75°F) wet bulb
temperatures, and averaged less than 15X for the 1U°C (57°F)
wet bulb temperature. Land cost was not included in the
tower capital cost due to wide variation throughout the
country.
Fan power requirements were also determined in a similar
manner, with less than 10% variation. The operating cost of
the towers was assumed to be primarily the cost of the
electricity to run the fans and pumps, and was charged at
the average rate for the particular type of unit, except in
the case of the peaking unit. In this case the average
power cost was 2.5 mills/kwh higher than the operating cost
of replacement gas turbines, assumed to be 10 mills/kwh.
Thus in this case, it was assumed that the power required to
operate the tower cost 10 mills/kwh. Ten percent of the
594
-------
operating cost of the fans and pumps was added to cover
maintenance and parts for this equipment.
Since there were three remaining life spans considered, and
since the tower had essentially no salvage value, the cost
of the tower had to be absorbed during the remaining plant
life. To account for this, three fixed charge rates were
used, one for each of the three remaining life spans as
follows: 6 years - 30X, 18 years - 19X, and 30 years - 15X.
These are rates for investor-owned utilities; public utility
rates would be lower.
It was assumed that the energy required by the cooling tower
system was replaced with energy produced by a gas turbine.
In addition, any capability loss due to operation at higher
turbine exhaust pressures was replaced with gas turbine
generating capacity. It was assumed that the installed cost
of these gas turbines was $90/kw. 1970 costs are used
throughout this analysis. Since the life of these units was
independent of the unit whose power they were replacing, a
30 year life was assumed and the fixed charge rate was
accordingly 15%. If base load capacity were used in place
of turbines to replace the capability loss, the annual costs
of replacement capacity would be less.
Any increase in turbine exhaust pressure results in a higher
heat rate, and consequently a higher generation cost. The
following changes in heat rate were assumed. They were
taken from a typical curve for a turbine with initial steam
conditions in the superheat region. Values used are shown
in Table B-VIII-13.
This increase in generating cost was based on the average
generating cost for the type of unit being considered.
These factors and assumptions are summarized in Table B-
VIII-14.
Several additional assumptions were made about each type of
unit, base, cyclic, and peaking. These were mainly con-
cerned with the number of hours the gas turbine would
operate and the fuel penalty that would be assessed. Since
the peak load normally comes in the summer months and this
period is the critical one for tower operation, the
penalties normally apply during this period. For the base
units, it was assumed that they would operate under
penalties equivalent to full penalty for one half of the
average number of hours per year. Cyclic units were assumed
to operate under full penalties for 2,000 hours per year.
Since peaking units average 1,800 hours per the penalties
595
-------
Table B-VIII- 13
ASSUMED INCREASE IN HEAT RATE COMPARED TO BASE HEAT RATE AS A FUNCTION
OF THE TURBINE EXHAUST PRESSURE
Ul
vr>
Turbine Exhaust Pressure, in. Hg
2.5
3.0
3.5
4.0
4.5
5.0
5.5
Increase in Heat Rate, % of base
Base
0.4
0.8
1.4
2.0
2.8
3.6
>
-------
Table B-VIII-
COST ASSUMPTIONS
Ul
vo
Pumps required for tower
Tower cost
Fan power
Pump power
Fan and pump operating cost
-Fixed charge rates
6 yr remaining life
18 yr remaining life
30 yr remaining life
Replacement power
Replacement power fixed charge rate
Fuel penalty
$100/HP @ 80 ft of head,
80% overall efficiency
Interpolation from Table B-VIII-2
Interpolation from Table B-VIII-2
80 ft of head, 80% efficiency
Electrical energy at average for type
of unit, plus 20% for maintenance
30%
19%
15%
Combustion gas turbines @ 90$/ kw
and 10 mills/kwh
15%
Assessed at cost of generation for type
of unit considered except for peaking
units, where cost is 10 mills/ kwh
-------
would apply during the full 1,800 hours of operation. These
values are considered near the maximum, and the actual
values will vary from unit to unit. Shut down of the unit
is required during the time required to connect the cooling
tower into the existing circulating water system. The time
required to make this connection will depend on the layout
and accessibility of the existing cooling water system
compments. It is estimated that the time required to
perform this work will vary from 2 to 5 months, depending on
these conditions, with an average time of 3 months. One
month of this requirement can normally be scheduled to
coincide with the annual maintenance period when the unit is
down in any case. Therefore, additional cost will be
incurred to supply the power normally generated by the unit
for a period of two months. It is further assumed that
shutdowns to allow these modifications to be made can be
scheduled to coincide with periods of low system demand.
Therefore, replacement power can be obtained by higher
utilization of other equipment in the system rather than by
wholesale import of power from other sources.
It may not be possible to have the tie-in coincide with
scheduled maintenance outages in some cases. In some
instances several units at a site may of necessity be taken
out of service concurrently to accomplish the tie-ins.**3
Replacement power for base-land units undergoing these
modificiations will be supplied by operating cycling units
more intensively. The utilities will incur additional
operating costs because these units are typically less
efficient than the base-loaded units. A differential energy
cost of 3 mills/kwh was assumed to be representative of the
increased operating costs of these types of units. The
total costs associated with loss of the unit was obtained by
multiplying the capacity of the unit by the number of hours
affected, the units annual capacity factor and the
differential operating cost. The decreased utilization of
cycling and peaking units will generally allow them to be
modified without incurring downtime costs as high as the
base-load units. However for the purposes of consistancy of
the analysis, similar penalties were assessed against these
units as well.
In order to extend this cost to the remaining units of power
production, the total cost was considered to be money
borrowed at an annual interest rate of 8* compounded. This
loan was then assumed to be repaid over the remaining life
of the unit and the annual costs obtained were spread over
the average annual generation.
598
-------
A sample calculation for a peaking tin it with a 2U°C (75°F)
wet bulb design temperature, is shown in Table B-VIII-15.
The procedure was to assume 8.45 kN/sq m (2.5 in. of Hg abs)
turbine exhaust pressure with its corresponding 99?F hot
water temperature. With a minimum approach of 6.7°C (12°F),
the maximum range of the tower is 6.7°C (12°F) or the
percentage of heat removed is 12/30 or 40%. Using a minimum
range at 5.5°C (10°F) the % of water flow through a tower
for heat removals below 40% were determined. The turbine
exhaust pressure was then increased to 10.1 kN/sq m (3.0 in.
of Hg abs), the maximum heat removal determined (60%) and
conditions for removal of from H0% to 6OX removal
determined. The same procedure was used at 11.8, 13.5, and
15.2 kN/sq m (3.5, U.O, and U.5 in. of Hg abs) until 100%
removal was obtained. The analysis then proceeded in an
orderly fashion as shown in Table B-VIII-15. The other 26
cases were treated in a similar manner, and the result was a
set of nine graphs showing the range of additional genera-
tion costs involved in backfitting the hypothetical 300 Mw
unit with mechanical draft cooling towers. Since all
factors were linear with size, these costs will be
applicable to any size plant in which the basic assumptions
are still applicable. Conversations with cooling tower
manufacturers indicate that for mechanical draft towers only
a small variation in cost would be expected in the range of
units involved, including a 1 Mw plant. Pump costs may
increase in the smaller size units.
The first three graphs. Figures B-VIII-l, B-VIII-3, and B-
VIII-4, cover base-load units. Additional generation costs
ranged from a low of 0.60 mills/kwh at a 13.9°C (57°F) wet
bulb temperature and 30 year remaining life to a high of
0.65 mills/kwh at a 28.3°C wet bulb temperature and 6 year
remaining life. These are for 100X (actually about 98%)
heat removal. As indicated on the graphs, it was necessary
to increase turbine exhaust pressure in every case to
achieve 100% heat removal within the limitations placed on
the hypothetical unit. At an average generation cost of
6.24 mills/kwh, the maximum additional cost of 1.10
mills/kwh is an increase of about 17%, with the minimum for
100% heat removal of about 10%.
To evaluate the effect of circulating water rise on
additional generation cost, additional calculations for a
6.7°C (12°F) circulating water rise were made for the 30
year and 18 year remaining life categories at a 23.9°C
(75°F) wet bulb temperature. The 6.7°C (12°F) rise
approximates the lowest value found in current plants. The
results are shown in Figures B-VIII-5 and B-VIII-6. At heat
removal fractions above 50%, costs are significantly higher.
599
-------
TABLB B-VIII. 15
COOLING TOUER ECONOMIC ANALYSIS
(300 Mwe Unit, Making Service, <*at Bulb Twaperature 75°D
Turbine
Exhaust
Pressure
•P' figifa
Percent Percent Tower Tower Tower Pusq> Total
o* Ueat of Mater R«nge Approach Cost Cost plus « Year
^*gr*l_thr¥TtlT*g fo' <°r) » s 2Si mf
Annual Annual Total
_?anOper- Puap ^par-plus 10% Fan
18 Year 30 Year ing Cos*, ing iost for Main. Power
Annual Coat
generating
Capital Annual puel Aflg^
Pump Capacity Total Cost of Cost Operating Penalty 6 Year 18 Year
Power 9*n*Lty Penalty Gas Turbine 15% Cost Cost Attaining
30 Year
ining Ramaining
40 100 12 12 760,700 354,200 1,393,600 416,100 2&'.,aOO 20'j.OOO 8,500 31,700 44,200
30 90 10 14 531,200 318,800 1,062,500 316,800 201,900 159,400 6,000 28,600 38,100
20 60 10 14 354,400 212,500 7O8.6OO 212.600 134,600 106,300 4,000 19.0CO 25,300
10 30 10 14 176,600 106,300 353,800 106,100 67,200 53.100 2,000 9,500 12,6OO
60 1OO IB 12 1,067,300 354.200 1,776,900 533,100 337,600 266,500 12,000 31,7rQ 48,000
SO 1OO 15 IS 749,400 354,200 1,379,500 413,800 262,100 207,000 8,400 31,700 44,100
40 95 13 17 561,200 336,500 1,122,100 336,600 213,200 166,300 6,200 31,700 41,700
77 100 , 23 12 |1,214,90Q 354,20O [1,961,400, 588,400 372,700 294,200 13,700, 31,700 I 49,900 .
70 100 ' 21 14 965,100 354,200 1,649,100 494,700 313,300 247,400 10,BOO 31,700 46,600
60 100 18 17 760,700 354,200 1,393,600 416,100 264,800 209,000 8,500 31,700 44,200
93 100 28 12 1,351,100 354,200 2,131,600 639,500 405,000 319,700 15,100 31,700 51,500
90 100 27 13 1,203,500 354,200 1,947,100 584,100 369,900 292,100 13,600 31,700 49,800
80 100 24 16 931,000 354,200 1,606,500 482,000 305,200 241,000 10,400 31,700 46,400
70 100 22 18 772,100 354,200 1,707,900 422,400 267,500 211,200 8,600 31,/uU 44,400
1OO 1OO 30 15 1,112,700 354,200 1,833.600 550,100 348,400 275,000 12,500 31,700 48,600
90 100 27 18 874,300 354,200 1,535,600 460,700 291,800 230,300 9,800 31,700 , 45,700
.7 2.6 0 3.3 301,500 45,200 40,200 0 2-90 2.14
.5 2.4 0 2.9 259,200 38,900 34,bOO 0 2.34 1.70
.3 1.6 0 1.9 171,900 25,800 22,900 0 1.56 1.13
.2 .8 0 1.0 85,500 12,600 11,400 0 .77 .56
1.0 2.6 1.4 5.0 435,600 65,300 56,000 18,000 3.93 2.86
.7 2.6 1.4 4.7 408,600 61,300 54,500 18,000 3.22 2.39
.5 2.5 1.4 4.4 380,700 57,100 50,300 18,000 2.74 2.07
1.2 2.6 2.7 6.5 556,200 63,400 74,200 35.800 4.80 3.62
< I
.9 2.6 2.7 6.2 534,600 80,200 71,300 35,800 3.96 2.98
.7 2.6 2.7 6.0 517,500 77,600 69,000 35,600 3.50 2.67
1.3 2.6 4.7 8.6 729.000 109,400 9/.200 65,100 5.23 3.96
1.1 2.6 4.7 8.4 717,300 107,600 95,600 65,100 4.90 3.74
.9 2.6 4.7 8.2 693,900 104,100 92,500 65,100 4.29 3.33
.7 2.6 4.7 6.0 680,400 102,100 90,700 65,100 3.94 3.10
1.0 2.6 6.8 10.4 871,200 130,700 116,200 88,200 5.08 3.98
.6 2.6 6.8 10.2 t 851,400 127,700 113,500 88,200 4.54 ( 3.62
1.84
1.47
.98
.49
2.48
2.09
1.83
3.20
2.62
2.37
3.49
3.32
2.98
2.79
3.58
3.29
-------
S.S'Hq
10 F Temperature Rise
_1 L-
10 20 JO 40 50 60 70 BO 90 100
iPercnnt Heat Removed
30 YEAR REMAINING LIFE
B-VIII-J
5.5-H,
«.9°C 75°r
13.9°C 57°F
I*-5VX'^ «et Bulb
Tewv rafirea
3.0-Hg
J.5'H
-------
These higher costs are deceptive, because a simple change to
the system can reduce the cost to approximately that at the
16.7°C (30°F) rise case. This change involves increasing
the turbine exhaust pressure and then cooling only part of
the circulating water to a level below that required. The
required temperature is obtained when the two streams are
remixed. This is possible due to the larger temperature
difference between the wet bulb and cold water temperatures
than in the 16.7°C (30°F) rise case. The tower cost is
significantly lower due to the lower flow through it. For
example, by increasing the turbine exhaust pressure to 11.8
kN/sq m1 (3.5 in. of Hg) and cooling 60% of the water 11.1°C
(20°F), the additional generation cost is reduced from 1.0
mills/kwh .to 0.7 mills/kwh. Thus the higher costs for the
6.7°C (12°F) rise case can be substantially reduced, an
option not as readily available in the 16.7°C (30°F) rise
case. The cost of this scheme is variable depending upon
site conditions and plant layout.
The results for the cyclic unit are shown in Figures B-VIII-
7, B-VIII-8, and B-VIII-9. The curves have essentially the
same shape as the base-load unit curves, however, the
additional generation costs are doubled. The reason for
this is that there is much less power generated in a cycling
plant against which the cost of the cooling towers can be
charged. With a six year remaining life, the 75°F wet bulb
case results in a higher incremental cost than the 83°F wet
bulb case. For the 18 and 30 year remaining lives, the
costs for the 75 °F and 83°F cases are the same. The
capacity factor for the cycling plant is HH% versus 11% for
the base-load unit. The penalties were assumed to be the
same as in the base-load unit, as the cycling units would be
heavily used during the summer peak load. If this were not
true for specific units, the cost would be somewhat lower.
The costs for the peaking units are shown in Figures B-VTII-
10, B-VIII-11, and B-VIII-12. The costs for these units are
almost an order of magnitude greater than those for the
base-load unit. The maximum was 11.0 mills/kwh for a unit
with 6 years remaining life and the minimum was 4.5
mills/kwh for a unit with 30 years remaining life. Here
again the major difference was the number of kwh's against
which the cost of the cooling system could be charged. The
capacity factor for peaking units used was 9% as opposed to
77% for base-load units. The change in additonal generation
cost with change in capacity factor, all other factors
remaining the same, can be determined from Figure B-VIII-13.
The cost of backfitting mechanical draft towers on nuclear
units was also determined, using the same techniques em-
602
-------
"5 i-l
1* ..:
10 ZO 30 40 SO CO TO 60 90
.„.»... He«t Removed
ADDITIONAL 0ENEMT1NO COSTS FflR
100 w CYCLIC UNIT
MECHANICAL DRAFT TOWERS
G YEAB REMAINING LIFE
Figure B-VIII- 1
40 50
Pwreert Heat Removal
ADDITIONAL OKKEXATZHO COSTS FOR
JOO MM CYCLIC UNIT
MECHANICAL DRAFT TOWERS
14 YFAR PEMAININT, LIFE
Figure B-VIII- 8
Percent H<
ADDITIONAL OEDtMTim COSTS FOR
100 H» CYCLIC UNIT
MECHANICAL DRAFT TOWERS
30 YEAH REMAINING LIFE
Figure B-VIII- 9
B0~ 90" life"1"
ADDITIONAL GENERATING COSTS FOR
JOO M« PEAKING UNIT
KECHA.1ICAL DRAFT TOWERS
t YFAB PEMAININT LIFF
Figure B-VIII-li
40 "50 ~60~ "T0~ 80 " 90
Percent Hear Peaoved
AOOITIOKAL OEHEBATIBG COSTS FOR
JOO «fe prAJtINC UNIT
MCOIAMICM DRAT? TfWERS
IB YF.AP PF1A[fT:)C LIFE
Figjc* B-VIII-"
12.0
11.0
10.0 .
s
J. '••
:S ...
Temperature Ri»e
TO20!o4050toTOio 90 100
Percent Heat Hraove
ADDITICMH. CZNZKATinO COSTS FOR
JOO •%. PEAMrtT. UNIT
MECHANICAL OBAFT TOWERS
tO YEAR REMAIIflMC LIFE
Figure B-VIII-IZ
-------
CF
, COMPARISON OF CAPACITY FACTORS
0.7 0.8 0.9 1.0
0.0^
0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2
ADDITIONAL GENERATION COST AT CAPACITY FACTOR (CF2) IN QUESTION, MILLS/ kwh
FIGURE B-VIII-13 VARIATION OF ADDITIONAL GENERATING COST WITH CAPACITY FACTOR
604
-------
ployed for the 300 Mw fossil-fueled plant. Except for a few
small experimental units, most nuclear facilities fall in
the 500 to 1000 Mw size range. An 800 Mw nuclear unit was
assumed for the economic analysis. The heat rate assumed
was 11,088 kJ/kwh (10,500 Btu/kwh) , with 6,86<» kJ/kwh (6,500
Btu/kwh) being rejected through the condenser. Two circu-
lating water temperature rises were used, 16.7°C and 6.7°C
(30°F and 12°F). The remaining assumptions were essentially
the same as for the 300 Mw fossil-fueled unit. Since there
are no large nuclear units over ten years old, only 18 and
30 years remaining lives were considered. All nuclear units
presently are intended for base-load service, so only the
base-load case was considered. Wet bulb temperature used
for tower design was 23.9°C (75°F). Capacity factor used
was 70S.
The costs resulting from this analysis are shown in Figures
B-VIII-HJ and B-VIII-15. For the 16.7°C (30°F) rise, the
additional generation cost was higher than for the fossil-
fueled unit due to the increased heat rejection to the water
as expected. Here again the 'case where the circulating
water rise was 6.7°C (12°F) was the most expensive.
However, the comments concerning this in the fossil-fueled
analysis are equally applicable to this case.
Two sets of estimated cost for retrofitting existing
powerplants were submitted as comments by the Utility Water
Act Group (UWAG).388 The first of these analyses, prepared
by Sargent and Lundy Engineers**7, addressed the retrofit of
a hypothetical matrix of plants which was selected to
represent variations in the basic design parameters . that
affect the cost of installing closed cooling systems at
existing plants. The Sargent and Lundy analysis is similar
to the cost analysis presented above and performed by Burns
and Roe in its draft development document. The results of
these two analyses are compared in Table B-VI11-16.
The second set of estimated costs submitted by UWAG is a
tabulation of a survey of utilities, each of which estimated
the cost of retrofitting plants in its system. This survey
is contained in Volume I of the UWAG comments. These
estimates are generally higher than those from the Sargent
and Lundy analysis, since they include site related costs
not fully accounted for in the Rypothetical analysis. The
results of the utility survey can be compared with the cost
curves shown in this document. These cost curves, prepared
by EPA, also reflect higher allowances for site related
conditions. The utility estimates and those of EPA are
compared in Table B-VIII-17.
605
-------
1.6
1.4
1.2
1.0
5 0.4
0.2
0.0
Condenser Pressures Shown
as "tig abs.
_ 23.9°C (75°F) Wet Bulb Temperature
2.5"Hg
4.5"Hg
10"203D 405060"70 80 90luu
Percent Heat Removed
ADDITIONAL GENERATING COSTS FOR
800 Hw NUCLEAR UNIT
MECHANICAL DRAFT TOWERS
18 YEAR REMAINING LIFE
Figure B-VIII-14
1.4
1.2
•o 0.4
a
Condenser Pressures Shown
as "Hg abs.
23.9°C (75°P) Wet Bulb Temperature
2.5"Hg
16.7°C (30°FI
10 20 ~30 40 50 60 70 80 90 100
Percent Heat Rejected
ADDITIONAL GENERATING COSTS FOR
800 Hw NUCLEAR UNIT
MECHANICAL DRAFT TOWERS
30 YEAR REMAINING LIFE
Figure B-VIII- 16
-------
Table B-VIII- 16
COMPARISON OF B&R ECONOMIC ANALYSIS OF RETROFITTING
COOLING TOWERS WITH SARG12NT & LUNDY ANALYSIS
CTi
O
No. of Plants •
in Analysis
Category
Peaking Units
Cycling Units
Base Loaded Units
Burns and Roe
Analysis
1
27
No.
9
9
9
27
Increased
Max.
5.70
1.31
0.62
Generating
Min.
2.90
0.64
0.31
Cost (Mills/kwh)
Avg.
4.
0.
0.
30
98
46
Sarqen
t and Lundy
Analysis
2
92
No.
3
32
54*
89
Increased
Max.
5.71
1.74
1.28
Generating
Min..
2.60
0.28
0.25
Cost (Mills/kwh)
Av
3.
0.
0.
9-
90
93
44
* Note that the S&L Analysis deletes 3 base loaded plants as "infeasible".
From Development Document for Effluent Limitation Guidelines and Standards
of Performance for Steam Electric Power Plants, Burns & Roe, Inc., June 1973,
Figures B-VIII-1-3, B-VIII-9-14.
UWAG comments on EPA proposed guidelines, Vol. 1, Attachment III -
Appendix A, June 1974.
-------
Table B-V1II-17
COMPARISON OF UTILITY SURVEY OF RETROFITTING COSTS
WITH EPA COST CURVES
No. of Plants
in Analysis
Category
Peaking Units
Cycling Units
Base Loaded Units .
EPA Cost Curves
27
Increased Generating Cost (Mills/kwh)
No. Max. Min. Avg.
9 9.30 4.30 6.22
9 2.00 l;02 1.44
9 1.12 -0.60 0.84
27
No.
2
97
(94)
25
(23)
or*
Increased
Max.
2.26
5.81
(3.40)
2.08
(1.89)
Utility Survey- •*•
92
Generating Cost (Mills/kwh)
Min.
2.26
0.72
(0.72)
0.46
(0.46)
Avg.
2.26
1.70
(1.58)
0.94
(0.84)
O
00
* Note: In addition.to the 124 units reported here the utility survey included
13 units for which the costs could not be broken out and 2 units scheduled
for retirement.
UWAG comments on EPA proposed guidelines, Vol. 1, Attachment III,
Appendix D, June 1974.
-------
The variables considered in the Sargent and Lundy (SSL)
matrix included weather conditions, stream temperatures,
capacity factor, unit age, extent of turbine back-end
loading, type of cooling and circulating water flow rate.
The Burns and Roe (B&R) analysis also used these same
variables, except for cooling type back-end loading, and
stream temperatures. The inclusion of these two additional
variables in the S&L analysis required a larger matrix (92
units) than used in the B&R analysis (27 units) . Estimated
capital costs in the two analysis were approximately the
same. For instance, the average construction cost for the 6
schemes for S&L*s 111 Mw fossil plant ($7.97/kw) compares to
the average construction cost of B&R's schemes for it's 300
Mw fossil plant ($7.30/kw). Both analyses allowed for both
capacity losses and energy losses as supplied by combustion
turbines. S&L allowed $106/kw for replacement capacity and
B&R used $90/kw. S&L estimated the cost of make-up energy
to be $.98/10* Btu which is equivalent to the B&R estimate
of 10 mills/Kwh for new gas turbines with heat rates of
10,000 Btu/Kwh. The major difference between the two
analysis was that the S&L analysis optimized the tower
design with respect to the individual condenser-turbine sets
whereas the B&R analysis did not. One would expect the
increased generating costs estimated by the S&L analysis to
be slightly lower than those estimated by the B&R analysis.
The comparison of the results of the two analyses is shown
in Table B-VTII-16. As can be seen from the table, the
average increase in generating cost resulting from the S&L
analysis is close to that estimated in the B&R analysis in
all three categories. For instance, the S&L analysis shows
an average increase of 0.44 mills/Kwh for 54 base loaded
units. The comparible number from the B&R analysis is 0.46
mills/Kwh. The comparisons for the other two categories are
also close. In all three cases the S&L estimate is slightly
lower, which reflects their tower optimization process.
Based on this comparison, it is concluded that the two
independent analysis are complementary and that the costs
for retrofitting power plants, exclusive of site related
factors, are satisfactorily established. The EPA cost
curves are shown in this document. The curves are based on
the original B&R analysis but contain a substantial
allowance (300% of tower base cost) for site related factors
which can increase the fixed cost of cooling tower
installations at some locations.
The utility survey represents the separate estimates of
eight utilities of the costs of retrofitting the units in
their individual systems. The factors considered and the
609
-------
format used for reporting the results is identical to that
used in the S6L analysis. However, these estimates do
include the costs associated with the various site related
factors that would be experienced at the separate plant
locations. The total number of units in the utility survey
was 139. Of these, 124 are included in the comparisons.
Thirteen additional units were not included since the costs
were reported on combinations of units which did not permit
breaking out of costs for peaking, cycling and base load
units. Two additional units in the utility survey were
scheduled for retirement and no costs were provided.
The comparison of the results of the EPA estimates and that
of the utility survey is shown on Table B-VIII-17. The cost
for retrofitting peaking units cannot be estimated from the
utility survey data since only 2 units were separately
estimated. Six other peaking units were reported, however,
the costs of retrofitting for these units were combined with
cycling and base loaded units. While there is some
difference between the maximum and minimum costs for
individual units, the average costs of retrofitting are
fairly clo~e for both base-loaded and cycling categories.
For instance, the average cost for retrofitting 25 base
loaded units, as estimated in the utility survey is 0.94
mills/Kwh. This rompares to an average cost for
retrofitting the 9 base loaded units in the EPA analysis of
0.84 mill/Kwh. Similarly, the estimated cost for the
cycling category is 1.70 mills/Kwh from the utility survey
and 1.44 mills/Kwh from the EPA curves. In addition, the
utility survey is strongly influenced by extremely high
costs for relatively few units. For instance, if the two
most costly units were removed from the utility analysis,
the remaining 23 units could be retrofitted at an average
cost of 0.84 mills/Kwh, which is identical to the EPA
estimate. If the three most costly cycling units were
removed from the utility analysis the remaining 94 units
could be retrofitted at an average cost of 1.58 mill/Kwh a
figure which is roughly 10% higher than the EPA estimate.
In summary, it appears that there is reasonable agreement
between EPA and the industry on the cost estimates upon
which the thermal effluent guidelines are based. First, the
theoretical basis used by BSR for establishing retrofitting
costs, exclusive of site related factors, is in close
agreement withe the results of the Sargent and Lundy
analysis. Moreover, the results of the EPA cost analysis,
which includes a large allowance for site related costs, are
also in close agreement with the results of the utility
survey at least for the cycling and base loaded categories.
610
-------
Energy (Fuel) Requirements
Energy significantly in excess of that normally required by
the circulating water system is required to operate all
cooling systems except the cooling pond. With spray canals,
the water is pumped into the spray nozzle. The natural
draft tower requires the water to be pumped to the top of
the packing. In the mechanical draft tower, in addition to
pumping the water to packing, power is required to run the
fans which move the air through the tower. The amount of
energy required varies by a factor of three for mechanical
draft towers due to its dependency on condenser design and
climatic conditions. A condenser with a high flow rate and
low temperature rise requires more pumping energy than a
condenser with a lower flow rate and higher rise, for the
same size plant. With adverse climatic conditions, more air
is required, resulting in bigger fans requiring more energy.
Fan motors for mechanical draft cooling towers are about 0.2
percent of the unit generating capacity; pump motors are
about 0.5 percent. However, fans and pumps need not be
operated continuously year round. Both fan power and pump
power can be reduced along with the generating demand.
Furthermore, fan power can be reduced when climatic con-
ditions permit to optimize the net unit power output. Only
incremental pumping power should be considered as chargeable
to closed cooling systems. Incremental energy (fuel)
consumption due to fans and pumps with mechanical draft
cooling towers is estimated to be approximately 0.7 percent
of base energy (fuel) consumption. With natural draft
towers and spray systems there is no fan power but
incremental pumping power is estimated to be approximately
0.7 percent or less of base fuel consumption. With cooling
ponds there is no fan power and pumping power would be
approximately the same as with once-through systems.
A further source of incremental energy (fuel) consumption
due to closed-cycle cooling systems is the incremental steam
cycle inefficiency due to changes in the turbine
backpressure. In many cases higher turbine backpressures
will result after backfitting closed-cycle cooling systems.
In these cases the higher backpressures will result in
incremental steam cycle inefficiencies during part of the
year. The incremental fuel consumption over any span of
time due to this factor is a product of the average
incremental inefficiency over that span and the power
generated over the span. For example, the fuel consumption
penalties due to increased turbine backpressure from a
closed-cycle cooling system (See Figure B-VIII-16) is shown
in Table B-VIII-18. The maximum penalty during any month is
611
-------
Figure B-VIII-16
TURBINE EXHAUST PRESSURE CORRECTION FACTORS (EXAMPLE/ PLANT NO0 3713)
to
Throttle Flow
1.5 x 10
2.5 x 10
mm 3.2 x 10
4.2 x 10 IbAr
4.4 x 10 IbAr
-------
Table B-VIII-18
ENERGY (FUEL) CONSUMPTION PENALTY DUE TO INCREASED TURBINE BACKPRESSURE
FROM CLOSED-CYCLE COOLING SYSTEM ***
Example calculated for plant no. 3713
Month
J
F
M
A
M
J
J
A
S
O
N
D
Dew Point
Temp. , F
32
32
36
46
56
64
67
67
61
50
39
32
Air
Temp. , F
42
43
50
59
68
75
78
77
71
61
50
42
Wet Bulb
Temp.,°F
38
39
43
52
60
68
70
70
64
55
45
38
Condenser Out-
let Temp. , F
68
69
73
82
90
98
100
100
94
85
75
68
Condensing
Temp. , F
73
74
78
87
95
1(33
105
105
99
90
80
73
Backpressure,
in. of Hg
0.82
0.85
0.97
1.29
1.66
2.11
2.24
2.24
1.88
1.42
1.03
0.82
Fuel Penalty*
% of base
Ool**
0.1**
0.0
0.0
0.1
0.5
0.7
0.7
0.3
0.2
0.0
0.1**
Annual Average 0.2
en
H
U)
** Note: This plant normally reduces the flowrate of cooling water in the winter to
minimize this type of penalty, therefore flowrate reduction with the closed-
cooling system is also assumed to eliminate the penalty during the winter months,
* Note: Assumes no penalty for once-through system, which is probably the case for
plant no. 3713. Some penalty for once-through systems could occur for other
plants during the summer months.
*** Notes The values given in the table are computed from mean values for each month. The
maximum backpressure penalty for which the cooling ststem would be designed to
operate would be base on the wet bulb temperature which would be exceeded no
more than 5% of the time during the three months of summer. For plant no. 3713,
this wet bulb temperature is 80 F and the maximum backpressure penalty is 2.1%.
-------
0.7 percent of base fuel consumption during that month.
Assuming uniform power generating from month to month, the
annual penalty is 0.2 percent of base fuel consumption. The
greatest fuel penalty expected would occur when the wet bulb
temperature reaches the maximum level for which the
evaporative cooling system is designed, i.e. the wet bulb
temperature which is exceeded no more than 5% of the time
during June, July, August and September. For the plant
shown the maximum penalty is 2.1%. In the case of a new
source the penalties would not be as great due to the
opportunities to optimize the design of both the steam
system (turbine, etc.) and the cooling system.
The total annual fuel penalty for the example above is 0.9
percent of base fuel consumption, assuming that the power
generated from month to month is about the same. If the
plant shown generates twice as much power during the months
of June through September compared to other months, the
annual backpressure penalty would approximately double to
0.4 percent, increasing the overall annual penalty to 1.1
percent of base fuel consumption. Based on the analysis
above, an annual fuel penalty of 2 percent of base fuel
consumption would be conservative.
Loss of Generating Capacity
In the case of Plant no. 3713 described in the above
discussion of fuel requirements, the loss of generating
capacity imposed by a closed-cycle cooling system would be
the sum of the fan power and pump power requirements (0.7%)
and the maximum backpressure penalty (2.1%), or a total of
2.8% of nameplate generating capacity. While the direct
effects of these penalties would be felt as lost generating
capacity only when the demand for generation and climatic
conditions coincide to actually limit generation to below
nameplate capacity, the probability of such an occurrence
must be considered in system planning leading to the
construction of replacement generating capacity.
Site-Dependent Factors
The analysis of the cost involved in installing cooling
devices on the circulating water systems assumed average
site conditions. At any particular station, costs will be
affected by specific conditions existing at the site. Some
of the more important factors are addressed in detail below.
Reference UU7 examined, by computer simulation, the effects
of wet-bulb temperature, circulating water flowrate, stream
temperature, extent of turbine back-end loading, dry bulb
614
-------
temperature, and other factors on equipment costs,
capability losses, energy losses, and generating costs. The
results are summarized in Tables B-VIII-19 through B-VIII-
22.
Age
The cost, expressed in relation to power generated, is
inversely related to the number of years of service life
remaining for a particular generating unit. That is, the
shorter the remaining useful life over which the cost of the
cooling system may be amortized, the greater will be the
percentage of the capital cost charged against each unit of
power generated. Moreover, the shorter the remaining useful
life, the less heat will be rejected to the environment
particularly since many older units traditionally operate
only during periods of higher demand. Accordingly, the
capital cost expressed as a function of units of heat
removed will be greater for older plants. In addition the
absolute cost of retrofitting existing once-through units
with closed-cycle cooling is substantially greater than is
the cost of installing cooling equipment at new units.
Assuming the capital cost of retrofitting closed-cycle
cooling systems to steam-electric generating units to be a
function of generating capacity only, the costs versus
effluent reduction benefits function for units of a given
capacity would be determined by the remaining life of the
units and the capacity factor for the unit over its
remaining life. If it is assumed that the useful life of
all generating units is 35 years (with the following
capacity factors: year 1 through 20, 0.7 capacity factor;
year 21 through 30, 0.4 capacity factor; year 31 through 35,
0.1 capacity factor) then a cost versus effluent reduction
benefit function can be established for thermal controls, as
a function of the age of the unit when controls are
implemented, as shown in Figure B-VIII-17. As can be seen
from the figure, the costs/effluent reduction benefits
increases gradually as the age of the unit increases with
the costs/benefits of a unit 5 years old being about 20%
greater than for retrofitting a unit of zero age, and about
60% greater for a unit 10 years old, which is half-way
through its assumed base-load service life. After this age,
the costs/benefits increases rapidly to about 120* greater
than the zero age unit at age 15 and 300% greater at age 20
which is the end of its assumed base-load service life.
During cyclic service, at age 25, the costs/benefits are
over 800% greater than for the zero age unit.
615
-------
Table B-VIII-19
Computer Simulation of Cost|4of Retrofitting
Cooling Towers
MECHANICAL DRAFT - 411 MW UNITS
72%CAPACITY FACTOR
\% Wet Bulb
CMt (I/to)
«5
78
gr«A« 300
7.97
600
9.10
1100
9.80
300
. 8.57
600
9.71
1100
10. Ul
600
11.37
Wet Bulb
Capability Lo.te. (*)
65
78
gpB/YW
1% Strean Temp.
C*)
58
78
93
300
1.7
l.U
-O.U
600
l.U
1.5
1.1
1100
1.8
1.8
1.8
300
2.U
2.1
0.3
600
2.U
2.5
2.1
1100
2.7
2.7
2.7
600
—
1.U3
«
Wet Bulb
65
tnirgf Lo«««« (%)
78
82
g-po/XW
1% Stream Temp.
(*P)
58
78
93
300
0.7
0.7
0.6
600
0.8
0.8
0.7
1100
0.7
0.7
0.8
300
0.7
0.7
0.7
600
0.7
0.7
0.7
1100
0.7
0.7
0.7
600
—
1.16
..
1% Wet Bulb
ToUl Coat (mlll./KWH)
65
78
KTO/MW
1% Stream Temp.
58
78
93
300
0.32
0.31
0.25
600
0.3U
o.3U
0.33
1100
o.)5
0.35
0.37
300
0.35
0.3U
0.29
600
0.36
0.36
0.37
1100
o.uo
o.uo
o.uo
600
.15
* Note: High back-end loaded
616
-------
Table B-VIII-20
Computer Simulation of Costs of Retrofitting
Cooling Towers
MECHANICAL DRAFT - 535 MW UNITS
44% CAPACITY FACTOR
If wet Bulb
Cr)
Equipment Cost($/IW)
65 78
«n/MW
300
11. UO
600
12.23
1100
11.93
300
11. UO
. 600
12.23
1100
13.1*2
300
11.86
600
13.70
1100
13.U2
Wet Bulb
Cr)
Capability Laaae* (%)
65 78
82
Q>m'ni^
1> Strean Temp.
CD
58
78
93
300
3.63
• 31
-3.7U
600
2.86
l.M»
.1.20
1100
2.80
2.11
.23
300
5.75
2.U9
-1.62
600
U.32
2.90
.25
1100
3.88
3.18
1.30
300
6.U8
3.15
-90
600
U.U7
3.06
.'•0
1100
U.l.3
3.7<«
1.85
'.'ct PL-IS
(V)
tner,y Uoues «)
78
02
*WMW
If Strcan Teop.
Cr)
58
78
93
W
2.38
1.26
-.06
600
2.33
1.8U
i.oe
1100
2.53
2.23
1.66
300
2.77
1.65
.33
600
2.56
2.07
1.18
1100
2.52
2.28
1.71
300
I..78
3.67
2.35
600
3.79
3.29
2.JI.
1100
t.y
v.ot
3.«>!
If Wet Bulb Cr)
65
Total Oott (Mllll/nm)
78
82
a»'*i
If Strcan Temp.
Cr)
58
78
93
300
.88
.61
.28
600
.88
.76
.55
1100
.68
.81
.67
300
1.02
.Tfc
.1*1
600
.96
.85
.63
1100
.99
.93
.78
300
1.31
l.Oh
.78
600
1.18
1.06
.85
1100
1.23
1.16
l.OJ
* Note: Medium back-end loaded
617
-------
Table B-VIII-21
Computer Simulation of Costs of Retrofitting Cooling Towers
447
1% Vet Bulb
CF)
NATURAL pRAFT - 41 1 MW UNITS
72% CAPACITY FACTOR
Equipment Coat($/foW)
65
78
IX Dry Bulb
«=/*••
CF)
300
12. kl
82
600
12-91
1100
13.30
96
300
13-29
600
13-72
1100
13.91
92
300
13- 7U
600
11*. 18
1100
15.11
111
300 600
1100
11*.1B 15.13
Vet Bulb
CF)
Capability Loiaeg (%)
65
78
1H Dry 3ulb
BjnA*
154 Stream Tenperatur*
CF)
58
78
93
300
2.00
1.67
-.123
82
600
1.95
2.00
1.66
1100
2. A
2.1,0
2.33
96
300
2.15
1.81
.037
600
2.12
2.17
1.91*
1100
2.55
2.61
2.51*
92
300 600
2.52 2.85
2.18 2.91
•393 2.55
1100
3.51
3-57
3.52
111
300 600
2-95
3.01
2.65
1100
3-U
3-^
3-1*
CTl
M
00
1* Vet "-:lb
CF)
Energy lx>esea (%)
65
78
IX Dry Sulb
erafa
W Stress Temperature
CF)
58
78
93
300
0.1*3
0.1.3
0.36
82
600
O.U.
O.U*
O.U5
1100
0.!*S
0.1*5
0.1*5
96
300
0.55
0.55
0.1*7
600
0.51*
0.55
0.55
1100 •
0'.63
0.63
0.61*
92
300
0.52
0.52
o.U.
600 1100
0.51 0.51
0.52 0.51
0.53 0.52
111
30C 600
0.^2
C.'3
0.73
1100
0.8?
0.81
0.82
\% Vet Bulb
CF)
Total Cost (Blll./KVH)
65
78
IX Dry Bulb
gjn/rrv
l>i Streaa Teaperature
CFJ
58
78
93
300
.1*
• 39
.31.
82
600
.1*1
.1.1
.1*1
1100
-1*3
.1*3
• 1*3
96
300
• U.
• 1.3
• 37
600
• i.5
.1*5
1100
.LI
.1*7
.1*7
92
300
.1*5
.U.
• 39
600
.1*7
• L7
• U
1100
.51
.51
• 51
111
3?0 600 1100
•50 .5^
.53 .55
•W -55
* Note: High back-end loaded
-------
Table B-VIII-22
Computer Simulation of Costs of Retrofitting
Cooling Towers
MECHANICAL DRAFT - 82°F WET BULB
78° F STREAM TEMPERATURE
600 GPM/MW
Equipment Cor.t ($/K'v)
MWe
?75
**
MWe
Energy Losses (%)
1*11
275
Total Cost (Mills/KWH)
535
***
Capacity Factor
72
9
MWe
Capacity Factor
72
1*1*
9
11.37
11.37
11.37
Capability Losses (%)
1*11
1.143
1.143
17.78',
17.78'.;
17.78:?
275
6.P3
6^23
13. (•'.)',
13-695
3.067
3.875
Capacity Factor
72
1*1*
9
1.157
1.727
1.156
5.71*0
6.669
8.760
2.672
3.298
3.700
MWe
275
535
Capacity Factor
72
.1448
.713
2.597
1.28)4
1.76).
5.715
.986
1.063
3.391
* Note: High back-end loaded
** Note: Low back-end loaded
*** Note: Medium back-end loaded
619
-------
-P
•H tP
IH £
0) -H
C -P
0) «J
« b
0)
G C
O Q)
-H tr>
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o to
3
•a en
0) a
« -H
-P
•P -P
C -H
0) ^
0 O
rH M
m .p
m -P
CO Q)
O ta
Oi
fO
0)
N
H O
fO
m §
4J fi
-HO
o
-P
•H
C
10
8
6
2
0
1980
Age of Generating Unit, years
5 10 15 20
25
1975
1970
1965
1960
1955
1950
Date of Initial Service if Retrofit Operation Begins in 1980
Figure B-VIII-17 Costs/Benefits of Retrofitting Versus Age of Unit
-------
National Economic Research Associates (NERA) projected
the percentage distribution of the 1983 U.S. generation by
the cost of closed-cycle cooling in mills/Kwh (See Figure B-
VIII-18), which includes the effect of the age of units.
Size
Assuming that, based on costs versus effluent reduction
benefits, retrofitting of thermal controls would affect' only
those units placed into service in 1970 and thereafter, an
analysis was performed to ascertain the relation of the
capital cost of retrofitting mechanical draft cooling towers
to the generating capacity of the unit in question. As a
basis for the costs, the data submitted to EPA by the
Utility Water Act Group were used, which resulted from a
survey of utilities and which include the effects of site-
dependent factors. The data used are displayed in graphical
form on Figure B-VIII-19. In all, data representing HH
generating units were used, ranging in size from 70
megawatts to 1300 megawatts generating capacity. Capital
costs ranged from $13.98/kw to $33.08/kw of generating
capacity. A statistical representation of the data using
the method of least squares indicates that, in general, the
capital cost of retrofitting ($/kw) decreases with
increasing unit size (generating capacity) . The average
capital cost of the sample was $25.63/kw, and the
statistical representation of the data indicates that this
is the most likely cost for a unit with a capacity of about
500 megawatts. Based on the statistical representation, the
capital costs for retrofitting a 100 Mw unit could most
likely be about $30/kw, and for a 1000 Mw unit the most
likely cost could be about $21/kw.
There are a very large number of small units (defined by the
Federal Power Commission as units in plants of 25 megawatts
or less and in systems of 150 megawatts total capacity or
less). Yet these systems and units represent only a very
small percentage of the total installed generating capacity
in the United States. Moreover, the potential for higher
costs due to site specific pecularities at any given unit
could be expected to be balanced by more favorably located
units in a larger utility system. In very small systems,
this expectation of counterbalancing unit costs is less
justifiable and the costs of meeting the thermal limits may
not be economically achievable.
Site-Dependent Factors in General
During the comment period, industry representatives supplied
two sets of data on the cost of installation of mechanical
621
-------
33.13
Figure B-VIII-18
33.13
Mills/Kwh"
to
wh — Percentage D^strib
4 • 0 •
3.5 -
3.0 -
2.5 -
2.0 •
1.5 •
1 0 •
Oc _
. j •
By Annual Cost o
ution of 1983 Generatigg-j
f Closed Cycle Cooling ~j
(Excludes hydro and cor.bustion turbine /
generation cron plants which, ir. the /
absence of ar.y
federal thermal guide-
lines, would operate with closed cycle
cooling. )
B=Base load (72% capacity factor) ,
C=Cyclic (44% capacity factor) /
P=Peaking (9% capacity factor) /
M=Mechanical draft tower
/
N=Natural draft tower I /
33,20,10,5 =Years of remaining life //
•
A -^
^y /^
B B
M N
33 33
iiit
10% 20% 30% 40%
J/
J
/^
f
B
M
20
i i •
J
f
B
N
20
/
/
1
B
M
.0
• i i
B
N
1C
r
c
M
10
/
/
/
/
C
N
10
i i
|]
Mills/Kwh
•4.0
•3.5
•3.0
•2.5
•2.0
•1.5
• i n
i. . U
• n s
w . J
\ M,N
15
50% 60"o 70% 80% 90% 100%
Percent of 1933 Generation
-------
K>
CO
•H HIJ
O
rtf
0,
O
O
rH -P
m -P
CJ r« 30
•H £
c 5
ra H
S
CP «•
C co
-P -\
^^^^CD 00°
"^ -^ CP
o> ^ ^ ^
@ CD /T\ ' — <-«) CD
^f Q ^ "*^ ^iL.
•^^
0 ^*^* — ^
.x^ ^^
x^ ^
o / ^^.^
CD ^ CD ^
^-^_
^-x Q).
Least squares representation of the data '
_ _
iii ill
200 400 600 800 1000 1200
Size of Unit, Generating Capacity, megawatts
1400
Figure B-VIII-19
Capital Cost of Retrofitting Mechanical Draft Cooling Towers to
Units Placed into Service after 1970 Versus Size of Unit
-------
draft cooling towers.383 The first was a report of an
engineering firm experienced with the construction of
cooling towers. Its estimate of the capital cost of
retrofitting, on a per kilowatt basis, was only slightly
higher than that used in the Agency's original cost
estimates of the proposed regulation.
The second was based on a survey of 60 plants, in several
utility systems, which represent approximately 12 percent of
the total steam electric generating capacity in the United
states. The results of the survey are summarized in Table
B-VIII-23 The average capital cost of this survey was
significantly higher than the previous industry estimate;
the disparity being accounted for by the commenter on the
ground that the higher estimates reflected additional costs
attributable to site-specific factors. The variability of
the plant by plant costs reported in the latter survey
approximates a normal distribution and ranges from about $9
per kilowatt to about $81 per kilowatt. The median of the
sample and the capacity weighted average cost is $21.9 per
kilowatt. Only three (5%) of the plants reported per
kilowatt costs significantly above the average value (in
excess by 100 percent or more.) The few exceptions with
extraordinarily high cost per kilowatt represent about 3
percent of the generating capacity covered by the sample.
Since the extensive sample of cost estimates from individual
plants addresses all site dependent factors in most
instances, and includes to some extent costs corresponding
to the factors addressed specifically below, EPA has
determined that the sample adequately depicts the effects of
the total of the site dependent factors that materially
influence the costs of achieving the effluent limitations on
heat. While the estimated costs of implementing thermal
controls at three of the plants were reported to reflect
costs in excess of twice the median cost, these incremental
cost factors would not significantly affect the economic
achievability of the effluent limitations. Favorable and
unfavorable site-dependent factors may be ,expected to
counterbalance one another, when applied across the several
units at individual plants and the numerous plants in an
electrical generating system. Hence, the average of the
cost estimates reported in the 60 plant sample represents a
realistic estimate of the retrofitting costs likely to be
encountered by any utility system except the very smallest.
Even in the extraordinary case of the one plant in the 60
plant sample reporting a cost estimate of $81 per kilowatt,
the incremental cost (above that within which 95 percent of
plants estimated costs reflecting site specific factors)
would not affect the economic achievability of the thermal
limitations. For example, the abnormal incremental costs at
624
-------
Table B-VXXI-23
SUMMARY OK SliUXTTD UTJLITIKC CAPITAL COSTS,
CAPABILITY LO.'JSnS AIID KIIERCY LOSSES FOR
MECHANICAL UltAfT AND 11/iTUIlAL UnAFT COOLIIIG TOWERS •»«"
(1973 Dollars)
Tower, Punp,
Site Costs and Site
Capacity Preparation Costs
Capability
Losses'
(Mw) (S/Kw) (Perec
(1) (2) O)
Mechanical Draft Cooling Towers
2,600
1,100
1,575
175
1,312
892
550
564
282
700
1,000
692
990
892
882
2,286
1,300
350
350
275
550
330
266
200
2,659
2,360
142
256
1,214
146
960
640
350
143
1,500
430
960
350
292
670
350
430
430
215
215
700
500
500
88
402
156
848
570
845
239
185
61
BOG
1,448
800
$14.83
21.57
19.75
19.75
19.09
21.21
18.26
22.61
22.61
21.39
22.24
24.24
20.74
28.05
'19.42
11.11
11.73
11.73
. 11.73
11.04
11.04
11.04
12.12
12.12
17.81
17.84
13.17
15.01
13.17*
32.48'
27.71*
27.51*
30.86*
62.24'
19.87*
30.70*
$27.50'
29.14'
40.41)
27.46*
29.14*
81.00*
29.76!
28.84*
31.63
18.35
21.34
17.58
17.43,
8.76!
9.45*
37.20
26.56,
26.20
33.68
33.12
27.72
49.99
26.93
29.41
1.42%
1.30
1.98
1.90
1.67
1.05
1.21
2.36
2.68
2.54
1.96
1.55
1.33
2.21
2.74
1.84
3.38
3.38
3.38
3.36
3.36
3.36
4.03
4.03
2.98
3.20
2.92
3.75
6.00
2.04
3.85
3.48
3.32
4.46
3.40
3.50
3.74%
3.03
3.55
4.70
3.48
4.00
3.26
3.07
3.41
1.91
1.52
1.47
3.35
2.08
2.30
2.35
2.22
2.71
1.56
0.09
4.08
2.78
2.37
2.50
Energy
Losses'
)
(4)
1.26%
1.43
2. 55
2.17
2.32
1.53
1.29
3.52
3.83
3.40
2.45
227
• A /
Inn
• o o
20*7
. 97
3.70
1.36
2.08
1.93
1.95
2.15
2.28
2.32
2.46
2.89
2.42
2.42
1.39
2.07
3.00
1.53
4.86
4.38
4.56
2.60
4.10
4.82
3.18%
3^ e
. 35
4.06
5.60
6.12
4.49
4.56
3.76
4.30
1.70
2.34
1.35
4.30
2.08
2.30
3.03
3.00
2.98
1.87
0.09
4.48
3.00
4.40
4.30
Site
Capacity
(Mw)
(1)
2,240
2,200
389
225
660
660
358
239
355
326
326
598
188
184
299
172
172
172
172
107
360
347
159
1,130
873
1,778
Total 14.689
Costs and Site Capability Energy
Preparation Costs Losses > Losses
($/Kw) (Percent)
(2) (3)
Natural Draft Cooling Towers
$17.47 5.89%
48.88 7.24
47.45 7.98
47.45 7.98
16.41 3.14
16.41 3.14
31.34 2.80
31.34 2.80
22.54 4.60
22.54 4.60
22.54 4.60
21.93 3.47
21.93 3.47
21.93 3.47
21.93 3.47
30.65 1.67
30.65 1.67
30.65 1.67
30.65 1.67
23.48 4.42
23.48 4.42
33.82 3.52
33.82 3.52
64.08 2.72
58.09 2.87
28.48 2.72
(4)
3.70%
6.90
6.85
6.89
3.68
3.46
3.45
2.42
5.35
3.49
'11.62
3.82
5.55
4.64
3.50
1.91
• 1.64
3.07
2.47
10.42
3.45
3.36
8.43
2.80
2.90
4.40
'Sum of losses from pumps, fans and back pressure.
'Excludes site preparation costs.
Weighted Average
Mechanical Towers
Weighted Average
Natural Draft Towers
Weighted Average
for All Towers
$21.89
$33.33
$24.81
625
-------
that site ($37 per kilowatt) would add about 1 mill per
kilowatt-hour to the cost of electricity generated by that
unit. Unusual compliance costs could impact the numerous
small units or small systems more severely.
Flow Rate
The cost of closed-cycle cooling equipment and the total
cost of generation are higher for units with higher flow
rates, all other factors being equal. Flow rates for a
particular unit can be reduced to some degree without
significant incremental cost to achieve the reduced flow.
In the cost analysis submitted to the Agency in support of
the proposed subcategorization criteria, the cooling
equipment costs for the cases of highest flow rate, all
other factors being equal, were less than 10 percent higher
than the average cost of all cases with various flow rates.
Total generation cost were less than approximately 10
percent higher for the cases with the highest flow rates.
In the cost analysis for the worst combination of intake
temperature, wet-bulb temperature, and flow rate, the
equipment cost exceeded the average equipment cost by 52
percent. These variations in equipment cost are within
the range of variations in cost that are anticipated
considering the numerous factors that combine, some
favorably and some unfavorably, at each site to determine
the final cost of thermal control implementation. A 10
percent cost differential is within the range of costs
reflecting the normal variability among site-dependent
factors in general as discussed above.
Intake Temperature
It is recognized that units with high intake water
temperature will incur higher costs, all other factors being
equal. This factor, however, is significant mainly during
the months when the high intake water temperatures occur and
also for those units for which high levels of blowdown flow
are necessary, thus requiring relatively large quantities of
makeup water. It is not as significant a factor for most
units which require normal quantities of makeup water flow.
In the cost analysis submitted to the Agency in support of
the proposed subcategorization criteria, this factor all
other factors being equal, added a maximum of 20 percent in
the most extreme case to the average total thermal control
equipment cost. This 20 percent cost differential is within
the range of costs reflecting the normal variability among
site-dependent factors in general as discussed above.
626
-------
Wet-Bulb Temperature
The general cost analysis presented at the beginning of this
section tested the significance of, wet-bulb temperature
costing various types of evaporative cooling systems
considering four geographic locations representative of the
range of wet-bulb temperatures in the United States. The
cost of cooling equipment at the most unfavorable location
based on wet-bulb temperature was 25 percent higher than the
average cost of all locations tested for conditions
otherwise identical. In the cost analysis submitted to the
Agency in support of the proposed subcategorization
criteria, this factor, all other factors being equal, added
a maximum of 24 percent to the total thermal control
equipment cost for the average of subcases covered for the
most costly case analyzed. This 24 percent cost
differential is within the range of costs reflecting the
normal variability among site-dependent factors in general
as discussed above.
Back-End Loading
The back-end loading of a unit is the maximum steam flow
which the unit "an pass through the last stage blades of the
low pressure turbine expressed as a percentage of the
maximum steam flow through che last stage blades which the
turbine is capable of accepting.
In the cost analysis submitted to the Agency in support
of the proposed subcategorizaticn criteria, this factor, all
other factors being equal, added a maximum of 22 percent to
the total thermal control equipment costs compared to the
average of the cases covered. The maximum cost reflected
the cost for a una \ ith a back-end loading of approximately
15 percent. Generation costs in mills per kilowatt-hour for
the worst case of a 15 percent back-end loadi ••g were
estimated to be about 1 mill per kilowatt-hour. This 22
percent differential in equipment costs is within the range
of costs reflecting the normal variability among site-
dependent factors in general, as discussed above.
Aircraft Safety
An examination of this potential hazard indicated that it is
unlikely that an existing powerplant which will be required
to install a recirculated cooling water system would pose a
hazard to commercial aircraft during periods of takeoff and
landing. However, the vulnerability of aircraft during this
portion of the flight pattern requires special consideration
of cases where a substantial hazard may be shown to exist.
627
-------
Miscellaneous Factors
Certain additional site-dependent factors have been
suggested by commenters which should be considered in
subcategorization for effluent limitations on heat because
they can materially affect cost; existing system layout,
soil conditions, site geology, and topography, while it is
acknowledged that these factors may affect case-by-case
costs, the costs attributable to these and other site-
dependent factors have been assumed in the computation of
the economic costs of thermal control.
Relative Humidity
Natural draft towers are limited for practical purposes to
localities where the relative humidity exceeds approximately
50%. The lower humidities result in prohibitively tall
towers to provide sufficient natural air flow through the
tower.
Land Requirements
The land area for installation of cooling systems varies
widely, as indicated on Table B-VTII-24. Obviously, cooling
ponds will need large areas, and can only be considered
where such land is economically available. The tower
systems also require significant amounts of land.
The mechanical draft tower cell for medium size plants is on
the order of 21 x 12 meters (70 x 40 ft). These cells are
placed side by side to make up the tower, which can be as
much as 183 m (600 ft) long, depending on capacity required.
For a single tower installation, anywhere from 30 to 60
meters (100 to 200 feet) of clear area is required around
the tower to avoid interference of surrounding structures on
tower performance. This means that from 3 to 6 times the
tower plan area is required. When two or more towers are
necessary, the separation between towers must be 120 to 180
meters (UOO to 600 feet) to avoid interference between
towers. Total area required for two towers would be U to 7
times the tower plan area.
Reference 52 presents the following discussion of re-
circulation and interference as related to tower placement.
The problems most usually encountered on large mechanical
draft industrial towers affecting the- entering wet-bulb
temperature are recirculation and interference. The former
is a pollution of the inlet air by a tower's discharge
vapors, and the latter is pollution of the inlet air by an
628
-------
TABLE B-VIII-24
EFFLUENT HEAT
APPLICABILITY OF CONTROL AND TREATMENT TECHNOLOGY
Size of Plant
Relative Humidity
Mechanical Draft
Met Cooling Tower
No limitation
No limitation
Natural Draft
Wet Cooling Tower
Greater than 500 Mw
Generally limited to nrcns
of th» country having an
avcrayo relative huni-Jity of
greater than 47%.
Surface Cooling
_(Pond3f Canals,_etc.j_
No limitation
No limitation
Mechanical Draft
Dry_Cpoling Tower
No limitation
No limitation
Fogging
Height
70 ft. wide x 150 - 600 ft.
long (depending on plant size);
separation for multiple towers
400-600 ft.; clear area of
100 to 200 ft. required
around perimeter of tower area.
Current performance - less
than .03% of circulating flow;
anticipated improvement to less
than .005%; potential problem
in brackish or salt water areas.
Potential local problem depend-
ing on location & climatic con-
ditions; reduction of fogging
possible with parallel-path wet/
dry type tower.
Potential problem only if
adjacent to sensitive area;
can be reduced by attenuation
devices.
350 - 550 ft. diameter plus
100 ft. open area around tower;
nuclear plant-tower must be
distance equivalent to height
away from reactor; 1/3 reduc-
tion of land area possible
with fan-assisted type tower.
Current performance - .005% of
circulating flow; one tower
under construction guaranteed
to be less than .002%; poten-
tial problem in brackish or
salt water areas.
Little anticipated at ground
level.
No limitation
Less serious than mechanical
draft towers, but still poten-
tial problem if very close to
sensitive area; noise can be
attenuated.
350-600 ft.; potential aviation
pro!.lem in specific locations;
compiv with FAA restrictions.
1-3 acres per kwh of capacit''
depending on climatic conditions;
use of spray modules reduces
land requirement by approximately
a factor of 10.
Applicable only with use of spray
modules; drift only in ijnmediate
area of pond, canal, etc.
Potential local problem depending
on location & climatic conditions.
Higher than land require-
ments of mechanical draft
wet cooling tower.
No limitation
Potential problem only if
adjacent to sensitive area; can
be reduced by attenuation devices.
No limitation
Water Consumption
Up to 0.7 gallons per
produced.
kwh
Up to 0.7 gallons per kwh
produced.
Up to 1.1 gallons per kwh
produced; includes natural evap-
oration from surface.
Energy Requirements
Max. wind Velocity
Foundation Require-
ments
Turbine Back Pres-
sure(Present units
limited to 5 in. Hg)
Aesthetic Consider-
ations
Fan power - 5-13 Hw per million
GPM of circulating water; pump-
ing power - 7-12 Mwper million
GPM of circulating water.
No limitation
Pumping power - 10-15 Mw per
million GPM of circulating water;
no fan power required.
Current design -120mph @ 30ft. elev.
Greater than 3000 psf soil bear- Greater than 6000 psf bearing
ing value or equivalent with piles, value or equivalent with piles.
Pumping requirements vary with
plane conditions; spray modules
generally 75 HP per unit.
No limitation
No limitation
Applicable to all plants;penalty Generally app3 icable only to Applicable to all plants; penalty
for operation at back pressure plants above 500 Mw ; penalty for for operation at back pressure
above original design. operation at back pressure above above original design.
original design.
visual plume.
visual plume; size and height.
No limitation
Total power requirement - .02-.08Mw
per installed Mw capacity.
No limitation
Greater than 3000 psf soil bearing
value or equivalent with piles.
Not applicable to existing plants;
results in back pressure of 8-15 in.
Hg during summer months; new plants
will require turbine re-design.
No limitation
-------
adjacent tower or other heat source. These problems are
nonexistent on hyperbolic towers because of the height of
vapor discharge.
The magnitude of recirculation is dependent primarily upon
wind direction and velocity, tower length, and atmospheric
conditions. Other factors are fan cylinder height and
spacing, exit air velocity, tower height and the density
difference between exit air and ambient air,
A longitudinal wind tends to carry discharge vapors along
the tower and the first few cells will not be seriously
affected. However, from the initial downwind point of entry
into the louver face or faces, the effect of recirculation
becomes increasingly severe along the length of the tower.
Therefore, as tower length increases, the more damaging a
longitudinal wind can become.
A broadside wind causes no recirculation on the windward
side of the tower. Recirculation is greatest towards the
midpoint on the leeward side. It diminishes towards the
ends because of fresh air flow around the ends of the tower.
High stacks and maximum space between stacks serve to reduce
the broadside recirculation effect in proportion to the
ratio of this free space area to the lee side louver area of
the tower.
It is apparent that recirculation is primarily a function of
tower length. Normally, placement of single towers with
ambient winds in a longitudinal direction is recommended for
tower lengths up to 200 to 250 feet. For tower lengths
greater than this, more rigorous study of the aforementioned
factors affecting the circulation is required to determine
the most suitable orientation. When tower length exceeds
300 to 350 feet, strong consideration should be given to
splitting into multiple units. The problem then becomes
more a matter of locating the units to minimize
interference.
The principal objective in arranging a multiple tower
installation is to orient the units for minimum
recirculation within themselves and minimum interference
between each other, particularly during the high capability
requirement periods. No set rules can be given for
orientation of multiple units, but generally, it can be
stated that as the number of units increases, the broadside
arrangement tends to be more favorable than longitudinal.
Each installation should be analyzed for orientation within
the prescribed real estate limitations with respect to the
following factors: (1) number of towers in system, (2)
630
-------
number of cells per tower, (3) cell length and height, (U)
height and spacing of stacks, (5) discharge air velocity and
density, (6) ambient atmospheric conditions, and (7)
prevailing wind rose for high wet-bulb hours. See Figures
B-VIII-20, and B-VIII-21 for possible broadside and
longitudinal multiple tower orientations.
The natural draft tower, which varies in diameter from 108
to 168 meters (350 to 550 feet) normally requires a clear
area 30 m (100 feet) wide around it perimeter to allow for
construction. This amounts to a land area twice the plan
area of the tower. For nuclear units, the tower must be
separated from the reactor buildings by a distance equal to
its height.
If land space is restricted, any number of solutions may be
used. Rearrangement of mechanical draft towers to fit
space, or use of a mechanical draft tower of a different
configuration, such as round, might be used. Natural draft
towers might require less land. A single large tower might
take the place of two smaller, more economical ones. The
fan-assisted natural draft tower appears to be a system with
minimum land requirements. One existing plant, located in
an urban area, is installing one of these towers in a former
parking lot. An analysis of land estimated to be required
for evaporative cooling towers at eight nuclear plants
indicates that 20 acres/1000 megawatt generating capacity
would be the maximum amount required.
The Federal Power Commission, National Power Survey (196<4)
puts the land requirement for mechanical draft evaporative
towers at 1,000 to 1,200 square feet per megawatt including
area required for spacing. Furthermore, natural draft
evaporative towers would require 350 to UOO square feet per
megawatt. For a 1,000 megawatt capacity tower requiring
1,200 square feet per megawatt, approximatley 28 acres of
land would be required.
Land requirements reported by other sources for various
cooling methods are summarized by Reference 385 as follows:
Cooling Ponds 1000-3000 acres/lOOOMw
Jet Spray Ponds 50- 300 acres/1000Mw
Natural Draft Wet Towers U- 5 acres/lOOOMw
Due to the variations in heat rate, climatic factors, etc.
from site-to-site, 28 acres per 1,000 megawatts generating
capacity should be sufficient land for any plant to apply
closed-cycle evaporative cooling towers. In many cases
where less than this amount of land is available, it would
631
-------
Prevailing wind-rose for
high wet-bulb hours
Figure B-VIII-20
BROADSIDE MULTIPLE TOWER ORIENTATION
Tower No. 2 placed typically in location a,b, or c
relative to Tower No. 1 and the wind-rose
632
-------
CO
CO
\
\
Figure B-VIII-21
LONGITUDINAL MULTIPLE TOWER ORIENTATION
Tower No. 2 placed typically in location a,b, or c
relative to Tower No. 1 and the wind-rose
Prevailing wind-rose for
high wet-bulb hours
-------
still be practicable to apply evaporative cooling towers due
to the conservatism of the 28 acres per 1000 megawatt
assessment and, further, due to the possible practicability
of natural draft or other systems at the site. Many plants
which do not have land immediately available for evaporative
cooling systems could make sufficient land available by
shifting, to some degree, present uses of land at the site
and by acquiring the use of neighboring land. Land
reguirements for other uses would depend on the types and
relative amounts of fuel, method of ash disposal, and other
factors in addition to plant generating capacity.
Reference 370 addresses the land requirments for projected
3,000-megawatt plants as compared to 1,500-megawatt plants.
The land required for a powerhouse containing three 500-
megawatt units is in the range of 3 to 4 acres; for three
1,000-megawatt units the range is 6 to 7 acres. These
figures include the service bay, but not space for equipment
and facilities outside the powerhouse. Electrostatic
precipitators, stacks, walkways, drives, and parking areas
immediately adjacent to the powerhouse would be about 2-3
acres for three 500-megawatt units and 6-7 acres for three
1000-megawatt units. Sulfur dioxide removal equipment would
add as much on 2-4 acres. Coal-fired plants require
inactive coal storage in an amount to supply 45 - 120 day's
burn at the total plant capacity. A typical coal-storage
yard to provide 90 days supply at a 3,000-megawatt plant
would require 40 acres and the coal pile would be 40 feet
high. The switchyard area requirements for a typical 3,000-
megawatt plant with 500-kv transmission voltage would be in
the range of 10-15 acres. The transmission lines connecting
a typical 3,000-megawatt plant with the existing
transmission system at 500 kilovolts would occupy
rights-of-way of from 100 to 150 acres per mile. On-site
ash disposal for a 3,000-megawatt coal-fired plant (assuming
35 year useful life and 50% capacity factor) would require
300 to 400 acres with ash piled to a depth of 25 feet to
store all the ash developed during the life of the plant.
Limestone-injection systems for controlling sulfur dioxide
emissions would double or triple the volume of ash produced
while the system is in operation. In some cases off-site
disposal of ash would be an available alternative to on-site
disposal.
Other facilities that would require significant amounts of
land include rail, barge and truck terminals for coal-fired
and oil-fired plants, oil storage for oil-fired plants, and
an exclusion area for nuclear plants. In summary, a 3,000-
megawatt plant would require, if coal-fired, 200 to 1200
acres, nuclear 200-400 acres, oil-fired 150-350 acres, and
634
-------
gas-fired 100 to 200 acres, assuming cm-site storage of coal
and oil, pipeline delivery of gas with some on-site storage,
and on-site coal-ash disposal.
In spite of the ingenuity of the cooling tower engineer,
there may be a significant number of units or plants where
addition of a cooling tower would not be practicable. In
the case of a plant in a location where the surrounding land
is already highly developed, the cost of available land may
be high, and it might be necessary to remove any existing
structures from the land, once it was purchased. Secondary
effects, such as fogging or drift could result in complaints
from surrounding neighbors, as well as a requirement to
repair resulting damage. Noise levels from the tower might
be unacceptable to the neighbors. The number of plants
located in the 50 largest metropolitan areas amounts to some
15% of the total (see Table IV-3). An equal number are
probably located within the city limits of small towns,
particularly in the Great Plains states. The practicality
of installing cooling towers will depend on the local
conditions at each plant. One may be surrounded by high
rise buildings, while the next may be adjacent to a vacant
city block. Another plant may be .01 a heavy industrialized
area, whereas another would be in a semi-residential area
where the tower noise aspect may be more sensitive. Land
values will vary greatly, from possibly $25,000 per ha
($10,000 per acre) in small towns to $2,500,000 per ha
($1,000,000 per acre) in the center of a large metropolitan
area.
In a case where 28 acres would need to be acquired for
cooling towers at a 1000 Mw plant, at $36,000 per acre, the
added land cost of $1,000,000 would be less than 5X of the
other capital costs of the towers at $22/kw ($22,000,000).
Reference 446, reporting results of a survey of utilities
concerning land availability for cooling towers and other
factors, found that sufficient land was considered to be
available in 75X of the plants sampled.
Nuclear plants would not normally be seriously affected by
land area limitations for two reason. They are not located
in metropolitan areas, and the required exclusion area
normally provides sufficient area for cooling system
installation unless topographic conditions are unfavorable.
However, when a nuclear plant goes from open to closed
system cooling, the low-level radwaste system normally needs
to be upgraded. With the open system, low-level radwastes
are added to the circulating water for dilution to meet
635
-------
standards for the discharge of radioactive materials. The
blowdown stream may not be sufficient for dilution, forcing
installation of a new low-level radwaste system. Cost of
this has been estimated to be several million dollars at one
nuclear plant.
Non-Water Quality Environmental Impact of Control and
Treatment Technology
The potential non-water quality environmental impacts which
could influence the type of system selected or which must be
minimized in certain cases include these listed below.
1. Drift., resulting in salt deposition on surrounding
areas.
2. Fogging, visual impact and safety hazards.
3. Noise levels unacceptable to neighbors.
U. Height, creating aviation hazards.
5. Water consumption by evaporative systems.
6. Aesthetic considerations, visual impact of cooling
device.
The influence of the majority of these factors on the selec-
tion and cost of the installation of these cooling systems
is summarized in Table B-VIII-21, with a detailed discussion
below of some of the factors not discussed elsewhere in this
document.
Drift
Water vapor and heated air are not the only effluents from a
cooling tower. Small droplets of the cooling water become
entrained in the air flow, and are carried out of the tower.
These drops have the same composition as the cooling water,
i.e., they contain the same concentration of dissolved
solids and water treatment chemicals. The water may
evaporate from the drops, leaving the solids behind, or the
drops may impinge upon the surrounding structures or
terrain. The chemicals and dissolved solids add a chemical
load to the air and surrounding terrain that must be taken
into account.
636
-------
Some data on estimated solids in drift from cooling towers
are shown in Table B-VIII-25. This was taken from the final
environmental statements for a number of nuclear stations.
There is obviously a large variation in the assumed drift
rates. All these values are mentioned in the literature/
with the lower values the more recent. Another factor is
the concentration of solids in the drift. It is obvious
that the proposed towers at Plant no. 1209, operating on sea
water, will have a higher solids loss through drift, as
indicated in Table B-VIII-25.
The amount of drift from any tower is primarily a function
of the tower design, and the drift eliminators in
particular. The total losses to drift are normally
expressed as a percentage of the flow through the tower.
Until recently, drift losses of less than 0.256 were
guaranteed. »*° Now cooling tower manufacturers are
guaranteeing much lower drift losses. Losses of 0.02S are
considered high. Several new towers have been awarded based
on drift guarantees in the range of 0.002 - 0.005 percent of
cooling water flow. A number of tests, summarized in a
report for EPA by the Argonne National Laboratory, 2«*
showed that drift from mechanical-draft towers averaged
0.005%, while that from natural-draft towers might average
half of that, or 0.0025X. With a 0.01X drift eliminater, an
estimated 1 ton of salt per day would be deposited downwind
of a 1,000 megawatt nuclear unit.
While better design is partially responsible for the lower
drift rates, better measurement techniques are equally, if
not more important in establishing drift rates. With the
older, less sophisticated methods, manufacturers were less
sure of the actual drift rates, resulting in high rates for
guarantees.
With the greater emphasis on environmental protection, it
became necessary to measure drift more accurately to deter-
mine the amount of solids leaving the tower to end up as
fallout on the surrounding terrain or suspended in the
atmosphere. Currently at least two systems are available.
The first, the Pills System, is for continuous monitoring of
drift. The second is a system for sampling the drift
intermi tt ently.
The Pills (Particle Instrumentation by Laser Light
Scattering). system is an electro-optical system for
monitoring the drift.
The intermittent sampling system is an isokinetic device.
The discharge air is sampled at its natural flow velocity as
637
-------
TABLE B-VIII-25
SOLIDS IN DRIFT FROM COOLING TOWERS
Plant
No.
1209
1311
3608
6506
3940
0109
3635
Size
Mw
1320
1644
873
850
872
1722
821
Cooling System
(Type )
Mech . Draft
(salt water)
Mech. Draft
Nat. Draft
Nat. Draft
Nat. Draft
Mech. Draft
Mech. Draft
Drift
(% Flow)
0.1
0.2
0.0025
.01
.01
.01
.005
i
Solids in Drift
Ibs ./yr .
3.8 x 107
6 x 105
1.1 x 106
4.0 x 105
9.0 x 104
10.5 x 105
4.7 x 104
Ibs/kwh
(installed)xl°
3.3
.042
.14
.054
.012
.070
.0065
CTl
CO
OO
-------
implied by the term "isokinetic". One device uses a
sampling tube filled with warmed glass beads. A vacuum
system pulls the sample into the tube where the drift im-
pinges on the glass beads. The moisture evaporates, leaving
the solids behind. Weighing of the sample tube determines
the solids collected. This, plus a knowledge of the solids
contents of the water, permits calculation of the amount of
drift. This device supersedes a number of isokinetic de-
vices considerably more cumbersome, and of doubtful
accuracy.
Drop size is another problem. Sensitive paper, and more
recently, the Pills system »*" are used to measure drop
sizes of 100 micron or larger. Several tests by one
manufacturer indicate that the drops accounting for 85% of
the mass of the drift have diameters greater than 100
microns, with less than IX over 500 microns.
The drift from cooling towers, mechanical draft in parti-
cular, potentially can create serious problems, depending on
the salts and chemicals in the cooling water. Drift coating
insulators on the transformers and switchyards can possibly
lead to leakage and insulator failure. Corrosion of
metallic surfaces, deterioration or discoloration of paint
and killing of vegetables have been noted. Thus, the
minimization of drift is an important design feature of the
cooling tower.
The use of brackish or seawater in cooling towers aggravates
the drift problem due to the high concentration of salt in
the water. Fifteen saltwater cooling towers are in use or
planned for steam electric powerplants. Numerous factors
affect the dispersion and deposition of drift from these
towers (See Table B-VIII-26),38S Proper location of the
towers with respect to the plant buildings and switchyards
can avoid most of the problems encountered with highly
saline drift. The rate of drift fallout is related to the
distance from the tower. (See Figure B-VIII-22) . This is
particularly true for mechanical draft towers which dis-
charge at relatively low levels.
Although the environmental effects of saltwater cooling
towers vary from case to case depending on the sensitivity
of local environment and diverse local meteorological
conditions, experience with existing salt water cooling
towers indicates that environmental problems would be
confined to areas in close proximity to the cooling tower.
One study (Reference U51) showed that about 70 percent of
all drift mass fell within 400 feet downwind of a typical
saltwater mechanical draft tower, well within the boundaries
639
-------
Table B-VIII-26
FACTORS AFFECTING DISPERSION AND DEPOSITION OF DR
FROM NATURAL-DRAFT AND MECHANICAL-DRAFT TOWERS
Factors associated with the design
and operation of the cooling tower
Factors related to atmospheric
conditions
Other factors
en
*>.
o
Volume of water circulating in the
tower per unit time
Salt concentration in the water
Drift rate
Mass size distribution of drift
droplets
Koist plume rise influenced by
tower diameter, height and mass
flux
Atmospheric conditions including
humidity, wind speed and direction,
temperature, Pasquill's stability
classes, which affect plume rise,
dispersion and deposition.
Tower wake effect which is especi-
ally important with mechanical
draft towers
Evaporation and growth of drift
droplets as a function of
atmospheric conditions and the
ambient conditions
Plume depletion effects
Adjustments for
nonrpoint source
geometry
Collection efficiency
of ground for drop-
lets
-------
c
o
E
0}
fc
6
o
o
m
u.r
K
CO
o
a.
to
.".r
1000
I 1
100
10
TT—TT
DIFFUSION
METHOD
SOSANQUET
METHOD
GAUSSIAN
METHOD
J I
1.0
HOSI.ER
_L ....... __ I ____ 1 ___ L.
10
100
DISTANCE DOWNWIND, kilometers
Figure B-VIII- 22
Crouiul-Lnvcl Salt Deposition Katie From A Natural-Draff Tc-./cr
As A 1'iip.ctj.on Of The Distance Do'.:m;incl. A Comparison I'utwcen
Various Prediction Method
641
-------
of most powerplants. The same study showed that even under
the most adverse conditions, all drift droplets that would
reach the ground would do so within 1,000 feet downwind.
The subject of this study was a hypothetical eight-cell
crossflow mechanical draft tower designed to cool 134,000
gallons per minute of water with the same chemical
composition and salinity as seawater. The plant was assumed
to be located on an estuary or bay, two miles from the
ocean. The drift rate was 0.004 percent of the circulating.
water.
Airborne drift from this tower plus natural background
salt nuclei from the sea exceeded conservative damage
thresholds for foliar injury for distances up to 2,200 feet
downwind of the tower. The background salt nuclei
contributed over 75 percent of the salt mass causing damage
at this distance from the tower. Moreover, the fractional
increase in airborne salt concentrations due to drift at
2,200 feet was insignificant as compared with normal
variations in the background level caused by changes in
atmospheric wind conditions.
Obviously, local plant life in areas potentially
affected by salt drift frcm towers must be capable of
withstanding these natural airborne salt levels if they are
to survive. Other possible recipients of . incremental salt
drift would likewise be affected by the natural ambient
levels.
The additional cost of drift eliminators does not
represent a significant increment to total cooling system
cost and should be reflected in the cost estimates supplied
by the industry for plants representing over 12 percent of
the Nation's total generating capacity.
Wistrom and Ovand36* concluded, from their study of field
experience during the last 20 years where salt or brackish
water has been used in cooling towers, that "cooling tower
drift effects in the environment are localized and that
beyond same reasonable distance that is usually within the
plant site boundary, drift does not significantly affect the
environment".
The fact remains that this salt will be deposited on the
surrounding terrain. Whether or not this influences the
environment, i.e., vegetation and ground water salinity,
will depend on the increase over the natural deposition of
salt on the surrounding terrain. The natural salt load,
particularly along ocean coasts exposed to continual wave
action, can be fairly high. If the tower drift results in a
642
-------
salt load of only a few percent of this natural salt
deposition rate, the effect would probably be minimal.
A summary of the state-of-the-art of saltwater cooling
towers (Reference No. 385) concluded that "although the
environmental effects of saltwater cooling towers vary from
case to case depending upon the sensitivity and diversity of
local conditions, experience with existing salt water
cooling towers indicates that the environmental problems
would be confined up to several hundreds meters from the
cooling tower." Environmental impact on the biota, bodies of
fresh water, soil salinity and structures is difficult to
detect at the levels of the long-term average in coastal
areas. The direct experimental data available about the
environmental effects are sparse. Most of the environmental
impact predictions are based upon research studies pertinent
to the coastal environment, which may or may not be
applicable for salt water cooling towers in other locations.
Most of this available information is descriptive in nature
and does not permit a correlation between the airborne salt
concentration or deposition rate and environmental effects."
Adverse environmental impacts due to drift are not a
national-scale problem. Technology is available to
integrate a low drift requirement into the overall tower
design at moderate cost. In addition, alternate cooling
systems selection and proper location of the tower with
respect to prevailing winds and surrounding land uses can
also be used to meet stringent drift requirements. New
plants have the additional flexibility of site selection to
help minimize this problem.
Fogging
Fogging is one of the most noticeable of the possible side
effects of the use of evaporative cooling devices. Fog is
produced when the warm, nearly saturated air from the
cooling facility mixes with the cooler ambient air. As the
warm air becomes cooler, it reaches first saturation, then
supersaturation with respect to water vapor content. When
this occurs, the vapor condenses into visible droplets, or
fog. The psychrometric chart in Figure B-VIII-23 shows
representative conditions through which the air-water
mixture can pass to create fog. The condition at point B is
that of the ambient air. As this air leaves the tower,
(point A) it mixes with the colder, less humid ambient air
following the dotted line which lies largely in the portion
of the chart which represents a condition where the air
contains more moisture than it can contain at 100X
saturation. In this condition condensation can occur.
643
-------
Saturation
(100% RH)
-P .H
-H
T) X
•H —
3 l-i
33 -H
n)
O
-H -a
o
0) A
20 -
15 .
10 .
80% RH
20 40 60 80 100
Dry Bulb Temperature (°F)
120
MODIFIED PSYCHROMETRIC CHART
(From Reference 128)
FIGURE B-VIII- 23
644
-------
producing fog although normally some supersaturation is
necessary. As more mixing occurs, the air condition
eventually returns to point B.
The development of fog by cooling devices is primarily de-
pendent on the local climatic conditions. The areas
normally susceptible to cooling tower fog are those in which
natural fogs frequently occur. EG £ G, Inc. in a report for
EPA, 219, defines three levels of potential for fogging, as
listed below.
a» High Potential! Regions where heavy fog is observed
over 45 days per year, wh^re during October through
March the maximum mixing depths are low (400-600 m), and
the frequency of low-level inversions is at least 20-
30%.
b. Moderate Potential; Regions where heavy fog is
observed over 20 days per year, where during October
through March the maximum mixing depths are less than
600 m, and the frequency of low-level inversions is at
least 20-30%.
c. Low Potential; Regions where heavy fog is observed
less than 20 days per year, and where October through
March the maximum depths are moderate to high (generally
greater than 600m).
Using this criteria and several meteorological references,
EG&G has developed the map shown in Figure B-VIII-24,
indicating the fogging potential of locations within the
United States.
The length of the expected fog plume can be estimated from
the following equation: »s
Xp = 5.7(Vg)°«s (320Vw)-o«s (Tge-Tgi) o«s (Tp-Tgi)-°«s
Where Xp = visible plume length, ft
Tg = air or plume temperature, °C
Tp = temperature at end of visible plume, °C
Vw = wind speed, ft/sec
Vg - total rate from tower cu m/hr (gas evaluated at 20°C)
i - tower inlet
e = tower exit
645
-------
HIGH POTENTIAL
MODERATE POTENTIAL
SLIGHT POTENTIAL
Figure B-VIII-24
GEOGRAPHICAL DISTRIBUTION OF POTENTIAL ADVERSE EFFECTS FROM COOLING TOWERS,
BASED ON FOG, LOW-LEVEL INVERSION AND LOW MIXING DEPTH FREQUENCY.
(From Reference 219)
-------
In order for fogging to create an impact it most exist in
close proximity to a land use with which it interfers such
as a major residential, commercial or industrial activity.
As can be seen from Figure B-VIII-2U, most of the major U.S.
residential, commercial and industrial centers do not lie in
the areas of high fogging potential.
Furthermore, local meteorology and the configuration of the
source and its surroundings must permit a downwash condition
to obtain fogging. These will not usually exist if the
cooling tower if properly designed and located.
In view of these factors a conservatively high estimate of
the plants that would be concerned with fogging problems
resulting from the installation of closed cooling systems is
less than 5 percent of the total plants. Moreover, fogging
would only be of concern at the plants for small fractions
of the total operating time,
The fog plume from a mechanical draft tower is emitted close
to the ground, and under appropriate conditions, can drop to
the ground. Under these conditions the fog can create a
serious hazard on nearby highways. If the fog passes
through the switchyard, insulator leakage problems can be
encountered. Thus, in addition to being highly visible, the
fog plumes create safety hazards and accelerate equipment
deterioration. Careful placement of the towers will
eliminate most of the problems. If placement is
unsatisfactory, or creation of hazards is still expected,
the use of a wet-dry tower can significantly reduce the
plumes. In the wet-dry tower (typically) ambient air is
heated from point B (See Figure B-VIII-23) to point C in the
dry section. Air from the wet section (point A) and dry
sections are mixed and exhausted at a condition represented
by point A*. In mixing with ambient air (dotted line)
subsaturated conditions exist and fogging cannot occur. Two
towers of this type are currently on order or under con-
struction for large generating plants in the U.S. It should
be noted ,however, that this type of tower is more costly
than the conventional wet-type tower (approximately 1.3 to
1.5 times the cost of a conventional tower). This would add
an increment of approximately 0.15 mills/kwh for plume
abatement for a large, modern base-load unit. While wet-dry
towers are more costly than conventional wet towers, the
cost of employing plume abatement in specific cases has been
accounted for in the general analysis of the cost of cooling
647
-------
tower construction. The general analysis is based on cost
data supplied by industry, which were, in turn, developed
from a sample of 60 plants and units and the costs for 18 of
the units in the sample reflected the use of wet-dry
towers.*47 Other possible techniques of plume abatement
include increasing the mechanical draft stack height,
heating tower exhaust air with natural gas burners,
installing electrostatic precipitators or mesh at the tower
exit, and spraying chemicals at the tower exhaust.
Another possible solution is to use a natural-draft tower.
The plumes from these towers are emitted at altitudes at 90
to 150 meters (300 to 5001) above the tower ground level,
and there is little possibility of local fog hazards, as the
plume is normally dispersed before it can reach the ground.
One hazard that might arise would be to aircraft operation,
although plumes are normally localized. The use of natural
draft cooling towers in high potential fog areas seems to be
an accepted practice, as indicated in Figure B-VIII-25 z«3,
which shows the location of 75% of the natural draft towers
expected to be constructed through 1977. Note that the
majority of them are in the eastern area of high fog
potential. Under freezing conditions the fog may turn to
ice upon contacting a freezing surface. The ice thus formed
is commonly called rime ice. This is a fragile ice, and
breaks off the structure before damage occurs from the
additional weight, except on horizontal surfaces. Here
again, although it is mentioned in the literature, the
problem is considered to be insignificant.
The potential for modification of regional climate exists,
but has not been verified to date. The Illinois Institute
of Technology Research Institute in its report 2a3 for EPA
on the field tests at Plant no, U217 in Pennsylvania de-
termined that the effects were minimal. This plant
evaporates approximately 0.63 cu m/s (10,000 gpm) of water
and releases approximately 0.5 x 10* kg cal/s (120 x 10«
btu/min) of heat to the atmosphere when operating at 1U40
Mw, 80% of its design capacity. Two natural draft towers
are installed at Plant no. 4217. A review of weather
station records at stations located 13 to 51 kilometers from
the plant resulted in Ma suggestion of precipitation en-
hancement". Initiation of cloud cover occurred rarely, and
only preceded natural development of cloud cover. The
cooling tower plume would merge with low stratus clouds when
they were at an appropriate elevation.
The current "state-of-the-art11 in meteorology has not pro-
gressed to the point where the effects of large thermal
releases to the atmosphere can be quantitatively evaluated.
648
-------
vo
Figure B-VIII-25
LOCATION OF NATURAL DRAFT COOLING TOWERS THROUGH 1977
(From Reference 283)
-------
Improvements in meteorological techniques currently in pro-
gress will undoubtedly result in quantification of these
effects. A number of meteorologists indicate that thermal
emissions to the atmosphere could have significant effects
on mesoscale phenomena, where mesoscale refers to a scale of
from 1 to 50 kilometers. A comparison of some natural and
artificial energy production rates is shown in Table B-VIII-
27. 3*7 It is obvious that some of our artificially
produced energy rates are equal in magnitude to those of
concentrated natural production rates.
It is possible that these thermal discharges may have a
"triggering" effect on a much larger phenomena, such as
thunderstorms, tornados, or general cloud development and
precipitation. This could prove beneficial if the trig-
gering could be adequately controlled, and possibly
disastrous if control was not possible.
Although no regional climatic changes have been noted to
date, this does not mean the possibility does not exist.
with larger and larger stations being built which reject
their heat to the atmosphere through wet cooling towers, it
becomes evident that this water must be added to the
rainfall at some location, wherever it may be, and that the
additional heat will influence the climatic conditions to
some extent. This probably falls into the category of
weather modification, even though it be unintentional, and
is currently being investigated by meteorologists.
With coal-fired or oil-fired plants, there is an additional
factor in relation to plumes. The stack gases of these
plants contain varying amounts of SO2,, depending on the
sulfur content of the fuel used and the degree of flue gas
desulfurization achieved. To the extent that the stack
gases and the cooling tower fog plume became intimately
intermixed, the fog will interact chemically with the SO£,
forming sulfuric acid. This is a corrosive acid, and
settlement on surrounding buildings will accelerate
deterioration. Vegetation will also be affected by this
"acid fog". The relationship between the two discharges
should be such as to minimize their intermixing.
In addition to the basic meterological considerations, two
other factors should be considered where stack and cooling
tower plume intermixing must be minimized, as follows: (1)
location of the cooling towers in relation to the stacks,
and (2) the buoyancy of the plumes as related to the stack
and tower heights. A further consideration is that in cases
when the plumes would intermingle, they would not
necessarily become intimately mixed. In the case of the
650
-------
TABLE B-VIII-27
ENERGY PRODUCTION OF SOME NATURAL AND ARTIFICIAL PROCESSES AT VARIOUS SCALES (367)
Area
(m2)
5 x 1014
1012
108
104
Natural Production
Event
Solar energy absorption
by atmosphere
Cyclone latent heat
release (1 cm rain
per day) .
Thunderstorm latent heat
release (1 cm rain per
30 min)
Tornado kinetic energy
production
Rate
(W/m2 )
25
200
5000
104
Artificial Production
Type of Use
Man's ultimate energy
production
Northeast U.S. ultimate
production (108 people,
20 kw each)
Super energy center or
city
Dry cooling tower for
1000- Mw (e) powerplant
Rate
(W/m2)
0.8
2.0
1000
105
cr
-------
study of plant no. 4217, cited previously, measurements
suggested that the plumes were not uniformly mixed and may
have been merely co-mingled.
In any case, since hundreds of evaporative cooling towers
have been operated over many years at coal-fired and oil-
fired stations scattered across the United States without
significant numbers of reports of adverse impacts due to
"acid fog", the engineering and other design practices
employed should be adequate to assure that this problem does
not arise in subsequent applications of evaporative cooling
towers.
In summary, potential adverse impacts due to fogging are not
a national-scale problem. In the relatively few instances
where it could be a problem, technology is available, at a
moderate incremental cost, to control or eliminate fogging
to the degree required by the related considerations.
Noise
Noise created by the operation of cooling towers, results
from the large high-speed fans. The enormous quantities of
air moving through restricted spaces, and large volumes of
falling water contacting the tower fill and cold water basin
also create noise. Mechanical draft towers will generate
higher noise levels than natural draft towers. At sites
where the incremental noise due to cooling towers might be a
problem, it should be considered in the design of cooling
tower installations. A three step procedure usually results
in adequate coverage of this problem.
1. Establish a noise criteria that will be acceptable to
the neighbors within hearing range of the proposed tower.
2. Estimate the tower noise levels, taking into account
distance to neighbors, location of the installation, and
orientation of the towers.
3. Compare the tower noise level with the acceptable noise
level.
Only if the tower noise level exceeds the acceptable noise
level need corrective action be taken.
All cooling towers and powered spray modules produce some
noise. The noise from powered spray modules and natural
draft cooling towers is primarily from the falling water.
In the mechanical draft dry tower there is the fan noise and
652
-------
possible noise from high velocity flow of the water through
the cooling surface.
Since the powered spray modules are normally located in a
canal, the banks tend to direct the sound upward, and the
bank surface can absorb part of the sound. Their use to
date has not created serious noise problems.
The noise level from cooling towers is of the same order of
magnitude as that in the rest of the station, and thus noise
from both sources can be a problem in noise sensitive areas.
Every effort should be made to place these structures away
from potential sources of complaints. Sound levels decrease
with the square of distance from the source. Large flat
wall surfaces can direct sound into sensitive areas. At the
same time, walls and buildings can act as a sound barrier.
Fan speeds can be reduced at night when load is lowest and
when ambient noise levels may also be lowest. Proper
attention to noise problems in tower design, selection, and
placement can avoid costly corrective measures.
It is possible to decrease fan noise about lOdB by reducing
tip speed from 12,000fpm to 8,000fpm. This reduction,
however, would be possible only if the fan being considered
had the capability of handling 125* more pressure and 50%
more flow without stalling. A rough estimate of fan cost
versus decibel reduction is shown in Figure B-VIII-26. A
lU-ft fan was used in the analysis but the costs would be
proportional for any fan.455
If the above procedures are unable to reduce noise levels in
the affected areas to acceptable levels, sound attenuation
can be done by modification or addition to the tower.
Discharge baffles, and acoustically lined plenums can be
used. Barrier walls, or baffles can be erected. Adequate
noise suppression is normally possible, but the cost can be
high. Good practices can minimize the expense involved in
noise suppression.
It is recognized that incremental costs would be incurred
where mechanical draft cooling towers may require noise
control. Little information is available on the cost of
implementing noise control procedures on powerplant cooling
towers principally because it has rarely been necessary to
employ these measures, even though powerplants with cooling
towers exist in areas of high population density. It is
doubtful that there will be a significant need for this
technology as a result of technology-based effluent
limitations on heat, since many plants in areas of high
population density would be exempted because of the lack of
653
-------
.1,5 WJ
3,000
2,500
2,000
1,500
1,000
500
0
12M
X
10M
_^x
S*
>
s
w..t
/
J
/
/to
Tip «peed
17.000 fpm
10.000 fpm
9,000 fpm
C.OOO fpm
4,000 fpm
• 14-h-dion>.el:r !.in>
1
-
106 104 102 100 98 96 94 92 90
Hemispherical PY/l dbA
Figure B-VIII-26
Fan Cost Versus Noise Reduction
Reference 455
654
-------
sufficient land for closed-cycle cooling systems, because of
the salt drift exemption, or because of the exemptions based
on age or size. Furthermore, alternative thermal control
technologies may be employed that are generally quieter than
mechanical draft cooling towers. In the only case cited by
comments on the proposed effluent limitations, guidelines
and standards, a plant in West Germany was reputed to have
incurred twice the normal capital cost for cooling towers
due to the installation of noise control equipment. This is
a most unusual case indeed. The plant cited is in West
Berlin, a politically land locked community isolated from
outside power sources. Increased demand and a paucity of
available sites required that a new plant be constructed in
close proximity to residences in an area of high population
density, hence, the need for noise abatement technology.
Furthermore, it is significant that cooling towers were
employed with noise suppressors in order to take advantage
of the site while accomodating the need to reduce noise to
locally required levels.
It is concluded that adverse impacts of noise is not a
national-scale problem. Technology is available at a
moderate cost to reduce the noise impact of cooling towers.
In addition, alternate cooling system selection and proper
locations of the towers can be used at highly sensitive
sites. New plants have the further flexibility of site
selection to help minimize this problem.
Height
The height of natural draft cooling towers, up to 183 meters
(600 ft) , results in a localized potential hazard to
aircraft. Location of such a tower would generally not be
permitted in the approaches to an airport. Other pertinent
FAA restrictions and regulations would have to be complied
with. Aircraft warning lights would have to be installed on
the tower along with provision for servicing them. The
height of alternative technologies would not present hazards
to aircraft.
Consumptive Water Use
All evaporative heat rejection systems result in the con-
sumptive use of water. The primary consumption occurs as
evaporation and drift. Even the once-through system is
responsible for consumptive use of water by evaporation
during the transfer of heat from the river, lake or ocean to
the atmosphere, the ultimate receiver.
655
-------
Heat is transferred from the river or lake to the atmosphere
by three major means, radiation, evaporation, and
conduction, with that by conduction being small compared to
the other two. The Edison Electric Institute report
entitled, "Heat Exchange in the Environment" •*, gives a
detailed analysis of these processes.
The closed systems, cooling towers and spray ponds, utilize
the same mechanisms, although their respective contributions
may be much different. Figure B-VIII-27, taken from a paper
by Woodson, 3»8 gives a graphic representation of the
percentages of heat transferred by each process. In a re-
port prepared for EPA, »°4 some representative consumptive
use rates for a 1000 Mw unit are shown (see Table B-VIII-
28). Consumptive use varies from 1.3 to 2.1 times that of a
river or lake, depending on the type of closed system used.
Woodson, in his article, 318 gives a more detailed analysis,
including costs to make up for penalties inherent in the use
of closed systems as shown in Table B-VIII-29. Consumptive
use, according to his figures, can be as much as 2.5 times
that of a once-through system.
The amount of water consumed depends to some extent on the
climatic conditions existing at the site. Some of these
factors and their effect are shown in Figure B-VIII-28. »"
The use of cooling ponds results in the highest consumptive
use, since the total consumptive loss is equal to the sum of
the natural evaporation plus that due to heat rejection to
the cooling pond. The increment of consumption due to
natural evaporation is approximately the difference between
the consumption of a cooling pond and that of a natural lake
or river. The consumptive use of water in a natural lake or
river is low, since the natural losses are not charged
against the power station, and in addition, a significant
part of the heat is transferred by radiation.
The dry-type cooling tower, as opposed to the wet-type
cooling tower, has essentially no consumptive use of water.
The only consumptive use would be losses from this closed
system due to leaks.
In general, the replacement of a once-through cooling system
with a closed system will result in somewhat higher water
consumption from a broad environmental standpoint. This in-
crease averages about 25% as shown in the referenced tables
and graphs, and only represents the absolute difference in
water consumed.
656
-------
ONCE-THROUGH
RIVER OR LAKE
RADIATION AND CONDUCTION
EVAPORATION
BASIN
COOLING
RADIATION AND CONDUCTION
EVAPORATION
BASIN COOLING
SPRAYS
RADIATION & CONDUCT^
i.
EVAPORATION
WET COOLING
TOWER
CONDUCTION
EVAPORATION
WET/DRY
COOLING TOdER
CONDUCTION
EVAPORATION
DRY COOLING
TOWER
CONDUCTION
0%
10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Figure B-VIII-27
HEAT TRANSFER MECHANISMS
WITH ALTERNATIVE COOLING SYSTEMS
(From Reference 318)
657
-------
TABLE B-VIII- 28
EVAPORATION RATES FOR VARIOUS COOLING SYSTEMS (Reference 104)
Cooling System
Cooling Pond (2 acres/Mw)
Cooling Pond (1 acre/ Mw)
i
; Mechanical Draft Tower
: . Spray Pond
Natural Draft Tower
i
< Natural Lake or River
i
Evaoorat ioir-
m-Vsec
.566
.453
.368
.360
.340
.266
cfs
20.0
16.0
13.0
12.7
12.0
9.4
For a 1000 Mwe fossil-fueled plant at 82 percent capacity factor average
annual evaporation (assume constant meteorological conditions).
658
-------
TABLE B-VIII- 29
COMPARATIVE UTILIZATION OF NATURAL RESOURCES
WITH ALTERNATIVE COOLING SYSTEMS
FOR .
FOSSIL FUEL PLANT WITH
680 Mw NET PLANT OUTPUT
(70 per cent annual load factor)
Once-through river or
lake cooling system
Alternative cooling systems
Basin cooling facility
Basin cool.ing with auxiliary sprays
Mechanical draft wet tower
Mechanical draft wet/dry tower
Mechanical draft dry tower
Natural draft wet tower
Gross
Generating
Capacity
kw
Net
Plant
Heat
Rate
Rtu/Vwh
Fuel
Input
Billions of
Btu/yr
Coal
Consumption
10,000 Rtu/lh
tons/yr
Water
Consumption
(Evaporation)
Acre ft/yr
Land
Area
acres
BASE REQUIREMENTS
715,580
9,489
39,567
1,978,343
2,800
ADDITIONS TO BASE REQUIREMENTS
-
6,360
4,420
5,070
17,770
3,060
19
103
77
86
1,173
59
79
429
321
358
4,682
246
3,950
71,450
16,050
17, 900
734,100
12,300
5,400
6,300
6,300
2,800
* (?,800)
6,300
1,000
500
15
15
6
15
01
Ui
vo
*Denotes Decreased Requirements
(From Reference 318)
-------
2 ACKIS/MW
1 ACRt/MW
MCCHANICAl GRAFT C.I
SPkAY PONDS
NATURAL DRAFT C.T.
NAIURAI UKE OR RIVU
SO 60
WET BULB TEMPERATURE •
WATER CONSUMPTION VERSUS
WET BULB TEMPERATURE
CAl/Kcl
1.6
KWH
NAlUSAl LAKE OR SIVER
KECHAIiiCAl DRAFT C.T.
SPRAY PONOS
NATURAL DRAFT C.T.
40 EO
RELATIVE HUMIDITY • %
WATER CONSUMPTION VERSUS
RELATIVE HUMIDITY
CAL/Nct KWH
1.20
2 ACRES.'KV
7 8 9 10 II 12 U U IS
WIND SPEED • MPH
WATER CONSUMPTION VERSUS
WIND SPEED
2 ACRES MW
NATURAL LAKE OR RIVtR '
0 10 20 30 40 50 60 70 60 90 100
CLOUD COVER• %
WATER CONSUMPTION VERSUS
CLOUD COVER
CAL/Nct KWH
I.I
1.0
.9
.8
.7
.6
.5
.4
.3
.2
.1
0
\
2 ACRCS MW
I ACRE MW
SPRAY POKO
NATURAL LAKE
OR KiVER
10 15
COOLING RANGE •'{
20
WATER CONSUMPTION VERSUS TEMPERA-
TURE RANGE FOR BODIES OF WATER
CAL/Nct KWH
.60
.73
.76
.74
.7J
.70
.r,3
.bG
.64
.62
.60
00
V
ATURAL DRAfT C.T.
10 12 14 li 18 20 2? 24 70 28 30 32 ]4 36 38 48
•{
WATER CONSUMPTION VERSUS TEMPERATURE
RANGE FOR COOLING TOWERS
(From Reference 133)
FIGURE B-VIII- 28
WATER CONSUMPTION VERSUS METEOROLOGY AND COOLING RANGE
660
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Present powerpiants have been sited, in many cases, where
the lack of a reliable supply of quality cooling water has
dictated the use of closed-cycle evaporative cooling. In
other words, where water is in short supply, the more-highly
water consuming evaporative cooling systems have been
justified and legal rights to water consumption have been
obtained where required. In many states water users and
consumers must obtain legal rights to use or consume water.
In some of these states all water use and consumption rights
have already been allocated but not necessarily utilized.
Rights can be bought and sold among users. Many powerplants
have rights to more water than they currently use or
consume. In some states powerplants have the power of
eminent domain over water rights, and are thereby authorized
to appropriate all or a part thereof to the necessary public
use, reasonable compensation being made.
A comprehensive study, prepared by the Utility Water Act
Group (Reference U41), of the water use implications of
applying closed-cycle evaporative cooling to all steam-
electric powerplants concluded that an increase of over 80
percent would result in the amount of fresh water consumed
annually by these plants. When considering total freshwater
consumption by all uses, complete closed-cycle cooling in
the year 2000 is projected by the same study to increase the
total water consumption nationally by 5.U percent when
compared to maintaining the existing mix of once-through and
closed cooling systems. At the same time, the Water
Resources Council projects possible shortages of water in
the year 2000 in major portions of the U.S. from California
to Texas. The study cited above projects for the year 1983
the following increases in freshwater consumption, over
present freshwater consumption by powerplants for the arid
regions from Texas to California:
Base Increases
Texas-Gulf 376.7MGD 125.7MGD
Rio Grande 36.8 0.0
Upper Colorado 13.1 0.0
Lower Colorado 65.6 0.0
Great Basin 5.3 0.2
California <*7.0 197. a
The regions listed above encompass the geographical areas
shown on Figure B-VIII-29.
The previously referenced study **» further estimates that,
in the case of California (which appears to be the worst
661
-------
WATER RESOURCE REGIONS
to
s-0.uils!E RAINY
~
• M»«"w«M»i/ ' ~~\ I/I ^rrAT I A'KES
"" "MSRI x uv^ute v' •
.BASIN ^ u\—-•—\ \\ t>
•CAJUSU
UPPER
COLORADO
^rgr—j^. ARKANSAS-WHITE-RED ^ss^i^
- "^
-4 MISSISSIPPI i SOUTH "v
' ')< ATLANTIC GULF
i-4-. \.crT ~]rSSirJ
Figure B- VIII- 29 Regions Upon Which Water Consumption Studies Have Been Based
441
-------
case for the 6 arid regions), in the year 2000 there will
be, as a base, a deficit of 29.1 billion gallons per day of
freshwater based on monthly flow available 95 percent of
months (20-year drought). Corresponding to this, the
freshwater consumption due to retrofitting of closed-cycle
cooling to steam-electric powerplants would add 1.1 billion
gallons per day to the base deficit during peak monthly
power demands under summer conditions. For this worst case
(of the 20-year condition) the increase in the water deficit
that may be attributable to retrofitting is 3.8 percent of
the base deficit.
The previously reference study prepared by the Utility Water
Act Group indicates the consumptive use of freshwater due to
retrofitting steam-electric powerplants in California for
1970, 1983 and 2000 as follows:
Base Increases
1970 19.8MGD 83.4MGD
1983 47.0 197.H
2000 198.9 835.9
The existing mix employed above for 1970 of 78.27 percent
capacity using once-through saline cooling systems, 6.48
percent using once-through freshwater, and 15.25 percent
using cooling towers, is based on FPC Form 67 data for 1970.
Projections of increases for the years 1983 and 2000 were
based on applying h same percentage to the base as was
applied for the 1970 computations.
From the 1970 mix described above it can be seen that the
consideration of salt water cooling towers 'which is an
available alternative for plants using once-through saline
systems would significantly diminish the projection of
freshwater consumption indicated by Reference 441, which is
based as the use cf freshwater towers for plants using once-
through saline systems. Reports submitted to the FPC by
regional reliability councils in 1973 in response to
Appendix A of Order 383-3 list projected steam-electric
units 300 megawatts and larger for which construction has
begun pr is scheduled to begin within 2 years. These
reports list 7,013 megawatts of generating capacity to be
added in California over the years 1973-1980. Of this 5,802
megawatts are planned with once-through saline systems and
cooling tcwers are planned for the remaining 2,211
megawatts. Considering all the plants listed in FPC Form 67
for 1970 and all the plants listed by the FPC for start-up
in 1973-^980, incremental freshwater consumption will result
only from retrofitting the 6.48S of the 1970 capacity which
663
-------
uses once-through freshwater cooling systems, or 1,280
megawatts cut of the 26,792 megawatts covered by the two FPC
sources. In contrast, the previously mentioned study by
UWAG assumes retrofit freshwater cooling systems on 34,500
megawatts of generating capacity by 1983 for California.
Similar results would be obtained for the Texas-Gulf region
which was assumed to have a capacity mix of 27.30 percent on
once-through saline systems; 15.30 percent on once-through
fresh systems; 36.00 percent on cooling ponds; and 21.40
percent on cooling towers. Subsequent to the publishing of
the reference study, virtually all of the capacity
identified above as being on once-through fresh systems has
been determined to actually be on cooling lakes.
Furthermore, the Electric Reliability Council of Texas,
whose geographical area roughly coincides with the Texas-
Gulf region, reported to the FPC in 1973 only 750 megawatts
of capacity planning once-through cooling for units 300
megawatts and larger, out of 14,737 megawatts for which
construction had begun or was scheduled to begin within 2
years. These capacity additions were planned to be placed
into service over the period 1973-1982.
In Florida, which Reference 441 identified as a potential
problem area for freshwater consumption due to retrofitting,
875 megawatts of capacity are reported by the southeastern
Electric Reliability Council to be planning once-through
freshwater cooling out of a total of 8,919 megawatts to be
added from 1973 to 1978.
Reported under FPC Docket R-362, April 1, 1974, Order No.
383-3, Appendix A-l are cooling methods for projected
generating unit additions, 300 megawatts and larger, for the
period 1974-1983, for the entire U.S. Closed-cycle sytems
total 181,702 megawatts and once-through systems (including
many salt water systems) total 51,265 megawatts. Closed-
cycle systems represent approximately 75 percent of the
added generating capacity reported for this period. In
summary, in all the regions where Reference 441 indicated
that retrofitting would add to the year 2000 freshwater
deficit, consideration of applying saltwater towers to once-
through saline systems, identification of cooling lakes
which had been accounted for as once-through freshwater
systems, utilizing for projections cooling systems mixes
based on regional reliability council reports rather than
projecting the 1970 mix, and exclusion of the older, smaller
generating units results in no indication of a significant
contribution to freshwater deficits due to retrofitting.
664
-------
Slowdown
In the closed cooling systems utilizing evaporative cooling,
there is a buildup of dissolved and suspended solids,
including water treatment chemicals, due to evaporation,
which removes pure water, leaving the above constituents
behind. Without some control over this buildup, scale and
corrosion may occur, damaging the equipment and reducing its
performance. To prevent excessive buildup, a small
percentage of the water is continually removed from the
circulating water system. This is normally called "tower
blowdown" or "blowdown". The water that is added to replace
this water, and the evaporative, drift and leakage losses,
is known as makeup. The amount of blowdown is dependent on
two factors. The primary factor is the avoidance of scale
or other detrimental effects in the circulating water
system. Of secondary importance is the quality of the
blowdown water. The two types of scale normally encountered
are CaCOj and CaSOU. The CaCO3 can be controlled by pH
adjustment, with sulfuric acid normally being used to lower
the pH. The CaSOU scale formation is avoided by maintaining
the concentration~of CaSOU below saturation. The CaSOU
concentration is controlled by the amount of blowdown. Thus
the amount of blowdown varies with the concentration of
dissolved solids in the makeup water. The blowdown on fresh
water towers amounts to on the order of 2% of the total flow
through the tower. With some types of water, blowdown rates
of less than 1% may be used. The blowdown rate is normally
determined by the number of concentrations of dissolved
salts allowed 'in the circulating water system.
Concentrations of 10 or less are common, with concentrations
as high as 20 being used.
Use of salt water makeup in ccoling towers would decrease
the number of permissible concentrations, increasing the
blowdown rate. A blowdown rate equal to the evaporation
rate would result in a blowdown twice as concentrated as the
makeup. In addition to concentrated salts, this blowdown
will have the chemicals used to treat .the water to prevent
corrosion and algae growth in the system. While chromates
were previously used to a large extent, their use has de-
creased in recent years with the availability of other types
of corrosion inhibitors.
Technology is currently available to control and treat
pollutants in blowdown, to levels up to and including no
discharge of pollutants. See Part A of this report for a
description of the technology related to pollutants in
blowdown.
Blowdown removed from the hot side of the circulating system
is advantageous to the plant, as the heat in the blowdown
665
-------
does not have to be removed in a tower. However, it is a
better environmental practice to discharge blowdown from the
cool side. The percentage of heat involved is in the order
of 2^> of the total, and the thermal discharge could be
correspondingly further reduced. The blowdown would
normally be at a higher temperature than the receiving body,
even if taken from the cool side, since the approach is to
the wet bulb temperature, not the receiving water
temperature.
Aesthetic Appearance
In addition to all the other factors described, the visual
impact of. the cooling system could be of concern to the
neighboring residents and visitors. Cooling towers create
two types of aesthetic impact. First, the large size of
natural draft towers will dominate most settings in which
they are placed. In this regard, natural draft towers can
be as high as a 50 story building and cover an area at the
base equivalent to several football fields. In all
applications, they will dwarf the associated powerplant.
Mechanical draft towers, on the other hand, are considerably
smaller in height than the natural draft towers, although
the aggregate base area of a multicelled unit may be larger
than the base area of a natural draft unit for the same size
plant. Therefore mechanical draft towers will not be as
objectionable in this regard as will natural draft towers.
The second type of aesthetic impact is common to both types
of towers. This impact is caused by the visible plume that
can be generated by both types of evaporative systems where
plume abatement is not employed. Cooling tower plumes will
sometimes be larger than the stack emission from a fossil-
fuel plant, especially in areas of high fogging potential.
At some plants cooling tower plumes can be so insignificant
that they escape notice by many viewers. Some cooling tower
plumes, however, can be visible for several miles and be
noticed even where the surrounding topography completely
hides both the plant and the tower. As with fogging, plume
abatement technology is available at moderate cost.
The question of whether a tower or its plume creates an
adverse aesthetic impact is a subjective issue since the
sensibilities of individual viewers varies widely. There
are those who believe that all cooling towers create a
visual nuisance. Others have expressed the opinion that the
hyperbolic shape of cooling towers is visually pleasing.
The aesthetic impact of cooling towers is not necessarily a
function of urban or rural location as some nave suggested.
666
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Discussions with utility representatives revealed as much
opposition to cooling towers placed in rural settings such
as along the California Coast and in scenic areas such as
the Hudson River, as was voiced over towers placed in urban
areas.
The impact of cooling tower aesthetics can effect the
application of cooling towers at existing plants as well as
at new sources. With existing plants locational factors
will have been fairly well established and relatively little
flexibility in the placement of the tower will be possible
compared to new plants. The most critical plants will be
those which are located in areas of mixed zoning. Residents
of those areas which have accepted a powerplant in close
proximity to their homes may object to the additional impact
of a massive structure and a new, large, visible emission.
In terms of aesthetic impact the mechanical draft tower is
superior to the natural draft tower. The physical size of
these units is much smaller than the natural draft tower and
the mechanical draft tower can be fitted with plume
suppressive equipment which is not yet available for natural
draft towers. It is anticipated that this latter difference
will be corrected in the near future. It may be that
another type of evaporative cooling could be substituted for
the tower in some instances. It is also noted that the fan-
assist modification to the natural draft tower can
substantially reduce its size.
For new plants where the location, site layout and archi-
tectural plan have not been finfelized, considerably more can
be done to abate adverse aesthetic impact than is possible
at existing plants. In addition to the selection of a less
imposing cooling system where possible, and the installation
of plume abatement systems, the site location can be
selected to reduce the cooling tower visual ar les to a
minimum. The site layout can be used to place natural
barriers between the tower and the surrounding land uses. A
pleasing grouping of building and common architectural
treatment can be used to blend the facility into its
surroundings.
Mechanical draft towers will more easily fit into the sur-
rounding area. Plant nc . 2612 is using the low hills sur-
rounding the plant to almost completely screen the towers
from view. Landscaping can hide or blend the towers into
other types of terrain. Painting the towers can aid in
making their appearance more pleasing.
Cooling lakes, if sufficiently large, can serve as
recreation sites. With appropriate landscaping and
667
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structures, camping, boating, swimming, and fishing can be
accommodated. One utility leases summer cabin sites along
its cooling lake. Being low, these lakes normally blend
well into the landscape. Landscaping of cuts and fill areas
will normally be required.
Spray canals can be very pleasing to the eye if properly de-
signed. Appropriate landscaping can hide the canal banks
and power distribution systems. The sprays themselves can
be attractive if arranged in a symmetrical pattern. They
can be decorative, and be a definite asset to the plant's
appearance.
In summary, aesthetics is not a national-scale problem. In
cases where aesthetic impacts of towers and plumes could
occur, alternative technologies are available and plume
abatement technology is available at moderate incremental
cost. New plants have the added flexibility of site
selection to help minimize this problem.
Icing Control
Icing can result from the operation of cooling towers in
cold weather. Ice formation is usually confined to the
tower itself and adjacent structures within the plant
boundaries. No cases of tower related ice formation at
locations external to the plant are known to have been
reported. Therefore, icing is an operational problem of the
cooling system similar to the control of biological growths
in the system rather than a nonwater quality environmental
impact.
Control of cooling tower ice formation can be obtained by
providing appropriate features in the tower design and
employing certain procedures in tower operation during
periods of cold weather. In the case of mechanical draft
towers, ice formation in the louvers can be melted by
periodically reversing the fans to drive air across the hot
water and through the louvers. Louvers can also be di-iced
by flooding them with hot water which is deliberatly spilled
from the outer edge of the water distribution basin and
allowed to cascade down over the louvers. In some instances
louver icing can be controlled by concentrating the hot
water load on the outmost segments of the fill during cold
weather. This is accomplished by means of partitioned
distribution basins and water distribution systems which
allow for flexibility in the distribution of the water load
over the fill area. For hyperbolics this is achieved by
providing an annular channel at the outside edge of the fill
668
-------
and a distribution system which can divert a large fraction
of the hot water into this channel.
During cold weather an annular segment of the fill of a
cross flow hyperbolic or one or more cells of mechanical
draft units may be taken off line. The resulting increased
water loading also serves to reduce tower icing. In some of
the new designs for hyperbolics, the fill is completely
bypassed during periods of very cold weather and small plant
loads.
Non-Water Quality Environmental Aspects of Spray Cooling
Systems
The text of this subsection is exerpted from Reference U05.
Ceramic Cooling Tower Co. presents a pseudo-technical
comparison, using known psychrometric principles, to display
the relative magnitude of fog intensity and frequency
probability between conventional cooling towers and powered
spray modules. Superiority of the spray is rationalized
qualitatively by comparing such apparent differences as: (a)
Sprays provide substantially greater area and air volume for
head dissipation of identical duty; (b) Air discharged from
the spray is not as near saturation as that from a tower;
(c) Temperature of air in tower exhaust is close to water
temperature but downwind of spray the air temperature is
significantly less.
Extensive winter tests of one Cherne Thermal Rotor module
were sponsored by 31 electric companies. On approximately
15 mornings when natural fog was present, observable amounts
of fog continued to be produced by the Rotor for 10-15
minutes after natural fog lifted. With winds less than 15
miles per hour (<^.3 kn) and air temperature less than 10°F
(-12°C) hoarfrost (rime ice) was observed to a maximum of
about 100 ft (30 m). Ice accumulated to several inches on a
embankment about 20 ft (6 m) from the edge of the spray
pattern.
Commonwealth Edison of Chicago (Illinois) contracted
detailed micrometeorological studies of a cooling lake and
test sprays at a plant in Illinois. Although the effects of
the sprays are difficult to isolate from the total,
observations made near the sprays may be useful. The
highest frequencies of steam fog occured in the early
morning. The overwhelming majority of steam fog observed
remained aloft. Fog travelled at or near ground level 150
ft (46 m) or more, for short periods of time, on 60 days out
of U56 from January, 1972, through March, 1973. Only 10 per
669
-------
cent of the extrusions were more than 175 ft (53 m). Six
times rime ice deposited at a distance of 150 ft (46 m) or
more; a maximum distance occurred twice at 425 ft (130 m) .
On two occasions during winter months a very light trace of
snow was observed to fall out of the steam fog.
Little objection is raised concerning environmental effects
of drift from freshwater systems, but some concern is
expressed for salt water systems because of potential
damages to surrounding area from the fallout of salt. Data
presented here were obtained by different methods and may
not be comparable.
Ceramic reports that the composite of substantial testing at
various sites of generally full scale systems, under
numersous atmospheric conditions, indicates that measureable
drift, during any meaningful time period, does not exceed a
distance of 600 ft (183 m) from the sprays. These tests are
based on dissolved solids fallout into collection pans of
accurately determined area of controlled time periods.
Average curves are presented for 1, 2, 4, and 6 units
arranged axially perpendicular to the predominant wind
direction. These curves show, for example, that one module
with 10 MPH (8.6 kn) wind will deposit 0.002 gal/day/sq ft
(0.082 1/day/sq m 100 ft (30m)) from the spray. Deposition
with multiple modules is not linear; six modules will
deposit about 0,004 gal/day/sq ft). "Drift Multipliers" for
approximating deposition at different wind speeds are
presented; these range from about 0.1 for 3 MPH (2.6 kn) to
2.2 for 15 MPH (13 kn).
Cherne presents a graph of maximum deposition rate as
function of distance for winds up to 14 MPH (12 kn). At 100
ft (30 m) from the Rotor the maximum rate is 0.05 Ibs/hr/sq
ft (5.86 1/day/sq m). At about 470 ft (143 m) the rate is
0.0004 Ibs/hr/sq ft (0.047 1/day/sq m), which is the
resolution limit of the test. The tests involved collecting
samples of droplet fallout over short time periods in glass
petri dishes and immediately weighing on precision
laboratory balance. Surprisingly, little correlation with
wind speeds up to 14 MPH (12 kn) was noted.
Richards approximates the drift emission characteristics, or
the amount carried away, in contrast to deposition. The
analysis is based on drop size distribution and particle
transport theory. The investigators point out that there
are no data available on either drop sizes or distribution
to be expected from breakup of massive sprays. However,
estimates of drop size distribution were made by analyzing
close-up photographs of sprays. These estimates agreed well
670
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with those predicted by Fan Jet theory. Turbulent effects
in vertical directions were ignored but compensated by other
conservative assumptions in the calculations.
Drift emission characteristics are presented graphically in
units of amount of suspended spray at various distances as a
function of different wind speeds. It is difficult to
summarize this complex graph, but typical numbers for a
single module are as follows: a 5 MPH (4.3 kn) wind carries
10 Ibs/hr (U.5 kg/hr) of spray a distance of 100 ¥t (30 m);
a 20 MPH (17 kn) wind carries the same amount to 500 ft (152
m) .
•
Measurements made for Ceramic during operation of full scale
PSM systems in various terrain situations indicates that the
sound pressure level from operation of the full system
reaches background level at 200-250 ft (61-76 m) when wind
was calm to 5 MPH (4.3 kn). The octave band level is rather
flat with a maximum around 425 Hertz. Tests with 14
Richards modules indicate attenuation to background at about
2,000 ft (610 m). No wind data are presented. Octave band
level near the sprays is rather flat also, with the maximum
around 500 Hertz. Higher frequencies decrease with
increasing distance.
Spray cooling requires less than 5 percent of the land area
of a cooling pond for the same cooling duty. No chemical
additives to the circulating water are required by spray
equipment. Consequently, possible air or water pollution by
such additives is not a problem. Under summer operating
conditions 80-90 percent of cooling is accomplished by
evaporation; less for annual average conditions.
Hoffman gives an excellent summary of spray systems. In it
he concludes: "It is the opinion of this author that
floating spray modules commercially available are an
attractive alternative when designing powerplant condenser
cooling systems. The thermal performance of such systems is
predictable and measurable. The adverse environmental
effects caused by spray systems can be largely mitigated by
careful design procedures and by taking advantage of the
operating flexibility that is inherent in spray canal
systems."
The data presented to date substantiate Hoffman's
conclusion. The major deficiency at this time is the
prefection and verification of models to predict drift
transport.
671
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The U.S. Environmental Protection agency has begun studies
in co-operation with Florida Power and Light Company on salt
water cooling at the Turkey Point Station near Miami
(Florida). These studies will include ambient (natural) air
chloride concentration and deposition, salt water drift
emissions from mechanical draft towers and spray modules,
fallout characteristics, and terrestrial effects on native
and cultured vegetation.
Ashbrook Corporation has entered into a co-operative program
in New York State University. The purpose is to determine
quantitatively ice formation and drift deposition rates as
functions of distance from the spray source.
Detroit Edison and its consultants are continuing to study
environmental effects of cooling system alternatives.
Non-Water Quality Environmental Aspects of Surface Cooling
The text of this subsection is exerpted from Reference 413.
In cooling ponds, evaporation is one of the main mechanism
in the dissipation of waste heat load and this takes place
at the water surface. If subsequent condensation occurs, it
will take place not far above the water surface. Induced
fogs (and freezing fogs) formed in this way may drift
downwind and reduce visibility. Evaporation of heated
effluent from once-through cooling systems would produce the
same effects.
There is a lack of information on the frequency, intensity,
and inland penetration of cooling pond-induced fogs.
Reported observations at existing cooling ponds indicate
that the fog, categorized as thin and wispy, will not
penetrate inland more than 30.5 to 152.5 m (100 to 500
feet)*14; although under severe conditions fog may extend
from 3 to 18 km (1.86 to 11.2 miles). Ice crystals
suspended in the atmosphere have also been observed. The
particular danger associated with freezing fog is that the
supercooled droplets, coming into contact with solid
surfaces, freeze immediately and form a thick and smooth
layer of ice. This could be a hazard on road surfaces.
Any increase in local fog or clouds created by either
cooling ponds or towers will lead to a decrease in the
amount of solar radiation, including ultraviolet radiation,.
received at the surface*1*.
Recent studies*1* on the severity of fogging caused by warm
water lagoons used for power station cooling show that
672
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steaming increases as the humidity increases, and the air
temperature decreases.
Comparison of Control Technologies
The available control and treatment technologies for
effluent heat are compared in Table B-VIII-30 based on
incremental costs (production, capital, fuel, and capacity),
effluent reduction benefits, and nonwater quality
environmental impacts.
Costs Versus Effluent Reduction Benefits
A study was made *s* of the incremental costs of controlling
at various levels the quantity of heat discharged into a
river (in Belgium) by a lOOOMw nuclear unit, using a once-
through system as a base. See Figure B-VIII-30. Various
methods were assumed for achieving successive incremental
reductions in effluent heat., as shown in Table B-VIII-31.
The incremental costs of each successive effluent heat
reduction are also given in the table compared to the
percent effluent heat reduction that would be attained. The
table shows that the incremental costs are lowest in
relation to the effluent reduction benefits for the
incremental heat removal with the closed circuit employing
simple treatment of make-up water. To achieve a 95.8
percent effluent heat reduction the incremental costs would
be 86.2 percent of the incremental costs of 100 percent heat
reduction.
The incremental costs (production, capital, fuel, and
capacity), and costs versus effluent reduction benefits of
the application of mechanical draft evaporative cooling
towers to nonnew nuclear units and fossil-fueled units
(base-load, cyclic, and peaking) with various years of
remaining service life is shown in Table B-VIII-32. A
similar costs breakdown for new units is given in Table B-
VIII-33. Both tables indicate the assumptions used in the
cost analyses.
In general for nonnew sources, the total costs of the
application of thermal control technology in relation to the
effluent reduction benefits to be achieved from such
application are the most favorable for the newest, most
highly utilized generating units, and, progressively, the
least favorable for the oldest, least utilized generating
units. For new sources the costs versus effluent reduction
benefits are even more favorable due to the absence of
"backfitting" costs of any kind, which would be a major cost
for nonnew sources. In the intermediate case of a nonnew
673
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TABLE B-VIII-30
CONTROL AND TREATMENT TECHNOLOGIES FOR HEAT
COSTS, EFFLUENT REDUCTION BENEFITS, AND NON-WATER QUALITY ENVIRONMENTAL IMPACTS
TECHNOLOGY
(Approx. no. of units
employing technology)
Once-Through ( 2500 )
Process Change (0)
Surface Cooling (100)
Unaugmented
Augmented
Evaporative (Wet) Tower
Mechanical Draft{250)
Natural Draft (60)
Dry Tower ( 1 )
Wet/Dry Tower (1)
Alternative Processes
Hydroelectric UOO ' s )
Internal CombustionClOO' s
Combined Cycle (approx. 50) a
INCREMENTAL COST FOR MAX. EFFL. RED.
% Base
Production
0
100
10-20
10-20
10-20
10-20
20-40
14-28
0
100
Capital
0
100
9-14
9-14
9-14
9-14
11-16
10-15
0
100
pp 50 app 50
Fuel
0
Capacity
0
ISgain ISgain
1-2
1-2
1-2
1-2
4-5
2-3
lOOgai
0
app 50gai
3-4
3-4
3-4
3-4
7-10
4-5
n 0
0
n 0
BFBL. RED. BENEFITS
% Base
0
15max
0-100
0-100
0-100
0-100
0-100
0-100
0-100
0-100
app 50
NONWATER ENVIRONMENTAL IMPACTS
% Base
Fog
0
0
0
*
*
0
0
0
0
0
0
Drift
0
0
0
*
*
Noise
0
0
0
0
*
0 ! 0
0
*
. 0
0
*
*
0
*
Aesthetics
0
0
0
*
*
*
0
0
0
0
Land
0
0
2000
1000
30
30
30
30
Water Consumption
0
0
100
200
200
200
30gain
35
2000 • SOgain
0 lOOgain
0 * 0 ' 0 SOgain
* Note: Some highly site-specific incremental impacts, but not generally anticipated to be limiting.
-------
1000 Mw nuclear unit
X
CO
-p
w
o
o
c
o
100 200 300 400
HEAT DISCHARGE DTTO TI-HD Rr/ER IN Meal/sec
500
AB - Closed circuit with decarbonation of the
malce-up water
BC - idem - simplified treatment
CD - H? - Lliyed circuit
DE - Cooling on discharge
0ii circuit
Figure B-VHI-30 Additional Cost Versus Heat Discharged
456
675
-------
Table B-VIII-31
COST VERSUS EFFLUENT REDUCTION BENEFITS, 0-100 % REMOVAL OF HEAT
Basis: Figure B-VIII-30 (Reference 456)
Cooling Method
\
Base: Open circuit
(once- through)
Cooling on dis-
charge (once-
through with
"helper")
Mixed circuit
(partial recycle
of water cooled
by the tower)
Closed circuit
with simple
treatment of
make-up water
Closed circuit
with decarbon-
ation of make-
up water
Effluent Heat Reduction,
% of base heat discharged
Incremental
0
8.5
63.9
23.4
4.2
Accumulated
0
8.5
72.4
95.8
100
Incremental Cost,
% of total incremental cost
for 100% heat reduction
Incremental
0
19.8
53.5
12.9
13.8
Accumulated
0
19.8
73.3
86.2
100
Incremental Cost,%
Incremental Heat Reduction, %
Incremental
-
2.33
0.84
0.55
3.29
Accumulated
-
2.33
1.01
0.90
1.00
-------
TABLE B-VIII-32
INCREMENTAL COST OF APPLICATION OF MECHANICAL DRAFT EVKPORATIVE COOLING TOWERS TO
NONNEW UNITS (BASIS 1970 DOLLARS)
TYPE UNIT REMAINING LIFE
Years
I. Nuclear 30-36
(All base-load) 24-30
18-24
12-18
6-12
0-6
Average excl. 0-6
II. Fossil-Fuel
A. Base-Load 30-36
24-30
18-24
12-18
6-12
0-6
Average excl. 0-6
B. Cyclic 30-36
24-30
18-24
2 12-18 '
-1 6-12
0-6
Average excl. 0-6
C. Peaking 30-36
24-30
18-24
12-18
6-12
0-6
Average excl. 0-6
INCREMENTAL PRODUCTION COSTS
% of Base Cost
13
14
15
16
19
30
15
11
12
13
14
16
22
13
14
15
16
18
20
30
17
40
40
45
50
60
100
47
Assumptions: TYPE UNIT Base Prod. Cost
mills/kwh
I. Nuclear 6.50
II. Fossil-Fuel
A. Base-Load 6.34
B. Cyclic 8.35
C. Peaking 12.5
Cost/Benefit
S/IMWHJ
XlO
4
5
5
6
7
11
5
4
4
4
5
5
7
4.
5
5
6
6
8
10
6
20
20
20
30
30
60
24
Base Cap. Cost
S/i™
150
120
120
120
INCREMENTAL CAPITAL COSTS
% of Base Cost Cost/Benefit
$/[MWH]
XlO
12 1
12 1
12 2
12 2
12 5
12 10
12 2
12 1
12 1
12 1
12 2
12 3
12 8
12 1.6
14 2
14 2
14 2
14 3
14 5
14 15
14 3
16 7
16 8
16 10
16 13
16 21
16 61
16 10
ADDITIONAL FUEL CONSUMPTION
% qf Base Fuel Cost/Benefit
Consumption [MWHJ /[MWHJ
xlOO
2 3
2 3
2 3
2 3
2 3
2 3
2 3
2 ' 3
2 3
2 3
2 3
2 3
2 3
2 1
2 3
2 3
2 • 3
2 3
2 3
2 3
2 T
2 3
2 3
2 3
2 3
2 3
2 3
2 3
GENERATION CAPACITY REDUCTION
% of Base Gen-
erating Capac.
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Annual Boiler Heat Rate Heat Loss Heat Converted Heat to Cooling Water
Capacity Factor Btu/ kuh Btu/kwh Btu/ kwh Btu/ kvh
0.70 10,500 200 3,500 6,800
0.77 1O,500 500 3,500 6,500
0.44 11,500 500 3,500 7,500
0.09 12.500 500 3.500 8.500
Cost/Benefit
MH/IMWII]
XlO
1
1
1
2
3
9
1.6
1
1
1
2
3
9
1.6
1
1
2
3
5
14
4
6
7
9
13
21
64
11
Cost Hcr-lacement
C3P-.C. $/ kw
^t>
90
90
90
Subscripts: F indicates electrical
calculated at 0.293 xio~
niivalence of fuel consumed, and T indicates electrical equivalence of heat rejected to cooling water. Both are
[MWHJ/Btu.
-------
TABLE 3-VIII-J3
INCREMENTAL COST OF APPLICATION OF MECHANICAL DRAFT EVAPORATIVE COOLING TOWERS TO
NEW UNITS (BASIS 1970 DOLLARS)
TYPE UNIT
I. Nuclear (All base-load)
II. Fossil-Fuel
A. Base-Load
B. Cyclic
C. Peaking
INCREMENTAL PRODUCTION COSTS
% of Base Cost
10
10
11
28
Cost/Benefit
5/tMWH]
xlO
3
3
4
13
INCREMENTAL CAPITAL COSTS
% of Base Cost
9
9
10
11
Cost/Benefit
S/IMWH]
xlO
1
2
4
18
ADDITIONAL FUEL CONSUMPTION GENERATION CAPACITY REDUCTION
% of Base Fuell Cost/Benefit % of Base Gen-
Consumption
1
1
1
1
[MWH] /[MWH]
xlOO
2
2
2
2
erating Capac.
3
4
4
4
Cost/Benefit
MW/IMWH]
XlO 1
1
1
1
4
Assumptions:
TYPE UNIT
I. Nuclear
II* Fossil-Fuel
A. Base-Load
B. Cyclic
C. Peaking
Useful Life
Years
40
36
36
36
Base Prod. Cost
mills/kwh
6.50
6.34
8.35
12.5
Base Cap. Cost
5/K.
150
120
120
120
Annual Boiler
Capacity Factor
0.70
0.77
0.44
0.09
Heat Rate
Btu/kwh
10,500
10,500
11,500
12,500
Heat Loss
Btu/kuh
200
500
500
500
Heat Converted
Btu/kwh
3,500
3,500
3,500
3,500
Heat to Cooling Water
Btu/ kwh •
6,800
6,500
7,500
8,500
Cost Replacement
Capac. s/kw
150
120
120
120
Subscripts: F indicates electrical equivalence of fuel consumed, and T indicates electrical equivalence of heat rejected to cooling water. Both are
calculated at 0.293x 10~ [MWH]/3tu.
-------
source for which construction has not been completed and
some backfitting cost attributable to construction aspects
would not occur, the costs versus effluent reduction
benefits are likewise at a level of favorability above the
typical operational nonnew source and below the new source.
For otherwise similar units, the cost versus effluent
reduction benefits are the most favorable for those that
will be the most highly utilized, or base-load units. The
costs versus effluent reduction benefits are the least
favorable for the units that will be utilized the least, or
peaking units. Cyclic units rank intermediate between
base-load and peaking units. In any case, the costs versus
effluent reduction benefits for units that are to be retired
from service within 6 years are very high when compared to
the newer units in that class of utilization (base-load,
cyclic, peaking) which have a greater remaining service
life.
Considerations of Section 316 fa)
Section 316 (a) of the Act authorizes the Administrator to
impose (on a case-by-case basis) less stringent effluent
limitations when a discharger can demonstrate that the
effluent limitation proposed for the thermal component of
the discharge from his source is more stringent than
necessary to assure the protection and propagation of a
balanced, indigenous population of shellfish, fish and
wildlife in and on the waterbody. The procedures for
implementing Section 316 (a) may extend over an estimated
time span of approximately from two months to twenty months
depending, from case-to-case, in the extent to which
additional studies are required to establish effluent
limitations based on environmental need. Correspondingly,
the timing for cases leading to significant thermal controls
could extend in some cases to the end of 1980. See Table B-
VIII-34. The Act does not authorize extentions of the
implementation dates for best practicable control technology
currently available at individual sources to dates after
July lt 1977, or for best available technology economically
achievable to dates after July 1, 1983, even in
consideration of Section 316 (a).
679
-------
Table B-VIII- 34
TIMING FOR CASES LEADING TO SIGNIFICANT THERMAL CONTROLS
ACCOMPLISHMENT
Propose effluent limitations guidelines
Propose Section 316 (a) procedures
Begin Section 316 (a) procedures
Promulgate effluent limitations guidelines
Promulgate Section 316 (a) procedures
Establish effluent limitation based
on Section 316 (a) procedures
Discharger selects control means
Discharger awards construction contract
Discharger meets effluent limitation with. . „
• Mechanical draft cooling tower
• Natural draft cooling tower
• Other means*
EARLIEST
Mar 1974
Mar 1974
Mar 1974
Oct 1974
Cct 1974
Oct 1974
Nov 1974
Feb 1975
Aug 1976
Jan 1978
Feb 1977
LIKELIEST
Mar 1974
Mar 1974
Mar 1974
Oct 1974
Cct 1974
Sep 1975
Nov 1975
Feb 1976
Nov 1977
Apr 1979
Feb 1978
LATEST
Mar 1974
Mar 1974
Mar 1974
Oct 1974
Oct 1974
Feb 1976
May 1977
Aug 1977
Aug 1979
Dec 1980
Aug 1979
00
o
* Note: Assumes two years after award of construction contract in each case.
-------
PART B
THERMAL DISCHARGES
SECTIONS IX, X, XI
BEST PRACTICABLE CONTROL TECHNOLOGY CURRENTLY
AVAILABLE, GUIDELINES AND LIMITATIONS
BEST AVAILABLE TECHNOLOGY ECONOMICALLY
ACHIEVABLE, GUIDELINES AND LIMITATIONS
NEW SOURCE PERFORMANCE STANDARDS
AND PRETREATMENT STANDARDS
Limitations
Based on consideration of the factors set forth in the Act,
the effluent limitations for thermal discharges
corresponding to the best practicable control technology
currently available, best available technology economically
achievable, and new source performance standards are
described below. No limitations on heat are prescribed for
pretreatment since this pollutant parameter is not
incompatible with municipal wastewater treatment processes.
The technological basis for limitations of no discharge of
heat is closed-cycle evaporative cooling, such as mechanical
draft and natural draft cooling towers, spray cooling
systems and cooling ponds and cooling lakes. For all new
sources the effluent limitation is no discharge of heat from
the main condenser except:
1. Heat may be discharged in blowdown from
recirculated cooling water systems provided the temperature
at which the blowdown is discharged does not exceed at any
time the lowest temperature of recirculated cooling water
prior to the addition of the make-up water.
2. Heat may be discharged in blowdown from cooling
ponds provided the temperature at which the blowdown is
discharged does not exceed at any time the lowest
temperature of recirculated cooling water prior to the
addition of the make-up water.
For all other sources the effluent limitation is no
discharge of heat from the main condensers except:
1. Heat may be discharged in blowdown from
recirculated cooling water systems provided the temperature
681
-------
at which the blowdown is discharged does not exceed at any
time the lowest temperature of recirculating cooling water
prior to the addition of the make-up water.
2. Heat may be discharged in blowdown from
recirculated cooling water systems which have been designed
to discharge blowdown water at a temperature above the
lowest temperature of recirculated cooling water prior to
the addition of make-up water providing such recirculating
cooling systems have been placed in operation or are under
construction prior to the effective date of this regulation.
3. Heat may be discharged where the owner or operator
of a unit otherwise subject to this limitation can
demonstrate that a cooling pcnd or cooling lake is used or
is under construction as of the effective date of this
regulation to cool recirculated cooling water before it is
recirculated to the main condensers.
4. Heat may be discharged where the owner or operator
of a unit otherwise subject to this limitation can
demonstrate that sufficient land for the construction and
operation of mechanical draft evaporative cooling towers is
not available (after consideration of alternate land use
assignments) on the premises or on adjoining property under
the ownership or control of the owner or operator as of
March 4, 1974 and that no alternate recirculating cooling
system is practicable.
5. Heat may be discharged where the owner or operator
of a unit otherwise subject to this limitation can
demonstrate that the total dissolved solids concentration in
blowdown exceeds 30,000 mg/1 and land not owned or
controlled by the owner or operator as of March 4, 1974 is
located within 150 meters (500 feet) in the prevailing
downwind direction of every practicable1 location for
mechanical draft cooling towers and that no alternate
recirculating cooling system is practicable.
6. Heat may be discharged where the owner or operator
of a unit otherwise subject to .this limitation can
demonstrate to the regional administrator or State, if the
State has NPDES permit issuing authority, that the plume
which must necessarily emit from a cooling tower would cause
a substantial hazard to commercial aviation and that no
alternate recirculated cooling water system is practicable.
In making such demonstration to the regional administrator
or State the owner or operator of such unit must include a
finding by the Federal Aviation Administration that the
682
-------
visible plume emitted from a well-operated cooling tower
would in fact cause a substantial hazard to commercial
aviation in the vicinity of a major commercial airport.
7. Heat may be discharged from a unit of less than 25
megawatts generating capacity or any unit which is part of
an electric utilities system with a total net generating
capacity of less than 150 megawatts.
8. Heat may be discharged from a unit of less than 500
megawatts generating capacity which was first placed in
service on or before January 1, 1974.
9. Heat may be discharge from a unit with a generating
capacity of 500 megawatts or greater which was first placed
in service on or before January 1, 1970.
Compliance dates for effluent limitations on heat for all
but new sources is July 1, 1981 except as follows:
In the event that a regional reliability council, or when no
functioning regional reliability council exists, a major
utility or consortium of utilities, can demonstrate to the
regional administrator or State, if the State has NPDES
permit issuing authority, that the system reliability would
be seriously impacted by complying with the effective date
set forth above, the regional administrator may accept an
alterna'feve proposed schedule of compliance on the part of
all the utilities concerned providing, however, that such
schedule of compliance will require that units representing
not less than 5035 of the affected generating capacity shall
meet the compliance date, that units representing not less
than an additional 30% of the generating capacity shall
comply not later than July 1, 1*82 and the balance of units
shall comply not later than July 1, 1983.
Factors
The Agency has reviewed the bases on which the thermal
limitations were determined to be applicable to units with
differing operating characteristics, climatic conditions,
and site related features. Additional distinctions among
units have been made as a result of this review. A very
large number of factors were considered including those
suggested, as potential criteria for exemption from thermal
control, by commentors who reviewed the proposed effluent
limitations guidelines and standards for steam-electric
powerplants. To address them in an orderly manner requires
683
-------
that those which serve explicitly or implicitly as a basis
for distinctions in the applicability of the requirement for
closed-cycle evaporative cooling be discussed first.
(A) Age
The cost, expressed in relation to power generated, is
inversely related to the number of years of service life
remaining for a particular generating unit. That is, the
shorter the remaining useful life over which the cost of the
cooling system may be amortized, the greater will be the
percentage of the capital cost charged against each unit of
power generated. Moreover, the shorter the remaining useful
life, the less heat will be rejected to the environment
particularly since many older units traditionally operate
only during periods of higher demand. Accordingly, the
capital cost expressed as a function of units of heat
removed will be greater for older plants.
In addition, however, the absolute cost of retrofitting
existing cnce-through units with closed-cycle cooling is
substantially greater than is the cost of installing cooling
equipment at new units. An exemption cast in terms of
remaining service life accomodates this disparity but does
so only in the most extreme cases.
In order to avoid the additional costs of conversion of
older units to closed-cycle cooling to the maximum degree
consistent with the protection of .the environment, the
Agency has expanded the exemption based on age. No unit
placed into operation before January 1, 1970 will be
required to meet the limitations on the discharge of heat.
Of the units placed into operation between January 1, 1970
and January 1, 1974 only the largest baseload units (i.e.,
those of 500 megawatt capacity or greater) will be subject
to control.
The Agency was urged to exempt all existing units from
thermal control, requiring closed-cycle cooling only of new
units. Because of the long lead times required for design
and construction of powerplants, particularly nuclear units,
and the definition of the terms "new source" and
"construction" in section 306 of the Act, this would have
resulted in confining applicability of the regulation to
units which will not commence operation until the end of the
684
-------
decade. Moreover, the units placed into service since the
start of this year and those scheduled for completion during
the next several years are typically large units. Adopting
a "new source" cutoff would exempt units exceeding 1000
megawatts, some of which will still be operating, and
discharging heat, past the year 2000. In view of the
extended periods of time during which these plants would be
operating and discharging heat, the Agency concluded that
they should remain subject to thermal control.
(B) Size
There are a very large number of small units (defined by the
Federal Power Commission as units in plants of 25 megawatts
or less and in systems of 150 megawatts total capacity or
less). Yet these systems and units represent only a very
small percentage of the total installed generating capacity
in the United States. Moreover, the potential for higher
costs due to site specific pecularities at any given unit
could be expected to be balanced by more favorably located
units in a larger utility system. In very small systems,
this expectation of counterbalancing unit costs is less
justifiable and the costs of meeting the thermal limits may
not be economically achievable. On this basis the Agency
proposed an exemption from the thermal limitations defining
best practicable control technology currently available for
existing small units and systems.
The exemption has been extended to apply to the thermal
limits required by the best available technology
economically achievable, in order to preclude the necessity
of retrofitting such small units.
The promulgated regulation makes a second distinction based
on rated capacity, or size. The effect of the revision to
the regulation described above is tc exempt from controls on
thermal discharge all units operating before January 1,
197U, except for units of 500 megawatts or greater. In the
case of such very large units, the regulation imposes
control on those placed into operation on or after January
1, 1970. An analysis of a survey of 60 plants submitted by
an industry representative during the comment period
indicates that the capital cost of retrofitting units placed
into service after January 1, 1970 is inversely correlated
with size. That is, the cost on a per kilowatt basis of
installing a mechanical draft cooling tower at a large unit.
685
-------
other factors being equal, is typically less than that
incurred by smaller units.
A 500 megawatt capacity unit's costs are approximately the
average costs of all units included in the survey; costs
will decline below the average as the size of the unit
increases.
Units of this size which are now less than five years old
may be expected to be operating for another 30 years. In
view of this extensive remaining service life, the
relatively lower retrofitting costs, and the larger volumes
of heated water discharged, the Agency has concluded that
the largest units coming on line since 1970 should be
included while smaller units, of comparable age, should not.
(C) Capacity Utilization
All generating units do not produce power at their full
capacity at all times. There are three major
classifications of powerplants based on the degree to which
their rated capacity is utilized on an annual basis.
Baseload units are designed to run at near full capacity
almost continuously. Peaking units are operated to supply
electricity during periods of maximum system demand. Units
which are operated for intermediate service between the
extremes of baseload and peaking are termed cycling units.
Generally accepted definitions term units generating 60
percent or more of their annual capacity as baseload, those
generating less than 20 percent as peaking, and those
between 20 and 60 percent as cycling.
Most large units (over 300 megawatts capacity) are baseload
units. Baseload units provide approximately 80 to 90
percent of the Nation's electric power and, account,
therefore, for approximately the same percentage of waste
heat. Because of their large size and high level of
utilization, uncontrolled heated discharges from these units
are generally considered to pose the greatest environmental
risk. •And because of their greater power output, the costs
of retrofitting cooling systems to baseload units is
considerably lower in mills per kilowatt hour than costs for
peaking or cycling units.
686
-------
Peaking units account for less than one percent of total
effluent heat from the industry. Moreover, the cost per
unit of production for thermal control is three to four
times that of baseload costs. On this basis, commenters
urged the Agency to exclude existing peaking and cycling
units from thermal control and the Agency essentially has
done so in the regulation promulgated today.
Though there is no explicit exemption based on capacity
utilization, the combined effect of the exemptions
predicated on age and size will effectively exclude almost
all existing units operating at substantially reduced
capacity factors.
Capacity utilization is related to age. With few
exceptions, units begin operation as baseload units. As
they become older and relatively less efficient, they are
replaced by newer more efficient baseload units and reduced
to cycling service. As they near the end of their service
life they are employed as peaking units. By confining the
coverage of the thermal limitations to units less than nine
months old (except for those of 500 megawatts capacity or
greater), the Agency has, in effect, excluded low capacity
utilization units. Virtually all units which have come on
line since January 1, 1970 which are in excess of 500
megawatts capacity are intended to be operated as baseload
units at the time the conversion to closed-cycle must be
effected.
(D) Units With Existing Closed-Cycle Cooling Systems
Some commenters suggested that units with existing closed-
cycle systems employing hot-side blowdown be exempted from
the requirement of cold-side blowdown.
The Agency agrees that incremental costs of converting to
cold-side blowdown for units which already have closed-cycle
systems employing hot-side blowdown is not justified in
light of the small reduction in thermal discharge that would
ensue.
687
-------
(E) Salt Drift
Although the environmental effects of saltwater cooling
towers vary from case to case depending on the sensitivity
of local environment and diverse local meteorological
conditions, experience with existing salt water cooling
towers indicates that environmental problems would be
confined to areas in close proximity to the cooling tower.
One study showed that about 70 percent of all drift mass
fell within 400 feet downwind of a typical saltwater
mechanical draft tower, well within the boundaries of most
powerplants. The same study showed that even under the most
adverse conditions, all drift droplets that would reach the
ground would do so within 1000 feet downwind. The subject
of this study was an eight-cell crossflow mechanical draft
tower designed to cool 134,000 gallons per minute of water
with the same chemical composition and salinity as seawater.
The plant was located on an estuary or bay, two miles from
the ocean. The drift rate was O.OOU percent of the
circulating water.
Airborne drift from this tower plus natural background salt
nuclei from the sea exceeded conservative damage thresholds
for foliar injury for distances up to 2200 feet downwind of
the tower. The background salt nuclei contributed over 75
percent of the salt mass causing damage at this distance
from the tower. Moreover, the fractional increase in
airborne salt concentrations due to drift at 2200 feet was
insignificant as compared with normal variations in the
background level caused by changes in atmospheric wind
conditions.
Obviously, local plant life in areas potentially affected by
salt drift from towers must be capable of withstanding these
natural airborne salt levels if they are to survive. Other
possible recipients of incremental salt drift would likewise
be affected by the natural ambient levels.
The additional cost of drift eliminators does not represent
a significant increment to total cooling system cost and
should be reflected in the cost estimates supplied by the
industry for plants representing over 12 percent of the
Nation's total generating capacity.
Potentially significant environmental damage over and above
that from ambient conditions may be expected to be confined
to areas in proximity to the tower and in the prevailing
downwind direction. The regulation therefore provides an
688
-------
exemption where land not owned by the plant is located
within 500 feet downwind of every practicable mechanical
draft tower site using saline intake water and where no
alternative closed cycle mode (such as natural draft towers
which have significantly less drift loss) is practicable.
(F) Land Availability
Some comments urged that the Agency liberalize its exemption
from thermal control for units which do not have sufficient
land on which to construct the necessary evaporative cooling
system, suggesting that where the costs of making land
available raise the total cost of installing closed-cycle
cooling above 1 mill per killowatt-hour the exemption should
apply. Others recommended that, in order not to reward
utilities for poor site planning, the determination of
sufficient land include property within two miles of the
unit whether owned by the utility or not, if it could be
acquired.
The size of the evaporative cooling tower required is
related to the generating capacity of the unit. Taking into
account the other factors which can influence tower size
(such as heat rate, climatic conditions, etc.) the Agency
has determined that 28 acres per 1000 megawatts generating
capacity is ample land on which any existing plant can
construct a mechanical draft cooling tower, the cooling
system which is most universally applicable and which
provides the basis for the Agency's cost estimates. This
conservative area-to-capacity standard is based on Federal
Power Commission estimates of mechanical draft cooling tower
land requirements and the Agency's review of mechanical
draft cooling tower land use requirements at nuclear units,
including sufficient allowances for construction and spacing
between towers.
In determining whether sufficient land is available at a
particular site the regulations require consideration of
reassignment of present land uses (parking areas, for
example) as well as the practicability of alternate
evaporative cooling systems. Natural draft towers, for
example, require less than 40 percent of the land needed for
mechanical draft towers. The judgment of whether or not the
reassignment of existing land is practicable cannot be
reduced to a single cost per unit of output figure as
suggested.
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Moreover, in many cases adjoining land may be purchased at
reasonable cost as an alternative to reassignment of
existing land uses. Nevertheless, adjacent land costs
could, in some instances, materially increase the cost of
installing closed cycle systems. Hence, the promulgated
regulations do not predicate the exemption from thermal
limitations on the acquisition of neighboring land. Instead
it is based solely on land owned or controlled by the owner
or operator of the plant as of the date of proposal of this
regulation.
(G) Aircraft Safety
Some comments urged the consideration of the possible hazard
to aircraft of steam plumes issuing from cooling towers.
An examination of this potential hazard indicated that
it is unlikely that an existing powerplant which will be
required to install a recirculated cooling water system
would pose a hazard to commercial aircraft during periods of
takeoff and landing. However, the vulnerability of aircraft
during this portion of the flight pattern requires special
consideration of cases where a substantial hazard may be
shown to exist. The promulgated regulation reflects this
consideration.
The Agency considered exempting units discharging into
oceans or coastal waters because of two reasons advanced in
comments that were received. First, because of the greater
dissipative capacity of oceans, heat discharges were said to
be less likely to cause environmental damage. Second, the
requirements of closed cycle cooling would exacerbate fresh
water shortages which could be expected in certain coastal
areas by the year 2000 during extreme low flow conditions.
No water shortage appears evident, or likely to ensue, by
the end of the century in Washington, Oregon, Northern
California, most Gulf Coast States, or the Atlantic Coast.
Moreover, the projection of increased fresh water
consumption was predicated on conversion of all existing
coastal plants from once-through saline systems to fresh
water evaporative towers and adoption of fresh water towers
by all new ocean sited plants. Such an assumption is
unrealistic, however, since salt water towers are presently
in operation and available to coastal plants in arid areas.
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Use of saline water in evaporative towers would, of course,
have no effect on the supply of fresh water.
On the other hand, there is evidence to suggest that the
discharge of heat into marine waters at sufficient depth and
distance from biologically sensitive shoreline zones may
pose considerably less of a threat to the environment than
do thermal discharges into rivers, lakes and estuaries. But
if the compatibility of thermal discharges with the
environmental integrity of aquatic communities at particular
sites can be demonstrated, a modification of the limitations
on heat may be made through the procedures established by
the Agency to implement section 316 (a). The Agency
recognized in the proposed regulation that artificial ponds
built for cooling and located on the property of the utility
constitute an acceptable process technology for the control
of heat. In response to criticisms of the lack of clarity
of the proposal, the regulation has been revised to make
clear that existing units otherwise subject to a "no
discharge" limitation on heat may discharge heat into
existing cooling lakes and ponds. Definitions of each term
have also been provided which differentiate between "cooling
ponds" (artificial water bodies constructed by means other
than impounding the flow of navigable water) and "cooling
lakes" (artificial water bodies whose construction does
entail blockage of navigable water flows) . While new units
whose cooling system involves creation of an "on stream"
cooling lake would remain subject to the limitations on heat
discharge from the condenser into such a projected
impoundment, the provisions of section 316 (a) would be
available to such units. Chemical discharges into
artificial water bodies which constitute navigable waters
under the Act must comply with the limitations on pollutants
other than heat.
The Agency is convinced that the electric utility industry
has both the economic and technological capability to
install closed cycle cooling systems on those units whose
thermal discharges are controlled by this regulation and to
do so by the compliance date established. The estimates of
reduced reserve capacity submitted were, the Agency
believes, over-stated since they assume that no units would
obtain exemptions under section 316(a). Moreover,
significant revisions to the proposed regulation have been
made to insure that the required conversion to closed-cycle
is realistic and that compliance with it entails no risk to
the continued reliable supply of electric power. First, the
number of units potentially subject to it has been reduced
drastically. Second, the date by which the largest units
are subjected to control has been extended by two years; the
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compliance date now being nearly seven years in the future.
Finally, the permit issuing authority is authorized to defer
compliance for an additional two years if, despite the above
described revision, compliance by all units in a related
system could, by virtue of outages during tie-in to the
cooling system, seriously impact system reliability. This
will permit each utility to plan, design, and construct off-
stream cooling systems at the optimum time in accordance
with planned maintenance schedules as well as in
consideration of reliability factors.
The Agency has reviewed the significance of the numerous
site-dependent factors both independently as well as their
aggregate impact. A summary of its conclusions as to the
collective significance of site dependent factors and each
individual variable follows.
(A) Site-Dependent Factors in General
During the comment period, industry representatives supplied
two sets of data on the cost of installation of mechanical
draft cooling towers. The first was a report of an
engineering firm experienced with the construction of
cooling towers. Its estimate of the capital cost of
retrofitting, on a per kilowatt basis, was only slightly
higher than that used in the Agency»s original cost
estimates of the proposed regulation.
The second was based on a survey of 60 plants, in several
utility systems, which represent approximately 12 percent of
the total steam electric generating capacity in the United
States. The average capital cost of this survey was
significantly higher than the previous industry estimate;
the disparity being accounted for by the commenter on the
ground that the higher estimates reflected additional costs
attributable to site-specific factors. The variability of
the plant by plant costs reported in the latter survey
approximates a normal distribution and ranges from about $9
per kilowatt to about $8.1 per kilowatt. The median of the
sample and the capacity weighted average cost is $21.9 per
kilowatt. The Agency adjusted its cost estimates of the
economic impact of the final regulation to a figure closely
approximating this industry-estimated cost. Only three of
the plants reported per kilowatt costs significantly above
the average value (in excess by 100 percent or more.) The
few exceptions with extraordinarily high cost per kilowatt
represent about 3 percent of the generating capacity covered
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by the sample. Since the extensive sample of cost estimates
from individual plants addresses all site dependent factors
in most instances, and includes to some extent costs
corresponding to the factors addressed specifically below,
EPA has determined that the sample adequately depicts the
effects of the total of the site dependent factors that
materially influence the costs of achieving the effluent
limitations on heat. While the estimated costs of
implementing thermal controls at three of the plants were
reported to reflect costs in excess of twice the median
cost, these incremental cost factors would not significantly
affect the economic achievability of the effluent
limitations. Favorable and unfavorable site-dependent
factors may be expected to counterbalance one another, when
applied across the several units at individual plants and
the numerous plants in an electrical generating system.
Hence, the average of the cost estimates reported in the 60
plant sample represents a realistic estimate of the
retrofitting costs likely to be encountered by any utility
system. Even in the extraordinary case of the one plant in
the 60 plant sample reporting a cost estimate of $81 per
kilowatt, the incremental cost (above that within which 95
percent of plants estimated costs reflecting site specific
factors) would not affect the economic achievability of the
thermal limitations. For example, the abnormal incremental
costs at that site ($37 per kilowatt) would add about 1 mill
per kilowatt-hour to the cost of electricity generated by
that unit. Unusual compliance costs could impact the
numerous small units or small systems more severely.
Consequently, these units have been exempted categorically
from the effluent limitations on heat.
(B) Type of Generation
In general, nuclear units reject more waste heat to
condenser cooling water than do comparable fossil-fueled
units. The Agency recognizes that the costs of installing
thermal control technology are greater for units which
reject more waste heat. Nevertheless, the cost differential
due to type of generation is approximately equivalent to the
additional waste heat discharged by nuclear plants and is
within the range of costs reflecting the normal variability
among site-dependent factors in general as discussed above.
In either case, the costs per unit of heat removed by closed
cycle cooling would be the same. Therefore, no distinction
need be made between nuclear and fossil-fueled units.
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Conversion of a nuclear unit from once-through cooling to a
closed cycle system may entail associated modifications to
the radioactive waste disposal system. Units employing
once-through cooling normally discharge treated liquid
radioactive wastes to the large volumes of non-recirculating
cooling water, relying on dilution in that stream to meet
water quality standards on the discharge of radioactive
materials. The volume of the blowdown from closed cycle
cooling may not provide sufficient dilution for this
practice to be continued. However, in three cases in which
closed cycle cooling systems were backfitted to nuclear
powerplants, none of the additional costs for radioactive
waste system modification were directly attributed to the
closed cycle backfit by the U. S. Atomic Energy Commission
in its final environmental statement. Since the Agency has
received no specific cost information concerning radioactive
waste system modification due to closed-cycle cooling system
backfitting, no incremental costs for this potential
modification have been included in the Agency's cost
estimates.
(C) Flow Rate
The cost of closed-cycle cooling equipment and the total
cost of generation are higher for units with higher flow
rates, all other factors being equal. Flow rates for a
particular unit can be reduced to some degree without
significant incremental cost to achieve the reduced flow.
In the cost analysis submitted to the Agency in support of
the proposed subcategorization criteria, the cooling
equipment costs for the cases of highest flow rate, all
other factors being equal, were less than 10 percent higher
than the average cost of all cases with various flow .rates.
Total generation cost were less than approximately 10
percent higher for the cases with the highest flow rates.
In the cost analysis for the worst combination of intake
temperature, wet-bulb temperature, and flow rate, the
equipment cost exceeded the average equipment cost by 52
percent. These variations in equipment cost are within
the range of variations in cost that are anticipated
considering the numerous factors that combine, some
favorably and some unfavorably, at each site to determine
the final cost of thermal control implementation. A 10
percent cost differential is within the range of costs
reflecting the normal variability among site-dependent
factors in general as discussed above. Therefore, no
distinction need be made for this factor.
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(D) Heat Rate
Units with high heat rates would be the most costly to
control due to the high incremental fuel cost associated
with the increased inefficiency attributable to thermal
controls. While no specific exemption is provided,
exemptions based on age and size will exclude most of the
units with high heat rates.
(E) Intake Temperature
EPA recognize that units with high intake water temperature
will incur higher costs, all other factors being equal.
This factor, however, is significant mainly . during the
months when the high intake water temperatures occur and
also for those units for which high levels of blowdown flow
are necessary, thus requiring relatively large quantities of
makeup water. It is not as significant a factor for most
units which require normal quantities of makeup water flow.
In the cost analysis submitted to the Agency in support of
the proposed subcategorization criteria, this factor all
other factors being equal, added a maximum of 20 percent in
the most extreme case to the average total thermal control
equipment cost. This 20 percent cost differential is within
the range of costs reflecting the normal variability among
site-dependent factors in general as discussed above.
Therefore, no distinction need be made for this factor.
(F) Wet-Bulb Temperature
EPA tested the significance of wet-bulb temperature as a
factor by costing various types of evaporative cooling
systems considering four geographic locations representative
of the range of wet-bulb temperatures in the United States.
The cost of cooling equipment at the most unfavorable
location based on wet-bulb temperature was 25 percent higher
than the average cost of all locations tested for conditions
otherwise identical. In the cost analysis submitted to the
Agency in support of the proposed subcategorization
criteria, this factor, all other factors being equal, added
a maximum of 24 percent to the total thermal control
equipment cost for the average of subcases covered for the
most costly case analyzed. This 21 percent cost
differential is within the range of costs reflecting the
normal variability among site-dependent factors in general
as discussed above. Therefore, no distinction need be made
for this factor.
(G) Back-End Loading
The back-end loading of a unit is the maximum steam flow
which the unit can pass through the last stage blades of the
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low pressure turbine expressed as a percentage of the
maximum steam flow through the last stage blades which the
turbine is capable of accepting.
In the cost analysis submitted to the Agency in support of
the proposed subcategorization criteria, this factor, all
other factors being equal, added a maximum of 22 percent to
the total thermal control equipment costs compared to the
average of the cases covered. The maximum cost reflected
the cost for a unit with a back-end loading of approximately
15 percent. • Generation costs in mills per kilowatt-hour for
the worst case of a 15 percent back-end loading were
estimated to be about 1 mill per kilowatt-hour. This 22
percent differential in equipment costs is within the range
of costs reflecting the normal variability among site-
dependent factors in general, as discussed above. The worst
case generation cost is in the range recommended by
industry, therefore, no distinction need be made for this
factor.
(H) Plume Abatement
Cooling towers can produce visible plumes consisting of
minute water droplets. Plumes are normally not a problem
unless they reach the ground and obstruct vision or cause
icing conditions. Under normal conditions, cooling tower
plumes rise due to their initial velocity and buoyancy and
rarely intersect the ground before they are mixed with the
ambient air and dissipated. However, under adverse climatic
conditions (i.e., high humidity and low temperature), the
moisture could produce a fog condition if it were trapped in
the lower levels of the atmosphere during an inversion,
i.e., a period of high atmospheric stability. In almost all
cases, natural draft towers are less likely to cause fogging
problems than mechanical draft towers. Even with mechanical
draft towers, in most cases fogging or icing would be on-
site (i.e., within 1000-2000 ft of the tower). Plume
abatement technology, e.g., wet-dry cooling towers, is
currently available. While wet-dry towers are more costly
than conventional wet towers, the Agency has accounted for
the cost of employing plume abatement in specific cases in
its estimate of the cost of codling tower construction.
This estimate is based on cost data supplied by industry.
The industry estimates, in turn, were developed from a
sample of 60 plants and units and the costs for 18 of the
units in the sample reflected the use of wet-dry towers.
Hence, no specific exemption based on the potential for
plume generation is warranted except where the plume
presents a substantial hazard to aircraft flight paths.
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(I) Noise Abatement Costs
EPA recognizes that incremental costs would be incurred in
cases where mechanical draft cooling towers may require
noise control. Little information is available on the cost
of implementing noise control procedures on powerplant
cooling tewers principally because it has rarely been
necessary to employ these measures, even though powerplants
with cooling towers exist in areas of high population
density. It is doubtful that there will be a significant
need for this technology as a result of this regulation,
since many plants in areas of high population density will
be exempted because of the lack of sufficient land for
closed-cycle cooling systems, because of the salt drift
exemption, or because of the exemptions based on age or
size. Furthermore, alternative thermal control technologies
may be employed that are generally quieter than mechanical
draft cooling towers. In the only case cited by commenters,
a plant in West Germany was reputed to have incurred twice
the normal capital cost for cooling towers due to the
installation of noise control equipment. This is a most
unusual case indeed. The plant cited is in West Berlin, a
politically land locked community isolated from outside
power sources. Increased demand and a paucity of available
sites required that a new plant be constructed in close
proximity to residences in an area of high population
density, hence, the need for noise abatement technology.
Furthermore, it is significant that cooling towers were
employed with noise suppressors in order to take advantage
of the site while accomodating the need to reduce noise to
locally required levels.
(J) Miscellaneous Factors
Certain additional site-dependent factors have been
suggested by commenters which should be considered in
subcategorization for effluent limitations on heat because
they can materially affect cost; existing system layout,
soil conditions, site geology, and topography. While it is
acknowledged that these factors may affect case-by-case
costs, the costs attributable to these and other site-
dependent factors have been assumed in the computation of
the economic costs of thermal control. All evaporative heat
rejection systems consume water. Even once-through systems
result in water consumption by evaporation during the
transfer of heat from the receiving water body to the
atmosphere. Consumptive use of water by mechanical draft
towers exceeds that of once-through systems by approximately
50-75 percent. Evidence received by the Agency suggested
that were all existing and new plants covered by the
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proposed regulation to install close cycle cooling, the
increase in water consumption by the year 2000 over that
which would be consumed by extrapolation of the 1970 mix of
cooling systems to the generating capacity expected to be on
line in that year, would approximate 8.5 billion gallons per
day. This projected increase, which was based on the
assumption that no plants would qualify for an exemption
under section 316 (a) of the Act during the next 25 years,
was conceded to be relatively insignificant compared to the
total water available in the United States during average
flow conditions. Federal Power Commission supplied
estimates of water consumption attributable to closed
cycling cooling suggest that the actual consumption may be
significantly lower.
However, for certain regions, the projected increase when
compared to the 10 and 20 years drought conditions, would
increase water deficits assumed to exist even in the absence
of closed cycle consumptive use. The regions of most
concern are Southern California and the Texas Gulf.
Much of the 3.8 percent increase in deficit for California
under the 20 year low flow conditions appears to be
attributable to the assumption that coastal plants will
convert to freshwater rather than saline towers. The
deficiencies of this assumption have been discussed
previously. In addition, however, the final regulation has
been revised to exempt most units constructed before 1974
from thermal control. Virtually all presently operating
coastal units (which represent nearly half of the present
generating capacity in California) will thus be exempt. To
the extent that expansion of generating capacity is composed
of new coastal units, the utility is free to select sites at
which the discharge would protect the balanced indigenous
aquatic community, thus qualifying for exemptions under
section 316 (a) and avoiding any consumptive use of
freshwater. Moreover, saltwater cooling towers could be
used at coastal sites with the result that no freshwater
would be consumed.
In other arid regions, such as Texas, use of closed-cycle
evaporative cooling systems (both towers and cooling ponds)
is already widespread for technological rather than
environmental reasons, since the available surface water
supply is not adequate for once-through cooling to be
effective. Much of the increase in the projected
consumptive use appears attributable to the assumption that
cooling towers would have to be constructed at existing man
made cooling lakes and offstream cooling ponds. The
regulation has been revised to make clear that cooling lakes
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and ponds meeting certain specifications are considered
acceptable heat abatement mechanisms and that towers need
not be constructed if such a system is in operation.
Powerplants normally place generating units out of service
on a scheduled basis for periods of a month or more in order
to perform necessary maintenance. Units may also be shut
down from time to time for unplanned maintenance. When
units are shut down, the lost generating capacity is
supplied by somewhat less efficient units within the system
or by purchase of power from outside the system. The
installation of new generating capacity in a system takes
into account, on a projected basis, the user demand in its
service area and such additional factors as scheduled
outages and probabilities of unscheduled outages. A well-
engineered retrofit design could be scheduled for tie-in to
an existing system in from one week to five weeks of actual
unit outage time. The regulation has been revised to
exclude most existing units from thermal control and to
defer the date of conversion for the remaining affected
units from 1978 to 1981. Moreover, the final regulation
incorporates commenters1 suggestions for flexibility in
further extending compliance dates in order to avoid
adversely impacting regional reliability. The Agency has
determined that tie-in outages can be scheduled concurrently
with planned maintenance in such a manner that one month
outage time would be required in addition to normal
maintenance and that replacement power during this period
can be supplied by the system's cycling units. Since no net
loss in generating capacity need occur for closed-cycle tie-
ins, there is no need for capital expenditures to be debited
against outages during construction.
The Agency estimates that the effluent limitations on heat
will increase the utility industry's capital requirements by
an additional 5.2 billion dollars by 1983, without allowing
for the reduction in capital cost which may be expected as a
result of exemptions from the thermal limitations obtained
under section 316 (a). (These and all other estimates are
expressed in constant 197U dollars). The operating
expenditures during the period 1974-1983 associated with the
thermal limitations are estimated to be 1.3 billion dollars
before 316 (a) exemptions, an increase O.U percent of total
industry operating expenses.
The fuel penalty associated with the thermal limitations
consists of additional fuel required to operate the closed-
cycle cooling system and additional fuel required per
kilowatt-hour resulting from efficiency losses due to
increased turbine back-pressure. The combined annual fuel
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penalty is approximately 3 percent. In addition, there will
be a transient 2.1 percent fuel penalty associated with
generation of interim replacement capacity during outages
for conversion to closed cycle. The fuel penalty estimated
represents approximately 16 million tons of coal (a 1.6
percent increase in projected 1983 coal consumption) and
44,000 barrels per day of oil (a 0.2 percent increase in
projected 1983 oil consumption) .
The effect of capital and generating costs for thermal
control would increase the cost of electricity to consumers
by a maximum of 2.2 percent by 1983. This price increase is
not expected to have a significant affect on the growth of
demand for electricity. Moreover, while the capital costs
are substantial in absolute terms, they represent, without
accounting for expected exemptions from thermal limitations,
approximately 3 percent of the capital which the industry is
planning to invest over the next decade for expansion of its
generating capacity. The Agency has concluded that the
industry will be able to obtain sufficient additional
capital to finance the expenditures for water pollution
control.
The costs of complying with the water pollution control
requirements are not expected to have any effect on the
production of electricity nor on employment in the industry.
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SECTON XII
ACKNOWLEDGMENTS
The development of this report was accomplished through the
efforts of Burns and Roe, Inc., and Dr. Charles R. Nichols
of the Effluent Guidelines Division. The following Burns
and Roe, Inc., technical staff members made significant
contributions to this effort:
Henry Gitterman, Director of Engineering
John L. Rose, Chief Environmental Engineer
Arnold S. Vernick, Project Manager
Phillip E. Bond, Senior Supervising Mechanical Engineer
Suleman Chalchal, Chemical Engineer
Ernst I. Ewoldsen, Senior Mechanical Engineer
William A. Foy, Senior Environmental Engineer
Dr. Benjamin J. intorre, Engineering Specialist
Paul D. Lanik, Environmental Engineer
Geoffrey L. Mahon, Mechanical Engineer
Dr. Shashank S. Nadgauda, Senior Chemical Engineer
Dr. Edward G. Pita, Senior Mechanical Engineer
Richard T. Richards, Supervising Civil Engineer
Harold J. Rodriguez, Senior Chemical Engineer
The physical preparation of this document was accomplished
through the efforts of the secretarial and other non-
technical staff members at Burns and Roe, Inc., and the
Effluent Guidelines Division. Significant contributions
were made by the following individuals:
Sharon Ashe, Effluent Guidelines Division
Brenda Holmone, Effluent Guidelines Division
Chris Miller, Effluent Guidelines Division
Kaye Starr, Effluent Guidelines Division
Alice Thompson, Effluent Guidelines Division
Nancy Zrubek, Effluent Guidelines Division
Marilyn Moran, Burns and Roe, Inc.
Edwin L. Stenius, Burns and Roe, Inc.
The contribution of Ernst P. Hall, Deputy Director, Effluent
Guidelines Division, were vital to the publication of this
report.
The members of the working group/steering committee, who
contributed in the preparation of this document and
coordinated the internal EPA review in addition to Mr. Cywin
and Dr. Nichols are:
Walter J. Hunt, Chief, Effluent Guidelines
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Development Branch, EGD
Dr. Clark Allen, Region VI
Alden Christiansen, National Environmental Research
Center, Corvallis
Swepe Davis, Office of Planning and Management
Don Goodwin, Office of Air Quality Planning and Standards
William Jordan, Office of Enforcement and General Counsel
Charles Kaplan, Region IV
Steve Levy, Office of Solid Waste Management Programs
Harvey Lunenfeld, Region II
George Manning, Office of Research and Development
Ray McDevitt, Office of Enforcement and General Counsel
Taylor Miller, Office of Enforcement and General Counsel
James Shaw, Region VIII
James Speyer, Office of Planning and Evaluation
Howard Zar, Region V
Acknowledged are the contributions of Dennis Cannon, Michael
LaGraff, Ronald McSwiney, and Lillian Stone, all formerly
with the Effluent Guidelines Division. The EPA Project
Officer also acknowledges the assistance of his wife, Janet
Nichols.
Other EPA and State personnel contributing to this effort
were:
Allan Abramson, Region IX
Walter Barber, Office of Planning and Evaluation
Ken Bigos, Region IX
Paul Brands, Office of Planning and Evaluation
Carl W. Blomgren, Region VTI
Danforth G. Bodien, Region X
Robert Burm, Region VIII
Richard Burkhalter, State of Washington
Gerald P. Calkins, State of Washington
Robert Chase, Region I
Barry Cohen, Region II
William Dierksheide, Region IX
William Eng, Region I
Joel Golumbek, Region II
James M. Gruhlke, Office of Radiation Programs
Joe Hein, Office of Water and Hazardous Materials
Joseph Hudek, Region II
Victor Kimm, Office of Planning and Management
William R. Lahs, Office of Radiation Programs
Frederick D. Leutner, Office of Water and Hazardous
Materials
John Lum, Region II
Dr. Guy R. Nelson, National Environmental Research
Center, Corvallis
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Dr. M. Perez, National Marine Water Quality Laboratory
Dr. Jan Praeger, National Marine Hater Quality
Laboratory
Ms. Lillian Regelson, Office of Water and Hazardous
Materials
Dr. Courtney Riordan, Office of Technical Analysis
Dr. Eric Schneider, National Marine Water Quality
Laboratory
William H. Schremp, Region III
Edward Stigall, Region VIJ
Dr. Bruce A. Tichener, National Environmental Research
Center, Corvallis
Dennis Tihanjky, Office of Planning and Evaluation
Srini Vasan, Region V
Dr. Joseph V. Yance, Office of Water and Hazardous
Materials
Michele Zarubica, Office of Planning and Evaluation
Additional comments were received from:
Effluent Standards and Water Quality Information
Advisory Committee
Dr. William A. Brungs, National Water Quality Laboratory
Duluth
Dr. W. D. Rowe, Office of Radiation Programs
E. David Harvard, Office of Radiation Programs
Dr. A. Gordon Everett, Office of Technical Analysis
Carl J. Schafer, Jr., Office of Enforcement and
General Counsel
Joel L. Fisher, Office of Program Integration
Jerome H. Svore, Region VII
John A. Green, Region VIII
Richard L. O'Connell, Region IX
Jack E. Ravan, Region IV
Arthur W. Busch, Region VI
Federal agencies cooperating were:
Atomic Energy Commission
National Marine Fisheries Service, National Oceanographic
and Atmospheric Administration, Department of Commerce
Bureau of Land Management, Department of the Interior
Bureau of Sport Fish and Wildlife, Department of the
Interior
Federal Power Commission .
Rural Electrification Administration, Department of
Agriculture
Tennessee Valley Authority
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Additional comments were received from:
Honorable Mike McCormack
Department of the Treasury
Water Resources Council
Department of Defense
Honorable David R. Bowen
Honorable Omar Burlesson
Honorable Harold T, Johnson
Honorable Edmund S, Muskie
Honorable Charles Wilson
Honorable James Wright
The Environmental Protection Agency also wishes to thank the
representatives of the steam electric generating industry,
including the Edison Electric Institute, the American Public
Power Association and the following utilities, regional
systems and governmental agencies for their cooperation and
assistance in arranging plant visits and furnishing data and
information.
Alabama Power Company
Bewag
Canal Electric Company
Central Hudson Gas and Electric Corporation
Central Electricity Generating Board, United Kingdom
Commonwealth Edison Company
Consolidated Edison Company of New York, Inc.
Consumers Power Company
Duke Power Company
Economic Commission for Europe, Committee on Electric
Power
Florida Power and Light company
Fremont, Nebraska Department of Utilities
MAPP Coordination center for the Mid-Continent
Area Power Systems
New England Power Company
New York Power Pool
New York State Electric and Gas Corporation
Niagara Mohawk Power Corporation
Nordostschweizerische Kraftwerke AG
Omaha Public Power District
Pacific Gas and Electric Company
Pacific Power and Light company
Pennsylvania Power and Light Company
Portland General Electric company
Potomac Electric Power Company
Preussag AG
Public Service Company of Colorado
Public Service Electric and Gas Company
Sacramento Municipal Utility District
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Southern California Edison Company
Taunton, Massachusetts Municipal Lighting Plant
Texas Electric Service Company
Vereninigte Elektrizitatswerke Westfalen AG
Virginia Electric and Power Company
Volkswagenwerk AG
Acknowledgment is also made to the following manufacturers
for their willing cooperation in providing information
needed in the course of this effort.
Allen-Sherman-Hoff
Balcke-Durr
Butterworth System Inc.
Ceramic Cooling Tower Company
Ecodyne corporation
GEA-Gesellschaft fur Luftkondensation m.b.H.
General Electric Company
Inland Environmental
Research-Cottrell, Inc., Hamon Cooling Tower Division
Resources Conservation Company
Richards of Rockford, Inc.
Stephens-Adamson
The Marley Company
Additional comments were received from:
State of California
State of Colorado
State of Illinois
State of Indiana
State of Iowa
State of Maryland
State of Michigan
State of Minnesota
State of Ohio
State of New York
Commonwealth of Puerto Rico
State of Texas
State of Wisconsin
Mississippi Power and Light Company
Arkansas Power and Light Company
West Associates
City of Colorado Springs Nebraska Public Power
District
American Electric Power Service Corporation
The Dayton Power and Light Company
International Ozone Institute, Inc.
City Public Service Board of San Antonio, Texas
The Toledo Edison Company
705
-------
Ford Motor company
Baltimore Gas and Electric Company
Jersey Central Power and Light Company
Metropolitan Edison Company
Pennsylvania Electric company
National Electric Reliability Council
Public Service Company of New Mexico
United Illuminating
Copper Development Association, Inc.
The Cincinnati Gas and Electric Company
Illinois Power Company
Indianapolis Power and Light Company
Tri-State Generation and Transmission Association,
Inc.
western Illinois Power Cooperative, Inc.
Alabama Electric Cooperative, Inc.
Wisconsin Public Service Corporation
N.W. Electric Power cooperative. Inc.
American Cyanamid Company
Carolina Power and Light Company
Foote Mineral Company
Cooperative Farm Chemicals Association
Pollution and Environmental Problems
Ebasco Services Incorporated
Brazos River Authority
Dr. Charles C. Goutant
Mr. Basil A. Bonk
Diamond Shamrock Chemical Company
Offshore Power Systems
Hawaiian Electric Company, Inc.
United for Survival
Mr. James R. Raring
Nalco Chemical company
Dow Chemical U.S.A.
Dairyland Power Cooperative
St. Joseph Light and Power Company
Burns and McDonnell Engineering Company
Bethlehem Steel Corporation
The Metropolitan Water District of Southern
California
Washington Public Power Supply System
Wright Chemical corporation
Mr. James W. Errant, Jr.
Texas Water Conservation Association
Ms. Constance A. Partious, League of Women Voters
Mr. David Allen
Mr. David B. Harvey
Mrs. Marvin Halye
Mr. Bruce Haflich
Mr. Samuel Labouisse, Jr.
706
-------
Connie Economy
Mr. Christopher A. Libby
Mr. Zachary A. Smith
Mr. Marion L. Sanford
Mr. Henry Peck
American Association of University Women
Ms. Lea P. Tonkin
Illinois Paddling Council
League of Women Voters
Mr. Roger H. Miller
Rohm and Haas Company
Mr. M. David Burghardt
Calgon Corporation
Stone and Webster Engineering Corporation
The Michigan Riparian, Inc.
Olin Water Services
Mrs. Martha K. Rudnicki
Don and Lynda Johnson
Mr. Lawrence D. Bahr
Mr. Harry L. Stout
Betz Laboratories, Inc.
Save the Dunes Council
Mr. and Mrs. John N. Lally
United Refining Company
Mr. J. C. Berghoff
Mr. Edward G. Talbot
Mr. Harlan Sandberg
Mr. Stephen C. Grado
Mr. Scott M. Bailey
Mr. David M. Peterson
Mr. David Levine
Mr. Don Pur it on
A. T. Economy and Tenya Economy
County of Monroe, New York
Mr. Steve Kraatz
Mr. R. Fenton Rood
Alaska Center for the Environment
Mrs. Marie B. Pettit
General Electric Company
Airco Alloys and Carbide
Johnson and Anderson, Inc.
Utah Power and Light Company
Middle South Services, Inc.
Natural Resources Defense Council, Inc.
Lake Michigan Federation
Mead
ECAR
Salt River Project
Houston Lighting and Power Company
Kansas City Power and Light Company
707
-------
Duquesene Light
Ohio Edison Company
Louisiana Power and Light
Arizona Public Service Company
Consolidated Edison Company of New York, Inc.
Wisconsin Electric Power Company
Toledo Edison
Arkansas Electric Cooperative Corporation
Northern States Power Company
Plains Electric Generation and Transmission
Cooperative, Inc.
Houghton Cluck Coughlin and Riley
Consumers Power Company
Bechtel Power Corporation
Buckeye Power Incorporated
Association of California Water Agencies
New Orleans Public Service, Inc.
Minnkota Power Cooperative, Inc.
Associated Electric Cooperative
Continental Can Company, Inc.
Columbus and Southern Ohio Electric Company
Dolph Briscoe, Governor of Texas
San Diego Gas and Electric Company
Quirk, Lawler and Matusky Engineers
Department of Water and Power of the City of
Los Angeles
Basin Electric Power Cooperative
Business and Professional People for the Public
Interest
Gulf Power Company
Atlantic City Electric
Southern Services, Inc.
Union Electric Company
E.I. du Pont de Nemours Company, Incorporated
Tucson Gas and Electric Company
California Farm Bureau Federation
Regional Planning council
Mr. Mayne E. Boiling
University of Texas
Mr. & Mrs. William Morlock
Ms. Alice Thornycroft
Mr. & Mrs. Fred and Peggy McAllister
Mrs. Robert Burke
Ms. Catherine Benner
Mr. Frank Lahr
Mr. & Mrs. Robert Upton
Dr. & Mrs. Dean Asasselin
Dr. & Mrs. D. Steinberg
South Texas Electric Cooperative, Inc.
Olin Brass
708
-------
Eastern Iowa Light and Power Cooperative
Shoreline Garden Club
Mr. Lawrence C. Frederick
Edison Electric Institute
National Rural Electric Cooperative Association
The Utility Water Act Group
Newberry Electric Cooperative
State of South Carolina
State of Arizona
Atomic Industrial Forum, Inc.
Delaware River Basin Commission
Montana-Dakota Utilities
E. B. Puspley
West Texas Utilities Company
Southern Electric Generating Company
John Eric Edinger, Ph.D.
North Central Missouri Electric Cooperative, Inc.
NUS Corporation
Texas Power and Light Company
Tennessee Valley Public Power Association
Southwestern Electric Power Company
Allegheny Power Service Corporation
Southern Central Power Company
Interlakes, Inc.
Missouri Clean Water Commission
Dallas Power and Light Company
Cajun Electric Power Corporation
Crawford Electric Cooperative
Dixie Electric Membership Corporation
Association of Illinois Electric Cooperatives
Rural Electric Convenience Cooperative Company
People»s Cooperative Power Association, Inc.
Jefferson Davis Electric Cooperative, Inc.
State of North Carolina
State of Nebraska
State of Kentucky
State of Georgia
Golden Valley Electric Association, Inc.
Hudson River Fisherman's Association
North Pine Electric Corporation, Inc.
Carteret-Craven Electric Membership Corporation
State of Pennsylvania
Public Service Comapny of New Hampshire
Jo-Carroll Electric Cooperative, Inc.
Roanoke Electric Membership Corporation
Tri-county Electric Cooperative
Plains Electric Generation and Transmission
Cooperative
Pierce-Pepin Electric Cooperative
Tri-County Rural Electric Cooperative, Inc.
709
-------
Union Rural Electric Association, Inc.
Western Illinois Power Cooperative, Inc.
Edgecomb-Martin County Electric Membership
Corporation
Burke Divide Electric Cooperative
Renville Sibley Cooperative Power Association
State of Alaska
State of Hawaii
710
-------
SECTION XIII
REFERENCES
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Southern Nuclear Engineering, Inc., Edition No. 5,
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2. "A Method for Predicting the Performance of Natural Draft
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3. "A Potassium Cycle Boosts Efficiency", Business Week,
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i*. "A Report by MARCA to the Federal Power Commission
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5. "A Summary of Environmental Studies on Water Problems",
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7. "A Survey of Alternate Methods for Cooling Condenser
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9. "A Survey of Alternate Methods for Cooling Condenser
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10. "A Survey of Thermal Power Plant Cooling Facilities",
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711
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11. Abrahamson, D. E., "Environmental Cost of Electric Power",
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12. "Advanced Nonthermally Polluting Gas Turbines In Utility
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1968) .
14. Albrecht, A. E., "Disposal of Alum Sludges", Journal AWWA,
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17. "1972 Annual Report of National Electric Reliability
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18. Argo, D. G., and G. L. Gulp, "Heavy metals removal in
wastewater treatment processes: Part 1, Water and
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19. Aschoff, A. F., "Water Reuse in Industry", Mechanical
Engineering, pp. 21-25, (April, 1973).
20. Askew, T., "Selecting Economics Boiler-Water Pretreatment
Equipment", Chemical Engineering, Vol. 80, No. 9,
pp* 114-120, (April 16, 1973).
21. Aynsley, E., and M. R. Jackson, "Industrial Waste
Studies: Steam Generating Plants", Draft Final Report,
Contract No. EPA-WQO 68-01-0032, for Water Quality
office, EPA, Washington, D.C., (December 31, 1970
through May 28, 1971).
22. Christiansen, P. B., and D. R. Colman, "Reduction of Slowdown
from Power Plant Cooling Tower Systems", American Institute
of Chemical Engineers Seminar or Cooling Towers, Houston,
Texas (1968) .
712
-------
23. Beall, S. E., Jr., "Uses of Haste Heat", Research
sponsored by the U. S. AEC under contract with the
Union Carbide Corporation, (November 3, 1969).
2U. Beall, S. E., Jr. and A. J. Miller, "The Use of Heat
as well as Electricity from Electricity Generating
Stations", paper presented at Annual meeting of American
Association for the Advancement of Science at the
Symposium on the Energy Crisis, Philadelphia, Pa.,
(December 29, 1971).
25. Beardsley, J. A., "Use of Polymers in Municipal Water
Treatment", Journal AWWA, 65:1:85 (January, 1973).
26. Berthoulex, P. M., "Evaluating Economy of Scale",
Journal WPCF, Vol. HH, 11, pp. 2111-2119, (November, 1972)
27. Betz Handbook of Industrial Water Conditioning* Beta,
Pennsylvania, Sixth Edition, (1962).
28. Bishop, D. F., et al, "Physical-Chemical Treatment of
Municipal Wastewater", Journal WPCF, pp. 361-371,
(March, 1972) .
29. Black, A. P., "Recovery of Calcium and Magnesium Values",
Journal AWWA, pp. 616-622.
30. Boersma, L., "Beneficial Use of Waste Heat in
Agriculture", Department of Soils, Oregon State Univ.
31. "Boiler-Water Treatment", (source unknown).
32. Brady, D. K., et al, "Cooling Water Studies for Edison
Electric Institute", Research Project RP-U9, Report
No. 5, the Johns Hopkins University (November, 1969).
33. Browning, J. E., "Ash - The Usable Waste", Chemical
Engineering, (April 16, 1973).
3H. Budenholzer, R. J., et al, "Selecting Heat Rejection
Systems for Future Steam-Electric Power Plants".
Westinghouse Engineer. (November, 1971).
35. Bugg, H. M., et al, "Polyelectrolyte Conditioning of Alum
Sludges", Journal AWWA, pp. 792-795, (December, 1970).
36. Burd, R. S., "A Study of Sludge Handling and Disposal",
U. S. Department of the Interior, Federal Water Pollution
Control Administration Publication WP-20-4 (May, 1968).
713
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37. "California's Projected Electrical Energy Demand and Supply"
Assembly Science 6 Technology Advisory Council, A report
to the Assembly General Research Committee California
Legislature, (November, 1971).
38. "Canals Cool Hot Water for Reuse", Environmental Science
and TechnologY, PP- 20-21, (January, 1973) .
39. Cecil, L. K., "Water Reuse and Disposal", Chemical
Engineering, (May 5, 1969).
40. Cheremisinoff, P. N., et al, "Cadmium, Chromium, Lead,
Mercury: A Plenary Account for Water Pollution. Part I -
Occurrence, Toxicity and Detection", "Part II - Removal
Techniques", Water and Sewage Works, (July - August, 1972).
41. Christopher, P. J., and V. T. Forster, "Rugeley Dry Cooling
Tower System", Proceedings of Institution of Mechanical
Engineers, pp. 197-211, (1969-1970).
42. Christiansen, A. G., and B. A. Tichenor, "Economic
Aspects of Thermal Pollution Control in the Electric
Power Industry", FWPCA Northwest Region, Pacific North-
west Water Laboratory working Paper No. 67, (September
1969).
43. Christiansen, P. B., and D. R. Colman, "Reduction of Blow-
down from Power Plant Cooling Tower Systems", A.I.Ch.E.
Workshop, Vol. 2 - Industrial Process Design for Water
Pollution Control, Houston, Texas (April 24-25, 1969).
44. "Clean-Air Route Has Made-In Mexico Label", Chemical
Engineering, Vo.l. 80, No. 2, pp. 58-60, (January 22, 1973) .
45. "Cleaning Up SO2", Chemical Engineering,
(April 16. 19737-
46. "Cleanup System Makes Pure Processing - Water", Chemical
Engineering, Vol. 80, No. 4, p. 66, (February 19, 1973).
47. Cohen, J. M., and I. J. Kugelman, "Wastewater Treatment -
Physical and Chemical Methods", Journal WPCF. pp. 915-923,
(June, 1972) .
48. Collins, W. D., "Temperature of Water Available for
Industrial Use in the United States", (April 24, 1925).
49. "Considerations in Viewing the Role of State Government
in Energy Planning and Power Plant Siting", Assembly Science
and Technology Advisory Council, A Report to the Assembly
General Research Committee California Legislature,
(February, 1973).
714
-------
50. "Control of Air Pollution from Fossil Fuel-Fired Steam
Generators Greater than 250 x 10* Btu/Hour Heat Input",
Environmental Protection Agency, Durham, North Carolina.
51. "Control of Air Pollution from Fossil Fuel-Fired Steam
Generators Greater than 250 x 10* Btu/Hour Heat Input,
(8.0 Appendices)", Environmental Protection Agency,
Durham, North Carolina.
52. Cooling Tower Fundamentals and Application Principles,
The Marley Company (1969).
53. "Cooling Towers - Part II, Are Hyperbolics a Waste of
Money?", Electric Light and_Power, pp. 36-39, (October,
1972).
54. "Cooling Towers - Part III, Drying Op the Cooling Cycle",
Electric Light and Power, pp. 45-U8, (November, 1972).
55. "Cooling Towers", Power Engineering, pp. 30-37,
(December, 1972).
56. "Cooling Towers", Power Special Report, Power,
(March, 1973) .
57. "Cooling Towers - Special Report", Industrial Water
Engineering, (May, 1970) .
58. "Cost of Wastewater Treatment Processes", Robert A. Taft
Water Research Center, FWPCA Report No. TWRC-6, (1968).
59. Cox, R. A., "Predictions of Fog Formation Due to A Warm
Water Lagoon Proposed for Power Station Cooling",
Atmospheric Environment, Vol. 7, pp. 363-368, Pergamon
Press, (1973) .
60. Culp, R. L., "The Operation of Wastewater Treatment
Plants", Part I, II 6 III, Public Works, (October,
November and December, 1970).
61. "Cumulative Research Index to FPC Reports", Vol. 19-35,
(January, 1958 - June, 1966).
62. Curtis, S. D., and R. M. Silverstein, "Corrosion and
Fouling Control of Cooling Waters", Chemical Engineering
Progress, Vol. 67, No. 7, pp. 39-4U, (July, 1971).
715
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63. Cywin, A., "Engineering Water Resources of the Future",
Paper presented at the ASME Winter Annual Meeting,
(November, 1970).
64. Cywin, A., "Engineering Water Resources for 2070",
Mechanical Engineering, pp. 7-9, (July, 1971).
65. Dallarie, E. E., "Thermal Pollution Threat Draws Nearer",
Civil Engineering, ASCE, pp. 67-71 (October, 1970).
66. Davis, J. C., "Scrubber-Design Spinoffs from Power Plant
Units", Chemical Engineering, Vol. 79, No. 28,
(December 11, 1972).
67. Dean, J. G., et al, "Removing Heavy Metals from Waste-
water", Environmental Science and Technology, Vol. 6,*
No. 6, pp. 518-522, (June, 1972) .
68. Decker, F. W., "Report on Cooling Towers and Weather"
Report for FWPCA, Corvallis, Oregon.
69. De Filippi, J. A., "Designing Filtration Plant Waste
Disposal Systems", Journal AWWA, 64:3:185, (March, 1972).
70. De Flon, J. G., "Design of Cooling Towers Circulating
Brackish Waters", Ind. & Proc. Design for Water Pollution
Control, Workshop of AIChE, (April 24-25, 1969).
71. DeMonbrun, J. R., "Factors to Consider in Selecting a
Cooling Tower", Chemical Engineering, (September 9, 1968).
72. Derrick, A. E., "Cooling Pond Proves to be the Economic
Choice at Four Corners", Power Engineering, (November,
1963).
73. "Development and Demonstration of Low-Level Drift
Instrumentation", Water Pollution Control Research
Series, EPA, 16130 GNK 10/71 (October, 1971).
74. Dickey J. B., Jr., "Managing Waste Heat with the Water
Cooling Tower", The Marley Company (1970).
75. "Directory", Public Power, Vol. 31, No. 1, (January -
February, 1973) .
76. "Dive Into Those Intakes", Electric Light & Power,
E/G edition, pp. 52-53, (November, 1972).
77. Donohue, J. M., and G. A. Woods, "Onstream Desludging
Restores Heat Transfer", Betz Laboratories, Inc., (1967).
716
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78. Doran, J. J., Jr., "Electric Power - Impact on the
Envi ronmentn, Proceedings American Power Conference,
32, pp. 1029-1036, (1970).
79. Drew, H. R., and J. E. Tilton, "Statement of the Electric
Reliability Council of Texas (ERCOT)M at the Texas Water
Quality Board Hearing on Texas water Quality Standards,
(April 6, 1973) .
80. Drew, H. R., and J. E. Tilton, "Review of Surface Water
Temperatures and Associated Biological Data as Related
to the Temperature Standards in Texas." Presented at
Texas Water Quality Board Hearing on Texas Water Quality
Standards, (April 6, 1973).
81. Drew, H. R., and J. E. Tilton, "Thermal Requirements
to Protect Aquatic Life in Texas Reservoirs", Journal
Water Pollutign^Control Federation, (April, 1970).
82. Eckenfelder, W. w., Jr. and J. L. Barnard, "Treatment -
Cost Relationship for Industrial Wastes", Chemical
Engineering Progress, Vol. 67, No. 69, (September, 1971).
83. Eckenfelder, W. W., Jr. and D. L. Ford, "Economics of
Wastewater Treatment", Chemical Engineering,
(August 25, 1969) .
8U. Edinger, J. E., and J. C. Geyer, "Heat Exchange in the
Environment", Cooling Water Studies for Edison Electric
Institute (RP-U9), The Johns Hopkins University (1965).
85. Edinger, J. E., et al, "The Variation of Water Temper-
atures Due to Steam Electric Cooling Operations",
Journal WPCF.pp. 1632-1639, (September, 1968).
86. "Electric Power Statistics", Federal Power Commission,
(January, 1972).
87. "Electric Utility Depreciation Practices", Federal Power
Commission, (January, 1970).
88. "Electric Utilities Industry Research and Development
Goals Through the Year 2000", Report of the R&D Goal
Task Force to the Electric Research Council.
i
89. "Electrical Power Supply and Demand Forecasts for the
United States Through 2050", Hittman Associates, Inc.,
(February, 1972).
717
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90. Electrical Wgrldj Directory of Electric Utilities,
McGraw-Hill IncT, New York, 31st Edition, (1972-1973).
91. Eller, 3., et al, "Water Reuse and Recycling in
Industry", Journal AWWA, pp. 1U9-154, (March, 1970).
92. Elliott, T. C., "Options for Cooling Large Plants in
the 70's", Power, (December, 1970).
93. "Energy Crisis", Consulting Engineer, pp. 97-192,
(March, 1973).
94. "Engineering Aspects of Heat Disposal from Power Genera-
tion", Summer Seminar Program, MIT, (June 26-30, 1972).
95. "Engineering for Resolution of the Energy - Environment
Dilemma", Committee on Power Plant Siting, National
Academy of Engineering, Washington, D.C., (1972).
96. "Environmental Effects of Producing Electric Power:
Hearings Before the Joint committee on Atomic Energy
91st Congress, Second Session", Parts 162, Vol. I & II,
(October and November, 1969 and January and February, 1970)
97. "Environmental Protection Research Catalog", EPA, Office
of Research & Monitoring, Research Information Division,
Washington, D. C., Parts I 6 II, (January, 1972).
98. "Estimating Costs and Manpower Requirements for Con-
ventional Wastewater Treatment Facilities", EPA, Water
Pollution Control Research Series, 17090 DAN 10/71,
(October, 1971) .
99. Evans, D. R., and J. C. Wilson, "Capital and Operating
Costs - Advanced Wastewater Treatment", Journal WPCF,
pp. 1-13, (January, 1972) .
100. "Experimental SO2 Removal System and Waste Disposal Pond
Widows Creek Steam Plant", Tennessee Valley Authority,
(January 15, 1973) .
101. Fair, G. M., et al, "An Assessment of the Effects of
Treatment and Disposal", Water and Wastewater Engineering*
Vol. 2, (November, 1967).
102. Fairbanks, R. B., et al, "An Assessment of the Effects
of Electrical Power Generation on Marine Resources in
the Cape Cod Canal", Mass. Dept. of Natural Resources,
Division of Marine Fisheries, (March, 1971).
718
-------
103. Farrell, J. B. , et al, "Natural Freezing for Dewatering
of Aluminum Hydroxide Sludges", Journal AWWA, pp.787-791,
(December, 1970).
IOH. "Feasibility of Alternative Means of Cooling for Thermal
Power Plants near Lake Michigan", U. S. Dept. of Interior,
(September, 1970) .
105. Feige, N. C., "Titanium Tubing for Surface Condenser
Heat Exchanger Service", Titanium Metals Corp. of
America, Bulletin SC-1, (January, 1971). .
106. Feige, N. C., "Titanium Tubing Proves Value in Estuary
Application", Power Engineering, (January, 1973).
107. Ferrel, J. F., "Sludge Incineration", Pollution
Engineering. (March, 1973).
108. Final Environmental Statement, USAEC, Directorate of
Licensing;
a) Arkansas Nuclear One Unit 1
Arkansas Power & Light Co., (February, 1973).
b) Arkansas Nuclear One Unit 2
Arkansas Power & Light Co., (September, 1972).
c) Davis-Besse Nuclear Power Station
Toledo Edison Company 6 Cleveland Electric
Illuminating Company (March, 1973) .
d) Duane Arnold Energy center
Iowa Electric Light 5 Power Co.
Central Iowa Power Cooperative
Corn Belt Power Cooperative, (March, 1973).
e) Enrico Fermi Atomic Power Plant Unit 2
Detroit Edison Company (July, 1972).
f) Fort Calhoun Station Unit 1
Omaha Public Power District, (August, 1972) .
g) Indian Point Nuclear Generating Plant Unit No. 2
Consolidated Edison Co. of New York, Inc., Vol. 1
(September, 1972) .
h) Indian Point Nuclear Generation Plant Unit No. 2
Consolidated Edison Co. of New York, Inc., Vol. II
(September, 1972) .
719
-------
i) James A. Fitzpatrick Nuclear Power Plant
Power Authority of the State of New York,
(March, 1973) .
j) Joseph M. Farley Nuclear Plant Units 1 and 2
Alabama Power Company (June, 1972).
k) Kewaunee Nuclear Power Plant
Wisconsin Public Service Corporation,
(December, 1972) .
1) Maine Yankee Atomic Power Station
Maine Yankee Atomic Power Company (July, 1972).
m) Oconee Nuclear Station Units 1, 2 and 3
Duke Power Company (March, 1972) .
n) Palisades Nuclear Generating Plant
Consumers Power Company (June, 1972) .
o) Pilgrim Nuclear Power Station
Boston Edison Company (May, 1972).
p) Point Beach Nuclear Plant Units 1 and 2
Wisconsin Electric Power Co. and
Wisconsin Michigan Power Company (May, 1972).
q) Quad-Cities Nuclear Power Station Units 1 & 2
Commonwealth Edison company and the
Iowa-Illinois Gas and Electric Company
(September, 1972).
r) Rancho Seco Nuclear Generating Station Unit 1
Sacramento Municipal Utility District, (March, 1973)
s) Salem Nuclear Generating Station Units 1 & 2
Public Service Gas & Electric Company (April, 1973).
t) Surry Power Station Unit 1 *
Virginia Electric and Power Co., (May, 1972).
u) Surry Power Station Unit 2
Virginia Electric & Power Co., (June, 1972).
v) The Edwin I. Hatch Nuclear Plant Unit 1 & 2
Georgia Power Company (October, 1972).
w) The Fort St. Vrain Nuclear Generating Station
Public Service Company of Colorado, (August, 1972).
720
-------
x) Three Mile Island Nuclear Station Units 1 and 2
Metropolitan Edison Company Pennsylvania Electric
Company Jersey Central Power and Light Co.,
(December, 1972).
y) Turkey Point Plant
Florida Power and Light Co., (July, 1972).
z) Vermont Yankee Nuclear Power Station
Vermont Yankee Nuclear Power Corporation, (July, 1972)
aa) Virgil C. Summer Nuclear Station Unit 1
South Carolina Electric 6 Gas Company (January, 1973) .
bb) William B. McGuire Nuclear Station Units 1 and 2
Duke Power Company (October, 1972)
cc) Zion Nuclear Power Station Units 1 and 2
Commonwealth Edison company (December, 1972).
dd) Monticellc Nuclear Generating Plant
Northern States Power Company (November, 1972).
ee) Shoreham Nuclear Power Station
Long Island Lighting Company (September, 1972) .
109. Final Environmental statement, Watts Bar Nuclear Plant
Units 1 and 2, Tennessee Valley Authority
(November 9, 1972) .
110. Fitch, N. R., "Temperature Surveys of St. Croix River",
for Allen S. King Generating Plant, Minn.,
(December 31, 1970) .
111. Flaherty J. J., "Fiscal Year 1973 Authorization
Hearings", by the Joint Committee on Atomic Energy
pp. 1-12, (February 3, 1972).
112. Fosberg, T. M., "Reclaiming Cooling Tower Slowdown",
Industrial Water Engineering, (June/July, 1972).
113. Frankel, R. J-, "Technologic and Economic Inter-
relationships Among Gaseous, Liquid and Solid Wastes
in the Coal-Energy Industry", Journal WPCF, Vol. *»0,
No. 5, Part 1, pp. 779-788, (May, 1968).
Gambs, G. C., and A. A. Rauth, "The Energy Crisis",
Chemical Engineering, pp. 56-68, .(May, 31, 1971).
721
-------
115. Carton, R. R. , "Biological Effects of Cooling Tower
Slowdown", for Presentation at 71st National Meeting
American Institute of Chemical Engineers.
(February 20-23, 1972).
116. Carton, R. R., and A. G. Christiansen, "Beneficial
Uses of waste Heat - An Evaluation", Presented at
Conference on Beneficial uses of Thermal Discharges,
sponsored by New York State, Department of Environmental
Conservation, (September, 1970) .
117. Carton, R. G. , and R. D. Harkins, "Guidelines:
Biological Surveys at Proposed Heat Dicharge Sites11,
EPA Water Quality Office, Northwest Region, (April, 1970)
118. Gartrell, F. E. , and J. C. Barber, "Environmental
Protection - TVA Experience", Journal of the Sanitary
Division, ASCE, pp. 1321-1333, (December, 1970).
119. "Geothermal Resources in California Potentials and
Problems", Assembly Science and Technology Advisory
Council, A Report to the Assembly General Research
Committee, California Legislature, (Nay, 1972) .
120. Geyer, J. C., et al, "Field Sites and Survey Methods
Report No. 3", Cooling Water Studies for Edison Electric
Institute (RP-49) , The John Hopkins Univ., (1968).
121. Gifford, D. C., "Will County Unit 1 Limestone Wet
Scrubber", Presented at American institute of Chemical
Engineers, N. Y. , (November 28, 1972).
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124. Golze, A. R., "Impact of Urban Planning on Electric
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127. "Handbook for Analytical Quality Control in Water and
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•\
128. Hansen, E. P., and R. E. Cates, "The Parallel Path
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129. Hansen, R. G., C. R. Knoll, and B. W. Mar, "Municipal
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132. Hauser, L. G., et al, "An Advanced Optimization
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133. Hauser, L. G., and K. A. Oleson, "Comparison of
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134. Hauser, L. G., "Cooling Water Requirements for the
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135. Hauser, L. G., "Cooling Water Sources for Power
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136. Hauser, L. G., "Evaluate Your Cost of Cooling Steam
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137. Hill, R. D., "Mine Drainage Treatment, State of the Art
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723
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139. Hollinden, G. A., and N. Kaplan, "Status of Application
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140. Holmberg, J. D. and O. L. Kinney, "Drift Technology
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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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724
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150. Jaske, R. T., et al, "Methods for Evaluating Effects of
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152. Jaske, R. T., "Thermal Pollution and Its Treatment,
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153. Jaske, R. T., "Use of Simulation in the Development of
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154. Jaske, R. T., "Water Resources 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 D. K. Brady, "Aquatic Ecosystems
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725
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160. Jimeson, R. M., and G. G. Adkins, "Waste Heat Disposal
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161. Jones, J. W., R. D. Stern, and F. T. Princiotta,
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164. Kibbel, W. H., Jr., "Hydrogen Peroxide for Industrial
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165. Kleinberg, B., "Introduction to Metric or Si", Civil
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169. Kumar, J., "Selecting and Installing Synthetic Pond
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170. "Lake Norman Hydrothermal Model Study, for Duke Power
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171. LaMantia, C. R., "Emission Control for Small Scale
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726
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173. Leung, Paul, "Cost Separation of Steam and Electricity
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175. Li, K. W., "Combined Cooling Systems for Power Plants",
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184. McNeil, W. J., "Beneficial Uses of Heated Sea Water in
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727
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186. "Typical LWR Nuclear Plant Project Schedule",
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191. "Missouri River Temperature Survey Near United Power
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197. "Nation's Bulk Power Systems Evaluated", National Electric
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728
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198. Nelson, B. D., "The Cherne Fixed Thermal Rotor System
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• t
204. Oleson, K. A., and R. R. Boyle, "How to Cool Steam
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206. Park, J. E.,and J. M. Vance, "Computer Model of Cross-
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210. Peterson, D. E., and R. T. Jaske, "Potential Thermal
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<
211. Peterson, D. E., and R. T. Jaske, "Simulation Modeling
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729
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212. Peterson, D. E.t and P. M. Schrotke, "Thermal Effects
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213. Peterson, D. E., A. M. Sonnichsen, Jr., et al, "Thermal
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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 T. L. Craig, "Commerical Experience with
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730
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225. Rabb, A., "For Steam Turbine Drives... Are Dry Cooling
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228. Sisson, William, "Langelier Index Predicts Water's
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229. "Report on Equipment Availability for the Twelve-Year
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230. "Review of Surface Water Temperature and Associated
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231. Rey, G., W. J. Lacy, and A. Cywin, "Industrial Water
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233. "Steam Electric Plant Air and Water Quality Control Data
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236. "Draft Development Document for Proposed Effluent
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731
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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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240. Rossie, J. P., et al, "Cost Comparison of Dry Type
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244. Ruckelshaus, W. D., and J. R. Quarles, "The First
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245. Ryan, P. P., "Condenser Retubed in 24 Days", Power
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246. Ryan, P. J., and D. R. F. Harleman, An Analytical
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247. Ryan, W. F., "Cost of Power".
732
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248. Schieber, J. R., "Control of Cooling Water Treatment -
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249. Schoenwetter, H.r "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., "Lovett Station Space Utilization
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252. Schoenwetter, H.„ "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 of
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256. Schuster, R., "The Year of the Gas Turbine", Power
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257. Seels, F. H., "Industrial Water Pretreatment",
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733
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743
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744
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745
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746
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747
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748
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749
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458. "Development Document for Effluent Limitations
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459. "Dunkirk Steam Station Waste Water Control
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466. Blecker, Herbert G., and Thomas M. Nichols,
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750
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467. Rosen, Richard H., "Discharge of Metallic Pollutants
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469. "Current Practices-Factors Influencing Need for Chemical
Cleaning of Boilers", ASME Research Committee Task Force
Report on Boiler Feedwater Studies, American Power
Conference, (May, 1973).
470. "Factors Affecting Ability to Retrofit Flue
.Gas Desulfurization Systems", Radian
Corporation, EPA 450/3-74-015, (December, 1973).
471. "Evaluation of Lime/Limestone Sludge
Disposal Options", Radian Corporation,
EPA 450/3-74-016, (November, 1973).
472. "Evaluation of the Controllability of
Power Plants Having a Significant
Impact on Air Quality Standards",
M.W. Kellogg Co., EPA 450/3-74-002,
(February, 1974).
473. "Report on the Status of Lime/Limestone
Wet Scrubber System", Radian Corporation,
EPA 450/3-74-014, (January, 1974).
751
-------
SECTION XIV
GLOSSARY
Absolute Pressure
The total force per unit area measured above absolute vacuum
as a reference. Standard atmospheric ' pressure is 101,326
N/sq m (14.696 psi) above absolute vacuum (zero pressure
absolute) .
Absolute Temperature
The temperature measured from a zero at which all molecular
activity ceases. The volume of an ideal gas is directly
proportional to its absolute temperature. It is measured in
°K (°R) corresponding to °C + 273 (°F + U59) .
A substance which dissolves in water with the formation of
hydrogen ion. A substance containing hydrogen which may be
displaced by metals to form salts.
Acidity
The quantitative capacity of aqueous solutions to react with
hydroxyl ions (OH-) . The condition of a water solution
having a pH of less than 7.
Aqglomer at ion
The coalescence of dispersed suspended matter into larger
floes or particles which settle more rapidly.
Alkali
A soluble substance which when dissolved in water yields
hydroxyl ions. Alkalies combine with acids to yield neutral
salts.
Alkaline
The condition of a water solution having a pH concentration
greater than 7.0, and having the properties of a base.
753
-------
Alkalinity
The capacity to neutralize acids, a property imparted to
water by its content of carbonates, bicarbonates, and
hydroxides. It is expressed in milligrams per liter of
equivalent CaCO.3.
Anion
The charged particle in a solution of an electrolyte which
carries a negative charge.
Anthracite
A hard natural coal of high luster which contains little
volatile matter.
Approach Temperature
The difference between the exit temperature of water from a
cooling tower, and the wet bulb temperature of the air.
Ash
The solid residue following combustion of a fuel.
Ash sluice
The transport of solid residue ash by water flow in a
conduit.
Backwash
Operation of a granular fixed bed in reverse flow to wash
out sediment and reclassify the granular media.
Bag Filters
A fabric type filter in which dust laden gas is made to pass
through woven fabric to remove the particulate matter.
Base
A compound which dissolves in water to yield hydroxyl ions
(OH-) .
Base-load Unit
An electric generating facility operating continuously at a
constant output with little hourly or daily fluctuation.
754
-------
Biocide
An agent used to control biological growth.
Bituminous
A coal of intermediate hardness containing between 50 and 92
percent carbon.
Slowdown
A portion of water in a closed system which is wasted in
order to prevent a build-up of dissolved solids.
BOD
Biochemical oxygen demand. The quantity of oxygen required
for the biochemical oxidation of organic matter in a sewage
or industrial waste in a specific time, at a specified
temperature and under specified conditions. A standard test
to assess wastewater pollution level.
Boiler
A device in which a liquid is converted into its vapor state
by the action of heat. In the steam electric generating
industry the equipment which converts water into steam.
Boiler Feedwater
The water supplied to a boiler to be converted into steam.
Boiler Fireside
The surface of boiler heat exchange elements exposed to the
hot combustion products.
Boiler Scale
An incrustation of salts deposited on the waterside of a
boiler as a result of the evaporation of water.
Boiler Tubes
Tubes contained in a boiler through which water passes
during its conversion into steam.
Bottom Ash
The solid residue left from the combustion of a fuel, which
falls to the bottom of the combustion chamber.
755
-------
Water having a dissolved solids content between that of
fresh water and that of sea water, generally from 1000 to
10,000 mg per liter.
Brine
Water saturated with a salt.
Bus Bar
A conductor forming a common junction between two or more
electrical circuits. A term commonly used in the electric
utility industry to refer to electric power leaving a
station boundary. Bus bar costs would refer to the cost per
unit of electrical energy leaving the station.
Capacity Factor
The ratio of energy actually produced to that which would
have been produced in the same period had the unit been
operated continuously at rated capacity.
Carbonate Hardness
Hardness of water caused by the presence of carbonates and
bicarbonates of calcium and magnesium.
Cation
The charged particles in solution of an electrolyte which
are positively charged.
Chemical Oxygen Demand fCOD)
A specific test to measure the amount of oxygen required for
the complete oxidation of all organic and inorganic matter
in a water sample which is susceptible to oxidation by a
strong chemical oxidant.
Circulating Water Pumps
Pumps which deliver cooling water to the condensers of a
powerplant.
756
-------
Circulating Water System
A system which conveys cooling water from its source to the
main condensers and then to the point of discharge.
Synonymous with cooling water system.
Clarification
A process for the removal of suspended matter from a water
solution.
Clarifier
A basin in which water flows at a low velocity to allow
settling of suspended matter.
Closed Circulating Water System
A system which passes water through the condensers, then
through an artificial cooling device, and keeps recycling
it.
Coal Pile Drainage
Runoff from the coal pile as a result of rainfall.
Condensate Polisher
An ion exchanger used to adsorb minute quantities of cations
and anions present in condensate as a result of corrosion
and erosion of metallic surfaces.
Condenser
A device for converting a vapor into its liquid phase.
C on s tr uc ti on
Any placement, assembly or installation of facilities or
equipment (including contractual obligations to purchase
such facilities or equipment) at the premises where the
equipment will be used, including preparation work at the
premises.
Convection
The heat transfer mechanism arising from the motion of a
fluid.
757
-------
Cooling Canal
A canal in which warm water enters at one end, is cooled by
contact with air, and is discharged at the other end.
Cooling Tower
A configured heat exchange device which transfers reject
heat from circulating water to the atmosphere.
Cooling Tower Basin
A basin located at the bottom of a cooling tower for
collecting the falling water.
Cooling Water System
See Circulating Water System
Corrosion Inhibitor
A chemical agent which slows down or prohibits a corrosion
reaction.
Counterflow
A process in which two media flow through a system in
opposite directions.
Critical Point
The temperature and pressure conditions at which the
saturated-liquid and saturated-vapor states of a fluid are
identical. For water-steam these conditions are 3208.2 psia
and 705.U7°F.
Cycling Plant
A generating facility which operates between peak load and
base load conditions.
Cyclone Furnace
A water-cooled horizontal cylinder in which fuel is fired,
heat is released at extremely high rates, and combustion is
completed. The hot gases are then ejected into the main
furnace. The fuel and combustion air enter tangentially
imparting a whirling motion to the burning fuel, hence the
name Cyclone Furnace. Molten slag forms on the cylinder
walls, and flows off for removal.
758
-------
Deaera-tion
A process by which dissolved air and oxygen are stripped
from water either by physical or chemical methods.
Deaerator
A device for the removal of oxygen, carbon dioxide and other
gases from water.
Degasification
The removal of a gas from a liquid.
Deionizer
A process for treating water by removal of cations and
anions.
Demine rali zer
See Deionizer
Demister
A device for trapping liquid entrainment from gas or vapor
streams.
Dewater
To remove a portion of the water from a sludge or a slurry.
Dew Point
The temperature of a gas-vapor mixture at which the vapor
condenses when it is cooled at constant humidity.
Diesel
An internal combustion engine in which the temperature at
the end of the compression is such that combustion is
initiated without external ignition.
Discharge
To release or vent.
759
-------
Discharge Pipe or Conduit
A section of pipe or conduit from the condenser discharge to
the point of discharge into receiving waters or cooling
device.
Drift
Entrained water carried from a cooling device by the exhaust
air.
Dry Bottom Furnace
Refers to a furnace in which the ash is collected as a dry
solid in hoppers at the bottom of the furnace, and removed
from the furnace in this state.
Dry Tower
A cooling tower in which the fluid to be cooled flows within
a closed system. This type of tower usually uses finned or
extended surfaces.
Dry. Hell
A dry compartment of a pump structure at or below pumping
level, where pumps are located.
Economizer
A heat exchanger which uses the heat of combustion gases to
raise the boiler feedwater temperature before the feedwater
enters the boiler.
Electrostatic Precipj.tator
A device for removing particles from a stream of gas based
on the principle that these particles carry electrostatic
charges and can therefore be attracted to an electrode by
imposing a potential across the stream of gas.
Evaporation
The process by which a liquid becomes a vapor.
Evaporator
A device which converts a liquid into a vapor by the
addition of heat.
760
-------
Feedwater Heater
Heat exchangers in which boiler feedwater is preheated by
steam extracted from the turbine.
Filter Bed
A device for removing suspended solids from water,
consisting of granular material placed in a layer(s) and
capable of being cleaned hydraulically by reversing the
direction of the flow.
Filtration
The process of passing a liquid through a filtering medium
for the removal of suspended or colloidal matter.
Fireside Cleaning
Cleaning of the outside surface of boiler tubes and
combustion chamber refractories to remove deposits formed
during the combustion.
Floe
Small gelatinous masses formed in a liquid by the reaction
of a coagulant added thereto, thru biochemical processes, or
.by agglomeration.
Flue Gas
The gaseous products resulting from the combustion process
after passage through the boiler.
Fly Ash.
A portion of the non-combustible residue from a fuel which
is carried out of the boiler by the flue gas.
Fossil Fuel
A natural solid, liquid or gaseous fuel such as coal,
petroleum or natural gas.
Generation
The conversion of chemical or mechanical energy into
electrical energy.
761
-------
Heat Rate
The fuel heat input (in Joules or Btus) required to generate
a kwh.
Heating Value
The heat available from the combustion of a given quantity
of fuel as determined by a standard calorimetric process.
Humidity
Pounds of.water vapor carried by 1 Ib of dry air.
ffi
A charged atom, molecule or radical, the migration of which
affects the transport of electricity through an electrolyte.
Ion Exchange
A chemical process involving reversible interchange of ions
between a liquid and a solid but no radical change in the
structure of the solid.
Lignite
A carbonaceous fuel ranked between peat and coal.
Makeup Water Pumps
Pumps which provide water to replace that lost by
evaporation, seepage, and blowdown.
Mechanical Draft Tower
A cooling tower in which the air flow through the tower is
maintained by fans. In forced draft towers the air is
forced through the tower by fans located at its base,
whereas in induced draft towers the air is pulled through
the tower by fans mounted on top of the tower.
Mill
One thousandth of a dollar.
Mine-mouth Plant
A steam electric powerplant located within a short distance
of a coal mine and to which the coal is transported from the
mine by, a conveyor system, slurry pipeline or truck.
762
-------
Mole
The molecular weight of a substance expressed in grams (or
pounds).
Name Plate
See Nominal Capacity
Natural Draft Cooling Tower
A cooling tower through which air is circulated by a natural
or chimney effect. A hyperbolic tower is a natural draft
tower that is hyperbolic in shape.
Neutrali zation
Reaction of acid or alkaline solutions with the opposite
reagent until the concentrations of hydrogen and hydroxyl
ions are about equal.
New Source
Any source, the construction of which is commenced after the
publication of proposed Section 306 regulations, (March 4,
1974 for the Steam Electric Power Generating Point Source
Category).
Nominal Capacity
Name plate - design rating of a plant, or specific piece of
equipment.
Nuclear Energy
The energy derived from the fission of nuclei of heavy
elements such as uranium or thorium or from the fusion of
the nuclei of light elements such as deuterium or tritium.
Once-through Circulating Water System
A circulating water system which draws water from a natural
source, passes it through the main condensers and returns it
to a natural body of water.
Overflow
(1) Excess water over the normal operating limits disposed
of by letting it flow out through a device provided for that
purpose; (2) The device itself that allows excess water to
flow out.
763
-------
Osmosis
The process of diffusion of a solvent through a semi-
permeable membrane from a solution of lower to one of higher
concentration.
Osmotic Pressure
The equilibrium pressure differential across a semi-
permeable membrane which separates a solution of lower from
one of higher concentration.
Oxidation
The addition of oxygen to a chemical compound, generally any
reaction which involves the loss of electrons from an atom.
Package Sewage Treatment Plant
A sewage treatment .facility contained in a small area and
generally prefabricated in a complete package.
Packing (Cooling Towers^
A media providing large surface area for the purpose of
enhancing mass and heat transfer, usually between a gas or
vapor, and a liquid.
Peak-load Plant
A generating facility operated only during periods of
maximum demand.
Penalty
A sum to be forfeited, or a loss due to some action.
EH Valug
A scale for expressing the acidity or alkalinity of a
solution. Mathematically it is the logarithm of the
reciprocal of the gram ionic hydrogen equivalents per liter.
Neutral water has a pH of 7.0 and hydrogen ion concentration
of 10~7 moles per liter.
Placed in Service
Refers to the date when a generating unit initially
generated electrical power to service customers.
764
-------
Plant Code Number
A four-digit number assigned to all powerplants in the
industry inventory for the purpose of this study.
Plume {Gas)
A conspicuous trail of gas or vapor emitted from a cooling
tower or chimney.
Powerplant
Equipment that produces electrical energy generally by
conversion from heat energy produced by chemical or nuclear
reaction.
Precipitation
A phenomenon that occurs when a substance held in solution
in a liquid phase passes out of solution into a solid phase.
Preheater
A unit used to heat the air needed for combustion by
absorbing heat from the products of combustion.
Psychrometric
Refers to air-water vapor mixtures and their properties. A
psychrometric chart graphically displays the relationship
between these properties.
Pulveriged Coal
Coal that has been ground to a powder, usually of a size
where 80 percent passes through a #200 U.S.S. sieve.
Pyrites
Combinations of iron and sulfur found in coal as FeS2.
Radwaste .
Radioactive waste streams from nuclear powerplants.
Range
Difference between entrance and exit temperature of water in
a cooling tower.
765
-------
Rank of Coal
A classification of coal based upon the fixed carbon on a
dry weight basis and the heat value.
Rankine Cycle
The thermodynamic cycle which is the basis of the steam-
electric generating process.
Recirculation System
Facilities which are specifically designed to divert the
major portion of the cooling water discharge back for reuse.
Reduction
A chemical reaction which involves the addition of electrons
to an ion to decrease its positive valence.
Regeneration •
Displacement from ion exchange resins of the ions removed
from the process solution.
Reheater
A heat exchange device for adding superheat to steam which
has been partially expanded in the turbine.
Reinfection
To return a flow, or portion of flow, into a process.
Relative Humidity
Ratio of the partial pressure of the water vapor to the
vapor pressure of water at air temperature.
Reverse Osmosis
The process of diffusion of a solute through a semi-
permeable membrane from a solution of lower to one of higher
concentration, affected by raising the pressure of the less
concentrated solution to above the osmotic pressure.
766
-------
Saline Wateg
Water containing salts.
Sampling Stations
Locations where several flow samples are tapped for
analysis.
Sanitary Wastewater
Wastewater discharged from sanitary conveniences of
dwellings and industrial facilities.
i
Saturated Air
Air in which water vapor is in equilibrium with liquid water
at air temperature.
Saturated Steam
Steam at the temperature and pressure at which the liquid
and vapor phase can exist in equilibrium.
Generally insoluble deposits on heat transfer surfaces which
inhibit the passage of heat through these surfaces.
Scrubber
A device for removing particles or objectionable gases from
a stream of gas.
Secondary Treatment
The treatment of sanitary waste water by biological means
after primary treatment by sedimentation.
Sedimentation
The process of subsidence and deposition of suspended matter
carried by a liquid.
Sequestering Agents
Chemical compounds which are added to water systems to
prevent the formation of scale by holding the insoluble com-
pounds in suspension.
767
-------
Service Water Pumps *
Pumps providing water for auxiliary plant heat exchangers
and other uses.
Slag Tap Furnace
Furnace in which the temperature is high enough to maintain
ash (slag) in a molten state until it leaves the furnace
through a tap at the bottom. The slag falls into the
sluicing water where it cools, disintegrates, and is carried
away.
Slimicide
An agent used to destroy or control slimes.
Sludge
Accumulated solids separated from a liquid during
processing.
Softener
Any device used to remove hardness from water. Hardness in
water is due mainly to calcium and magnesium salts. Natural
zeolites, ion exchange resins, and precipitation processes
are used to remove the calcium and magnesium.
Spinning Reserve
The power generating reserve connected to the bus bar and
ready to take load. Normally consists of units operating at
less than full load. Gas turbines, even though not running,
are considered spinning reserve due to their quick start up
time.
Spray Module {Powered Sp.ray. ModuleL
A water cooling device consisting of a pump and spray nozzle
or nozzles mounted on floats and moored in the body of water
to be cooled. Heat is transfered principally by evaporation
from the water drops as they fall through the air.
Station
A plant comprising one or several units for the generation
of power.
768
-------
Steam Drum'
Vessel in which the saturated steam is separated from the
steam-water mixture and into which the feedwater is intro-
duced.
Supercritical
Refers to boilers designed to operate at or above the
critical point of water 22,100 kN/sq m and '374.0°C (3206.2
psia and 705. 4°F) .
Superheated Steam
Steam which has been heated to a temperature above that
corresponding to saturation at a specific pressure.
Thermal Efficiency
The efficiency of the thermodynamic cycle in producing work
from heat. The ratio of usable energy to heat input
expressed as a percent.
Thickening
Process of increasing the solids content of sludge.
Total Dynamic Head
Total energy provided by a pump consisting of the difference
in elevation between the suction and discharge levels, plus
losses due to unrecovered velocity heads and friction.
Turbidity
Presence of suspended matter such as organic or inorganic
material, plankton or other microscopic organisms which
reduce the clarity of the water.
Turbine
A device used to convert the energy of steam or gas into
rotational mechanical energy and used as prime mover to
drive electric generators.
769
-------
In steam electric generation, the basic system for power
generation consisting of a boiler and its associated turbine
and generator with the required auxiliary equipment.
Utility
(Public utility) A company either investor-owned or publicly
owned which provides service to the public in general. The
electric utilities generate and distribute electric power.
Volatile Combustion Matter
The relatively light components in a fuel which readily
vaporize at a relatively low temperature and which when
combined or reacted with oxygen, give out light and heat.
Wet Bottom Furnace
See slag-tap furnace.
Wet Bulb Temperature
The steady-state, nonequilibrium temperature reached by a
small mass of water immersed under adiabatic conditions in a
continuous stream of air.
Wet Scrubber
A device for the collection of particulate matter from a gas
stream or absorption of certain gases from the stream.
Zeolite
Complex sodium aluminum silicate materials, which have ion
exchange properties and were the original ion exchange
materials before synthetic resins were processed.
770
-------
APPENDIX 1
-------
INVENTORY NOTES
1. Unless otherwise noted, the generating capacity given
is the installed capacity based on Federal Power
Commission data of June 30, 1970, updated to Janu-
ary 1, 1972 through the Electrical World Directory of
fc Electric Utilities, 1972-1973, published by McGraw-Hill,
Inc.
2. Plants under construction are indicated by (*).
3. Plant types indicated are as follows:
F - Fossil fuel plant
N - Nuclear plant
G - Gas turbine unit within a fossil fuel plant
4. Unless otherwise indicated 60 Hz is the frequency of
electricity generated.
-------
EPA REGION I
Region: Connecticut, Maine, Massachusetts
New Hampshire, Rhode Island, Vermont
Region Office: Boston, Massachusetts
CONNECTICUT
Utility
Conn. Light & Power
Company
Conn. Yankee
Atomic Power Co .
Hartford Electric
Light Company
Norwich Department
Of Pub. Utilities
United Illuminating
Company
U. S. Navy
Plant
Devon
Montville
Norwalk Harbor
Millstone Point
Conn. Yankee Atomic
Middletown
Stamford
South Meadow
Millstone No. 2
Norwich
English Plant
Steel Point
Bridgeport Harbor
Derby Station
New London Sub. Base
Locat ion
Milford
Montville
Norwa Ik
Waterford
Haddam
Middletown
Stamford
Hartford
Waterford
Norwich
New Haven
Bridgeport
Bridgeport
Derby
New London
Gen. Capacity
(MW)
454
16.3
577.4
326.4
16.3
661.5
600.0
422
18.6
52.5
216.8
180
828
14.3
163.2
174.5
660.5
18.6
20.0
10.5
Type
F
G
F
F
G
N
N
F
G
F
F
G
N
F
F
F
F
G
F
F
Wallingford
Electric Div.
Alfred L. Pierce
Wallingford
22.5
Al-1
-------
EPA REGION I
NEW HAMPSHIRE
Utility
Public Service Co.
of New Hampshire
Utility
Blackstone Valley
Electric Co.
The Narragansett
Electric Co.
Newport Electric
Corp
U. S. Navy
Utility
Light Dept.
Central Vermont
Plant
Daniel Street
Kelley Falls
Manchester Steam
Merrimack
Schiller
RHODE ISLAND
Plant
Pawtucket
South Street
Manchester Street
Newport
Quonset Point
VERMONT
Plant
J. Edward Moran
Milton Steam
Rutland
Location
Portsmouth
Manchester
Manchester
Bow
Portsmouth
Location
Pawtucket
Providence
Providence
Newport
Location
Burlington
St. Albans
Gen. Capacity
(MW)
21
18.8
20
459
37.2
178.8
Gen. Capacity
(MW)
33.5
188.6
132
11.0
5.0
Gen. Capacity
(MW)
30
28
4.0
31.2
Type
F
F
F
F
G
F
Type
F
F
F
F
F
Type
F
G
F
F
Vermont Yankee Vermont Yankee
Nuclear Power Corp.
Vernon
513
N
Al-2
-------
EPA REGION I
MAINE
Utility
Bangor Hydro Electric Graham
Company
Central Maine Power Cape
Company
Maine Public
Service Co.
Maine Yankee
Atomic Power Co.
U. S. Navy
Utility
Boston Edison Co.
Braintree Electric
Light Dept.
Brockton Edison Co.
Cambridge Electric
Light Company
Canal Electric Co.
Plant
Graham
Cape
Mason
W. F. Wyman
Caribou
Bailey Point No. 1
Kittery
MASSACHUSETTS
Plant
New Boston Sta.No. 400
L Street Sta. No. 4
Edgar Station No. 75
Mystic Sta. No. 200
Leland St. Sta. No. 240.
Pilgrim
Allen Street
N.P. Potter
East Bridgewater
Blackstone Street
Kendell Square
Location
Bangor
South Portland
Wiscasset
Yarmouth
Caribou
Location
South Boston
South Boston
N. Weymouth
Everett
Framingham
Braintree
Braintree
Gen. Capacity
(MW)
57.5
12.0
22.5
146.5
213.6
19
855*
7
4.3
Gen. Capacity
(MW)
717.75
153.75
18.6
457.9
33.5
618.8
16.8
33.5
650*
21.0
12.5
East Bridgewater 20
Cambr idge
Cambridge
24.8
67.5
Type
F
G
F
F
F
F
N
F
F
Typ
F
F
G
F
G
F
F
F
N
F
F
F
F
F
Canal
Sandwich
542.5
Al-3
-------
EPA REGION I
MASSACHUSETTS (continued)
Utility
Fall River Electric
Light Company
Fitchburg Gas &
Electric Light Co.
Holyoke Munic. Gas
& Electric Dept.
Holyoke Water Power Co.
Mass. Bay Trans.
Authority
Mass. Electric Co.
Montaup Electric Co.
New Bedford Gas &
Edison Light Co.
New England Power Co.
Taunton 'Municipal
Lighting Plant
U. S. Navy
Western Massachusetts
Electric Co.
Gen. Capacity
Plant
Hathaway Street
Sawyer Passway
Holyoke
Mt. Tom Power Pit.
Riverside Station
South Boston
Lincoln
Webster Street
Lynnway
Somerset Station
Cannon Street
•Salem Harbor
Brayton Point
Westwater Street
B. F. cleary
Boston Navy Yard
West Springfield
Location
Fall River
Fitchburg
Holyoke
Holyoke
Holyoke
Worcester
Lynn
Fall River
New Bed ford
Salem
Somerset
Taunton
Taunton
West Springfield
MW
14.3
61.4
30
10
136
44.8
120
60
34.5
49.0
344
48
115.5
319.9
1124.7
49
28.3
22
209.6
18.6
Type
F
F
F
G
F
F
F
F
F
F
F
G
F
F
F
F
F
F
F
G
Yankee Atomic
Electric Co.
Yankee Atomic
Rowe
185
Al-4
-------
EPA REGION II
Region: New Jersey, New York, Puerto Rico, Virgin Islands
Region Office: New York, New York
NEW JERSEY
Utility
Atlantic City Elec: Co.
Jersey Central Power
& Light Company
New Jersey Power &
Light Company
Public Service Elec.
s Gas Company
Plant
Missouri Ave.
Deepwater
Greenwich
B.L. England
•
E. H. Werner
Sayreville
Oyster Creek
Gilbert
Bergen
Burlington
Essex
Hudson
Kearny
Linden
Marion
Mercer
Sewaren
Salem 1
Salem 2
Location
Atlantic City
Penns Grove
Gibbstown
Bees leys Pt.
South Amboy
Sayreville
Lacey Township
Milford
Ridgef ield
Burlington
Newark
Jersey City
Kearny
Linden
Jersey City
Hamilton
Sewaren
Gen. Capacity
MW
50
55.8
308.3
18.6
10
299.2
116.3
343.8
640
126.1
640.4
18.6
490.5
329
417
1114.5
115.2
598.5
311.2
519.4
113.8
125
652.8
115.2
820
115.2
1090*
1115*
Tyj
F
G
F
G
F
F
F
F
N
F
F
G
F
F
G
F
G
F
F
F
G
F
F
G
F
G
N
N
Vineland Electric
Utility
Vineland
Vineland
67.3
Al-5
-------
Utility
Central Hudson Gas &
Electric Corp.
Consolidated Edison
Co. of N. Y., Inc.
Consolidated Edison
Co. of N. Y.
Jamestown Board of
Public Utilities
EPA REGION II
NEW YORK
Gen. Capacity
Plant
Danskammer Point
Rivers ide
Arthur Kill
Astoria
East River
Hell Gate
Hudson Ave .
Indian Point
Kent Avenue
Ravenswood
Sherman Creek
Waters ide # 1 & 2
74th Street
59th Street
Location
Roseton
Poughkeeps ie
New York
Queen
New York
New York
Brooklyn
New York
Brooklyn
New York
New York
New York
New York
New York
MW
531.9
5.5
12
911.7
16.3
1550.6
496
119.8
773.7
60
541.3
70
845
846
275
2138*
107.5
28
1827.7
481.8
216.5
140
572.3
14
125
144
37.2
184.5
34.2
Type
F
G
F
F
G
F
G
G
F
F 25
F
F 25
F
G
N
N
F 25
G
F
G
F
F 25
F
G
F 25
F
G
F 25
G
Hz
Hz
Hz
Hz
Hz
Hz
Samuel A. Carlson Jamestown
Lawrence Park
Heat, Light & Power Co. Lawrence Park
Lawrence Park
82.5
1.1
Al-6
-------
EPA REGION II
NEW YORK (continued)
Utility
Plant
Location
Gen. Capacity
MW Type
Long Island Lighting Co. E. F. Barret island Park
Glenwood Glenwood Landing
Port Jefferson Port Jefferson
Far Rockaway
Northport
New York State Elec.
S Gas Corporation
Goudey
Greenridge
Jennison
Hickling
Milliken
Bell
Niagara Mohawk Power Corp. Albany
Orange & Rockland
Utilities Inc.
Power Authority
State of N. Y.
Charles L.
Huntley
Oswego
Lovett
Bowlin
Far Rockaway
Northport
Johnson City
Dresden
Bainbridge
East Corning
Ludlowville
Near Ludlowville
Albany
Buffalo
Dunkirk Dunkirk
Nine Mile Point Oswego
Oswego
Tonkins Cove
Near New Milford
375
258
403
467
16
113.6
774.2
387.0*
16
145.8
30.0
160
60
70
270
853*
400
155
828
0.7
628
642
5.7
376
0.7
489.5
1246*
F
G
F
F
G
F
F
F
G
F
F
F
F
F
F
N
F
G
F
G
F
N
G
F
G
F
F
J.A. Fitzpatrick Oswego
800.*
Al-7
-------
EPA REGION II
NEW YORK (continued)
Utility
Rochester Gas & Elec.
Corp.
Plant
Rochester #3
Rochester #7
Rochester #8
Rochester #9
Rochester #12
Ginna R.G.
Location
Gen. Capacity
MW
Rochester
Greece
Rochester
Rochester
Ontario
Rochester
206.2
18.0
252.6
8
3
420
517.1
F
G
F
F
F
N
U.S. Military Academy
(Light & Power Plant)
Light Power
U.S. Military
Academy
West Point,N.Y.
4.5
PUERTO RICO
Utility
Puerto Rico Water
Resources Auth.
Plant Location
San Juan San Juan
South Coast Guayanilla
Palo Seco Catano
Gen. Capacity
MW
640
30
287.5
10
820*
40
657
30
Tyj
F
G
F
G
F
G
F
G
U.S. Navy
Ceiba
Ceiba
VIRGIN ISLANDS
Utility
Virgin Island Water &
Power Authority
Plant
St. Thomas/
St Johns
St. Croix
Gen. Capacity
Location MW
Virgin Island 29.2
15.1
Virgin Island 25.5
18
TVP«
F
G
F
G
Al-8
-------
EPA REGION III
Region: Delaware, Maryland, Pennsylvania, Virginia
West Virginia, District of Columbia
Region Office: Philadelphia, Pennsylvania
DELAWARE
-Utility
Delmarva Power & Light Co.
Dover Munic. Power Plant
Utility
Baltimore Gas & Elec. Co.
Delmarva Power & Light
Co. of Maryland
Plant
Delaware City
Indian River
Edge Moore
McKee Runn
St . Jones River
MARYLAND
-
Plant
Westport
Gould Street
Pratt Street
Riverside
Wagner, Herbert, A .
Crane P. Charles
Calvert Cliffs
Vienna
Location
Delaware City
Millsboro
Edge Moore
Dover
Dover
Location
Baltimore
Baltimore
Baltimore
Baltimore
Ba It imore
Baltimore
Nr. Annapolis
Vienna
Gen. Capacity
MW
130
18.6
330.2
18.6
389.8
15
378*
37.5
8.8
Gen. Capacity
MW
194
121.5
173.5
20
333.5
173.5
627.8
16
414.7*
399.8
16
1804*
244.5
18.6
Type
F
G
F
G
F
G
F
F
F
Type
F
G
F
F
F
G
F
G
F
F
G
N
F
G
Hagerstown Munic. Elec.
and Light Plant
Hagerstown
Hagerstown
38.8
Al-9
-------
EPA REGION III
MARYLAND (continued)
Utility
The Potomac Edison Co.
Potomac Elec. Power Co.
Utility
Chambersburg Municipal
Electric Dept.
Duguesne Light Co.
Lansdale Elec. Dept.
Metropolitan Edison Co.
Plant
Smith, R . Paul
Cumberland
Celanese
Dickerson
Chalkpoint
Morgantown
PENNSYLVANIA
Plant
Chambersburg
Elrama
Frank R. Phillips
James H . Reed
Co If ax
Shippingport
Cheswick
Lansdale
Portland
Titus
Crawford
Eyler
Three Mile Island
Location
Williamsport
Cumberland
Amcella
Dickerson
Aquasco
Newburg
Location
Chambersburg
Elrama
Wireton
Pittsburg
Cheswick
Shippingport
Springdale
Lansdale
Portland
Reading
Middletown
Reading
Nr . Harrisburg
Gen. Capacity
MW
159.5
30
10
586.5
16.2
726.6
16.1
1146
35.8
Gen. Capacity
MW
15
525
411.2
180
262.5
100
525
24.5
11.3
426.7
37.6
225
18
116.8
84
1780*
Type
F
F
F
F
G
F
G
F
G
Type
F
F
F
F
F
N
F
F
G
F
G
F
G
F
F
N
Al-10
-------
EPA REGION III
PENNSYLVANIA (continued)
Utility
Pennsylvania Power Co.
Pennsylvania Power s
Light Co.
Philadelphia Elec. Co.
Philadelphia Elec. Co.
Plant
New Castle
Burner Island
HoItwood
Keystone Plant
Martins Creek
Stanton
Sunbury
Suburban
Montour
Schuylkill
Chester
Delaware '
Richmond
Barbadoes
Southwark
Cromby
Eddystone
Peach Bottom 1
Peach Bottom 2
Peach Bottom 3
Limerick 1
Limerick 2
Locat ion
Gen. Capacity
MW
U.G.I. Corporation
Hunlock Creek
West Pittsburgh
York Haven
Ho It wood
Schelocta
Martins Creek
Harding
Shamokin Dam
Washingtonville
Philadelphia
Chester
Philadelphia
Philadelphia
Norristown
Philadelphia
Phoenixville
Eddystone
Delta
Philadelphia
Hunlock
425.8
1577.7
1064*
105
1872
312.5
5
140.5
409.8
6.0
29.3
822.7*
50.0
275.4
18.6
256
55.8
439.3
76.2
594.0
487.2
155
65.4
345
74.4
417.5
275
707.2
37.2
40
18I!*3*
1065*
1065*
93.0
— — r-
F
F
F
F
F
F
G
F
F
G
F
F
F 25 Hz
F
G
F
G
F
G
F
G
F
G
F
G
F
G
F
G
N
N
N
N
F
Al-11
-------
EPA REGION III
PENNSYLVANIA (continued)
Gen. Capacity
Utility
Pennsylvania Elec. Co.
Pennsylvania State Uni.
Quakertown Mun. System
Saxton Experimental Corp.
Weatherly Borough
Elec . Dept .
West Penn Power Co.
Utility
Appalachian Power Co.
The Potomac Edison Co.
of Virginia
Virginia Elec. & Power Co.
Plant
Shawville
Seward
Warren
Front street
Saxton
Williamsburg
Homer City
Conemaugh
Central
Generating plant
Saxton
Weatherly
Springdale
Mitchell
Armstrong ,
Milesburg
Hartfield's Ferry
VIRGINIA
Plant
Glen Lyn
Clinch River
Riverton
Bremo
Chesterfield
Portsmouth
Location
Shawville
Seward
Warren
Erie
Saxton
Williamsburg
Homer city
University Park
Quakertown
Weatherly
Springdale
Courtney
Reesedale
Milesburg
Mansontown
Location
Glen Lyn
Cleveland
Riverton
Bremo Bluff
Chester
Norfolk
MW
640
268.3
73.4
118.8
30
39
1320
936
936*
7.5
9.9
10
1.5
416
448.7
326.4
46
576
1000*
Gen. Capacity
MW
401.1
669
34.5
284.3
1434.5
649.6
195.4
TyP'
F
F
F
F
F
F
F
F
F
F
F
N
F
F
F
F
F
F
F
Tyj
F
F
F
F
F
F
G
Al-12
-------
EPA REGION III
VIRGINIA (continued)
Utility
Virginia Elec. & Power Co.
Danville Water, Gas &
Electric Dept.
Virginia Polytechnic
Heat & Power Plant
Potomac Electric Power Co.
U. S. Navy
Davi (MUN)
Plant
Possum Point
Reeves Ave.
12th street
Yorktown
Surry
North Anna
Brantley Steam St.
VPI Central Heat
Potomac River
Portsmouth
Brantley
Location
Dumfries
Norfolk
Richmond
Hornsbyville
Nr . Richmond
Alexandria
Gen. Capacity
MW
491
96
100
102.5
375
845*
1600*
1750*
29.0
1.8
514.8
27
29
Type
F
G
F
F
F
F
N
N
F
F
F
F
. F
WEST VIRGINIA
Utility
Monongahela Power Co.
Appalachian Power Co.
Ohio Power Co.
Plant
Albright
Riversville
Willow Island
Fort Martin
Harrison
Kanahwa River
Cabin Creek
Philip Sporn
John Amos
Krammer
Windsor
Mitchell
Locat i on
Albrighi-
Riversv-lle
Willow Island
Maidsville
Shinnston
Glasgow
Cabin Creek
New Haven
Winfield
Capt ina
Power
Capt ina
Gen. Capacity
MW
263
174.8
215
1152
1950*
426
273.6
1960
2950
675
300
1600
Type
F
F
F
F
F
F
F
F
F
F
F
F
* under construction
A1.-13
-------
EPA REGION III
WEST VIRGINIA (continued)
Utility
Plant
Virginia Elec. & Power Co. Mount Storm
Location
Mount Storm
Gen. Capacity
MW
1140.5
18.6
555*
F
G
F
Utility
Potomac Elec. Power Co.
DISTRICT OF COLUMBIA
Plant Location
Benning
Buzzard Point
Washington
Washington
Gen. Capacity
MW
553.6
289*
50
270
288
Type
F
F 25 Hz
F
G
Al-14
-------
EPA REGION IV
Region: Alabama, Florida, Georgia, Kentucky, Mississippi,
North Carolina, South Carolina, Tennessee
Region Office: Atlanta, Georgia
Utility
Alabama Elec.Coop.,Inc.
Alabama Power Co.
Southern Elec.Gen. Co.
Tennesee Valley Auth.
Utility
Florida Pwr. & Light Co.
ALABAMA
Gen. Capacity
Plant
McWilliams
Tombigee
Barry
Chickasaw
Gorgas
Gadsden 1 & 2
Green County
Farley Unit 1
Farley Unit 2
Gaston C. Ernest
Colbert
Widows Creek
Brown's Ferry
FLORIDA
Location
Andalusia
Leroy
Bucks
Chickasaw
Gorgas
Gadsden
Demopolis
Nr. Cedar Springs
ii it ii
Wilsonville
Pride
Bridgeport
Near Decatur
MW
40
11.05
75
1770
60
138
756
138
568.5
820*
820*
1060.8
850
21.3
1396.5
1978
3456*
Gen. Capacity
Plant
Sanford
Palatka
Fort Myers
Port Everglades
Lauderdale
Riviera
Miami
Cutler
Cape Kennedy
Turkey Point
Turkey Point, 3 &
Hutchinson Island
Fort Pierce
Al-15
Location
Sanford
Palatka
Fort Myers
Port Everglades
Dania
Riviera
Miami
Cutler
Cape Kennedy
Florida City
4 Nr. Miami
Hutchinson Is .
Fort Pierce
MW
156.3
109.5
558.3
1254.6
312.5
739.6
46
346.3
804
817.5
1456.6*
892.5*
1500*
Type
F
G
F
F
G
F
F
F
F
N
N
F
F
G
F
F
N
F
F
F
F
F
F
F
F
F
F
N
N
N
-------
EPA REGION IV
Utility
Florida Power Corp.
Tampa Elec. Co.
Gainsville Utilities
Jacksonville Elec. Auth.
Plant
FLORIDA (continued)
Location
Gen. Capacity
MW Type
Bayboro
Paul L. Bartow
Higgins
Inglis
Suwannee River
Avon Park
George E. Turner
Crystal River
Port St. Joe
Rio Pinar
Anclote
St. Petersburg
St . Petersburg
Oldsmar
Inglis
Live Oak
Avon Park
Enterprise
Red Level
Port St . Joe
Rio Pinar
Tarpon Springs
51.3
494.4 .,
-
138
131.9
53.8
147
61
201.6
34
964.3
40.5
15
886*
F
F
G
F
G
F
F
F
F
F
F
F
N
Florida Public Utiilites Marianna
Gulf Power Co.
Marianna
2.0
Crist
Lansing Smith
I
Scholz
Big Bend
Hookers Point
Francis J. Gannon
Peter 0. Knight
John R. Kelly
DeEr haven
J. Dillon Kennedy
Norths ide
Souths ide
Pennsecola
Pannama city
Chattahoochee
Tampa
Tampa
Tampa
Tampa
Gainsville
Hague
Jacksonville
Jacksonville
Jacksonville
651
578*
340
40
98
869.2
18
232.6
1270.4
18
60
99
43.5
81
356.6
40
560
32.9
356.6
34
F
F
F
G
F
F
G
F
F
G
F
F
G
F
F
G
F
G
F
G
Al-16
-------
EPA REGION IV
FLORIDA (continued)
Gen. Capacity
Utility
Key West Utility Board
Lakeland Dept. of Elec.
& Water Utilities
New Smyrna Utilities
Tallahassee Elec. Dept.
Vero Beach Mun. Utilities
Orlando Utilities Coiran.
Utility
Georgia' Power Co.
Plant
City Elect . System
Larsen Memorial
Power Plant #3
Lake Mirror
Swoope
S. O. Purdom
Aruah B. Hopkins
Vero Beach
Orlando
Lake Highland
GEORGIA
Plant
Arkwright
Atkinson
Bowen
Hammond
Harlee Branch
Jack McDonough
McManus
Mitchell
Location
Key West
Lakeland
Lakeland
Lakeland
MW
70
120
33.8
90
10
New Smyrna Beach 7.5
St. Marks
Tallahassee
Vero Beach
Titusville
Orlando
Location
Macon
Smyrna
Catersville
Coos a
Milledgeville
Smyrna
Brunswick
Albany
130
25
80.9
17.0
62
294.3
317*
103.8
Gen. Capacity
MW
181.3
32.6
258
83.7
771.6
39.4
953
1539.7
598.4
80
143.8
159
218.3
Type
F
F
G
F
F
F
F
H
F
G
F
F
F
F
*•
Type
F
G
F
G
F
G
F
F
F
G
F
G
F
Al-17
-------
EPA REGION IV
Utility
Georgia Power Co.
Plant
Yates
Etowah
Hatch.
Wansley
Savannah Elec. & Power Co. Riverside
Port Wentworth
Effingham
Thomasville"Water & Light Thomasville
GEORGIA (continued)
Location
Gen. Capacity
MW Type
Newman
Nr. Jessup
Savannah
Port Wentworth
Nr . Guyton
Thomasville
680
2470*
40
1701*
1760*
111
207.9
21.6
120.3
158*
15.5
F
F
G
N
F
F
F
G
F
F
F
Crisp Co. Power Comm.
Crisp
Warwick
10.0
KENTUCKY
Utility
Plant
Locat ion
Gen. Capacity
MW . Type
Kentucky Utilities Co.
Louisville Gas & Elec. Co.
Owensboro Mun. Utilities
Green River
Tyrone
E. W. Brown
Pieneville
Ghent
Hae fling
Canal
Cane Run
Paddy's Run
Millcreek
Owensboro
Elmer Smith
Central City
Versailles
Bur gin
Four Mile
Nr. Madison
Lexington
Louisville
Louisville
Louisville
Louisville
Owensboro
Owensboro
236.7
137.5
724.1
37.5
500
51
50
1016.7
16.3
337.5
48.5
642.2*
52.5
151
265
F
F
F
F
F
F
F
F
G
F
G
F
F
F
F
Al-18
-------
EPA REGION IV
KENTUCKY (continued)
Utility
Henderson Mun. Light
Big River Rural Elec.
E. Kentucky Rural Elec.
Tennessee Valley Auth.
Kentucky Power Co.
Utility
Mississippi Power & Light
Greenwood Utilities
Yazoo City - Public
Service Commission
South Mississippi Elec.
Power Association
Clafksdale Public Utility
Commiss ion
Plant
Henderson
Robert Reid
Coleman
Wm. C. Dale
Cooper John Sherman
Ohio River
Paradise
Shawnee
Big Sandy
MISSISSIPPI
Plant
Rex Brown
Delta
Natchez
Baxter Wilson
Wright
Henderson
Yazoo City
Moselle
Clarksdale
Location
Henderson
Sabree
Hanesville
Ford
Burns ide
Near Boone
Paradise
Paducah
Louisa
Location
Jackson
Cleveland
Natchez
Vicksburg
Greenwood
Greenwood
Yazoo City
Hattiesburg
Clarksdale
Gen. Capacity
MW
50.6
2
80
340
160
196
322
450*
2558.2
1750
1003
Gen. Capacity
MW
383.2
10
220.5
66
544.6
700
23.5
12.6
11.5
19
12.5
177
29.5
14.3
Typi
F
G
F
F
G
F
F
F
F
F
F
TyjDi
F
G
F
F
F
F
F
F
G
F
G
F
F
G
A-19
-------
EPA REGION IV
NORTH CAROLINA
Utility
Carolina Power & Light
Duke Power Co.
Gen. Capacity
Plant
Cape Fear
H. F. Lee
W. H. Weatherspoon
Louis V. Button
Asheville
Roxboro
Brunswick
Riverbend
Buck
Dan River
Cliff side
Allen
Marshall
Be lews Creek
McGuire
Location
Moncure
Goldsboro
Lumberton
Wilmington
Asheville
Roxboro
Tranquil Harbor
Mount Holly
Spencer
Draper
Cliff side
Be Imont
Terrell
Near Greensboro
Near Mooresville
MW
421
72
402.5
16.3
89.9
165.5
79.5
225
91.3
420*
206.6
200.0
1067.8
720*
16.3
1642*
631
120
440
112.5
290
85
210
570*
1155
200
2160*
2300*
Type
F
G
F
G
G
F
G
F
G
F
F
F
F
F
G
N
F
G
F
G
F
G
F
F
F
F
F
N
Al-20
-------
EPA REGION IV
SOUTH CAROLINA
Utility
Lockhart Power Co.
Plant
Lockhart
Location
Lockhart
Gen. Capacity
MW
South Carolina Elec. &
Gas Co.
So. Carolina Public
Service Authority
Duke Power Co.
Greenwood Mills
Carolina Power & Light
McMeekin
Hagood
Canadys
Urquhart
Parr
Wateree
Buahy Park
Jef feries
Grainger
Lee
Tiger
Buzzard Roost
Melhews No. 1
Melhews No. 2
H. B. Robinson
Brunswick 1 & 2
Irmo
Charleston
Canady
Beech Island
Parr
Wateree
Nr. Moncks Corner
Moncks Corner
Conway
Pelzer
Duncan
Chappels
Greenwood
Greenwood
Hartsville
Wilmington
293.8
94.4
489.6
16.3
34.5
250
75.8
72.5
74
700
550*
60
272.8
172.8
163.2
345
90
30.0
16.1
196
25
32.5
206
21.3
700
1641*
F
F
F
G
G
F
G
F
G
F
F
G
F
P
F
F
G
F
F
G
F
F
F
G
N
N
Al-21
-------
EPA REGION IV
TENNESSEE
Utility
Tennessee valley Auth.
Plant
Thomas H. Allen
Bull Run
Gallatin
John Sevier
Johnsonville
Kingston
Walts Bar
Cumberland.
Seguoyah
Location
Gen. Capacity
MW
Type
Memphis 990
Clinton 950
Gallatin 1255.2
Rogersville 823.3
New Johnsonville 1485.2
Kingston 1700
.Walts Bar Dam 240
Cumberland 2600*
Daisy 2441.2*
F
P
F
F
F
F
F
F
N
Al-22
-------
EPA REGION V
Region: Illinois, Indiana, Michigan, Minnesota, Ohio, Wisconsin
Region Office: Chicago, Illinois
ILLINOIS
Utility
Central 111. Light Co.
Central Illinois Public
Service Co.
Commonwealth Edison Co.
Plant
Locat ion
Gen. Capacity
MW
R. S. Wallace
Liberty Street
E . D . Edwards
Keystone
Coffeen
Grand Tower
Hutsonville
Meredosia
Ridge land
Powerton
Joliet
Fisk
Dresden Nuclear #1
Dresden #2 & 3
Fordom
Crawford
Ca lumet
Waukegan
Dixon
Will County
Sabrooke
East Peoria
Peoria
South of Peoria
Bartonville
Coffeen
Grand Tower
Hutsonville
Meredos ia
Stickney
Pekin
Joliet
Chicago
•9
Morris
Morris
Rockford
Chicago
Chicago
Waukegan
Dixon
Joliet
Rockford
351.4
25
416
350*
54.4
389
600*
232.66
212.5
354.4
690
315
840*
1862
144
546.6
25
226.1
208
1620
75.3
701.5
192
174
292
1042
113
119
1258.9
196.4
148
F
F
F
F
F
F
F
F
F
F
F
F
F
F
G
F
F
G
N
N
F
F
G
F
G
F
G
F
F
F
G
Al-23
-------
EPA REGION V
ILLINOIS (continued)
Utility
Commonwealth Edison Co.
Electric Energy, Inc.
Illinois Power Co.
Plant
Kincaid
Quad Cities
Zion
LaSalle County
Joppa
Havana
Hennepin
Vermilion
Wood River
Baldwin
Location
Kincaid
Near Albany
Waukegan
Seneca
Elen
Havana
Hennepin
Oakwood
East Alton
Baldwin
Gen. Capacity
MW
1319.4
1618*
2100*
1156*
1078*
1100
230
306.3
182.3
15.0
650
623
1246.1*
Typ<
F
N
N
N
N
F
F
F
F
G
F
F
F
Mt. Carmel Public Mt. Carmel
Utility Co.
Carlyle Municipal Carlyle
Utilities
Highland Electric Highland
Light Dept.
Mascoutah Munic. Light Mascoutah
& Water Dept.
McLeansboro Munic. Light McLeansboro
& Power Plant
Mt. Carme1
Carlyle
Highland
Mascoutah
McLeansboro
20.5
12.5
0.75
Rochelie Municipal Rochelie
Utilities
Springfield Water, Lakeside
Light & Power Dept. Dallman
Rochelie
Springfield
Springfield
12.5
155
70.2
F
F
Al-24
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EPA REGION V
ILLINOIS (continued)
Utility
Winnetka Municipal
Electric & Water Dept.
Southern Illinois
Power Cooperative
Western Illinois Power
Cooperative, Inc.
University of Illinois
Union Electric Co.
Peru Light Dept.
Iowa-Illinois Gas &
Electric Company
Chicago, Metropolitan
Sanitary District
Utility
Indiana & Michigan
Electric Co.
Indianapolis Power &
Light Company
Plant
Winnetka
Marion
Pearl
Abbott
Cahokia
Venice No. 1 & 2
Peru
Mo line
Chicago
INDIANA
Plant
Twin Branch
Tanners Creek
Breed
H. T. Pritchard
Elmer W. Stout
C. C. Perry
(Sec. K)
C. C. Perry
(Sec. W)
Petersburg
Location
Winnetka
Gen. Capacity
MW
25.5
South of Marion 94
Jacksonville
Sauget
Venice
Peru
Moline
Chicago
Location
Mishawka
Lawre ncebur g
Sullivan
Martinsville
Indianapolis
Indianapolis
Indianapolis
Petersburg
27.2
27.2
304
529
15.3
99.1
30.5
Gen. Capacity
MW
384
1098
450
393.6
372.6
47.5
11
724.4
Typ<
F
F
F
F
F
F
F
F
F
Typ<
F
F
F
F
F
F
F
F
Al-25
-------
EPA REGION V
INDIANA (continued)
Utility
North Indiana Public
Service Company .
Public Service Co.
of Indiana, Inc.
Southern Indiana Gas &
Electric Company
Logansport Municipal
Utilities
Plant
Location
Gen. Capacity
MW
Michigan City
Dean H. Mitchell
Bailly
Dresser
Edwardsport
Noblesville
Wabash River
Robert A. Gallagher
Rushville
Cayuga
Ohio River
Culley
Warrick Unit #4
Logansport
Michigan City
Gary
Dune Acres
Terre Haute
Edwardsport
Noblesville
West Terre Haute
New Albany
Rushville
Cayuga
Evansville
Newburgh
Yankeetown
Logansport
211
529.4
52.2
615.6
33.9
535*
210
146.8
100
962
8
600
8.25
500
500*
121.5
153.7
250*
150
55.5
18
F
F
G
F
G
F
F
F
F
F
G
F
F
F
F
F
F
F
F
F
G
Peru Electric Light &
Power Dept .
Indiana Statewide Rural
Electric Corp., Inc.
Indiana -Kentucky
Electric Corp.
Frankfort Light &
Power Dept.
Peru
Petersburg
Clifty Creek
Frankfort
Peru
Petersburg
Madison
Frankfort
40
200*
1303.6
32.5
16.5
F
G
Al-26
-------
EPA REGION V
INDIANA (continued)
Utility
Crawfordsville Elec.
Light & Power Co.
Commonwealth Edison Co.
of Indiana, Inc.
Plant
Crawfordsville
State line
Gen. Capacity
Location MW Type
40.2 F
Crawfords ville
Hammond
972
Richmond Power and
Light Dept.
Whitewater Valley Richmond
Johnson Street Richmond
Richmond
30
30
66*
F
F
F
MICHIGAN
Utility
Consumer Power Co.
Plant
Gen. Capacity
Location MW Type
John C. Weadock
Saginaw River
Dane E. Karn
Bryce E. Morrow
Kalamazoo .
Elm street
Justin R. Whiting
B. C. Cobb
Wealthy Street
J. H. Campbell
Big Rock
Palisades
Midland
Essexville
Saginaw
Essexville
Comstock
Kalamazoo
Battle Creek
Erie
Muskegon
Grand Rapids
West Olive
Charlevoix
Palisades
Free Pond
614.5
' 20.6
100
530
615*
186
35
20
30
325
20.6
510.5
20
650
20.6
75
811.7*
1381.3*
F
G
F
F
F
F
G
F
F
F
G
F
F
F
G
N
N
N
Al-27
-------
EPA REGION V
Utility
Detroit Edison Co.
Indiana & Michigan
Power Co.
Plant
MICHIGAN (continued)
Location
Gen. Capacity
MW
Donald C. Cook
Upper Peninsula Power Co. Escanaba
John H. Warden
Presque Isle
Bridgman
Escanaba
L'Anse
Marquette
2200*
25.3
15.6
174.7
170*
Beacon St.
St. Clair
River Rouge
Greenwood Energy
Center
Conners Creek
Trenton Channel
Delray
Marysville
Pennsalt
Wyandotte North
Wyandotte South
Port Huron
Harbor Beach
Monroe
Fermi
French Island
Detroit
Bell River
River Rouge
Detroit
Detroit
Trenton
Detroit
Marysville
Wyandotte
Wyandotte
Wyandotte
Port Huron
Harbor Beach
Monroe
Detroit
27.8
1905
18.6
933.2
800*
585
1075.5
391
300
37
54.1
18.5
11.75
121
3000*
158
64
1075*
136
F
F
G
F
N
F
F
F
F
F
F
F
F
F
F
N
G
N
F
F
F
F
F
Coldwater Board of
Public Utilities
Coldwater
Coldwater
11.125
Detroit Public Lighting
Commission
Mistersky
Detroit
174
Escanaba Municipal
Electric Utility
Escanaba
Wells
25
Al-28
-------
EPA REGION V
MICHIGAN (continued)
Utility
Grand Haven Board of
Light & Power
Plant
Location
Island Steam Plant Grand Haven
Gen. Capacity
MW Type
20 F
Holland Board of
Public Works
James De Young Holland
77.2
Lansing Board of Water
and Light
Marquette Board of
Light & Power
Ottawa
Eckert
Delta
Lansing
Lansing
Lans ing
Marquette Gen.Pit. Marquette
81.5
381
160*
34.5
F
F
F
Traverse City Light
& Power Dept.
Traverse City Pit. Bay
35
Northern Michigan
Electric Coop., Inc.
Advance
Boyne City
41.8
Michigan State Univ.
Wyandotte Munic.
Service Commission
Utility
Minnesota Power &
Light Co.
Northern State Power
Co. (Minn.)
Sixty- five
Wyandotte
MINNESOTA
Plant
Aurora
Clay Boswell
M. L. Hibbard
Black Dog
High Bridge
Island
East Lansing
Wyandotte
Location
Aurora
Cohasset
Duluth
Nichols
St. Paul
St. Paul
31
41.5
23
Gen. capacity
MW
116.1
150
122.5
480.7
458.8
16
F
F
G
Type
F
F
F
F
F
F
Al-29
-------
EPA REGION V
MINNESOTA (continued)
Utility
Northern State Power
Co. (Minn.)
Otter Tail Power Co.
Alexandria Board of
Public Works
Austin Utilities
Plant
Locat ion
Gen. Capacity
MW
King
Mont ice llo
Red Wing
Minnesota Valley
Rivers ide
South East
Whitney
Wilmarth
Winona
Prairie Island
Crockston
Hoot Lake
Canby
Ortonville
Bemid j i
Alexandria
Austin
Bayport
Mont ice llo
Red Wing
Granite Falls
Minneapolis
Minneapolis
St. Cloud
Mankato
Winona
Near Hasting
Crockston
Fergus Falls
Canby
Ortonville
Bemid j i
Alexandria
Austin
598.4
569
28
65
506.4
30
21
25
26
1186*
10
136.9
7.5
15
37
5.25
27.5
6
30
F
N
F
F
F
F
F
F
F
N
F
F
F
F
F
F
F
G
N
Benson Water & Light
Dept.
Blue Earth Power &
Water Dept.
Detroit Lakes Public
Utilities Dept.
Fairmouht Public
Utilities Commission
Benson
Blue Earth
Detroit Lakes
Fairmount
Benson 0.45
Blue Earth 5.0
Detroit Lakes 6.0
Fairmount 26.5
Jackson Electric Light
Dept.
Jackson
Jackson
2.0
Al-30
-------
EPA REGION V
MINNESOTA (continued)
Utility
Litchfield Public
Utilities Commission
Luverne Municipal util. Luverne
Madison Munic. Util.
Marshall Munic. Util.
Moorhead Public
Service Dept.
Mountain Iron (MUN)
New Ulm Public Util.
Commission
Owatonna Municipal Owatonna
Public Utilities
Redwood Falls Public Redwood
Utilities Comm.
Rochester Public Rochester
Utility Dept.
Sleepy Eye Munic.Util. Sleepy Eye
Springfield Pub. Util. Springfield
Two Harbor Municipal Two Harbors
Water & Light Plant
Virginia Dept. of Virginia
Public Utilities
Plant
Litchfield
Luverne
Madison
Marshall
Moorhead
Mountain Iron
New Ulm
Location
Litchfield
Luverne
Madison
Marshall
Elm St. South
Mountain Iron
New Ulm
Gen. Capacity
MW
3.5
3.0
1.85
3.0
16.5
34
10
1.2
27
Type
F
F
F
F
G
F
G
F
F
Owatonna 34.5
Redwood Falls 2.0
Rochester 113
Sleepy Eye 3.25
Springfield 2.75
Two Harbor 6.0
F
F
F
Virginia
34.5
Al-31
-------
EPA REGION V
MINNESOTA (continued)
Utility
Willmar Municipal
Utilities Commission
Windom Munic. Util.
Worthington Munic.
Public Utilities
Northern Minn. Power
Association
Assn.
Interstate Power Co.
Utility
Cincinnati Gas &
Electric Co.
Cleveland Electric
Illuminating Co.
Plant
Willmar
Windom
Worthington
Kettle River
Elk River
Albert Lea
Fox Lake
OHIO
Plant
West End
Miami Fort
W. C. Beckjord
J. M. Suaurt
Zimmer
Ashtabula
Avon Lake
East Lake
Lake Shore
Location
Willmar
Windom
Worthington
Kettle River
Elk River
Albert Lea
Sherburn
Location
Cincinnati
North Bend
New Richmond
Aberdeen
Near Berlin
Ashtabula
Avon Lake
East Lake
Cleveland
Gen. Capacity
MW
32.4
3.0
16.5
4.25
45.0
22
17.2
18.5
104
Sen. Capacity
MW
219.3
519.2
182
760.5
460.8*
1830
610*
1756*
456
1275
577
680*
514
Type
F
F
F
F
F
N
G
F
F
Type
F
F
G
F
F
F
F
N
F
F
F
F
F
Al-32
-------
EPA REGION V
Utilities
Columbus & Southern
Ohio Electric Co.
The Dayton Power &
Light Co.
Ohio Edison Company
Ohio Power Company
Plant
OHIO (continued)
Location
Gen. Capacity
MW
Poston
Conesville
Picway
Walnut
Miamisburg
J. M. Straut
Frank M. Tait
O. H. Hutchings
Troy
W. H. Sammis
R. E. Burger
Toronto
Niles
Edgewater
Gorge
Mad River
Scioto
Muskingum River
Woodcock
Tidd
Philo
Cardinal
Genl. James M.Gavin
Caldwell
Martins Ferry
Athens
Conesville
Columbus
Columbus
Miamisburg
Aberdeen
Dayton
Dayton
Troy
Stratton
Shady Side
Toronto
Niles
Lorain
Akron
Springfield
Scioto
Beverly
Bluffton
Brilliant
Philo
Brilliant
Near Gallipolis
Caldwell
Martins Ferry
232
13.8
433.5
842*
13.8
230.8
251.28
75
65.3'
6.4
610.2
444.1
414
32.6
24
1979
323*
544
315.8
250
174.9
87.5
75
40.3
1466.8
42.5
222.2
500
1270.5
2600*
2.8
6.5
2.0
F
G
F
F
G
F
G
F
G
F
F
F
F
G
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
G
Al-33
-------
EPA REGION V
OHIO (continued)
Utility
Ohio Valley Elec. Corp.
Toledo Edison Co.
Cleveland Div. of
Light & Power
Columbus Munic. Electric Columbus
Light Dept.
Celina Munic. Util.
Dover Electric Dept.
East Palestine Munic.
Elect. Dept.
Hamilton Dept. of
Public Utilities
Napoleon Munic. Util.
Norwalk Municipal
Elect. Dept.
Orriville Munic. Util.
Gen. Capacity
Plant
Kyger Creek
Bay Shore
Acme
Clyde
Davis -Bee se
Lake Rd.
East 53rd St.
West 41st St.
Columbus
Celina
Dover
East Palestine
Hamilton
Napoleon
Wood lawn Ave.
Orriville
Location
Gallipolis
Oregon
Toledo
Clyde
Toledo
Cleveland
Cleveland
Cleveland
Columbus
Celina
Dover
East Palestine
Hamilton
Napoleon
Norwalk
Orriville
MW
1086.3
639.5
16
307
30
1
2
870*
172.5
50
35.6
43.5
14.5
25
20*
33.2
16.5
84
28.9
22.65
31.3
38.5
62.5*
Typ«
F
F
G
2'
F'
F
F
N
F
F
F
F
G
F
G
F
F
F
G
F
F
F
F
5 Hz
Painesville Electric
Power Dept.
Painesville
Painesville
38
Al-34
-------
EPA REGION V
OHIO (continued)
Gen. Capacity
Utility
Piqua Munic. Power Plant Piqua
Reading Municipal Water Prospect
and Light Plant
St. Marys Munic. Light
& Power
Shelby Munic. Elect.
Plant
Utility
Lake Superior District
Power Co.
Madison Gas G Elect.Co.
Northern States Power
Co. (Wisconsin)
Superior Water, Light &
Power Co.
Wisconsin Electric
Power Co.
Plant
Piqua
Prospect
St. Marys
Shelby
WISCONSIN
Location
Piqua
Read ing
St. Marys
' Shelby
MW
53
9.5
14*
22
26.5
12.5*
3
2600*
Type
F
F
F
F
F
F
G
N
Gen. Capacity
Plant
Bay Front
Blount
Edison
French Is land
Sherbourne
Wins low
Lakeside
Commerce
East wells
Port Washington
Port Washington
North Oak Creek
South Oak Creek
Location
Ashland
Madison
La Crosse
La Crosse
Superior
St. Francis
Milwaukee
Milwaukee
Port Washington
Port Washington
Oak Creek
Oak Creek
MW
82.2
195.5
5
25
1360*
25.2
344.7
35
13.7
400
19
500
1170
19
Type
F
F
F
F
F
F
F
F
F
G
F
F
G
Al-35
-------
EPA REGION V
WISCONSIN (continued)
Utility
Plant
Location
Gen. Capacity
MM Type
Wisconsin Electric
Power Co .
Wisconsin Power & Light
Company
Wisconsin Public Service
Corp.
Manitowoc Public Util.
Marshfield Electric &
Valley
Point Beach
Point Beach 1 & 2
Edgewater
Rock River
Black Hawk
Nepson Devy
Kewaunee
Columbia
Pulliam
Weston
Manitowoc
Wildwood
Milwaukee
Two Creeks
Manitowoc
Sheboygan
Beloit
Beloit
Cassville
Kewaunee
Near Portage
Green Bay
Rothschild
Manitowoc
Marshfield
269.7
19.6
1005.7
351
129
159.4
46.8
57.5
227.3
527*
527*
392.5
135
19.6
75
50.2
F
F
N
F
F
' F
G
F
F
N
F
F
F
G
F
F
Water Dept.
Menasha Electric &
Water Utilities
Menasha
Menasha
29.2
Richland Center Munic.
Utilities
Richland Center
Richland Center
14.2
Dairyland Power Coop.
Alma
Stoneman
Genoa St. #1
Genoa St. #2
Genoa St. #3
Alma
Cassville
Genoa
Genoa
Genoa
187
51.8
14.0
50
300
F
F
F
N
F
Oconto Elec. Coop.
Stiles
Stiles
Al-36
-------
EPA REGION VI
Region: Arkansas, Louisiana, New Mexico, Texas, Oklahoma
Region Office: Dallas, Texas
ARKANSAS
Utility
Plant
Location
Gen. Capacity
MW Type
Arkansas Power & Light Co.
Hope Water & Light Pit.
Jonesboro Water & Light
Plant
Arkansas Electric Coop.
Corp.
Robert Ritchie
Lake Catherine
Cecil Lynch
Harvey Couch
Hamilton Moses
Russellville
Hope
Jonesboro
Fitzhugh
Bailey
McClellan
Helena
Hot Springs
N. Little Rock
Stamps
Forest City
Russellville
Hope
Jonesboro
Ozark
Augusta
Camden
903.6
18
756.0
259.8
187.5
138
793*
920*
6
27.7
59.8
122
200*
134
F
G
F
F
F
F
N
N
F
F
F
F
F
F
Utility
Central Louisiana
Elec. Co., Inc.
New Orleans Public
Service, Inc.
LOUISIANA
Plant
Coughlin
Teche
Little Gypsy
Nine Mile Point
Sterlington
Mark St. Station
A. B. Patterson
Michoud
Location
Gen. Capacity
MW Type
St. Landry
Baldwin
La Place
Westwego
Sterlington
New Orleans
New Orleans
New Orleans
483.3
428
1250.8
1101
351.5
96.3
218.3
959.3
F
F
F
F
F
F
F
F
Al-37
-------
EPA REGION VI
LOUISIANA (continued)
Utility
Southwestern Electric
Power Co.
Alexandria Munic. Power
& Light Dept.
Homer Light & Power
Dept.
Houma Munic. Light Pit.
Lafayette Util. System
Minden Light s Power
Dept.
Monroe Util. Comm.
Morgan City Munic.
Electric Plant
Natchitoches Munic.
Elec. Light & Water
Ruston Munic. Light Dept. Ruston
Opelousas Munic. Elec.
Dept.
Plaquemine Light Dept.
New Orleans Sewage &
Water Board
Plant
Arsenal Hill
Liberman
Alexandria
Homer
Houma
Rodemacher
Louis "Doc" Bonin
Minden
Park Ave.
Morgan
Natchitoches
Ruston
Opelousas
Plaquemine
Power House No. 2
Location
Shreveport
Mooringsport
Alexandria
Homer
Houma
Lafayette
Lafayette
Minden
Monroe
Morgan City
Natchitoches
Ruston
Opelousas
Plaquemine
New Orleans
Gen. Capacity
MW
170.0
277.3
97.5
80*
8.7
40.7
45.7
143.3
25
172
10
31
55.8
41.4
12.7
26*
20.5*
10.8
47.0
20
Type
F
F
F
F
F
F
F
F
F
F
G
F
F
F
F
F
F
G
F-25 Hz
G-25 HZ
Al-38
-------
EPA REGION VI
Utility
Gulf State Utilities Co.
Louisiana Electric
Coop., Inc.
Utility
New Mexico Electric
Service Co.
Public Service Co. of
New Mexico
Clayton Municipal
Electric System
Farmington Electric
Utility
The Raton Public
Service Company
Lea County Electric
Cooperative, Inc.
Plains Elec. Generation
& Trans. Coop., Inc.
Plant
LOUISIANA (continued)
Location
Gen. Capacity
MW Type
Louisiana St. #1&2
Roy S. Nelson
Willow Glen
River Bend #1&2
New Roads
NEW MEXICO
Plant
Maddox
Reeves
Person
Prager
Santa Fe
Baton Rouge
Westlake
St. Gabriel
Baton Rouge
Near Morganza
Location
Hobbs
Albuquerque
Albuquerque
Albuquerque
Santa Fe
428
920.5
994.4
530*
1880*
230*
Gen. Capacity
MW
118
175
125
35
12
F
F
F
F
N
F
Type
F
F
F
F
F
Clayton
Animas
Raton
Lea County
Plains
Clayton
Farmington 28.5
Raton 12
N. Lovington 59.6
Algodones 51.8
Al-39
-------
EPA REGION VI
NEW MEXICO (continued)
Plant
Utility
Southwestern Public
Service Co.
Arizona Public Service Co. Four Corners
U.S. Atomic Energy TA-3
Commission
Gallup Electric Light Gallup
& Power System
Locat ion
Gen. Capacity
MW
Nr.Farmington 2369.8
Los Alamos 20
Gallup
16.1
Cunningham
Carlsbad
Roswell
Hobbs
Carlsbad
Roswell
265.4
44.3
24.2
11.5
F
F
F
G
TEXAS
Utility
Central Power & Light Co.
Dallas Power & Light Co.
El Paso Electric Co.
Plant
Locat ion
Gen. Capacity
MW Type
La Palma
Victor P.S.
Nueces Bay
Lon C. Hill
Laredo P.S.
J. L. Bates
E. S. Jospin
Dallas
Mountain Creek
Parksdale
North Lake
Lake Hubbard
Big Brown
Rio Grande
Newman
San Benito
Victoria
Corpus Christ i
Calallen
Laredo
Mission
Point Comfort
Dallas
Dallas
Dallas
Dallas
Dallas
Dallas
El Paso
El Paso
217
553.5 .
244.5
574.2
72
188.7
234.9
223.5
989.7
340.6
708.6
396.5
526.0*
83.3
235
265.8
F
F
F
F
F
F
F
F
F
F
P
F
F
F
F
F
Al-40
-------
EPA REGION VI
TEXAS (continued)
Utility
Gulf State util. Co.
Houston Lighting &
Power Company
Southwestern Electric
Service Co.
Plant
Gen. Capacity
Location MW Type
Neches
Sabine
Lewis Creek
Deepwater
Gable Street
Deepwater -Champion
Hiram O. Clarke
Greens Bayou
Cedar Bayou
Webster
Bertrom, Sam
T. H. Wharton
W. A. Parish
P. H. Robinson
Beaumont
Bridge City
Willis
Houston
Houston
Houston
Houston
Houston
Bayton
Webster
Houston
Houston
Richmond
Bacliff
452.3
952
580*
500
334.125
84.1
334.9
210
96
375
692
823*
614
16.3
826.3
49
322.8
16.3
1255.4
16.3
1549.5
16.3
.. ifl -. ..
F
F
F
F
F
F
F
F
G
F
F
F
F
G
F
G
F
G
F
G
F
G
Jacksonville
Alabama
11.0
Southwestern Public
Service Co.
Plant "X"
Nichols
Denver City
East Plant
Riverview
Jones.
Moore County
Tuco
Earth, Tex. 434.4
Amarillo, Tex. 474.8
Denver City,Tex. 87.5
Amarillo 71
Borger 69.5
Lubbock 235.2
Sunray 68.2
Abernathy 40
F
F
F
F
F
F
F
F
Al-41
-------
EPA REGION VI
TEXAS (continued)
Utility
Texas Electric Service
Company
Texas Power s Light Co.
West Texas Util. Co.
Austin Electric Dept.
Plant
Location
Gen. capacity
MW Type
Graham
Eagle Mountain
Hand ley
North Main
Wichita Falls
Permian Basin
Morgan Creek
Big Brown
Collin
Lake Creek
River Crest
Stryker Creek
Trading House Creek
Trinidad
Valley
Waco
De Cordova
Abilene
Concho
Pauline
Oak Creek
Paint Creek
Rio Pecos
San Angelo
Seaholm Station
Holly Street
Decker Creek
Graham
Fort Worth
Fort Worth
Fort Worth
Wichita Falls
Monahans
Colorado City
Fair fie Id
Frisco, Tex.
Waco , Tex .
Bogata
Rusk, Tex.
Waco, Tex.
Trinidad, Tex.
Savoy, Tex.
Waco, Tex.
Abilene, Tex.
San Angelo
Quanah
Bronte
Stamford
Girvin, Tex.
San Angelo
Austin
Austin
Austin
634.8
706.2
523.4
116.3
25
165
535.5*
845.8
593
156.3
315.6
112.5
703.5
588.2
799.2*
413.3
1175
13
775*
26.3
52.5
44.5
81.6
241.6
136.5
5.0
100.8
32.6
134
416
300
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
G
F
G
F
F
F
Bryan Municipal
Elect. System
Bryan
Bryan
128.7
Al-42
-------
EPA REGION VI
TEXAS (continued)
Gen. Capacity
Utility
Coleman Munic. Power
& Light Dept.
Denton Munic. Util.
Garland Electric Dept.
Greenville Munic. Light
s Power Dept.
Lubbock Power & Light
Dept.
San Antonio Public
Service Board
Brownsville Public
Utilities Board
Brazos Electric Power
Coop., Inc.
South Texas Electric
Coop., Inc.
Texas ASM University
Lower Colorado River
Authority
Plant
Coleman
Denton
C. E. Newman
Ray Olinger
Greenville
Holly Ave.
Leon Creek
Mission Rd.
W. B. Tuttle
W. H. Brattnig
Owsommers
Pearsall
Comal
Silas Ray
Poage
Worth Tex.
Randle W. Miller
Sam Rayburn
Univ. Utilities
Comal
Sim Gideon
Granite Shoals
Location
Coleman
Denton
Garland
Garland
Greenville
Lubbock
San Antonio
San Antonio
San Antonio
San Antonio
San Antonio
San Antonio
San Antonio
Brownsville
Belton
Weathorford
Palo Pinto
Nursery
College Station
New Braunfels
Bastrop
Marble Falls
MW
9.2
123.8
96.5
187
48.2
130.5
29.5
263.6
163.6
493.9
882
430
75
60
53.0
15.0
23
81.6
166
25
23
22.25
60
250
315*
408*
Type
F
F
F
F
F
F
G
F
F
F'
F
F
F
F
F
G
F
F
F
F
G
F
F
F
F
F
Al-43
-------
EPA REGION VI
Utility
Southwestern Electric
Power Co.
Utility
Oklahoma Gas & Elect.Co.
Public Service Co. of
Oklahoma
Kingfisher Munic. Light
Dept.
Ponca City Munic.
Water & Light Dept.
Stillwater Water &
& Light Dept.
Plant
TEXAS (continued)
Location
Gen. Capacity
MW Type
Knox Lee
Lone Star
Wilkes
OKLAHOMA
Plant
Seminole Sta .
Horse Shoe Lake
Mustang
Arbuckle
Belle Isle
Riverbank
Osage
Byng
Southwestern
Tulsa
Weleetka
Northeastern
Lawton
Long view
Lone Star
Jefferson
Location
Konawa
Harrah
Okla. City
Sulphur
Okla. City
Muskogee
Ponca City
Byng
Washita
Tulsa
Weleetka
Oolagah
Lawton
186
50
49
869.5
Gen. Capacity
MW
567
22
916.2
27.2
509.3
80
73.5
55.0
8.0
195.9
40
14
482.7
482
83
642.5
29.5
F
F
G
F
Type
F
F
F
G
F
G
F
F
G
F
F
F
F
F
F
F
F
Kingfisher
Ponca City
Boomer Lake
Kingfisher
Ponca City
Stillwater
16.5
22.65
Al-44
-------
EPA REGION VI
OKLAHOMA (continued)
Gen. Capacity
Utility Plant Location MW Type
Western Farmers Anadarko Anadarko 83 p
Electric Coop. Mooreland Mooreland 191 F
Grand River Dam Chouteau chouteau 56.3 F
Al-45
-------
EPA REGION VII
Region: Iowa, Kansas, Missouri, Nebraska
Region Office: Kansas City, Missouri
IOWA
Utility
Interstate Power Co.
Iowa Electric Light
& Power Co.
Iowa, Illinois Gas &
Electric Co.
Iowa Power & Light Co.
Iowa Public Service Co.
Iowa Southern Util. Co.
Plant
M. L. Kapp
Dubuque
Lans ing
Mason City
Sutherland
Boone
Iowa Falls
Cedar Rapids
Duane Arnold
Rivers ide
Des Moines Pwr.
Station #2
Council Bluffs
Neal
Maynard
B ig S ioux
Kirk
Hawkeye
I.P.S. Gen. Pit.
I.P.S. Gen. Pit.
Charles City
Burlington
Bridgeport
Location
Clinton
Dubuque
Lans ing
Mason City
Marshaltown
Boone
Iowa Falls
Cedar Rapids
Cedar Rapids
Beltendorf
Des Moines
Council Bluffs
Sioux City
Waterloo
Sioux City
Sioux City
Storm lake
Caroll
Eagle Grove
Burlington
Eddyville
Gen. Capacity
MW
237.2
91.3
64
23.5
156.6
34.3
12.8
92.3
550*
237
72
324.6
103.6
147
300*
107.4
41
17.5
19
> 10.75
7.5
4.5
36.0
212
71
Type
F
F
F
F
F
F
F
F
N
F
G
F
F
F
F
F
F
F
F
F
F
F
G
F
F
Al-46
-------
EPA REGION VII
IOWA (continued)
Gen. Capacity
Utility
Ames Electric Utility
Atlantic Munic. Util.
Cedar Falls Munic. Util.
Denison Munic. Util.
Grundy Center Munic.
Light & Power
Harlan Munic. Util.
Mt. Pleasant Util.
Muscatine Power &
Water Dept.
Pella Munic. Power &
Light Dept.
Sibley Munic. Util.
Spencer Munic. Util.
Trear Munic. Util.
Webster City. Munic.
Light & Power Dept.
Central Iowa Power Coop.
Corn Belt Pwr. Coop.
Plant
Ames Municipal
Atlantic
Streeter
Denison
Grundy Center
Harlan
Mt. Pleasant Munic.
Muscatine
Pella
Sibley
Spencer
Trear
Webster City
Prairie Creek
Summit Lake
Location
Ames
Atlantic
Cedar Falls
Denison
Grundy Center
Harlan
Mt. Pleasant
Muscatine
Pella
Sibley
Spencer
Trear
Webster City
Cedar Rapids
MW
63.7
14.75
31.3
22
4.5
1.25
6.4
13.3
108
17.0
2.5
17.5
22.4
1
15.4
20.6
244.7
22.5
Typt
F
F
F
G
F
F
F
F
F
F
F
F
G
F
F
G
F
F
Humbolt
43.8
Al-47
-------
EPA REGION VII
Utility
Central Kansas Power Co.
Kansas Gas & Elec. Co.
Plant
Location
Gen. Capacity
MW_ Type
Kansas Pwr. & Light Co.
Western Power Div.
Central Telephone &
Utilities Corp.
Anthony Electric Dept.
Chanute Munic. Elec.Dept.
Clay Center Munic.
Electric Dept.
Coffeyville Munic. Water
& Light Dept.
lola Electric Dept.
Kansas City Board of
Public Utilities
Lamed Elec. Light Dept. Larned
Hays
Ross Beach
Colby
Gordon Evans
Murray Gill
Neosho
Ripley
Wichita
Tecumseh
Lawrence
Hutch ins on
Abilene
Phillipsburg
Arthur Mullergren
Power Station
Chanute
Clay Center
Coffeyville
Municipal
KAW
Quindaro
Hays
Hill City
Colby
Wichita
Wichita
Parsons
Wichita
Wichita
Tecumseh
Lawrence
Hutchinson
Abilene
Phillipsburg
Great Bend
Anthony
Chanute
Clay Center
Coffeyville
lola
Kansas City
Kansas City
17
35
12
539.3
348.3
113.5
87.3
22.8
346.1
613.4
252.2
33.8
3.0
133.5
5.25
19
12.5
40.25
15.5
161.3
331.6
15
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
G
Larned
12.8
Al-48
-------
EPA REGION VII
KANSAS (continued)
Utility
Plant
Location
Gen. Capacity
MW Type
Mepherson Board of
of Public Utilities
Ottawa Water & Light
Dept.
Pratt Munic. Elect. Dept.
Washington Munic . Light
Plant
Winfield Munic. Elec.
Wheatland Elec. Coop., Inc.
Sunflower Elec. Coop.
Empire Dist. Elec. Co.
Utility
Empire Dist. Elec. Co.
Kansas City Power &
Light Co.
Mepherson #1
Mepherson #2
Ottawa
Pratt
Washington
Winfield
Winfield
Garden City
Ross Beach
Riverton
MISSOURI
Plant
Asbury
Motrose
Hawthorn
Northeast
Grand Avenue
Mepherson
Mepherson
Ottawa
Pratt
Washington
Winfield
Winfield
Garden City
Ros£ Beach
Riverton
Location
Clinton
Kansas City
Kansas City
Kansas City
25.5
32
7.25
11.8
23.8
4.8
18
11.3
26.5
28.5
15
25
42.5
112.5
12.5
Gen. Capacity
MW
200
563.1
887
156
116.8
10
F
F
t
F
G
F
F
F
G
F
F
G
F
F 25 Hz
F
G
Type
F
F
F
F
F
F 25 Hz
Al-49
-------
EPA REGION VII
MISSOURI (continuted)
Utility
Plant
Location
Gen. Capacity
MW Type
Missouri Public Service
Inc.
St. Joseph Light &
Power Co.
Union Electric Co.
Chillicothe Munic.Util.
Columbia Water & Light
Dept.
Fulton Board of Public
Works
Hannibal Board of Public Hannibal
Works
Independence Power &
Light Dept.
Macon Municipal Util.
Sikeston Board of
Munic. Utilities
Springfield City Util.
Northeast Missouri
Elec. Power Corp.
Gen. Plant
Gen. Plant
Sibley
Ralph Green
St. Joseph Gen. Pit.
St. Joseph Gen. Pit.
Labad ie
Meramec
Ashley
Mound
Sioux
Chillicothe
Columbia
Fulton Pit. #1
Fulton Pit. #2
Hannibal
Blue Valley
Dodgion Street
Macon
Coleman
James River
Gen. Plant
Jefferson City
Mexico
Sibley
Pleasant Hill
St . Joseph
St . Joseph
Labad ie
SE St. Louis Co.
St. Louis
St. Louis
Near Portage Des
Sioux
Wabash Tracks
Columbia
Fulton
Fulton
Hannibal
Independence
Independence
Macon
S ikes ton
K is sick
South River Sta.
12.7
19
518
49.5
42.5
150.5
1110
923
70
40
1099.6
15
90
11.5
8.3
34
115
. 10
4.5
6.25
268
15
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
Al-50
-------
Utility
EPA REGION VII
MISSOURI (continued)
Plant Location
Gen. Capacity
MW Type
N.W. Electric Pwr. Coop., Generation Pit. Missouri City 40
Inc.
Arkansas-Missouri
Power Co.
Jim Hill
33
ASEC
Thomas Hill
Central Elec. Power Coop. Chamois
440*
59
F
F
NEBRASKA
Utility Plant
Alliance Munic. Elec. Alliance
Dept.
Fairbury Light & Water Fairbury
Dept.
Location
Alliance
Fairbury
Gen. Capacity
MW
16.5
21.5
Type
F
Fremont Dept. of Util.
Grand Island Elec. Dept.
Hasting Utilities Dept.
Schuyler Dept. of Util.
Central Nebraska Public
Power & Irrigation Dist.
Nebraska Public Power
District
Fremont
C. W. Brudick
Hasting
Schuyler
Canady
Bluffs
Gen. Plant
Sheldon
Kramer
K Street
Cooper
Fremont
Grand Is land
Hasting
Schuyler
Lexington
Scottsbluff
Ogallala
Hallam
Bellevue
Lincoln
Nr. Nebraska City
70.0
70.5
60*
54
9
100
42.4
9
228.6
113
31.1
800*
F
F
F
F
F
F
F
F
F
F
F
N
Al-51
-------
EPA REGION VII
NEBRASKA (continued)
Gen. Capacity
Utility Plant Location MW Type
Omaha Public Pwr. Dist. Jones Street Omaha 173.5 F
North Omaha Omaha 644.7 F
South Omaha Omaha 20 F
Ft. Calhoun Omaha 455* N
Al-52
-------
EPA REGION VIII
Region: Colorado, Montana, North Dakota, South Dakota,
Utah, Wyoming
Region Office: Denver, Colorado
COLORADO
Gen. capacity
Utility
Public Service Co. of
Colorado
Central Telephone &
Utilities Corp.
Western Colorado Power Co.
Colorado Springs Dept.
of Public Utilities
Burlington Municipal
Light & Power
Ft. Collins Light & Power
Lamar Utilities Board
Plant
Valmont
Zuni
Alamosa
Arapahoe
Cameo
Cherokee
Ft. St. Vrain
Comenche
Pueblo
Canon C:ty
Rocky Ford
J. Bullock
Durango
Oliver
G. Bridsall
Martin Drake
Burlington
Ft. Collins
Lamar
Location
Va Imont
Denver
Alamosa
Denver
Cameo
Denver
Plattsville
Comenche
Pueblo
Canon City
Rocky Ford
Mont rose
Durange
Paonia
Colorado Springs
Colorado Springs
Burlington
Ft. Collins
Lamar
MW
281.8
115.3
18.9
250.5
75
250.5
330*
350
30
43.8
7.5
10
5
3
62.5
150
7.5
8.0
34
Typ
F
F
F
F
F
F
N
F
F
F
F
F
F
F
F
F
F
F
F
Trinidad Municipal
Power & Light
Trinidad
Trinidad
7.5
Al-53
-------
DRAFT
Utility
Walsenburg Utilities
Colorado utilities
Elec. Assn. Inc.
Utility
Montana-Dakota
Utilities Co.
Montana Light & Power
Montana Power Co.
Utility
Montana-Dakota
Utilities Co.
Valley City Municipal
Utility
EPA REGION VIII
COLORADO (Continued)
Plant
Welsenburg
Hayden
Nucla
McGregor
MONTANA
Plant
Lewis & Clark
Glendive
Miles City
Baker
Libby
Troy
Frank Bird
J.E. Corette
NORTH DAKOTA
Plant
R. M. Heskett
Beulah
Williston
Location
Welsenburg
Hayden
Nucla
McGregor
Location
Sidney
Glendive
Miles City
Baker
Troy
Troy
Billings
Billings
Locat ion
Mandan
Beuhla
Williston
Gen. Capacity
MW
11.0
163.2
34.5
5.3
Gen. Capacity
MW
50
7
2
1
12.6
3.5
69
172.8
Gen. Capacity
MW
100.1
13.5
2
Type
F
F
F
F
Type
F
F
F
F
F
F
F
F
Type
F
F
F
Valley City
Valley City
Basin Electric Power Coop. Leland Olds
Stanton
240
Al-54
-------
EPA REGION VIII
NORTH DAKOTA (continued)
Utility
Central Power E lee. Coop.
Minnkota Power Coop., Inc.
United Power Assoc.
Utility
Black Hills Power & Light
Northern States Power Co .
Northwestern Public
Service Co.
Rushmore Elec . Power
Coop . , Inc .
Utility
Utah Power & Light
Plant
Wm. J. Neal
F. P. Wood
Milton R. Young
Stanton
SOUTH DAKOTA
Plant
Kirk
Ben French St.
Lawrence
Path Finder
Sioux Falls
Aberdeen
Mitchell
Kirk
UTAH
Plant
Carbon
Gads by
Hale
Jordan
Location
Velva
Grand Forks
Centre
Stanton
Location
Lead
Rapid City
Sioux Falls
Sioux Falls
Sioux Falls
Aberdeen
Mitchell
Near Whitewood
Location
Castle Gate
Salt Lake City
Or em
Salt Lake City
Gen. Capacity
MW
38
21.5
234.5
172
Gen. Capacity
MW
31.5
22
48
66
72
16
12.5
12.5
15
16.5
Gen. Capacity
MW
188.6
251.6
59
25.0
Type
F
F
F
F
Type
F
F
F
F
N
F
F
F
F
F
Type
F
F
F
F
Provo City Power
California-Pacific
Utilities Co.
Provo
Cedar
Provo
Cedar City
14
7.5
Al-55
-------
EPA REGION VIII
WYOMING
Utility
Plant
Montana-Dakota Utilities Acme
Black Hills Power & Light Neil Simpson
Osage
Pacific Power & Light Co. D. Johnaron
Trona
Location
Gen. Capacity
MW Type
Sheridan
Wyodak
Osage
Glenrock
Near Green River
12
27.7
34.5
456.7
330*
15.6
F
F
F
F
F
F
Utah Power & Light Co. Naughton
Rushmore Elec. Power
Coop., Inc. Naughton
Sinclair Refining Co. Sinclair
Kemmerer
S incla ir
707
380.8
200*
6.2
F
F
F
Al-56
-------
EPA REGION EC
Region: Arizona, California, Hawaii, Nevada
Region Office: San Francisco, California
ARIZONA
Utility
Tucson Gas & Elec. Co.
Arizona Elect. Power
Coop., Inc.
Salt River Project
Agricultural Impr. &
Power District
Southern Calif. Edison
Plant
Location
Gen. Capacity
MW
Yuma Axis
Saguaro
Ocotillo
Cholla Point
Phoenix
DeMos s - Pe tr ie
Irving ton
Apache
Agua Fria
Crosscut
Kyrene
Navajo
Yuma Axis
Yuma
Red Rock
Tempe
Joshep City
Phoenix
Tucson
Tucson
Cochise
Glendale
Tempe
Tempe
Paige
Yuma
86.7
250
227.3
113.6
116.0
104.5
504.5
75
11.3
390.5
30
108
2310
75
F
F
F
F
F
F
F
F
G
F
F
F
*F
F
Utility
Pacific Gas & Elec. Co.
CALIFORNIA
Plant
Location
Gen. Capacity
MW Type
Avon
Contra Costa
Humboldt Bay
Hunters Point
Kern
Avon
Antioch
Eureka
San Francisco
Bakers fie Id
40
1253.6
102.4
60
391.4
152
F
F
F
N
F
F
Al-57
-------
EPA REGION EC
Utility
Pacific Gas & Elec. Co.
(cont.)
San Diego Gas & Elec.Co.
Southern California
Edison Co.
Burbank Public Service
Dept.
Plant
CALIFORNIA (continued)
Location
Gen. Capacity
MW Type
Martinez
Morro Bay
Moss Landing
Oleum
Pittsburg
Potrero
Geysers
Diablo Canyon
Station B
Silver gate
Encina
South Bay
Redondo Beach
Long Beach
Etiwanda
Alamitos
El Segundo
Huntington Beach
Mandlay Steam
Ormond Beach
Highgrove
San Bernardino
Cool Water
San Onofre
Mangolia
Olive
Martinez
Morro Bay
Salinas
Oleum
Pittsburg, Cal.
San Francisco
Geysers
Near Oceano
San Diego
San Diego
San Diego
Chula Vista
Redondo Beach
Long Beach
Etiwanda
Long Beach
El Segundo
Hermosa Beach
Oxnard
Ormond Beach
Colton
Loma Linda
Dagget
San Clemente
Burbank
Burbank
40
1056.3
2152.2
80
1277.8
317.9
190
1134*
93
247
330.8
20
738.0
18.6
1579.4
180
911
138.1
1982.4
138.0
996.5
870.4
121
435.2
121
750
169
130.6
146.9
450
70
21
99
F
F
F
F
F
F
F
N
F
F
F
G
F
G
F
F
F
G
F
G
F
F
G
F
G
F
F
F
F
N.
F
G
F
Al-58
-------
EPA REGION DC
CALIFORNIA (continued)
Gen. Capacity
Utility
Glendale Public Service
Dept.
Los Angeles Dept. of
Water and Power
Pasadena Water & Power
Dept.
Imperial Irrigation Dist.
Sacramento Municipal
Utility District
Utility
Hawaiian Electric Co.
Kauai Electric Co.
Maui Elec. Co.,, Ltd.
Plant
Glendale
Harbor
Valley
Scattergood
Haynes
Broadway
Glenram
El Centre Steam PI.
Rancho Seco
HAWAII
Plant
Honolulu
Waiau
Kahe
Hilo
Maui
Location
Glendale
Wilmington
Sun Valley
Playa Del Rey
Seal Beach
Pasadena
Pasadena
El Centre
Rancho Seco
Location
Honolulu
Waiau
Kahe
Hilo
Maui
MW
163
355
512.5
312.5
1606
171
65.3
187.6
913*
Gen. Capacity
MW
168.2
394.5
239.0
37.5
11.7
35
Type
F
F
F
F
F
F
F
F
N
Typ*
F
F
F
F
G
F
Port Allen
Kahului
Kauai
Maui
10
38.5
Al-59
-------
EPA REGION DC
Utility
Nevada Power Co.
NEVADA
Plant
Clark Station
Sunrise Station
Reid Gardner St.
Sierra-Pacific Power Co. Tracy Steam Pit.
Fort Churchill
Steam Plant
Location
Gen. Capac ity
*MW
East Las Vegas
Las Vegas
Moapa
Sparks
Yerington
190.3
81.6
227.3
135
25
110
Type
F
F
F
F
G
F
Southern California
Edison Co.
Mohave
Near Big Bend 1210
Al-60
-------
EPA REGION X
Region: Alaska, Idaho, Oregon, Washington
Region Office: Portland, Oregon
ALASKA
Utility
Fairbanks Municipal
Utilities System
Qhugach Electric
Association Inc.
Golden Valley Electric
Association Inc.
U. S. Air Force
U. S. Army
U. S. Navy
Utility
Potlatch Forests Inc.
Plant
Gen. Capacity
Location MW Type
Fair Banks
Kink Arm
Fairbanks
Healy
Elmendorf West
Elmendorf Central
Fort Wainwright
Eielson
Clear AFB
Ft. Richardson
Ft. Greely
Port Whit tier
Kodiak
Adak
IDAHO
Plant
Lewinston
Fa ir banks
Anchorage
Fairbanks
Healy
Elmendorf
Elmendorf
Near Fairbanks
Eielson
Near Nenana
Anchorage
Ft. Greely
Portage
Kodiak
Adak
Location
Lewinston
8.5
7.0
14.5
9.5
17.5
22
22.5
9.0
23.5
10
22.5
18.0
2.0
6.5
4.0
15.9
Gen. Capacity
MW
10
F
G
F
F
G
F
P
F
F
F
F
F
N
F
F
F
Tyj
F
Al-61
-------
EPA REGION X
OREGON
Utility
Plant
Location
Gen. Capacity
MW Type
Pacific Power & Light Co.
Portland Gen. Elec. Co.
Eugene Water & Elec . Board
Utility
Seattle Dept. of Light.
Tacoma Public Utilities-
Light Division
Pacific Power & Light Co.
Public Utility Dist . No. 1
of Cowlitz County
Public Utility Dist.. No. 1
of Pend Dreille Co.
Puget Sound Power & Light
Lincoln
North Bend
Astoria
Springfield
Station L
Eweb
WASHINGTON
Plant
Lake Union
Georgetown
Steam Plant #1
Steam Plant #2
Centralia
Long ViiiW
Box Canyon
Shuffleton
Portland
North Bend
Astoria
Springfield
Portland
Eugene
Location
Seattle
Seattle
Tacoma
Tacoma
Centralia
Lewis River
Lone
Renton
35
15
8
5
75.5
25
Gen. Capacity
MW
30
22
9
50
700
700*
26.7
77.2
87.5
F
F
F
F
F
F
Type
F
F
F
F
F
F
F
F
F
Washington Public Power
Supply System Hanford
Hanford
860 N
1135* N
Al-62
-------
APPENDIX 2
-------
FORMAL COORDINATING ORGANIZATIONS OR POWER POOLS 292
1. New England
2. New York
3. P-J-M Interconnection
4. California
5. The Southern Company System
6. American Electric Power System
7. Allegheny Power System
8. Central Area Power Coordination
9. Kentucky • Indiana
10. Michigan
11. Cincinnati, Columbus, Dayton
12. Illinois • Missouri
13. Iowa
14. Upper Mississippi Valley
15. Wisconsin
16. Missouri Basin Systems Group
17. Missouri - Kansas
18. Middle South Utilities System
19. Texas Utilities Company System
20. South Central Electric Companies
21. Pacific Northwest Coordination
NOTE: Not ill systems operitini ii cadi of Hie 21 wets ire formil power pool members.
Figure A-2-1
A2-1
-------
INFORMAL COORDINATING GROUPS 292
January 1, 1970
10,12
Associated Mountain Power Systems
Colorado Power Pool
Colorado Systems Coordinating Council
Florida Operating Committee
Joint Power Planning Council
Mid-Continent Area Power Planners
New Mexico Power Pool
Northwest Power Pool
Rocky Mountain Power Pool
Southern California Municipal Group
11. The Intercompany Pool
12. Western Energy Supply & Transmission Associates
13. Wisconsin Upper Michigan Systems
7.
8.
9.
10.
NOTE: Are* boundaries are only general; not id system
within a boundary ire members of the designated orpniutions
Figure A-2-2
A2-2
-------
NATIONAL ELECTRIC RELIABILITY COUNCIL REGIONS
Canadian Portions Net Included
292
WSCC Western Systems
Coordinating Council
MARCA Miittontinent Area Reliability
Coordination Agreement
SPP Southwest Power Pool
ERCOT Electric Reliability Council Of Texas
MAIN Mid-America Interpool Network
NPCC
Northeast Power
Coordinating Council
MAAC Mid-Atlantic Area
Coordination Group
ECAR East Central Area Reliability
Coordination Agreement
SERC Southeastern Electric
Reliability Council
Figure A-2-3
A2-3
-------
Table B-2-l
Mambera of Formal Coordinating Ora.anli«tr»lis •» *owaf Pswjlt O Q O
Ijaaiury I. I'JTO)
.H,. A>(I«W rwv> JW (NKPOOI.) '
Nlllllf.**! Clllilirt '
lb»HNi l^liixa Company ,
New l.«.ifl-nd Meurk System *
Omul M.«inJe»-«s.y.W ;«*rr««rr». (PJM)
Pulitir S^rviie IJeetrie and Cas Company
I'liil.t-l'iiii.ia Kktrik Company
Cener;il r..Un Utilities Crirpnralinn
Mrli'.f*i.liiin felbun Company
IVnmylv.mil Ueclric Company
Jersey Central Power ami Light Compaay
New Jeney Power ft Light Company
Public Setvice Omiiiany of New MampshM
tjMtrra Ulilitirl AaM.Ulr* •
Nrw rJiKluxl CM ft Klrctfk AMDC.'
Central Vcrrn. n Public Sen*c Co.
Onlral lludxxi Ca! A r^ectrk Corp.
Korhrilrr (iai an>l Klrclrie Corp.
(haniir and Ruralaml UliliuVl, Inc.
Powef Authority ul tl>e .Suu of N. V.
Pronsrlvuiia Po^r » IJirkl Company
Baltimorr Oji and Kktlrie Company
'Potomac rUeetric Power Company
oxi-rauai /W (MOKAN) •
Kinuire Mavfal Klnlik Cumpmy
K»nta> itnpxiiy
Huhlii: Service <4>. of < >kUlH.ina
SuulJiwrnrrn Wei Irk- I'uwer (>Nnpany
ICaiMaa Pow*v and IJtli* f^Mwpany
MianMiri PuUic Vrvkr
. MiwiMippj Power A IJ«I|I Company
New (likana Pul^k Service. Inc.
Araanus Power aod tiithl Company
LAuiaiana Power and l.ferhl Ojntpany
Mi«KMtpf>i Power and l.ighl Cnmpany
KanMa Cat and FJeclrie Company
Lmpire Ubiricl FJectric Company
Dallas Power (k l^lil Ctimpiay
'IVxaa l-Jectrtc S«rvire Company
Teua Power and Light CbmpMr
r-furu.* />Mm JW (CARVA) •
Virxir.il F.lrctric ft Power Company
Carolina Power i IJfhl Company
Alabama Power Company
Georgia Power Compaay
Duke Power Company •
South Carolina Electric & CV»r {MM (APS) (HMut C—f-,)
Monongahela Power Company
Potomac Cdijon Company
W« Penn Power Company
Art* ftuMt CWAjHTM Citmp (CAPCO)
Mklugan Power Co.
Scwell Valley Utilitid Co.
Wheeling Electric Co.
Ohio Power Company
Central lUiaoaf Pofalk Service Co.
Illinoii Power Company
Union FJeetrie Compaay
Uff* MimiiiHi VJU, /Wr> /W
CooperativcB
. Cooperative Power Aanclatko
Dabylaad'Power Cooperative
Mmnfcota Power Cooperative
rnverua
edCompaniei
Intentate Power Company
Lake Superior District Power Co.
Minaeaou Power & Light Compaay
Iowa FJectnc I Jghl and Power Co.
lowa-IUinoia Ca« and Eire. Co.
Iowa Power and Light Company
Cleveland fjectric lUumuiating Company
Duquetoe Ljfht Company
Cw»-a. draarfu. D.*. IW (CCO)
Ohio Edaon System (Hotding Company)
1 Ohio Prison Cnmpany
Pennsylvania Power Company
Toledo Cdisoa Company
* Soothem Ohio FJectric Co.
Daytoa Power a Light Co.
Ciacinaati Cas ft Ekctric Co.
rWrr *i«l (KIP)
!:. power ft Lajbt Co.
Public Service Co. at Indiana
Kentucky Utilities Coaspaay
Wawaa P.btk Service Corporalloa
Wlaconain Power and Li, hi Company
Madison Cas and Elecinc Company
nsart ahna Sj*m, CVsap (MBSC)
U. S. Bureaa of Reclamation
Basin Electric rower Cooperative
Central Power Elecuk Cooperative
Northern Minnesota Power Assoe.
Rural Cooperative Power Assoc.
United Power Aasociatina '
Mcntana-Oaiota Utilities Ca.
Northern Stairs Power Compaay
Northwestern PuMk Service Cump.M
Oiler Tail Power Company
Iowa Public Service Company
Iowa Southern Utilities Company
Com Belt Power Cooperative
Nebraska Public Power System
Other Members
Oetroa Edaon Coeapaay
Suuthrro California Edison Company
Pacific Cai and Klrclrk Company
Sjn Diego Gas ft Electric Company
nonsicville Power Adminiatralion
City of F.ugene, Oregon
City of VatuV, Waihinglnn
anaa Traasmiviwjn Company
Montana Hnwrr Company .
Paeifk Power a I jfthl CVrtnpany
Piirlbjnd Cmrtal l.leclric aall.4ding..«npany.
. • Power Aulht»ily rf the Sute ol New York lakes part in pool planning and operations, but DM In commercial trana-
actions of Ihr p>>4.
• hvaing agieiustal lerminated as of rsrmher 2H, 1470.
• There are akn liv« uteltile memhrrs: *t. jiarjili IJghl ft f>mn Co.; Board a( Puljk Utllilln of Kansas (Sly. Kansas:
Uty W l»drpn>.leate, Mi^iurii fVnlral Ttkphoae aad Utilities Corp.- Western Power Uiviamai and Asaocialeit rJrilric
raiasnaiive. Inc.
A2-4
-------
fc
171
Table A-2-2
(January I. 1970)
PLANNING ORGANIZATIONS AND THEIR MEMBERS
Aovr Sftwiu (AMPS)
Idaho Power Co.
Montana Power Co.
Pacific Power ft Ughi Co.
* Pmv Fiatmf C*aHn7(JPPC)
Pacific Power ft Light Company
Portland General Electric Co.
Puget Sound Power ft Light Co.
Uuh Power ft Light Co.
Total 3 System
Washington Water Power CD.
BonoevUle Power Administration
Publicly Owned UtIHtks in Oregon, Washrngfaa,
Idaho and Montana {104 System)
Total 109 Systems
/•Cfi.'iwwl Arn Ptx.tr Pt**xtrt (MAPP)
Bljrk Hilli Power ft Light Co.
NwthwraterD Witronwn Electric Co.
Omaha Public Power Dblrkt
.NVbraika Publk Power Diitrict
Central Iowa Power Cooperative
Eaitrm Iowa Light ft Power Coop.
Iowa Power Pool Members
owa r'lectrif t.irht and Power Co.
owa-lllinou Oaj and Klrrtric Co.
o«a Power and Light Co.
t Publk Service Co.
s SoulSrm Utilities Co.
Corn Belt Power Gxiper.itive
Union r'leetric Otnpjuiy
Munu-ipil Syiienu in Nebraska. South Dakota, Iowa
Manitoba Hydro-Electric Board
Upper Mivlanppi Valley Power Pod
Cooperatives
Cooperative Power AasneUUoa
Dalryland Power Cooperative
Minnkota Power Cooperative
Northern Minnesota Power Aane.
Rural Cooperative Power Aasoc.
lnvettor-o
Intrntate Power Company
Lake Superior Dbtrtct Power Co.
Mlnnoota Power & Light Company
Montana-Dakota Utilities Company
Northern Siata Power Company
North wo i cm Public Service Co.
Otter T*il Power Company
Total 34 Syrtems
E.vf\ Sffftt & Trwiitrion Ainrittn (WEST)
Arizona Public Service Co.
Lo« Anseln Prui. of Water & Power
EJ PA» tl«tric Co.
Nr*-jd* Power Co.
Public Service Company of Colorado
San Pirtro G« & tier trie Co.
Sierra Pjcine Power Co.
Southern California T(]i*oa Co.
Tueioa CM ft Flecirie Co.
t't»h Po»er A I ieht Co.
Arizona Flectric Power Coop.
Public Service'Co. of New Mexico
Arizona Power Authority
Burbank Publir Servke Dept.
City of Colorado Spring* ,
Colorado-Uie Electric Awoclation, Inc.
ClemJale Public Service Departmeat
Imperial Irrigation Dbuki
Pacific Power ft Light Co.
PaudenA Municipal Light & Power Dept.
Plain* Electric C.&T. Coop., Inc..
Salt River Project
Central Telephone A Utilities Corp. (Soulhen Goto.
Power Div.)
Total n Syttemi
OTHER INFORMAL COORDINATING CROUPS AND THEIR MEMBERS
CWaraA P*~f /W (COLOPP)
Publk Vrviee Company of Colorado
City of Coltjrado Springs
Southern Colorado Power Div. of C.T.U.
P*W (INTKHPOOL)
Power & l.i*ht fVmipany
(irn-r.il Metric Co.
Total SSrrtetm
Pufet Sound Power ft Light Co.
Washington Watirr Power Co.
Total 4 System*
UwW.>«/ Onmp (SCMO)
\f* Angelet Departmeni of Wafer and Power
Gkndale Public Service Dept.
Burbank Public Service D-pf
Paiadena Municipal Light & Power Drpt.
Total4Syite»
CWwaA Sgitmi CWA'Minv Cmmi( (CSCC)
Centra] Munkrpal Light ft Power System
Colorado Spring* Dept. of Public Utility
Town of Etie* Park
Fort Oollim Light & Power Depanment
City of Fort Morgan
Clenwoort Spring! Municipal FJec. System
Julrtburg Power ft Light Department
U Junta Municipal Utilities
Utilitiei Board or*r Mkkigm fytumt (WUMS)
Wiacoetin-Mkhigan Power Co.
Upper Prnmiula Power Co,
Xar*s A/M0tf«M Aowr /W (RMPP)
Public Service Company of Colorado
Pacific Power Ik Light Co.
USBR Region* 4 and 7
Montana Power Co.
OuMumen Public Power Dlilrief
Southern Colorado Power Division of C.T.U.
CJly of Colorado Spring*
Tamp* FJECIKC O».
City of Jark.«mvUle
Orlando L'tiliii^i CumraiMion
ToUlS Systems
Wisconsin Power P'xri (3 S«!-r
Wbeoniin tlrc*ric Pcw-r Co.
Total 6 Syrtctm
Utah Power & Light Company
Black Ililli Pnw«r ft Ligl.t Co.
TrvSute G. ft T. Aaue.. Inf.
Colorado-t_'te Elec. Aworiation, f
CrKycnne I.^M. F*ir| ft V'.^-r
Western Co'era'Jo r*oi*er O>
Total 13 Synems
,tf/m» /Wrr /W (NMPP)
Comanmity Public Service Compaay
El Paso Electric Company
Plain* F4ectrie O. ft T. Coop.
USBR Rio Grande Project
Total 3 Syttf ma
fA.I*rf /'«*A /W (SWPP)
Bnnnrvilk Power Administration
Eugene Water & Eleciric Hoard
Idaho Power Co.
Montana Power Co.
Pacifr Power ft I^ght Co.,
Portland Cenrral Electric Co.
Pugrt Sound Power ft Light Co.
P.L'.D. No. 1 of Chelan County
P.U.D. No. I ofDoutlj* County
P.U.D. No. 7 of Trant O»J. Pacific I>v.
ITSBR-BPA'tSouthern Ida^sl
Total 18 S
-------
Table A-2-3
OQO
Multiple Membership* in Informal Coordinating Organizations or Power Pools
System
|. H O
El Paso Electric Co ............................................. X X
Public Service Co. of N.M ....................................... X X
Plains Electric G. & T. Coop ...................................... X X
City of Los Angeles ................................................. X X
City of Glendale [[[ X X
City of Burbank [[[ .'X X
City of Pasadena [[[ X X
Pacific P. & L. Co. (Wyoming) ........................ ............... X ............ X
Utah Power & Light Co ............................................. X ........ X X ..... ."..../. X
Public Service Co. of Colorado ....................................... X .... X .... X X
City of Colorado Springs ............................ ................. X ____ X ____ X X
Central Telephone & Utilities Corp. (Southern Colorado Power
Division) [[[ X ____ X ____ X X
Colorado-Ute Electric Association ............ ......................... X .... X .... X
Western Colorado Power Co ................................................. X ____ X
Tri-State G. & T. Association ................................................ X .... X
Bureau of Reclamation ................. ......................... X ........ X ____ X
Portland General Electric Co [[[ X ........ X X
Puget Sound Power & Light Co .................................................. X ........ X X
Pacific Power & Light Co [[[ X ........ X X X
Washington Water Power Co. [[[ X ........ X X X
-------
Table A-2-4
brfWMiMl M.mW. W (.gUMl I
ncUl1
292
BM« KJntrir ftmu Cbepcnttvt
U«k 1Mb IWcT ttt U|W Ok
Crttlr*! luwa ftf^rr CVM»
Guoprralnc Powrt Amc.
COCK Hrll Pow^r Coop.
IteirvUnd Powrr OH^.
burn l IJ^ki mt NMT Che*.
Inunuic Fbvcr O*.
low* Ekcltk l.«ht ft r»«r OK
lOM-a-Iltinoil <*as & Ekctm QK
lo»> i'uwn «od Uflrl Co.
low. Publk Soviet Ot.
Iowa Soudteni Utilidn OK
Aaoei«tn: Uni(MI Ekclfk Ok.
Muiiuba H)dn>-EJ«ctric limd ofCu>a>
er rW ^iiinwnl tfPT)
Arkansas-Electric Coop. Corp.
Arkamas-Mitsouri rWe» Co.
Arkarua* Power ft Lif bt Co,
Associated Electric Coop., lac.
Boaid of Public CtiBtks. Kaasas Otr. Ka*.
CratraJ Loukiaaa Uecflrk Co.. lac. (TV)
City Powrr & U*tu Dept.. Independence, Mo.
Giy Liilmes of Springfield. MisMtiri
Empire Dbtrici tUectric Co. (The)
Cnml River Dun Authority
Cutf States UtUitks Cunapsny
K*eu* GIT Powrr * IJffcl Oh
KaiUM Uai and Electric Co.
KaniM Power * Light Co. (The)
AiUmk City Electric Co.
Baltimore Cai and Electric Co.
Delmarva Power & I-ighi Co.
Jrrwy Central Powrr ft Lifffal Ch
.M^tnipoliua Cdboa Co.
Nrw jemy Pow«r & Lifbt Oh
Alabama l!>rlt k Cknprraiive
AUbkma Power (kxnpany
Carotin. Po*rr & L^ht Co,
CrUp t'ounty I'u
l>ukc Puwer f^mipany
flotilla Power ( :>ir|*rr.ittan
rU-«i* Power & l^hl Co.
(((•urgta Puwrr O>.
illr Kli'Ctrir Autliurily
l>pi. i^ I Or. & Water
A,.,MU-|»..n IWr, (i,
CiiKJiuuli (•;<« •"-• I.)" Ifif. iiiiinMtinK ('•"•
f >4'imlMr> A; .S.»II|M-III Oluo KWtric (
Pi«w<-r (ij.
Nrw rjlfflMMt |>* hi
Nrw l^iciMft f ;«• A r>rt(ir
Nrw Viwk S»,,ir l>rlnr
Nnrlliraat l.'lUtlin
Onetr •ml KirklaMl Dlitil**. lac.
Pow-« Aulhiirity itf th*> .Sl.M «f New V<-fc
KorhrMrr Gu and Kkciric Ctvp.
Tl«r tinned lUwmmalMia; .tny
I^NUKMH" lJi;t"t C^fiii|Mny
l_^i Kmiixky kiii.il t. W »ik- ti-
liHtMn^-Krnno ky IJ'i nk (inp.
IlKlbna A Mfl.iit^n l.l-'l. (-.
Lake Swprrkir DMtrirt Powrr Co.
Uinnrvxa Ptiwrr ft IJajbl CM.
Minnkoia P«mrr f *Akirta Utility Co.
Nrliraiaa Pnhlir Pawn District
Norilvrn Minor«uU fawtt AaMxia
Northrto States Puwrr Co.
Northwrflrm Puhlk Service Co.
Onaba Publk Power District
Onrr Tail Puwer Co.
Rural Coop. Power AsMciation
U. S. Bureau of Reclamation
Loumaaa Power ft . Co.
Mawsnppi Power * t.ight Co.
Minouri EdiMn Co.1
. Miaouri Tower & Liffht Co.1
Misnuri Public Service Co.
Mivouri Utilitiei Corapany
New Ortrattt Publk Service, Inc.
Oklahoma Gas & Electric Co.
Publk Scrvke Co. of OVUhoma
St. joaeph Ufhi & Power Co.
Southweiiem Elevtrk Power Go.
Southwestern Power Admimitranon
WeMem Fannen Electric Coop.
Wotera Power Uviiioa—CT & U
Pew»ylv»oia Electric Co.
PenosyrvaoU Power & Light Co.
PhiUdrlphi* F.leeiric Cov
Potomac Klectric Power Co.
Pttblk SenHre Ekctrie «nd Gu Co.
UGICorp.
er Co.
r & Uiuitvtlk <,M ft Clrririr L'rfim
Norlliern Indi.ma TuMir Srrvicr f'a.
Ohio M'atM Omiji.my
Ohio Piiwrr r^Ht>|..iny
• Ohio Valley r.lrftii. (i«p.
Prnniylvrftiix I'owrr lrfiin|Mny
PulrwnAC K«livj«i (V»m|i4iiy
Putilk Servirr <'*. <•! Imli.nia
Snutlfm Imliiin.i Cji A Klmrir Co.
A»«MirW4'llltn.Mi (.*• ft rJrctrk Co.*
luwa I'owrr ft t Jf^rt Compwy *
XZftftw KHtmMtti C^mit if 7V»*i (tJtCOT)
H-K r.lnlric (xjtip., Int.
rUird. t:.ty of
Kinlrii r.liHific <>np., lac.
Uuehrinnrl KJrr. C-mp., Inc.
Ko^rne I'lililiri
lluwtr. City uf
Brady W^irr K IJRl.l Workl
Bra«n I'.ln . I'uwer Omp., Inc.
Birnl^ni Muni. i|*al UliUtia
BrownivilKC^iyiif
Bryan.'Uly.d
(^>p K«i k Kite. <**»., Inc.
Omral I'.iMrr & UK In Conipaay
City ..I Aiitlin
Ctily I'.iMtc .'y-rvirr Board (San' Antonio)
rVilrttun, City trf
(i.m.,ni l.r (>Hmtv f>c. (*x,p. Asv>c.
< Jiimnumty I'ulilic, St-rvN'r (*jmp*uy
Cftrtliyl.Ml, (.Jty ol
Kaufman (>«unty Kleetrir Conp.. lor-
Kitnlilr Klrriric Coop., lor.
I-aGranirr. Cily ol
ljunar (.4>uniy.r.kt.trie Coop, Aon.
I Jmniunr County Klec. Coop., lac.
IJvinir«t«in, (Uty of
l.uck.hart L>tilhirt
Lower Colundo Kivrr Ambority
Lulin^ L'lititin
Ma«k Vilify Kin-trie Coop., loc.
McC JiUoch Elcciric Coop.. Inc.
McUrtnan County FJrctrk Cuop.. like.
Mrtlina Klcrtrk Cuop., loc.
Mid.S.iuih FUxirtr Coop. Asm.
MidVnt Klectrk C*wp., Inc.
N*v*rro County Llrctfk Coop.. Inc.
Nrw BraunCrli ClUiltn
New Era Electric Coop., Inc.
Nuece* Electric Coop.. Inc.
Kobrnioii rJn-tric Coup., loc.
Kobtlown, City of
Sam Houston tlectiic Coop^ Inc.
San Bernard Uectric Coop^ Inc.
Wntnn SjtUmi CMr^inatimf Owm/ ( tt'SCC)
Arizona Power Authority
Arizona Publk Service. Co.
BonnevUle Power Adminiitration
Briihh ColumUa Hydro & Power Authority
' Cjlifninia Dept. of W.iter Knourcei
Central Telephone & Utilitiei {South Colorado 'Row
hiviiion)
Chelan County P.U.I). No. I
Gty of Clrndale. Pulilk Servire Drpt.
f4iy of'l'acuma, l>«-[ii. Public Uiililin
C.ty of Scsuk IVpl. ••( l.iRhiinK
Otwliti fijunty P.U.I). No. I
Colorado— Ute Klrrtrir. Anncialiun, Inc.
l)u.»Klai fVwnty P.l',1). No. 1
I'.l I'M Urririr (x»ti|tany
Kiyrni- Water ft Untric Board
Gi>f:< (vMimy P (J.I). No. '2
l I'nwrr f ^ifnp^ny
Ixn Anyflrt lV|iartiiiriil ij Wjirr ft Power
a To
Inwa PuMir Srrvkr O-o,'
Iowa SiMtll^-tn 1,'ltlitlrl Co.*
M«ilrir Co.
Northern Kiatn Power Co.*
llninn Unttir fltimpaiiy
Up|KT Prninitila Ptiwrr Co.
WiviMttin l.lertiK. Powrr f^N
WiM-iinon.MM ltif«n Power O
Wiwcni.n Power and 1J«M Cumpa«y
WMcoruin PuUk .Service tp.
Cuero MltrtiM; IVpt.
Djill.it Powrr ft l.iKhi Company
IVrp l.jfl 'let.t« Mrr. (k»ip.. Inc.
Srlnik nbunr. City of
S.-nu.n. . Ji Klrc. Coup.. Inc.
Soutliwrii Trim tire. Coop.. Inc.
Stamford Klt-ctnc Cuup., Inc.
Traffur, Ctt> jny
PariftcCuft Klrrtfirt^.
Pacific Power & l.iKlit (Jtnipan
Portland Grnrral t.l..ir>. *rp>t.f l.nKM>'inRion XVjfrr l'.,»r, C^m
Writ KiMitraay Powei & l.ntlil
Wnl Peon I'owrr O
hi.ll .. rr(x,,
of MAIN l
l«-r o( M'P.
i^r
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Multiply (English Units)
English Unit
CONVERSION FACTORS
by
Abbreviation Conversion
Abbreviation
Obtain (Metric Units)
Metric Unit
acres
acre-feet
British Thermal Unit
British Thermal Unit/pound
cubic feet/minute
cubic feet/second
cubic feet
cubic feet
cubic inches
degree Fahrenheit
feet
gallon
gallon/minute
horsepower
inches
inches of mercury
pounds
million gallons/day
mile
pound/square inch (guage)
square feet
square inches
tons (short)
yard
ac
ac ft
Btu
Btu/lb
cfm
cfs
cu ft
cu ft
cu in
°F
ft
gal
gpm
hp
in
0.03342
Ib
mgd
mi
psig
sq ft
sq in
t
y
0.405
1233.5
0.252
0.555
0.028
1.7
0.028
28.32
16.39
0.555(a)
CF-32)
0.3048
3.785
0.0631
0.7457
2.54
atm
0.454
3,785
1.609
(0.06805(a)
psig +1)
0.0929
6.452
0.907
0.9144
ha
cu m
kg cal
kg cal/kkg
cu m/min
cu m/min
cu m
1
cu cm
°C
m
1
I/sec
kw
cm
atmospheres
kg
cu m/day
km
atm
sq m
sq cm
kkg
m
hectares
cubic meters
kilogram-calories
kilogram-calories/kilogram
cubic meters /minute
cubic meters /minute
cubic meters
liters
cubic centimeters
degree Centigrade
meters
liters
liters/second
kilowatts
centimeters
kilograms
cubic meters/day
kilometer
atmospheres (absolute)
square meters
square centimeters
metric tons (1000 kilograms)
meters
(a) Actual conversion, not a multiplier
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