DEVELOPMENT DOCUMENT FOR
PROPOSED EFFLUENT LIMITATIONS GUIDELINES
AND NEW SOURCE PERFORMANCE STANDARDS
FOR THE
STEAM ELECTRIC POWER GENERATING
POINT SOURCE CATEGORY
^ PRO^
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
MARCH 1974
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Publication Notice
This is a development document for proposed effluent limitations
guidelines and new source performance standards. As such, this report
is subject to changes resulting from comments received during the period
of public comments of the proposed regulations. This document in its
final form ;will be published at the time the regulations for this
industry are promulgated.
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DEVELOPMENT DOCUMENT
for
PROPOSED EFFLUENT LIMITATIONS GUIDELINES
and
NEW SOURCE PERFORMANCE STANDARDS
for the
STEAM ELECTRIC POWER GENERATING
POINT SOURCE CATEGORY
Russell E. Train
Ad mi ni st r ator
Roger Strelow
Acting Assistant Administrator for Air 6 Water Programs
Allen Cywin, P.E.
Director, Effluent Guidelines Division
Dr. Charles R. Nichols, P.E.
Project Officer
March, 197U
Effluent Guidelines Division
Office of Air and Water Programs
S. Environmental Protection Agency
Washington, D. C. 20460
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ABSTRACT
This document presents the findings of an extensive study of the steam
electric power generating point source category for the purpose of
developing effluent limitations guidelines, standards of performance for
new sources, and pretreatment standards for the industry in compliance
with and to implement Sections 304, 306 and 307 of the Federal Water
Pollution Control Act Amendments of 1972.
Effluent limitation guidelines contained herein set forth as mandated by
the "Act":
(1) The degree of effluent reduction attainable through the
application of the "best practicable control technology currently
available" which must be achieved by nonnew point sources by no
later than July 1, 1977.
(2) The degree of effluent reduction attainable through the
application of the "best available technology economically
achievable" which must be achieved by nonnew point sources by no
later than July 1, 1983.
The standards of performance for new sources contained herein set forth
the degree of effluent reduction which is achievable through the
application of the "test available demonstrated control technology,
process, operating methods, or other alternatives."
This report contains findings, conclusions and recommendations on
control and treatment technology relating to chemical wastes and thermal
discharges from steam electric powerplants. Supporting data and
rationale for development of the proposed effluent limitations
guidelines and standards of performance are contained herein.
iii
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CONTENTS
Part Section Page
I CONCLUSIONS 1
II RECOMMENDATIONS 3
III INTRODUCTION 7
General Background 7
Purpose and Authority 8
Scope of Work and Technical Approach 9
Industry Description 12
Process Description 21
Alternate Processes 23
Industry Regulation 31
Construction Schedules 32
IV INDUSTRY CATEGORIZATION 35
Process Considerations 35
Raw Materials 43
Information on U.S. Generating Facilities 46
Site Characteristics 53
Mode of Operation (Utilization) 58
Categorization 68
Summary 75
A Chemical Wastes 81
V WASTE CHARACTERIZATION 81
Introduction 81
Once-through Cooling Systems 87
Recirculating Systems 88
Water Treatment 93
Boiler or PWR Steam Generator Blowdown 105
Equipment Cleaning 107
Ash Handling 116
Coalpile Drainage 128
Floor and Yard Drains 131
Air Pollution Control 133
Miscellaneous Waste Streams 134
Low Level Rad Wastes 138
Summary of Chemical Wastes 144
Classification of Waste Water Sources 144
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CONTENTS (Continued)
Part Section Page
VI SELECTION OF POLLUTANT PARAMETERS
147
Definition of Pollutants 147
Introduction 147
Common Pollutants 147
Pollutants from Specific Waste Streams 150
Other Potentially Significant Pollutants 155
Selection of Pollutant Parameters 156
VII CONTROL AND TREATMENT TECHNOLOGY 161
Introduction 161
Continuous Wastes 162
Periodic Wastes 173
Miscellaneous Wastes 174
Pollutant-Specific Treatment Technology 192
Combined Chemical Treatment 202
Other Processes 212
Powerplant Wastewater Treatment Systems 213
Wastewater Management 215
Summary 221
VIII COST, ENERGY AND NON-WATER QUALITY ASPECT 229
Introduction 229
Wastes Not Treated at Central Treatment Plant 230
Complete Treatment of Chemical Wastes for Re-use 238
Energy Requirements 244
Ultimate Disposal of Brines and Sludges 245
IX,X,XI BEST PRACTICABLE CONTROL TECHNOLOGY CURRENTLY 247
AVAILABLE, GUIDELINES AND LIMITATIONS
BEST AVAILABLE TECHNOLOGY ECONOMICALLY
ACHIEVABLE, GUIDELINES AND LIMITATIONS
NEW SOURCE PERFORMANCE STANDARDS AND
PRETREATMENT STANDARDS
Best Practicable Control Technology 247
Currently Available
Best Available Technology Economically 250
Achievable
New Source Standards 251
Cost of Technology 251
Energy and Non-Water Quality Environmental 253
Impacts
vi
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CONTENTS (Continued)
Section Page
Thermal Discharges £55
V WASTE CHARACTERIZATION 255
General 255
Quantification of Main Condenser 255
Cooling Characteristics
Effluent Heat Characteristics from Systems 269
Other Than Main Condenser Cooling Water
VI SELECTION OF POLLUTANT PARAMETERS 275
VII CONTROL AND TREATMENT TECHNOLOGY 277
Introduction 277
Process Change 279
Waste Heat Utilization 308
Cooling Water Treatment 313
General 313
Once-through (Nonrecirculating Systems) 314
Once-through Systems with Supplemental 315
Heat Removal (Helper Systems)
Closed or Recirculating Systems 322
Cooling Ponds 323
Spray Ponds 333
Wet-Type Cooling Towers 341
Dry-Type Cooling Towers 364
Survey of Existing Cooling Water Systems 372
VIII COST, ENERGY AND NON-WATER QUALITY ASPECT 381
Cost and Energy 381
Cost Data 385
Costs Analysis 388
Energy (Fuel) Requirements 404
Loss of Generating Capacity 407
Non-Water Quality Environmental Impact 410
of Control and Treatment Technology
General 410
Drift 418
Fogging 424
Noise 432
Height 433
Consumptive Water Use 434
Pollutants in Blowdown 439
Aesthetic Appearance 440
Icing Control 442
Comparison of Control Technologies 443
Considerations of Section 316(a) 443
vii
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CONTENTS (Continued)
Part Section
IX,X,XI BEST PRACTICABLE CONTROL TECHNOLOGY CURRENTLY 453
AVAILABLE, GUIDELINES AND LIMITATIONS
BEST AVAILABLE TECHNOLOGY ECONOMICALLY
ACHIEVABLE, GUIDELINES AND LIMITATIONS
NEW SOURCE PERFORMANCE STANDARDS AND
PRETREATMENT STANDARDS
453
Categorization ,,-c
Waste Characteristics
Control and Treatment Technology
Cost of Technology
Energy and Other Non-Water Quality
Environmental Impacts
XII ACKNOWLEDGEMENTS
XIII REFERENCES 469
XIV GLOSSARY 503
Appendix 1 Industry Inventory Al-1
Appendix 2 Plant Data Sheets A2-1
Appendix 3 40 CFR Part 423 Effluent Limitations A3-1
Guidelines for Existing Sources and Standards
of Performance and Pretreatment Standards
for New Sources for the Steam Electric Power
Generating Category (as published in proposed
form in the Federal Register on March 4, 1974).
vm
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FIGURES
Number title
III-1 Projected Total U.S. Energy Flow 19
Pattern (1980)
III-2 Condensed Construction Schedule, 33
200 MW Oil-Fired Unit
III-3 Typical LWR Nuclear Plant Project 34
Schedule, Highlights Only
IV-1 Schematic Flow Diagram, Typical Steam 36
Electric Generating Plant
IV-2 Schematic Cooling Water Circuit 42
IV-3 Cumulative Frequency Distribution of Entire 48
' Powerplant Inventory for All EPA Regions
IV-4 Cumulative Frequency Distribution of Fossil- 49
Steam Powerplants for All EPA Regions
IV-5 Cumulative Frequency Distribution of Nuclear- 50
Steam Powerplants for All EPA Regions
IV-6 Largest Fossil-Fueled Steam Electric 52
Turbine-Generators in Service (1900-1990)
IV-7 Heat Rates of Fossil-Fueled Steam 54
Electric Plants
IV-8 Heat Rate vs Unit Capacity 55
IV-9 Heat Rate vs Unit Age 56
A-V-1 Typical Flow Diagram, Steam Electric 82
Powerplant (Fossil-Fueled)
A-V-2 Simplified Water System Flow Diagram 83
for a Nuclear Unit
A-V-3 Nomogram to Determine Langelier 91
Saturation Index
A-V-4 Clarifier 94
A-V-5 Filter 94
IX
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FIGURES (continued)
Number Title Pa?e
A-V-6 Ion Exchange Process, Cationic and 96
Anionic Type
A-V-7 Ion Exchange Process, Mixed Resin Type 98
A-V-8 Evaporation Process 101
A-V-9 Typical Ash Pond 118
A-V-10 Flow Diagram - Air Pollution Control 135
Scrubbing Device at Plant 4216
A-V-11 Liquid Radioactive Waste Handling 141
System PWR Nuclear Plants
A-V-12 Liquid Radioactive Waste Handling System 143
1100 MW BWR Nuclear Plant
A-VII-1 Chlorine Feed Control, Once-Through 164
Condenser Cooling Water
A-VII-2 Recirculating condenser Cooling 168
System, pH Control of Slowdown
A-VII-3 Clarification Waste Treatment Process 169
A-VTI-U Ion Exchange Waste Treatment Process 171
A-VII-5 Neutralization Pond 172
A-VII-6 Ash Sedimentation System - Plant No. 5305 178
A-VII-7 Ash Handling System - Plant No. 3626 179
A-VII-8 Ash Handling System, Oil Fuel Plant 180
- Plant No. 2512
A-VII-9 Cost of Neutralization Chemicals 183
A-VII-10 Comparison of Lime, Limestone, and 184
Soda Ash Reactivities
A-VII-11 Comparison of Settling Rate 185
A-VII-12 Coal Pile - Plant No. 5305 186
A-VII-13 Cylindrical Air Flotation Unit 188
A-VII-14 Typical A.F.I. Oil-Water Separator 188
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FIGURES (continued)
Number Title Page
A-VII-15 Oil Separator and Air Flotation Unit 189
- Plant No. 0610
A-VII-16 Corrugated Plate Type Oil Water 190
Separator
A-VII-17 oil Water Separator 191
A-VII-18 Effect of pH on Phosphorus Concentration 198
of Effluent from Filters Following Lime
Clarifier
A-VII-19 Solubility cf Copper, Nickel, Chromium, 203
and Zinc as a Function of pH
A-VII-20 Theoretical Solubilities of Metal Ions 204
as a Function of pH
A-VII-21 Experimental Values - Solubility of 205
Metal Ions as a Function of pH
A-VII-22 Experimentally Determined Solubilities 206
of Metal Ions as a Function of pH
A-VII-23 Change in the Solubilities of Zinc, 207
Cadmium, Copper, and Nickel
Precipitates (Produced with Lime
Additions) as a Function of Standing
Time and pH Value
A-VII-24 Sewage and Kaste Water Disposal for a 216
Typical Coal-Fired Unit, 600 MW
A-VII-25 Recycle of Sewage and Waste Water for a 217
Typical Coal-Fired Unit, 600 MW
A-VII-26 Recycle Water System, Plant No. 2750 218
A-VIII-1 Chemical Wastes, Central Treatment Plant 231
A-VIII-2 Cost for Coal Pile Run-off Collection 237
A-VIII-3 100 MW Coal-Fired Steam Electric 239
Powerplant, Recycle and Reuse of
Chemical Wastes
A-VIII-4 100 MW Oil-Fired Steam Electric 240
- Powerplant, Recycle and Reuse of
Chemical Wastes
xi
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Number
FIGURES (continued)
Title
Page
B-V-1
B-V-2
B-V-3
B-V-4
B-V-5
B-V-6
B-V-7
B-V-8
B-V-9
B-V-10
B-VII-1
B-VII-2
B-VII-3
B-VII-4
B-VII-5
B-VII-6
B-VII-7
B-VII-8
B-VII-9
B-VII-10
B-VII-11
B-VII-12
B-VII-13
B-VII-14
Unit Condenser Delta (T)
Unit Heat Rate Distribution
Maximum Summer Outfall Temperature
Delta (T) vs Unit Age
Base Unit Heat Rates
Cycling Unit Heat Rates
Peaking Unit Heat Rates
Base Unit Condenser Delta (T)
Cycling Unit Condenser Delta (T)
Peaking Unit Condenser Delta (T)
Energy Flow for a Power plant
Energy Balance for a Powerplant
Powerplant Violating Second Law
Powerplant Violating First Law
Powerplant Conforming to First
and Second Law
Carnot Cycle Steam Powerplant
Rankine Cycle Powerplant
Rankine Cycle with Superheat
Powerplant
Regenerative Cycle Powerplant
Reheat Cycle Powerplant
Drain Cooler Addition to Powerplant
Drains Pumped Forward in Powerplant
Superposed Plant Addition
Simple Brayton Cycle Gas Turbine
256
257
260
264
266
267
268
270
271
272
281
281
283
283
284
287
290
291
292
294
299
300
301
303
Powerplant
xii
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FIGURES (continued)
Number Title
B-VII-15 Brayton Cycle with Regenerator Gas 304
Turbine Powerplant
B-VII-16 Combined Gas-Steam Powerplant 306
B-VII-17 Once-Through (Open) Circulating 316
Water System
B-VII-18 Once-Through (Open) System with 317
Helper Cooling System Installed
B-VII-19 Cooling System Capable of Both 319
Open and Closed Mode Operation
B-VII-20 Plant Layout at Plant No. 2119 320
B-VII-21 Seasonal Variation of Helper Cooling 321
Tower
B-VII-22 Cooling Canal - Plant No. 1209 325
B-VII-23 Chart for Estimating Cooling Pond 328
Surface Heat Exchange Coefficient
B-VII-24 Cooling Pond Surface Area vs Heat 330
Exchange Coefficient
B-VII-25 Determination of Surface Temperature 331
Increase Resulting From Thermal
Discharge of Station
B-VII-26 Determination of Average Surface 332
Temperature Increase Resulting
From Thermal Discharge of Station
B-VII-27 Estimation of Capital Cost of 334
Cooling Pond
B-VII-28 Unitized Spray Module 335
B-VII-29 Four Spray Module 336
B-VII-30 Spray Canal - Plant No. 0610 338
B-VII-31 Spray Modules - Plant No. 0610 339
B-VII-32 Graphic Representation of Design 340
of Spray Augmented Cooling Pond
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FIGURES (continued)
Number Title Page
B-VII-33 Thermal Rotcr System 342
B-VII-34 Double Spray Fixed Thermal Rotor 343
B-VII-35 Graphic Representation of Preliminary 344
Cost Data on Rotating Disc Device
B-VII-36 Determination of Required Flow per 345
Disc for Rotating Disc Device
B-VII-37 Counterflow Mechanical Draft Tower 346
B-VII-38 Crossflow Mechanical Draft Tower 346
B-VI1-39 Crossflow Natural Draft Tower 348
B-VII-40 Counterflow Natural Draft Cooling 348
Tower
B-VTI-41 Typical chart for Determining 352
Rating Factor
B-VII-42 Cost Vs Rating Factor, 353
Mechanical Draft Tower
B-VII-43 Cooling Tower Performance Curves 354
B-VII-44 Comparison of K-Factor and Rating 355
Factor for the Performance of
Mechanical Draft Cooling Towers
B-VII-45 Graph Showing Variation of Cost of 356
Mechanical Eraft Cooling Towers
with Water Flow
B-VII-46 Mechanical Forced Draft Cooling 359
B-VII-47 Parallel Path Wet-Dry Cooling 359
Tower Psychometrics
B-VII-48 Parallel Path Wet-Dry Cooling 361
Tower for Plume Abatement
B-VII-49 Parallel Path Wet-Dry Cooling 362
Tower (Enlarged Dry Section)
B-VII-50 Typical Natural Draft Cooling 353
Towers - Plant No. 4217
xiv
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FIGURES (continued)
Number Title Page
B-VII-51 Hyperbolic Natural Draft Crossflow 365
Cooling Towers, Typical Cost
Performance Curves for Budget
Estimates
B-VII-52 Hyperbolic Natural Draft Crossflow 366
Cooling Towers, Typical Cost
Performance Curves ror auage-c
Estimates
B-VII-53 Fan-Assisted Natural Draft Cooling 367
Tower
B-VII-54 Direct, Dry-Type Cooling Tower 369
Condensing System With Mechanical
Draft Tower
B-VII-55 Indirect, Dry-Type cooling Tower 370
Condensing System With Natural-
Draft Tower
B-VII-56 Temperature Diagram of Indirect Dry 370
Cooling Tower Heat-Transfer System
B-VII-57 Representative Cost of Heat Removal 373
With Dry Tower Systems for Nuclear
Plants
B-VTI-58 Steam Type Direct Contact Condenser 374
B-VII-59 Effect of Turbine Exhaust Pressure on 375
Fuel Consumption and Power Output
B-VIII-1a Example of Optimization of Net Unit 384
Power Output by Reduction of Cooling
Tower Fans
B-VIII-1 Additional Generating Costs for 401
Mechanical Draft Towers, Base-Load
Dnit, 300 MW, 6 Year Remaining Life
B-VIII-2 Additional Generating Costs for 401
Mechanical Draft Towers, Base-Load
Unit, 300 MW, 18 Year Remaining Life
B-VIII-3 Additional Generating Costs for 401
Mechanical Draft Towers, Base-Load
Unit, 300 MW, 30 Year Remaining Life
xv
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FIGURES (continued)
Number Title Page
B-VIII-4 Additional Generating Costs for 401
Mechanical Craft Towers, Base-Load
Unit, 300 MW, 18 Year Remaining Life
B-VIII-5 Additional Generating Costs for 401
Mechanical Draft Towers, Base-Load
Unit, 300 MW, 30 Year Remaining Life
B-VIII-6 Additional Generating Costs for 403
300 MW Cyclic Unit, Mechanical
Draft Towers, 6 Year Remaining Life
B-VIII-7 Additional Generating Costs for 403
300 MW Cyclic Unit, Mechanical
Draft Towers, 18 Year Remaining Life
B-VIII-8 Additional Generating Costs for 403
300 MW Cyclic Unit, Mechanical
Draft Towers, 30 Year Remaining Life
B-VIII-9 Additional Generating Costs for 403
300 MW Peaking Unit, Mechanical
Draft Towers, 6 Year Remaining Life
B=VIII-10 Additional Generating Costs for 403
300 MW Peaking Unit, Mechanical
Draft Towers, 18 Year Remaining Life
B-VIII-11 Additional Generating Costs for 403
300 MW Peaking Unit, Mechanical
Draft Towers, 30 Year Remaining Life
B-VIII-12 Variation of Additional Generation 405
Cost with Capacity Factor
B-VIII-13 Additional Generating Costs for 800 MW 406
Nuclear Unit, Mechanical
Draft Cooling Towers, 18 Year
Remaining Life
B-VIII-14 Additional Generating Costs for 800 MW 406
Nuclear Unit, Mechanical
Draft Cooling Towers, 30 Year
Remaining Life
B-VIII-15 Turbine Exhaust Pressure Correction 408
Factors (Example, Plant No. 3713)
xv i
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FIGURES (continued)
Number Title Page
B-vm-16 Broadside Multiple Tower Orientation 414
B-VIIl-17 Longitudinal Multiple Tower Orientation
B-VIIl-18 Ground-Level Salt Deposition Rate from 423
a Natural-Draft Tower as a Function of
the Distance Downwind: A Comparison
Between Various Prediction Methods
B-VIII-19 Modified Psychrometric Chart 425
B-VIII-20 Graphical Distribution of Potential 427
Adverse Effects From Cooling Towers
Based on Fog, Low-Level Inversion and
Low Mixing Depth Frequency
B-VIII-21 Location of Natural Draft Cooling 429
Towers Through 1977
B-VIII-22 Heat Transfer Mechanisms With 435
Alternative Cooling Systems
B-VIII-23 Water Consumption Versus 438
Meteorology and Cooling Range
B-VIII-2U Estimated U.S. Energy Situation (1980) 450
Relevant to Environmentally-Based Control
of Thermal Discharge from Steam Electric
Powerpiants
xvn
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TABLES
Number Title Page
II-1 Summary of Effluent Limitations Guidelines 4
and Standards for Pollutants Other Than Heat
II-2 Summary of Effluent Limitations Guidelines 5
and Standards for Heat
III-1 Principal Statutory Considerations 10
III-2 Summary Description Electrical Power 14
Generating Industry (Year 1970)
III-3 Projected Growth of Utility Electric 16
Generating Capacity
III-4 FPC Projection of Fuel Use 17
in Steam Electric Powerplants
III-5 FPC Projected Annual Fuel Requirements 18
for Steam Electric Powerplants
IV-1 Industry Inventory Summary 47
IV-2 Urban Steam Electric Powerplants 57
IV-3 Characteristics of Units Based on 65
Annual Hours of Operation
IV-4 Chemical Waste Categories 70
IV-5 Applicability of Chemical Waste 72
Categories ty Fuel Type
IV-6 General Subcategorization Rationale 76
IV-7 Subcategorization Rationale for Heat 77
IV-8 Subcategorization Rationale for Pollutants 78
Other Than Heat
A-V-1 Recirculating Water Quality Limitations 90
A-V-2 Typical Water Treatment Waste Water Flows 1Q2
A-V-3 Arithmetic Mean and Deviation of 104
Selected Water Treatment Waste Para-
meters
XVT11
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TABLES (continued)
Number Title Page
A-V-I+ chemical Waste characterization, llOff.
Boiler Tubes' Cleaning
A-V-5 Chemical Waste Characterization, 115
Air Preheater Cleaning, Boiler
Fireside Cleaning
A-V-6 Constituents cf Coal Ash 119
A-V-7 Time of Flow for Ash Handling Systems 120
A-V-8 Chemical Waste Characterization, 122ff.
Ash Pond Overflow - Net Discharge
A-V-9 Coal Pile Drainage 129
A-V-10 Chemical Waste Characterization 132
Coal Pile Drainage
A-V-11 Chemicals Used in Steam Electric Powerplants 145
A-V-12 Class of Various Waste Water Sources 146
A-VI-1 Applicability of Parameters to Chem- 148
ical Waste Streams
A-VI-2 Chemical Wastes - Number of Plants 149
with Recorded Data
A-VI-3 Selection of Pollutant Parameters 157ff.
A-VI-4 Selected Pollutant Parameters 160
A-VII-1 Ash Pond Performance 175
A-VII-2 Summary of EPA Data Verifying 177
Ash Pond Performance, Plant No. 0107
A-VII-3 Ash Pond Effluent Total 201
Suspended Solids
A-VII-4 Comparison of Alkaline Agents 209
for Chemical Treatment
A-VII-5 Chemical Wastes - Control and 222ff.
Treatment Technology
A-VII-6 Flow Rates - Chemical Wastes 224
xix
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TABLES (continued)
Number Title Page
A-VII-7 Costs/Effluent Reduction Benefits, 225
Control and Treatment Technology for
Pollutants Other Than Heat, High
Volume Waste Streams
A-VII-8 Costs/Effluent Reduction Benefits, 226
Control and Treatment Technology for
Pollutants Other Than Heat,
Intermediate Volume Waste Streams
A-Vll-9 Costs/Effluent Reduction Benefits, 227
Control and Treatment Technology for
Pollutants Other Than Heat,
Low Volume ftaste Streams
A-VII-10 Costs/Effluent Reduction Benefits, 228
Control and Treatment Technology for
Pollutants Other Than Heat,
Rainfall Runoff Waste Streams
A-VIII-1 Design Flow for Chemical Wastes 232
Treatment Plant
A-VIII-2 Estimated Capital Costs, Chemical 233
Wastes Treatment Plant
A-VIII-3 Estimated Annual Operating Costs, 234
Chemical Wastes Treatment Plant
A-VIII-4 Estimated Annual and Unit Costs, 235
Chemical Wastes Treatment Plant
A-VIII-5 Estimated Capital Costs, Treatment 241
of Chemical Wastes
A-VIII-6 Estimated Annual Operating Costs, 242
Treatment of Chemical Wastes for
Reuse
A-VIII-7 Estimated Annual and Unit Costs, 243
Treatment of Chemical Wastes for
Reuse
B-V-1 Efficiencies, Heat Rates, and Heat 259
Rejected by Cooling Water
B-V-2 Plant Visit Thermal Data 261
B-V-3 Typical Characteristics of Waste
Heat Rejection 273
xx
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TABLES (continued)
Number Title Page
B-V-U Total Plant Thermal Discharges 274
B-VII-1 Efficiency Improvements 297
B-VII-2 Energy Demand by Heat Using 312
Applications (1970)
B-VII-3 Uses of Various Types of 376
Cooling Systems
B-VII-4 Extent to Which Steam Electric 377
Powerplarits are Already committed
to the Application of Thermal
Control Technologies
B-VII-5 Cooling Water Systems Data, Plants 378
Visited
B-VIII-1 Cooling Water Systems - Cost Data, 386
Plants Visited
B-VIII-2 Cost of Cooling System Equipment 390
B-VIII-3 Hypothetical Plant Operating Parameters 392
B-VIII-U Revised Plant Operation Parameters 392
B-VIII-5 Typical Plant Characteristics 394
B-VIII-6 Assumed Increase in Heat Rate Compared
to Base Heat Rate as a Function of the 397
Turbine Exhaust Pressure
B-VIII-7 Cost Assumptions 398
B-VIII-8 Cooling Tower Economic Analysis 400
B-VIII-9 Energy (Fuel) Consumption Penalty 409
Due to Increased Turbine Backpressure
from Closed-Cycle Cooling System
B-VIII-10 Effluent Heat, Applicability of 412
Control and Treatment Technology
B-VIII-11 Solids in Drift From Cooling Towers 420
B-VIII-12 Factors Affecting Dispersion and
Deposition of Drift from Natural-Draft 422
and Mechanical-Draft Cooling Towers
xxi
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TABLES (continued)
Number Title
Page
B-VIII-13 Energy Production of Some Natural 431
and Artificial Processes at Various
Scales
B-VIII-1U Evaporation Rates for Various Cooling Systems 436
B-VIII-15 Comparative Utilization of Natural 437
Resources With Alternative Cooling
Systems for Fossil-Fuel Plant with
680 MW Net Plant Output
B-VTII-16 Control and Treatment Technologies 444
for Heat: Ccsts, Effluent Reduction
Benefits, and Non-Water Quality
Environmental Impacts
B-VIII-17 Incremental Cost of Application of 445
Mechanical Eraft Evaporative Cooling
Towers to Nonnew Units (Basis 1970 Dollars)
B-VIII-18 Incremental Cost of Application of 446
Mechanical Eraft Evaporative Cooling
Towers to New Units (Basis 1970 Dollars)
B-VIII-19 Timing for Cases Leading to Significant 448
Thermal Controls by July 1, 1977
B-VIII-20 Estimated Number of Units Requiring 449
Thermal Controls Based on Environmental Need
B-VIII-21 Incremental Oil Consumption If All 451
Environmentally-Based Thermal Controls
Are Added by July 1, 1977
xxii
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SECTION I
CONCLUSIONS
For the purpose of establishing effluent limitations guidelines and
standards of performance for steam electric powerpiants, it has been
found that separate consideration must be given to effluent heat and to
pollutants other than heat, and these are therefore discussed in
separate parts of this report.
Informal categories for establishing guidelines for pollutants other
than heat (chemical-type wastes) have been based on the types of waste
streams generated in each plant, which in turn are dependent on fuels
used, processes employed, plant site characteristics and waste control
technologies. Categories for chemical-type wastes include wastes from
the water treatment system, power cycle system, ash handling system, air
pollution control system, coal pile, yard and floor drainage, condenser
cooling system and miscellaneous wastes.
Informal categories for guidelines for effluent heat (thermal
discharges) include a basic division of the industry by degree of
utilization into base-load, cycling and peaking units. Additional
subcategorizations are based on age and size of facilities.
A survey of current industry practices has indicated that many plants
provide only minimal treatment of chemical type wastes at the present
time, although some of the more recently constructed plants employ
elaborate re-use and recycle systems as a means of water management.
Current industry practice as far as thermal discharges are concerned is
that they have been successfully controlled where required by
environmental considerations or at sites where the lack of sufficient
naturally available cooling water made once-through cooling systems
impractical.
Current treatment ard control technology in the general field of waste
treatment includes many processes which could be applied by powerplants
to reduce the discharge of chemical pollutants. It is therefore
concluded that best practicable control technology currently available
to be applied no later than July 1, 1977, consists of the control and
treatment of chemical-type wastes to achieve significant reductions in
the level of pollutants discharged from existing sources. It is also
concluded that best available technology economically achievable to be
applied no later than July 1, 1983, for chemical-type wastes is
reflected by no discharge of pollutants, other than from cooling water
systems, storm water run-off, sanitary waste systems, and low-level
radwaste systems. No discharge is achievable through the application of
an integrated system of water management which provides for the multiple
re-use of water in uses having descendingly stringent water quality
requirements. Standards of performance for new sources will provide for
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essentially the same effluent levels as best practical control
technology currently available to due the immediate technical risks of
applying best available technology.
For thermal effluents, it is concluded that technology is currently
available and is widely utilized in the industry to achieve any desired
or necessary degree of reduction of the thermal component of powerplant
discharges, including essentially the complete elimination of thermal
discharges. The technological basis for best practicable control
technology currently available, best available technology economically
achievable, and new source performance standards consist of closed-cycle
evaporative cooling systems such as mechanical and natural draft cooling
towers and cooling ponds, lakes and canals.
The designation of specific control and/or treatment as best practicable
control technology currently available, best available technology
economically achievable, or as the basis for new source standards for
both chemical and thermal discharges is intended to satisfy sections
301, 304 and 306 of the Act. Technology so designated provides the
basis for establishment of thermal and chemical effluent limitations
guidelines and standards, in that the technology selected is available
and capable of meeting the recommended guidelines. However, the
designation of specific technology as "best practicable and standards",
etc., does not mean that it alone must be utilized to meet the effluent
limitations. Any technology capable of meeting the guidelines may be
employed by any powerplant so long as the effluent limitations are
achieved.
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SECTION II
RECOMMENDATIONS
As a result of the findings and conclusions contained in this report,
the effluent limitations guidelines and standards of performance
recommended for the steam electric power generating point source
category, in compliance with the mandates of the Federal Water Pollution
Control Act Amendments of 1972, are summarized in Tables II-1 and II-2.
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Table II-l
SUMMARY EFFLUENT LIMITATIONS GUIDELINES AND STANDARDS FOR POLLUTANTS OTHER THAN HEAT
SOURCE
Nonre circulating cooling water systems
Recirculating cooling water systems
Nonrecirculating ash sluicing systems
Nonrecirculating wet-scrubber air
pollution control systems
Low-volume waste sources taken
collectively , as if from one source
Rainfall runoff taken collectively.
as if from one source
Sanitary wastes
Radwastes
Clarification water treatment
Softening water treatment
Transformers
Intake screens
Recirculating ash sluicing systems for
flv ash or oil bottom ash
POLLUTANTS
Chemical additives (biocides)
Chlorine-free available
Chlorine-total residual
Chemical additives (corrosion inhibitors)
Chlorine- free available
Chlorine-total residual
Chr omi urn- 1 ot a 1
Oil and grease
pH value
Total phosphorus (as P)
Total suspended (nonf ilterable) solids
Zinc-total
Oil and grease
pH value
Total suspended (nonf ilterable) solids
Oil and grease
pH value
Total suspended (nonf ilterable) solids
Copper-total
Iron-total
Oil and grease
pH value
Total suspended (nonf ilterable) solids
Oil and grease
pH value
Total suspended (nonf ilterable) solids
All pollutants
All pollutants
All pollutants
All pollutants
Polychlorinated biphenyls
Debris
All pollutants
EFFLUENT LIMITATIONS*
BPCTCA (1977)
No limitation
0.2 (0.5 max)*-*
No limitation
No limitation
0.2 (0.5 max)**
No limitation
No limitation
10
600 to 9oO
No limitation
15 (100 max)***
No limitation
10
600 to 9.0
15 (100 max)***
10
600 to 9.0
15 (100 max)***
1
1 it[i[t
10 (20 max)***
600 to 9.0
15 (100 max)
10 (20 max)**
6.0 to 9.0
15 {100 max) **
Municipal stds .
No limitation
No discharge
No discharge
No discharge
No discharge
_
BATEA (1983)
No limitation
002 (005 max)**
No limitation
No limitation
No limitation
No discharge
002
10
6.0 to 9.0
' 5
15 (100 max)
1
No discharge
-
No discharge
No discharge
-
No discharge
No discharge
No discharge
No discharge
No discharge
-
No discharge
10 (20 max) +
6.0 to 9.0
15 (100 max)4"
Municipal stds .
No limitation
No discharge
No discharge
No discharge
No discharge
_
New Sources
j±
Approx. no discharge,.
Approx. no discharge*.
Approx. no discharge
No discharge
0.2 (0.5 max)***
No limitation
No discharge
10
600 to 9oO
No discharge
15 (100 max)***
No discharge
No discharge
-
No discharge
10
6.0 to 900
15 (100 max)
1
1
10 (20 max)***
6.0 to 9.0
15 (100 max)
10 (20 max)**
6.0 to 9,0
15 (100 max) **
Municipal stds.
No limitation
No discharge
No discharge
No discharge
No discharge
No discharge
* Note: Numbers are concentrations, mg/1, except for pH values. Effluent limitations, except where otherwise indicated, are monthly averages of daily
amounts, mg, to be determined by the concentration shown and the flow of waste water from the source in question. In some cases there are lim-
itations shown on the maximum amount for any day. Where waste waters from one source with effluent limitations for a particular pollutant are
combined with other waste waters, the effluent limitation, mg (or mg/1), for the particular pollutant, excluding pH, for the combined stream
shall be the sum of the effluent limitations (for concentration limits apply appropriate dilution factors) for each of the streams which contri-
bute to the combined stream except that the actual amount, mg (or mg/1), of the pollutant in a contributing stream will be used in place of the
effluent limitation for those contributing streams where the actual amount, mg (or mg/1), of the pollutant is less than the effluent limitation,
mg (or mg/1), for the contributing stream. The pH value should be in the range given at all times.
** Note: Effluent limitations are average concentrations during a maximum of one 2-hour period a day and maximum concentrations at any time. No more than
one unit at a plant may be chlorinated at any time. Limitations are subject to case-by-case variances it higher levels or more-lengntny periods
are needed for condenser tube cleanliness.
*** Note: Or influent amounts, mg, to that source in the same day, whichever is the greater.
# Note: No discharge of chlorine or other biocides used for biological control in condenser tubes.
## Note: Effluent limitations are average concentrations during the time span of each runoff event and maximum concentrations at any time.
### Note: Average is amount, mg, and maximum is concentration, mg/1.
+ Note: Same as ## except that limitations apply separately to (1) the segregated first 15 minutes of runoff from any rainfall event, and (2) the
remainder of the rainfall runoff from any rainfall event.
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Table H-2
SUMMARY OF EFFLUENT LIMITATIONS GUIDELINES AND STANDARDS FOR HEAT
TYPE OF UNIT
BEST PRACTICABLE CONTROL
TECHNOLOGY CURRENTLY AVAILABLE
to be met no later than
July 1, 1977
BEST AVAILABLE TECHNOLOGY
ECONOMICALLY ACHIEVABLE
to be met no later than
LARGE BASE-LOAD
Construction completed
after July 1, 1977
Construction completed
before July 1, 1977
• 500 MW and larger
• 300-499 MW
• all other
SMALL BASE-LOAD
CYCLIC
PEAKING
NO DISCHARGE
NO DISCHARGE (July 1, 1980)
NO LIMITATION
NO LIMITATION
NO LIMITATION
NO LIMITATION
NO LIMITATION
NO LIMITATION
NO DISCHARGE
NO DISCHARGE
NO DISCHARGE
NO DISCHARGE
NO DISCHARGE
NO DISCHARGE
(July 1,
(July 1,
(July 1,
(July 1,
(July 1,
(July 1,
1978)
1979)
1980)
1983)
1983)
1983)
Large means units in plants over 25 MW and in systems over 150 MW.
No limitation for any unit with a remaining service life of six years or less.
No limitation on once-through house service water for nuclear units.
No discharge excludes blowdown,which is limited to a temperature not exceeding the
temperature of water returned to the condenser.
Variations can be granted on a case-by-case basis where sufficient land is not available
and (for best practicable control technology currently available, only) where
neighboring land uses would be impacted by saltwater drift, provided (for both land
availability and saltwater drift) alternative technologies are not practicable.
r
STANDARD OF PERFORMANCE FOR NEW SOURCES IS NO DISCHARGE OF HEAT (EXCEPT FOR SLOWDOWN)
FOR ALL UNITS/ WITHOUT EXCEPTION
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SECTION III
INTRODUCTION
General Background
The involvement of the Federal Government in water pollution control
dates back to 1948, when Congress enacted the first comprehensive
measure aimed specifically at this problem. At that time the Surgeon
General, through the U. S. Public Health Service, was authorized to
assist states in various ways to attack the problem. The emergence of a
national water pollution ccntrol program came about with the enactment
of the Water Pollution Control Act of 1956 (Public Law 84-660) which to
this date remains the basic law governing water pollution. This law set
up the basic system cf technical and financial assistance to states and
municipalities, and established enforcement procedures by which the
Federal Government could initiate legal steps against polluters.
The present program dates back to the Water Quality Act of 1965 and the
Clean Water Restoration Act of 1966. Under the 1965 Act, the states
were required to adopt water quality standards for interstate waters,
and to submit to the Federal Government, for approval, plans to
implement and enforce these standards. The 1966 Act authorized massive
Federal participation in the construction of sewage treatment plants.
An amendment, the Water Quality Act of 1970, extended Federal activities
into such areas as pollution by oil, hazardous substances, sewage from
vessels, and mine drainage.
Originally, pollution ccntrol activities were the responsibility of the
U. S. Public Health Service. In 1961, the Federal Water Pollution
Control Administration (FWPCA) was created in the Department of Health,
Education, and Welfare, and in 1966, the FWPCA was transferred to the
Department of the Interior. The name was changed in early 1970 to the
Federal Water Quality Administration and in December 1970, the
Environmental Protection Agency (EPA) was created by Executive Order as
an independent agency outside the Department of the Interior. Also by
Executive Order 11574 on December 23, 1970, President Richard M. Nixon
established the Permit Program, requiring all industries to obtain
permits for the discharge of wastes into navigable waters or their
tributaries under the provisions of the 1899 River and Harbor Act
(Refuse Act). The permit program immediately became involved in legal
problems resulting eventually in a ruling by a Federal court that
effectively stopped the issuance of a significant number of permits, but
it did result in the filing with EPA, through the U.S. Army Corps of
Engineers, of applications for permits which, without doubt, represent
the most complete inventory of industrial waste discharges yet compiled.
The granting of a permit under the Refuse Act was dependent on the
discharge being able to meet applicable water quality standards.
-------
Although EPA could not specify methods of treatment, they could require
minimum effluent levels necessary to meet water quality standards.
The Federal Water Pollution Control Act Amendments of 1972 (the "Act")
made a number of fundamental changes in the approach to achieving clean
water. One of the most significant changes was from a reliance on water
quantity related effluent limitations to a direct control of effluents
through the establishment of technology-based effluent guidelines to
form an additional basis, as a minimum, for issuance of discharge
permits. The permit program under the 1899 Refuse Act was placed under
full control of EPA, with much of the responsibility to be delegated to
the States.
Purpose and Authority
The Act requires the EPA to establish guidelines for technology-based
effluent limitations which must be achieved by point sources of
discharges into the navigable waters of the United States. Section
301 (b) of the Act requires the achievement by not later than July 1,
1977, of effluent limitations for point sources, other than publicly
owned treatment works, which are based on the application of the best
practicable control technology currently available as defined by the
Administrator pursuant to Section 304(b) of the Act. Section 301 (b)
also requires the achievement by not later than July 1, 1983, of
effluent limitations for point sources, other than publicly owned
treatment works, which are based on the application of the best
available technology economically achievable which will result in
reasonable further progress toward the national goal of eliminating the
discharge of all pollutants, as determined in accordance with
regulations issued by the Administrator pursuant to Section 304 (b) of
the Act. Section 306 of the Act requires the achievement by new sources
of a Federal standard of performance providing for the control of the
discharge of pollutants which reflects the greatest degree of effluent
reduction which the Administrator determines to be achievable through
the application of the best available demonstrated control technology,
processes, operating methods, or other alternatives, including, where
practicable, a standard permitting no discharge of pollutants. Section
304(b) of the Act requires the Administrator to publish within one year
of enactment of the Act, regulations providing guidelines for effluent
limitations setting forth the degree of effluent reduction attainable
through the application of the best practicable control technology
currently available and the degree of effluent reduction attainable
through the application of the best control measures and practices
achievable including treatment techniques, process and procedure
innovations, operation methods and other alternatives. The regulations
proposed herein set forth effluent limitations guidelines pursuant to
Section 304(b) of the Act for the steam electric powerplant industry.
Section 306 of the Act requires the Administrator, within one year after
a category of sources is included in a list published pursuant to
-------
Section 306 (b) (1) (A) of the Act, to propose regulations establishing
Federal standards of performances for new sources within such
categories. The Administrator published in the Federal Register of
January 16, 1973 (38 F.R. 1624), a list of 27 source categories.
Publication of the list constituted announcement of the Administrator1s
intention of establishing, under Section 306, standards of performance
applicable to new sources within the steam electric powerplants industry
category, which was included within the list published January 16, 1973.
See Table III-1 for a summary of the principal statutory considerations.
Section 316(a) of the Act provides that whenever the owner or operator
of any point source can demonstrate to the satisfaction of the
Administrator that any effluent limitation proposed for the control of
the thermal component of any discharge will require more stringent
control measures than are necessary to assure the protection and
propagation of a balanced, indigenous population of shellfish, fish and
wildlife in and on the body of water into which the discharge is to be
made the Administrator may impose less stringent limitations with
respect to the thermal component, (taking into account the interaction
of such thermal component with other pollutants) that will assure the
protection and propagation of a balanced, indigenous population of
shellfish, fish, and wildlife in and on that body of water.
The Act defines a new source to mean any source, the construction of
which is commenced after the publication of proposed regulations
prescribing a standard of performance. Construction means any
placement, assembly, or installation of facilities or equipment
(including contractual obligations to purchase such facilities or
equipment) at the premises ehere such equipment will be used, including
preparation work at such premises.
Scope of Work and.Technical Approach
This document was developed, specifically, for effluent discharge from
steam electric powerplants covered under Standard Industrial
Classification 1972 Industry Nos. 4911, 4931, and 4932, relating to
liquid discharges to navigable waters of the United States. The study
was limited to powerplants comprising the electric utility industry, and
did not include steam electric powerplants in industrial, commercial or
other facilities. Electric generating facilities other than steam
electric, such as combustion gas turbines, diesel engines, etc. are
included to the extent that power generated by the establishment in
question is primary through steam electric processes.
This report covers effluents from both fossil-fueled and nuclear plants
and excludes the radiological aspects of effluents.
The Act requires that in developing effluent limitations guidelines and
standards of performance for a given industry, certain factors must be
considered, such as the total cost of the application of technology in
-------
Table III-1
PRINCIPAL STATUTORY CONSIDERATIONS
STATUTORY
BASIS General Description Process Changes Cost
Process
Employed, Age
& Size of Equip-
ment & Facilities-
"Non Water Quality
Environmental
Impact & Energy
Best Practicable
Control Technology
Currently Available
304(b)(l)(A)
[Existing Sources]
1. Achieve by 1977.
2. Generally average
of best existing per-
formance; high con-
fidence in engineering-
viability.
3. Where treatment
uniformly inadequate
a higher degree of
treatment may be
required if practic-
able [compare exist-
ing treatment of
similar wastes].
Normally does not
emphasize in-process
controls, except
where presently
commonly practiced.
Balancing of
total cost of
treatment against
effluent reduc-
tion benefits.
Age, size &
process employed
may require
variations in
discharge limits
(taking into account
compatibility of costs
and process technology)
Assess impact of
alternative controls
on air, solid waste,
noise, radiation
and energy require-
ments.
Best Available
Technology
Economically
Achievable
304(b)(l)(B)
[Existing Sources]
1. Achieve by 1983.
2. Generally best
existing performance
but may include tech-
nology which is capable
of being designed,
though not yet in
place; further
development work could
be required.
Emphasizes both
in-process and end-
of-process control.
Costs considered
relative to broad
test of reasons
ableness.
Age, size &
process employed
may require
variations in
discharge limits
(taking into account
compatibility of costs
and process technology)
Assess impact of
alternative controls
on air, solid waste
noise, radiation and
energy requirements.
Standards of
Performance Best
Available
Demonstrated Con*
trol Technology
306
[New Sources]
1. Achieved by sources Emphasizes process
for which "construe- changes.
tion" commences after
proposal of regula-
tions.
2. Generally same
considerations as for 1983;
more critical analysis
of present availability.
Cost considered
relative to broad
test of reasonable-
ness.
N/A
Assess impact of
alternative controls
on air, solid waste,
noise, radiation
and energy require-
ments.
-------
relation to the effluent reduction benefits to be achieved, age of
equipment and facilities, processes employed, engineering aspects of the
application of various types of control techniques, process changes,
non-water quality enviornmental impact (including energy requirments)
and other factors. For steam electric powerplants, formal segmentation
of the industry based on all the factors mentioned in the Act has been
found to be inapplicable. However, the two basic aspects of the
effluents produced by the industry, chemical aspects and thermal
aspects, were found tc involve such divergent considerations that a
basic distinction between guidelines for chemical wastes and thermal
discharges was determined to be most useful in achieving the objectives
of the Act. Accordingly, this report covers waste categorization,
control and treatment technology and recommendations for effluent
limitations for chemical and other nonthermal aspects of waste discharge
in Part A and similar subjects for thermal aspects of discharges in Part
B of this report considering the factors cited in the Act.
Section 502(6) of the Act defines the term pollutant in relation to the
discharge into water of certain materials, substances and other
constituents of discharge. The inclusion of heat in the list of
pollutants indicates the clear intention on the part of Congress to have
this pollutant included in the same manner as other pollutants in the
establishment of effluent limitation guidelines and standards of
performance. The only recognition of heat in any special terms in the
Act is in Sections 104(t) and 316.
Section 104(t) requires the EPA Administrator in cooperation with other
agencies and organizations to conduct continuing comprehensive studies
of the effects and methods of control of thermal discharges. The
studies are to include cost-effectiveness analysis and total impact on
the environment. The Act states that they are to be used by EPA in
carrying out Section 316 of the Act, and by the States in establishing
water quality standards. However it does not indicate that the studies
are to be utilized in establishing effluent limitation guidelines and
standards of performance. Section 316(a) does provide for individual
variances to be granted from effluent guidelines for thermal discharges,
where such a variance will assure the protection and propogation of a
balanced, indigenous population of shellfish, fish and wildlife in and
on that body of water.
Consequently, the Act requires effluent guidelines and standards of
performance for heat to be developed in the same manner as for other
pollutants, but also allows for individual relief from the guidelines
and standards under Section 316. In this context, this report only
contains an evaluation of control and treatment technology for thermal
discharges which reduces or eliminates the amounts of heat discharged.
Consideration of mixing zone technology is therefore not included, since
mixing zones do not reduce the effluent heat but rely in part upon the
dilution effect of the receiving water to decrease the overall receiving
water temperatures to meet applicable limitations based on environmental
11
-------
criteria. Therefore they do not qualify as a control or treatment
technology for the establishment of technology-based effluent
limitations guidelines or standards of performance.
The effluent limitations guidelines and standards of performance
proposed herein have been developed from a detailed review of current
practices in the steam electric powerplant industry. A critical
examination was made of treatment methods now in use in the industry and
methods used in other industries to achieve solutions to problems
similar to those encountered in steam electric powerplants. As part of
the review of current practices, applications for discharge permits
filed in accordance with ether provisions of the Act were examined.
However, since these permit applications cover only the characteristics
of the effluent with no quantification of the corresponding treatment
practices, the value of the information obtainable from them is fairly
limited. Also as part of this effort visits were made to 27 plants,
with at least one plant visit to each of the ten EPA regions. Sampling
programs were conducted at plants where it was felt that sufficient
information could be obtained to document exemplary treatment practices.
The economic analysis contained in this report pertain only to costs
related to control and treatment technology for the reduction and/or
elimination of the discharge of pollutants from steam electric
powerplants. Benefits derived from associated costs are simply the
reduction and/or elimination of pollutant discharges. Cost/benefit
analysis which consider environmental effects, benefits to society,
economic impact, etc. are beyond the scope of this report.
In arriving at recommendations for effluent limitations guidelines and
standards of performance, extensive use has been made of prior studies
in this area made for EPA, in-house informatipn developed by EPA, and
information developed by industry sources. In particular, reference was
made to unpublished material contained in a draft report prepared by
Freeman Laboratories, Inc., for the Water Quality Office, EPA, under
Contract No. EPA-WQO 68-01-0032, entitled Industrial Waste Studies:
Steam Generating Plants, dated May 1971.
Industry Description
Steam electric powerplants are the production facilities of the electric
power industry. The industry also provides for the transmission and
distribution of electric energy. The industry is made up of two
basically distinct ownership categories, investor-owned and publicly-
owned, with the latter further divided into Federal agencies, non-
Federal agencies, and cooperatives. About two-thirds of the 3400
systems in the United States perform only the distribution function, but
many perform all three functions, production (generally referred to as
generation) , transmission, and distribution. In general, the larger
systems are vertically integrated, while the smaller systems, largely in
the municipal and cooperative categories, rely on firm purchases to meet
12
-------
all cr part of their requirements. Many of the systems are
interconnected, and can, under emergency conditions, obtain power from
other systems.
Historically, the industry started around 1880 with the construction of
Edison's steam electric plant in New York City. For the next sixty
years, growth was continuous, but unspectacular, due to the fairly
limited demand for power. However, since 1940 the annual per capita
production of electric energy has grown at a rate of about six percent
per year, and the total energy consumption by about seven percent. In
I970, there were about one thousand generating systems in the United
States. These systems had a combined generating capacity of 340,000
megawatts (MW) and produced 1,530,000,000 megawatt hours (MWH) of
energy. A breakdown of the capacity and production by ownership
categories is given in Table III-2.
The industry produces, transmits and distributes a single product,
electric energy. The product is distinguished from other products of
the American industry by the fact that it cannot be stored, and that the
industry must be ready tc produce at any give time all the product the
consumer desires to utilize. While some industrial power is sold on a
so-called "interruptitle" basis, the total amount sold on this basis is
insignificant compared to the overall power consumption. As a matter of
fact, the ability cf the industry to meet any instantaneous demand is
the criterium for what constitutes satisfactory performance in the
industry and is the single most significant factor in determining the
need for new generating facilities.
Other special considerations involved in a discussion of the industry
relate to its role as a public utility, a monopoly, and a regulated
industry. As a public utility, its major objective is to provide a
public service. It mist supply its product to all customers within its
assigned service-area, but it cannot discriminate between customers, and
it must supply its product to all customers within a given class at
equal cost. As a monopoly, the industry is generally assigned a service
area, but within that area is exempt from competition except perhaps for
competition with other sources of energy, particularly in the industrial
area. However, in return for the granting of a monopoly, the industry
is required to furnish service. Thus it • cannot cease to service a
certain area when such service appears to be unprofitable. Finally, in
view of its position as a public utility and a monopoly, both the
quality of service it must provide and the rates it may charge for its
service are regulated by both State and Federal regulatory agencies.
Since the rates it is allowed to charge are a function of the cost of
providing service, any prudent costs imposed on the industry by
regulatory agencies will eventually be passed on to the electricity
consumer. And since the consumer, particularly at the retail
residential level, has very few options to the use of electricity, the
relationship between costs and consumption is generally considered to be
13
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Table HI- 2
SUMMARY DESCRIPTION
ELECTRICAL POWER GENERATING INDUSTRY (YEAR 1970)
Number of plants (stations) approx. 1000
Number of generating units approx. 3000
OWNERSHIP
Investor
Federal
Public (non—Fed)
Cooperative
NUMBER OF SYSTEMS*
250
2
700
65
GENERATING CAPACITY, MW*
265,000
40,000
35,000
5,000
GENERATION, 10 MWH*
1,180
190
140
22
CUSTOMERS
Residential
Commercial
Industrial
Other
NUMBER
55,000,000
8,000,000
400,000
ENERGY SOLD, MWH
450,000,000
325,000,000
575,000,000
60,000,000
PROJECTED GROWTH
1970
1980
1990
INSTALLED CAPACITY, MW
266,000
540,000
1.057.000
FUEL USED
Coal
Natural Gas
Oil
Nuclear
PERCENT HEAT INPUT
54
29
15
2
COST (YEAR 1968)
Production
To Customers
mills/KWH
7.7
15.4
* Note: Includes some hydroelectric and internal combustion.
-------
"inelastic" in the short time, that is, an increase in cost has little
effect on the level of consumption.
The use of electric energy can be divided into three major categories:
industrial, residential and commercial. In 1965, industrial use
accounted for 41% cf all energy generated. Residential use accounted
for 24% and commercial use for 18%. Another 17% of the energy generated
was used by miscellaneous users for auxiliary operations within the
industry or lost in transmissions. Studies by the Federal Power
commission (FPC) indicate no change in this basic use pattern over the
next two decades.
On the other hand, the total amount of electric energy that will be used
is expected to increase significantly over the next two decades. Again,
based on studies by the FPC, it is believed that the required generating
capacity will increase from 340,000 MW in 1970 to 665,000 MW in 1980 and
1,260,000 MW in 1990. The industry's 1970 generating facilities would
therefore have to be almost doubled by 1980 and again doubled by 1990.
At the present time, steam electric powerplants, including both fossil"
fueled and nuclear-fueled plants, account for about 79% of total
generating capacity and 83% of the total power generated. The remainder
is accounted for by hydroelectric generation, both of the once-through
and pumpedstorage types, and by direct combustion-generation processes
such as gas turbines and diesel engine driven generators. Table III-3,
taken from reports of the FPC, shows the projected growth of generating
capacity over the next two decades.
Four basic fuels are used in steam electric powerplants, three fossil
fuels-coal, natural gas and oil - and uranium, presently the basic fuel
of nuclear power. A potential fuel, reclaimed refuse, is being burned
at one experimental facility, but is not likely to have a major impact
on the industry within the foreseeable future. Table III-4, again from
FPC reports, shows the projected distribution of fuel use for steam
electric power generation for the next two decades.
Table III-5 shows the projected annual fuel requirements for steam
electric powerplants over the next two decades. See also Figure III-1
for a graphical presentation of the projection, by the Joint Committee
on Atomic Energy, of the U*S. energy flow pattern for 1980. Although
their share of the total fuel use is declining, the actual use of all
three fossil fuels is projected to continue to increase. Most
significant is the fact that utility consumption of coal will more than
double although coal's share of the total use will decrease from 54% to
31%. These projections assume no major slippages in the construction of
nuclear generating plants, should such slippages occur, it is possible
that coal will be called upon to assume an even greater role in meeting
the nation's energy needs.
15
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TABLE III- 3
CTl
PROJECTED GROWTH OF UTILITY ELECTRIC GENERATING CAPACITY
(Figures in thousands of megawatts)
Type of Plant
Fossil Steam
Nuclear Steam
Subtotal Steam
Hydroelectric-
conventional
Hydroelectric-
pumped storage
Gas-Turbine and Diesel
TOTALS
1970 (actual)
% of
Capacity Total
260 76
6 2
266 78
52 15
4 1
19 6
341 100
1980
% of
Capacity Total
393 59
147 22
540 81
68 10
27 4
31 5
666 100
1990
% of
Capacity Total
557 44
500 40
1,057 84
82 6
71 6
51 4
1,261 100
Notes: (1)
(2)
(3)
These projections are keyed to the electrical energy demand projections made
by Regional Advisory Committee studies carried out in the 1966-1969 period.
The projections are premised on an average gross reserve margin of 20%.
Since different types of plants are operated at different capacity factors,
this capacity breakdown is not directly representative of share of kilowatt-hours
production. For example, since nuclear plants are customarily used in base-load
service and therefore operate at comparatively high capacity factors, nuclear
power's contribution to total electricity production would be higher than its
capacity share.
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Table III-4
FPC PROJECTION OF FUEL USE IN STEAM ELECTRIC
POWERPLANTS
Fuel
Coal
Natural Gas
Fuel Oil
Nuclear
1970
54%
29
15
2
1980
41%
14
14
31
1990
30%
8
9
53
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Table III- 5
PPG PROJECTED ANNUAL FUEL REQUIREMENTS FOR
STEAM ELECTRIC POWERPLANTS
Fuel
Coal
Natural Gas
Fuel Oil
U^00
3 8
Measure
10 tons
12
10 cubic feet
10 barrels
3
10 tons to diffusion
plants without re-
cycle of plutonium
1970
332
3.6
331
7.5
1980
500
3.8
640
41
1990
500
3.8
800
127
00
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Figure III-l
PROJECTED TOTAL U.S. ENERGY PLOW PATTERN (1980)
234
HYDROELECTRIC
GEOTHERMAL
NUCLEAR
GAS
[IMPORTS)
GAS
(DOMESTIC)
COAL
OIL
(IMPORTS)
OIL
(DOMESTIC)
Sgj^CONyERSIONLOSSES
ELECTRICAL
ENERGY
GENERATION
13.2
(UNITS: MILLION BBLS/DAY OIL EQUIVALENTI
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Coal is the most abundant of the fossil fuels. Nationwide it
estimated that proven recoverable reserves are sufficient to supply
needs for the next 200 to 300 years. A problem with coal is that it
varies in chemical properties and its geographic distribution does not
coincide with the geographic distribution of the demand for electric
energy. A primary concern is the sulfur content of the coal. Most of
the Eastern coal is too high in sulfur content to meet the increasingly
stringent limits on sulfur dioxide in stack gases.
Sulfur dioxide removal systems are being employed at a number of
powerplants. All indications are that limitations on sulfur dioxide
emissions will substantially increase production costs in coal-burning
powerplants. In the West, there are large deposits of low sulfur coal,
but here the cost of either shipping the coal or transmitting electric
energy are substantial. The possibilities of further environmental
restrictions as much as the actual environmental regulations now in
force has possibly resulted in the conversion of a large number of coal
burning plants to ether forms of fossil fuel, and the construction of
new generating facilities using less abundant but more environmentally
acceptable fuels.
Both natural gas and low sulfur residual oils are in short supply. The
natural gas situation was initially felt to be more critical and some
generating plants were being converted from natural gas to fuel oil.
The FPC projections indicated that natural gas utilization would remain
fairly constant and that the use of fuel oil would increase at
approximately the same rate as the use of coal. All of these
projections were based on the assumption that there would be no
additional governmental actions regulating the utilization of fuels and
that nothing would happen to affect our present heavy reliance on
foreign sources for fuel oil. Subsequently, the fuel oil problem became
critical, projections were altered and certain plants were considered
for reconversion to ccal.
Finally, the projected growth of nuclear generating capacity is
dependent in the short run on the discovery of additional deposits of
low-cost uranium and the construction of additional ore processing
facilities. In the Icng run, it is dependent on the successful
development and use of breeder reactor systems. The United States may
have a full-scale breeder plant in operation in the 1980's.
In summary, this report deals with the setting of effluent guidelines
for an industry with many complex aspects. It is a public utility and
therefore is regulated both as to the quality of its service and the
rates it can charge for the service. While regulation limits the rates
it can charge, it alsc insures that any prudently increased costs will
eventually be passed on to the retail customer. Except for some
competition in the industrial use of electricity, there is little
competition for the use of its product. On the other hand, the industry
itself has little mobility. A powerplant generally cannot be moved and
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a generating unit can be shut down only when an equivalent unit has been
provided, since its product cannot be stored and must be produced to
meet a fluctuating demand, much of its capacity is used only part time.
With suitable sites near the centers of demand largely used up, it has
to go further and further from its demand to obtain satisfactory
generating sites, and even then is often encountering pressure from
environmental groups opposed to the construction of the new facilities.
Generally, the slippage in the schedules for new powerplants is
requiring the industry to continue to operate some of the older, less
efficient, and perhaps less environmentally acceptable plants.
Amplification of the "energy crisis" has evoked considerable attention,
constraints, and changes in the industry. In addition to some shifts in
fuel and fuel costs, reduced projections for the demand for electricity
have caused at least one major system to announce a slowdown in planned
expansion resulting in the delay in construction of two large generating
units.
The setting of effluent standards for steam electric powerplants has
therefore involved a large number of complex factors, many of which do
not apply to a conventional manufacturing industry producing a non-
perishable, transportable product in a competitive market.
Process Description
The "production" of electrical energy always involves the utilization
and conversion of some other form of energy.
The three most important sources of energy which are converted to
electric energy are the gravitational potential energy of water, the
atomic energy of nuclear fuels, and the chemical energy of fossil fuels.
The utilization of water power involves the transformation of one form
of mechanical energy into another prior to conversion to electrical
energy, and can be accomplished at greater than 90 percent of
theoretical efficiency. Therefore, hydroelectric power generation
involves only a minimal amount of waste heat production due to
conversion inefficiencies. Present day methods of utilizing the energy
of fossil fuels, on the other hand, are based on a combustion process,
followed by steam generation to convert the heat first into mechanical
energy and then to convert the mechanical energy into electrical energy.
Nuclear processes as generally utilized also depend on the conversion of
thermal energy (heat) to mechanical energy via a steam cycle* Although
progress in powerplant development has been rapid, a large part of the
energy released by the fuel as heat at a high temperature level, in even
the most efficient plants, is not converted to useful electrical energy,
but is exhausted as heat at a lower temperature level. This is due to
the second law of thermodynamics which rests an experimental evidence.
Where a water-steam cycle is used to convert heat to work, the maximum
theoretical efficiency that can be obtained is limited by the
temperatures at which the heat can be absorbed by the steam and
21
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discarded to the environment. The upper temperature is limited by the
temperature of the fuel bed and the structural strength and other
aspects of the boiler. The lower temperature is ideally the ambient
temperature of the environment, although for practical purposes the
reject temperature must be set by design significantly above the highest
anticipated ambient temperature. Within these temperatures it can be
shown that the conversion of heat into any other form of energy is
limited to efficiencies of about 40 percent regardless of any
improvements to the machines employed. The limited boiler temperature
utilized by present day light water nuclear powerplants is the major
reason of the lower efficiency of these plants compared to fossil-fueled
plants. For any steam electric power generation scheme, therefore, a
minimum of 60 percent of the energy contained in the fuel must be
rejected to the environment as waste heat. The extent to which existing
and future steam electric powerplants approach this theoretical limit
will be discussed later in this report, as will alternate methods of
converting fuel energy to electric energy which do not employ a steam
cycle and therefore are not limited to steam cycle efficiencies.
Fossil-fueled steam electric powerplants produce electric energy in a
four stage process. The first operation consists of the burning of the
fuel in a boiler and the conversion of water into steam by the heat of
combustion. The second operation consists of the conversion of the
high-temperature high-pressure steam into mechanical energy in a steam
turbine. The steam leaving the turbine is condensed to water,
transferring heat to the cooling medium, which is normally water. The
turbine output is conveyed mechanically to a generator, which converts
the mechanical energy into electrical energy. The condensed steam is
reintroduced into the boiler to complete the cycle.
Nuclear powerplants utilize a similar cycle except that the source of
heat is atomic interactions due to nuclear fuel rather than combustion
of fossil fuel.- Water serves as both moderator and coolant as it passes
through the nuclear reactor core. In a pressurized water reactor, the
heated water then passes through a separate heat exchanger, where steam
is produced on the secondary side. This steam, which is not
radioactive, drives the turbine. In a boiling water reactor, steam is
generated directly in the reactor core and is then piped directly to the
turbine. This arrangement results in some radioactivity in the steam
and therefore requires some shielding of the turbine. Long term fuel
performance and thermal efficiencies are similar for the two types of
nuclear systems.
The theoretical water-steam cycle employed in steam electric powerplants
is known as the Rankine cycle. Actual cycles in powerplants only
approach the performance of the Rankine cycle because of practical
considerations. Thus, the heat absorption does not occur at constant
temperature, but consists of heating of the liquid to the boiling point,
converting of liquid to vapor and superheating (heating above the
saturation equilibrium temperature) the steam. Superheating is
22
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necessary to prevent excess condensation in the turbines and results in
an increase in cycle efficiency. Reheating, the raising of the temper-
ature above saturation of the partially expanded steam, is used to
obtain improvements in efficiency and again to prevent excess
condensation. Preheating, bringing of condensate to near boiling
temperatures with waste heat, is also used for this purpose. Condensers
cannot be designed to operate at theoretically optimum values because it
would require infinitely large equipment. All of these divergences from
the optimum theoretical conditions cause a decrease in efficiency and an
increase in the amount cf heat rejected per unit of production. As a
result, only a few of the larger and newer plants approach even the
efficiencies possible under, the ideal Rankine cycle. Also as a result
of second law limitations» modifications of the steam cycle of an
existing plant are not likely to result in significant reductions in
heat rejection.
Alternate Processes
Alternate processes for generating electric energy can be divided into
three distinct groups. The first group includes those processes that
are presently being used to generate significant amounts of electrical
energy. This group includes hydroelectric power generation, combustion
gas turbines, and diesel engines. The second group includes processes
that seek to improve on the steam electric cycle by utilizing new fuels
or new energy technology* This group includes liquid metal fast breeder
reactors, geothermal generation, utilization of solar energy, and
various forms of combining cycles to obtain greater thermal efficiency.
The last group includes .those systems, also mostly still under
development, that seek to eliminate the inherent limitations of the
Rankine cycle by providing for some type of direct conversion of
chemical energy intc electrical energy. This group includes
magnetohydrodynamics, electrogasdynamics and fuel cells.
Presently Available Alternate Processes
Hydroelectric Power
Hydroelectric developments harness the energy of falling water to
produce electric power, and have a number of distinct advantages over
steam electric plants. Operation and maintenance costs are generally
lower. Although the initial capital cost may be higher, hydroelectric
developments have longer life and lower rates of depreciation, and
capital charges may therefore be less. The cost of fuel is not an item
of operating cost. Beth availability and reliability are greater than
for steam electric units. Hydroelectric plants are well suited for
rapid start and rapid changes in power output and are therefore
particularly well adapted to serve peak loads. Best of all,
hydroelectric plants do not consume natural fuel resources, produce no
emissions that affect air quality and discharge no significant amounts
of heat to receiving waters.
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Unfortunately, the availability of hydroelectric power is limited to
locations where nature has created the opportunity by providing both the
stream and the difference in elevation to make the energy extractable.
In many instances this means generation far away from load centers with
long transmission lines required to bring the energy to its point of
use. At the present time, hydroelectric generation in the United States
is a major factor only in the Far West, in New York State, and in some
areas of the Appalachian Region. Total hydroelectric capacity installed
at the end of 1970 amounted to 52,300 MW, amounting to about 15S5 of the
total installed U. S. generating capacity. In spite of a projected
growth of about 30,000 MW by 1990, the share of once-through electric
power is expected to decline to about 1% by 1990. The primary reason
for this decline is that the best available sites for hydroelectric
power have already been developed and that the remaining sites are
either too far from lead centers or too costly to develop. Development
of some sites may be prohibited by legislation such as the Colorado
River Basin Project Act (P. L. 90-537) and the Wild and Scenic Rivers
Act (P. L. 90-542). Development of the maximum potential at other
sites may be limited ty the Federal Power Act which requires that a
project to be licensed or relicensed be best adapted to a comprehensive
plan for the use of the basin's resources.
There is a possibility of importing substantial blocks of hydroelectric
power from eastern Canada, but the rapid rate of growth in Canada has
possibly been a factor in the inability of that country and the United
States to enter into long-term contracts for the sale of power. As much
as 5,000 MW might be available on a short-term basis of about twenty
years and could be transmitted to load centers in the Northeastern
United States at economically feasible costs.
One form of hydroelectric power, pumped storage projects, is expected' to
play an increasing role in electric power generation. In a pumped
storage project water is pumped, by electricity generated by thermal
units, into an elevated reservoir site during off-peak hours and
electricity is then generated by conventional hydro means during the
periods of peak usage. Pumped storage plants retain the same favorable
operating characteristics as once-through hydroelectric plants. Their
ability to accept or reject large blocks of energy very quickly make
them much more flexible than either fossil-fueled or nuclear plants. Of
course, the power required to pump the water into the reservoir must be
generated by some ether generating facility. Efficiencies of pumping
and of hydroelectric generation are such that about 3 KWH of energy must
be generated for each 2 KWH recovered, but on many systems the loss of 1
KWH of non-peak fuel consumption in lieu of 2 KWH (equivalent) of
capital expenditure for additional peak generating capacity is favorable
in the light of overall system economics.
Although the earliest pumped storage project dates back to 1929, total
pumped storage capacity at the end of 1970 amounted to only 3,700 MW.
FPC estimates indicate that pumped storage capacity may reach 70,000 MW
24
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by 1990. This would represent a higher rate of growth than the
projected growth of the entire industry.
Although hydroelectric plants produce neither air emissions nor thermal
discharges, some proposed projects have drawn opposition from
environmental groups because of the large volumes of water being drawn
through the turbine-pump units, with the associated potential for damage
to marine life, and the relatively large areas of uncertainty
surrounding the effect of artificial reservoirs on groundwater regimen.
Several of the pumped storage project reservoirs have required remedial
measures to reduce leakage of water from the reservoir.
In general, hydroelectric power represents a viable alternative to
fossil-fueled or nuclear steam cycle generation where geographic,
environmental and economic conditions are favorable. Pumped storage
additionally offers an opportunity to improve overall system performance
and reliability, particularly for rapid startup and maintenance of
reserves ready to be loaded on very short notice.
Combustion Gas Turbines and Diesel Engines
Combustion gas turbines and diesel engines are devices for converting
the chemical energy of fuels into mechanical energy by using the Brayton
and Diesel thermal cycles as opposed to the Rankine cycle used with
steam. As with the Rankine cycle, the second law of thermodynamics
imposes upper limits as their ideal energy conversion efficiencies based
on the maximum combustion temperature and the heat sink temperature
(ambrient air). The actual conversion efficiencies of combustion gas
turbines and diesel engines are lower than those of the better steam
cycle plants. Diesel engines are used in small and isolated systems as
a principal generator of electrical energy and in larger systems for
emergency or standby service. Combustion gas turbines are used
increasingly as peaking units and in some instances as part of combined
cycle plants, where the hot exhaust gases from a combustion gas turbine
are passed through a toiler to generate steam for a steam turbine. Both
types of units are relatively low in capital cost ($/KW), require little
operating labor, are capable of remote controlled operation, and are
able to start quickly. Since these units typically operate less than
1,000 hours per year, fuel costs are generally not a deciding factor.
In a combustion gas turbine, fuel is injected into compressed air in a
combustion chamber. The fuel ignites, generating heat and combustion
gases, and the gas mixture expands to drive a turbine, which is usually
located on the same axle as the compressor. Various heat recovery and
staged compression and combustion schemes are in use in order to
increase overall efficiency. Aircraft jet engines have been used to
drive turbines which in turn are connected to electric generators. In
such units, the entire jet engine may be removed for maintenance and a
spare installed with a minimum of outage time. Combustion gas turbines
25
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require little or no cooling water and therefore produce no significant
thermal effluent.
Diesel engines can be operated at partial or full loads, are capable of
being started in a very short time, and are ideally suited for peaking
use. Many large steair electric plants contain diesel generators for
emergency shutdown and startup power if the plant is isolated from
outside sources of power.
In 1970, combustion gas turbine and diesel engines represented 6% of the
total United States generating capacity. This represented 15,000 MW of
combustion gas turbines and 4,000 MW of diesel engines.
Alternate Processes Under Active Development
Future Nuclear Types
At the present time almost all of the nuclear powerplants in operation
in the United States are of the boiling water reactor (BWR) or
pressurized water reactor (PWR) type. As previously discussed some
technical aspects of these types of reactors limit their thermal
efficiency to about 30%. There are potential problems in the area of
fuel availability if the entire future nuclear capacity is to be met
with these types of reactors. In order to overcome these problems, a
number of other types of nuclear reactors are in various stages of
development. The objective of developing these reactors is two-fold, to
improve overall efficiency by being able to produce steam under
temperature and pressure conditions similar to those being achieved in
fossil fuel plants, and to assure an adequate supply of nuclear fuel at
a minimum cost. Included in this group are the high temperature gas-
cooled reactor (HTGR), the seed blanket light water breeder reactor
(LWBR), the liquid metal fast breeder reactor (LMFBR) , and the gas-
cooled fast breeder reactor (GCFBR). All of these utilize a steam cycle
as the last stage before generation of electric energy. Both the HTGR
and the LMFBR have advanced sufficiently to be considered as potentially
viable alternate processes.
The HTGR is a graphite-moderated reactor which uses helium as a primary
coolant. The helium is heated to about 750 degrees centigrade (1400
degrees Fahrenheit), and then gives up its heat to a steam cycle which
operates at a maximum temperature of about 550 degrees centigrade (1,000
degrees Fahrenheit) . As a result, the HTGR can be expected to produce
electric energy at an overall thermal efficiency of about 40%. One HTGR
is operating in the United States at this time, with another expected to
be operating in 1974. The HTGR should be responsible for a significant
portion of the total nuclear capacity by about 1985. The thermal
effects of its discharges should be similar to those of an equivalent
capacity of fossil-fueled plants. Its chemical wastes will be provided
with essentially similar treatment systems that are presently being
provided for BWR and PWR plants.
26
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The LMFBR will have a primary and secondary loop cooled with sodium, and
a tertiary power producing loop utilizing a conventional steam system.
Present estimates are that the LMFBR will operate at an overall thermal
efficiency of about 36%, although higher efficiencies are deemed to be
ultimately possible. The circulating water thermal discharges of the
LMFBR will initially be about halfway between those of the best fossil-
fueled plants and the current generation of nuclear plants. Chemical
wastes will be similar tc those of current nuclear plants.
Coal Gasification
The technology for producing from coal a low BTU gas suitable for
combustion in a utility powerplant has long been available. Thus far,
the economics of processing the coal at the mine and transporting gas to
the point of use have not been sufficiently favorable to lead to the
construction of large scale facilities based on this process.
The attractiveness of the concept lies in its potential for utilizing
the most abundant of the fossil fuels, coal, without the problems
usually associated with coal, sulfur and particulates in the stack gases
and ash and slag problems in the boiler. The drawbacks are that coal
gasification only returns 2 KW for each 3 KW of coal processed, large
capital investments are required, and the resulting cost per BTU is
high.
The Federal Government and a number of private organizations are
supporting research and development seeking to reduce the cost of coal
gasification. There are at least eight process alternates in various
stages of development with different by-products or energy requirements.
Best current estimates are that low BTU gas could be produced from coal
for about twice the average price currently (1973) paid by electric
utilities for natural gas. With an increasing shortage of natural gas
and fuel oil and increasing pressure on the utilities for
environmentally "clean" generation of electric energy, coal gasification
could well turn into a significant factor in the steam electric
powerplant industry.
Combined Cycles
One possible avenue toward greater overall thermal efficiency lies in
first utilizing the net gases generated by combustion of the fuel in a
combustion gas turbine and then passing the exhaust of the turbine
through a steam boiler. A small number of plants based on this concept
have been constructed. One problem lies in the fact that present-day
turbine technology requires a relatively clean gas or light oil (natural
gas or refined oil) fuel. Gas turbines are used primarily as peaking
units due to the shortage of natural gas supplies, its high cost per
unit of heating value, and the relatively high maintenance cost of the
equipment. Thermal efficiency is a primary consideration only for base
27
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loaded units and experience with gas turbines used as base- load units
is limited.
A major advantage cf the combustion gas turbine is the fact that it
requires no cooling water. Conversion of existing units or plants to
combined cycle offers, at least in theory, the potential for reducing
the thermal effects associated with a given production of electrical
energy. In practice, the modification of existing equipment is
generally likely to be technically difficult, if not impossible, and of
doubtful economic viability.
One form of combining cycles that holds special attraction is the
utilization of municipal refuse as a source of energy for the production
of steam and electrical power. Municipal refuse has an average heating
value of about 12,000 J/g (5000 BTU/lb). Many municipalities have been
forced to incineration of their refuse by the growing scarcity of
available and environmentally acceptable sites for landfill operations.
In European countries, higher fuel costs and lower wages have resulted
in economics favorable to the recovery of heat from the incineration of
refuse. In the United States, general practice has been to incinerate
refuse in refractory furnaces without attempt at heat recovery, although
several large municipal incinerators now generate steam.
Plant No. 2913 has teen converted to accept a mixture of 1C to 2Q%
shredded refuse and 80 to 90% powdered coal. The refuse has previously
been processed to remcve a portion of the ferrous metals. The operation
appears to be reasonably successful, although its economic justification
is more difficult to document. Refuse can never supply more than a
minor fraction of the energy requirements of a community and the
modifications to both the refuse disposal operations and the production
of electric energy are such that the economics must be carefully
evaluated in each individual case.
Future Generating Systems
Magnetohydrodynamics
Magnetohydrodynamic (MHD) power generation consists of passing a hot
ionized gas or liquid metal through a magnetic field to generate direct
current. The concept has been known for many years, although specific
research directed towards the development of viable systems for
generating significant quantities of electric energy has only been in
progress for the past ten years.
The promise of MHD lies in its potential for high overall system
efficiencies, particularly if applied as a "topping" unit in conjunction
with a conventional steam turbine. The exhaust from a MHD generator is
still at a sufficiently high temperature to be utilized in a waste heat
boiler. The combined MHD-steam cycle could result in overall system
28
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efficiencies of 50 to 60% and would require substantially less cooling
water than presently available systems.
The problems with MHD lie in the development of suitable materials that
can withstand temperatures in the 2200-2800°C (4000-5000°F) range. This
includes electrodes, channels, and auxiliary components. There are also
problems in the burning of commercial fuels containing various
impurities (such as sulfur-containing coal) and problems resulting from
the fixation of nitrogen and the lack of satisfactory methods to remove
nitrous oxides from the stack gases.
Although the Soviet Union and Japan are actively engaged in MHD research
and development, including the ccnstruction of a commercial size MHD
plant in Moscow, experimental generators in the United States have
produced only moderate outputs for short periods of time or small
outputs for periods of up to hundreds of hours. In spite of substantial
interest in and support of MHD research by the Office of Coal Research
of the U. S. Department of the Interior, and the Edison Electric
Institute, it does not seem likely that MHD will reach commercial
operations in the United States within the next ten years.
Electrogasdynamics
Electrogasdynamics (EGD) produces power by passing an electrically
charged gas through an electric field. The process converts the kinetic
energy of the moving gas to high voltage direct current electricity.
The promise of EGD is similar to the promise of MHD. Units would be
smaller, with a minimum of moving parts, would not be limited by thermal
cycle efficiencies and would not require cooling water. The system
could also be adapted to any source of fuel or energy including coal,
gas, oil or nuclear reactors.
Unfortunately, the problems of developing commercially practical units
are also similar to those associated with MHD. A pilot plant was
constructed in the United States in 1966, but tests on the pilot model
uncovered major technical problems and resulted in a termination of the
project. In view of these difficulties and the relatively small current
effort toward further work on this process, it seems unlikely that EGD
will have an impact on the national energy picture within the next
twenty years.
Fuel Cells
Fuel cells are electrochemical devices, similar to storage batteries, in
which the chemical energy of a fuel such as hydrogen is converted
continuously into low voltage electric current. Fuel cells presently
under development produce less that 2 volts per cell. In order to
create a usable potential, many cells have to be arranged in series and
many of these series arrangements must be paralleled in order to produce
29
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a significant current. Converters would be required to convert the
direct current produced by the cells into alternating current.
The main attractiveness of the fuel cell lies in its modular capability
and the possibility cf tailoring power output to the immediate needs.
Fuel can be stored and used when needed. Losses in transporting fuel
are also less that the corresponding losses incurred in transmitting
electricity. The efficiency of the direct conversion from chemical to
electric energy is high and the heat losses are minimal.
Main problem areas at the present time lie in developing low cost
materials of construction and low cost fuels. The most effective
electrodes presently available are platinum electrodes, which can be
used in military and space applications, but are not economically
competitive for commercial use. Presently used fuels include hydrogen,
hydrazine and methyl alcohol. The use of relatively low cost fuels such
as coal, natural gas or petroleum is not feasible at this time.
Unfortunately, the iranufacture of the usable fuels also involves the
utilization of significant quantities of electric and other energy, so
that the overall benefits are questionable.
A strong effort is teing made in the United States to develop the fuel
cell for residential and commercial service. A number of prototype
units have been installed.and are operating successfully. However the
fuel cell is not expected to replace a significant portion of the
central plant power generation within the next ten years.
Geothermal Generation
Geothermal generation utilizes natural steam or hot water trapped in the
earth's crust to produce electrical energy. At the present time,
geothermal generation is limited to areas of geothermal activity such as
fumaroles, geysers and hot springs. If steam is obtained directly from
the earth, it can be used to drive a turbine. Hot water must first be
flashed to steam or used to evaporate some other type of working fluid.
Advantages of this type of power generation are that the source of
energy is essentially free, although the costs of drilling are not
insignificant. Disadvantages are that the steam must first be cleaned
and that, at the current state of the art, this scheme is practical only
where there is geothermal activity near the surface of the earth. With
the advances being made in deep drilling for locating oil, it would seem
possible to tap energy sources almost anywhere on earth. However,
economic considerations appear to lead to the conclusion that geothermal
generation will be feasible only under specially favorable geologic
conditions.
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Industry Regulation
At the Federal level, numerous agencies have regulatory authority or
direct responsibility for certain aspects of the industry. These
include the Atomic Energy Commission (AEC), Department of Agriculture,
Department of the Interior, Federal Power Commission, the Department of
the Treasury, Securities and Exchange Commission, Tennessee Valley
Authority, Environmental Protection Agency and the Department of Labor.
The Federal Power Commission (FPC) is authorized to provide certain
types of economic regulation over certain investor-owned electric
utilities and administrative supervision over certain publicly-owned
systems. It licenses all non-Federal.hydroelectric projects, regulates
all interstate rates and services, and requires systems to keep a
specific system of accounts and submit reports on their activities. The
annual report FPC Form 67, Steam Electric Plant Air and Water Quality
Control Data, with responses from 654 plants, and the Summary Report for
the year ended December 31, 1969, formed one of the major sources of
data for this report. The 654 plants reporting represented steam
electric plants of 25 MW or greater capacity which were part of a power
supply system of 150 MW or greater and plants of 25 MW or greater
capacity operating in one of the Air Quality Control Regions.
The Atomic Energy Commission (AEC) has the responsibility for licensing
construction and operation of nuclear plants (stations). A utility
proposing to build a nuclear plant must first apply for a construction
permit. With this application the utility must file a Preliminary
Safety Analysis Report and an Environmental Impact Statement. After the
major design details have been completed, and while construction is
under way, the utility has to submit a Final Safety Analysis Report
which then becomes the basis for an operating license. In conformance
with a recent decision by the United States Court of Appeals, AEC
licensing procedures now include consideration of all environmental
factors, non-nuclear as well as nuclear, as required by the National
Environmental Policy Act (NEPA) of 1969.
At the state level, all states except Minnesota, Nebraska, Texas and
South Dakota have regulatory commissions with authority over investor
owned utilities. In less than half the states, the commissions also
have the power to regulate publicly-owned utilities. The degrees of
authority vary, but generally include territorial rights, quality of
service, safety, and rate-setting. The rate-setting power generally
requires a utility to demonstrate to the regulatory authority that a
proposed rate structure is necessary in order to permit the utility to
earn a return on its equity investment, also known as a rate base. The
rate base may be determined from historical cost or fair market value or
some other valuation formula, but in most cases, commissions in effect
assure the utility of a minimum return on capital invested in its
system.
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Construction Schedules
Construction schedules for nuclear plants and fossil-fueled plants are
significantly different in the total time span required from the concept
study stage to comirercial operation. For example, the condensed
construction schedule for a 200 MW oil-fired unit shown in Figure III-2
encompasses a span cf about three years from initiation of the concept
study to commercial operation. In contrast. Figure III-3 shows excerpts
from a typical LWR nuclear plant project schedule. The time span shown
from the initiation of the preliminary design until commercial operation
is about 8-9 years.
32
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Figure IH-2
CONDENSED CONSTRUCTION SCHEDULE, 200 MW OIL-FIRED UNIT* (Reference No. 187)
U>
U)
Years
Months
Concept Study Begun
Grading and Excavation
Piling
Substructure
Structural Steel
Superstructure
Gallery Work
Steam Generator
Steam Turbine-Generator
Condensing Equipment
Cooling Tower**
Equipment Erection
Flues, Ducts and Stack
Misc. Field Erection
Piping System
Thermal Insulation
Electrical
1972
JFMAMJJASOND
-
1973
JFMAMJJASONT
Initd
.__ Commerci
...
1974
JFMAMJJASOND
Boilout — ^
jal Steam
M
1975
JFMAMJ
»
fc
* Note: Base-load type unit with provisions for cycling duty. Major items of
equipment include one main transformer, one generator, one steam turbine,
one steam condenser, two condensate pumps, five closed feedwater heaters,
one deaerating heater, two boiler feedwater pumps, one steam generator,
one combustion burner group, and two combustion air fans and compressors.
** Note: Cooling tower is mechanical draft.
-------
Figure III-3
TYPICAL LWR NUCLEAR PLANT PROJECT SCHEDULE (HIGHLIGHTS ONLY)*
Task
Year
1 2
8
10
00
Site Selection and Acquisition
Environmental Studies
Prepare NSSS and Fuel Specifications
Vendor Bid Preparation
Bid Evaluation and Negotiation
Contract Awards
Preliminary Design
Detailed Design
Site Clearance and Excavation
Foundations and Buildings
Containment Erection
NSSS Equipment Installation
Turbine-Generator Erection
NSSS and T-G Auxiliary Equipment
Fuel Loading
Testing
Commercial Operation
* Note: Excerpts from Reference No. 186.
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SECTION IV
INDUSTRY CATEGORIZATION
Steam electric powerplants are characterized by many diverse aspects,
and at the same time by many similarities. Categorization of the
industry into discrete segments for the purpose of establishing effluent
limitations guidelines requires consideration of the various factors
causing both this diversity and similarity. Specific factors which
require detailed analysis in order to categorize the industry include
the processes employed, raw materials utilized, the number and size of
generating facilities, their age and location and their mode of
operation.
Process Considerations
There are five major unit processes involved in the generation of
electric power - the storage and handling of fuel related materials both
before and after usage, the production of high-pressure steam, the
expansion of the steam in a turbine which drives the generator, the
condensation of the steam leaving the turbine and its return to the
boiler, and the generation of electric energy from the rotating
mechanical energy. Figure IV-1 shows a schematic flow diagram of a
typical steam electric powerplant.
Fuel Storage and Handling
All fuels must be delivered to the plant site, stored until usage, and
the spent fuel materials stored on the premises or removed.
Fossil-fueled plants require off-loading facilities and fuel storage in
quantities based on the size of the plant and the limited reliability of
delivery. Fossil-fuels are transported to the furnace where combustion
takes place. The combustion of fossil fuels results in gaseous products
of combustion and non-gaseous non-combustible residues called ash. A
portion of the ash is carried along with the hot gases. This portion is
referred to as fly ash. The remainder of the ash settles to the bottom
of the furnace in the combustion zone and is called bottom ash. The
amount and characteristics of each type of ash is dependent on the fuel
and the type of boiler employed. Coal produces a relatively large
amount of bottom ash. Oil produces little bottom ash but substantial
fly ash. Gas produces little ash of any type.
Coal-fired steam generators can be categorized as wet or dry bottom
according to ash characteristics. Gas-fired and oil-fired steam
generators are generally run with dry bottoms. In one type of wet
bottom steam generator the coal is burned in such a manner as to form a
molten slag which is collected in the bottom and is tapped off similar
to the tapping of a blast furnace. In dry bottom steam generators.
35
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U)
VENT
A
>! f
SSCONDARY ! |4
SUPERHEATER1' '
SECTION
S5ES
ill1'
jLr|~
Wf
EHEAT
<;.«
i
|
t-
S-
R
Lj_i
1
=*y
•^i"
^
—
t^.
.-
— ~
^
*,
***
^^^
f -*\
-^
OILER
LOWDOWN
RUM \
i — r
i
\
\
j
•
FIGURE IV-I
SCHEMATIC FLOW DIAGRAM
BOILER FEED
PUMP
CONDENSATE
PUMP
TYPICAL STEAM ELECTRIC GENERATING PLANT
-------
where ash is removed hydraulically, it is customary to pump the ash
slurry to a pond or settling tank, where the water and ash are
separated.
Many modern powerplants remove fly ash from the gaseous products of
combustion by means of electrostatic precipitators, although scrubbers
may be required in the future on plants burning fossil fuels containing
more than a minimal amount of sulfur. The removal of fly ash collected
in an electrostatic precipitator depends on the method of ultimate
disposal. If the fly ash is to be used in the manufacture of cement or
bricks or otherwise used commercially, it is generally collected dry and
handled with an air conveyor. If it is to be disposed of in an ash pond
or settling basin, it is sluiced out hydraulically.
Many of the operations involving fossil-fuels are potential sources of
water pollutants. The storage and handling of nuclear fuels in
comparison is not a continuous operation, requires little space, is
highly sophisticated from the standpoint of engineering precision and
attention to details, and is not considered to be a potential source of
nonradiation water pollutants.
Steam Production
The production of high-pressure steam from water involves the combustion
of fuel with air and the transfer of the heat of combustion from the hot
gases produced by the combustion to the water and steam by radiation and
convection. In order to obtain the highest thermal efficiency, as much
of the heat of combustion as possible must be transferred from the gases
to the steam and the gases discharged at the lowest possible
temperature. This requires the transfer to be accomplished in a series
of steps, each designed for optimum efficiency of the overall process.
Not every boiler provides each of the steps outlined in this section,
but most of the boilers supplying steam to larger and newer generating
units (over 200 MW and built in the last twenty years) provide these
steps as a minimum.
Feedwater is introduced into the boiler by the boiler feed pump and
first enters a series of tubes (regenerative feedwater heater) near the
point where the gases exit from the boiler. There it is heated to near
the boiling point. The water then flows to one or more drums connected
by a number of tubes. The tubes are arranged in vertical rows along the
walls of the combustion zone of the boiler. In this zone, the water in
the tubes is vaporized to saturated steam primarily by the radiant heat
of combustion. The saturated steam is then further heated to higher
temperatures primarily by convection of the hot gases in the superheater
section of the boiler. In some boilers, the steam is reheated after
passage through the initial sections of the turbine. Finally, the flue
gases are passed through a heat exchanger (air heater) in order to
transfer heat at a low temperature to the air being blown into the
boiler.
37
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As far as steam production is concerned, the efficiencies possible from
the conversion of the chemical energy of the fuel to electric energy
depend on the maximum steam temperatures and pressures and on the extent
of the utilization of regeneration feedwater heaters, reheat and air
heating. For a simple cycle using saturated steam with a maximum
pressure of 6.3 MN/m2 (900 psi) expanded in the turbine to atmospheric
pressure and using exhaust steam to heat the feedwater, the total cycle
efficiency would be atout 20%. If the saturated steam is superheated to
530°C (1,000°F), the efficiency is increased by an increment of 5 to 6%.
The addition of a high-vacuum 863 Kg/m2 (2-1/2 in Hg abs) condenser and
the addition of feedwater heating will increase possible efficiencies by
an increment of 12 - 13% to about 38%. By increasing the maximum
pressure still further and reheating the steam, the efficiency can be
increased to about 4558. These are turbine cycle efficiencies and do not
reflect various losses in the boiler and auxiliary power requirements.
Indications are that these efficiencies represent the limit obtainable
from the processes presently in use. Higher efficiencies would require
higher steam pressures and temperatures would present material problems
that do not seem to be near solution. The alternate of lower terminal
temperatures is not possible since the waste heat must be rejected to
the environment under ambient conditions.
In the effort to improve the efficiency of the steam cycle, designers
have attempted to resort to higher temperatures and pressures. Maximum
turbine operating pressures increased from about 1,000 psi in the early
1930's to 5000 psi in the early 1960»s. Since then, turbine design
pressures for new units have receded slightly to a maximum of 3500 psi.
Similarly, maximum operating temperatures increased from 800°F to 1200°F
for a brief period and then receded to a maximum of 1050°F, as designers
looked to more sophisticated reheat cycles and turbine designs to
optimize plant performance.
Nuclear generators presently in operation fall into two classes,
pressurized water reactors (PWR) and boiling water reactors (BWR). In a
PWR, water under a pressure of about 14 MN/m2 (2,000 psig) is heated as
it circulates past the nuclear fuel rods in a closed loop. This hot
water then exchanges heat with a secondary water system which is allowed
to vaporize to steam. In the BWR, water heated in the reactor core
under a pressure of about 7 MN/m2 (1,000 psig) is allowed to vaporize to
steam directly. Neither of these processes produce steam with
significant amounts of superheat and this limits their thermal cycle
efficiencies to about 30%.
The size or rating of boilers is in terms of thousands of pounds of
steam supplied per hour. According to the FPC the increase in boiler
capacity was rather slow until 1955, when the maximum capacity of
boilers installed began to rise from a level of about 1,500 thousand
pounds per hour to the present level of about 10,000 thousand pounds per
hour. Prior to 1950, individual boilers were kept small, in large part
because boiler outages were rather numerous, so that it was common
38
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design practice to provide multiple boilers and steam header systems to
supply a turbine-generator. Some plants report to the FPC that the
steam headers are connected to multiple turbine-generators. Advances in
metal technology since 1950r with associated lower costs of larger
units, have made it economical and reliable to have one boiler per
turbine-generator.
Steam Expansion
The conversion of the pressure energy of the steam into mechanical
energy occurs in the steam turbine. In the turbine the steam flows
through a succession of . passages made up of blades mounted on
alternately moving and plantary discs. Each set of moving and plantary
discs is called a stage. The moving discs are mounted on a rotating
shaft while the plantary discs are attached to the turbine casing. As
the steam passes from disc to disc, it gives up its energy to the
rotating blades and in the process loses pressure and increases in
volume. If the steam enters the turbine in a saturated condition, a
small portion of the steam will condense as it passes through the
turbine. One reason for superheating or reheating steam is to reduce
this condensation and the mechanical problems associated with it.
There are many different types of turbines and turbine arrangements in
use in steam electric powerplants. Almost all turbines in use in
central generating plants are of the condensing type, discharging the
steam from the last stage at below atmospheric pressure. The efficiency
of the turbine is highly sensitive to the exhaust pressure
(backpressure). A turbine designed optimally for one level of
backpressure will not operate as efficiently at the other levels of
backpressure. Some turbines designed for 863 Kg/in2 (2-1/2 in Hg abs)
backpressure cannot operate at 1730 Kg/in2 (5 in Hg abs) because of high
temperature in the last stages. In general, turbines designed for once-
through cooling systems will generally be operated at lower
backpressures than those designed for closed cooling systems. Moreover,
if a turbine designed for the low backpressures corresponding to once-
through cooling system is operated instead with a closed cooling system,
an incremental decrease in turbine efficiency will result during times
when the back pressure is higher than it would have been for
once-through cooling.
In most turbine arrangements a portion of the steam leaves the casing
before the final stage. This type of turbine is called an extraction
turbine. The extracted steam is used for feedwater heating purposes.
In some turbines, a portion of the steam is extracted, reheated in the
boiler, and returned tc the turbine or to another turbine as a means of
improving overall efficiency. Many different mechanical arrangements of
high pressure and low pressure turbines on one or more shafts are
possible, and have been utilized.
39
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While there are no major effluents associated with the steam expansion
phase other than those resulting from housekeeping operations, the
significance of the steam expansion lies in its effect on plant
efficiency and therefore on the thermal discharge. In many plants,
turbine design will fce a key factor determining the extent of the
feasibility of converting a once-through cooling system to a closed
system.
Steam Condensation
Steam electric powerplants use a condenser to maintain a low turbine
exhaust pressure by condensing the steam leaving the turbine at a
temperature corresponding to vacuum conditions, thus providing a high
cycle efficiency and recovering the condensate for return to the cycle.
Alternatively, the spent steam could be exhausted directly to the
atmosphere thus avoiding the requirement for condensers or condenser
cooling water, but with poor cycle efficiency and a requirement for
large quantities of high purity water. There are two basic types of
condensers, surface and direct contact. Nearly all powerplants use
surface condensers of the shell and tube heat exchanger type. The
condenser consists of a shell with a chamber at each end, connected by
banks of tubes. If all of the water flows through the condenser tubes
in one direction, it is called a single-pass condenser. If the water
passes through one half of the tubes in one direction and the other half
in the opposite direction, it is called a two-pass condenser. Steam
passed into the shell condenses on the outer surface of the cooled
tubes.
A single-pass condenser tends to require a larger water supply than a
two-pass condenser and will generally result in a lower temperature rise
in the cooling water. In most instances it will also produce a lower
turbine backpressure. A two-pass condenser is utilized where the
cooling water supply is limited or in a closed system where it is
desired to reduce the size of the cooling device, and improve its
efficiency by raising the temperatures of operation.
Many condensers at the more-recently built powerplants have divided
water boxes so that half the condenser can be taken out of service for
cleaning while the unit is kept running under reduced loads. Since
cleanliness of the condenser is essential to maintaining maximum heat
transfer efficiency, it is common practice to add some type of biocide
to the cooling water to control the growth of algae or slimes in the
condenser. In spite cf these biocides most powerplants clean condensers
mechanically as part cf regularly scheduled maintenance procedures.
Operation of the condenser requires large quantities of cooling water.
Wherever adequate supplies of cooling water are available, it has been
common practice to take cooling water from a natural source, pump it
through the condenser, and discharge it to the same body of water from
which it was obtained. This is known as a "once-thro ugh11 system. One
40
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of the major considerations in siting powerplants is the availability of
an adequate source of high-quality once-through cooling water. If
sufficient water for a once-through system is not available and other
considerations prevail in determining the location of the plant, cooling
water must be recirculated within the plant. In this case some form of
cooling device, an artificial pond with or without sprays, or a cooling
tower must be provided to keep the temperature from rising above the
maximum level permissible or desirable for turbine operation. Figure
IV-2 shows a schematic flow diagram of a typical recirculating (closed)
system utilizing cooling towers. For reasons of economy closed systems
typically operate at higher temperature differentials across the
condenser than once-through systems, balancing the somewhat reduced
efficiency of the turbine against the lower quantity of cooling water
required, and therefore the smaller size and lower cost of the cooling
device. However, since nearly all cooling devices currently in use
obtain their cooling effect from evaporation, the dissolved solids
concentration of closed cooling systems tends to increase, eventually
reaching, if uncontrolled, a point where scaling of the condenser would
interfere with heat transfer. A portion of the concentrated circulating
water must therefore be discharged continually as blowdown to remove
dissolved solids, and purer fresh water must be provided to make up for
losses due to evaporation, blowdown, liquid carryover (drift), and
leaks.
Flow rates of cooling water vary with the type of plant, its heat rate
and the temperature rise across the condenser. A fossil plant with a
heat rate of 10,000 KJ/KWH (9,500 BTU per KWH) and a 6.7°C (12°F) rise
across the condenser (values typical of exemplary plants in the industry
using once-through coding systems) will require about 0.5 x 10~*
m3/sec. (0.8 gpm) of cooling water for every KW of generating capacity.
A nuclear plant with a heat rate of 11,100 KJ/KWH (10,500 BTU per KWH)
and a 11°C (20°F) rise across the condenser, (typical of plants using
closed cooling systems) will require about 0.46 x 10~* m3/sec. (0.73
gpm) . Because of differences in thermal efficiencies, nuclear plants
under identical conditions require about 50% more cooling capacity than
comparible fossil plants.
While both once-through and closed cooling systems are currently in use
in the industry, the use of closed systems has generally been dictated
by lack of sufficient water supplies to operate a once-through system
and not generally by considerations of the thermal effects of the
cooling water discharge. A few plants have installed cooling devices on
their effluents to meet receiving water quality standards and a few
others have installed or are planning to install cooling devices or to
convert to closed systems in order to meet receiving water temperature
requirements.
41
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,
Los*
SCHEMATIC COOLING WATER CIRCUIT
FIGURE IV- 2
42
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Generating of Electricity
The actual generation of electric energy is accomplished in a generator,
usually directly connected to the turbine. The generator consists of a
rotating element called a rotor revolving in a plantary frame called a
stator. The process converts mechanical energy into electric energy at
almost 100X of theoretical efficiency and therefore produces little
waste heat.
Raw Materials
General aspects of the four basic fuels in use in the industry have been
discussed in the previous section. In this section some of the
characteristics of each of the fuels will be discussed as they affect
the process and the waste effluents produced.
Coal
Coals are ranked according to their geological age which determines
their fuel value and ether characteristics. The oldest coals are the
anthracites, which contain in excess of 92% fixed carbon. Most
anthracite lies in a limited region of eastern Pennsylvania and is not a
major factor in the nationwide generation of electric energy. Most of
the power is produced from bituminous coal (the next lower rank) which
contains between 50 and 92% fixed carbon and varies in fuel value
between 19,300 and 32,600 J/g (8,300 and 14,000 BTU per Ib). A
substantial amount of power is also produced from lignite containing
less than SOX carbon and having an average heating value of 15,600 J/g
(6,700 BTU per Ib).
Three major characteristics of coal that affect its use in powerplants
are the percentages of volatile combustible matter, sulfur and ash. The
sulfur content of coal is particularly critical since air pollution
limitations restrict the emission of sulfur dioxide. The sulfur content
of U. S. coals varies from 0.2 to 7.0 percent by weight. Most of the
low sulfur coal deposits are located west of the Mississippi River. In
the East, a large portion of the low sulfur coal has been dedicated to
metallurgical and expert uses.
The ash content of coal varies from 5 to 20J& by weight. Ash can create
problems of air pollution, slagging, abrasion and generally reduced
efficiency. One problem of substituting low sulfur coal for coal with a
higher sulfur content is that low sulfur coals tend to have higher ash
fusion temperatures, which may cause problems in boiler operation. The
•fly ash produced by low sulfur coal tends to have higher electrical
resistivity which reduces the efficiency of electrostatic precipitators.
Several other aspects of coal as a fuel for steam electric powerplants
should be noted. The first is the increased popularity of mine-mouth
plants, that is plants built for the purpose of using coal from a
specific mine and located in the immediate vicinity of that mine. Much
of the current construction of coal-fired units consists of mine-mouth
43
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plants. These plants in effect trade off the cost of transporting coal
against the cost of transmitting the electrical energy generated. Their
major advantages are that in most cases that they are not located in or
near urban centers and therefore do not arouse public opposition or have
the same type of environmental impact as plants located within those
centers. Most mine-mouth plants are base-load operated and many use
cooling towers because of the absence of adequate cooling water
supplies. They compete favorably on a unit cost basis with nuclear
plants and in many instances can be constructed with a substantially
shorter lead time.
A second aspect consists of the potential impact on the industry of the
successful development of a commercial-scale coal gasification process.
A number of processes are currently under development. The potential of
coal gasification lies in its ability to produce a storable product that
can be transported economically by pipeline and can be burned without
ash or sulfur problems. At the present, the estimated cost of synthetic
gas is still substantially higher than the cost of alternate fuels, but
upward pressures on natural gas and residual oil prices may make coal
gasification economically attractive.
Natural Gas
The use of natural gas as a fuel for generating electricity is a fairly
recent development, dating back to about 1930. In 1970 0.1 trillion m3
(3.9 trillion cu ft) cf natural gas were burned to generate electricity,
placing natural gas second among the fossil fuels and accounting for
almost 30% of the energy generated from fossil fuels.
The original attractions of natural gas were its availability and its
economics. For a long time natural gas was considered almost a by-
product. At the same time, its use in utility powerplants resulted in
simpler and less costly fuel handling, burning facilities and a marked
reduction in ash handling and air pollution problems. However, the
availability of natural gas has declined sharply in the last few years,
and utilities are finding it increasingly difficult to conclude long-
term agreements for natural gas supplied for central generating plants.
The future availability of natural gas is uncertain. Present reserves
of natural gas amount to an estimated twelve times our current annual
production, and the annual discovery of new sources is less than the
current rate of consumption.
Estimates by the FPC project a fairly stable level of natural gas
consumption by the electric utility industry over the next twenty years.
However, in view of the projected growth of the industry as a whole, the
share of the total electricity generated is expected to decrease to 835
by 1990. This trend could be affected by several technological develop-
ments. One of these is the successful commercial application of coal
gasification. Another is an AEC program to increase the yield of
natural gas from underground formations by the underground explosion of
44
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nuclear devices. In the meantime, some existing plants using natural
gas as a fuel were being converted to oil in spite of the advantages of
natural gas in the ash and air pollution areas.
Fuel Oil
Fuel cil is presently the third most significant source of fossil fuel
for generating electricity, accounting for 15% of the total generation
in 1970. However, in the New England- Middle Atlantic area it accounted
for 82% of the theriral generation, primarily as a result of the
conversion of coal-burning plants to residual fuel oil in order to meet
air pollution standards.
Three types of fuel oil are used in utility powerplants: crude oil,
distillate oil, and residual oil. A key problem with the use of fuel
oil, as with the use cf coal, is the sulfur content. At the present
time, powerplants in the Northeast are burning oil containing less than
1% sulfur by weight. Domestic supplies of low sulfur crudes are quite
limited and will not be improved significantly when Alaskan oil is
available in the contiguous United States. As a result, utilities have
been highly dependent on foreign sources of supply. Major foreign
sources include Venezuela, and the Middle East. Venezuelan sources must
be, and are, desulfurized at the source, while Middle Eastern crudes are
low in sulfur in their original state.
With the future availability of petroleum products of all types in
question, it appears doubtful that the recent trend toward increased
burning of oil in powerplants will continue in the future. FPC
projections (1970) indicated a slight increase in the percentage share
of oil compared to total use of fossil fuels over the next five years,
with a leveling off thereafter. The price of fuel oil, which had
remained fairly constant during the early 1960's has increased in recent
years, and will possibly increase further in the future.
A possible technological development which might affect the supply of
fuel oil is the extraction of oil from oil shales. Certain areas of
Colorado, Utah and Wyoming contain large reserves of oil shale, with
unfavorable economics being the major obstruction to the development of
an oil shale industry. If crude oil prices continue to escalate and oil
supplies continue to dwindle, the development of this source may become
economically viable.
Fuel oil use in powerplants minimizes bottom ash problems, although fly
ash can continue to be troublesome. Some fuel oils also contain
vanadium and may contain other unusual components which may or may not
wind up in a powerplant effluent.
45
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Refuse
Emphasis on recycling waste products has increased interest in use of
another fuel - solid waste. Refuse and garbage are not confined to
kitchen wastes, but include a mixture of all household wastes with
commercial and industrial wastes. Large-scale inorganic industrial
wastes are generally not included. The average American domestic refuse
has many combustibles which raise its heating value to approximately 40%
of that of coal. Incineration coupled with steam generation has been
practiced for a considerable period in Europe, where household garbage
as collected is mixed, especially during the winter months, with the
ashes of household coal furnaces. Garbage is generally shredded and
most non-combustibles are removed by magnetic and centrifugal separators
before firing to the furnace. However, furnaces must still be designed
for non-combustible loadings. Garbage is essentially sulfur- free but
can generate moderate quantities of hydrogen chloride from the
combustion of polyvinyl chloride and other chlorinated polymers.
Because of the presence of these materials, studies must be made of the
removal of acid gases from the furnace stack gases, and the disposal of
the effluents resulting from these operations.
At the present time there is one powerplant in the United States that
burns refuse as part of its fuel. The plant has the capability of using
as much as 20% refuse with at least 80% coal, although operation to date
has been limited to 10% refuse and 90% coal. Refuse is not expected to
be a major source of fuel for the steam electric powerplant industry in
the immediate future.
Information on U.S. Generating Facilities
An inventory of operating steam electric powerplants in the United
States is presented in Appendix A of this report. The list has been
divided into ten sections to conform to the ten EPA regions of the
country. The inventory shows the operating utilities by states, plants,
and their specific geographic location. It also shows the total plant
capacity in megawatts, with an indication of whether the plant is
nuclear or fossil-fueled, and a designation of plants that are under
construction. Gas combustion turbine facilities operating within
fossil-fueled generating plants have been indicated on a separate line.
The inventory shows a total of 1037 operating generating plants in the
United States as of January 1, 1972, consisting of 1011 fossil-fired
plants and 26 nuclear plants. A total of 59 plants were under
construction as of the date indicated, of this total, 42 are nuclear
plants and 17 are fossil-fueled plants. Table IV-1 provides a summary
of the industry inventory by EPA region and individual states.
Figures IV-3 through IV-5 provide a cumulative frequency distribution
plot of plant size within the steam electric powerplant industry. It
can be seen from Figure IV-3 that approximately 50 percent of the plants
in the industry are 100 MW or larger, and that 25 percent of all plants
are larger than 400 MW. Figure IV-4 shows that the size distribution of
46
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TABLE IV-1
INDUSTRY INVENTORY SUMMARY
— PLANTS UNDER
OPERATING PLANTS CONSTRUCTION
STATE TOTAL FOSSIL NUCLEAR FOSSIL NUCLEAR
EPA Region 1
Connecticut 16 13 3 00
New Hampshire 550 00
Rhode Island 550 00
Vermont 431 00
Maine 660 01
Massachusetts 29 28 1 01
EPA Region 2
New Jersey 18 17 1 01
New York 39 36 3 12
Puerto Rico 440 00
Virgin Islands 220 00
EPA Region 3
Delaware550 00
Maryland 14 14 0 01
Pennsylvania 48 45 3 0 2
Virginia 15 15 0 02
West Virginia 12 12 0 10
District of Columbia 220 00
EPA Region 4
Alabama 10 10 0 03
Florida 43 43 0 04
Georgia 13 13 0 31
Kentucky 19 19 0 20
Mississippi 990 00
North Carolina 12 12 0 12
South Carolina 16 15 1 11
Tennessee 770 11
EPA Region 5
Illinois45 43 2 13
Indiana 29 29 0 10
Michigan 40 38 2 24
Minnesota 48 45 3 01
Ohio 54 54 0 03
Wisconsin 33 31 2 01
EPA Region 6
Arkansas10 10 0 01
Louisiana 27 27 0 11
New Mexico 16 16 0 00
Texas 91 91 0 10
Oklahoma 19 19 0 00
EPA Region 7
Iowa 37 37 0 01
Kansas 32 32 0 00
Missouri 31 31 0 00
Nebraska 15 15 0 02
EPA Region 8
Colorado 23 23 0 0 1
Montana 880 00
North Dakota 990 00
South Dakota 981 00
Utah 660 00
Wyoming 880 00
EPA Region 9
Arizona 12 12 0 10
California 39 37 2 02
Hawaii 770 00
Nevada 660 00
EPA Region 10
Alaska 14 13 1 00
Idaho 110 00
Oregon 660 00
Washington 990 00
TOTAL 1037 1011 26 17 42
47
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CUMULRTIVE FREQUENCY DISTRIBUTION OF
ENTIRE POWER PLflNT INVENTORY
FOR flLL EPfl REGIONS
o
o
°0.00
>Q
PERCENT OF
25.00
PLflNTS
37.50
EQURL
50.00
TO OR
62.50 75?00 87.50
LRRGER THRN STflTED SIZE
100.0
FIGURE IV-3
48
-------
O
O-
3-
o
o
o
CD.
to
CUMULRTIVE FREQUENCY DISTRIBUTION OF
FOSSIL-STEflM POWER PLRNTS
FOR flLL EPR REGIONS
o
o
o
C\J_
co
0 12.50
PERCENT OF
25.00
PLflNTS
•37.50
Eouni
50.00 62.50 75.00 87.50
I OR LflRGER THflN STRTED SIZE
100.oc
FIGURE IV-4
49
-------
TT
o
o
o.
ir
O
O
o
U2.
on
o
O
O
CO.
co
o
o
Oo
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2°
^0
' ' o
(\J
LU
COO
CUMULRTIVE FREQUENCY DISTRIBUTION QF
NUCLEflR-STEflM POWER PLflNTS
FOR PLL EPR REGIONS
°0.00 12.50 25.00 37.50
PERCENT OF PLflNTS EQUflL
50.00 62.50 75.00 87.50
TO OR LflRGER THflN STflTED SIZE
100.oc
FIGURE IV-5
50
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fossil-fueled plants roughly corresponds to the industry profile.
However, Figure IV-5 illustrates the large size of nuclear plants,
showing that 50 percent of these plants are larger than 800 MW, and that
25 percent are larger than 1500 MW.
The Federal Power Commission Form 67, "Steam-Electric Plant Air and
Water Quality Control Data for the Year Ended December 31, 1969"
provides data on the capacity utilization, age, etc., of generating
units. This form nrust be filed annually by plants with a generating
capacity of 25 MW or greater, provided the plant is part of a system
with a total capacity of 150 MW or more.
Size of Units
According to the Federal Power Commission (FPC) 1970 National Power
Survey, in 1930, the largest steam-electric unit in the United states
was about 200 megawatts, and the average size of all units was 20
megawatts. Over 95 percent of all -units in operation at that time had
capacities of 50 megawatts or less; By 1955, when the swing to larger
units began to be significant, the largest unit size had increased to
about 300 megawatts, and the average size had increased to 35 megawatts,
(see Figure IV-6). There were then 31 units of 200 megawatts or larger.
By 1968, the largest unit in operation was 1,000 megawatts; there were
65 units in the 400 to 1,000 megawatt range; and the average size for
all operating units had increased to 66 megawatts. In 1970, the largest
unit in service was 1,150 megawatts; three 1,300-megawatt units were
under construction; and three additional 1,300-megawatt units were on
order. The average size of all units under construction was about 450
megawatts. As the smaller and older units are retired, the average size
of units is. expected to increase to about 160 megawatts by 1980 and 370
megawatts by 1990.
Age of Facilities
In the steam electric powerplant industry, age of generating facilities
must be discussed on the basis of units rather than on a plant basis.
Generally, the units comprising a generating plant have been installed
at different times over a period of years, so that the age of equipment
within a given plant is likely to be distributed over .a range of years.
In addition, age may play a peculiar role in assigning a unit to a
particular type of operation as outlined below.
In general, the thermal efficiency of newly designed power generation
plants has increased as operating experience and design technology have
progressed. Early plants generated saturated steam at low pressures and
consumed large quantities of fuel to produce a unit of electrical
energy. One electrical kilowatt hour of energy is equivalent to 860 K
cals (3,413 BTU) of heat energy. Steam pressures and temperatures
increased from about 1.17 MN/mz (170 psig) at the turn of the century to
1.72 - 1.90 MN/m2 (250> - 275 psig) and 293°C (560°F) by World War I, and
51
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Figure IV- 6
LARGEST FOSSIL-FUELED STEAM-ELECTRIC
TURBINE-GENERATORS IN SERVICE
1900 - 199*0
2500 r
2000
292
oo
1500
1000
500
I
1900
1930
YEAR
1960
1990
52
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to 3.10 - 4.48 MN/m« (450-640 psig) and 370-400°C (700-750°F) by 1924.
278 In 1924 and 1925 there was a surge to 8.27 MN/m2 (1,200 psig) and
370°C (700°F) and it has steadily increased since then, until by 1953
pressures had reached the critical pressure of steam (22.11 MN/m2 (3,206
psia) and temperatures of 540-565°C (1,000-1,050°F) . 278 Above the
critical pressure the liquid and vapor phases are indistinguishable and
there is no need for a steam drum (separator). The economic jus-
tification of the supercritical cycle has resulted in a limited number
of this type of unit to date.
These changes have had the effect of reducing the amount of fuel
required to gen-erate a kilowatt hour, as shown in Figure IV-*7, taken
from Reference No. 292. In 1900 it required 2.72 Kg (6 pounds) of coal,
(4i,700 K cals (75,000 BTU) to generate one KWH. Today a supercritical,
double-reheat unit of Plant no. 3927 has established an annual heat rate
of 2197 K cals/KWH (8,717 BTU/KWH). 28° This amounts to 0.318 Kg
(seven-tenths of a pound) of coal per KWH. The heat economies of the
newer facilities generally make it desirable to keep them in full-time
base-load operation. The older units with their"higher fuel consumption
are therefore generally relegated to cycling or peaking service. In
spite of this general trend, there are indications that heat rates have
been increasing since 1972 as a result of pressures to reduce capital
cost in relation tc fuel prices, and increasing use of air and water
pollution control equipment which tend to reduce generating efficiency.
A computer plot of heat rate in BTU/KWH vs unit capacity in megawatts (x
10) is shown in Figure IV-8. The plot is a print-out of data obtained
from FPC Form 67 for the year 1969. In the plot, data obtained from
newer plants (under 10 years old) are represented by squares, those 10-
20 years old by triangles, and those over 20 years by X's. Similarly,
Figure IV-9 is a printout of the same information replotted with BTU/KWH
as the ordinate and unit age as the abscissa. The data from both plots
represent over 1,000 operating units, and are not conclusive, but do
show general trends. The newer plants, of larger size, generally are
more efficient. Thus the data illustrates the improvement in efficiency
achieved as the industry has progressed to newer and larger generating
facilities.
Site Characteristics
Engineering criteria require an adequate supply of cooling water,
adequacy of fuel supply, fuel delivery and handling facilities, and
proximity of load centers. These have always been important factors in
the selection of powerplant sites. 2»2 Traditionally, plants have been
located in or near population centers to reduce transmission costs and
satisfy the other key site factors mentioned. Table IV-2 shows a total
of 153 plants located in the 50 largest cities of the country. This
total represents approximately 15 percent of all plants in the industry,
and does not include suburban plants near the cities in question, or
urban plants in smaller population centers. Clearly, a significant
53
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30,000
25,000
20,000
\
h
UJ
LJ
CL
D
CO
15,000
10,000
5,000
\
Y
MATIONAL AVE'RAGE
BEST
PLANT
0
1920 1930 1940 1950 I960 1970 I960 1990
HEAT RATES OF FOSSIL-FUELED
STEAM ELECTRIC PLANTS
FIGURE IV- 7
292
54
-------
o
o
LEGEND
m UNITS UNDER 10 YEflRS OLD
A 10 TO 20 YEflRS OLD
X OVER 20 YEflRS OLD
).00
20.00
40.00 60.00 80.00
UNIT CflPflCITY (MW)
100.00
120.00
HlO1
140.00
160.00
HEHT RRTE VS UNIT CRPfiCITY
Figure IV-8
55
-------
o
o
d
0_,
CO
LEGEND
CD UNITS UNDER 100 MW
A 100 TO 300 MW
X OVER 300 MW
o
o
o
00^
CM
o
o
o
CM"
o
o
o
CM"
o
CM
CM
O
O
O
O
CM
CC
a
a
CD
— CD
cr —
CC
a
a
a
a
an
a i
a
a
o
o
o
CM
O
O
O
x a
x
xax
an
Q „ m
"t.OO 5.00 10.00 15.00 20.00 25.00 30.00 35.00 40.00
UNIT RGE IN TERRS
HERT RRTE VS. UNIT RGE
Figure IV-9
56
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TABLE IV-2
URBAN STEAM.ELECTRIC POWER PLANTS
HO.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
CITY
.New York
Chicago
Los Angeles
Philadelphia
Detroit
Houston
Baltimore
Dallas
Washington
Cleveland
Indianapolis
Milwaukee
San Francisco
San Diego
San Antonio
Boston
Memphis
St. Louis
New Orleans
Phoenix
Columbus
Seattle
Jacksonville
Pittsburgh
Denver
Kansas City
Atlanta
Buffalo
Cincinnati
San Jose
Minneapolis
Fort Worth
Toledo
Newark
Portland
Oklahoma City
Louisville
Oakland
Long Beach
Omaha
Miami
Tulsa
Honolulu
El Paso
St. Paul
Norfolk
Birmingham
Rochester
Tampa
Wichita
STATE
New York
Illinois
California
Pennsylvania
Michigan
Texas
Maryland
Texas
D.C.
Ohio
Indiana
Wisconsin
California
California
Texas
Mas s achus ett s
Tennessee
Missouri
Louisiana
Arizona
Ohio
Washington
Florida
Pennsylvania
Colorado
Missouri
Georgia
New York
Ohio
California
Minnesota
Texas
Ohio
New Jersey
Oregon
Oklahoma
Kentucky
California
California
Nebraska
Florida
Oklahoma
Hawaii
Texas
Minnesota
Virginia
Alabama
New York
Florida
Kansas
POPULATION
7,894,862
3,369,359
2,809,596
1,950,098
1,513,601
1,232,802
905,759
844,401
756,510
750,879
744,743
717,372
715,674
697,027
654,153
641,071
623,530
622,236
593,471
581,562
540,025
530,831
528,865
520,117
514,678
507,330
497.421
462,768
452,524
445,779
434,400
393,476
383,818
382,288
380,555
368,856
361,958
361,561
358,633
346,929
334,859
330,350
324,871
322,261
309,828
307,951
300,910
296,233
277,767
276,554
NUMBER OF
PLANTS
12
4
4
4
6
7
6
6
2
3
3
3
2
3
7
2
1
3
4
1
3
2
3
5
3
3
1
1
2
0
2
3
2
1
2
2
4
1
2
4
1
1
1
2
2
3
2
3
4
4
Total 152
57
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number of existing plants in the steam electric generating industry are
situated in locations which interface with a reasonable percentage of
the country's population.
The trend in recent years toward larger units, combined with the advent
of commercial nuclear power generation and the institution of mine-mouth
coal-fired plants has resulted in a greater number of plants being
constructed in rural areas. Site selection for new generating
facilities is not only governed by the factors cited, but increasingly
by environmental considerations. The prevention and control of air and
water pollution is undoubtedly as important as many of the traditional
factors involved in the selection of new plant sites. Factors generally
considered in decisions on plant location include land requirements,
water supply, fuel supply and delivery, etc.
Land requirements are quite variable. For plants situated near
population centers, land cost is a prime consideration. The largest
consumers of land are the fuel storage area, ash disposal area and water
cooling ponds, lakes etc. if utilized. Since they are public utilities,
power generating plants must have sufficient fuel storage capacity to
allow uninterrupted operation for the duration of a major transportation
strike. This means that unless the plant is very near its source of
supply, it must have a storage capability up to approximately three
month's fuel. Even mine-mouth plants must have fuel storage to allow
them to withstand a miners' strike.
Most steam plants require water for two main purposes - boiler feed
water make-up and steam condensation. The cost of preparation of the
high purity boiler feed water required by modern boilers is a function
of the purity of the source water. It is possible to use saline water
for cooling purposes, but it cannot be used in a boiler. Preparation of
boiler feed from saline water by evaporation or reverse osmosis is
generally quite expensive. The availability of large quantities of
cooling water has traditionally affected the decisions made regarding
plant location. In areas where water is critically short, recirculation
of cooling water using cooling towers or ponds has been widely
practiced. This subject is discussed in detail in subsequent sections
of this report.
Plant location may also be influenced by energy transportation costs.
The cost of transmission of energy as electricity must be weighed
against the cost of transporting fuel. Generally, fuel availability and
economic factors will be the major considerations regarding the
relationship between fuel and plant siting.
Air Pollution Control
The methods used to control atmospheric pollution by stack gases vary.
With plants burning solid fuel, a particulate emission problem may
exist. The usual control system is the electrostatic precipitator.
58
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Finely divided solid particles suspended in a gas stream will accept an
electrostatic charge when they pass through an electrical field. If
they are then passed between two oppositely charged plates, they are
attracted to one of the plates, depending on the polarity of the
charges. On the plates they agglomerate and may be removed by rapping
the plates. This operation is usually carried out at temperatures
between 121° and 177°C (250-350°F). Finely divided solids may also be
removed from the vent gases by using bag filters or by intimately
contacting them with water in a venturi scrubber or similiar device.
Sulfur dioxide in stack gases can present another air pollution problem.
This, of course, is most easily controlled by firing low sulfur fuel,
which is a relatively costly procedure. Many alternatives have been
proposed to remove the SQ2, and several are being tried on a commercial
scale. Most involve neutralization of the acid SO2 .with alkaline
materials such as soda ash, lime, limestone, magnesia~"or dolomite, and
ammonia. The processes developed to date consist of both once-through
and recycle systems. A detailed analysis of air pollution control
systems which produce a liquid waste stream is presented in another
section of this report.
Mode of Operation (Utilization)
The need for considering a subcategorization of the industry based on
utilization arises because of the costs and economics associated with
the installation of supplemental cooling facilities. The unit cost
increment (mills/KWh) required to amortize the capital costs of the
cooling system is dependent on the remaining KWh's that individual units
will generate. The remaining generation is a function of both the
manner in which the individual unit is utilized and the number of years
that the unit will operate prior to retirement. These two factors are
not fully independent variables. In general, utilities will employ
their most efficient, usually newest equipment most intensively. This
equipment will also generally have the longest remaining useful life.
The cost of installing supplemental cooling water equipment for these
units relative to the remaining generation will therefore be relatively
low. Therefore, these more modern, high-utilized units, which also
would reject relatively large amounts of the waste heat, are better able
to carry the costs associated with thermal effluent control.
Less efficient, usually elder equipment will be utilized to a lesser
degree to meet daily and seasonal peak loads. This lower annual
utilization is compounded by the fact that this equipment has relatively
fewer remaining years of service prior to retirement. Therefore, the
cost of amortizing supplemental cooling equipment for these units will
be substantially higher than for the newer, more highly utilized units.
Because of their low utilization, these units will reject considerably
less heat per unit of capacity than the newer equipment. Also, because
of the higher costs associated with this equipment, utilities might
consider early retirement of much of this equipment rather than the
59
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installion of costly treatment equipment. Since these units provide an
important function as peaking or standby capacity, retirement prior to
the installation of replacement capacity would have associated
penalties.
According to the FPC National Power Survey (1970), all of the high-
pressure, high-temperature, fossil-fueled steam-electric generating
units, 500 megawatts and larger, have been designed as "base load" units
and built for continuous operation at or near full load. Daily or
frequent "stops" and "starts" are not consistent with their design and
construction and so-called "cycling" or part-time variable generation
was not originally comtemplated for these units. However, by the time
units having lower incremental production costs become available for
base load operation, it is believed that the earlier "base load" units
can be adapted and used as "intermediate" peaking units. The units
placed in service during the 1960's still have 15 or more years of base
load service ahead of them, but eventually the installation of more
economical base load equipment may make it desirable to convert to
peaking service those units which are suitable for such conversion.
Steam-electric peaking units, sometimes referred to as mid-range peaking
units, are designed for minimum capital cost and to operate at low
capacity factor. They are oil- or gas-fired, with a minimum of
duplicate auxiliaries, and operate at relatively low pressures,
temperatures, and efficiencies. They are capable of quick startups and
stops and variable loading, without jeopardizing the integrity of the
facilities. Such units are economical because low capital costs and low
annual fixed charges offset low efficiency and operation at low capacity
factors. The units can, however, be operated for extended periods, if
needed, to meet emergency situations.
The first of such fossil-fueled steam-electric peaking units, a
100-megawatt, 1,450 psi, 1000°F., non-reheat, gas-fired unit, was
installed in 1960. Two earlier low capital cost fossil-fueled
steam-electric plants--a 69-megawatt, single-unit plant (1952), and a
313-megawatt, two-unit plant (1954)—were generally classified as hydro
standby; they were not straight peaking installations. The 313-megawatt
plant was later modified for base load operation.
With increasing loads and the accompanying need for additional peaking
capacity, at least 27 peaking units of this general type were on order
or under construction at the end of 1970. All are either oil- or
gas-fired, because the added costs of coal and ash handling facilities
for peaking units are not justified by the small fuel cost saving that
might be realized by using coal. Eight of the 27 units are in the 250
to 350-megawatt class, fifteen in the 400-megawatt class, and four in
the 600-megawatt class. Most of the units are designed for steam
conditions of 1,800 psi and 950°/950°F.
60
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The use of the nuclear power plant in conjunction with other forms of
generation in order to provide energy to meet the daily requirements of
a power system will probably not be vastly different from the use of a
fossil-fueled plant of the same capacity. There are some differences,
however, that may affect the operation of the nuclear plant, such as
relative operating costs, refueling time, inspections,
Because an economic loading schedule for a power system will tend to
favor operation of units with the lowest incremental production cost,
the capacity factor of a nuclear fueled plant is expected to be
relatively high when it is added to a system consisting of fossil-fueled
plants. However, when newer, more efficient nuclear plants are added to
the system, which can operate with even lower production costs, the
first nuclear plants will begin to have decreasing capacity factors.
Most of the plants that have been ordered during the past three years
will probably have annual capacity factors of 80 percent or better for a
period of ten to fifteen years, depending on the operating requirements
and makeup of the system. The acceptance of the breeder reactor will
introduce another factor in the economic evaluation of light water
reactor operation as the water reactors produce the plutonium utilized
so efficiently by the breeder. Ultimately, however, the water reactors
may become the marginal operating plants on a utility's system.
The limited operating experience to date with the comparatively small
nuclear plants indicates that they are able to handle load swings
without difficulty. It is expected that the larger units now on order
will perform similarly, but it may develop that they will not be
amenable to load regulation. In the event, fossil units, pumped-stroage
units, conventional hydro units, or other types of peaking units will be
installed to carry peak load with nuclear units being maintained at base
load for substantially all of their useful lives. If nuclear units are
to be utilized with very low annual capacity factors, substantial
research and engineering effort must go into the determination of core
designs to economically accomplish this type of operation.
Base-load units are responsible for the bulk of the thermal discharges,
will continue to operate for many more years, and are able to support
the required technology with relatively small increases in the bus-bar
cost of power. The balance of the steam-electric power generation
inventory is made up of older equipment, which reject considerably less
heat and for which the cost of installing control and treatment
technology would be considerably higher relative to the effluent
reduction benefits obtained. It is understood that considerable
abatement will take place in time in this older portion of the inventory
due to normal attrition.
Traditionally, the power industry has employed two categories for
generating equipment. Units that are continuously connected to load,
with the exception of scheduled and unscheduled maintenance periods have
been termed base-loaded units. Units which are operated to meet
61
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seasonal peak loads have been termed peaking units. Daily load swings
have usually been met by modulation of the base-loaded units. More
recently, the increased cycle sophistication built into the newer base-
loaded equipment has made them less efficient in accommodating large
daily load swings. Therefore, a tnird type of capacity called cyclic or
intermediate generation unit has come into general acceptance within the
industry. This third type of unit is usually a downgraded base-loaded
unit which can be adapted to the intermittent operation with fairly
rapid load swings.
The progression of individual units of capacity through the three types
of duty assignments generally follows the sequence given below:
1. New steam electric capacity has historically been added as base-
load units. All but a few existing steam electric generating units were
at one time base-loaded units. Beginning in the middle 1960's some new
peaking units, both steam electric and gas turbine types have been
constructed. More recently (late 1960«s early 1970's) several units of
the combined (gas turbine/steam turbine) cycle design have been designed
specifically for cyclic or intermittent duty. The aggregate existing
capacity of units originally built for peaking or cyclic service is
considerably less than 195 of the total steam electric inventory.
2. Cycling capacity and peaking capacity has been obtained by
downgrading the older less efficient base-loaded equipment as more
efficient replacement capacity has been built. The manner in which a
unit is downgraded depends upon the needs of the individual utility and
the requirements of its system load curve. Toward the end of its useful
life, the unit may be held in standby duty to be used only in the event
of an outage to the other units.
3. Units have been retired from the bottom level of utilization.
Therefore, retirements of steam electric capacity have generally been
made from the peaking inventory. While the annual retirement of steam
electric powerplant capacity have been significantly less than 1% of the
total capacity, this amount constitutes a significant portion of the
present peaking inventory.
The typical utility makes duty assignments by comparing the capability
of its available generating units against the requirements of its system
load curve. Efficient system operation dictates that the most efficient
equipment be operated continuously. These are the base-loaded units,
In descending order, the less efficient equipment is assigned lower
utilization duty to meet daily and seasonal variations in the load
curve. The process of matching capacity to load is different for each
utility. The systeir load curve will be different for each utility as
will the capability of its individual generating units.
Large systems will have sufficient diversity of load which will dampen
extreme peaks and valleys in the characteristic load curve. They will
62
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also have multiple units serving eadh of the load segments and
considerable flexibility in making duty assignments. Individual large
industrial loads may dominate the system load curve for smaller
utilities and highs and lows of load may be more exaggerated. Duty
assignments for smaller systems will be more constrained by the lack of
multiple units and single units may be found which service all three
load segments. Duty assignments are also influenced by the needs of the
regional power grid in which most utilities participate through a series
of agreements governing interconnections.
The diversity in both load and available capacity complicates the
process of establishing concrete limits between the three types of
generating equipment. The following bases of establishing definitions
of base-load, cyclic and peaking units have been considered.
1. Qualitative descriptions of the three types of operation.
2. Annual hours cf operation.
3. Plant index numbers such as load factor, capacity factor,
utilization factor, etc.
The relative merits of definitions based on these systems are discussed
below. The ideal definition should be relatively easy to employ, allow
effective separation of the three types of generation, and be understood
and accepted.
Definitions Based on Qualitative Description of the Three Types of
Generation
This would rely on a description of the three types of generation as the
basis of separation. Suggested definitions of the three types of
generation are as follows:
A base-loaded unit is one which is continuously connected to load except
for periods of scheduled or unscheduled maintenance.
A cycling unit is one which services daily load variations above the
base-load. This type of unit is typically connected to load some 250
days per year for a typical period of about 12 hours. When not
connected to load the boiler is kept warm to allow rapid return to the
system.
A peaking unit is one which is operated to meet seasonal peak loads
only. During periods of operation the unit is held in standby or is
shut down.
This type of classification system would require a designation by the
utilities as to which units are in each group. This could be validated
by EPA's field representatives. These definitions would probably be
63
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generally accepted fcy the industry. The base-loaded units could be
identified on the basis of these definitions. Some disagreement would
be expected concerning the differentiation between cycling and peaking
units under these definitions.
Definitions Based on Annual Hours of Operation
It is clear that a tasic difference between the three types of
generation is the amount of time that the different units operate.
Reference 292, Part II suggests that steam peaking units are designed to
operate less than 2,000 hours per year. Reference 256 indicates that
base-load units operate in excess of 6,000 hours per year. Units which
operate between these two limits would be defined as cycling units. The
hours of operation referred to in this system are hours that the unit is
connected to load. Hours of boiler operation are not satisfactory.
There is considerable difference in hours of boiler operation and hours
connected to load for cycling and peaking units. Hours of condenser
operation could be used as a substitute since it is equivalent to hours
connected to load. See Table IV-3 for the heat rate, service life, and
capacity factors characteristic of units within the above groupings
based on hours of operation.
Historical records cf annual hours of operation are required to employ
this sytem. There will be instances where base-loaded units will have
been operated less than 6,000 hours per year because of extended
maintenance requirements. On the other hand there will be cases of
stretching out the operating schedules of peaking and cycling units
because of capacity shortage in particular systems. This system does
have the advantage of a basic simplicity in discriminating between the
different categories cf generation.
Definitions on the Basis of Unit Indices
This would require relating the utilization of a unit to indices of its
performance. Several of these indices are described below.
Load Factor
Load factor is the ratio of the average demand for power (kilowatts)
over a designated period to the maximum demand for power occurring in
that period. The average demand is the total (kilowatt hours) for the
period divided by the total time span (hours) . For example, in the
twelve months ended December 31, 1971, the electric energy generated and
purchased less sales to other electric utilities amounted to
35,720,253,101 KWHRS. The one-hour net maximum demand was 7,719,000 KW.
The average hourly deirand was, consequently, 35,720,253,101 / 8760 =
4,078,000 KW. The annual system load factor is, therefore, 4,078,000 /
7,719,000 = 0.528 or 52.8%. The load factor may be regarded as
providing some measure of the variation of demand during a given period.
64
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Table IV-3
CHARACTERISTICS OP UNITS BASED ON ANNUAL
HOURS OF OPERATION
Annual Hours of
Operation
0 - 2000
2000 - 6000
6000 - 8760
Heat Rate, Btu/kwhr
Min. Mean Max.
8727 15793 27315
8735 12493 27748
8706 10636 26741
Remaining Service? yr
Min. Mean Max.
1 11 26
1 15 26
1 19 32
Capacity Factor
Min. Mean Max.
.01 .07 .17
.03 .35 .71
.15 .67 1.12
* Note: Based on a total service life of 36 years,
cn
-------
Thus, if the load factor is 100% over a period of 24 hours, we at once
know that the demand has been maintained constant for the duration of
the period.
Operating Load Factor
If the maximum demand varies from day to day, then the operating load
factor is the ratio of the average demand to the average value of the
maximum demands for the period. For example, the daily maximum demands
for a ten-day period and the corresponding KWHRS are as follows:
Maximum Demand Kilowatt Hours
Day KW Per day
1 1,000 19,200
2 950 13,700
3 800 14,400
4 980 9,700
5 700 10,900
6 850 18,000
7 500 7,000
8 750 10,000
9 820 9, 100
10 900 12,000
Totals 8,250 124,000
Maximum Demand 1,000 KW
Average Maximum Demand = 8,250 / 10 = 825 KW
Average Demand = 124,000 / (10 x 24) = 517 KW
Load Factor = (517 / 1000) x 100 = 51.7%
Operating Load Factor = (517 / 825) x 100 = 62.6%
Thus the operating load factor takes into account the variation of the
daily maximum demand.
Capacity Factor
Capacity factor defines the relation between energy output over a given
time span and the capacity for energy production over the same time
span, and normally provides measure of the utilization of the generating
equipment relative to investment. This factor is also a ratio of the
average load to the total rating of the installed generating equipment
for a given period. For example, in the twelve months ended December
31, 1970, one unit generated 4,465,175,600 KWHRS (exclusive of gas
turbine generation) . The maximum unit capacity (winter rating) was
878,000 KW. The average hourly load was 4,465,175,600 / 8760 = 509,723
KW. The annual capacity factor is therefore, 509,723 / 878,000 = 0.5806
or 58.1%.
66
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Operating Capacity Factor
Although a plant may have installed equipment of a certain amount of
generating capacity, cnly part of this may be in actual operation for
the given period. Suppose for a certain generating plant the capacity
of the installed equipment is 770,000 KW and for some particular month
only 600,000 KW of boiler capacity is actually operating. This means
that the maximum demand that can be imposed on the plant is limited to
600,000 KW. The operating capacity factor for the month would then be
in the ratio of the average demand for power to 600,000 KW, the maximum
capacity utilized. This factor therefore, determines the relation
between average output and the peak demand for power which the plant is
prepared to meet.
Use Factor
This term is generally used in connection with the performance of
turbo-generators. It is the ratio of the actual energy output of a
machine during a certain period to the energy generation which could
have been obtained during the actual operating hours in that period by
operating the machine at rated capacity. A turbo-generator operating
for 7,000 hours generated 350,000,000 KWHRS. The rated capacity of the
unit is 100,000 KW. The use factor was 350,000,000 / (100,000 x 7,000)
= 0.5 or 50%.
Section 304 (b) of the Act requires the Administrator to take into
account, in determining the applicable control measures and practices,
the total cost of application of technology in relation to the effluent
reduction benefits to be achieved from such application. Among the
above factors, the capacity factor alone would determine, for otherwise
similar circumstances, the incremental capital cost associated with the
application of pollution control technology in relation to the effluent
reduction benefits to be achieved. Similarily, the capacity factor
could determine, in relation to the effluent reduction benefits, the
incremental production cost and the incremental reduction in reserve
margin due to lost generating capacity.
The 1970 National Power Survey by the Federal Power Commission (FPC)
describes base-load, intermediate, and peaking units as follows. Base-
load units are designed to run more or less continuously near full
capacity, except for periodic maintenance shutdowns. Peaking units are
designed to supply electricity principally during times of maximum
system demand and characteristically run only a few hours a day. Units
used for intermediate service between the extremes of base-load and
peaking service must be able to respond readily to swings in systems
demand, or cycling. Units used for base-load service produce 60
percent, or more, cf their intended maximum output during any given
year, i.e., 60 percent, or more, capacity factor; peaking units less
than 20 percent; and cycling units 20 to 60 percent. The FPC Form 67,
which must be submitted annually by all steam electric plants (except
67
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small plants or plants in small systems) reports annual boiler capacity
factors for each boiler. The boiler capacity factor is indicative of
the gross generation of the associated generating unit.
Categorization
The Act requires, for the purposes of assessment of the best practicable
control technology currently available, that the toal cost of
application of technology in relation to the effluent reduction benefits
to be achieved from such application be considered. Other factors to be
considered are the age of equipment and facilities involved, the process
employed, the engineering aspects of the application of various types of
control techniques, process changes, nonwater quality environmental
impact (including energy requirements) and other factors as deemed
appropriate. For best available technology economically achievable the
Act substitutes "cost of achieving such effluent reduction" for "total
cost ... in relation to effluent reduction benefits..." For new source
standards which reflect the greatest degree of effluent reduction
achievable through the application of the best available demonstrated
control technology, processes, operating methods, or other alternatives,
the Act requires only the consideration of the cost of achieving such
effluent reduction and any nonwater quality environmental impact anc
energy requirements.
There are two radically different types of waste produced by steam
electric powerplants. The first type consists of the essentially
chemical wastes which originate from different processes and operations
within a plant. These wastes are highly variable from plant to plant,
depending on fuel, raw water quality, processes used in the plant and
other factors. Some waste streams are not directly related to in-
dividual generating units but result from auxiliary process systems such
as water treatment, ash disposal, housekeeping operations, and air
pollution control. However, all of these waste streams are at least in
a qualitive way comparable to waste streams produced by other
manufacturing operations.
The second type of waste consists of the waste heat produced by the
plant and disposed to the environment through the cooling water system.
As previously indicated, waste heat is an integral part of the process
of producing electric energy. As long as electric energy is produced by
the use of thermal energy from fuels to produce steam, waste heat will
be produced, and will ultimately have to be dissipated to the
environment. Under present day technology, the atmosphere is the final
recipient for this heat, but water is generally used as an intermediate
recipient. The choices available in the control of thermal discharges
therefore in most cases are limited to accelerating the transfer of the
waste heat from water to the atmosphere. There is no available means of
significantly reducing the waste heat itself.
68
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Furthermore, while the technology for affecting this transfer is
available, its application is dependent on many factors not directly
associated with the production process. The effectiveness of heat
transfer devices is tc seme degree governed by atmospheric conditions.
The achievement of any specific level of reduction does not follow the
type of cost - effectiveness curve associated with the removal of more
conventional pollutions.
The basic categorization in this report therefore is to separate
consideration of the chemical wastes from the effects of thermal
discharges. Within the chemical waste category, each plant is
considered as a whole and sub-elements have been established according
to the type of wastes produced by each plant. In the consideration of
thermal discharges, each generating unit is considered separately.
Chemical Wastes
The origin and character of chemical wastes within a powerplant is
dependent upon the factors indicated above. Plants utilizing different
fuels will produce different wastes to the degree that certain waste
streams are completely absent in plants employing one type of fuel.
Coal pile runoff is not a problem in oil-fired plants, and similarly ash
sluicing is not necessary in gas-fired plants. Nuclear plants have
closed waste systems to contain any waste which is, or may be,
radioactive. These wastes are handled in a manner prescribed by the
Atomic Energy Commission, and are not relevant to the categorization of
the industry for the purposes of this project. As a result, many of the
waste streams present in fossil-fired plants are not normally present,
or of concern in a nuclear plant.
Another factor, such as raw water quality, will determine the type of
water treatment employed within a specific plant, and in turn the wastes
produced from water treatment processes. Although these wastes are
extremely variable, depending upon the treatment employed
(clarification, softening, ion exchange, evaporation, etc), they are
wastes which are common to all powerplants regardless of fuel or other
factors. Other waste streams depend upon the specific characteristics
of the particular plant in question.
As a result, the industry has been categorized for chemical waste
characteristics by individual waste sources. The basis of evaluation of
plants in the industry will be a combination of the appropriate waste
sources for a particular powerplant. Guidelines will be established for
each waste source, anc can then be applied and utilized in the manner of
a building-block concept. Waste streams may be combined, and in many
cases this would have obvious advantages, and the appropriate guidelines
would then also be combined for application to the new waste stream.
Subcategories have been based on distinguishing factors within groups of
plants. Table IV-4 provides the informal categorization for the
purposes of the development of effluent limitations guidelines and
69
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TABLE IV-4
CHEMICAL WASTE CATEGORIES
I. Condenser Cooling System
A. Once-through
B. Recirculating
II. Water Treatment
A. Clarification
B. Softening
C. Ion Exchange
D. Evaporator
E. Filtration
F. Other Treatment
III. Boiler or PWR Steam Generator
A. Slowdown
IV. Maintenance Cleaning
A. Boiler or PWR Steam Generator Tubes
B. Boiler Fireside
C. Air Preheater
D. Misc. Small Equipment
E. Stack
F. Cooling Tower Basin
V. Ash Handling
A. Oil-Fired Plants
1. fly ash
2. bottom ash
B. Coal-Fired Plants
1. fly ash
2. bottom ash
VI. Drainage
A. Coal Pile
B. Contaminated Floor and Yard Drains
VII. Air Pollution Control Devices
A. SO2 Removal
VIII. Miscellaneous Waste Streams
A. Sanitary Wastes
B. Plant Laboratory and Sampling Systems
C. Intake Screen Backwash
D. Closed Cooling Water Systems
E. Low-Level Rad Wastes
F. Construction Activity
70
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standards for chemical wastes, and Table IV-5 shows the applicability of
the categories to plants utilizing the four basic fuels for producing
electricity.
Thermal Discharge Characteristics
The most obvious factor influencing the rejection of waste heat to
navigable waterbodies is the type of condenser cooling system utilized
within a plant. Powerplants which recycle cooling water through a
cooling device only affect the receiving water by way of the telatively
small blowdown stream from the cooling tower, pond, etc. On the other
hand, plants operating with once-through cooling systems are primarily
responsible for the discharge of waste heat to receiving waters.
Consequently, the basic subcategorization for thermal discharge
characteristics divides the generating units by type of cooling system
utilized, into plants having recirculating cooling systems, or once-
through cooling systeirs.
As indicated above, the primary factor in consideration of waste heat
rejection is the generating unit in question. Therefore,
subcategorization of once-through cooling systems has been made on a
unit, rather than a plant basis. The evaluation of generating units to
further sub-divide the industry considered in detail the various factors
described in this section of the report; namely, fuel, size, age, and
site characteristics and mode of operation utilized. The evaluation of
these factors will be described below to provide the rationale for the
subcategorization developed.
The consideration of fuel as a factor in waste heat rejection from a
powerplant essentially focuses on the differences between present
nuclear and fossil-fueled units. In general, the inherent
characteristics of a light water nuclear unit make it less efficient
than fossil-fired units. This difference in efficiency results in the
rejection of more waste heat to receiving waters from nuclear units than
from comparable fossil units. Subsequent sections of the report will
discuss the technical factors which cause this difference.
Nuclear units generally have basic .similarities with regard to age,
size, location and utilization which also tend to differentiate them
from fossil-fueled units. Nuclear units can be generally classified as
being relatively new^ relatively large, located in rural or semi-rural
areas, and operated as base-load facilities.
These factors are extremely variable when applied to fossil-fueled units
on a broad basis. Also, the thermal waste characteristics of units
burning different fossil fuels indicate that there is no basis for
distinguishing between fossil fuels for the thermal categorization of
the industry. Consequently, the basic subcategorization of once-through
cooling systems divides the industry between nuclear and fossil-fueled
units.
71
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TA3LE IV-5
APPLICABILITY OF CHEMICAL WASTE CATEGORIES
BY TYPE OF FUEL
at ion
X
X
Proces
I. Condenser Cooling System
A. Once-through
B. Recirculating
II. Water Treatment
A. Clarification
B. Softening
C. Ion Exchange
D. Evaporator
E. Filtration
F. Other Treatment
III. Boiler or Generator Slowdown
IV. Maintenance Cleaning
A. Boiler or Generator Tubes
B. Boiler Fireside
C. Air Preheater
D. Misc. Small Equipment
E. Stack
F. Cooling Tower Basin
V. Ash
A. Bottom Ash
B. Fly Ash
VI. Drainage
A. Coal Pile
B. Floor and Yard Drains
VII. Air Pollution (SO2) Control Devices
VIII. Miscellaneous
A, Sanitary Wastes X
B. Plant Laboratory and
Sampling Streams X
C. Intake Screen Backwash X
D. Closed Cooling Water Systems X
E. Low-Level Had Wastes x
F. Construction Activity X
Nuclear Coal Oil Gas
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
72
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A major factor of concern with regard to fossil-fueled generating
facilities is the utilization of individual units. An earlier portion
of this section of the report described the relationship of this factor
with age and with efficiency or heat rate of a generating unit. In
addition to this aspect of utilization, another point of concern is the
relationship between utilization and the cost of installing facilities
to treat waste heat. Utilization is significant in economic analysis,
as it provides the operating time against which capital costs may be
applied. Furthermore, utilization reflects the effluent heat reduction
benefit to be achieved by the application of control technology. As
defined earlier, the utilization aspect of power generation is defined
by peaking, cycling and base load generating facilities. Peaking units
are defined as facilities which have annual capacity factors less than
0.20, while cycling units have annual capacity factors between 0.20 and
0.60 and base-load units have annual capacity factors in excess of 0.60.
Some difficulty could be encountered, for the purpose of effluent
limitations, in determining the level of utilization that a generating
unit will achieve in the years to come. It is known, however, that all
of the nuclear steam-electric generating units and all of the
high-pressure, high-temperature, fossil-fueled units 500 megawatts (MW)
and larger have been designed as base-load units. Almost all nuclear
units are 500 MW and larger.
All of these units presently operating were placed into service since
1960 (excepting only one small nuclear unit initially operated in 1957).
The units placed in service during the 1960's had 15 or more years of
base-load service ahead of them as of 1970, and would thus have 8 or
more years of base-load life as of 1977.
A further difficulty that could be encountered in determining the level
of utilization of a generating unit relates to the fact that the only
official record of the utilization of individual generating units is the
Form 67 "Steam-Electric Plant Air and Water Quality Control Data", which
must be filed annually with the Federal Power Commission. Utilities are
required to report the capacity and average annual capacity factor
(level of utilization) for each boiler, but not the turbine-generator.
Furthermore, prior to 1950, individual boilers were kept small, in large
part because boiler outages were rather numerous, so that it was common
design practice to provide multiple boilers and steam header systems to
supply a turbine-generator. Some stations have the headers connected to
multiple turbine-generators. Hence, the problem could arise in these
cases as to what comprises a generating unit (boiler (s) plus
turbine-generator) and what is its level of utilization. Furthermore,
the problem of applying a closed-loop cooling system could be more
difficult where multiple boilers supply single or multiple
turbine-generators due to the physical and operating problems arising
from the multiple connections involved.
73
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However, advances in metal technology since 1950, with associated lower
costs of larger units, have made it economical and reliable to have one
boiler per turbine-generator. The trend to the larger, one boiler per
turbine-generator units began to be significant when the first 300 MW
unit was placed into service in 1955. From 1930 until that time the
largest steam electric unit in the U.S. was about 200 MW. Hence, for
units 300 MW and larger, the unit itself and its level of utilization
are clearly defined and the physical and operating problems associated
with a closed-loop cooling system and arising from the multiple
connections involved are not encountered.
Age was identified in the Act as a factor to be taken into account in
the establishment of effluent limitation guidelines and performance
standards. As indicated above, the interrelationship between age,
utilization and efficiency, has generally been well documented in the
steam electric generating industry. Age is also important because the
remaining life of equipirent provides the basis for the economic write-
off of capital investment. Consequently, age is of significance in
subcategorizing steam electric generating units not only for technical
reasons, but also for economic considerations.
Federal Power Commission depreciation practices indicate the estimated
average service life of equipment for steam elecelectric production to
be 36 years 87. Figure IV-7, which shows the improvement of efficiency
in the generation of electricity since 1920, indicates a sudden dip in
the curve in approximately 1949, or 24 years ago. Based on this process
factor and the anticipated service life of equipment, it was decided to
subcategorize fossil-fueled units by age, with 6 (six-year)
subcategories defining the range of age with regard to generating units.
Site characteristics were considered as a possibility for
subcategorization of the industry for thermal discharges. The basic
consideration involving location related to the situation of a plant
with regard to its cooling water source (ocean, river, estuary, lake,
etc.) . However, categorization along these lines would in reality
violate the intent of the Act, which stresses national uniformity of
application and is technology oriented. The control and treatment of
waste heat is essentially an internal matter within a powerplant,
Absolute location will influence the cost of such control and treatment,
but will not generally determine its feasibility. This type of location
factor is primarily related to environmental considerations, which are
taken into account under Section 316 of the Act. Consequently, it was
decided not to establish any subcategories for thermal waste
characteristics based on location.
Size was another factor which conceivably could torm the basis for
thermal waste subcategorization of the steam electric powerplant
industry. Among these technical and economic factors considered
relative to the size of a unit were availability and degree of
74
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practicability of control and treatment technology, and unit costs of
control and treatment technology with relation to other generating
costs. The primary basis for a size subcategorization would be the
precedent established by the Federal Power Commission with regard to the
requirements for Filing Form 67, "Steam Electric Plant Air and Water
Quality Control Data". The FPC does not require filing of this form by
powerplants smaller than 25 megawatts, or plants larger than 25
megawatts which do not belong to a utility system with a capacity equal
to, or greater than 150 megawatts. Size subcategorization based on this
precedent was seriously considered, because the form in question
outlines the environmental details of each powerplant required to
respond.
However, investigation indicated that the exclusion of smaller units was
based primarily on procedural considerations rather than technical
factors. There is no significant technical factor which suggests
division of the industry on the same basis as established by the FPC.
In addition, other subcategories based on size were also considered.
However, no technical or economic bases were found to justify
subcategorization by size of unit or plant. It was therefore decided
not to establish formal subcategories on the basis of size of facility.
As a result of evaluation of the factors outlined above, informal
categorization for the purposes of the development of effluent
limitations guidelines and standards for heat includes a division
between nuclear and fossil units and further division of fossil units
based on utilization, all followed by age considerations (six groups
covering the span of 36 years).
Summary
In summary, the most significant of the basic components of all steam
electric powerplants which relate to waste water characteristics are the
fuel storage and handling facilities, water treatment equipment, boiler,
condenser, and auxiliary facilities. Steam electric powerplants
(plants) are comprised of one or more generating units. A generating
unit consists of a discrete boiler, turbine-generator and condenser
system. Fuel storage and handling facilities, water treatment
equipment, electrical transmission facilities, and auxiliary components
may be a part of a discrete generating unit or may service more than one
generating unit. The characteristic quantity and intensity of the waste
heat transferred in the condenser from the expended steam to the cooling
water is related to the combined characteristics of the plant components
that are its source.
•The general subcategorization rationale is summarized in Table IV-6 the
subcategorization rationale for heat is summarized in Table IV-7 and the
subcategorization rationale for pollutants other than heat is summarized
in Table IV-8.
75
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Table IV-6
GENERAL SUBCATEGORIZATION RATIONALE
Subcategorization for heat is approached separately
from subcategorization for other pollutants because:
• Control and treatment technology for heat relate
primarily to the characteristics of generating units,
while nonthermal control and treatment technologies
relate primarily to characteristics of stations.
• Control and treatment technologies are dissimilar; and
• The costs of thermal control and treatment technology
are much greater than nonthermal control and treatment
technologies.
-------
Table IV-7
SUBCATEGORIZATION RATIONALE FOR POLLUTANTS OTHER THAN HEAT
Characteristic
of Plant
Need for Sub-
categorization
Rationale
Utilization (base-load,
cyclic, or peaking)
Age
Fuel
Size
Land Availability
Water Consumption
Non-Water Quality Envir-
onmental Impact (inclu-
ding energy consumption
Process Employed
No
No
Yes
No
NO
NO
NO
No
Yes
Climate
No
Costs versus effluent reduction benefits
vary significantly but are small in all cases
Costs versus effluent reduction benefits
vary significantly but are small in all cases
Certain technologies are practicable for new
sources but not for others
Effects on costs versus effluent reduction
benefits are not significant
Costs for small plants would be significantly
greater but still relativelly small
Treatment technology includes small-sized
configured equipment as well as lagoon—type
facilities
Negligible consumption
Not significant
Practicability of treatment technology
is related to the volumes of waste water
treated, therefore subcategories should
be based on the specific waste water -streams,
especially those of significant volume
Not significant except for effect on rainfall
runoff treatment costs, but costs are small
for all plants
-------
Table IV-8
SUBCATEGORIZATION RATIONALE FOR HEAT
Characteristic of Unit
Need for
Subcategorization
Rationale
-j
00
Utilization(Base-load,
cyclic, or peaking)
Age
Fuel
Size
Process Employed
Land Availability
Water Consumption
Climate
Non-Water Quality
Environmental Impacts
•Saltwater Drift
•Fogging
•Noise
•Aesthetics
Yes
Yes
Yes
Yes
No
Yes
No
No
Yes
No
N<3
No
Coupled with age, this factor determines the
incremental cost of production versus the effluent
reduction benefits related to the thermal control
technology.
Coupled with utilization, this factor determines
the incremental cost of production versus the
effluent reduction benefits related to the thermal
control technology.
Nuclear-fueled units reject significantly more
heat to cooling water than do comparible
fossil-fueled units.
Capital is less readily available and design
engineering manpower requirements higher for
small plants and systems relative to the effluent
reduction benefits of thermal control technologies.
All significant differences already accounted
for by factors of utilization, age, fuel, and size.
Numerous units, due to urban locations, have
insufficient land available to implement the
control technology.
Where required water consumption rights can add an
incremental but insignificant cost over the cost
of water use rights otherwise required.
Variabilities are primarily cost related and
taken into account in the cost analysis
While technology is available to limit drift
to very low levels, significant impacts could
occur for units in urban areas on saltwater
Dodies.
Technology is available to abate fogging in
the few cases where it might otherwise have
a significant impact.
Technology is available to abate noise in
the few cases where it might otherwise have
a significant impact.
Would only be a problem in a case-by-case
evaluation of alternatives.
-------
The degree of nonthermal effluent reductions that can be achieved by the
application of specific control and treatment technologies are related
to the type of source components involved, and further to water use and
quality and other considerations peculiar to individual plants. Both
unit and plant related characteristics affect the degree of
practicability of applying nonthermal waste water control and treatment
technology.
Accordingly, the general categorization scheme developed was approached
from the basis that separate subcategorizations would be constructed for
thermal characteristics and for nonthermal characteristics so that the
rationale supporting the one would not necessarily be supportive of the
other, and candidate approaches to either could be utilized or discarded
on their own merits. Numerous factors" were considered as candidates for
further subcategorization and are as follows: the age of equipment and
facilities, the process employed, waste source (nonthermal
characteristics), nonwater quality environmental impact (including
energy requirements), site characteristics, size of plant, fuel
utilized, and utilization characteristics of the plant, with only the
age of unit and its utilization characteristics qualifying as further
bases for subcategorization of thermal discharges, and waste source for
nonthermal discharges.
An important footnote to the subject of industry subcategorization is
that while certain factors were net found to qualify as candidates for
general subcategorization, some were found to be factors which in
particular cases could affect the degree of the practicability of
applying certain waste water control and treatment technologies. Those
factors which must be further considered are the following: available
land characteristics, size of the unit, accessibility of existing
cooling system, ability of existing structures to accommodate a new
recirculating cooling system, requirements imposed by nearby land uses
(drift, fogging, noise, structure height), climatic considerations
(wind, relative humidity), soil strengths, significance of consumptive
use of water, significance of system reliability requirements, and
characteristics of intake water (temperature, concentrations of
constituents) .
79
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PART A
CHEMICAL WASTES
SECTION V
WASTE CHARACTERIZATION
Introduction
In this part of- the study (Part A) only the nonthermal, or chemical
wastes are dealt with. Part B of the report deals with thermal
discharges.
Chemical wastes produced by a steam electric powerplant can result from
a number of operations at the site. Seme wastes are discharged more or
less continuously as long as the plant is operating. Some wastes are
produced intermittently, but on a fairly regularly scheduled basis such
as daily or weekly, but which are still associated with the production
of electrical energy. Other wastes are also produced intermittently,
but at less frequent intervals and are generally associated with either
the shutdown or startup of a boiler or generating unit. Additional
wastes exist that are essentially unrelated to production but depend on
meteorological or other factors.
Waste waters are produced relatively continously from the following
sources (where applicable) : cooling water systems, ash handling
systems, wet-scrubber air pollution control systems, boiler blowdown.
Waste water is produced intermittently, on a regular basis, by water
treatment operations which utilize a cleaning or regenerative step as
part of their cycle (ion exchange, filtration, clarification,
evaporation).
Waste water produced by the maintenance cleaning of major units of
equipment on a scheduled basis either during maintenance shutdown or
during startup of a new unit may result from boiler cleaning (water
side) , boiler cleaning (fire side), air preheater cleaning, stack
cleaning, cooling tower basin cleaning and cleaning of miscellaneous
small equipment. The efficiency of a powerplant depends largely on the
cleanliness of its heat transfer surfaces. Internal cleaning of this
equipment is usually done by chemical means, and requires strong
chemicals to remove deposits formed on these surfaces. Actually the
cleaning is not successful unless the surfaces are cleaned to bare
metal, and this means in turn that some metal has to be dissolved in the
cleaning solution. Cleaning of other facilities is accomplished by use
of a water jet only.
81
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•jo ATMo«-Pt4e-e.&
cvltwiCMS
CVlEMICALS
12A.W WATEE.
, IUTAUJE scERil
*H, CLOSED
COOUU6 WATEE. SYSTEMS
LKJUID flovl
SA* t *TEAM f lovH
» • « opyiouAl. I
^YPICAL FLOW DIAGRAM - S1EAM EI£CTRIC POWER PLANT (POSSIIr-PUEIiED)
SOURCES OF CHEMICAL HASTES
FIGURE A-V-1
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CO
FOLSOM
SOUTH
CANAL
WATER
700 GPM
10.000-14.000 GPM
REGENERANT
CHEMICALS
DEMORALIZED
MAKE-UP .
SYSTEM
230 GPM
6 GPM
440 GPM
r «
RAW WATER
DEMINERALIZER
SANITARY
SYSTEMS
PLANT RAW
SERVICE
WATER SYSTEM
EMINERALIZED
WATER
REGENERA
PRIMARY
AND
SECONDARY
SYSTEMS
NT WASTE
SEWAGE
TREATMENT
iL.
H
i
STORAGE TANK
cr
OEM
A_
NDENSATE
NERMIZERS
1REGENERAN1
WASTE
EGENERiXT
OLDUP1ANK
I
*-
NEUTRAUZATIGfc
CKE;\AICALS
REGENERANT
CHEMICALS
COfcDENSATE
STORAGE
TAN<
5000-11.400 GPM
0-3200 GPM
ATMOSPHERE
Figure A-V- 2
SIMPLIFIED WATER SYSTEM FLCW DIAGRAM FOR A NUCLEAR UNIT
108r
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Rainfall runoff results in drainage from coal piles, floor and yard
drains, and from construction activity.
A diagram indicating sources of chemical wastes in a fossil-fueled steam
electric powerplant is shown in Figure A-V-1. A simplified flow diagram
for a nuclear plant is shown in Figure A-V-2. Heat input to the boiler
comes from the fuel. Recycled condensate water, with some pretreated
make-up water, is supplied to the boiler for producing steairu Make-up
requirements depend upon boiler operations such as blowdown, steam soot
blowing and steam losses. The quality of this make-up water is
dependant upon raw water quality and boiler operating pressure. For
example, in boilers where operating pressure is below 2800 kw/m* (400
psi), good quality municipal water may be used without pretreatment. On
the other hand, modern high-pressure, high-temperature boilers need a
controlled high-quality water. The water treatment includes such
operations as lime-soda softening, clarification, ion exchange, etc.
These water treatment operations produce chemical wastes. According to
the FPC23*, the principal chemical additives reported for boiler water
treatment are phosphate, caustic soda, lime and alum.
As a result of evaporation, there is a build-up of total dissolved
solids (TDS) in the boiler water. To maintain TDS below allowable
limits for boiler operation, a controlled amount of boiler water is
sometimes bled off (boiler blowdown).
The steam produced in the boiler is expanded in the turbine generator to
produce electricity. The spent steam proceeds to a condenser where the
heat of vaporization of the steam is transferred to the condenser
cooling system. The condensed steam (condensate) is recycled to the
boiler after pretreatirent (condensate polishing) if necessary, depending
upon water quality requirements for the boiler. As a result of
condensate polishing (filtration and ion exchange) , waste water streams
are created.
In a nonrecirculating (once-through) condenser cooling system, warm
water is discharged without recycle after cooling. The cool water
withdrawn from an ocean, lake, river, estuary or groundwater source may
generate biological growth and accumulation in the condenser thereby
reducing its efficiency. Chlorine is usually added to once-through
condenser cooling systems to minimize this fouling of heat transfer
surfaces. Chlorine is therefore a parameter which must be considered
for nonrecirculating cooling water systems.
Cooling devices such as cooling towers are employed in the recirculating
cooling systems. Bleed streams (blowdown) must generally be provided to
control the build-up of certain or all dissolved solids within the
recirculating evaporative cooling systems. These streams may also
contain chlorine and ether chemical additives. According to the FPC234,
the principal chemical additives reported for cooling water treatment
are phosphate, lime, alum and chlorine.
84
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As a result of fossil-fuel combustion in the boiler, flue gases are
produced which are vented to the atmosphere. Depending upon the type of
fossil fuel, the flue gases carry certain amounts of entrained
particulate matter (fly ash) which are removed in mechanical dust
collectors, electrostatic precipitators or wet scrubbing devices. Thus
fly ash removal may create another waste water stream in a powerplant.
A portion of the noncombustible matter of the fuel is left in the
boiler. This bottom ash is usually transported as a slurry in a water
sluicing operation. This ash handling operation presents another
possible source of waste water within a powerplant.
Depending upon the sulfur content of the fossil fuel, SO2 scrubbing may
be carried out to remove sulfur emissions in the flue gases. Such
operations generally create liquid waste streams. Note that SO2
scrubbing is not required for gas-fired plants, or facilities burning
oil with a low sulfur content. Nuclear plants, of course, have no ash
or flue gas scrubbing waste streams.
As a result of combustion processes in the boiler, residue accumulates
on the boiler sections and air preheater. To maintain efficient heat
transfer rates, these accumulated residues are removed by washing with
water. The resulting wastes represent periodic (intermittent) waste
streams.
In spite of the high quality water used in boilers, there is a build-up
of scale and corrosion products on the heat transfer surfaces over a
period of time. This build-up is usually due to condenser leaks, oxygen
leaks into the water and occasional erosion of metallic parts by boiler
water. Periodically, this scale build-up is removed by cleaning the
boiler tubes with different chemicals - such as acids, alkali, and
chelating compounds. These cleaning wastes, though occuring only
periodically, contain metalic species such as copper, iron, etc. which
may require treatment prior to discharge.
The build-up of scale in cooling tower basins and soot build-up in
stacks require periodic washings and these operations also give rise to
waste streams.
For coal-fired generating units, outside storage of coal at or near the
site is necessary to assure continuous plant operation. Normally, a
supply of 90 days is maintained. Coal is stored either in "active"
piles or "storage" piles. As coal storage piles are normally open,
contact of coal with air and moisture results in oxidation of metal
sulfides, present in the coal, to sulfuric acid. The precipitate
trickles or seeps through the coal. When rain falls on these piles, the
acid is washed out and eventually winds up in coal pile runoff, creating
another waste stream. Similarly, contaminated floor and yard drains are
another source of pollution within the powerplant.
85
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Besides these major waste streams, there are other miscellaneous waste
streams in a powerplant such as sanitary wastes, laboratory and sampling
wastes, etc. which are also shown in Figure No. A-V-1.
In a nuclear-fueled powerplant, high quality water is used in the steam
generating section. Conventional water treatment operations give rise
to chemical waste streams similar to those in fossil-fueled powerplants.
Similarly, the cooling tower blowdown is another waste stream common to
both fossil-fueled and nuclear fueled powerplants. Some wastes in a
nuclear plant contain radioactive material. The discharge of such
wastes is strictly controlled and is beyond the scope of this project.
However, the steam generator in a PWR plant is a secondary system,
having a blowdown and periodic cleaning wastes which are not
radioactive. Some of the disposal problems associated with low-level
radiation wastes from nuclear fuel powerplants are briefly described in
this report.
Data was accumulated from different sources to characterize the various
chemical wastes described above. The sources of data include:
a. Plants visits and collection of samples for analysis
b. Permit applications submitted by powerplants to the U. S. Army Corps
of Engineers.
c. Tennessee Valley Authority (TVA) reports of operating plants
d. EPA Region II - questionnaire
e. EPA Region V - summary of permit applications data by National
Environmental Research Center, Corvallis
f. Southwest Energy Study - Appendices
g. U.S. Atomic Energy Commission, Environmental Impact Statements
h. In-house data at Eurns and Roe, Inc.
These data are included in Appendix 2. Note that a code system is used
for individual plant identification.
Based on these data and other industrial and governmental literature,
recommended effluent limitations guidelines proposed were developed for
chemical wastes from the following operations in steam electric
powerplants.
I. Condenser Cooling System
A. Once-through
B. Recirculating
86
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II. Water Treatment
A. Clarification
B. Softening
C. Ion Exchange
D. Evaporator
E. Filtration
F. Other Treatment
III. Boiler or PWR Steam Generator
A. Slowdown
IV. Maintenance Cleaning
A. Boiler or PWR steam Generator Tubes
B. Boiler Fireside
C. Air Preheater
D. Misc. Small Equipment
E. Stack
F. Cooling Tower Basin
V. Ash Handling
A. Oil-fired plants
1. fly ash
2. bottom ash
B. Coal-fired plants
1. fly ash
2. bottom ash
VI. Drainage
A. Coal Pile
B. Contaminated floor and yard drains
VII. Air Pollution Control Devices
A. SO2 Removal
VIII. Miscellaneous Waste Streams
A. Sanitary Wastes
B. Plant Laboratory and Sampling Streams
C. Intake Screen Backwash
D. Closed Cooling Water Systems
E. Low-Level Rad Wastes
F. construction Activity
Once-through Cooling Systems
The common biocides used are chlorine or hypochlorites. The amount of
chlorine dosage varies from site to site and depends upon the source of
cooling water and ambient conditions. For example, in winter the
biological growth is not as pronounced as in spring or summer.
Consequently, chlorine demand is less in winter. Normally, the chlorine
is supplied as a slug rather than by continuous injection. The
87
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frequency of chlorine dosage differs in each plant, and may vary from
once a day to ten times a day. Treatment duration varies between 5
minutes and 2 hours. Chlorination results in residual chlorine
concentrations in the range of 0.1 to 1 mg/1 (ppm) . Higher
concentrations can be found in cases where higher level organisms, such
as jellyfish, or eels, tend to accumulate on condenser surfaces.
Recirculating Systems
In the operation of a closed, evaporative cooling system, the bulk of
the warm circulating water returning to the cooling tower, pond, etc. is
cooled by the evaporation of a small fraction of it. During this
evaporation only water vapor is lost, except for some net entrainment of
droplets in the air draft (drift loss), and the salts dissolved in the
remaining liquid become more concentrated. Most natural waters contain
calcium (Ca++) , magnesium (Mg-H-) , sodium (Na+) , and other metallic ions,
and carbonate (CO3—) , bicarbonate (HCO3-), sulfate (SOU—), chloride
(C1-) and other acidic ions in solution. All combinations of these ions
are possible. When the concentration of ions in any possible
combination exceeds the solubility limits under the existing conditions,
the corresponding salt will precipitate. Some of these salts are
characterized by reverse solubility, that is, their solubility decreases
when the temperature rises. If water saturated with such a salt leaves
the cooling tower at the cool water temperature, as the water is heated
in passing thru the condenser the solubility will decrease and the salt
will deposit as a scale on the condenser tube walls and hinder heat
transfer thru the tubes.
The formation of scale may be controlled in several ways. The most
common is to blowdown a portion of the circulating water stream and
replace that quantity with fresh water so that the circulating water
does not reach saturation at any time. Blowdown therefore is the
constant or intermittent discharge of a small portion of the circulating
water in a closed cooling system to prevent a buildup of high
concentrations of dissolved solids. The blowdown (B) is a function of
the available makeup (B+D+Ev) water quality and is related to
evaporation (Ev) and drift (D) in the following manner:
C = (B + Ev + D)/(B + D)
In this equation, C equals cycles of concentration, a dimensionless
number which expresses the number of times the concentration of any
constituent is multiplied from its original value in the makeup water.
(It does not represent the number of passes through the system) . B, Ev,
and D are expressed in consistent units (e.g. percent of circulating
water flow rate or actual flow rate).***
For average makeup water quality, conventional practice sets the value
of C between U and 6. For extremely high quality makeup water (or
treated water) C values of 15 and above are possible. For salt or
88
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saline water, c values as low as 1.2 to 1.5 may be required, this is
usually not a materials or operating limit, but rather a means of
preventing biological damage from blowdown salinity.1*4
The chemical characteristics of the recirculating water (treated or
untreated) determine the maximum c value. Table A-V-1 provides some
"rules of thumb" to be used in establishing the maximum C value. Note
that the C subscript designations used in the table represent individual
constituent concentrations and should not be confused with Cr cycles of
concentration used above.***
The "Limitation" column in Table A-V-1 indicates the maximum value
allowed in the recirculating water for each chemical characteristic
given. The maximum C value would be established when any one of the
"Limitations" is exceeded. Note that this table provides "rule of
thumb" estimates, which may not be applicable, to unique water quality
problems.***
The equation for C can be rewritten for blowdown (B):
B = Ev-DfC-1)
C - 1
In order to minimize the total amount of makeup water and blowdown the
cooling tower should be operated at as high a C value as possible. The
following data were computed using the above equation and illustrate the
effect of C on the blowdown and makeup flow rates:
C Blowdown Makeup
(cycles of concentration) (cf si (cfs)
1.2 107 128
1.5 42.8 64.2
2.0 21.14 42.8
5JO 5.3 26.7
10.0 2.3 23.7
20.0 1.1 22J5
This table was developed assuming an evaporation rate (Ev) of 21.4 cfs
and a drift rate (D) cf 0.05 cfs (0.0053S of 950 cfs).»**
There are several advantages to maintaining a high C value:
a. Minimizing the makeup water requirement, thus reducing the
number of organisms entrained in the cooling water.
b. Minimizing the volume of blowdown water to be discharged.
c. Reducing the size and cost of makeup and blowdown handling
facilities (i.e., pumps, pipes, screens, etc.).1**
89
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Table A-V-1
RECIRCULATING WATER QUALITY LIMITATIONS
144
Characteristic
Limitation
Comment
pH and Hardness
pH and Hardness
with addition of
proprietory chemicals
for deposit control.
Langelier Saturation
Index = 2.5
Langelier Saturation
Index = 1.0
Langelier Saturation
Index = pH-pHs
where
pH = measured pH
pHs = pH at saturation
with CajK>3
See Figure A-V-3 for
nomograph solution.
Sulfate and Calcium
CSQ = concentration of
4 S04 in mg/1
Cc = concentration of
Ca in mg/1 as CaC03
Silica
CJ..Q = concentration of
Si02 in mg/1
Magnesium and Silica
(C
SiO
= 35'000
M
= concentration of
Mg in mg/1 as
90
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Figure A-V-3
NOMOGRAM TO DETERMINE LANGELIER SATURATION INDEX
228
Courtesy Power Engineering
t 6000
MILLION
r-4000
I-3OOO
' pALK AND
": pC a SCALE
r2000 4.0
- *.?
E'°°° 1 as
r 800 2.4-4
r 600 T
Rrrpr>r'fjt~p J
t > t f-'.iVOC O 4 -
; paws *?-z"3 ac
^^ (V 1 :
r 30<)^* ^ \ V?c° . 2-°^1
: ^ ^* ~^^ \ "- _j 25-
-~I>ALK * 1.3 ^ -
d"^5.o--
- ;oo IG-*
(so ; I
r 60 M^ /.5-
"C"5C4££ -j -
r 40 4
/.2 4
- 30 A/0.
: 32
- 40
j- 50
r fio
r 70
— so
~r QO
— too
~r i in
-!20
-140
160
180
^ /./•*-_.
TEMf?,f
IO
Example: Water at 124 F has a pH
of 7.7, total bOtius. of 400 ppm. ca!-
ciurrr hardness as CaCU3 of 240 ppm,
and alkalinity as CaCO., of 196 ppm.
Find the Langelier saturation index.
Solution: (i) Join 400 ppm nn the
iefthand scale with 1?4 F on the tern-
persti-re r-^=?!s. .At rrtterccotior. with
C sci-Ie note value of 1.7. (2) Join
240 ppm with pCa reference point
and extend to pCa scale. Read pCa=
2.62. (3) Join 196-ppm with pALK
reference point, extend to pALK scale
and read pALK=2.40. Add the three
values:
PHS=C + pCa + pALK=6.72
lndex=pH-pHs=7.2-6.72=+ 0.48
91
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Values for evaporation from cooling systems average about 0.75X of
cooling water flow for every 10°F of condenser delta T for cooling
towers and approximately SOX higher for cooling ponds. This is
equivalent to a range of 15.0 to 30.0 gpm/MW for cooling towers and 22.5
to 45.0 gpm/MW for cooling ponds. Drift constitutes a relatively small
portion of the required makeup water. For new cooling towers, drift
losses can be kept as low as O.OOSX of the cooling water flow for
mechanical draft towers and 0.00256 for natural draft towers. Drift
losses for ponds are negligible. Estimates of the allowable blowdown
flow based on these factors can be made once the cooling water flow,
condenser delta T, and allowable concentration factors are known.
The heat content of the blowdown as a % of condenser heat rejection can
be quite variable. The heat content of the blowdown can vary from a
fraction of 1% of the total condenser heat rejection to as high as 7 to
856 of this value. Higher rates of heat rejection in the blowd'own are
due to larger blowdown flows (smaller C values) required in salt water
systems and systems that blowdown from the hot side of the system.
Systems that blowdown from the cold side of the cooling system should
contain no more than 1 to 2% of the condenser heat rejection.
Scale formation may be controlled by chemical means such as softening or
ion exchange to substitute more soluble ions for the scale formers, such
as Naf substitution for Ca-J-+ and Mg-H-. Advantage may be taken of the
greater solubility of some ions. For instance SO4— may be substituted
for CO3— or HCO3-, as: ~
Ca CO3 + H2 SO4 = CaSOU + H2O + CO2 (g)
Mg (HCO3) + H2S04 = MgSOU +2H2 +2CO2(g)
In these reactions, CO2 is released as a gas. Sulfates have a much
greater solubility than carbonates and bicarbonates, and scale formation
is reduced. Organic "sequestering" agents are used to tie up the
insoluble metallic icns so that they cannot combine with the carbonates
and bicarbonates to form scale. Many of these agents are proprietary
compounds and their compositions are not generally known. The use of
chemical dispersants and makeup water softening to reduce or eliminate
blowdown at certain powerplants is discussed in Reference 22.
Eventually the limit is reached and there must be some bleed through
drift or blowdown although its quantity may be greatly reduced,
resulting in higher concentrations. Data obtained from the study of
fifteen plants (See Appendix 2) reveals an extremely large variation in
the parameters listed. Generally, the important pollutant parameters
are: total suspended solids (TSS), pH, hardness, alkalinity, total
dissolved solids and phosphorus.
In general, condenser materials are chosen so as to resist corrosion by
the recirculating water. Consequently, chemicals are generally not
92
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required in the recirculating water for corrosion resistance, except in
cases where the recirculating water (because of the make-up water
quality) has high chloride concentrations chromates or other chemicals
are added as corrosion inhibitors.
In recirculating systems, growth organisms such as algae, fungi and
slimes occur because of the warm and moist environment. Such biological
growth will affect condenser efficiencies and chlorine is commonly used
as a biocide. The chlorine dosage is usually in slugs. The residual
chlorine is generally in the range of 1 mg/liter. Higher residual
chlorine concentrations may cause corrosion problems. In cooling towers
with wood filling, sodium pentachlorophenate is sometimes added to
inhibit fungi attack on wood. The chemicals are generally added to the
cooling tower basin to ensure adequate mixing. Depending upon the
chlorine dosage frequency (one to three times a day) and sodium salt
addition, the concentration of these pollutants in the blowdown will
vary for each case.
Water Treatment
All water supplies contain varying amounts of suspended solid matter and
dissolved chemical salts. Salts are dissolved from rock and mineral
formations by water as it flows into rivers and lakes. In the boiler,
as water evaporates to steam, mineral salts deposit on metal surfaces as
scale. Scale reduces transfer of heat through the metal tubes, and if
allowed to accumulate reduces the flow area, eventually causing failure
of the tubes. To prevent scaling, water is treated for removal of
mineral salts before its use as boiler feed water.
Removal of the dissolved mineral salts can be accomplished by
evaporation, chemical precipitation or by ion exchange* Evaporation
produces a distilled-water-quality product but is not always economical
and results in a stream of brine waste. Chemical precipitation is of
limited use in the removal of dissolved solids, as the product water of
the process contains soluble quantities of mineral salt. To produce a
boiler feed water, chemical precipitation followed by evaporation is
used occasionally, but cost is not always economical.
Clarification
Chemical precipitates and naturally occurring suspended solids are very
fine and light. Clarification is a process of agglomerating the solids
and separating them from the water by settling. Suspended solids are
coagulated, made to join together into larger, heavier particles and
then allowed to settle. Clarified water is drawn off and filtered to
remove the last traces of turbidity. Settled solids, more commonly
called sludge, are withdrawn from the clarifier basin, continuously or
intermittently and discharged to waste. Figures A-V-U and A-V-5 show
simplified flow diagrams for clarification and filtration processes
respectively. Surface water, in addition to dissolved impurities, may
93
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TRJEATMEMT
J
CLEAB. WATEIZ.
CLARIFICATION PROCESS
FIGURE A-V-4
FILTRATION PROCESS
FIGURE
94
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contain suspended matter, causing turbidity or objectionable color.
Removal of turbidity by coagulation is an electro-chemical phenomenon.
Iron and aluminum ions of positive charge form a bridge with the
negative charge of the sediments, causing an agglomeration of the
particles. Most commonly used coagulants are aluminum sulfate (alum,
filter alum, A12(SO4)3 . 18 H2O), ferrous sulfate (copperas, FeSC4 . 2
H20) , ferric sulfate (ferrifloc, Fe2 (SO4)3) , and sodium aluminate"" (soda
alum, Na2 A12 O4). Polyelectrolytes" and other coagulant aids are
frequently used in the process.
Softening
In the softening process, chemical precipitation is applied to hardness
and alkalinity. Principal chemicals used are calcium hydroxide
(hydrated lime - Ca (OH) 2) and sodium carbonate (soda ash-Na2CO3) .
Calcium is precipitated as calcium carbonate (CaCO3) and magnesium'as
magnesium hydroxide (Mg (OH) 2) . ~
Chemical precipitation of calcium and magnesium can be carried out at
ambient temperatures, which is known as cold process softening, or may
be carried out at elevated temperatures, 100°C (212<>F) , known as hot
process softening. Hot process softening is generally employed for
boiler feed water in steam electric powerpiants when steam is generated
for heating purposes as well as electric power generation. The hot
process accelerates the reactions and reduces the solubility of calcium
carbonate and magnesium hydroxide.
Since there is always some carryover of fine particles from the
clarifiers, these are generally followed by filters. Filters may
contain graded sizes of sand, anthracite coal or other filter media.
Filters are also required in case clarifiers have an upset and
precipitates are carried over into the clear water overflow.
Ion Exchange
Ion exchange processes can be designed to remove all mineral salts in
one unit process operation. These processes produce high-quality water
suitable for boiler feed purposes. All of the mineral constituents are
removed in one process. The ion exchange material is an organic
resinous type material manufactured in granular bead form. Resin beads
contain pores that make them similiar to a sponge. The surface area is
electrically charged and attracts to the surface chemical ions of op-
posite charge.
Basically there are two major types of resin, cation and anion. Cation
resin attracts the positively charged ions and anion resin attracts the
negatively charged ions. When the charded sites on the resin surface
are filled with ions exchanged from the water, the resin ceases to
function .and must be regenerated. (Figure A-V-6)
95
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RAW
ION EXCHANGE PRCXTESS
CATIONIC AND ANIONIC TYPE
FIGURE A-V- 6
96
-------
The regeneration process is a three-step operation for all ion exchange
units except mixed resin units. Mixed resin units (Figure A-V-7)
contain a mixture of cation and anion resin in a single vessel. The
resin is in a mixed form during the service run and is separated during
the regeneration.
During the service run, water flow in an ion exchanger is generally
downflow through the resin bed. This downward flow of water causes a
compaction of the bed which in turn causes an increase in resistance to
flow through the bed. In addition, the raw water being treated always
contains some micro-size particles which collect at the top surface of
the bed and add to the resistance to flow. To alleviate this
resistance, normal water flow to the bed is stopped and direction of
flow through the bed is reversed, causing the bed to erupt, and wash the
solids out. Ion exchange beds are usually washed for a period of 10 to
15 minutes. Flow rates vary with the size of vessel and the type of
resin. The flow rate is adjusted to expand the resin bed 80 to 100X of
its settled bed depth. Flow rates of 3.4-U.1 10-3 m3/s/mz (5-6 gallons
per minute per square foot) are typical. The second stage of
regeneration is the contacting step. Chemical solution is passed
through the bed at a controlled flow rate such that resin is contacted
with the chemical solution for a certain time. Cation resins are
contacted for approximately 30 minutes while anion resins are contacted
for approximately 90 minutes. Immediately after this chemical contact,
the bed is given a slow rinse. The normal volume of rinse is two bed
volumes. The purpose of the rinse is to-wash the regenerant solution
remaining in the voids of the bed after the regenerant flow is stopped.
The bed is then rinsed until effluent quality reaches de-ionized water
specification. Quantity of rinse water depends on the resin. Cation
rinse water is approximately 8.0 m3 water per m3 resin. Anion rinse
water is approximately 10.0 m3 water per m3 resin. With mixed resin
units, there are two additional steps in the regeneration process.
After rinsing, the water level is drained until it is just above the
settled resin bed level. Air is injected into the bottom of the vessel
causing the two stratified layers of resin to mix. After this mixing,
the vessel is filled with water and the resin bed is given a short final
rinse.
Chemical characteristic of the spent regenerant depend, on the type of
service that an ion-exchanger is performing. Cation exchange in
hydrogen cycle absorbs calcium, magnesium, potassium, and sodium ions
from the water. The cation unit is regenerated with sulfuric acid. The
acid concentration is maintained low to prevent calcium sulfate
precipitation. The spent regenerant solution contains the eluted ions
with excess acid.
In'order for the regeneration process to proceed there must be a driving
force. The driving force is excess chemical quantity. The quantity of
acid required for regeneration, on a weight basis, is 2-U times the
stoichiometric exchange capacity of the resin. On a weight basis, the
97
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Acio
wAsye-
ION EXCHANGE PROCESS
MIXED RESIN TYPE
FIGURE A-V-7
98
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waste sulfuric acid will consist of 1/4-1/3 part mixed cations and 2/3-
3/4 part of excess sulfuric acid. Concentration of cations in the waste
depends on their distribution in the water supply.
Occasionally, hydrochloric acid is used for hydrogen cycle regeneration.
Hydrochloric acid yields a greater regeneration efficiency than sulfuric
acid. The cost of hydrochloric acid is generally higher than sulfuric
acid, therefore, it is used only when the economics justify it.
Anion exchange units are regenerated with sodium hydroxide. The
concentration is approximately 45S. The spent regenerant will contain
the eluted anions. These are sulfate, chloride, nitrate, phosphate,
alkalinity, bicarbonate, carbonate, and hydroxide. Silica in the form
of HSiO3- is also absorbed by anion exchangers and may be present in the
spent regenerant.
In high-pressure steam electric plants, condensate is deionized to
prevent dissolved salts from condenser tube leaks from entering the
boiler system, and eliminate minute quantities of iron and/or copper
formed as a result of corrosion. The condensate is then polished in
mixed resin units. The ion exchange resin is regenerated with sulfuric
acid and sodium hydroxide. Sometimes, ammonium hydroxide is used in
place of sodium hydroxide. The quantity of iron and copper found in the
spent regenerants is usually negligible.
Sodium cycle ion exchange is the exchange of calcium and magnesium ions
for sodium ions. Hard water is often softened by this process, but the
content of dissolved solids is not appreciably changed. The exchange
resin is regenerated with 1056 sodium chloride solution. The waste
regenerant consists of approximately 1/3 part calcium and magnesium
chloride and 2/3 part sodium chloride.
Evaporator
Evaporation is a process of purifying water for boiler feed by
vaporizing it with a heat source and then condensing the water vapor on
a cool surface, and collecting it externally of the evaporator unit. In
the process, a portion of the boiling water is drawn off as blowdown.
The evaporator consists of a vessel, usually in a horizontal position in
order to provide a large surface area for boiling. In steam electric
plants, evaporators are usually heated by a waste source of heat, such
as extraction steam from the turbine cycle. The water evaporates into
the upper surface of the vessel and is ducted to an external condenser.
In the lower portion of the vessel, a pool of the boiling water is
maintained at a constant level to keep the steam tubes immersed in
liquid. As water evaporates from the pool, the raw water salts in the
pool become concentrated. If allowed to concentrate too much, the salts
will scale the heating surfaces and the heat transfer rate diminishes.
To prevent scaling, a portion of the pool water is drawn off as
99
-------
blowdown. A simplified flow diagram of the process is shown in Figure
A-V-8.
Chemical composition of the blowdown is similar to that of the raw water
feed except that it is concentrated several times. The blowdown is
alkaline, with a pH in the range of 9-11. This is due to decomposition
of bicarbonate ion to carbon dioxide and carbonate ion. The carbon
dioxide is degassed from the evaporator leaving carbonate in solution
and yielding an alkaline pH. If the concentration of calcium sulfate is
high enough, it will precipitate out of solution. Some steam electric
power plants feed phosphate to the raw water feed. This phosphate re-
acts with calcium and lessens the precipitation of calcium carbonate and
calcium sulfate.
Evaporators are usually found in older low-pressure steam electric
plants. Ultra pure water required in the modern high pressure units may
generally be obtained more economically by the ion exchange processes.
A typical powerplant may employ a combination of the different water
treatment operations described above. However, the waste streams from
all these water treatment operations are generally similar in pollutant
characteristics. Consequently, a description of the combined pollutants
found in the waste streams is given below.
Character of Water Treatment Wastes
Water treatment waste streams should be described by three parameters:
1) pH, 2) suspended solids concentration, and 3) concentration
parameters typical cf processes involved or toxic elements involved in
the process. Reference 21 reports waste water flows as shown in Table
A-V-2.
Clarification wastes consist of clarifier sludge and filter washes.
Clarifier sludge could be either alum or iron salt sludge, from
coagulant chemicals. If the clarifier is lime softening, then the
sludge would be a calcium carbonate-magnesium hydroxide sludge. Filter
washes would contain suspended solids either as light carry-over floe
from the clarifier or as naturally contained in unclarified raw water,
Activated carbon absorber wash would contain light suspended particles
or very fine activated carbon particles due to attrition of the carbon.
Various attempts have been made to classify clarifier sludges. Although
these vary from plant to plant, the basic characteristics are quite
similar. Alum sludge is a non-Newtonian, bulky gelatinous substance
composed of aluminium hydroxide, inorganic particles, such as clay or
sand, color colloids, micro-organisms including plankton and other
organic matter removed from water.
The major constituent in sludge from lime soda softening is calcium
carbonate. Other consituents which may be present are magnesium
100
-------
FEED
COU06USE&
COJJD.
J
EVAPORATION PROCESS
FIGURE A-V-8
101
-------
Table A^V-2
TYPICAL WATER TREATMENT WASTE
WATER FLOWS (Ref . 21)
PROCESS
RANGE OF FLOWS
gal/ 1000 Ib water
treated
Clarifier blowdown
Lime-soda
Raw water filtration backwash
Feed water filter
Sodium zeolite regeneration
Cation exchange regeneration
Anion exchange regeneration
Evaporator blowdown
Condensate filtration and
ion exchange
Condensate powdex
1-4
1-4
0-6
0-6
0.5 - 3
0.5 - 3
0.5 - 3
12 -40
0.02 - 0.6
0.01 - 0.06
102
-------
hydroxide, hydroxides of aluminum or iron, insoluble matter such as
clay, silt or sand, and organic matter such as algae or other plankton
removed from the water.
The American Water Works Association Research Foundation has conducted a
study among its members to gather information on the nature of waste
disposal problems in water treatment plant to assist the utilities. »*
Waste sludges from clarifiers, generally have a solids content in the
range of 3,000 - 15,000 mg per liter. Suspended solids amount to
approximately 75 - 8058 of total solids with the quantity of volatile
solids being 20 - 25X of total solids. The BOD level usually is 30 -
100 mg per liter. A large corresponding COD level of 500 - 10,000 mg
per liter shows that the sludge is not biodegradable, but that it is
readily oxidizable. The sludge has a pH of about 5-9.
Filter backwash is more dilute than the wastes from clarifiers.
Generally, it is not a large volume of waste. Turbidity of wash water
is usually less than 5 mg per liter and the COD is about 160 mg per
liter. The total solids existing in filter backwash from plants
producing an alum sludge is about 400 mg per liter with only 40 - 100 mg
per liter suspended solids.
All ion exchange wastes are either acidic or alkaline except sodium
chloride solutions which are neutral. While ion exchange wastes do not
naturally have any significant amount of suspended solids, certain
chemicals such as calcium sulfate and calcium carbonate have extremely
low solubilities and are often precipitated because of common ion
effects. Calcium sulfate precipitation is common in ion exchange
systems because of excess quantities of sulfuric acid.
Evaporator blowdown consists of concentrated salts from the feed water.
Evaporators are usually operated to a point where the blowdown is three
to five times the concentration of the feed water. Due to the low
solubility of calcium carbonate and calcium sulfate, it is possible that
there will be precipitation of calcium carbonate and sulfate, if present
in the feed water. While the concentrated salts of the feed water are
neutral, decomposition of bicarbonate to carbon dioxide and calcium
carbonate, creates an alkaline waste stream from the evaporator.
Table A-V-3 shows the arithemetic mean and standard deviation for a
number of parameters for water treatment wastes. These data were
gathered from many different sources and reported in various ways.
Therefore they show wide variations. As can be seen, the standard
deviation of each parameter chosen, is two to three times greater than
the mean value of the parameter.
Undoubtedly, other factors that do not appear in the data caused this
variation. Under the sub-heading of clarification wastes, the reported
data do hot indicate whether the waste stream is a sludge from a
103
-------
TABLE A-V-3
ARITHMETIC MEAN AND DEVIATION OF
SELECTED WATER TREATMENT WASTE PARAMETERS
ARITHMETIC STANDARD 0~
MEAN DEVIATION m
m 0-
CLARIFICATION WASTES
Flow - M3 per day
Turbidity - J.T.U.
Total Suspended Solids -
Total Suspended Solids -
mg TSS per 1
kg TSS per day
Total Hardness - mg CaCO.3 per 1
1
25
2
3
Total Hardness - kg CaC03_ per day
Iron - mg Fe per 1
Iron - kg Fe per day
Aluminum
ION EXCHANGE WASTE
Flow"- MT~per day
Total Dissolved Solids -
Total Dissolved Solids -
Sulfate *• mg SO4per 1
Sulfate - kg SO4 per day
Chloride - rag Cl per 1
Chloride - kg Cl per day
Sodium - mg Na per 1
Sodium - kg Na per day
Ammonia - mg NHJ - N per
Ammonia - kg NH3 - N per
EVAPORATOR ^ SLOWDOWN
Flow""- M* per day
Total Dissolved Solids -
Total Dissolved Solids -
Total Suspended Solids -
Total Suspended Solids -
Sulfate - mg SO4 per 1
Sulfate - kg SOjj per day
Chloride - mg Cl per 1
Chloride - kg Cl per day
316
,088
,213
,673
,215
27
352
212
2
53
5
7
1 Piece
mg TDS per 1
kg TDS per day
1
day
mg TDS per 1
kg TDS per day
mg TSS per 1
kg TSS per day
74
7
1
2,
1
1
3
,515
,408
,311
085
,100
,708
124
,112
558
46
14
38
730
88
175
16
79
4
194
17
374
11
4
3,
3
4
6
1
613
,015
,060
,594
,812
63
572
662
Data
,737
,550
,263
859
,414
,603
389
,448
,572
137
41
62
805
187
443
36
109
8
337
31
1.
1.
2.
2.
2.
2.
1.
3.
—
5.
1.
3.
1.8
3.
2.
3.
2.
2.
3.
2.
1.
1.
2.
2.
2.
1.
2.
1.
1.
9
8
1
1
4
3
6
1
0
6
2
1
7
1
1
8
0
9
6
1
1
5
2
4
0
7
8
104
-------
clarifier removing suspended solids, a sludge from a lime softener for
hard water, or a wash-water from a filter. Obviously, waste stream
composition will vary depending upon its origin.
Similarly, data listed under ion-exchange wastes do not indicate whether
the waste is acid, caustic or brine waste. There are no indicators of
what source the waste originated from, or if the waste was neutralized
before reporting. In summary, data collected on water treating wastes is
of limited value because of the process variations which were not
reported, and because of the limited quantity of information available
on these waste streams.
Boiler or PWR steam Generator Slowdown
Except for. zero solid treatment systems, no external water treatment
regardless how efficient, is in itself protection against boiler scale
without the use of supplementary internal chemical treatment of the
boiler water.
The primary cause of scale formation is that the solubilities of scale
forming salts decrease with an increase in temperature. The higher the
temperature and pressure of boiler operation, the more insoluble the
scale forming salts become. No method of external chemical treatment
operates at a temperature as high as that of the boiler water. Con-
sequently, when the toiler feed water is heated to the boiler operating
temperatures, the solubility of the scale forming salts is exceeded and
they crystallize from solution as scale on the boiler heating surfaces.
Calcium and magnesium salts are the most common source of difficulty
with boiler scale. Internal chemical treatment is required to prevent
deposit scale formation from the residual hardness concentration
remaining in the feed water. One of the most common sources of scale is
the decomposition by heat of calcium bicarbonate to calcium carbonate
and carbon dioxide.
Ca(HCO3)2 + Heat = CaCO3 (s) + H2) + CO2(g)
Deposits of iron oxide, metalic copper and copper oxide are frequently
found in boilers operating with very pure feedwater. The source of
deposits is corrosion. Causes of the corrosive action are dissolved
oxygen and carbon dioxide.
To prevent calcium and magnesium salts from scaling on boiler
evaporative surfaces, internal treatment consists of precipitating the
calcium and magnesium salts as a sludge and maintaining the sludge in a
fluid form so that it may be removed by boiler blowdown. The blowdown
can be continuous or intermittent and the operation involves controlled
discharge of a certain quantity of boiler water. The most common
chemicals used for precipitation of calcium salts are the sodium
phosphates.
105
-------
Chelating or complexing agents are sometimes applied. Tetrasodium salt
of ethylenediaminetetracetic acid (Na4-EDTA) and trisodium salt of
nitrilotriacetic acid (NaJ-NTA) are the most commonly used chelating
agents. The chelating agents complex the calcium, magnesium, iron and
copper in exchange for the sodium.
The solubility of iron in water increases as the pH decreases below the
neutral point. To prevent corrosion, neutralization of the acid with an
alkali is necessary. Sodium carbonate, sodium hydroxide and/or ammonia
are commonly employed for this purpose.
Dissolved oxygen present in boiler water causes corrosion of metallic
surfaces. Dissolved oxygen is introduced into the boiler, not only by
the makeup water, but by air infiltration in the condensate system. In
addition to mechanical deaeration, sodium sulfite is employed for
chemical deaeration.
2 Na2SO3 + O2 = 2Na2SO4
It is common practice tc maintain an excess of the sulfite, to assure
complete oxygen removal. The use of sodium sulfite is restricted to low
pressure boilers because the reaction products are sulfate and dissolved
solids which are undesirable in high pressure boilers.
Hydrazine is a reducing agent which does not possess these disadvantages
for high pressure operation. Hydrazine reacts with oxygen to form
water.
N2HIH- 02 - 2H20 + N2
The excess hydrazine is decomposed by heat to ammonia and nitrogen.
The characteristics of boiler blowdown are an alkaline waste with pH
from 9.5-10.0 for bcilers treated with hydrazine and pH from 10-11 for
boilers treated with phosphates.
Blowdown from medium pressure boiler has a total dissolved solids (TDS)
in the range of 100-500 mg/1. High-pressure boiler blowdown has a total
dissolved solids in the range of 10-100 mg/1. Blowdown from boiler
plants using phosphate treatment contain 5-50 mg/1 phosphate and 10-
100mg/1 hydroxide alkalinity. Boiler plants with hydrazine treatment
produce a blowdown containing 0-2 mg/1 ammonia.
In PWR nuclear-fueled powerplants, the steam generator employs ultrafine
quality water. Consequently the blowdown frequency and the impurities
are much less than that in fossil fuel plants.
The blowdown frequency is commonly once a day. Most of the data also
confirm the typical alkaline nature of the blowdown. The data do not
show completely the type of treatment and the raw water treatment
106
-------
Efficiency. Consequently, the data have greatly varying parameters.
'Reference 21 reports waste water flows from boiler blowdown ranging from
tO-4 gal/1000 Ib steam generated.
ii
Equipment Cleaning
i
^Chemical Cleaning Boiler or PWR steam Generator Tubes
Boilers are subject to two major chemical problems, corrosion and scale
•^formation. Proper operation and maintenance involves the pretreatment
"of boiler makeup water, and the addition of various corrosion and scale
control additives to the feed water. Boilers operating at high
'pressures (and temperatures) require more critical control of boiler
water chemistry than low pressure boilers.
Even with the best preventive maintenance, occasional boiler cleaning is
a necessary operation for proper performance of steam boilers.
scondenser leaks, oxygen leaks in the boiler water and corrosion/erosion
i of metallic parts by toiler water may increase the frequency of boiler
>t cleanings.
Chemical cleaning of boilers can be of two types - 1) Preoperational--
2necessary for new boilers before going on-stream and 2) Operational-
:'necessary for scale and corrosion products removal to maintain normal
boiler operating performance.
Preoperational Boiler Cleaning Wastes
, During the manufacture and assembly of boiler steel components, a black
iron oxide scale (mill scale) is formed on metal surfaces. The removal
-of mill scale is necessary to eliminate potential galvanic corrosion and
erosion of turbine blades which can occur because of trapped mill scale
in the steam path. Similarly, the presence of oil, grease (used during
fabrication and assembly) and construction debris can be detrimental to
[boilers. Consequently, preoperational cleaning of boilers is an
: important aspect of powerplant start-up procedures.
iTypical steps for preoperational cleaning involve:
it*
(i) an alkaline bo i lout using a solution containing caustic or soda
ash, phosphates, wetting or emulsifying agents and sodium nitrite as an
^inhibitor to protect against caustic embrittlement.
i
" (ii) draining of the solution after achieving satisfactory removal of
oil, grease, silica, loose scale, dirt and construction debris etc.
(iii) rinsing of the toiler
u
(iv) acid cleaning of the boiler to remove mill scale using corrosion
inhibited hydrochloric acid or organic acids, such as citric and formic
acids or patented chelating scale removers.
107
-------
(v) draining of the acid solution using nitrogen to prevent metal
rusting
(vi) second rinsing of the boiler with demineralized water
(vii) an alkaline boil out to neutralize trapped acid and to remove
trapped hydrogen gas molecules (which if left in the boiler can cause
metal embrittlement over a period of time)
(viii) and finally followed by a passivation rinse using sodium nitrite
and phosphate solution.
These typical preoperational cleaning steps are followed for drum type
boilers. For once-through boilers, process steps are similar except
that instead of boilout, continuous flushing is carried out.
The pollution parameters associated with preoperational boiler cleanings
are extreme pH values (acidic or alkaline solutions) , phosphates,
nitrates, BOD from the organic emulsifying agents, oil and grease and
suspended solids. The quantity of these wastes and the pollutant
concentrations vary for each specific case.
Operational Boiler Cleaning Wastes
A variety of cleaning formulations are used to chemically clean boilers
whose operation has deteriorated due to build up of scale and corrosion
products. Analyses of scale deposits are made on sample sections of
tubes cut from the boiler. Based on the composition of scale discovered
in these samples, a cleaning program is selected. Some procedures are
more effective for copper removal, others for iron removal, and still
others for silica removal. The composition of boiler scale and
corrosion products is briefly described. This is followed by a
description of methods used to renovate boilers.
Composition of Scale
Boiler scale contains precipitated salts and corrosion products.
Precipitation occurs because of local supersaturation of their solution
concentration near the heated tube surfaces. These salts include
calcium carbonate and sulfate, calcium and magnesium phosphates and
silicates, and magnesium hydroxide as principal constituents. Iron and
copper oxides are present as corrosion byproducts and various trace
metals as zinc, nickel, aluminum may be present either as constituents
of the feed water, or as corrosion products. In addition, mud, silt,
dirt or other debris introduced via condenser leaks are also present.
Oil contamination of toiler water results in carbonation of this waste
and this is incorporated into the boiler scale. The composition of
boiler scale is dependent on the composition of boiler feed water,
materials of construction, boiler chemical additives, and contaminants
108
-------
leaked into the boiler water, and therefore will differ with each
successive cleaning of the boiler.
Frequency of Boiler Cleanings
There are many factors which affect the cleaning schedule for power
utility steam boilers. High pressure boilers require more critical
control of feed water purity and consequently usually require less
frequent cleanings. A review of boiler cleaning data in Table A-V-4
shows that cleaning frequency varies from once in seven months to once
in one hundred months. The mean time between boiler cleanings is
estimated from these data as thirty months with a standard deviation of
eighteen months.
Types of Boiler Tube Cleaning Processes
Alkaline Cleaning Mixtures with Oxiding Agents for Copper Removal
These foundations may contain free ammonia and ammonium salts, (sulfate
or carbonate), an oxidizing agent such as potassium or sodium bromate or
chlorate, or ammonium persulfate, nitrates or nitrites, and sometimes
caustic soda. Air is sometimes used as the oxidant. These mixtures
clean by the following mechanism: Oxidizing agents convert metallic
copper deposits to copper oxide. Ammonia reacts with the copper oxide
to solubilize it as the copper ammonium blue complex.
Since metallic copper interferes with the conventional acid cleaning
process described below, this cleaning formulation is frequently used to
precede acid cleaning when high copper levels are present in the boiler
scale.
The pollutants introduced by these cleaning formulations are as follows:
ammonium ion, oxidizing agents, high alkalinity, and high levels of iron
and copper ion dissolved from the boiler scale.
Acid Cleaning Mixtures
These mixtures are usually based on inhibited hydrochloric acid as
solvent, although sulfuric, sulfamic, phosphoric, nitric, citric, formic
and hydroxyacetic acids are also used. Hydrofluoric acid or fluoride
salts are added for silica removal. Corrosion inhibitors, wetting
agents, and complexing agents to solubilize copper may also be included.
These mixtures are effective in removal of scale due to water hardness,
iron oxides, and copper oxide, but not metallic copper.
The principal pollutants introduced to the waste stream from these
cleaning chemicals are acidity, phosphates, fluorides, and organic
compounds (BOD). In addition large quantities of copper, iron,
109
-------
TABIE A-V-4
CHEMICAL HASTE CHARACTERIZATION
INCREASE IN POLLUTANT QUANTITY PER CLEANING CYCLE
BOILER TUBES' CLEANING
A
as*
3409
3409
3410
3412
3414
3416
3404
3603
3603
3604
3604
3604
3604
3604
3605
3605
3605
3605
3605
3605
3606
3606
3609
3609
3609
3607
3610
3610
3610
3610
3611
3611
3612
3612
3612
3612
3612
3612
3612
3612
3612
3612
3614
3614
3614
3614
3614
3614
3613
3613
3613
B
Cleaning
months
24
24
12
24
12
22
23
IS
20
13
7
20
50
60
50
12
24
24
36
22
48
100
74
15
12
9
18
15
50
100
60
30
50
40
24
30
36
40
40
30
40
24
20
36
14
12
30
24
24
C
Boiler
m3
174
174
106
215
303
190
571
314.58
117.1
278.8
163.4
163.4
261.19
261.19
261.19
143.45
143.45
189.3
183.1
183.1
108.95
108.95
108.95
148.903
136.18
136.18
136.18
136.18
129.6
129.6
52.65
52.65
52.65
52.65
77.17
77.17
77.17
77.17
137.54
137.54
59.9
74.4
74.4
74.4
74.4
74.4
74.9
74.9
74.9
D E F G H
Volume Alkalinity (CaCCh ) BOD
(1000 gal.) (lb> Kg (Ib) kg
46 1380 626 104 47.2
46 1380 626 104 47.2
28 181 82 -9.8 -4.45
57 -158 -72 -8.3 -3.8
80 3770 1711.9 121.4 55
50 158.4 71.94 -1.65 -0.75
150.8 -23.8 -10.84 0 0
83.09
30.93 - - - -
43.165 - - - -
43.165 - - - -
92.92
35.97
35.97 - - - -
69.18 - - - -
69.18 - - - -
69.18 - - - -
37.89 - - - -
37.89 - - - -
50.0 - - - -
48.37 - - -
48.37 - -
28.78 - - - -
28.78
28.78
39.33 - - - -
35.97 - - -
35.97 - - - -
35.97 - - -
35.97 - - - -
34.23 - - - -
34.23 - - - -
13.9 - - - -
13.9 - - - -
13.9 - - -
13.9 - - - -
20.38 - - - -
20.38 - - - -
20.38 - - - -
20.38 - - - -
36.33 - - - -
36.33 - - - -
15.82 - - - -
19.66 - - - -
19.66 - - - -
19.66 - - - -
19.66 - - - -
19.66 - - - -
19.78 - - -
19.78 - - - -
19.78 - - -
IJKLMNOPQR
Total Total
COD Total Solids Dissolved Solids Suspended Solids Ammonia
(Ib) kg (Ib) kg (Ib) kg (Ib) kg (Ib) kg
4017 1823 11816 5369 8588 3899 176 80 16.7 7.58
4017 1823 11816 5369 8588 3899 176 80 16.7 7.58
5091 2311 12024 5458 10684 4850 9.8 4.45 1.2 0.54
8302 3769 11972 5435 11225 5096 75 34 9.8 4.45
11101 5040 34817 15807 1983 900.4 505.2 229.4 52.86 24.0
9169 4163 39698 18023 37196 16887 246 111.7 3.2 1.454
-14.07 -6.39 99.34 45.1 99.34 45.1 0000
_ - - _- -_
_ - - ____---
_ - - - - --
- - - -------
_ - - _- -
_ - - -------
_-- _ - _ -
_ - - -------
- - - - - - -
--- -- _-
- - - -- - -
- - - _______
--- -- -_
--- -- - -
--- -- - -
--- -- - -
--- -- --
--- -- --
--- -- - -
--- -------
--- -------
--- -- - -
-_- -- - -
--- -- - -
--- -------
--- -------
--- -------
--- -------
--- -- --
--- -- - -
--- -- --
--- -------
--- -- - -
-_- -------
--- -- - -
--- -------
--- -- - -
--- -- - -
- - - - - - -
--- - - --
-_- --_____
--- -- - -
--- - - --
- _ _
-------
TABLE A-V-4
CHErflCAL WASTE CHARACTERIZATION
INCREASE IN POLLUTANT QUANTITY PER CLEANING CYCLE
RniLgp TtmKs' CLEANING (continued)
A
Plant
Code
3409
3409
3410
3412
3414
3416
3404
3603
3603
3604
3604
3604
3604
3604
3605
3605
3605
3605
3605
3605
3606
3606
3609
3609
3609
3607
3610
3610
36J.O
3610
3611
3611
3612
3612
3612
3612
3612
3612
3612
3612
3612
3612
3614
3614
3614
3614
3614
3614
3613
3613
3613
B C
Nickel
(Ib)
95.8
95.8
—
294
108.4
-
Ill
_
-
-
100
-
-
81.9
-
-
-
-
-
577
-
33
-
-
46.2
-
-
44
-
41.8
-
-
-
-
-
-
-
-
-
44.0
-
-
-
-
-
24.23
-
24.23
-
-
kg
43.5
43.5
—
133.88
49.22
-
50.4
«
-
-
45.4
-
-
37.2
-
-
-
-
-
262
-
15
-
-
21
_
-
20
-
19
-
-
-
-
-
-
-
-
-
20
-
-
-
-
-
11
-
11
-
-
D E
Zinc
'(lb)
5.99
5.99
10.3
-0.045
169.6
91.56
0.00018
141
_
-
-
126
-
-
106
-
-
-
-
-
74.89
-
44
-
-
59.4
-
-
55
-
52.8
-
-
-
-
-
-
-
-
-
55
-
-
-
-
-
30.8
-
30.8
-
-
2.72
2.72
4.67
-0.02
77
41.57
0.00008
64
_
-
-
57.2
-
-
48.1
-
-
-
-
-
34
-
20
-
-
27
-
-
25
-
24
-
-
-
-
-
-
-
-
-
25
-
-
-
-
-
14
-
14
-
-
F G H I
Sodium Nitrate
1076
1076
2018
-
4885
12378
-55.9
-
_
2569
2569
3504
1902
2742
3363
3363
5007
2200
1515
2031
182
243
128
-
-
-
2603
1301
2603
-
3500
5374
1144
573
1144
573
3027
3027
-
-
-
-
201
-
55.7
-
1440
2161
2105
810
2105
kg (lb) kg
488 0.56 0.25
488 0.56 0.25
916 -5.6 -2.54
-0.542 -0.25
2218 2.9 1.32
5620 0.817 0.371
-25.46
-
~ _ -
1166
1166
1590
863
1244
1526
1526
2273
998
687
922
82
110.3
58
_
_
.
1181
590.6
1244
-
1589
2441
519
260
519
260
1374
1374
- - -
- - -
- - -
-
91.4
_ - -
25.28
_
653
981
955
367
955
J K L M
Hardness Bromide
(lb) kg (lb)
I'll 550
1211 550
-29.19 -13.25
89.86 40.8
_
1.25 0.57
-
_ _ -
484
484
492
582
484
_
_
_
503
503
773
635
847
444
_ -
_ -
_
476
635
476
476
465
465
481
243
481
243
270
270
- -
-
- -
- -
698
- -
193
- -
-
-
201
328
201
kg
-
-
-
-
-
_
219.7
219.7
223
264
219.7
-
-
-
228
228
350.9
288
384
201
-
-
-
216
288
216
216
211
211
218
110
218
110
122
122
-
-
-
-
317
-
87.6
-
-
-
91.2
148.9
91.2
N 0
Manganese
(lb)
-
-
-
0.0059
30.8
_
-
-
27.9
-
-
48.9
-
-
-
-
-
15.4
-
11
-
-
13.2
-
-
11
-
11
-
-
-
-
-
-
-
-
-
11
-
-
-
-
-
6.6
-
6.6
-
-
kg
•
-
-
0.0027
14
_
-
-
12.7
-
-
22.2
-
-
-
-
-
7
-
5
-
-
6
-
-
5
-
5
-
-
-
-
-
-
-
-
-
5
-
-
-
-
-
3
-
3
-
-
p
Acidity, Oil and Grease,
Mercury, Sulfite, lead..
Turbidity Selenium. Phenols. Surfactants
JTU
370
370
276
23
387
100
0
-
_
NO DATA
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-------
TABLE A-V-4
CHEMICAL WASTE CHARACTERIZATION
A B C D E F G
Code Phosphorus Sulfate Chloride
(Ib) kg (Ib)
34C9 4.07 1.84 11.26
3406 4.07 1.84 11.26
3410 0.4 0.18 -40
3412 -0.08 -0.036
3414 7.26 3.3 73.37
3416 -0.001674 -0.00076 0.33
3404 -0.0125 -0.0057 2.24
3603 74 33.6
3603 -
3604 -
3604 -
3604 78.9 35.82
3604 -
3604 -
3605 58.72 26.66
3605 -
3605 -
3605 -
3605 -
3605 -
3606 40.97 18.6
3606 -
3609 24.45 11.1
3609 -
3609 -
3607 33.76 15.33
3610 -
3610 -
3610 30.1 13.7
3610 -
3611 28.7 13.05
3611 - - -
3612 -
3612 -
3612 -
3612 -
3612 -
3612 -
3612 - - -
3612 -
3612 30.9 14.03
3612 -
3614 -
3614 -
3614 -
3614 -
3614 17.24 7.83
3614 -
3613 17.24 7.83
3613 -
3613 -
kg (IX)
5.11 7772
5.11 7772
-18.6 19100
6142
33.31 25898
0.15 32191
1.02 6.03
40361
15052
21006
21006
45224
14588
14588
42085
38290
42085
18440
18440
24332
29422
29422
13167
13167
13167
19140
14588
17506
14588
14588
19477
16696
6768
8460
6768
8460
8266
8266
12398
11572
17101
14733
9625
11962
9568
11962
11962
11962
8022
8022
8022
kg
3528
3528
8671
2788
11758
14615
2.74
18324
6834
9537
9537
20532
6623
6623
19107
17834
19107
8372
8372
11047
13358
13358
5978
5978
5978
8690
6623
7948
6623
6623
8843
7580
3073
3841
3073
3841
3753
3753
5629
5254
7764
6689
4370
5431
4344
5431
5431
5431
3642
3642
3642
INCREASE IN POLLUTANT QUANTITY PER CLEANING CYCLE
BOILER TUBES' CLEANING (continued)
HI J K L M
Fluoride Aluminum Chromium
(Ib)
_
-
-
-
-
_
_
870
_
478
478
2509
514.7
514.7
3837
3837
3837
1050
1050
1385
-
-
1596
-
399
-
514.7
997
514.7
514.7
864.5
864.5
192.8
192.8
192.8
192.8
282
282
1130
1130
504
504
253
1092
546
546
552
829
549
362.3
275
kg (Ib)
_ _
-
-
-
-
-
-
395 18.94
-
217
217
1139 17
233
233
1742 13.87
1742
1742
477
477
628
11.0
-
724 28.6
-
181
8.8
233.6
452.6
233.6 8.8
233.6
392.4 6.6
392.4
87.53
87.53
87.53
87.53
128
128
513
513
228.8 8.8
228.8
114.86
495
247.88
247.88
250.6 4.4
376.3
249.2 4.4
164.5
124.8
kg (Ib) kg
6.91 3.13
6 . 91 3 . 13
1.4 0.63
1.21 0.55
23. 17 10.52
0.0832 0.0378
0.035 0.0160
8.6
- - -
- - -
- - -
7.7 16.9 7.7
- - -
- - -
5.3 13.87 6.3
.
-
- - -
- - -
- - -
5 11.01 5
- - -
13 6.6 3
- - -
- - -
4 8.8 4
- - -
-
4 " -
_
3 6.6 3
-
_
-
-
-
-
-
- - -
-
4 8.8 4
- - -
_
-
_
_
2 13.2 6
- - -
2 4.4 2
-
- - -
N 0
Copper
(Ib)
251.6
251.6
245.5
-
718
325
0.00006
800
800
900
800
500
300
600
200
100
25
500
600
600
200
300
400
200
300
300
500
400
500
500
600
400
200
100
200
300
300
400
100
100
300
200
500
100
100
100
50
50
200
200
200
kg
114.2
114.2
111.4
-
326
147.7
0.00003
363
363
408.6
363
227
136.2
272
90.8
45.4
11.35
227
272
272
90.8
136.2
181.6
90.8
136.2
136.2
227
181.6
227
227
272
181.6
90.8
45.4
90.8
136.2
136.2
181.6
45.4
45.4
136.2
90.8
227
45.4
45.4
45.4
22.7
22.7
90.8
90.8
90.8
P Q
Iron
(li)
599
599
1571
1668
1841
5491
0.001
3100
3100
2400
4900
3800
2200
2100
4000
3000
3000
1100
1100
5000
3500
4500
1500
2500
3000
3000
100
1000
1000
900
2000
2500
900
800
700
500
1000
1000
1500
1000
3000
1500
1600
1400
1200
1000
1000
500
1000
1000
1000
kg
271.9
271.9
713.2
757.2
836
2493
0.00045
1407
1407
1089
2224
1725
999
953
1816
1362
1362
499
499
2270
1816
2043
681
1135
1362
1362
45.4
454
454
408
908
1135
408
363
318
227
454
45.4
681
454
1362
681
726
635
545
454
454
227
454
454
454
R S
Maqnes ium
(Ib) kg
224 101.7
224 101.7
-
-
13.83 6.28
-
-
66 29.9
-
-
-
59.0 26.8
-
-
48.9 22.2
-
-
-
-
-
33 15
-
22 10
-
-
28.6 13
-
-
26.43 12
-
24.23 11
-
-
-
-
-
-
-
-
-
26.43 12
-
_
-
-
-
13.22 6
-
13.22 6
-
-
-------
hardness, phosphates and turbidity are released as a result of loosening
and dissolving the boiler scale.
Alkaline Chelating Rinses and Alkaline Passivating Rinses
These formulations contain ammonia, caustic soda or soda ash, EDTA, NTA,
citrates, gluconates, or other chelating agents, and may contain certain
phosphates, chromates, nitrates or nitrites as corrosion inhibitors.
These cleaning mixtures may be used alone, or after acid cleaning to
neutralize residual acidity and to remove additional amounts of iron,
copper, alkaline earth scale compounds, and silica. Their use
introduces the following pollutants to the discharged wastes:
alkalinity, organic compounds (BOD), phosphates, and scale components
such as iron, copper and hardness.
Proprietary Processes
Frequently boiler tubes are cleaned by specialized companies using
proprietary processes and cleaning chemicals. Most of these chemicals
are similar to those described earlier and the resulting wastes contain:
alkalinity, organic compounds (BOD), phosphate, ammonium compounds, and
scale compounds such as iron, copper and hardness.
The data in Table A-V-4 shows pollutant concentrations for specific
cases. Inasmuch as boiler cleaning is tailored for individual
requirements, generalization about pollutant concentration is not
possible. However, the data does indicate generally observed high
amounts of metallic species and COD requirements.
In this study, boiler tube cleaning was not categorized on the basis of
once-through or drum-type. However, it is to be noted that similar
cleaning as described earlier is followed for once-through type boilers.
The other major heat transfer component in a boiler system is the
condenser. The spent steam from the turbine is liquefied in the
condenser by the condenser cooling water system. Condenser tubes are
made out of stainless steel, titanium or copper alloys. Preoperational
cleaning of the condensers is done with alkaline solutions, with
emphasis on the steam side of the condenser because of high quality
water circulation. Operational cleaning on the steam side depends upon
boiler water quality and is not done frequently. The water side of the
condenser is cleaned with inhibited hydrochloric acid.
In nuclear powerplants of the PWR type, strict control on the quality of
steam generator water is maintained. Cleaning frequently varies with
plant characteristics, as in fossil-fuel power plants, but the cleaning
methods are the same.
113
-------
Boiler Fireside
The fireside of boiler tubes collects fuel ash, corrosion products and
airborne dust. Gas-fired boilers have the cleanest combustion process.
In order to maintain an efficient heat transfer, boiler firesides are
cleaned with high pressure fire hoses, while the boilers are hot. Soda
ash or other alkaline materials may be used to enhance the cleaning.
Depending upon the sulfur content of the fuel, the cleaning wastes are
more or less acid.
Data was available from only two plants for boiler fireside cleaning,
These data are shown in Table A-V-5. The pollutants in the waste stream
may reveal extreme values of pH, hardness and suspended solids as well
as some metals.
Air Preheater
Air preheaters are an integral part of the steam generating system,
They are used to preheat the ambient air required for combustion and
thus economize thermal energy. Two types of preheaters are used —
tubular or regenerative. In either case, part of the sensible heat of
the combustion flue gases is transferred to the incoming fresh air.
In tubular air preheaters, cold fresh air is forced through a heat
exchanger tube bundle using a forced-draft-fan. The flue gases leaving
the economizer flow around the tubes and heat is transferred through the
metal interface. Regenerative type preheaters are used more frequently
in large powerplants. In this type, heat is regenerated by using
metallic elements in a rotor. The rotor revolves between two ducts --
outlet duct carrying hot flue gases to the stack and intake duct
carrying fresh air to the boiler windbox. Heat is transferred to the
metallic elements which in turn transfer it to the fresh air by
convection.
Soot and fly ash accumulate on the preheater surfaces and the deposits
must be removed periodically to maintain good heat transfer rates as
well as to avoid plugging of the tubes or metallic elements. Preheaters
are cleaned by hosing them down with high-pressure water from fire
hoses.
Depending upon the sulfur content of the fuel, the cleaning wastes are
more or less acidic in nature. The washing fluid may contain soda ash
and phosphates or detergents which have been added to neutralize excess
acidity or alkaline depending on the cleaning product used. Fly ash and
soot, rust, magnesium salts, and metallic ions leached from the ash and
soot are normal constituents of the cleaning wastes. Copper, iron,
nickel, and chromium are usually prevalent in this discharge, and in
oil-fired installations vanadium may also be present at significant
levels.
114
-------
TABLE A-V-5
TON
INCREASE IN POLLUTANT QUANTITY PER CLEANING CYCLE
AIR PREHEATER CLEANING
A
— Line Codl?
1) 3409
2) 3410
3) 3411
4) 3412
5) 3413
6) 3414
7) 3415
B
Cleaning
cycles/yr
12
12
8
12
5
6
4
C
Batch
m3
409
852
1363
2272
265
162.8
378.6
0
Volume
(1000 gal.)
108
225
360
600
70
43
100
E
F
Alkalinity
(Ib)
-72.02
-76.65
-90.08
-530.39
189.73
-19.71
-25.02
kg
-32.7
-34.8
-40.9
-240.8
86.14
-8.95
-11.36
G
COD
(Ib)
14.4
16.87
14.98
35.02
116.7
5.72
9.16
H
kg
6.54
7.66
6.8
15.9
53
2.6
4.16
I
Total
(Ib)
11951
24964
40528
65515
2616
4768
11257
J
Solids
kg
5426
11334
18400
29744
1188
2165
5111
K
Dissolved
(Ib)
7907
16605
27022
44264
4467
3189
8249
L
Solids
kg
3590
7539
12268
20096
2028
1448
3745
M
Tot
Suspend*
(Ib)
1975
4008
6603
10788
477.9
785.24
1834
N
d Solids
kg
897
1820
2998
4898
217
356.5
833
O
P
Sulfate
(Ib)
1066
2231
3601
6114
692
423.8
979
kg
484
1013
1635
2776
314.2
192.4
444.5
Q
R
Chloride
(Ib)
1.801
0
0
9989
0
-8.96
-14.16
kg
0.8178
0
0
4534
0
-4.07
-6.43
BOILER FIRESIDE CLEANING
8) 3410
9) 3411
2
8
2626
90.8
720
24
-240
5.99
-109
-2.72
1134
19
515
8.63
40861
4002
18551
1817
35127
3002
15948
1363
3823
119.09
1736
54.07
11949
299.4
5425
135.9
0
18.01
0
8.18
AIR PREHEAIER CI£ANING (continued)
Line
1)
2)
3)
4)
5)
6)
7)
8)
9)
A
s»*
3409
3410
3411
3412
3413
3414
3415
3410
3411
B C
Ammonia
(Ib)
2.378
4.49
8.1
12
0.722
0.925
2.)76
1.49
0.039
kg
1.08
2.04
3.68
5.45
0.328
0.42
0.988
0.68
0.018
D E
Nitrate
(Ib)
3.414
5.06
11.25
5.48
0.471
1.074
3.37
14.75
0.7
kg
1.55
2.3
5.11
2.49
0.214
0.488
1.53
6.7
0.318
F G
Phosphorus
(Ib)
0.513
2.66
4.67
5.86
0.035
0.559
1.32
11.1
0.257
kg
0.233
1.21
2.12
2.66
0.016
0.254
0.6
5.04
0.117
H I
Hardness
(Ib)
3949
8255
13372
22196
476.8
1577
3709
35409
791.41
kg
1793
3748
6071
10077
216.5
716
1684
BOILER
16076
359.3
J K
Chromium
(Ib)
1.1
24.25
39.03
59.19
0.749
0.458
0.533
FIRESIDE
0.0299
0.998
kg
0.529
11.01
17.72
26.875
0.34
0.208
0.242
CLEANING
0.0136
0.453
L M NO
Copper Iron
(Ib)
4.434
-
-
0
2.907
1.788
1.86
(continued)
0.249
kg (Ib)
2.018 1531
3189
5103
0 8506
1.32 3.495
0.812 2.13
0.848 2.379
900
0.113 30
kg
695.1
1448
2317
3862
1.587
0.967
1.08
408.9
13.63
P Q
Magnesium
(Ib)
874.45
1850
2986
4812
107.4
352.4
828
11949
190.35
kg
397
840
1356
2185
48.76
160
376
5425
86.42
B S
Nickel
(Ib)
67.55
140.72
225
375.3
28.63
17.93
20.83
30.02
-
kg
30.67
63.89
102.2
170.38
13
8.14
9.46
13.63
-
AIR PREHEATER CLEANING (continued)
Line_
1)
2)
3)
4)
5)
6)
7)
8)
9)
A
«#*
3409
3410
3411
3412
3413-
3414
3415
3410
3411
B C
Sodium
(Ib)
1.799
0
0
8630
552
-0.35
1.66
0
9
kg
0.818
0
0
^ 3918
' 251
-0.16
0.757
0
4.09
D
Zinc
(Ib)
4.43
8.97
14.93
25.02
0.283
1.788
2.07
28.72
2
E
kg
2.011
4.075
6.78
11.36
0.1285
0.812
0.942
13.042
0.908
F
(Ib)
3.6
0
0
15.01
2.335
1.793
1.668
0
0
G
BCD
kg
1.635
0
0
6.815
1.06
0.814
0.757
0
0
H
Turbidity
JTU
495
476
497
478
500
500
498
476
98
BOILER FIRESIDE CLEANING (continued)
-------
Cleaning frequency is usually about once a month, but frequencies of 4
to 180 cleanings per year are reported in Table A-V-5.
Chemical data for air preheater cleaning are also shown in Table A-V-5.
Data for plant number 3412 appears to deviate considerably from the
other plants, and much of the data reported varies considerably from
other plants, by as much as an order of magnitude.
Miscellaneous small equipment
At infrequent intervals, other plant components such as condensate
coolers, hydrogen coolers, air compressor coolers, stator oil coolers,
etc. are cleaned chemically. Inhibited hydrochloric acid is a common
chemical used for cleaning. Detergents and wetting agents are also
added when necessary. The waste volume is, of course, smaller than that
encountered in other type of chemical cleanings. Pollutant parameters
are — low-high pH, total suspended solids (TSS) metallic components,
oil, etc.
Stack
Depending upon the fossil fuel used, the stack may have deposits of fly
ash, and soot. Acidity in these deposits can be imparted by the sulfur
oxides in the flue gases. If a wet scrubber is used to clean the flue
gas, process or equipment upsets can result in additional scaling on the
stack interior. Normally, high-pressure water is used to clean the
deposits on stack walls. These wastes may contain total suspended
solids (TSS), high or low pH values, metallic species, oil, etc.
Cooling tower basin
Depending upon the quality of the make-up water used in the cooling
tower, carbonates can be deposited in the tower basin. Similarly,
depending upon the inefficiency of chlorine dosages, some algae growth
may occur on basin walls. Some debris carried in the atmosphere may
also collect in the basin. Consequently, periodic basin washings with
water is carried out. The waste water primarily contains total
suspended solids (TSS) as a pollutant.
Ash handling
Steam-electric powerplants which utilize oil or coal as a fuel produce
ash as a waste product of combustion. The total ash is of two sorts:
bottom ash and fly ash. Bottom ash is the residue which accumulates in
the furnace bottom, and fly ash is the material which is carried over in
the flue gas stream.
Ash-handling is the conveyance of the accumulated waste products to a
disposal system. The method of conveyance may be either wet (sluicing)
116
-------
or dry (pneumatic). This report discusses the wet ash handling system
and in particular, the waste water which it produces.
The chemical characteristics of ash handling waste water is basically a
function of the fuel burned. The following table lists commercial fuels
for power production. 27a
Fuels Containing Fuels Containing
Ash Little or No Ash
All coals Natural gas
Fuel oil-"Bunker C" Manufactured gas
Refinery sludge Coke-oven gas (clean)
Tank residues Refinery gas
Refinery Coke Distillates (most)
Most tars Combustion-turbine exhaust
Wood and wood products
Other products of vege-
table
Waste-heat gases (most)
Blast-furnace gas
Cement-kiln gases
Of the fuels containing ash, coals and fuel oil are mostly used in the
power industry.
Coal
Coal is the most widely used fossil fuel in United Stated powerplants.
In 1972, 335 million tons of coal were consumed in the U.S. for power
generation. The average ash content of coal is 11 % for the nation, 238
with a range from 6 to 20%. It may, therefore be estimated that roughly
37,000,000 tons of ash were produced in 1972 by U.S. powerplants.
Disposal of this quantity of solids from the waste water stream has
prompted most utilities to install some sedimentation facility. In many
cases, ash settling pcnds are used. A typical ash pond is illustrated
in Figure A-V-9, which is located in plant no. U217. However, in some
cases, because of unavailability of land, aesthetics, or some other
reason, utilities have installed more sophisticated materials-handling
systems based on the sedimentation process.
The characteristics of the water handling coal ash is related to the
physico-chemical properties of that ash and to the volume and initial
quality of the water used. Table A-V-6 lists some of the constituents
of coal ash.23* Table A-V-7 shows the volume and time variabilities of
water flow in an ash handling system. Reference 21 reports that water
requirements for ash handling are as follows:
fly ash 1,200-40,000 gal/ton ash conveyed
117
-------
TYPICAL ASH POND
PLANT NO. 4217
Figure A-V-9
118
-------
Table A-V-6
CONSTITUENTS OP COAL ASH
238
Constituent
Si°2
A12°3
Pe2°3
Ti02
CaO
MgO
Na2°
so3
C and volatiles
P
B
U and Th
Cu
Mn
Ni
Pb
Zn
Sr
Ba
Zr
Percent
30-50
20-30
10-30
0.4-1.3
1.5-4.7
0.5-1.1
0.4 1.5
1.0-3.0
0.2-3.2
0.1-4.0
0.1-0.3
0.1-0.6
0.0-0.1
trace
trace
trace
trace
trace
trace
trace
trace
119
-------
Table A-V-7
TIME OF FLOW FOR ASH HANDLING SYSTEMS
Plant No. 0110, a 952 MW unit fueled by pulverized coal
- basis is one 8-hr cycle -
Duty
H. E. #1
Flushing
H. E. #2
Flushing
H. E. #3
Flushing
Purge
FW
Pyrites Tank
Purge
Grlder Seal
Mill Rejects
Pressure Transfer
Hydrovac*
Bubblers
Cool Weirs
Pyrites Tank Make-wp
Flow Rate, gpm
1,960
600
1,960
600
1.960
600
1,960
1,500
2,660
2,660
8
515
1
4.604
4
540
640
Duration, minutes
73
15
60
20
47
15
3x8 each
3 x 15 each
12
8
180
7x6 each
210
270
continuous
continuous
12
*NOTE: Only significant Hem pertaining to fly ash handling.
other Items pertain to bottom ash handling.
All
120
-------
bottom ash 2,400-40,000 gal/ton ash conveyed
The relative percentages of bottom ash and fly ash depend upon the mode
of firing and the type of combustion chamber. Following figures are
satisfactory averages, for a coal of 13,000 Btu/lb.
Type of operation Fly ash (56 of total ash)
Pulverized coal burners
Dry bottom, regardless of type
of burner 85
Wet bottom 65
(without fly ash reinjection)
Cvclone furnaces 2 0
Spreader stokers
(without fly ash reinjection) 65
The number of variables involved in characterizing the water used for
ash handling is such that it is not probable that any two plants would
exhibit the same waste stream characteristics. The approach taken in
this report is to examine a cross section of plant data. There are no
data available on the actual ash sluicing waste water. However, since
most plants now employ a settling pond, the ash pond overflow data can
be used to evaluate associated waste water characteristics. These .data
are summarized in Table A-V-8.
In that table, plant capacities range from 31MW to 2533MW and the ash
pond overflow varies between 1817 M3/day (480,000gpd) and 122,946 M^/day
(32,473,000 gpd) .
Because of the large variation in quality of coal used in powerplants,
the data also show a wide variation in concentration of trace metals in
the effluent. Some of the metals discharged may be harmful to aquatic
life.
Oil
The ash content of fuel oils is low (about 1X of the amount commonly
found in coal). 278 It is generally 0.10 to 0.15X by weight, although
it may be as high as 0.2%.
The quantity of ash produced in an oil-fired plant is very small, but
the settling characteristics of oil ash are not as favorable as those of
coal ash. It has been found that in some cases recycling oil fly into
the furnance increases efficiency and eliminates the fly ash disposal
problem. Depending on the vanadium content of the oil, the dry bottom
ash can actually be a saleable by-product.
Most oil ash deposits are partially soluble and can be removed by water
washing. Generally the washing is done while the unit is out of
121
-------
TABLE A-V-8
CHEMICAL WASTE CHARACTERIZATION
ASH POND OVERFLOW -' NET DISCHARGE
CHANGE IN PARAMETER LEVEL FROM INTAKE TO DISCHARGE
Plant
Code
3412
3416
3404
3402
3401
3405
1703
1720
1710
1722
1709
1711
1711
*1711
3936
M 3936
to .
to *3936
3927
2616
1808
1729
1718
3930
3930
*3930
1825
1825
1825
1825
*1825
3920
1816
2608
0111
4704
2119
2119
*2119
0107
3514
1716
1716
*1716
Plant Capacity Fuel
HW
1114.5
740
300
308
31
116.2
766
1178
1162
1232
690
1179
1086
1469
933
732
186
1042
500
1304
544
600
510
1300
823
2558
568
2152
676
MWHr/day
13205
10525
5420
4965
865
1629
6288
161S5
3164
15563
0706
21872
18908
21705
14276
12050
2978
138S6
3816
24813
7695
10149
7550
18169
9874
31458
5741
11315
11092
C - Coal
0 - Oil
C/0
C
C/0
C/0
C
C/0
C
C
C/0
C
0
C
C
C
C
C
C
c/o
C
C
C
C
C
C
C
C
C
C
C
Flow
m3/day
19574
13100
2556
2726
9132
18.17
22716
49218
2726
98436
3786
32560
2650
35210
3786
22716
26502
5300
15901
15144
1817
53000
15144
3786
18930
37103
12115
6058
114
55390
27259
3786
5679
27782
15434
40694
82252
122946
2726
10865
1893
568
2461
(lOOOgpd)
5170
3460
675
720
2412
4.8
6000
13000
720
26000
1000
8600
700
9300
1000
6000
7000
1400
4200
4000
480
14000
4000
1000
5000
9800
3200
1600
30
14630
7200
1000
1500
7338
4076
10748
21725
32473
720
2870
500
150
650
mg/1
3560
-23
1879
54
-1338
-18509
-240
362
0
112
309
509
506
387
680
647
0
121
670
79
1124
1084
626
525
500
1000
300
1290
230
295.5
-1
475
61
182
-
414
324
Total Solids
(Ib/day)
153490
-663
10577
324
-26914
-745
-12008
39247
0
24284
2574.9
36506
2954
39460
3227
34026
37253
7552
0
4035
2680
9222
37491
9013
46504
51163
14011
6669
250.2
72093
18614
10757
2876
18084
- 34
42578
11052
53630
1093
-
1724.7
405.32
2129.39
kg/day
69688
-301
4802
147
-12219
-338
-5452
17818
0
11025
1169
16574
1341
17915
1465
15448
16913
3429
0
1832
1217
4187
17021
4092
21213
23228
6361
3028
113.6
32730
8451
4884
1306
8210 '
-15
19330
5017
24347
496.16
-
783
184.01
967
(Ib/MWHr)
11.62'
-0.064
1.952
0.065
-31.1
-0.457
-1.91
2.423
0
1.54
0.295
1.652
0.135
1.787
0.169
1.799
1.968
0.345
0
0.334
0.9
0.665
9.82
2.356
12.176
2.06
0.564
0.268
0.01
2.9031
2.41
1.06
0.362
0.9953
-.0034
1.3535
.3513
1-7048
0.1904
-
.1553
.0365
0.1928
kg/MWHr
5.272
-0.0292
0.886
0.0296
-14.12
-0.207
-0.867
1.1
0
0.7
0.134
0.075
0.061
0.0811
0.077
0.816
0.893
0.157
0
0.152
0.408
0.302
4.46
1.07
5.53
0.936
0.256
0.122
0.0045
1.319
1.098
0.481
0.164
0.4518
-.0016
.6145
.1595
0.7740
0.0864
-
.0705
.0166
0.0871
mg/1
3328
-110
1852
40
-1309
-18520
-129
330
108
106
328
486
499
447
650
620
0
364
646
75
1059
1081
611
435
460
500
-320
1210
225
-
-
-
-
193
844
445
277
Total
(Ib/day)
143495
-3174
10423
240.2
-26323
-741.41
-6453
35777
648.45
22984
2735
34856
2912
37768
2892
32524
35416
7237
0
12143
2586
8755
35328
9013
44341
49934
11608
6136
125.11
67803
-18614
10090
2812
-
-
-
-
-
1159
20201
1854
346.52
2200
Dissolved Solids
kg/day
65147
-1441
4732
109.04
-11951
-336.6
-2930
16243
294.4
10435
12417
15825
1322
17147
1313
14766
16079
3286
0
5513
1174
3975
16039
4092
20131
22670
5270
2786
56.8
30782
-8451
4581
1277
-
-
_
-
-
526
9171
842
157.32
999
(Ib/MWHr)
10.87
-0.308
1.92
0.483
-30.41
-0.455
-1.026
2.12
0.2048
1.475
0.3127
1.586
0.133
1.719
0.153
1.719
1.873
0.3326
0
1.006
0.868
0.632
9.25
2.356
11.606
2
-0.467
0.247
.00504
2.72
-2.398
0.994
0.354
_
_
_
_
_
0.2019
1.785
.1672
.0312
0.1984
kg/MWHr
4.929
-0.14
0.873
0.219
-13.81
-0.206
-0.465
1
0.093
0.67
0.142
0.72
0.06
0.78
0.069
0.78
0.85
0.151
0
0.457
0.394
0.287
4.2
1.07
5.27
0.91
0.212
0.112
0.00229
1.237
-1.098
0.4513
0.1607
_
_
_
_
_
0.0917
0.8098
.0759
.0142
0.0891
rag/1
91
40
27
14
1
11
-111
32
0
-1
-13
23
7
17
94
17
0
-243
51
1
65
3
15
85
35
100
-4
36
5
_
-
_
_
-11
-337
-7
69
Total Suspended Solids
(Ib/day)
3923
1154
152
84.05
20.11
0.44
-5552
3469
0
-216.7
-108.3
1647
40.86
1687.86
141.76
4702
4843.76
198.45
0
-8105
203.96
116.74
2167.4
25
2192.4
1224.67
2268
4669
25.02
8186
-300
300
62.53
-
_
_
_
_
-66.05
-8066
-29.07
86.319
57.25
kg/day
1781
524
69
38.16
9.13
0.20
-2521
1575
0
-98.4
-49.2
748
18.55
766.55
64.36
2135
2199.36
90.1
0
-3680
92.6
53
984
11.35
995.35
556
1030
212
11.36
1809
-136.3
136.3
28.39
_
_
_
_
_
-29.98
-17767
-13.2
39.188
26
(Ib/MWHr)
x 106
297100
112066
28044
16931
2323
270
-89867
213656
0
-13920
-12445
75110
1868
76978
7467
248678
256145
9141
0
-671800
68491
8266
567841
6555
574396
49339
91418
18819
1008
160584
-39017
29581
7868
_
_
_
-11504
-712900
-2621
7782
5161
kg/MWHr
x 10s
134800
50878
12732
7687
1055
123
-40800
97000
0
-6320
-5650
34100
848
34948
3390
112900
116290
4150
0
-305000
31095
3753
257800
2976
260776
22400
41504
8544
458
72906
-17714
13430
3572
_
_
-5223
-323400
-1190
3533
2343
*total of more than one waste stream for plant
-------
TABLE A-V- 8
CHEMICAL MASTE CHARACTERIZATION
acu D^MTI rnrRBS-T^id i
Plant
Code
3412
3416
3404
3402
3401
340S
1703
1720
1710
1722
1709
1711
1711
*1711
3936
3936
*3936
3927
2616
1808
1729
1718
3930
3930
*3930
1825
1825
.1825
1825
•1825
3920
1816
2608
0111
4704
2119
2119
*2119
0107
3514
1716
1716
•1716
Total ""^^nsaa fCfliCO* )
mg/1
736
25
-
-12
-
-252
-
99
255
357
220
110
207
335
275
-
-
388
51
340
350
406
250
200
270
-
-
0
283
-134.8
272.3
31.3
:
83
74
(Ib/day)
31733
1010
-
-72.04
-
-10.04
-
10731
55293
2975
15777
642
16419
1724
16762
18486
3209
-
-
1552
5953
11341
2918
14259
33182
6671
2668
67.55
42588
-
-
0
17319
-4582
24408
5671
30079
-
346
92.57
438
kg/day
14407
458.5
-
-32.71
-
-4.56
-
4872
25103
1351
7163
291.55
7454
783
7610
8393
1457
-
-
705
2703
5149
1325
6474
15065
3029
1211.5
30.67
19336
-
-
0
7863
-2078
11081
2574
13655
_
157.1
42.02
199
(Ib/MWHr)
x 106
2403000
98057
-
-14513
-
-6165
-
662995
3.546xl06
341409
720264
29361
749625
90969
886249
977218
147577
-
-
521445
429687
2970000
764860
3735000
1320000
268881
107541
2722
1699000
-
-
0
953233
-464000
775892
180278
956170
-
31057
8346
39403
kg/MWHr
x 106
1090000
44518
-
-6589
-
-2799
-
301000
1610000
155000
327000
13330
340330
41300
402357
443657
67000
-
-
236736
195078
1349000
347248
1696000
600000
122072
48824
1236
772132
-
-
0
432768
-210500
352255
81846
434101
_
14100
3789
17889
mg/1
152
2.2
120
8
-240
-996
45
-18
43
63
34
286
-26
158
201
60
123
128
527
98
220
300
180
225
314
132
-
200
28
93
61.5
-
-
-
129.9
446
230
-49
MRT nTcrHAiwns! (continued)
CHANGE IN PARAMETER IEVEL FROM INTAKE TO DISCHARGE
__gulfate Alupiimim Chromium
(Ib/day)
6554
63.48
675.5
48.01
-4826
-42.5
2251
-1951
258.19
13658
258.37
20513
-151.78
20665
1317
10057
11374
700
4308
4268
2109
11440
7339
2501
9840
14709
60044
4189
33.01
78975
-
1667
350.22
5691.5
2090.6
-
-
-
840.07
10675
959
-61.3
897.3
kg/day
2973
28.82
306.68
21.8
-2191
-19.3
1022
-886
117.22
6201
117.3
9313
-68.91
9244
598
4566
5164
318
1956
1938
957.5
5194
3332
1135.8
4467.8
6678
2726
1902
14.99
11321
-
757
159
2584
949
-
-
-
381.1
4846
435.4
-27.83
407.6
(lb,MWHr)
x 106
496300
6163
124378
9676
-5570000
-26165
357929
-120704
81497
876651
29515
936123
-6940
929183
69603
531749
601352
32158
301762
352420
708205
825674
1922907
655599
2578506
592511
241993
168841
1330
1004675
-
164097
44057
313253
211730
-
-
-
146328
943400
86343
-5526
80817
kg/MWHr mg/1
x 106
225100 0.075
2798
56468
4393
-2530000
-11879
162500 -
-54800 0.011
37000
398000 0.15
13400 0.1
425000 6
-3151 -0.145
421849
31600
241414
273014
14600 0.153
137000 1.67
160000
321525
374856 1.350
873000 0.021
297642 0.021
1070642
269000
109865
76654
604
456123
-
74500 6
20002
142217
96125
-
-
-
66433 5.30
428300 -
39200 -0.22
-2509 0.1
36691 -0.12
(Ib/day) kg/day
3.233 1.468
-
-
-
-
-
-
1.19 0.541
32.51 14.76
0.722 0.378
0 0
-0.8326 -0.384
-0.8326 -0.384
-
-
-
1.784 0.81
58.48 26.55
-
-
157.62 71.56
0.7 0.318
0.175 0.0795
0.875 0.3975
-
-
-
-
-
-
50 22.72
-
-
-
-
-
-
32.12 14.58
-0.916 -0.4160
0.125 0.0568
-0.791 -0.3592
(Ib/HWHr)
x 106
244
-
-
-
-
-
-
72.68
2070
94.71
0
-39.6
-39.6
-
-
-
81.49-
4097
-
-
11376
182.82
46.25
229.07
-
-
-
-
-
-
4912
-
-
-
-
-
-
5597
-81.49
11
-70.49
kg/HWHr
x iff
111
-
-
-
-
-
-
33
940
43
0
-18
-18
-
-
-
37
1860
-
-
5165
83
21
104
-
-
-
-
-
-
2230
-
-
-
-
-
-
2541
-37
5
-28
mg/1
-0.113
0
-
0.01
-
0.139
O.OOOO1
-O.O14
-
-
0
-0.03
0.0005
O.O07
O.O11
-
-
-
O.OO1
-
-
0.080
0.004
0.007
0.005
-
_
-
-
-
-
-
-
0
-
-
(li/day)
-4.86
0
-
0.059
-
0.0055
0.0005
-1.515
-
-
0
-O.174
-0.17
O.OO44
0.35
0.354
0.1277
-
-
-
0.116
-
-
_
6.54
0.105
0.092
0.001251
6.738
-
-
-
-
-
-
_
_
0
-
_
-
kg/day
-2.21
0
-
0.027
-
0.0025
0.00023
-0.688
_
-
0
-0.079
-O.079
O.O019
0.159
0.16O9
0.058
-
-
-
0.053
-
-
-
2.97
0.048
0.042
0.000568
3.O6
-
_
-
_
-
_
_
_
0
_
_
-
(Ib/MWHr)
xlO6
-368
0
-
11
-
3.407
0.079
-92.5
_
-
0
-8.8
-8.8
0.218
17.6
17.81
5.88
-
-
-
8.81
-
-
_
262
4.4
4.4
0.005
270.85
-
_
-
.
_
_
_
_
0
_
_
_
kg/MWHr
x 106
-167
0
-
5
-
1.547
0.036
-42
-
-
0
-4
-4
0.099
8
8.099
2.67
-
-
-
4
-
_
_
119
2
2
0.023
123.03
-
_
_
_
_
_
_
_
0
_
_
_
•total of more than one waste stream for plant
-------
TABLE A-V- 8
CHEMICAL WASTE CHARACTERIZATION
ASH POND OVERFLOW - NET DISCHARGE
Plant
3412
3416
3404
3402
3401
3405
1703
1720
1710
1722
1709
1711
1711
*1711
3936
3936
*3936
3927
2616
1808
1729
1718
3930
3930
*3930
1825
1825
1825
1825
*1825
3920
1816
2608
0111
4704
2119
2119
*2119
0101
3514
1716
1716
*1716
mg/1
0
-4
-
-
52
-1609
982
-
26
-
-3
173
30
32
73
14
-
-
3
92
88
27
23
18
37
-
-
23
-
-
-
-
-
-
-45
-136
-------
TABLE ArV-8
CHEMICAL WASIE CHARACTERIZATION
ASH POND OVFRFLOK'— NET P1SCHARGR
Plant
Code
3412
3416
3404
3402
3401
3405
1703
1720
1710
1722
1709
1711
1711
*1711
3936
3936
*3936
3927
2616
1808
1729
1718
3930
3930
*3930
1825
1825
1825
1825
*1825
3920
1816
2608
0111
4704
2119
2119
*2119
0107
3514
1716
1716
*1716
Chloride
mg/1
2415
-1
1700
13.5
-140
-
15
75
1
34
81
21
-16
35
51
161
2
1
41
8
120
120
30
29
32
152
-
41
-
-2.5
-43.7
-13.4
-16.4
-
73
163
26
(Ib/day)
104121
-28.85
9570
81.01
-2815
-
750.5
8130
6
7372
675.3
1506
-93.4
1412.6
291.85
2551
2842
1879
70.04
33.35
164.1
934
4002
1000
5002
' 2451
773.78
426.8
38.01
3689
-
341.4
-
-153
-1485
-1201
-2971
-4172
-
1747
679.6
32.52
712.1
kg/day
47271
-13.1
4345
36.78
-1278
-
340.74
3T691
2.726
3347
306.6
683.7
-42.4
641.3
132.5
1158.5
1291
853.3
31.8
15.144
74.5
424
1817
454.3
2271
1113
351.3
193.8
17.26
1675
-
155
-
-69.46
-674
-545.3
-1349
-1894
-
793.2
308.56
14.76
323.32
(Ib/MWHr)
x 106
7885000
-3215
1765918
16319
-3230000
-
119350
503295
1898
473678
77588
68859
-4271
64588
15431
134909
150340
86594
4907
2768
55101
67400
1049000
262240
1311000
98804
31189
17207
1533
148733
-
33480
-
-8421
-150449
-38183
-94458
-132641
-
-
61273
2932
64105
CHANGE IN PARAMETER IEVEL FROM INTAKE 1C
Copper
kg/MWHr mg/1 (Ib/day) kg/day (Ib/MWHr) kg/MWHr
x 10s x 106 x 106
3577000 -0.001 -0.043 -0.0196 -3 -1
-1460 0000 0
801727 - - - -
7409 -0.006 -0.0359 -0.0163 -6.6 -3
-1470000 -
-
54185 -
228496 - - - -
862 -
215050 - - - -
35225 0.02 0.166 0.075 18.94 8.6
31262 -
-1939 -
29323 -
7006 - - - -
61249 -
68255 -
39314 0.005 0.0573 0.026 2.62 1.19
2228 -
1257 -
25016 -Q.037 -0.148 -0.0672 -50.66 -23
30600 -
476226 -
119057 - - - -
595283 -
44857 -
14160 -
7812 - - - -
696 -
67525 -
_
15200 - - - -
_
' -3823 -
-68303 -
-17335 -
-42884 -
-60219 -
0.06 0.36 0.1635 62 28
_
27818 -
1331 -
29149 -
mg/1
-0.479
0.045
-
-4.6
-
-
-
0.6
-
0.28
0.001
0
-0.252
0.034
0.040
0.099
1.770
-
-0.593
-0.387
-
-
0.02
0.09
0.032
0.098
0.141
-
-
-
0.44
2.894
-
-
0.15
-
-
-
(continuted)
1 DISCHARGE
(Ib/day)
-20.65
1.297
-
-27.62
-
-
-
65
-
60.7
0.008326
0
-1.4978
-1.4978
0.2819
2.0
2.2819
1.15
61.98
-
-2.37
-45.8
-
-
-
1.634
2.4
0.4270
0.0245
4.4855
-
-
-
26.92
98.37
-
-
-
0.9
-
-
-
-
kg/day
-9.376
0.589
-
-12.54
-
-
-
29.53
-
27.56
0.00378
0
-0.68
-0.68
0.128
0.908
1.208
0.524
28.14
-
-1.077
-20.8
-
-
-
0.742
1.09
0.194
0.0111
2.037
-
-
-
12.22.
44.66
-
-
-
0.409
-
-
i-
-
(Lb/MWHr)
x 106
-1600
125.55
-
-5563
-
-
-
4008
-
3898
0.9559
0
-68.28
-68.28
14.98
105.72
120.70
52.86
4341
-
-797
-3306
-
-
-
63.87
96.9
17.6
0.984
179.35
-
-
-
1482
9963
-
-
-
32
-
-
-
-
Manganese
kg/MWHr mg/1 (Ib/day) kg/day (Ib/MWHr)
x 106 x 106
-726 -
57
_
-2626
-
_
_
1820 -
_
1770 0.02 4.34 1.97 277.5
0.434 0.0002 0.001652 O.OOO75 0.189
0 -
-31
-31 -
6.8 -
48
54.8 -
24 0.076 8.85 4.02 40.74
1971 - - -
_
-362 -
-1501 -
-
_
-
29
44
8 - - -
0.447 -
81.447 - -
-
-
_
673 -0.02 -1.224 -0.555 -68
4523 0.102 3.467 1.574 350
_
-
-
71
-
-
-
-
kg/MWHr
x 106
-
-
-
-
-
-
-
-
-
126
0.0861
-
-
-
-
-
-
18.5
-
-
-
-
-
-
-
-
-
-
-
-
_
-
-
-31
159
-
-
-
-
_
_
-
-
•total of more than one waste stream for plant
-------
TABIE A-V- 8
CHEMICA
Maqnes ium
ASH POND OVERFLOW - NET DISCHARGE (continued)
CHANGE IN PARAMETER I£VEL FROM INTAKE TO DISCHARGE
Mercury
3412
3416
3404
3402
3401
3405
1703
1720
1710
1722
1709
1711
1711
*1711
3936
3936
•3936
3927
2616
1808
1729
1718
3930
3930
*3930
1825
1825
1825
1825
*L825
3920
1816
2608
0111
4704
2119
2119
*2119
0107
3514
1716
1716
*1716
mg/1
156
-
-
-11
-
-
-
18
-
25
-
-3
10
15
14
21
0.1
-
-
-2
-
-
0
12
11
12
-
-
-
-3.8
-1.9
-
-
-
10
6
18
(Ib/day)
6724
-
-
-54.03
-
-
-
1951
-
5420
-
-215.6
58.37
-157.23
125.11
700
825.11
244.5
3.50
-
-
-233.48
-
-
-
0
320.26
146.76
2.99
470
-
-
-
-232.55
-64.58
-
-
-
-
239.36
25.02
22.52
47.54
kg/day
3053
-
-
-24.53
-
-
-
886
-
2461
-
-97.9
26.5
-71.4
56.8
318
374.8
111
1.59
-
-
-106
-
-
-
0
145.4
66.63
1.36
213.4
-
-
-
-105.58
-29.32
-
-
-
-
108.67
11.36
10.22
21.58
(Ib/MWHr)
x 106
509200
-
-
-10885
-
-
-
120704
-
348017
-
-9846
2669
-7177
6608
37037
43645
11233
3898
-
-
-16850
-
-
-
0
12907
5914
121.1
13942
-
-
-
-12800
-6542
-
-
-
-
21100
2247
2031
4278
kg/MWHr mg/1 (Ib/day) kg/day (Ib/MWHr) kg/MWHr mg/1
x 106 x 106 x 106
231600 - - - - - -0.054
- ' -
- _ -
-4942 - - -
_ _
_ _
- _
54800 - - -
- _
158000 0.0002 0.044 0.0197 2.77 1.26 0.01
- _
-4470 - - - - - -
1212 - - - - - -
-3258 - - -
3000 - - - - -
16815 - - - - - -
19815 - - -
5100 - - - - - 0.011
1770 - - - - - -
- - - - - - -
-0.002 -0.00793 -0.0036 -0.44 -0.2
-7650 - - - - - -
- - - - 0.015
- - - - - 0.008
-
0 - - - - - -
5860 - - - -
2685 - - - - - -
55 -
8600 - - -
- - - - -
- -
- - -
-5811 - - - - - -
-2970 - - -
- _
- - -
-
- 0 0 00 0 -
9600 - - - - -
1020 - - - - - -
922 - - - - - -
1942 - - -
(Ib/day) kg/day (lb/ MWHr) kg/MWHr mq/1
x 106 x 106
-2.32 -1.057 -175 -80 -0.014
- - - - 0.162
- - - - 0.00013
_
- - - - 0.17
- - - - 0.117
0
- - - - -0.073
- - - -
2.167 0.984 139.2 63.2 0.03
- - - - 0.011
-
_
-
- - - - 0.009
- - - - 0.009
_
0.1277 0.058 5.88 2.67 0.003
_
- - - - -0.01
- - _ _ •
- - - - 0.03
0.5 0.227 130.83 59.4 0.003
0.066 0.0302 17.62 8 0.013
0.566 0.257 148.45 67.4
- - - - 0.07
- - - - -0.007
- -0.006
- - - - o.ooi
-
- - - -
- - - -
- - - -
- - - -
- - - -
- - - -
- - - -
- - - -
- - - - 0.05
- - - -
- - - - 0.12
- - - - -0.02
- - - -
(lb/
-------
TABLE A-V- 8
CHEM
Plant
Code
3412
3416
3404
3402
3401
340S
1703
1720
1710
1722
1709
1711
1711
*1711
3936
3936
*3936
3927
2616
1808
1729
1718
3930
3930
*3930
1825
1825
1825
1825
*1825
3920
1816
2608
0111
4704
2119
2119
*2119
0107
3514
1716
1716
*1716
mg/1
_
-
0
0
-
-0.5
-0.33
-0.7
-
-0.09
-1.19
-0.7
0.1
0.2
0.14
0
0.26
0.08
-0.05
-
-
-
-
-
-
-0.09
0.41
-0.06
-'
-
-
-
-
-
-0.23
-0.23
(lb/day)
_
-
0
0
-
-0.02
16.5
-75.88
-
-19.51
-9.91
-50.22
-50.22
0.815
10
10.815
1.63
0
8.65
0.319
-5.83
-
-
-
-
-
-
-
-
-5.4
3.41
-0.749
-
-
-
-
-
-
-
-0.958
-0.280
-1.238
Ehosohori]
kg/day
_
-
0
0
-
-0.01
-7.49
-34.45
-
-8.86
-4.5
-22.8
-22.8
0.37
4.54
4.91
0.74
0
3.93
0.145
-2.65
-
-
-
-
-
-
-
-
-2.45
1.55
-0.34
-
-
-
-
-
-
-
-0.435
-0.13
-0.565
is /WIBr)
x 106
_
-
0
0
-
-10
-2623
-33480
-
-1253
-1136
-2290
-2290
41.8
528
569.8
74.89
0
718
107,93
-420
-
-
-
-
-
-
-
-
-702.6
337
-94.7
-
-
-
-
-
-
-
-85.9
26
-59.9
kg/MHHr
x 106
_
_
0
0
-
-5
-1191
-15200
-
-569
-516
-1040
-1040
19
240
259
34
0
326
49
-191
-
-
-
-
-
-
-
-
-319
153
-43
-
-
-
-
-
-
-
-39
12
-27
ASH POND OVERFLOW - NET DISCHARGE (continued)
CHANGE IN PARAMETER LEVEL FROM INTAKE TO DISCHARGE
Sulfite, lead. Oil and Grease,
.tv Phenols. Surfactants, AloicldeB
-5
13
-29
183
8
0
10
27
-14
1
-2
-22
-2.2
16.3
-13
-13
*total of more than one waste stream for plant
-------
service. In-service water washing at reduced loads has been practiced
to some extent, using the hot, high-pH boiler water in carefully
regulated amounts.
Limited data are available on the characteristics of oil ash handling
waste water. Table A-V-8 lists 6 plants which use both coal and oil,
but only one plant is listed using oil alone. No data are reported for
vanadium in waste streams. In certain cases, however, when other means
of collecting the vanadium are not available, the content of vanadium in
waste water should be evaluated, because of its possibly toxic effect on
aquatic life.
Coalpile Drainage
For coal-fired generating plants, outside storage of coal at or near the
site is necessary to assure continuous plant operation. Normally, a
supply of 90 days is maintained. These storage piles are typically 8 to
12 meters (25-40 ft) high spread over an area of several square meters
(or acres) . Typically from 600 to 1,800 cubic meters (780 to 2340 cu
yd) are required for coal storage for every MW of rated capacity. AS
such a 1000 MW plant would require from 600,000 to 1,800,000 cubic
meters (78,000 to 2,340,000 cu yd) of storage. Depending on coal pile
height, this represents between 60,000 to 300,000 square meters (15-75
acres) of coal storage area.
Coal is stored either in active piles or storage piles. Active piles
are open and contact of active coal with air and moisture results in
oxidation of metal sulfides, present in the coal, to sulfuric acid. The
precipitation trickles or seeps into coal piles. When rain falls on
these piles, the acid is washed out and eventually winds up in coal pile
runoff. Storage piles are sometimes sprayed with a tar to seal their
outer surface. In such cases, the precipitation runs down the side of
the pile.
Based on typical rainfall rates, pile runoff may range from 64,000 to
over 32,0000 cubic meters (17 to 85 million gallons) per year with
average figures around 75,000 to 100,000 cubic meters (20 to 26 million
gallons) per year. Table A-V-9 presents the amount of coal consumed per
day, area and height of coal pile, average rainfall and runoff from
various coal-fired generating plants across the country.
Liquid drainage from coal storage piles presents a potential danger of
stream contamination, if it is allowed to drain into waterways or to
seep into useful aquifers. Ground seepage can be minimized by storing
the coal on an imprevious base. Vinyl liners of various thicknesses
have been used for that purpose. To prevent the sharp edges of coal
particles from puncturing the liner, a 15 cm(6") bed of sand or earth is
placed on top of a liner before forming the coal pile.
128
-------
TABLE A-V-9
COAL PILE DRAINAGE
PLANT
ID
4701
4706
4702
4705
4703
2120
4704
2119
0112
5305
COAL CONSUMED/DAY
Ibs Kgs
xlO6 xlO5
15 6.81
31 14.07
15 6.81
27.6 12.53
20.6 9.35
25.4 11.53
14.34 6.51
47.6 21.6
35.8 16.25
-
AREA OF PILE
Acres M^
x!03
25 101.85
58 236.29
75 305.55
28 114.07
18 73.33
61 248.5
21 85.55
25 101.85
25 101.85
120 488.8
HEIGHT OF PILE
Ft. Meters
40 12.19
25 7.62
17 5.18
25 7.62
40 12.19
22 6.7
25 7.62
-
40 12.19
-
AVERAGE ANNUAL
RAINFALL
Inches Meters
44 1.117
-
54.7 1.389
-
45.84 1.164
-
43.1 1.094
44.4 1.1277
-
60 1.524
RUN -OFF PER YEAR
Million M3
Gallons xUQ^
20 75.7
-
25 94.62
-
25 94.62
-
17 64.34
22 83.27
26.5 100.3
-
-------
Water pollution associated with coal pile runoff is due to the chemical
pollutants and suspended solids usually transported in coal piie
drainage. Drainage quality and quantity is variable, depending on the
meteorological condition, area of pile and type of coal used. Areas of
high average rainfall have much higher drainage than those of low
average rainfall. Contact of coal with air and moisture results in
oxidation of metal sulfides to sulfuric acid and precipitation of ferric
compounds. High humidity areas have higher precipitation and produce
larger runoffs.
Coal pile runoff, like coal mine drainage, can be classified into three
distinct types according to chemical characteristics. The first type of
drainage will usually have a pH of 6.5 to 7.5 or greater, very little or
no acidity, and contain iron, usually in the ferrous state. Alkaline
drainage may occur where no acid-producing material is associated with
the mineral seam or where the acid is neutralized by alkaline material
present in the coal. Some alkaline waters have high concentration of
ferrous ion, and, upon oxidation and hydrolysis, precipitate large
amounts of iron.
A second type of drainage is highly acidic. This water contains large
amount of iron, mostly in ferrous state, and aluminum. l37
Coal pile runoff is commonly characterized as having a low pH (high
acidity) and a high concentration of total dissolved solids including
iron, magnesium and sulfate. Undesirable concentrations of aluminum,
sodium, manganese and other metals may also be present. Contact of coal
with air and moisture results in oxidation of the metal sulfides present
in the coal to sulfuric acid. Pyrites are also oxidized by ferric ion
to produce ferrous sulfate. When rain falls on these piles, the acid is
washed out and eventually winds up in the coal pile drainage. At the
low pH produced, other metals such as aluminum, copper, manganese, zinc,
etc. are dissolved to further degrade the water.
Although the exact reaction process is still not fully understood, the
formation of acid coal pile drainage can be illustrated by the following
equations. Initial reaction that occurs when iron sulfate and sulfuric
acid
2 FeS2+7 O2 +2 H2O = 2 FeSO4+2 H2SO4
Subsequent oxidation of ferrous sulfate produces ferric sul-
fate:
H F6SO4+2 H2SO4+O2 = 2Fe2(SO4)3+2 H2O
Depending on physical and chemical conditions, the reaction
may then proceed to form ferric hydroxide or basic ferric
sulfate:
130
-------
Fe2 (SOU) 3+6H20 = 2Fe (OH) 3+3H2SO4
and/or
Fe2(S04) 3+2H20 = 2Fe (OH) (SO4) +H2SO4
Pyrites can also be oxidized to ferric ions as shown below:
FeS2*1t Fe+3=8H2O =15
Regardless of the reaction mechanism, the oxidation of one mole of
pyrite ultimately leads to the release of two moles of sulfuric acid
(acidity) .
Other constitutents found in coal pile drainage are produced by
secondary reactions of sulfuric acid with minerals and organic compounds
present in the coal, such secondary reactions are dependent upon type
of coal and physico-chemical conditions of the pile.
The pollution of streams by coal-pile runoff may be attributed to higher
concentration of dissolved solids, mineral acid, iron, and sulfate
present in the runoff. In addition, aluminum, copper, zinc and
manganese may be present. The degree of harm caused by these elements
is compounded by synergism among several of them; for example zinc with
copper. The harmful effects of iron, copper and zinc solutions can be
greater in the acid water polluted by coal pile drainage than in neutral
or alkaline water. Data reported from various plants are shown in Table
A-V-10. An inspection of these data reveals an extremely large
variation in the pollutant parameters listed. The concentration of
runoff is dependent on the type of coal used, history of the pile and
rate of flow. Plant nos. 1729, 3626 , and 0107 using high sulfur coal
are highly acidic (low pH) , and have high sulfate and metallic
concentrations.
The acidity, - sulfate and metal concentrations of plant no. 3505 which
uses very low sulfur coal are very small. The concentration of
pollutants during heavy rainfall will be very small after an initial
removal of precipitated material from coal, while during low flow
conditions the retention time may be high enough to complete oxidation,
resulting in higher runoff concentrations.
Floor and Yard Drains
The floor drains within a powerplant generally include dust, fly ash,
coal dust (coal- fired plants) and floor scrubbing detergent. This waste
stream also contains lubricating oil or other oils which are washed away
during equipment cleaning, oil from leakage of pump seals, etc., and oil
collected from spillage around storage tank area.
No data regarding the flow 'and composition of this waste stream have
been reported, however, oil, suspended solids, and phosphate from floor
scrubbing detergent may be present in the floor drains. The discharge
131
-------
TABLE A-V-10
A B C
Plant
Line Code Alkalinity BOD
mg/1 mg/1
1) 3402 6 0
2) 3401 0 0
3) 3936 0 10
4) 1825
5) 1726 82 3
6) 1729
7) 3626
8) 0107 0
9) 5305 21.36
10) 5305 14.32
11) 5305 36.41
A B C
Plant
Line Code Copper Iron
mg/1 mg/1
1) 3402 1.6 0.168
2) 3401 1.6 0.168
3) 3936
4) 1825 - 0.06
5) 1726
6) 1729 - 0.368
7) 3626 1.8 4700
8) 0107 3.4 93000
9) 5305 - 1.0
10) 5305 - 1.05
11) 5305 - 0.9
D E F
COD TS IDS
mg/1 mg/1 mg/1
1080 1330 720
1080 1330 720
806 9999 7743
85 6000 5800
1099 3549 247
-
28970
45000 44050
_
-
Discharqe Concentrations
D E
Maqnesiuni Zinc
mg/1 mg/1
1.6
1.6
89 2.43
174 0.006
0.08
-
12.5
23
-
-
-
G
TSS
mg/1
610
610
22
200
3302
-
100
950
-
-
F
Sodium
mg/1
1260
1260
160
-
-
-
-
-
-
-
-
H
Ammonia
mg/1
0
0
1.77
1.35
0.35
-
-
-
-
-
G
pH
pH
2.8
2.8
3
4.4
7.8
2.7
2.1
2.8
6.7
6.6
6.6
Discharqe Concentrations
Nitrate Phosphorus Turbidi
mg/1 mg/1 mg/1
0.3 - 505
0.3 - 505
1.9 1.2
1.8
2.25 0.23
-
_
_
8.37
2.77
6.13
mg/1
mg/1
130
130
1109
1850
21700
27310
8.68
10.25
8.84
525
525
5231
861
133
6837
19000
21920
3.6
3.6
481
1200
825
mg/1
0
0
0.37
0.05
15.7
0.3
-------
stream will be acidic if any wash water from air preheater or fireside
of the boiler winds up in floor drains.
Air Pollution Control
A number of processes have been proposed for removing particulate and
S02 emissions from stack gases 4S. Some of these processes have been
suggested for potential application in fossil-fuel powerplants 1*1,220.
In general the SO2 removal processes can be categorized as follows: *23
(1) Alkali scrubbing using calcium carbonate or lime
with no recovery of SO^.
(2) Alkali scrubbing with recovery of SO2, to produce
elemental sulfur or sulfuric acid. ~
(3) Catalytic oxidation of SO2 in hot flue gases to
sulfur trioxide for sulfuric acid formation.
(4) Dry-bed absorption of SO2 from hot flue gases
with regeneration and recovery of elemental sul-
fur.
(5) Dry injection of limestone into the boiler furnace
for removal of SO2 by gas-solid reaction.
The removal of particulate from stack gases can also be carried out
separately - using an electrostatic precipitator or a dry mechanical
collector, "Wet" scrubbing for SO2 removal can be applied subsequently.
The waste water problems are mainly concerned with "wet" processes
(first three types mentioned above) . Wastewater' problems associated
with particulate (fly-ash) removal devices are described in an earlier
portion of this section of the report.
At present the "wet" processes - alkali scrubbing with and without SO2
recovery, oxidation of SO2 for sulfuric acid production - are mainly in
pilot plant or prototype stage of development. Of the three processes,
sufficient data is available only for the alkali scrubbing process
without SO2 recovery, and consequently only this process is described
briefly in the following paragraph.
Flue gas from electrostatic precipitators (optional equipment) is cooled
and saturated by water spray. It then passes through a contacting
(scrubbing) device where SO2 is removed by an aqueous stream of lime
absorbent. The clean gas is then reheated (optional step) and vented to
the atmosphere through an induced draft fan if necessary. The lime
absorbent necessary for scrubbing is produced by slaking and diluting
quicklime in commercial equipment and passing it to the delay tank for
recycle as a slurry through the absorber column(s). Use of the delay
133
-------
tank provides sufficient residence time for the reaction of dissolved
SO2 and alkali to produce calcium sulfite and sulfate. The waste
sulfite/sulfate is them pumped as a slurry to a lined settling pond or
mechanical system where sulfite is oxidized to sulfate. The clear
supernatent liquid is returned to the process for reuse. The waste
sludge containing fly ash (if electrostatic precipitator is not
employed) and calcium sulfate is sent for disposal (as a landfill).
The process described above suffers from potential scaling problems.
The calcium salts tend to form a deposit, causing equipment shutdown and
requiring frequent maintenance.
The process is a closed loop type and consequently there is a no net
liquid discharge from the process. The disposal of sludge has been
covered in the literature 16». However, depending upon the solids
separation efficiency in a pond or mechanical equipment-, there may be
excess free water associated with the sludge. To dewater this sludge,
mechanical filtration equipment may be necessary.
To date eleven utilities have committed themselves to fullscale
installation of the alkali scrubbing process without SO.2 recovery 2".
During the course of the present study, visits were made to two plants
for observing the scrubbing devices. However, in plant no. 1720, the
scrubber was not running because of operational problems. The process
for the other plant (no. 4216) is described in this section.
Plant no. 4216 of 79 MW capacity burns 0.7X sulfur coal. The boiler
gases are split into two streams - approximately 7558 going to a scrubber
and the remaining 25% going to an electrostatic precipitator. The
exhaust gases from the two are then recombined and vented to atmosphere
at 210°F. This splitting of the boiler gases is done to reheat the
scrubber exhaust gases which are at 124°F (saturated) . This stack gas
reheating is achieved to minimize scaling problems from moist gases.
The scrubber is not specifically used for SO2 removal. Rather, the
primary function is to remove particulates. On the other hand, some S02
pick-up is achieved. This is evident from Figure A-V-8 where the net
output from the process (thickener underflow) is richer in sulfate than
the process input (river water) . The flow diagram and the different
stream compositions are shown in Figure No. A-V-10.
Miscellaneous Waste Steams
The operations and the waste streams described earlier are centered
around meeting the steam generating boiler requirements. Besides these
chemical waste streams, there are also miscellaneous waste streams
originating in a steam electric plant. These waste streams are
described in the remainder of this section.
134
-------
"ST/ICK 64SES
~65GPM_
STEAM TO TURBINES
»
i
^270,000 JCFH
BOILER
179 MW PLANT)
L J"LJiE^A^f s«- J
~"
JNLCT
SCRUBBER LIQUOR
TJQ1 £; IN TUI5 PLANT
OFTHF'
FLUE GASES GO THROOSff
THE-ELECTROSTATICL PRBCIHTATOR
AND NOT THROUGH THE
SCRUBBER
-3500 GPM
OVERFLOW
RIVER WATER
-160 GPM
MAX
LI ME SLURRY
3-5 GPM
FLYASH FRCM
4505PM PRECIR1TATOR
_ AND SERVICE
-pH" WATER DISCHAffSES
SETTUNS
POKP
-50OGPM
t
TO "RTWR
LOSS TO SOU.
STREA
W1METIR
PH
Acioirr PP
ALMUN/Tr/ho
HARDNETSS
5ULFATE
SULFITE
ns DRY we
TS5
M*
UNIT
INPPfl
-'
GCO,
C-C03
CoCOj
504
S03
PPM
PPM
1
.JNLET
ifflJBBEK
WATER
2.0
3900
O
1950
4095
-------
Sanitary Wastes
The amount of sanitary waste depends upon the number of employees. This
in turn is dependent upon the type of plant—coal, oil, or gas, its size
and its age. A powerplant employs administrative personnel and plant
personnel (plant crews and maintenance personnel). Coal-fired plants
require more operational personnel then others. For a coal- fired
plant, the breakdown in types of employees is typically as follows:
operational personnel: 1 per 20-40 Mw
maintenance personnel: 1 per 10-15 Mw
administrative personnel: 1 per 15-25 Mw
A typical three boiler 1,000 MW coal-fired plant may employ 150-300
people. Whereas, in a oil plant of similar size, the total number of
employees may be in the range of 80-150.
The typical parameters which define the pollutional characteristics of
sanitary wastes are BOD-5 and suspended solids. The following table
lists per capita design estimates for the waste stream:
FLOW BOD-5 TSS
Office/Admin. 0.095m3/day 30 g 70 g
(25 gpd) (0.07 Ib) (0.15 Ib)
Plant 0.133 m3/day 40 g 85 g
(35 gpd) (0.09 Ib) (0.19 Ib)
Knowing the number of personnel in the office/administrative and plant
categories, the characteristics of the raw sewage waste stream can be
estimated. Typically, for an oil-fired plant generating 1,000 MW the
personnel required might be 20 office and administrative, and 85 plant
personnel. The raw sewage characteristics for this plant can be
estimated on the basis presented above as follows:
FLOW BOD-5 TSS
Office/Admin. 1.890 m3/day 635 g 1360 g
(500 gpd) (1.40 Ib) (3.00 Ib)
Plant 1.125 mVday 3480 g 7330 g
(2975 gpd) (7.65 Ib) (16.15 Ib)
Total 3.015 m3/day 4115 g 8690 g
(3475 gpd) (9.05 Ib) (19.15 Ib)
The sanitary waste from steam electric powerplants is generally similar
to municipal sanitary wastes with the exception that powerplant wastes
do not normally contain laundry or kitchen wastes. Moreover, the per
capita hydraulic loading for powerplant personnel is relatively small
(25 to 35 gallons) in comparision to domestic usage (100 to 150
136
-------
gallons). Normally the local health agencies dictate requirements for
treating sanitary wastes. In metropolitan areas, the raw sewage may be
discharged to a municipal treatment plant. In rural areas, packaged
treatment plants for sanitary wastes may be employed.
plant Laboratory 6 Sampling Streams
Laboratory facilities are maintained in many steam electric powerplants
to carry out chemical analysis for checking different operations such as
ion exchange, water treatment, boiler tube cleaning requirements, etc.
The size of the laboratory depends upon the size, type, and age of the
plant. Modern high pressure steam plants require closer control on the
operations and consequently increased laboratory activity. In nuclear
plants the use of a laboratory is extensive.
The waste from laboratories vary in quantity and constituents, depending
upon the use of the facilities and the type of powerplant.
Intake Screen Wash
Powerplants require water for various operations. Plants using once-
through type condenser cooling systems draw the cooling water from a
waterbody such as an ocean, a lake, a river, etc. On the other hand,
plants using a recirculating condenser cooling system need less water
intake than the once-through types. Depending upon the water require-
ments and the source of intake water, traveling screens are used to
prevent river debris, fish, leaves, etc from entering the intake system.
The accumulated debris is collected and the screens hosed down to
prevent plugging.
Service Water System
Service water systems supply water which is used for such house services
as bearing and gland cooling for pumps and fans, auxiliary cooling and
heat exchangers, hydrogen cooler and fire pumps. In many cases toilet
and potable water is included in this category.
Basically, there are two types of service water systems. Once-through
service water systems are most common. In these types raw water with no
treatment chemical is added. These types of systems are operated in
parallel to the condenser cooling water system. Raw water is used and
no continuous treatment is practiced, occasional shock chlorination is
given to similar levels as with condenser cooling water. Chlorination
treatment is, however, much less frequent. Many nuclear plants
integrate the emergency core cooling system with a once-through service
water system. Once-through service water systems can be used
exclusively or in conjunction with closed-loop recirculatory systems.
With recirculatory systems the makeup can be supplied from either raw or
city water. This makeup is pretreated to a high degree of purity. This
closed loop recirculatory water is treated to a high degree to prevent
137
-------
corrosion within the system. In general, chromates are used in
conjunction with caustic soda for control of pH at 9.5 to 10 up to
levels of 250 ppm. Borate-nitrate corrosion inhibition treatment is
also used to levels of between 500 to 2,000 ppm. Generally, there is
little or no loss from these closed-loop systems. The only occasions
when water loss can occur are during maintenance or occasionally if the
system has to be drained for cleaning, which although infrequent can
occur at a three year frequency.21
Service water requirements cover a wide range. For once-through systems
water flows range from 0.5 to 35 gpm per MW of rated plant capacity.
Typically, the flow is 10 to 11 gpm per MW of rated capacity. Where
closed-loop systems are operated a figure of 22 to 23 gpm per MW of
rated capacity is typical. On this basis, closed-loop blowdown can
typically be 5 gallons per day with a settleable solids content of 1 to
2 ppm.21 Service water requirements of plant no. 4251, a nuclear unit of
851 MW using 480,000 gpm of main condenser cooling water, are as
follows:
Primary plant component cooling water 5,800 gpm
Secondary plant component cooling water 16,000 gpm
Centrifugal water chiller 3,000 gpm
Control room air conditioner 210 gpm
Construction Activity
There are liquid wastes associated with on-site construction activities.
Such wastes will depend upon the type and size of construction and the
location.
Generally, waste water resulting from construction activity will consist
of storm water runoff from the site during the course of construction.
This stream can be characterized by suspended solids and turbidity
resulting from the erosion of soil disturbed by the construction
activity.
Low Level Rad Wastes
The radioactive waste handling system is beyond the scope of this study.
Some of the low level rad wastes from a nuclear powerplant contain boron
and therefore can also be considered as chemical wastes. Consequently,
a brief description of the waste handling systems in a nuclear power-
plant is included. The sources of radioactive wastes are the reactor
coolant and spent fuel coolant and the various systems with which these
coolants come into contact. In general, the radioactive fluids are
treated by filtration, ion exchange, and distillation. The fluids are
then either recycled for use in the plant or diluted with condenser
cooling water for discharge to the environment.
138
-------
Most commercial nuclear powerplants in the country are either
pressurized water reactors (PWRs) or boiling water reactors (BWRs). In
a pressurized water reactor, the primary coolant is maintained at a
pressure (2,200 psi) sufficient to keep it from boiling. After the
primary coolant is heated in the reactor, it flows through the tube side
of large heat exchangers generating steam on the shellside. This steam
is used to drive the turbine and is then condensed and returned to the
steam generator thrcugh a series of preheaters. Thus, in a PWR, the
primary coolant is isolated from the steam-condensate system. However,
some leakage through defects in steam-generator tubes may occur
resulting in contamination of the steam-condensate system. There are
several other fluid systems which may be contaminated. In a PWR, boron
is used in the primary coolant to help control reactivity. As the fuel
burn-up progresses, the boron concentration is lowered by feed and bleed
of reactor coolant.
Two systems are associated with this process. The first system, which
is sometimes called the chemical and volume control system (CVCS) , is on
stream at all times and is used to control the radioactivity chemistry
and volume of reactor coolant. Reactor coolant is continously bled from
the primary system into the CVCS where it usually passes through filters
and ion exchangers. The coolant can then be returned to the reactor or
diverted to the second system to allow addition of water with a
different bcron concentration to the reactor through the CVCS. The
second system can be labeled the boron management system (BMS). It
processes the reactor coolant letdown after it has passed through the
CVCS ion exchangers. Processing in the BMS usually includes gas
stripping to remove hydrogen and the radioactive noble gases, ion
exchange, and distillation. The distillate may be recycled for use as
reactor coolant or diluted with condenser cooling water for discharge to
the environment. The concentrated bottoms from the distillation process
are either recycled as boric acid for use in the reactor coolant or
mixed with cement and placed in drums or larger containers for shipment
to a solid radioactive waste burial site.
Provisions are made so that after reactor shutdown it is possible to
cycle reactor coolant through ion exchangers prior to flooding the
reactor area and fuel transfer canal with water from the refueling water
tank. However, there is still some residual activity in both the
refueling water tank and the fuel storage pools. Thus, it is possible
that refueling water, spent fuel coolant, new fuel pool water and
secondary coolant are contaminated as well as reactor coolant and let-
down. Also, the fluids used to transfer or regenerate resins in any of
the systems mentioned above may be contaminated. Therefore, all leaks
and resin-handling and regeneration fluids from these systems are
collected and processed in a radioactive waste management system (WMS) .
This WMS also uses filtration, ion exchange, or distillation or a
combination of the three to produce very low activity water suitable in
most cases for discharge to the environment. Because the WMS processes
139
-------
a wide variety of liquids, some of which may be contaminated with oil or
other undesirable substances, the WMS effluent is generally not
recycled. Figure A-V-11 shows a block diagram of the liquid radioactive
waste management system for a PWR.
In BWRs, the reactor coolant is itself boiled and thus flows through the
steam condensate system. The condensate is usually heated and returned
to the reactor. The solutions produced in handling or regenerating the
ion exchange resins constitute the major radioactive liquid waste in a
BWR. In addition to the equipment for "polishing condensate" a system
is provided for filtering and demineralizing the reactor coolant. This
system, called the reactor water cleanup system (RWCS) , takes coolant
from the reactor vessel, cools it, filters and demineralizes it and
returns it to the reactor coolant system, thus controlling nonvolatile
corrosion products and impurities in the reactor water. Because no
boric acid is used in the reactor water under normal circumstances there
is no feed and bleed operation for boron concentration control and
consequently no boron management system.
As in the PWR, the water for refueling also becomes contaminated and any
leakage of refueling water as well as any leakage and resin regenerating
or transporting fluids and filter backwash (from any of the contaminated
systems discussed above) is collected and treated. Treatment of wastes
in a BWR also includes filtration, ion exchange, and distillation. The
exact design of the systems vary from plant to plant; however, from the
liquid radioactive waste point of view, BWRs may be placed in. two
categories: (1) those which use disposable ground resin in filter de-
mineralizers for condensate polishing, and (2) those which use resin
regenerable in deep bed demineralizers. In general, it appears that the
former system is favored except where saline cooling water is used.
The use of regenerable resin means that large volumes of regenerant
solutions have to be processed every day. The processing usually
involves the use of large evaporators with total through-put capacity on
the order of 0.0025 M3/s (40gpm) or more for some plants. The
distillate from these evaporators is generally sent to high-purity waste
system for further treatment by ion exchange. About 90% of the effluent
of this high-purity waste system is recycled for use in the reactor and
10X discharged.
In those plants which use ground resin units for condensate polishing,
no regeneration takes place since water is used only to transport the
powder. Thus, considerably less fluid has to be treated and, since the
radionuclides are not dissolved into the water, only mechanical separa-
tion such as settling, filtration and centrifugi^ig is used for initial
treatment of the water. Again the water is sent to a high-purity waste
system where it is treated by ion exchange and the bulk of the water is
recycled for use in the reactor with the remainder discharged into the
cooling water.
140
-------
LIQUID RADIOACTIVE WASTE HANDLING•SYSTEM
PWR NUCLEAR PLANT
FIGURE A-V-H
-------
BWRs usually use ground resin filter demineralizers in the RWCS and the
liquid from transporting ground resin in the RWCS is treated in the same
way as that used for ground resin condensate polishers.
Other liquid wastes from BWRs are treated by ion exchange, evaporation,
and filtration. Other sources of wastes are floor drains and laundry
drains (including personnel decontamination and cask cleaning).
Distillates from evaporation of these waste are generally discharged to
the environment. Concentrated bottoms from evaporators and solids from
dewatering equipment are drummed for off-site shipment. Figure A-V-12
shows a block diagram of the liquid radioactive waste handling systems
of a BWR of 1,100MW capacity.
It is difficult to establish the exact amount of liquid which will be
released by the radioactive waste handling systems of a power reactor.
The number and type of shutdowns and load changes the amount of leakage
from various systems, and the degree of recycle of processed waste all
affect the quantities of liquid discharged. However, in the process of
obtaining licenses for construction and operation of a nuclear
powerplant, estimates are made of these releases based on expected
operating conditions. A review of several Environmental Impact
Statements for PWRs and BWRs indicates a range of effluent quantities
which are expected to be discharged.
PWR wastes processed in the BMS are usually of high enough quality to be
recycled. In general, the distillate from BMSs contains concentrations
much lower than 1 mg/1 of all chemicals other than boric acid which is
present at a maximum concentration of 60 mg/1. The anticipated
quantities of BMS discharge for a sampling of PWRs ranges from 0 to over
5,000,000 gallons per year. The quantity of distillate discharged from
the BMS depends on the operating mode of the plant (i.e. base loaded or
load following) , number of shutdowns and the degree of distillate
recycling.
Distillate from the WMS can generally be expected to have the same
chemical purity as that from the BMS although it may occasionally
contain a few mg/1 of sulfates and chlorides resulting from processing
condensate polisher regenerants during primary to secondary leaks.
Some of the fluids routed to the WMS are not necessarily treated by the
radwaste evaporator. These wastes are expected to be of such low
activity that they will be filtered, monitored, and then treated as
conventional wastes. The quantity of liquid discharged from the WMS of
a PWR can vary widely. For example, during a primary to secondary leak,
plant condensate polishers may process the polisher regenerants through
the WMS. While this means that millions of gallons of distillate may be
discharged from the WMS, it doesn't add to overall plant waste
discharged since the regenerants would have to be processed and
discharged at nearly the same rate by chemical treatment system in the
event there were no primary to secondary leak.
142
-------
REACTOR)^
i—r
CLEAN-UP SYSTEM
FILTERS-
OEUIKERALIZERS «l
POWOEX PHASE
SEPARATORS (4)
1 I
TURBINE
CONDENSER
CONDENSATE
DEMINERALIZERS (6)
CONDENSATE
STORAGE
TANKS (2)
400.000 gal.
LOW CONDUCTIVITY WASTE
EQUIPMENT DRAINS FROM
DRY WELL. RE ACTOR BUILDING
AND TURBINE BUIlttlNG ETC.
HIGH CONDUCTIVITY WASTE
FLOOR DRAINS FROM
DRY WELL ANO REACTOR.
TURBINE. AND RADWASTC
BUILDINGS. ETC.
CHEMICAL WASTE
LABORATORY DRAINS
SAMPLE DRAINS. ETC
DECONTAMINATION
DETERGENT WASTE
CASK CLEANING
PERSONNEL DECONTAMINATION
*
WASTE
COLLECTOR
TANK
2O.OOO gal.
COLLECTOR
TANK
20.000 gal.
• CHtMICAL.
WASTE
" TANKS (2)
• 13.000 gal.
DETERGENT
DRAIN TANKS
(21
l£00 gal
Iru real
•! FILTER H
X
HFILTER'I-
01 STILL ATE
13.000 gal
WASTE T „
WASTE SAM
TANKS I
I FLOOR DRAIN I
[ " DEMINERALIZERl
1
I
T A
— • WASTE
:ONCENTRATOR
(2)
S.S gpm
gal.
11%
FLOOR DRAIN
» SAMPLE TANK
2O.OOO gal,
SOLID WASTE
S DISPOSAL SYSTEM
SPENT RESIH
FILTER SLUDC
1 CENTRIFU
CONCENTRATED) „ DRUMMING
AND
E TANKS ~
SE AND
STATION
JA
DRUM
_^ WASTI
OFF-
DISPC
1
MSCHARG
TBiirnic
RADIATION
MONITOR
ONITOR 1
4,000 •»•
I INTAKE
rrrrr=^l STRUCTURE RT
—^-~— -- ~ COLUMBIA
LIQUID RADIOACTIVE WASTE HANDLING SYSTEM
1100 MW BWR NUCLEAR PLANT
FIGURE A-V-12
-------
As discussed above, the nature and quantity of liquid discharged by the
radioactive waste systems of a BWR differ greatly between units which
use ground resin condensate polishing and those which use conventional
ion exchangers. Even within a given type of plant there is a large
variation in techniques for handling the various wastes and the
anticipated discharge quantities vary considerably. For example one
plant using ground resin condensate polishers is expected to discharge
approximately 1.5 million gallons per year while another also using
similar polishers may discharge five times that amount.
Because of the treatment requirements for removing radioisotopes from
waste streams, it is expected that most discharges from radioactive
waste systems in BWRs will contain extremely low concentrations of
chemical pollutants.
Summary of Chemical Usage
Table A-V-11 lists chemicals used in steam electric powerplants
corresponding to various classes of uses.
Classification of Waste Waters Sources
Waste water sources can be classified as high-volume, intermediate-
volume, low-volume, or rainfall run-off. Table A-V-12 lists the
individual waste water sources according to the above classification.
144
-------
Table A-V-11
CHEMICALS USED IN STEAM ELECTRIC POWERPLANTS
Major source is Reference 21.
Use
Coagulant in clarification
water treatment
Regeneration of ion ex-
change water treatment
Lime soda softening
water treatment
Corrosion inhibition or scale
prevention in boilers
pH control in boilers
Sludge conditioning
Oxygen scavengers in boilers
Boiler cleaning
Regenerants of ion exchange
for condensate treatment
Chemical
Aluminum sulfate
Sodium aluminate
Ferrous sulfate
Ferric chloride
Calcium carbonate
Sulfuric acid
Caustic soda
Hydrochloric acid
Common salt
Soda ash
Ammonium hydroxide
Soda ash
Lime
Activated magnesia
Ferric coagulate
Dolomitic lime
Disodium phosphate
Trisodium phosphate
Sodium nitrate
Ammonia
Cyclohexylamine
Tannins
Lignins
Chelates such as EDTA,NTA
Hydrazine
Morphaline
Hydrochloric acid
Citric acid
Formic acid
Hydroxyacetic acid
Potassium bromate
Phosphates
Thiourea
Hydrazine
Ammonium hydroxide
Sodium hydroxide
Sodium carbonate
Nitrates
Caustic soda
Sulfuric acid
Ammonex
Use
Corrosion inhibition or scale
prevention in cooling towers
Biocides in cooling towers
pH control in cooling towers
Dispersing agents in
cooling towers
Biocides in condenser cooling
water systems
Additives to house service
water systems
Additives to primary coolant
in nuclear units
Numerous uses
Chemical
Organic phosphates
Sodium phosphate
Chromates
Zinc salts
Synthetic organics
Chlorine
Hydrochlorous acid
Sodium hypochlorite
Calcium hypochlorite
Organic chromates
Organic zinc compounds
Chlorophenates
Thi ocyanates
Organic sulfurs
Sulfuric acid
Hydrochloric acid
Lignins
Tannins
Polyacrylonitrile
Polyacrylamide
Polyacrylic acids
Polyacrylic acid salts
Chlorine
Hypochlorites
Chlorine
Chromates
Caustic soda
Borates
Nitrates
Boric acid
Lithium hydroxide
Hydrazine
Numerous.proprietary
chemicals
-------
Table A-V-12
CIASS OF VARIOUS WASTE WATER SOURCES
Class
Source
High Volume
Nonrecirculating main condenser
cooling water
Intermediate Volume
Nonrecirculating house service water
Slowdown from recirculating main
cooling water system
Nonrecirculating ash sluicing systems
Nonrecirculating wet-scrubber air
pollution control systems
Low Volume
Clarifier water treatment
Softening water treatment
Evaporator water treatment
Ion exchange water treatment
Reverse osmosis water treatment
Condensate treatment
Boiler blowdown
Boiler tube cleaning
Boiler fireside cleaning
Air preheater cleaning
Stack cleaning
Miscellaneous equipment cleaning
Recirculating ash sluicing systems
Recirculating wet-scrubber air
pollution control systems
Intake screen backwash
Laboratory and sampling streams
Cooling tower basin cleaning
Rad wastes
Sanitary system
Recirculating house service water
Floor drainage
Miscellaneous streams
Rainfall Runoff
Coal pile drainage
Yard and roof drainage
Construction activities
146
-------
PART A
CHEMICAL WASTES
SECTION VI
SELECTION OF POLLUTANT PARAMETERS
Definition of Pollutants
Section 502(6) defines the term "pollutant" to mean dredged spoil, solid
waste, incineratior residue, sewage, garbage, radioactive materials,
heat, wrecked or discarded equipment, rock, sand, cellar dirt and
industrial, municipal and agricultural waste discharged into water.
This report addresses all pollutants discharged from steam electric
powerplants with the exception of both high-level and low-level
radioactive wastes of nuclear powerplants. The exclusion is made for
two reasons: (1) administratively, the permiting or licensing authority
for nuclear plants, from the standpoint of radiation safety resides with
the U.S. Atomic Energy Commission; and (2) it is not known that the
application of conventional waste water treatment technology for the
control of non-radiation aspects of radioactive waste will not result in
the creation of a radiation hazard (e.g. due to the concentration of the
suspended solids removed).
Introduction
Section A-V describes various operations in a steam electric powerpiant
which give rise to chemical wastes. Reported data were included for
each waste stream wherever available. The waste streams are specific to
each powerpiant and depend upon factors such as raw water quality, type
and size of plant, age of plant, ambient conditions and operator
preferences. Table A-VI-1 summarizes the pollutants present in the
various chemical waste streams based on data recorded in Section A-V,
Waste characterization, and knowledge of the respective processes. The
data in many cases show a wide variation from plant to plant. This wide
variation in data and the presence of many pollutants in a single waste
stream makes the selection of characteristic pollutants a difficult
task. Table A-VI-2 summarizes the number of plants for which data was
recorded in Section A-V for each waste stream.
Common Pollutants
Since powerpiant waste effluents are primarily due to inorganic
chemicals, the common pollutants reflect the general level of inorganic
chemical concentration.
147
-------
TABLE A-VI-1
APPLICABILITY OF PARAMETERS TO CHEMICAL WASTE STREAMS
PARAMETER
ALKALINITY
BOD
COD
TS
TDS
TSS
AMMONIA
NITRATE
PHOSPHOROUS
TURBID IT Y
FECAL COLIFORM
ACIDITY
HARDNESS, TOTAL
SULFATE
SULFITE
BROMIDE
CHLORIDE
FLUORIDE
ALUMINUM
BORON
CHROMIUM
COPPER
IRON
LEAD
MAGNESIUM
MERCURY
NICKEL
SELENIUM
VANADIUM
ZINC
OIL S GREASE
PHENOLS
SURFACTANTS
ALGICIDES
CHLORINE
MANGANESE
Conde
Cooli
Syste
Once
Through
X
x
X
X
x
x
riser
ng
m
Recircu-
latinq
X
X
X
x
y
x
y
Y
X
X
X
x
X
X
X
X
X
X
X
X
X
X
Water
Treatment
Clarifi-
cation Wastes
x
X
x
x
x
X
x
V
X
X
X
X
x
X
X
X
X
X
x
X
Ion Ex-
change Wastes
X
X
X
x
X
x
X
X
X
X
X
x
Evaporator
X
X
X
x
x
X
V
X
X
X
X
X
x
X X
x i x
X
X
X
X
X
X
X
X
X
x
X
Boiler
Blowdown
X
x
X
x
x
X
X
x
X
X
x
X
X
X
X
X
x
X
Chemical
Cleaning
Boiler
Tubes
X
x
X
X
x
x.
x
X
x
X
X
x
X
y
X
X
X
X
x
X
X
X
X
X
X
Air Pre-
heater
X
X
X
x
X
x
X
X
X
X
X
X
X
X
Boiler
F ires ide
x
X
x
x
x
X
X
X
X
X
X
X
X
X
X
x
X
Ash Pond
Overflow
X
x
X
X
x
x
X
X
X
X
X
X
X
X
x
X
X
X
X
X
x
x
X
x
X
X
x
X
X
Coal Pile
[ Drainage
X
x
x
x
x
X
X
Floor
Drains
X
x
X
X
x'
X
X
X
X
1
X
x
X
X
X
X
X
x
x
X
X
X
x
X
X
X _,
x
Air Pollution
S02 Removal
X
X
x
Y
X
X
X
X
X
X
X
X
X
X
x
x
X
1 Sanitary
Wastes
x
X
X
X
X
x
x
X
x
x
X
X
X
id w
K <1)
3 01
X
NOTE: Miscellaneous streams such as laboratory sampling, stack chemical cleanings, etc.
are not included since the species are accounted for in other streams.
148
-------
TABLE A-VI-2
CHEMICAL WASTES-
NUMBER OF PLANTS WITH RECORDED DATA
PARAMETER
ALKALINITY
BOD
COD
TS
TDS
TSS
AMMONIA
NITRATE
PHOSPHOROUS
TURBIDITY
FECAL COLIFORM
ACIDITY
HARDNESS, TOTAL
SULFATE
SULFITE
BROMIDE
CHLORIDE
FLUORIDE
ALUMINUM
BORON
CHROMIUM
COPPER
IRON
LEAD
MAGNESIUM
MERCURY
NICKEL
SELENIUM
VANADIUM
ZINC
OIL & GREASE
PHENOLS
SURFACTANTS
ALGICIDES
CHLORINE
MANGANESE
Condenser
Cooling
System
Once
Through
_
-
-
_
-
-
•
-
-
_
-
f
-
1
_
_
2
—
-
_
—
-
—
-
-
_
-
-
-
-
-
-
-
-
-
-
Recircu-
lating
6
4
4
4
6
5
5
6
9
-
-
6
11
-
-
10
2
1
-
4
1
5
-
6
-
1
-
-
5
-
2
-
—
-
3
Water
Treatnj
Clarification
Wastes
5
4
5
6
6
6
5
6
6
6
-
6
6
-
-
6
-
1
-
5
4
5
-
5
-
2
-
5
-
-
-
-
-
-
Ion Exchange
Wastes
12
12
12
16
18
16
15
17
20
7
-
15
23
-
-
21
-
-
-
14
8
13
-
17
2
.5
-
16
2
5
-
-
-
4
ent
Evaporator
5
7
7
8
9
8
7
7
9
5
-
7
7
-
-
8
-
-
-
8
5
5
-
6
2
2
-•
8
3
2
-
-
2
Boiler 1
Slowdown 1
17
18
17
17
18
17
15
14
19
10
-
11
16
-
-
17
-
-
-
11
7
8
-
6
-
5
-
13
-
5
-
-
-
-
Chemical
Cleaning
Boiler
Tubes
6
6
6
6
6
6
6
5
17
6
-
4
5
-
-
17
10
11
-
15
17
17
-
13
-
14
-
13
-
-
-
-
-
12
Air Pre-
heater
7
7
7
7
6
7
7
7
7
7
'-
7
7
-
-
7
-
-
-
7
5
7
-
7
-
7
-
7
-
-
-
-
-
-
Boiler
Fireside
2
2
2
2
2
2
2
2
2
2
-
2
2
-
'-
2
-
-
-
2
1
2
-
2
-
1
-
2
-
-
-
-
-
-
Ash Pond 1
Overflow |
27
-
-
28
26
26
21
21
18
12
-
19
27
-
-
25
-
12
-
12
7
16
-
15
2
4
-
16
-
-
-
-
-
5
Coal Pile 1
Drainage |
9
4
5
6
7
7
5
5
2
3
3
4
8
-
-
4
-
2
-
6
4
7
-
2
-
-
7
-
-
-
-
-
Floor
Drains
3
3
3
3
3
3
3
3
3
3
_
-
1
_
_
3
..
_
_
1
-
_
-
-
_
-
1
1
1
-
-
-
Air Pollution
Devices
SO2 Removal
1
-
-
-
1
1
-
1
1
_
_
1
2
2
_.
_
_
1
_
1
1
_
1
1
1
—
-
-
-
-
-
-
Sanitary
Wastes
-
-
-
-
-
-
-
_
_
_
•
_
_
_
_
_
_
_
_
_
—
_
—
-
_
_
-
-
_
-
-
-
TJ
(0 W
£ 0)
4-1
IS (0
SI
-
—
-
-
-
-
-
_
_
_
_
_
_
_
_
_
_
_
_
_
_
_
—
-
-
—
-
-
-
_
-
-
-
149
-------
pH Value
pH value indicates the general alkaline or acidic nature of a waste
stream, and represents perhaps the most significant single criteria for
the assessment of its pollutional potential. While a pH in the neutral
range between 6.0 and 9.0 does not by itself assure that the waste
stream does not contain detrimental pollutants, a pH outside of this
range is an immediate indication of the presence of potential
pollutants.
Total Dissolved Solids
Total dissolved solids represents the residue (exclusive of total
suspended solids after evaporation and includes soluble salts such as
sulfates, nitrates, chlorides, and bromides. Total dissolved solids are
particularly significant as a pollutant in discharges from closed
systems which involve recirculation and re-use. These systems tend to
concentrate dissolved solids as a result of evaporation and require
blowdown to maintain dissolved solids within ranges established by
process requirements. The blowdown may contain specific pollutants in
detrimental amounts depending on the number of cycles of concentration.
Total Suspended Solids
Total suspended solids is another pollutant which is a characteristic of
all the waste streams. Suspended solids are significant as an indicator
of the effectiveness of solids separation, devices such as mechanical
clarifiers, ash ponds, etc. One of the functions of water use in a
powerplant is to convey solids from one stage of the process to another
or to a point of final disposal. Some processes used in a powerplant
create suspended solids by chemically treating compounds in solution so
that they become insoluble and precipitate. Turbidity is related to
suspended solids but is a function of particle size and not an
independent pollutant.
Having established the three common pollutants, the characteristic
pollutants of individual waste streams are outlined below.
Pollutants from Specific Waste streams
Biochemical Oxygen Demand (BOD - 5 day)
BOD is a significant pollutuant only for sanitary waste water
originating from the use of sanitary facilities by plant personnel.
Chemical Oxygen Demand (COD)
COD is a pollutant usually attributed to the organic fraction of
industrial waste waters, since steam electric powerplants do not have a
significant volume of organic wastes, COD is generally not a significant
150
-------
pollutant in powerplant effluents, but may be used as gross indicator
for certain combined wastes.
Oil and Grease
Oil and grease enter into the plant drainage system primarily as a
result of spillage and subsequent washdown during housekeeping
operations or following natural precipitation. Oil and grease are also
removed from equipment during preoperational cleaning. Oil and grease
is normally present in the following waste streams:
Chemical cleaning - boiler tubes;
- boiler fireside;
- air preheater;
- miscellaneous small equipment;
Ash handling
wastes - oil fired plants;
- coal fired plants;
- floor and yard drains;
Drainage and misc.
waste streams - closed cooling water systems; and
- construction activity.
Ammonia
Ammonia is a significant pollutant in plants that use ammonia compounds
in their operations. Ammonia may be used to control the pH in the
boiler feedwater. It may also be used for ion exchange regeneration in
condensate polishing and in boiler cleaning. An ammonia derivative,
hydrazine, is used as an oxygen scavenger, but is used only in small
quantities. Because of its instability, it is not likely to be a
component of a waste stream. Ammonia will therefore be a component of
those waste streams which emanate from the operations during which
ammonia is added to the system, such as ion exchange wastes, boiler
blowdown, boiler tube cleaning and closed cooling water systems.
Total Phosphorus
Phosphates are used by some powerplants in recirculating systems to
prevent scaling on heat transfer surfaces. To the extent that they are
used, they will be a component of any blowdown from such systems. These
include primarily boiler and PWR steam generator blowdown and blowdown
from closed cooling water systems but could also include a number of
minor auxiliary systems. In some cases, phosphorus compounds are also
used in boiler cleaning operations and would therefore be a possible
component of cleaning wastes.
151
-------
Chlorine - Free Available
Many condenser cooling water systems use chlorine or hypochlorites to
control biological growth on the inside surface of condenser tubes. The
biological growth, if left uncontrolled, causes excessive tube
blockages, poor heat transfer, and accelerated system corrosion—all Of
which reduce plant efficiency. For any cooling tower system the length
of time of the chlorine feed period and the number of chlorine feed
periods per day, week, or month change as the biological growth
situation changes. In most cooling systems, the chlorine is added at or
near the condenser inlet in sufficient quantity to produce a free
available chlorine level of 0.1-0.6 mg/1 in the water leaving the
condenser. The amounts of chlorine added to maintain the free available
chlorine depend upon the amount of chlorine demand agents and ammonia in
the water.
Chlorine and ammonia react to form chloramines. Chloramines contribute
to the combined residual chlorine of the water. The combined residual
chlorine is less efficient and slower in providing biological control
than is the free available chlorine. Total residual chlorine is the sum
of the free available chlorine arid the combined residual chlorine.
Although chlorination is effective for slime control in condenser tubes
of cooling system, its application may result in the discharge of total
residual chlorine to the receiving water. The effects of total residual
chlorine on aquatic life are of great concern.
Metals
Various metals may be contained in some of the waste streams as a result
of corrosion and erosion of metal surfaces and as soluble components of
the residues of combustion where such residues have been handled
hy dr aul ical ly -
Blowdown from boiler feedwater systems and from closed cooling water
systems will contain trace amounts of the metals making up the heat
exchanger surfaces with which they have been in contact* Treatment of
these waters generally minimizes the amount of corrosion. However,
cleaning operations of these systems are designed specifically to
restore the heat transfer surfaces to bare metal. In this process
significant• amounts of metal and metal oxide are dissolved and are
conveyed with the waste streams. The two most common metals likely to
be present in cleaning wastes are iron and copper.
Metals present in wastes from fuel storage and from ash handling
operations will depend on the metals present in the fuel.
Generalization is difficult because of the wide variation in fuel
composition, but iron and aluminum are typically present in significant
quantities in ash from coal. Mercury may be present if the coal used
contained mercury- Vanadium is present in sufficient quantities in ash
resulting from the burning of some types of residual fuel oil, notably
of Venezuelan origin.
152
-------
If chromates and/or zinc compounds are used for the treatment of closed
cooling water systems, chromium and/or zinc will be significant
pollutants for any blcwdcwn or leakage from these systems.
These metals are likely to occur in the following waste streams:
1. Iron
water treatment - clarification;
maintenance cleaning - boiler tubes;
- boiler fireside;
- air preheater;
ash handling - coal fired plants;
and coal pile drainage.
2. Copper
boiler and steam generator (PWR) blowdown;
chemical cleaning - boiler tubes;
- air preheater;
- bciler fireside
condenser cooling
water systems - once through; and recirculating
3. Mercury
ash handling - coal fired plants; and coal
pile drainage.
4. Vanadium (oil-fired plants only)
ash handling;
qhemical cleaning - boiler fireside; and
- air preheater.
5. Chromium and Zinc
recirculating condenser cooling, system; and
closed cooling water system.
6. Aluminum and Zinc
coal pile drainage;
ash handling - coal fired plants;
water treatment - clarification;
chemical cleaning - boiler fireside; and
- air preheater.
153
-------
Phenols
Polychlorinated biphenyls (PCS's) are sometimes used as coolants in
large transformers. In case of leaks or spills, these materials could
find their way into the yard drainage system. Materials showing up as
phenols are also possible in drainage from coal piles, floor and yard
drainage, ash handling streams, and cooling tower blowdown.
Sulfate
Sulfates in powerplant effluents arise primarily from the regenerant
wastes of ion exchange processes. Sulfate may occur in ion exchange and
evaporator wastes, toiler fireside and air preheater cleaning, ash
handling and coal pile drainage.
Sulfite
Sulfite is used as an oxygen scavenger in the boiler feedwater system in
some plants. Plants using sulfite may discharge the sulfite with their
boiler blowdown. Because of its high oxygen demand, sulfite in
significant quantities is considered undesirable in a plant discharge.
Sulfite may occur in the following waste streams:
maintenance cleaning - boiler fireside;
- air preheater;
- stack;
- cooling tower basin;
ash handling - oil fired plants;
-coal fired plants;
coal pile drainage; and
air pollution control
devices for SO.2 removal.
Boron
Oxidizing agents such as potassium or sodium borate may be contained in
cleaning mixtures used for copper removal in the chemical cleaning of
boiler and steam generator (PWR) tubes.
Fluoride
Hydrofluoric acid or fluoride salts are added for silica removal in the
chemical cleaning of toiler and steam generator (PWR) tubes.
Alkalinity and Acidity
Both alkalinity and acidity are parameters which are closely related to
the pH of a waste stream.
154
-------
Total Solids
Total solids is the sum of the total suspended solids and the total
dissolved solids.
Fecal Coliform
Fecal coliform is only significant in sanitary waste.
Total Hardness
Hardness is a constitutent of natural waters, and as such is not
generally considered as a pollutant in effluents from industrial
processes. Also, hardness is not harmful in the concentrations recorded
in Section A-V.
Chloride and Magnesiuir
Both chloride and magnesium are not practicably treatable at the levels
recorded, and also are not harmful at the levels present in the various
waste streams.
Bromide
Bromide may result from boiler cleaning operations, but is not
considered harmful at the levels present. Moreover, it is not
practicably treatable at these levels.
Nitrate and Manganese
Nitrate and manganese are also not harmful nor practicably treatable at
the levels present in the various waste streams.
Surfactants
Surfactants are not practicably treatable at the recorded levels.
Algicides
Very little data was found for algicides (exclusive of chlorine)
although various algicides may be utilized in cooling water systems.
Most utilities requiring algicides utilize chlorine.
Other Potentially Significant Pollutants
The following are potentially significant pollutants, which may be
present in effluents from steam electric powerplants, but for which
little data are available at this time.
155
-------
Cadmium
Lead
Nickel
Selenium
Complete analyses of the fossil fuel used by a particular plant can be
used as a basis for determining which pollutants, in addition to those
covered by effluent limitations guidelines and standards, are likely to
be present in effluents in quantities justifying monitoring and the
establishment of effluent limitations.
Selection of Pollutant Parameters
The U. S. Environmental Protection Agency published (Federal Register,
Volume 38, No. 199, pp. 28758-28670, October 16, 1973) 40 CFR 136
Guidelines Establishing Test Procedures for the Analysis of Pollutants.
Seventy-one pollutant parameters were covered. This list with the
addition of free available chlorine, polychlorinated biphenyls, chemical
additives, debris and pH which were not included provides the basis for
the selection of pollutant parameters for the purpose of developing
effluent limitations guidelines and standards. All listed parameters
are selected except for those excluded for one or more of the following
reasons:
1. Not harmful when selected parameters are controlled
2. Not present in significant amounts
3. Not cont rol 1 ab le
4. Control substitutes more harmful pollutant
5. Insufficient data available
6. Indirectly controlled when selected parameters are controlled
7. Indirectly measured by another parameter
8. Radiological pollutants not within the scope of effluent
limitations guidelines and standards.
Table A-VI-3 presents a breakdown of the methodology for selection of
parameters for the following waste water stream (except for sanitary
wastes) which comprise the entire waste water discharged from steam
electric powerplants:
High Volume
nonrecirculating (once-through) condenser cooling systems
156
-------
Table A-VI-3
SELECTION OP POLLUTANT PARAMETERS*
POLLUTANT PARAMETER
Acidity (as CaCO )
Alkalinity (as CaCO )
Ammonia (as N)
Biochemical oxygen demand (5-day)
Chemical oxvaen demand
Hardness- total
Kjeldahl nitrogen (as N)
Nitrate (as N)
Nitrite (as N)
pH value
Total dissolved (filterable) solids
Total organic carbon
Total phosphorus (as P)
Total solids
Total suspended (nonf ilterable) solids
Total volatile solids
Nutrients. Anions. and Orcranics
Algicides
Benzidine
Bromide
Chloride
Chlorinated organic compounds
Chlorine-free available
Chlorine-total residual
Cyanide— total
Debris
Flouride
oil and grease
Organic nitrogen (as N)
Ortho-phosphate (as P)
Pesticides
Phenols
Polychlorinated biphenyls
Sulfate (as SO )
Sulfide (as S)4
Sulfite (as SO_)
Surfactants
Chemical additives (biocide/corr.inhib. )
CLASS OF WASTE WATER STREAMS
High-Volume
1
1
2
2
2
3
2
2
2
2
3
2
2
3
3
2
6
2
2
3
2
•
6 **
2
•
2
2
2
2
2
2
2
3
3
3
2
6**
Intermediate-Volume
1
1
2
2
2
4
2
2
2
•
3
2
•
6
•
2
6
2
3
3
5
•
6**
2
2
2
•
2
6
5
2
2
3
3
3
6
6**
Low-Volume
1
1
2
2
9
4
2
2
2
•
6
2
6
6
•
2
5
2
3
3
5
2
2
2
2
6
•
2
6
2
2
2
3
3
3
6
6
Rainfall Runoff
1
1
2
2
2
4
2
2
2
•
3
2
2
6
•
2
2
5
3
3
5
2
2
2
2
2
•
2
2
5
2
•
3
3
3
2
2
*Key: • =Selected 5 =Rejected because insufficient data available
1 =Rejected because not harmful when selected parameters are controlled 6 =Rejected because indirectly controlled when selected parameters
2 =Rejected because not present in significant amounts are controlled
3 =Rejected because not controllable
4 =Rejected because control substitutes a more harmful pollutant 8
** Selected where technology is available to achieve no discharge
=Rejected because indirectly measured by another parameter
=Rejected because radiological pollutants are not within the
scope of E.P.A. guidelines and standards
-------
Table A-VI-3 (continued)
SELECTION OF POLLUTANT PARAMETERS *
POLLUTANT PARAMETER
Trace Metals
Aluminum— total
Ant imony— tota 1
Arsenic— total
Barium- total
Beryllium-total
Boron- total
Cadmium— total
Calcium-total
Chromium- VI
Chromium— total
Cobalt-total
Copper-total
Iron— total
Lead-total
Magnes ium— total
Manganese- total
Mercury-total
Molybdenum-total
Nickel-total
Potassium-total
Selenium— total
Silver-total
Sodium-total
Thallium-total
Tin-total
Titanium-total
Vanadium- total
Zinc-total
Physical and Biological
Coliform bacteria (fecal)
Coliform bacteria (total)
Color
Fecal streptococci
Specific conductance
Turbidity
Radiological
Alpha-counting error
Alpha-total
Beta-counting error
Beta-total
Radium— total
CLA
High-Volume >
2
2
2
2
2
2
2
1
2
2
2
3
3
2
1
2
2
2
3
1
2
2
1
2
2
2
2
2
2
2
2
2
2
3
8
8
8
8
8
SS OF WASTE WATER STREAMS
Intermediate-Volume
6
2
2
2
2
3
3
1
6
•
2
6
6
2
1
2
2
2
6
1
2
2
1
2
2
2
2
•
2
2
6
2
7
6
8
8
8
8
8
Low— Volume
6
2
2
2
2
3
2
1
6
6
2
•
•
2
1
2
2
2
6
1
2
2
1
2
2
2
2
6
2
2
6
2
7
6
8
8
8
8
8
Rainfall Runoff
6
2
2
2
2
3
2
1
2
2
2
2
2
2
1
2
2
2
6
1
2
2
1
2
2
2
2
2
2
2
6
2
7
6
8
8
8
8
8
*Key • =Selected
1 =Rejected because not harmful when selected parameters are controlled
2 =Rejected because not present in significant amounts
3 =Rejected because not controllable
4 =Rejected because control substitutes a more harmful pollutant
5 -Rejected because insufficient data avialable
6 =Rejected because indirectly controlled when selected parameters
are controlled
7 =Rejected because indirectly measured by another parameter
8 -Rejected because radiological pollutants are not within the
scope of E.P.A. guidelines and standards
-------
Intermediate Volume
blowdown from recirculating condenser cooling water systems
nonrecirculating ash sluicing systems;
nonreciruclating service water systems
nonrecirculating wet-scrubbing air pollution control systems
Low Volume
blowdown from recirculating ash sluicing systems
blowdown from recirculating wet-scrubber air pollution control
systems
boiler blowdown
. equipment cleaning (air preheater, boiler fireside, boiler
tubes, stack, etc.)
. evaporator blowdown
flow drains
intake screen backwash
recirculating service water systems
. water treatment system
Rainfall Runoff
coal pile drainage
road and yard drains
Sanitary System
The selected parameters for the various classes of waste water
streams are shown in Table A-VT-4.
159
-------
Table A-VI- 4
SELECTED POLLUTANT PARAMETERS
Class of Waste Water Stream
Parameter
High Volume
Chemical additives
(biocides)*
Chlorine-free available
Chlorine-total residual*
Debris
Intermediate Volume
Chemical additives
(corrosion inhibitors)*
Chlorine-free available
Chlorine-total residual*
Chromium-total
Oil and grease
pH value
Total phosphorus (as P)
Total suspended solids
Zinc-total
Low Volume
Copper-total
Iron-total
Oil and grease
pH value
Total suspended solids
Rainfall Runoff
Oil and grease
pH value
Polychlorinated biphenyls
Total suspended solids
* Note: Selected where technology is available to
achieve no discharge.
160
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PART A
CHEMICAL WASTES
SECTION VII
CONTROL AND TREATMENT TECHNOLOGY
introduction
Curry371 presents a general methodology for metallic waste treatment.
Some of the principles are also applicable, however, to other types of
wastes. The following outline conveys, with some modifications, the
general principles of Curry*s work:
I. Omit flows with a pollutant concentration lower than the
concentration in equilibrium with the precipitate formed
'II. Reduce the waste water volumes requiring treatment
IH. Minimize the solubility of the pollutant
A. Eliminate compounds that form soluble complexes
B. Reduce concentration of interfering ions that increase
pollutants solubilities
C. Maintain conditions that minimize total solubility
IV. Control conditions to increase the proportion of the pollutants
in the ionic form required for its precipitation or adsorbent
reaction
V. Avoid conditions that will form harmful amounts of gases during
treatment
VI. Select a process that will give the lowest practicable or
economically achievable amounts of pollutants in the effluent,
up to and including no discharge of pollutants
VII. Select a process that produces a sludge that can be disposed of
in accordance with environmental considerations.
The control and treatment technology for the discharge of chemical
wastes from a steam electric powerplant involves one or more
combinations of the fcllowing techniques:
(1) Elimination of pollutants by:
a) process modifications
161
-------
b) material substitutions
c) good housekeeping practices
(2) Control of waste streams by maximum reuse
and conservation of water
(3) Removal of pollutant from waste stream
In order to select and implement an efficient waste management program,
it is necessary to evaluate the control and treatment techniques
corresponding to specific factors applicable in each case.
In this section alternate control and treatment techniques and their
limitations are evaluated for different chemical waste streams.
Advantages and disadvantages are presented. Based on the reported data,
industry-wide practices and exemplary facilities are indicated.
Chemical wastes can be discussed in three general groups (continuous
wastes, periodic wastes, and wastes whose characteristics are unrelated
to the powerplant operations) even though, for the purposes of guideline
development, a classification by volume would be appropriate. The
continuous wastes are those directly associated with the continuous
production of electrical energy. -They include condenser cooling water
discharge (for once-through systems) or blowdown (for closed systems),
water treatment plant wastes, boiler or PWR steam generator blowdown,
discharges from house service water systems, laboratory, ash handling
systems, air pollution control devices, and floor drains. The periodic
wastes are those associated with the regularly scheduled cleaning of
major units of equipment,, usually at a time of plant or unit shutdown.
Those include spent cleaning solutions from the cleaning of the boiler
or PWR steam generator tubes, boiler fireside, air preheater and con-
denser cooling system, and other miscellaneous equipment cleaning
wastes. The final group of wastes includes drainage from coal piles of
coal fueled plants, drainage from roof and yard drains, run-off from on-
site construction and sanitary wastes. Control and treatment of
discharges from systems involving high-level or low-level rad wastes are
not known to be practicable due to the possible adverse affects which
might arise from concentrating the radioactive materials in the
treatment operation.
Continuous Wastes
Once-through Condenser Cooling System
In the once-through systems, chlorine is the major chemical pollutant
where it is added for biological ccntrol. Excess total residual
chlorine discharge can be minimized by monitoring and controlling free
available chlorine concentrations in the discharge stream. Commercial
monitoring and controlling instruments are available which can measure
and maintain concentrations down to 0.2 mg/1.
162
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AS shown in Figure A-VTI-1, chlorine can be regulated by feedback
instrumentation. The chlorine feeder is activated manually or by a
timer. Chlorine is then added to the cooling water before it goes to
the condenser. Cooling water leaving the condenser flows to the cooling
pond or to the receiving water body. Chlorine level in the discharge is
monitored by chlorine analyzer AC-1. When chlorine reaches 0.2 mg/1 the
analyzer opens ACS-1 which shuts down the feeder until it is restarted
manually or by timer KS-1. This type of system is not in general use in
the industry at this time, but is common practice in municipal sewage
treatment plants. Intermittent programs of chlorine or hypochlorite
addition can be employed to reduce to total chlorine residual
discharged. A further technique to reduce the total residual chlorine
discharged is to employ chlorination at periods of low condenser flow
for a unit. If only one unit at a time at a multiunit station is
chlorinated, the concentration of total residual chlorine in the
combined effluent from the station is reduced. Chlorination can further
be employed at times in harmony with more favorable receiving water
conditions.
Controlled addition of chlorine can also be achieved without the daily
use of monitoring instruments. Sampling and laboratory analysis can be
employed for a number of days until a correlation is established between
chlorine addition characteristics (schedule, rate, duration) and the
effluent total residual chlorine concentrations. Subsequent use of the
correlation with no effluent sampling, except for occasional checks, may
be satisfactory in many cases.
Mechanical means for cleaning stainless steel condenser tubes is used in
a few plants in place of some portion of the total required chlorine
addition, however, the degree of practicability is related to the
configuration of the process piping and structures involved at any
station.
The substitution of stainless steel and titanium condenser tubes in
place of copper alloy tubes is possible but is not known to have
employed solely to reduce the quantities of copper alloy materials
discharged.
Closed Condenser Cooling System Slowdown
In a closed condenser cooling system a blowdown is required to prevent
scaling of the condenser. The significant pollutant parameters of this
waste are TSS, chlorine and chromates.
The monitoring of chlorine in the blowdown stream can be achieved in a
manner similar to that described for the once-through system.
Further potential methods of reducing or eliminating residual chlorine
levels in the blowdown are as follows:
163
-------
WATER.
SDppL-f
ct-kLofciUA-yD(2
LEGEND;
AC-1:
ACS1:
KS-1:
Chlorine Analyzer
Chlorine Feeder Contacts
Controller (Timer Optional)
Flow Path
Optional Flow Path
• Instrument Signal
CHLORINE FEED CONTROL
ONCE-THRU CONDENSER COOLING SYSTEM
FIGURE A-VII-1
164
-------
a) Installing residual data feedback equipment into the chlorine
feed system.
b) Practicing split stream chlorination (splitting the condenser
flow into separate streams which are chlorinated one at a time).
c) Reducing the chlorine feed period, if possible.
d) Reducing the initial residual chlorine level in the condenser
effluent.
e) Increasing the water volume of the cooling tower. This
alternative may not apply to existing cooling towers because it
involves the system design. The alternative can apply to systems on
the engineering drawing boards. This alternative may have other
advantages—such as an extra supply of water for fire protection.
f) Cutting off the blowdown when residual chlorine appears in the
sump. The blowdcwn flow can resume after the residual is dissipated
by the flashing effect and the makeup water chlorine demand. The
length of time during which the blowdown can be eliminated' is a
function of the system's upper limit on dissolved solids.
g) Mixing the blowdown with another stream which has a high
chlorine demand.
An end-of-pipe treatment for reducing chlorine levels is the addition of
reducing agents such as sodium bisulfite (NaHSO3). Chlorine being an
oxidizing agent will oxidize these chemicals. One mole of bisulfite is
required per mole of chlorine or 1.47 mg/1 per mg/1 of chlorine. By
maintaining a 10X excess of sodium bisulfite in the discharge stream,
chlorine can be eliminated. However, the excess sodium sulfite creates
an oxygen demand, thus substituting one pollutant problem for another.
A system of this type is currently being installed in a nuclear plant
currently under construction.
The amounts of pollutants discharged in blowdown can be reduced by
reducing the blowdown flow. This reduction in flow can be achieved by
substituting more soluble ions for scale formers. Similarly, the use of
organic sequestering agents such as polyolesters and phosphonates can be
used to reduce blowdown flow rates. 33* These then become pollutants in
the blowdown.
Water treatment chemicals are used to control several problem areas.
The use of these chemicals has been greatly reduced by the substitution
of plastic or plastic-coated cooling tower components. The plastic
shows considerable resistance to microbiological attack, corrosion, and
erosion. Many new installations using cooling towers are going this
route. Where water treatment is necessary, several chemicals are being
used to control the various problem areas associated with the cooling
towers.
Wood deterioration includes three types of attack; chemical, biological,
and physical. Chemical deterioration, which removes the lignin, is
especially severe with the combined, presence of high chlorine residual
and high alkalinity (chlorine should be less than 1 ppm) . This
165
-------
deterioration can be checked by maintaining the pH below 8.0,
Biological attack on wood is caused by cellulolytic fungi. Bie
application of chlorinated phenolic compounds in a controlled foam form
has been found to be highly effective in promoting prolonged protection
of cooling tower wood. Physical attack on wood is caused by high-
temperature waters, high solids concentration, and freezing and thawing
conditions.
Oxidizing bioddes effectively kill the organisms, but their activity is
short-lived. (Requires frequent or continuous feeding) . Chemicals
which are used include chlorine and calcium and sodium hydrochlorites.
One method is to dose to a free available chlorine concentration of 0.3
- 0.6 ppm for a period of four hours daily. The chlorinated cyanurates
and inocyanurates and other chlorinated organic materials are also used
to introduce chlorine to water. Persulfate compounds, which are
odorless, are also often used (potassium hydrogen persulfate) . Ozone,
another oxidizing biocide, is undergoing experiment for use in various
systems. It is a very powerful oxidizing agent and is twice as potent
as chlorine for destroying bacteria and organic matter. It also
oxidizes undesirable metals such as iron and manganese. Several
nonoxidizing biocides are also being used. Some of these compounds
include: chlorinated phenolic compounds - chlorinated and phenylated
phenols and their sodium or potassium salts; organotin - complex amine
combinations; surface-active agents such as quartenary ammonium groups;
organo-sulphur compounds such as dithocarbamate salts and the thiuram
mono - and disulfides; rosin amine salts formed by reaction with
carboxylic acids and acidic phenols such as the salts of acetic acid and
pentachlorophenol; copper salts such as copper sulfate; thiocyanates
such as methylene thiocyanates and bisthiocyanate; and acrolein which is
highly flammable and may be toxic to warm-blooded animals.
In cooling water systems, two types of corrosion inhibitors can be used
anodic and cathodic. Chromates, orthophosphates and nitrite - based
products are examples of anodic corrosion inhibitors. Poly phosphate,
silicate, and metal salts which form sparingly soluble hydroxides,
oxides and carbonates (such as zinc) act as cathodic inhibitors.
Chromates and other heavy metals may be harmful to aquatic organisms.
Phosphates can serve as a nutrient to aquatic life. Inorganic,
nonchromate corrosion inhibitors consist of various combinations of
polyphosphates, silicates, ferrocyanides, nitrates, and metal ions such
as zinc and copper (straight polyphosphate, zinc - polyphosphate, and
ferro cyanide - polyphosphate) . Work is being done to develop
nonpolluting corrosion inhibiting components. Two such compounds are
sodium and mercaptobenzothiazole and derivatives of organo-phosphorus.
Dearborn Chemical Division of W. R. Grace and Company has developed a
nonchromate, nonphosphate corrosion inhibitor. The synthetic-organic
corrosion inhibitor which is hydrolytically stable and possibly
nontoxic. This compound is designed to reduce scaling and fouling on
heat transfer surfaces* It is not as effective as zinc and Chromates,
166
-------
but is at least as effective as other comparative nonchromate and zinc
polyphosphate compounds.
A film-forming sulfophosphated organic corrosion inhibitor is put out by
the Tretolite Division of Petrolite Corporation. Tretolite states that
it is effective in both fresh and high brine waters and is less toxic to
fish and other aquatic life than metal salts such as chromate. Its
toxicity compares to that of methanol, gasoline, and xylene. It is said
that the inhibitor also performs well in the presence of HJ2S or CO2.
Scale deposits are prevented by controlling the hardness and alkalinity
of the water system. This is normally done by feeding an acid to the
water to neutralize the bicarbonate alkalinity. An acid which is widely
used is sulfuric acid. Most cooling tower systems are controlled in the
pH range of six tc seven. This range depends on the balance between
corrosion inhibition and deposit control. Phosphonates and
polyelectrolites are used as deposit-control agents. A possible
arrangement for pH control is shown in Figure A-VTI-2.
Water Treatment Wastes
Clarification, Softening and Filtration
The waste streams from these operations are sludges, whose composition
will vary depending on the raw water quality and the method of
treatment. Sludges from plain sedimentation are essentially silty in
character. If alum is used as a coagulant, the sludges will contain
aluminum hydroxide together with whatever organic or inorganic colloids
have been coagulated by the alum. Sludges from lime softening contain
primarily calcium and magnesium carbonates and hydroxides. Sludges from
filter backwash operations reflect the processes that' preceded the
filter and differ only to the extent that filter backwash is generally a
periodic operation, whereas sludges from setting basins are withdrawn
more or less continuously.
Sludges will generally contain between 0.5 and 5.OX of suspended solids.
Accepted treatment techniques in the water and wastewater treatment
industry consist of hydraulically thickening these sludges to about 10
to 15X solids content. Following thickening, the sludges can be further
dewatered by land disposal, centrification, filtration, or incineration.
Figure A-Vll-3 shows two typical clarifier waste systems. These
processes are discussed in further detail in Section A-IX. The
supernatent from sludge thickening is generally returned to the original
solids separation unit.
Ion Exchange wastes
Ion exchange resin beds must be regenerated periodically in order to
.maintain their exchange capacity. For cation resins, the most common
regenerant is sulfuric acid. For anion resins, the common regenerant is
167
-------
RIVER
WATER
oo
LEGEM*
AC-I
E/F-I
FC-I
PH SEMSOR f TRANSMITTER
ELECTROPMEUMATID
FLOW COWTROL VALVE
FLOW PATH
COV1TROL S»QWAL (ELECTRICAL)
CONTROL Sl&W/M. (rNEU»AAT»C)
SOLUTIOW
RECIRCULATING CONDENSER COOLING SYSTEM
pH CONTROL OF SLOWDOWN
FIGURE A-VII-2
BLOWfrOWN
AUI> OR
ALKALI TAMK
-------
CLEAR WATER OVERFLOW TO RECYCLE
PAW
WATER,,
aj r
CLARIFIER
WATCB.
WA5H
'«. +
WATER TO
PROCESS
, SLUDGE, ,
/ / / / / / 7 7 7 / 7 /
THICK-
ENER
SLUDGE:,
MECHANICAL
DE WATER ING
R.&cYcL&
Ul WAjEe.1
I pg.oceg
SLUD6&
I
MOIST 50LID5
DISPOSAL
TO
TO
SOliD-b
CLARIFICATION WASTE TREATMENT PR(XESSES
FIGURE A-VI1-3
169
-------
sodium hydroxide, alttough ammonium hydroxide is used in some plants,
Since powerplant practice is to use excess amounts of regenerants, the
waste streams contain primarily sulfuric acid and sodium hydroxide,
together with the ions removed from the water during the exhaustion
cycle. The waste stream also includes rinse water, that is water passed
through the resin beds to remove all traces of regenerant. Typical
practice is to regenerate ion exchange units whenever a specified
exhaustion has been reached while the units are in service. Figure A-
VII-4 shows a simplified flow system.
Waste regenerants and rinses from both the cation and anion resins are
normally collected in a neutralization tank and the pH is then adjusted
to within the range of 6.0 to 9.0 on a batch basis by the addition of
sulfuric acid or sodium hydroxide as required. If any precipitates are
formed after neutralization, they "are separated from the liquid by
settling or by filtration. Figure A-VII-5 shows, a neutralization pond.
The neutralized wastes are high in TDS and would require further
treatment before they could be used for other water uses requiring low
TDS water. However, they are suitable for use as makeup for closed
condenser cooling systems or for such uses as ash sluicing or gas
scrubbing, which do net require high quality sources of supply. It may
be desirable for some uses in the powerplant to use ion exchange wastes
without neutralization. Closed cooling water systems generally require
some acid treatment to reduce the buildup of alkalinity and air
pollution control devices may require an -alkaline source of water. Ion
exchange waste therefore can often form an economical source of low
grade acid or caustic for other uses in the plant.
Substantial reductions in the volume of demineralizer wastes can be
achieved by the use cf systems which substitute reverse osmosis (RO) or
electrodialysis combined with ion exchange (IE) for systems using ion
exchange alone. One study shows that RO plus IE systems are less costly
than IE systems alone for total dissolved solids of 500 mg/1 as CaC03 in
the natural water available. The study is based on 100,000 gallons/day
product capacity, no labor costs, and a waste disposal cost of $5/1000
gallons.383 A 250 gpm product capacity RO system has been recently
installed at plant no. 5405. The available water total dissolved solids
level is 750 mg/1 as CaCO_3. The system is designed to reduce the
dissolved solids level of pretreated river water to the range for which
the conventional resin-bed deionizers are designed.384
Evaporator Slowdown
In those plants still utilizing evaporators to produce boiler feedwater
makeup, the blowdown from the evaporator contains the salts of the
original water supply in concentrated form, but generally still in the
solution phase. Treatment is similar to the treatment of ion exchange
wastes by adjusting the pH to the neutral range of 6.0 to 9.0 with
170
-------
ACID ADJUSTMENT
CAUSTIC ADJUSTMENT
ION EXCHANGE WASTE
ai
RECIRCULATE
DISCHARGE
NEUTRALIZATION
TANK
¥
ION EXCHANGE WASTE TREATMENT PROCESS
FIGURE A-VI1-4
171
-------
NEUTRALIZATION POND
Figure A-VII-5
172
-------
sulfuric acid or sodium hydroxide. If precipitates are formed during
neutralization, these are removed by sedimentation and filtration.
As for ion exchange wastes, the most desirable method of disposal is by
reuse within the plant for applications not requiring low TDS sources of
supply.
Boiler or PWR Steam Generator Slowdown
Since the quality cf the boiler feedwater must be maintained at very
high levels of purity, the blowdown from these units is generally of
high quality also. Boiler blowdown seldom exceeds 100 mg/1 TDS and in
most cases is as low as 20 mg/1. For most plants, the quality of the
boiler blowdown is better than the quality of the raw water supply,
whether it be from a natural source or a municipal water system. The
most desirable reuse of boiler blowdown is therefore as makeup to the
demineralization system.
Boiler blowdown is usually slightly alkaline, but because of the low TDS
level, the pH changes very readily. Neutralization is generally not
necessary for any of the forms of reuse previously discussed in this
section.
Periodic Wastes
Maintenance Cleaning Wastes
All heat transfer surfaces require periodic cleaning and the usual
method of cleaning boiler tube internals is to contact these surfaces
with solutions containing chemicals which will dissolve any scale or
other deposits on these surfaces. Cleaning operations utilizing water
include cleaning of the fire side of boiler tubes, the air preheater,
the cooling water side of the condenser, and other miscellaneous heat
exchange equipment.
Modern steam generators do not permit inspection of areas most likely to
be in distress due to internal deposits, nor can they be cleaned
mechanically. Hence, the only practical and generally accepted method
of cleaning is by chemical means. "*
Boiler cleaning wastes pose special problems of disposal. In order to
be effective, the chemicals used for cleaning must form soluble
compounds with the scale and deposits on the surfaces to be cleaned.
Since scale is evidence of the precipitation of an insoluble compound,
the cleaning solution must somehow change that solubility. The most
common means of accomplishing this objective is by extremes of pH and
strong oxidation potential. Where acids are utilized as cleaning agent,
there is the additional problem of metals being dissolved into the
cleaning solution.
173
-------
Cleaning of heat transfer surfaces is a relatively infrequent operation.
The rate of deposition determines the frequency. However, no general
agreement exists as to how to determine when the point has been reached
which calls for cleaning. Most operators clean on a time schedule,
frequently established by trial and error. A majority of those that d0
not clean on a time schedule remove tube sections to gauge the amount of
deposition.377 Boilers are usually cleaned not more than once per year.
Some of the auxiliary units may be cleaned twice a year. Cleaning
operations are scheduled in advance in order to minimize the effect of
the outage on the ability of the utility to meet the demands for
electric power.
Powerplants use essentially two types of cleaning solutions. One type
is an acid solution, usuallly hot hydrochloric acid, used to clean the
water side of the bciler tubes. Hydrochloric acid cleaning is the
cheapest and most effective of the cleaning methods, but requires a
larger volume of water and takes longer than methods employing other
chemicals. Citric and phosphoric acids are also used, primarily because
they involve less outage time than hydrochloric acid. Fireside cleaning
of boilers and cleaning of air preheaters is accomplished using alkaline
solutions, primarily containing soda ash.
Many utilities discharge their cleaning wastes with once-»through
condenser cooling water, relying on the high dilution ratio to minimize
adverse effects of the discharge. Some utilities collect spent cleaning
solutions in storage basins or ash ponds and adjust the pH to the
neutral range. This causes the precipitation of some of the less
soluble compounds. The supernatent is discharged to the receiving water
and the solids are removed from the basin when this becomes necessary.
This technique is followed at plant no. 2525, which neutralizes its
cleaning wastes before discharge to a large settling pond. Plant no.
3601 also collects cleaning wastes in a storage basin, applies lime or
caustic for neutralization, and then discharges the supernatent.
Current control and treatment technology for cleaning wastes involves
segregation of the waste, chemical treatment to bring the pH into the
neutral range, and separation of any precipitates resulting from the
neutralization.
Miscellaneous Wastes
Ash Handling Wastes
Most of the coal-fired plants use ash ponds. The data from existing ash
settling ponds was reviewed in Part A Section V of this report. Of the
plants for which useful data was obtained, 28% have a negative or zero
net discharge of total suspended solids from the ash pond. For example,
Federal discharge permit applications for four of these stations are
given in Table A-VII-1. The data of one of these, plant no. 0107, were
174
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Table A-VII-1
ASH POND PERFORMANCE
Source: Federal discharge permit applications
Plant No.
0104
0105
0106
0107
Concentration Total Suspended Solids, mg/1
Plant Intake
31
35
10
13
Effluent
22
6
3
10
-J
tn
-------
verified by analyses of samples taken at. the site by EPA personnel.
These data are summarized in Table A-VTI-2.
pH adjustment has been discussed earlier for other waste streams. Some
plants provide pH control on ash pond effluent. In pH adjustment,
addition of chemicals (such as lime) to the pond should be carried out
such that adequate mixing and settling is provided in the pond. This
can be achieved by separating the pond in two areas by use of overflow
weirs.
At plant No. 3626 the fly ash is handled dry by a pressurized collection
system, and the bottom ash is collected hydraulically. Once per shift
the bottom ash is sluiced from the furnace bottom for settling. Water
for the next sluice is recycled from the effluent of the sedimentation
unit. The settled solids are periodically drained for disposal. The
system is designed for complete recycle, with blowdown achieved by water
retained in the settled solids. The recycle stream concentrations have
equilibrated and the system has operated successfully for a number of
years. A similar system in operation at plant no. 3630 was installed as
a retrofit. Bottom ash from the combustion of pulverized coal at plant
no. 3630 is trucked from the plant site by a purchaser. The system is
shown in Figures A-VII-6 and A-VII-7.
Most oil fired plants use dry ash handling, although closed-looped wet
systems are also in use. At plant No. 2512, the fly ash sluicing system
was designed to be a closed system. The ash collected by the
precipitators is sluiced from the hoppers to two concrete ponds,
Suspended solids settle out in the ponds and a relatively clear liquor
is returned to the precipitators to sluice additional ash to the ponds
on a continuous basis. Due to excessive rainfall and leakage of pump
sealing water, the system requires a blowdown of approximately 132.5 m3
(35,000 gal.) per week. The blowdcwn is treated in another
clarification pond where the solids are allowed to settle. The effluent
from this pond goes to a neutralizing tank for pH adjustment, and is
settled prior to discharge. The system is shown on Figure A-VII-8.
The settled solids are intermittently dug out and sold to reclaiming
companies for vanadium recovery. The cost of the ash handling system is
estimated at $461,000.
The above plant is presently investigating a vacuum filter system for
continuous withdrawal and treatment of settled solids, to replace the
intermittent withdrawal system now used.
At plant No. 1209 fly ash from the mechanical collectors is recirculated
to the boilers for reburning. Accumulated bottom ash is periodically
removed during maintenance and sold for the vanadium content. The
utility representatives indicate that other plants in their system
utilize similar ash handling techniques.
176
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Table A-VII- 2
SUMMARY OF E.P.A. DATA VERIFYING ASH POND PERFORMANCE, PLANT NO. 0107
Location
Intake
Inlet to Ash Pond
• from fly ash
• from bottom ash
Ash Pond Discharge
TSS
mg/1
22
76,440
4,110
14
pH
6.3
4.4
5.6
4.3
Aluminum*
mg/1
0.7
1100
56
6.0
Chromium*
mg/1
<0.04
1.3
0.1
< 0.04
Copper*
mg/1
< 0.04
5.1
0.3
0.1
Iron*
mg/1
0.5
2500
112
0.6
Mercury*
mg/1
<0.04
0.1
< 0.04
< 0.1
Zinc*
mg/1
<0.05
2.8
0.1
0.1
* Note: Total
-------
ASH SEDIMENTATION SYSTEM
PLANT NO. 5305
Figure A-VII-6
178
-------
LEGEND
1. Ash Hopper
2. Slide Gate
3. Ash sump with Clinker Grinder
4. Ash Pump
5. Ash Pump Discharge to Hydrobin
6. Hydrobin - This is where ash is separated from water.
7. Unloading of Ashes into Truck
8. Hydrobin Overflow Trough
9. Upper Decant Line
10. Lower Decant Line
11. Hydrobin Drain
12. Surge Tank
13. Let Down Line - The regulating valve is not n use. This is now a hand
operation to let water into lower compartment of surge tank.
14. Hpuse Service Supply Line - Not normal makeup.
15. Line from Surge Tank to Ash Sumps
16. House Service Supply Line - At present date is source of makeup - hand operation
17 - Regulating Valve to Ash Sump
18. House Service Supply Line - No longer in use.
19. Hopper Wash Down Line - A means of putting water into ash hoppers
from main cycle.
20. Ash Hopper Overflow
21. Boiler Seal Trough - Water overflows from here to ash hopper thus another
source of makeup water.
22. Boiler Feed Pump Hydraulic Coupling Cooling Water
23. Drain Back Line - Drains ash pump discharge line.
24. Overflow Trough - Discharges into circulating water discharge.
ASH HANDLING SYSTEM
(Plant No. 3626)
FIGURE A-VII-7
179
-------
WA5TE TO
FLUME
CHEMICAL CLEANING WASTF5
\. BOILER TUBES
2. BOILER FIRESIDE
3 ASH POND
oc
o
OWfKFLOW
100 GPM (MAX.)
WASTE/
NEUTRALIZING
TANK
50,000 GAL.
RECIRCULATION
WASTE
SUMP
2,500 GAL.
ACID CAUSTIC
NEUTRALIZATION
WASTE POND
350,000 GAL.
(CONCRETE)
FLOATING 5UCTION
WASTE POND PUMP
TAKES CLEAR LIQUOR
FROM POND TO NEUTRALIZATION
TANK PRIOR TO DISCHARGE
PL/MP5
ASH HANDLING SYSTEM
OIL FUEL PLANT
(Plant No.2512)
FIGURE A-VII-0
-------
Plant No. 3621 employs the same type of dry bottom ash handling and
reinjection of fly ash as mentioned above. The oil burned is Bunker "C"
- Venezuela oil, with an ash content of 0.1%, a sulphur content of 3%,
and a vanadium content of 300-400 ppm. A magnesium oxide fuel additive
is used and it is estimated that bottom ash is 30%, and fly ash is 70%,
of the total ash and additives residue. The following factors
influenced the utility1s choice of ash handling system: in a wet ash
handling system it is estimated that 74.6% of the oil ash is soluble in
water, and 30-40% of this ash remains in solution upon settling unless
the detention time is very great - hence a large settling area
requirement; oil ash sluice is expected to be acidic (pH 3.5- 4) and may
cause corrosion and maintenance problems; the dry bottom ash collection
system would allow a credit for the sale of this ash for its vanadium
content of about $ 0.001 per g ($0.50 per Ib) .
Plant nos. 5509 and 5511 employ completely recirculating wet fly ash
handling systems. Dry bottom ash systems are in use at a few plants.
Coal Pile Runoff
In areas where water evaporation rates are higher than precipitation
rates, it is possible tc direct coal pile runoff to a storage pond.
These ponds may be provided with an impervious liner to avoid leakage
that may contaminate a ground water aquifer. Since the amount of runoff
depends on rainfall, for an average annual rainfall of 100 cm (40") a
flow rate of 100,000 cubic meter (26.4 million gallons) per year could
be expected for a one hundred thousand square meter (25 acres) storage
pile. However, a precipitation of 5 cm (2") in one hour is also
possible resulting in 5000 m3 (1.32 million gallons) runoff. Inasmuch
as the evaporation of water is dependent on the surface area of pond,
large pond areas will be required for these runoff flows. Furthermore,
a leaping weir or similar device can be used to retain the initial,
potentially significantly polluting, portions of storm rainfall (say the
first 15 minutes of the design storm) and to divert the remaining
relatively nonpolluting portions of the storm.
Storage ponds for retention and treatment of coal pile runoff should be
designed for local weather conditions. The design basis of the pond
should be complete retention of runoff resulting from a storm which
occurs once in ten years. Piping and/or open channels used for
collection of runoff from the coal,pile should be designed to bypass all
flow which exceeds the design basis of the storage pond. Weirs, baffles
and regulators such as utilized in combined municipal sewer systems may
be employed to bypass excess flow and avoid overloading of the storage
pond.
Coal pile drainage with pH from 6 to 9.0, and low dissolved solids can
be pumped to an ash pcnd along with other waste streams, depending upon
available area of the pond.
181
-------
Runoff from coal pile with high acid and sulfate content can be
neutralized by lime, limestone or soda ash. Any of these chemicals used
for the neutralization process involves essentially the same unit
operation. A typical sequence of unit operation is (a) holding (b)
adding the neutralizing agent and mixing (c) sludge settling and
disposal. The major difference between soda ash neutralization and lime
or limestone neutralization is that soda ash produces a water low in
hardness and calcium, but high in sodium. Other chemical parameters are
comparable between the three neutralizing agent. Figure A-VIi-g
presents the chemical cost for these three chemicals.
Limestone handling is easier than that of lime because of its low
reactivity. Limestone reaction is not very sensitive quantitatively;
i.e. small changes in limestone feed rate or runoff quality do not cause
large changes in product water quality so that the accuracy of limestone
feeding need not be controlled with the precision required for lime.
Unlike lime, accidental over treatment is not a pollution problem with
limestone because of its low solubility.
A major disadvantage in limestone neutralization can be attributed to
the slow oxidation rate of ferrous iron and consequently lower rate of
settling. The rate of settling can be increased by the addition of
coagulant aids. Figure A-VII-10 and Figure A-VII-11 present a
comparison of lime, limestone and soda ash reactivities and settling
rates respectively. For a coal pile runoff containing ferrous iron
(FeSO4) and free acid (H2SO4) , the overall neutralization reaction using
limestone (CaCO3) can be represented in the following simplified manner:
3CaCO3 + 2F6SO4 + H2SO4 + 0.5 02 + 2H20 = 3CaSO4 + 2Fe (OH) 3 + 3C02
A method of collecting and neutralizing coal pile drainage is to
excavate a channel arcund the coal pile large enough to have a 10 minute
detention time. The bottom of the channel should contain a limestone
bed for neutralizing the acid content of the runoff. The channel should
be sloped so as to have the runoff drain to a sump from where it can be
pumped or gravity fed to a holding pond prior to discharge.
Insoluble material or precipitated products from neutralization can be
separated by sedimentation or filtration. The removal of solids by
sedimentation has been described earlier. Figure A-VII-12 shows a
typical coal pile, with a runoff collection ditch around the perimeter.
Plant no. 3630 has a retrofit system for collecting and filtering coal
pile drainage. The coal pile trench is designed to handle a 15-hour,
once-in-36-years rainfall (3.9 inches). The inflow to the coal pile is
gradually transferred to a collecting basin, which also receives yard
and building drains. The maximum flow to the 100 ft diameter filtering
pond is 2400 gpm. The filter medium is a 4 ft deep layer of 0.4 mm
sand. The loading is 3.5 gpm/ftz and is designed to achieve 35 mg/1
total suspended solids in the effluent. A design for lower effluent
total suspended solids would involve a deeper bed, a better filter
182
-------
oo
04
0)
§
8
1.2
1.1
1.0
0.9
0.8
§ 0.7
o
0.6
c 0.5
•H
to
-P
03
o
o
o
0)
g
0.4
0.3
0.1
0
S
CO
6 7 8 9 10
ACIDITY IN 1000 MG./L
11 12
13 14 15 16 17
COST OF NEUTRALIZATION CHEMICALS
(/From Reference 313)
FIGURE A-VII-.9
-------
oc
pH 10 -
pH 8 ~
pH 6
PH 4 -
O SODA ASH
A LIME
LIMESTONE
pH 2
0 GRAMS 0.2 0.4 0.6 0.8
0 2.0 4.0 6.0 8.0
1.0 (LIME, SODA ASH)
10.0 (LIMESTONE)
GRAMS ADDED TO ONE LITER OF RUNOFF -(From-Reference 313)
(INITIAL HOT ACIDITY = 619 MG/1)
COMPARISON OF LIME, LIMESTONE, AND SODA ASH REACTIVITIES
A-VII-10
-------
oc>
VI
0)
tn
C
U
-------
COAL PILE
PLANT NO. 5305
Figure A-VII-12
186
-------
media, or a larger bed area. This filter has achieved effluent total
suspended solids levels of 15 mg/1 or less over approximately 75 percent
of the storm events to date. The trench and collecting basin
construction costs were about $750,000 and the filtering pond about
$150,000.
Floor and Yard Drains
Floor drains from a coal-fired generating station can be collected and
pumped directly on to the coal pile so that the oil present in the
drainage stream is absorbed by the coal and burned with it. The water
will serve the purpose .of keeping the pile wet in order to avoid
spontaneous combustion. Floor drains from plants using a fuel mixture
or fuel other than coal, can be neutralized (if necessary) by lime or
acid to bring the pH between 6 and 9.0* Oil will be removed by passing
the stream through an air floatation unit or an oil-water separator
(Figures A-VII-13, 14). If the drains contain high levels of TSS,
sedimentation techniques described earlier can be used. An air
floatation unit used for flooraand yard drains is shown in Figure A-VII-
15. Contaminated stormwater runoff can be treated in a similiar manner.
Stormwater collected in oil storage tank basins is generally held for
controlled discharge to an oil-water separator (Figures A-VII-16, 17).
Air Pollution Control Scrubbing Devices
The nonrecovery alkali scrubbing process is a closed-loop type? and the
process employs recycle lime scrubbing liquor. The process requires a
make-up water for saturating.the boiler gases. Consequently, the liquid
effluent associated with the sludge removal step should be kept to a
minimum to minimize make-up water requirements. This can be achieved by
providing adequately sized ponds and adding flocculants for efficient
settling. Use of mechanical filtration equipment will further dewater
the sludge and thus minimize liquid effluent discharge. Oxidation of
the scrubber discharge effluent will ensure that sulfite level in the
sludge is minimal. Lime/limestone addition is necessary to eliminate
acidity. If the process employs a pond in the scrubber liquor recycle
loop, the pond should be lined to minimize ground seepage.
Sanitary Wastes
Sanitary wastes can be discharged to municipal sewerage systems where
possible. In rural areas, packaged sewage treatment plants are commonly
used for treating this waste. Most of these plants are based on the
biological principle of aerobic decomposition of the organic wastes and
are able to reduce the raw sewage concentrations of BOD-5 and TSS to
meet effluent standards applicable to publicly-owned treatment works.
187
-------
CYLINDRICAL AIR FLOTATION UNIT
FIGURE A-VII-13
61L coUecpua -r
PjLIMAVZrf
SUMP*
TYPICAL A.P.I. OIL-WATER SEPARATOR
FIGURE A-VII-14
188
-------
OIL SEPARATOR AND AIR FLOATATION UNIT
PLANT NO. 0610
FigureA-VII-15
189
-------
CORRUGATED PLATE 'TYPE OIL WATER SEPARATOR
FIGURE A-VII-16
190
-------
OIL
OIL WATER SEPARATOR
FIGURE A-
191
-------
Other Wastes
Intake screen backwash can be collected, viable organisms returned to
the waterway, and the collected debris removed before discharging the
effluent to the receiving waters. Collected debris can be disposed of
in a landfill or other solid waste disposal facility.
For other miscellaneous wastes, such as those from laboratory and
sampling activities, etc., pH adjustment and TSS removal is similar to
that followed in other waste streams. Technology for the control qf
pollution from construction activities is treated comprehensively in
Reference 382.
Oil spillage from transformers can be absorbed in slag-filled pits under
and around the transformers. Curbing of the pits prevents flooding by
surface water and floating off the oil.
Waste water from the primary coolant loop of nuclear plants may contain
boron; however, no treatment is known for boron removal. As explained
in Part A Section V, nuclear plants follow a radioactive waste
management system. Any treatment or recycle concept applied to remove
non-radioactive pollutants from these wastes would have to consider the
radioactive components of this waste.
Pollutant-Specific Treatment Technology
Applicable control and treatment technology relevant to specific
pollutants is disciussed in the J.W. Patterson, et al, report "Wastewater
Treatment Technology".208 Based on the data of that report and other
sources, the following information is given on pollutant-specific
treatment technology.
Aluminum
Precipitates as the hydroxide at pH 6-7-371
Ammonia
Ammonia can be removed from waste waters by stripping with steam or air.
Steam stripping systems are capable of achieving effluent ammonia
concentrations of from 5 to 30 mg/1. Cooling towers could be considered
as air strippers of ammonia from contaminated waters. However, the
reverse effect can occur, i.e. air-borne ammonia is absorbed.'7s
Antimony
Solubility data indicates a potential removal of about 90 percent by
lime coagulation treatment.1*
192
-------
Arsenic
Treatment processes employed involve coagulation at pH 6.0 to produce
ferric hydroxide floe to tie up the arsenic and carry it from solution.
This process has consistently yielded arsenic levels of 0.05 mg/1 or
less.
Barium
Precipitation as barium sulfate after addition of ferric or sodium
sulfate at pH 6.0 yields effluent levels of 0.03-0.27 mg/1.
Beryllium
No information was found concerning treatment methods for the removal of
beryllium from industrial waste waters. However, precipitation of
insoluble sulfate, carbonate or hydroxide may be possible.
Boron
No practicable treatment is reported. Borate-nitrate corrosion
inhibition treatment is used in closed-loop house service water systems.
Boron from this source could be reduced by minimizing the use of boron-
containing chemicals. However, some boron chemicals could discharge
from ash sluicing operations as a result of boron content in raw coal
used for firing.
Cadmium
Cadmium precipitates as the hydroxide at elevated pH. Its' solubility at
pH 10 is 0. 1 mg/1. The presence of iron hydroxide can enhance removal
due to co-precipitation with, or adsorption on the iron floe.
Complexing agents in the waste stream can reduce the effectiveness of
precipitative removal.
Calcium
The lime-soda process precipitates calcium as calcium carbonate.
Chromium
The most common method of chromium removal is chemical reduction of
hexavalent chromium to the trivalent ion and subsequent chemical
precipitation. The standard reduction technique is to lower the waste
stream pH to 3 or below by addition of sulfuric acid, and to add sulfur
dioxide, sodium bisulfite (or metabisulf ite or hydrosulfite) , or ferrous
sulfate as reducing agent. Trivalent chromium is then removed by
precipitation with line at pH 8.5-9.5.
The residual of hexavalent chromium after the reduction step depends on
the pH, retention time, and the concentration and type of reducing agent
193
-------
employed. The following effluent levels are reported for treatment of
industrial wastes:
metal finishing wastes,
using sulfure dioxide --------1 mg/1
metal finishing wastes,
using sulfur dioxide -------- "zero"
wood preserving wastes,
using sulfur dioxide -------- 0.1 mg/1
electroplating wastes,
using sodium bisulfite ------- 0.7-1.0 mg/1
cooling tower blowdcwn,
using metabisulfite ------ below 0.5 mg/1
cooling tower blowdcwn,
using metabisulfite ---------- 0*025-0.05 mg/1
metal plating wastes,
using metabisulfite ---------0.1 mg/1 or less
chrome plating wastes,
using metabisulfite --------- 0.05-0.1 mg/1
Ion exchange treatment of metal finishing wastes has successfully net
chrome effluent standards equivalent to a hexavalent chromium
concentration of 0.023 mg/1.
The solubility of trivalent chromium is less than approximately 0.1 mg/1
in the pH range 8-9.5. Effluent levels, after precipitation of
industrial wastes with lime, are reported ,as follows:
electroplating wastes,
using coagulant aid ------------- 0.06 mg/1
metal finishing wastes,
using settling ------------- below 3 mg/1
wood preserving wastes,
using settling ---------------- o.02 mg/1
metal finishing wastes,
using an anionic polyelectrolyte ------- 0.75 mg/1
Ion exchange removal can effect complete removal of trivalent chromium.
The U.S. Atomic Energy Commission reports total chromate effluents of
0.1-0.2 mg/1 after either chemical treatment or ion exchange.372-373
Cobalt
No information was found concerning treatment methods for the removal of
cobalt from industrial waste waters.
194
-------
copper
Effluent concentrations of 0.5 mg/1 can be consistently achieved by
precipitation with lime employing proper pH control and proper settler
design and operation. The maximum solubility of the metal hydroxide is
in the range pH 8.5-9.5. In a powerplant, copper can appear in the
waste water effluent as a result of corrosion of copper-containing
components of the necessary plant hydraulic systems. Normally, every
practicable effort is made, as a part of standard design and operating
practices, to reduce corrosion of plant components. However, copper is
not used in once-through boilers and, consequently, is not found in
corresponding spent cleaning solutions. Excessively stringent effluent
limitations on copper may necessitate complete redesign and alteration
of condenser cooling and other systems. The following effluent levels
of copper are reported for full-scale treatment of industrial wastes by
lime precipitation followed by sedimentation (except as noted):
metal processing wastes --------0.5 mg/1
metal processing wastes -------- 0.2-2.5 mg/1
metal processing wastes, using
sand filtration - ------ 0.2-0.5 mg/1
metal fabrication wastes,
using coagulant ---.--------2.2 mg/1
metal finishing wastes ------ avg. 0.2 mg/1
metal mill wastes ----------- 1-2 mg/1
wood preserving wastes -------- 0.1-O.U mg/1
A significant problem in achieving a low residual concentration of
copper can result if complexing agents are present, especially cyanide
and ammonia.
Iron
In general, acidic and/or anaerobic conditions are necessary for
appreciable concentrations of soluble iron to exist. "Complete" iron
removal with lime addition, aeration, and settling followed by sand
filtration has been reported. Existing technology is capable of soluble
iron removals to levels well below 0.3 mg/1. Failure to achieve these
levels would be the result of improper pH control. The minimum
solubility of ferric hydroxide is at pH 7. In some cases, apparently
soluble iron may actually be present as finely divided solids due to
inefficient settling of ferric hydroxide. Polishing treatment such as
rapid sand filters will remove these solids. In a powerplant, iron, as
with copper, can appear in the waste water effluent as a result of
corrosion to iron-containing components of the necessary plant hydraulic
systems. Normally, every practicable effort is made, as a part of
standard design and operating procedures, to reduce corrosion of plant
components. Excessively stringent effluent limitations on iron, as with
copper, may necessitate complete redesign and alteration of condenser
cooling and other systems.
195
-------
Lead
Precipitation by lime and sedimentation has been reported. Little data
is available on effluent lead after treatment; however, the extreme
insolubility of lead hydroxide indicates that good conversion of soluble
lead to insoluble lead can be achieved, with subsequent removal by
settling or filtration.
Magnesium
The lime-soda process precipitates magnesium as the hydroxide.
Manganese
Precipitates upon lime addition. Significant' removals during water
treatment are achieved at pH 9.4 and above.
Molybdenum
No information was found concerning treatment methods for the removal of
molybdenum from industrial waste waters. However, precipitation as
chloride or sulfide may be possible.
Mercury
General treatment methods exist which are applicable to mercury-bearing
waste streams. One of the most common, simplest, and most effective
methods to remove mercury from solution is precipitation of an insoluble
mercury compound. Sodium sulfide (Na^S) and sodium hydro-sulfide (NaHS)
are effective in forming the extremely insoluble Hgs. This method is
not favored, however, when recovery of mercury is desired, since
offensive and poisonous hydrogen sulfide (H2S) gas is formed in the
reduction process. Other methods include filtration with adsorptive
compounds such as activated carbon and graphite powder, chemical
flocculation, and ion exchange.
Nickel
Nickel forms insoluble nickel hydroxide upon addition of lime. Little
efficiency is gained above a pH of 10, where the minimum theoretical
solubility is 0.01 mg/1.
Oil and Grease
Certain preventative measures can be applied to prevent spillage of oil
and the entrance of oil into the plant drainage system. For example,
plant No. 1201 employs inflatable "stoppers" in the entrance to plant
floor drains to trap spilled oil and so that it may be removed before
entering the floor drain system. Means for oil separation from waste
water have been discussed in a previous discussion of treatment of floor
and yard drain waste water.
196
-------
Flotation is efficient in removing emulsified oil and requires minimum
space. It can be used without chemical addition, but demulsifiers and
coagulants can improve performance in some cases. Whenever possible,
primary separation facilities should be employed to remove free oil and
solids before the water enters the flotation unit. Multi-stage units
are more effective than single-stage units. .Partial-recycle units are
more effective than full-pressure units. Oil removal facilities
including single-cell flotation can achieve effluent oil and grease
levels from 10-20 mg/1, while multi-stage units can achieve 2-10 mg/1.
Total Phosphorus (as Pi
Phosphorus concentrations of less than 0.1 mg/1 can be routinely
obtained using two-stage lime clarification at pH 11, followed by multi-
media pressure filters. Single-stage lime clarification at pH 9-11 with
or without filtration can achieve phosphorus concentrations of 2 mg/1 or
less. Figure A-VII-18 shows the effect of pH on phosphorus
concentration of effluent after filtration. The average concentration
for a clarifier pH of 9.5, and prior to filtration was 0.75 mg/l."*
Potassium
No information was found concerning treatment methods for the removal of
potassium from industrial waste waters.
Polychlorinated Biphenyls (PCBs)
PCBs are commonly used as coolants in large transformers. Special care
should be taken to prevent leaks and spills and to contain possible
spills of these fluids in order to prevent their discharge to water
bodies.
Selenium
No information was found concerning treatment methods for the removal of
selenium.
Silver
Precipitation with chloride ion can remove silver to the mg/1 level.
However, co-precipitation with other metal hydroxides under alkaline
conditions improves silver removal to less than 0.1 mg/1.
Sodium
No information was found concerning treatment methods for the removal of
sodium from industrial waste waters.
197
-------
2.0
8.5
9.0
9.5 10.0 10.5
CLARIFIER pH
11.0
11.5
Figure A-VII-18
Effect of pH on Phosphorus Concentration
of Effluent from Filters Following
374
Lime Clarifier
198
-------
Sulfate
Use of lime (calcium carbonate) in place of dolomite (mixture of calcium
carbonate and magnesium carbonate) in lime treatment will minimize the
presence of soluble sulfates, due to insolubility of calcium sulfate and
solubility of magnesium sulfate.
Thaliium
No information was found concerning treatment methods for the removal of
thallium from industrial waste waters. However, the trivalent hydroxide
is insoluble and may te removed by lime addition.
Tin
No information was found concerning treatment methods for the removal of
tin from industrial waste waters. However, precipitation as hydroxide
or sulfite may occur.
Titanium
No information was found concerning treatment methods for the removal of
titanium from industrial waste water.
Total Dissolved Solids
Removal of total dissolved solids (IDS) from waste waters is one of the
more difficult and more expensive waste treatment procedures. Where TDS
result from heavy metal or hardness ions, reduction can be achieved by
chemical precipitation methods; however, where dissolved solids are
present as sodium, calcium, or potassium compounds, then TDS reduction
requires more specialized treatment, such as reverse osmosis,
electrodialysis, distillation, and ion exchange.
Total Suspended Solids
Suspended solids removal can be achieved by sedimentation and filtration
operations. Sedimentation lagoons are commonly used at steam electric
powerplants. Some plants employed configured tanks. Tanks can be used
where space limitations are important. Filtration is used for rainfall
runoff waste water at plant No. 3630. Tanks constructed for solids
removal usually have built-in facilities for continuous or intermittent
sludge removal. Designs based on maximum flow anticipated can provide
the best performance. Equalization can be provided to regulate flow.
The retention time required is related to the particle characteristics.
Plant No. 3905 employs a settling basin 250,000 sq ft x 5 ft deep to
provide a minimum retention time of 24 hours for a waste stream of
normally 1800 gpm (3300 gpm maximum). The ash pond is 600 acres in area
and will contain 6,700 acre ft. Coal used at the plant is pulverized to
a size passing 80 percent through a 200 mesh screen. Approximately 80
percent of the ash is discharged as fly ash. No cooling water is
discharged to the ash pond. The distance from inlet to outfall is about
199
-------
one mile. The narrow water stream in the pond meanders through the
settled ash piles. The reported flow is about 500 gpm.
Nine out of the ten fossil-fueled steam electric powerplants operated by
the Tennessee Valley Authority use ash ponds for both fly ash and bottom
ash, as well as for other plant wastes such as from boiler cleaning.
Effluent samples from these ponds have been taken quarterly over a
period of several years. Analyses were performed and reported on
numerous parameters including total solids, total dissolved solids and
turbidity. Total suspended solids values can be inferred as the
difference between total solids and total dissolved solids. Total
suspended solids can be determined from 74 of these samples. See Table
A-VII-3. The minimum number of samples for any one plant is 6 and the
maximum number is 16. Total suspended solids levels were 0 mg/1 in 25
samples, 10 mg/1 in 24 samples, and from 20 to 270 mg/1 in the remaining
25 samples. Ninety-five percent of the samples were 70 mg/1 or lower.
The median value of the sample is 10 mg/1 and the average (mean) value
of the low 95 percent of samples is 15 mg/1 total suspended solids.
Flow rates range from 3,000 to 15,000 gpm and ash pond sizes from 35 to
275 acres.
Vanadium
No information was found concerning treatment methods for the removal of
vanadium from industrial waste waters. However, precipitation as the
insoluble hydroxides may occur.
Zinc
Lime addition for pH adjustment can result in precipitation of zinc
hydroxide. Operational data indicate that levels below 1 mg/1 zinc are
readily obtainable with lime precipitation. The use of zinc can be
minimized since other treatment chemicals are available to reduce
corrosion in closed cooling-water cycle. Zinc removals have been
reported for a range of industrial systems and, generally, treatment is
not for zinc alone. Lime addition with hydroxide precipitation followed
by sedimentation (except as indicated) has yielded the following
effluent zinc levels:
plating wastes ------------ 0.2-0.5 mg/1
plating wastes ------------ 2 mg/1
plating wastes, using
sand filtration -----------0.6 mg/1
plating wastes - ----------- less than 1 mg/1
fiber manufacturing wastes ------ less than 1 mg/1
tableware manufacturing wastes,
using sand filtration -------- 0.02-0.23 mg/1
fiber manufacturing wastes ------ 0.9-1.5 mg/1
fiber manufacturing wastes ----.*- i mg/l
metal fabrication wastes ------- 0.5-1*2 mg/1
200
-------
Table A-VII-3
ASH POND EFFLUENT TOTAL SUSPENDED SOLIDS, mg/1
386
Plant No.
Flow Rate, gpm
Pond Size, acres
Total suspended
solids, mg/1
0111
6,OOO
45
0
0
10
20
40
100
0112
15,000
_
0
0
0
10
10
10
20
20
30
2120
14,000
185
0
0
0
10
10
40
60
60
4701
7,000
35
0
0
10
10
10
10
10
10
10
10
30
40
40
60
70
370
4702
7,000
110
0
0
0
10
10
20
40
70
200
4703
8,000
340
0
0
10
10
10
20
30
4704
3,000
40
0
0
0
0
10
10
10
10
40
4705
5,000
90
0
0
0
10
20
160
4706
15,000
275
0
0
0
10
10
10
20
20
ro
o
-------
metal fabrication wastes, using
sand filtration - ----- - ---- 0.1-0.5 mg/1
Combined Chemical^Tr eatment
Precipitation
The effluent levels of metal ions attainable by combined chemical
treatment depend upon the insolubility of metal hydroxides in the
treated water and upon the ability to mechanically separate the
hydroxides from the process stream. The theoretical solubilities of
copper* nickel, chromium, zinc, silver, lead, cadmium, tellurium and
ferric and ferrous ircn as a function of pH are shown in Figures A-VII-
19, 20. At a pH of 9.5 the solubility of copper, zinc, chromium, nickel
and iron is of the order of 0.1 mg/}., or less. Experimental values
plotted in Figures A-VII-21, 22 vary somewhat from the theoretical
values. Nevertheless, the need for fairly close pH control in order to
avoid high concentrations of dissolved metal in the effluent is evident.
A pH of 8.5 to 9.0 is best for minimizing the solubility of copper,
chromium and zinc, but a pH of 10.0 is optimum for minimizing the
solubility of nickel and iron. To limit the solubility of all of these
metals in a mixed solution, an intermediate pH level would be selected.
379
A further aspect related to solubility is the time for reaction. Figure
A-VII-23 shows the change in solubilities of zinc, cadmium, copper and
nickel with time for various levels of pR.
The theoretical and experimental results do not always agree well with
results obtained in practice. Concentrations can be obtained that are
lower than the above experimental values, often at pH values that are
not optimum on the basis of the above considerations. Effects of co-
precipitation and adsorption on the flocculating agents added to aid in
settling the precipitate play a significant role in reducing the
concentration of the metal ions. Dissolved solids made up of noncommon
ions can increase the solubility of the metal hydroxides according to
the Debye-Huckel Theory. In a treated solution from a typical
electroplating plant, which contained 230 mg/1 of sodium sulfate and
1,060 mg/1 of sodium chloride, the concentration of nickel was 1.63
times its theoretical solubility in pure water. Therefore, salt
concentrations up to approximately 1,000 ppm should not increase the
solubility more than 100 percent as compared to the solubility in pure
water. However, dissolved solids concentrations of several thousand ppm
could have a marked effect upon the solubility of the hydroxide. 379
When solubilizing ccmplexing agents are present, the equilibrium con-
stant of the complexing reaction has to be taken into account in
determining theoretical solubility with the result that the solubility
of the metal is generally increased. Complexing agents such as EDTA
202
-------
io pr
i.o
0.1
>>
2
0.01
0.001
8 9 10
Solution, pH
II
\2
Figure A-VII-19
SOLUBILITY OF COPPER, NICKEL, CHROMIUM,
AND ZINC AS A FUNCTION OF pH
j/y
203
-------
u
f
O
CO
0.01
0.001
0.0001
Figure A-VII-20 THEORETICAL SOLUBILITIES OF METAL IONS
AS A FUNCTION OF pH
204
-------
o>
O
in
0.2 —
O.I
Zinc
Legend
O Nickel
D Chromium
X Zinc
A Copper
Note: Values plotted as O.I mg/1
were reported as zero.The
O.I mg/Z value is assumed
to be the detectable limit.
13
8 9 10 II 12
Solution , pH
Figure A-VII-21
EXPERIMENTAL VALUES - SOLUBILITY OF METAL IONS AS
A FUNCTION OF pH 379
14
205
-------
0.01
7 8 9 10
pH(After 2-hr Standing)
II
12
Figure A-VII-22 EXPERIMENTALLY DETERMINED SOLUBILITIES
OF METAL IONS AS A FUNCTION OF pH
Reference No. 236
206
-------
ov
70
/
— pH = 7.5
t~ 1 1
i i I i i ;
o 20 '
310
0)
H «*
•9 i
H 1.6
*i.a
H
\0.8
B 0.4
0
— PH -
— pH =
fcr- 1 1 1 1 \ 1
J
pH •=
nH c
1 1 1 I 1 1
/
8.0
8.5
\ \
A-o'
.a.. 5
10 . i
i
1234 567 8
Standing time, hours
ZINC
(0
u
0)
0
w
AUU
80
60
t
20'
10
PH -
~ ''• DH •
L. i I .1 I I i
J
pH =
_ I i !• 1 1 I
8.5
9.0
» /
9.5
1 ,
4. Oi---
3.0
2.0
1.0
0.4
0.2
= 10.
1 l._.l. !._]_.. I l_.
. , »
i u i k 't J
Standing time, hours
CADMIUM
0 1234 567 8
Standing time, hours
COPPER
) 1 2 3 4 5 6 7 8
Standing time, hours
NICKEL
Figure A-VII-23 CHANGE IN THE SOLUBILITIES OF ZINC, CADMIUM, COPPER, AND
AND NICKEL PRECIPITATES (PRODUCED WITH LIME
ADDITIONS) AS A FUNCTION OF STANDING TIME AND
pH VALUE. Reference No. 236.
207
-------
(ethylene-diamine-tetraacetic acid) , could have serious consequences
upon the removal of metal ions by precipitation. 379
Superposed on the situation presented above for chemical treatment for
the removal of iron, copper, chromium and nickel could be requirements
for removal of other heavy metals and phosphorus. Phosphorus effluents
of 2 mq/1 are achievable with or without filtration at pH 9-11,
therefore, no problem of phosphorus removal is anticipated at pH values
which are optimum for the removal of iron, copper, chromium and nickel,
Reference 380 presents minimum pH values for complete (effluent
generally 1 mg/1) precipitation of metal ions as hydroxides as follows;
Sn+2(pH 4.2), Fe+3(pH 4.3), A1+3 (pH 5.2), Pb+2(pH 6.3), Cu+2(pH 7.2),
Zn+2(pH 8.4), Ni+2(pH 9.3), Fe+2(9.5), cd+2 (pH 9.7), Mn+2 (pH 10.6). in
the case of amphoteric metals such as aluminum and zinc,
resolubilization will occur if the solution becomes too alkaline.
Alkali Selection
Several alkaline materials are available for use in chemical treatment,
e.g. lime, hydrated lime, limestone, caustic soda, soda ash. The choice
among these may depend on availability, cost, desired effluent quality,
ease of handling, reactivity, or characteristics of sludge produced. A
comparison of these materials is given in Table A-VII-4. When cost and
effluent quality are the most important factors, lime, hydrated lime and
limestone would be the more commonly used alkalis.
Lime is readily available and relatively simple to use. In acid (coal)
mine drainage applications, it consistently neutralizes the acidity and
removes the iron and other metals present in mine drainage at a
reasonable cost, if net the least cost. For these reasons, lime is used
in most of the estimated 300 plants that treat mine drainage.380 The
relative disadvantages of lime are: an increase in the hardness of the
treated water, problems of scale (gypsum) formation on plant equipment,
and the difficulties in dewatering or disposal of the sludge volumes
produced. There are four basic steps in lime treatment. First, waste
waters are neutralized by addition of slurried lime with vigorous mixing
for 1-2 minutes. Aeration is provided for 15-30 minutes to oxidize
ferrous iron to the ferric state. Solids separation is provided in
either mechanical clarifiers, or large earthen settling basins. The
treated water is discharged and the sludge is disposed of. Capital
costs range from about $40/m3 processed/day for a 40,000 m3/day process
to about $100/m3/day for a 2,000 m3/day process to about $1,000/m3/day
for a 400 m3/day process for treatment of acid mine drainage. Operating
costs vary from 3 to 12 cents per 1,000 m3 (11 to 45 cents per million
gallons) per mg/1 of acidity but are generally in the range 4 to 7 (15
to 27) cents.380 Sludge disposal costs can be as much as 50 percent of
the total operating costs.
Limestone has several advantages over other alkaline agents. The sludge
produced settles more rapidly and occupies a smaller volume. The pH of
208
-------
Table A-VII-4
COMPARISON OF ALKALINE AGENTS FOR CHEMICAL TREATMENT
380
Agent
Cost, $/ unit of CaCO equiv,
vo
Limestone, Rock (calcium carbonate)
Limestone, Dust (calcium carbonate)
Quick Lime (calcium oxide)
Hydrated Lime (calcium hydroxide)
Magnesite (magnesium carbonate)
Soda Ash (sodium carbonate, 50%)
Dolomite (calcium-magnesium carbonate)
Ammonium Hydroxide
Caustic Soda (sodium hydroxide,50%)
8.82
11.02
14.19
20.40
23.24
42.08
47.70
50.14
67.02
-------
the treatment is not so sensitive to feed rate. Limestone is easier to
handle than the other alkaline materials. Disadvantages center around
its slow reactivity which requires larger detention times and larger
treatment vessels. As a result of its disadvantages few actual
operating systems have been installed.
Aeration
The oxidation of ferrous iron to ferric iron can be accompli she'd by
either diffused or mechanical aeration equipment. Capital costs range
from about $2,000 for a 100 m3 flow/day process to about $50,000 fora
10,000 m3 flow/day process. Operating costs will vary from 10-20
percent of the total plant operating costs.380
Solids Separation
The first step in separating the precipitated metals is settling, which
is very slow for gel like zinc hydroxide, but accelerated by co-
precipitation with the hydroxides of copper and chromium. Coagulation
can also be aided by adding metal ions such as ferric iron which forms
ferric hydroxide and absorbs some of the other hydroxide, forming a floe
that will settle. Ferric iron has been used for this purpose in sewage
treatment for many years as has aluminum sulfate. Ferric chloride is
frequently added to the clarifier of chemical waste-treatment plants in
plating installations. Flocculation and settling are further improved
by use of polyelectrolytes, which are high molecular weight polymers
containing several ionizable ions. Due to their ionic character they
are capable of swelling in water and adsorbing the metal hydroxide which
they carry down during settling.
Settling is accomplished in the batch process in mechanical clarifier or
a stagnant tank, and after a time the sludge may be emptied through the
bottom and the clear effluent drawn off through the side or top. The
continuous system uses a baffled tank such that the stream flows first
to the bottom but rises with a decreasing vertical velocity until the
floe can settle in a practically stagnant fluid.
Although the design of the clarifiers has been improved through many
years of experience, no settling technique or clarifier is 100 percent
effective; some of the floe is found in the effluent - typically 10 to
20 mg/1. This floe could contain 2 to 10 mg/1 of metal. Polishing
filters or sand filters can be used on the effluent following
clarification. The general effectiveness of such filtering has not been
ascertained.
Sludge Disposal
Clarifier underflow (sludge) contains typically 1 to 2 percent solids
and can be carried to a lagoon. Run-off through porous soil to ground-
water can be objectionable since precipitated metal hydroxides tend to
210
-------
get into adjacent streams or lakes. ' Impervious lagoons »require
evaporation into the atmosphere; however, the average annual rainfall in
many locations balances atmospheric evaporation. Additionally, heavy
rainfalls can fill and overflow the lagoon. Lagooning can be avoided by
dewatering the sludge to a semi-dry or dry condition. ^
Several devices are available for dewatering sludge. Rotary vacuum
filters will concentrate sludge containing 4 to 8 percent solids to 20
to 25 percent solids. Since the effluent concentration of solids is
generally less than 4 percent, a thickening tank is generally employed
between the clarifier and the filter. The filtrate will contain more
than the allowed amount of suspended solids, and must, therefore, be
sent back to the clarifier.
Centrifuges will alsc thicken sludges to the above range of consistency
and have the advantage of using less floor space. The .effluent contains
at least 10 percent solids and is returned to the clarifier.
Pressure filters may be used. In contrast to rotary filters and
centrifuges, pressure filters will produce a filtrate with less than 3
mg/1 of suspended solids. The filter cake contains approximately 20 to
25 percent solids. Pressure filters are usually designed for a
filtration rate of 2.04 to 2.44 liters/min/sq m (0.05 to 0.06 gpm/sq ft)
of clarifier sludge.
Solids contents from 25 to 35 percent in filter cakes can be achieved
with semi-continuous tank filters rated at 10.19 to 13.44 liters/min/sq
m (0.25 to 0.33 gpm/sq ft) surface. A solids content of less than 3
mg/1 is normally accepted for direct effluent discharge. The units
require minimum floor space.
Plate and frame presses produce filter cakes with 40 to 50 percent dry
solids and a filtrate with less than 5 mg/1 total suspended solids.
Because automation of these presses is difficult, labor costs tend to be
high. The operating costs are partially off-set by low* capital
equipment costs.
Automated tank-type pressure filters produce a cake the solids content
of which can reach as high as 60 percent while the filtrate may ^have up
to 5 mg/1 of total suspended solids. The filtration "rate is
approximately 2.04 liters/min/sq m (0.05 gpm/sq ft) filter surface area.
Pressure filters can also be used directly for neutralized wastes
containing from 300 to 500 mg/1 suspended solids at design rates of 4.88
to 6.52 liters/min/sq m (0.12 to 0.16 gpm/sq ft) and still maintain a
low solids content in the filtrate. Filter cakes can easily be
collected in solid waste containers and hauled to land fills.
Several companies have developed proprietary chemical fixation processes
which are being used to solidify sludges prior to land disposal. In
contrast to filtration, the amount of dried sludge to be hauled is
211
-------
increased. Claims are that the process produces insoluble metal ions so
that in leaching tests only a fraction of a part per million is found in
solution. However, much information is lacking on the long term
behavior of the "fixed" product, and potential leachate problems which
might arise. The leachate test data and historical information to date
indicate that the process has been successfully applied in the disposal
of polyvalent metal icns and it apparently does have advantages in
producing easier to handle materials and in eliminating free water.
Utilization of the chemical fixation process is felt to be an
improvement over many of the environmentally unacceptable disposal
methods now in common usage by industry. Nevertheless, chemically fixed
wastes should be regarded as easier-to-handle equivalents of the raw
wastes and the same precautions and requirements required for proper
landfilling of raw waste sludges should be applied.
Evaporation Processes
Basic processes, in addition to evaporation ponds, include multi-stage
flash evaporation, multi-effect long-tube (vertical) evaporation, and
vapor compression evaporation. The multi-stage flash evaporation
process has been considered potentially applicable to the production of
potable water from acid mine drainage.380 Major problems which have
confronted this process are calcium sulfite scaling and brine deposit.
The product water at 50 mg/1 TDS is suitable for recycle to almost all
water uses in steam electric powerplants.
Evaporation ponds are in use at a number of steam electric powerplants
to reduce waste streams to dryness. Plant No. 4883 uses 101,000 sq ft
of lined evaporation pond to evaporate a maximum flow of 43,000 gal/day
of waste water (with treatment, boiler blowdown) to dryness. Configured
systems are being installed at three steam electric powerplants (plant
nos. 0413, 3517 and 4907) . The configured systems use brine
concentrators which recycle the distillate to the demineralizer system
or to the cooling tower. All process 156 gpm of cooling tower blowdown.
However, water treatment wastes, etc., are combined with the
recirculation cooling water. The plants involved are designed to
achieve no discharge of pollutants through recycle of waste water
streams. Therefore, the concentrated brine ultimately contains all
plant wastes. The costs of the units are approximately $2-4/kW with
about 18 months required for installation. The application of
evaporative brine concentrators to low-volume waste stream effluents
after chemical treatment is not known to have been achieved. Therefore,
some technical risks may be involved in applying this technology
directly to low-volume waste water of powerplants.
Other Processes
Membrane processes are capable of acceptably high levels of brine
concentration. However, flux-rate reduction with increasing brine
concentration, and membrane fouling are problems which have not been
212
-------
satisfactorily overcome. Insufficient information is available to judge
the performance, reliability, costs of membrane electrodialysis, ion
exchange, freezing, electrochemical oxidation (of ferrous iron), ozone
oxidization or any other process for the treatment of steam electric
powerplant waste waters.
powerplant Wastewater Treatment Systems
Previous sections of this report have discussed the significant
parameters of chemical pollution present in various waste streams and
the control and treatment technology available to reduce these
parameters to-acceptable limits. It would generally not be practicable
for powerplants to provide separate treatment facilities for each of the
waste streams described. However, segregation and treatment of boiler
cleaning waste water and ion exchange water treatment waste water is
practiced in'a relatively few stations, but is potentially practicable
for all stations. Cily waste waters are segregated from nonoily waste
streams at some stations and the oil and grease removed by gravity
separators and/or flotation units. Combined treatment of waste water
streams is practiced in numerous plants. However, in most cases
treatment is accomplished only to extent that self-neutralization,
coprecipitation and sedimentation occur because of the joining and
detention of the waste water streams. Chemicals are added during
combined treatment at some plants for pH control. Most of these
stations employ lagcons, or ash ponds, while a few plants employ
configured settling tanks. It would be generally practicable, from the
standpoint of costs versus effluent reduction benefits, for powerplants
to treat separately the low-volume waste streams, certain
intermediate-volume waste streams, the high-volume waste streams, and
the waste stream caused by rainfall runoff.
The major problem in providing a central treatment facility is the
variability of the flow characteristics of the waste streams generated
in a powerplant. As previously indicated, some of the flows are either
continuous or daily batch discharges, while others only occur a few
times per year and others depend on meteorological conditions. The
provision of adequate storage to retain the maximum anticipated single
batch discharge is therefore a critica.1 aspect of the design of a
centralized treatment facility. For purposes of this report it has been
assumed that sufficient storage would be provided to store the largest
batch discharge, which in most plants would be the boiler cleaning
waste, and deliver it to the treatment units at an essentially uniform
rate.
A small, highly efficient central treatment facility would be primarily
designed to handle low volume wastes with relatively high concentrations
of heavy metals, suspended solids, acidity, alkalinity, etc. The
addition of intermediate-volume wastes such as cooling tower blowdown
and nonrecirculating ash sluice water to this facility would require a
significantly more costly investment and would not with the same
213
-------
practices be able to affect as high a degree of effluent reduction
(pounds) due to the dilution factors involved. The capital investment
required for inclusion of cooling tower blowdown in the central facility
may be significant. The benefit derived from including this stream in
terms of suspended solids removal is questionable when compared to the
added cost involved. Cooling tower blowdown and nonrecirculating ash
sluice water was not considered in development of the model treatment
facility because the characteristics of these streams are not
necessarily compatible with the treatment objectives of the central
facility. Cooling tower blowdown generally can be characterized by a
relatively high concentration of the total dissolved solids present in
the water source and a somewhat lower concentration of the suspended
solids present in the water source. In addition, tower blowdown
generally contains small concentrations of chlorine and other additives
from the closed cooling system. The objective of directing cooling
tower blowdown to a central treatment facility would most likely be for
the removal of suspended solids. However, in general treatment for
removal of suspended solids prior to the use of water as make up to a
cooling tower would be practiced if the suspended solids level is at all
significant. In any event, some concentration of the suspended solids
level will occur in the tower due to evaporation and, in some cases, due
to contact with airborne particulates. However, the cooling tower basin
also acts as a settling basin to some degree, so that suspended solids
in many cases will settle out in the cooling tower basin. In any case,
the objective of suspended solids removal from these intermediate-volume
waste streams can best be achieved by the commonly employed practice of
using sedimentation lagoons. In some cases in both fossil-fueled (plant
no. 2119) and nuclear plants (plant no. 3905) cooling tower blowdown is
combined with low volume wastes in the sedimentation pond. Better
results can be obtained by segregation of these low-volume and
intermediate-volume waste streams. In plant no. 3905 the pond is
designed for 24 hours detention and is divided by a dike to provide
settled solids accumulation in the forepond to facilitate removal, and
further to prevent short-channeling of waste water flows. Segregation
could have been provided at an incremental cost for the additional
piping required. Where sufficient land is not available for effective
ash ponds and/or where no discharge of heavy metals, etc., would be
required, closed-loop recirculating systems can be employed which
require much less available land. Recirculating ash sluicing systems of
this type are capable of achieving no discharge of ash in waste water
effluents. An example of such a system is the upgraded waste treatment
facility now operating at plant No. 3630. In this system, bottom ash is
sluiced from the ash hoppers and collected in the hydrobins. The
sluicing water is recirculated back to the hoppers thus making a closed
loop system.
214
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wastewater Management
Because of the varied uses that are made of water in a powerplant and
the wide range of water quality required for those uses, powerplants
present unusual opportunities for wastewater management and water reuse.
The highest water quality requirements are for the boiler feedwater
supply. Makeup to this system must be demineralized to TDS
concentrations of the order of 50 mg/1 for intermediate pressure plants
and 2 mg/1 for high pressure plants. Boiler blowdown is generally of
higher purity than the original source of supply, and can be recycled
for any other use in the plant, including makeup to the demineralizers.
In plants using closed cooling water systems, the blowdown from the
cooling system is of the same chemical quality as the water circulating
in the condenser cooling system. Limits on the water quality .in that
system is governed by the need to remain below concentrations at which
scale forms in the condenser. However, if calcium is the limiting
component, the introduction of a softening step in the blowdown stream
would restore the waste to a quality suitable for reuse. Even without
softening, the blowdown from the condenser cooling water system is
suitable for makeup to the ash sluicing system, or for plants using
alkaline scrubbers; for control of sulfur dioxide in stack gases, as
makeup to that system. Plants located adjacent to mines (mine-mouth
plants) often have additional requirements for low quality water for ore
processing at the mine.
With these cascading water uses it is frequently possible to devise
water management systems in which there is no effluent as such from the
powerplant. These plants still have significant overall water
requirements, but the water is used consumptively for evaporation and
drift in cooling towers, for sulfur dioxide removal, or for ash handling
and ore preparation. Figures A-VTI-24, 25 show flow diagrams, taken
from Reference 378, for a typical 600-Mw coal-fired plant, with and
without waste water management to achieve no discharge of pollutants.
An equalization basin is usually provided for temporary large waste
discharges such as result from cleaning operations, but even these
wastes can be reintroduced into the system at a later time. Several
"exemplary" plants visited during this study were using water management
schemes of this type without economic penalties. Water management may
be the most economical mode for operating a powerplant in a water short
area. There can be no doubt that the concept of no discharge of
pollutant is feasible for many steam electric powerplants. A number of
plants within the industry currently practice recycle and reuse in
varying degrees and in a number of different ways. Several plants
constructed within the last few years were designed for minimal or no
discharge. See Figure A-VII-26.
Plant No. 3206 was intended to be a no discharge facility and is
achieving that goal although some operating problems have been
encountered. The plant receives slurried coal by pipeline and after
dewatering reuses the water in its service system. Makeup to the
cooling towers is softened to obtain 16-17 concentrations in the system
and therby minimize blowdown. Ash sluicing water is also recycled and
215
-------
EVAPORATION & DRIFT LOSS
DISCHARGE
BOILER SLOWDOWN
20 GPM
Figure A-VII-24 Sewage and Waste Water Disposal for a Typical Coal-Fired Unit, 600 MW
378
-------
EVAPORATION & DRIFT LOSS
CORROSION INHIBITORS -,
CHLORINE I I
EVAPORATOR + BOILER SLOWDOWN 220 GPM
Figure A-VII-25 Recycle of Sewage and Waste Water for a Typical Coal-Fired Uhit, 600 MW
378
-------
CO
HOPPER JETTING NOZZLES
EVAPORATION 4 DRIFT
.^ RIVER
Figure A-VII-26
RECYCLE WATER SYSTEM, PLANT NO. 2750
254
-------
blowdown from this system along with other blowdown streams are sent to
evaporation ponds for final disposal.
Plant No. 5305 is a mine-mouth facility which also was designed to
produce no discharge other than that resulting from coal pile drainage
and the effluent from the sewage treatment plant. Discharges from plant
operations, including cooling tower blowdown, water treatment wastes,
boiler blowdown, floor drains and blowdown from a closed ash sluicing
system are collected in effluent storage ponds. Makeup to the ash
sluicing operation is taken from these ponds, but the major portion of
the water is transported to the mine and coal preparation plant. The
plant is an excellent example of cascading water reuse to usages
requiring successively lower water quality. A large amount of the water
withdrawn from the river is lost through evaporation in the cooling
towers. The remainder is either ultimately tied up with filter cake at
the coal preparation plant or disposed of with wet ash. Both the filter
cake and the ash are returned to the mine for use as fill.
Plant No. 0801 utilizes a series of ponds to achieve intermittent
controlled discharge for use in irrigation. The ponds provide the water
required for condenser cooling, boiler feed, flue gas scrubbing and ash
sluicing. Ash sluice, boiler blowdown and scrubber wash water are
discharged to two alternately used ash ponds. Overflow from these ponds
and condenser cooling water are discharged to a series of three ponds or
lakes. The third in the series of ponds serves as the water source,
thus providing a completely closed system.
Several generating stations are utilizing closed-loop recirculating
systems for ash sluicing operations. Systems of this type are capable
of achieving no discharge of as in wastewater effluents. Examples of
such systems include plants 3630 (a retrofit) and 3626. . Both of these
installations collect sluiced bottom ash in hydrobins, and recirculate
the water back to the ash hoppers for sluicing. This type of system is
particularly suited to plants where sufficient land is not available for
effective ash ponds. Plant No. 4846 also utilizes a closed-loop ash
sluicing system, but employs an ash pond with discharge from the pond
being pumped back to the plant.
Plant No. 3630 has a retrofit system for achieving no discharge of
pollutants from bottom ash sluicing, boiler cleaning wastes, floor
drainage, boiler blowdown, evaporator blowdown, and demineralizer
wastes. This is achieved through the re-use of neutralized
demineralizer waste water, boiler cleaning effluents, floor drainage,
boiler blowdown, and evaporation blowdown in the ash sluicing operation.
Ultimate blowdown is achieved through the moisture content (15-20
"percent) of the bottom ash discharged to trucks for off-site use. Fly
ash, handled dry, is also trucked to off-site uses. The plant capacity
is 600 Mw and operates in the base-load mode. The bottom ash recycle
and handling system occupies a space approximately 200 ft square. The
entire system cost about $2 million including equipment, foundations.
219
-------
re-piping, pumps, and instrumentation and took approximately two years
to install including engineering, purchasing, delivery, and
installation. The same plant retrofit a system for collecting and
filtering coal-pile drainage and road and building drainage. The coal
pile trench is designed to handle drainage from a "once-in-30-years"
rainfall (3.9 inches) . The filtering pond is 100 ft in diameter and the
filter bed is sand. Trash from the bar screens of the intake is buried
on-site. The demineralizer neutralization system cost about $80,000,
the boiler cleaning effluent tanks about $100,000, re-piping about
$250,000, and the intake screen washing system about $35,000.
Other plants employ various recycle and reuse techniques depending upon
their water needs, environmental effects, plant layout, etc. Plants
2119 and 4217 utilize cooling tower blowdown as makeup to the ash
sluicing system. Plant No. 3713 discharges treated chemical wastes from
the ash pond into the intake to the condenser cooling water stream.
Plant No. 4216 utilizes a closed-loop wet scrubbing device for air
pollution control, and plant 2512 sluices fly ash from an electrostatic
precipitator to a pond and reuses the water in the sluicing system.
A number of plants, including Nos. 2512, 2525, 3601A, and 4217 utilize
central treatment facilities or ponds to treat chemical type wastes to
acceptable levels for discharge. The effluents produced could be
reused, but the availability of an adequate, cheap water supply has not
made this necessary in these instances.
Recycling in nuclear plants and plants with no ash sluicing will depend
primarily upon treatment of cooling tower blowdown and re-use of the
blowdown as make up to the tower. The wastes resulting from water
treatment could be recycled to the influent of the water treatment
plant. Blowdown from these internal recycling schemes would be treated
by desalination techniques to remove total dissolved solids, and as a
result, water produced by this treatment could also be recycled. In
plants where a water surplus would occur, the intent would be complete
treatment for removal of all pollutants and discharge of clean water to
the receiving stream. This interpretation of "no discharge" is meant to
be no discharge of pollutants, rather than no discharge of any liquid
stream. Generally, however, it is anticipated that even nuclear plants
and plants with no ash sluicing will not have a water surplus, but will
require makeup to the various internal recycling schemes.
In any case the degree of practicability of recycle and re-use systems
would be favored in cases where; a) Tower construction is corrosion
resistant to water high in TDS, sulfates and chlorides, b) Piping
systems and equipment are lined or resistant to corrosion, c) Condenser
leakage affecting feedwater quality for sustained power operation is
minimized or compensated for. d) Sludge handling and disposal
facilities are adequately designed and available, e) Designs for tower
operation at a high nuirber of cycles of concentration could be feasible
220
-------
if windage and drift losses are minimized to eliminate heavy carryover
of solids to the surrounding areas.
In summary, the concept of recyle or re-use is not new to the steam
electric powerplant industry* Many plants utilize a variety of recycle
schemes to satisfy particular needs, and these systems have the
potential for broad application in the industry to meet effluent
limitation guidelines.
Summary
Table A-VIII-5 provides a summary of the control and treatment
technology for the various waste streams. The table includes the
effluent reduction achievable with each alternative, the usage in the
steam electric powerplant industry and approximately capital and
operating costs. Table A-VIII-6 summarizes flow data for chemical
wastes, indicating the range of values from reported data and typical
flows or volumes for each chemical waste stream.
The' costs of the application of various control and treatment
technologies in relation to the effluent reduction benefits to be
achieved are given in Table A-VII-7 for large volume waste streams.
Table A-VII-8 for intermediate volume waste streams. Table A-VII-9 for
low volume waste streams, and Table A-VII-10 for rainfall waste streams.
221
-------
TABLE a-VII-5
CHEMICAL WASTES
CONTROL S TREATMENT TECHNOLOGY
Control and/or
Treatment
Pollutant Parameter Technology
Common :
pH Neutralization
with chemicals
Dissolved Solids 1.
2.
3.
Suspended Solids 1 .
2.
3.
Specific:
Phosphate 1.
(Blowd own, chemical
Cleaning, Floor &
Yard Drains, Plant
Laboratory & Sampling)
2.
Iron 1 .
(Water Treatment,
Chemical Cleaning
Coal Ash Handling,
Coal Pile Drainage) 2.
Copper 1 .
(Once-through
Condenser Cooling)
Copper 1.
(Slowdown, Chemical
Cleaning)
2.
3.
Mercury 1 .
(Coal -Ash Handling
& Coal Pile Drainage)
2.
3.
Vanadium 1.
(Chemical cleaning)
2.
Vanadium 1.
(Oil Ash Handling)
2.
Concentration and
e vaporat ion
Reverse Osmosis
Distillation
Sedimentation
Chemical Coagulation
and Precipitation
Filtration
Chemical coagulation
and Precipitation
Deep Well Disposal
Oxidation, chemical
coagulation &
precipitation
Deep Well Disposal
Replace condenser
tubes with stain-
less steel or
Titanium.
Chemical Coagulation
and Precipitation
Ion Exchange
Deep Well Disposal
Reduction S Precip-
itation
Ion Exchange
Adsorption
H S Treatment & /""
Precipitation 3
Ion Exchange /
Convert to Dry
Collection
Total Recycle with
Slowdown fi Pre-
Effluent
Reduction
Achievable
Neutral pH
Complete Removal
50-95%
60-90%
90-95%
95-99%
95%
Industry
Usage
Common
Not generally
in use De-
salinization
technology
Not in use
Desalinization
technology.
Not in use
Desalinization
technology .
Extensive
Moderate
Not generally
pract iced-water
treatment
technology.
Not generally
practiced-water
treatment
technology.
Ultimate Disposal Not practiced
Costs
Capital Operating
$10-20,000 (tanks, $3-30,000 (Chemicals,
feeder, etc.) labor, etc.)
$250 , 000-$ 1 , 660 , 000 $150 , 000-$450 , 000
from Table A-VIII-5; from Table A-VIII-6;
costs are signifir costs are significantly
cantly less in areas less in areas where
where evaporation evaporation ponds are
ponds are feasible, feasible.
50-SO
-------
Table A-VII-5
CHEMICftL WASTES
CONTROL S TREATMENT TECHNOLOGY
(continued)
Pollutant Parameter
Chlorine
(Once-through Con-
denser Cooling)
Chlorine
(Recirculating)
Aluminum/Zinc
(Water Treatment,
Chemical Cleaning,
Coal Ash Handling,
Coal Pile Drainage)
Oil
(Chemical Cleaning,
Ash Handling, Floor
s Yard Drains)
Phenols
(Ash Handling, Coal
Pile Drainage, Floor
s Yard Drains)
Sulfate/Sulfite
(Water Treatment,
Chemical Cleaning,
Ash Handling, Coal
Pile Drainage, SO
Removal)
Control and/or
Treatment
Technology
1. Control of Residual
C12 with automatic
instrumentation
2. utilize mechanical
cleaning
1. Control of Residual
Cl with automatic
instrumentation
2. Reduction of Cl
with sodium
bisulfite
1. Chemical Precip-
itat ion
2. ion Exchange
3. Deep Well Disposal -
1. Oil-water Separator
(Sedimentation
with skimming)
2. Air Flotation
1. Biological
Treatment
2 . Ozone Treatment
3. Activated Carbon
Ion Exchange (Sulfate)
Oxidation £ Ion
Exchange (Sulfite)
Ammonia 1. Stripping
(Water Treatment,
Slowdown, Chemical
Cleaning, Closed
Cooling Water Systems)
2. Biological
Nitrification
3 . Ion Exchange
Oxidizing Agents
(Chemical Cleaning)
BOD/COD
(Sanitary Wastes)
COD (Water Treatment
Chemical Cleaning)
Fluoride
(Chemical cleaning)
Neutralization with
reducing agent and
precipitation where
necessary.
Biological Treatment
, 1. Chemical Oxidation
2 . Aeration
3. Biological Treat.
Effluent
Reduction
Achievable
Control to
0.2 mg/1
Eliminates
Cl discharge
Industry
Usage
Costs
Capital
Operating
Limited usage in $5,000 Negligible'
the industry-
Technology from
sewage treatment
practiced in some No Cost Data Available
plants -a 11 systems
are not capable of
being converted to
mechanical cleaning .
Below detect-
able limits
Removal to
1.0 mg/1
Similar to
Copper
Removal to
15 mg/1
Removal to
10 mg/1
Removal to
1 mg/1
Removal to
<0.01 mg/1
Removal to
< 0.01 mg/1
75-95%
50-90%
Removal to
2 mg/1
80-95%
Neutral pH &
^95% removal
85-95%
85-95%
85-95%
85-95%
Chemical Precipitation Removal to
1 mg/1
Being installed in No Cost
a new nuclear
f ac ility ; however
excess NaHSO is
discharged.
Limited usage
Common usage
Limited usage
Not practiced
in the industry.
Not practiced
in the industry.
Not practiced
in the industry.
Not practiced
in the industry.
$500-$3000/1000 gpd
$1,500-$ 15, 000
based on 500 gal/MW
25-400 MW range
$5,000-$50,000
$150-$2800/1000 gpd
No data
$50-$ 350/1000 gpd
Data Available
10-1804/1000 gal.
No data
No data
224/1000 gal.
No data
44-154/1000 gal.
Total cost of $2.00/1000 gal.
Not practiced? Total cost - 34/1000 gal.
several installa-
tions in sewage
treatment
Not practiced for No Data Available
these waste' streams
Not practiced Total cost - IOC/1000 gal.
Limited usage
Common practice
Limited usage
Not practiced
Not practiced
Limited usage
No Data
$25,000-$35,000
NO Data
No Data
No Data
Available
Negligible
Available
Available
Available
Total cost - 10-504/1000 gal.
Boron
(Low Level Radwastes)
Ion Exchange
Removal to
1 mg/1
223
Not generally
pract iced-rad io-
active material would
concentrate on ion
exchange resin requir-
ing inclusion in solid
radwaste disposal
system.
No
Data
Available
-------
TABLE A-VII- 6
PLOW RATES-CHEMICAL WASTES
Waste Stream
Condenser Cooling Water
Once-Through
Recirculating
Water Treatment
Clarification
Softening
Ion Exchange
Evaporator
Boiler Slowdown
Chemical Cleaning
Boiler Tubes
Boiler Fireside
Air Preheater
Misc. Small Equip.
Stack
Cooling Tower Basin
Ash Handling
Drainage
Coal pile
Reported Data
Waste Flow or Volume
20-7200 x 103 GPD
No Discharge
No Discharge,
1-533,00 x 10 GPD
-3
0.1-1060 x 10 GPD
0.05-1120 x 103 GPD
3-5 Boiler Volumes
24-720 X 10 GAL.
43-600 x 103 GAL.
No reported data
No reported data
No reported data
5-32,000 x 103 GPD
c
17-27 X 10° GAL/YR.
Typical
Frequency Flow or Volume Basis
500-1500 GPM/MW
Varies from 0,3% to 4% of
curculating water flow.
52-365
cycles/yr .
300-365
cycles/yr.
25-365
cycles/yr.
once/7 mos.- 1 boiler vol. per Frequency-once
once/100 mos. 1-2 hrs. -Boiler per 24-30 mos.
draindown time.
2-8/yr. 300,000 GAL. 5/yr.
4-12/yr. 200,000 GAL. 6-12/yr.
-
Dependent Reported data
on rainfall based on 43-60
inches of rain
year.
Remarks
Flow reported in FPC
Form 67.,
Blowdown depends on wate:
quality and varies from
2-20 concentrations.
Extremely variable-
depending on raw water
quality.
Extremely variable-
depending on raw water
quality.
Flow reported in FPC
Form 67.
Cleaned infrequently
Cleaned infrequently
Overflow from ash punus
reported in FPC Form 67.
Flow dependent upon
frequency, duration and
intensity of rainfall
Floor & Yard Drains No reported data
Air Pollution Control No Discharge
Devices
Flow dependent upon fre-
quency & duration of
cleaning and stormwater
runoff.
Misc. Waste Streams
Sanitary Wastes
No reported data
25-35 gal/capita/ Personnel:
day operators-1 per 20-40 MW
maintenance-1 per 10-15 MW
administrative-1 per 15-25 MW
Plant Laboratory and No reported data
Sampling
Intake Screen Backwash No reported data
Closed Cooling Systems No reported data
Low Level Rad Wastes No reported data
Construction Activity No reported data
5 gal./day
224
Nominal, variable flow
Guideline requires col-
lection & removal of
debris-flow data not
significant.
Flow extremely vari-
able depending on treat-
ment techniques, leakage,
etc.
Flow depends primarily
on rainfall.
-------
Table A-VII-7
COSTS/EFFLUENT REDUCTION BENEFITS
CONTROL AND TREATMENT TECHNOLOGY FOR POLLUTANTS OTHER THAN HEAT
HIGH VOLUME WASTE STREAMS-
Waste Stream: Nonrecirculating main condenser cooling water
Pollutant / Technology
Cost / Effluent Reduction Benefit,
[mill/tea] / [mg/l]effluent concentration
ro
ro
en
Chlorine-free available
Uncontrolled addition(S)
Controlled addition(S) less than
Shutdown mechanical cleaning(S)
On-line mechanical cleaning
Chemical addition treatment*(N)
Alternative biocide use*(N)
Copper
Present system(C)
Alternative condenser
tube material(S)*
One-stage chemical treatment(N)
Base
0.01/2
0.01/approaching 0
0;01/approaching 0
for existing units
less than 0.01/approaching 0
for new units
Prohibitive
Unknown
Base
Prohibitive for existing
units
0.01/0 "for new units
Prohibitive
Meaning of C
Symbols CT
PT
commonly employed N
currently transferrable S
potentially transferrable *
= net known to be practiced
= some usage
= may substitute one pollutant
for another
-------
Table A-VII-8
COSTS/EFFLUENT REDUCTION BENEFITS
CONTROL AND TREATMENT TECHNOLOGY FOR POLLUTANTS OTHER THAN HEAT
-INTERMEDIATE VOLUME WASTE STREAMS-
Waste Streams: Slowdown from recirculating main condenser cooling water systems
Nonrecirculating ash sluicing water
Nonrecirculating wet-scrubber air pollution control systems
Nonrecirculating house service water
Pollutant / Technology
Cost / Effluent Reduction Benefit,
[mill/KWH] / [mg/l] concentration
Chlorine-free available
Uncontrolled addition(S)
Controlled addition(S)
Shutdown mechanical cleaning(S)
..On-line mechanical cleaning(S)
Chemical addition, treatment* (S)
Alternative biocide use*(N)
Copper-total
Present system(C)
Alternative condenser
tube material(S)*
One-stage chemical treatment(N)
Chemical Additives
Uncontrolled addition(S)
Controlled addition.(S)
Chemical subst itut ion*(S)
Design for corrosion protection(C)
Mercury-total
Present system(C)
One-stage chemical treatment(CT)
Fuel substitution(N)
Oil and Grease
Present system(C)
One-stage separation(S)
Two-stage separation(CT)
Total Phosphorus (as P)
Present system (S)
One-stage chemical treatment(CT)
Chemical treatment
with filtration(CT)
Chemical substitution (PT)
PH value
Present system(C)
Coneutralizat ion(C)
Chemical addition (6)
Total Suspended Solids
Present system(C)
Conventional solids separation(C)
Fine solids separation(CT)
Dry ash handling system(S)
Total Dissolved Solids
Present system(N)
Brine concentration(CT)
.Chromiuai-total
'present system (S)
Chemical treatment (CT)
Chemical substitution (PT)
Zinc-total
Present system (S)
Chemical treatment (CT)
Chemical substitution (PT)
Base
less than 0.01/2
0.01/approaching 0
0.01/approaching 0
for existing units
less than 0.01/approaching 0
for new units
0.01/approaching 0
Unknown
Base
Prohibitive
for existing units
0.01/0 for new units
0.03/1
Base
Better than base
Unknown
Costly for existing
closed coaling
systems
less than 0.01/approaching 0
for new systems
Base
Unknown/0.3
Unknown
Base
0.01/10
0.02/8
Base
0.03/5
0.05/less than 5
Unknown
Base
less than 0.01
less than 0.01
Base
0.01/15
Prohibitive
0.01/sign. red.
Base
Prohibitive
Base
(SI/1000 gal)/0.2
Unknown
Base
0.05/1
Unknown
Meaning of C = commonly employed
Symbols CT = currently transferrable
PT = potentially transferrable
N = not known to be practiced
S ='some usage
* = may substitute one pollutant
for another
226
-------
Table A-VII-9
COSTS/EFFLUENT REDUCTION BENEFITS
CONTROL AND TREATMENT TECHNOLOGY FOR POLLUTANTS CITHER THAN HEAT
-LOW VOLUME WASTE STREAMS-
Waste Streams:
Slowdown from recalculating ash-sluicing systems
Slowdown form recirculating wet-scrubber air
pollution control systems
Boiler blowdown
Cooling tower basin cleanings
Floor drainage
Intake screen backwash
Laboratory and sampling streams
Low-level radwastes*
Miscellaneous equipment cleaning
- Air preheater
- Boiler fireside
- Boiler tubes
- Small equipment
- Stack, etc.
Sanitary system
Service and small cooling water systems blowdown,
Water treatment
etc.
Technology / Pollutant
Cost / Effluent Reduction Benefit,
[mill/KWH] , [mg/1] ... . . .
' effluent concentration
Present System(C)
One-Stage Chemical Treatment(S}
Copper-total
Iron-total
Heavy metals in general
Oil and grease
pH value
Total Suspended Solido
Numerous misc. parameters
Two-Stage Chemical Treatment(CT)
Chromium-total
Copper-total
Iron-total
Heavy metals in general
Oil and grease
pH value
Total suspended solids
Numerous misc. parameters
Brine Concentration and Recycle(PT)
All parameters
Biological Treatment(C)
BOD, etc.
Base
0.05 mill/KWH
10 mg/1
10 mg/1
10 mg/1
10 mg/...
6.0 to 9.0
15 mg/1
significant reductions
0.1 mill/KWH
0.2 mg/1
1 mg/1
1 mg/1
1 mg/1
< 10 mg/1
6.0 to 9.0
15 mg/1
significant reductions
0.5 mill/KWH
no discharge
0.01 mill/KWH
municipal stds.
Meaning of C = commonly employed
Symbols CT = currently transferrable
PT = potentially transferrable
N = not known to be practiced
S = some usage
* = no applicable technology due to
possible radiation hazards
227
-------
Table A-VII-10
COSTS/EFFLUENT REDUCTION BENEFITS
CONTROL AND TREATMENT TECHNOLOGY FOR POLLUTANTS OTHER THAN HEAT
-RAINFALL RUNOFF WASTE STREAMS-
Waste Streams:
Coal-pile drainage
Yard and roof drainage
Construction activities
Technology / Pollutant
ro
ro
oo
Present System(C)
Conventional Solids Separation(S)
Oil and grease
pH value
Total suspended solids
One-Stage Chemical Treatment of
First 15 Minutes Runoff (CT)
Oil and grease
pH value
Total suspended solids
Numerous misc. parameters
One-Stage Chemical Treatment of
Entire Runoff(N)
Two-Stage Chemical Treatment(N)
Cost / Effluent Reduction Benefit,
[mill/KWH] , tmg/l] concentration
Base
0.01 mill/KWH
no reduction
no change
15 mg/1
0.01 mill/KWH
10 mg/1
6.0 to 9.0
15 mg/1
significant reductions
unknown
unknown
Meaning of
Symbols
C = commonly employed
CT = currently trans ferrable
PT = potentially transf errable
N = not known to be practiced
S = some usage
-------
PART A
CHEMICAL WASTES
SECTION VIII
COST, ENERGY AND NON-WATER QUALITY ASPECTS
Introduction
This section discusses cost estimates for the control and treatment
technology discussed in the previous section, energy requirements for
this treatment technology and non-water quality related aspects of this
technology such as recovery of byproducts, ultimate disposal of brines
and sludges, and effects on the overall energy situation.
The estimates contained herein assume ample availability of land. It is
recognized that powerplants located in highly developed urban areas may
incur costs several times in excess of those shown. Other assumptions
include no unusual foundation or site preparation problems. Estimates
do not consider regional differences in construction costs.
Although powerplants produce many different wastewater streams with
different pollutants and different flow characteristics, the most
feasible concept of treatment consists of the combination of all
compatible wastewater streams, with equalization or holding tanks to
equalize the flow through the treatment units. Figure A-VIII-1 shows a
typical flow diagram for a possible central treatment plant for chemical
wastes. Two equalization basins provide separate storage for oily and
oil-free wastes. The main treatment unit is a clarifier; lime is added
to raise the pH to a level at which most of the metallic ions are
precipitated. A flocculant is added to assist in the precipitation.
Wastewater treatment facilities for treating chemical wastes therefore
consist essentially of a series of tanks and pumps, and interconnecting
piping: special equipment such as pressure filters, vacuum filters,
centrifuges, or incinerators as may be required. Tanks serve for
several purposes, as equalization tanks to permit the following units to
operate under constant flow conditions, as neutralization tanks to
adjust acidity or alkalinity, or as coagulation and precipitation tanks
to provide for mixing of a coagulant, the formation of the precipitates
and the separation of the precipitates from the treated flow. In most
cases, the mechanical equipment inside the tank is a minor cost
consideration, although in the case of certain types of tanks used for
softening and similar reactions the equipment cost may be significant.
Chemical feeders may be of the dry volumetric type or of the solution
type. in either case, the cost of the feeder is likely to be minor,
although costs of associated equipment for the storage of chemicals is
229
-------
often significant. A substantial amount of data is available on
chemical feeders.
Two cost analyses are presented. The first cost analysis is based on
the concept of a central treatment plant as shown in Figure A-VIII-l for
all low-volume waste waters containing chemical pollutants. Table A-
VIIl-1 shows the design flows assumed for this plant. The second cost
analysis is based on the concept of complete treatment of chemical
wastes with no discharge of pollutants.
Tables A-VIII-2, A-VIII-3, and A-VIII-4 contain estimates of capital
costs, operating costs and annual and unit costs for a central chemical
waste treatment. Estimates are presented for three sizes of powerplants
with generating capacities of 100 MW, 500 MW and 1000 MW respectively.
The unit cost of treatment is computed under three assumptions as to
plant capacity factors. The first assumption is a capacity factor of
1.0, representing continuous operation at full capacity. Unit costs are
also presented for capacity factors of 0.67, representative of base load
plants, and 0.35, representative of cycling plants. Under these
assumptions and conditions, the cost of treating chemical wastes is
found to vary from 0.05 mills per KWH to 0.38 mills per KWH.
Wastes not Treated at Central Treatment Plant
The following wastes are not considered suitable for treatment at a
central treatment plant for chemical wastes:
Cooling water (once-through system), cooling water blowdown (closed
system) , sanitary wastes, roof and yard drains, coal pile runoff, intake
screen backwash, radwastes, nonrecirculating ash sluice water,
nonrecirculating wet-scrubbing air pollution control waste water, and
once-through (nonrecirculating) house service water.
Cost factors applicable to the treatment of these wastes are discussed
in the following paragraphs. None of the costs are of a sufficient
magnitude to result in a detectable increase in the unit cost of
generation.
Cooling Water-Once Through Systems
The treatment technology for once-through condenser cooling water
systems consist of maintaining the residual chlorine in the effluent
below an established limit by controlling the chlorine added to the
system. The capital costs involved consist of the cost of a residual
chlorine analyzer and feedback controls to adjust the feed rate. The
installed cost of a residual chlorine analyzer and control equipment is
estimated to be about $5,000 regardless of size of unit. This cost is
easily amortized through savings realized by reduced consumption of
chlorine.
230
-------
Ufc. i SAMPU1& 5TWW»
* r
pll- 6* _
eouALiTATioil
TAUK.
teoo«*l/M*)
O.'OTSM'/C
( 19 GPD/K
UAt *01L PIB6D PLAM1%)
PTtoWAL PATtJ FOB COAL flB6D
poe. COST
CHEMICAL rfASTES-IENTRAI, TREATMENT PLANT
FIGDBE A-VIII-1
-------
TABLE A-VIII-1
DESIGN FLOW FOR CHEMICAL WASTES TREATMENT PLANT
Waste Stream
Ion exchange
Evaporator blowdown
Boiler blowdown
Boiler tube cleaning
Boiler fireside cleaning
Air preheater cleaning
Misc. small equipment
& stack cleaning
Cooling tower basin
Lab. & sampling streams
Average Volume per day-MW
Frequency
Daily
Daily
Daily
I/year
2 /year
6 /year
2/year
2 /year
. Daily
Total Volume/MW
m3
0.333
0.208
0.137
0.34
6.06
15.9
-
-
-
Assumed Design
Gal
88
55
52
90
1600
4200
-
-
-
Average Volume
Per Day-MW
m^
0.333
0.208
0.197
-
0.017
0.044
0.004
0.004
0.044
0.847
0.88
Gal
88
55
52
0.25
4.44
11.7
1.11
2.11
10
223.61
230
ro
CO
ro
-------
TABLE A-VIII-2
ESTIMATED CAPITAL COSTS
CHEMICAL WASTES TREATMENT PLANT
CO
Descriotion
Equalization tank
Treatment tank
Holding tank
Clarifier
Filter
Pump
Piping
Ma jot equipment cost
Installation cost @50%
Instrumentation cost @20%
Total construction cost
Engineering (§>15%
Contingency @>15%
Total capital cost
Powerplant Generating Capacity
100 MW
$ 42,500
4,700
3,400
7,000
32,000
3,200
3,200
$ 94,000
47,000
18,800
$159,800
24,000
24,000
$207,800
500 MW
$124,000
6,800
7,900
16,000
40,200
2,000
3,200
$201,100
100,500
40,200
$341,800
51,300
51,300
$444,400
1000 MW
$248,000
7,800
9,400
22,000
61,000
2,500
7,900
$359,400
179,700
71,900
$611,000
91,700
91,700
$794,400
-------
TABLE A-VIII-3
ESTIMATED ANNUAL OPERATING COSTS
CHEMICAL WASTES TREATMENT PLANT
Description
Chemicals and Power
Requirements :
Lime
Flocculants
Electricity
Annual Costs:
Operat ing labor
Lime
Floccularit
. Electricity
Annual Operating Cost:
Exclusive of labor
Including labor
Units
tons/year
Ibs/year
HP
$15,000
$27/ton
$0.05/lb
12 mils/KWH
Powerplant Generating Capacity
100 MW
54
4200
10
$75,000
1,500
2,100
900
$ 4,500
$79,500
500 MW
275
21.000
30
$105,000
7,400
10,500
2,600
$ 20,500
$125,500
1000 MW
550
42,000
75
$135,000
15,000
21,000
6,500
$ 42,500
$177,500
ro
-------
TABLE A-VIII-4
ESTIMATED ANNUAL AND UNIT COSTS
CHEMICAL WASTES TREATMENT PLANT
ro
CO
in
Description
Total capital costs
Fixed charges @15%
Maintenance @3% of construction cost
Annual operating cost excluding labor
Operating labor
Total annual costs :
t
Unit costs, mils/KWH of
Generating capacity
Production (base load)
Production (cycling plant)
Powerplan
100 MW
$207,800
31,200
4.800
4,500
75,000
$115,500
0.132
0.200
0.377
t Generating
500 MW
$444,400
66,700
10,300
20,500
105,000
$202,500
0.046
0.07
0.14
Capacity
1000 MW
$794,400
119,200
18,300
42,500
135,000
$315,000
0.036
0.054
0.11
-------
Cooling Water Slowdown - Closed Systems
The treatment technology is essentially the same as for a once-through
system. Residual chlorine is monitored in the effluent, and blowdown is
permitted only when the residual chlorine is below the established
limit. It is possible to schedule blowdown only at such times when the
residual chlorine level meets the effluent limitation. Additional costs
would occur in cases where sedimentation would be provided for suspended
solids removal, and where chemical treatment would be required for
removal of chromium, phosphorus, or zinc. Sedimentation costs, where
needed, would be approximately 7 cents/1000 gallons treated and chemical
treatment costs, where needed, would be about $1/1000 gallons.
Sanitary Wastes
Sanitary wastes are generally discharged to municipal sewerage systems,
or if municipal sewers are not available, treated in biological process
treatment plants. The volume of sanitary wastes is primarily a function
of the size of the labor force. For most powerplants in isolated
locations, a minimum size factory preassembled activated sludge type
treatment plant will provide adequate treatment. The installed cost of
these plants is estimated to be $25,000 - $35,000 depending on
geographic location.
Coal Pile Runoff
The cost of coal pile runoff treatment is a function of the
meteorological conditions at each particular site. Capital costs of
lined retention ponds capable of holding various volumes of runoff are
shown in Figure A-VIII-2. Costs for liming contents of pond will vary
with pH and frequency of treatment.
Intake Screen Backwash
The incremental cost of land disposal of debris removed from intake
screens would be very insignificant in most Ceases.
Radwaste
No treatment is assumed due to possible hazardous effects of
concentrating radioactive wastes.
Nonrecirculating Ash Sluice Water
In cases where sedimentation would be required for suspended solids
removal from ash sluice water, the costs would be about 7 cents/1000
gallons. Having achieved adequate suspended solids removal, the
effluent is suitable for recycle for ash sluicing, which would involve
an incremental cost for pumps, piping and blowdown controls.
236
-------
140
120
T
100
o
Q
O
o
o
80
4J
to 60
o
u
•P
•H
ft
3 40
20
©
0
©
Storage Capacity of Pond in
Terms of Runoff from Pile Area
1.25 cm (0.5")
3.75 cm (1.5")
7.5 cm (3")
10
I
20
30
400 800 1200
Area of Coal Pile
40
1606
50 acres
2000 hm2
COST FOR COAL PILE RUNOFF COLLECTION
FIGURE A-VIII-2
237
-------
The backfitted configured recirculating ash sluicing system at plant No.
3630 cost approximately 3 million dollars to handle the bottom ash from
coal burned at a rate of 3,000 tons/day. However, the costs for this
system include modification of floor and yard drainage, neutralization
and disposal of dendneralizer and boiler cleaning wastes and
modification of trash screens as well as the configured ash water
recycle system. System components include a coal pile trench,
collecting basin, filtering pond, neutralizing tanks, pumps, piping,
hydrobins, settling tank and recirculating tank. The system is designed
to achieve no discharge of pollutants except for those contained in the
moisture removed with the settled ash.
Complete Treatment ^.of Chemical Wastes for Reuse
Costs associated with the complete treatment of chemical wastes for
reuse within the plant will vary from plant to plant. In order to
arrive at an estimate of typical costs likely to be incurred by an
existing plant in implementing a complete water reuse plan, conceptual
flow diagrams have been developed for such plans for coal-fired and oil-
fired powerplants. These flow diagrams are shown jji Figures A-VIII-3
and A-VTII-4. Cost estimates were then prepared based on these flow
diagrams.
The three major process units required to provide a complete treatment
of chemical wastes for reuse within a powerplant include a softener and
chemical feed system to reduce the hardness of the cooling tower
blowdown, a brine concentrator to preconcentrate the blowdown brines
resulting from the recirculating of ash sluicing water, and an
evaporator-dryer to finally reduce the sludge to a solid cake for
disposal by landfill.
Tables A-VIII-5, A-VIII-6 and A-VIII-7 contain estimates of capital
costs, operating costs, and annual and unit costs for a complete
treatment system for chemical wastes. This system will produce no
discharge of pollutants while returning the water to the process for
reuse. The costs shown in these tables represent upper limits of cost.
At some plants it may not be necessary to concentrate brine and
evaporate to dryness. For example, plants in the southwestern United
States will probably be able to utilize evaporation ponds at a
substantial saving in cost. Mine-mouth plants will frequently have
requirements for large volumes of low quality water for coal processing
with ultimate disposal to the mine. The estimates assume that no
alternate ultimate disposal methods for the brines are available and
that evaporation to dryness is the only feasible method of ultimate
disposal. Under these assumptions, the cost of complete treatment is
estimated to be 0.30 mills per KWH and the assumption of a unity
capacity factor, for a 100 MW plant and 0.11 mills per KWH for a 1,000
MW plant. For a typical base load plant operating at a capacity factor
of 0.67, these costs increase to 0.45 mills for a 100 MW plant and 0.17
mills per KWH for a 1,000 MW plant. Costs for a typical plant operated
238
-------
- o.4-C6/iojoooBio
- I«i000 »TU />-«>•
.- T.6 L»/10,000»TO
. .
ARE'S "y.
100 HM COAL-FIBED STEAM EI£CTCIC PCMERPLANT
RRCY£I£ AND REUSE OF CHEMICAL HASTES
FIGURE A-VIH-3
-------
_J
•sittr
CLEAUlUft
WAS>T6*
9000SPV
\
JWATeRl
UB-i
SAMpCiHl
STRfAw
1000 &t
(A«OMg
3
S
3
»)
OIL fOtt
e««oft.u
\
•
Flooe AUD
YARD
TOAIUAS6
.HA
f *
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w/ATee. PE.OOOCED IM FXue SA-&ES- o,e4
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$ BfcillJ CLEAUIKIS ~5500 SPY
OftwATlejSI
/
LEGeUO
\VA^t^.
K ii • oil
-*-«-*-OPTNOMAV
MOI&T SOLIDS
100 MH OIL-FIHED STEAM EIECTRIC POWERPIAHT
RECYCI£ AND REUSE OF CHEMICAL iJASTES
FIGURE A-VIII-4
-------
TABLE A-VIII-5
ESTIMATED CAPITAL COSTS
TREATMENT OF CHEMICAL WASTES
Description
Cooling tower blowdown treatment
Ash -hand ling system modifications
Brine concentrator
Evaporator
Major equipment cost
Installation cost @60%
Instrumentation d>20%
Construction cost
Engineering d>15%
Contingency @15%
Capital costs:
Reuse facilities
Waste treatment plant
Total capital cost
Powerplant Generating Capacity
100 MW
$ 36,300
10,400
77,000
40,000
$163,700
98,200
32,700
$294,600
44,200
44,200
$383,000
207,800
$590,800
1000 MW
$121,300
37,000
460,000
.250,000
$868,300
521,000
73,400
$1,562,700.
234,300
234,300
$2,031,300
794,400
$2,825,700
-------
TABLE A-VIII-6
ro
ESTIMATED ANNUAL OPERATING COSTS
TREATMENT OF CHEMICAL WASTES FOR REUSE
Description
Chemicals and Power
Requirements :
Lime
Flocculants
Electric Power
Steam
Annual Costs:
Operating Labor
Lime
Electricty
Steam
Flocculants
Total Operating Cost:
Excluding labor
Including labor
Units
tons/yr
Ib/yr
HP
10 J Ib/yr
Unit Cost
$15,000
$27/ton
12 mils/kwh
1 mil/lb
$0.50/lb
Powerplant Generating Capacity
100MW
80
4,200
140
8,760
$135,000
2,200
12,300
8, gOO
2,100
$ 25,400
$160,400
1000MW
800
42,000
1,100
87,600
$270,000
21,600
96,400
87,600
21,000
$225,600
$495,600
-------
TABLE A-VIII-7
ESTIMATED ANNUAL AND UNIT COSTS
TREATMENT OF CHEMICAL WASTES FOR REUSE
Description
Total capital costs
Fixed charges @15%
Maintenance @3% of construction cost
Annual operating cost excluding labor
Operating labor
Total annual costs
Unit costs, mils/KWH of
Generating capacity
Production (base load)
Production (cycling plant)
Powerplant Generating Capacity
100 MW
$590,800
88,600
13,600
25,400
135,000
$262,600
0.30
0.45
0.86
1000 MW
$2,825,700
423,900
76,200
225,600
270,000
$995,700
0.11
0.17
0.32
-------
in the cycling mode at a capacity factor of 0.35 are about 0.86 mills
and 0.32 mills respectively. The costs of achieving no discharge of
pollutants other than heat by complete chemical treatment and recycle
provide a conservatively high estimate of achieving no discharge of
pollutants from low-volume waste sources only.
Energy Requirements
Energy requirements fcr the treatment of chemical wastes are not a
significant consideration. Most of the processes utilized for the
treatment of chemical wastes require no input of energy other than that
required for conveying the liquid. Some of the processes involved in
the technology for achieving no discharge of pollutants involve a change
of state from the liquid phase to the vapor phase, and others such as
vacuum filters and reverse osmosis require substantial mechanical
energy. However, these processes are generally applied to only a small
portion of the total wastes, so that again the overall effect is
negligible. Based on the flow diagrams for a central chemical wastes
treatment plant and for complete treatment facilities designed to
achieve no discharge of pollutant, the estimated energy requirements for
central waste treatment are less than 10 KW per 100,000 KW of plant
capacity, or less than 0.01% of the plant output. For complete
treatment and reuse, including steam evaporation to dry material for
ultimate disposal, the energy requirements are less than 0.2X of the
plant output. For plants capable of achieving no discharge by utilizing
evaporation ponds, energy requirements are about 0.04% of the plant
output.
Ultimate Disposal of Brines and Sludges
The waste treatment processes previously discussed are essentially
separation techniques which produce a liquid fraction suitable for
discharge or reuse and a liquid-solid residue which requires ultimate
disposal. The residues from ion exchange, evaporation, and reverse
osmosis processes are concentrated brines, which carry the solids in
solution form. The residues from other waste treatment processes are
sludges of various types and concentration, which may contain from 0.5
to 5.0 % solids in the suspended form. The ease with which these
sludges can be further dewatered depends on the type of sludge. At one
end of the scale are sludges which contain a high proportion of mineral
solids, and which dewater readily to about 20% solids. At the other end
of the scale are gelatinous sludges such as those resulting from alum
coagulation which are very difficult to dewater. The following
paragraphs describe seme of the dewatering and ultimate disposal
techniques applicable to steam electric powerplants.
Conveyance to Off-Site Disposal
Conveying brines and sludges to off-site disposal facilities is a method
of ultimate disposal provided that the wastes have been concentrated to
244
-------
make conveying economically attractive and provided there is a facility
to\which the wastes can be delivered. Alternate methods of conveyance
are by trucks, railroad cars or pipeline. Pipeline Conveyance is the
mosi economical means for quantities in excess of 100 m3 (26,000 gal)
per day. For smaller quantities, truck or rail hauling is more
economical, with distance the deciding factor. Trucking is more
economical for distances below 50 km (35 miles) with rail haul more
economical for longer distances. In any case, costs are of the order of
$0.01*- 0.10 per m'-'km ($0.05 - $0.50 per 1000 gal - mile) exclusive of
disposal charges by the receiving agency, '*» These costs are
sufficiently high to make conveyance economically unattractive except at
sites having no alternate means of disposal.
Evaporation Ponds (Jiagoons)
Evaporation ponds are a feasible method of ultimate disposal for plants
having the necessary land area available and having climatic conditions
favorable to this method. In general, annual evaporation should exceed
annual rainfall by over 50 cm(20 in.). This would restrict uncovered
evaporation ponds to the southwestern portion of the United states.
Ponds are generally }ined to prevent seepage into the ground. Multiple
ponds are usually provided to allow evaporation from one pond while
other ponds are receiving wastes. Facilities must also be provided to
remove solids accumulated in the pond.
Landfill
Landfills are the nrost common method of disposal of solid residues.
However, leachate from chemical wastes deposited in landfills may cause
groundwater problems. If the wastes contain soluble components, fill
areas must be lined and leachate and runoff collected and treated as for
coal pile runoff*.
Intermediate Dewatering Devices
A number of devices are available for the intermediate dewatering of
sludges from their original concentration of 1-5% solids to about 15*30%
solids. These devices include vacuum' filters, pressure filters and
centrifuges.
Vacuum filters are devices consisting of a drum covered by a filter
media and rotating slowly while partially submerged in a reservoir
containing the sludge to be dewatered. A vacuum of 40 to 80 KN/m2 (12
to 25 in. Hg) is applied to the inside of the drum, causing a layer of
sludge to adhere to the surface of the media. As the layer emerges from
the reservoir, it is further dried by air being drawn through the layer
and into the interior of the drum. Just prior to resubmerging into the
reservoir, the dewatered sludge is removed from the drum by a scraper
and conveyed to disposal.
245
-------
Some sludges contain very fine or filamentous solids that clog the
filter media and prevent the flow of liquid and air through the media.
Such sludges must be treated to increase the porosity of the filter
cake. Treatments pricr to filtration may consist of the addition of
ferric chloride to colloidal sludges or diatomaceous earth to sludges
containing a high proportion of silty material. 182
Pressure filters are similar to vacuum filters except that the sludge or
suspension is forced through the filter media by pressure rather than by
vacuum. The most cominon filter media arrangement consists of a series
of vertical frames covered by a cloth media. The sludge is applied
through a header to the outside of the filter media* while the filtrate
is collected from the inside. A filter aid is commonly used to increase
the filterability of the sludges.
Neither vacuum filters nor pressure filters have been used for pollution
control in steam electric powerplants to any significant extent,
although certain types cf pressure filters are used in some forms of
condensate polishing.
Centrifuges are intermediate dewatering devices which make use of the
gravitational forces in liquids rotating at high speeds to separate
particulate matter from suspensions. There are no known instances of
centrifuges being used by steam electric powerplants for pollution
control, but the technology is available and should be considered as a
means of concentrating and dewatering sludges.
246
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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.
Chlorine concentrations in both recirculating and nonrecirculating
cooling water systems are to be limited to average concentrations of 0.2
mg/1 during a maximum of one 2-hour period a day and maximum
concentrations of 0.5 mg/1. These limitations can be achieved by means
of available feedback control systems presently in wide use in other
applications. Chlorination for biological control can be applied
intermittently and thus should not be applied on two or more units at
the same plant simultaneously in order to minimize the maximum
concentration of total residual chlorine at any time in the combined
cooling water discharged from the plant. Furthermore, Chlorination of
individual units should be applied at times of lowest flow through the
condensers to minimize the total amounts (mass) of total residual
chlorine discharged. Generally Chlorination is not required for more
than two hours each day for each unit. However, additional Chlorination
may be allowed in specific cases to maintain tube cleanliness.
Alternative methods cf reducing the total residual chlorine in
nonrecirculating condenser cooling water systems include chemical
treatment, substitution of other less harmful chemicals, and use of
mechanical means of cleaning condenser tubes. Mechanical cleaning is
employed in some plants but its practicability depends on the
configuration of the process piping and structures involved at the
particular unit. Moreover, chlorine may still be discharged even with
mechanical cleaning of condenser tubes, because of its continued use in
maintaining biological control in other parts of the cooling system.
Further removal of residual chlorine dn nonrecirculating condenser
cooling water systeirs by chemical treatment is available but is not
generally practicable because of the additional costs involved to treat
the large volumes of water involved.
Chemical treatment of recirculating cooling water systems would be
less costly and the pollution potential of residual bisulfide chemicals
added would be less significant than with nonrecirculating cooling water
systems due to the smaller wastes water volumes requiring treatment.
247
-------
Experience in this technology is highly limited in the powerplant field;
however, this is a well established technology in the water supply
industry. Other technologies potentially available for recirculating
cooling water systems are split stream chlorination, blowdown retention,
and intermittent discharge programmed with intermittent chlorination.
The use of chemicals for control of biological growth, scaling and
corrosion in evaporative cooling towers is commonplace. The types and
amounts of chemicals required is highly site-dependent. Chromate
addition is not generally required for corrosion control. Phosphates
and zinc salts are employed in some cases. Insufficient data exists to
judge what alternative chemicals for control of corrosion, etc., would
be generally practicable from a cost versus effluent reduction benefit
standpoint. Minimum discharge of added chemicals can be achieved by
employing the best practicable technology for water treatment and water
chemistry to minimize the quantities of blowdown flow required, in
cases where cooling towers are planned, design for corrosion protection
can eliminate the need for chemical additives for corrosion protection.
Treatment of cooling tower blowdown for oil and grease removal, by
chemical addition fcr effluent pH ccntrol, and by sedimentation for
reduction of effluent total suspended solids is achievable. Effluent
levels of 10 mg/1 oil and grease and 15 mg/1 total suspended solids are
achievable based on the treatment of similar waste waters. Due to wide
range of flow of waste water from recirculating cooling water systems,
the effluent limitations in mass units, in any particular plant would be
the products of the flow times the respective concentration levels.
Costs in general would be approximately 0.1 mill/kwh in the relatively
small number of cases where it would be needed.
Limitation for Low-Volume Waste Waters.
Low-volume waste water sources include boiler blowdown, ion exchange
water treatment, water treatment evaporative blowdown, boiler and air
heater cleaning, other equipment cleaning, laboratory and sampling
streams, floor drainage, cooling tower basin cleaning, blowdown from
recirculating ash sluicing systems, blowdown from recirculating
wet-scrubber air pollution control systems, and other relatively low
volume streams. These wastes can be practicably treated collectively by
segregation from higher volume wastes, equalization, oil separation,
chemical addition, solids separation, and pH adjustment.
Oily streams such as waste waters from boiler fireside cleaning, air
preheater cleaning and miscellaneous equipment and stack cleaning would
be practicably treated for separation of oil and grease, if needed, to a
daily average level of 10 mg/1. Addition of sufficient chemicals to
attain a pH level in the range 9 to 10 and total suspended solids of 15
mg/1 in the effluent of this treatment stage would be generally
practicable considering the pH levels of the untreated waste streams and
the waste water flow volumes involved. Generally, the higher the pH
level, with total suspended solids of 15 mg/1, the greater the effluent
248
-------
reduction benefits attained for the numerous chemicals removed by
treatment. Examples of pollutants significantly reduced by this
treatment are the following: acidity, aluminum, biochemical oxygen
demand, copper, fluoride, iron, zinc, lead, magnesium, manganese,
mercury, oil and grease, total chromates, total phosphorous, total
suspended solids, and turbidity. Some waste water characteristics, such
as alkalinity, total dissolved solids, and total hardness are increased,
however. Following the above treatment it would be practicable, in a
second stage, to adjust the effluent pH to a level in the range 6.0 to
9.0 in compliance with stream standards, with sedimentation to attain
final daily average effluent total suspended solids levels of 15 mg/1.
Effluent daily average concentrations of levels of 1 mg/1 total copper
and 1 mg/1 total ircn are achievable by the application of this
technology. The effluent limitations in mass units, in any particular
plant, would be the products of the collective flow of all low-volume
waste sources times the respective concentration levels.
Segregation and treatment of boiler cleaning waste water and ion
exchange water treatment waste water is practiced in a relatively few
plants, but is potentially practicable for all plants. Oily waste
waters are segregated from non-oily waste streams at some plants and the
oil and grease removed by gravity separators and flotation units.
Combined treatment of waste water streams is practiced in numerous
plants. However, in most cases treatment is accomplished only to the
extent that self-neutralization, coprecipitation and sedimentation occur
because of the joining and detention of the waste water streams.
Chemicals are added during combined treatment at some plants for pH
control. Most of these plants employ lagoons, or ash ponds, while a few
plants employ configured settling tanks.
Limitations for Once-Through Ash and Air Pollution Control Systems.
Daily average effluent total suspended solids levels of 15 mg/1 are
practicably attainable as are oil and grease levels of 10 mg/ and pH
values in the range 6.0 to 9.0. Due to the fact that intake water to
ash sluicing and air pollution control systems is often well in excess
of this level, an effluent limitation of 15 mg/1 total suspended solids
times the waste water flow would, in many of those cases, require the
removal of large quantities of suspended solids not added by the plant.
In the light of this, an effluent total suspended solids level for these
streams should be limited to a daily average of 15 mg/1 times the waste
water flow or a number of pounds per day not in excess of the total
intake to the station for these systems, whichever represents the
greater number of pounds per day.
Dry processes are used by most oil-fired plants for ash handling, while
only fly ash is handled dry at some coal-fired plants. Gas-fired plants
have little or no ash. The extent of the practicability of employing
dry processes for bottom ash handling at coal-fired plants is not known.
249
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Limitations for Rainfall Run-off Waste Water Sources.
Rainfall run-off waste water sources include coal-pile drainage, yard
and roof drainage, and run-off from construction activities. Effluent
limitations reflect the technology of diking, oil-water separation,
solids separation, and neutralization.
Best Available Technology Economically Achievable.
The best available technology economically achievable for all plants is
re-use and recycle of all waste water to the maximum practicable extent,
with distillation to concentrate all lew-volume water wastes and to
recycle water to the process, and with evaporation to dryness of the
concentrated waste followed by suitable land disposal.
Re-use of waste water streams is practiced at relatively few plants, but
some employ recycle of ash sluice water. Distillation concentration
with recycle is currently planned for at least three plants. Some
stations plan to employ re-use of cooling tower blowdown in wet-scrubber
air pollution control systems. Since water quality requirements for ash
sluicing and wet scrubbing are relatively low, some degree of re-use
should be practicable for most plants where these operations are
employed. The concept of cascading water use, i.e., recycle and re-use
of water from applications requiring high quality water to applications
requiring successively lower water quality, to reduce to the volume of
waste water, if any, ultimately requiring evaporation or other
treatment, while practicable in all cases, would generally be subject to
a case-by-case analysis to determine the optimum among the various
candidate systems.
Chemical treatment of blowdown from recirculating cooling water system
for removal of total chromium, total phosphorus (as P) and zinc, while
not currently demonstrated, could be achieved by 1983, in the relatively
small number of cases where it would be needed. Corresponding effluent
limitations, based on the application of this technology, are 0.2 mg/1
total chromium, 5 mg/1 total phosphorus (as P) , and 1 mg/1 zinc-total,
all times the waste water flow.
Maximum effluent reductions are attainable by segregating the initial 15
minutes of run-off from a rainfall event from the remainder of the
run-off, and by treating both streams separately, each stream to achieve
effluent levels of 15 mg/1 total suspended solids, 10 mg/1 oil and
grease and a pH value in the range of 6.0 to 9.0. Chlorination programs
to achieve no discharge of total residual chlorine from recirculating
cooling water systeirs, while not currently demonstrated, could be
applied by 1983.
250
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New Source Standards.
In view of the current technical risks associated with the application
of distillation technology to waste water recycle, chlorination programs
to achieve no discharge of total residual chlorine from recirculating
cooling water systems, and segregation of rainfall run-off streams, new
source performance standards have been determined to be identical to the
limitations prescribed for best practicable control technology currently
available with the following exceptions. No discharge is allowed of
corrosion inhibitors in blowdown from recirculating evaporative cooling
water system, based on the availability of design technology for
corrosion prevention. No discharge of total residual chlorine or other
additives for biological control in main condenser tubes, based on the
availability of mechanical systems to achieve biological control in main
condenser tubes. No discharge of pollutants from nonrecirculating ash
sluicing system, based on the availability of dry systems and of
recirculating wet systems.
Cost of Technology.
Due to the wide range of water volumes required from plant to plant for
the individual unit operations involved, and further, due to the wide
range (from plant to plant) of costs per unit volume of water treated,
which are further related to the effluent reductions obtained, the costs
vary widely for the removal of specific pollutants to various degrees.
For example, toiler fireside chemical cleaning volumes vary from 2ft,000
gal to 720,000 gal per cleaning, with cleaning frequencies ranging from
2 to 8 times per year.~ The operating costs of chemical precipitation
treatment for copper and iron removal to 1 mg/1 effluent concentration
and for chromium removal to an effluent of 0.2 mg/1 range from $0.10 to
$1.30/1000 gal. Furthermore, there are approximately 10 or more
separate unit operations which are sources of waste water at power
generating plants, each with its station-specific flow rate and waste
water characteristics, as well as cost peculiarities. Site-related
factors concerning the practicability of various re-use practices make
these practices even more difficult to cost, due to the added
complexities involved.
The incremental costs of controlled additions of chlorine, in the cases
where chlorine is required for biological control, are less than 0.01
mill/kwh. In the relatively few cases where chromates are added for
corrosion control and where other less harmful chemicals and methods can
provide effective corrosion control the incremental costs are less than
0.01 mill per kilowatt hour. The incremental cost of mechanical
cleaning to replace some fraction of the total required chlorine
additives is approximately 0.01 mill/kwh for existing stations and
considerably less for new units whether at new or existing plants.
Cost estimates based on the combined treatment of selected low-volume
streams for oil and grease separation, equalization, chemical
precipitation, solids separation, and further based on generalizations
with respect to the cost of land, construction, site preparation and
251
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with respect to the waste water volume, indicate an approximate cost of
0.1 mill per kilowatt hour depending upon the plant's generating
capacity and utilization. The highest costs are associated with the
smaller plants and peaking plants which generally have the highest basic
generating cost. In general, the entire incremental cost should be felt
by individual plants since this type of complete chemical treatment is
not generally employed.
Sedimentation of ash sluicing water, cooling tower blowdown, etc., would
cost typically about 7 cents/1000 gal, with the incremental cost in
mills/kwh being related to the quantitites of water treated. Since many
plants already have some type of sedimentation facility, the
increlemental costs of improved sedimentation performance if required
will be some fraction of the cost cited.
In the few cases where it would be required chemical treatment for
removal of phosphorus, total chromium or zinc from cooling tower
blowdown would cost about $1/1000 gal treated. Incremental costs of dry
ash handling systems where mechanically feasible are less than 0.01
mill/kwh for existing stations converting from wet systems and are
considerably less for new sources.
Recirculating ash sluicing systems require sedimentation discussed above
plus pumps, piping and a blowdown system. Incremental costs above
sedimentation are less than 0.01 mill/kwh for existing plants and
considerably less for new plants.
The cost of evaporation in configured equipment is approximately 1.4
dollars/1000 ga!J.. The corresponding incremental cost in mills/kwh is
related to the quantities of waste water requiring evaporation. Costs
would be significantly less in climates where solar evaporation in ponds
could be employed.
The incremental costs of equipment design for corrosion protection are
normally largely offset by other cost benefits such as reduced costs of
chemicals. The net incremental costs for both lined cooling tower
components and stainless steel or titanium condenser tubes would be less
than 0.1 mill/kwh total, even in the case where new or old copper alloy
condenser tubes were retrofitted, due to the high offsetting salvage
value of copper. Replacement of existing cooling tower components would
be more expensive however.
Because of the wide range of opportunities and associated incremental
costs of achieving no discharge of pollutants from waste water sources
other than cooling water systems and rainfall run-off (based on the
technology of maximum recycle with evaporation of the final effluent) a
model plant is employed as a basis for considerations of this higher
level of technology. The features of the model plant are selected to
produce conservatively high incremental costs of applying this
technology, i.e. the determined costs would be at a level higher than
252
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would be expected for almost all other plants. The model plant would
have such adverse characteristics that recycle of all water (except that
used in ash sluicing systems or in wet-scrubber air pollution control
systems) would not be practicable except after distillation.
Distillation is much more costly than the chemical addition and
sedimentation treatments which would be used in most cases. Ash
sluicing water and wet-scrubber water would be recycled after
sedimentation (or filtration) for solids removal. The model plant would
have to distill blcwdown from ash sluicing for recycle to other
processes, however, the quantities of water distilled would be less than
the feed intake to the system of low quality waste waters from other
sources by the amount of evaporation during sluicing and the amount of
moisture removed in the ash. Therefore, the assumption of the presence
of wet ash sluicing is consistent with the conservative approach of the
cost analysis. Similar considerations pertain to wet-scrubber air pol-
lution control systems. Non-solar evaporation is further assumed.
The incremental costs for achieving no discharge of pollutants,
exclusive of cooling water and rainfall run-off, for the model station
as previously stated are approximately 0.3 mills per kilowatt-hour for a
100 megawatt capacity base-load plant, 0.5 mills per kilowatt-hour for a
cyclic plant and 1.5 mills per kilowatt-hour for a peaking plant. These
costs are about 5, 6, and 12 percent of production costs, respectively.
Costs for smaller plants would be generally higher and costs for larger
plants would be generally lower. Costs would be less for plants in
climates suitable for solar evaporation. Cost would be generally less
for nuclear plants and for gas-fired plants because there is no require-
ment for water related to ash handling. From an overall standpoint,
costs would be generally lower than the costs for the model plant due to
the conservative assumptions employed in the model. Full recycle of
blowdown from evaporative recirculating cooling water systems would be
significantly more costly.
Energy and Other Non^-Water Quality Environmental Impacts.
Energy requirements for technologies reflecting the application of the
best available technology economically achievable for pollutants other
than heat are less than 0.2 percent of the total plant output.
The non-water quality impacts of technologies available to achieve
limitations on pollutants other than heat are negligible with respect to
air quality, noise, water consumption and aesthetics. Solid waste
disposal problems associated with achieving the limits required by best
practicable control technology currently available are similarly
insignificant. Systems with evaporation and recycle of waste water,
which may be required to attain the effluent reductions required for
best available technology economically achievable will not generally
create significant amounts of solid waste. If recycle of blowdown from
evaporative recirculating cooling systems were to be employed, however,
considerable volumes of solid waste may be generated. Jn most cases
253
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these are nonhazardous substances requiring only minimal custodial care,
However, some constituents may be hazardous and may require special
consideration. In order to ensure long term protection of the
environment from these hazardous or harmful constituents, special
consideration of disposal sites may be made. All landfill sites where
such hazardous wastes are disposed should be selected so as to prevent
horizontal and vertical migration of these contaminants to ground or
surface waters. In cases where geologic conditions may not reasonably
ensure this, adequate legal and mechanical precautions (e.g. impervious
liners) should be taken to ensure long term protection to the
environment from hazardous materials. Where appropriate the location of
solid hazardous materials .disposal sites should be permanently recorded
in the appropriate office of legal jurisdiction.
254
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PART B
THERMAL DISCHARGES
SECTION V
WASTE CHARACTERIZATION
Significant thermal discharges from steam electric powerplants occur
when a powerplant utilizes a once-through circulating water system to
reject the heat not converted into electric energy. The amount of heat
energy discharged with the circulating water is equal to the heat value
of the fuel less the heat value converted into electric energy and
miscellaneous station losses. The heat energy discharged is therefore
directly related to the efficiency of the plant. According to industry
practices, the efficiency of a generating unit is expressed as its heat
rate, in units of Joules per KWH (BTO per KWH) . A new fossil-fired
generating unit may be designed for a heat rate of 9.5 million Joules
per KWH (9000 BTU/KWH) . Since one KWH is equivalent to 3.6 million
J/KWH (3413 BTU), such a plant would have an efficiency of 38X.
The transfer of heat from the condensing steam to the cooling water
results in a temperature rise of the cooling water. For a given amount
of heat transfer, the temperature rise of the cooling water is inversely
proportional to its flow. That is, one.may either heat a small quantity
of water a great deal, or a large quantity of water a small amount. On
the average, temperature rises have been centered about 9 degrees C (16
degrees F) for economic and process considerations (Figure B-V-1) . It
is clear however, that almost any lower limit on temperature rise can be
achieved given a sufficiently large source of cooling water and no eco-
nomic constraints. It is also clear, however, that a temperature
difference reduction does not limit the amount of heat rejection.
Quantification of Main Condenser Cooling Characteristics
The data presented below were obtained .from the Federal Power Commission
and represent a summary of the data collected on "FPC Form 67" for the
year 1969.28° These data have been screened to eliminate obvious in-
consistancies. The statistical analyses have been performed using
standard subroutines available from IBM in their scientific subroutine
package (1000) operating units. All units in this sample are fossil-
fueled. Heat rates for the industry are profiled in Figure B-V--2. This
figure shows the mean unit heat rate to be approximately 11*8 million
Joules/KWH (11,200 BTU/KWH) with a standard deviation of approximately
2.86 million Joules/ KWH (2700 BTU/KWH). These statistics are not
weighted by generation. Weighted figures show the national average heat
rate to be about seven (7) percent lower.2a* Given the heat rate, one
255
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MINIMUM=1
MRXIMUM=38
MERN-15
STRND8RD DEV=5
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5.00 10.00 15.00 20.00 25.00 30.00 35.00 40.00
CONDENSER DELTR T (DEC. F)
UNIT CONDENSER DELTR T
FIGURE B-V-1
256
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MINIMUM-8706
MRXIMUM=27748
° STRNDRRD DEV=2710
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"TOOO120 00160.00 200.00 240.00 280.00 320.00 360.00 400.00
UNIT HERT RRTE (BTU/KH-HR) *102
UNIT HEflT RflTE DISTRIBUTION
FIGURE B-V-2
257
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may calculate the cooling water heat rejection for fossil plants in the
following manner:
1. Multiply the heat rate by the boiler efficiency (0.8-0.9 are
reasonable efficiencies to use for this calculation)
2. Subtract from that number the energy of one (1) KWH (3,$00,000
Joules or 3,413 BTU).
3. The result is the heat rejected to the cooling water stream.
The result obtained from this calculation is slightly higher than the
real requirement in most cases. This analysis ignores the difference
between the lower and higher heating values of the fuel. Heat rates can
be reported using high heating values although all this energy is not
available to do work. The difference is lost forming water vapor from
the hydrogen in the fuel and oxygen in the air. Various in-plant heat
and steam losses, and the power requirements of the plant's auxilliary
equipment are also ignored. Using this analysis, the mean plant in our
sample rejects about seven (7) million Joules (6,640 BTU) per net KWH
generated. Table B-V-1 lists heat rates, efficiencies, and waste heat
produced for a range cf plants typical of the industry. The heat
rejection requirements calculated above are satisfied by the heating of
the circulating water. Figure B-V-1 indicates that the mean temperature
rise (unit basis, not weighted) of the cooling water is between eight
and nine degrees C (about 15 degrees FJ with a standard deviation of
about three degrees C (5 degrees F).
Flow rates range from about 1,100 liter/min (300 gpm) to 4,000 liter/min
(1,100 gpm) for each megawatt of load.280 Thus a 100 MW unit operating
at capacity may discharge up to 400,000 liter/min (110,000 gpm) of water
heated to nine degrees C (15-16 degrees F) above ambient. (A more
typical number would be about two-thirds of this example based on
national heat rates).
The maximum summertime temperature of the heated effluent varies with
location, but is strongly centered (Figure B-V-3) about 35 degrees C (95
degrees F). It is interesting to note the large number of plants
operating at or above a maximum summertime outfall temperature of 39
degrees C (102 degrees F). At elevated temperatures turbine efficiency
frequently begins to suffer.
Table B-V-2 summarizes data received from powerplants visited under this
contract. Many of the plants visited were among the most efficient in
the nation.
The visits were, in general, made to examine unique features in control
or efficiency incorporated in the plant. These data, therefore,
represent typical values for newer modern plants rather than an
industry-wide cross section. Of some interest, however, are the data
258
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Table B-V-1
EFFICIENCIES, HEAT RATES AND HEAT REJECTED BY COOLING WATER
Plant
Efficiency,
%
38
34
29
23
17
34
29
Plant
Heat Rate
Heat Converted
to Electricity
Stack and Plant
Heat Losses
Heat Rejected
to Cooling Water
Joules per KWH x 10"6 (Btu/KWH)
Fossil-Fueled Units
9.5 ( 9,000)
10.5 (10,000)
12.5 (12,000)
15.5 (15,000)
21.0 (20,000)
3.6 (3,400)
3.6 (3,400)
3.6 (3,400)
3.6 (3,400)
3.6 (3,400)
0.95 ( 900)
1.05 (1,000)
1.25 (1,200)
1.55 (1,500)
2.1 (2,000)
4.95 ( 4,700)
5.85 ( 5,600)
7.65 ( 7,400)
10.35 (11,100)
15.3 (14,600)
Nuclear Units
10.5 (10,000)
12.5 (12,000)
3.6 (3,400)
3.6 (3,400)
0.5 ( 500)
0.6 ( 600)
6.4 ( 6,100)
8.3 ( 8,000)
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20.00 40.00 60.00 80.00 100.00 120.00 140.00 160.00
MflX. 0UTFRLL TEMP. (DEC. F)
MRX, SUMMER OUTFRLL TEMP0
FIGURE B-V-3
260
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TABLE B-V-2
PLANT VISIT THERMAL DATA
ro
cr,
Plant
0640
1209
2612
1723
3117
1201
1201
5105
2525
0801
1209
4217
4846
3713
2512
3115
2527
0610
2119
ID Fuel
Nuclear
Nuclear
Nuclear
Nuclear
Nuclear
Oil & Gas
Oil & Gas
Oil
Oil
Coal & Gas
Coal & Gas
Coal
Coal
Coal
Oil
Oil & Gas
Oil
Oil & Gas
Coal
Capacity
(MW)
916
1456
700
1618
457
139.8
792
1157
1165
300
820
1640
1150
2137
542.5
644.7
28
750
2534
Nuclear Averages
Fossil
Averages
Heat Rate
Joule s/KWH
X 10-'
N.A.
1.1
1.1
N.A.
1.07
1.02
N.A.
1.09
.95
1.12
.99
1.03
1.05
.92
.94
1.06
1.02
1.15
N.A.
1.09
1.03
Cooling Temp.
Water Flow Rise
M3/min °C
1688
4735
1476
3564
1362
439
2002
1851
2346
1056
2078
2120
2838
3883
632
1429
94.6
1332
2937
N/A
N/A
15.6
8.9
13.9
13.3
10.0
5.7
8.5
13.2
8.2
N.A.
7.3
14.4
7.5
10.0
16.1
9.3
N.A.
10.0
13.9
12.34
10.34
Discharge Temp.
°C
Summer
30.0
40.6
N.A.
36.7
28.6
34.0
39.6
45.4
31.0
N.A.
38.9
31.7
N.A.
28.3
33.4
28.2
N.A.
36.7
N.A.
N/A
N/A
Winter
27.0
28.9
N.A.
14.4
13.9
22.3
29.1
18.2
12.7
N.A.
27.3
17.8
N.A.
17.8
22.6
13.2
N.A.
20.0
N.A.
N/A
N/A
I
Average
28.3
35.6
N.A.
N.A.
21.7
26.8
32.4
36.3
21.4
N.A.
33.9
26.7
N.A.
N.A.
28.0
21.0
N.A.
26.7
N.A.
N/A
N/A
Heat Dissipation
Joules/Hr
X 10-9
6580
10588
5135
11916
3417
624.3
4271
6116
4840
N.A.
3786
7676
5336
9744
2552
3343
N.A.
3343
10229
N/A
N/A
Joules/KWH
X 10-6
7.194
7.27
7.349
7.37
7.48
4.466
5.39
5.285
4.156
N.A.
4.626
4.68
4.645
4.56
4.71
5.196
N.A.
4.46
4.04
7.33
4.68
N.A. - Not Available
N/A - Not Applicable
-------
from the nuclear plants visited. Since all nuclear plants in utility
service are relatively new, these plants may be considered typical of
nuclear plants. It is observed that the heat rejection is considerably
higher for nuclear plants (by a factor of more than 1.5) than for the
fossil-fueled plants studied. In addition* the temperature rise for the
nuclear plants is generally higher.
Industry-wide Variations
Heat rate varies about thirteen percent regionally. *«l This variation is
due to relative equipment age, availability of high quality fuel, and
economic and other factors. For example, the northeastern section of
the country has many eld, relatively inefficient units which must be
operated to meet loading requirements. On the other hand, the western
section of the country uses a great deal of lower heating-value lignite
which contributes to its' higher average heat rate. The southeastern
section of the country can attribute its lower average heat rate to many
new, large, efficient units burning high-quality fuel. The net effect
of the regional heat rate variation on heat rejection requirements may
be' as high as twenty percent (see previous section for calculations).
This number may be considered conservative, however, since some of the
regional heat rate variation is fuel quality dependent.
Temperature rise varies with both heat rate and cooling water
availability. In addition, considerations such as economics, ambient
water temperature, and water quality requirements weigh heavily upon the
design cooling water temperature rise. Thus, temperature rise requires
a plant by plant evaluation.
Maximum temperature of the outfall varies with both ambient temperatures
and temperature rise. Thus higher temperatures should be expected in
the southern section of the country. This expectation is somewhat
mitigated by the fact that the steam cycre has efficiency limitations
beyond certain temperatures. Thus, utilities economically optimize
temperature rise (a lower temperature rise requires more pumping power
and/or a larger condenser) and final temperature (a higher final
temperature reduces turbine efficiency) . Therefore, regional variations
in maximum summertime outfall temperature are not as large as regional
variations in ambient water temperatures;
Seasonal variations in heat rate, temperature rise and outfall
temperature may be significant but move in opposing directions. That
is, when the ambient temperature, the maximum outfall temperature and
the heat rate increase, the temperature rise, in general, falls. In
many sections of the country, the summer heat rate is higher than the
winter heat rate because many inefficient peaking plants are run only in
the summer months. This effect is in addition to the efficiency loss
created by ambient conditions. The efficiency loss is of particular
concern since peak demand usually coincides with the worst (for power
generation) ambient conditions, which can cause power shortages. Con-
262
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versely, the wintertime heat rate (usually better than summer) occurs at
a time when demand is below peak. Therefore, the heat rejected per KWH,
the total heat rejected, and the maximum outfall temperature are all
lower. While the temperature rise may be higher in the winter, it can
be controlled by increasing the cooling water flow (which was cut back
for economic reasons to cause the higher rise in the first place).
Age is a frequently mentioned parameter for the thermal effluent of
powerplants. Historically, plant aging has been a double edged sword.
The aging process included material and equipment deterioration (turbine
blade erosion, etc.) which is an absolute loss over a period of time,
and obsolescence which is a relative deterioration. Recent history
indicates*8** however, that there has been no heat rate improvement on a
national basis for over a decade. Therefore, heat rate deterioration
with age is only a function of material deterioration which is much less
dramatic than the historic cycle improvements. Furthermore, older
plants are traditionally smaller than newer plants. With the demand for
electricity increasing exponentially, the capacity required for peaking
and cycling in a system approaches the capacity of their older plants.
Therefore, the older plants are usually derated to peaking and cycling
service while the larger new units are base loaded. Temperature rise is
not significantly affected by age (Figure B-rV-4). While the trend has
been slightly upward over the years, the increase has been slight
(largely for thermodynamic reasons). Maximum outfall temperature has
not changed materially over the years because the two determining
factors (other than natural conditions) have changed in offsetting
directions.
Unit capacity has a sirall effect on heat rate and virtually no effect on
temperature rise. The effect on heat rate is due largely to engineering
and capital cost considerations and to the fact that small plants are
not usually base loaded.
Variation with Industry Grouping
Nuclear plants reject about 50% more heat to the cooling water per KWH
than fossil plants. Fossil-fueled plants reject from 10% to 20X of the
available fuel energy to the atmosphere through the stack. This energy
leaves the plant in the form of water vapor (heat of vaporization)
created by burning hydrogenous fuel and' heated exhaust gases.
Nuclear plants reject virtually all their heat to the cooling water. If
this were the only factor, nuclear plants of the same efficiency as
fossil plants would reject from 18X to 43X more heat per KWH than fossil
plants. However, nuclear plants of current design (PWR, BWR) cannot
produce superheated steam for the generation cycle. For this reason, a
well-designed nuclear plant can seldom be expected to exceed a thermal
efficiency of 34X under even ideal conditions while well-designed, well-
run fossil plants have achieved thermal efficiencies of up to 39% as an
average for an entire year*s operation (plant no. 3713)281- Thus,
263
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LEGEND
CO RLL UNITS IN INVENTORY
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).00 5.0Q 10.00 15.00 20.00 25.00 30.00 35.00 40.00
UNIT RGE IN TERRS
DELTfl T VS UNIT RGE
FIGURE B-V-4
264
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nuclear plants can be expected to reject more heat than fossil plants
for thermodynamic reasons. The sum of these two effects yields cooling
water heat rejection requirements in the range of 5036 higher for nuclear
plants than for fossil plants. The higher heat rejection requirements
for nuclear plants are usually met by increasing the cooling water flow
and slightly raising the temperature difference across the condenser.
This method is practiced to avoid the additional thermodynamic
inefficiencies associated with higher outfall temperatures.
Nuclear plants, then, closely approximate new fossil plants in
temperature rise and nraximum outfall temperature and are significantly
higher in cooling water requirements. Fossil-fueled units can be
divided into three categories, based on hours operated per year. The
lowest group are operated less than two thousand (2,000) hours per year.
The intermediate group are operated more than two thousand (2,000) and
less than six thousand (6,000) hours per year, while the highest groups
are operated more than six thousand (6,000) hours per year.
The highest group heat rates average 11.25 million Joules per KWH
(10,636 BTU/KWH, see Figure B>-V-5) with a standard deviation of about
3.1 million Joules per KWH (2,100 BTU/KWH). Intermediate group heat
rates average about 13.3 million Joules per KWH (12,494 BTU/KWH, see
Figure B-V-6) with a standard deviation of about 3.1 million Joules per
KWH (2,950 BTU/KWH) , while the lowest group averages about 16.6 million
Joules per KWH (15,793 BTU/KWH, see Figure B-V-7) with a standard
deviation of 4.72 million Joules per KWH (4,480 BTU/KWH). The variation
in the heat rate mean is over forty-seven percent, with heat rate
varying inversely with utilization. The variation in cooling water heat
rejection requirements is clearly higher than the variation in heat rate
since the major portion of the additional heat must be rejected to the
cooling water. This is only true when the plant is on-line. If a plant
is on hot standby, the heat is rejected to the atmosphere through the
stack. The impact of the increased heat rate is reduced sharply by two
factors. The units with the higher heat rates are on-line less than the
most utilized units and produce far less electric power. As a result,
the total heat rejection per year is far less than for the most utilized
units. Furthermore, a significant contribution to the high heat rates
of the less utilized units is the practice of keeping these units on hot
standby during periods when the probability of peaking demands is high.
During these periods, these units produce no electricity and, therefore,
have an infinite heat rate but reject little or no heat to the cooling
water. Thus, the heat rate figures for the least utilized plants tend
to be misleading (on the high side) as well as less important than those
for the most utilized.
(It should again be noted that all statistics in this section are
unweighted arithmetic means. Weighing averages by generation would
produce lower heat rates, and, therefore, lower cooling water heat
rejection requirements) .
265
-------
o
o
o
c\j_
f\j
o
o
en •
o
O
O
'
MflXIMUM-26741
MERN-1C636
STRNDflRD DEV-2096
^0.00 120.00 160.00 200.00 240.00 280.00 320.00 360.00 400.00
HERT RRTE (BTU/KW-HR) *102
BRSE UNIT HERT RRTES
FIGURE B-V-5
266
-------
o
o
a
o
o.
(M
a
o
o
o
MINIMUM=8735
MflXIMUM=27748
MEflN=12493
STflNDRRD DEV=2951
to
1 'o
ZO
CD
n E E
LiJO
o
CD"
o
o
o
o
n m
CKD DO C121 CJCl
o
o
. 1 B—im-mmu—mmymummjmum ^ijui^u^uujijiujqji^Ljuii^i^iui^uii^i^ujujnLji^jiiiiJMAajja-
00 120 00 160.00 200.00 2UO.OO 280.00 320.00 360.00 400.00
HERT RflTE (BTU/KW-HR) xlO2
CYCLING UNIT HERT RRTES
FIGURE B-V-6
267
-------
CD
CEo
LJO
CD '
MINIMUM=8727
MRXIMUM=27315
MERN=15793
STflNDflRD DEV=U482
a a
E) OD DO CD CDEJ
I EEKD
IJH — n
! n Bonn
^0.00 120.00 160.00 200.00 240.00 280.00 320.00 360.00 400.00
HERT RRTE (BTU/KN-HR) *102
PERKING UNIT HERT RRTES
FIGURE B-V-7
268
-------
Condenser temperature rise does not vary with industry categorization
(for fossil units) . The mean for all three groups (based on hours
operated per year) is about eight to nine degrees C (15-16 degrees F)
with a standard deviation of a little under three degrees C (5 degrees
F). (See Figures B-V-8, B-V-9, and B-V-10) .
Maximum outfall temperature will not vary with industry grouping since
it is the sum of ambient water temperature (which is unrelated to
grouping) and temperature rise across the condenser (which does not vary
with grouping).
In summary, the only waste stream characteristic which varies with
industry grouping is the quantity of heat rejected to the cooling water.
The other characteristics vary with locale, season, etc., and require
site-by-site evaluation to draw any reasonable conclusion.
Finally, Table B-V-3 summarizes typical waste stream characteristic
ranges for each grouping.
Effluent Heat Characteristics from Systems Other Than Main
Condenser Cooling Water
Waste heat from house service water systems and other smaller sources
can contribute about 155 of the total effluent heat discharged from a
generating plant. For example, the thermal discharges of one nuclear
plant (no. 4251) are shown in Table B-V-U. House service water systems
can be either once-through (nonrecirculatory) or recirculating. Nuclear
plants have emergency core cooling systems connected to the house
service water system. Where closed house service water systems are used
for nuclear plants, U.S. Atomic Energy Commission Safety Guide 27
requires (indirectly) that sufficient water be stored on-site (storage
pond) to assure an ultimate heat sink for safety purposes.
269
-------
§
o
C\J_
C\J
CO
ZD
SI
MINIMUM=1
MflXIMUM=32
MEflN=15
STflNDRRD DEV=5
n n n
3
gi am i en ass CD no i a mn a BCD i n oro CD CUD i a BCD ID aa;
1.00 8.00 12.00 16.00 20.00 24.00
CONDENSER DELTfl T (DEC. F)
28.00
32.00
BRSE UNIT CONDENSER DELTfl T
FIGURE B-V-8
270
-------
MINIMUM=1
MRXIMUM=29
ZO
=»=;.
r\j
O
—'o
CJo
UJ
OD<°-
g STflNDflRD DEV=5
m n
n
n n n D
o
o
••IH-
') 00 U" 00 S'.OO 12.00 16.00 20,00 24.00 28.00 32.00
CONDENSER DELTfl T (DEC. F)
CYCLING UNIT CONDENSER DEL T
FIGURE B-V-9
271
-------
MINIMUM-9
MRXIMUM=38
MEflN-16
STRNDRRD DEV
CO
cro
LUO
u_
to
UJO
o
o
_*^ JQ—BE G3C3G1G] i ED—HH—H—QIQ] | n—OH—GCDEG] [ ED—ClDnCDOEDtllEpDEDilinJDtllCTnEDiynDJIBESCTOitDCllDlEpEDtllCnCIlEDCDEDCtlCDCpCTEDCDID ESG][!]II3[1][!][!1EI][I3
'"bi. 00 12,00 16.00 20.00 24.00 28.00 32.00 36.00 40.00
' CONDENSER DELTfl T (DEC. F)
PERKING UNIT CONDENSER DEL T
FIGURE B-V-10
272
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Table B-V-3
TYPICAL CHARACTERISTICS OP WASTE HEAT REJECTION
Grouping
Nuclear
Fossil (Nat-
ional Average)
Reference 281
High Utilization
Intermediate
Utilization
Low Utilization
^.Heat Rate,
Joules/KHW
x 10~7
1.02 - 1.16
1.11
0.92 - 1.32
1.05 - 1.69
1.05 - 2.1
Heat Rejection to Water ?
Joules/KWH
x 10
0.72 - 0.80
0.58
0.42 - 0.80
0.53 - 10.7
0.53 - 1.43
Temperature Rise,
°C
10 - 16
8.6
4.5-13
4.5-13
4.5-11
ro
*»j
CO
* Note: Calculated by method discussed in this section for fossil-fueled plants
and from Table B-V-2 for nuclear plants.
-------
Table B-V-4
TOTAL PLANT THERMAL DISCHARGES
Plant No. 4251 (nuclear)
Cooling Water System
Main Condenser
Primary Plant Components
Secondary Plant Components
Centrifugal Water Chiller
Control Room Air Conditioner
Steam Generator Slowdown
(Discharged 1 hr out of
every 100 hr)
Flowrate, gpm
480,400
5,800
11,000
3,000
200
50 max
AT, °F
26
22
10
9
10
120
Heat, Btu/hr x 10"
6,290
66*
55
13
1
3 max
ro
* Note: 175 x 10 Btu/hr during plant cooldown once a year.
-------
PART B
THERMAL DISCHARGES
SECTION VI
SELECTION OF POLLUTANT PARAMETER
The Act, Section 502(6) , defines heat as a pollutant.
The purpose of this analysis is to suggest a functional parameter
reflecting the level of effluent heat reductions achievable by the
application of available control and treatment technology for steam
electric powerplants. The determination of a suitable parameter for
measuring the thermal component of the effluent is an essential part of
the work in developing effluent limitation guidelines for thermal
discharges.
The change that has occurred in the cooling water passing through the
condenser is an increase in its internal energy. This term is also
called "heat content". The change in internal energy or heat content is
a product of the mass rate of water flow, its temperature increase, and
its average specific heat.
Both the temperature increase of the cooling water and its discharge
temperature do not include the quantity of water discharged at this
temperature level, and thus do not reflect the total energy or heat
discharged. A parameter based on temperature alone, therefore, would
not be a reflection of the effluent heat in the discharge. To
adequately evaluate the heat rejection to a receiving waterbody, a
parameter reflecting total internal energy of the discharge is required.
The parameter that has been chosen in this report to represent the
effluent thermal characteristics is the total increase in internal
energy or heat content of the cooling water. This parameter directly
reflects that change in the effluent which results in thermal effects.
The increase in internal energy or heat content of the cooling water is
a function of the size of the powerplant. In order to compare different
size plants, the increase in internal energy must be determined per
kilowatt hour of plant output for each case. The increase in internal
energy or heat content of the condenser cooling water is determined as
follows:
U = m x c x T
KW
Where U = increase in internal energy of
condenser cooling water
275
-------
m = mass flow rate of cooling water
c = specific heat of cooling water
T = temperature increase of cooling water
KW = unit power output
With commonly used sets of units U would be expressed in
J/KWH (BTU/KWH) . Dimensionally , m is expressed Kg/hr
(Ibs/hr) of cooling water, c = 4.186J/Kg/°C (1 BTU/lb/°F)
and T is expressed in °C (°F)
For example, consider a powerplant with the following conditions:
Power output: KW = 225 x 10 kilowatts
Cooling water flowrate: m = 2.72 x 10 Kg/hr (6.0 x 10 Ibs/hr)
Temperature increase of cooling water: T = 11.1°C (20°F)
Specific heat of cooling water: C = 4.186 x 10 J/Kg/°C (1 BTU/lb°F)
The resultant internal energy increase is:
U = 2.72 x 10 (4.186 x 10 ) (11.1) = 5626 x 10 J/KWH
225 x 10
or in English units:
U = 6JL10_x_iO _m_L20l =533 BTU/KWH
225 x 10
This parameter provides a measure of the heat rejected to the receiving
waterbody in a manner which can be readily monitored. The only
quantities in the equation requiring measurement are the cooling water
flow and temperature rise and power output of the unit. Each of these
can be monitored directly without difficulty and utilized in a straight-
forward manner to compute the increase in internal energy or heat
content.
276
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PART B
THERMAL DISCHARGES
SECTION VII
CONTROL AND TREATMENT TECHNOLOGY
Introduction
This section contains a general discussion of the various methods for
controlling thermal discharge from steam electric power stations* There
are three methods available to reduce the gross amount of heat rejected
to receiving waters from the steam electric power generation process.
These methods are:
. process change
. waste heat utilization
. cooling water treatment
Various process changes can be made to the basic Rankine cycle to
increase its theriral efficiency. These process changes include
increasing boiler temperature and pressure rating, the addition of
reheat and regenerative cycles and reducing turbine exhaust pressure.
In addition, the Rankine cycle can be replaced with other forms of
generation which are inherently non-polluting. Several of these new
forms of generation are already available, such as the gas turbine
Brayton cycle and the combined cycle plant. Looking to the future,
transfer of gas turbine technology from the aerospace industry offers
the promise of gross plant thermal efficiencies approaching SOX in the
latter part of the decade. Since the gas turbine is air cooled, its
increased use can significantly reduce heat rejection to receiving
waters.
The replacement of the conventional Rankine steam plant with other forms
of power generation is also receiving increased attention. It is
anticipated that conservation of available energy resources will require
larger expenditures in ccal research and in the development of new power
generation technologies which do not require fluid fossil fuel. These
new generation technologies include solar generation, fuel cells, MHD
and geothermal power. In the nuclear power field, the production of a
demonstrator breeder reactor by the end of the decade will lead to
higher thermal efficiencies in nuclear power generation.
The utilization of portions of heat contained in the discharge of
condenser cooling water can reduce the amount of heat rejected from
steam electric powerplants. There are two different ways in which power
station waste heat can be beneficially employed by others. This first
is to use the low grade heat contained in the condenser cooling water
277
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itself. Several small-scale projects for utilizing low-grade heat
(mostly for agriculture and aquaculture purposes) will be described.
Other uses for partially expanded steam (extraction steam utilization)
for industrial process steam, space heating and cooling, and water
desalting have been practiced at several locations in conjunction with
electric power generation. The use of extraction steam methods
generally involves a degradation of the power cycle since the steam at
the extraction point has significant enthalpy remaining. Because of
this loss of cycle efficiency, extraction steam utilization tends to
raise the heat discharged as measured in Joules/KWH. It is necessary in
evaluating this type cf alternate use of steam to combine both the
powerplant and the alternate use to determine the benefits derived.
The major weakness of most programs of low-grade heat utilization and
single-purpose extraction steam utilization is that many of the
alternate uses of the available heat are seasonal. This means that the
additional costs associated with providing the steam distribution
systems must be written off over relatively few hours during the year.
It also means that the full amount of heat must be discharged to the
waterway during those periods when the secondary heat consumers are not
operating. This weakness largely defeats the purpose of employing low-
grade heat utilization systems. The total energy concept seeks to
overcome this shortcoming by aggregating all uses of heat in a region to
fully utilize available energy on a year-round basis. Most total energy
systems in this country are small, consisting of individual shopping
centers, educational complexes and commercial developments. Larger
total energy systems exist in Europe. It is felt that the rapidly
increasing cost of energy brought about by greater worldwide competition
for the earth's retraining fossil-fuel resources will make the total
energy concept more attractive in the future. Several different waste
heat utilization projects will be described.
A number of different technologies have been applied to condenser
cooling water discharges to reduce heat rejected to the waterways.
Three basic treatment options are available; open cooling systems,
closed cooling systems, and combinations of the two. Open cooling
systems discharge the full condenser flow following supplemental
cooling. Closed systems recycle the bulk of the circulating water flow
back to the condenser following supplemental cooling and discharge a
small fraction as blowdown to control salinity buildup in the system.
Open cooling systems employing evaporative cooling have the basic
disadvantage of not being able to maintain a desired level of treatment
year-round due to seasonal variations in wet bulb temperature. Open
cooling systems have a distinct advantage over closed systems in that
they do not affect the turbine backpressure. A closed cooling system
can produce a low-level heat discharge year-round at the expense of
increased turbine backpressures. Increasing turbine backpressure
entails increased station cost above the cost associated with the
cooling system. These additional costs are incurred to buy replacement
278
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power for those periods when the station (because of high backpressures)
cannot produce its rated capacity (capacity penalty) and also to pay for
increased fuel cost for less efficient turbine performance (energy
penalty) . Both open systems and closed systems require additional power
to operate pumps, fans, etc., which affects station capacity and fuel
cost to some degree. Incremental capacity and fuel costs are higher for
backfitting existing units than for new units.
Most existing treatment of condenser cooling water has been designed to
operate in a recycle mode. These systems have generally been installed
where sufficient water for once-through cooling was unavailable. Some
closed systems are designed to allow open system operation for a portion
of the year. All of the available cooling water treatment technologies
will be described in this section.
Process Change
In order to properly understand both the problems and possible solutions
regarding thermal discharges from powerplants, it is necessary to review
a few essential thermodynamic principles. Only those principles that
directly relate to the situation being investigated will be discussed.
They will be presented in simplified terms, allowing a small relaxation
of rigorous scientific exactitude.
The discussion is presented in three steps. First presented are
principles, and then shown how they affect the steam electric powerplant
cycle. Next, historic.developments are reviewed, relating them to the
principles. This is important to understanding some approaches to
improving plants in regard to thermal effects. Finally, we have related
principles as guides to possible new types of power generating systems
with improved thermal effects characteristics.
Thermodynamics is the study of the conversion of energy from one form to
another, particularly the forms of energy called "heat" and "work". The
purpose of a steam electric powerplant is to convert heat into work or
power, which is the rate of work. Thus, steam electric powerplants are
directly concerned with thermodynamics. Important questions to pose
about this process of getting work from heat are:
1. How can we increase the amount of work obtainable from a given
amount of heat?
2. Is there a limit to how much work obtainable from a given amount of
heat?
3. What happens to the heat that is not converted into work?
Thermodynamics is based largely on two laws. These are called the
"First Law" and "Second Law". Before stating these laws, it is
279
-------
necessary to include a few definitions of words or phrases used in the
statements of these laws, or in explaining them.
Heat engine (powerplant) - a device or plant used to convert heat into
work.
Energy - the ability to do work. Heat and work are both forms of
energy. Work may appear as mechanical energy (such as the rotation of a
wheel) or electrical energy.
Cycle - the processes or changes which the working fluid of heat engine
(powerplant) goes through.
Efficiency - the proportion of energy input (heat) to a powerplant which
is converted to energy output (work).
Reservoir - an energy source or an energy receiver.
There are a number of ways of stating the laws Of thermodynamics. We
have chosen a special phrasing that seems most applicable to this study.
It should be remembered that this is a restricted non-rigorous
statement.
First Law - the total energy supplied to a powerplant must be removed
from the plant.
This statement is akin to the conservation of energy interpretation of
the First Law, i.e., there must be a budget or accounting of the energy,
and this budget must balance.
Figure B-VII-1 shows a simplified example of the energy flow for a power
producing engine or plant.
The powerplant receives energy in the form of heat from combustion of
fossil fuels, or from nuclear reaction. Some of this energy is
converted to a useful output in the form of work (electricity) . There
is also heat energy output from the plant. This is mainly the energy
associated with thermal discharge to receiving waters.
The First Law, which requires an energy balance, thus can be stated in
equational form for this example as:
Energy In (Heat) = Energy Out (Work) + Energy Out (Heat)
or rearranging Energy Out (Heat) = Energy In (Heat) -
Energy Out (Work)
The importance of this for thermal discharges is that once the
proportion of Heat Energy In that is converted to Work Energy Out is
determined, the remainder is a source of thermal discharge. For
example, in Figure B-VII-2 relative values of energy are indicated for a
280
-------
J
(HEAT)
POWER
PLA.MT
— *•
ENERGY OUT
(WORK)
ENERGY OUT
(HEAT)
ENERGY FLOW FOR A POWER PLANT
FIGURE B-VII-1
IOO ENERGY UNITS
CHEAT)
POWER
PLA.NT
4-0 ENERQY UWITS OUT
(WORK)
&O EKIER^Y UWITS OUT
(HEAT)
ENERGY BALANCE FOR A POWER PIANT
(FIRST LAW)
FIGURE B-VII-2
281
-------
hypothetical powerplant. For this plant, for every 100 units of energy
input, 40 units are converted to useful work. The First Law reveals
that inexorably there are 60 units of energy that must be rejected to
the surroundings. (The relative values in this example are close to
those typical of modern steam electric powerplants) .
Note however, that the First Law does not require that any heat be
rejected from the powerplant. It only says that we cannot produce more
energy in the form of work than the quantity of energy (in the form of
heat) supplied. At this point, the following might be asked:
"Does the energy rejected have to be in the form of heat?" "Can we
build a plant with a better efficiency than in the example cited,
which seems pretty inefficient (40%) ?" "Is there any limit on
efficiency, other than economic considerations? This is, can we
reduce the heat rejected to the environment, without limit?"
Such questions have important implications. They lead to a statement of
the Second Law of Thermodynamics:
"It is impossible for a powerplant to receive heat energy from a
source and to produce the same amount of energy as work."
It might be noted at this point that the Second Law of Thermodynamics
cannot be proven from other principles. It is a conclusion reached by
experience: observation and experimentation. We can picture a
powerplant that would violate the Second Law as stated in Figure B-VII-
3. Note that it does not violate the First Law. In order to bring this
powerplant into conformity with the Second Law, we try to rearrange its
operation as shown in Figure B-VII-4. We are not producing the same
amount of energy as work, as was supplied in the form of heat. But now
we are violating the First Law, as there is an energy unbalance.
In order to make this plant conform to both laws, we must rearrange its
operation as shown in Figure B-VII-5.
The remaining 60 energy units in the form of heat must be rejected to
the receiver, which is the environment.
Based on our senses and experience, we are usually psychologically
comfort a"ble with the First Law. It expresses a principle that a budget
must balance. Yet the Second Law may seem irrational. There seems to
be nothing unnatural in having a powerplant receive heat energy and, as
a result, produce some power with no other results or effects occurring.
Nevertheless, evidence indicates that such a powerplant cannot be built.
Some heat must be rejected. But how much? Could we build a powerplant
that is 99X efficient, if we considered it financially feasible, thus
rejecting a negligible quantity of heat to the environment?
282
-------
POWER
PLANT
100 ENERGY UNITS
OUT
POWER PLANT VIOLATING SECOND LAW
FIGURE B-VII-3
100 ENERGY
HEAT VUWITS
SOURCE/ (HEAT)*
POWER
PUNT
4O ENERGY OWITS
OUT (WORK')
POWER PLANT VIOLATING FIRST LAW
FIGURE B-VII-4
283
-------
too
UNITS' IN
(MEAT')
POWER
PLAMT
GO
UNITS OUT
40 ENERGY UNITS
OUT (WORK)
POWER PLANT CONFORMING TO FIRST AND SECOND LAW
FIGURE B-VII-5
-------
There is an upper limit on the efficiency of any powerplant. This limit
is that provided by a powerplant that operates on a completely
reversible cycle. In this type of cycle, the plant receives heat only
at a constant temperature and rejects heat only at a constant
temperature. In addition, there are no losses such as friction in any
of the processes taking place. The efficiency of such a powerplant
depends only on the temperature at which the plant receives heat from
the source, and the temperature at which it rejects heat to the
surroundings.
The efficiency of this type of plant can be determined from the
following equation:
Ere = 100 (1-T2) (1J
Tl
where Ere = efficiency of reversible cycle powerplant
Tl = temperature at which plant receives heat
from heat source, expressed in absolute units
T2 = temperature at which plant rejects heat to
surroundings expressed in absolute units
This equation can be derived from the Second Law of Thermodynamics, in a
somewhat lengthy procedure. There are a number of these completely
reversible cycles that have been conceived of. The best known is called
the Carnot cycle. For this reason, the above efficiency is often called
the Carnot Efficiency, although any cycle that meets the specified
conditions will have the same efficiency.
It will be instructive to determine what the efficiency of a completely
reversible cycle would be for temperatures, representative of modern
steam electric powerplants. The maximum temperature at which a plant
receives heat is about 600°C (1000°F). This is a limit resulting from
the decreasing strength of metals at elevated temperatures. The minimum
temperature at which a plant rejects heat is about 32°C (90°F) . This is
a limit resulting from the available temperature of normal surroundings,
unless a plant could reject heat to outer space at absolute zero, -273°C
(-460°F) .
Converting these temperatures to their absolute values, (degrees
Rankine), and calculating the efficiency:
Tl = 1000 + 160 = 1460°R
T2 = 90 + 460 = 550°R
285
-------
Ere = 100 (1-5_50) = 62%
1460
This is the highest efficiency that can be reached by any powerplant
operating within these temperature limits. The efficiency of the most
modern powerplants incorporating the best technology features, operating
within these temperature limits, reaches 4055. These modern powerplants
achieve a quite high efficiency, relative to the maximum. If one does
not consider the Second Law limitations, 40% seems a low figure, and we
might conclude that great increases in efficiency could be made with
reasonable research investment. But in reality, the "perfect"
powerplant under these conditions is itself only 62% efficient. Thus,
an actual modern pcwerplant has an efficiency relative to the
theoretical possible of:
Relative Efficiency = 4£ x 100 = 65%
64
Considering additionally, the minimum practical losses in each of the
components in a powerplant, even the relative efficiency of 65% is low
as an indicator of the likelihood of further improvements in the
existing steam electric powerplant cycle. In any case, even with the
best theoretical cycle, the same basic problem would exist of
discharging large amounts of waste heat to the surroundings, since only
about a 33% reduction in present thermal discharges would be
accomplished.
Referring to Equation (1) , note that the efficiency of the completely
reversible cycle is increased by raising Tl or lowering T2, and that
100% efficiency can be achieved only with an absolute zero temperature
T2, or approached with an infinite temperature T1.
History of the Steam Electric Power Plant Cycle
In this section, we will outline the chronological development of the
thermodynamic cycle of the steam electric powerplant. The purpose of
this approach is to indicate what methods have been developed to improve
cycle efficiency, and indirectly reduce the heat discharged to the
environment. This will aid in understanding problems and possible
directions for future cycle improvements.
The discussion should begin with a description of a completely
reversible cycle, as it is the best theoretically achievable. In this
way, each actual powerplant development may be compared to the paragon.
The Carnot cycle is chosen as the completely reversible cycle to
describe. Figure B-VII-6 shows the basic components of the Carnot stean
powerplant cycle: bciler, turbine, condenser and compressor. ThJ
286
-------
POWER OUT
ro
oo
BOILER
HEAT
RECEIVER
POWER iN
CARNOT CYCLE STEAM POWER PLANT
FIGURE B-VII-6
-------
components are connected by piping as shown, with the direction of flow
of the fluid between them as indicated.
The heat source may be combustion of fossil fuel or nuclear reaction (or
recently geothermal heat) . Heat is transferred from the source to water
in the boiler. The water enters the boiler in a saturated liquid
condition. This means that it is at a temperature where it will begin
to boil when heated. It does not need to be heated up to boiling
temperature. The water is completely evaporated, and it leaves as
saturated steam. This means that it has been completely converted to
vapor, but its temperature has not increased. (Further heating of the
vapor to a higher temperature produces superheated steam). \
The steam then flows to a steam turbine, where its energy is used to
rotate a shaft and generate power. In so doing, the steam temperature
and pressure 'drop considerably in the turbine. Steam leaving the
turbine flows to the condenser, where heat is removed from it.
The condenser removes enough heat to partially condense the steam
entering. Thus a mixture of liquid and vapor leaves the condenser. The
temperature of the condensing steam does not change during the process.
This mixture is then compressed in a compressor. This compression
process raises the temperature and pressure of the fluid, and a]so
causes the condensation of the remaining vapor. The result is that the
fluid leaves the compressor at the predetermined conditions set for the
boiler, as a saturated liquid. Note that power is required to operate
the compressor.
As heat is added in the boiler at a constant temperature and removed In
the condenser at a constant temperature, and assuming no losses in any
equipment, the cycle will be a completely reversible one, with tie
maximum efficiency possible for the temperatures specified.
With this paragon continually in mind as a reference standard, let us
now turn to the historical development of the actual cycles used in the
steam electric powerplant. We have observed that the cycle
modifications and developments improved efficiency, usually however, at
the expense of increased plant complexity. We also note that th«
developments brought the actual cycle closer to some of the features of
the Carnot cycle, which being the best possible, is not a surprising
development. Yet the Carnot cycle itself has great practical
deficiencies.
It is worth noting that the development of the cycle was largely
accomplished by inventive-minded engineers, and to a great extent at a
time before thermodynamics was a fully understood or applied science.
288
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Rankine cycle
Named after the engineer W. J. M. Rankine (1820-1872) , Professor at the
University of Glasgow, the components and flow for this cycle are shown
in Figure B-VII-7.
The cycle has four basic components: boiler, turbine, condenser and
pump. A heat source furnishes heat to the boiler. Water entering the
boiler is first heated up to its saturation temperature and then
evaporated completely. The steam flows
to the turbine where its energy is used to rotate a shaft and generate
power. The steam leaves the turbine at a lower temperature and
pressure, and flows to the condenser. Here the steam is completely
dondensed to liquid water by removing heat. A pump delivers the
feedwater to the boiler at the boiler pressure. Some of the heat is
added in the boiler to the water, which is at a temperature lower than
it would be in the boiler in a Carnot cycle at the same maximum
temperature. Thus the efficiency of the Rankine cycle will be lower
than that of the Garnet cycle.
Rankine cycle with Superheat
Even at very high pressures, the boiling temperature of water is
considerably lower than can be achieved in the boiler, with present
technology. Recalling the fact that the higher the temperature at which
heat is added to the plant, the greater the efficiency, this means that
with the Rankine cycle, efficiency is unnecessarily restricted.
A relatively simple means of improving this situation is to superheat
the steam. A schematic flow diagram of the Rankine Cycle with superheat
is shown in Figure B-VII-8. After the water has been completely
evaporated, the steam is superheated to a higher temperature, within
metallurgical limits. As the average temperature at which heat is
supplied to the plant is higher than with the simple Rankine cycle, a
'higher efficiency will result.
Regenerative Cycle
With the Rankine cycle, water entering the boiler is at a relatively low
temperature, i.e. the temperature at which it is condensed in the
condenser. As with the Carnot cycle, the lower the condensing
temperature, the greater the efficiency. However, with the Rankine
cycle, having this cocl water entering the boiler means that a good part
of the heat is added to the working fluid at an average temperature
considerably below the maximum.
If the average temperature at which heat is added could be increased,
the cycle efficiency would improve. This is the basis for the
regenerative cycle. A schematic flow diagram with components for one
version of the regenerative cycle shown in Figure B-VII-9.
289
-------
ro
vo
o
POWER
OUT
BOILER
POWER
IN
RANKINE CYCLE POWER PLANT
FIGURE B-VII-7
-------
1C
POWER
OUT
TURBINE
SUPERHEATER
BOILER
POWER
: IN
RANKINE CYCLE WITH SUPERHEAT POWER PLANT
FIGURE B-VII-8
-------
POWER OUT
MEAT IN
ro
<£>
ro
HEAT OUT /M r AT
CONDENSES/ /HEAT
POWER IN
REGENERATIVE CYCLE POWER PLANT
FIGURE B-VII-9
-------
In this cycle, the boiler feed water is preheated in a heater before
entering the boiler, by means of steam at an intermediate temperature
and pressure bled from the steam turbine. The water entering the boiler
is therefore at a higher temperature than it would be with the Rankine
cycle. The heat added from the external source will now be added in the
boiley at a higher average temperature, and the cycle efficiency will be
higher.
To increase the efficiency still further, a few heaters in series can be
used, with steam bled from the turbine at progressively different
conditions. Of course, the complexity and cost of the plant increases
with more heaters.
As the number of feedwater heating stages increases, the regenerative
cycle more closely approaches the Carnot cycle, because less of the heat
is added externally at lower than maximum temperatures (more is being
added internally - hence the word regenerative) . The question naturally
arises as to why the Carnot cycle itself is not used, as it has a
greater efficiency, and would avoid the complexity and expense of the
feedwater heating stages.
In actual conditions, the Carnot cycle applied to real equipment would
have a poor efficiency. The turbines, pumps and compressors have losses
due to mechanical friction, fluid turbulence and similar phenomenae.
Thus the pump and compressor will require more power to operate than
under ideal conditions. It is the nature of the Carnot cycle that the
compressor is a very large power consuming device. In a real plant, the
actual power to operate this compressor would reduce the actual plant
efficiency considerably. The Rankine cycle does not suffer from this
shortcoming, as the pump requires relatively only a small amount of
power.
Reheat Cycle
As the steam expands in the turbine, in addition to its temperature and
pressure dropping, it begins to condense. The result is that in the
latter stages of the turbine liquid water droplets form. Only a small
amount of moisture can be tolerated, due to possible erosion of the
turbine blades and reduction of turbine efficiency. Depending on the
inlet temperature and pressure, if the designer attempts to use the
minimum condensing temperature available, the moisture content in the
turbine might be excessive. In that case, he would have to design the
Rankine or regenerative cycle with a higher condensing temperature and
suffer a loss of efficiency.
A method of overcoming this difficulty is with the reheat cycle. Figure
B-VII-10 is a flow diagram of a typical reheat cycle.
Steam leaving the superheater enters a high pressure turbine. The steam
does not expand in this turbine to a temperature low enough to create
293
-------
ro
ID
-pa
^-REHEATER
REHEAT CYCLE POWER PIANT
FIGURE B-VII-10
-------
excess moisture. The steam leaving the turbine is reheated at the lower
pressure back to a high temperature. It then flows to a low pressure
turbine where it can be expanded down to the minimum condensing
temperature without excess moisture being created in the turbine. The
reheat cycle can be combined with the regenerative cycle also, in a
similar manner.
Historical Process Changes
changes in existing processes or their conditions may be considered as a
possible way to improve plant heat rate and thus reduce heat rejection.
It is worthwhile tc see how the plant heat rate has already been
improved by such changes up to the present time, and then to view the
progress for further improvements.
By the 1920's typical plants used steam pressures and temperatures
reaching about 1900 kN/ir,2 (275 psi) and 293°C (560°F) . The improved
equipment and materials that became available in the decade enabled
pressures and temperatures to be increased to the neighborhood of 3792
kN/m2 (550 psi) and 3U3°C (650°F), resulting in increased efficiency.
Expansion in the turbine from these conditions, however, resulted in
excessive moisture in the turbine, and as a result these plants adopted
the reheat cycle.
By the 1930's further material improvements resulted in the availability
of steam pressures and temperatures of about 6205 kN/M2 (900 psi) and
i»82°C (900°F). Under these conditions, expansion in the turbine occurs
down to minimum condensing pressure without excessive moisture, and as a
result plants were typically designed without reheat.
Further material improvements since the 1930•s resulted in higher
available steam pressures. A pressure of 17200 kN/m2 (2500 psi) and
temperature of 538°C (1000°F) might be typical today. This increase in
pressure with correspondingly little increase in temperature would
result in a condition of excessive moisture if full expansion were taken
in the turbine in one pass. Because of this, reheat has been adopted
again in recent decades. In addition, higher fuel costs justify the
increase in efficiency gained from reheat. Generally only one stage
(single) reheat is economical. For plants that are designed to operate
at supercritical pressures 2400 kN/m2 (3500 psi), however, double reheat
may be justifiable. Triple reheat has not been found economically
feasible under any conditions. Along with these developments, adoption
of the regenerative cycle had become standard due to its increased
efficiency over the Rankine cycle. The efficiency increases with the
number (stages) of feed water heaters used, but of course the plant
initial cost increases correspondingly. For large plants, present costs
justify 7 or 8 stages of heating.
295
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Process Changes for Existing Plants
A summary of possible individual changes in existing plants is shown in
Table B-VII-1, Efficiency Improvements. Included in this table are
approximate estimates of the improvement resulting from the change, the
work required to effect- it, estimates of outage time that the plant will
be down to make changes, and approximate capital costs. These figures
are quite approximate, because they actually vary with existing plant
conditions.
Feedwater Heaters
Addition of one heater improves the heat rate about 285 kJ/ KWH (270
BTU/KWH), perhaps 2%. Further heaters would improve the heat rate by a
succeedingly smaller amount. Turbine modifications would probably be
required.
Reduce Backpressure (Condensing Pressure)
This is accomplished by increasing the velocity of water in the
condenser tubes, which results in better heat transfer and thus lower
condensing temperature and pressure. The degree to which this
improvement can be effected is small. Tubes must be changed to take the
higher velocities without erosion, but this is limited. In any case,
the increased pumping power would offset part, if not all, of the gain
in efficiency.
Increase Steam Temperature
Small increases might be accomplished with boiler and main steam piping
modifications. Larger increases require turbine replacement also. In
any case, the maximum steam temperature practical at the present level
of technology is about 5UO°C (1000 °F).
Increase Steam Pressure
Improvements in efficiency of the order shown may be accomplished by
increasing steam pressures. However, extensive replacement of much of
the plant is required.
Reheat
On lower pressure units, 10000 kN/m2 (1450 psi and less) , the efficiency
gain from reheat is less than for higher pressure units, 12UOO kN/m2
(1800 psi and higher). The gains and work required are as shown in
Table B-VII-1. The extent of work approaches a complete replacement of
the plant.
296
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TABLE B-VII-1
EFFICIENCY IMPROVEMENTS
Modification
Improvement
in Heat Rate
Work Required
Outage
Time
Cost
Remarks
Add Feedwater
Heaters
270 Btu/Htr.
Replace turbine, add
heater and piping
8 mos. $25/KW For same steam flow the unit output
would be reduced by 5%. Charge
required for replacement energy.
Lower Back l%/0.5"Hg Change condenser tubes for
Pressure higher velocity. Add new
(Pump more circulating water pumps
C.W.) with new intake bays and
piping as required.
2 mos. $6-8/KW Limit of improvement is in the order
0.25"Hg and any gain would probably
be lost to increase pump power.
Increase
Steam
Temperature
PO
10
0.8%/50
Possibility of boiler
modification to obtain
-25 F. Some modification
of turbine will be required.
Main steam piping will have
to be replaced.
3 mos.
$6-8/KW
Practical limit for steam temperature
is 1000 F. Limitation primarily due
to boiler, however turbine also poses
problems
For 50-100 F increase
make extensive modifi-
cation to boiler(or replace)
and replace turbine plus
steam piping. Turbine
pedestal modifications will
also be required.
8-16 mos. $35-50/KW
Increase 1450-1800psig Replace boiler, turbine.
Steam =1.7%;1800- steam and feedwater piping.
Temperature 2400psig=2.0%; some changes to feedwater
2400-3500 psig heaters. Modify turbine
=1.7% pedestal and install new
^ feedwater pumps.
16 mos. $60-80/KW
Increases of 3-5% possible without
modification.However,this will not
increase cycle efficiency because the
turbine is designed for maximum
efficiency at rated pressure.
Add
Reheat
3-4% for units
operating at
1800 psi and
above.
2-3% for units
operating at
1200-1450 psi
Replace boiler,turbine
and hot reheat piping,
rebuild turbine pedestal,
modify boiler controls,
modify condenser and make
changes to feedwater
heating system.
24 mos.
$100/KW Typical new reheat unit would be 75MW
or less in size and would operate at
1450 psi and 950°F.
-------
Increased Cooling Gas Pressure
By increasing the pressure of the hydrogen gas used for cooling the
generator, it would be possible to produce slightly more power from the
generator, with higher input.
Drain Coolers
Cycle efficiency may be improved slightly by the addition of drain
coolers to the existing feedwater heating system, if not already
included. Figure B-VII-11 shows this arrangement. The drain cooler
takes the hot condensate from the feedwater heater and uses it to
preheat the feedwater leaving the condenser. In this way the cycle
efficiency is increased slightly.
/
Drains Pumped Forward
Cycle efficiency may be improved slightly by pumping the feedwater
drains forward, instead of draining it back to the condenser. Figure B-
VII-12 shows this arrangement. Note that an additional pump is required
for pumping the drains.
Superposed Plants
A method of improving the efficiency of older plants that has met with
some success is the superposition of a higher pressure and temperature
system on top of the existing plant. A hew boiler, turbine, feedwater
heaters and pumps are added to the plant, exhausting steam to the old
turbine at its design conditions (Figure B-VII-13). The new boiler may
replace the old boiler ,or supplement it. The advantage of this
procedure is that the existing turbine and condenser are retained, and
made use of. Economical upgrades of a number of plants were carried out
in this way in the 1930*s. It is doubtful that this approach would be
economically justifiable under existing capital cost conditions.
Complete Plant Upgrading
Consider a typical non-reheat unit, rated at 75 MW, to be upgraded to
get a turbine cycle heat rate of approximately 8,450 kJ/KWH (8,000
BTU/KWH). The following changes would be required:
1. Raise pressure to 16,500 KN/m2 (2,400 psi)
2. Increase superheat temperature to 537°C (1,000°F)
3. Add reheat to 537° (1,000°F)
4. Modify the regenerative feedwater heating cycle
To make these changes, the following work is required:
1. New boiler, turbine and boiler feed pumps
298
-------
ro
vo
10
DRAIN
WNA
COOLER
DRAIN COOLER ADDITION TO POWER PLANT
FIGURE B-VII-11
-------
to
o
o
[CONDENSER
DRAINS PUMPED FORWARD IN POWER PLANT
FIGURE B-VII-12
-------
NEW PLANT• ADDITION
ORIGINAL PLANT
SUPERPOSED PLANT ADDITION
FIGURE B-VII-13
301
-------
2. New steam and feedwater piping
3. New boiler controls
4. New feedwater heaters
5. Add cold and hot reheat piping
6. Rebuild the turbine pedestal
7- Modify the condenser
8. Modify parts of the turbine building and rebuild the boiler building
The cost of all this work would be at least as much as that of a new
plant, as that is what it involves. It is estimated that a 2-3 year
plant outage would be required for the work.
Future Improvements in Present Cycles
At the present time, maximum steam temperatures are limited to about
537°C (1,000°F) . Temperatures above this requires changes in the type
of steel used in boiler tubing, piping and in turbines that greatly
increase plant costs. There is a general consensus in the utility
industry that significant increases in steam temperature are not
forthcoming in the immediate future.
Most of the average size units being installed at the present time, in
the 300 to 600 MW size range, are at a pressure level of around 17,200
KN/m2 (2,500 psi). A significant increase to supercritical pressures,
around 24,100 KN/m2 (3,500 psi) is being used for some of the larger
units. A cycle efficiency improvement of about 1.5 to 2.OX occurs with
this pressure increase.
Gas Cycles
In addition to the steam vapor powerplant cycle, gas cycles may be
considered for generating electric power. These plants usually operate
on the Brayton (Joule) cycle or some modification of this cycle. Figure
B-VII-14 indicates an arrangement of components, and the gas flow.
Air is drawn into the compressor. After compression the air flows to a
combustor where a gaseous or liquid fuel is burned in the air. The
products of combustion at high temperature and pressure flow through the
turbine and generate power. This cycle may have a relatively low
thermal efficiency, even though heat is added at a relatively high
temperature. This is because the gases discharged from the turbine are
still at a quite high temperature. To overcome this a regenerative heat
exchanger is added to the cycle, as shown in Figure B-VII-15.
302
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POWER IN
o
OJ
'.FUEL IN
COMBUSTOR
IN
.POWER OUT
COMBUSTION
GAS OUT
SIMPLE BRAYTON CYCLE GAS TURBINE POWER PLANT
FIGURE B-VII-14
-------
FUEL
1
COMBUSTOR
POWER. \M
AIR.
f
REGENERATOR
POWER OUT
COMBUSTION
BRAYTON CYCLE WITH REGENERATOR GAS TURBINE POWER PLANT
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 interceding between
compressor stages and by reheating, using a second combustion chamber.
With these refinements the efficiency of the cycle may increase further.
Gas cycle power generation precludes any significant thermal wastewater,
as the main effluent is a gas.
Gas Cycle Plants - Base Power
Plants using gas cycles are used for tase power today only in special
applications. The cycle efficiency does not equal that of the steam
vapor cycles. Gas turbines are not available in sizes adequate for the
larger units of present pcwerplant design.
Present development of turbines and other plant components to withstand
higher temperatures may make the gas cycle more attractive in future
decades.
Gas Cycle Plants - Peaking Power
The gas turbine cycle is used today for purposes of peaking power. The
structure of some power system loads is such that there is a base load
plus short term requirements for peaks above that load. A gas turbine
plant addition is a natural consideration for this use. A relatively
inefficient cycle can be used, because of the short periods of use. The
incremental capital cost of the plant addition is low.
The result of this arrangement is no increase in the thermal wastewater
discharge for the additional power generated. However this holds only
for the incremental power and only during the short time period that the
peaking equipment produces this power.
Combined Gas - Steam Plants
An efficient combination can be obtained by utilizing the high
temperature at which heat is added to the plant in the gas cycle and the
low temperature at which heat is rejected from the plant in the steam
cycle. An example of the plant component arrangement is shown in Figure
B-VII-16.
The combined cycle has proven advantageous as a method of up-grading
existing older steam plants. Usually the situation is one where the
existing boilers need replacement or veary extensive rebuilding. The
efficiency of the existing plant is usually not high, as the steam
temperatures and pressure are considerably lower than those possible
today. The modernization procedure usually consists of replacing
existing boilers with gas turbine exhaust heat boilers which supply
305
-------
TO
STACK
"I
1
r
EXHAUST
HEAT
BOILER
COMfcUSTOR
STEAM
TURBINE
PLOW
STEAM FLOW
COMPRESSOR
AIR IN
COMBINED GAS-STEAM POWER PLANT
FIGURE B-VII-16
-------
steam to the existing steam turbines. The overall plant efficiency of
such an arrangement might increase 5 to 10%, thereby reducing the
thermal discharge correspondingly.
Plant No. 3708 has up-graded part of its plant with such a combined
system. The result has been to reduce the heat rate on that part of the
plant from 14,770 kJ/KWH (14,000 BTU/KWH) to 11,610 kJ/KWH (11,000
BTU/KWH) .
The combined gas-steam cycle has also been chosen in some new plants
recently. The overall plant efficiency is approximately the same as
that which would be achieved with a modern steam plant. However, gas
turbines that will withstand significantly greater temperatures are
expected to be available within a few years. Higher temperatures are
already in use in aircraft gas turbines, and the spin-off in technology
should follow as it has previously. This is estimated to result in
cycle efficiency improvements of 5 to 1035 for the next generation of
combined gas-steam plants over the best steam plants today. The present
design of steam plants is not expected to improve by a similar increase
of temperature. Technological improvements in boilers to match those of
gas turbines are not expected. If such developments occured,
it seems likely that the resultant steam plant would not economically
compete with the combined plant.
Future Generation Processes
; Binary Topping Cycles
i With steam vapor cycles, much of the heat is added to the plant at lower
temperatures than the iraximum possible. This heat is largely used to
evaporate the water. Vaporization of water cannot take place above
374°C (705°F), therefore this inefficient heat addition process cannot
be avoided.
To overcome this defect, plants using two fluids, each in a separate
cycle, have been conceived. An example is the mercury-steam binary
cycle. Mercury is used in the topping cycle, steam in the bottom (lower
temperature) cycle. Heat can be added to the mercury at practically the
highest temperature metallurgically permissible, A few powerplants have
been constructed using this arrangement.
Although this cycle has an inherently higher efficiency than with the
steam cycle alone, serious disadvantages have led to its demise.
Mercury is extremely expensive and highly toxic. Some operating
problems were not satisfactorily resolved in the plants built.
Theoretical interest has been shown in using other fluids for the
topping cycle (e.g., potassium) but developmental work has been limited.
307
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Geothermal Steam
Geological conditions in certain locations provide a natural source of
steam from the earth's heat. The steam can be used in a conventional
power turbine. The thermal discharge .rejected from the plant has less
internal energy than the steam, so there is a net negative thermal
discharge. However, the disposed waste heat could still be in an
objectionable form and location. The use of this power source is
practicably confined to only a few locations on the earth, and thus does
not affect thermal discharges generally.
MHD
Magnetohydrodynamics (MHD) is a principle of producing power quite
different from the steam cycle. An electrically conducting hot gas is
moved at high velocity through a magnetic field, a procedure that
directly generates electricity in a surrounding coil. The present
status of this phenomenon for power production is in experimental
development stages only.
Fuel Cells
The efficiency of a fuel cell is not limited to that of the Carnot
cycle, as it does not receive its energy by means of conversion of heat
energy to work. Energy is converted directly from chemical to
electrical energy. Fuel cells have been commercially developed for
certain applications in small power requirements, but at the present
time there is no prospect for large units on the scale of steam power-
plants.
Waste Heat Utilization
There are three ways in which heat produced by powerplants might be
utilized in an alternate manner to reduce the amount of heat rejected to
receiving waters. These alternate heat consuming methods are as
follows:
- utilization of low-grade heat
- utilization of extraction steam
- total energy systems
Utilization of low grade heat
This process means the use of the condenser cooling water in the
condition it is in as it leaves the condenser. Using low-grade heat in
this manner is desirable because no modification to plant performance is
required. The disadvantage of this type of system is that the heat
content of the condenser water that is useable is small and large
volumes of water must be transported to get a significant quantity of
heat. Of the several systems of low-grade heat utilization in operation
308
-------
or in various stages of development, most are agriculturally or
aquacultnrally oriented. The findings of some of these programs are
discussed below.
Agricultural uses
A considerable amount of related work has been planned by the Tennessee
Valley Authority. TVA has set aside 7,280 hm2 (180 acres) of land at a
major nuclear installation (Plant No. 0113) for the testing of various
ways of using waste heat.
The initial effort at the TVA plant will be concentrated on the
development of greenhouse technology for the production of high value
horticultural crops utilizing the condenser discharge water for both
heating and cooling. The information on these programs has been taken
from Reference 353. Initial tests will include conventional greenhouse
crops such as lettuce, tomatoes, cucumbers, and radishes. Later work
will include such crops as strawberries for the fresh out-of-season
market. Eventually, a mix of crops which fits well in sequence during
the year with production and marketing conditions and which grow well in
the greenhouse climate will be determined.
Preliminary calculations have been made of several crop combinations to
obtain an estimate cf the potential sale value per acre of greenhouse.
The data indicate gross sale potential of from $40,000 to $60,000 per
40.5 hm2 (acre) per year is obtainable depending on crop mix. The
savings in fuel cost alone in utilizing the waste heat in this manner
may be upwards of $10,000 per 40.5 hm2 (acre) per year. Calculations
show that the development of 1,300 hm2 (32 acres) of greenhouse tomato
production and 2,350 hm2 (58 acres) of lettuce would utilize about 6% of
the available condenser water at the plant, and provide about 1.4% of
the total requirements for these products in the Southeast. The lettuce
production would amount to 30 percent of that now shipped into the
combined Atlanta, Memphis, Nashville, and Birmingham markets. TVA is
also planning other projects for agricultural use of waste heat for
subsurface heating cf the ground, and also utilizing the greenhouse
concept for the raising of pork and poultry. These programs are not
very far advanced at this point.
A similar study of greenhouse use of waste heat has been performed by
the ABC and is reported in Reference 351. This study centered on the
use of waste heat from a new high-temperature gas-cooled reactor located
in the Denver vicinity. The study concluded that the cost of equipment
required to utilize the warm water was in the range of the cost of heat-
ing systems for conventional greenhouses. Since the cost of heating
greenhouses in the Denver area is over $5,000 per year, the potential
value of the heat being wasted is greater than $1,000,000 per year.
309
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Aquaeulture
The use of low-grade heat to improve the yields and productivity for
fish and seafood species is called aquaculture. Basic data indicate
that catfish grow three times faster at 28.3°C (83°F) than at 24.4<>c
(76°F). Similarly, shrimp growth is increased by about 80% when water
is maintained at 26.6°C (80°F) instead of 21.1°C (70°F) .
Several commercial operations of this type are in existence in the U.S.
utilizing waste heat from powerplants. A commercial oyster farming
operation is in existance on Long Island, N.Y. using the thermal
effluent from powerplant No. 3621. Normal growing periods of four years
have been reduced tc 2.5 years by selective breeding, spawning, larvae
growth and seeding oysters in the hatchery. This avoids reliance on
variable natural conditions and permits accelerated growth in the
thermal effluent discharge lagoon over a period of about 4-6 months when
the water would otherwise be too cold for maximum growth. The product
is marketed for $15-20/bushel (1971) which is the upper end of the
wholesale price range.
Catfish have been cultured in cages set into the thermal discharge canal
of a fossil-fueled plant (plant No. 4815) located in Texas. During the
winter of 1969-70 growth rates achieved were equivalent to 2250 Kg/hm2-
year (200,000 Ib/acre-year). This is comparable to the yields of
rainbow trout culture in moving water. The Texas operation is now on a
commercial basis.
TVA also operates a small-scale catfish raising facility at its waste
heat complex. Results from the first year's operation confirmed that
the growth rate of the catfish was significantly enhanced by the
addition of the heated water and that the growing season was
significantly lengthened. However, several problems prevented expansion
to a commercial scale operation. Feed loss and mortality rates were
high. Water quality studies showed that high intensity production of
catfish generated substantial quantities of waste material and that the
equivalent of secondary treatment would be necessary before the
facilities could be expanded.
The major weaknesses of low-grade heat utilization are the following:
1. Inability to utilize large quantities of total waste heat available.
This is due not only to the capital requirement but also to the fact
that the product is produced in such quantities that it may exceed
market demand.
2. Uses are seasonal which require either the dumping of waste heat in
the off season or the building of a cooling tower in addition to the
waste heat utilization systems.
3. Inability to provide needed heat when plant is shut down and
unadaptability of the cultured organisms to rapid temperature change.
310
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Utilization of Extraction steam
Extraction steam utilization increases both the number and the size of
the potential heat users. Table B-VII-2 following shows the total
annual energy demand by several types of heat using processes in the
United States. The table is taken from Reference 24.
The most notable extraction steam heating system is located in downtown
Manhattan, in which approximately 300 MW of heat is supplied from
extraction and back pressure turbines. This system has been in
operation for many years. District heating systems of this type are
expected to increase in usage in those places where it can be marketed
successfully for operation of large tonnage air conditioning loads.
Extraction steam heat utilization is also used to supply industrial
'process steam. The classic case of extraction steam utilization for
industrial process steam takes place at powerplant No. 3414 located in
the Northeast. This plant supplies the bulk of the process steam to an
adjacent oil refinery. The plant was designed with this capability in
mind. The alternate utilization scheme increases the efficiency of the
generation cycle from 34X to 54%. This is equivalent to reducing the
waste heat rejected to the environment by 25%.
Another form of extraction steam utilization is the use of steam to
desalt saline or sea water. This type of use is common in arid
locations and also in many of the small islands in the Carribean.
Unfortunately, the quantities of heat consumed by water desalting
processes are relatively small. The largest water desalting plant in
operation today has a capacity of only 5.0 million gallons of water per
day. This would require much less than IX of the waste heat from a new
ilOOO MW nuclear plant.
The major disadvantage of extraction steam methods is the necessity of
combining the plant and the adjacent steam utilizing process to
• determine the overall performance of the system. In addition, it is
difficult to balance the often variable steam requirements with the
power production process.
Total Energy Systems
The total energy concept seeks to overcome some of the obvious
shortcomings of the Icw-grade and extraction steam utilization concepts
by aggregation of all energy consuming interests in a well defined area.
Most total energy systems in the United States are relatively small,
consisting of individual shopping centers, educational complexes and in-
dustrial complexes. The total energy concept is practiced more
intensively in Europe.
311
-------
U)
M
NJ
Table B-VII-2
ENERGY DEMAND BY HEAT USING APPLICATIONS (1970)
24
Application
Electricity
Space Heat
Domestic Hot Water
Industrial Steam
Supply Temperature, F
-
200
200
300-400
Energy Used, trillion Btu
4,000
6,000
1,000
5,000
-------
A major study conducted by the Oak Ridge National Laboratory, Reference
No. 350, tested the economic feasibility of a large energy system
serving a hypothetical new town of 389,000 people. The climate of the
new town was similar to that of Philadelphia, Pa. The system provided
in addition to electricity, heat for space heating, hot water, and air
conditioning for the commercial buildings and portions of the apartment
buildings. Heat was also available for manufacturing processes and
desalting of sewage plant effluent for reuse. The study concluded that
it would be possible in the 1975-1980 period and beyond to supply low
cost thermal energy from steam electric powerplants to new cities, espe-
cially those in the population range of 200,000 to 400,000. With
respect to climate, the cities could be located anywhere in the
continental United States except perhaps in the most southern portions.
The use of thermal energy extracted for the turbines of the generating
plants would be economically attractive. For example, in one
configuration of a 1980 city with a population of 389,000 people and a
climate similar to that of Philadelphia, Pennsylvania, the cost of heat
for space heating and domestic hot water was estimated to be
approximately $1.98/MBTU. '«s This system was considered to be
competitive in that its use would result in an approximately equal cost
compared with other systems. It is anticipated that interest in total
energy systems will increase as the rapidly increasing cost of fuel will
require corresponding increases in the efficiency of fuel consumption.
Cooling Water Treatment
General
Steam electric powerplants employ four types of circulating water
systems to reject tfce waste heat represented by the difference between
the energy released by the fuel and the electric energy produced by the
generators. These systems are the once-through system, once-through
with supplemental cooling of the discharge, closed systems, and
combinations of the three systems. In a once-through system, the entire
waste heat is discharged to the receiving body of water. The
applicability of this system is dependent on the availability of an
adequate supply of water to carry off the waste heat and the ability of
the receiving body of water to absorb the' energy. There is no reduction
of total waste heat energy being discharged by the plant in a once-
through system.
A once-through system with supplemental cooling removes a portion of
heat energy discharged by the plant from the plant effluent and
transfers this energy directly to the atmosphere. Various devices are
used to achieve this transfer. A long discharge canal could be a
cooling device. If a sufficient surface area is not available, the rate
of evaporation per unit area may be increased by installing sprays in
the discharge canal. If sprays do not provide sufficient evaporative
capacity, cooling towers may be utilized in the supplemental cooling
313
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mode. The amount of heat that can be removed from the circulating water
discharge is a function of atmosphere conditions and the type and size
of the cooling device provided.
Recirculating cooling water systems provide a certain type of design and
operational flexibility leading to lower costs that is not available
with helper systems. The costs of cooling devices are related to their
size. The use of higher cooling water temperatures allows for the use
of smaller, less costly cooling devices to transfer the same amount of
waste heat to the environment. The recirculation to the condensers of
all, or a part, of the cooling water leaving a cooling device (if its
temperature exceeds intake cooling water temperature) would elevate all
temperatures in the system. The result would be that, for a fixed
system, more waste heat would be transferred to the atmosphere, or, for
a fixed waste heat load, a smaller and less costly cooling device could
be used. In any case, the added or reduced costs due to changes in the
energy conversion efficiency brought about by the changed recirculation
temperatures would become significant in relation to the extent of the
temperature changes involved. A further cost savings of recirculating
cooling water systems would be attributable to the small intake and
discharge structures.
A further characteristic of helper systems is that they are designed
primarily to reduce the temperature of the water discharged and not the
amount of heat discharged. When recirculation of a portion or all of
the cooling water is practiced, the temperature of the discharged water
is actually increased (compared to operating in the helper mode) but the
effluent heat is reduced (compared to the helper mode) because of the
reduction in discharge volume.
Closed circulating water systems are currently in common use in the
industry, although in the past the reason for employing closed systems
has seldom been the elimination of thermal effects, but rather the lack
of a source of water supply adequate for a nonrecirculating system.
The following section describes each of these systems in further detail.
Once-through (Nonrecirculating) Systems
These are defined as those systems in which the water is removed from
the water source, pumped through the condenser in one or m,ore passes to
pick up the rejected heat, and then returned to the water source. These
systems are arranged so that the warm water discharged to the receiving
body of water does net recirculate directly to the intake point. Once-
through systems have teen the most prevalent in the United States to
date. In general, other systems have been used only when sufficient
water for once-through operation has not been available. The trend has
been away from the use of once-through systems. Only about one-half of
all new units are committed to once-through systems, whereas about 80fl
of all existing systems are once-through.
314
-------
The basic design of the once-through, or open, system is shown in Figure
B-VII-17. The purpose of the intake structure has generally been to
prevent trash, fish, grass and other materials from entering the
condenser and either plugging or damaging the condenser tubes, resulting
in decreased performance or shut down of the unit for repair of
condenser tubes. In some cases skimmer walls are used to insure drawing
cooling water from deep in the supply source, where the water is colder.
The pumps required to circulate the water through the condenser are
normally located at the intake structure. Normally there are several
pumps for each unit, due to the large flows involved and due to the
requirement of providing a higher degree of flexibility and safety in
the operation of the cooling water system. Flows for a single unit can
exceed 30 m3/sec (500,000 gpm), and some of the large stations require
over 60 m3/sec (1,000,000 gpm). The total annual use of cooling water
by steam electric powerplants is an amount equivalent to about 15% of
the total flow of all rivers and streams in the U.S. The cooling water
flow rates in some plants is comparable to the flow rates of some
rivers.
The discharge from the condenser can be returned to the source via a
canal or pipe, depending on the local conditions. The discharge
structure serves two purposes. The first is to return the water in such
a manner that damage to the stream bank and bottom in the immediate
vicinity is minimized. The second is to promote the type of thermal
mixing required. On lakes or estuaries where water velocities are low,
considerable separation between the intake and outlet structures is
required to prevent warm water from recirculating directly into the
intake.
When compared to closed systems, the water temperature of the
circulating water in the open system tends to be lower, thereby
sometimes allowing a higher generating efficiency for the plant with the
open system. Plant No. 3713 has one of the best heat rates in the
country, due, in part, to the low inlet water temperature, which does
not exceed 2H°C (75°F), during the summer months. This is discussed in
more detail under closed systems. As a result of the above, the best
plant efficiencies are generally obtained with once-through systems.
Once-through Systems with Supplemental Heat Removal (Helper Systems)
With the development of the larger generating stations, it has been
determined in some cases that the large amount of heat rejected to the
environment by cooling water discharged from these stations could
seriously affect the water environment. Consequently, in those cases,
the utilities have been required to re-evaluate their thermal discharge
systems. One consideration short of recycling condenser cooling water
would be to remove heat from the nonrecirculating system prior tb
discharge to the environment. This would be accomplished by a cooling
device placed in the circuit between the condenser and the discharge
point, as shown in Figure B-VII-18 to divert some heat directly to the
315
-------
Steam
Flow
I
Condenser
Generator
Discharge
Canal or
Piping
Cooling
Water
Pumps
00
Intake
Piping
00
Intake
Structure
General Water Flow
Lake
River
Estuary
Ocean
ONCE THROUGH (OPEN) CIRCULATING WATER SYSTEM
FIGURE B-VII-17
316
-------
Steam
Intake
Piping
Pumping
Station
Intake
Structure
|
Condenser
Generator
Discharge Piping
or Canal
eat
Removal
System
Discharge
1Structure
General Water Flow
Lake
River
Estuary
Ocean
ONCE THROUGH (OPEN) SYSTEM
WITH HELPER COOLING SYSTEM INSTALLED
FIGURE B-VII-18
317
-------
atmosphere. The amount of heat that could be removed by such a device
operating at full capacity would be dependent upon the atmospheric or
climatic conditions, principally wet bulb and dry bulb temperatures, or
even wind velocity, sclar intensity, and cloud cover, depending on the
type of device used.
Since these heat removal systems are also applicable to closed systems,
they will be discussed here in general terms only. The design and
operation of each of the systems is covered in detail under the closed
systems section. Special considerations only are covered in this
section. In general, limiting climatic conditions are such that while a
majority of the heat can be removed, the discharge stream temperature
will always be higher than the receiving water at the discharge point.
The systems considered for this end of pipe, or helper mode of thermal
discharge control are cooling towers, both natural draft and mechanical
draft, and ponds or canals which can contain floating powered spray
modules to augment the natural cooling process. The known installations
tend to be designed for operation in any one of several alternative
modes. For example. Plant No. 2708 (Ref. No. 108dd) employs a
mechanical draft evaporative cooling tower system capable of (a) off-
line, (b) helper, (c) partial recirculating and (d) closed-cycle modes
of operation that is expected to be capable of meeting water quality
standards.
Diagrams of two systems presently in use are shown in Figures B-VII-19
and B-VII-20. The system in Figure B-VII-19 can be operated in both
open and closed modes. The system shewn in Figure B-VTI-20 is much more
complex. Units 1 and 2 were originally once-through. When Unit 3 was
added, a once-through system could not be used due to low water
availability in the summmer.359 In designing the closed cooling tower
system for Unit 3, it was decided to add one additional tower, which
would permit operation of all three units on an almost closed system
during the summer when the temperature of the discharge to the river is
severely limited by environmental protection considerations. The
systems illustrated indicate the degree of flexibility which can be
built into a once-through system by using supplemental heat removal
systems.
The seasonal variability of the performance of a helper system is shown
in Figure B-VII-21. This curve shows the average monthly performance of
a tower located in the East, and designed to remove 10056 of the heat in
September. The circulating water temperature rise was assumed to be
11°C (20°F). With a stream temperature of 27.2°C £81°F), the approach
was 1.5°C (8°F). During the month of March, with a stream temperature
of 5.6°C (42°F) and a wet bulb of 7.8°C (46°F) the same tower removes
only 22.556 of the heat, even though the approach has increased to 6.4°C
318
-------
TEAM
VO
COOLING SYSTEM CAPABLE OF BOTH OPEN
AND CLOSED MODE OPERATION
'(Ref. 108z)
FIGURE B-VII-19
-------
UNDERWATER DAt,
WEIR
OUTLET
RIVER
SKIMMER WALL
PLANT LAYOUT AT PLANT No.
(From Reference 359)
FIGURE B-VII-20
2119
320
-------
-TO TOWER
• FROM
TOWER
\ \
\
\
-."STREAM TEMP.
40
as
p
in
u.
Q
in
is:
ro
CL
<
R
in
(vi
(M
5
a.
In
CO
6*
in
£ E S
cc
LU
CO
Lu
LU
to
8
LJ
CO
O
in
cvi
cc
Lu
CO
2:
LU
O
in
is:
CO
o:
iu
CO
Lu
In
SEASONAL VARIATION OF "HELPER" COOLING TOWER
(From Reference 74)
FIGURE B-VII-21
321
-------
This decrease is due to the variation in relationship between stream
temperature and wet bulb temperature. In the summer the stream
temperature is well above the wet bulb temperature. In winter, in this
location, the stream temperature drops below the vet bulb temperature.
In addition, tower performance is lower at the lower winter
temperatures.
This obviously poses a problem in the design of towers for "helper" use,
In the case shown, a tower designed tc remove 100X of effluent heat
under the worst winter condition (March) would be over-sized by a factor
of U during most of the summer.
There is a relatively simple solution to this dilema, and that is to
partially close the system during the winter months. Part of the warm
circulating water would be recirculated into the intake stream,
increasing its temperature. This would increase the discharge
temperature, and consequently the water temperatures in the tower. This
in turn would increase the difference between the water and the wet bulb
temperature and increase the amount of heat removed. The water not
recirculated would be discharged. A problem then arises in that the
water discharged would have a temperature significantly above the stream
temperature. This temperature might not meet applicable stream
standards, which would mean operation of the tower in two modes: open in
summer and closed in winter. The tower would be designed to handle the
heat load under the more difficult of the two operating conditions.
All evaporative type cooling systems would have this degrease in heat
removal performance during winter months when operated in the "helper"
mode.
One other system should be mentioned in this section. This is the
dilution system to liirit the temperature effect of the discharge on the
water to which it is discharged. In this method an excess of water,
above the quantity required in the condenser is pumped through the
intake system, with the excess being mixed with the hot condenser
effluent prior to discharge into the receiving water. While this
dilution reduces the combined discharge water temperature, the amount of
total heat discharged to the water is slightly greater due to the added
generation (and heat rejection) required to power the dilution pumps.
Closed or Recirculating Systems
Closed systems recirculate water first through the condenser for heat
removal, and then through a cooling device where this heat is released
to the atmosphere, and finally back to the condenser. Three basic
methods of heat rejection are used. The one of most commercial
significance in the power industry is wet, or evaporative cooling using
cooling towers, or spray augmented ponds. Evaporation at 5 x 105 J/kg
(1,000 BTU/lb) is the principal means of heat transfer. There is also
some sensible heat transfer. A second method of closed system cooling
322
-------
commonly employed is the use of cooling lakes, which are similar in
principal to open, cnce-through systems, but which are closed inasmuch
as no thermal discharge occurs beyond the confines of the lake. Dry
cooling towers, in which heat is transferred by conduction and
convection, have found very limited use.
The following subsections describe the available technology for
achieving waste heat removal in closed or recirculation cooling systems.
1. cooling ponds or lakes
2. Spray augmented ponds
3. Canals with powered spray modules
4. Rotating 'spray system
5. Wet tower, natural draft - crossflow
6. Wet tower, natural draft - counterflow
7. Wet tower, mechanical forced draft
8. Wet tower, mechanical induced- draft, crossflow
9. Wet tower, mechanical induced draft, counterflow
10. Dry tower, direct
11. Dry tower, indirect
12. Combined wet-dry mechanical draft tower
Cooling Ponds
Cooling ponds are normally artificial lakes constructed for the purpose
of rejecting the waste heat from a powerplant. A secondary purpose for
which the pond is utilized is the storage of water for plant operation
during periods of low natural availability of water. This dual usage
makes cooling ponds economical in the more arid areas of the country.
There are also a significant number of cooling ponds in use in the
southern part of the United States. While cooling towers could be used
to provide cooling in conjunction with a storage pond, the consumptive
use of water in the cooling tower, plus the losses from the water
storage pond, is generally greater than the losses from a dual purpose
pond.
Two distinct types of ponds can be identified, based on the legal means
in which discharge is defined. The first is a pond located where there
323
-------
is little or no natural drainage, or where the water rights on the
watershed belong solely to the utility company, and there is no thermal
discharge from the pond. In this case, the cooling pond is considered
to be completely under the control of the utility company, and the pond
is operated solely to give the best plant performance. The cooling pond
at plant No. 3514 is an example of this type. While the pond itself may
not come under thermal discharge regulations, any chemical discharges
(blowdown) from the pcnd will. In addition, any other effects of the
cooling lake on the environment would also have to be taken into
account.
The second case is where the pond is constructed on a watershed having
significant runoff, and where the utility does not own the pond and the
total water rights on the watershed. In this case, the pond is legally
considered to be external to the plant, and control of the thermal
discharge is subject to state and federal regulations. Plant No. 3713
in North Carolina is an example of this type.
Cooling ponds are normally formed by construction of a dam at a suitable
location in a natural watershed. Soil under the pond must be relatively
impervious to avoid excessive loss of water. Ponds may be constructed
by excavation, but generally the cost would be much higher than for a
dammed watershed. The size of the pond is primarily related to the
plant generating capacity, and rough approximations of 4000-8000 m2 (1
to 2 acres) per MW, are found in the literature. At 81 hm2 (2 acres)
per MW, the pond for a 1,000 MW plant would be 81,000 hm* (2,000 acres)
in size. Thus, the pond size for such a plant would normally be large
enough to serve as a recreational site in addition to its primary
function.
When a watershed is dammed to form a cooling pond, the shape is
determined by the topography of the area. The station intake and
discharge structures are placed on the cooling pond so that maximum use
is derived from the pond, i.e. widely separated, if no^. at opposite
ends of the pond. With excavated ponds, the shape is not totally
limited by the topography. One station currently uses a pond with a
dike separating the intake and outfall structures, and extending almost
across the lake to prcvide a U-shaped pond. Another station, plant No.
1209, utilizes a series of canals as a "cooling pond" as shown in Figure
B-VII-22. The land is flat, and the dikes between the canals provide a
convenient place to pile the material dredged from the canal.
Considerable research on thermal aspects of cooling ponds has been
undertaken. Likewise seme of the research on the discharge of condenser
water into lakes and rivers may be applicable. References (32), (84),
and (120) are part of a series of five reports dealing with cooling
ponds, and a more comprehensive study is described in Reference 246.
The performance of a cooling pond is dependent to a large extent on its
physical features, as indicated below.
324
-------
COOLING CANAL
PLANT NO. 1209
Figure B-VII-22
325
-------
1. Ponds have been arbitrarily categorized in a number of
ways, such as shallow or deepr stratified or non-stratified,
and plug flow or completely mixed ponds. In terms of the
above, the ideal pond is a deep, stratified pond in which
the hot water flows through the pond on the pond surface
with no longitudinal mixing, and the cool water is removed
from a deep portion of the lake.
2. The configuration of the discharge structure for discharg-
ing the hot water from the plant, particularly in the case
of shallow ponds, greatly affects pond performance. The
discharge structure should be designed to spread the hot
water in a thin layer over the lake surface thus prevent-
ing mixing with the cooler subsurface water, and sustain-
ing a high pond surface temperature to promote rapid heat
transfer to the atmosphere. The suitability of the dis-
charge structure is sometimes evaluated in terms of the
Froude No., a ratio of the fluid momentum forces to the
fluid gravitational forces and which relates the veloci-
ty of discharge to a characteristic length of the struc-
ture, normally the width of the channel.
Froude No. = V^/Lg
where V = Velocity of discharge, m/s (ft/sec)
L = Width of discharge channel, m (ft)
g = Gravitational constant, 9.82 m/secz (32.2 ft/
sec2)
Discharge structures are generally considered adequate
for use in relation to cooling ponds when the Froude
No. is less than 1.0.
3. The intake structure is normally located well beneath
the pond surface, if not at the bottom. Its position
in relation to the discharge structure is important.
Currents within the pond, particularly wind currents,
must be considered in placing the structure to get the
best performance out of the pond.
U. The pond shape has some effect on performance. The
extent of the effect is dependent on the degree to
which density currents exist within the pond. For
those ponds with strong density currents, the pond
shape is usually insignificant.
5. The temperature of the discharge into the pond sets
the driving forces for loss of heat to the atmosphere.
326
-------
Other important considerations include climatic factors,
particularly wind speed, gross solar radiation, dewpoint
temperature, and other factors which affect the equilib-
rium temperature of the pond. The pond size required
for a particular plant depends on the climatic condi-
tions in the immediate vicinity of the pond. Pond design is usually
based on conditions which approach the most unfavorable
conditions expected. The more accurate, reliable, and extensive
the available data is, the more confidence can be placed
in a design based on these data. The importance of the
climatic factors outlined above is demonstrated in the
following equations which describe the relationships
among the principal factors involved in sizing a cooling
pond. At steady state conditions, the net heat loss
from the pond is equal to the waste heat from the power-
plant. The steady net heat loss from the lake surface
is normally expressed as:
Heat loss = KA (Ts -TE)
where K = Heat Exchange Coefficient, J/m2-day-°C
(BTU/ftz-day-°F)
A = Area of Lake, m« (ft«)
Ts = Average Surface Temperature, °C (°F)
TE = Equilibrium Temperature, °C (°F)
The equilibrium temperature (TE) can be estimated by
the following equation: ~"
TE = Td •»• HS/K
where Td = Dewpoint Temperature, °C (°F)
Hs = Gross Solar Radiation, J/mz-day (BTU/ft2-day)
K = Heat Exchange Coefficient, J/m2-day-°C
(BTU/ft2-day-°F)
The heat exchange coefficient (K) is closely related to
windspeed as shown in Figure B-VII-23, which permits
determination of K in terms of windspeed and the temper-
ature T = Td + Ts where an initiate value of Ts must be
2
assumed.
The estimation of the average pond surface temperature is an
important part of the analysis. Parameters necessary for this
327
-------
en
EH
+
B
oo
-P
m
^
0)
I
35
30
25
20
15
10
12 345 6
Windspeed (m/s)
CHART FOR ESTIMATING COOLING POND SURFACE HEAT EXCHANGE COEFFICIENT
(From Reference 32)
FIGURE B-VII-23
-------
determination are the expected temperature rise and circulating
water flow rate. The degree of mixing in the pond must be
estimated. Where there is little mixing (slug flow) , the
temperature decrease occurs during the entire transit of the pond by
a typical slug of circulating water. The other extreme is where
complete mixing occurs, and the temperature throughout the pond is
the same. The actual degree of mixing in any particular case would
lie between these two extremes.
The first step in the procedure for estimating the average pond surface
temperature is to determine the discharge temperature to the cooling
pond. This is done by first determining the quantity:
KA
where K = Heat exchange coefficient estimated from Figure
B-VII-23, J/m2-day-°C (BTU/ft2-day~°F)
A = Assumed pond area, m2 (ft2)
p = Density water, kg/m3 (lb/ft3)
cp = Heat capacity, J/kg-°C (BTU/lb-°F)
Qg = Condenser flow, m3/day (ft3/day)
Figure B-VII-24 can be used to determine the approximate area A. With
the condenser rise, from Figure B-VII-25, 0 (excess of discharge
temperature, Tj>, over the equilibrium temperature, TE) is determined.
Note that curves for slug flow and complete mixing are given. Then the
discharge temperature, Tg, and the inlet temperature, Tc, can be deter*
mined.
Tp = TE + 6r
Tc = T|> - Condenser rise
From Figure B-VII-26, using 9 and KA/pcQ£, 6 average is determined,
since 9 is Ts - TE, Ts is determined. This value of Ts will normally
not correspond to the assumed value used to determine K. The correct
value is then determined by iteration, i.e., new values for Ts are
assumed and the process repeated until the two values of Ts agree to the
degree of accuracy desired.
Once Ts has been estimated, the pond area can be determined from Figure
B-VIl-24, which determines the area required for each million kJ
(million BTU) of heat to be rejected. If the cost per acre of pond
329
-------
3.0
2.5
2.0
1.5
1.0
0.5
T = Surface Temperature ( C)
s
T = Equilibrium Temperature ( c)
0
"180 200 220 240 260 280 300 320 340 360 .380 400
2 o
Heat Exchange Coefficient, k, J/m - C-day
COOLING POND SURFACE AREA VERSUS HEAT EXCHANGE COEFFICIENT
FIGURE B-VII-24
3-3 ft-
-------
35
30
o
-------
U
-------
surface is known, the cost per million kJ (million BTU) of heat rejected
can be determined from Figure B-VII-27.
Costs for cooling ponds are very dependent on local terrain. In
general, costs would include the following:
I. Preliminary
1. Soil surveys
2. Topographical mapping
II. Construction
1. Dam or basin
2. Discharge structure
3. Intake structure
4. Canals or pipelines associated with 2 and 3
5. Make'up water system (pipelines, canals, pumps, etc.),
if required.
6. Auxiliary equipment for above, roads, fencing, etc.
III. Maintenance
1. Canal, pipeline maintenance
2. Intake and discharge structures
Spray Ponds
Spray systems can te utilized to reduce the large area required by
cooling ponds by up tc a factor of ten. Two types of spray systems are
available. In a fixed system, which essentially operates in a once-
through mode, the hot water is pumped through a grid of piping, into
which nozzles have been placed at regular intervals. The water is
sprayed out, and cools by evaporation and sensible heat transfer to the
air as it falls tc the pond below. Water from the pond is pumped
directly to the condenser. To obtain adequate cooling on this once-
through basis, the spray must be fine. This factor, coupled with wind
factors, can lead to large drift losses and associated problems in the
vicinity of the pond. The relatively high pumping losses and lengthy
piping required for such a fixed system would make this type of design
relatively costly for a medium-sized power station.
The second type of spray pond is commonly called a spray canal due to
its flow-through hydraulics and shape which makes full use of prevailing
winds to enhance cooling performance. The spray is produced by modules
moored at intervals in the canal and floating on the water surface. Two
types currently in use are illustrated in Figures B-VII-28 and B-VII-29.
The module in Figure B-VII-28 is a unitized pump and spray module. The
module in Figure B-VII-29 has a central pump supplying four nozzles.
Both units are powered by 56,000 watt (75 HP) motors and spray 0.631
mVsec to 0-789 m3/sec (10,000 to 12,500 gpm). Two characteristics
333
-------
3.0 L
Cost per Hectometer of Pond Surface
X
re
-------
u>
u>
en
UNITIZED SPRAY MODULE
(From Reference 365)
FIGURE B-VII-28
-------
U)
U)
CTl
!/
i/
if
f
—•wsw"'
FOUR SPRAY MODULE
(From Reference 366)
FIGURE B-VII-29
-------
of this system are important. The first is that each slug of water can
be sprayed in repetitive steps, thus minimizing the need for small
droplets required by the fixed system. The droplet size can be larger,
reducing the drift problem. Secondly, not all the water need be
sprayed, but enough to provide the required cooling. This permits
adjustment of the number of modules operating to the climatic conditions
and generating level cf the plant.
The use of these modules in the utility industry is relatively new,
although tests have been underway for some years. . Plant No. 3304 and
Plant No. 5105 are using, or are installing powered spray modules. The
largest installation in use is at Plant No. 0610. The canal of plant
no. 0610 is U-shaped as shown in Figure B-VII-30. The intake and
discharge structures are at the same end of the pond. The power and
control systems for the modules are located on the central dike. Figure
B-VII-31 shows the modules in operation. The diameter of the spray
pattern is about 15 meters (50 feet) .
Plant No. 1723 is installing a large number of each design. Spray
modules are being used primarily for helper systems on existing plants
when additional units are added to a plant.
The design of the cooling canal is more complex than that of a cooling
tower, and computer programs are often used. To make the best use of
climatic conditions, these systems are designed as canals where all the
modules are exposed insofar as possible to the ambient air conditions,
reducing adverse interference of performance due to proximity to other
modules. The canals can be circular in shape, or straight, as required.
The canals should be aligned perpendicular to the prevailing winds for
maximum ambient air exposure, and therefore maximum module efficiency.
Design of the system involves determining the incremental contribution
to cooling of each set of modules in series. The first module^ inlet
temperature is the condenser discharge temperature. The cooled spray
from the first module remixes with the water in the canal, and the
resulting temperature of the canal is the temperature at the inlet to
the second set of modules. This procedure is continued until the
desired temperature is reached, or the increase in overall performance
with additional modules is not cost effective. Using some general data
on one manufacturer's units. Figure B-VTI-32 was developed to give a
pictorial representation of the process. The initial temperature is the
inlet temperature to the first set of modules (condenser discharge tem-
perature) . The wet bulb temperature is then used to determine the ex-
pected temperature decrease of the sprayed water. From the percentage
of water sprayed, the change in canal temperature can be determined, and
this translated into a new exit temperature from the modules. This then
becomes the initial temperature for the second set of modules. The
number of modules in parallel at any point in the canal can also be
optimized.
337
-------
SPRAY CANAL
PLANT NO. 0610
Figure B-VII-30
338
-------
SPRAY MODULES
PLANT NO. 0610
Figure B-VII-31
339
-------
100 90 80 70 60 50 40 30 20 10 8 -
Initial Temperature
GRAPHIC REPRESENTATION OF DESIGN OF SPRAY AUGMENTED COOLING POND
Figure B—VII—32
Wet Bulb Temp.
17.8°C
Initial Temperature ( C)
-------
The retrofit installation at plant no. 1723 is representative. The two
generating units at the plant are rated at 809 MW each. The cooling
canal will encircle the plant and will be 4.1 km (2.5 miles) long. The
canal will contain 176 units from one manufacturer, and 152 units from
another manufacturer. The number of modules, or blocks of them
operating at any one time will be adjusted to give the amount of cooling
required. The installed power for the 328 units is 18,300 KW (24,600
HP). At 90% efficiency, this amounts to 20.4 megawatts, or 1.26% of the
plant's previous output using once-through cooling. Since higher
cooling water temperatures are expected, thereby reducing the plants
gross generating capacity, the combined reduction in plant generating
capacity will be greater than 1.26X.
For the past several years, another manufacturer has been- testing a
rotating disc design for producing sprays. Their current design is
shown in Figure B-VII-33, This design is currently undergoing field
evaluation at a station in the United States. A cross section of a
proposed installation is shown in Figure B-VII-34. The spray droplets
produced by these rotating discs are about 1 nun in size. As with the
fixed spray systems, this size is required to get adequate cooling
performance. With this size drop, drift is a problem, and adequate
provision to minimize drift losses must be made.
Insufficient data has been published to make reliable performance or
cost estimates. From some of the limited performance data the curves in
Figures B-VII-35 and B-VII-36 were developed.
Wet Type Cooling Towers
A number of different types of evaporative cooling towers have been, and
are currently, in use. The basic types are as follows:
Natural Draft
Mechanical Draft: (Hyperbolic): Dry Type:
Counterflow-Induced Draft Counterflow Direct
Crossflow-Induced Draft Crossflow Indirect
Counterflow-Forced Draft Counterflow-
Crossflow-Forced Draft Fan Assisted
Wet-Dry—Any Of the above
The terms crossflow and counterflow refer to the relationship between
the air flow and the water flow. In counterflow, the water flows
downward through the packing and the air flows upward (Figure B-VII-37).
In crossflow, the water still flows downward, but the air flows
horizontally (or perpendicularly to the water) from outside to inside as
shown in Figure B.-VII-38. Induced draft refers to the means for
developing the air flew by a fan mounted on top of the tower which pulls
the air through the tower (Figures B-VII-37 and B-VII-38) . In the
older, and little used today, forced draft system fans are mounted
341
-------
U)
£>
NJ
THERMAL ROTOR SYSTEM
FIGURE B-Vn-33
(From Reference -389)
-------
1
1
1
t-^-r' """'"•
L
COOLED WATER CHANNEL
f nt^p t,,, ,,Trt,im j^i .^(i.. ., ~*f \..\ ,...n. ,.
HOT WATER
SPRAY
ji A
r V
<^F?
**rr
Hl1 i|
O
o
•
V
il
"1
^-i-
P-T
r
9JTIMLET PIPE -/
PLAN
r
t
A
./a 4-*
j
&
HOT WATER CHANNEL
f
1
i^ROTORS
COOLED WATER ^HOT WATER
SECTION THRU ROTORS
X A
tr tr
70'
(-
SERVICE
ROAD
SECTION THRU CHANNELS
-POLYVINYL CHLORIDE LINER
"'
HOT WATER
DOUBLE SPRAY FIXED THERMAL ROTOR
(From Reference 360)
FIGURE B-VII-34
-------
Range
•P
c
0) !-3
8*
*s
H O
(0 H
-P \
•H )-
A —
(0
U
1000
900
800
700
600
500
fOO
300
200
100
16
I
.4
.8 1.0 1.2 1.4 1.6
3 3
Water Flor per Disc (m /s x 10 )
1.8
GRAPHIC REPRESENTATION OF PRELIMINARY COST DATA
ON ROTATING DISC DEVICE
FIGURE B-VII-35
344
-------
1.6
1.4
1.2
-------
t AIR f
I OUTLET j
WATER
COUNTERFLOW MECHANrCAL DRAFl' TOWER
FIGURE B-VII-37
CROSSFLOW MECHANICAL DRAFT TCWER
FIGURE B-VII-38
346
-------
around the periphery of the tower at ground level and force the air
upward through the tower.
Drift eliminators, common to all towers except the dry-type, are used to
remove most of the entrained water droplets from the air stream prior to
its leaving the tower.
The wet-dry tower is a relatively new development. It consists of an
upper section of dry tower emitting warm air heated solely by
conduction, and a lower wet section emitting the nearly saturated air
which has a high fogging potential. These two air streams are mixed in
the tower, significantly reducing the fogging potential.
Natural draft towers are commonly known as hyperbolic towers, since the
chimneys are hyperbolic in shape to take advantage, of the excellent
stress characteristics of this shape. The chimneys are normally
constructed of reinforced concrete. A crossflow tower is shown in
Figure B-VII-39. The tower shown in Figure B-VII-40, takes up less land
space than the crossflow tower. The chimneys on these towers are tall,
ranging from 90 to over 150 m (300 to over 500 feet) . The tower height
has the advantage that the plume is emitted high enough above the ground
that if fog develops, it will normally not create a ground level hazard.
A recent modification to the natural draft tower is the fan-assisted
hyperbolic. In this design, fans are placed at the periphery of the
tower, along the bottom to force the air through the tower. The
required tower height is diminished, since air flow does not depend
solely on the difference in air density inside and outside the tower as
in the unassisted tower. Several of these fan-assisted towers are in
use in Europe, and have been proposed for use in specific cases in this
country.
The dry-type cooling towers rely solely upon conductive and convective
heat transfer for their cooling effect. Two types of systems are used.
In the "direct" system, the steam condenses directly in the tubes of the
heat exchanger in the tower. This type is restricted to relatively
small plants due to the size of the steam piping required to circulate
the relatively low density steam. In the "indirect" sytem, cold water
from the tower is used to condense the steam from the turbine and the
warmed water is circulated through the tower. Since the system is
completely closed, a direct contact condenser can be used, greatly
reducing the condenser terminal temperature difference (TTD). with the
direct contact condenser, the circulating water must be of the same
quality as the boiler makeup water, however direct contact condensers
are less expensive than shell and tube condensers. The air system for
the tower may be either induced, forced, or natural draft.
347
-------
t *'" t
I OUTLET |
WATER OUTLET
CROSSFLOW NATURAL DRAFT TOWER
FIGURE B-VII-39
DRIFT / HOT-WATER
ELIMINATOR / DISTRIBUTION
FILL
AIR
INLET
COLD-WATER BASIN
COUNTERFLOW NATURAL-DRAFT COOLING TOWER
FIGURE B-VI1-40
348
-------
Wet Mechanical Draft Towers
The wet tower cools the water by bringing it into contact with
unsaturated air and allowing evaporation to occur. Heat is removed from
the water as latent heat required to evaporate part of the water.
Approximately 75X of the total heat transferred is by evaporation, the
remainder by sensible heat transfer to the air. (6)
In addition to the thermodynamic potentials, several other factors
influence the actual rate of heat transfer, and ultimately, the
temperatrue range of the tower. A large water surface area promotes
evaporation, and sensible heat transfer rates are proportional to the
water surface area provided. Packing (an internal lattice work) is
often used to produce srrall droplets of water and thus increasing the
total surface area per unit of throughput. For a given water flow,
increasing the air flew increases the amount of heat removed by
maintaining higher thermodynamic potentials. The packing height in the
tower should be high enough so that the air leaving the tower is close
to saturation.
The mechanical draft tower consists of the following essential
functional components:
1. Inlet (hot) water distribution
2. Packing (film)
3. Air moving fans
4. Inlet-air louvers
5. Drift or carry over eliminators
6. Cooled water storage basin
Although the principal construction material in mechanical draft towers
is wood, other materials are used extensively. In the interest of long
life and minimum maintance, wood is generally pressure treated with a
water-borne preservative. Although the tower structure is still
generally treated redwood, a reasonable amount of treated fir has been
used in this and other portions of the tower in recent years. Sheathing
and louvers are generally of asbestos cement, and fan stacks of fiber
glass. The trend in fill is to fire-resistant extruded PVC which, at
little or no increase in cost, offers the advantage of unlimited life to
its fire-resistant properties. Some asbestos cement is also used for
fill. Even the*trend in drift eliminators is away from wood to either
PVC or asbestos cement.
Two problems arise from the use of wood: decay, and its susceptibility
to fire. On multi-celled towers, the cost of fire prevention system can
run into several hundred thousand dollars or more. Constant exposure to
349
-------
water results in leaching of the lignin from the wood, reducing its
strength. Steel construction is occasionally used, but not extensively,
if at all, for units in the powerplant industry.
Concrete construction, never popular because of relatively high labor
costs, is actively being considered for large units of the type used in
steam electric generating stations. The savings in fire protection
costs and extended life make this alternative attractive in many cases.
Inlet water distribution systems are operated at low pressure and wood
stave pipe, plastic and metallic pipe have been used. The blades on the
fans must be reasonably lightweight, and corrosion resistant. Both cast
aluminum and GRP (glass reinforced plastic) , are generally used today.
For large towers mounted on .the ground, concrete cooled-water storage
basins are used almcst exclusively.' For other applications, both wood
and sheet metal basins have been used.
Wet Mechanical Draft Tower - Induced Draft - Crossflow
Currently one of the most widely used wet mechanical draft towers in the
larger sizes is the induced draft crossflow tower illustrated in Figure
B-VII-38. Primary advantages for this tower are6:
1. Lower pumping head as a result of lower packing.
2. Lower pressure drop .through the packing.
3. Higher water leadings for a given height.
4. Lesser overall tower height.
Compared to the counterflow tower, crossflow towers have the following
di sadvantages 6:
1. A substantial correction factor must be applied to the
driving force to take into account the reduced thermo-
dynamic potentials in parts of the fill. This is par-
ticularly true at wide ranges and close approaches.
More ground area and more fan horsepower may be required
in some cases.
2. The packing is not as efficient, and more air flow is
required for an equivalent capacity tower.
Despite these disadvantages, the crossflow tower is widely used. With
proper louver design, ice buildup is minimal. The design is much more
versatile, with a tower available to meet almost every need.
350
-------
Sizing and costing of mechanical draft towers are dependent on climatic
or operating conditions. Basic parameters controlling size and cost
include:
1. Climatic conditions, particularly wet bulb temperatures
during the summer months.
2. Heat load from the powerplant.
3. cooling water flow rate (or temperature range).
4. Approach temperature.
Two of the major cooling tower manufacturers use proprietary factors for
estimating the cost of cooling towers. Wet bulb temperature, approach
temperature ^nd cooling tower range are used to determine the factor.
Then, the factor and the circulating water flow are used to determine
the tower cost. Tables illustrating use of the factor by one of the
manufacturers are shown in Figure B-VTI-41. The"rating factor obtained
from these curves is inserted into the following
equation:
Tower Units = Rating Factor x Cooling Flow (gpm)
A set of simple calculations then provides Figure B-VII-U2; where
cost/106 BTU is shown as a function of Rating Factor and cooling tower
range. The cost factor used was $8.11 for the cost of a tower unit.
The other manufacturer mentioned uses a slightly different technique.
Using the cooling range, wet bulb temperature, and approach temperature,
a "K" factor is determined. (Figure B-VTI-43). The "K" factor is
multiplied by the cooling water flow rate. Another chart gives a "C"
factor, which multiplied by the flow through the tower gives an
estimated capital ccst. The graph for the "C" factor also has curves
for determining fan horsepower and basin area. A comparison between the
rating factor of Manufacturer A and the K-Factor of Manufacturer B is
shown in Figure B-VII-44. The relationship between the two factors is
essentially linear.
The curves in Figure E-VII-43 take into account a size factor, something
that the other procedure omits. Some costs for various K-Factors and
ranges are shown in Figure B-VII-45.
In addition to water lost by evaporation, a small percentage of the
water is lost as drift, or small droplets carried out of the tower with
the air flow. Drift eliminators are generally used in the tower to
reduce this to a minimum. Current designs reduce these losses to a
small percentage of the throughput. This drift contains salts and
chemicals added to the water for treatment. These droplets fall out in
351
-------
70° WET BULB
40
30
20
/«
• 5 0-6 0-7 0-8 0*9 1-0 1-1 1-2 i-3 1-4 1-5 1-6
RATING FACTOR
TYPICAL CHART FOR DETERMINING RATING FACTOR
(From Reference 74)
Figure B-VII-41
352
-------
3000
250TJ
4
OC
I
\
H2000
04
***"
1500
u.
<
-------
APPROACH.? 678
L
12
K
16
C05T-C X $100,000
BASIN AREA » Cx 100 FT,2
FAN HORSE POWER * C x 100
PUMP HORSFPOWf fl - GPWY
O.OIE ,
^
0.5 1.0 1.5 2.0 2.5 30 35" 4.0
K xGPM x I06
COOLING TOWER PERFORMANCE CURVES
FIGURE B-VII-43
(57)
354
-------
150
140
130
120
110
100
90
80
H
0
•P
8 70
-------
O
.H
\
M-l
0
CO
O
u
a
1400
1300
1200
1100
1000
900
800
700
600
500
400
ft 300
nj
O
200
100
K=70
16.7°C
K=50
Range l6.7°f
Range 5.s°c
K=5° Range 5.50C
^ JIJ Kane '^u
K=3° Range 5.5°n
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
Water Flow Through Tower (m /s)
GRAPH SHOWING VARIATION OF COST OF MECHANICAL DRAFT COOLING TOWERS
WITH WATER FLOW (from Reference 57)
FIGURE B-VII-45
356
-------
the surrounding area and could result in problems of corrosion to
equipment or damage to plants and trees.
In addition to losses from drift, a certain amount of the water is
intentionally removed from the system as blowdown to control the
concentration of salts and chemical additives in the cooling water. The
amount of blowdown varies with the quality of the makeup water. The
amount of heat in this blowdown stream is relatively small.
Aside from the appearance of the physical structure, an additional
visual result of usage of cooling towers is the formation of visible
plumes of condensed water vapor under appropriate weather conditions.
These plumes are formed when the temperature of the moisture-laden air
leaving the tower drcps below the dew point. With mechanical draft
cooling towers, these plumes are close to the ground due to the low
tower height, and will drop to the ground under certain wind conditions.
With their tall chimneys, natural draft towers produce plumes at 300-500
feet above the ground. Further discussion of plumes is provided in a
subsequent section of the report.
Wet Mechanical Draft Towers - Induced Draft - Counterflow
This type of tower, pictured in Figure B-VII-37 is only slightly
different from the crossflow type. The air flow is counter to the water
flow. This makes the tower taller than the crossflow tower, because
additional space must be allowed at the bottom of the tower for the air
to enter.
Some advantages of this system are *:
1. The coldest water contacts the driest air. The air, as
it travels up through the water, contacts progressively
warmer water, maintaining the potential for evaporation.
2. The fan forces the air straight up, minimizing air recir-
culation.
3. Larger fans can be used (up to 18.3 meters (60 feet)).
4. Closer approaches and large cooling ranges are possible.
There are a number of disadvantages also *:
1. The small air opening at the bottom of the tower leads
to high pressure drops, and subsequently, higher fan
horsepower requirements.
2. A more sophisticated air distribution system is required
to maintain uniform air flow through the packing.
357
-------
3. Since the top of the packing is higher above the ground,
the required pumping head is higher.
Wet Mechanical Draft Tower - Forced Draft
This tower design, pictured in Figure B-VII-46, is not currently being
used to any extent, particularly in the steam electric utility industry.
Its principal advantages are:
1. Noise levels and vibration are reduced, since fans are
mounted at the base of the tower.
2. Blade erosion is non-existent and condensation in gear
boxes is greatly reduced.
3. Fan units are slightly more efficient than induced draft
type, since development of static pressure in tower per-
mits some recovery of work.
Disadvantages of the forced draft tower 6:
1. Fan size is limited to about 3.6 m (12 ft), necessitating
multiple fan installations.
2. Baffles are necessary for air distribution.
3. Recirculation of the hot, humid discharge air is a prob-
lem, as it can flow back to the low pressure intake.
4. During cold weather, ice may form on the fan blades,
causing damage and reducing air flow.
A modern adaptation of the type of tower is. the fan-assisted natural
draft tower, which is discussed under the section on natural draft
towers.
Wet-Dry Cooling Tower
A fairly recent development in the mechanical draft cooling tower is the
wet-dry system. This design combines the wet and dry tower principles,
as shown in Figure B-VTI-47. The concept was originally developed to
reduce or eliminate the plumes from mechanical draft towers.
The principles of operation are shown in the psychrometric chart in
Figure B-VII-47. The air passing through the dry section is heated
along line 1-3. The air passing through the wet section is heated and
humidified along line 1-2. When the air from these two sections is
mixed in the fan plenum, the condition of the mixture lies along line 2-
3, at some point U. The position of this point is dependent on the
relative amount of the two air streams mixed. The relative size of the
358
-------
MECHANICAL-FORCED DRAFT COOLING
FIGURE B-VII-46
twv section
SUPER HEAT
(Non-Fog) ARIA
SUPER SATURATION
(fog) AREA
DRY BULB TEMPERATURE (°F)
PARALLEL PATH WET DRY COOLING TOWER PSYCHOMETRICS
FIGURE B-VII-47
(From Reference 128)
359
-------
dry section is dependent on the local climatic conditions as related to
the probability of fog formation.
The details of construction of the tower for plume abatement are shown
in Figure B-VII-48. Note the summer damper door used to shut off" most
of the air flow through the dry section during the summer when plume
abatement is not required. This shunts the air flow to the wet section
during the summer when increased cooling is necessary.
While plume reduction itself can be beneficial, the concept of combining
the wet and dry sections opens up possibilities for applications where
water consumption considerations are important. By enlarging the dry
section, as shown in Figure B-VII-49, the principal cooling o'ccurs in
the dry system, with the wet section used only as required. The tower
performance in such a situation is iridicated on the psychrometric chart
in Figure B-VII-49. A contract has been signed for the installation of
four wet-dry towers at plant No. 2416. The towers will cool 172,000 gpm
of brackish water.
Natural Draft Cooling Towers
The natural draft tower, or hyperbolic tower, as it is commonly known,
has the advantage that no mechanical energy is required to circulate the
air through the tower. The tall chimney is used to develop sufficient
driving force between the hot, humid air from the fill and the cooler
air outside the chimney. This force 'difference must overcome the
internal resistance tc air flow.
(pa - pt) g__ X h = Pressure drop through packing +
go tower friction loss + kinetic energy
of air leaving the tower.
where pa = density of air entering the tower
pt = density of humid air in the tower
g = gravitational constant at elevation of tower
go = reference gravitational constant
h = height of tower
Approximately a tenth of the tower height is utilized for the air-water
contact section, the remaining 90% is used solely to develop the
required driving force for adequate air circulation.. A typical
installation, in plant No. 4217, is shown in Figure B-VII-50.
The economical use of natural draft towers is restricted to regions with
moderate temperatures and average humidities. In areas such as the
360
-------
SUB-SATURATED AIR MIXTURE
AIR COOLED
HEAT
EXCHANGERS
HINGED SUMMER
DAMPER DOOR
SUMMER
HOT WATER FLOW ONLY
INLET PIPE
INTERMEDIATE
WATER
EVAPORATIVE
FILL
SECTION ,
COLD WATER
BASIN
PARALLEL-PATH WET DRY COOLING TOWER FOR PLUME ABATEMENT
FIGURE B-VII-48
(From Reference 128)
361
-------
co
en
to
<
Q
tt
o
S
D
X
v
iu
o.
V)
SUPER SATURATION
(Fog) AREA
"T&Y STiHAM
DIMENSIONS INDICATE
RELATIVE FLOW RATE
SUPER HEAT
(Non-Fog) AREA
-WET STREAM MASS FLOW
DRY BULB TEMPERATURE (°F)
COt.0 WATER
PARALLEL-PATH WET DRY COOLING TOWER (ENLARGED DRY SECTION)
FIGURE B-VII-49 (FrOrn
128)
-------
TYPICAL NATURAL DRAFT
COOLING TOWERS
PLANT NO. 4217
Figure B-VII-50
363
-------
Southwest, with high temperatures and low humidities, the potentials for
favorable density differences are decreased, resulting in an
impractically high chimney to provide circulation for the cooling tower.
Climatic conditions in the Southeast and Gulf Coast areas do not favor
natural draft towers because of the high wind design loadings.
One of the benefits of the natural draft tower, and perhaps the reason
it has become so popular, is that the fog plume is released several
hundred feet in the air, and does not create any local hazards due to
fogging. However, care should be taken to assure that the stack gases
and the tower plume do not intermix, as any S
-------
15° RANGE
10096 RH APPROACHES
01234
TOWER COST - DOLLARS PER THOUSAND BTU/HR.
25° RANGE
10096 RH
APPROACHES
0123
TOWER COST - DOLLARS PER THOUSAND BTU/HR.
15° RANGE
5096 RH APPROACHES
01234
TOWER COST - DOLLARS PER THOUSAND BTU/HR.
25° RANGE
5096 RH
ui
80
75
70
65
60
APPROACHES
0123
TOWER COST - DOLLARS PER THOUSANb BTU/HR.
15° RANGE
2596RH APPROACHES
0123
TOWER COST - DOLLARS PER THOUSAND BTU/HR.
25°RANGE
2596 RH APPROACHES
80
75
70
I-
UJ
65
60
01234
TOWER COST - DOLLARS PER THOUSAND BTU/HR.
HYPERBOLIC NATURAL DRAFT CROSSFLOW WATER COOLING TOWERS
TYPICAL COST-PERFORMANCE CURVES FOR BUDGET ESTIMATES
(From Reference 74)
Figure B-VII-51
365
-------
35° RANGE
10096 RH
APPROACHES
0123
TOWER COST - DOLLARS PER THOUSAND BTU/HR.
45°RANGE
100% RH
80
I 2 3
TOWER COST - DOLLARS PER THOUSAND BTU/HR.
35° RANGE
5036 RH
APPROACHES
I 2 3
TOWER COST - DOLLARS PER THOUSAND BTU/HR
45° RANGE
5096 RH
APPROACHES
01234
TOWER COST - DOLLARS PER THOUSAND BTU/HR,
35° RANGE
25% RH
APPROACHES
BO
0123
TOWER COST - DOLLARS PER THOUSAND BTU/HR.
45° RANGE
2596 RH
APPROACHES
I 2 3
TOWER COST - DOLLARS PER THOUSAND BTU/HR
HYPERBOLIC NATURAL DRAFT CROSSFLOW WATERCCOOLING TOWERS
TYPICAL COST-PERFORMANCE CURVES FOR BUDGET ESTIMATES
(From Reference 74)
Figure B-VII-52
366
-------
Reinforced-concrete veil
based on same design prin-
ciples as Research-Cottrell
hyperbolic natural draft
towers. Creates natural
draft, reducing fan power
requirement. No need for
orientation with respect to
prevailing wind, or wide
spacing between multiple
units.
Forced-draft fans assist
natural draft, reducing
required tower height.
Tower height can be
just enough to avoid
problems of vapor
plume downdraft to
ground level, and of
moist air reclrculo-
tton. C
Counterflow design
locates the fill inside the
tower, minimizing pump-
ing head. Fill can with-
stand ice load, if it should
ever accidentally occur,
without destruction. Veil
and-fill are constructed
entirely of fireproof, rot-
proof materials—essen-
tially maintenance free.
PAN-ASSISTED NATURAL DRAFT COOLING TOWER
FIGURE B-VII-53
(From Reference 358)
367
-------
this, the utility industry is considering this type of system for
specific installations where insufficient water is available for wet
towers. There are approximately six electric generating stations usiag
dry-type cooling towers, principally in Europe. The one operating
facility in the U.S. is a 20 MW unit. This is a "direct" unit, with the
steam condensing directly in the coils. Construction of a 330 MW unit
at the same site utilizing a dry tower is contemplated. The two types
of dry towers, direct and indirect, are shown in Figures B-VII-54 and B-
VII-55.
The principal drawback to the use of this type of tower is the higher
turbine exhaust pressures which result. Current turbine designs would
have to be changed, as most turbines are designed for a maximum turbine
exhaust pressure of 127 mm Hg (5 in Hg abs) whereas with dry-type
cooling towers, the maximum turbine exhaust pressure would range from
200 to 380 mm Hg (8 to 15 in Hg) . Dry bulb temperatures range from 5.50
to 20°C (10° to 35°F) above the wet bulb temperature. Due to the higher
heat transfer equipment costs, dry-type towers optimize at higher
approaches than wet towers, additionally increasing the turbine exhaust
pressure.
A temperature diagram for an indirect, dry cooling tower is shown in
Figure B-VII-56. In dry cooling towers the initial temperature
difference (ITD) is used as a design parameter. The ITD is the
difference between the saturated steam temperature of the turbine
exhaust and the temperature of ambient air entering the cooling tower.
The corresponding temperature difference in the wet tower system is the
sum of the approach to wet bulb, cooling range and terminal temperature
difference (TTD).
Assuming the design parameters typical of an eastern U.S. location (dry
bulb temperature equal to 32°C (90°F) and wet bulb temperature of 25°C
(76°F)), the turbine exhaust pressures corresponding to a wet system and
corresponding to a dry system can be compared. For the wet tower,
typical values of the cooling range, approach, and terminal temperature
difference are 12, 11 and 5.5°C, respectively.
The sum of these is 29°C (52°FJ , which yields a condensing temperature
of 53.5°C (128°F) with a corresponding pressure of 14.5 kN/m2 (4.3 in Hg
abs) in the wet system.
A corresponding dry-type tower with an ITD of 29°C (52°F) with the
ambient temperature of 32.2°C (90°F) , gives a condensing temperature of
61.1°C (142°F) with a corresponding pressure of 20.4 kN/m2 (6.2 in Hg
abs) . This is almost 50SS higher than the condensing pressure in the wet
system.
A number of economic studies have been made comparing the cost and
benefits of dry-type towers with wet towers. Some data from one of
these has been used to calculate the cost curves shown in Figure B-VII-
368
-------
U)
-------
U)
^J
o
STEAM
TURBINE
NATURAL-
DRAFT TOWER
COOLING COILS
EXHAUST
STEAM
DIRECT-CONTACT
CONDENSER
WATER RECOVERY
TURBINE
STEAM SUPPLY
CIRCULATING PUMP
MOTOR
CIRCULATING
WATER PUMP
CONDENSATE POLISHERS
CONDENSATE TO
REACTOR FEEDWATER
CIRCUIT
Figure B-VII-55
INDIRECT, DRY-TYPE COOLING TOWER
CONDENSING SYSTEM WITH NATURAL-DRAFT TOWER 241
-------
t
UJ
oe
tt
UJ
0.
*
UJ
I-
DIRECT-CONTACT
CONDENSER
TURBINE EXHAUST
STEAM
COOLING COILS
r
•TRANSFER OF HOT CIRCULATING
WATER FROM CONDENSER
TO TOWER
-TRANSFER OF COLD CIRCULATING WATER
FROM TOWER TO CONDENSER
(I)
(2)
I
(3)
I
(4)
I
AIR
(I) WATER AND STEAM ENTERING CONDENSER
(2) WATER LEAVING CONDENSER
(3) WATER ENTERING TOWER AND AIR LEAVING TOWER
(4) AIR ENTERING TOWER AND WATER LEAVING TOWER
Figure B-VII-56
TEMPERATURE DIAGRAM OF
INDIRECT DRY COOLING TOWER
HEAT-TRANSFER SYSTEM 24°
371
-------
57. The curves are for the cooling tower only. The variation in cost
shown is due primarily to the variation in construction costs in the
different locationsr Northeast, West, and Southeast rather than to
variations in the design dry bulb temperature indicated on the figure.
The direct contact condenser is considerably cheaper than the normal
shell and tube condenser, as it does not require expensive alloy tubes,
A typical direct contact condenser is shown in Figure B-VTI-58. The
lower condenser costs particularly make up for the greatly increased
cost of the cooling tower.
There are a number of other benefits from the dry-type cooling tower.
1. No water usage, thus no large makeup requirements and no buildup of
solids, chemicals, etc., in the water as in an evaporative tower.
2. There is no possibility of fogging and there are no drift losses to
deposit minerals on the surrounding territory.
On the other side of the ledger, there is a significant loss in plant
efficiency due to the higher turbine exhaust pressures. Figure B-VII-59
gives the expected increases in fuel consumption and decrease in power
output for a nuclear and fossil-fueled plant, provided the turbine could
operate at the higher pressures indicated. Not only is there a loss in
efficiency, but the maxiirum plant capacity is also reduced.
Survey of Existing Cooling Water Systems
The FPC Form 67 Summary Report for 1970 summarizes the use of
once-through cooling, cooling ponds, cooling towers, and combined
systems by number of plants and by installed capacity (Table B-VII-3).
In 1970 about 23% of the plants (18%) of installed capacity) used
cooling ponds or towers. Data submitted to the FPC by Regional
Reliability Councils indicates that cooling ponds or cooling towers are
already committed f cr over 50% of the total capacity of units to be
installed 1974 through 1980. See Table E-VII-4.
Site visits were made to a number of steam electric generating plants.
One purpose of these visits was to observe actual operations of cooling
water systems and to discuss operating experiences with plant personnel.
Design and operating data were obtained for these plants, including
basic plant information, type of cooling system, quantitative data such
as flow rate, temperatures, and approximate cost data.
Plants visited were chosen to result in a spectrum of fossil-fueled and
nuclear units, geographical locations, sizes, and types of cooling
systems. Table B-VII-5 presents a list of plants visited and the basic
cooling water data collected. A few plants that were visited are not
included in this list as a result of incomplete data.
372
-------
s
*
o
H
4J
§
•H
04
5
10,000 .
9,000
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
Natural Draft
Towers
Average Design
Dry Bulb Temperature
is-
18
ITD (°C)
30
35
40
"45
REPRESENTATIVE COST OF HEAT REMOVAL WITH DRY TOWER SYSTEMS
(from Ref. 240) FOR NUCLEAR PLANTS
FIGURE B-VII-57
373
-------
OJ
WATER INLET
AIR VAPOR
OFFTAKE
CASCADE
PLATES
CONDENSATE
OUTLETS
STEAM INLET
EXPANSION JOINT
STEAM INLET FROM
TURBINE EXHAUST
WATER DISTRIBUTION
PLATE
PERFORATED
TRAYS
Figure B-VII-58
STREAM TYPE
DIRECT CONTACT CONDENSER240
-------
w
"3
*l
8
PERCENT INCREASE IN FUEL CONSUMPTION (ABOVE
O ui o
S
13
*i n so
H O M
O 3 en
S CO
Jo 50 G
to M (0 1«
^j Hi M
in td fl>
I H O
< g S3
H y
H O >rj
i o> q
01 H
\O M F
CT»
VO O
H
§
TFRCENTOECREASE IN TURBINE OUTPUT
. ABS.)
-------
Table B-VII-3
USES OF VARIOUS TYPES OF COOLING SYSTEMS 233
Based on FPC Form 67 for 1969, 1970
Type of Cooling
Once-through, fresh
Once-through, saline
Cooling ponds
Cooling towers
Combined systems
Number of Plants,
% total
1969
49.8
18.9
5.4
17.2
8.7
1970
49.4
18.5
5.7
17.5
8.9
Installed Capacity,
% of total
1969
50.5
23.5
5.9
10.9
9.2
1970
50.1
22.8
6.7
11.2
9.2
-o
en
-------
Table B-VII-4
EXTENT TO WHICH STEAM ELECTRIC POWERPIANTS ARE
ALREADY COMMITTED TO THE APPLICATION OF
THERMAL CONTROL TECHNOLOGIES
CONTROL TECHNOLOGY
ASSOCIATED GENERATING CAPACITY, THOUS. MW
IN ACTUAL USE
IN 1973
COMMITTED FOR UNITS INSTALLED
1974 THROUGH 1980
00
No Control (Once-Through)
Controlled
• Cooling Towers
• Cooling Ponds
• Combinations
Unknown
230
110
50
30
30
60
130
80
40
10
30
-------
Table B-VII-5
COOLING WATER SYSTEMS DATA
PLANTS VISITED
Plant
Plant ID Type of Capacity
Code No, Fuel MW
0640
1201
1201
5105
0801
1209
1209
2612
4217
4846
, 3713
•vj
00 3626
1723
2512
3115
3117
2527
0610
2119
NUCLEAR
OIL & GAS
OIL & GAS
OIL
OIL
COAL.S GAS
:OftL & GAS
NUCLEAR
NUCLEAR
COAL
COAL
COAL
COAL
NUCLEAR
OIL
OIL & GAS
NUCLEAR
OIL
OIL & GAS
COAL
916
139.8
792
1386
1165
300
820
1456
700
1640
1150
2137
290
1618
542.5
644.7
457
28
750
2534
Coolinq Tower
Type
Natural
Draft
Mechanics.
Draft
Natural
Draft
latural
Draft
Heiqht Diameter
Ft. Meters Ft. M
425
1
62
323
437
129.5
18.89
98.45
133.2
325
48
247
311
Water
Range
°F
!
99.6
14.63
75.28
94.8
28
Coolinq Pond or Lake
Type
of Pond
Surface Area Volume
Acres M^(103) Acre Ft. M^llO*)^
Artifical 1100 4460
Spray
30
28
Canal 7.35
Spray
Canal x^
29.8
57.17
Natural
Lakes 536.63 2176
Artifical
Canal 3860
Artifical
Lake 2353
Artifical
Reservoir 32510
27.7
Natural
Lake
Spray
Pond
28
15652
9541
131830
113.54
9350
132
11234.3
20,000
50600
1093600
171
11556
163.15
13885
24719
62541
135167
211.35
Average
Time
%
:oo
100
Once-Throuqh Svstem
Lenqth of Pipe Diameter of Pipe
Ft. M Ft. M
Discharge
Type Comments
850
800
3300
356
3619
>50 (Inlet
>35(Outle
10 (Inlet)
.5 (OUT)
80
250
4
243.84
1005
JOS. 5
1103
76.2
fc> 71.62
12.19
4.57
24.38
o (Inlet)
10 (Outlet
11
0.75
16
5.5(IN)
7. 5 (OUT)
5.5(IN)
7. 5 (OUT)
4.5
1.22
1.828
3.048
3.352
0.228
4.876
1.676
2.28
1.676
2.28
1.51
Gravity
Gravity
Gravity
L
Gravity
Gravity
lultiple
Jiffuser
Systems
•3 mos . one
3 mos . spr
Dnce thro
units Is
canal wi
Jsed by a
units
sngth of
650 ft
two towe
are us
2 thr
,canal
ugh
2
LI be
11 4
tower
rs
2d
spr. canal will
51 installed
to replace dif
Gravity j SYS •
Outfall
Gravity
Type
Concre.te
Tunnel
3 such t
:or 3 Uni
wers
:s
-------
Many of these plants have once^through or open condenser cooling water
systems. Sources of cooling water for plants visited include lakes,
wells, rivers, and estuaries. Generally, the water in these plants is
discharged at the temperature at which it leaves the condenser.
However, several "helper" systems were observed, where the water is
cooled before being returned to the source, using a cooling tower or
other device. One plant discharged cooling water to a municipal water
system.
some of the plants that have been designed with or have used once-
through cooling systems are installing closed cooling systems as a
result of environmental regulations. In most instances, a small loss of
plant capacity and efficiency has resulted when this change has been
made.
Other plants visited have closed condenser cooling water systems, where
the cooling water is not discharged to the receiving water, in order to
avoid a thermal impact, but is recirculated utilizing cooling ponds and
cooling towers.
A number of plants use cooling ponds. These may be artificially
constructed lakes, or may be canal shaped. If available land is
limited, a smaller pond may be constructed by utilizing spray modules.
Among the plants visited with conventional cooling ponds, operation
generally appeared satisfactory, and as predicted. Some plants using
spray ponds, however, seem to be having difficulties in maintaining
satisfactory operation with these units.
Cooling towers are also used in a number of cases for cooling the
condenser cooling water in closed recirculating systems. Both
mechanical draft and natural draft wet towers were observed. Natural
draft towers seem to have been specified in cases where there was
concern over possible fogging effects from mechanical draft towers.
Performance of plants with cooling towers appears to have been
satisfactory in all cases.
379
-------
PART B
THERMAL DISCHARGES
SECTION VIII
COST, ENERGY AND NON-WATER QUALITY ASPECT
cost and Energy
The evaluation of the additional costs to be assessed against the power
generated in a unit to which a helper or closed cooling system has been
added are of prime importance to a utility. This provides a basis for
determining the required rate increases. In addition, the capacity of a
unit is reduced by the amount of power used in the cooling system plus
any penalties that may be incurred by required shifting of unit
operating parameters, primarily, the increase in the turbine exhaust
pressure. This lost capacity must be replaced, either by new capacity,
or operation of other units more intensively.
The economic analysis of adding a supplemental cooling system to an
existing unit consists of evaluating the costs of the following:
1. Installing the cooling system
2. operating and maintenance costs of cooling systems
3. Providing additional generation capacity to replace power used or
capacity lost
4. Operating and maintenance costs for replacement capacity
5. Additional cost of generation of remaining power due to a decrease
in plant heat rate
Once these individual costs are determined, the total cost for the
addition of a cooling system to an existing plant can be developed*
There are a number of methods in which the costs can be evaluated.
These methods include annual costs, present worth, and capitalized cost.
Probably the most popular method of comparing investment alternatives
for return on capital is the present worth method. The result of this
type of analysis, and the capitalized cost method, is a dollar value for
each alternative.
In this study, the interest is primarily in incremental costs, i.e., how
many mills/KWH will the addition of a cooling system add to the cost of
generation of each KWH? Since generation costs are normally expressed
in mills per kilowatt hour, this was chosen as the cost basis for the
381
-------
addition of cooling systems. This cost was developed using the method
of annual costs. The additional costs for the year were totaled and
divided by the power generated to give an additional generation cost.
The capital investment involved in the addition of a new cooling system
to a once-through plant can be split into two parts. The first is the
installed cost of the tower and its necessary auxiliaries. These
include new pumps, controls, power system, motor starters, and
modifications to the existing condenser and piping system. The second
part is the capital cost of the replacement generation capability, it
is normally assumed that gas turbine units will be installed to provide
the power to replace that no longer available due to installation of the
cooling system. Once these costs have been determined, the annual cost
is determined by use of the fixed charge rate. The fixed charge rate is
a percentage, which when multiplied by the capital investment, gives the
annual expenses incurred for the capital invested. Included in the
fixed charge rate are interest on this capital, depreciation or
amortization, taxes, and insurance. The actual fixed charge rates vary
for each utility, but generally they average around 15% for investor-
owned utilities. The fixed charge rate for publicly-owned utilities is
normally several percent lower, with a 11% rate corresponding to the 158
for the investor-owned utility*
Of the four items included in the fixed charge rate, interest on the
capital and depreciation or amortization account for the largest portion
of the total. Interest on the capital varies with the current cost of
money. Depreciation or.amortization rates depend primarily on the life
of the equipment to be built.. An installation with a life of 25 years
would be depreciated at 4%, while an installation with a life of 5 years
would be depreciated at 20%.
When the complete plant is built at the same time, one rate is normally
used to cover the entire installation. When adding a cooling system
onto an existing unit, the period over which the cooling system is
depreciated is the remaining life of the unit, not the life of the
cooling system. Whether the cooling system will have any salvage value
when the unit is shut dcwn depends on the location and type of system
used. Obviously, if the cooling system can be switched to another unit,
it will have salvage value. For evaporative type towers, switching to
another unit is generally not possible," and the tower will therefore
have no salvage value. It will usually be uneconomical to move the
tower due to the high construction costs involved. Powered spray
modules will have salvage value, as they could be moved to other sites.
If the cooling system will have a salvage value when the unit is
retired, the amount upon which the depreciation is figured is the
difference between the installed cost and the salvage value.
The operating and maintenance costs for a cooling system include the
incremental power required by the pumps and fans (if mechanical draft is
used) , maintenance and annual overhaul labor and parts and associated
382
-------
overhead. Both the pumps and fans are low maintenance items, so the
major cost is the energy to operate the system, one cooling tower
manufacturer gives a figure of about $200 per year per fan cell as a
tower maintenance ccst. The circulating pumps would normally be
overhauled once a year, which is a two week job on the average.
The amount of replacement generation capacity required is determined by
adding the capacity penalty on the unit due to increased turbine
backpressures to the power required by the cooling system. The unit
capacity rating is normally given for a stated steam inlet condition and
flow, and corresponding turbine exhaust pressure. If the cooling system
can be added without changing the turbine exhaust pressure, there is no
backpressure penalty. However, if the turbine exhaust pressure is
increased, which normally occurs with a closed cooling system, the
output of the unit is decreased by up to several percent, depending on
the increase in turbine backpressure. Turbine manufacturers supply the
curves necessary to determine this decrease in capacity with the
turbine. The backpressure cannot be increased without limit, without
necessitating redesigns of the turbine. For current condensing
turbines, the maximum turbine exhaust pressures are 17 to 18.5 kN/m2(5.0
to 5.5 in Hg abs). The limiting factor is the design of the last stages
in the turbine. Once the amount of replacement capacity is determined,
its cost can be calculated. If new capacity is installed, it would be
completely separate from the unit, and would be depreciated
independently of the unit for which the capacity was required.
The operating cost of this replacement power must be charged against the
cooling system. The total operating cost would depend upon how many
hours a year the additional generation was required. Throughout most of
the United States, peak loads come during the summer months. Thus the
replacement power would probably only be required during the summer.
The remainder of the year, the units with backfitted cooling systems
should be capable of handling the demand, even at the reduced capacity.
The annual operating hours for which replacement power would be required
and the associated cost would depend on the particular utility involved.
Associated with any capacity penalty is an increase in unit heat rate.
The Joules (BTU) heat input to the unit is changed by adding the cooling
system, but less power is generated due to the higher turbine exhaust
pressure. This means that more Joules (BTU) are being used per Kwhr
generated. Again, by making use of the turbine curve, the corresponding
magnitude of the change in generation cost can be determined. Here
again, the penalty will apply only part of the year. Only when the
climatic conditions are such that the design turbine exhaust pressure is
exceeded will this increased generation cost exist. Furthermore, the
operation of the fans in mechanical draft towers need not be continuous
throughout the year. Figure B-VIII-lais an example of how the net power
output of a unit can be optimized by reducing fan power. This is again
dependent on the specific unit in question.
383
-------
100%
OPTIMUM COOLING
TOWER FAN
CAPACITY IN
SERVICE
to
oo
50%
0
WET BULB TEMPERATURE
Figure B-VIII-la
EXAMPLE OF OPTIMIZATION OF NET UNIT POWER OUTPUT BY REDUCTION OF
COOLING TOWER FANS362
-------
Once the annual costs for the above items have been determined, they can
be totaled to give an annual cost for the addition of the cooling system
for the unit. The total generation expected to be delivered to the bus
bar is then determined, and the additional generation cost due to addi-
tion of the cooling system can then be determined directly.
Cost Data
Cost data were obtained from the steam electric generating stations
which were visited during the course of this study. The utilities
involved were very helpful, with seventeen providing the requested
information in time for inclusion in this report. In general, the
plants chosen for the visits were those considered by the Regional EPA
offices as being exemplary stations, or those having an exemplary
treatment system.
Nuclear plants and all three types of fossil-fueled plants (coal, oil,
and gas) were visited. The size of the stations visited ranged from 28
MW to the largest in the country at approximately 2500 MW. One station
had a unit constructed in 1924. In the remaining stations, all units
were constructed after 1952, with 12 stations being constructed after
1960. Of the total number of plants visited, 5 were nuclear. Seven af
the plants had once-through cooling systems, the remaining were on, or
in the process of installing, closed or helper cooling systems.
The types of closed systems involved were mechanical and natural draft
cooling towers, spray canals, and man-made cooling ponds. One of the
two helper systems inspected utilized natural draft cooling towers, the
other spray modules in the discharge canal.
Two types of information were requested, the first involved the physical
description of the plant and its operation. The second was concerned
with the cost of the plant, and the cooling system in particular. In
addition, by visiting plants throughout the country, a great deal of
information about regional problems and their solutions was collected.
A compilation of the cost data is shown in Table B-VIII-1. Probably the
most important feature of this table is the great variation of costs
involved. The land for plant No. 5105, a 1157 MW station, cost
$172,000. The land at plant No. 0610, for a 750 MW unit, cost
$3,335,000, most of which was for a spray canal. In the table, the unit
cost ($/KW) varies from a low of $68/KW to a high of $387/KW, with the
higher values being those for the nuclear plants. The costs also vary
with year of installation, with the older units having lower costs. The
highest unit cost for a fossil-fueled station is plant No. 2527 at
$155/KW, for a 28 MW station. Larger stations tend to have lower unit
costs. Plant No. 2525 at 1,165 MW and a unit cost of S142/KW, seems to
be an exception.
385
-------
TABLE B-VIII-1
COOLING WATER SYSTEMS - COST DATA
PLANTS VISITED
Plant
ID
0640
1201
1201
5105
2525
0801
1209
1209
2612
4217
3713
3626
1723
2512
3115
3117
2527
0610
2119
Type of | Capacity
Fuel I MH
] ' " ~
Plant Cost Data
Date of
Cons t .
NUCLEAR 916 ; 1969-74
OIL s GAS
OIL & GAS
OIL
OIL
COM, S GAS
COAL S GAS
NUCLEAR
NUCLEAR
COAL
COAL
COAL
NUCLEAR
OIL
OIL S GAS
NUCLEAR
OIL
OIL S GAS
COAL
139.8 1956-59
1
792 1969-72
1157 ! 1958-69
1165
300
820
1961-69
1924-64
1964-67
1486
1967-73
700 1966-70
1640
1965-68
2137 ' 1962-70
290
1952-55
1618 1966-72
I
542.5
644.7
457
28
750
2534
1963-68
1954
1967-73
1964-66
1968-72
1969
Land
$
(1000)
Structure
$
(1000)
-
.
1958
172
605
408
_
]
( 2213
)
2393
3692
781
69.58
1062
236
844
213
45
3335
"
1960
26000
8638
20915
5858
37735
19502
30163
4609
34833
7994
13806
165480
1072
4036
~
Equip.
S
(1000)
-
12130
85000
L16255
L38127
29288
106856
158783
174913
18511
110542
55283
71233
3283
97681
-
(1) fo
(2) On
to
(3) No
Total Cap-
ital Cost
S (1000)
355,000
14,090
112,958
125,065
159,648
35,554
59,175
252,381
146,984
181,977
205,857
23,190
146,437
63,513
85,883
165,693
4,400
105,052
(1)
125,000
I Unit 3
ly fracti
station
t given i
Unit
Cost
$/KM
387
88.06
134.8
110.29
142
118.5
68.5
170.0
210
105
102.9
153.12
118
117
143
344
r
Cooling Sys
Date of
Cons t .
1969-71
1956-59
1969-72
1970-71
1971-74
1924-64
1964-67
1971-74
1972-74
1965-68
1952-55
1963-68
155
143
109
jnly
on of thi
3713, bre
ncluded i
1971-72
1969
; cost al
ikdown no
i plant c
Land Structure
5 ?
(1000) (1000)
111 13,021
_
316
1544
6,350
109 1,082
(3) 1,820
(3) 1,762
(2)
11524
20
2496
"
Locatable
: given i
3St
(2)
25,517
258
268
"
1 data
tern Cost
Equip.
?
(1000)
205
825
4,045
1,349
261
2,146
(2)
16,243
585
568
6975
"
1
[
Total Caj
ital Cost
$(1000)
13,337
1,141
11,939
2,540
8,000
2,081
3,908
37,858
19,600
15,750
(2)
53,284
844
6804
856
4818
9471
8036
-% of
Plant
Cost
3.76
8.1
10.6
-
4.5
3.67
4.6
1.35
8.03
9
~
Energy Cost
Ope ratine
s Main."
Cost
S(IOOO)
-
11
Cooling
System
Snergy
Require-
ments
—
-
13 '
-
7.04
-
4MW
-
10
14Mrt
36
48.5
4.632
—
28.5
12
Increasec
Heat
Rate
BTU/KrfH
-
-
89
-
31
-
_
100
267
156
Los s of
Capacity
MW
~
_
6-8
4
-
_
9
41.4
42
Type of
Syst
Natural I
Tower
Once Thrc
Cooling
elper Sp
lelper Sp
Ilosed Sp
Cooling
(three
Dnce Thro
Pooling C
echanica
rfet Towe
Cooling
em
raft Wet
ugh Flow
Pond
tray Canal
ray Canal
ray Canal
*onds
ugh Flow
anal
. Draft
natural Draft Wet
Tower
Cooling
Once Thr
Spray C,
(in proc
3nce Thro
(seawate
Dnce Thro
)nce Thro
3nce Thro
Spray Can
Nat . Drf i
Hlpr&Cloj
Ake
5ugh Flow
inal
;ss)
igh Flow
igh Flow
igh Flow
igh Flow
il
Wet Twr
ied Modes
When Ins
in Stat
Origina.
Origina!
1 un,
Origina
2 uni
Backfitt
neet stre
3 uni
tailed
ion
Design
Design
t
L Design
;s
sd to
un stds
:s
Bckf€td to meet
Str StdsfSunits)
Ong.Des. (lunitj
Original
Original
(to Be ad
cooling
Backfitt
lose sys
Bckfttd t
cooling
Original
Original
Original
Bckfttd t
cooling
Original
Original
Original
Original
Change, f r
inrough c
constr.
3ckfttd o
3rig.Des.
Design
Design
del td
canal)
ed to
:em
o close
system
Design
Design
Design
o close
system
Design
Design
Design
Design
3m once
or ing
i 2 units
1 unit
-------
Land costs for cooling ponds or spray canals are higher than those for
other systems due to larger land requirements. The cost of the cooling
system as a percentage of total plant cost varied from 1.35% for a once-
through system to 9% for a spray canal system. The costs depend a great
deal on local conditions. In addition to varying land costs, foundation
problems vary as well as length of intake and discharge channels, etc.
Of the data collected, costs for cooling systems averaged less than 10%
of the plant cost.
Operating and maintenance cost data for cooling systems are sketchy. In
general, operating and maintenance costs appear to be a small part of
the total operating cost for a station. In only one case was the
reported operation and maintenance cost of the cooling system greater
than 1% of the capital cost of the cooling system (Plant no. 3626) .
Energy required to operate the cooling systems, as reported, was 2% or
less of the rated station capacity. Loss in capacity due to higher
turbine exhaust pressures varied from 0.4SS to 2.5%.
Of the five stations reporting increases in heat rate, three reported
increases of 105 kJ/KWH (100 Btu/KWH) (roughly 1% of gross plant heat
rate) or greater. When a specific station is considered for a cooling
system other than once-through, the station cooling system design is
normally optimized. This means some increase in turbine exhaust
pressure, and consequently higher circulating water temperatures. This
permits use of smaller cooling towers, and the savings realized on
smaller towers more than offset the increase in costs due to the higher
turbine exhaust pressure. Thus part of the heat rate increase is
intentional, and results in lower overall costs.
The last two columns of the table describe the cooling, system currently
in use or being installed and the reason for its installation. Stations
employing different types of closed cooling systems were included in the
plants visited. In the table, a lake is differentiated from a cooling
pond in that the lake in question was created by damming a stream in
which the water rights did not belong to the power company. In a
cooling pond the water rights belong to the utility involved.
The last column designates whether the current cooling system is the
original design or has been backfitted. Of the twenty stations visited,
six are backfitted. Two of the stations visited were backfitting for
the second time to meet increasingly stringent stream water quality
standards. several of the plants backfitting with closed systems are
doing so as a result of legal action. In these cases the trend has been
to go to a closed system. The necessity of getting additional
generating capacity "on line" has been an important factor in
determining the course of action taken.
It was evident from the visits that the spray canal with the powered
spray modules is used primarily as a helper system to cool the
circulating water to meet stream standards. This technology is
387
-------
relatively new, and some ancilliary problems remain to be solved before
this technology becomes sufficiently reliable for extensive utility use.
A preliminary study 232 has been completed to assess the feasibility of
backfitting closed-cycle cooling system with national draft cooling
towers at two TVA powerplants. Plant No. 4704 has four units with a
total capacity of 823 MW, has a capacity factor between 0.2 and 0.6, and
will have 12 years useful service life after 1983. Plant No. 0112 has
eight units with a total capacity of 1978 MW. Units 1-6 have a capacity
factor between 0.2 and 0.6, and a useful life of 9 years after 1983.
Units 7 and 8 have a capacity factor near 0.6 and a useful life of 29
years after 1977. The pertinent results of the study are as follows:
1) the conversions are feasible
2) cost for plant No. 4704 is $16.5 million;
cost for units 1-6 of plant No. 0112 is $18.6 million; and
cost for units 7, 8 of plant No. 0112 is $15.0 million
3) scheduled plant outage for any of the three is 2-3 months
In each case the cost of the tower including foundations is about 4.0X of
the total cost, civil work (dikes, pump station, earthwork, etc.) about
40-50%, electrical work less than 3%r and mechanical work (pump, piping,
etc.) about 10-15%.
Based on the FPC Form 67 data for the year 1970 233^ the capial costs
reported for once-through (fresh) ccoling is $4.03 per KW, once-through
(saline) is $4.63 per KW, cooling ponds is $5.43 per KW, and cooling
towers is $6/25 per KW. The incremental cost shown of cooling towers
over once-through systems is about $1.6 - $2.2 per KW.
Costs Analysis
The initial part of this work consisted of preparing cost estimates for
placing the various types of evaporative cooling in a number of
hypothetical plants in various representative locations in the United
States.
Four typical plants were chosen:
100 MW fossil-fueled unit
300 MW fossil-fueled unit
600 MW fossil-fueled unit
1,000 MW nuclear-fueled unit
Two condenser temperature rises were chosen, 6.7°C (12°F) and 11.1°C
(20°F) . These represent the lower and upper design averages in plants
currently operating in the once-through mode, or plants that would be
388
-------
considered for backfitting with closed cooling systems. A turbine
exhaust pressure of 8.45 kN/m* (2.5 in Hg) abs. was chosen as being an
average of the units in this group. This pressure* plus the climatic
conditions, permitted design of a closed cooling system.
The four locations chosen for this analysis were Seattle, Washington
(cool). Phoenix, Arizona (hot and dry), Richmond, Virginia (average),
and Pensaoola, Florida (hot and humid). The wet bulb temperatures used
were those listed as being egualed or exceeded only 5% of the time, on
the average during the four months of June through September. 52 This
amounts to 110 hours for this period.
The necessary information was submitted to three cooling tower
manufacturers and twc powered spray module manufacturers for cost
estimates. These conditions assumed 100% heat removal in the tower and
no change to the generating unit, i.e., cooling water temperature was
the same. Of the total of 32 separate plants resulting from the matrix
of conditions, 20 were capable of being backfitted with mechanical draft
cooling towers, and 16 with natural draft cooling towers. Use of
natural draft towers in Phoenix were not practical due to low humidity.
One powered spray module manufacturer proposed systems for 28 of the 32
cases, while the other proposed for 16 of the 32 cases. The costs of
the equipment only is shown in Table B-VIII-2. The mechanical draft
tower (wood construction) , and the natural draft tower (concrete
construction) , are the two types of cooling towers most widely used in
this industry. These are considered available technology. Powered
spray modules are being used for backfitting to reduce circulating water
temperatures to meet gtream standards. As such, they are available
technology. At one major plant the powered spray modules are being
installed in a closed system.
Table B-VTII-2 illustrates a number of points. The first is that under
the conditions specified* natural draft cooling towers are considerably
more expensive to buy than the other types. This is particularly true
for smaller plant sizes in which the natural draft tower would not be
expected to be competitive. However, operating costs are less, which
makes their overall cost lower than the tower cost would seem to in-
dicate. For mechanical draft towers, it appears that concrete
construction is more expensive than wood by a factor of 1.4. The cost
of all the systems, exclusive of the natural draft tower is about the
same. Thus if mechanical towers are used as a technology to investigate
the costs of their application, use of the other systems would result in
similar costs. This leaves a number of options open to utilities for
about the same cost. Each plant would have to be evaluated on an
individual basis to determine the most economical system for that
station. cooling pcnds were not covered in detail since their use is
not dependent upon equipment supplied by a manufacturer. Their cost is
almost entirely composed of land cost and the cost of the retrofit.
389
-------
TABLE B-VIII-2
COST OF COOLING SYSTEM EQUIPMENT
Unit
Size
(MW)
100
300
600
1000
L
Unit
Location
Seattle
Phoenix
Richmond
Pensacola
Seattle
Phoenix
Richmond
Pensacola
Seattle
Phoenix
Richmond
Pensacola
Seattle
Phoenix
Richmond
Pensacola
Circulating
Water Rise (F)
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
Cost For System (.$ x 10b).
Mech. Draft
Wood Constr .
.400
.459
.612
.567
.728
1.050
1.195
1.768
1.640
2.025
1.815
2.154
3.102
2.648
3.497
4.275
4.840
7.281
6.765
8.337
Mech.
Concrete
Mfr. A
,550
.648
.857
.798
1.019
1.442
1.665
2.478
2.300
2.835
2.491
3.014
4.332
3.705
4.897
5.867
6.780
10.191
9.465
11.677
Draft
Contr .
Mfr. B
.650
.825
0.800
0.955
1.490
2.232
2.010
2.530
2.640
3.825
3.525
4.470
6.000
9.050
8.250
9.900
Natural
Draft
2.5
2.8
4.1
4.3
3.9
4.7
8.0
8.3
5.5
6.8
14.6
15.1
10.1
14.7
30.8
31.9
Powered Spray
Module
Mfr. A
.380
.532
.684
1.596
.684
1.293
.836
1.064
1.293
1.824
4.180
1.748
3.345
2.05
1.748
2.20Q
3.118
7.22
2.965
5.700
3.57
4.180
4.940
7.380
16.040
6.920
12.700
8.51
Mfr. B
.364
.401
.765
.656
.875
1.130
1.933
1.695
1.531
1.763
3.390
2.984
3.255
3.933
8.070
6.984
390
-------
This optical is available for use and considered as a lower cost
available technology for those plants where suitable land is available.
Operating Costs
For the overall costs analysis, the additional cost (in mills/KWH) to
install and operate a mechanical draft cooling tower as a function of
the percent of heat removed from the circulating water is generally
representative of the overall cost of the application of effluent heat
reduction technology, due to general similarity of costs among available
technologies. Due to the broad spectrum of unit sizes and conditions
throughout the United States, the number of cases studied had to be
strictly limited to provide a manageable number of analyses. The first
restrictions were made on the basis of the categorization of the
industry. Fossil-fueled plants only were considered, as these make up
the bulk of existing facilities at present. The next break came on the
basis of unit use. A statistical analysis of the plants reporting to
FPC on Form 67 resulted in the statistics shown in Table B-VTII-3.
Based on these figures, the figures shewn in Table B-VIII-4 were used in
the analysis. The only adjustment, other than rounding off, were made
in the heat rate. These heat rates are based on total fuel burned and
total KWH1s generated during the year. Since by definition a base unit
is operating at or near capacity most of the year, this heat rate is
fairly representative of the actual heat rate while operating at near
full capacity. The same is not true of the other two cases. The cyclic
unit, operates for longer periods of time at lower loads, where
efficiency is lower. This unit may act as spinning or standby reserve
where the boiler is up to pressure, but little power is being generated.
Thus the heat rate is higher than that actually existing when the plant
is operating at near full capacity, the heat rate desired for this
analysis. The cyclic unit heat rate was reduced to 12,000 kJ/KWH
(11,500 BTU/KWH) , considered to be more truly representative of the
actual unit heat "rate. The same factors influence the heat rate of the
peaking unit, even to a greater degree. The heat rate of peaking units
was reduced to 13,200 kJ/KWH (12,500 BTU/KWH) as being a more realistic
figure. Note that when a unit is being held in a warm standby condition
it is normally not connected to the circulating water system. Thus,
most of the increased heat is discharged to the stack and not to the
receiving water. Since the purpose of the analysis was to determine the
range of costs involved in installing wet cooling towers on existing
units, three wet bulb temperatures were chosen as the worst, near
average and best wet bulb temperatures, for cooling tower design
purposes, in the United States. The worst, or highest wet bulb
temperature was 28°C (83°F). This was at the IX level, exceeded only
one percent of the time during June through September. An average
chosen was 24°C (75°F), and the lowest summer wet bulb at the IX level
was 14°C (57°F) .
The remaining factor was unit age, and this was taken into consideration
as unit remaining life, assuming a unit life of 36 years. The median
391
-------
TABLE B-VIII-3
HYPOTHETICAL PLANT OPERATING PARAMETERS
Type
of Unit
Base
Cyclic
Peaking
Hours Up
per Year
7685
4475
1155
Heat Rate
kJ/KWH
11,231
13,192
16,677
BTU/KWH
10,636
12,493
15,793
Capacity
Factor
0.77
0.44
0.09
Bus Bar Cost
Mils/KWH
6.24
8.35
12.50
TABLE B-VIII-4
REVISED PLANT OPERATION PARAMETERS
Type
of Unit
Base
Cyclic
Peaking
Hours Up
per Year
7690
4500
1200
Heat Rate
kJ/KWH [ BTU/KWH
11,088
12,144
13,200
10,500
11,500
12,500
Capacity
Factor
0.77
0.44
0.09
Bus Bar Cost
Mils/KWH
6.34
8.35
12.50
392
-------
ages of the three age categories, 6, 18, and 30 years, were used. This
gives a total of 27 cases, 3 types of units multiplied by 3 wet bulb
temperatures multiplied by 3 ages.
Some additional information on the unit must be specified. The plant
size chosen was 300 MW. By using a 300 MW unit, some idea of the
magnitude of the various costs could be made. Since parameters and
costs used varied linearly with unit size, the costs, in terms of
mills/per KWH, will be applicable to any unit for which the basic
assumptions are valid and operating parameters fall within the range
indicated. It was further assumed that operation of the unit at a
turbine exhaust pressure of 8.45 kN/m* (2.5 in Hg abs) would incur no
operating penalty other than the power requirements of the tower and
pumps. Any increase in pressure above this would result in both an
additional capacity penalty and a fuel penalty.
A circulating water temperature rise of 16.7°C (30°F> was chosen as
being the highest to be found in the units being considered for
back fitting. Due tc the restrictions on approach and cold water
temperature to the condenser, this is the most restrictive set of
temperature criteria for tower design. The other extreme of circulating
water rise is about 6.7°C (12°F) . For the same size plant, the cooling
water flow would be increased by a factor of 2.5. This has a
significant effect on tower cost, but the temperature criteria are much
less restrictive. This permits, as will be explained later,
modification of the cooling system to significantly reduce the cost for
the case with a 6.7°C (12°F) temperature rise.
Two additional parameters were chosen, the first was a terminal
temperature difference cf 5.5°C (10°F) in the condenser. The second was
to establish 6.7°C (12°F) as the minimum approach to be used in tower
design. This value was determined through conferences with cooling
tower manufacturers.
The above plant characteristics are summarized in Table B-VII-5.
A number of additicnal assumptions related to the economics of the
utility industry were necessary to complete the analysis. Since the
pumps required to circulate water through the cooling tower are not
included in the cost of the tower, these were priced using a total
dynamic head of 24 meters (SO1)* of this 24 meters (80«) , 18 meters
(60*) was required in the tower, and the remaining 6 meters (20'Vas for
pipe losses and additional lift required. Since most once-through
condensers make use of the siphon effect to lower pumping requirements,
the original pumps are low head, and would not be suitable for cooling
tower service. There are a number of ways in which the cooling tower
could be connected, but all include new pumps, either to handle the
entire system or to be placed in series with current pumps. The cost of
the pumps was estimated at $100/HP, and an overall pump-motor efficiency
393
-------
TABLE B-VIII-5
TYPICAL PLANT CHARACTERISTICS
Unit Size - 300 MW
Unit Types - Base, Cyclic, and Peaking
Wet Bulb Temperatures - 83°F, 75°F, 57°F
Median Remaining Unit Life - 6, 18, and 30 years
Circulating Water Rise - 30°F (Upper Limit)
Condenser TTD - 10°F
Cooling Tower Approach - 12°F minimum
394
-------
of 80% was assumed. The cost of connecting the cooling tower into the
existing circulating water system is site dependent and is therefore
extremely variable. Factors that influence the cost of the tower
installation include the relative locations of tower and plant, the type
of terrain and soil conditions, and the site, type and locations of
connections that must be broken into. Indirect costs for engineering,
legal, and contingencies must also be included.
Table B-VIII-1 shows the cost of installing the cooling systems at the
plants visited during the study. The average value for retrofitted
closed cooling systems was S14.1/KW, and average value pf $15/KW was
assumed for the purposes of this analysis. For a 300 MW unit, this
amounts to $4,500,000 for the complete installation. The cost of the
tower and pumps alone for this installation would be approximately
$1,121,600. Therefore, the total installed cost is approximately H00%
of the cost of the major equipment involved. The basis for this
estimate was a base unit installed at a location where the design wet
bulb temperature was 75°F. The cost will vary for other wet bulb
temperatures with a range of about $13/KW to S25/KW.
For the purposes of the economic analysis a markup of 300°C above the
the base cost of the najor equipment items was allowed to cover the
installation costs and indirect costs mentioned above. This allowance
is considered to be conservative for most cases.
To determine the tower costs, the cost information on mechanical draft
towers from Table B-VIII-2 was used to develop a linear relationship
between the tower parameters (approach, range, flow, and wet bulb) and
cost. The variation in cost was less than 5% at the 28°C (75°F) wet
bulb temperatures, and averaged less than 15% for the 14°C (57°F) wet
bulb temperature. Land cost was not included in the tower capital cost
due to wide variation throughout the country.
Fan power requirements were also determined in a similar manner, with
less than 10X variation. The operating cost of the towers was assumed
to be primarily the ccst of the electricity to run the fans and pumps,
and was charged at the average rate for the particular type of unit,
except in the case of the peaking unit. In this case the average power
cost was 2. 5 mills/KWH higher than the operating cost of replacement gas
turbines, assumed to be 10 mills/KWH. Thus in this case, it was assumed
that the power required to operate the tower cost 10 mills/KWH. Ten
percent of the operating cost of the fans and pumps was added to cover
maintenance and parts for this equipment.
Since there were three remaining life spans considered, and since the
tower had essentially no salvage value, the cost of the tower had to be
absorbed during the remaining plant life. To account for this, three
fixed charge rates were used, one for each of the three remaining life
spans as follows: 6 years - 30X, 18. years - 19%, and 30 years - 15%.
395
-------
These are rates for investor-owned utilities; public utility rates would
be lower.
It was assumed that the energy required by the cooling tower system was
replaced with energy produced by a gas turbine. In addition, any
capability loss due to operation at higher turbine exhaust pressures was
replaced with gas turbine generating capacity. It was assumed that the
installed cost of these gas turbines was $90/KW. 1970 costs are used
throughout this analysis. Since the life of these units was independent
of the unit whose power they were replacing, a 30 year life was assumed
and the fixed charge rate was accordingly 15S6. If base load capacity
were used in place cf turbines to replace the capability loss, the
annual costs of replacement capacity would be less.
Any increase in turbine exhaust pressure results in a higher heat rate,
and consequently a higher generation cost. The following changes in
heat rate were assumed. They were taken from a typical curve for a
turbine with initial steam conditions in the superheat region. Values
used are shown in Table B-VIII-6.
This increase in generating cost was based on the average generating
cost for the type of unit being considered. These factors and
assumptions are summarized in Table B-VIII-7.
Several additional assumptions were made about each type of unit, base,
cyclic, and peaking. These were mainly concerned with the number of
hours the gas turbine would operate and the fuel penalty that would be
assessed. Since the peak load normally comes in the summer months and
this period is the critical one for tower operation, the penalties
normally apply during this period. For the base units, it was assumed
that they would operate under penalties equivalent to full penalty for
one half of the average number of hours per year. Cyclic units were
assumed to operate under full penalties for 2,000 hours per year. Since
peaking units average 1,800 hours per the penalties would apply during
the full 1,800 hours of operation. These values are considered near the
maximum, and the actual values will vary from unit to unit. Shut down
of the unit is required during the time required to connect the cooling
tower into the existing circulating water system. The time required to
make this connection will depend on the layout and accessibility of the
existing cooling water system compments. It is estimated that the time
required to perform this work will vary from 2 to 5 months, depending on
these conditions, with an average time of 3 months. One month of this
requirement can norirally be scheduled to coincide with the annual
maintenance period when the unit is down in anycase. Therefore,
additional cost will be incurred to supply the power normally generated
by the unit for a period of two months. It is further assumed that
shutdowns to allow these modifications to be made can be scheduled to
coincide with periods of low system demand. Therefore, replacement
power can be obtained by higher utilization of other equipment in the
system rather than by wholesale import of power from other sources.
396
-------
Table B-VIII-6
ASSUMED INCREASE IN HEAT RATE COMPARED TO BASE HEAT RATE AS A FUNCTION
OF THE TURBINE EXHAUST PRESSURE
Turbine Exhaust Pressure, in Hg
OJ
2.5
3.0
3.5
4.0
4.5
5.0
5.5
Increase in Heat Rate, % of base
Base
0.4
0.8
1.4
2.0
2.8
3.6
-------
LJ
10
00
Table B-VIII-7
COST ASSUMPTIONS
Pumps required for tower
Tower cost
Fan power
Pump power
Fan and pump operating cost
Fixed charge rates
6 yr remaining life
18 yr remaining life
30 yr remaining life
Replacement power
Replacement power fixed charge rate
Fuel penalty
$100/HP @ 80 ft of head,
80% overall efficiency
Interpolation from Table B-VIII-2
Interpolation from Table B-VIII-2
80 ft of head, 80% efficiency
Electrical energy at average for type
of unit, plus 20% for maintenance
30%
19%
15%
Combustion gas turbines
and 10 mills/KWH
15%
90$/KW
Assessed at cost of generation for type
of unit considered except for peaking
units, where cost is 10 mills/KWH
-------
Replacement power for base-land units undergoing these modificiations
will be supplied by operating cycling units more intensively. The
utilities will incur additional operating costs because these units are
typically less efficient than the base-loaded units. A differential
energy cost of 3 mills/KWH was assumed to be representative of the
increased operating costs of these types of units. The total costs
associated with loss of the unit was obtained by multiplying the
capacity of the unit by the number of hours affected, the units annual
capacity factor and the differential operating cost. The decreased
utilization of cycling and peaking units will generally allow them to be
modified without incurring downtime costs as high as the base-load
units. However for the purposes of consistancy of the analysis, similar
penalties were assessed against these units as well.
In order to extend this cost to the remaining units of power, production.
The total cost was considered to be money borrowed at an annual interest
rate of 8% compounded. This loan was then assumed to be repaid over the
remaining life of the unit and the annual costs obtained were spread
over the average annual generation.
A sample calculation for a peaking unit with a 24°C (75°F) wet bulb
design temperature, is shown in Table B-VIII-8. The procedure was to
assume 8.45 kN/m2 (2.5" Hg abs) turbine exhaust pressure with its
corresponding 99°F hot water temperature. With a minimum approach of
6.7°C (12°F) , the iraximum range of the tower is 6.7°C (12°F) or the
percentage of heat removed is 12/30 or 40%. Using a minimum range at
5.5°C (10°F) the % of water flow through a tower for heat removals below
40X were determined. The turbine exhaust pressure was then increased to
10.1 kN/m* (3.0 in Hg abs), the maximum heat removal determined (6055)
and conditions for removal of from 40% to 60% removal determined. The
same procedure was used at 11.8, 13.5, and 15.2 kN/m2 (3.5, 4.0, and 4.5
in Hg abs) until 100% removal was obtained. The analysis then proceeded
in an orderly fashion as shown in Table B-VIII-8. The other 26 cases
were treated in a similar manner, and the result was a set of nine
graphs showing the range of additional generation costs involved in
backfitting the hypothetical 300 MW unit with mechanical draft cooling
towers. since all factors were linear with size, these costs will be
applicable to any size plant in which the basic assumptions are still
applicable. Conversations with cooling tower manufacturers indicate
that for mechanical draft towers only a small variation in cost would be
expected in the range of units involved, including a 1 MW plant. Pump
-osts may increase in the smaller size units.
The first three graphs. Figures B-VIII-1, B-VIII-2, and B-VIII-3, cover
aase-load units. Additional generation costs ranged from a low of 0.60
nills/KWH at a 13.9°C (57°F) wet bulb temperature and 30 year remaining
Life to a high of 0.65 mills/KWH at a 28.3°C wet bulb temperature and 6
fear remaining life. These are for 100% (actually about 98%) heat
removal. As indicated en the graphs, it was necessary to increase
turbine exhaust pressure in every case to achieve 100% heat removal
399
-------
TABLE B-VIII-8
COOLING TOWER ECONOMIC ANALYSIS
(300 MHe Unit, Peaking Service, Wet Bulb Itemperatu:
Turbine
Exhaust Percent Percent Tower Tower Tower Pump Tota
Pressure of Heat of Water Range Approach Cost Cdst plus
in. Ha abs. Removal thru Tower l°F) (°F) $ $ 2S*
2 5
30 90 10 14 531,200 318,800 1,062
20 60 10 14 354,400 212,500 708
10 30 10 14 176,800 106,300 353
; 3.0 60 100 18 12 1,067,300 354,200 1,776
50 100 15 15 ! 749,400 354,200 1,379
40 95 13 , 17 | 561, 200! 336,500 1,122
3.5 . 77 100 i 23 ,12 i,2l4,90Q 354,200 1,961
4.0 93 100 28 12 1,351,100 354,200 2,131
80 100 24 16 931,000 354,200 1,606
70 100 22 18 , 772,100 354,200.1,707
4.5 100 100 30 15 j.,112,700 354, 200 [l, 833
90 100 27 18 874,300 354,200 ;1 , 535
6 Year 18 Year 30 Year
Life Life Ltft
500 318,800 201,900 159, 40C
Annual
Fan Oper-
ing Cos $
8,500
6,000
600 212 , 600 134 , 600 106 ,300 4 , 000
80q 106,100 67,200 53,100 2,000
900 533,100 337,600 266,500 12,000
Annual Total
Pump Dper-plus 10% Fan Pump
ing Cost for Main. Power Power
— tfl {*) Mfe Mfe
31..20.0.-
28 , 600
19,000
9,500
31,7J10
50CJ 413,800 262,100 207,000 8,400 j 31,700
10Q 336,600 213,200 166,300 6,200
40Q 588,400 372,700 294,200 13,700
q
60CJ 639,500 405,000 319, 70C
8,500
15,100
500 482,000 305,200 241,000 10,400
900 422,400 267, 50Q 211,200 8,600
600 5 50 , 1 00 348, 400 2 75 , OOC
600 460,700 291,800 230, 30C
1
1
12,500
9,800
31,700
31,700
31,700
31,700
31,700
. 44_,_200 .
38,100
25,300 ,
12,600
.7 \ ?._6__
.5 2.4
.3 1.6
.2 .8
48,000 1.0 2.6
44,100
41,700
49,900
44,200 ,
51,500
46,400 ,
31, TOO" j 44,400
31,700
31,700
48,600
45,700
.7 2.6
.5 2.5
1.2 2.6
.7 2.6
1.3 2.6
.9 2.6
.7 2.6
1.0 2,6
.8 2.6
Capital Annual
Capacity Total Cost of Cost Operating
Penalty Penalty Gas Turbine 15% Cost
0
3.3 __,. 101^500. 45,200 . 40_-2QQ
2.9 259,200J 38,900 34,600
0 1.9 171,900
0 1.0 85,500
1.4 ' 5.0 435,600
1 .4
1.4
2.7
2.7
4.7
4.7
4.7
6.8
6.8
q.7 i 408,600
4.4 ' 380,700
6.5 556,200
6.0 517,500
8.6 729,000
8.2 693,900
25,800 22,900
12,800
11,400
65,300 58,000
61,300
57,100
83,400
80,200
77,600
109, 40C
107, 60C
104, 10(
54,500
50,800
74,200
71,300
69,000
97,200
95,600
92,500
8.0 680,400 102,100 90,700
10.4 871,200 130,700 116,200
Fuel
Additional Generatinq Cost (mills/KWH)
Penalty 6 Year 18 Year 30 Year
Cost KeMining Remaining Remaining
0
0
0
0
18,000
18,000
18,000
35,800
35,800
35,800
65,100
65,100
65,100
65,100
88,200
2.9S i 2.14 1.84 -j - i
2.34 1.70 1.47 j
1.56 1.13 .98
.77
.56 .49
3.93 I 2.86 j 2.48
3.22
2.74
4.80
3.96
3.50
5.23
4.90
4.29
3.94
5.08
2.39
2.07
3.62
2.98
2.67
3.96
3.74
3.33
3.10
3.98
2.09
1.83
3.20
2.62
2.37
3.49
3.32
2.98
2.79
3.58
-------
8.3°X: (B3°F)
3.9°C (75°F)
•13.9°C I57°P)
Wet Bulb
Temperatures
5.5-Hg
18 YEAR REMAINING LIP)
30°F Temperature Rise
2B.3"C (B3->>
23.9 C (75°P)
13.9°C (57°F)
Wet Bulb
Temperatures
!!"
- 30 YEAR REMAINING LIFE
10 20 30 40 50 60 70 80 90 100
Percent Heat Removed
10 20 30 40 50 60 70 80 90 100
Percent Heat Removed
10 20 30 40 SO 60 70 80 90 100
Percent Beat Renoved
Figures B-VTII-1,2,3,4,5
ADDITIONAL GENERATING COSTS FOR
MECHANICAL DRAFT COOLING TOWERS
Base-Load Unit, 300HW
16.7°C (30°F) 5
Condenser Pressures shown
as "Hg abs.
10 20 30 40 50 60 70 80 90 100
Percent Heat Rejected
. 6.7°C
Temperature
Rise
16.7°C (30°F)
75 °F Wet Bulb Teraperatu
10 20 30 40 50 60 70 80 90 100
Percent Beat Removed
-------
within the limitations placed on the hypothetical unit. At an average
generation cost of 6.24 mills/KWH, the maximum additional cost of 1,10
mills/KWH is an increase of about 17%, with the minimum for 100% heat
removal of about 10%.
To evaluate the effect of circulating water rise on additional
generation cost, additional calculations for a 6.7°C (12°F) circulating
water rise were made for the 30 year and 18 year remaining life
categories at a 23.9°C (75°F) wet bulb temperature. The 6.7°C (12°F)
rise approximates the lowest value found in current plants. The results
are shown in Figures B-VIII-4 and B-VIII-5. At heat removal fractions
above 50%, costs are significantly higher. These higher costs are
deceptive, because a simple change to the system can reduce the cost to
approximately that at the 16.7°C (30°F) rise case. This change involves
increasing the turbine exhaust pressure and then cooling only part of
the circulating water to a level below that required. The required
temperature is obtained when the two streams are remixed. This is
possible due to the larger temperature difference between the wet bulb
and cold water temperatures than in the 16.7°C (30°F) rise case. The
tower cost is significantly lower due to the lower flow through it. For
example, by increasing the turbine exhaust pressure to 11.8 kN/m2 (3.5
in Hg) and cooling 60% of the water 11.1°C (20°F) , the additional
generation cost is reduced from 1.0 mills/KWH to 0.7 mills/KWH. Thus
the higher costs for the 6.7°C (12°F) rise case can be substantially re-
duced, an option not as readily available in the 16.7°C (30°F) rise
case. The cost of this scheme is variable depending upon site
conditions and plant layout.
The results for the cyclic unit are shown in Figures B-VIII-6, B-VIII-7,
and B-VIII-8. The curves have essentially the same shape as the base.-
load unit curves, however, the additional generation costs are doubled.
The reason for this is that there is much less power generated in a
cycling plant against which the cost of the cooling towers can be
charged. With a six year remaining life, the 75°F wet bulb case results
in a higher incremental cost than the 83°F wet bulb case. For the 18
and 30 year remaining lives, the costs for the 75°F and 83°F cases are
the same. The capacity factor for the cycling plant is 44% versus 11%
for the base-load unit. The penalties were assumed to be the same as in
the base-load unit, as the cycling units would be heavily used during
the summer peak load. If this were not'true for specific units, the
cost would be somewhat lower.
The costs for the peaking units are shown in Figures B-VIII>9, B-VIII-
10, and B-VI11-11. The costs for these units are almost an order of
magnitude greater than those for the base-load unit. The maximum was
11.0 mills/KWH for a unit with 6 years remaining life and the minimum
was 4.5 mills/KWH for a unit with 30 years remaining life. Here again
the major difference was the number of KWH's against which the cost of
the cooling system could be charged. The capacity factor for peaking
units used was 9% as opposed to 77% for base-load units. The change in
402
-------
2.4
2.2
2.0
§
1-6
1.2
1.0
0.8
0.6
30°F Temperature Rise
10 20 30 40 SO 60 70 80 90 1
Percent Beat Removed
ADDITIONAL GENERATING COSTS FOR
300 HH CYCLIC UNIT
MECHANICAL DRAFT TOWERS
6 YEAR REMAINING LIFE
Figure B-VII1-6
2.4
2.2
2.0
i.a
i.,
0.6
0.4
0.2
0.0
•• "Hg aba.
!6.3°C (83°P)
3.9°C (75°F)
13.9°C (57°f)
Wet Bulb
Tamper at lire
30 P Temperature Rise
Percent Heat Removal
ADDITIONAL GENERATING COSTS FOR
300 HIT CYCLIC UNIT
MECHANICAL DRAFT TOWERS
18 YEAR REMAINING LIFE
Figure B-VIII-7
C2B.3°C (83
l23.90C (75°F)
13.9°C (57°P)
Het Bulb
Temperature
90
Percent Beat Removal
ADDITIONAL GEHERAHSG COSTS FOR
300 MT CYCLIC OHIT
KECHAVIOU. DRAFT TOWERS
30 YEAR REMAINING LIFE
Figure B-VHI-B
Percent Heat Removed
ADDITIONAL GENERATING COSTS FO1
300 HH PEAKING UNIT
MECHANICAL DRAFT TOWERS
6 YEAR REMAINING LIFE
Figure B-VIII-9
23.9°C <7S°F)
8.3°C (83°F)
*3.9°C (57°F)
Het Bulb
Temperature
12.0
11.0
10.0
i '°
3_ "•"
4JB
Si 7.0
S
-------
additonal generation cost with change in capacity factor, all other
factors remaining the same, can be determined from Figure B-VIII-12.
The cost of backfitting mechanical draft towers on nuclear units was
also determined, using the same techniques employed for the 300 MW
fossil-fueled plant. Except for a few small experimental units, most
nuclear facilities fall in the 500 to 1000 MW size range. An 800 MW
nuclear unit was assumed for the economic analysis. The heat rate
assumed was 11,088 kJ/KWH (10,500 BTU/KWH) , with 6,864 kJ/KWH (6,500
BTU/KWH) being rejected through the condenser. Two circulating water
temperature rises were used, 16.7°C and 6.7°C (30°F and 12°F). The
remaining assumptions were essentially the same as for the 300 MW
fossil-fueled unit. Since there are no large nuclear units over ten
years old, only 18 and 30 years remaining lives were considered. All
nuclear units presently are base-loaded, so only the base-load case was
considered. Wet bulb temperature used for tower design was 23.9°c
(75°F). Capacity factor used was 70%.
The costs resulting from this analysis are shown in Figures B-VIII-13
and B-VIII-14. For the 16.7°C (30°F) rise, the additional generation
cost was higher than for the fossil-fueled unit due to the increased
heat rejection to the water as expected. Here again the case where the
circulating water rise was 6.7°C (12°F) was the most expensive.
However, the comments concerning this in the fossil-fueled analysis are
equally applicable to this case.
Reference 368 presents nomgraphs which permit the estimation of cooling
system performance anc costs.
Energy (Fuel) Requirements
Energy significantly in excess of that normally required by the
circulating water system is required to operate all cooling systems ex-
cept the cooling pond. With spray canals, the water is pumped into the
spray nozzle. The natural draft tower requires the water to be pumped
to the top of the packing. In the mechanical draft tower, in addition
to pumping the water to packing, power is required to run the fans which
move the air through the tower. The amount of energy required varies
by a factor of three for mechanical draft towers due to its dependency
on condenser design and climatic conditions. A condenser with a high
flow rate and low temperature rise requires more pumping energy than a
condenser with a lower flow rate and higher rise, for the same size
plant. With adverse climatic conditions, more air is required,
resulting in bigger fans requiring more energy.
Fan motors for mechanical draft cooling towers are about 0.2 percent of
the unit generating capacity; pump motors are about 0.5 percent,
However, fans and pumps need not be operated continuously year round.
Both fan power and pump power can be reduced along with the generating
demand. Furthermore, fan power can be reduced when climatic conditions
404
-------
CF
-=— , comparison of capacity factors
2
0.7 0.8 0.4 1.0
a
0
tj
id
-P
•rl
U
(0
P! W
nj 2
o S
.p D)
(0 H
H
-P -H
W fi
0
O *
B
h co
0) C
C 0
(U-H
O -P
n>
H H
S3
0 H
•H n>
•P O
,-H
•0 C
•0 -H
00
QO O.I O.I 03 0.4- 0.5 06 07 OB 0.9 1.0 l.l \
Additional Generation Cost at Capacity Factor (CF ) in
Question, mills/KWH
Figure B-VIII-12
VARIATION OF ADDITIONAL GENERATING COST WITH CAPACITY FACTOR
405
-------
o
o
§
•H ^~
•P 33
Id 3
C 01
0) H
O H
1~
O
i
1.6
1.4
1.2
1.0
0.8
0.6
0.4
0.2
0.0
Condenser Pressures Shown
as "Kg abs.
_ 23.9°C (75°F) Wet Bulb Temperature
2.5"Hg
Temperature
Rise
16.7°C (30°F)
4.5"Hg
—^j—AJ—^o—E^J /o—8^3—gV
Percent Heat Removed
ADDITIONAL GENERATING COSTS FOR
800 MW NUCLEAR UNIT
MECHANICAL DRAFT TOWERS
18 YEAR REMAINING LIFE
Figure B-VIII-13
1.4 -
1.2 -
1.0
o
u
c
o
•H --^
C M
0) iH
O H
•H
H e
1TJ v
0
-H
4J
•r-1
TJ
0.6
0.4
0.2
,0.0
Condenser Pressures Shown
as "Hg abs.
2.5"Hg
Temperature
Rise
16.7°C (30°F)
_L
_L
_L
_L
10 20 30 40 50 60 70 80 90
Percent Heat Rejected
ADDITIONAL GENERATING COSTS FOR
BOO MW NUCLEAR UNIT
MECHANICAL DRAFT TOWERS
30 YEAR REMAINING LIFE
Figure B-VIII-14
100
-------
permit to optimize the- net unit power output. Only incremental pumping
power should be considered as chargeable to closed cooling systems.
Incremental energy (fuel) consumption due to fans and pumps with
mechanical draft cooling towers is estimated to be approximately 0.7
percent of base energy (fuel) consumption. With natural draft towers
and spray systems there is no fan power but incremental pumping power is
estimated to be approximately 0.7 percent or less of base fuel
consumption. With coding ponds there is no fan power and pumping power
would be approximately the same as with once-through systems.
A further source of incremental energy (fuel) consumption due to
closed-cycle cooling systems is the incremental steam cycle inefficiency
due to changes in the turbine backpressure. In many cases higher
turbine backpressures will result after backfitting closed-cycle cooling
systems. In these cases the higher backpressures will result in
incremental steam cycle inefficiencies during most of the years. The
incremental fuel consumption over any span of time due to this factor is
a product of the average incremental inefficiency over that span and the
power generated over the span. For example, the fuel consumption
penalties due to increased turbine backpressure from a closed-cycle
cooling system (See Figure B-VIII-15) is shown in fable B-VIII-9. The
maximum penalty during any month is 0.7 percent of base fuel consumption
during that month. Assuming uniform power generating from month to
month, the annual penalty is 0.2 percent of base fuel consumption. The
greatest fuel penalty expected would occur when the wet bulb temperature
reaches the maximum level for which the evaporative cooling system is
designed, i.e. the wet bulb temperature which is exceeded no more than
5X of the time during June, July, August and September. For the plant
shown the maximum penalty is 2.1X. In the case of a new source the
penalties would not be as great due to the opportunities to optimize the
design of both the steam system (turbine, etc.) and the cooling system.
The total annual fuel penalty for the example above is 0.9 percent of
base fuel consumption, assuming that the power generated from month to
month is about the same. If the plant shown generates twice as much
power during the months of June through September compared to other
months, the annual backpressure penalty would approximately double to
0.4 percent, increasing the overall annual penalty to 1.1 percent of
base fuel consumption. Based on the analysis above, an annual fuel
penalty of 2 percent cf base fuel consumption would be conservative.
Loss of Generating Capacity
In the case of Plant no. 3713 described in the above discussion of fuel
requirements, the loss cf generating capacity imposed by a closed-cycle
cooling system would be the sum of the fan power and pump power require-
ments (0.7X) and the maximum backpressure penalty (2.IX), or a total of
2.8X of nameplate generating capacity. While the direct effects of
these penalties would be felt as lost generating capacity only when the
demand for generation and climatic conditions coincide to actually limit
407
-------
Figure B-VIII-15
TURBINE EXHAUST PRESSURE CORRECTION FACTORS (EXAMPLE/ PLANT NO0 3713)
o
00
Throttle Flow
1.5 x 10 lb/hr
2.5 x 10 IbAr
3.2 x 10
4.2 x 10 lb/hr
4.4 x 10
9 -P a»
*• G fO W
•H 05 (0
-------
Table B-VIII-9
ENERGY (FUEL) CONSUMPTION PENALTY DUE TO INCREASED TURBINE BACKPRESSURE
FROM CLOSED-CYCLE COOLING SYSTEM***
Example calculated for plant no. 3713
Month
J
F
M
A
M
J
J
A
S
O
N
D
Dew Point
Temp., F
32
32
36
46
56
64
67
67
61
50
39
32
Air
Temp. , F
42
43
50
59
68
75
78
77
71
61
50
42
Wet Bulb
Temp. , F
38
39
43
52
60
68
70
70
64
55
45
38
Condenser Out-
let Temp.,°F
68
69
73
82
90
98
100
100
94
85
75
68
Condensing
Temp. , F
73
74
78
87
95
103
105
105
99
90
80
73
Backpressure,
in of Hg
0.82
0.85
0.97
1.29
1.66
2.11
2.24
2.24
1.88
1.42
1.03
0.82
Fuel Penalty*
% of base
0.1**
0.1**
0.0
0.0
0.1
0.5
0.7
0.7
0.3
0.2
0.0
0.1**
Annual Average 0.2
** Note: This plant normally reduces the flowrate of cooling water in the winter to
minimize this type of penalty, therefore flowrate reduction with the closed-
cooling system is also assumed to eliminate the penalty during the winter months,
* Notes Assumes no penalty for once-through system, which is probably the case for
plant no. 3713. Some penalty for once-through systems could occur for other
plants during the summer months.
*** Note: The values given in the table are computed from mean values for each month. The
maximum backpressure penalty for which the cooling ststem would be designed to
operate would be base on the wet bulb temperature which would be exceeded no
more than 5% of the time duringQthe three months of summer. For plant no. 3713,
this wet bulb temperature is 80 F and the maximum backpressure penalty is 2.1%.
-------
generation to below nameplate capacity, the probability of such an
occurrence must be considered in system planning leading to the
construction of replacement generating capacity.
The economic analysis of the cost involved in installing cooling devices
on the circulating water systems assumed average site conditions. At
any particular station, costs will be affected by specific conditions
existing at the site. Seme of the more important factors are the
following:
1. Cost of needed land
2. Layout of existing structures in plant
3. Design pressure of existing circulating water system
U. Soil conditions at the site
5. Site geology and topography
6. Replacement generating capacity cost
7. Power requirements of system
8. Cost of connecting unit, including loss of unit's capacity
9. Related changes required within the station
10. Reduction of non-water quality environmental impacts
Non-Water Quality Environmental Impact of Control and Treatment
Technology
General
The potential non- water quality environmental impacts which could
influence type of system selected or which must be minimized in certain
cases include these listed below.
1. Drift, resulting in salt deposition on surrounding areas.
2. Fogging, visual impact and safety hazards.
3. Noise levels unacceptable to neighbors.
4. Height, creating aviation hazards.
5. Water consumption by evaporative systems.
6. Aesthetic considerations, visual impact of cooling device.
410
-------
The influence of the majority of these factors on the selection and cost
of the installation of these cooling systems is summarized in Table B-
VIII-10, with a detailed discussion below of each factor included in the
table.
Size of Plant
The use of natural draft towers is normally limited to new units of 500
MW or greater. While towers have been built for smaller units, the
mechanical draft tower would probably be more economical for older,
smaller units. The size and number of towers would be related to the
size and number of units served.
Relative Humidity
Natural draft towers are limited for practical purposes to localities
where the relative humidity exceeds approximately 50%. The lower
humidities result in prohibitively tall towers to provide sufficient
natural air flow through the tower.
Land Requirements
The land area for installation of cooling systems varies widely, as
indicated on Table B-VIII-10. Obviously, cooling ponds will need large
areas, and can only te considered where such land is economically
available. The tower systems also require significant amounts of land.
The mechanical draft tower cell for medium size plants is on the order
of 21 x 12 meters (70 x 40 ft). These cells are placed side by side to
make up the tower, which can be as much as 183 m (600 ft) long,
depending on capacity required. For a single tower installation,
anywhere from 30 to 60 meters (100 to 200 feet) of clear area is
required around the tower to avoid interference of surrounding struc-
tures on tower performance. This means that from 3 to 6 times the tower
plan area is required. When two or more towers are necessary, the
separation between towers must be 120 to 180 meters (400 to 600 feet) to
avoid interference between towers. Total area required for two towers
would be 4 to 7 times the tower plan area.
Reference 52 presents the following discussion of recirculation and
interference as related to tower placement.
The problems most usually encountered on large mechanical draft
industrial towers affecting the entering wet-bulb temperature are
recirculation and interference. The former is a pollution of the inlet
air by a tower's discharge vapors, and the latter is pollution of the
inlet air by an adjacent tower or other heat source. These problems are
411
-------
Factor
Size of Plant
Relative Humidity
TABLE B-VIII-10
EFFLUENT HEAT
APPLICABILITY OF CONTROL AND TREATMENT TECHNOLOGY
Mechanical Draft
Wet Cooling Tower
No limitation
No limitation
Natural Draft
Wet Cooling Tower
Greater than 500 MW
Generally limited to areas
of the country having an
average relative humidity of
greater than 47%.
Surface Cooling
(Ponds, Canals, etc.)
No limitation
No limitation
Mechanical Draft
Dry Cooling Tower
No limitation
No limitation
Land Area
Drift
70 ft. wide x 150 - 600 ft.
long (depending on plant size) ;
separation for multiple towers
400-600 ft.; clear area of
100 to 200 ft. required
around perimeter of tower area.
Current performance - less
than .03% of circulating flow;
anticipated improvement to less
than .005%; potential problem
in brackish or salt water areas.
350 - 550 ft. diameter plus
100 ft. open area around tower;
nuclear plant-tower must be
distance equivalent to height
away from reactor; 1/3 reduc-
tion of land area possible
with fan-assisted type tower.
Current performance - .005% of
circulating flow; one tower
under construction guaranteed
to be less than .002%; poten-
tial problem in brackish or
salt water areas.
1-3 acres per Kw of capacity
depending on climatic conditions;
use of spray modules reduces
land requirement by approximately
a factor of 10.
Applicable only with use of spray
modules; drift only in immediate
area of pond, canal, etc.
Higher than land require-
ments of mechanical draft
wet cooling tower.
None
Fogging
Noise
Potential local problem depend-
ing on location s climatic con-
ditions; reduction of fogging
possible with parallel-path wet/
dry type tower.
Potential problem only if
adjacent to sensitive area;
can be reduced by attenuation
devices.
Little anticipated at ground
level.
Less serious than mechanical
draft towers, but still poten-
tial problem if very close to
sensitive area; noise can be
attenuated.
Potential local problem depending
on location s climatic conditions.
None
None
Potential problem only if
adjacent to sensitive area; can
be reduced by attenuation devices.
Height
Water Consumption
No limitation
Up to 0.7 gallons per Kw hour
produced.
350-600 ft.; potential aviation
problem in specific locations;
comply with FAA restrictions.
Up to 0.7 gallons per Kw hour
produced.
No limitation No limitation
Up to 1.1 gallons per Kw hour None
produced; includes natural evap-
oration from surface.
Energy Requirements
Max. Wind Velocity
Foundation Require-
ments
Turbine Back Pres-
sure (Present units
limited to 5 in. Hg)
Aesthetic Consider-
ations
Fan power - 5-13 MW per million
GPM of circulating water; pump-
ing power - 7-12 MW per million
GPM of circulating water.
No limitation
Pumping power - 10-15 MW per
million GPM of circulating water;
no fan power required.
Pumping requirements vary with
plant conditions; spray modules
generally 75 HP per unit.
Current design -120mph @ 30ft. elev. No limitation
No limitation
Greater than 3000 psf soil bear- Greater than 6000 psf bearing
ing value or equivalent with piles, value or equivalent with piles.
Applicable to all plants;penalty Generally applicable only to Applicable to all plants; penalty
for operation at back pressure plants above 500 MW; penalty for for operation at back pressure
above original design. operation at back pressure above above original design.
original design.
Visual plume.
Visual plume; size ancl height.
No limitation
Total power requirement - .02-.08 MW
per installed MW capacity.
No limitation
Greater than 3000 psf soil bearing
value or equivalent with piles.
Not applicable to existing plants;
results in back pressure of 8-15 in.
Hg during summer months ; new plants
will recpaire turbine re-design.
No limitation
-------
nonexistent on hyperbolic towers because of the height of vapor
discharge.S2
The magnitude of recirculatioa is dependent primarily upon wind
direction and velocity, tower length, and atmospheric conditions. Other
factors are fan cylinder height and spacing, exit air velocity, tower
height and the density difference between exit air and ambient air.«
A longitudinal wind tends to carry discharge vapors along the tower and
the first few cells will not be seriously affected. However, from the
initial downwind point of entry into the louver face or faces, the
effect of recirculaticn becomes increasingly severe along the length of
the tower. Therefore, as tower length increases, the more damaging a
longitudinal wind can become.sz
A broadside wind causes no recirculation on the windward side of the
tower. Recirculation is greatest towards the midpoint on the leeward
side. It diminishes towards the ends because of fresh air flow around
the ends of the tower. High stacks and maximum space between stacks
serve to reduce the broadside recirculation effect in proportion td the
ratio of this free space area to the lee side louver area of the
tower.52
It is apparent that recirculation is primarily a function of tower
length. Normally, placement of single towers with ambient winds in a
longitudinal direction is recommended for tower lengths up to 200 to 250
feet. For tower lengths greater than this, more rigorous study of the
aforementioned factors affecting the circulation is required to
determine the most suitable orientation. When tower length exceeds 300
to 350 feet, strong consideration should be given to splitting into
multiple units. The problem then becomes more a matter of locating the
units to minimize interference.52
The principal objective in arranging a multiple tower installation is to
orient the units for minimum recirculation within themselves and minimum
interference between each other, particularly during the high capability
requirement periods. No set rules can be given for orientation of
mulitple units, but generally, it can be stated that as the number of
units increases, the broadside arrangement tends to be more favorable
than longitudinal. Each installation should be analyzed for orientation
within the prescribed real estate limitations with respect to the
following factors: (1) number of towers in system, (2) number of cells
per tower, (3) cell length and height, (4) height and spacing of stacks,
(5) discharge air velocity and density, (6) ambient atmospheric
conditions, and (7) prevailing wind rose for high wet-bulb hours.52 See
Figures B-VIII-16, 17 for possible broadside and longitudinal multiple
tower orientations.
The natural draft tower, which varies in diameter from 108 to 168 meters
(350 to 550 feet) normally requires a clear area 30 m (100 feet) wide
413
-------
X
Prevailing wind-rose for
high wet-bulb hours
Figure B-VIII-16
BROADSIDE MULTIPLE TOWER ORIENTATION
Tower No. 2 placed typically in location a,b, or c
relative to Tower No. 1 and the wind-rose
414
-------
in
Figure B-VIII-17
LONGITUDINAL MULTIPLE TOWER ORIENTATION
Tower No. 2 placed typically in location a,b, or c
relative to Tower No. 1 and the wind-rose
Prevailing wind-rose for
high wet-bulb hours
-------
around it perimeter to allow for construction. This amounts to a land
area twice the plan area of the tower. For nuclear units, the tower
must be separated from the reactor buildings by a distance equal to its
height.
If land space is restricted, any number of solutions may be used.
Rearrangement of mechanical draft towers to fit space, or use of a
mechanical draft tower of a different configuration, such as round,
might be used. Natural draft towers might require less land. A single
large tower might take the place of two smaller, more economical ones.
The fan-assisted natural draft tower appears to be a system with minimum
land requirements. One existing plant, located in an urban area, is
installing one of these towers in a former parking lot. An analysis of
land estimated to be required for evaporative cooling towers at eight
nuclear plants indicates that 20 acres/1000 megawatt generating capacity
would be the maximum amount required.
The Federal Power Comirission, National Power Survey (1964) puts the land
requirement for mechanical draft evaporative towers at 1,000 to 1,200
square feet per megawatt including area required for spacing.
Furthermore, natural draft evaporative towers would require 350 to 400
square feet per megawatt. For a 1,000 megawatt capacity tower requiring
1,200 square feet per megawatt, approximatley 28 acres of land would be
required.
Due to the variations in heat rate, climatic factors, etc. from
site-to-site, 28 acres per 1,000 megawatts generating capacity should be
sufficient land for any plant to apply closed-cycle evaporative cooling
towers. In many cases where less than this amount of land is available,
it would still be practicable to apply evaporative cooling towers due to
the conservatism of the 28 acres per 1000 megawatt assessment and,
further, due to the possible practicability of natural draft or other
systems at the site. Many plants which do not have land immediately
available for evaporative cooling systems could make sufficient land
available by shifting, to some degree, present uses of land at the site
and by acquiring the use of neighboring land. Land requirements for
other uses would depend on the types and relative amounts of fuel,
method of ash disposal, and other factors in addition to plant
generating capacity.
Reference 370 addresses the land requirments for projected 3,000-
megawatt plants as compared to 1,500-megawatt plants. The land required
for a powerhouse containing three 500-megawatt units is in the range of
3 to 4 acres; for three 1,000-megawatt units the range is 6 to 7 acres.
These figures include the service bay, but not space for equipment and
facilities outside the powerhouse. Electrostatic precipitators, stacks,
walkways, drives, and parking areas immediately adjacent to the
powerhouse would be about 2-3 acres for three 500-megawatt units and 6-7
acres for three 1000-megawatt units. Sulfur dioxide removal equipment
would add as much on 2-4 acres. Coal-fired plants require inactive coal
416
-------
storage in an amount to supply 45 - 120 day's burn at the total plant
capacity. A typical coal-storage yard to provide 90 days supply at a
3,000-megawatt plant would require 40 acres and the coal pile would be
40 feet high. The switchyard area requirements for a typical 3,000-
megawatt plant with 500-kv-transmission voltage would be in the range of
10-15 acres. The transmission lines connecting a typical 3,000-megawatt
plant with the existing transmission system at 500 kilovolts would
occupy rights-of-way cf from 100 to 150 acres per mile. On-site ash
disposal for a 3,000-megawatt coal-fired plant (assuming 35 year useful
life and 50% capacity factor) would require 300 to 400 acres with ash
piled to a depth of 25 feet to store all the ash developed during the
life of the plant. Limestone-injection systems for controlling sulfur
dioxide emissions would double or triple the volume of ash produced
while the system is in operation. In some cases off-site disposal of
ash would be an available alternative to on-site disposal.
Other facilities that would require significant amounts of land include
rail, barge and truck terminals for coal-fired and oil-fired plants, oil
storage for oil-fired plants, and an exclusion area for nuclear plants.
In summary, a 3,000-megawatt plant would require, if coal-fired, 200 to
1200 acres, nuclear 200-400 acres, oil-fired 150-350 acres, and
gas-fired 100 to 200 acres, assuming en-site storage of coal and oil,
pipeline delivery of gas with same on-site storage, and on-site coal-ash
disposal.
Inspite of the ingenuity of the cooling tower engineer, there may be a
significant number of units or plants where addition of a cooling tower
would not be practicable. In the case of a plant in a location where
the surrounding land is already highly developed, the cost of available
land may be high, and it might be necessary to remove any existing
structures from the land, once it was purchased. Secondary effects,
such as fogging or drift could result in complaints from surrounding
neighbors, as well as a requirement to repair resulting damage. Noise
levels from the tower might be unacceptable to the neighbors. The
number of plants located in the 50 largest metropolitan areas amounts to
some 15X of the total (see Table IV-2) . An equal number are probably
located within the city limits of small towns, particularly in the Great
Plains states. The practicality of installing cooling towers will
depend on the local conditions at each plant. One may be surrounded by
high rise buildings, while the next may be adjacent to a vacant city
block. Another plant may be in a heavy industrialized area, whereas
another would be in a semi-residential area where the tower noise aspect
may be more sensitive. Land values will vary greatly, from possibly
$250 per hm2 ($10,000 per acre) in small towns to $25,000 per hmz
($1,000,000 per acre) in the center of a large metropolitan area.
Nuclear plants would not normally be seriously affected by land area
limitations for two reason. They are not located in metropolitan areas,
and the required exclusion area normally provides sufficient area for
417
-------
cooling system installation unless topographic conditions are
unfavorable. However, when a nuclear plant goes from open to closed
system cooling, the lew-level radwaste system normally needs to be
upgraded. With the open system, low-level radwastes are added to the
circulating water for dilution to meet standards for the discharge of
radioactive materials. The blowdown stream may not be sufficient for
dilution, forcing installation of a new low-level radwaste system, cost
of this has been estimated to be several million dollars at one nuclear
plant.
Additional Installation Costs
The cost of installation of cooling towers can be significantly higher
at sites with adverse local conditions. Land with insufficient bearing
strength (see Table B-VIII-10) would require piling, or Use of
mechanical draft towers instead of natural draft, or both. Conversely,
in hilly terrain, extensive, and expensive, excavation into hard rock
might be required. Even if only piping has to be excavated into rock,
the cost is increased significantly. Reference 250 contains a detailed
study of tower installations at such a site. Proximity of stations to
earthquake faults means additional structural strength will be required,
particularly in natural-draft towers. Towers in Florida and the
Southeast require hurricane-resistant design. Other factors of a
specific local nature at other sites will increase the cost of
installation of cooling towers.
Addition of a cooling system to an existing plant will require breaking
into existing structures, piping or tunnels. Suitability of existing
structures used in the new system will have to be evaluated. Will the
structures withstand the new pressures? Will it be easier to modify the
condensers for increased pressures, and connect directly to them, or
should the cooling system be connected at the present intake and
outfall? These are questions that must be answered during design of the
cooling system. The current layout, pump size, and location of intake
and outfall structures will influence the required decisions.
The plant or unit will be shut down during the final period of
installation when the new system is connected to the unit. The unit's
generating capacity is lost during this period. In some cases the
connections can be made during the annual scheduled overhaul. In other
cases extended downtiire may be required, maybe as much as three or four
months. Costs would vary accordingly. The dollar value of these costs
will vary from plant to plant. Some costs for the few plants currently
involved in installing cooling systems are given in Table B-VIII-1.
Drift
Water vapor and heated air are not the only effluents from a cooling
tower. Small droplets of the cooling water become entrained in the air
418
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flow, and are carried out of the tower. These drops have the same
composition as the cooling water, i.e., they contain the same
concentration of dissolved solids and water treatment chemicals. The
water may evaporate from the drops, leaving the solids behind, or the
drops may impinge upon the surrounding structures or terrain. The
chemicals and dissolved solids add a chemical load to the air and
surrounding terrain that must be taken into account.
some data on estimated solids in drift from cooling towers are shown in
Table B-VIII-11. This was taken from the final environmental statements
for a number of nuclear stations. There is obviously a large variation
in the assumed drift rates. All these values are mentioned in the
literature, with the lower values the more recent. Another factor is
the concentration of solids in the drift. It is obvious that the
proposed towers at Plant no. 1209, operating on sea water, will have a
higher solids loss through drift, as indicated in Table B-VIII-11.
The amount of drift from any tower is primarily a function of the tower
design, and the drift eliminators in particular. The total losses to
drift are normally expressed as a percentage of the flow through the
tower. Until recently, drift losses of less than 0.2% were guaranteed.
MO NOW cooling tower manufacturers are guaranteeing much lower drift
losses. Losses of 0.02% are considered high. Several new towers have
been awarded based on drift guarantees in the range of 0.002 - 0.005
percent of cooling water flow. A number of tests, summarized in a
report for EPA by the Argonne National Laboratory, 2««, showed that
drift from mechanical-draft towers averaged 0.0053J, while that from
natural-draft towers might average half of that, or 0.0.025%. With a
0.01X drift eliminater, an estimated 1 ton of salt per day would be
deposited downwind of a 1,000 megawatt nuclear unit.
While better design is partially responsible for the lower drift rates,
better measurement techniques are equally, if not more important in
establishing drift rates. With the older, less sophisticated methods,
manufacturers were less sure of the actual drift rates, resulting in
high rates for guarantees.
With the greater emphasis on environmental protection, it became
necessary to measure drift more accurately to determine the amount of
solids leaving the tower to end up as fallout on the surrounding terrain
or suspended in the atmosphere. Currently at least two systems are
available. The first, the Pills System, is for continuous monitoring of
drift. The second is a system for sampling the drift intermittently.
The Pills (Particle Instrumentation by Laser Light Scattering) system is
an electro-optical system for monitoring the drift.
The intermittent sampling system is an isokinetic device. The discharge
air is sampled at its natural flow velocity as implied by the term
"isokinetic11. One device uses a sampling tube filled with warmed glass
419
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TABLE B-VIII-11
SOLIDS IN DRIFT FROM COOLING TOWERS
Plant
No.
1209
1311
3608
6506
3940
0109
3635
Size
MW
1320
1644
873
850
872
1722
821
Cooling System
(Type)
Mech. Draft
(salt water)
Mech. Draft
Nat. Draft
Nat. Draft
Nat. Draft
Mech. Draft
Mech. Draft
Drift
(% Flow)
0.1
0.2
0.0025
.01
.01
.01
.005
Solids in Drift
Ibs . /yr .
3.8 x 107
6 x 105
1.1 x 10^
4.0 x 105
9.0 x 104
10.5 x 105
4.7 x 104
Ibs/KWH 3
(installed)xl°
3.3
.042
.14
.054
.012
.070
.0065
ro
o
-------
beads. A vacuum system pulls the sample into the tube where the drift
impinges on the glass beads. The moisture evaporates, leaving the
solids behind. Weighing of the sample tube determines the solids
collected. This, plus a knowledge of the solids contents of the water,
permits calculation of the amount of drift. This device supersedes a
number of isokinetic devices considerably more cumbersome, and pf
doubtful accuracy.
Drop size is another problem. Sensitive paper, and more recently, the
Pills system **° are used to measure drop sizes of 100 micron or larger.
Several tests by one manufacturer indicate that the drops accounting for
85X of the mass of the drift have diameters greater than 100 microns,
with less than 1% over 500 microns.
The drift from cooling towers, mechanical draft in particular,
potentially can create serious problems, depending on the salts and
chemicals in the cooling water. Drift coating insulators on the
transformers and switchyards can possibly lead to leakage and insulator
failure. Corrosion of metallic surfaces, deterioration or discoloration
of paint and killing of vegetables have been noted. Thus, the
minimization of drift is an important design feature of the cooling
tower.
The use of brackish or seawater in cooling towers aggravates the drift
problem due to the high concentration of salt in the water. Fifteen
saltwater cooling towers and in use or planned for steam electric
powerplants. Numerous factors affect the dispersion and deposition of
drift from these towers (See Table B-VIII-12)-38S Proper location of the
towers with respect to the plant buildings and switchyards can avoid
most of the problems encountered with highly saline drift. The rate of
drift fallout is related to the distance from the tower. (See Figure B-
VIII-18) . This is particularly true for mechanical draft towers which
discharge at relatively low levels. Tests . at one installation have
shown that up to two-thirds of the drift hits the ground in the first
400 feet from the tower and substantially all drift droplets will reach
the ground in the first 1,000 feet. In many instances therefore, drift
impact can be reducted by location of the tower so that the bulk of the
drift is contained within plant boundaries.
Wistrom and Ovand'63 concluded, from their study of field experience
during the last 20 years where salt or brackish water has been used in
cooling towers, that "cooling tower drift effects in the environment are
localized and that beyond same reasonable distance that is usually
within the plant site boundary, drift does not significantly affect the
environment" -
The fact remains that this salt will be deposited on the surrounding
terrain. whether or not this influences the environment, i.e.,
vegetation and ground water salinity, will depend on the increase over
the natural deposition of salt on the surrounding terrain. The natural
421
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Table B-VIII-12
FACTORS AFFECTING DISPERSION AND DEPOSITION OF DRIFT
FROM NATURAL-DRAFT AND MECHANICAL-DRAFT TOWERS 385
Factors associated with the design
and operation of the cooling tower
Factors related to atmospheric
conditions
Other factors
ro
ro
Volume of water circulating in the
tower per" unit time
Salt concentration in the water
Drift rate
Mass size distribution of drift
droplets
Moist plume rise influenced by
tower diameter, height and mass
flux
Atmospheric conditions including
humidity, wind speed and direction,
temperature, Pasquill's stability
classes, which affect plume rise,
dispersion and deposition.
Tower wake effect which is especi-
ally important with mechanical
draft towers
Evaporation and growth of drift
droplets as a function of
atmospheric conditions and the
ambient conditions
Plume depletion effects
Adjustments for
non-point source
geometry
Collection efficiency
of ground for drop-
lets
-------
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£
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o
k.
o»
o
UJ
o
Q.
<
(O
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UJ
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(f
100
10
DIFFUSION
METHOD
BOSANQUET
METHOD
II 111
I I I
HOSLER
METHOD
I I I 1
O.I
1.0 10 100
DISTANCE DOWNWIND, kilometers
Figure B-VIII-18
Ground-Level Salt Deposition Rate From A Natural-Draft Tower
As A Function Of The Distance_Downwind. A Comparison Between
Various Prediction Methods
385
423
-------
salt load, particularly along ocean coasts exposed to continual wave
action, can be fairly high. If the tower drift results in a salt load
of only a few percent of this natural salt deposition rate, the effect
would probably be minimal.
A summary of the state-cf-the-art of saltwater cooling towers (Reference
No. 385) concluded that "although the environmental effects of saltwater
cooling towers vary from case to case depending upon the sensitivity and
diversity of local conditions, experience with existing salt water
cooling towers indicates that the environmental problems would be
confined up to several hundreds meters from the cooling tower.
Environmental impact on the biota, bodies of fresh water, soil salinity
and structures is difficult to detect at the levels of the long-term
average in coastal areas. The direct experimental data available about
the enviornmental effects are aparse. Most of the environmental impact
predictions are based upon research studies pertinent to the coastal
environment, which may or may not be applicable for salt water cooling
towers in other locations. Most of this available information is
descriptive in nature and does not permit a correlation between the
airborne salt concentration or deposition rate and environmental
effects."
Adverse environmental impacts due to drift are not a national-scale
problem. Technology is availab-le to integrate a low drift requirement
into the overall tower design at moderate cost. In addition, alternate
cooling systems selection and proper location of the tower with respect
to prevailing winds and surrounding land uses can also be used to meet
stringent drift requirements. New plants have the additional
flexibility of site selection to help minimize this problem.
Fogging
Fogging is one of the most noticeable of the possible side effects of
the use of evaporative cooling devices. Fog is produced when the warm,
nearly saturated air from the cooling facility mixes with the cooler
ambient air. As the warm air becomes cooler, it reaches first
saturation, then supersaturation with respect to water vapor content.
When this occurs, the vapor condenses into visible droplets, or fog.
The psychrometric chart in Figure B-VTII-19 shows representative con-
ditions through which the air-water mixture can pass to create fog. The
condition at point B is that of the ambient air. As this air leaves the
tower, (point A) it mixes with the colder, less humid ambient air
following the dotted line which lies largely in the portion of the chart
which represents a condition where the air contains more moisture than
it can contain at 100% saturation. In this condition condensation
producing fog can occur, although normally some supersaturation is
necessary. As more mixing occurs, the air condition eventually returns
to point B.
424
-------
Saturation
(100% RH)
4J H
•H
1° £
(0
•H M
•H tJ
U
S -0
ftH
to\
80% RH
120
Dry Bulb Temperature ( F)
MODIFIED PSYCHROMETRIC CHART
(From Reference 128)
FIGURE B-VIII- 19
425
-------
The development of fog by cooling devices is primarily dependent on the
local climatic conditions. The areas normally susceptible to cooling
tower fog are those in which natural fogs frequently occur. EG & G,
Inc. in a report for EPA, 2i«, defines three levels of potential for
fogging, as listed below.
a« High Potential; Regions where heavy fog is observed over 45
days per year, where during October through March the maximum mixing
depths are low (400-600 m) , and the frequency of low-level
inversions is at least 20-30%.
b. Moderate Potential: Regions where heavy fog is observed over 20
days per year, where during October through March the maximum mixing
depths are less than 600 m, and the frequency of low-level
inversions is at least 20-3035.
c. Low Potential; Regions where heavy fog is observed less than 20
days per year, and where October through March the maximum depths
are moderate to high (generally greater than 600m).
Using this criteria and several meteorological references, EGSG has
developed the map shown in Figure E-VIII-20, indicating the fogging
potential of locations within the United States.
The length of the expected fog plume can be estimated from
the following equation: 9S
Xp = 5.7(Vg)i«2 (438Vm)»»2 (Tge-Tgi) t«z (Tp-Tgi)-»«z
Where Xp = visible plume length, ft
Tg = air or plume temperature, °C
Tp = temperature at end of visible plume, °C
Vw = wind speed, ft/sec
Vg = total rate from tower m^/hr (gas evaluated at 20°C)
i = tower inlet
e = tower exit
In order for fogging to create an impact it most exist in close
proximity to a land use with which it interfers such as a major
residential, commercial or industrial activity. As can be seen from
Figure B-VIII-20, most of the major U.S. residential, commerical and
industrial centers do not lie in the area of high fogging potential.
426
-------
ro
J SLIGHT POTENTIAL
HIGH POTENTIAL
MODERATE POTENTIAL
Figure B-VIII-20
GEOGRAPHICAL DISTRIBUTION OF POTENTIAL ADVERSE EFFECTS FROM COOLING TOWERS,
BASED ON FOG. LOW-LEVEL INVERSION AND LOW MIXING DEPTH FREQUENCY.
(From Reference 219)
-------
Furthermore, local meteorology and the configuration of the source and
its surroundings must permit a downwash condition to obtain fogging.
These will not usually exist if the cooling tower if properly designed
and located.
In view of these factors a conservatively high estimate of the plants
that would be concerned with fogging problems resulting from the
installation of closed cooling systems is less than 5 percent of the
total plants. Moreover, fogging could only be of concern at the plants
for small fractions of the total operating time.
The fog plume from a mechanical draft tower is emitted close to the
ground, and under appropriate conditions, can drop to the ground. Under
these conditions the fog can create a serious hazard on nearby highways.
If the fog passes through the switchyard, insulator leakage problems can
be encountered. Thus, in addition to being highly visible, the fog
plumes create safety hazards and accelerate equipment deterioration.
Careful placement of the towers will eliminate most of the problems, if
placement is unsatisfactory, or creation of hazards is still expected,
the use of a wet-dry tower can significantly reduce the plumes. In the
wet-dry tower (typically) ambient air is heated from point B (See Figure
B-VIII-19) to point C in the dry section. Air from the wet section
(point A) and dry sections are mixed and exhausted at a condition
represented by point A1, In mixing with ambient air (dotted line)
subsaturated conditions exist and fogging cannot occur. Two towers of
this type are currently on order or under construction for large
generating plants in the U.S. It should be noted ,however, that this
type of tower is more costly than the conventional wet-type tower
(approximately 1.3 to 1.5 times the cost of a conventional tower). This
would add an increment of approximately 0.15 mills/KWH for plume
abatement for a large, modern base-load unit. Other possible techniques
of plume abatement includes increasing the mechanical draft stack
height, heating tower exhaust air with natural gas burners, installing
electrostatic precipitatcrs or mesh at the tower exit, and spraying
chemicals at the tower exhaust.
Another possible solution is to use a natural-draft tower. The plumes
from these towers are emitted at altitudes at 90 to 150 meters (300 to
500 •) above the tower ground level, and there is little possibility of
local fog hazards, as plume is normally dispersed before it can reach
the ground. One hazard that might arise would be to aircraft operation,
although plumes are normally localized. The use of natural draft
cooling towers in high potential fog areas seems to be an accepted
practice, as indicated in Figure B-VIII-21 2«3, which shows location of
75% of the natural draft towers expected to be constructed through 1977.
Note that the majority of them are in the eastern area of high fog
potential. Under freezing condition the fog may turn to ice upon
contacting a freezing surface. The ice thus formed is commonly called
rime ice. This is a fragile ice, and breaks off the structure before
428
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Figure B-VITX-21
LOCATION OF NATURAL DRAFT COOLING TOWERS THROUGH 1977
(From Reference 283)
-------
damage occurs from the additional weight, except on horizontal surfaces.
Here again, although it is mentioned in the literature, the problem is
considered 'to be insignificant.
The potential for modification of regional climate exists, but has not
been verified to date. The Illinois Institute of Technology Research
Institute in its report 283, for EPA on the field tests at Plant no.
4217 in Pennsylvania determined that the effects were minimal. This
plant released approximately 0.63 m3/s (10,000 gpm) and 126 KG/min (120
x 106 BTU/min) to the atmosphere when operating at 1440 MW, 80% of its
design capacity. Two natural draft towers are installed at Plant no.
4217. A review of weather station records at stations located 13 to 51
kilometers from the plant resulted in "a suggestion of precipitation en-
hancement". Initiation of cloud cover occurred rarely, and only
preceded natural development of cloud cover. The cooling tower plume
would merge with lew stratus clouds when they were at an appropriate
elevation.
The current "state-of-the-art" in meteorology has not progressed to the
point where the effects of large thermal releases to the atmosphere can
be quantitatively evaluated. Improvements in meteorological techniques
currently in progress will undoubtedly result in quantification of these
effects. A number of meteorologists indicate that thermal emissions to
the atmosphere could have significant effects on mesoscale phenomena,
where mesoscale refers to a scale of from 1 to 50 kilometers. A
comparison of some natural and artificial energy production rates is
shown in Table B-VIII-13. 367 It is obvious that some of our arti-
ficially produced energy rates are equal in magnitude to those of
concentrated natural production rates.
It is possible that these thermal discharges may have a "triggering"
effect on a much larger phenomena, such as thunderstorms, tornados, or
general cloud development and precipitation. This could prove
beneficial if the triggering could be adequately controlled, and
possibly disastrous if control was not possible.
Although no regional climatic changes have been noted to date, this does
not mean the possibility does not exist. With larger and larger
stations being built which reject their heat to the atmosphere through
wet cooling towers, it becomes evident that this water must be added to
the rainfall at some location, wherever it may be, and that the
additional heat will influence the climatic conditions to some extent.
This probably falls into the category of weather modification, even
though it be unintentional, and is currently being investigated by
meteorologists.
With coal-fired or oil-fired plants, there is an additional factor in
relation to plumes. The stack gases of these plants contain varying
amounts of SO2, depending on the sulfur content of the fuel used and the
degree of flue gas desulfurization achieved. To the extent that the
430
-------
TABLE B-VIII-13
ENERGY PRODUCTION OP SOME NATURAL AND ARTIFICIAL PROCESSES AT VARIOUS SCALES (367)
Area
(m2)
Natural Production
Event
Rate
(W/m2)
Artificial Production
Type of Use
Rate
(W/m2)
CO
5 x 1014
1012
10
8
Solar energy absorption
by atmosphere
Cyclone latent heat
release (1 cm rain
per day)
Thunderstorm latent heat
release (1 cm rain per
30 min)
Tornado kinetic energy
production
25
200
5000
Man's ultimate energy
production
Northeast U.S. ultimate
production (10** people,
20 KW each)
Super energy center or
city
Dry cooling tower for
1000-MW (e) powerplant
0.8
2.0
1000
105
-------
stack gases and the cooling tower fog plume became intimately
intermixed, the fog will interact chemically with the S02, forming sul-
furic acid. This is a corrosive acid, and settlement on surrounding
buildings will accelerate deterioration. Vegetation will also be
affected by this "acid fog". The relationship between the two
discharges should be such as to minimize their intermixing.
In addition to the basic meterological considerations, two other factors
should be considered where stack and cooling tower plume intermixing
must be minimized, as follows: (1) location of the cooling towers in
relation to the stacks, and (2) the buoyancy of the plumes as related
to the stack and tower- heights. A further consideration is that in
cases when the plumes would intermingle, they would not necessarily
become intimately mixed. In the case of the study of Plant no. 4217,
cited previously, measurements suggested that the plumes were not
uniformly mixed and may have been merely co-mingled.
In any case, since hundreds of evaporative cooling towers have been
operated over many years at coal-fired and oil-fired stations scattered
across the United States without significant numbers of reports of
adverse impacts due to "acid fog", the engineering and other design
practices employed should be adequate to assure that this problem does
not arise in subsequent applications of evaporative cooling towers.
In summary, potential adverse impacts due to fogging are not a national-
scale problem. In the relatively few instances where it could be a
problem, technology is available, at a moderate incremental cost, to
control or eliminate fogging to the degree required by the related
considerations.
Noise
Noise created by the operation of cooling towers, results from the large
high-speed fans. The enormous quantitites of air moving through
restricted spaces, and large volumes of falling water contacting the
tower fill and cold water basin. Mechanical draft towers will generate
higher noise levels than natural draft towers. At sites where the
incremental noise due to cooling towers might be a problem, it should be
considered in the design of cooling tower installations. A three step
procedure usually results in adequate coverage of this problem.
1. Establish a noise criteria that will be acceptable to the neighbors
within hearing range cf the proposed tower.
2. Estimate the tower noise levels, taking into account distance to
neighbors, location of the installation, and orientation of the towers.
3. Compare the tower noise level with the acceptable noise level.
432
-------
Only if the tower noise level exceeds the acceptable noise level need
corrective action be taken
cooling towers and powered spray modules produce some noise. The
noise from powered spray modules and natural draft cooling towers is
primarily from the falling water. In the mechanical draft wet tower
there is the added fan noise. In the mechanical draft dry tower there
is the fan noise and possible noise from high velocity flow of the water
through the cooling surface.
Since the powered spray modules are normally located in a canal, the
banks tend to direct the sound upward, and the bank surface can absorb
part of the sound. Their use to date has not created serious noise
problems.
The noise level, from cooling towers is of the samerorder of magnitude as
that in the rest of the station, and thus noise can be a problem in
noise sensitive areas. Every effort should be made to place these
structures away from potential sources of complaints. Sound levels
decrease with the square of distance from the source. Large flat wall
surfaces can direct sound into sensitive areas. At the same time, walls
and buildings can act as a sound barrier. Fan speeds can be reduced at
night when load is lowest and when ambient noise levels may also be
lowest. Proper attention to noise problems in tower design, selection,
and placement can avoid costly corrective measures.
If the above procedures are unable to reduce noise levels in the
affected areas to acceptable levels, sound attenuation can be done by
modification or addition to the tower. Discharge baffles, and
accoustically lined plenums can be used. Barrier walls, or baffles can
be erected. Adequate noise suppression is normally possible, but the
cost can be high. Good practices can minimize the expense involved in
noise suppression.
It is concluded that adverse impacts of noise is not a national- scale
problem. Technology is available at a moderate cost to reduce the noise
impact of cooling towers. In addition, alternate cooling system
selection and proper locations of the tower can be used at highly
sensitive sites. New plants have the further flexibility of site
selection to help minimize this problem.
Height
The height of natural draft cooling towers, up to 183 meters (600 ft)
results in a localized potential hazard to aircraft. Location of such a
tower would generally not be permitted in the approaches to an airport.
Other pertinent FAA restrictions and regulations would have to be
complied with. Aircraft warning lights would have to be installed on
the tower along with provision for servicing them. The height of
alternative technologies would not present hazards to aircraft.
433
-------
Consumptive Water Use
All evaporative heat rejection systems result in the consumptive use of
water. The primary consumption occurs as evaporation and drift. Even
the once-through system is responsible for consumptive use of water by
evaporation during the transfer of heat from the river, lake or ocean to
the atmosphere, the ultimate receiver.
Heat is transferred from the river or lake to the atmosphere by three
major means, radiation, evaporation, and conduction, with that by
conduction being small compared to the other two. The Edison Electric
Institute report entitled, "Heat Exchange in the Environment" a*, gives
a detailed analysis of these processes.
The closed systems, cooling towers and spray ponds, utilize the same
mechanisms, although their respective contributions may be much
different. Figure B-VIII-22, taken from a paper by Woodson, 3iar gives
a graphic representation of the percentages of heat transferred by each
process. In a report prepared for EPA, 104, some representative
consumptive use rates for a 1000 MW unit are shown (see Table B-VIII-
14) . Consumptive use varies from 1.3 to 2.1 times that of a river or
lake, depending on the type of closed system used.
Woodson, in his article, 318 gives a more detailed analysis, including
costs to make up for penalties inherent in the use of closed systems as
shown in Table B-VII1-15. Consumptive use, according to his figures can
be as much as 2.5 times that of a once-through system.
The amount of water consumed depends to some extent on the climatic
conditions existing at the site. Some of these factors and their effect
are shown in Figure B-VIII-23. 133 The use of cooling ponds results in
the highest consumptive use, since the total consumptive loss is equal
to the sum of the natural evaporation plus that due to heat rejection to
the cooling pond. The increment of consumption due to natural
evaporation is approximately the difference between the consumption of a
cooling pond and that of a natural lake or river. The consumptive use
of water in a natural lake of river is low, since the natural losses are
not charged against the power station, and in addition, a significant
part of the heat is transferred by radiation.
The dry-type cooling tower, as opposed to the wet-type cooling tower,
has essentially no consumptive use of water. The only consumptive use
would be losses from this closed system due to leaks.
In general, the replacement of a once-through cooling system with a
closed system will result in somewhat higher water consumption from a
broad environmental standpoint. This increase averages about 25% as
shown in the referenced tables and graphs, and only presents the
absolute difference in water consumed.
434
-------
OHCE-THROUGH
OR LAKE
COOLING
BASIN COOLING
WITH SPRAYS
WET COOLING
TOWER
WET/DRY
COOLING TOrfER
DRY COOLING
TOWER
RADIATION. AND CONDUCTION
EVAPORATION
i
RADIATION AND" CONDUCTION
EVAPORATION
j
I
RADIATION & CONDUCTJ,
EVAPORATION j
CONDUCTION
EVAPORATION j
CONDUCTION j
EVAPORATIO
I
1
1
CONDUCTION
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Figure B-VIII-22
HEAT TRANSFER MECHANISMS
WITH ALTERNATIVE COOLING SYSTEMS
(From Reference 318)
435
-------
TABLE B-VIII- 14
EVAPORATION RATES FOR VARIOUS COOLING SYSTEMS (Reference 104)
Cooling System
Cooling Pond (2 acres/MW)
Cooling Pond (1 acre/MW)
Mechanical Draft Tower
Spray Pond
Natural Draft Tower
Natural Lake or River
Evaporat
m-Vsec
.566
.453
.368
.360
.340
.266
. ion1
cfs
20.0
16.0
13.0
12.7
12.0
9.4
For a 1000 MWe fossil-fueled plant at 82 percent capacity factor average
annual evaporation (assume constant meteorological conditions).
436
-------
TABLE B-VIII- 15
COMPARATIVE UTILIZATION OF NATURAL RESOURCES
WITH ALTERNATIVE COOLING SYSTEMS
FOR
FOSSIL FUEL PLANT WITH
680 MW NET PLANT OUTPUT
(70 per cent annual load factor)
Once-through river or
lake cooling system
Alternative cooling systems
Basin cooling facility
Basin cool-ing with auxiliary sprays
Mechanical draft wet tower
Mechanical draft wet/dry tower
Mechanical draft dry tower
Natural draft wet tower
Gross
Generating
Capacity
KW
Net
Plant
Heat
Rate
BTU/KWH
Fuel
Input
Billions of
BTU/ yr . -
Coal
Consumption
10,000 btu/lb
tons/yr
Water
Consumption
( Evapor at ion)
Acre ft/yr
Land
Area
acres
BASE REQUIREMENTS
715,580
9,489
39,567
1,978,343
2,800
ADDITIONS TO BASE REQUIREMENTS
-
6,360
4,420
5.070
17,770
3,060
19
103
77
86
1,1?3
59
79
429
321
358
4,682
246
3,950
?1,450
16,050
17,900
?34,100
12,300
5,400
6,300
6,300
2,800
*(2,800)
6,300
1,000
500
15
15
6
15
OJ
*Denotes Decreased Requirements
(From Reference 318)
-------
2 ACKF.S/MW
1 ACfit/MW
MECHANICAL DRAFT C.7,
SPRAY PONDS
NATURAL DRAFT C.T.
NA1URAL LAKE OR RIVER
50 60
WET BULB TEMPERATURE <
WATER CONSUMPTION VERSUS
WET BULB TEMPERATURE
NAJUSAL LAKE 03
MECHANICAL DRAFT C.T.
SPRAY PONDS
NATURAL DRAFT C.T.
EO 60
RELATIVE HUMIDITY • %
WATER CONSUMPTION VERSUS
RELATIVE HUMIDITY
1 8 9 JO 11
WIND SPEED • MPH
12 13 14 1$
WATER CONSUMPTION VERSUS
WIND SPEED
GAL.Net KWH
1.2
1.0
2 ACRES MW
NATURAL LAKE OR RIVER
10 20
30 40 50 60 70
CLOUD COVER• %
60 90 100
WATER CONSUMPTION VERSUS
CLOUD COVER
CAL/Net KWH
I.I
t.O
.9
.6
.7
.6
.5
.4
.3
.2
.1
0
\
10 15
COOLING RANGE -°f
2 ACRES MW
1 ACRE MW
20
25
CAl/Net KWH
.60
1* 16 IB 20 ?? 71 76 J8 30 32 3< 36 38 40
COOLING HAI.Ct -°f
WATER CONSUMPTION VERSUS TEMPERA-
TURE RANGE FOR BODIES OF WATER
WATER CONSUMPTION VERSUS TEMPERATURE
RANGE FOR COOLING TOWERS
(From Reference 133)
FIGURE B-VIII- 23
WATER CONSUMPTION VERSUS METEOROLOGY AND COOLING RANGE
438
-------
present powerplants have been sited, in many cases, where the lack of a
reliable supply of quality cooling water has dictated the use of closed-
cycle evaporative cooling. In other words, where water is in short
supply/ the more-highly water consuming evaporative cooling systems have
been justified and legal rights to water consumption have been obtained
where required. In many states where water uses and consumers must
obtain legal rights to use or consume water. In some of these states
all water use and consumption rights have already been allocated but not
necessarily utilized. Rights can be bought and sold among users. Many
powerplants have rights to more water than they currently use or
consume. In some states powerplants have the power of eminent domain
over water rights, and are thereby authorized to appropriate all or a
part thereof to the necessary public use, reasonable compensation being
made.
Pollutants in Slowdown
In the closed cooling systems utilizing evaporative cooling, there is a
buildup of dissolved and suspended solids, including water treatment
chemicals, due to evaporation, which removes pure water, leaving the
above constituents behind. Without some control over this buildup,
scale and corrosion may occur, damaging the equipment and reducing its
performance. To prevent excessive buildup, a small percentage of the
water is continually removed from the circulating water system. This is
normally called "tower blowdown" or "blowdown". The water that is added
to replace this water, and the evaporative and drift losses, is known as
makeup. The amount of blowdown is dependent on two factors. The
primary factor is the avoidance of scale or other detrimental effects in
the circulating water system. Of secondary importance is
the quality of the blowdown water. The two types of scale normally
encountered are CaCO.3 and CaS04. The CaCO3 can be controlled by pH
adjustment, with sulfuric acid normally being used to lower the pH. The
CaS04 scale formation is avoided by maintaining the concentration of
CaS04 below saturation. The CaSOjf concentration is controlled by the
amount of blowdown. Thus the amount of blowdown varies with the
concentration of dissolved solids in the makeup water. The blowdown on
fresh water towers amounts to on the order of 2% of the total flow
through the tower. With some types of water, blowdown rates of less
than 1% may be used. The blowdown rate is normally determined by the
number of concentrations of dissolved salts allowed in the circulating
water system. Concentrations of 10 or less are common, with
concentrations as high as 20 being used.
Use of salt water makeup in cooling towers would decrease the number of
permissible concentrations, increasing the blowdown rate. A blowdown
rate equal to the evaporation rate would result in a blowdown twice as
concentrated as the makeup. In addition to concentrated salts, this
blowdown will have the chemicals used to treat the water to prevent
corrosion and algae growth in the system. While chromates were
439
-------
previously used to a large extent, their use has decreased in recent
years with the availability of other types of corrosion inhibitors.
Technology is currently available to control and treat pollutants in
blowdown, to levels up to and including no discharge of pollutants. See
Part A of this report for a description of the technology related to
pollutants in blowdown.
Blowdown removed from the hot side of the circulating system is
advantageous to the plant, as the heat in the blowdown does not have to
be removed in a tower. However, it is a better environmental practice
to discharge blowdown from the cool side. The percentage of heat
involved is in the order of 2% of the total, and thermal discharge could
be further reduced. The blowdown would normally be at a higher
temperature than the receiving body, even if taken from the cool side,
since the approach is to the wet bulb temperature, not the receiving
water temperature.
Aesthetic Appearance
In addition to all the ether factors described, the visual impact of the
cooling system could be of concern to the neighboring residents and
visitors. Cooling towers create two types of aesthetic impact. First,
the large size of natural draft towers will dominate most settings in
which they are placed. In this regard, natural draft towers can be as
high as a 50 story building and cover an area at the base equivalent to
several football fields. In all applications, they will dwarf the
associated powerplant. Mechanical draft towers, on the other hand, are
considerably smaller in height than the natural draft towers, although
the aggregate base area of a multicelled unit may be larger than the
base area of a natural draft unit for the same size plant. Therefore
mechanical draft towers will not be as objectionable in this regard as
will natural draft towers.
The second type of aesthetic impact is common to both types of towers.
This impact is caused by the visible plume that can be generated by both
types of evaporative systems where plume abatement is not employed.
Cooling tower plumes will sometimes be larger than the stack emission
from a fossil-fuel plant, especially in areas of high fogging potential.
At some plants cooling tower plumes can be so insignificant that they
escape notice by many viewers. Some cooling tower plumes, however, can
be visible for several miles and be noticed even where the surrounding
topography completely hides both the plant and the tower* As with
fogging, plume abatement technology is available at moderate cost.
The question of whether a tower or its plume creates an adverse
aesthetic impact is a subjective issue since the sensibilities of
individual viewers varies widely. There are those who believe that all
cooling towers create a visual nuisance. Others have expressed the
440
-------
opinion that the hyperbolic shape of cooling towers is visually
pleasing.
The aesthetic impact of cooling towers is not necessarily a function of
urban or rural location as some have suggested. Discussions with
utility representatives revealed as much opposition to cooling towers
placed in rural settings such as along the California Coast and in
scenic areas such as the Hudson River, as was voiced over towers placed
in urban areas.
The impact of cooling tower aesthetics can effect the application of
cooling towers at existing plants as well as at new sources, with
existing plants locational factors will have been fairly well
established and relatively little flexibility in the placement of the
tower will be possible compared to new plants. The most critical plants
will be those which are located in areas of mixed zoning. Residents of
those areas which have accepted a powerplant in close proximity to their
homes may object to the additional impact of a massive structure and a
new, large, visible emission. In terms of aesthetic impact the
mechanical draft tower is superior to the natural draft tower. The
physical size of these units is much smaller than the natural draft
tower and the mechanical draft tower can be fitted with plume
suppressive equipment which is not yet available for natural draft
towers. It is anticipated that this latter difference will be corrected
in the near future. It may be that another type of evaporative cooling
could be substituted for the tower in some instances. It is also noted
that the fan-assist modification to the natural draft tower can
substantially reduce its size.
For new plants where the location, site layout and architectural plan
have not been finalized, considerably more can be done to abate adverse
aesthetic impact than is possible at existing plants. In addition to
the selection of a less imposing cooling system where possible, and the
installation of plume abatement systems, the site location can be
selected to reduce the cooling tower visual angles to a minimum. The
site layout can be used to place natural barriers between the tower and
the surrounding land uses. A pleasing grouping of building and common
architectural treatment can be used to blend the facility into its
surroundings.
Mechanical draft towers will more easily fit into the surrounding area.
Plant no. 2612 is using the low hills surrounding the plant to almost
completely screen the towers from view. Landscaping can hide or blend
the towers into other types of terrain. Painting the towers can aid in
making their appearance more pleasing.
Cooling lakes, if sufficiently large, can serve as recreation sites.
With appropriate landscaping and structures, camping, boating, swimming,
and fishing can be accommodated. One utility leases summer cabin sites
along its cooling lake. Being low, these lakes normally blend well into
441
-------
the landscape. Landscaping of cuts and fill areas will normally be
required.
Spray canals can be very pleasing to the eye if properly designed.
Appropriate landscaping can hide the canal banks and power distribution
systems. The sprays themselves can be attractive if arranged in a
symmetrical pattern. They can be decorative, and be a definite asset to
the plant's appearance.
In summary, aesthetics is not a national-scale problem. In cases where
aesthetic impacts of towers and plumes could occur, alternative
technologies are available and plume abatement technology is available
at moderate incremental cost. New plants have the added flexibility of
site selection to help irinimize this problem.
Icing Control
Icing can result from the operation of cooling towers in cold weather.
Ice formation is usually confined to the tower itself, and adjacent
structures within the plant boundaries. No cases of tower related ice
formation at locations external to the plant have been reported.
Therefore, icing is an operational problem of the cooling system similar
to the control of biological growths in the system rather than a
nonwater quality environmental impact.
Control of cooling tower ice formation can be obtained by providing
appropriate features as the tower design and employing certain
procedures in tower operation during periods of cold weather. In the
case of mechanical draft towers, ice formation in the louvers can be
melted by periodically reversing the fans to drive air across the hot
water and through the louvers. Louvers can also be di-iced by flooding
them with hot water which is deliberatly spilled from the outer edge of
the water distribution basin and allowed to cascade down over the
louvers. In some instances louver icing can be controlled by
concentrating the hct water load on the outmost segments of the fill
during cold weather. This is accomplished by means of partitioned
distribution basins and water distribution systems which allow for
flexibility in the distribution of the water load over the fill area.
For hyperbolics this is achieved by providing an annular channel at the
outside edge of the fill and a distribution system which can divert a
large fraction of the hot water into this channel.
During cold weather an annular segment of the fill of a cross flow
hyperbolic or one or irore cells of mechanical draft units may be taken
off line. The resulting increased water loading also serves to reduce
tower icing. In some of the new designs for hyperbolics, the fill is
completely bypassed during periods of very cold weather and small plant
loads.
442
-------
comparison of Control Technologies
The available control and treatment technologies for effluent heat are
compared in Table B-VIII-16 based on incremental costs (production,
capital, fuel, and capacity), effluent reduction benefits, and nonwater
quality environmental impacts.
The incremental costs (production, capital, fuel, and capacity), and
costs versus effluent reduction benefits of the application of
mechanical draft evaporative cooling towers to nonnew nuclear units and
fossil-fueled units (base-load, cyclic, and peaking) with various years
of remaining service life-is shown in Table B-VIII-17- A similar costs
breakdown for new units is given in Table B-VIII-18. Both tables
indicate the assumptions used in the cost analyses.
In general for nonnew sources, the total costs of the application of
thermal control technology in relation to the effluent reduction
benefits to be achieved from such application are the most favorable for
the newest, most highly utilized generating units, and, progressively,
the least favorable for the oldest, least utilized generating units.
For new sources the costs versus effluent reduction benefits are even
more favorable due to the absence of "backfitting" costs of any kind,
which would be a major cost for nonnew sources. In the intermediate
case of a nonnew source for which construction has not been completed
and some backfitting cost attributable to construction aspects would not
occur, the costs versus effluent reduction benefits are likewise at a
level of favorability above the typical operational nonnew source and
below the new source.
For otherwise similar units, the cost versus effluent reduction benefi-ts
are the most favorable for those that will be the most highly utilized,
or base-load units. The costs versus effluent reduction benefits are
the least favorable for the units that will be utilized the least, or
peaking units. Cyclic units rank intermediate between base-load and
peaking units. In any case, the costs versus effluent reduction
benefits for units that are to be retired from service within 6 years
are very high when compared to the newer units in that class of
utilization (base-load, cyclic, peaking) which have a greater remaining
service life.
Considerations of Section 316 (a)
Section 316(a) of the Act authorizes the Administrator to impose (on a
case-by-case basis) less stringent effluent limitations when a
discharger can demonstrate that the effluent limitation proposed for the
thermal component of the discharge from his source is more stringent
than necessary to assure the protection and propagation of a balanced,
indigenous population of shellfish, fish and wildlife in and on the
waterbody. The procedures for implementing Section 316(a) may extend
over an estimated time span of approximately from two months to twenty
months depending, from case-to-case, in the extent to which additional
studies are required to establish effluent limitations based on
443
-------
TABLE B-VIII-16
CONTROL AND TREATMENT TECHNOLOGIES FOR HEAT
COSTS, EFFLUENT REDUCTION BENEFITS, AND NON-WATER QUALITY ENVIRONMENTAL IMPACTS
TECHNOLOGY
(Approx. no. of units
employing technology)
Once-Through ( 2500 )
Process Change (0)
Surface Cooling (100)
Unaugment ed
Augmented
Evaporative (Wet) Tower
Mechanical Draft ( 250 )
Natural Draft (60)
Dry Tower (1)
Wet/Dry Tower ( 1 )
Alternative Processes
Hydroelectric (100 ' s)
Internal Combustion (100 ' s)
Combined Cycle (approx. 50) c
INCREMENTAL COST FOR MAX. EFFL. RED.
% Base
Production
0
100
10-20
10-20
10-20
10-20
20-40
14-28
0
100
PP 50
Capital
0
100
9-14
9-14
9-14
9-14
11-16
10-15
0
100
PP 50
Fuel
0
15gai
1-2
1-2
1-2
1-2
4-5
2-3
lOOgai
0
app SOgai
Capacity
0
n ISgair
3-4
3-4
3-4
3-4
7-10
4-5
n 0
0
n 0
EFEL. RED. BENEFITS
% Base
0
15max
0-100
0-100
0-100
0-100
0-100
0-100
0-100
0-100
app 50
NONWATER ENVIRONMENTAL IMPACTS
% Base
Fog
0
0
0
*
*
0
o
0
Drift
0
0
0
*
*
0
0
*
I
0 0
0 0
0 0
Noise
0
0
0
0
*
0
*
*
0
*
*
Aesthetics
0
0
0
*
*
*
0
0
0
0
0
Land
0
0
2000
1000
30
30
30
30
2000
0
0
Water Consumption
0
0
100
2QO
200
200
30gain
35
SOgain
lOOgain
SOgain
* Note: Some highly site-specific incremental impacts, but not generally anticipated to be limiting.
-------
TABLE B-VIII-17
INCREMENBXL COST OF APPLICATION OF MECHANICAL DRAFT S7KPO8&TIVE COOLING TOWERS TO
NONNEW UNITS (BASIS 1970 DOLLARS)
TYPE UNIT REMAINING tIFE
Years
X. Nuclear 30-36
(All base-load) 24-30
18-24
12-18
6-12
0-6
Average excl. 0-6
II. Fossil-Fuel
A. Base-Load 30-36
24-30
18-24
12-18
6-12
0-6
Average excl. 0-6
£ B. Cyclic 30-36
-------
TABLE B-Vin-18
INCREMENEftL COST OF APPLICATION OF MECHANICAL DRAFT EVAPORATIVE COOLING TOWERS TO
NEW UNITS (BASIS 1970 DOLLARS)
TYPE UNIT
I. Nuclear (All base-load)
II. Fossil-Fuel
A. Base-Load
B. Cyclic
C. Peaking
INCREMENTAL PRODUCTION COSTS
% of Base Cost
10
10
11
28
Cost/Benefit
$/[MWH]
xlO
3
3
4
13
INCREMENTAL CAPITAL COSTS
% of Base Cost
9
9
10
11
Sost/Benefit
$/[MWH]
xlO
1
2
4
18
ADDITION*!, FUEL CONSUMPTION
% of Base Fuel
Consumpt ion
1
1
1
1
Cost/Benefit
[MWH] /[MWH]
xlOO
r
2
2
2
2
GENERATION CAPACITY REDUCTION
% of Base Gen-
erating Capac.
3
4
4
4
Cost/Benefit
MW/[MWH]
xlO' 1
1
1
1
4
Assumptions :
> TYPE UNIT
r*
I. Nuclear
-I. Fossil-Fuel
A. Base-Load
B. Cyclic
C. Peaking
Useful Life
Years
40
36
36
36
Base Prod. Cost
mills/KWH
6.50
6.34
8.35
12.5
Base Cap. Cost
$/KW
150
120
120
120
Annual Boiler
Capacity Factor
0.70
0.77
0.44
0.09
Heat Rate
Btu/KWH
10,500
10,500
11,500
12,500
Heat Loss
Btu/KWH
200
500
500
500
Heat Converted
Btu/KWH
3,500
3,500
3,500
3,500
Heat to Cooling Water
Btu/KWH
6,800
6,500
7,500
8,500
Cost Replacement
Capac.. $/KW
150
120
120
120
Subscripts: F indicates electrical equivalence of fuel consumed, and T indicates electrical equivalence of heat rejected to cooling water. Both are
calculated at 0.293x 10 [MWH]/Btu.
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environmental need. Correspondingly, the timing for cases leading to
significant thermal controls could extend in many cases beyond July 1,
1977. See Table B-VIII-19. The Act does not authorize extentions of
the implementation dates for best practicable control technology
currently available at individual sources to dates after July 1, 1977,
even in consideration of Section 316(a).
EPA estimates of the number of various, types of units that will require
some thermal controls based on environmental need (Section 316(a)
determination) are shown in Table B-VIII-20.
The incremental U.S. fuel consumption of thermal controls based on
environmental need (Section 316(a) determination) can be estimated based
on the following assumptions:
1) One-haJ-f of the plants with once-through cooling systems have no
thermal effluent limitations.
2) "No discharge" thermal controls are required for one-half of the
capacity of remaining once-through plants during 3-4 months of the
year, scattered, in the aggregate, year round.
3) Thermal effluent limitations will be met using mechanical draft
evaporative cooling towers. (This is highly conservative since all
other technologies, except dry cooling towers, use less energy).
4) Equal controls regardless of fuel types.
5) No net changes from distribution shown in Figure III-l.
The estimated incremental consumption of fuels, based on the above
assumptions, is 0.12% increase in nuclear fuel, 0.06% increase in coal,
0.02% increase in natural gas, and a 0.01% increase in oil, by 1980.
This result is shown in graph form in Figure B-VIII-24. Further, based
in a similar analysis, the annual incremental oil consumption assuming,
conservatively that all thermal controls needed are added by July 1,
1977, is shown in Table B-VIII-21. Incremental oil consumption is zero
unitl July 1, 1977, with the 1980 level estimated at 41,000 barrels per
day, compared to a projected total U.S-. oil usage of 21,500,000 barrels
per day by 1980.
447
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Table B-VIII-19
TIMING FOR CASES LEADING TO SIGNIFICANT THERMAL CONTROLS
BY JULY 1, 1977
ACCOMPLISHMENT
Propose effluent limitations guidelines
Propose Section 316 (a) procedures
Begin Section 316 (a) procedures
Promulgate effluent limitations guidelines
Promulgate Section 316 (a) procedures
Establish, effluent limitation based
on Section 316 (a) procedures
Discharger selects control means
Discharger awards construction contract
Discharger meets effluent limitation with...
• Mechanical draft cooling tower
• Natural draft cooling tower
• Other means
EARLIEST
Mar 1974
Mar 1974
Mar 1974
Jul 1974
Jul 1974
May 1974
May 1974
Aug 1974
Feb 1976
Jul 1977
Jul 1977
LIKELIEST
Mar 1974
Mar 1974
Mar 1974
Jul 1974
Jul 1974
Jun 1975
Jul 1975
Oct 1975
Jul 1977
(Dec 1978)
Jul 1977
LATEST
Mar 1974
Mar 1974
Mar 1974
Jul 1974
Jul 1974
Nov 1975
Feb 1976
May 1976
(May 1978)
(Oct 1979)
Jul 1977
00
) indicates noncompliance with 1977 date
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Table B-VIII-20
vo
ESTIMATED NUMBER OF UNITS REQUIRING THERMAL CONTROLS
BASED ON ENVIRONMENTAL NEED
Type of Unit
Base-Load
Completing construction
after July 1, 1977
Completing construction
prior to July 1, 1977
• Capacity 500 MW and
greater
• Capacity 300 to 500 MW
• Capacity less than
300 MW*
All Other Units
Total Number
of Units
40
260
200
1000
1500
Number Already Com-
mitted to Controls
20
80
50
250
300
Number Requiring Some
Controls Based on
Environmental Need
10
90
50
350
600
* Note: Excludes units in plants under 25 MW or in systems less than 150 MW
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w
J
ji EH
°§
Figure B-VIII-24
ESTIMATED U.S. ENERGY SITUATION (1980) RELEVANT TO ENVIRONMENTALLY-BASED CONTROL
OF THERMAL DISCHARGES FROM STEAM ELECTRIC POWERPLANTS
POWER
AT PLANTS
NEEDING
NO CONTROL
AT PLANTS
NEEDING
SOME CONTROL
CONTR
OLLED
ALREADY CONTROLLED
NATURAL GAS
OIL
FRACTION TOTAL ENERGY
— BY FUEL SOURCE —
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Table B-VIII-21
INCREMENTAL OIL CONSUMPTION IP ALL ENVIRONMENTALLY-BASED
THERMAL CONTROLS ARE ADDED BY JULY 1, 1977
en
YEAR
1974
1975
1976
1977
1978
1979
1980
TOTAL PROJECTED OIL CONSUMPTION
BY PCWERPLANTS
thousand barrels per day
2,200
2,400
2,600
2,800
3,000
3,200
3,400
MAXIMUM* INCREMENTAL
OIL
CONSUMPTION DUE TO
THERMAL CONTROLS
thousand barrels per
0
0
0
17
36
38
41
day
* Note: Based on the application of mechanical draft cooling towers, which
consume more incremental energy than do alternative technologies
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PART B
THERMAL DISCHARGES
SECTIONS IX, X, XI
BEST PRACTICABLE CONTROL TECHNOLOGY CURRENTLY
AVAILABLE, GUIDELINES AND LIMITATIONS
BEST AVAILABLE TECHNOLOGY ECONOMICALLY
ACHIEVABLE, GUIDELINES AND LIMITATIONS
NEW SOURCE PERFORMANCE STANDARDS
AND PRETREATMENT STANDARDS
Cat e gor ization
Steam electric powerplants utilize heat released from suitable fuels to
produce steam which, in turn, drives turbine generators which produce
electrical energy. The used, expanded steam is condensed into water by
rejecting unusable waste heat into a cooling water circuit. The
condensed steam, now high-purity water, is then returned to the
powerplant boiler ready for re-use. The rejected heat must be discarded
to the environment.
Steam electric powerplants (stations) are comprised of one or more
generating units. A generating unit typically consists of a discrete
boiler, turbine-gen era tor and condenser system; however, some units
employ multiple boilers with common headers to multiple turbine-
generators. Fuel storage and handling facilities, water treatment
equipment, electrical transmission facilities, and auxiliary components
may be a part of a discrete generating unit or may service more than one
generating unit.
While there are no formal subcategories, differences in age, size,
processes employed, etc., were considered in development of limitations
and are reflected in the limitations and in the dates by which the
limitations must be achieved. Because technology for the control and
treatment of heat is specific to that parameter and higher in cost than
technology required to control other parameters, the guidelines for heat
were developed separately. Guidelines for other parameters apply
(generally) to all generating units because factors such as age, size,
etc., are not correlated with waste load or practicability of employing
control technology.
The characteristics of waste water heat discharges and the degree of
practicability of control and treatment technology for heat are closely
associated with characteristics of the individual generating units
employed. The most significant factors governing the quantity of waste
heat generated relative to the electrical energy produced (a measure of
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the process efficiency) are the characteristics of the generating
process employed. The significant process factors include the raw
materials (fuel) employed, the boiler design pressure and temperature
cycle characteristics such as reheat and regeneration, and the turbine
characteristics. Generally the newer, larger, more-efficient units are
assigned base-load service and the older, smaller, less-efficient units
are used for meeting peak demands. The type of service (base-load,
etc.) and remaining service life characteristics are significant factors
affecting the degree of practicability of attaining effluent reductions
relative to the quantities of heat generated inasmuch as they determine,
in combination, the airount of corresponding electrical energy production
to which the control and treatment costs are compared.
The 1970 National Power Survey, a report by the Federal Power Commission
(FPC) describes base-load, intermediate, and peaking units as follows,
Base-load units are designed to run more or less continuously near full
capacity, except for periodic maintenance shutdowns. Peaking units are
designed to supply electricity, principally during times of maximum
system demand, and characteristically run only a few hours a day. Units
used for intermediate service between the extremes of base-load and
peaking service must be able to respond readily to swings in systems
demand, or cycling. Units used for base-load service produce 60
percent, or more, cf their intended maximum output during any given
year, i.e., 60 percent, or more, capacity factor; peaking units less
than 20 percent; and cycling units 20 to 60 percent. The FPC Form 67,
which must be submitted annually by all steam electric plants (except
small plants or plants in small systems) , reports average boiler
capacity factors for each boiler. The boiler capacity factor is
indicative of the gross generation of the associated generating unit.
The net generation is less than the gross generation to the extent that
electricity is used by the plant itself.
The operations and economics of nuclear power generation dictate base-
load service for these units inspite of the significantly larger
quantities of waste heat rejected to cooling water compared to otherwise
similar fossil-fueled base-load units. Similarly, all of the large
high-pressure, high-temperature, fossil-fueled units have been designed
for base-load service.
The base-load units placed in service in the 1960«s had as of 1970
approximately 15 or mere years of base-load service remaining, but
eventually the installation of more economic base-load generating units
may make it desirable to convert certain units to cyclic or peaking
service. However, some fossil-fueled units have been initially built
for cyclic or peaking service, beginning in 1960 and extending to the
present. Features of units designed for cyclic or peaking service
include the absence of the use of coal as a fuel, high-pressure, high-
temperature steam conditions, reheat stages, and some additional feed-
water heaters which are normally used with most base-load units.
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Base-load units represent approximately 70. percent of the total U.S.
installed capacity of steam-electric powerplants, cycling units 25
percent, and peaking units 5 percent. However base-load units account
for approximately 90 percent of the total U.S. steam electric energy
generation, and therefore, approximately 90 percent of total effluent
heat. Cycling units account for approximately 10 percent of the total
effluent heat, and peaking units less than 1 percent.
Waste Characteristics
Steam electric powerplants discharge about 50 trillion gallons of waste
water per year, which is roughly 15 X of the total flow of waters in U.S.
rivers and streams. Almost all of this water contains heat added by the
powerplants.
Control and Treatment Technology
Thermal (waste heat) control arid treatment technologies are of two
general types; those which are designed to reduce the quantities of
waste heat rejected from the process in relation to the quantities of
electrical energy generated and those which are designed to eliminate to
some degree the reliance upon a navigable water body as an intervening
step leading to the ultimate transfer of the rejected heat to and beyond
the atmosphere. The former type of thermal control is confined to in-
process means, while the latter takes the form of external devices,
other than navigable water bodies, which extract heat from the
circulating cooling water after it obtains the rejected heat at the
condenser. For the purpose of effluent heat reduction the latter is
clearly the most cost effective over the range of significant effluent
reductions.
External thermal control means take the form, on one extreme, of surface
water bodies confined to the property of the powerplant; and, on the
other, of configured engineering structures. Other methods between
.these extremes combine engineering equipment with the confined surface
water bodies. The configured engineering structures (towers) are more
universally applicable than means involving to any degree confined
surface water bodies due to the significantly larger land areas needed
for the latter*
Cooling towers are available utilizing any one, and in some cases more
than one, of the following combinations of engineering characteristics:
evaporative or nonevaporative, mechanical draft or natural draft, forced
mechanical draft or induced mechanical draft, fan-assisted natural draft
or unassisted natural draft, and crossflow or counterflow. The specific
type of cooling tower most widely used at powerplants today is the
crossflow, induced mechanical draft, evaporative tower. Theoretically,
a cooling tower of any type could be designed to remove a part of or all
of the waste heat rejected by any powerplant. In practice, however,
site-dependent factors prevail which can preclude the application of any
455
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particular means for any particular powerplant and which further lead to
•the selection of the rrost appropriate means from the remaining
candidates due to cost and other considerations.
Mechanical draft evaporative cooling towers are in operation in
conjuntion with approximately 200-300 or more steam electric generating
units in the U.S. cut of a total of about 3000 units at approximately
1000 plants. Natural draft evaporative cooling towers have been
constructed, or are on order, for approximately 60 additional generating
units. Between 50 and 100 more units employ unaugmented or mechanically
augmented cooling lakes, ponds and canals. One dry (non-evaporative)
cooling tower is in use in. the U.S. In most cases, the external thermal
control means are employed to completely recirculate the cooling water,
except for the relatively small amounts discharged in the bleed* or
blowdown, necessary for control of cooling water chemistry to achieve a
practical degree of corrosion and scaling protection. In this manner
essentially 100% of the waste heat rejected to the cooling water is
removed and tranferred directly to the atmosphere.
In establishing effluent limitations reflecting levels of technology
corresponding to to best practicable control technology currently avail-
able (to be achieved no later than July 1, 1977) , best available
technology economically achievable (to be achieved no later than July 1,
1983), standards of performance for new sources, and pretreatment
standards, it must te concluded that there is only one suitable
technology available and demonstrated, • evaporative external cooling to
achieve essentially nc discharge of heat, except for cold-side blowdown,
in a closed, recirculating cooling system. The judgments involved are
therefore reduced tc the determination of the types of units to which
the technology should be applied and when it should be applied, in the
light of incremental national-scale costs versus effluent reduction
benefits as well as unit-by-unit costs versus effluent reduction
benefits and other factors.
In consideration of the total costs of the application of technology in
relation to the effluent reduction benefits for heat, and other factors
including energy and other non-water quality environmental impacts, the
effluent limitations corresponding to the best practicable control
technology currently available are no discharge of heat except for cold-
side blowdown, for all large base-load units the construction of which
is completed after July 1, 1977, as is reflected by the application of
closed-cycle evaporative cooling systems. The mechanical draft
evaporative cooling tcwer provides the basis for the analysis used to
evaluate the costs, effluent reduction benefits and other factors. No
limitation on heat is reflected by the best practicable control
technology for cyclic and peaking units. No limitation on heat is
reflected by the best practicable control technology for units with
insufficient land available for mechanical draft towers, including
spacing, or where salt water drift from mechanical draft towers could
456
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adversely impact neighboring land uses, provided no alternative
technologies would be practicable. In addition, for all units the
construction of which has been or will be completed by July 1, 1977, no
limitation on heat is reflected by the best practicable control
technology, since, as more fully explained below, the limitation of no
discharge of heat except for cold-side blowdown is not practically
achievable by July 1, 1977, the date mandated by the Act for achievement
of best practicable control technology currently available.
In consideration of the relevant factors including those required in the
Act, such as the cost of achieving effluent reductions, energy and
non-water quality environmental impacts, the effluent limitations
corresponding to the best available technology economically achievable
are no discharge of heat, except for cold-side blowdown, for all but the
very oldest base-load units not covered by best practicable control
technology currently available and for all cyclic and peaking units, as
is reflected by the application of closed-cycle evaporative cooling
systems. The mechanical draft evaporative cooling tower provides the
basis for the analyses of costs and other factors. No limitation on
heat is reflected by the best available technology economically
achievable for units where sufficient land cannot be made available for
mechanical draft towers, including spacing.
The time required for owners and operators of base-load units to
complete the procedures for the consideration by the Regional
Administrator of exemptions to the effluent limitations on heat, as
provided by section 316(a) of the Act renders an effluent limitation of
no discharge of heat except for cold-side blowdown outside the scope of
best practicable control technology currently available for any unit
which must achieve such limitation before July 1, 1977. An owner or
operator following the procedure but failing to demonstrate that the
effluent limitation proposed is excessively stringent could achieve an
effluent limitation of no discharge by July 1, 1977, under only an
optimistic set of conditions, if construction of the control means was
not begun until after completion of the section 316(a) procedures.
Hence, universal achievement of no discharge of effluent limitations by
existing base-load sources, by July 1, 1977, would not be realistic in
the light of the time required for section 316(a) procedures. The Act
contains no provisions which would allow for the delay of the required
date for the application of section 301 effluent limitations in
individual cases. However, since the Act requires that effluent
limitations reflecting the application of the best available technology
economically achievable by "no later than" July 1, 1983, it is concluded
that these regulations can require that the effluent limitations be
achieved by certain dates prior to July 1, 1983, if such dates are
realistically achievable. Correspondingly, the realistic achievement of
the goals of the Act would be served if dates for complete
implementation of best available technologyzeconomically achievable were
established that were realistic but not far past the 1977 horizon. This
can be accomplished by limiting the coverage of the best practicable
457
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control technology currently available to the relatively small number of
sources that would not be completed until after July 1, 1977. Since the
scheduled dates for completion of construction for these sources would
be distributed over the years 1977 to 1982, a no discharge limitation
would be realistically achievable by the time the affected sources would
become operational. Realistically achievable dates for the base-load
units constructed before July 1, 1977, would be as follows:
1.capacity of 500 MW and greater: July 1, 1978
2.capacity 300 to 499 MW: July 1, 1979
3.capacity 299 MW and less, except for small units: July 1, 1980
4.small units, i.e., unit in a plant with a capacity less than 25 MW or
in a system with a capacity less than 150 MW: July 1, 1983.
The proposed best practicable control technology currently available and
best available technology economically achievable for heat are based on
the above rationale.
In consideration of the relevant factors including those required in the
Act, such as the cost of achieving effluent reductions, energy and non-
water quality environmental impacts, the effluent limitations
corresponding to standards of performance for new sources for heat are
no discharge of heat, except for cold- side blowdown, from all new
sources, without variation.
Cost of Technology
The unit costs of the application of available external control and
treatment technology for heat to generating units of various sizes is
essentially invariant with size, over the range of present processes,
due to the general availability of small modules applicable to
incremental loads.
Factors affecting the incremental costs of effluent heat reductions for
any particular generating unit are dependent upon the characteristics of
the plant site, as follows: available land, generating unit
configuration (accessibility of existing condenser cooling system,
ability of space to accomodate a new circulating cooling system),
requirements imposed by nearby land uses (drift, fogging and icing,
noise, structure height and appearance), climatic considerations (wind
direction and velocity, wet bulb temperature, relative humidity, dry
bulb temperature, equilibrium temperature of natural (surface) cooling,
soil bearing characteristics, significance of regional consumptive use
of water, significance of impact on regional demand availability of
power to consumers, and characterisitics of intake water (temperature,
concentrations of dissolved materials).
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The significant costs of external cooling systems themselves are
determined characteristically by three major engineering design
parameters: the cooling water flow rate, the rate of heat removal
required, and the difference between the desired temperature of the cold
water returned to the condenser and the lowest cold water return
temperature theoretically achievable. Other major costs generally
associated with applying external cooling in the place of systems
employing no external cooling means are attributable to additional
piping and pumps and to the physical alterations in the cooling system
that are required by the conversion. The incremental energy (fuel)
consumption costs of external cooling system are determined largely by
the additional pumping energy required, the power required to drive the
circulating air fans, and in most cases where the cooling water
discharged from the external cooling means is recirculated to the
condensers, the increase in waste heat rejected due to the process
energy conversion inefficiency imposed by the resulting increased
turbine exhaust pressure. A further cost of external cooling means can
be the reduced margin of reserve generating capacity of a system
employing the generating unit to meet peak demands for power. The
reduced capacity of a unit corresponds to the energy losses incurred
during full capacity operation. A further reduction in margin of
reserve generating capacity of a system will occur during the time in
which a unit must be shut down in order to complete the changeover to
the closed-cycle cooling system. Many changeovers can be made during
normal periodic shutdowns for maintenance. Incremental downtime due to
changeovers may be from 30 to 90 days for each unit.
In general, the monetary and energy consumption costs of effluent heat
reductions of less than 100 percent would be approximately proportional
to the corresponding percentage reduction. It must be noted that, while
fractional heat removals are theoretically achievable, no external
cooling means have teen employed to date to meet requirements based on
fractional heat removals for individual units. Moreover, the
application of open cooling systems to achieve significant fractional
heat removals would cause more damage to organisms brought into the
cooling water system than would a closed-cycle system for essentially
100 percent heat removal due to the higher volume of intake water
required by the former.
The following analysis of the monetary, energy consumption and capacity
loss costs of external cooling systems are based on the requirement of
the guidelines that blowdown is permitted only from the cold side of the
external cooling means. On the conservative assumption that all
external cooling means already employed on existing units provide for
blowdown from the hot side, then the incremental costs associated with
requiring blowdown from the cold side of the external cooling means of
these units would be a fraction of the total cost of the required
external cooling means, said fraction being approximately the ratio of
the present blowdown flow rate to the total flow rate through the
459
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condensers, neglecting drift loss effects. This fraction is typically
less than 2 percent.
The average incremental costs of the application of mechanical draft
evaporative cooling towers to base-load units to achieve no discharge of
heat except for blowdcwn are estimated to be as follows:
1.production costs: 14 percent of base
2.capital costs: 12 precent of base
3.fuel consumption: 2 percent of base
4.capacity reduction: 3 percent of base
Incremental dollar costs for cyclic units are higher by about 20S5, while
fuel consumption and capacity reductions are the same as for base-load
units. Incremental production costs for peaking units are about three
times the costs for base-load units. Incremental capital costs are
about 40% higher than for base-load units, and fuel consumption and
capacity reductions are the same.
The average incremental costs versus effluent reduction benefits
(dollars/unit heat removed) for cyclic units are about double those for
base-load units, except for fuel consumption which is invariant with the
degree of utilization. Average incremental costs versus effluent
reduction benefits for peaking units are about three to four times those
for cyclic units.
For new sources for base-load, cyclic and peaking units respectively/
the average incremental production costs are 10, 11 and 28 percent of
base costs; the incremental capital costs are 9, 10, and 11 percent of
base costs, the fuel consumption costs are all 1 percent of base fuel
consumption, and the generating capacity reduction is 0 to 2 percent of
base capacity depending on whether the capability to overdesign is
considered.
The above costs for non-new sources do not reflect the exemptions from
the no discharge limitation for units for which insufficient land is
available for the construction of mechanical draft evaporative cooling
towers or for which salt water drift precludes their use. The analyses
on which the cost estimates are based assume the application of state-
of-the-art technology for drift elimination, but do not assume purchase
of land. The factors of adverse climate, fogging and icing, and noise,
while possibly adding marginal costs where additional levels of
technology are required for control, are not national-scale factors.
Since the overall costs and the land availability and saltwater drift
factors are based on mechanical draft evaporative cooling towers, with
incremental costs for plume abatement, etc. if required, the potential
aesthetic factors associated with the tall structure of natural draft
460
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towers, with spray ponds, with cooling ponds, or with cooling tower
plumes have been indirectly taken into account.
While the mechanical draft evaporative cooling tower was selected as a
model for the cost analyses because of its widespread use and more
universal applicability, this in nc way precludes the actual use of
other technologies to achieve the effluent limitations.
The costs of other external evaporative systems for effluent heat
reduction are generally comparable to the costs of mechanical draft
evaporative cooling tcwers. Site-dependent factors, however, could tend
to increase some costs and lower others significantly depending on the
location involved. Costs that would be incurred and corresponding
effluent reduction benefits for units already planning or employing
closed-cycle cooling systems would be zero or relatively insignificant
depending upon whether the blowdown is from the cold-side or not.
However, in the case of hot-side blowdown, the costs versus effluent
reduction benefits related to achieving cold-side blowdown would be
approximately in the same proportion as the costs versus effluent
reduction benefits for achieving closed-cycle cooling for an otherwise
similar unit with an open cooling system.
Energy and Other Nonwater Quality Environmental Impacts Impacts.
Energy
The incremental energy (fuel) consumption costs of mechanical draft
evaporative cooling tcwers applied to existing units are typically about
1 to 2 percent of the energy generated or fuel consumed. Corresponding
costs of unassisted natural draft cooling towers and of spray canals and
ponds are lower by an increment of approximately 1/2 percent or less.
Fuel consumption costs for unaugmented cooling lakes are lower by about
1/2 percent. The energy costs of mechanical draft dry (nonevaporative)
cooling towers are higher by an increment of more than 2 percent.
Energy (fuel) consumption costs of applying these closed-cycle cooling
systems to new units would be less due to the opportunity provided for
overall optimization cf the process as well as the cooling system.
A typical existing generating unit to which mechanical draft evaporative
cooling towers would te applied for essentially 100 percent reduction of
effluent heat would be reduced in generating capacity by about 3 to 4
percent of its former capacity during part of the year. Reduced
capacity corresponding to other types of cooling employed at existing
units would be approximately proportional to the fuel consumption cost
percentages cited above. For new units no capacity loss would occur
since the unit would be oversized to make up for this factor.
Energy requirements for technologies reflecting the application of the
best available technology economically achievable for pollutants other
than heat are less than 0.2 percent of the total plant output.
461
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Reduced margins of reserve capacity due to lost generating capacity
could be significantly offset by delayed retirements, but not without
some added generating costs due to the relative inefficiency of the
older units. The installation of combustion turbines to replace lost
capacity can be accomplished relatively quickly. Eventually the lost
capacity could be replaced by the construction of new highly-efficient
base-load units.
Potentially, the construction of additional transmission lines and other
efforts to achieve higher degrees of regional and national reliability
coordination could completely offset the reduced margins of reserve
capacity due to lost generating capacity. Furthermore, citizen and
other user efforts to reduce consumption during the brief periods of
peak demand could significantly lessen the impact of reduced reserve
margins. The above factors are especially significant in the case of
the numerous units in small plants and systems where the engineering
design manpower requirements would be high relative to the heat removals
achieved, the availability of capital would be somewhat lower due to the
smaller amounts and higher risks involved, and the possible impact of
reduced reserve capacity would be larger due to the relatively limited
extent of the systems.
Other Non-Water Quality Environmental Impacts
Non-water quality environmental impacts of external thermal control
technology include possible effects of salt water drift (droplet
carryover from evaporative towers and spray systems) , increased fogging
or water consumption with evaporative systems, noise if mechanical draft
towers are adjacent tc populated areas, and increased aesthetic impacts
due to the size of natural draft towers and visible plumes from all
evaporative towers. The potential effects of salt water drift have been
taken into account by the exemption provided in the guidelines from the
no discharge requirements in instances in which it is likely to present
a significant problem.
However, in the limited number of cases where it would be required,
technology is available to reduce or eliminate drift, fogging, visible
plumes and noise effects, and water consumption rights are available
where required, each at incremental costs above standard evaporative
cooling systems for closed-cycle cooling.
Economic Impact Including Impact on U.S. Fuel Consumption
The proposed effluent limitations are based on the technological
capabilities of steam electric powerplants. Section 316(a) of the Act
allows for exemptions to the proposed limitations on heat, in a
case-by-case basis, based on the consideration of environmental need.
It has been estimated, based on an analytical model of the cooling
capacity of U.S. rivers and from a survey of EPA regional personnel,
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that approximately one-half to two-thirds of the steam electric
powerplants (by capacity) not already achieving "no thermal discharge"
are not now in violation of present or projected thermal environmental
criteria. Of the remainder, "no discharge" thermal controls
corresponding to generally one-half of the capacity at each plant would
be warranted during certain parts of the year, based on environmental
considerations. It is further estimated that generally thermal controls
would be needed during 3-4 months of the year, or approximately 3055 of
the time, scattered, in the aggregate, year round.
Approximately 20% of existing steam electric powerplants already achieve
"no thermal discharge." A significantly larger percentage (over 50%) of
plants that are not considered "new sources" under the definitions of
the Act but will begin initial operation in the period 1974 - 1982 are
already committed to closed cooling systems.
By 1980 approximately 30% of all U.S. energy uses has been projected to
be through electrical generation. The electrical generation processes
have been projected by one source tc be comprised of approximately 40%
coal-fueled, 25% nuclear, 15% oil-fueled, 15% gas-fueled and 5% hydro
and geothermal plants. Approximately 50% of all coal is projected to go
to powerplants, 15% of all natural gas, and 10% of all oil.
Incremental fuel consumption due to closed cooling water systems at
steam electric powerplants is due to the power required to drive the
pumps and fans (if they are employed) in the closed system and to the
reduced energy conversion efficiency brought about by changes in steam
condensing pressures. Generally the increased fuel consumption relative
to base fuel consumption would be approximately 1% for pumps and fans
(if they are employed) and 1% for changing steam pressures. Mechnical
draft evaporative ccoling towers are the most widely used means for
achieving closed-cycle cooling. They employ both pumps and fans. Other
means commonly employed use no fans (natural draft towers, spray canals,
cooling ponds) or no additional pumping (cooling ponds) .
Environmentally-based thermal effluent limitations may be met by
open-cycle systems, that cause no loss in energy conversion efficiency
due to changing steam pressures and which use the preceeding means and
others.
Assuming equal environmentally-based thermal controls regardless of
fuel, no net changes in generating distribution among the fuels used and
use of mechanical draft cooling towers (highest fuel consumption) the
above numbers translate into a 0.12% increase in nuclear fuel con-
sumption to meet theriral controls, a 0.06% increase in total U.S. coal
consumption, a 0.02% increase in total U.S. natural gas consumption and
a 0.01% increase in tctal U.S. oil consumption, by 1980.
The estimated economic impact by 1983, of the proposed effluent
limitations guidelines, considering the estimated effect of exemptions
463
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to be allowed through appeals under section 316(a) of the Act are as
follows:
1.Total capital required is $12.0 billion which is 3.3% of the base
capital required.
2.Cost to consumers vould reach $4.1 billion per year, which is 3.6% of
the base cost to consumers.
3.Price increase by 0.9 mills per kwh, or 1.2% of base production costs.
4.Fuel consumed would reach a level equivalent to 9 million tons of coal
per year, or 0.2% of U.S. consumption for all purposes.
5.Capacity loss of 3,300 MW, or 0.4% of U.S. generating capacity.
Similarily for new sources, between 1985 and 1990, the above costs,
respectively, are $11.8 billion (2.0% base), $1.7 billion per year (Q.1%
base), 0.05 mills per KWH (1.4% base production costs), 8 million tons
per year (0.12% base), and 3,100 MW (0.25% base).
464
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SECTON XII
ACKNOWLEDGEMENTS
The development of this report was accomplished through the efforts of
Burns and Roe, Inc., and Dr. Charles R. Nichols of the Effluent
Guidelines Division. The following Burns and Roe, Inc., technical staff
members made significant contributions to this effort:
Henry Gitterman, Director of Engineering
John L. Rose, Chief Environmental Engineer
Arnold S. Vernick, Project Manager
Phillip E. Bond, Senior Supervising Mechanical Engineer
Suleman Chalchal, Chemical Engineer
Ernst I. Ewoldsen, Senior Mechanical Engineer
William A"! Foy, Senior Environmental Engineer
Dr. Benjamin J. Intorre, Engineering Specialist
Paul D. Lanik, Environmental Engineer
Geoffrey L. Mahon, Mechanical Engineer
Dr. Shashank S. Nadgauda, Senior Chemical Engineer
Dr. Edward G. Pita, Senior Mechanical Engineer
Richard T. Richards, Supervising Civil Engineer
Harold J. Rodriguez, Senior Chemical Engineer
The physical preparation of this document was accomplished through the
efforts of the secretarial and other non-technical staff members at
Burns and Roe, Inc., and the Effluent Guidelines Division. Significant
contributions were made by the follwing individuals:
Sharon As he. Effluent Guidelines Division
Chris Miller, Effluent Guidelines Division
Marilyn Moran, Burns and Roe, Inci
Kaye Starr, Effluent Guidelines Division
Nancy Zrubek, Effluent Guidelines Division
Edwin L. Stenius, Burns and Roe, Inc.
The contribution of Ernst P. Hall, Deputy Director, Effluent Guidelines
Division, were vital to the timely publication of this report.
The members of the working group/steering committee, who contributed in
the preparation of this document and coordinated the internal EPA review
in addition to Mr. Cywin and Dr. Nichols are:
Walter J. Hunt, Chief, Effluent Guidelines Development Branch, EGD
Dr. Clark Allen, Region VI
Alden Christiansen, National Environmental Research
Center, Corvailis
Swepe Davis, Office of Planning and Management
Don Goodwin, Office of Air Quality Planning and Standards
William Jordan, Office of Enforcement and General Counsel
465
-------
Charles Kaplan, Region IV
Steve Levy, Office cf Solid Waste Management Programs
Harvey Lunenfeld, Region II
George Manning, Office of Research and Development
Ray McDevitt, Office of Enforcement and General Counsel
Taylor Miller, Office of Enforcement and General Counsel
James Shaw, Region VIII
James Speyer, Office of Planning and Management
Howard Zar, Region V
Also acknowledged are the contributions of Dennis Cannon,
Michael LaGraff, Ronald McSwiney, and Lillian Stone, all
formerly with the Effluent Guidelines Division.
Other EPA and State personnel contributing to this effort were:
Allan Abramson, Region IX
Ken Bigos, Region IX
Carl W. Blomgren, Region VII
Danforth G. Bodien, Region X
Richard Burkhalter, State of Washington
Gerald P. Calkins, State of Washington
Robert Chase, Region I
Barry Cohen, Region II
William Dierksheide, Region IX
William Eng, Region I
Joel Golumbek, Region II
James M. Gruhlke, Office of Radiation Programs
Joseph Hudek, Region II
William R. Lahs, Office of Radiation Programs
John Lum, Region II
Dr. Guy R. Nelson, National Enviornmental Research Center,
Corvallis
Courtney Riordan, Office of Technical Analysis
William H. Schremp, Region III
Edward Stigall, Region VII
Dr. Bruce A. Tichener, National Environmental Research
Center, Corvallis
Srini Vasan, Regicn V
Other Federal agencies cooperating were:
Atomic Energy Comnrission
National Marine Fisheries Service, National Oceanographic
and Atmospheric Administration, Department of Commerce
Bureau of Land Management, Department of the Interior
Bureau of Sport Fish and Wildlife, Department of the Interior
Federal Power Commission
Rural Electrification Administration, Department of
Agriculture
Tennessee Valley Authority
466
-------
The Environmental Protection Agency also wishes to thank the
representatives of the steam electric generating industry, including the
Edison Electric Institute, the American Public Power Association and the
following utilities and regional systems for their cooperation and
assistance in arranging plant visits and furnishing data and
information.
Alabama Power Company
Canal Electric Conrpany
Central Hudson Gas and Electric Corporation
Commonwealth Ediscn Company
Consolidated Ediscn Company of New York, Inc.
Consumers Power Company
Duke Power Company
Florida Power and Light Company
Fremont, Nebraska Department of Utilities
MAPP Coordination Center for the Mid-Continent
Area Power Systems
New England Power Company
New York Power Pocl
New York State Electric and Gas Corporation
Niagara Mohawk Power Corporation
Omaha Public Power District
Pacific Gas and Electric Company
Pacific Power and Light Company
Pennsylvania Power and Light Company
Portland General Electric Company
Potomac Electric Power Company
Public Service Company of Colorado
Public Service Electric and Gas Company
Sacramento Municipal Utility District
Southern California Edison Company
Taunton, Massachusetts Municipal Light Plant
Texas Electric Service Company
Virginia Electric and Power Company
Acknowledgement is also made to the following manufacturers for their
willing cooperation in providing information needed in the course of
this effort.
Allen-Sherman-Hoff
Butterworth Systeir Inc.
Ceramic Cooling Tower Company
Ecodyne Corporation
General Electric Company
Inland Environmental
Research-Cottrell, Inc., Hamon Cooling Tower, Division
Resources Conservation Company
.Richards of Rockfcrd, Inc.
Ste phen s- Adamson
The Marley Company
467
-------
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472
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476
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Licensing;
a) Arkansas Nuclear One Unit 1
Arkansas Power 6 Light Co., (February 1973).
b) Arkansas Nuclear One Unit 2
Arkansas Power & Light Co., (September 1972).
c) Davis-Bessee Nuclear Power Station
Toledo Edison Company & Cleveland Electric
Illuminating Company, (March 1973).
d) Duane Arnold Energy Center
Iowa Electric Light & Power Co.
Central Iowa Power Cooperative
Corn Belt Power Cooperative, (March 1973).
e) Enrico Fermi Atomic Power Plant Unit 2
Detroit Edison Company, (July 1972) .
f) Fort Calhoun Station Unit 1
Omaha Public Power District, (August 1972) .
g) Indian Point Nuclear Generating Plant Unit No. 2
Consolidated Edison Co. of New York, Inc., Vol. 1
(September 1972) .
h) Indian Point Nuclear Generation Plant Unit No. 2
Consolidated Edison Co. of New York, Inc., Vol. II
(September 1972) .
i) James A. Fitzpatrick Nuclear Power Plant
Power Authority of the state of New York,
(March 1973) .
j) Joseph M. Farley Nuclear Plant Units 1 and 2
Alabama Power Company, (June 1972).
477
-------
k) Kewaunee Nuclear Power Plant
Wisconsin Public Service Corporation,
(December 1972) .
1) Maine Yankee Atomic Power Station
Maine Yankee Atomic Power Company, (July 1972).
m) Oconee Nuclear Station Units 1, 2 and 3
Duke Power Company, (March 1972) .
n) Palisades Nuclear Generating Plant
Consumers Power Company, (June 1972) .
o) Pilgrim Nuclear Power Station
Boston Edison Company, (May 1972).
p) Point Beach Nuclear Plant Units 1 and 2
Wisconsin Electric Power Co. and
Wisconsin Michigan Power Company, (May 1972).
q) Quad-Cities Nuclear Power Station Units 1 & 2
Commonwealth Edison Company and the
Iowa-Illinois Gas and Electric Company,
(September 1972) .
r) Rancho Seco Nuclear Generating Station Unit 1
Sacramento Municipal Utility District, (March 1973)
s) Salem Nuclear Generating Station Units 1 & 2
Public Service Gas & Electric Company, (April 1973)
t) Surry Power Station Unit 1
Virginia Electric and Power Power Co., (May 1972).
u) Surry Power Station Unit 2
Virginia Electric & Power Co., (June 1972) .
v) The Edwin I. Hatch Nuclear Plant Unit 1 & 2
Georgia Power Company, (October 1972).
w) The Fort St. Vrain Nuclear Generating Station
Public Service Company of Colorado, (August 1972).
x) Three Mile Island Nuclear Station Units 1 and 2
Metropolitan Edison Company, Pennsylvania Electric
and Company, Jersey Central Power and Light Co.,
(December 1972) .
y) Turkey Point Plant
Florida Power and Light Co. , (July 1972) .
478
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zj Vermont Yankee Nuclear Power Station
Vermont Yankee Nuclear Power Corporation, (July 1972).
aa) Virgil C. Summer Nuclear Station Unit 1
South Carolina Electric £ Gas Company, (January 1973).
bb) William B. McGuire Nuclear station Units 1 and 2
Duke Power Company, (October 1972).
cc) Zion Nuclear Power Station Units 1 and 2
Commonwealth Edison Company, (December 1972).
dd) Monticello Nuclear Generating Plant
Northern States Power Company, (November 1972).
109. Final Environmental Statement. Watts Bar Nuclear Plant
Units 1 and 2, Tennessee Valley Authority,
(November 9, 1972).
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for Allen S. King Generating Plant, Minn.,
(December 31, 1970).
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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
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116. Garton, R. R. and Christiansen, A. G., "Beneficial
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117. Garton, R. G. and Harkins, R. D., Guidelines:
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118. Gartrell, F. E. and Barber, J. C., "Environmental
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119. Geothermal Resources in California Potentials and
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120. Geyer, J. C., et al, Field Sites and Survey Methods,
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121. Gifford, D. C., "Will County Unit 1 Limestone Wet
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122. Gilbert Generating Station Units 4, 5, 6£ 7, and 8
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123. Goldman, E. and Kelleher, P. J., "Water Reuse in Fossil-
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124. Golze, A. R., "Impact of Urban Planning on Electric
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125. Hales, William K., "Control Cooling Water Deposition",
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126. Hall, W. A., Coding Tower Plume Abatement, Chem. Enq.
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128. Hansen, E. P. and Gates, R. E., "The Parallel Path
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129. Hansen, R. G., Knoll, C. R., and Mar, B. W., "Municipal
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480
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132. Hauser, L. G. , et al, "An Advanced Optimization
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133. Hauser, L. G. and Oleson, K. A., "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. , "Evaulate Your Cost of Cooling Steam
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137. Hill, R. D., "Mine Drainage Treatment, State of the Art
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138. Hirayama, K. , and Hirano, R., "Influences of High
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139. Hollinden, G. A., and Kaplan, N., "Status of Application
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140. Holmberg, J. D. and Kinney, O. L. , Drift Technology
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141. Horlacher, W. R., et al, "Four SO2 Removal Systems",
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481
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142. Industrial Waste Guide on Thermal Pollutionf FWPCA,
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143. Inorganic Chemicals Industry Profile, EPA, Water
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144. "Reviewing Environmental Impact Statements: Power Plant
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145. Jaske, R. T. and Reardon, W. A., "A Nuclear Future in
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146. Jaske, R. T., "Heat as a Pollutant, Session 7, presented
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147. Jaske, R. T., et al, "Heat Rejection Requirements of the
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148. Jaske, R. T., "Is there a Future for Once-Through Cooling
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149. Jaske, R. T., et al, "Multiple Purpose Use of Thermal
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150. Jaske, R. T., et al, "Methods for Evaluating Effects of
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151. Jaske, R. T., "Technical and Economic Alternatives in
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152. Jaske, R. T., "Thermal Pollution and Its Treatment",
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482
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153. Jaske, R. T., "Use of Simulation in the Development of
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154. Jaske, R. T., "Water Resoureces Problems in Meeting
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155. Jaske, R. T., "Water Reuse in Power Production an
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156. Jenson, L. D. and Brady, D. K., "Aquatic Ecosystems
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157. Jimeson, R. M. and Chilton, C. H., "A Model for
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158. Jimeson, R. M., and Adkins, G. G., "Factors in Waste
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159. Jimeson, R. M. , "The Demand for Sulfur Control Methods
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160. Jimeson, R. M., and Adkins, G. G., "Waste Heat Disposal
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161. Jones, J. W., Stern, R. D., and Princiotta, F. T.,
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162. Kaup, E., "Design Factors in Reverse Osmosis", Chemical
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483
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163. Kelley, R. B., "Large-Scale Spray Cooling", Industrial
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164. Kibbel, Jr., w. H., "Hydrogen Peroxide for Industrial
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165. Kleinberg, B., "Introduction to Metric or Si", Civil
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166. Kolflat, T. D., Cooling Towers - State of the Art,
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167. "Kool-Flow Thermal Pollution Control", Richards of
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168. Krieger, J. H. , "Energy: "The Squeeze Begins", Chemical
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169. Kumar, J., "Selecting and Installing Synthetic Pond
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170. Lake Norman Hydro-thermal Model Study for Duke Power
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171. LaMantia, C. R., "Emission Control for Small Scale
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172. LaQue, F. L. and Cordovi, M. A., "Experiences with
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173. Leung, Paul, "Cost Separation of Steam and Electricity
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174. Leung, P., and Moore, R. E., "Thermal Cycle Arrangements
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175. Li, K. W., Combined Cooling Systems for Power Plants.
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484
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176. Lot, G. and Ward, J. c., "Economics of Thermal
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177. Long, N. A., "Recent Operating Experience with Stainless
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179. Loucks, C. M., "Boosting Capacities with Chemicals",
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180. Lunenfeld, H., "Electric Power & Water Pollution Control".
181. Lusby, W. S. and Somers, E. V., "Power Plant Effluent -
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184. McNeil, W. J., "Beneficial Uses of Heated Sea Water in
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185. McNeil, W., "Selecting and Sizing Cooling Towers",
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186. "Typical LWR Nuclear Plant Project Schedule,"
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187. Kolflat, T., "Conventional Steam Cycle Unit Meets Need,"
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188. Meeting the Electrical Energy Requirements for California,
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189. Methods for Chemical Analysis of Water & Wastes. Clean
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485
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190. Metric Practice Guide, (A Guide to the Use of Si - The
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191. Mis so uri_ River Temperature Survey Near United Power
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192. Moore, F. K. and Jaluria, Y., "Thermal Effects of Power
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193. Moores, C. W. , "Wastewater Bi ©treatment: What It Can
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195. Morse, F. T., Power Plant Engineering - The Theory and
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197. "Nations Bulk Pcwer Systems Evaluated", National Electric
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198. Nelson, B. D. , The Cherne Fixed Thermal Rotor System
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199. Nester, D. M. , "Salt Water Cooling Tower", Chemical
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200. "New Generating Capacity: Who*s Doing What?", Power
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201. Olds, F. C., "Capital Cost Calculations for Future
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486
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203. Olesonr K. A. and Budenholzer, R. J., "Economics of
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206. Park, J. E. and Vance, J. M., "Computer Model of Cross-
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208. Patterson, J. W. and Minear, R. A., Wastewater Treatment
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209. Patterson, W. D., et al, "The Capacity of Cooling Ponds
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210. Peterson, D. E. and Jaske, R. T., "Potential Thermal
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211. Peterson, D. E. and Jaske, R. T., "Simulation Modeling
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212. Peterson, D. E. and schrotke, P- M., "Thermal Effects
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213. Peterson, D. E., Sonnichsen, Jr., A. M., et al, "Thermal
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214. "Pilot Plant to Upgrade Coal", Chemical Engineering,
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487
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216. Pita, E. G., "Thermal Pollution - The Effectiveness of
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217. Policastro, A. J., "Thermal Discharges into Lakes and
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218. Possible Impact of Costs of Selected Pollution Control
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219. Potential Environmental Modifications Produced by Large
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220. Potter, B. and Craig, T. L., "Commercial Experience with
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221. "Power Gas and Combined Cycles: Clean Power from Fossil
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222. "Power Plant Dry Cooling Tower Cost, Indirect Type",
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223. "Predictions of Fog Formation Due to a Warm Water Lagoon
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224. Prolected Wastewater Treatment Costs in the Organic
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225. Rabb, A., "For Steam Turbine Drives... Are Dry Cooling
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226. Rainwater, F. H., "Research in Thermal Pollution
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228. Sisson, William, "Langelier Index Predicts Water1s
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488
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229. Resort on Equipment Availability for the Twelve-Year
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230. Review of Surface Water Temperatures and Associated
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231. Key, G., Lacy, Vi. J. and Cywin, A., "Industrial Water
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232. "Preliminary Cooling Tower Feasibility Study for John Sevier
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233. "Steam Electric Plant Air and Water Quality Control Data
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234. "Understanding the 'National Energy Dilemma1" Print
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235. Rickles, R. N., "Waste Recovery and Pollution Abatement",
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236. "Draft Development Document for Proposed Effluent
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237. Roe, K. A., "Soire Environmental Considerations in Power
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238. Rohrman, F. A., "Power Plant Ash as a Potential
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239. Rossie, J. P., "Dry-Type Cooling Systems", Chemical
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489
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240. Rossie, J. P., et al. Cost Comparison of Dry Type
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241. Rossie, J. P- and Cecil, E. A., Researeh_on Dry-
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242. Rossie, J. P. and Williams, W. A., "The Cost of
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243. Rowe, W. H. and Laurino, R. R., "Design of Liquid
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244. Ruckelshaus, W. D. and Quarles, J. R., "The First
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245. Ryan, F. P-, "Condenser Retubed in 24 Days", Power
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246. Ryan, P. J. and Harleman, D. R. F., An Analytical
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247. Ryan, W. F., "Cost of Power".
248. Schieber, J. R., "Control of Cooling Water Treatment -
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249. Schoenwetter, H., Cooling Tower, Condenser and Turbine
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250. Schoenwetter, H. D., Indian Point Nuclear Station
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BSR~report, (June 28, 1972) . ~
251. Schoenwetter, H. D., Lgyett^Station Space Utilization
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490
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252. Schoenwetter, H.f Updated Site Selection Report
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253. Schreiber, D. L., "Missouri River Hydrology (Streamflow
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254. Kettner, J.E., et al, "Sherburne County Generating
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Proceedings of the American Power Conference,
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255. Schurr, S. H., Energy Research Needs, Resources fo
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256. Schuster, R., "The Year of the Gas Turbine", Power
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257. Seels, F. H., "Industrial Water Pretreatment",
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258. Shafir, S., "Industrial Microbiocides for Open
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259. Shah, K. L. and Reid, G. W., "Techniques for Estimating
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260. Shirazi, M. A., "Dry Cooling Towers for Steam Electric
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261. Shirazi, M. A. , Thermoelectric Generators Powered by
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263. Silvestri, Jr., G. J. and Davids, J., "Effects of High
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264. Simpson, R. W. and Garlow, W., "Design of Settling Units
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491
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265. Site Selection Report for Nuclear Prelect No. 2
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266. Skrotzki, B. G. A. and Vopat, W. A., Power Station
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267. Slack, A. V., "Removing S02 from Stack Gases,"
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268. Smith, R., "Cost of Conventional and Advanced
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269. Smith, E. C. and Larinoff, M. W., "Power Plant Siting,
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270. Some Considerations in the Use of Cooling Water for
Inland Power Plant Sites in California, Assembly
Science and Technology Advisory Council, A report
to the Assembly General Research Committee, Calif.
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271. "Effects and Methods of Control of Thermal Discharges:
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272. Sonnichsen, Jr. J. C., et al. Cooling Ponds - A Survey
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274. Standard Methods - Water and Wastewater, American Public
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275. Standard of Performance for New & Substantially
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492
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276. Statistics of Privately Owned Electric Utilities
iS_the_Ui_si_z_1970r Federal Power Commission,
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277. Statistics of Publicly Owned Electric Utilities
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278. Steam. Its Generation and Use, The Babcock & Wilcox
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279. Steam Electric Plant Factors. National Coal Assoc.,
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280. Steam Electric Plant, Air and Water Quality Control,
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281. Steam Electric Plant Construction Cost and
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282. Stille, M. M., "Tampa Electric Goes Stainless",
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283. Stockham, J., Cooling Tower Study , Report for EPA,
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284. Stott, W. J., "Chemicals for Water Treatment",
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285. Stumm, W. and Morgan, J. J., Aguatic Chemistry,
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286. Summary of Recent Technical Information Concerning
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287. Swengel, F. M. , "Quick-Start and Cyclic Capacity for
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288. Technical & Economic Feasibility of Non-Coastal Power
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289. The Cherne Thermal Rotor System, Cherne Industrial, Inc.
493
-------
290. The Electricity Supply Industry. 22nd Inquiry, The
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291. The Industrial Wastes Studies Program, Summary Report
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292. The 1970 National Power Survey, Parts I, II,III, and IV
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293. "The Energy Crisis", Mechanical Engineering, pp. 29-36,
(January 1973) . ~~
294. The Water Use and Management Aspects of Steam Electric
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295. Thermal Effects and U. S, Nuclear Power Stations
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AEC, (August 1971) .
296. Thermal Pollutien - 1968, Part 3 - Hearings before the
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297. Thermal Pollution - .1968, Part 4 - Hearings before
the Subcommittee on Air and Water Pollution of the
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298. Thompson, A. R., "Cooling Towers, A Water Pollution
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299. Tichenor, B. A. and Christiansen, A. G., "Cooling Pond
Temperature versus Size and Water Loss", Journal of the
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300. Toone, D. E., "Spray Pond Cooling Water Requires Careful
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301. Twenty Fourth Survey of Electric Power Equipment,
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494
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303. Walko, j. F., "Controlling Biological Fouling in Cooling
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304. Walters, M. L. , "Cooling Tower Maintenance Problems
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305. Waste_Heat_from Steam-Electric Generating Plants using
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307. "Water Pollution Control", Chemical Engineering,
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308. Water Quality and Treatment. McGraw-Hill Co., N. Y.
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309. Water Quality Standards Criteria Digest - A Compilation
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310. Water Quality Standards Criteria Digest - A Compilation
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311. "Water, Water Everywhere, But not a Drop... For Cooling",
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312. Weight, R. H., "Ocean Cooling Water System for 800 MW
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313. Wilmoth, R. C. and Hill, "Neutralization of High Ferric
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314. Winkelman, F. W., Modern Practices in Handling the
Pr-orh^j-g of rombustion from Coal Fired Steam Generators
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315. Winkelman, F. W., "Systems Available for Removing Oil
Soot from Precipitator Hoppers", Power. (June 1972).
495
-------
316. Winiarski, L. D. and Byram, K. V., "Reflective Cooling
Ponds", ASME Paper 70 WA/PWR-4.
317. Winiarski, L. D. and Tichenor, B. A., "Model of Natural
Draft Cooling Tower Performance", Journal of the Sanitary
Eng. Div.. ASCE, pp. 927-943, (August 1970) .
318. Woodson, R. D., "Cooling Alternatives for Power Plants",
paper presented to Minnesota Pollution Control Agency
(November 30, 1972) .
319. Woodson, R. D., "Cooling Towers"
320. World Power Data 1969, Federal Power Commission
"(March 1972) .
321. Wrinkle, R. B., "Performance of Counterflow Cooling
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322. Yarosh, M. M., et al. Agricultural & Aquacultural
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ORNL 4997, (July 1972) .
323. Young, R. A., "Combined Treatment Answers - Two Problems
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324. Zanker, A., "Estimating Cooling Tower Costs from Operating
Data"-
325. An Evaluation of the Feasibility of Salt Water Cooling
Towers for Turkey Point, Southern Nuclear Engineering,
Inc., (February 1970).
326. An Evaluation of the Powered Spray Module for Salt
Water Service for Turkey Point, Southern Nuclear
Engineering, Inc., (May 1970)7
327. Control of Thernral Pollution - A Preliminary Report,
Struthers Research & Development Corp., (September 25,
1968) .
328. Perry, J. H., Editor, Chemical Engineers Handbook,
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329. Lund, H. F., Industrial Pollution Control Handbook,
McGraw-Hill Book Co., N. Y. (1971).
330. Iranzen, A. E., et al, "Tertiary Treatment of Process
Water", Chem. Eng. Prog., Vol. 68, No. 8, (August 1972).
496
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331. Unit_Process Operating and Maintenance Costs for
Conventional Waste^Treatment^Plants, u. S. Dept. of
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332. Smith, A. P. and Eacon, S. W., "Economic Boiler Makeup
with Four-Bed Deionizer in Two Vessels", Power Engineering,
(April 1973) .
333. Sawyer, J. A., "New Trends in Wastewater Treatment and
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334. "Pollution Control Cost", Chemical Week. (June 1970).
335. DeLorenzi, O., Editor, Combustion Engineering,
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336. Freedman, A. J. and Shannon J. E., "Modern Alkaline
Cooling Water Treatment", Industrial Water Engineering,
p. 31, (January/February 1^73) .
337. Disposal of Wastes from Water Treatment Plants, AWWA
Research Foundation Report, Part 1 Journal AWWA,
Vol. 61, No. 10, p. 541, Part 2, Vol. 61, No. 11, p. 619,
Part 3, Vol. 61, No. 12, p. 681, Part 4, Vol. 62, No. 1,
p. 63, (October/November/December 1969 and January 1970) .
338. Beychok, M. R., "Kastewater Treatment", Hydrocarbon
Processing, (December 1971) .
339. Oil-Water Separator Process Design, Disposal of Refinery
Waste, Volume on Liquid Wastes, API, pp. 5-3 to 5-13,
(1969) .
340. Morrison, J., "lilted-Plate Separators for Refinery
Waste Water", Oil & Gas Journal, (December 14, 1970).
341. Pollution Control, "Methods for Cleaning Seas", Marine
Enaineering/Log, (July 1971).
342. Wurtz, C. B. and Renn, C. E., Water Temperatures and
Aquatic Life, Report No. 1, The John Hopkins University,
Cooling Water Studies for Edison Electric Institute,
(June 1, 1965).
343. Jensen, L. D., et al, The Effects of Elevated Temperature
Upon Aquatic Invertebrates, Report No. 4, The John
Hopkins University, Cooling Water Studies for Edison
Electric Institute, (September 1969).
497
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344. Marks, D. H. and Borenstein, R. A., An Optimal Siting
Model for Thermal Plants with Temperature Constraints,
Report No. 6, The Johns Hopkins University, Cooling
Water Studies fcr Edison Electric Institute,
(August 1970) .
345. Brady, D. K. and Geyer, J. C., Development of a General
Commuter^Model £or Simulating Thermal Pishearges in
Three Dimensions, Report No. 7, The Johns Hopkins
University, Cooling Water Studies for Edison Electric
Institute, (February 1972).
350. Somers, E. V., et al, "Beneficial Uses of Waste Heat
from Electric Pcwerplants for New Town Heating and
Cooling", Scientific Paper 71-1E8-TECOL-P1, Westing-
house Research Lafcrcatories, Pittsburgh, Pennsylvania,
(May 19, 1971) .
351. Beal, S. E. and Samuels, G., "The Use of Warm Water
for Heating and Cooling Plant and Animal Enclosures",
Oak Ridge National Laboratory (June 1971).
352. Use of Waste Heat for Greenhouse Heating and Cooling,
Progress Report, Agricultural Resource Development
Branch.
353. Bond, B. J., et al, "Beneficial Uses of Waste Heat",
TVA Projects Paper presented at the National Conference
on Complete Water Reuse, Washington, D. C. (April 23-27,
1973) .
354. Yar.osh, M. M., "Waste Heat Utilization", proceedings of
the National Conference, Gatlinburg, Tennessee (May 1972)
355. Miller, A. J., et al, "Use of Steam-Electric Powerplants
to Provide Thermal Energy to Urban Areas", Oak Ridge
National Laboratory, Oak Ridge, Tennessee (January 1971).
356. Austin, G., et al, "Multilevel Outlet Works at Four
Existing Reservoirs", Journal of Hydraulics Division,
Proceedings of the ASCE, (November 1969) . ~"
357. Preparation of Environmental Reports for Nuclear Plants,
Regulatory Guide 4.2, U. S. Atomic Energy Commission,
Directorate of Regulatory Standards, (March 1973) .
358. The Fan-Assisted Natural^Draft Cooling Tower, Res earch-
Cottrell, Inc., Hamon Cooling Tower Division, N. J.
498
-------
359. Ford, G. L. , "Combined Condenser Cooling System Ups
Plant Availability", Power Engineering.
360. The Cherne Fixed Thermal Rotor System Demonstration,
Interim Test Report, Allen S. King Plant (August/
October 1972).
361. "Projected Steam Units 300 MW and Larger" Reported
to FPC April 1, 1973 by Regional Reliability Councils
in Response to Appendix A of Order 383-3.
362. Kolflat, T.D., "Cooling Tower Practices" Power
Engineering (January, 1974).
363. Wistrom, G.R. and J.C. Ovard, "Cooling Tower Drift -
Its Measurement, Control, and Environmental Effects,"
Paper presented at Cooling Tower Institute Houston
Meeting (January, 1973).
364. Smith, W. S., et al, "Atmospheric Emissions from
Coal Combustion - An Inventory Guide", U. S. Dept.
of HEW., Publication No. 999 AP-24, (April 1966).
365. Kool-Flow, Water Cooling System for Controlling
Thermal Pollution, Richards of Rockford, Inc., 111.
366. An Evaluation of the Powered Spray Module for Salt
Water Service for Turkey Point, Southern Nuclear
Engineering, Inc., (May 1970).
367. Boyack, B. E. and Kearney, D. W., Plume Behavior
and Potential Environmental Effects of Large Dry
Cooling Towers, Final Report - Gulf General Atomic,
(February 1973).
368. Jedlicka, C.L., "Nomographs for Thermal Pollution
Control Systems" U. S. Environmental Protection Agency
Report EPA-660/2-73-004 (September, 1973).
369. Mulbarger, M. C., Sludges and Brines Handling,
Conditioning, Treatment and Disposal, Ultimate
Disposal Research Activities, Division of Research,
FWPCA Cincinnati Water Research Laboratory (1968).
370. Considerations Affecting Steam Power Plant Site Selection,
A report sponsored by The Energy Policy Staff, Office of
Science and Technology (1968).
371. Curry, Nolan A., Philosophy and Methodology of Metallic
Waste Treatment, Paper presented at the 27th Industrial
Waste Conference, Purdue University, May 2-4, 1972.
499
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372. Jones, D.B. and W.E. Wienie, "Recovery of Chromate
from Cooling Water System Slowdown Water," Goodyear
Atomic Corp. for U.S. Atomic Energy Commission
(December 1, 1966).
373. Richardson, E.W., et al, "Waste Chromate Recovery
by Ion Exchange," Union Carbide Corp. for U.S. Atomic
Energy Commission (April 3, 1968).
374. "Process Design Manual for Phosphorus Removal" Black and
Veatch for U.S. Environmental Protection Agency
(October, 1971).
375. "Development Document for Proposed Effluent
Limitations Guidelines and New Source
Performance Standards for the Basic
Fertilizer Chemicals Segment of the Fertilizer
Manufacturing Point Source Category
"U.S. Environmental Protection Agency (November
1973).
376. Nelson, Guy R., "Predicting and Controlling Residual
Chlorine in Cooling Tower Blowdown "U.S. Environmental
Protection Agency (July, 1973).
377. "Current Practices - Factors Influencing Need for Chemical
Cleaning Boilers" ASME Research Committee Task Force
on Boiler Feedwater Studies Presented to American Power
Conference (May, 1973).
378. Goldman, E. and P.J. Kelleher, "Water Reuse in Fossil-
Fueled Power Stations" Paper presented at the National
Conference on Complete Watereuse sponsored by the
American Institute of Chemical Engineers and the
U.S. Environmental Protection Agency (April, 1973).
379. "Development Document for Proposed Effluent Limitations
Guidelines and New Source Standards for the Copper,
Nickel, Chromium, and Zinc Segment of the Electroplating
Point Source Category"zU.S. Environmental Protection
Agency (August, 1973).
380. "Processes, Procedures and Methods to Control Pollution
z from Mining Activities," U.S. Environmental Protection
Agency (October, 1973).
381. "Environmental Report, Beaver Valley Power Station
Unit 1 - Operating License Stage, "Duquesne Light Company
(September, 1971).
500
-------
382. "Processes, Procedures, and Methods to Control Pollution
Resulting from All Construction Activity," U.S. Environmental
Protection Agency (October, 1973).
383. Mercer, B.W. and R.T. Jaske, "Methods for Reducing
Demineralizer Waste Discharges from Thermo-Electric
Power Plants" Paper presented at National Conference
on Complete Watereuse, sponsored by the America
Institute of Chemical Engineers and the U.S.
Environmental Protection Agency (April, 1973).
384. Burns, V.T., Jr., "Reverse Osmosis Water Treatment at
Harrison Power Station," Paper presented at American
Power Conference (May, 1973).
385. Roffman, A., et al, "The State of the Art of Saltwater
Cooling Towers for Steam Electric Generating Plants"
prepared for the U.S. Atomic Energy Commission (February,
1973).
386. "Review of Wastewater Control Systems" Tennessee Valley
Authority (separate documents for each TVA powerplant).
501
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SECTION XIV
GLOSSARY
Absolute Pressure
The total force per unit area measured above absolute vacuum as a
reference. standard atmospheric pressure is 101,326 M/m* (14.696 psi)
above absolute vacuum (zero pressure absolute).
Absolute Temperature
The temperature measured from a zero at which all molecular activity
ceases. The volume of an ideal gas is directly- proportional to its
absolute temperature. It is measured in °K (°R) corresponding to °C +
273 (°F * 459).
Acid
A substance which dissolves in water with the formation of hydrogen ion.
A substance containing hydrogen which may be displaced by metals to form
salts.
Acidity
The quantitative capacity of aqueous solutions to react with hydroxyl
ions (OH-). The condition of a water solution havi-ng a pH of less than
7.
Agglomeration
The coalescence of dispersed suspended matter into larger floes or
particles which settle more rapidly.
A soluble substance which when dissolved in water yields hydroxyl ions.
Alkalies combine with acids to yield neutral salts.
Alkaline
The condition of a water solution having a pH concentration greater than
7.0, and having the properties of a base.
Alkalinity
The capacity to neutralize acids, a property imparted to water by its
content of carbonates, bicarbonates, and hydroxides. It is expressed in
milligrams per liter of equivalent CaCO3_.
503
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Anion
The charged particle in a solution of an electrolyte which carries a
negative charge.
Anthracite
A hard natural coal of high luster which contains little volatile
matter.
Approach Temperature
The difference between the exit temperature of water from a cooling
tower, and the wet bulb temperature of the air.
Ash
The solid residue following combustion of a fuel.
Ash Sluice
The transport of solid residue ash by water flow in a conduit.
Backwash
Operation of a granular fixed bed in reverse flow to wash out sediment
and reclassify the granular media.
Bag Filters
A fabric type filter in which dust laden gas is made to pass through
woven fabric to remove the particulate matter.
Base
A compound which dissolves in water to yield hydroxyl ions (OH~).
Base-load Unit
An electric generating facility operating continuously at a constant
output with little hourly or daily fluctuation.
Biocide
An agent used to control biological growth.
Bituminous
A coal of intermediate hardness containing between 50 and 92 percent
carbon.
504
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Slowdown
A portion of water in a closed system which is wasted in order to
prevent a build-up of dissolved solids.
BOD
Biochemical oxygen demand. The quantity of oxygen required for the
biochemical oxidation cf organic matter in a sewage or industrial waste
in a specific time, at a specified temperature and under specified
conditions. A standard test to assess wastewater pollution level.
A device in which a liquid is converted into its vapor state by the
action of heat. In the steam electric generating industry, the
equipment which converts water into steam.
Boiler Feedwater
The water supplied to a boiler to be converted into steam.
Boiler Fireside
The surface of boiler heat exchange elements exposed to the hot
combustion products.
Boiler Scale
An incrustation of salts deposited on the waterside of a boiler as a
result of the evaporation of water.
Boiler Tubes
Tubes contained in a boiler through which water passes during its
conversion into steam.
Bottom Ash
The solid residue left from the combustion of a fuel, which falls to the
bottom of the combustion chamber.
Brackish Water
Water having a dissolved solids content between that of fresh water and
that of sea water, generally from 1000 to 10,000 mg per liter.
Brine
'Water saturated with a salt.
505
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Bus Bar
A conductor forming a common junction between two or more electrical
circuits. A term commonly used in the electric utility industry to
refer to electric power leaving a station boundary. Bus bar costs would
refer to the cost per unit of electrical energy leaving the station.
Capacity Factor
The ratio of energy actually produced to that which would have been
produced in the same period had the unit been operated continuously at
rated capacity.
The charged particles in solution of an electrolyte which are positively
charged.
Carbonate Hardness
Hardness of water caused by the presence of carbonates and bicarbonates
of calcium and magnesiurr.
Chemical Oxygen Demand (COD)
A specific test to measure the amount of oxygen required for the
complete oxidation of all organic and inorganic matter in a water sample
which is susceptible to oxidation by a strong chemical oxidant.
Circulating Water Pumps
Pumps which deliver cooling water to the condensers of a powerplant.
Circulating Water System
A system which conveys cooling water from its source to the main
condensers and then to the point of discharge. Synonymous with cooling
water system.
Clarification
A process for the removal of suspended matter from a water solution.
Clarifier
A basin in which vvater flows at a low velocity to allow settling of
suspended matter.
506
-------
Closed Circulating Water System
A system which passes water through the Condensers, then through an
artificial cooling device, and keeps recycling it.
Coal Pile Drainage
Runoff from the coal pile as a result of rainfall.
Cgndensate Polisher
An ion exchanger used to adsorb minute quantities of cations and anions
present in condensate as a result of corrosion and erosion of metallic
surfaces.
Condenser j
A device for converting a vapor into its liquid phase.
Construction
Any placement, assembly, or installation of facilities or equipment
(including contractual obligations to purchase such facilities or
equipment) at the premises where the equipment will be used, including
preparation work at the premises.
A device for converting a vapor into its liquid phase.
Convection
The heat transfer mechanism arising from the motion of a fluid.
Cooling Canal
A canal in which warm water enters at one end, is cooled by contact with
air, and is discharged at the other end.
Cooling Lake
See Cooling Pond
Cooling Pond
A body of water in which warm water is cooled by contact with air, and
is either discharged cr returned for reuse.
Cooling Tower
A configured heat exchange device which transfers reject heat from
circulating water to the atmosphere.
507
-------
Cooling Tower Basin
A basin located at the bottom of a cooling tower for collecting the
falling water.
Sstem
See Circulating Water System
Corrosion Inhibitor
A chemical agent which slows down or prohibits a corrosion reaction.
CQunterf low
A process in which two media flow through a system in opposite
directions.
Critical Point
The temperature and pressure conditions at which the saturated-liquid
and saturated- vapor states of a fluid are identical. For water- steam
these conditions are 3208.2 psia and 705.U7°F.
Cycling Plant
A generating facility which operates between peak load and base load
conditions. In this report, a facility operating between 2000 and 6000
hours per year.
Cyclone Furnace
A water-cooled horizontal cylinder in which fuel is fired, heat- is
released at extremely high rates, and combustion is completed. The hot
gases are then ejected into the main furnace. The fuel and combustion
air enter tan gent ially, imparting a whirling motion to the burning fuel,
hence the name Cyclone Furnace. Molten slag forms on the cylinder
walls, and flows off for removal.
Deae ration
A process by which dissolved air and oxygen are stripped from water
either by physical or chemical methods.
De aerator
A device for the removal of oxygen, carbon dioxide and other gases from
water.
508
-------
neqasification
The removal of a gas from a liquid.
Deionizer
A process for treating water by removal of cations and anions.
Demineralizer
See Deionizer
Demister
A device for trapping liquid entrainment from gas or vapor streams.
Dewater
To remove a portion of the water from a sludge or a slurry.
Dew Point
The temperature of a gas-vapor mixture at which the vapor condenses when
it is cooled at constant humidity.
Diesel
An internal combustion engine in which the temperature at the end of the
compression is such that combustion is initiated without external
ignition.
Discharge
To release or vent.
Discharge Pipe or Conduit
A section of pipe or conduit from the condenser discharge to the point
of discharge into receiving waters or cooling device.
Drift
Entrained water carried from a cooling device by the exhaust air.
Bottom Furnace
Refers to a furnace in which the ash is collected as a dry solid in
hoppers at the bottom of the furnace, and removed from the furnace in
this state.
509
-------
Dry Tower
A cooling tower in which the fluid to be cooled flows within a closed
system. This type of tower usually uses finned or extended surfaces.
Dry. Well
A dry compartment of a pump structure at or below pumping level, where
pumps are located.
Economizer
A heat exchanger which uses the heat of combustion gases to raise the
boiler feedwater temperature before the feedwater enters the boiler.
Electrostatic Precipitator
A device for removing particles from a stream of gas based on the
principle that these particles carry electrostatic charges and can
therefore be attracted to an electrode by imposing a potential across
the stream of gas.
Evaporation
The process by which a liquid becomes a vapor.
Evaporator
A device which converts a liquid into a vapor by the addition of heat.
Feedwater Heater
Heat exchangers in which boiler feedwater is preheated by steam
extracted from the turbine.
Filter Bed
A device for removing suspended solids from water, consisting of
granular material placed in horizontal layers and capable of being
cleaned hydraulically by reversing the direction of the flow.
Filtration
The process of passing a liquid through a filtering medium for the
removal of suspended cr colloidal matter.
Fireside Cleaning
Cleaning of the outside surface of boiler tubes and combustion chamber
refractories to remove deposits formed during the combustion*
510
-------
FlOC
Small gelatinous masses formed in a liquid by the reaction of a
coagulant added thereto, thru biochemical processes, or by
agg lome r ati on.
Flue Gas
The gaseous products resulting from the combustion process after passage
through the boiler.
Fly. Ash
A portion of the nen-combustible residue from a fuel which is carried
out of the boiler by the flue gas
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