United States Industrial Environmental Research EPA-600/7-80-012b
Environmental Protection Laboratory March 1980
Agency Research Triangle Park NC 27711
Waste and Water
Management for
Conventional Coal
Combustion Assessment
Report - 1979;
Volume II.
Water Management
Interagency
Energy/Environment
R&D Program Report
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide'range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-80-012b
March 1980
Waste and Water Management for
Conventional Coal Combustion
Assessment Report - 1979;
Volume II. Water Management
by
C.J. Santhanam, R.R. Lunt, C.B. Cooper,
D.E. Klimschmidt, I. Bodek, and W.A. Tucker (ADL);
and C.R. Ullrich (University of Louisville)
Arthur D. Little, Inc.
20 Acorn Park
Cambridge, Massachusetts 02140
Contract No. 68-02-2654
Program Element No. EHE624A
EPA Project Officer: Julian W. Jones
Industrial Environmental Research Laboratory
Office of Environmental Engineering and Technology
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
-------
PARTICIPANTS IN THIS STUDY
This First Annual R&D Report is submitted by Arthur D. Little, Inc.
to the U. S. Environmental Protection Agency (EPA) under Contract No.
68-02-2654. The Report reflects the work of many members of the
Arthur D. Little staff, subcontractors and consultants. Those partici-
pating in the study are listed below.
Principal Investigators
Chakra J. Santhanam
Richard R. Lunt
Charles B. Cooper
David E. Kleinschmidt
Itamar Bodek
William A. Tucker
Contributing Staff
Armand A. Balasco Warren J. Lyman
James D. Birkett Shashank S. Nadgauda
Sara E. Bysshe James E. Oberholtzer
Diane E. Gilbert James I. Stevens
Sandra L. Johnson James R. Valentine
Subcontractors
D. Joseph Hagerty University of Louisville
C. Robert Ullrich University of Louisville
We would like to note the helpful views offered by and discussions
with Michael Osborne of EPA-IERL in Research Triangle Park, N. C. , and
John Lum of EPA-Effluent Guidelines Division in Washington, D. C.
Above all, we thank Julian W. Jones, the EPA Project Officer, for
his guidance throughout the course of this work and in the preparation
of this report.
ii
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ACKNOWLEDGEMENTS
Many other individuals and organizations helped by discussions with
the principal investigators. In particular, grateful appreciation is
expressed to:
Aerospace Corporation - Paul Leo, Jerome Rossoff
Auburn University - Ray Tarrer and others
Department of Energy - Val E. Weaver
Dravo Corporation - Carl Gilbert, Carl Labovitz, Earl Rothfuss
and others
Electric Power Research Institute (EPRI) - John Maulbetsch,
Thomas Moraski and Dean Golden
Environmental Protection Agency, Municipal Environmental Research
Laboratory - Robert Landreth, Michael Roulier, and Don Sanning
Federal Highway Authority - W. Clayton Ormsby
IU Conversion Systems (IUCS) - Ron Bacskai, Hugh Mullen
Beverly Roberts, and others
Louisville Gas and Electric Company - Robert P. Van Ness
National Ash Association - John Faber
National Bureau of Standards - Paul Brown
Southern Services - Reed Edwards, Lament Larrimore, and Randall Rush
Tennessee Valley Authority (TVA) - James Crowe, T-Y. J. Chu,
H. William Elder, Hollis B. Flora, R. James Ruane,
Steven K. Seale, and others
iii
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CONVERSION FACTORS
English/American Units
Length:
1 inch
1 foot
1 fathom
1 mile (statute)
1 mile (nautical)
Area :
1 square foot
1 acre
Volume:
1 cubic foot
1 cubic yard
1 gallon
1 barrel (42 gals)
Weight/Mass:
1 pound
1 ton (short)
Pressure:
1 atmosphere (Normal)
1 pound per square inch
1 pound per square inch
Concentration:
1 part per million (weight)
Speed:
1 knot
Energy/Power:
1 British Thermal Unit
1 megawatt
1 kilowatt hour
Temperature:
1 degree Fahrenheit
Metric Equivalent
2.540 centimeters
0.3048 meters
1.829 meters
1.609 kilometers
1.852 kilometers
0.0929 square meters
4,047 square meters
28.316 liters
0.7641 cubic meters
3.785 liters
0.1589 cu. meters
0.4536 kilograms
0.9072 metric tons
101,325 pascal
0.07031 kilograms per square centimeter
6894 pascal
1 milligram per liter
1.853 kilometers per hour
1,054.8 joules
3.600 x 109 joules per hour
3.60 x 106 joules
5/9 degree Centigrade
iv
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GLOSSARY
Cementitious: A chemically precipitated binding of particles
resulting in the formation of a solid mass.
Fixation: The process of putting into a stable or unalterable
form.
Impoundment: Reservoir, pond, or area used to retain, confine,
or accumulate a fluid material.
Leachate: Soluble constituents removed from a substance by the
action of a percolating liquid.
Leaching Agent: A material used to percolate through something
that results in the leaching of soluble constituents.
Pozzolan: A siliceous or aluminosiliceous material that in
itself possess little or no cementitious value but that in
finely divided form and in the presence of moisture will react
with alkali or alkaline earth hydroxide to form compounds possessing
cementitious properties.
Pozzolanic Reaction; A reaction producing a pozzolanic product.
Stabilization: Making stable by physical or chemical treatment.
-------
ABBREVIATIONS
BOD biochemical oxygen demand
Btu British thermal unit
cc cubic centimeter
cm centimeter
COD chemical oxygen demand
°C degrees Centigrade (Celcius)
°F degrees Fahrenheit
ESP electrostatic precipitator
FGC flue gas cleaning
FGD flue gas desulfurization
ft feet
g gram
gal gallon
gpd gallons per day
gpm gallons per minute
hp horsepower
hr hour
in. inch
j joule
j/s Joule per second
k thousand
kg kilogram
kCal kilocalorie
km kilometer
kw kilowatt
kwh kilowatthour
Si or lit liter
lb pound
M million
•a?- square meter
in^ cubic meter
mg milligram
MGD million gallons per day
MW megawatt
MWe megawatt electric
MWH megawatt hour
yg microgram
mil milliliter
min minute
ppm parts per million
psi pounds per square inch
psia pounds per square inch absolute
scf/m standard cubic feet per minute
sec second
TDS total dissolved solids
TOS total oxidizable sulfur
TSS total suspended solids
tpy tons per year
yr year
vi
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TABLE OF CONTENTS
ACKNOWLEDGEMENTS iv
CONVERSION FACTORS v
GLOSSARY vi
ABBREVIATIONS vii
LIST OF TABLES xii
LIST OF FIGURES xvii
1.0 INTRODUCTION 1-1
1.1 Purpose and Content 1-1
1.2 Report Organization 1-5
2.0 WATER USAGE IN POWER PLANTS 2-1
2.1 Overall Perspective 2-1
2.2 Water Balance in Coal-Fired Plants 2-22
2.3 Current R&D Studies 2-26
3.0 OVERALL WATER BALANCES IN POWER PLANTS 3~i
3.1 Waste Stream Flows 3~1
3.1.1 Condenser Cooling System 3~1
3.1.2 Steam Generation 3~2
3.1.3 Water Treatment Systems 3~2
3.1.4 Ash Handling Systems 3~^
3.1.5 Flue Gas Desulf urization (FGD) Systems 3~^
3.1.6 Miscellaneous Operations 3~°
f -3 _ -i
3.1.7 Maintenance Cleaning J '
3.1.8 Drainage 3~8
3.2 Treatment Technology in General 3~9
3.3 Condenser Cooling System Wastes 3-17
3.3.1 General 3~17
3.3.2 Once-Through Cooling 3~17
3.3.3 Recirculating Systems 3~20
3.3.4 Water Conservation and Chemical 3-2 j
Waste Streams
3.3.5 Wet Cooling Tower 3~24
3.3.6 Cooling Tower Blowdown Treatment 3~36
3.4 Steam Generation Wastes
vii
3-62
-------
TABLE OF CONTENTS
(Continued)
Page
3.4.1 System Operation 3-62
3.4.2 Waste Characteristics 3-66
3.4.3 Boiler Slowdown Treatment Options 3-66
3.5 Water Treatment Systems 3-69
3.5.1 System Operation 3-69
3.5.2 Waste Characteristics 3-70
3.5.3 Treatment Options and Economics 3-76
3.5.4 Trends in Water Treatment 3-76
3.6 Ash Handling 3-79
3.6.1 Ash Characteristics 3-79
3.6.2 Ash Collection-Handling Systems 3-82
3.6.3 Conveying Systems to Storage or Disposal 3-87
3.6.4 System Design Considerations 3-89
3.6.5 Waste Streams from Ash Handling 3-90
3.6.6 Present Treatment Methods 3-101
3.6.7 Treatment Options for Recycle/Reuse 3-104
3.6.8 Dry Handling Systems 3-112
3.6.9 Economics of Treatment 3-112
3.7 FGD Systems 3-113
3.7.1 Process Description 3-113
3.7.2 Makeup Water Requirements 3-120
3.7.3 Water Recycle Options 3-127
3.7.4 Recent Studies 3-130
3.8 Miscellaneous Operations 3-132
3.8.1 Description of Operations 3-132
3.8.2 Waste Characteristics 3-133
3.8.3 Treatment Options 3-133
3.8.4 Recycle/Reuse 3-133
3.9 Maintenance Cleaning Wastes 3-135
3.9.1 Description of Operations 3-135
3.9.2 Waste Characteristics 3-138
3.9.3 Treatment Options 3-139
3.10 Drainage 3-U6
3.10.1 Description 3~146
viii
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TABLE OF CONTENTS
(Continued)
3.10.2 Waste Characteristics 3-147
3.10.3 Treatment Options 3-150
4.0 REGULATORY CONSIDERATIONS 4-1
4.1 Existing and Proposed Regulations 4-1
4.1.1 Wastewater Discharges Requiring
NPDES Permit 4-1
4.1.2 Discharges to a Publicly Owned
Treatment Works (POTW) 4-4
4.1.3 Water Intakes 4-6
4.1.4 Remand Decision 4-7
4.1.5 Priority Pollutant Removal 4-9
4.1.6 "Zero Discharge" Goal of PL 92-500 4-11
4.1.7 Clean Water Act of 1977 (PL 95-217) 4-13
4.1.8 Resource Conservation and Recovery
Act of 1976 (RCRA) 4-13
4.1.9 National Energy Act of 1978 4-14
4.2 Possible Future Regulations 4-15
4.2.1 A Multimedia Approach May be Required 4-15
4.2.2 Interrelationship of Toxics Controls
and Water Reuse Technology 4-16
5.0 RECYCLE/REUSE OF WATER 5-1
5.1 General 5-1
5.2 Combined Central Treatment 5-1
5.2.1 Wastewater Management 5-1
5.2.2 Treatment Technology 5-2
5.2.3 Central Treatment System 5-2
5.3 Water Reuse Considerations 5-5
5.3.1 General 5-5
5.3.2 Technology for Reuse 5-8
5.3.3 Reuse Schemes 5-14
5.3.4 Toxic Substances Control 5-28
5.3.5 Dry Systems 5-30
5.4 Overview on System Constraints 5-39
ix
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LIST OF TABLES
Table No. Pag p.
2.1 Water Used for Electric Utility Generation
of Thermoelectric Power, In Million Gallons
per Day, By States, 1975 2-2
2.2 Power Production, 1975 2-4
2.3 Trends in Steam Electric Power Generation 2-5
2.4 Projected Electric Power Generation by Fuel 2-7
2.5 Water Used for Electric Utility Generation of
Thermoelectric Power, in Million Gallons
per Day, By Region, 1975 2-8
2.6 Annual Water Requirements for Steam-Electric
Power Plants 2-10
2.7 General Information Summary Condenser Cooling
Systems 2-13
2.8 Number of Plants, Capacities, and Types of
Cooling by Water Resource Region, 1973 2-15
2.9 Average Cooling Water Use, By Water Resource
Regions, 1973 2-16
2.10 Coal-Fired Steam-Electric Power Plants with
Cooling Towers, 1975 2-17
2.11 Coal-Fired Steam-Electric Power Plants witii
Cooling Ponds, .1975' , 2-20
2.12 Use of Chemical Additives by Water Resources
Region 1973 2~23
2.13 EPA Projects Concerning Water Recycle/Treatment/
Reuse in Power Plants 2-27
2.14 EPRI Projects Concerning Water Recycle/Treading/
Reuse in Power Plants 2-28
3.1 Chemical Waste Categories - Coal-Fired Power
Plants 3-10
3.2 Summary of Chemical Characteristics of Utility
Effluent Systems (Coal-Fired Plants) 3-11
xi
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LIST OF TABLES
(Continued)
Table No. Page
3.21 Boiler Slowdown Flowrates 3~68
3.22 Typical Water Treatment Wastewater Flows 3-73
3.23 Water Treatment Wastes in Coal-Fired
Power Plants 3~75
3.2A Ion Exchange Material Types and Regenerant
Requirement 3-78
3.25 Fly Ash/Bottom Ash Percentages 3~81
3.26 Ash Handling Systems 3-83
3.27 Coal Ash Handling at Power Plants 3-91
3.28 Typical Ash Pond Inlet and Discharge 3-93
3.29 Characteristics of Once-Through Combined
Ash Pond Discharges 3-97
3.30 Relationships Between Plant Operation
Conditions and pH Values of Ash Pond
Effluents at Ten Coal-Fired Power Plants 3-98
3.31 Ash Reactivity Determined from Leaching
Studies 3-100
3.32 Effluent Guidelines and Standards for
Power Plant Ash Ponds 3-105
3.33 Ryznar Stability Index 3-108
3.34 Suggested Control Limits for Ash Pond
Recirculating Water 3-110
3.35 Recirculating Bottom Ash System with
Treatment of Bottom Ash Blowdown 3-114
3.36 Recirculating Bottom Ash System with
Combined Ash Pond Overflow 3-115
3.37 Process Factors Affecting Water Balances
in Nonregenerable FGC Scrubber Systems 3-124
xiii
-------
LIST OF TABLES
(Continued)
Table No. Page
3^38 Water Requirements for Generalized
Nonrecovery Scrubbing Systems 3-126
3.39 FGD Systems in Coal-Fired Plants 3-128
3.40 Sanitary Wastes in Power Plants 3-134
3.41 Wastewater Flow Range - Maintenance Cleaning 3-140
3.42 Raw Waste Flow and Loadings - Maintenance
Cleaning 3-141
3.43 Coal Pile Drainage 3-148
3.44 Typical Coal Pile Runoff Characteristics 3-149
4.1 Summary of Wastewater Guidelines and
Standards for Steam Electric Power
Plants (excluding heated discharges) 4-2
4.2 Summary of Effluent Limitations Guidelines
and Standards for Heat 4-3
4.3 Threshold Concentrations of Pollutants
that are Inhibitory to Biological Treat-
ment Processes 4-5
4.4 Priority Pollutants Potentially Present in
Utility Effluents 4-10
4.5 Total Metals Discharged from Power Plants in
the U.S. (1973) Compared to Other Industrial
Sources 4-12
4.6 Total Iron and Copper Discharges from Coal-
Fired Power Plants in the U.S., 1973 4-12
5.1 Treatment Technology for Wastewaters
in Power Plants 5-3
5.2 Capital and Operating Costs - Central Treatment 5-7
5.3 Radian Study for the EPA - Selected Plants for
Water Recycle/Reuse Study 5-18
xiv
-------
LIST OF TABLES
(Continued)
Table No.
Page
5.4 Radian Study for the EPA 5-20
5.5 Radian Study for the EPA 5-21
5.6 Radian Study for the EPA 5-22
5.7 Radian Study for the EPA 5-23
5.8 Radian Study for the EPA 5-24
5.9 Pollutants Reported in 308 Form for
Cooling Systems in Coal-Fired Power Plants 5-29
5.10 Priority Pollutant Removal on Selected
Technologies 5-31
5.11 Comparison of Technologies for Priority
Pollutants 5-32
5.12 Summary of Fly Ash Handling Systems Reported
by Coal-Fired Steam Electric Power Plants 5-36
5.13 Fly Ash Handling: Comparison of Wet and
Dry System Costs 5-38
6.1 Potential Impact Issues for Coal-Fired
Utility Cooling Systems and Ash Disposal
Systems 6-2
.6.2 Examples of Chemical Additives Characteristically
Found in Cooling Tower Slowdown as a Result of
Makeup Water Treatment 6-8
6.3 EPA Projects Concerning Water Recycle/Treatment
Reuse in Power Plants 6-25
6.4 EPRI Projects Concerning Water Recycle/Treatment
Reuse in Power Plants 6-26
xv
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LIST OF FIGURES
Figure No.
2.1 Water Resource Regions 2-9
2.2 Generalized Schematic Water Balance for
a Typical 1000 MW Coal-Fired Power Plant 2-25
3.1 Power Cycle Diagram 3-3
3.2 An Example of Recycle/Treatment/Reuse
Scheme for Coal-Fired Power Plants with FGD 3-15
3.3 Cooling Systems 3-18
3.4 Lime-Soda Ash Softening for Zero Discharge 3-48
3.5 Zeolite Softening for Zero Discharge 3-48
3.6 Chromate Removal by Reduction 3-50
3.7 Chromate Removal by Ion Exchange 3-51
3.8 Electrochemical Reduction of Chromium 3-52
3.9 Typical Water Treatment Processes 3-71
3.10 Silica Concentration in Boiler Water 3-72
3.11 Example of a Recirculating Bottom Ash System 3-94
3.12 Water Balance-Fly Ash Handling 3-95
3.13 Recirculating Bottom Ash Sluicing System
Slowdown Treatment 3-102
3.14 Treatment of Combined Ash Overflow 3-103
3.15 Langelier Saturation Index 3-106
3.16 Generalized FGD System 3-117
3.17 Limestone Slurry FGD System 3-118
3.18 Water Balance Factors for Nonregenerable
FGD Systems 3-121
5.1 Coal-Fired Plant - Central Treatment
of Wastewater 5-6
xv i
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LIST OF FIGURES
(Continued)
Figure No. Page
5.2 Vapor Compression Evaporator 5-9
5.3 Vapor Compression Evaporator for Cooling
Tower Slowdown Reuse 5-10
5.4 Water Management at a 600 MW Coal-Fired
Unit 5-15
5.5 Reuse of Water at a Typical Coal-Fired
Power Plant 5-16
5.6 Water Recycle/Reuse at a 1100 MW
Coal-Fired Power Plant 5-26
5.7 Water Management at a Typical 1980 Coal
Fired Power Plant 5-27
xvii
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1.0 INTRODUCTION
1.1 Purpose and Content
The issue of water management in steam-electric power plants is a
complex one encompassing technology, environmental protection, aesthetics
and economics. Prior to the advent of national environmental legisla-
tion, the magnitude and nature of water management including recycle,
treatment, and/or reuse was determined principally by the two factors of
water supply availability and economics. Since by far the largest water
usage is for cooling, those regions of limited water availability were the
first to focus on recycle systems such as cooling towers or ponds, whereas
those regions with ample water supplies often utilized once-through cool-
ing. The installation of water treatment systems prior to environmental
regulations was based principally upon operational economics, i.e., the
necessity to control the quality of the water going into the boiler, and
so on in order to sustain operability, reduce maintenance, etc. The
large population centers and, concomitantly, the large electric users are
predominantly located in water-plentiful parts of the United States; hence,
the usage of water management systems was, until recently, limited.
With the passage of the Water Pollution Control Act Amendments
of 1972 (PL-92-500) the Clean Water Act of 1977 and other increasingly
stringent environmental regulations on industrial effluent discharges
and increasing pressure on available water supplies, water management in
power plants assumed increasing importance. In recent years, substantial
focus has been on technology for water recycle and reuse. With the mid-
course corrections effected under the Clean Water Act Amendments of 1977,
the emphasis on zero discharge requirements under the 1983 guidelines for
the nation has been modified. The emphasis is probably likely to be on con-
trol of priority pollutants in the effluent discharges; zero discharge may
still be a distant goal. The other regulatory framerork which will impact
water management is the Resource Conservation and Recovery Act of 1976
(RCRA). Against this background of these regulatory requirements, the
emphasis is likely to be on optimum water management at power plants
rather than total water reuse.
1-1
-------
The multiplicity of uses of water in a power plant and the widely
varying requirements for water quality in those uses, present power
plants with major opportunities for water management through a combina-
tion of:
• Proper wastewater management to minimize net effluent
leaving the plant. For example, boiler Slowdown is often
of higher purity than the original source of supply and
may be used as makeup to demineralizers.
• Combining of compatible wastewater streams with appropriate
equalization.
• Treatment of the appropriate streams for potential reuse in
the power plant itself or, if that Is unjustified on economic
or regulatory grounds, for discharge to a receiving stream
after meeting regulatory requirements for effluents. In the
future, concentrations of priority pollutants in effluents
are likely to be major considerations.
This is the second volume in a five-volume report assessing vater
and waste management for conventional combustion sources and assesses
the current status of various studies and programs in water management
and trends in water recycle/reuse.
Water management at coal-fired power plants involves the maximum
technical and economic constraints among fossil fuel units due to the
need for broad application of particulate and sulfur control technology.
In view of the nation's commitment to increasing use of coal, water
management at coal-fired power plants has become the focus of substantial
exploration by the EPA.
While the primary focus of this section is coal-fired power plants,
many of the assessment considerations discussed apply to power plants
using other types of fossil fuels (gas and oil). Since coal-fired plants
generate the maximum range of wastes, they can serve as the logical focus
to assess all environmental and technological problems of water management
at fossil fuel power plants.
1-2
-------
A coal-fired (or any steam-electric) power plant produces two broad
categories of wastes:
1. Chemical wastes from various processes and operations
in the plant. Usually these are aqueous since water is
often the process fluid and handling medium.
2. Thermal wastes produced in the process of steam-electric
generation. These are rejected into the atmosphere with
water as an intermediate recipient of waste heat.
The above are separate subcategories in EPA guidelines documents.
This report focuses on chemical pollution aspects in assessing water
management including recycle/treatment/reuse and will mainly be con-
cerned with item 1.
To the extent that chemicals are used in heat rejection processes,
their impact on water treatment/reuse and on effluents are also considered.
Water management will lead to increasing recycle/reuse of water even
though zero discharge may not be achieved. Increasing the amounts of
water recycled or reused in any or all of the various streams in a power
plant is affected by the chemicals that enter either through their
occurrence in natural waters or through the operation of the plant (for
example, corrosion inhibitors, slimicides, etc.). Hence, the nature and
type of treatment of water for recycle or reuse is determined both by
these factors and the regulatory limitation now in existence and which
may be placed in the future on discharges to the environment. Con-
sequently, the water treatment technologies applicable to power plants
attempting to achieve high recycle or reuse rates are influenced prin-
cipally by site-specific and system-specific factors. In addition, the
difference between existing and new (or planned) power plants on economic
water recycle and reuse are many. In existing plants, piping and
collection systems for wastewater management and increased recycle or
reuse can be a major expense item and may potentially outweigh any other
consideration.
1-3
-------
On balance, if economic consideration were to be ignored, technology
does exist for almost complete, if not total, reuse of water and elimination
of pollutant discharges. In many cases, however, economic constraints may
be prohibitive, particularly in old and existing plants. Economic con-
siderations also raise two important factors:
1. Existing technology in many cases is from other industries
and in some cases on a smaller scale than required in the
utility industry.
2. Understandably, the utility industry being a regulated industry
has been very reluctant to accept economic estimates on
technology unless such technology is demonstrated on a large
scale in this industry.
Increasingly stringent regulations and constraints on water avail-
ability will force further emphasis on water management. This will be
resisted principally on an economic basis since the installation and
operation of the technologies required to effect tighter water management
may result in reduced overall plant efficiencies and increased capital
investments with no concomitant increase in the generation of power. This
situation will be exacerbated by the industry's reluctance to install
systems which have not been widely demonstrated and, furthermore, which
require a degree of integration with the power generation cycle which has
not heretofore been necessary. Consequently, an effective program of
technology transfer coupled with a judicious assessment of the techno-
economic-environmental aspects of environmental regulations will be pre-
eminent in determining the degree of water management in the steam-electric
power industry.
The review and assessment has involved two separate efforts as
described below:
1-4
-------
1. Review of the data and information available as
of February 1979 on the water management in power
plants. The review is based upon published reports
and documents as well as contacts with private
companies and other organizations engaged in water
management technology development or involved in
the design and operation of wastewater disposal
facilities. Much of the information has been
drawn from the waste characterization studies and
technology development/demonstration pro-
grams sponsored by the Environmental Protection
Agency (EPA) and the Electric Power Research Institute
(EPRI).
2. Based upon the review of the data and assessment of
ongoing work in waste characterization, identification
of data and information gaps relating to wastewater
properties and the development of recommendations for
potential EPA initiatives to assist in covering these
gaps. The principal purpose of this effort is to
ensure that, ultimately, adequate data will be avail-
able to permit reasonable assessment of the impacts
associated with the management of water in power
plants.
Throughout this work, emphasis has been placed upon technology now
commercially demonstrated and, where data are available, upon technologies
in advanced stages of development that are likely to achieve commercializa-
tion in the United States in the near future.
1.2 Report Organization
Based on an assessment of ongoing EPA and other programs, this
report presents:
1-5
-------
• Water balances and water use in coal-fired power
plants.
• Available wastewater management and treatment technology
practices from the point of view of increased water
recycle/reuse. Economic data on technology, where
available, are updated to mid-1978 levels and reported.
• Present regulatory requirements and trends for the future.
• Environmental impact issues discussed briefly against the
background of water management technology and regulatory
requirements.
• Based on the above assessment, identification of data
gaps and prioritization of the same.
1-6
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2.0 WATER USAGE IN POWER PLANTS
2.1 Overall Perspective
Water Use
A fossil-fired power plant requires water for several uses.
The major use points for water and, hence, generation points for
effluents in a coal-fired power plant are:
I. Continuous
1. Condenser Cooling
2. Steam Generation
3. Water Treatment
4. Ash Handling
5. Flue Gas Desulfurization
6. Miscellaneous
II. Intermittent
7. Maintenance Cleaning
8. Drainage (including coal pile runoff)
Power Generation
Most electric power generated in the United States, particularly
base load power, is generated through steam-electric systems (or thermo-
electric systems). Use of gas turbines, advanced power cycles and other
means are relatively minor and are expected to remain so in the near
future. This report will focus on steam-electric power plants only; in
such power plants, water is required for two purposes:
• Consumption uses such as evaporation in cooling towers to
dispose of waste heat and unavoidable losses at various
use points, and as a
• Handling and transportation medium for unit operations and
unit processes such as ash handling.
Table 2.1 presents data (for 1975) on a state-by-state basis for
water used in steam-electric power generation [1] . In 1975, total water
use by steam electric plants amounted to 190 bgd, an increase of 18% over
1970. Total power production by utilities and industry is summarized in
Table 2.2. Trends in power production by steam electric plants from 1971
to 1975 is summarized in Table 2.3. Because of large water demand, steam electric
2-1
-------
I
K)
Table 2.1
Water Used for Electric Utility Generation of Thermoelectric Power, In
Million Gallons Per Day, By States, 1975
(Partial figures may not add to totals because of independent rounding]
Condenser und re;:t:tor
State
AJiski
Colorado
G"or -i-i
MiuM.
!0-il.o
I'l'il MS
Kup%j* ,
M.i-yl.md
MK».I, in
Ncv/ Hampshire
jV'\v Jersey
cooliiig
Self-supplied
Ficsh
water
0
2.2
33
2.0
380
32
0
27
52
0
140
6.8
.7
1.2
2.0
42
0
0
0
0
0
C
32
11
7.3
0
270
5.9
0
0
Surface water
Fresh
6,600
18
110
1,700
1,100
100
720
0
1.600
3,500
32
0
8.800
7,200
2,600
250
2,200
5,300
22
410
880
12.000
2,700
i20
3,r,oO
160
620
87
74
880
Saline
100
1.0
0
0
9,200
0
1,200
11400
11,000
510
980
0
0
0
0
0
0
0
600
5.200
6,400
0
0
540
0
0
0
0
620
3.400
Public
supplies
0
0
0
0
0
0
.1
0
1.5
0
0
0
1.0
1.0
14
0
0
0
0
0
0
0
15
0
0
0
84
0
0
0
Other ihurmoclcclric uses
Self-
supplied "~
and
public
supplies
6,800
22
140
1,700
11,000
130
1,900
1,500
13,000
4,000
1.200
6.8
8,800
7,200
2.700
300
2.200
5.300
620
5,600
7,200
12,000
2,800
3.01W
160
970
93
700
4.3DO
Self-supplied
Fresh
water
2.2
0
0
0
0
0
.3
0
8.5
15
0
.2
7.0
.4
0
0
1.8
37
1.0
1.0
0
0
.7
2.0
0
0
0
2.0
0
1.2
Surface
Fresh
250
0
0
0
0
.1
3.7
0
2.3
74
0
0
320
110
81
0
90
120
1.0
10
0
58
57
0
0
0
0
0
0
3.2
water
Saline
2.1
0
0
0
0
0
3.7
0
0
1.5
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
13
Public
supplies
0.1
0
0
0
0
.1
1.0
0
1.6
0
0
0
3.0
0
.3
0
14
0
1.0
0
0
0
.3
0
0
0
0
.3
0
5.1
Self-
supplied
and
supplies
250
0
0
0
0
.2
8.7
0
12
90
0
.2
320
110
82
0
110
150
3.0
11
0
58
58
2.0
0
0
0
2.3
0
43
WVi-r
consumed
I K-sh
25
1.0
41
3.0
32
12
4.7
0
36
42
Q
1.8
5.0
65
15
?5
45
300
0
2.0
0
0
53
8.0
29
.3
8,4
72
0
.F.
Saline
0.2
0
ft
0
60
0
0
0
91
0
0
0
0
0
0
(I
1.7
0
18
0
0
0
9.0
0
0
0
0
0
1.7
-------
Table 2.1 (Continued)
Water Used for Electric Utility Generation of Thermoelectric Power, In
Million Gallons Per Day, By States, 1975
New Mexico ,
New York ,
North Carolina
North Dakota
Oh:o
Oic'-un
Pcr.nsylvania
Rlmdc Island
So'Jih Carolina
South <>akota
'j'c^ncsice
Texas
N> 1.1, -'i
I*) Vermont
Vi"»..ia
U';,v::nvton
V.'cst Viiginta .'....
\Vi"-nrMn
V.yom.ng
District of
"fcit'j Kicu—
Vir;_-in Island?
L'ni'.c'l States'
19
0
0
.3
17
1.0
0
1.3
0
0
.8
0.
37
0
0
0
0
0
0
.4
0
0
. 1,100
22
6.800
3.500
620
12,000
180
22
11,000
0
4,900
5.3
5,800
8,900
15
220
3,400
7.0
5,200
2.200
180
130
0
130,000
0
12.000
950
0
0
0
0
160
330
8.3
0
0
2.800
0
0
2,500
0
0
0
0
0
3.300
64.000
0
36
0
0
42
0
0
0
0
0
.2
0
4.9
0
0
0
0
0
0
0
0
5.0
200
41
19.000
4,500
f-7.0
1 2,000
180
22
11,000
330
4,900
6.3
5.800
12,000
15
220
5,900
7.0
5,200
2.200
180
130
3,300
190.000
0
190
.1
0
5.9
0
0
2.5
0
.1
.2
0
1.3
0
0
.9
0
0
0
.7
0
0 .
290
0
370
36
0
130
1.4
0
96
0
40
.1
0
2.8
0
22
0
0
140
0
4.9
0
0
2.000
0
0
0
0
0
0
0
0
0
.4
0
0
.3
0
0
0
0
0
0
0
0
0
41
0
6.0
0
0
1.3
.4
0
0
0
0
0
0
.1
0
0
0
0
0
0
0
0
0
35
0
570
36
0
140
1.8
0
98
0
41
.3
0
4.5
0
22
0
0
140
0
5.6
0
0
2.400
33
15
45
19
78
53
0
2:')
0
C-9
3.3
,-Q
-•:j
8.0
94
0
7.0
1.2
30
M
2.0
5.0
1,900
0
24
20
0
0
0
0
1.0
0
.2
0
0
28
0
0
0
0
0
0
0
0
2.0
:r,o
Including Puerto Rico and Virgin Islands.
Source: [11
-------
Table 2.2
Power Production, 1975
Basis: Billions of kWh
Utility Industry Total
1. Thermoelectric
Fossil Fuel 1445
Nuclear 172
Total Thermoelectric 1617 85
2. Other Means
(Hydroelectric) 301
TOTAL POWER 1918 85 2003
Source: [1]
2-4
-------
Table 2.3
Trends in Steam Electric Power Generation
K>
I
Year
Installed
Total Net
Capacity Generation
Thousands of MW Trillions
1971
1972
1973
1974
1975
283.4
309.9
340.0
372.0
396.0
of kWh
1,293.7
1,411.9
1,536.4
1,504.5
1,558.4
Coal
7.244
7.794
8.583
8.476
8.679
Fuel Used
Quads (1015Btu)
Gil
2.328
2.816
3.270
3.052
3.010
Gas
3.841
3.811
3.517
3.315
3.101
Total
13.413
14.421
15.370
14.843
14.790
Source: [2]
-------
plants furnish practically all their own water. In 1975, less than
1/2% of water requirements by utilities were filled by purchases from
public supplies. Saline water constituted 33% of water withdrawal for
steam electric power generation in 1975. No data are available at
present on the projected growth of power use and coal utilization taking
into account the full implications of the National Energy Act of 1978.
However, some earlier projections on power generation are presented in
Table 2.4. Water use in steam-electric power generation by water
resource regions is shown in Table 2.5; Figure 2.1 shows the correspond-
ing water resource regions.
Future Trends
Not only does the power industry withdraw the largest quantity of
water (of any industrial sector) for off-channel use, but the projected
rate of increase in usage by thermoelectric power plants makes the latter
the fastest growing of major withdrawal uses of water. Table 2.6
presents data on off-channel water use for steam-electric power genera-
tion by water quality regions in 1975 together with projected data for
1985 and 2000 [3].
Data for steam-electric water uses are based on steam-powered
generation plants with 25 megawatts or more installed capacities. In
general, smaller plants operate for limited periods during the year
and use relatively minor quantities of water. The data for electric
power generation do not include water used for hydroelectric generation
which is primarily an instream use.
Water Availability for Steam Electric Power
A recent study by Cameron Engineers for the EPA [4] on water avail-
ability for steam electric power plants and other uses reaches the
following conclusions (among others) for water availability:
• Under dry year conditions, there is not sufficient water
in most regions of the conterminous United States to fully
satisfy all users at their current rates of use. This
situation is particularly critical in the Southwest and
will become worse.
2-6
-------
Table 2.4
Projected Electric Power Generation by Fuel
Basis: Assessments made before the National Energy Act of 1978. The data presented below are based on projections
In the Annual Environmental Analysis Report [Ref. 101] and are based on analysis of the energy situation
conducted In 1977.
Number
1.
2.
3.
It.
5.
fO
1 6.
->l
7.
8.
9.
Census Region
New England
-------
Table 2.5
Water Used for Electric Utility Generation of Thermoelectric Power,
in Million Gallons per Day, by Regions, 1975
[Partial figures may not add to totals because of independent rounding]
i
oo
Condenser and reactor cooling
Water Resources Council
region
New England
Mid-Atlantic
South Atlantic-Gulf
Great Lakes
Ohio
Tennessee . j
llppcr Mississippi
l.oxvcr Mississippi
Souris-Kcd-Riiiny
Miv.ouri Hasin
Atkansjs-\Vliite-Rcd
Tcxas-liulf
Rio Grande
Upper Culuiado
Gii'at Itjiin
Pacific Northwest
California
Al.r.'xn
llv.vaii
CatiblKan
Fresh
ground
water
0
27
63
8.2
20
0
28
0
0
310
46
31
22
0
36
4.3
6.8
380
2.2
140
0
1,100
Self-supplied
Surface
Fresh
1,900
14,000
18,000
25,000
26,000
8,600
13,000
5,900
190
3,900
2,800
7.600
5.2
160
110
78
29
1,100
18
32
0
1 30.000
water
Saline
9,200
2S.COO
14,000
0
0
0
0
0
0
0
0
2,800
0
0
0
0
0
9,200
1.0
980
3.300
64,000
Public
supplies
0.1
36
1.5
34
9.8
0
30
0
0
85
0
4.9
0
0
0
0
0
0
0
0
5.0
200
Self-
and
public
supplies
11.000
39.000
31,000
25.000
26.000
8.600
13,000
5,900
190
4.300
2,800
10,000
27
160
150
83
36
11.000
22
1.200
3.300
190.000
Other thermoelectric uses
Self-supplied
Fresh
ground
water
1.3
140
28
• 56
13
0
6.5
27
0
.9
10
1.1
.2
0
2.0
0
.2
0
0
0
0
290
Surface
Fresh
24
300
330
300
420
74
420
120
1.0
25
1.7
2.5
0
2.1
0
0
0
0
0
0
0
2.000
water
Saline
3.7
33
4.0
0
0
0
0
0
0
0
0
.3
0
0
0
0
0
0
0
0
0
41
Public
supplies
2.0
9.3
1.7
3.1
IS
0
3.1
0
0
.1
.4
.1
0
0
.3
0
0
0
0
0
0
35
Self-
supplied
and
public
supplies
31
4 HO
360
360
450
74
430
140
1.0
26
12
4.0
.2
2.1
2.3
0
.2
0
0
0
0
2,400
Water
consumed
Fresh
96
140
210
52
280
59
96
291)
1.2
68
95
380
20
60
47
5.7
8.8
\1
1.0
0
5.0
1,900
Saline
0
46
120
0
0
0
0
1.7
0
0
0
28
0
0
0
0
0
60
0
0
2.0
260
Including Caribbean region.
Source: [1]
-------
l*3h«*
1X3
I
>., SOURIS RED RAINY
- ••'-••''•
, p,_ .
!- -..._ E'^/C '>
~"
L j-vj,
' soun. a/ ^
M.ISSOUR
BASIN ' 'U UPPER
MISSISSIPPI
> » '
V ^-,
- ARKANSAS-WHITE-Ro
•-'•-—MISSISSIPPI:
i SOUTH
ATLANTIC GULF
PUERTO RICO
Figure 2.1 Water Resource Regions
-------
t-o
I
O
Table 2.6
Annual Water Requirements for Steam-Electric Power Plants
Basis: 1. Hydroelectric power use is excluded.
2. Steam-electric plant use as % of total off-stream usage of water.
1975
1985
(Est.)
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
.11.
12.
Region
New England
Mid-Atlantic
South Atlantic-Gulf
Great Lakes
Ohio
Tennessee
Upper Mississippi
Lower Mississippi
Souris-Red-Rainy
Missouri
At kansas-Wi i te-Red
'/I'X.T-i Glllf
Steam
Electric
MGD
21
103
153
175
324
42
129
54
1
68
89
99
As % of
Total
Consumption
4.30
5.46
2.70
6.68
17.94
13.33
10.90
1.23
0.82
0.39
0.96
0.79
Steam
Electric
MGD
18
224
722
497
656
231
352
118
0
243
237
270
As % of
Total
Consumption
2.76
8.83
9.38
14.90
25.86
35.59
21.17
2.38
0
1.12
2.38
2.41
2000
(Est.)
Steam
Electric
MGD
167
644
1,857
1,384
1,692
417
1,079
291
0
644
457
994
As % of
Total
0
Consunipt Ion
1 .•U.IPI. - . . T ... •>*«.
15.68
17.75
16.75
29.21
38. H')
37. f>/
38.91
4.89
0
2.87
4.r-6
,3.;-«;
-------
Table 2.6 (Continued)
Annual Water Requirements for Steam Electric Power Plants^
Basis! 1. Hydroelectric power use is excluded
2. Steam-electric plant use as % of total off-stream usage of water
1975
13.
14.
15.
16.
17.
18.
Region
Rio Grande
Upper Colorado
Lower Colorado
Great Basin
Pacific Northwest
California
Steam
Electric
MGD
18
43
63
8
16
34
As % of
Total
Consumption
0.39
1.61
1.34
0.19
0.11
0.12
1985
(Est.
Steam
Electric
MGD
9
120
134
44
134
101
As % of
Total 2
Consumption
0.19
3.63
2.75
1.04
0.74
0.34
2000
(Est.
Steam
Electric
MCD
5
155
126
52
392
242
As % of
Total
Consumption
0.11
4 . 40
2.62
1.15
2.10
0 . 76
Conterminous United States 1,440
1.23
4,110
3.10
10,598
7.22
Source: [4]
-------
• Relative to the total consumption, the percentage con-
sumption for steam electric generation was 1.23% in 1975
and will grow to 3.10% in 1985 and to 7.22% in the year 2000.
This major increase is due to anticipated growth in power
generation and shift in fossil fuel use. Water conservation
practices are likely to impact various industrial sectors
differently.
• All segments of society which consume water must develop a
water conservation strategy and implement that strategy.
Since agriculture consumes the largest quantity of water
by comparison with other water users, substantial water
savings can be accomplished even with small percentage
reductions in agricultural use through better utilization
of the water resources. Conversely, a large percentage
reduction in the consumption for steam electric power
generation is small by comparison.
It is clear that increased emphasis on water management is going
to be essential not only to minimize environmental impacts but also
to assure availability and adequacy of supplies for various uses.
Use for Cooling
The operation of steam-electric power tlants involves the disposal
of large quantities of waste heat. Since, on the average, more than
one-half of the heat input to a typical steam-electric power plant is
rejected at the condenser, the condenser cooling water represents by
far the largest water use in the plant. This heat added to the cooling
water must then be dissipated into the environment by one or more of
the following available cooling methods:
• Once-through cooling.
• Recirculating systems including cooling ponds,
cooling towers, and combined systems.
Table 2.7 indicates the extent to which each of these various types
of cooling methods were used by power plants during 1971-1975. The extent to
which each method was used is expressed both as percent of total number
2-12
-------
Table 2.7
General Information Summary Condenser Cooling Systems
1971-1975
Type of Cooling
Once-through, fresh
Once-through, saline
Cooling ponds
Cooling towers
Combined systems
Total
Type of Cooling
Once-through, fresh
Once-through, saline
Cooling ponds
Cooling towers
Combined systems
Total
Percent
1971
48.1
18.1
6.0
18.1
9.7
100.0
Percent
1971
47.7
21.5
7.3
12.9
10.6
100.0
of Total
1972
47.2
17.3
6.3
18.6
10.6
100.0
of Total
1972
45.4
20.9
8.0
13.4
12.3
100.0
Number
1973
44.0
16.4
6.0
21.5
12.1
100.0
of Plants
1974
43.4
15.5
6.6
23.4
11.1
100.0
1975
42.7
15.6
7.1
22.8
11.8
100.0
Installed Capacity
1973
43.1
20.1
8.6
14.4
13.8
100.0
1974
41.1
18.9
8.5
16.1
15.4
100.0
1975
39.4
18.5
9.0
16.6
16.5
100.0
Source: [2]
2-13
-------
of plants and as percent of total installed capacity. For comparison,
corresponding percentages are also shown for the years 1969 through 1972.
As indicated for 1973, most of the plants (approximately 60%) providing
the major share of steam-electric power capacity (approximately 63%)
employed once-through cooling using either fresh or saline water. The
second most widely used method of cooling is cooling towers which account
for approximately 20% of the total number of plants and about 15% of the
total installed plant capacity. However, during the five-year period
1969-1973, there existed a trend away from once-through cooling toward
the use of cooling ponds, cooling towers, and combined systems. This
trend is expected to accelerate in the future.
Table 2.8 presents data compiled by the FPC [2] on the number of
steam-electric power plants, capacities and types of cooling by water
resource regions in 1973. Table 2.9 summarizes average cooling water
use by water resource regions.
Water recycle/reuse for cooling purposes can employ cooling towers
or cooling ponds. The technical considerations on these types insofar
as they impact chemical wastes are discussed later. However, the follow-
ing tables summarize the data on some exemplary plants:
• Table 2.10 is a listing of the more typical, exemplary,
coal-fired steam-electric power plants employing cooling
towers which exhibit minimal water usage (gal/MWH).
• Table 2.11 is a similar listing of the more typical,
exemplary, coal-fired steam-electric power plants
exhibiting minimal water usage (gal/MWH) employing
cooling ponds.
Chemical Additives
Even prior to the advent of environmental concerns, power plants
made substantial use of chemical additives for one of two reasons:
• Process requirements for steam generation requiring very
high quality water.
• Water conservation needs that prompted water recycle
related requirements. Scale and corrosion control are
two examples.
2-14
-------
Table 2.8
Number of Plants, Capacities, and Types of Cooling
by Water Resource Region, 1973
Once Through
Fresh
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Water Resource Region
New England
Middle Atlantic
South Atlantic - Gulf
Great Lakes
Ohio
Tennessee
Upper Mississippi
Lower Mississippi
Souris - Red - Rainy
Missouri
Arkansas - White - Red
Texas - Gulf
Rio Grande
Upper Colorado
Lower Colorado
Great Basin
Columbia - North Pacific
California - South Pacific
Totals - Contiguous U.S.
Alaska
Hawaii
Puerto Rico
Totals - Non-Contiguous
U.S.
TOTALS - UNITED STATES
No. of
Plants
10
35
37
64
70
10
50
14
1
28
6
9
2
5
341
341
Capacity
(MW)
2,209.84
12,275.29
17,553.01
28,025.93
35,846.15
11,058.19
16,811.50
9,901.96
110.00
5,427.32
2,922.74
2,093.62
84.00
1,085.80
145,405.35
145,405.35
Once Through
Saline
No. of
Plants
25
40
25
2
2
1
22
117
3
3
7
124
Capacity
(MW)
11,348.99
21,828.85
10,739.43
1,183.25
1,547.50
59.00
17,589.65
64,296.67
542 . 88
2,437.20
3,241.08
67,537.75
Cooling Ponds
No. of
Plants
5
2
1
1
4
4
7
18
1
1
1
45
1
46
Capacity
(MW)
6,186.44
68.83
99.00
413.63
3,674.21
1,994.75
2,963.50
10,495.55
2,269.80
113.60
220.00
28,499.31
1,186.80
29,686.11
Cooling Towers
No. of
Plants
1
2
9
2
19
1
8
11
17
30
20
15
3
12
3
1
14
168
168
Capacity
(MW)
35.95
1,679.20
2,857.93
190.00
14,897.35
712.50
478.55
2,125.27
2,553.80
6,444.22
4,307.49
2,827.99
659.20
2,324.59
2,478.84
1,329.80
3,369.61
49,272.29
49,272.29
Combined Systems
No. of
Plants
5
8
13
1
9
10
4
1
6
11
10
2
3
2
1
2
88
1
1
2
90
Capacity
(MW)
2,604.64
4,197.68
8,449.02
386.00
9,668.20
5,259.96
1,1118.58
136.90
1,508.65
2,888.13
8,220.82
164.30
142.50
138.00
133.00
2,085.15
47,101.53
568.80
395.00
963.80
48,065.33
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Source: [2]
-------
Table 2.9
Average Cooling Water Use, by Water Resource Region, 1973
Total Designed
Average Hate of Water Use Poring the Year (CFS)
NJ
I
Line
No. Water Resource Region
1 Mew England
2 Middle Atlantic
3 South Atlantic - Gulf
It Great Lakes
5 Ohio
6 Tennessee
7 Upper Mississippi
8 Lower Mississippi
9 Souris - Red - Rainy
10 Missouri
11 Arkansas - White - Red
12 Texas - Gulf
13 Rio Grande
14 Upper Colorado
15 Lower Colorado
16 Great Basin
17 Colunbia - North Pacific
18 California - South Pacific
19 Totals - Contiguous U.S.
20 Alaska
21 Hawaii
22 Puerto Rico
23 Totals - Non-Contiguous U.S.
24 TOTALS - UNITED STATES
Condenser
Fresh
5,601.70
21,872.26
39,254.78
48,226.61
73,262.95
14,682.10
37,106.55
13,520.33
365.80
13,156.34
19,843.18
33,683.63
5,475.44
3,447.90
2,793.13
3,086.10
3,678.70
6,781.06
345,838.56
645.00
2.159.00
347,997.56
Flow (CFS)
Saline
14,359.12
36,843.10
21,263.15
1,492.40
2,151.50
131.00
18,667.80
94,908.07
2,027.00
3,657.00
6,009.00
100,917.07
Withdrawal
Fresh
4,763.80
16,621.45
36,539.74
33,501.54
47,000.72
11,497.40
17,549.32
8,926.77
315.08
7,776.92
4,485.38
13,038.01
90.06
242.64
204.94
192.04
953.65
1,271.86
194,971.32
388.50
399.10
195,370.42
Saline
10,643.30
26,961.60
17,535.86
560.00
•
1,520.90
28.98
14,431.24
71,681.88
1,571.00
3,649.34
5,535.34
77,217.22
Consumption
Fresh Saline
13.00 2.33
251.95 5.80
98.76 2.64
95.35
406.87
87.50
129.15
198.91
.11
128.31
104.25
167.27 9.00
30.16
46.14
45.66
35.04
18.70
38.14 19.27
1,895.27 39.04
4.90
4.90
1,900.17 39.04
Discharge
Fresh
4,750.80
16,569.84
26,441.31
33,405.48
47,132.80
11,411.60
17,423.17
8,735.99
314.97
7,610.51
4,383.19
12,910.50
59.22
196.50
158.36
157.00
934.95
1,233.74
193,829.93
383.60
394.20
194,224.13
Saline
10,652.97
26,955.80
17,533.22
560.00
1,511.90
28.98
14,412.77
71,655.64
1,550.00
3,649.34
5,514.34
77,169.98
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Source: [2]
-------
Table 2.10
Coal-Fired Steam-Electric Power Plants With Cooling Towers, 1975
I
(-•
^J
Plant General Information
No.
Utility Name vonnay-\nania Rlpri-r-fr Company
Plant Name ifoy.-cnr.o
1 State Located ppnnsylvan
-------
Table 2.1 (Continued)
Coal-Fired Steam-Electric Power Plants With Cooling Towers, 1975
Isj
M
oo
Plant General Information
No.
Utility Name Utah Power & Light Company
Plant Name Hun tine ton
7 State Located yt?tl
Plant Caoacitv HVO 4^1
Fuel Fired Coal, Oil
Utility Name Southern California ^Ison
Plant Name Mohave
8 State Located Nevada
Plant Capacity (MW) 1636r2
Fuel Fired Cpal, Gaa
Utility Name Pacific Power & Lleht Company
_ Plant Name Centralia
State Located Wa shine ton
Plant Capacity (MM) 1330
Fuel Fired Coal. Oil
Utility Name Appalachian Power Comnanv
Plant Name AMDS
10 State Located West Virginia
Plant Capacity (tw) 2900
Fuel Fired Coal, Oil
Utility Name Ohio Electric Company
, Plant Name Gavin
State Located ohlo
Plant Capacity ^MW) 2600
Fuel Fired Coal, oil
Utility Name Kentucky Power Comoanv
Plant Name BiR sandv
12 State Located Kentucky
Plant capacity (HW) 1060
Fuel Fired ry.«l P11
Plant Heat
Rate
(Btu/kwh)
10,154
15,709
10,265
9,505
9,797
9,480
Annual
Generation
(MWH)
2,536,400
6,368,700
6,131,500
15,575,700
12,135,200
5,018,800
Source
River
River
River
River
River
River
Cooling Water
Usage
(gal /MWH)
830
840
900
965
990
1,050
Additives
CWb BFWC
C.O P.O
C,0 P, CS
A, 0
C.O P.CS
C,0
C,0 CS.A,
C,0
C,0 P.CS,
L C.O
Pond Discharge
('000 ft3/yr)
BDd AS6
_
635,00 635,000
88,300
*P - Phosphate, CS - Caustic Soda, L - Lime, A - Alum. C - Chlorine, 0 - Others
bCW - Cooling Water
CBFW - Boiler Makeup
dBD - Boiler Slowdown Pond
eAS - Ash Settling Pond
-------
N>
I
Table 2.10 (Continued)
Coal-Fired Steam-Electric Power Plants With Cooling Towers, 1975
Plant General Information
No.
Utility Name Public Service Co. of New Mexico
Plant Name San Juan
13 State Located New Mexico
Plant Capacity «W) 3287
Fuel Fired Coal, Oil
Utility Name Pennsylvania Electric Company
Plant Name u^mor Citv
14 State Located Pennsylvania
Plant Capacity (MW) ] I2n
Fuel Fired Coal. Oil
Utility Name Pennsylvania Power & Lieht Company
Plant Name Montour
J State Located ' Pennsylvania
Plant Capacity (MW) 1641.7
Fuel Fired Coal, Oil
Utility Name
Plant Name
State Located
Plant Capacity (MW)
Fuel Fired
Utility Name
Plane Name
State Located
Plant Capacity (MW)
Fuel Fired
Utility Name
Plant Name
State Located
Plant Capacity (MW)
Fuel Fired
Plant Heat
• Rate
(Btu/kwh)
10,155
10,338
9,856
Annual
Generation
(MWH)
2,432,000
4,445,800
9,394,400
Source
River
Creek
River
Cooling Water
Usage
(gal /MWH)
1 075
1,140
1,155
Additives
CWb BFWC
P.C. P.CS.
0 L,A,0
L,C, CS,0
0
C CS.A,
Pond Discharge
('000 ft3/yr)
BDd ASe
_
98.00C
*? - Phosphate, CS - Caustic Soda, L - Lime, A - Alum, C - Chlorine, 0 - Others
bCW - Cooling Water
CBFW - Boiler Makeup
dBD - Boiler Slowdown Pond
eAS - Ash Settling Pond
Source: [2] and Arthur D. Little, Inc.
-------
Table 2.11
Coal-Fired Steam-Electric Power Plants With Cooling Ponds, 1975
I
N>
O
Plane General Information
No.
Utility Name T»Y«« Power & LIfht Co.
Plant Name Big Brown
1 State Located T*-*a«
Plant Capacity «W) 1186.8
Fuel Fired Coal, Baa
Utility Name Mlnnkom Power Cor nor at ion
Plant Name Young
2 State Located North Dakota
Plant Capacity (MU) 256.5
Fuel Fired Coal, Oil
Utility Nane South Carolina Public Service Authority
Plane Name Winyah
3 State Located South Carolina
Plant Capacity (MM) 315
Fuel Fired Coal
Utility Nane Otter Tall Pover Company
Plant Name Big Stone
4 State Located South Dakota
Plant Capacity (MU) 455.66
Fuel Ftred^. Coal, Oil
Utility Name Commonwealth Edison Company
Plant Name Klncaid
5 State Located Illinois
Plant Capacity (KW> 1319
Fuel Fired Coal. Oil, Gas
Utility Name Ar<-"-» P-AH- s-riH™ r/mpaiiy
Plant Name Vni,r Co™,..
6 State Locate.' Hew Mexico
Plant Capacity (W) 2212.20
Fuel Fired Oil °»s
Plant Heat
Rate
(Btu/kwh)
10,239
10,967
9,622
11,779
10,768
10,317
Annual
Generation
(MWH)
7,264,000
1,752,100
1,302,000
1,406,100
4,316,300
.0,484,000
Source
Creek
Creek
River
Lake
Other
River
Cooling Water
Usage
(gal /MWH)
345
501
545
595
600
800
Additives
CVb BFWC
C CS.O
C P.CS,
L.A.O
- CS.A.O
C CS.L,
C,0
C CS.L.O
C P.CS,
L.A.O
Pond Discharge
('000 ft3/yr)
BDd ASe
_ _
_ _
-
-
817,000
77.000
T> - Phosphate, CS - Caustic Soda, L - Line, A - Alum, C - Chlorine, 0 - Others
bCW - Cooling Water
CBFW - Boiler Makeup
dBD - Boiler Slowdown Pond
eAS - Ash Settling Pond
-------
ISJ
I
N5
Table 2.11 (Continued)
Coal-Fired Steam-Electric Power Plants With Cooling Ponds, 1975
Plant General Information
No.
Utility Name Illinois Power Company
Plant Name Baldwin
7 State Located Illinois
Plant Capacity «W) 1892.05
Fuel Fired Coal, Oil
Utility Name Wisconsin Power & Lieht Company
Plant Name Columbia
0 State Located Wisconsin
Plant Capacity (MW) 512
Fuel Fired Coal. Oil
Utility Name Carolina Power & Light Company
Plant Name Button
q State Located North Carolina
Plant Capacity (MW) 671.62
Fuel Fired Coal, Oil
Utility Name Public Service Co. of Indiana. Inc.
Plant Name Gibson
It) State Located Indiana
Plant Capacity (MW) 550
Fuel Fired Coal. Oil
Utility Name
Plant Name
State Located
Plant Capacity (MW)
Fuel Fired
Utility Name
Plant Name
State Located
Plant Capacity (MW)
Fuel Fired
Plant Heat
Rate
(Btu/kwh)
9,627
10,044
11,252
9,183
Annual
Generation
(MWH)
8,633,700
1,565,000
1,197,400
2,470,000
Source
River
River
River
River
••
Cooling Water
Usage
(gal /MWH)
900
3,365
5,915
8,170
Additives
CVt> BFWC
C P.CS,
L.A.O
C P.O
C P.O
C CS,L,0
Pond Discharge
('000 ft3/yr)
BDd ASe
374,000
179,000
200,000
*P - Phosphate, CS - Caustic Soda, L - Lime, A - Alum, C - Chlorine, 0 - Others
bCW - Cooling Water
CBFW - Boiler Makeup
BD - Boiler Slowdown Pond
BAS - Ash Settling Pond
Source: [2] and Arthur D. Little, Inc.
-------
Table 2.12 summarizes, by FPC-designated water resource regions,
both the type and quantity of chemical additives used in the treatment
of power plant cooling water and boiler feed water. The principal
chemical additives reportedly used in 1973 for cooling water treatment
(for the prevention of condenser tube fouling) were lime, alum, and
chlorine, with chlorine being used in the largest quantity. In the
case of boiler feed water treatment, the principal additives were
phosphate, lime, alum and caustic soda, with caustic soda being the
most widely used.
2.2 Water Balance in Coal-Fired Power Plants
The water balance in a power plant is dependent upon a number of
factors such as:
• Site location
• Ambient conditions
• Plant size and age
• Fuel characteristics
• Source(s) of water
• Plant design
• Operating practices
• Management philosophies
• Environmental regulations
There are two entirely different types of wastes produced by steam-
electric power plants:
(a) Chemical Wastes
The chemical wastes originate from different processes
and operations within a plant. These wastes vary from
plant to plant, depending on fuel, raw water quality, processes
used in the plant, and other factors. Usually, water is employed
as the handling and process medium and, hence, the chemical wastes
are often present as aqueous streams.
(b) Thermal Wastes
These wastes are associated with the condenser heat
rejection. The waste heat produced by the plant is disposed to
the environment through the condenser cooling water system. Waste
2-22
-------
Table 2.12
Use of Chemical Additives by Water Resources Region, 1973
Line
No. Water Resource Region
1 New England
2 Middle Atlantic
3 South Atlantic - Gulf
4 Great Lakes
5 Ohio
6 Tennessee
7 Upper Mississippi
8 Lower Mississippi
9 Souris - Red - Rainy
10 Missouri
11 Arkansas - White - Red
12 Texas - Gulf
13 Rio Grande
14 Upper Colorado
15 Lower Colorado
16 Great Basin
17 Columbia - North Pacific
18 California - South Pacific
19 Totals - Contiguous U.S.
20 Alaska
21 Hawaii
22 Puerto Rico
23 Totals - Non-Contiguous
U.S.
24 TOTALS - UNITED STATES
Cooling Water Additives (Tons)
Phosphate
4.44
.34
13.87
.01
47.79
.24
9.63
1.40
60.36
204.94
47.06
54.13
14.84
135.33
101.81
696.19
696.19
Lime
.18
8,585.67
202.15
104.41
2,504.78
2,709.38
1,818.33
202.45
3.69
2,598.25
2.19
18,731.48
18,731.48
Alum
25.20
270.95
853.49
584.87
84.10
163.36
207.44
191.46
118.59
19.70
65.70
5.77
2,590.63
2,590.63
Chlorine
1,209.02
8,639.48
1,451.55
2,623.07
2,989.32
301.56
4,200.80
335.25
4.28
286.68
410.50
2,303.29
84.92
69.00
456.08
39.79
36.00
1,084.14
26,524.73
69.00
4.50
247.50
26,772.23
Phosphate
83.04
294.74
83.96
150.76
77.57
13.08
190.86
23.25
.72
43.88
22.99
34.55
7.07
2.50
3.08
6.80
9.40
50.97
1,099.22
2.18
6.56
9.19
1,108.41
Boiler Water Additives
Caustic
" Soda
1,138.78
12,115.00
6,493.88
5,828.37
8,792.95
365.35
6,667.25
3,659.55
.87
1,644.86
3,753.49
6,861.34
85.69
168.78
349.76
102.13
234.83
1,654.71
59,917.59
22.50
.37
1,357.58
1,461.82
61,379.41
Lime
2.25
60.47
610.28
962.70
2,191.09
1,330.26
1,094.43
1,104.20
686.31
369.00
17.10
131.13
34.39
36.50
431.29
9,061.40
9,061.40
(Tons)
Alum
17.51
823.11
825.90
308.18
381.89
125.49
229.91
150.76
8.38
118.82
16.98
15.09
55.69
5.45
32.02
3,115.18
3,115.18
Chlorine
.97
16.71
40.99
22.62
66.71
4.74
182.42
6.11
.73
1.11
12.97
10.23
.03
55.00
7.53
428.87
428.87
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Source: [2]
-------
heat is an integral part of the process of producing power by
thermoelectric methods. The atmosphere is the final recipient
for this heat, with water generally used as the intermediate
recipient.
The EPA has been cognizant of the basic differences between these
types of wastes and has established separate subcategories for chemical
and thermal wastes [5]. Subcategorization for heat is approached sepa-
rately from Subcategorization for other pollutants because:
• Control and treatment technology for heat relate primarily
to the characteristics of generating units, while non-thermal
control and treatment technologies relate primarily to charac-
teristics of stations.
• Control and treatment technologies are dissimilar.
• The costs of thermal control and treatment technology are much
greater than non-thermal control and treatment technologies.
This report will focus on the chemical wastes in assessing water
management in power plants. However, chemicals are extensively employed
in cooling systems which also produce substantial quantities of effluents.
To the extent these impact water management, they have been considered.
Overall, the basic factors which relate to chemical wastewater
characteristics are the fuel storage and handling facilities, water
treatment equipment, boiler, condenser, type of cooling systems, and
auxiliary facilities. Steam-electric power plants are comprised of one
or more generating units. In prevalent practice, a generating unit
consists of a discrete boiler, a turbine-generator, and a condenser
system. Fuel storage and handling facilities, water treatment equip-
ment* electrical transmission facilities, and auxiliary components may
be a part of a. discrete generating unit or may service more than one
generating unit.
Based on the flow ranges reported in the literature, a generalized
schematic water balance for a new 1,000-MW coal-fired power plant with
a cooling tower is presented in Figure 2.2. The waste streams are of
continuous or intermittent nature and can be categorized by their sources
2-24
-------
LEGEND
LlOue FLOW
CAS OR STEAM
CHEMICALS
OPTIONAL MTU
CONTINUOUS WASTES
INTERMITTENT WASTES
CHEMICALS
WATER1 FOR
MAINTENANCE CLEANING
TO STACK
BOILER TUBE
CLEANING,
FIRE-SIDE 6
AIR-PREHEATER
WASHINGS
EVAPORATION
LOSSES
MAKE-UP
WATER
3-5.3
1800-14001
WATER
FOR BACKWASH
19-60 m3/day .
15000-16,000 G»0t
CHEMICALS
N>
I
RAW WATER
0.11-0.32
(30-851
WATER FOR
REGENERATION
400-600 in*
r
CONDENSER
(100.000-150.000 GPO>
CHEMICALS
4°°-6<)0m3/da»
noo,ooo-i5o.oooGPO>
WASTE WATER
EVAPORATION
COAL
PILE
LAB, SANITARY, E
MISC. OPERATIONS.
AUXILIARY COOLING
SYSTEM OPERATIONS
— *- RUN-OFF
1100-6000 mJ/«la,
10.3-1.6 10«6«ll
~ WASTE WATER
MO-190mVdoy
(30.000-50.000GPDI
r^
®
J_
DISCHARGE TO
WATER BODY
\
\ COOLING
40-52 \ TOWER
UO.JOO-13.800I \
EVAPORATION
. DRIFT LOSS
EVAPORATION
MAKE-UP
WATER
MAKE-UP
WATER
0.4-0.6
1100-1501
BLOWDOWN
8-10
(2100-2BOO)
BLOWDOWN
04-06
1100- ISO)
NOTES;
1. FLOW RATES SHOWN ARE IN mVmin ICPM) UNLESS OTHERWISE NOTED.
2. TYPICAL RANGES SHOWN. VALUES NOT NECESSARILY ADDITIVE
Source: Arthur D. Little, Inc.
Figure 2.2 Generalized Schematic Water Balance for a Typical 1000 MW
Coal-Fired Power Plant (with a Cooling Tower)
-------
of generation as follows:
(a) Continuous Wastes
• Condenser cooling system
• Steam generation
• Water treatment systems
• Ash handling systems
• Flue gas desulfurization systems
• Miscellaneous operations
(b) Intermittent Wastes
• Maintenance cleaning
• Drainage (principally coal pile runoff)
For assessing the treatment technology for power plant application,
it is to be recognized that, depending upon the specifics of the applica-
tion, the systems required for collecting these waters can be a major
factor. For example, wastewater streams from maintenance cleaning oper-
ations originate at drain points which are located below grade. The
piping and pumping systems for collecting these streams prior to treat-
ment and recycle require large capital expenditure, and this aspect is
particularly significant in existing plants for designing retrofit
systems for increased recycle/reuse.
2.3 Current R&D Studies
The EPA, EPRI, and others have sponsored a number of studies in the
field of water management. Some of the more important ongoing EPA
programs are listed in Table 2.13 and those of EPRI are summarized in
Table 2.14. While these are some of the generic studies on water
management, it should be emphasized that many utilities have conducted
in-house studies and sponsored those by equipment vendors and manufac-
turers. Many of these studies appear in the literature and are
included in this assessment of water management technology.
2-26
-------
Table 2.13
EPA Projects Concerning Water Recycle/Treatraent/Reuse in Power Plants
tails: Only currently ongoing (as of December 1978) project! pertaining to chemical watte it ream production arc Hated.
Further project* under EPA's Thermal Program* are not listed here.
No.
N>
N3
Project Title
1 Assessment of Technology for Control of Voter
and Vnste Pollution from Combustion Sources
I Water Recycle/Reuse Alternatives In Coal-Fired
Steam Electric Power Plants
Contractor
Arthur 0. Little
Radian Corporation
3 Characterization of Effluents froa Coal-Fired
Utility Bollera
Tennessee Valley Authority
Tn-.itment of Power Plant Wastes with Membrane
Technology
Assessment of Measurement Techniques froa
Hazardous Pollution froa Thermal Cooling
Systecs
Assessncnt of the Effects of Chlorinated
Sea Water from Power Plants on Aquatic
OrganJsas
Evaluation of Lime Precipitation for
Treat rent of Boiler Tube Cleaning Waste
Assess Conparjtlve Merits of Reverse
Gtr^osls, Vnpor Conpression Evaporation and
Vertical Tube Foam Evaporation (Excluding
Softening. T!i<.Ta.il Softening, and Hultl-
St.irc Fl.ir.'i) for Treatment of Cooling
lower BUwdovns
Tennessee Valley Authority
Lockheed Electronics
Company (Northrop Corp.)
TRW. Incorporated
Hlttnan Associates,
Incorporated
Bechtel
Project Focus/Status
Reference
rpose Is to asttiMnble , review, evaluate, and report
t.i from research, development, nn»l demonst r.it Ion
tivities pertaining ro FCC waste illspos.il/utlllza-
n and power plnnr u-.iter rocyclc/i i ^.ttpicnt/rcu'jc.
Purpo
d.it
acti
tlon and pow
Investigate water rervcle/ronse alternatives for
coal-fired power plants fiirploytnp cfollnp, towers, ash
sluicing, and S0j/|.-art l<-ul.iti- scruMiinp systems, ;i.q
wfll na for combined yv-^tt-ms develop rouRh coat
estimates for scvcr.il polei'trd al ti-i nat Ivcs which
wuulil potrntially ntnlmlzc power pl.mt water requlro-
raetits anJ dlnchnrf.es.
The objectives of this prefect are r» (1) cliaracifrlze
coal pile dratn.tpv; (2) assesn the effect of pll .nl'nist-
ment on asli pond effluent; (J) ns.ses-: and then design
an effective prop.r.im tor ifKiniturinp, ash pond efll'Hnt;
(A) evaluate clilor in.-itcd water cfflmnt quality fic?n
a once-t:irouf.h cooling system; (5) js'icns, cli.ir.T f-rlze
and quantify coal a<^h le.ichnte efft-.'ts on proundv.iter
quality; and (6) study gaseous and r> '.rtlculate ^ml^stona
from several types of boilers.
Investigate tlie feasibility of cmpUwing mombrdtif
ti'i'hnoloRy In the treatment of power plant wasteviier.
Invest i g.ite the feasibility of usinf; an organic .tu.ilytl-
cal tucltnlquc to rapidly assess the effect of cooling
water effluents on tin- environment.
Chamctorlza t loa and evaluation of tlie toxicity of
compound-; formed by chlorlnat Ion of :;ea water by power
plants.
Perform hench se.ilc htudles to evaluate lime precipitation
as a technology to control metal discharges In boiler water-
side tube cleaning waste-waters. Use of hydrochloric acid
copper chemicals, citric acid, hydroxy acitic acid, and
EDTA may be considered later.
a) Monitoring of EPRI funded demonstration of vertical
tube fonra evaporation demonstration (VTFE-D)
b) Assess economic and energy efficiencies of VTh'E.
Reverse osmosl» nni! vapor coir.pr"'s:ilon evaporation.
9 Duractcili.it Jon of Ann, Fond Discharges
* Ongoing Projects
Overall Reference: [6]
Hit titan Associates,
Incorporated
For the EPA-Effluent Guidelines Division development
of Industiy wide data on ash pond dlbchurf.es.
-------
Table 2.14
EPRI Projects Concerning Water Recycle/Treatment/Reuse in Power Plants
Baslst 1. Only currently ongoing (•• of November 1978) projects are Hated.
2. Only projects pertinent to chemical wastt streams art listed. Purely thena! studies are not listed.
to
CO
Ko. Prolect Title
1 Development of Comprehensive Water
Management Methodology
Trace Element Removal by Adsorption
on Iron Hydroxides
Fundamental Studies of Mechanisms
of Blofoulant Film Buildup and
Destruction
Numerical Modeling Techniques for
Three-Dimensional, Reclrculating
Flows in the Near-Field of Cooling
Tower Pluraes
Acceptance Test Methodology fdr
Cooling Towers
Validation of Cooling Tower Pluae
and Drift Deposition Models
Agricultural Waste Water for
Power Plant Cooling
Ozone Dosage and Contacting for
Condenser Bio-Fouling Control
9 Other Chemical Alternatives to
Clilorln.it ion for Bio-Foul Ing
Control
10 Demonstration of Vertical Tube
Fo.-ia Evaporation for Slowdown
Treatment
Contractor
Water Purification Associates
Stanford University
Rice University
Environdyne, Ltd.
Environmental Systems Corporation
Argonne National Laboratory
California Department of Water Resources
Public Service Electric & Gas (N.J.)
Northwestern University
University of California at Berkeley
Project Focus
Develop Design and optimization r.uidelines for
an integrated water management system in fossil
fuel power plants.
Demonstrate a novel insolubilizntion process as
a feasible first step for trace iretal removal
from power plant discharge water streams.
Laboratory study of slime film l-uMdup In con-
densers and Its destruction; control by blocidsi
agents, such as chlorine.
Development of a general three-dlmiusional,
numerical model for representing the near-field
behavior of cooling tower plumes.
Develop and demonstrate Instrumentation and test
procedures for performing definite acceptance
tests on large mechanical draft cooling towers.
Assemble all available cooling tower plume field
data in a common format suitable Cor model
verification.
Develop an economical and reliable pretrentment
method for .iRrlcultural wasteuatL-r to reduce Its
scale-forming tendencies, so as to make tc accept-
able for pouer plant cooling.
Experimentally determine the dosatjo required and
the economic feasibility of USITV.; ozone to control
biofouling in model power plant condensers.
Assess other chemical alternative:; to chlorInation.
Demonstration of Vertical Tube Foam Evaporation
(VTFE-D). Equipment Involved is funded by prior
EPA study.
! [B]19]
-------
3.0 OVERALL WATER BALANCES IN POWER PLANTS
3.1 Waste Stream Flows
3.1.1 Condenser Cooling System
Of the total heat input in the power plant, 55-60% is rejected as
waste heat in the condenser. The condenser cooling systems can be of
once-through or recirculating type. The once-through system with its
resultant lower back-pressure at the turbine has been used predominantly
for plants located in the proximity of large bodies of water.
The recirculating condenser cooling systems can utilize wet
(evaporative) cooling tower, cooling ponds, dry cooling tower or a
combination of the three. In a wet cooling tower, water is lost by
evaporation, blowdown, and windage and drift losses. The windage and
drift loss is small, generally in the range of 0.02-0.1% of the tower
circulation rate. The evaporative loss is the largest part of the total
loss, generally 0.7-0.8% of the tower circulation rate for every 5.5°C
(10°F) rise in the condenser. The blowdown flow depends upon the maximum
allowable concentration for each of the dissolved and suspended species
in the circulating water without risking undue scale formation and corrosion
in the cooling systems. An increase in cycles of concentration (defined
as the ratio of concentration between circulating water and makeup water
for a constituent species) will reduce proportionately the blowdown flow
and, hence, the total makeup water requirements. However, the decrease
in makeup water requirement beyond about five cycles of concentration is
not appreciable because the evaporation loss becomes proportionately quite
large at this level of recycle and does not change significantly with
further increase in cycles of concentration.
The dry cooling tower is a recent technology and its long-term
implications on water consumption cannot be evaluated comprehensively
at the present time. Under certain favorable conditions, water con-
sumption in systems using cooling ponds can be lower because only a
portion of the heat is dissipated through evaporation while the rest
dissipates through natural convection. However, usually the solar radia-
tion adds to the water evaporation rate in cooling ponds. The radiation
varies the amount of evaporation. Cooling ponds are potentially better in
3-1
-------
dry years because of the amount of water they can hold. Cooling ponds
makeup can be seasonable and not constant. The selection of a condenser
cooling system is site-specific. The EPA and EPRI have sponsored studies
and are currently reviewing the modeling of such systems in order to
better understand all of the factors involved.
3.1.2 Steam Generation
In a modern 1,000-MW power plant with its high-pressure boiler the
steam production rate is in the range of 2.27-3.18 Mkg/hr (5-7 Mlb/hr).
An example of a power cycle diagram is shown in Figure 3.1 [16]. The
modern, high-pressure boilers require very high quality water; the water
chemistry has to be strictly controlled to minimize scale and corrosion.
This is achieved by proper feedwater treatment, condensate polishing,
deaeration, addition of supplementary chemicals (internal treatment),
and blowdown.
The boiler blowdown rate is generally in the range of 0.1-3% of the
steam flow. The lower range of the rates is normally encountered in large
high-pressure boilers. The boiler blowdown is generally alkaline (pH of
about 8) and contains 20-50 mg/£ of TDS (generally, the higher the pressure
the lower the total dissolved solids (TDS) value). Boiler blowdown does
usually contain significant concentrations of trace metals including Cu,
Fe, Ni and Zn. While boiler blowdown is a "clean" stream in the source
of potential reuse within the plant, its discharge into the environment
may be unacceptable due to the trace metals mentioned above.
3.1.3 Water Treatment Systems
It is necessary to treat raw water prior to its use as makeup in
the boiler feed water loop. Depending upon the raw water source and the
specific water quality required, the treatment operations consist of
clarification, softening, filtration and ion exchange. In some of the
older plants, distillation processes are used as part of the treatment
system in lieu of ion exchange. In recent years, reverse osmosis has
also been employed for boiler feed water treatment [11]. In high-pressure
boiler applications, condensate polishing is normally included as a treat-
ment step to achieve the required overall water quality.
3-2
-------
Stack Lo*i Mr In
N«tPow«r Lets
OJ
I
Forced Dr«ft Fan
7
Fan Powtr Heat Recovery
To Gas Rexirtulatlng Fan
Fu«l In •
Flue Gas
k
.— —
^ .
^*
High Pressure
Turbine
r-
Ash Pit LOSS
LX
High Pressure Bleed Heaters
Low Pressure Bleed Heaters
Boiler Feed Pump
Net Power
Transmission
Loss
Condenser
LOSS
Net
Generator
& Mechanical
Loss
Source: [10]
Figure 3.1 Power Cycle Diagram, Fossil Fuel - Single Reheat,
8-stage Regenerative Feed Heating
3515 psia, 1000F/1000F steam
-------
The quality and quantity of the waste streams from water treatment
systems are dependent upon the specifics of the plant. However, in
general, the technology for treating these wastes is fairly well estab-
lished; the unit operations and processes involved are well defined.
3-4
-------
3.1.4 Ash Handling Systems
The combustion of coal generates a large quantity of ash. Depending
on the ash content of the coal, a 1,000-MW coal-fired plant can produce
31.8-68 Mkg/hr (70-150 Mlb/hr) of ash. The distribution between fly ash
and bottom ash depends upon the type of boiler. The fly ash may consti-
tute 85% of the total ash in a pulverized coal burner, compared with 65%
in a spreader-stoker furnace or 20% in a cyclone furnace.
Ashes can be transported from points of collection (e.g., fly ash
from electrostatic precipitators, and bottom ash from furnace) to dis-
posal systems by either dry or hydraulic methods. However, in the
United States, the hydraulic method is widely used and a large amount
of sluicing water is required. The spent sluicing water, heavily laden
with dissolved and suspended solids, can represent a serious disposal
problem if recycling is not employed. Sluicing water requirements are
dependent upon the hydraulic design considerations. The following ranges
have been reported as typical values for sluicing water [5]:
• Bottom ash: 10-18 tons/ton of ash
• Fly ash: 5-12.5 tons/ton of ash
The TDS concentrations in sluicing water can vary between a few hundred
to many thousand mg/£. The species are diverse and include salts of
sodium, magnesium, calcium, potassium, and numerous trace elements. The
salts are generally present as sulfites, sulfates, chlorides, and oxides.
3.1.5 Flue Gas Desulfurization (FGD) Systems
Removal of sulfur dioxide from stack gases is required for most types
of coal to comply with the current emission standards. FGD systems can be
generally categorized into two groups: nonrecovery or throwaway systems
which produce a waste material for disposal, and recovery systems which
produce a saleable byproduct (sulfur or sulfuric acid). Recovery systems
usually have prescrubbers and produce smaller quantities of wastes for
disposal. There are now over 50,000 MW of coal-fired electric utility
boilers in the United States to which FGD systems are being applied
(including systems in operation, under construction, or in procurement).
About 90% of this capacity involves recovery systems, most of which employ
3-5
-------
lime or limestone to produce a solid waste, calcium-sulfur salt for
disposal. This technology can be expected to dominate in boiler
applications on FGD systems for the foreseeable future.
Water consumption in the nonrecovery FGD process includes that for
saturating flue gases, 2.7-4.6 lit/min (0.7-1.2 gpm) per MW and water
losses with the waste, 0.08-2 lit/min (0.02-0.53 gpm) per MW. Saturation
losses depend primarily upon the type of boiler and boiler operating con-
ditions, whereas water losses in FGD wastes depend upon the sulfur content
of the coal and the sludge dewatering method employed in the FGD system.
Makeup water for FGD systems can be overflow and/or wastewater from other
plant operations such as ash pond overflow, coal pile runoff, and certain
ion exchange regenerants. However, the chemistry of the wastewater must
be well defined so that appropriate pretreatment can be employed if nec-
essary. A detailed discussion of FGD technology is presented in Volume 3
and water consumption and usage reviewed in Section 3.7.
3.1.6 Miscellaneous Operations
Water used for miscellaneous operations can produce minor waste
streams. These operations include laboratory and sampling activities,
auxiliary cooling water system(s), sanitary facilities, and washing of
intake screens.
Laboratory and sampling wastes can differ from plant to plant.
Modern plants, where closer controls on operations are required, have
more extensive sampling and laboratory activities. There are no quan-
titative data reported in the literature; however, these wastes are minor
(perhaps in the range of 190 m3/day or 50,000 gpd) and are relatively
insensitive to plant size beyond 500 MW.
The auxiliary cooling water systems can be either once-through or
recirculating type. The flow through the once-through system ranges
from 1.9-133 lit/min (0.5-35 gpm) per MW with a typical value of ap-
proximately 40 lit/min (10 gpm) per MW. This total flow represents
the wastewater stream. In closed systems, the recirculation rate is
typically 91-95 lit/min (23-25 gpm) per MW. Slowdown from this system
is reported to be 0-19 lit/day (0-5 gpd) per MW [5].
3-6
-------
Sanitary wastes in a 1,000-MW coal-fired plant employing about 200
people are usually about 26.5 m3/day (7,000 gpd), or less than <0.01 gpm
per MW at 70% load. Wastes from washing of intake screens are minor and
contain mainly suspended solids. Consequently, their impact on the overall
water balance and treatment technology can be considered insignificant.
3.1.7 Maintenance Cleaning
Periodic maintenance cleaning of boiler tubes, boiler fireside air
preheater, condenser, miscellaneous small equipment, stack, and cooling
tower basin creates wastewater streams. These streams (especially those
from boiler and air preheater) are characterized by high toxicity and
large volumes. For these streams, flow equalization prior to treatment
is usually required. However, in stations with multiple units, it is
possible to schedule the cleaning frequencies so that storage require-
ments for flow equalization prior to treatment can be minimized.
The steps involved in cleaning of boiler tubes depend upon the scale
composition and the chemicals selected to remove the scale. For example,
copper scale is removed by alkaline solutions containing ammonia, soda
ash, and an oxidizing agent such as bromates or by using ammoniated
alkaline solutions which contain chelating compounds such as EDTA.
Inhibited hydrochloric acid is used to remove iron scale. The volume
of wastes resulting from boiler tube cleaning operations can vary between
3 to 10 times the boiler volume, depending upon the specifics of the
application. The boiler fireside is cleaned with high-pressure alka-
line water containing sodium salts such as soda ash, caustic soda, and/or
phosphates. The frequency of cleaning boiler tubes and boiler fireside
varies from once in seven months to once in 100 months. The typical
cleaning frequency is once in 36 months [5,12].
Air preheaters are cleaned more frequently (once or twice a month).
Alkaline water with detergents is used and the volume depends predomi-
nantly on the maintenance procedures. Condenser tubes are cleaned with
inhibited acid solution. The steam side of the condenser is cleaned less
frequently unless there is evidence of excessive tube leakage.
3-7
-------
The stacks and cooling tower basins also require periodic cleaning,
although less frequently than boilers. Cooling tower basins accumulate
sludges over a period of time and need cleaning. Removal of these sludges
is usually done by a front end-loader and a dump truck; such sludges are
usually disposed of along with other solid wastes such as coal ash and
FGD wastes. Wastes from stack cleaning can be acidic, depending upon
flue gas composition (with or without FGD systems).
3.1.8 Drainage
Drainage is composed of two waste streams:
• Coal pile runoff which constitutes the major
drainage stream in many cases, and
• Contaminated floor and yard drains.
Coal storage is dependent upon considerations such as distance from
source, transportation methods, labor conditions, availability of land
and coal prices. Typically, a 90-day supply is maintained as an active
pile. This corresponds to 600-1800 m (0.5-1.5 acre-ft) per MW. The
storage piles are 8-12 meters (25-40 ft) high and thus the coal pile
area ranges between 50-225 m2 (0.013-0.06 acres) per MW. The quantit
the runoff depends upon the amount of rainfall and is initially highly
acidic. Runoff contains significant concentrations of dissolved solids
including iron, sulfate and manganese. Significant amounts of
aluminum, zinc, copper, cadmium, chromium, vanadium, silver, lead,
and other metals are also present in the runoff.
Contaminated floor and yard drains are another intermittent source
but are often a minor one. Oil and grease are major contaminants in
floor and yard drains.
3-8
-------
3.2 Treatment Technology in General
In this subsection, the focus will be on the potential(s) for water
recycle/treatment/reuse of individual streams.
Chemical wastes in power plants can be broken down into individual
waste sources. In its evaluation of power plants for developing effluent
guidelines, the EPA identified individual streams for a power plant.
Table 3.1 provides a listing of these streams.
The degree of effluent reductions that can be achieved by the
application of specific control and treatment technology is related
to the type of source components involved and, further, to water use,
quality, and other considerations specific to individual plants. Both
site- and plant-related characteristics affect the degree of practica-
bility of applying wastewater control and treatment technology.
The generalized chemical characteristics of wastewater streams in
a coal-fired power plant are summarized in Table 3.2 [13,14,15]. An
example of a water management scheme for a coal-fired power plant with
an FGD system is shown in Figure 3.2. In the subsequent sections, an
assessment of each waste stream will be presented including:
• A brief description of the system generating the waste.
• Waste characterization (typical).
• Conventional methods for minimizing or treating the
particular waste stream.
• Data (if generically applicable and available) on
economics of such treatment.
• Recent studies on water management of the waste streams.
In Sections 5.2 and 5.3, considerations on combining many of the
waste streams for water management will be discussed. It should be
emphasized that maximum technical potential for water management,
including recycle/treatment/reuse at power plants lies in such
combination of waste streams. Such an approach also usually provides
economic optimum for water management under given regulatory and water
supply constraints for the whole plant. In addition, water management
will involve many site-specific and power plant system-specific
3-9
-------
Table 3.1
Chemical Waste Categories - Coal-Fired Power Plants
I. Continuous
1. Condenser Cooling System
A. Once-through
B. Recirculating
2. Boiler
A. Slowdown
3. Water Treatment
A. Clarification
B. Softening
C. Ion Exchange
D. Evaporator
E. Filtration
F. Reverse Osmosis
G. Other Treatment
4. Ash Handling
A. Fly Ash
B. Bottom Ash
5. Flue Gas Desulfurization
6. Miscellaneous Waste Streams
A. Sanitary Wastes
B. Plant Laboratory and Sampling Systems
C. Intake Stream Backwash
D. Auxiliary Cooling Water Systems
E. Construction Activity
II. Intermittent
7. Maintenance Cleaning
A. Boiler Steam Generator Tubes
B. Boiler Fireside
C. Air Preheater
D. Miscellaneous Small Equipment
E. Stack
F. Cooling Tower Basin
8. Drainage
A. Coal Pile
B. Contaminated Floor and Yard Drains
Source: Arthur D. Little, Inc.
3-10
-------
Table 3.2
Summary of Chemical Characteristics of Utility Effluent Systems (Coal-Fired Plants)
No. Effluent Stream
Cooling Tower
Slowdown
Process or
Operation
Corrosion Inhibi-
tion
Scale Control
Biological
Fouling (Algae
Slimes, Fungi)
Suspended Solids
Dispersion
Leaching of wood
preservatives
from wood cool-
ing towers
Chemical
Additive(s)
Chroraate
Zinc
Phosphate
Silicates
Proprietary Organics
>ical Conr . of
kdditive or
Pollutant
-50 mg/1 as CrO
•35 mg/1 as Zn
Resulting Priority
Pollutant Expected
in Effluent
Chromium
Zinc
Expected Cone.
of Pollutants
in Effluent
10-50 mg/1
8-35 mg/1
Comments
15-60 mg/1 as PO,
4
3-10 mg/1 as organic
Acid (H SO ) 2-5 mg/1
Inorganic rolyphosphates
Chelating Agents
Polyelectrolyte 1-2 mg/1
Antiprecipitants
Organic/Polymer Dispersants 20-50 mg/1
Chlorine
Hypochlorite
Chlorophenates
Thiocyanates
Organic Sulfur Compound
-------
Table 3.2 (Continued)
Summary of Chemical Characteristics of Utility Effluent Systems (Coal-Fired Plants)
No. Effluent Stream
Process or
OperatIon
Boiler Slowdown Scale Control
u>
i
Corrosion Control
pH Control
Solids Deposition
Chemical
Addltive(g)
Typical Cone, of
Additive or
Pollutant
3-60 mg/1 of PO,
Di fc Tri Sodium Phosphates
Ethylene
dla»ln«tetracetic acid(EDTA) 20-100 mg/1
Hltrolatriacetlc acid(NTA) 10-60 mg/1
AlgiMtes 50-100 mg/1
Polyacrylates 50-100 mg/1
Polymethacrylates 50-100 mg/1
Sodium Sulfite
Hydrazlne
Morpholine
Sodium Hydroxide
Sodium Carbonate
Ammonia
Morpholie
Uydrazlne
Starch
Alginates
Polyacrylamldes
Polyacrylates
Tannins
Lignin Derivatives
Polymethocrylates
Resulting Priority
Pollutant Expected
in Effluent
Expected Cone.
of Pollutants
in Effluent
Comments
<200 mg/1
5-45 mg/1
5-45 mg/1
variable added to adjust
pH to 8-11.0
20-50 mg/1
20-50 mg/1
20-50 mg/1
20-50 mg/1
-------
Table 3.2 (Continued)
Summary of Chemical Characteristics of Utility Effluent Systems (Coal-Fired Plants)
No. Effluent Stream
Ash Handling
Process or
Operation
Coal Asli Sluic-
ing
(fly ash and
bottom ash)
Chemical
Additive(s)
None
Typical Cone, of
Additive or
Pollutant
Resulting Priority
Pollutant Expected
in Effluent
Expected Cone.
of Pollutants
in Effluent
Comments
Pollutants in sluice In addition to
water before sluicing Source Water:
Cadmium
Chromium
Copper
Lead
Magnesium
Nickel
Trace metals in the cod
or oil are leached into
the sluicing liquor
FGD Systems
Miscellaneous
Lime/Limestone
Lime or Limestone
Alkaline Fly Ash
Dual Alkali
Lab & Sampling Sanitary
Intake Screen Backwash
Auxiliary Cooling
TDS=25,000 to 70,000
Cadmium
Arsenic
Mercury
Zinc
Others
Can be leached to
surface or ground-
water
1 Chemical Cleaning
boiler waterside Acid Solvents and Toxic
cleaning and Solvents
condenser water-
side cleaning
boiler fireside
Water or slightly alka-
line wash
Na.CO
NaOH
Phosphates
Nickel
Zinc
Aluminum
Copper
iron
nickel
chromium
vanadium
zinc
Heavy metals "are
dissolved into the
cleaning solution
from equipment sup-
faces
Much of the prior-
ity pollutants con
from dissolution
of deposits on b 4
boiler tube surfa*
The deposits orig-
inate in the coal
or oil burned
-------
Table 3.2 (Continued)
Summary of Chemical Characteristics of Utility Effluent Systems (Coal-Fired Plants)
ND. Kffluent Stream
Process or
Operat ion
ChemicaI
Additive(s)
Typira 1 Cone. of
Adi) it i ve or
I'n I lutanr
Resulting Priority
Pollutant Expected
in Effluent
Expected Cone.
of Pollutants
in Effluent
Comments
Coal Storage &
Handling
Rainfall/runoff
Floor & Yard
Drains
A! i.m i num
Sul fall's
Chi or ides
Depends on intake
water
Iron
Cadmium
Beryllium
Nickel
Chromium
Vanad iutn
Zinc-
Copper
Dissolution of
trace metals im<
water
Process, Spills
and Leaks
Accidents involving
general plant operations
I
h-*
J>
Source: [13, 14, 15]
-------
Source: [14]
Figure 3.2 An Example of Recycle/Treatment/Reuse Scheme
for Coal-Fired Power Plants with FGD
-------
considerations. Only broad generic possibilities will be discussed in
this report.
In considering water management, one needs to be cognizant of
substantial differences between new and existing power plants. The
concern regarding collection and piping systems for waste streams for
combined water management was mentioned earlier. In any retrofit appli-
cation, the costs associated with piping and collection may exceed that
of any treatment system for wastewater. In a new plant, the costs can
be minimized by taking into account the systems requirements in the
design phase.
3.3 Condenser Cooling System Wastes
3.3.1 General
In a large, coal-fired power plant, of the total heat input, 35-40%
is converted to electricity and the remaining 60-65% is rejected as
waste heat in stack gases and condenser. The energy lost in stack gases
is about 10% of the amount rejected in the condenser. This means that
about 55-60% of the heat input is rejected in the condenser. The water
flow required in a power plant is inversely related to the operating
temperature difference in the condenser (i.e., temperature of water out
of the condenser minus the temperature of the water into the condenser).
For a typical 1000-MW power plant, the watei flow times the tempera-
ture difference is approximated as follows:
gpm x A + (°F) = 11.7 x 106 or
m3/min x A + (°C) = 79.8 x 103.
The condenser cooling system can be of the following types:
• Once-through
• Recirculating
- Cooling ponds
- Wet (evaporated) cooling tower
- Dry cooling tower
- Combination (hybrid) system.
3-16
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Figure 3.3 presents simplified schematics of these types. Table 3.3
presents typical data on water requirements associated with each type
of cooling system.
Based on data from 800 plants, EPA recently reported [101] that
67% of steam electric power plants use once-through cooling water in
water in their condensers. Thus in spite of water availability con-
straints and environmental regulations, once-through cooling is the larg-
est mode in power plants. However, in the future, new plants are expected
to use cooling towers more widely.
3.3.2 Once-through Cooling
This is the earliest type of system and is now employed if the power
plant is in proximity to large bodies of water; if seawater is employed
for condenser cooling, once-through systems are usually employed.
Figure 3.2 outlines the schematic. Once-through cooling systems are
unique since the total cooling water flow is discharged as a wastewater
effluent. After passing through the condenser, the cooling water is
discharged to a receiving body (i.e., river, lake, pond). Water use in
55 4
once-through cooling varies from 1 x 10 to 3.5 x 10 lit/MWH (2.6 x 10
to 9.3 x 104 gal/MWH) [5].
In a once-through system, the chemical composition of the effluent
water is essentially equivalent to that of the influent water. Water
quality parameters such as total dissolved and suspended solids, pH,
etc., should be largely governed by the characteristics of the cooling
water source and not by the operation of the cooling system. Slight
changes in the chemical compositions between influent and effluent for
these systems may occur, however, as a result of the formation of
corrosion products and/or the addition of treatment chemicals (i.e.,
biocides).
Water-side corrosion of the main condenser will result in corrosion
products (i.e., metal oxides) appearing in the cooling water effluent.
Condenser metallurgy would normally be selected so as to minimize water-
side corrosion problems.
3-17
-------
SURFACt
SURFACfi WATER.
HEKT TO
c;
U)
I
oo
EXHA.U6T STEAM
FROM. TUICBlME
A.RE. SHOWN-
2. COOUIKft POHOS AK£ ANALOGOUS TO COOUlHG
TOWCR.
Figure 3.3 Cooling Systems
-------
Table 3.3
Typical Gross Water Intake Requirements
For Cooling Systems
Type of Relative Quantity
No. Cooling of Water-*-
1 Once-through 1000
2 Cooling towers and in-QD
ponds^
3 Hybrid (wet/dry) 1-10
4 Dry 0
The quantities are specified as relative quantities. However,
for a typical 1000-MW power plant, these are in cubic feet
per second.
2
Usually evaporation rate is about 18 to 23 and blowdown rate
is 5 to 60.
Source: Arthur D. Little, Inc.
3-19
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The only major potential pollutants are blocides used to control
microbial growth in heat exchanger tubes. Chlorine and hypochlorite
are the most common biocides used. Dosage of biocide is site-specific
but may vary from 1 to 10 times per day; "shock" or "slug" type of treat-
ment is frequently used. Residual chlorine concentration in the
effluent varies from 0.1-1 mg/A[5]. However, when using certain influent
waters—such as seawater—chlorine concentration as high as 12 mg/i or
more may be used to inhibit crustacean growth [16].
The first major attempt at water recycle/reuse at power plants
involved the transition from once-through to recirculating wet cooling-
systems. In recent years, research has focused on recirculating dry or
hybrid (wet/dry) cooling systems.
3.3.3 Recirculating Systems
3.3.3.1 Recirculating Wet Systems
Condenser cooling water can be recirculated within the plant.
This is accomplished by:
• Cooling Ponds - In these large, recirculating systems, the
water for rejection of the waste heat is drawn from a large
pond, canal or other body with substantial surface area ex-
posure. The water, after absorbing the waste heat, is recycled
back to the pond or canal. The rejection of waste heat from
such cooling ponds is via evaporation from the pond and radiant
heat transfer.
• Cooling Towers - In these systems, the rejection of heat is
accomplished by allowing the water to spray through a cooling
tower system. The more conventional systems are wet cooling
towers; modifications that are now under development involve
dry cooling towers and wet/dry combinations.
3-20
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Wet cooling towers generally reject heat from the cooling
water to the atmosphere by sensible heat exchange (about 20%)
and evaporation (80%).
Ponds are used only where large areas of inexpensive land
are available, since a large plant may require over 1,000
acres of pond surface. Cooling towers may be either of the
wet or hybrid (wet/dry) types, and are used where sufficient
land for ponds is unavailable or too expensive. Since all
cooling devices (except dry cooling systems) transfer the
process waste heat to the atmosphere mainly by evaporation
(radiant and sensible transfer of heat may be significant
for large ponds), additional water must be added to the system
to make up for these losses due to evaporation, drift and
blowdown. The potential for water recycle/reuse in cooling
towers and ponds is analogous. However, cooling ponds
offer substantial water storage capability to weather dry periods.
Figure 3.3(b) (page 3-18) outlines the schematic of a recirculating
cooling system using cooling towers. EPA [116] has made some esti-
mates on cooling tower water requirements assuming certain levels of
typical intake water quality. While generic studies are useful, a site-
specific analysis is normally required to determine water require-
ments adequately.
3.3.3.2 Recirculating Dry Systems
Dry recirculating systems use a recirculating fluid to transfer heat
from the condenser to the atmosphere (see Figure 3.3[d]) via air-cooled
heat exchangers. Thus, these function in a manner analogous to the
radiator in an automobile and do not require make up water. Dry
systems are more expensive than wet cooling towers or hybrid systems
discussed later.
3-21
-------
A recent survey article by Rossie and Cecil (17) suggests that
there are a number of possible savings that can be effected by utilities
using dry towers. For example, such plants can be located nearer the
sources of fuel without regard for the availability of large quantities
of water, which would effect a savings in the cost of fuel transportation.
This added flexibility in location could be used also to optimize real
estate costs, power-transmission costs, environmental damage, and aesthetic
factors. Unlike the case in which plants use wet towers, the cost of
energy will be free from the cost of water and the cost of effluent
control.
Although these advantages may appear attractive on paper, the power
industry has been reluctant to seriously consider using completely dry
cooling for two main reasons: (1) Since a dry tower cannot cool the
water below the ambient dry-bulb temperature, the design must be based
on the maximum summertime temperatures. This leads to large and there-
fore expensive installations occupying large land areas. (2) The higher
cold-water temperatures, which result part of the time (especially during
summer operation), mean that the turbine has to operate at higher back
pressures. Existing turbines, if operated at the required higher back
pressures, will suffer in efficiency and thereby increase the fuel con-
sumption. Turbine designers have not succeeded so far in building high
back-pressure turbines without penalties in efficiency. On balance, it
is unlikely that dry cooling towers will be used by themselves for large
power plants in any significant proportions in the foreseeable future.
3.3.3.3 Recirculating Hybrid (Wet/Dry) System
The wet/dry cooling tower is a relatively new cooling system which
provides for control of environmental impact from effluents as related
to plume (fog) abatement and water conservation [18,19]. The wet/dry
tower (see Figure 3.3(d)) combines air-cooled heat exchangers and con-
ventional evaporative cooling sections into a configuration utilizing
a common fan (predominantly induced draft). The heat exchangers (dry
section) allow for the removal of part of the heat load via sensible
heat transfer (constant absolute humidity), whereas the remaining heat
3-22
-------
load is removed via latent and sensible heat transfer in the evaporative
section. The effect is to reduce the relative humidity or moisture content
of the tower effluent, thereby reducing the frequency of plume formation
and decreasing to some extent water loss via evaporation and drift. Hybrid
systems are normally intermediate between wet and dry cooling systems in
terms of capital and operating costs and also in size.
3.3.4 Water Conservation and Chemical Waste Streams
All recirculating systems reduce water requirements from those for
once-through systems. To provide a rough idea on gross water intake
requirements (and remembering that the water in once-through cooling
is returned to the source), the order of magnitude values shown in
Table 3.3 may be suggested.
Wet and, to a lesser extent, hybrid (wet/dry) recirculating systems
produce a blowdown for treatment. Dry cooling towers do not produce any
blowdown but are more costly than any of the alternatives.
United Engineers recently completed a study for the EPA [18] on water
consumption and costs for steam-electric power plant cooling systems. The
principal conclusions from this study are:
1. Where water is available, wet cooling will continue to be
the economic choice in most circumstances. However, for
sites with remote water supply sources, the advantage of
wet cooling over wet/dry cooling may be small. In cases
where resource limitations or environmental criteria make
water costs excessive, wet/dry cooling can reach economic
parity with wet cooling.
2. Wet/dry cooling tower systems can be designed to provide a
significant economic advantage over dry cooling, yet closely
match the dry tower's ability to conserve water. The wet/dry
systems which save as much as 98% of the makeup water
required by a wet tower can maintain that economic advantage.
Therefore, for power plant sites where water is in short supply,
wet/dry cooling is the economic choice over dry cooling. Even
where water supply is remote from the plant site, this advan-
tage holds.
3-23
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3. Ground fogging from low profile wet cooling towers can be
significantly reduced by increasing the number of cells,
thereby reducing the liquid water concentration in the
plume. These design changes can be made without significantly
increasing the total evaluated cost of the wet cooling tower.
In cases of restrictive site conditions or fogging limitations
hybrid wet/dry cooling towers may be used effectively at costs
which approximate those of enlarged wet towers.
From the viewpoint of chemical waste streams and control thereof
(which is the focus of this report), recirculating wet cooling tower
systems provide the maximum complexity. All other systems, in fact,
require only parts of the overall considerations involved in wet cool-
ing towers as far as technology and environmental impacts are concerned.
Hence the focus of this subsection will be the recirculating cooling tower.
3.3.5 Wet Cooling Tower
3.3.5.1 Process Variables
The approach (difference between the water temperature leaving the
tower and the ambient design wet-bulb temperature) is usually in the range
of 4-8°C (7-14°F) and it depends upon the number of heat transfer units
provided by the tower. Evaporation and drift losses are dependent upon
the cooling load, ambient atmospheric conditions, and the tower design.
The term "cycles of concentration" is defined as the ratio of the
recirculating species concentration to the makeup species concentration
and can be expressed in terms of flow rate as in Equation 3.1 [5,16].
E + B + D M
B+D B+D (3.1)
where C * cycles of concentration
E = evaporation rate
B • blowdown rate
D - drift rate
M = makeup rate.
In assessing pollutants from cooling towers, it is well to note that
the past few years have seen major changes with regard to cooling tower
design and construction. The typiccal cooling tower of some years ago was
constructed of a wooden structure, employed wooden fill material and
3-24
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The blowdown stream is a slip stream withdrawn from the system to
control the cycles of concentration. In all recirculating systems, a
blowdown must be withdrawn from the system to control the concentrations
of impurities and contaminants. This stream represents the wastewater
from the recirculating cooling system. The cooling tower blowdown (or
the blowdown from any recirculating system) is thus a wastewater stream
of concern from the condenser cooling water system and is maintained at
a level sufficient to prevent scale formation in the condenser. Such
scale formations on the condenser tubes reduce the heat transfer effi-
ciency of the condenser, resulting in increased back pressure on the
turbine which leads to an overall loss in the cycle efficiency. Scale
formation depends upon the operating temperature, the makeup water quality
and the cycles of concentration. In practice, C is usually between 4
and 6. For very high quality makeup water, C may be as high as 15, and
for very saline water, C may be as low as 1.2-1.5. The evaporation rate
(E) from cooling towers averages about 1.5% of the cooling water flow
for every 10°C (10°F) rise in cooling water temperature as the water
passes through the condensers. The drift rate (D) for new cooling towers
is about 0.005% of the cooling water flow for mechanical draft towers,
and about 0.002% for natural draft towers.
Blowdown quantity is set by the maximum concentration of a limiting
impurity (i.e., hardness, dissolved solids, suspended solids) that can
be tolerated in the system or by the solubility limit of scaling salts
such as calcium sulfate, calcium carbonate, etc. The blowdown rate
typically ranges between 0.5-3.0% of the recirculating water flow. (19,20)
The recirculating flow required is about 0.1 lit/Kcal (12 gal/1,000 Btu)
of heat removal for every 10°C (10°F) rise in cooling water temperature.
Typically, blowdown will contain everything in the makeup times the
cycles of concentration factor C except the volatiles. Additionally,
various amounts of the conditioning chemicals will be present.
Table 3.4 presents a typical cooling tower blowdown analysis.
In recirculating systems, the chemical characteristics of the re-
circulating water influence the maximum cycles of concentration C. Table
3.4 presents some broad guidelines in establishing the quality of water
in recirculating cooling tower sytems.
3-25
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Table 3.4
Cooling Tower Recirculating Water Quality Guidelines
LIMITS
Parameters
Langelier Saturation Index
2
Ryznar Stability Index
PH
Calcium,mg/fc as CaCO-
Total iron, mg/K,
Manganese, mg/fc
Copper, mg/j,
Aluminum, mg/&
Sulfide, mg/SL
Silica, mg/£
(Ca)'(S04), product
Total dissolved solids, m;
Conductivity, micromhos/cm"
Suspended solids, mg/"£
Minimum
+0.5
+6.5
6.0
20-50
Maximum
+1.5
+7.5
8.0
300
400
0.5
0.5
0.08
1
5
150
100
500,000
2,500
4,000
100-150
Remarks
Nonchromate treatment
Nonchromate treatment
Nonchromate treatment
Chromate treatment
For pH < 7.5
For pH > 7.5
Both calcium and sulfate
expressed as mg/5,
CaCO.,
The limits for the Langelier Saturation Index (an indication of CaCO,
saturation) presume the presence of precipitation inhibitors in non-
chromate treatment programs. In the absence of such additives, the
limits would be reduced to 0 and 0.5.
2
For a discussion of Langelier Saturation Index and Ryznar Stability
Index, see Section 3.6.7.
Source: [21]
3-26
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trend in utility cooling towers is towards concrete structures, asbestos
cement fill and natural draft operation. In recent years, there has been
substantial focus on the carcinogenicity of asbestos. In cooling towers
constructed of asbestos cement fill, the cooling tower blowdown has been
reported to contain asbestos [101,115]. Erosion of the fill material is
the principal reason for asbestos fibers in the blowdown. No asbestos
was reported in the effluents to the receiving waters. Also, lignins
and tannins in wooden cooling towers affect scaling.
3.3.5.2 Makeup Water Treatment
In all recirculating cooling systems, the concentration of non-volatile
dissolved solids increases with increasing cycles of concentration. Further-
more, microorganisms such as fungi, algae, and bacteria can also cause rapid
and severe wood rot and metal corrosion [63]. Hence, various chemicals are
added to the cooling tower either in the makeup waters or in a slip stream
to prevent biological growth in cooling towers and to prevent scale accumu-
lation and corrosion in condensers. Usually, such additives include:
• Corrosion inhibitors,
• Scale control chemicals,
• Chemicals for biofouling control, and
• Suspended solids dispersants (antiprecipitants).
Table 3.5 outlines typical treatments commonly employed. A full list of
compounds employed as chemical additives for cooling tower systems is
reported [102]. In addition, as mentioned earlier, chrysolite asbestos
and acrolein have been reported in the tower basins [101] but not in any
final effluents [115]. The asbestos is presumably from asbestos cement
used in natural draft cooling towers.
The basic purpose in chemical conditioning is to maintain condenser
tubes or other heat exchange equipment with an inherent new-tube clean-
liness which is most important to keep the efficiency and economics of
the process at its designed level. The cost penalty of tube fouling
increases proportionately as the cleanliness decreases. If allowed to
continue, an unscheduled outage may be required to clean the tubes,
thereby losing production and further compounding additional costs.
3-27
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Chemical Treatment Summary for Recirculatlng Cooling Systems
Treatment Objective
Chemical Additive
Typical Additive
Concentrations in Blowdown
Comments
Corrosion Inhibition
Scale Control
oo
Biological Fouling
(algae, slimes,
fungi) Control
Suspended Solids
Dispersion
Chrornate
Zinc
Phosphate
Silicates
Proprietary Organics
Acid Treatment
Inorganic Polyphos-
phates
Chelating Agents
Polyelectrolyte
Antiprecipitants
Organic/Polymer
Dispersants
Chlorine
Hypochlorite
Chlorophenates
Thiocyanates
Organic Sulfur
Compounds
Tannins
Lignlns
Proprietary Organics/
Polymers
Polyelectrolytes/Non-
ionic Polymers
10-50 mg/8. as CrO^
8-35 mg/i as Zn
15-60 mg/i as PO^
3-10 mg/i as organic
Cooling water pH is main-
tained between 6.5 and 8.0.
2-5 mg/i
1-2 mg/i
20-50 mg/i
£ 0.5 mg/8. residual C12
^ 30 mg/i residual con-
centrations
20-50 mg/i
1-2 mg/e
Chromate treatment has been the traditional corrosion
inhibitor system. Since chromate has been found to be
highly toxic to aquatic life, water treatment vendors
are now offering alternative corrosion inhibitor treat-
ments which employ various combinations of chromate,
zinc, phosphate, silicate, and organic additives. These
alternative treatments are designed to either minimize
the chromate concentration that is necessary for co rrosion
protection or to completely eliminate the need fov
chromate by substituting other chemical additives.
Scale control allows reclrculating cooling systems to
operate at higher concentration factors without the
formation of scale on condenser heat transfer surfaces.
Acid treatment, polyphosphatcs, and chelating agents
maintain the solubility of the common scaling salts
(i.e., CaCO-, CaSO,, etc.) below the scaling limit (the
point at which they will precipitate from solution).
Polyelectrolyte antiprecipltants allow supersaturation of
the cooling water with respect to scaling salts without
precipitation of these salts occurring. Dispersants
do not inhibit scale precipitation, but prevent
precipitated salts from settling and adhering to heat
transfer surfaces.
Blocldes used to control biological fouling are either
the oxidizing or non-oxidizing types. Oxidizing blocides
(chlorine and hypochlorite) have been discussed for
once-through cooling systems in the "Once-Through Cooling
Water" section. These biocides are used in recirculating
cooling systems in a fashion similar to that described
for once-through systems. Non-oxidizing biocides
(chlorophenates, thiocyanates, organic sulfur compounds,
etc.) are employed when other chemical additives such as
organic corrosion inhibitors, scale control agents, or
solids control agents are destroyed by the conventional
oxidizing biocides.
Chemical dispersants maintain suspended solids from
settling and adhering to heat transfer surfaces.
-------
The objective is to maintain the cleanliness factor at an acceptable
level by one or more methods. Chemical treatment of makeup water is
only one technique to achieve this, although it is often employed.
In general, available techniques include [5]:
1. Continuous and complete chemical conditioning of the
cooling system while operating,
2. Chemical cleaning of the heat exchanger tubes at the
scheduled outage,
3. Mechanical cleaning of the tubes while operating with
equipment utilizing either sponge rubber balls or brushes,
slightly oversized to pass through the tubes, and
4. Mechanical cleaning of the tubes at a scheduled outage.
Chemical treatment of makeup water (or a slip stream) can increase
the number of cycles and reduce net blowdown. Thus, chemical treatment
may be envisioned as the first step in recycle/reuse. Against this back-
ground, some of the major treatment methods outlined in Table 3.5 are
discussed below.
a. Scale Control
Scale control allows recirculating cooling tower water to operate
at higher levels of concentration of contaminants without forming scale
on the condenser tubes. Important methods of scale control are:
1. Acid Treatment for Scale Control - Sulfuric acid is often
employed in cooling towers to control the pH of the water
and thereby control the precipitation of calcium carbonate,
hydrated magnesium oxides, and some of the silicate scales.
The level of acid required to control scales rises with the
cycles of concentration in a nonlinear fashion. Another factor
is the makeup water quality. The latter determines which species
are more likely to scale. Potentially the acidic wastes from
ion exchange units can be used as a source of H ions. Chemical
reactions involved are [18]:
CaCO- + H SO, -»• CaSO, + H-O + CO t
Mg(HC03)2 + H2S04 -> MgS04 + 2H20
3-29
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2. Other Removal Processes for Scale Control - Conventional
lime and lime/soda ash softening can be used to reduce Ca"*""1"
Mg and silica constituents from the makeup water.
For example, one scale-forming species which cannot be con-
trolled with acid treatment alone is gypsum (CaSO^ • 2H20).
Softening is a technique used to reduce the calcium concentra-
tion in an aqueous stream. In lime softening, calcium oxide
(as lime) is added to the liquid stream to increase the pH of
the solution and precipitate calcium carbonate. Softening is
among the less expensive systems to control gypsum scale. If
gypsum scale formation is not controlled by an adequate calcium
treatment, the cooling tower blowdown may have to be excessive
and require more expensive treatment of the ultimate effluent
in any zero discharge scheme. Removal processes can be carried
out at elevated temperatures (hot versus cold softening) and
higher removal efficiencies attained [21].
Softening is a more expensive treatment method when compared
with acid treatment; it requires more capital outlay and greater
maintenance. Hence, the size of the softened stream can have
a major impact on the total cost of treatment. A small slip
stream of the recirculated water can be softened to maintain
total calcium level rather than treating a larger makeup stream.
If softening of a small slip stream is used, it will generally
have to be done with soda ash (instead of the usual lime)
because of the loss of C02 in aeration, 2H+ + CC-3= -»• C02 t + H20.
A major problem is that soda ash is five times more expensive
than lime; however, soda ash is a better softening agent.
On balance, it appears that a combination of makeup and slip
stream treatment would result in an optimum system. Stone and
Webster Engineering Corporation at Sun Desert Nuclear Power
Plant found that softening the makeup and slip stream combined
to be the most efficient method [117].
3-30
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Other methods which should be noted are:
• Ion exchange. Ion exchange technology can be employed
for softening or demineralization. However, expense and
the generation of additional waste tend to preclude use
of ion exchange in this duty.
• Reverse osmosis. Reverse osmosis requires softening,
pretreatment of the water and disposal of resultant waste
brine.
• Evaporative techniques including Resource Conservation
Company's (RCC) brine concentration discussed later in
Section 5.3. However, evaporative methods should be
considered augmenting softening rather than replacing it.
Where the water to be used in a cooling tower system is
sufficiently hard (that is, the water contains moderately
high concentrations of calcium and magnesium ions, which may
produce scale-forming precipitates upon increasing the con-
centration at high temperatures), polyphosphates and silicates
are sometimes added to inhibit scale formation. EDTA has also
been used for this purpose in special applications but the
relatively high cost of this substance prohibits its wide-
spread use. In addition to these, a number of nitrogen con-
taining organic, non-chromate corrosion inhibitors have also
appeared in recent years and provide proper protection against
corrosion. Many of these are proprietary formulations.
In the presence of polyelectrolyte antiprecipitants, the
scaling salts can be maintained at supersaturated concentra-
tion without scaling. Organic/polymer dispersants prevent
precipitated salts from settling on heat transfer surfaces.
Many of these chemicals are proprietary compounds, and even
though they reduce the blowdown flow, their presence in the
blowdown can be a problem because of possible synergistic
reaction with chlorine [13].
3-31
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For a brief review of the theory of scale control, the
reader is referred to [32].
b. Corrosion Inhibition
In addition to scale control, the use of corrosion controlling
compounds is also practiced extensively. Corrosion control is one of
the major requirements in cooling water systems. Corrosion control is
usually accomplished by employing corrosion inhibitor chemicals. Such
inhibitor chemicals can be classified as anodic or cathodic or both
depending on the corrosion control mechanism. Inhibition results from
one or more of three mechanisms [32].
• The inhibitor molecule is adsorbed on the metal surface by the
process of chemisorption, forming a thin protective film either
by itself or in conjunction with metallic ions.
• Some inhibitors, however, merely cause a metal to form its own
protective film of metal oxides, thereby increasing its resistance
• The inhibitor reacts with a potentially corrosive substance in
the water.
Choice of the proper inhibitor is determined by the cooling system
design parameters and water composition. The type of metals in the
system, stress conditions, cleanliness, and designed water velocity all
affect inhibitor selection. In addition, other factors to be considered
include treatment levels required, pH, dissolved oxygen content, and
salt and suspended matter composition.
The most effective inhibitor in use is chromate or dichromate which
is an anodic inhibitor. Synergistic blends of zinc and chromium compounds
have been standard in the treatment of cooling tower systems for many yea
Thus, chromium and zinc are important heavy metals that may exist in co
ing tower blowdown. Environmental regulations severely limit chromate
discharge to levels as low as 0.05 mg/X. as chromium [33]. This is well
below the effective level for good corrosion protection in the cooling
water system and will require treatment. Zinc is often present since zi
salts are added to reduce total chromium loadings. Since methods for
removal of chromium also remove zinc, these will be considered together
3-32
-------
Corrosion and erosion are caused by a number of factors, some of
which are outlined in Table 3.6. Many of the chemical blends used to
inhibit dissolved oxygen corrosion in cooling systems often contain at
least two of the following three ions: zinc, chromate, and phosphate.
Chromates and phosphates, both typical inorganic and anodic inhibitors,
have been used separately or in combination for corrosion prevention in
cooling tower recirculation systems. When used alone, chromates are
often required in concentrations of about 200 mg/K, as Na2CrO . In
combination with polyphosphates, the total level of treatment is reduced
to about 40-60 mg/£. Chromates owe their protective action to their
ability to form a thin passivating film directly on the anodic portion
of metals. Besides chromates and phosphates, silicates, nitrites and
ferrocyanides have also been employed as scale inhibitors. In recent
years, the demerits of chromates and phosphates have been the focus of
significant attention, and several alternatives are now available [32,33].
Table 3.7 lists the various corrosion inhibitor systems used and
the typical levels of concentration in the blowdown streams from these
systems. Chemicals based on chromates, orthophosphates, and nitrites
form thin passivating film on anodic portions of metals (anodic corro-
sion inhibitors). Polyphosphates, silicates and zinc salts act as
cathodic corrosion inhibitors [5].
c. Other Treatment
In addition to scale and corrosion control, other chemicals are
added to control biofouling and disperse suspended solids (i.e., anti-
precipitants); chlorine or hypochlorite are the common biocides. These
are discussed in Section 3.3.6.
The complexity of optimizing the cost effectiveness of chemical
treatment and environmental constraints on effluents from cooling tower
systems have led to the development of data banks to optimize, by on-line
computer control, chemical treatment. One system offered by Calgon [111]
reportedly can achieve such optimization. It is likely that system opti-
mization is likely to be more widely practiced not only on cooling water
systems but overall water management in power plants.
3-33
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Table 3.6
Factors Affecting Corrosion
Ckmlui
A. pH
Acid Soluble Metals—oxides more soluble as pH
decreases. Increased corrosion.
Amphoteric Metals—oxides soluble at low or high pH
Protection lavored at intermediate pH.
Noble Metals-oxides insoluble at any pH. Inert to corro-
sion.
Dissolved Salts
Chloride, Sullate can penetrate passive metal oxide films
and promote local attack.
Calcium. Magnesium, Alkalinity may precipitate to torm
protective barrier deposits.
C. Dissolved Gases
Carbon Dioxide-reduces pH and promotes acid attack
Oxygen—depolarizes corrosion reaction at cathode, ox-
ygen deficient areas become anodic (differential aeration
cell).
Nitrogen—aggravates cavitation corrosion.
Ammonia—selectively corrosive to copper based metals
Hydrogen SuHide- promotes acid attack; forms deposits
thai promote galvanic corrosion
Chlorine-promotes acid attack, strips corrosion inhibitor
films
0. Suspended Solids
Mud, sand, silt, clay, dirt, etc. settle to torm deposits pro-
moting differential aeration cell corrosion.
A. Relative Areas
In a galvanic couple, as ratio of cathodic to anode area in-
creases, corrosion increases.
«
B Temperature
Increased temperature favors oxygen depolarization,
lowers hydrogen overvoltage, increases corrosion
Higher temperature areas become anodic to other areas.
Higher temperatures change metal potentials (e.g.
reverse galvanizing).
C. Velocity
High velocity promotes erosion corrosion, removes certain
passivating corrosion products
Low velocity increases sedimentation and differential
aeration cell corrosion, decreases amount of corrosion in-
hibitor reaching and passivating metal surfaces.
D. Heat Transfer
Favors oxygen depolarization by "hot wall effects."
Favors differential aeration cell formation by increasing
precipitation and sedimentation of solids
E. Metallurgy
Surface flaws-cuts, nicks, scratches, etc favor anodic
site formation
Stress—internal stresses promote anodic site formation.
Microstructuie—metal inclusions, precipation at grain
boundaries, differing adjacent grains, etc promote
galvanic cell formation.
E. Microorganisms
Promote acid attack, differential aeration cell corrosion,
calhodic depolarization, galvanic corrosion.
Source: [32]
3-34
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Table 3.7
Waste Disposal Characteristics -
Typical Cooling Water Treatment Systems
Inhibitor
System
Chromate Only
Concentration in
Recirculating Water
(mg/1)
200 - 500 as CrO,
Zinc
Chromate
8 - 35 as Zn
17 - 65 as CrO,
Chromate
Phosphate
Zinc
10 - 15 as CrO,
30 - 45 as PO,
8 - 35 as Zn
Phosphate
15 - 60 as PO,
Zinc
Phosphate
8 - 35 as Zn
15 - 60 as P04
Phosphate
Organic
15 - 60 as PO,
3 - 10 as organic
Organic Only
100 - 200 as organic
10 est. as BOD
100 est. as COD
50 est. as CCl^
extract
5 est. as MBAS
Organic
Biocide
30 as clorophenol
5 as sulfone
1 as thiocyanate
Source: [5]
3-35
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3.3.6 Cooling Tower Slowdown Treatment
3.3.6.1 Overall Approach
The blowdown from a recirculating cooling system will have the same
chemical composition as the recirculating water. The composition of blow-
down will be influenced by:
• Makeup water characteristics,
• Chemical treatment of the recirculating cooling water,
• Intimate contacting of air-water in the cooling device, and
• Cycles of concentration.
As mentioned earlier, the blowdown contains significant concentrations
of dissolved solids from the source water, suspended solids, as well as
small concentrations of chlorine and other chemical additives introduced
into the system. Usually because of the multiple scale-forming species
involved (Ca"1"4", Mg"*"*, S04~, silica, phosphates, C03~~), the blowdown
flow is maintained at a larger value than that predicted by theoretical
considerations. The quality of cooling tower makeup water may be raw
water or water extensively treated to permit high cycles of concentra-
tion. In all instances, chemicals are added continuously or at intervals
to control corrosion, inhibit biological growth and prevent deposits.
Withdrawal of blowdown may be on a continucus or intermittent basis.
Treatment of cooling tower blowdown for recycle/reuse can be
considered from the following viewpoints:
a. Optimization of makeup water conditioning to maximize recycle
b. Treatment for chlorine in blowdown,
c. Treatment for zinc and chromium in blowdown,
d. Utilization of treated or untreated cooling tower blowdown
in other parts of the power plant, and
e. In dry areas, high TDS blowdown water may be unacceptable for
discharge. Thus, it must be stored or evaporated.
Item (a) has been discussed earlier, and item (d) will be considered
in Section 5.3; items (b) and (c) are discussed in the following Sections
3.3.6.2 and 3.3.6.3.
3-36
-------
3.3.6.2 Residual Chlorine in Slowdown
Most power plants use chlorine for biofouling control. In 1972,
the reported usages of chlorine for power plant cooling water treatment
alone was 25,700 metric tons (28,600 short tons) compared with 233
metric tons (256 short tons) of chlorine for boiler feedwater treatment
[24]. To show the pattern of chlorine usage, details on breakdown of
chlorine use for different types of cooling systems are presented in
Table 3.8.
On a megawatt basis, a saline water system consumes 0.150 metric
ton (0.167 short ton) C12/MW per year versus 0.068 metric ton (0.075
short ton) Cl /MW per year for fresh water.
Current chlorination practice is to provide adequate free chlorine
residual (e.g., 0.2 to 1.0 mg/2,) at the outlet side of the condenser.
As noted earlier, recent research has indicated that this free chlorine
reacts with a variety of organic compounds to form carciogenic compounds,
which are of great concern if they enter public drinking water systems.
It is noted that chlorinated organics can be formed by use of chlorine
and many chlorinated organics are on the current list of 129 priority
pollutants. (See Sec. 4.1.5.)' To protect both the public and aquatic life,
the EPA has established allowable concentrations of free chlorine in new
plant effluents as an average of 0.2 mg/& [25]; California has set an even
more stringent limit of 0.1 mg/£ in undiluted effluent [26]. The EPA has
also suggested that continuous exposure of the aquatic community to chlorine
compounds, including chloramines, should not exceed 0.002 mg/£ [27].
Chlorination programs to achieve zero discharge of total residual chlorine
from recirculating cooling water systems have been determined to be not
fully demonstrated and therefore cannot be generally applied soon [5].
A substantial amount of research has been conducted on the formation
of chlorinated organics in fresh water. Jolley et al,[106] isolated over
50 chlorinated organics from concentrates of Watts Bar lake water and
Mississippi river water which were chlorinated. Saline water behaves in
an analogous manner but product formation is more complex.
3-37
-------
Table 3.8
Breakdown on Chlorine Usage for Different Types of Cooling Systems, 1970
System
Once-through Cooling
(fresh)
Once-through Cooling
(saline)
Capacity
MW
132,000 54.0
57,800 23.7
1
u>
00
Cooling Ponds
Cooling Towers
Combinations
14,800
28,000
11,500
6.1
11.5
4.7
8,980
8,890
489
C12
Metric Short
Tons Tons
9,880 42.8
9,780 42.3
538
2.3
1,540 1,690 7.3
1,110 1,220 5.3
C12/MW
Metric Short
Tons Tons
0.068
0.055
0.075
0.154 0.169
0.033 0.036
0.060
0.095 0.105
Source: [2]
-------
The frequency, level, and duration of chlorine injection which will
insure adequate cleaning but not result in excessive chlorine addition
needs to be determined for each cooling water system. The point of in-
jection should be selected so that a minimum residence time for effective
cleaning performance is achieved. As discussed later in the subsection,
there is a choice of various control variables which may be used for in-
strumental feedback. These variables include total residual chlorine,
turbine discharge vacuum, discharge water temperature, temperature
differential across the inlet and outlet of the condenser. Minimizing
the quantity of chlorine used is a feasible and desirable practice for
all chlorine using power plants for these reasons:
• Minimizing cost of chlorine used and subsequent chlorine
removal treatment,, and
• Minimizing potentially adverse environmental impacts from
discharges.
Various states and some EPA regional offices have required chlorine
minimization of some type.
In order to decrease the potentially harmful environmental impacts
(in the receiving waters) of current chlorination practices, the EPA has
sponsored several studies on alternatives to chlorination [24,28], Mon-
santo [24], in an EPA-sponsored study, explored several potential alter-
natives to chlorination. Table 3.9 outlines a summary of their conclu-
sions. The problem with many of the alternative methods discussed in
their report (as was pointed out by them) is the lack of a field test
that readily establishes the efficiency of the processes.
It is clear from the Monsanto study [24] that . . . several improved
methods for control of cooling water biofouling which use chlorine are
available; such methods are more efficient and cause fewer problems than
traditionally continuous chlorination. These are:
• Dosing near the inlet of condenser ,
• Addition of dechlorination chemicals,
• Slowdown timing control., and
• Chlorination by feedback control of chlorine residuals.
3-39
-------
Table 3.9
Summary of Alternative to Chlorination of Power Plant Cooling Water
u>
I
TrsetBacnt alternative
Cbeatlcal treatsjent
Chlorine (Cl )
IroeJa* chloride (IrCl)
Iodine (I )
Ozone (0 )
Chlorine dioxide (CIO )
Cont rolled-re lease pesticides
On-lln* Batch.u.lce.1 cleaning
Irush device
Hot **ter backfluath
Ultraviolet radiation
Improved Methods of chealcal application
Doaing «t inlet of condensers, serially
Dcchlorlnat ion
Blowdovn lining control
Once- tt.rouftli
Fresh ferine
E E
P P
P P
E E
P P
P P
H P
M N
E E
E E
t E
Closed cycle
Freeh Marine tnvlronesmtal effects
E B Cl, residuals
P P MOM
N II Hone
P P None
E E Bloc 14* reel duals
P P Hone
N P Periodic thermal discharge
N N Radiation exposure
l
E E Mlnisu.1
E E Klnlsuil
N - Hot jppllcabl*
E - Excellent
P - Partially
applicable
Costs
Relative costs c/»
Engineering ptoblcM Capital Opersiloo ChesUcal (c/1.000 gale)
Ho«* Bate Use .Use 0. OB
(0.3)
Corrosive L L H
Ho*e L L H
Corrosive H M 8 0.0»[0. 3(«lectron>] to
O.IO.O(coror.a)l
Explosive, voLstlle. L L H
photodecossjios 1 1 Ion
(0.3)
KHM L L L
SOB* fouling H H L J
Plugging, grooving H M L S
None M H L V
Hay need pretreatoent H H 11
Need radiation shield H H L I
None L L L
H - High (>10 tises over Clj)
H - Hedian
L - Low (coeparable to Cl.)
(c/lb)
15.* to 17. a
<7 lo l>
(23)
2M
(120)
11. » to 27. 5
(7 to 12. S)
(100)
(15)
11.2
(6)
18,326
(8,330)
Co— nt.
Still newted la Che future
Brcl la v*ttar than ftr
Poor algiclda; uaad in awlaMlne, poola
Lab acala: uaad la waate and drinking watera
02d^d
ttot tter t 2
Hore (LAD needed, high initial cheaical
sppllcatioo coiti low MlfUetunce coat
are not capable of being converted to
•echsnlcal cleaning. E 1 ladoa t loo of Cl.
discharge
Only pilot scale in water and wastetrater
no logy is available. Cl2 discharge can b*
controlled to 0.2 »&/l. Cose 8 arc negli-
gible.
Source: [24J
-------
Use of one or a combination of the above control techniques would
make chlorination systems more complicated and may require some modifica-
tions while having an important compensation: The total amount of
chlorine used and discharged chlorine residuals would be reduced to the
practical minimum without impeding the control of biofouling of conden-
ser tubes and other parts of cooling water circuits. The size of the
chlorination system in terms of chlorine feed rate could be reduced by
upto severalfold depending on the number of parallel condensers serving
the power plant.
In addition, there are several potentially viable alternative methods of
reducing the total residual chlorine in condenser cooling water systems. These
include chemical treatment with other less harmful chemicals and use of
on-line mechanical means of cleaning condenser tubes. Mechanical
cleaning is employed in some plants, as a supplement to chlorination,
but its practicability depends on the design configuration of the
existing process piping and structures involved at the particular plant.
Not all existing power plants can be retrofitted with mechanical clean-
ing techniques. Mechanical cleaning of condenser tubes, which is used
in Europe, deserves to be explored more actively in the United States,
especially for those power plants using cooling water with high chlorine
demands. Use of mechanical cleaning usually reduces but does not fully
eliminate use of chlorine. Chlorine may still be required because
biological control may also be needed for other parts of the cooling
system or for control of hard-shelled organisms in marine water circuits.
Other approaches to biofouling control include:
• Chemicals other than chlorine,
• Dechlorination chemicals, and
• Physical chemical dechlorination.
Biofouling could be accomplished by chemicals other than chlorine.
Bromine chloride (BrCl), Ozone (0_) and chlorine dioxide have been
studied [24,28]. The chemical cost of bromine chloride is about three
times that of chlorine, and the cost of ozonation is reported to be two
3-41
-------
to ten times higher than of chlorination. Chlorination is currently
much cheaper than ozonation in both capital and operating costs. How-
ever, it should be emphasized that the costs of cooling water treatment
are a very small part of total power production costs. A more important
factor is the potential impact of bromine components
on the environment. These alternatives should be surveyed for potential
production of carcinogins in the environment.
Martin Marietta [28] evaluated bromine chloride in low-level doses
at a 575-MWe plant and concluded that it is about twice as effective at
equal dosage as chlorine but 2-1/2 times as costly. Thus, it appears
that potential ecological and cost advantages may be gained by using
bromine chloride for chlorine. Products of chlorobromination of water
containing ammonia or organic nitrogen are more easily degraded and less
obnoxious than their chlorinated analogs; e.g., chloramines. The
predominant products formed from several competitive reactions of BrCl
in water are chloride and bromide salts. In addition to the fast decay
feature, BrCl is less hazardous to marine life than chlorine while still
exhibiting biocidal activity [29].
Dow Chemical, a manufacturer of BrCl, has currently undertaken
field trials for its use in wastewater disinfection. The results in-
dicate that BrCl is an alternative to chlorine [29, 30]. It is reported th
BrCl costs about 0.8
-------
Ozone is more expensive than chlorine; furthermore, poor ozone
transfer efficiency, lack of residual protection against downstream
contamination for the cooling tower, and lack of field demonstration
are among the reasons why ozonation has not been practiced in power plant
cooling water systems in the past. However, recent improvements in
economics of ozone generation and stringent chlorine levels permissible
by regulations may make this an area where further exploration may be
worthwhile. At present, a study is being undertaken for EPRI by Public
Service Electric & Gas (New Jersey) and Emery/Foster Wheeler to determine
experimentally the dosage required and the economic feasibility of using
ozone for biofouling control in model condensers (i.e., three tube) [8,9].
Some initial results from these studies may be in 1979.
Dechlorination, which is another approach, may be accomplished by
sulfur dioxide, sodium bisulfite, or other analogous reductant. A
dechlorination system has been tried at a nuclear plant using sodium
bisulfite [5]. It should be noted that while dechlorination chemicals
can remove free and combined chlorine, they are ineffective on chlorinated
organics except for chloramines; this often is not a problem in cooling
tower blowdown. Dechlorination chemicals are not in widespread use in
power plants; however, these have been used commonly in municipal sewage
treatment plants.
Dechlorination by SO™ involves the following reactions:
H S03 + HOC1 -»• H2S04 + HC1
NH2C1 + H2S03 + H20 ->- NH4 S04 + HC1
The reaction between residual chlorine and sulfur dioxide is very rapid;
complete mixing of the sulfur dioxide prior to discharge in the receiving
water is necessary and can be accomplished easily. Since the reaction is
virtually instantaneous, the residence time requirement is minimal. Adequate
mixing between the dechlorinating chemical and the cooling water stream can
be achieved if the Reynolds number of the cooling water is over 2000 [102].
3-43
-------
The reaction between residual chlorine and sulfur dioxide is virtually
instantaneous, so that the only necessity is for complete mixing of the
sulfur dioxide prior to discharge in the receiving water. Adequate mixing
between the dechlorinating chemical and the cooling water stream can be
achieved if the Reynolds number of the cooling water is over 2000 [109],
EPA reports [ 101] that several power plants are now operating dechlorina-
tion systems. The data on three plants are reported in Table 3.10. A
system design to dechlorinate using S02 is described by Pacific Gas &
Electric [108].
The current applicability of various biofouling methods is shown
In Table 3.11. It appears that the alternatives to the use of chlorine
in cooling water treatment in power plants are presently limited, es-
pecially where units that are already in operation must be included.
Further research in this field may be a logical area for potential EPA
initiatives.
3.3.6.3 Chromium and Zinc in Slowdown
As stated earlier, corrosion control is one of the major require-
ments in cooling water systems. Corrosion control is usually accomplished
by employing corrosion inhibitor chemicals. Such inhibitor chemicals can
be classified as anodic or cathodic or botl depending on the corrosion
control mechanism. Inhibition results from one or more of three mechan-
isms [32].
3.3.6.4 Chromium and Zinc in Slowdown,
Several options are available in terms of meeting chromium standards
in the effluent and still maintaining good corrosion protection in the
condenser tubes. Among these are the following:
a. Recycle of all cooling tower blowdown,
b- Recovery or removal of chromium (and zinc) from the effluent, and
c. Non-chromate corrosion control.
3-44
-------
Table 3.10
Comparison of Chlorination/Dechlorination Data
Between Plants
Dechlorination
chemical
Amount fed per
chlorination
(concentration)
Chlorination
chemical
Amount fed per
chlorination
(concentration
available
chlorine)
Total flow rate
of discharge
Delay time
(condenser outlet
to headwall)
Dechlorination
feed
Plant 2603
Catalyzed Sodium
Sulfite (11/77)
Sodium Thiosulfate
(4/6/78)
winter
50 Ib (.9 ppm)
summer
50 Ib (.9 ppm)
Chlorine Gas
winter
8 Ib (.22 ppm)
summer
40 Ib (1.06 ppm)
150,000 gpm
(2 circ pumps)
Plant 2608
Catalyzed Sodium
Sulfite (11/77)
winter
50 Ib (.07 ppm)
summer
150 Ib (.2 ppm)
Plant 2607
Sodium Thiosulfate
(11/77)
winter
18 Ib (.14 ppm)
summer
36 Ib (.3 ppm)
Sodium Hypochlorite Sodium Hypochlorite
winter
30 Ib (.04 ppm)
summer
90 Ib (.11 ppm)
405,000 gpm
(5 circ pumps)
calculated - 5 min calculated - 1-2
actual - 4.5 min min
Gravity feed to Gravity feed to
condenser outlet condenser outlet
then injected then injected in
across duct through side of duct
a distribution
header
winter
12 Ib (.11 ppm)
summer
24 Ib (.22 ppm)
214,000 gpm
(3 circ pumps)
calculated - 6 min
Gravity feed to
condenser outlet
then injected in
side of duct
Source: [104]
3-45
-------
Table 3.11
Current Applicability of Various Bio-fouling Control Techniques
Treatment Alternative Old Plant New Plant
a
Not applicable to all plants due to design limitations of existing plants.
Chlorine would probably be required.
Requires further field testing and demonstration.
Source: [24]
Chlorination
a
Dosing near the inlet of condenser, serially Yes or no Yes
Addition of dechlorination chemicals Yes Yes
Slowdown timing control (closed cycle) Yes Yes
Chlorination by feedback control of chlorine residuals Yes Yes
Mechanical Cleaning Yes or no Yes
Other Alternative Chemicals0 -C -C
-------
a. Recycle of Cooling Tower Slowdown
Several methods of recycle with zero discharge have been considered
with the objective of eliminating blowdown while maintaining good scale
and corrosion protection in the system. Two typical methods are described
below:
Lime Softening - One such method is to install a lime and soda
ash softened for the cooling tower makeup water. In addition,
chromate bearing blowdown is recycled through the lime softening
[33, 34]. Figure 3.4 outlines the system. With certain types of
makeup water and operating conditions, a lime and soda ash soft-
ener can reduce the dissolved and suspended solids sufficiently
to provide a stable cooling tower water. In lime softening,
blowdown losses occur in the sludge removed for disposal and in
windage losses. Water supplies with high chlorides or high
silica may create problems, since limited removal would be
expected in the lime and soda ash softener. Silica removal is
usually accomplished by magneseum compounds.
Ion Exchange - Ion exchange could be employed to treat cooling
tower blowdown for recycle. Two important points to note
about ion exchange are:
• cost
• need to treat or dispose of ion exchange wastes.
Zeolite Softening - Another method of achieving zero discharge
that has been successful is to zeolite soften the cooling tower
makeup water and run the cooling water concentrations up to 10
to 20 cycles as controlled by windage loss [35].: In other words,
in this method, windage is the "blowdown" from the system. Figure
3.5 outlines the system. A potential hazard is the environmental
impact of drift; windage losses can drift and deposit chromium and
zinc into the environment. It may also be necessary to install
a sidestream sediment filter to filter between 2% and 5% of the
total circulation rate of the cooling tower water in order to
prevent a build-up of suspended solids. Water supplies with high
silica generally prevent utilization of this approach.
3-47
-------
1J_
HEAT
COOLING
WATER-
I
F
U
A
|
FEED
SODA- KfeH
Figure 3.A Lime-soda Ash Softening for Zero Discharge
WmPA.&e
yw
HEAT
Ik
T
ZEO \-\TE.
Figure 3.5 Zeolite Softening for Zero Discharge
3-48
-------
All of the above methods of treating cooling tower blowdown generate
sludges or waste streams that need to be disposed of. Such waste streams
often contain significant concentrations of undesirable components
including trace metals. Disposal of these in an environmentally sound
manner needs to be included in any plan of cooling tower blowdown
treatment.
b. Chromate Removal
A second approach is to remove all chromates (and zinc) from the
blowdown prior to discharge. Important methods of chromate removal are:
Chemical Reduction - In this method, chromate is reduced to tri-
valent chromium and precipitated as chromium hydroxide; the
latter is separated from the blowdown stream. Reduction of chro-
mate is readily accomplished at a pH range of 2 to 3; most common
reducing agents are SO-, ferrous sulfate, sodium bisulfite or
sodium metabisulfite [36]. A typical system is illustrated in
Figure 3.6.
Ion Exchange - In this method a weakly basic anion exchange resin
is employed to remove chromium [33,36]. A typical system is
shown in Figure 3.7. Regeneration of the resin is usually done
by sodium hydroxide. Published reports indicate that consider-
able experimental work has been done in this methodology [37],
Electrochemical Reduction - Chromate can also be removed by
electrochemical methods using sacrificial iron anodes and cathodes.
In such systems, direct electrical current on iron anodes and
cathodes produces ferrous hydroxide; the latter reduces hexava-
lant chromium to trivalent. Figure 3.8 illustrates the system.
This method is in commercial use today [36].
c. Non-Chromate Treatment Alternatives
Non-chromate alternatives to control corrosion can involve either
of the following two approaches or a combination of the two:
o Use of better materials for construction with less property
to corrosion [118]. For example, 316SS, other stainless
3-49
-------
COOLIMG
HEKT
COWTKOU
-O
FEED
J 1
T\6P-
'i L
r
^
TO
TO
Figure 3.6 Chromate Removal by Reduction
3-50
-------
TOWGR.
FEED
T T 9
F\LTtRS
» * L
E-XCHM^Gt
CO\-UV/,U X
LOAPIHS
PEE.O
pH
CYCV-g
S.FFUUE.HT
TC?
D \SPOSAM_
Figure 3.7 Chromate Removal bv ion Exchange
-------
Figure 3.8 Electrochemical Reduction of Chromium
3-52
-------
steels, and titanium are much less susceptible to corrosion.
Capital costs will remain an important factor discouraging
utilization of such materials. However, for new plants in
the future, a case-by-case study on optimum materials is
to be recommended. Furthermore, life cycle costs including
costs of environmental controls should be evaluated in
deciding on the optimum materials of construction.
• A number of alternatives to chromate treatment are in use.
Table 3.12 presents data on some alternatives of associated
corrosion rates. It is noted that chromium-zinc treatment
is still the most effective. However, due to the capital
outlay, operating costs and complexity of chromate removal
or zero discharge operation of cooling tower systems, many
plants are considering non-chromate programs.
3.3.6.4 Other Factors Contributing to Pollutants in Effluents
Chemical treatment as commonly practiced in cooling towers and its
impact on waste streams has been discussed in the preceeding paragraphs.
In addition, other factors contribute suspended and dissolved solids in
the cooling tower blowdown [7,24]. The most important of these are as
follows:
• The intimate contact which occurs between air and water in the
cooling system enables particulate matter and soluble gases to
be scrubbed from the air contacted. In addition, cooling towers
can introduce contaminants into the air. Airborne solids captured
by the cooling water can contribute significantly to the solids
that accumulate in the cooling system. It is estimated that, in
dusty regions, up to 80% of the suspended solids in recirculating
systems originally come into the system as airborne particulates [23]
• Erosion of asbestos from asbestos concrete fill type towers has
been mentioned earlier [5, 115],
3-53
-------
Table 3.12
Typical Corrosion Rates Under Reclrculating System Conditions
Treatment Program
Open System Inhibitors
Chromate-zinc
Zinc-lignin
Z inc-phosphona te
Polyphosphate-phosphonate-polymer
Polyphosphate-zinc
Aromatic azole-phosphonate-lignin
Closed System Inhibitors
Surface chelant
Nitrite-borate-organic
Sodium chromate
Untreated Control
*Dosage (ppm)
50
150
75
100
50
150
1000
2000
500
pH Range
6.5-7.0
7.0-7.5
7.0-7.
7.0-7,
7.0-7
.5
.5
.5
8.0-8.5
7.0-7.5
8.5-10.0
7.0-7.5
Corrosion Rate
(mpy)
0.7-1.9
1.6-2.7
1.8-2.6
1.7-2.4
2.2-3.4
2.6-3.6
0.1-1.3
0.6-1.1
0.2-0.7
50-100
*Dosage data is based on proprietary
formulated products.
Source: [32]
-------
• Leaching of preservatives from treated wood cooling towers con-
stitutes an additional source of potentially hazardous components
in cooling water blowdown. Preservatives commonly used include
acid copper chromate (ACC), chromated copper arsenate (CCA),
creosote and pentachlorophenol. The extent of this leaching is
not currently known [13].
• Additional potential contaminants which may be present include
insecticides and herbicides from agricultural runoff, or phenolic
compounds from vegetation decay, which may be toxic. Chlorine
addition to control biological fouling can result in chlorination
of these or other hydrocarbons entering with the makeup and may
result in highly undesirable reaction products. These could
contain potential priority pollutants
3.3.6.5 Economics
Capital and operating costs associated with various treatment options
for cooling tower blowdown and for any other waste stream described in
subsequent subsections in this paper are difficult to estimate for several
reasons.
a. Costs are site- and system-specific.
b. In many instances, treatment systems handle combined streams.
c . Good housekeeping practices and proper operation can have
major positive impact on volumes to be treated.
d. Recycle/reuse possibilities within a power plant further
complicate the economics of treatment.
Cost information presented in this R&D report needs to be considered
with the above understanding of the limitations of such data.
While technical data on treatment systems for cooling tower blowdown
are extensively available, cost information is somewhat limited. The
most extensive data appear to be those in the Guidelines Development
Documents [5,12]. These and other cost data (wherever indicated) have
been updated to mid-1978 levels by using Chemical Engineering Plant Cost
Index for both operating and capital costs. This procedure for operating
3-55
-------
costs Is only approximate; however, in view of the limitations on any
cost data, and the fact that such data are presented only for an overall
perspective on impacts, this may be satisfactory for such an assessment.
Cost data available in the literature on cooling tower-related
streams are as follows:
a. Chlorination - Capital cost of direct chlorination
equipment is low ($5,000-$8,000) for a typical system
(100-600mw power plant [22]). The annualized costs
are principally those associated with the consumed
chlorine.
b. Capital and operating costs estimates for on-line tube cleaning
equipment are shown in Table 3.13.
c. Capital and operating costs for chromate reduction systems are
presented in Table 3.14. Impact of capacity factor on annualized
cost is shown in Table 3.15,
The reader is also referred to Section 5.3 for a discussion on
economics of central treatment.
3.3.6.6 Recycle/Reuse in Cooling Towers
Wastewater management and combined treatment considerations are
discussed in Sections 3.3.3 and 3.3.4. However, some points specific to
cooling towers should be noted here. The degree of recirculation is
measured by the cycles of concentration. Increasing the cycles of concen-
tration in a cooling tower will reduce the makeup and the blowdown rates
but will increase the potential for scale formation. Treatment methods
discussed earlier can reduce the scale potential of cooling towers which
operate at high cycles of concentration.
In a recent study for the EPA, Radian [7] evaluated cooling systems
at five power plants to explore reuse possibilities; four of these plants
employed wet cooling towers. Table 3.16 outlines the design parameters
for the cooling towers studied. Using computer simulation, Radian
concludes that improvements over existing operations could be made
3-56
-------
Table 3,13
Capital and Operating Costs For On Line Tube Cleaning Equipment
Basis: Mid-1978 Cost Levels (CE Cost Index 218,8)
System
01
Recirculating
Sponge Balls
Plastic Brushes
Capital Costs
$/10° Btu/hr
Rejected
$/kw
190-460 0.77-1,86
60-200 0.24-0,80
Operating and Maintenance
$/10° Btu/hr Rejected
4,56-8,24
4,91^9.79
Source: [5] and Arthur D. Little, Inc., update of cost data.
-------
Table 3.14
Capital Costs for Chromate Reduction Systems
Basis: Mid-1978 Cost Levels (CE Cost Index 218.8)
Cycles of
Slowdown Rate Concentration Capital Co»t-
gpm
0.34 5,400 3 $1,248,000
0.14 2,400 5 860,000
0.05 720 10 582,000
Assumptions: 1,000 MW fossil-fuel
Heat rate 10,400 Btu/kWh (Efficiency = 33%)
600,000 gpm at 20°F AT
Evap. - 2%
Source: [5] and Arthur D. Little, Inc., update of cost data.
3-58
-------
Table 3.15
%
Unit Costs of Chromate Reduction Systems
Basis: Mid-1978 Cost Levels (CE Cost Index 218.8)
1000 MW fossil-fuel plant, 5 cycles, 10 mg/S- Chromate
Annual Costs; Capital Charges @ 15% x Total
Maintenance @ 3% x constr. cost
Labor $20,000/man/year
Materials and Supplies
Unit Costs. mills/kWh
Capacity Factor 1.00 0,67 0,35
Annualized Cost
mills/kWh 0.092 0.104 0.133
Source: [5] and Arthur D. Little, Inc., update of cost data.
3-59
-------
Table 3.16
Radian Study for the EPA - Cooling Tower System Design Parameters
Georgia Power Co. * Colorado Public Service Montana Power CD.
Plant town CneanrtM Colatrfp
Note: The flffh n1*nt- mt-n/t1*A kw VmAImn fnr t-K^ KPi <«a t-K« Vn.rr Cj*m*rm Plan* nnmrmtfA kv Lrtrnnm PiiKHi*
>>1a unit n>a rnnHno pnnrta.
iJH"
Number of Towera
Electric Generating
Capacity per Toner. MW
Circulating Hater Rate
per Tower, t/eec (8P»)
Temperature Change
*-** Arroai Condeneer, *C (*F)
O
Air Flow Rate per Tower.
Tower, tfr/hr (ACFM)
Cooling Tower Drift
Rate, l/eec (gpm)
Cooling Hater Approach,
•C (*F)
Evaporation Rate per
Tower, t/sec (gpm)
Hyperbolic natural draft ladoced draft Induced draft Hyperbolic natural draft
4 22 2
700 350 350 750
890
16.000 (260.000) 9.100 (145.000) 6.5OO (100.000) 15.800 (250.000)
19.000 (310.000)
14 (26) 14 (26) 18 (32) 16 (28)
16 (28)
2.5 x 107 (1.45 x 107) 2.7 x 1O7 (1.6 x 107) 1.7 x XO7 (X.Q x IO7) 3-5 * 10r (Z.06 x 107J
3.5 x 107 (2.07 x 107)
3.3 (52) 9.0 (142) 1.3 (20) 1U5 (500)
3.4 (62)
11 (19) 8 (15) 12 (22) 10 (19)
10 (18)
340 (5.500) 190 (3.000) 160 (2.600) 390 (6,200)
400 (6.500)
'Plant Boven baa cooling
Source: [71
coven of two dlffemt •**•*. Tba lint Urn rafen to Halt* 1 a 2 avd the
rafara to Doit* 3*4.
-------
which would reduce water use and discharge. In cooling tower cases where
CaCO,. or CaSO, • 2E^O are the limiting scale-forming species, recircula-
tion of the cooling water may be increased so that the entire blowdown
can be used as makeup to another major water consumer(s) in the plant.
Sulfuric acid addition and/or lime softening may be required to achieve
this degree of recirculation depending on the plant makeup water
quality. Kinetic studies are recommended by Radian for Silica-based
scale-forming species so that the maximum safe degree of recirculation
in tower systems where these solids are limiting may be more adequately
defined.
3-61
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3.4 Steam Generation Wastes
3.4.1 System Operation
The major waste stream from the boiler system is the boiler blowdown
Boiler blowdovm is the purge from the boiler system of a small portion of
boiler water to maintain the required boiler water quality. The blowdown
rate is generally in the range of 0.1-3% of the steam flow [5,22], and
it is either continuous or intermittent on a daily basis [5], In a
power plant, the boilers are either of a once-through or drum type. The
former design is generally used in high-pressure super critical boilers
and does not have a wastewater stream directly associated with the boiler
operation. However, in a drum-type boiler, the impurities in the feed-
water get concentrated as steam is generated (steam and water being at
equilibrium) and blowdown is determined by the allowable cycles of con-
centration [32]. Mathematically,
j rv.ivij - concentration of X in f eedwater
concentration of X in blowdown - ; ^ ^ at-ejr
<_uiii-^w cycles of concentration
The cycles of concentration are controlled by total suspended solids
(TSS), total dissolved solids (TDS), total alkalinity, or silica. The
recommended limits of total and suspended solids for boilers are shown
in Table 3.17. The boiler blowdown contains these species as well as
scale constituents formed in boiler water, boiler tube corrosion products
and internal chemicals added to boiler water. Data for typical chemicals
added for internal treatment and their residual concentration in boiler
water (and hence, boiler blowdown) are shown in Table 3.18. The use of
these chemicals is discussed briefly below. More detailed information
is available in references (10).
Scale Control
Scale control requires that calcium, magnesium and silica be con-
trolled. Calcium ions can be precipitated by phosphate and hydroxyl
ions. Magnesium ions and in some cases silicates are removed by hydroxvl
ions in a pre-treatment step. The reactions involved are as follows (40) -
10(Ca**) + 6(P04") + 2 (OH") -»• 3Ca3(P04)2 • Ca(OH2)
calcium hydroxyapatite
3-62
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Table 3.17
Recommended Limits of Total Solids and Suspended
Solids in Boiler Water for Drum Boilers
Limits Recommended for Boiler Feedwater
Drum Pressure
Total solids, mg/£
Total hardness as
mg/fc CaC03
Iron, mg/£
Copper, mg/A
Oxygen, mg/£
PH
Organic
Below
40 atm
*
0
0.1
0.05
0.007
8.0-9.5
0
40 to
68 atm
*
0
0.05
0.03
0.007
8.0-9.5
0
60 to
136 atm
0.15
0
0.01
0.005
0,007
8.5-9.5
0
Over
136 atm
0.05
0
0T01
0.002
0,007
8.5-9,5
0
No value reported
Limits Recommended for Total
(Dissolved and Suspended) Solids
Drum
(atm)
0 -
20.41 -
30.51 -
' 40.81 -
51.01 -
61.11 -
68.01 -
102.01 -
>136
20.4
30.4
40.8
51.0
61.1
68.0
102.0
136
Pressure
(psi)
0
301
451
601
751
901
1001
1501
- 300
- 450
- 600
- 750
- 900
- 1000
- 1500
- 2000
>2000
Total Solids (mg/£)
3500
3000
2500
2000
1500
1250
1000 :
750
15
Source: [10]
3-63
-------
Source: [13]
Table 3,18
Chemical Additives Commonly Associated
with Internal Boiler Treatment
Control
Objective
Scale
Corrosion
PH
Solids
Deposition
Candidate Chemical Additives
di- and tri-sodium phosphates
Ethylene diaminetetracetic
acid (EDTA)
Nitrilotriacetic acid (NTA)
Alginates
Polyacrylates
Polymethacrylates
Sodium sulfite and catalyzed
sodium sulfite
Hydrazine
Morpholine
Sodium hydroxide
Sodium carbonate
Ammonia
Morpholine
Hydrazine
Starch
Alginates
Polyacrylamides
Polyacrylates
Polymethacrylates
Tannins
Lignin derivatives
Residual Concentration
in Boiler ftater
3-60 mg/£ as PO^
20-100 mg/fc
10-60 rng/l
up to 50-100 mg/A
up to 50-lQQ nig/*
up to 50-100
less than 200
5-45 mg/fc
5-45
Added to adjust
boiler water pH
to the desired
level, typically
8,0-11,0
20-50
20-50
20-50 mg/X,
20-50 mg/il
20-50 mg/fc
^200 mg/A
-200
3-64
-------
3 Mg + 6 OH + 2 Si02 + 2 MgSi03 . Mg(OH>2 . 2H20
serpentine
Calcium hydroxyapatite and serpentine do not adhere to boiler tubes and,
hence, are preferred. Organics such as lignin and tannin form a coating
on the sludge, giving a negative charge to the particles and, hence,
keeping them in suspension.
I I
Chelating agents such as EDTA and NTA are used to solubilize Ca and
I I
Mg ions. Polymers (such as polyacrylates, polynethacrylates) select
organics (such as tannin, lignins) and antiscalents (threshold sequester-
ants) are adsorbed on the precipitates; this prevents agglomeration and
departition of larger solid partitions.
Corrosion Control
Dissolved oxygen in the boiler water (introduced via feedwater and
condensate system leakage) causes corrosion. In addition to mechanical
deaeration, sodium sulfite and hydrazine are used as oxygen scavengers.
The reactions are [40]:
2 Na2S03 + 02 -* 2 Na^O^
N2H4 + °2 ~" N2 + 2 H2°
Sulfites can precipitate as solids on turbine blades; hence hydrazine is
preferred for high pressure applications. If the reaction time is insuf-
ficient, catalyzed hydrazine is used.
iH Control
Leaks of organic or mineral acids in boiler water results in severe
corrosion and hence, the pH is typically maintained between 8-11 by adding
NaOH, Na^COo, NHo, volatile amines (morpholine and cyclohexylamine) , or
hydrazine. Excessive pH can cause caustic embrittlement by destroying
the protective magnetic iron hydroxide film (Fe~0,) as follows [39]:
4 NaOH + Fe304 -> Na2Fe02 + 2 NaFe02 + 2
2 NaOH + Fe •> Na2?e02 + H2
Filming amines such as octadeylamine can be added to prevent the corrosive
condensate from attacking the metal surfaces.
3-65
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Solids Deposition
Polymers, select organics, and threshold sequesterants prevent the
precipitated matter formed in boiler water from adhering to boiler tubes.
Long chain molecules in these additives attach themselves to an active
site in the growing crystalline state and thus distort the crystalline
scale, with the result that the precipitate is maintained as colloidal
matter. The effectiveness of polymers in scale reduction is presented
in Table 3.19 [32].
Afterboiler corrosion is a common problem and leads to increased
maintenance costs for boiler and condensate systems. The usual causes
are low pH caused by C02 and oxygen attack. CC^-related corrosion occurs
in the condensate system and is caused by CO^ formation as below.
2 HC03~ + Heat •* C03~~ + C(y + H20
C0~~ + H20 + Heat - 2 OH~ + CO^
3.4.2 Waste Characteristics
Boiler blowdown is an alkaline waste with pH from 9.5 to 10 for
boilers treated with hydrazine and pH from 10 to 11 for boilers treated
with phosphates. Blowdown from medium-pressure boilers has a TDS concen-
tration in the range of 100-500 mg/JU High pressure boiler blowdown has
a TDS concentration in the range of 10-100 mg/4. Blowdown from boiler
plants using phosphate treatment contains 5-50 mg/fc phosphate and 10-100
mg/2. hydroxide alkalinity. Boiler plants with hydrazine treatment produce
a blowdown containing 0-2 mg/£ ammonia [5].
Volume of boiler blowdown varies widely from 5 to 70 lit/MWH (1.3-
18.5 gal/MWH). Some data for boiler blowdown from four plants, as pre-
sented by the EPA, are shown in Tables 3.20 and 3.21. EPA reports [101]
that a total of 544 out of 794 plants surveyed recently have boiler blow-
down treatment at their facilities.
3.4.3 Boiler Blowdown Treatment Options
Boiler blowdown is often treated in conjunction with many other
streams [19]. The reader is referred to Section 5.2 for a technical
3-66
-------
Table 3.19
Effectiveness of Polymers on Scale Reduction
Polymer
Polyacrylic acid
Polyacrylic acid
Polymethacrylic acid
Polymethacrylic acid
Polymaleic anhydride
Polymaleic anhydride
Molecular
Weight
20,000
5,000
10,000
5,000
10,000
5,000
Typical
Cone.
(ppm)
3
3
3
3
3
2
Scale
Reduction
52
71
62
68
85
97
Source: [32]
3-67
-------
Table 3.20
Boiler Slowdown, Raw Waste Concentrations
(Historical Data)
Mean
Pollutant
Name
Copper
Iron
Oil & Grease
Phosphorus
Suspended
Source: [101]
Variable
Fuel : Coal
Flow
Flow/gen
Fuel : Gas
Flow
Flow/ gen
Fuel: Oil
Flow
Flow/gen
Source:
No- of Concentration
Points (mg/l)
258
273
151
19
230
Table 3.21
.14
.53
1.74
17.07
66.26
Boiler Slowdown Flowrates
(Flow in gpd, Flow/Gen in gpd/MW)
Number
of Plants
231
230
189
189
1A8
148
Mean Standard Minimum
Value Deviation Value
33,259 71,682 0.11
148 392
19,346 60,933 4
163 669 0.08
66,173 320,106 2.7
287 1,237 0.12
Maximum
Value
650,000
3,717
700,000
8,470
3,810,000
14,066
3-68
-------
discussion on such combined treatment and associated economics. Three
plants have reported that they follow equalization, neutralization, and
oil skinming or settling ponds prior to discharging the blowdown to
publicly owned treatment works (POTW) [12]. TVA reports [91] on dis-
charging blowdown from a low pressure drum type boiler to neutral and
alkaline ash ponds to precipitate iron and copper.
Potentially, several options could be considered for using boiler
blowdown:
• The blowdown causes flashing and the exhaust stream
could be used in feedwater heaters or in deaerators.
• If the flow is large enough, the heat in water flow
from the flash tank could be utilized in a heat
recovery heat exchanger.
• The quality of boiler blowdown (from the viewpoint of
total dissolved solids) is often better than the
quality of the raw water supply and, hence, the blow-
down could be used as makeup to the demineralizer
system. It can also be used in other plant operations
requiring water of such quality that boiler blowdown
may be accomplished (e.g., cooling tower makeup,
external washing of equipment, etc.).
There are no published data available regarding the extent of
recycle/reuse practices followed for boiler blowdown. The blowdown
quality and quantity are system-specific, and the blowdown stream can
be controlled by judicious operating procedures for external and internal
water treatment. However, it should be noted that among various waste
streams in a power plant, boiler blowdown is generally among those of the
highest quality. As such, ample possibilities usually exist to use such
blowdown and achieve total recycle of this particular waste stream.
3.5 Water Treatment Systems
3.5.1 System Operation
Raw water has to be treated prior to its use as makeup in the boiler
3-69
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feedwater loop. The makeup water requirement decreases with increasing
production rate [39]. The treatment operations can be divided into the
following categories [32]:
Group A Processes: First pretreatment step for removing
hardness, silica and suspended solids in
the preparation of higher quality water.
Group B Processes: Filtration—or special adaptation for the
removal of suspended matter.
Group C Processes: Ion exchange and other techniques for the
alteration of removal of dissolved solids
by methods not involving chemical precipi-
tation .
Figure 3.9 shows the possible combinations of external water treat-
ment processes [32]. Based on the raw water source, specific combinations
of these processes are selected for achieving the boiler water quality
parameters such as total solids, alkalinity, silica, etc. [40], The
importance of these parameters (except silica) in boiler operations is
described in relation to the internal boiler water treatment aspects of
the boiler blowdown wastevater stream (Section 3.4). The control of
silica and sodium compounds is necessary to prevent its volatilization
and/or carry down from the boiler and subsequent deposition on turbine
blades. Figure 3.10 shows allowable silica concentration in the boiler
water as a function of operating pressures. At values above those shown
silica is known to volatilize and deposit on turbine blades [39].
3.5.2 Waste Characteristics
The quality and quantity of the waste streams from water treatment
systems is dependent upon the specifics of the plant. The range of waste-
water stream flows resulting from the various processes used in raw water
treatment is shown in Table 3.22. The reported data for the quality of
these wastes exhibit a large variation [5,12] and a meaningful correlation
with feedwater or MW production is difficult. Waste sludges from
clarifiers usually have a solids content in the range of 3,000 to
3-70
-------
WATER SUP PUt1
pKOTECTIOKl
"*•
SROUP
A.
PROCESSES
REVERSE QSMOS19
OIST \LLXm ON
PURS. WMER,
LOW VN SOU OS
BOILtRS
U\-TRAPU(Z.e WATER <3MC£
THB.U SOlL-EIt ISOO
PUU*
NV&C.
PROCCS«
PUttTMER.
Source: [32]
P *M?VA A.C E UT1C Av\_
Figure 3.9 Typical Water Treatment Processes
3-71
-------
40
30
20
1
««
'A •
2?
S 6
1s
"4
1
V
\
\
\
\
*
\
\
\
\
\
900 1100 1300 1500 1700 1900 2100
•OILER PflESSUR€.*SlG
Source: [39]
Figure 3.10 Silica Concentration in Boiler Water
3-72
-------
Table 3.22
Typical Water Treatment Wastewater Flows
Process Range of Flows
gal/1000 Ib water treated
Clarifier blowdown 1-4
Lime-soda 1-4
Raw water filtration backwash 0-6
Feed water filter 0-6
Sodium zeolite regeneration 0.5-3
Cation exchange regeneration 0.5-3
Anion exchange regeneration 0.5-3
Evaporator blowdown 12 - 40
Condensate filtration and
ion exchange 0.02- 0.6
Condensate powdex 0.01- 0.06
Source: [5]
3-73
-------
15,000 mg/i. Suspended solids amount to approximately 75-80% of total
solids with the quantity of volatile solids being 20 to 25% of total
solids. The BOD level usually is 30-100 mg/£. A large corresponding
COD level of 500-10,000 mg/Jl shows that the sludge is not biodegradable
but that it is oxidizable. The sludge usually has a pH range of about
6 to 8.
Filter backwash is more dilute than the"wastes from clarifiers.
Generally, it is not a large volume waste. Turbidity of wash water is
usually less than 5 JTU and the COD is about 160 mg/j,. The total
solids existing in filter backwash from plants producing an alum sludge
is about AOO mg/& with only 40-100 mg/fc suspended solids.
Ion exchange wastes are either acidic or alkaline. While ion ex-
change wastes do not naturally have any significant amount of suspended
solids, certain chemicals such as calcium sulfate and calcium carbonate
have extremely low solubilities and are often precipitated because of
common ion effects. Calcium sulfate precipitation is common in wastes
from ion exchange systems using sulfuric acid as a regenerant. Its pre-
cipitation is prevented by using gradually increasing concentrations of
I _|_ _,_
acid so that the product of (Ca ) and (SO^ ) ion concentration is suf-
ficiently low.
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 feedwater. Due to the
low solubility of calcium carbonate and calcium sulfate, precipitation of
these components can occur if these are present in the feedwater. If
bicarbonates are used as a buffer in the feedwater, two reactions occur:
2 HC03~ + Heat •»• C0^~~ + CO.^ + H20
C03~~ + H20 + Heat •»• CO^ + 2 OH
Thus the buffering salt produces an alkaline waste stream from the
evaporator.
Generalized data are reported on the above waste streams in a recent
EPA technical report [101] and are summarized in Table 3.23.
3-74
-------
Ul
Table 2.23
Water Treatment Wastes in Coal-Fired Power Plants
Number
1
2
3
4
5
6
Stream
Clarifier Slowdown
Filter Backwash
Ion Exchange Regeneration
Lime Softener Slowdown
Reverse Osmosis Brine
Evaporator Slowdown
No. of
Plants
88
154
104
37
3
104
26
25
9
26
10
29
Flow
(gpd)
,966
,460
,290
,228
,674
,310
Flow/ gen
(gpd/MW)
64.8
71.0
79.0
56.0
31.0
126.0
(Mean
pH = 6
TDS =
oil &
Cu = 0
Other Data
of reported
.15, SS = 44
6057 mg/1
grease = 6.0
.39
, Fe = 0.
values)
mg/1,
mg/1
54,
Oil & Grease =2.1
SS = 28.4
Source: [101]
-------
3.5.3 Treatment Options and Economics
Water treatment system wastes are usually treated in a combined
system (see Section 5.2). Neutralization and clarification are widely
employed and produce a sludge. This sludge can be further dewatered
by thickening or filtration and the supernatant recycled back, thus
closing the water loop around the system. The backwash waste stream
from sand and gravel filters contain TSS and coagulant compounds used
as filter aids. The waste stream flow rates are small and can be sent
to ash ponds for disposal. Alternatively, TSS from these streams can
be removed by vacuum or pressure filtration.
Waste regenerants and rinses from both ion exchange units 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. The neutralized wastes are high in IDS and
would require further treatment before they could be used for other
uses.
In those plants still utilizing evaporators to produce boiler feed-
water 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 ex-
change wastes by adjusting the pH to the neutral range of 6.0 to 9.0
with sulfuric acid or sodium hydroxide. If precipitates are formed
during neutralization, these are removed by sedimentation and filtration
3.5.4 Trends in Water Treatment
Complex feedwatef treatment and condensate polishing systems are
required for high pressure supercritical boilers currently in use
in the utility industry. The trends in these systems and other
advanced treatment technologies are discussed below in brief because of
their potential impact on the resulting wastevater streams as well as
their potential use in treating power plant wastes containing TDS and
toxic pollutants.
3-76
-------
Ion exchange units contain cation resins, anion resins, or a mixture
of the resins (mixed-bed units). Cation resins operate in the sodium
cycle or hydrogen cycle (weak or strong acid). Anion resins operate in
the chloride cycle or hydroxide cycle (weak or strong base) [41].
Table 3.24 shows typical ion exchange material types and regenerant
requirements. Counter current regeneration of single resin units improves
the product water quality and reduces disposal problems. The reduction
in disposal problems results from higher regeneration efficiency and less
water concentration required for "air hold down" type operations [42],
Pilot studies have indicated that ozone application can be successful in
destroying high molecular weight resinic acids from the raw water, which
were fouling the anion resin bed [43].
Substantial reductions in the volume of demineralizer wastes can be
achieved by the use of systems which employ reverse osmosis (RO) or
electrodialysis in conjunction with ion exchange (IE) instead of using ion
exchange alone. One study shows that RO plus IE systems are less costly
than IE systems alone for TDS of 500 mg/£ as CaC03 in the natural water
available. The study, published in 1973 and based on 379 m3/day
(100,000 gpd) product capacity, reported a waste disposal cost of $5 per
3
1000 gal ($1.32/m ) excluded labor costs in 1973 [5], A recent pilot
scale study by the EPA for organic chemical manufacturing wastewaters
indicates that total annualized cost of wastewater renovation to boiler
feedwater quality employing RO and IE would be $7.50/3.8 m (1000 gal) in
1978 dollars [44]. Of this total cost, $1.95 and $1.15 are assocaited with
the RO and IE, respectively. This cost does not include costs for sludge
or brine disposal.
A similar experience with RO units in series with demineralizers
was reported at the Willow Glen Power Station of Gulf States Utilities
Company in Louisiana [45]. The RO unit addition .75 m (200 gpm) capacity
has improved feedwater quality, decreased the regeneration frequency and
has resulted in a saving of approximately $30,000 per year for acid and
caustic costs (presumably in 1977 dollars).
The Peoples Gas, Light and Coke Company in Chicago has achieved a
zero discharge at their McDowell Energy Center which produces synthetic
3-77
-------
Table 3.24
Ion-Exchange Material Types and Regenerant Requirement
Ion Exchange Material
Description of Operation
•sganermt Solution
Theoretical Aaoqnt
Cation Exchange
Sodium Cycle
Hydrogen Cycle
Weak Acid
Sodium cycle ion exchange is used a* a water
softening process. Calcium, magnesium, and
other divalent cations are exchanged for
•ore soluble sodium cations, i.e.,
2R - Ha •*• Ca
2Rc-«a
(Rc)2 - Ca
2 Ha'
* (*c)2-Mg + 2
Ma
Weak acid ion exchange removes cations fro*
water in quantities equivalent to the total
alkalinity present in the water, i.e..
10Z brine (Had) solution or sow
otter solution with • relatively
high sodium content such as sea
water
n^SO^ or HO. solutions with acid
strengths as low as O.SZ
11O-120Z
t
~j
oo
Hydrogen Cycle
Strong Acid
2Rc-H + Ca(HC03)2
Strong acid Ion exchange revovea catiooa of
all soluble salts in water, i.e. ,
83804 or HC1 solutions with add
strengths ranging from 2.0-6.OX
200-WOI
Anlon Exchange
Weak Base
Anlon Exchange
Strong Base
Weak base ion exchange renoves anions of all
strong nlneral acids (H.SO., HC1, HRO., etc.),
i.e..
2RA-OH
2HOH
Strong baae ion exchange removes anions of
all soluble salts in water, I.e.,
R - OH + H CO, I R. - HCO + HOB
A £, j A -j
RaOB, MH40B, Ha2C03 solutions of
variable strength
NaOH solutions at approximate 4.01
strength
12O-I4OT
L5O-300Z
Source: [13]
-------
natural gas (SNG). The SNG plant requires high purity steam for hydrogen
production. By proper design of the deionizer system, multi-stage evap-
oration and spray dryer, the plant has achieved zero liquid discharge [46].
Deep-bed condensate polishing systems employ a mixture of cation and
anion resins. The regeneration of these units must be properly achieved
to eliminate the possibility of sodium carryover and/or leakage into the
condensate system [47], Magnetic filters have been pilot tested to
remove iron impurities in the condensate prior to its demineralization.
The results indicate that with these filters, the frequency of regeneration
would be reduced; and correspondingly, the loss of condensate in backwash
and regeneration would be decreased [48].
A study was completed recently for the EPA as part of its efforts
to develop background information on effluent standards for priority
pollutants in power plants [13]. This study evaluated various control
technologies, which are also applicable in boiler feedwater treatment
and/or wastewater treatment. The summary results of this study are
shown in Table 5.10 in Section 5.
A previous study for the EPA evaluated 47 treatment processes appli-
cable to industrial wastes [49]. It is noted that the data in this
study (published in 1976) did not specifically evaluate the utility
industry. However, in the absence of other data, this information can
be used as a first starting point in evaluating the applicability of some
of the treatment processes discussed above in a power plant.
3.6 Ash Handling
3.6.1 Ash Characteristics
Coal-fired utility and industrial boilers generate two types of coal
ash—fly ash and bottom ash. The distribution of total ash into fly ash
and bottom ash is determined by the design of the boiler. Both types of
ashes together constitute the noncombustible (mineral) fraction of the
coal and the unburned residuals. Fly ash, which accounts for the majority
of the ash generated, is the fine ash fraction carried out of the boiler
in the flue gas. Bottom ash represents that material which drops to the
bottom of the boiler and is collected either as boiler slag or dry bottom
ash, depending upon the type of boiler.
3-79
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The total amount of coal ash produced is a function of the ash con-
tent of the coal fired and can range from a few percent of the weight of
the coal fired to as much as 35%. Coal/ash/FGD waste relationships are
discussed in Volume 3. Table 3.25 provides some data on the percentage
of total coal ash that is produced as fly ash for various types of boiler
The chemical composition of coal ash (bottom ash, fly ash, and
slag) varies widely, both in concentrations of major and minor constituent
In Volume 3 the chemical composition and physical properties of both
fly ash and bottom ash from a wide range of different coals are discussed
The principal factor affecting the variation in the composition is
the variability in the mineralogy of the coal. However, differences in
composition can exist between fly ash and bottom ash (or boiler slag)
generated from the same coal due to differences in the degree of pulver-
ization of the coal prior to firing, the type of boiler in which the
coal is fired, and the boiler operating parameters and combustion efficien
Regardless of the type of ash (either fly ash or bottom ash), more than
80% of the total weight of the ash is usually made up of silica, alumina
iron oxide, and lime.
While the major constituents of bottom ash and fly ash are generally
similar, there is usually an enrichment of trace elements in the fly ash
as compared with the bottom ash based upon the total quantity of trace
elements in the coal fired. A few of the elements originally present in
the coal (notably sulfur, mercury, and chlorine) are almost completely
volatilized and leave the boiler as gaseous species which are not
collected downstream in dry ash collection equipment. However, these can
be collected in wet scrubber systems, as discussed later.
Up to 10% of fly ash can be water-soluble, so the potential exists
for release of contaminants through leaching. The principal soluble
species are usually calcium, magnesium, potassium, sulfate, and chloride
Bench scale leaching tests using deionized water indicate that the
ash reactivity varies considerably with pH and the specific ash being
investigated [7]. Leachates resulting from ash are usually alkaline fro
the presence of calcium oxide and other alkaline species, although some
ashes have been found to be inherently neutral or even acidic.
3-80
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Table 3.25
Fly Ash/Bottom Ash Percentages
Basis: Average for a 13,000 Btu/lb coal
Fly Ash
Type of Operation (% of total ash)
Pulverized coal burners
Dry bottom, regardless of
type of burner 85
Wet bottom
(without fly ash rein-
fection) 65
Cyclone furnaces 20
Spreader stokers
(without fly ash rein-
jection) 65
Source: [5]
3-81
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Bottom ash can be collected either dry or in a molten state, in
which case it is generally referred to as boiler slag. Bottom ash is
usually heavier than fly ash, with a larger particle size distribution.
Its chemical composition is analogous to that of fly ash; however, it is
usually less reactive than fly ash. Boiler slag is a black, glassy sub-
stance composed chiefly of angular or rod-like particles, with a particle
size distribution ranging from fine gravel to sand. Boiler slag is porous
although not of so great a porosity as dry bottom ash.
3.6.2 Ash Collection-Handling Systems
As the size of boilers has grown, systems for handling ash have
grown to more complex units with increasing levels of combustion. Ash
handling can be broadly broken into:
• Ash collection (discussed in Volume 3) and handling systems,
and
• Conveying systems to storage or disposal.
Ash collection and handling systems often handle the following [50]:
• Bottom ash or slag, the material dropped out of the main
furnace in either the dry or wet (molten) state,
• Fly ash, the fine particles trapped by dust collectors,
usually electrostatic precipitators,
• Economizer and air heater ash, the coarser particles
dropped out of flue gases at changes in the direction
of a gas stream, and
• Mill rejects, or pyrites, which may consist of a variety
of coarse, heavy pieces of stone, slate and iron pyrite.
Table 3.26 lists the available methods of handling each class of
material and the choice which is probably often the optimum from an
economic standpoint for either utility or industrial boilers.
Ash handling systems include all components for handling the coal
ash from the particulate collector and boiler to a disposal area. Fly
3-82
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Table 3.26
Ash Handling Systems
Ho.
1.
2.
3.
4.
5.
Type of Ash
Dry Bottom
Ash
Slag (Wet Bot-
tom Ash)
Fly Ash
Economizer
Air Heater Ash
Mill Rejects
Practical
System
Hydraulic Pneumatic
X X
X
X
X X
X X
Usual
Economic Preference
Utility
H
H
P
P
H
Industrial
H or P
H
P
P
H or P
Source: [50]
3-83
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ash carried in the flue gas stream can be collected in a number of ways
to meet current particulate emission control limitations. Typical methods
include mechanical collection, electrostatic precipitation, fabric fil-
tration, and wet scrubbing. Mechanical collectors generally are not
capable of meeting present ern-LSsions control limitations and, when used,
are generally followed by either an electrostatic precipitator or high
efficiency wet scrubbing systems.
Bottom ash is typically removed from a boiler by periodic washing,
and subsequent transport of the ash. The limited conveying capacity of
pneumatic conveyors will usually eliminate considering them for handling
bottom ash from the larger utility boiler plants. Fly ash, on the other
hand, must be continuously removed from the flue gases to prevent the
discharge of large amounts of particulate matter into the atmosphere through
the stack. Once fly ash has been collected, it may be conveyed by
pneumatic or hydraulic means. While in the past fly ash was simultaneously
removed with S02 in the scrubber, the current trend in utilities is to
have a separate fly ash collection system (usually an electrostatic
precipitator) before FGD to ensure a more reliable service; this trend
will accelerate with the tightening particulate limits in emissions. A
small percentage C\>15%) of the total ash produced in the United States
today is sold for further utilization. But the major part (about 85%)
is disposed of in various land disposal sites. Fly ash may also be
employed to stabilize FGD wastes. (See Volume 3.)
In the United States, fly ash handling at utilities usually is done
by hydraulic methods; but pneumatic means are coming into use. For
utility or industrial boilers located in congested areas where space and
water supply are not available, dry pneumatic systems are preferred.
Mechanical conveyors, except for isolated segments lu some ash
handling systems, have not been applied in the United States; hydraulic
and pneumatic conveyors are universally employed.
3-84
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The ash handling system in a utility or large industrial operation
may fall into one of the following types:
a> Hydraulic Bottom Ash Handling. This may involve:
• Sluicing by means of ejectors or centrifugal pumps
to a disposal area,
• Conveying by water jet or pumping to dewatering bins
for removal by trucks or railroad cars, and
• Conveying by water jet or pumping to dewatering bins
as above with the addition of a complete water re-
covery system to permit recirculation and reuse of
conveying water.
Bottom ash is usually removed from the furnace by mechanical means
such as "drag-bar" conveyor, and water-quenched to approximately
ambient temperatures. With proper control, liquid drainage
from the quench operation can be eliminated or held to a.
minimum. Mcst of the quench water is either vaporized or
sorbed by the ash. Water consumption in this method is
pically lower by a factor of 15, than that of a wet
thod on a once-through basis, and can importantly reduce
cne water pollution problems associated with ash handling
operations.
b. Fly Ash Handling. This may involve one or more of a number
of variations such as:
• Conveying the ash by vacuum produced by hydraulic means
(i.e., water jet). In this case, the water mixes with
the ash producing a slurry that is allowed to flow by
gravity to a fill area.
• Pneumatic conveying to a dry storage silo with vacuum.
The vacuum required can be created by hydraulic or
mechanical means.
3-85
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• Vacuum conveying to an intermediate pump or mixing
tank where fly ash can be mixed with bottom ash for
disposal*
• Pneumatic conveying by pressure from individually
controlled air-locks to dry storage silos.
• Pressurized conveying to a wetting device with the
resultant slurry discharged by gravity to a fill
area through the bottom ash line or an independent
slurry discharge line.
• In cases where the fly ash has residual heating
value, pressurized conveying from fly ash hoppers
to re-injection at the furnace.
• Vacuum conveying to a transfer point from which
material is conveyed pneumatically by pressure
to remote disposal point.
The following general observations on fly
ash handling appear to be valid:
1. While hydraulic methods are employed after a central
collection point, vacuum or pressure type pneumatic
components are often part of fly ash handling from
the particulate collector.
2. Vacuum systems cannot be designed except for limited
lengths. The distance material can be conveyed depends
on configuration of the system and plant altitude above
sea Level.
• Pressure systems are applied where the length of the
conveying system is too great for vacuum conveying or
where altitude limits the vacuum that can be developed.
• Vacuum-pressure systems usually are economical
where the number of precipitator hoppers exceeds
twenty and where the length of the conveying system
3-86
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exceeds the capability of a vacuum system to attain
a satisfactory conveying rate [50].
c. Economizer Ash Handling. The coarser fly ash particles which
fall out under economizers and air heaters can be handled in
the same systems described for fly ash. Precautions may be
necessary to prevent the entrance of over-size material which
may be caused by sintering where ash is allowed to remain
for any length of time in hot areas. Where coarse material
is formed, crushers are provided to reduce all ash to particles
about 9.5 millimeter (3/8") in diameter which can be handled
pneumatically in conventional systems [50].
Economizer and air heater ash may, under suitable conditions,
be deposited continuously in water filled tanks from which it
can be pumped periodically. Hydraulic storage and removal
generally is acceptable only where ash can be disposed of
on a fill area. Economizer ash is difficult to dewater
when pumped into dewatering bins with bottom ash.
3.6.3 Conveying Systems to Storage or Disposal
The ash collected from particulate collectors or equipment as
described above is conveyed to storage or disposal. The major systems
are as follows:
a. Bottom Ash Conveying System: Hydraulic methods are
universally employed. The terminal point of such an
ash conveying system can be:
• A low area where the ash can be deposited:and dried
out by permitting run-off of the conveying water.
• A pond or lagoon in which the ash is allowed to
settle to the bottom with excess water eventually
overflowing to adjacent natural streams. With
3-87
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proper layout, ponds can be arranged to recover
conveying water for reuse.
• A dewatering bin into which the ash-water slurry is
pumped; ashes are settled and water is removed
through decanting and dewatering elements, so that
relatively dry ash can be delivered to trucks or
railroad cars. Dewatering bins are essential to
closed-loop hydraulic ash handling systems where
environmental regulations prohibit or minimize the
discharge of ash-contaminated water into any bodies
of natural water; the exceptions are areas of net
evaporation (i.e., where evaporation exceeds precipita-
tion). In such cases, dewatering bins become an
integral part of recirculating systems.
Bottom ash is usually either trucked to a utilization or
disposal site or sluiced to an ash pond for disposal.
b. Fly Ash Conveying System. Both pneumatic (vacuum,
pressure or pressure/vacuum) and hydraulic systems are
applicable although the latter is more common. If
handled and conveyed to a central storage point by
pneumatic means, water is often added to make a slurry
for onward transfer and disposal.
c. Closed Loop Recirculation Systems. Fully closed cycle
recirculating systems for ash handling may be considered
if one of two constraints require such systems:
• Limited availability of water and hence the need
to conserve it.
• Regulations prohibiting discharge of ash handling
water into severs or receiving waters.
At present, such recirculating systems are in wide use
for bottom ash only. Recent studies have focussed on
the requirements for recirculating fly ash water [14,110],
3-88
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3.6.4 System Design Considerations
The chemical composition of the bottom ash and fly ash produced,
as well as that of the conveying air or water, and the temperatures of
the products of combustion at the various points of collection, all
must be considered in system design. Furthermore, these considerations
impact extent of water recycle/reuse in wet handling systems. Some
important factors are:
a. Effect of Composition of Fly Ash on Flow. Probably the
most trouble in obtaining the flow of fly ash from pre-
cipitator hoppers is caused by moisture which makes the
dust into a sticky mass. This is the result of the
presence of hydroscopic salts which will cause difficulty
well above the dew point temperatures of the flue gases.
The solution is to raise the temperature in the areas of
dust storage by the application of heat to storage
hoppers or by locating the dust collectors ahead of air
heaters. Where permissible, external vibrators may be
used as added insurance that dust is made to flow from
the storage hoppers. Internal vibrating plates have
generally proven to be unsatisfactory. Heated fluidizing
air, introduced through porous stones properly located
in the storage hoppers, is an effective means for promoting
the free flow of dust into the conveying system. Usually
fluidizing air will amount to about 0.283 m /rain (10 ft /min)
for each hopper feeding continuously into the conveying
system [50].
b. Pipeline Velocities for Pneumatic Handling. The required
conveying velocity for any material is dependent upon
material density, particle size, concentration, and the
physical characteristics of the conveying air or gas.
Altitude is an important factor, particularly for vacuum
systems. Critical velocities for any materials in a
pneumatic conveying system are usually those at points
most remote from the discharge end of the system. Usually
3-89
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pickup velocities are in the range of 460 to 1200 meters/
minute (about 1500-4000 ft/min).
c. Pipeline Velocities for Hydraulic Handling. Any boiler
refuse can usually be conveyed hydraulically. Conveying
velocities will range between 1.5 and 3.7 meters per second
(5 to 12 ft/sec), depending on material density particle
size and conveyor pipe configuration. For coarser materials
such as bottom ash and mill rejects, conveying velocities
will be in the higher range, particularly in vertical pipes
such as may be encountered when pumping to elevated dewatering
bins. In long pipelines handling coarse materials, exceeding
about 1200 meters (4000 ft) in length, velocities must be
increased above those used for shorter lines. In addition,
some device to create turbulence must be introduced beyond
this limit to maintain homogeneous slurry mix, particularly
when conveying bottom ash or mill rejects. Fly ash slurries
with finer particles can be pumped at the lower range of
velocities.
3.6.5 Waste Streams from Ash Handling
In a recent study, fly ash and coal ash handling practices were sum-
marized and are outlined in Table 3.27. While some plants use dry systems
a typical ash handling system at utilities today use ash ponds. Usually
sedimentation lagoons are commonly used although some plants use con-
figured tanks [5]; the latter may be used more in industrial boilers.
Ash ponds are designed to have a disposal capacity to accept the
total wastes produced during a designed length of plant life. Often
ash ponds are large; Chu [91] reports a range of 80,000 to 150,000 m^
at TVA plants. Usually the ash pond is not designed for the whole life
of the power plant. They are designed to serve for a few years and
retire; then new ones are dug up. Another major factor in ash pond design
is the clarity of the ash pond overflow. Settling tests indicate that
most ash particles follow hindered settling characteristics while the
remaining fine ash particles follow discrete settling characteristics.
3-90
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Table 3.27
Coal Ash Handling at Power Plants
Basis: 308 Letter responses to EPA
Type of No. of
Number Ash System Plants
1 Bottom Ash Dry 99
Wet once-through 256
Wet Recirculating 33
Not Reported 399
2 Fly Ash Dry 193
Wet once-through 164
Wet Recirculating 17
Not Reported 413
Source: [101]
3-91
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To meet an effluent guideline limit of 30 mg/£, the fine ash particles
and the floated cenospheres are the critical factors in ash pond design.
Retention time in ash ponds is usually significantly more than 24 hours
providing effective removal of suspended particles to less than 30 mg/Jl
[91]. Clarified ash pond effluent is discharged through spillways;
each spillway is encircled by a skimmer extending about 0.6 meters
(about 2 ft) below the top of the weir to prevent floating cenospheres
from entering the discharge. When more water depth is needed, spillways
are elevated. Ash ponds are maintained at a freeboard of at least 1.2
meters (4 ft); to maintain this as more ash accumulates, the top of
ash pond dikes are raised periodically.
Typical intake and pond discharge data for an ash pond are presented
In Table 3.28. Figure 3.11 presents a typical recirculating bottom ash
system for an 800-MW plant, while Figure 3.12 shows components of water
balance for once-through flow and dry handling.
The characteristics of the water handling coal ash are related to:
• Type and amount of ash,
• Sluicing water flow rates,
• Makeup water quality, and
• Mode of operation
- Once-through vs. recirculating
- Separate vs. combined systems for fly ash and bottom ash.
The sluicing water requirement for ash handling varies widely in
the following range [5,22]:
• Bottom Ash: 9 to 151 metric tons (10 to 167 short tons)
3
per ton of ash conveyed. 10 to 170 m (2,400 to 10,000 gal)
per ton of ash.
• Fly Ash: 4.5 to 154 metric tons (5 to 167 short tons) per
ton of ash
ton of ash.
ton of ash conveyed. 5 to 170 m3 (1,200 to 40,000 gal) per
3-92
-------
Table 3.28
Typical Ash Pond Inlet and Discharge
TSS
CO
I
LO
Location
Intake
Inlet to Ash Pond
• from fly ash
• from bottom ash
Ash Pond Discharge
22
6.3
76,440. 4.4
4,110 5.6
14 4.3
Aluminum* Chromium* Copper* Iron* Mercury* Zinc*
mg/£, mg/i.
0.7
<0.04
<0.04
1100
56
6.0
1.3
0.1
<0.04
5.1
0.3
0.1
0.5 <0.04
2500 0.1
112 <0.04
0.6 <0 . 1
<0.05
2.8
0.1
0.1
*Note: Total
Source: [5]
-------
RECYCLE
2470 gpm
(4450/MW)
ASH
HANDLING
SYSTEM
.EVAPORATION
LOSS 45 gpm
2425gpm
SETTLING
POND
MAKEUP
56 gpm
ASH WASTE FOR DISPOSAL
(~ZO% MOISTURE)
~11gpm WATER LOSS
(19.8/MW)
Source: [5]
Figure 3.11
Example of a Recirculating
Bottom Ash System
3-94
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0,.)
WET
FLY ASH
COLLECTOR.
WATER.
SLURRY
I
t
TO
ASH POND SLUD&S
TO ULTIMATE
DISPOSAL
b-; PRY
.TO LAND
DISPOSAL.
Figure 3.12 Water Balance-Fly Ash Handling
3-95
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The ash pond effluent analyses for a large coal-fired plant, where
separate fly ash and bottom ash ponds were used on a once-through basis
are shown in Table 3.29 [14]. Additional data on TVA's power plants are
reported [14]. The relation between overall plant operations and quantity
and pH ash pond effluents is summarized in Table 3.30.
The leachability of constituents, particularly trace metals from
ash into the water is governed by the surface concentration of each
constituent in the ash matrix [92], the nature of the chemical, bonding
in the ash and the resulting pH of the solution. Neutralization of ash
pond effluents, particularly acidic ones, usually removes some trace
in the ash and the resulting pH of the solution. Neutralization of ash
pond effluents, particularly acidic ones, usually removes some trace
metals. However, trace metals such as arsenic and selenium are not
effectively removed at neutral or alkaline pH [91]; if the levels of
these are unacceptably high in the effluent, pH adjustment alone will
be inadequate. While trace metals migrate to groundwater by seepage
from ash ponds, the mass flow of trace metals into the environment is
much greater from surface discharges than from leachates reaching
groundwater [93].
Due to regulatory pressure and other reasons, circulating systems
are being used more widely. Significant advurse environmental impacts
and high water consumption are associated with the once-through systems.
Of all the water streams in the power plant, the ash sluicing water in
particular for bottom ash has the least stringent quality requirements.
Consequently, other wastewater streams (e.g., equipment cleaning, coal
pile runoff, cooling tower blowdown, etc.) can be used as makeup, particu-
larly to the bottom ash handling system. This use as the sink for other
waatewater streams will affect the composition of the blowdown from the
ash handling system.
In all recirculating streams, makeup water requirements are
influenced by:
• Pond evaporation rate,
• sludge solids concentration, and
• Blowdown and method of handling the blowdown.
3-96
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Table 3.29
Characteristics of Once-Through Combined Ash Pond Discharges
Parameters
Plant C Plant E Plant F Plant H Plant K
LO
I
Flow (gal/min)
pH*
Total Alkalinity (mg/1 as CaCO )*
Phen. Alkalinity (mg/1 as CaCOo)*
Total Hardness (mg/1 as CaCO^*
Conductivity (pmhos/cm)*
Total Dissolved Solids (mg)*
Suspended Solids (mg/1)*
Phosphorous (mg/1)
Ammonia (mg/1 as N)
Sulfate (mg/1)
Chloride (mg/1)
Cyanide (mg/1)
Silica (mg/1)
Calcium (rag/1)
Magnesium (mg/1)
Aluminum (mg/1)
Arsenic (mg/L)
Berium (mg/1)
Beryllium (mg/1)
Cadmium (mg/1)
Chromium (mg/1)
Copper (mg/1)
Iron (mg/1)
Lead (mg/1)
Manganese (mg/1)
Mercury (mg/1)
Nickel (mg/1)
Selenium (mg/1)
Silver (mg/1)
Zinc (mg/1)
Notes: 1. ^11 numbers are averages of quarterly grab samples collected during 1974 except
with an asterisk are averages of weekly grab samples.
The reported values include background concentrations in the rjiw water supply.
2. All these data are from coal-fired plants of TVA.
7,689
7.1
69
0
222
521
403
48
0.02
. 0.10
178
12
<0.01
7.5
83
8.4
1.4
0.015
0.3
<0.01
0.004
0.01
0.06
2.0
0.02
0.24
0.029
0.06
0.004
<0.02
0.16
4,391
10.8
176
142
266
796
340
29
0.01
0.05
130
6
<0.01
5.8
130
0.5
2.6
0.005
0.3
<0.01
0.002
0.02
0.07
0.45
0.03
0.02
0.0002
<0.05
0.011
<0.01
0.06
32,940 2
11.2
113
96
301
855
452
39
0.02
0.23
144
4
<0.01
6.8
117
0.6
2.2
0.005
0.3
<0.24
0.001
0.05
0.03
0.15
0.02
0.01
0.075
<0.05
0.018
<0.01
0.06
,486
8.1
61
0
110
408
268
20
0.09
0.71
98
11
<0.01
5.4
44
6.7
1.2
0.075
0.2
<0.01
<0.001
0.005
0.07
0.6
0.01
0.05
0.0005
0.06
0.012
<0.01
0.07
21,405
10.8
79
63
172
427
261
15
0.02
0.05
97
10
<0.01
7.1
74
1.2
1.8
0.01
0.2
<0.01
0.001
0.02
0.08
0.3
0.02
<0.01
< 0.0002
<0.05
0.010
<0.01
0.06
those shown
Source: [51]
-------
co
10
oo
Table 3.30
Relationships Between Plant Operation Conditions and
pH Values of Ash Pond Effluents at Ten Coal-Fired Power Plants
Parameters
Plant D
Plant H
Plant J
Plant E
Plant F
Plant C
Plant I
Plant K
Plane L
Plant C
Coal sources E. Kentucky Virginia E. Kentucky W. Kentucky V. Kentuckv U. Kentucky V. I' -ntucky S. Illinois U. Kentucky W. Kentucky
E. Kentucky E. Tennessee S. Illinois W. Kentucky W. Alabama S. Illinois
E. Tennessee
Method of
firing
Ash content
in the coal*. •
Fly ash of
total ash*. *;
Bottom ash of
total ash*. *
Sluice water :.-
ash ratio*.
(gal/tons)
pH value of
raw water*
pH value of ash
pond effluent*
Tangential Tangential Tangential Circular
15.5 15
75
25
10,770
67
33
11,425
7.5
8.6
7.0
8.9
'Based on average values during 1974.
7.6
6.3
Opposed Tangential Tangential Circular Horizontal Cyclone
11
30
70
23,065
.19.1
75
25
520
tangential
15. J
67
33
0.585
16.3
80
20
19,490
horizontal
15.7
80
20
12.345
14
70
30
42.430
15.6
75
25
17.265
tangent!
16
75
25
15,370
7.0
11.1
7.4
11.2
7.3
9.6
7.4
11.2
7.6
10.8
7.5
10.1
7.4
7.1
Source: [112]
-------
In some cases, as the power plant at Colstrip (7), the blowdown from
bottom ash handling is sent to scrubber ponds. However, this is not
typical for fly ash disposal, since the amount of leachable species in
fly ash (Ca, Mg, Na and SO,) is usually much greater than in bottom ash.
A recirculating ash sluicing system is more susceptible to scaling
since dissolved solids are concentrated in addition to species leached
from ash. The parameters that may influence scaling potential include:
• Ash reactivity,
• Makeup water quality,
• C0« transfer with atmosphere in the pond, and
• Degree of recycle.
Radian [7] in their evaluation of water recycle/reuse at five power
plants for the EPA made the following comments:
a. Ash Reactivity. Data on ash reactivity as determined
by leaching studies are reported in Table 3.31. Calcium
and sulfate are major species leached. In the five plants
studied, magnesium was present in significant amounts in
only one case.
b. Makeup Water Quality. The composition of the makeup water
used in a recirculating ash sluicing system will influence
the composition of the sluice water and therefore the scaling
tendency of the system. Bench-scale experiments and computer
simulation led Radian to conclude that poor water quality,
particularly in calcium and sulfate concentrations significantly
increased scale potential in fly ash slurry liquor.
c. COo Transfer. Degree of C02 transfer depends on the pH of
the pond water and fly ash slurry composition. Both CaCCL
and Mg (OH)« relative saturations are pH dependent (i.e., they
tend to precipitate at higher pH); hence, C02 transfer has a
significant effect on scaling tendency. Samples taken appear
to indicate that complete equilibrium with CO- is not usually
attained.
3-99
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O
o
Table 3.31
Ash Reactivity Determined from Leaching Studies*
Species ,
wt. %.
pH
Ca
Montour
6.0
.32
8.1
.28
6.0
1.3
Bowen
8.5
.76
Four Corners
10.4
.56
3.0
.83
6.0
.71
8.5
.62
Comanche ..
6.0 8.5
2.9 2.2
Co Is trip
4.0 6.0 8.0
5.1 3.7 3.2
Mg .02 .02 — — — — — — .11 .05 .66 .21 .06
Ma .04 .04 .12 .10 .07 .02 .02 .02 .04 .03
SO,, .76 .79 1.3 .1.2 1.0 .15 .04 .07 1.2 .83 .55 .60 .57
*Reported as wt. % of ash.
Source: [7]
-------
d. Degree of Recycle. The above discussions were for closed
loop ash sluicing systems. Recirculation was practiced
only for bottom ash; these studies by Radian revealed that
recirculation is feasible for fly ash also, but that
treatment may be necessary to prevent gypsum scale. Level
of treatment is determined by ash reactivity and makeup
water quality. Recirculation of ash pond overflow in
other parts of the power plant may be feasible. For
example, ash pond overflow may be usable as makeup to
a scrubber system. Degree of slipstream treatment to
control gypsum scale potential varies with the type of
loop considered.
3.6.6 Present Treatment Methods
At present, ash ponds have an overflow either to a receiving water
or a slipstream to another point in the power plant. Recirculation is
often practiced with bottom ash that is non-reactive. The EPA in its
survey for Effluent Guidelines Development Document [5] reported on
two systems presented in Figures 3.13 and 3.14. In both cases (one
for bottom ash and the other with combined overflow):
• recycle is limited to bottom ash; and
• filtration of suspended solids is practiced prior to
discharge to receiving water (filter sludge is sent
to disposal on land)
An increasing number of plants are now practicing recycle. EPA
reports [101] that bottom ash water recycle is practiced at 33 plants.
These plants recirculate the water from existing bottom ash or combined
pond or hydrabins. Chemical addition is not normally required. Further-
more, recycle of fly ash water is practiced at 17 plants. As noted
earlier, (unlike bottom ash) fly ash has higher concentrations of divalent
cations, sulfates, suspended solids and trace metals. Lime/soda treatment
(described later) or other options are required to recirculate fly ash
water. EPA has a survey underway [101] to determine the treatment prac-
tices at these 17 plants that recirculate fly ash water.
3-101
-------
OJ
(->
O
to
€>LUIC.ING WATER.
Source: [5]
Figure 3.13 Recirculating Bottom Ash Sluicing
System Slowdown Treatment
-------
U)
i
i-1
o
LO
FOR. BOTTOM /XSW SLUICING
(SOOO
FLY AAH SLUICIMG
POKD
»\V>/\OOOga\
Source: [52]
IO,OOO gpd/rnw
AS
nut OR. A.CID
r-
0.8
(I Vw. D6TEMTIOM )
ASSUMES THKT "TWE. WElGKT OF
PRECirUNTE »«>
OF POLLUTANTS-
Figure 3.14 Treatment of Combined Ash Overflow
-------
3.6.7 Treatment Options for Recycle/Reuse
The EPA's effluent guidelines for ash ponds [6] are summarized
in Table 3.32. Under best available technology (BAT) guidelines and
those for new plants, the EPA has proposed separation of bottom and
fly ash transport with different limits for each. For BAT, it is
proposed that the bottom ash sluice water system be closed and re-
cycled, with an estimated maximum blowdown of 8% of the recycle rate
but with a maximum of _5%^blowdown for new sources. The once-through
discharge of fly ash transport water would still be permitted, but
not for new sources. Fly ash and bottom ash disposal may be combined
within one pond and the sluice water discharged after once-through
sluicing by existing plants provided the quantities of each ash sluice
water are known and the weighted concentration of the combined discharge
is less than or equal to that allowed in the guidelines. For the
closed system, with increased cycle time and concentration, certain
limitations and precautions may be needed to deal with higher levels of
suspended solids, high alkalinity, and high concentrations of soluble
salts to avoid exceeding the solubility limits of calcium carbonate,
calcium sulfate, and others.
The problem of exceeding solubility limits has been mentioned
earlier. Solubility limit of calcium carbonate is governed by the
Langelier & Ryznar Indexes which are described below:
a. Langelier Index. A technique of predicting whether water
will tend to dissolve or precipitate calcium carbonate.
If the water precipitates calcium carbonate, scale forma-
tion may result. If the water dissolves calcium carbonate
it has a corrosive tendency. To calculate Langelier1s Index
the actual pH value of the water and Langelier's saturation
pH value is determined by the relationship between the
calcium hardness, the total alkalinity, the total solids
concentration and the temperature of the water.
Langelier's Index is then determined from the expression
pH-pHs. Figure 3.15 is a chart used for determining
3-104
-------
Table 3.32
Effluent Guidelines and Standards for Power Plant Ash Ponds
Discharge Stream
Controlled Parameter
BPCTCA
BATEA
NSPS'
All Plant Discharges pH
Poly chlorinated
biphenyls (PCBs)
Bottom Ash total suspended
w Transport Water solids (TSS)
M
£> oil and grease
Fly Ash TSS
Transport Water
oil and grease
6.0-9
zero
30-day
average
30
15
30
15
.0
daily
maximum
100
20
100
20
6.0-9
zero
30-day
average
30rl2.5b
15U2.5
30
15
.0
daily
maximum
100rl2.5
20rl2.5
100
20
6.0-9.0
zero
30-day daily
average maximum
30^20 100^20
15T20 20T20
zero zero
zero zero
All quantities except pH are in units of mg/£.
v!2.5 or ^-20 indicates the required degree of recycle (or "number of cycles") of water;
r!2.5 means 8% blowdown allowed, while ^20 means 5% blowdown allowed.
Source: [6]
-------
10 20 30 50 100 200300500 1000
PARTS PER MILLION
5000
1.1
Source: [32]
Figure 3.15 Langelier Saturation Index
3-106
-------
Langelier's Index. The interpretation of the results
obtained are shown below:
pH-pHs Tendency of Water
Positive value Scale forming
Negative value Corrosive
Zero Neither scale forming
nor corrosive
The presence of dissolved oxygen in the water may cause
water with a "zero" Langelier's Index to be corrosive
rather than "neutral." Furthermore, differences in
temperature within a system and chemicals may adversely
impact the applicability of the Index.
Ryznar Stability Index. This is an empirical method for pre-
dicting scaling tendencies of water based on a study of
operating results with water of various saturation indices.
Stability Index = 2 pHs-pH
where: pHs = Langelier's Saturation pH
This Index is often used in combination with the Langelier
Index to improve the accuracy in predicting the scaling or
corrosion tendencies of a water. Table 3.33 illustrates
the use of this Index.
In addition to solubility of CaC03, solubility limits of
CaSO^ and seprolite [Mg2,Si3Og,(H20)rl are important in
considering recycle of ash pond water; these are determined
by their respective solubility products and "by temperature
pH and common ion effects. Generally in a typical ash pond
solubility limits for CaSO, and CaCO-, can be exceeded in a
few cycles in an untreated recirculating loop. Hence, any
recirculating loop requires treatment for scale control.
Such recycle may also be desirable to control ash pond water
iron and removal of trace metals. Suggested control limits
3-107
-------
Table 3.33
Ryznar Stability Index
r Stability Index Tendency of Water
4.0 - 5.0 heavy scale
5.0 - 6.0 li«ht scale
6 0 - 7.0 little scale or corrosion
7 0 - 7.5 corrosion significant
7.5-9.0 • heavy corrosion
9.0 and higher corrosion intolerable
Source: [32]
3-108
-------
for ash pond recirculating water composition are presented
In Table 3.34. It is noted that the solubility product
of CaSO, varies significantly with ionic strength.
Chu et^ _al. [14,110] evaluated the potential for complete reuse
of ash pond effluents. Their report is from the perspective
of TVA's coal-fired power plants. The TVA has two coal-fired
plants with separate bottom and fly ash ponds, but ten are
combined (bottom and fly ash) treatment ponds. Chu et al.
[14] conclude (among other conclusions) that:
• Complete reuse may be possible using sidestream treatment.
One option is to use lime soda softening. The softening
process would eliminate the scaling problem, and complete
reuse would reduce the discharge of trace metals to surface
streams. The reuse scheme proposed would require
softening of only a portion of the sluice water.
• Reverse osmosis or ion exchange may be applicable for
high dissolved solids operation (supplementing lime-
soda softening) for higher quality water usage.
• A mathematical model was developed for determining
the proportion of ash sluice water that would require
softening in order to prevent scaling in the sluicing
system.
• Laboratory jar tests on lime-soda softening of con-
centrated bottom ash pond water showed good removal
of turbidity, calcium, and magnesium, and some
removal of silica. The addition of soda ash was
necessary for adequate hardness removal because of
the high non-carbonate calcium content. The sulfate
buildup in the closed-loop system can be controlled
by the addition of excess lime in the sidestream
treatment processes. Because of the wide variation
in water quality characteristics between various
power plants, additional testing is needed.
3-109
-------
Table 3.34
Suggested Control Limits for Ash Pond Recirculating Water
No. Characteristics Limit Reference
1 pH and hardness Langelier Saturation Index
0.0 to 1.0
Ryznar Stability Index
Jsat * 2pHg - PH - 6.0 to 7.0 (51)
/
2 sulfate & calcium CSQ, X CCa - 200,000 /52\
3 magnesium &
silica C^ X CSI() - 8,505 (52)
3-110
-------
• Good removal of cadmium, copper, iron, lead, and
zinc was obtained by addition of lime to an acidic
fly ash pond effluent, raising the pH to a value of
10. The lime-soda process appears to be effective
only for those species of trace metals which tend to
form insoluble metal hydroxides or carbonates, or those
which readily absorb on CaCCL or Mg(OH)2.
The complete reuse scheme suggested in this study P4 ] is discussed
in Section 5.3.
In a recent study [103], activated carbon, reverse osmosis, and
chemical precipitation were tested on a bench scale for cooling tower and
ash pond overflow. There exist very few organics in both the ash pond
overflow and cooling tower blowdown. For those pollutants present, the
test result does indicate some probable applicability of the various tech-
nologies as follows:
• Reverse Osmosis: Reverse osmosis was tested to determine
the degree of flow reduction and pollutant concentration
achievable. The result indicates that reverse osmosis is
effective for concentrating copper, nickel, zinc, lead,
silver, chromium and arsenic. RO was also found to be
effective in concentrating dibromochloromethane and bromo-
form. Removal efficiency for the other pollutants was not
determined because of its low concentration in the waste
streams tested.
• Chemical Precipitation: Four chemicals were used in batch
precipitation tests performed with sample water from both
of the waste streams. Lime was used as the primary precip-
itating agent, but sodium sulfide was also tested for
cadmium and mercury removal since lime treatment alone may
not be effective for these metals [103]. In addition ferric
sulfate and ferrous sulfate were also tested to examine
their effect upon metal removal due to coprecipitation and
adsorption mechanisms. Organic analysis was not performed
3-111
-------
for evaluation of chemical precipitation as this technology
was not intended as a method for removal of organics. The
results indicate that chemical precipitation with lime is
effective in decreasing copper, zinc, arsenic, chromium
and lead.
• Activated Carbon: In most cases, the organics in the two
waste streams are at such low concentration that removal
efficiencies can not be determined. In the case of bromo-
fonn and dibromochloromethane from cooling tower blowdown
of one plant, activate carbon was found to be effective.
3.6.8 Dry Handling Systems
In recent years, a shift towards dry handling systems for ash has
been noted [52]. This trend will substantially impact water needs for
ash ponds and potential pollution by effluent overflow. Recently,
American Electric Power disclosed it was going to convert its major
units from a wet system with sluice ponds to on-site collection silos
and the placement of the ash they do not market into structural
landfills* Space conservation was listed as the major reason for the
shift [52].
However, the split among wet vs. dry systems remains pretty even
among utility producers at present. New environmental regulations
which will require closed loops on wet systems will also expedite the
changeover. About 68% of the power plants have dry collection and
unloading facilities for fly ash [52]. The switch to dry systems will
also result in a separation of fly ash and bottom ash now being dis-
posed of together at 72% of the installations. Some recent trends in drv
handling of ash and associated economics are discussed in Section 5.3.5
3.6.9 Economics of Treatment
The general observations regarding cost data for treatment of
individual streams also apply to ash handling wastes. The EPA in
developing guidelines [5] established approximate cost data for two cases*
3-112
-------
• Recirculating bottom ash system with treatment of bottom
ash blowdown. Figure 3.13 describes this type of system
(see page 3.98)- Table 3.35 presents capital and operating
costs for such systems in 1978 dollars (CE Cost Index 218.8).
• Recirculating bottom ash with treatment of combined ash
overflow. Figure 3.14 describes this type of system (see
page 3.99). Table 3.36 presents capital and operating
costs for such systems in 1978 dollars (CE Cost Index 218.8).
3.7 FGD Systems
3.7.1 Process Description
FGD systems can be generally categorized into two groups: non-
regenerable, or throwaway, systems which produce a waste material for
disposal; and regenerable, or recovery, systems which produce a saleable
byproduct (sulfur or sulfuric acid). There are now over 50,000 MW of
coal-fired electric utility boilers in the United States to which flue
gas desulfurization systems are being applied (including systems in op-
eration, under construction, or in procurement). About 90% of this
capacity involves nonrecovery systems, most of which employ lime or lime-
stone to produce a solid waste, calcium-sulfur salt for disposal. This
technology can be expected to dominate in boiler applications on FGD
systems for the foreseeable future.
All commercial nonrecovery processes today involve wet scrubbing
where gases are contacted at some stage with aqueous slurries or solutions
of absorbent; some dry solvent systems are expected to be operational by
the early 1980's. Although most nonrecovery systems can withstand
relatively high levels of particulate and trace contaminants and many in
the past have been designed for simultaneous SC>2 and particulate removal,
most systems being installed today, particularly on utility-scale boilers,
follow high efficiency electrostatic precipitators in order to ensure a
more reliable service. The notable exceptions to this are systems which
utilize the alkalinity in the fly ash for S02 control and therefore fre-
quently remove fly ash and SO^ simultaneously.
3-113
-------
Table 3.35
Recirculating Bottom Ash System
With Treatment of Bottom Ash Slowdown
Basis: 1. Sec Figure 3.15 for typical system (page
2. Cost in mid-1978 dollars (CE Index 218.8)
3. Capital cost « Major Equipment
+ 50% for installation in new plants
or 100% for installation in existing plants
+ 20Z for instrumentation
•4- 15% for engineering
+.'15% contingency
4. Annual Cost « 3% of capital for maintenance
+ 15% of capital for fixed costs
•4- chemicals - labor and power
100 MW 1000 MW
Retrofit .New Sources Retrofit New Sources
Ho. Item "($1000) ($1000) ($1000) ($1000)
1 Total Capital 213 164 671 518
Cost ($/kW) (2.13) (1.64) (0.67) (0.52)
2 Anmialized Cost
a) Total $ 231 188 572 400
b) mills/kWh
Caseload
(0.77 cap.
factor) 0.341 0.279 0.085 0.059
cyclic
(0.44 cap.
factor) 0.597 0.488 0.148 0.104
peaking
(0.09 cap.
factor) 2.92 2.39 0.725 0.507
Source: [5] and Arthur D. Little, Inc., updates
3-114
-------
Table 3.36
Recirculating Bottom Ash System
With Combined Ash Pond Overflow
Basis: 1. See Figure 3.16 for typical section (page
2. Cost in mid-1978 dollars (CE Index 218.8)
3. Capital cost = Major Equipment
4- 50% for installation in nev plants
or 100% for installation in existing plants
+ 20% for instrumentation
4- 15% for engineering
r
+ 15% for contingency
4. Annual Cost = 3% of capital for maintenance
4- 15% of capital for fixed costs
4 chemicals, labor and po^ar
100 MW 1000 MW
Ho. Item Retrofit New Sources Re .r of it Kew Sources
— ' "($1000) ($1000) ($1000) ($1000)
1 Total capital cost 481 371 1,767 1,365
Cost ($/kW)
Annualized cost
a) Total $ 599 - 2,355
b) -mills/kWh
baseload (.capital
factor 0.77) 0.89 - - 0.35
cyclic (capital
factor 0.44) 1.55 - 0.61
peaking (capital
factor 0.09) 7.60 - 3.00
Source: [51 and Arthur D. Little, Inc., update
3-115
-------
The principal types of nonrecovery systems producing solid wastes
as sludges for disposal are:
• Direct limestone scrubbing,
• Direct lime scrubbing,
• Alkaline fly ash scrubbing, and
• Double (dual) alkali scrubbing.
Most nonrecovery systems in operation today are lime or limes tone
scrubbing systems. These utilize a slurry of lime or limestone for SO
removal and can produce a waste ranging from a slurry to a relatively drv
filter cake. Lime, limestone, and fly ash scrubbing are now considered
to be a commercially available technology. A number of these systems hav
demonstrated high availability and reliability on utility-scale boiler
applications. Double (dual) alkali systems represent a second generatlo
technology which is now reaching commercial demonstration. Double alkali
systems utilize solutions for sodium salts for S02 removal which are then
reacted with lime outside the scrubber system to produce a waste dlschar»*d
as filter cake. It is anticipated that for the next several years, non-
recovery systems will remain the only ones practical on a large scale.
Excepting in site-specific instances where local economic considerations
favor the byproduct or areas where stringent environmental regulations
constrain both land and ocean disposal, recovery systems are not likelv
to find broad, large-scale use in the immediate future. Furthermore
most recovery systems will employ prescrubbers that produce wastes for
disposal. Hence, In this report, the discussion on FGD wastes and its
impact on water recycle/reuse in power plants will focus on such non-
recovery systems. For a brief review of regenerable systems, the reader
is referred to Volume 3.
A generic FGD scrubber system (nonregenerable) is shown in Figure
3.16. Gas cleaning is accomplished in the scrubber while solid precipi-
tation occurs in the reaction tank and solids concentration can be
achieved in a solid liquid separator or in a land disposal site. A mo
detailed schematic for limestone based FGD systems is shown in Figure
3.17 [53].
3-116
-------
MAKEUP
WATER
FLUE
GAS
ALKALI
STACK
GAS
DEMISTER
SCRUBBER
REACTION
TANK
i
SOLID/LIQUID
SEPARATION
WASTE
Figure 3.16 Generalized FGD System
3-117
-------
I
M
M
00
STEAM PUMfT
"
REHCATOA
i
PULVERIZED
COAL
HOPPCRS. FEEDERS AND CONVEYORS
SLURRY
FCEO
TAMK
Source; [54]
Figure 3.17 Limestone Slurry F6D System
-------
FGD scrubbing systems comprise three operations:
a, gas cleaning,
b. solids precipitation, and
c. solid/liquid separation.
a. Gas Cleaning
Gas cleaning in all commercially nonregenerable processes involves
wet scrubbing where gases are contacted at some stage with aqueous slur-
ries or solutions of absorbent. Most gas cleaning systems installed in
utility boilers today involve high efficiency electrostatic precipitators
for particulate removal followed by a scrubbing system for S02 removal.
Such decoupling ensures a more reliable service. The exceptions are
those cases employing the alkalinity of fly ash to remove S(>2.
b. Solids Precipitation
The second major operation in the scrubbing system is the solid
precipitation. In direct lime and limestone scrubbing systems, the SC>2
is removed from the system by precipitation of calcium sulfate and
sulfite. The required rate of precipitation is determined by the rate
of absorption of S02 from the flue gas. The precipitation occurs in a
reaction tank with adequate time for crystal growth of the recirculated
particles. Waste solids (calcium sulfite/sulfate and fly ash) are
removed from the scrubber in a bleed stream from the absorber recircu-
lation. The rate of bleed (and hence, water makeup) is used to control
the solids concentration to the desired level.
c. Solid/Liquid Separation
In order to minimize water requirements for the scrubbing system,
the spent slurry is dewatered to recover a portion of the water. De-
watering can range from simple settling in a disposal pond to a thick-
ening and filtration (centrifugation) to produce a relatively dry (soil)
waste. The water recovered can be recycled to the scrubbing system to
minimize aqueous discharge and reduce makeup water requirements. The
final water content of the waste solids and evaporation occurring in the
scrubber determines the makeup requirement for the total system.
3-119
-------
3.7.2 Makeup Water Requirements
Flue gases contain both particulates and SOX which are usually re-
moved separately. Total wastes from both particulate and SOX removal
systems are referred to as FGC wastes while SOX removal wastes alone ar
called FGD wastes. Many water recycle/reuse considerations for FGC and
FGD wastes are analogous. Furthermore, in the future, FGD wastes will
need to be stabilized prior to land disposal; often fly ash will be con-
sidered for this purpose. Hence, future trend may be to consider the
total FGC system.
Makeup water requirements for nonregenerable scrubbing systems for
S02 and combined S02/particulate control depend upon a number of process
variables which define the quantity and quality of water needed, and,
thereby the potential for use of power plant wastewater streams in the
FGD or FGC system. In general, FGC systems (encompassing waste disposal)
can be classified into two groups with regard to water balance—
open-loop and closed-loop. This classification can be applied regardless
of the type of system and disposal operation. The current criterion gen-
erally considered to define closed-loop operation of FGC systems is no
discharge of process water other than that which is occluded with the
dewatered solid, i.e., zero aqueous discharge.
Figure 3.18 shows block diagrams indicating the principal water
balance factors (uses and disposition) for the two basic disposal
approaches—one incorporating wet ponding, the other dry impoundment.
The total quantity of makeup water is determined primarily by three
factors:
• The evaporation of water in the scrubber to the flue gas
• The quantity of waste solids produced, and
• The extent to which the waste solids are, or can be,
dewatered (either mechanically or naturally).
Other factors which are generally of much lesser importance incl A
• Rainfall and evaporation in open process tanks,
• The nature of the calcium-sulfur salts produced (gypsum contai
four times the amount of bound water as calcium sulfite, altho
3-120
-------
(a) EGD SYSTEM WITH WET POND DISPOSAL
Co
r
M
NJ
(Non Regenerable Te
Evaporai
In Flue
Deniister Wash
Pump Seals/Instrume
Reactant Slurry Pre
GD Systems)
. A Atmospheric
tion ^ r
Gas 1 Evap. Rainfall
1 t 1
^
W FGD
ats
fc
W
p. SYSTEM
(b) FGD SYSTEM WITH DRY IMPOUNDMENT
Solids |"~ '
w 1 TREATMENT 1
Slurry *! SYSTIiM '
i !
^
Recycle Liquor
Evap. In * Atmospheric
Flue Gas Evap. Rainfall
t 1
„. . ,,, f Demister Wash
c ,. . J Pump Seal
Re
Re
Dual Alkali
" Ca
Scrubbing _
actant Slurry
actant Slurry
ko Wash
mp Seals
FGD SYSTEM
WITH
FILTRATION
OR
CENTRIFUGATION
Evap. Rainfall
t i
WET
^
W
POND
1
| Seepage
if
T
( i
! TREATMENT 1 To
1 K.
1 P>Dry
SYSTEM , y
I | Disposal
L -J
NOTE: Treatment System Refers to
Sludge Stabilization Processes
Figure 3.18 Water Balance Factors for
Nonregenerable FGD Systems
-------
the absolute quantity is small in the context of the overall
water balance), and
• For wet disposal, evaporation and rainfall at the disposal site
Direct Scrubbing Systems
The principal uses for water in direct slurry scrubbing systems are
demister wash and pump seals. Some amount of water may also be used in
reactant slurry preparation; however, most systems utilize clarified
liquor alone for this purpose.
One of the most important considerations in the design of direct
scrubbing systems for closed-loop operation is scale control and the
largest use of water is for this purpose. Scale control includes the
prevention of:
• Chemically induced formation of calcium-sulfur salt scale
either alone or in combination with fly ash and other con-
stituents on scrubber internals,
• Chemical precipitation/deposition of other constitutents
resulting from buildup of impurities in solution,
• Deposition of solids due to evaporation at wet/dry
interfaces and on reheaters, and
• Buildup of precipitated solids due to physical deposition.
The prevention of calcium-sulfur salt scale formation (usually
calcium sulfate) is a key factor in the design and operation of any
direct slurry scrubbing system. An important aspect is the control of
system chemistry to avoid supersaturation with respect to gypsum (actually
a small degree of supersaturation is usually acceptable). This can in-
volve many considerations such as the allowance for proper reaction tine
in hold tanks; control of pH, reactant stoichiometry, and/or scrubber
liquid-to-gas ratios; control of solids concentration to ensure adequate
nucleation sites for crystal growth; and makeup water control (both
quality and how it us used).
One area of particular concern in slurry scrubbers is the demister
which is prone to scale formation and plugging. It is washed (either
continuously or intermittently) using fresh process makeup water or a
3-122
-------
combination of fresh water and clarified liquor to remove physical
deposits and prevent chemically induced scaling by reducing solution
concentrations to below saturation levels. In some systems a tray is
installed just ahead of the demister across which liquor is recirculated
to remove solids before they reach the demister. A principal requirement
±9 that the liquor used for washing the demister, or used on a wash tray,
have a low level of suspended solids, calcium and sulfate levels low
enough to prevent precipitation, and little or no dissolved solids which
can cause chemical precipitation when contacted with scrubber liquor.
In most systems, all available makeup water is used in demister
scale control, and efforts are made to minimize all other water uses.
The water balance and the quality of makeup water, therefore, can be
critical in controlling scaling. In some direct scrubbing systems,
because of design and/or operational constraints, it is necessary to
operate open-loop (continuously or intermittently) to prevent scaling,
which can result in appreciable water discharge from disposal ponds.
However, most recent direct scrubbing systems are designed for closed-
loop operation, or at least as close an approach as site conditions and
design constraints allow.
Dual Alkali Systems
In dual alkali systems, which involve solution scrubbing with
regeneration of the spent solution using lime or limestone to produce
a waste calcium-sulfur solid, no extensive scale control measures are
required and therefore, no demister wash is needed. However, dual alkali
systems do utilize fresh makeup water for washing of the filter cake to
recover absorbent occluded with the solids and to prepare reactant (lime)
slurries. (Clarified liquor cannot be used.) The principal uses are
reactant slurry preparation and cake wash.
Table 3.37 lists the principal process factors affecting the water
balance for closed-loop systems. It is important to note that while many
of these process factors may vary among different systems, most are not
really variables. For example, for a given boiler application where the
site conditions (including water availability), boiler characteristics,
fuel properties, and emissions and disposal requirements are defined,
3-123
-------
Table 3.37
Process Factors Affecting Water Balances
in Nonregenerable FGC Scrubber Systems
Water Inputs
Reactant Slurry (Dual Alkali)
Pump Seals/Instruments
Demister Wash (Direct Scrubbing)
Filter Cake Wash (Dual Alkali)
Water Outputs
Evaporation to Flue Gas
Net Atmospheric
Evaporation/Rainfall
Waste Solids
FGD Process Factors
SecondarjT
ASO_
Reactant (Lime)
Properties
AAsh
Scale Control
Source: Arthur D. Little, Inc.
AAsh
None
Type of Disposal Open Vessel Area
AAsh
Reactant Type
& fctoichiometry
Degree Oxidation
Type/Degree Dewatering
3-124
-------
most of the process factors are set (i.e., S02 removal, ash removal,
type of disposal and, to a large extent, the degree of dewatering of the
wastes). Once the general process type is selected (direct lime, direct
limestone with/without forced oxidation, dual alkali, or fly ash
alkalinity) there is little freedom left in many cases to manipulate the
water balance. Thus, the selection of the type of process can be very
important with regard to the ability of the FGD system to utilize other
power plant wastewater streams.
Table 3.38 shows estimates of typical makeup water requirements and
uses in nonrecovery FGC systems for a typical 500-MW boiler at full
load firing 3.5% sulfur coal (with an emissions requirement of 85% SC>2
removal) and 1.0% sulfur coal (with an emissions requirement of 0.2 Ib
807/10^ Btu heat input). The purpose of this table is simply to il-
lustrate the effects of SC>2 removal, ash removal, and waste solids on
system water requirements. Some simplifying assumptions have been made
regarding waste properties and process parameters. It has also been
assumed that there is no net evaporation or rainfall.
It is apparent in Table 3.38 that evaporation of water to the flue
gas is the single most important factor in a system water balance. The
amount of evaporation is essentially independent of the type of process
or process operation. Rather, it is a function of the boiler design and
its operating conditions and is determined by the flue gas rate, tempera-
ture and humidity; all of which depend on the boiler efficiency (and
design)* fuel composition and combustion air rate (and humidity). By
comparison, the amount of water lost with the waste solids amounts to
less than 10% of the flue gas evaporation in low sulfur coal systems
(less than about 1.0% sulfur) and as much as 30% for moderately higher
sulfur coal (about 3.5% sulfur). In estimating water losses with waste
solids, it has been assumed that the solids content of the wastes is
roughly that which can be achieved with filtration and/or pond settlement.
In this regard, it has been assumed that the presence of fly ash in
sulfite-rich waste (from high sulfur coal) improves the dewatering prop-
erties slightly. The result is that there is only a slight increase in
water losses with the wastes when ash is simultaneously removed.
3-125
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Table 3.38
Water Requirements for Generalized Nonrecovery Scrubbing Systems
Bail*: 500 W Boiler
9500 Btu /Wh
Full Load Conditions
Coal: 3.5Z Sulfur Coal: 1Z Sulfur
10Z Ash 12Z Ash
12,000 Btu/lb 10,000 Btu/lb
S02: 851 S02: 80Z
Direct Scrubbing* Dual Alkali Direct Scrubbing8
With Aah Without Ash With Aah Without Ash With Ash Without Ash
Water Losses (gpsO
Evaporation to Flue Gas 475 475 475 475 475 475
Waste Solldsc 130 115 1Z5 110 _40 15
Total 605 590 600 585 515 490
u> Water Uses (gpm)
Reactant Slurryd - - 205 205
Pump Seals0 150 120 80 50 130 100
Demlster Wash 455 470 - - 385 390
Filter Cake Wash - - 315 330 z -
Total 605 590 600 585 515 490
8 Lime Stoichiometry -1.1 (90Z CaO in Raw Lime) or
Limestone Stoichiometry -1.3 (95Z CaC03 in Raw Limestone),
b Lime Stoichiometry - 1.0 (90Z CaO in Haw Lime).
0 Waste Solids Properties Assumed:
Waste Solids Content
wo /Ash With Aah
3.5Z S Coal - 15Z CaS04/85Z CaS03 50 wtZ 60 wtZ
l.OZ S Coal - 100Z CaS04 80 wtZ 80 wtZ
Lime Slurry Concentration - 20Z Solids Based on CaO.
* Pump Seal Hater Requirements are illustrative only since they caa vary considerably fro* these numbers.
Source: Arthur D. Little, lac.
-------
These assumptions concerning the extent of dewatering and the effects
of simultaneous ash removal are generalized and will actually vary from
system to system. However, only where the ash and/or sulfur levels in
the coal are quite high or the dewatering properties of the wastes par-
ticularly poor (less than 40% solids by filtration or settlement in a
disposal pond) will the quantity of water lost with the wastes represent
a significant fraction of the water lost to evaporation. For example,
with a 5% sulfur coal (12,000 Btu/lb) containing about 15% ash, the water
lost with FGC wastes (including SOX and particulate removal) dewatered
to 50% solids will equal about 60% of the evaporation rate.
In addition to sulfur and ash removal rates and the degree of de-
watering, the type of system, the reactant used, and the reactant stoi-
chiometry can all affect water losses in wastes.
It should be noted that the water requirements and consumption
shown in Table 3.37 reflect full load conditions. The water balance can
change significantly as load is reduced. In general, sulfur and ash re-
moval and evaporation are a direct function of boiler load. As the load
decreases, the water losses to evaporation and waste discharge decrease
(almost proportionately). The requirement for pump seal water and
demister wash, though, are not directly related to boiler load. These
typically change in a step-wise fashion as modules (or trains) are taken
0ff_Htie or put on-line; and this is usually dependent upon the turndown
capability of the modules and the operating philosophy. Thus, as load
decreases, water balance can become a concern. In fact, some direct
scrubbing systems that operate in a closed-loop at relatively high average
loads (>60%), require some amount of water discharge during extended
periods at relatively low average loads.
A statistical analysis of raw wastewater and scrubber pond overflow
was compiled in a recent study [101] and is summarized in Table 3.39.
3.7.3 Water Recycle Options
Some FGD systems now use cooling tower blowdown or ash sluice water
for part or all of the scrubber makeup water requirement. The ability
3-127
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Table 3.39
FGD Systems in Coal-Fired Plants
No. of Flow Flow/Gen
No. Variable Plants (gpd) (ePd/MW)
Scrubber 13 1,715,876 2,027
Slowdown
Pond 7 842,898 15,749
Overflow
Source: [104]
3-128
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to use these or other waste streams can only be determined under site-
specific and system-specific conditions. However, two important factors
that must be considered in evaluating the feasibility of using such water
are:
• The chloride levels, and
• The calcium content.
High chloride levels in scrubber liquors can result in extreme cor-
rosion problems. As shown in Table 3.37, scrubbing systems can concentrate
highly soluble impurities by factors ranging from 2 to 10 times the levels
present in the makeup water. Hence, the effects of high levels of chloride
(or other species) can be magnified considerably.
High calcium levels in makeup water may limit the amount which can
be used for demister wash. Calcium levels in many plant wastewater
streams, such as ash sluice water or cooling tower blowdown, may be
saturated with respect to gypsum. When contacted with scrubbing liquor,
this calcium may precipitate causing scaling problems. This could limit
its use even for pump seals.
There are other potential impurities as well which can cause prob-
lems. Dissolved silica, for example, may present a problem since it is
relatively insoluble at low pH, and therefore, can precipitate in the
scrubbing liquor. The presence or potential buildup of such species can
only be evaluated from a relatively detailed analysis of the potential
makeup water streams and the operating conditions and requirements of the
FGC systems. In some cases, pilot plant testing is needed to ensure
satisfactory FGC system operation. Such testing is frequently conducted
as a part of the design work for many systems.
As a part of its contract with the EPA, Radian Corporation [7] has
evaluated the potential for use of a number of plant wastewater streams
as makeup to FGC systems at five plants. Results indicate the potential
for use of combined cooling tower blowdown (CTBD) or ash pond water and
fresh water as demister wash and in pump seals. However, careful proc-
ess analyses and pilot studies are required in each case.
3-129
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Incorporation of supernate from FGD systems into overall water
management is feasible with treatment, but was practiced only in 6 out
of 34 plants in 1977. [HO] Some pertinent points on recirculation are:
• Wash water from the mist eliminator may be 2 to 4 times the
makeup water amount.
• Bleedoff from a recirculating system is essential to prevent
scaling and buildup of dissolved solids.
• To obtain effective closed loop, supernate from mechanical
or pond dewatering should be included in the overall loop.
Data on scrubber liquors are presented in Volume III.
The impact of FGD waste disposal practices on groundwater is discussed
in Volume 5.
3.7.4 Recent Studies
In recent years, the EPA had initiated studies concerning water pol- •
lution impact of SOX control and effective control thereof. The important
ones are as follows:
a. In a study completed in 1976, Aerospace [54] assessed
potential reuse of scrubber liquid from nonrecovery
FGD processes. A number of potentially available water
treatment processes were studied to permit reuse.
Lime-soda softening, ion exchange evaporation and
membrane methods were assessed.
b. Radian Corporation [55] assessed the water pollution
impact of controlling SO by nonrecovery processes
X
as part of a review of New Source Performance Stan-
dards. They concluded that:
• SOX control increases total water demand by
8 to 11% depending on the process used. For
a 500-MW plant, this amounts to 1.9 - 2.7 m3
(500-700 gal) per minute.
-------
• If physical coal cleaning is added, total
water demand is increased by about 4% (in
addition to scrubber needs).
• Stricter NSPS do not nave significant effect
on water use.
• Effluent streams can be heated to acceptable
levels using commercially available technology.
c . Resource Conservation Company [56] studied the use of a
vertical tube, falling film, vapor compression evaporator
to treat wash water from Chiyoda FGD process. Their test
program demonstrated that:
• Net discharge of wastewater could be reduced to
as little as 1% of initial volume with the rest
available as high quality water (<10 ppm IDS) for
reuse.
• The system can operate for long periods without
scaling. To prevent calcium sulfate scaling in
feed heat exchangers and deaerators up to 15 mg/i
of scale inhibitor was added.
• At very high concentration factors (140) energy
consumption was 2.6 to 3.2 kWh/m3 (9.8 to 12.1 kWh
per 1,000 gallons).
• Capital cost of full scale system was estimated
at $1,350 to $2,300 per m3/day ($5.11 to $8.71 per
gpd) (1977 dollars). This is higher than current
desalination technology costs. Operating; costs were
estimated at $0.65 to $0.95 per m3 ($2.46 to $3.59
per 1,000 gal).
Overall, it appears that this is a technically feasible technology,
but economics may not be acceptable in many cases.
The TVA [91] plans to discharge mist eliminator wash water from
FGD systems to ash ponds at one power plant. Acidity of the wash water
will help reduce alkalinity of the ash pond.
3-131
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In a recent FGD system, SQ^ removal was reportedly attained [1131
with zero discharge; water requirement was minimized by use of boiler
and cooling tower blowdown to supplement well water supply for the FGD
system. In principle, zero discharge can be attained by ponding, and sol
evaporation in net evaporation areas. However, the overall objective
should be optimum water management which would require minimum intake
and environmental impacts associated with disposal. The Colstrip Plant
of Montana Power [114] is a plant designed on closed loop mode wherein
water only leaves the system by evaporation or in the FGD sludge. Close
approach to the design has been achieved at Colstrip.
3.8 Miscellaneous Operations
3.8.1 Description of Operations
Water, used for miscellaneous operations such as laboratory and
sampling activities, auxiliary cooling water syatem(s), sanitary facUiti
and washing of intake screens, can produce minor waste streams.
Laboratory and sampling wastes can differ from plant to plant.
Modern plants, where closer controls on operations are required, have
more extensive sampling and laboratory activities. There are no quan-
titative data reported in the literature; however, these wastes are minor
(typically about 190 m3/day or 50,000 gpd) and are probably relatively
insensitive to plant size beyond 500 MW.
The auxiliary cooling water systems can be either once-through or
recirculating type. The flow-through the once-through system ranges fro»
1.9-133 lit/min (0.5-35 gpm) per MW with a typical value of approximatel
40 lit/min (10 gpm) per MW. This total flow represents the wastewater
stream. In closed systems, the recirculation rate is typically 91-95
lit/min (23-25 gpm) per MW. Blowdown from this system is reported to b
0-19 lit/day (0-5 gpd) per MW (13).
Sanitary wastes in a 1,000-MW coal-fired plant employing about 200
people is usually about 26.5 m3/day (7,000 gpd). Wastes from washina *
3-132
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intake screens are minor and contain mainly suspended solids. Conse-
quently, there impact on the overall water balance and treatment tech-
nology can be considered insignificant.
3.8.2 Waste Characteristics
Laboratory and sampling wastes contain pollutants from the plant
stream being tested as well as the reagents used for measuring their
concentrations. Data for the quality of laboratory and sampling wastes
are not available [5, 12].
The once-through auxiliary cooling water systems are not chemically
treated except for occasional shock chlorination [5, 12]. The closed
systems employ high purity makeup water. In general, chromates are used
up to the 250-mg/Jl level with caustic soda to maintain pH at 9.5 to 10.
Borate and nitrate corrosion system is also used to levels between 500
and 2000 mg/&. Generally, there is no loss from these closed systems
except during maintenance cleaning. This cleaning frequency is about
once every three years [5].
The sanitary wastes are similar to domestic sewage except that the
per capita hydraulic loading is small [.085-.132 m3 (25-35 gal) per day
* o
in the power plant vs. .378-.567 m-5 (100-150 gal) per day for domestic
sewage]. The sanitary wastes from a coal-fired plant can be estimated
in Table 3.40.
3.8.3 Treatment Options
The laboratory and sampling wastes can be treated in a manner similar
to the water treatment wastes. Some of the treatment possibilities men-
tioned for condenser cooling systems can be adapted for auxiliary cooling
ater systems. The sanitary wastes can be treated in packaged treatment
plants or the wastes can be sent to POTW for disposal [5]. Usually these
miscellaneous wastewaters are not treated separately but combined with
ther streams for central treatment, (See Section 5.2.)
3.8.4 Recycle/Reuse
The above mentioned miscellaneous wastes are minor in nature and
they can potentially be sent to a bottom ash pond for reuse (except for
sanitary wastes).
3-133
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Source: [5]
Table 3.40
Sanitary Wastes in Power Plants
Administrative
Personnel
Flow
BOD-5
TSS
m /day (gpd) gm (Ib) gm (lb)
0.095 (25) 30 (0.07) 70 (0.15)
Plant Personnel
0.133 (85) 40 (0.09) 85 (0.19)
3-134
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3.9 Maintenance Cleaning Wastes
3.9.1 Description of Operations
Periodic maintenance cleaning of boiler tubes, boiler fireside, air
preheater, condenser, feedwater heaters, miscellaneous small equipment,
stack and cooling tower basin is essential in a power plant to preserve
the cycle efficiencies. The quantity and quality of resulting aqueous
wastes are determined by the plant operating and maintenance procedures
as well as the cleaning practices followed by the utility.
Boiler Tube Cleaning
A variety of cleaning formulations are used to chemically clean
boilers whose operation has deteriorated due to buildup of scale and
corrosion products. Analyses of scale deposits are made on sample sec-
tions of tubes cut from the boiler. Based on the composition of scale
discovered in these samples, a cleaning program is selected. The cleaning
program may employ soak or circulation methods. In the former method,
the boiler is filled with the cleaning solution and held stagnant (at the
appropriate temperature) until the desired degree of cleaning is achieved.
In the circulation method, the cleaning solution is circulated through
the boiler internals [13].
Alkaline cleaning mixtures with oxidizing agents are used for cop-
per removal. These formulations may contain free ammonia and ammonium
salts, (sulfate or carbonate), an oxidizing agent such as potassium or
sodium bromate or chlorate, or ammonium persulfate, nitrates or nitrites,
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 and ammonia reacts with the cop-
per 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.
3-135
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Acid cleaning mixtures are usually based on inhibited hydrochloric
acid as solvent, although sulfuric, phosphoric, nitric and organic acids
are also used. Hydrofluoric acid or fluoride salts are added for silica
removal. Corrosion inhibitors, wetting agents, coaplexing agents to
solubilize copper may also be included. The organic acids such as EDTA
oxalic, citric, gluconic, acetic, sulfamic, and formic acids are being
used increasingly because they are less toxic and easier to handle than
hydrochloric acid [57]. These acid mixtures are effective in removal
of scale due to water hardness, iron oxides, and copper oxide, but not
metallic copper.
Alkaline chelating rinses and alkaline passivating rinses formula-
tions contain ammonia, caustic soda or soda ash, EDTA, NTA, citrates,
gluconates, or other chelating agents, and may contain certain phos-
phates, chroma tea, nitrates, or nitrites as corrosion inhibitors. These
cleaning mixtures may be used alone, or after acid cleaning to neutralise
residual acidity and to remove additional amounts of iron, copper,
alkaline earth scale compounds, and silica.
Finally, proprietary processes (e.g., Vertan, Citrisolov, etc.),
offered by specialized companies, are also used for cleaning boiler
tubes. These processes utilize chemicals which are similar to those used
In the formulations mentioned earlier.
Waste streams from the soaking method which consist of:
• an add Iron waste in which the iron is not
chelsted with the cleaning solvent,
• an alkaline copper waste in which the copper
is strongly complexed with ammonia, and
• a neutralization drain.
The waste streams from the circulation method usually consist of:
• an acid iron waste in which the iron is chelated with
cleaning solvent such as citric acid, and
• a neutralization drain.
3-136
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Condenser Cleaning
The second major heat transfer component in a power plant is the
condenser. Condenser tubes are made out of stainless steel, titanium,
or copper alloys. 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 [19].
Boiler Fireside Cleaning
The fireside of boiler tubes collects fuel ash, corrosion products
and airborne dust. 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.
Air Preheater Cleaning
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 with high-pressure fire hoses. The washing fluid
may contain soda ash and phosphates or detergents which are added to
neutralize excess acidity.
Feedwater Heaters Cleaning
The number of closed feedwater heaters in the preboiler cycle ranges
from 4 to 10. Tubes may be formed from admiralty brass; 90/10, 80/20,
70/30 cupro-nickel; monel and arsenical copper in the nonferrous group
and carbon steel and stainless steel in the ferrous family. Tube sizes
are 15.8 - 19.5 millimeter (5/8" or 3/4") O.D. by 4.5 - 24.2 meters (15' - 80')
long. They may be straight or hairpin bent tubes. Feedwater flows through the
tubes, extracting heat from the steam which surrounds the tubes.
Operational cleaning in general has not been required on the ferrous
alloy tubes. Deposits found on the water side of the copper alloy tubing
have been predominantly copper and iron oxides. The common solvent used
has been 5-20% hydrochloric acid, circulated for six to eight hours at a
temperature of 66°C (150°F). Neutralization of the system is often
accomplished by circulating a 0.5-1.0% soda ash or caustic soda solution
for two to three hours at 49-66°C (120-150°F) followed by rinsing with
demineralized water.
3-137
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Miscellaneous Small Equipment Cleaning
Occasionally, other plant components such as condensate coolers,
hydrogen coolers, air compressor coolers, stator oil coolers, etc. are
cleaned chemically. Inhibited hydrochloric acid is the common chemical
used for cleaning. Detergents and wetting agents are also added when
necessary. The waste volume is, of course, smaller than that encoun-
tered in other types of chemical cleaning.
Stack Cleaning
Depending upon the fossil fuel used, the stack may have deposits
of fly ash, and soot. Acidity in these deposits can be imparted by the
sulfur oxides in the flue gases. If a 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,
Cooling Tower Basin Cleaning
Depending upon the quality of the makeup water used in the cooling
tower, carbonates can be deposited in the tower basin,; silt and sand al
accumulate here. 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
moval of sludge is carried out usually with front end loader and truck
3.9.2 Waste Characteristics
Wastes resulting from maintenance cleaning operations are inter-
mittent in nature and are characterized by extreme pH ranges, high
toxlcity and instantaneous large volumes. Chemical cleaning wastes
contain scale constituents and the chemicals used for cleaning. Wast
from air preheater washing are generally acidic (pH being dependent upon
the SOX concentration in flue gases) and contain a large concentration
of iron. Wastes from washing of stack and cooling tower basin originate
less frequently than others and their composition depends upon FGD
system and cooling tower performance, respectively.
3-138
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The range of wastewater flows from maintenance cleaning is summarized
in Table 3.41. The range of wastewater composition is shown in Table 3.42,
Steiner, et al. [99] report on characteristics of metal cleaning wastes
at TVA plants and indicate a volume of 1136 to 3400 cubic meters (300,000 to
900,000 gallons) per cleaning excluding hydroejectors used to discharge
the cleaning solution from the boiler. Additional data from a number of
plants are reported in a recent EPA study [101 ].
3.9.3 Treatment Options
The most significant of the periodic wastes in terms of potential
environmental impact are the metal cleaning wastes. Pollutants in metal
cleaning wastes include chemicals used for cleaning of metal and depos-
its removed by cleaning. However, options for process modification are
minimal and end of pipe treatment is required. Three basic methodologies
are available:
• incineration
• ash basin treatment
• physical-chemical treatment
Incineration
With increasing use of organics, incineration has gained in popular-
ity. Some utilities have employed incineration for these wastes from
various types of cleaning including ammoniated EDTA, ammoniacal bromate,
citric acid, hydroxy acetic acid/formic acid containing ammonium bifluor-
ide. [101] Incineration involves controlled injection of spent boiler
cleaning chemicals into the furnace of an operational boiler.
Air Basin Treatment
Ash ponds are used to treat boiler cleaning wastes [101]. The theory
is that ash ponds can be the equivalent of conventional lime treatment
providing the ash is alkaline. (Many fly ashes are alkaline). In one
demonstration project 0.12], other factors including the effect of dilution
in breaking the ammonia complex bond for ammoniated bromate wastes was also
considered important.
3-139
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Table 3.41
Wastewater Flow Range - Maintenance Cleaning
Boiler Tubes
Boiler Fireside
Air Preheater
Miscellaneous
Small Equipment
Stack
Cooling Tower Basin
Flow/Volume
Range
3-5 boiler volumes
24-720 x 103 gal
43-600 x 103 gal
No Data
No Data
No Data
Frequency
once/7 months-
once/100 months
2-8/year
4-12/year
Typical
FlQW/Vo] imio
1 boiler/1-2
hours
300,000 gal
200,000 gal
Source: T5]
3-140
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Table 3.42
Raw Waste Flow and Loadings - Maintenance Cleaning
ft.' of Plants in Survey
f^ffWAter Source
Cleaning Frequency
{»h*
jpj^-finno liter)
Para9eter (kg)
lODf
trovf.de (Bromate)
ODD
Chroiniu* (Total)
— """.. +*
Oi*o«iu»
Cot»p«*
Cyanide (Total)
Iron
lickel
HJ. and Grease
iboflphate (Total)
otal Dissolved
Solid*
^^l~Su«pended
' Solid*
rSSTs^lida
««rf»ctanta
zinc
_ °
7 plants
Air Preheater
4-12
163-2,271
Kg
0-6.82
-_—
2.6-15,9
0.21-26,88
— —
0-2.02
0.97-3862
8,14-170,38
Q.Q2-2.66
1,448-20,096
217-4,898
1.188-29.744
0. 13-11.36
2 jplanta
Boiler Fireside
2-8
91-2,725
Kg
0
8.63-515.00
0.01-0.45
0-0.11
13.63-408.90
0-13.63
0,12-5.04
1,363-15,948
54,07-1,736
1.817-18.551
0.91-13.04
7 plants
Boiler Tubes
0-2
568-18,622
Kg
0.45-19,387
0.21-10,524
0.06-931,185
0.51-595.96
42,592-133,826
— — _
0.02-3.48
111.11-43,598
0-1,590
111.11-48,868
..
0.35-391,098
Source: [5]
3-141
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Physical/Chemical Treatment
A number of treatment schemes employing physical/chemical processes
have been tested, designed, and implemented for the treatment of boiler
chemical cleaning wastes. The basic mechanism behind these treatment
schemes involves neutralization with caustic or lime followed by precipi-
tation of the metal-hydroxide compounds [101]. However, there are a
number of additional unit processes which have been employed on certain
waste chemical solutions in order to increase the degree of attainable
reduction of certain constituents. These additional unit processes
include: mixing with other metal cleaning waste source, oxidation,
sulfide addition, filtration, membrane technology, and carbon adsorption.
In the treatment of waste boiler chemical cleaning solutions, the use of
these unit processes, either alone or in combination with others, is
dependent upon which waste solution is being treated. Various characteris-
tics of individual waste streams make the use of certain unit processes
feasible. The overall scheme has to be highly system specific.
Since the maintenance cleaning wastes are intermittent in nature
flov equalization is necessary prior to treatment. The storage require-
ments can be minimized by scheduling the cleaning frequencies on a con-
trolled basis. As was noted for many other wastewater streams, main-
tenance cleaning wastes are often mixed with other streams and treated
in a control treatment facility see Section 5.2). However, specific
treatment for heavy metals and organics removal has been practiced. In
many cases, control treatment of maintenance cleaning wastes may be
viable.
Heavy metals (Cu, Fe) from the maintenance cleaning wastes can be
removed as insoluble hydroxides by lime addition [5]. The dissociation
of completed copper (copper-ammonia, copper-ammonia-EDTA) may require
ammonia stripping to facilitate copper precipitation by lime. The pres-
ence of other heavy metals (mainly iron) from air preheating wastes will
also facilitate the dissociation of copper complexes because of compe-
tition for hydroxyl ions. Oxidizing ions (such as chlorates and bromates)
used for copper removal can be decomposed by reduction (to chloride and
bromide ions).
3-142
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Some specific treatment methods are:
• The iron waste from the soaking method can be treated by
chemical neutralization of pH 9 with lime followed by
sedimentation. TVA [91] has demonstrated that this acid
iron waste can be treated in alkaline ash ponds that have a
pH greater than 9. The high iron concentration in the waste
will precipitate and be retained in the alkaline ash pond.
• Iron waste from the circulation method may not be effect-
ively treated by conventional chemical neutralization-pre-
cipitation processes because of complex compounds such as
iron citrate [ 91J. The structure of the complexing agent
appears to determine the effectiveness of treatment. Bench-
scale tests performed at TVA indicated [91] that iron could
be removed from the citric acid cleaning waste from 4,000
mg/1 to less than 1 mg/1 at the high pH level of 13.
9 The copper waste from the soaking method cannot be reduced
to a copper concentration of less than 1 mg/1 by chemical
neutralization alone because of the strong, complex copper-
ammonia compounds. Other treatment processes such as aera-
tion plus chemical neutralization-precipitation, chemical
precipitation with sodium sulfide, ion exchange, and reverse
osmosis can reduce the copper concentration to less than 1 mg/1
[96]. Aeration plus chemical precipitation can remove both
copper and ammonia, however, column stripping may not be
practical because of the scaling problem in the stripping
tower. Chemical precipitation with sodium sulfide to break
the complex copper-ammonia bonding is attractive, but post-
treatment of residual sulfide would be required to control
hydrogen sulfide gas evolution.
Reverse osmosis is a feasible method to remove copper after neutraliza-
tion and precipitation has removed the bulk of the solubles in the waste.
Thus some pretreatment states are required (to avoid the scaling problem in
the membrane modules at high-volume recovery). Incineration of the copper
waste in the steam plant furnace [95] is another alternative.
3-143
-------
The incineration method may require extensive monitoring
studies to ensure that copper would not redissolve in the
ash sluice water and to assess the increase in levels of
NO in the stack gas, which results from incinerating
A
the nitrogen compounds.
Chu [96] reports that TVA has investigated a process of treating the
copper waste in alkaline ash ponds. It was found that the chelated copper-
ammonia bonds can be broken by dilution with ash pond water, after which
copper ion is precipitated at alkaline pH levels. Also, copper adsorbs on
fly ash. Although the adsorption capacity of copper on fly ash is limited
(about 4.7 yg copper per gram of fly ash), the additional copper removal
by ash adsorption can ensure the reduction of copper concentration (exclud-
ing the dilution factor) to less than 1 mg/1.
Steiner, et al. [99] based on bench-scale tests on TVA wastes,
concludes that in general, six methods of treatment of metal cleaning wastes
(which include acid, alkaline and passivation wastes) are potentially availabl
a. Treatment of acid wastes in alkaline ash ponds.
b. Treatment of alkaline wastes in alkaline ash ponds.
At four TVA plants where ammoniated bromate is used,
it is reported that treatment would require five
steps:
1. Maintain the pH of the ash pond above 8.5.
2. Hold the waste for several days in the holding
pond to allow evolution of excess ammonia and
precipitation of some copper.
3. Discharge the waste from the holding pond into
the ash pond near the fly ash sluice pipe to
optimize copper adsorption on fly ash.
4. Discharge the waste from the holding pond at a
rate dependent on the copper and ammonia concen-
trations in the waste and the flow rate of the
ash pond.
3-144
-------
5. Maintain an approximate retention time in the ash
pond of about 10 hours.
c. Combined chemical treatment.
d. Chemical treatment of acid and passivation wastes.
e.. Chemical treatment of alkaline wastes.
f. Treatment of suspended metals.
In most of the above methods, pH control is used as a key variable.
Hittman Associates recently initiated a study [58] for the EPA to
evaluate lime treatment of boiler cleaning wastes. This study, now
under way, will evaluate the application of lime precipitation to boiler
cleaning wastes to destabilize metal chelates and complexes. The plan
of work includes the following:
• Perform an engineering analysis (including types of
deposits to be removed, type of metal to be cleaned,
cleaning economics, etc.) of several chemical
cleaning systems applicable to waterside boiler tube
cleaning.
• Perform lime precipitation, fireside wastewater
dilution, flocculation and sedimentation bench-scale
tests on selected boiler cleaning wastewater samples,
so as to select the optimum wastewater control proc-
ess scheme.
• Evaluate the performance of an existing full-scale,
lime precipitation, boiler tube cleaning wastewater
treatment system employing the previously selected
optimum treatment scheme.
The overall objective of this effort is to determine the effective-
ness of lime precipitation in meeting effluent guideline limitation of
1 tng/£ f°r iron an(* copper in the treated wastewater from boiler cleaning.
Chemical cleaning wastes containing organic compounds can be dis-
posed by incineration [5, 57]. Some of the organic acids (citric acid,
eluconic acid) are biodegradable and the cleaning wastes which contain
these acids can be disposed by biological methods [57].
3-145
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3.10 Drainage
3.10.1 Description
The principal wastewater streams comprising drainage are discussed
below:
a. Floor and Yard Drains; These collect wastes from leakage,
numerous cleaning operations, and process spills and leaks.
Often the wastewater contains dust, fly ash, coal dust,
oil and detergents [12]. Such wastes are at present
discharged to POTW in many cases.
b. Coal Pile Runoff; Coal-fired power plants require the
storage of large quantities of coal, at or near the
site, to both ensure continuous plant operation and
simplify delivery by the supplier. Normally, a supply
of 90 days is maintained. Storage piles are generally
8 to 12 meters (25-40 ft) high, spread over an area of
several square meters (or acres). Typically, from
600 to 1800 cubic meters (780 to 2340 cu yds) are
required for coal storage for every MW of rated
capacity [5]. Therefore, a 1000-MW plant would
require from 600,000 to 1,800,000 cubic meters
(780,000 to 2,340,000 cu yards) of storage. Depend-
ing on coal pile height, this represents between
60,000 and 300,000 square meters (15 to 75 acres) of
coal storage. Coal pile reserves are stored in either
active or inactive storage piles. Active storage piles
are usually open and exposed to all weather conditions
Inactive piles are generally sealed with a tar spray or
some other impervious covering which provides protection
from the weather. Consequently, only runoff from active
coal storage piles is of major concern.
3-146
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3.10.2 Waste Characteristics
a. Floor and Yard Drains; These are usually a minor stream but
vary widely in total volume. With proper operating procedures,
these can be minimized. In some of the open or dry areas of
the country some plants do not need and do not have yard drains
[5]. Typical characteristics of yard and floor drains are
listed in Table 3.37.
b. Coal Pile Run-Off; Surface run-off and seepage from coal piles
constitute coal pile runoff. Table 3.43 presents some typical
coal piles and the volume of run-off.
Waste discharges from coal piles can be acidic or alkaline
[12]. Acid drainage is the result of the reaction of pyrites
(FeS2) with water and oxygen (in air) which produces iron
sulfate and sulfuric acid. Such drainage is highly acidic and
often contains aluminum. Alkaline discharges occur when the
acidic discharge is neutralized by other materials in the coal.
Alkaline drainage has a pH of 6.5 to 7.5 or more, and has fer-
rous salts. If the pH and concentration are high enough, iron
may precipitate by oxidation and hydrolysis. In addition, coal
pile drainage contains high concentrations of other dissolved
solids and significant amounts of copper, zinc and manganese.
Some coal pile runoff data are presented in Table 3.44.
A recent study [61] undertaken by the TVA to characterize coal
pile drainage at two TVA coal-fired power plants concludes that;
"1. Coal pile drainage is a highly acidic waste stream
containing high concentrations of iron, manganese,
sulfate, TDS, and a variety of trace elements.
2. About 73% of total rainfall results as direct runoff.
3. Shaker type elution studies in the lab cannot, at
least at the time, be used to predict runoff quality.
4. Coal pile drainage can effectively be treated with
alkaline fly ash."
3-147
-------
H-1
*-
OO
Table 3.43
Coal Pile Drainage
Coal Consumed/Day Area of Pile Height of Pile
Annual Average
Rainfall
Runoff Per Year
IbxlO*
15
15
20.6
14.34
kgxlO6
6.81
6.81
9.35
6.51
Acres
25
75
18
21
M*xlOJ
101.85
305.55
73.33
85.55
Ft.
40
17
40
25
Meters
12.19
5.18
12.19
7.62
Inches
44
54.7
45.84
43.1
Meters
1.117
1.389
1.164
1.094
Million
Gallons
20
25
25
17
MJxlOJ
75.7
94.62
94.62
64.34
For illustrative purposes only.
Source [5]
-------
Table 3.44
Typical Coal Pile Runoff Characteristics
Plant No. TDS TSS pH
(mg/ft) (mg/l.)
720
610
2.8
Copper Zinc Iron Magnesium
(mg/Jt) (mg/&) (mg/Jl) (mg/jQ
1.6
1.6
0.17
7,743
22
3.0
2.4
u>
5,800
200
4.4
0.006 174
44,050
950
2.8
3.4
23.0
93,000
For illustrative purposes only.
Source [5]
-------
3.10.3 Treatment Options
The drainage from coal piles is acidic; hence, the solubility of
iron, manganese, and some other trace metals are increased. If the
drainage is discharged to a receiving stream, some degree of treatment
may be required to prevent adverse environmental impact. Treatment
of coal pile drainage could be achieved by collecting and diverting the
drainage to a storage basin for coal fine settling and for pH adjust-
ment with lime before discharge to the river.
The extent of contamination from coal pile runoff can be sub-
stantially reduced by proper construction of the coal storage area.
Inactive coal piles can be sprayed with tar or covered with plastic
sheeting to seal the surface to water infiltration. In areas where the
rate of evaporation is higher than the rate of precipitation, runoff
can be disposed of by evaporation in ponds. Alternatively, a drainage
system can be constructed so as to collect the coal pile drainage and
use it in processes which tolerate low quality waters such as ash hand-
ling systems. If the plant is located near a mine, such water can be
used in the coal washers to remove mineral matter.
Systems to collect coal pile runoff installed in recent years vary
considerably in both complexity and costs. Elaborate collection systems
would be required at some plants where unusual terrain conditions and
space limitations exist. At one midwestem plant of about 1,000-MW
capability a new system collects runoff by gravity in a concrete basin
from which it is pumped to an adjacent ash settling basin. The collection
and treatment systems would cost (mid-1978 dollars) about $800,000 to
install. On the other hand, at one Eastern plant such collection is
accomplished merely by grading the adjacent areas to route run-off by
gravity to an existing ash pond. Such a system would cost (mid-1978
dollars) about $31,000 to install. These are updates on cost data (to
mid-1978 levels) reported in the literature [5,12].
It is reported that at TVA [91,96], the present strategy for dis-
charge of coal pile drainage is to route it through the ash pond before
it is discharged into receiving streams. The ratio of total coal pile
3-150
-------
drainage flow to total ash pond discharge flow averages 0.001 to 0.012
at TVA's 12 coal-fired power plants. The iron in the coal pile drain-
age can be removed to less than 1 mg/£ after it is combined with ash
pond water having a pH above 6 [96], Concentrations of trace metals are
lower after dilution of the coal pile drainage with alkaline ash pond
water; most of these trace metals precipitate on machinery near neutral
or slightly alkaline pH values.
3-151
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4.0 REGULATORY CONSIDERATIONS
4.1 Existing and Proposed Regulations
Existing regulations covering waste water discharges from steam-
electric power plants are given in the Code of Federal Regulations (CFR),
Part 423. They were formulated following the industry study which
resulted in the publication of the Development Document in October, 1974 [5].
4.1.1 Waste Water Discharges Requiring NPDES Permit
A summary of National Pollutant Discharge Elimination System (NPDES)
guidelines and standards for chemical parameters in steam-electric power
plant effluents is given in Table 4.1. Eight waste streams from plant
sites are regulated individually and the guidelines for each vary with
the size of the generating units. Thermal effluents are similarly regulated
by the size of the unit but an additional factor, the unit's age, is
accounted for, as shown in Table 4.2.
The EPA's Effluent Guidelines Division is reconsidering several
regulations successfully challenged by the industry in the courts. The
remanded regulations included thermal discharges; zero discharge of TSS
from fly ash ponds for new sources; and portions of the area runoff regula-
tions (excluding coal piles and chemical handling areas). New regulations
have not yet been proposed and may not be for some time. The impact of
this court-ordered remand on discharge permits may not be significant
since states and/or regional EPA offices where NPDES discharge permits
are issued have a fairly wide latitude in using their own judgment and
consideration of local and site specific factors in writing permits.
The existing regulations do exert some limited pressure, primarily
on new plants, to increase the amount of water recycled and reused. The
specific areas involved are: fly ash transport water, cooling tower
blowdown, and heat from main condenser cooling water.
BAT guidelines for cooling tower blowdown are less stringent than
NSPS (no detectable amount) which provide a more significant inducement
for recycling water in existing units. In many cases it would be less
costly to treat the used water for reuse rather than to meet the more
4-1
-------
Table 4.1
Summary of Wastewater Guidelines and Standards for Steam Electric Power Plants
(excluding heated discharges)
u*:.7E STREAMS
1. Lov Volunt Waste Sources
2. Ash Transport Water
(Bottom and/or Fly)
\
3. Mrt;il Cleaning Wastes.
4. Boiler Slowdown
5. Once-through Cooling
Vater
6. Cooling Tower Slowdown
7. All of above (except f5
for pi!)
8. Material Storage and
Construction Runoff (up
Co li> vr.-2« hr. Rainfall
Source: 40 CFR 423
PAJtAMETEK
TSS
O&G
TSS
OiC
TSS
o&c
Cu (Tot.)
Fo (T»t.)
Tree Cl
Free Cl
Zn
Cr
P
Corrosion
Inhibitors
pH, units
PCB's
TSS
PH
EFFLUENT corcnnnATiows (»g/i)t AVERAGE (MAXIMUM)
SUBPAKT At CFNF.PATINC
BPT BAT
30(100) 30(100)
15(20) 15(20)
30(100) 30(100)
15(20) 15(20)
30(100) 30(100)
15(20) 13(20)
1(1) 1(1)
1(1) 1(1)
.2(.3) .2(.5)
.J(.5) ,2(.5)
- 1<1>
- .2(.2)
- 5£5J
— caap-by
case
6-9 6-9
0 0
-(30) -(30)
6-9 6-9
WITS
W5FS
30(100)
15(20)
P:Non«
6:30(100)
F:None
8*15(20)
TO (100)
15(20)
1(1)
1(1)
.2(.5)
.2(.3)
Wo
detect-
able
a -wont
6-9
0
-(50)
6-9
Si'PrART B: SMALL WITS
BPT BAT
30(100) 30(100)
13(20) 13(20)
30(100) 30(100)
13(20) 13(20)
30(100) 30(100)
15(20) 15(20)
1(1) KD
1(1) 1(1)
.2(.3) .J(.5)
.2(.S) .2(.3)
— KD
.2(.2)
— 5(5;
case-by
cose
6-9 6-9
0 0
-(50) -(50)
6-9 6-9
NSPS
30(100)
15(20)
30(100)
15(20)
30(lJO)
15(20)
1(1)
1(1)
.2(.5)
•2(.5)
No
detect-
able
amount
6-9
0
-(50)
6-9
SUSPART C: OLD VNITS
BrT IAT
30(100) 30(100)
15(20) 15(20)
30(100) 30(100)
15(20) 15.CO)
30(100) 30(100)
15(20) 15(20)
1(1) 1(1)
1(1) . 1(1)
.2(.5) .2(.5)
.2(.5) .2(.5)
— 1(1)
.2(.:>
— 5(5) !
-- case-by
caoc
6-9 6-9 '
O 0
-(50) -(50)
6-9 6-9
F (Fly Ash) B (Bottom Ash)
-------
Table 4.2
Summary of Effluent Limitations Guidelines and Standards for Heat*
All no-discharge limitations allow for blowdown to be discharged at a temperature not to exceed the cold-side
temperature, except where a unit has existing closed-cycle cooling blowdown may exceed the cold-side temperature.
All limitations for existing units to be achieved by no later than July 1, 1981, except where system reliability
would be seriously impacted, the compliance date can be extended to no later than July 1, 1983.
EXISTING GENTHATIMG USITS
Capacity 500 MW and greater
Placed into service prior to January 1, 1970
Placed into service January 1, 1970 to thereafter
Capacity 25 MW to 499 MW
Placed into service prior to January 1, 197A
Placed into service January 1, 1974 or thereafter
Capacity less than 25 MW
NO LIMITATION
NO DISCHARGEt
NO LIMITATION
NO DISCUARGEt
NO LIMITATION
Mtote: Exceptions prescribed on a case-by-case basis for units in systems of less
than 150 MW capacity, units with cooling ponds or cooling lakes, units wi-th-
• out sufficient land available, units vith blowdown TDS 30,000 mg/1 or greater
and neighboring land within 500 ft. of cooling tower(s), and units where FAA
finds a hazard to .commercial aviation would exist.
I.TW 50'JPCES
NO DISCHARGE
*Notes: No effluent limitations on heat from sources other than main condenser cooling water.
Source: 40 CFR 423
-------
strict discharge requirements. New and recently built sources cannot
discharge heated main condenser water except under unusual cooling cir-
cumstances. New,sources are essentially forced to use a recycle system
(with discharge of heated blowdown allowed) while older recently built
systems have additional options. It is currently believed that while
zero discharge under BAT may still be a distant goal, recent focus has
been on priority pollutants discussed later.
4.1.2 Discharges to a Publicly Owned Treatment Works (POTW)
It is estimated [98] that 250 steam-electric power plants in the
United States discharge some wastes to Publicly Owned Treatment Works '
(POTW). A significant fraction of these discharges (by number) may consist
only of sanitary wastes since, in a separate report [12], the number of
steam-electric power plants discharging "chemical" wastes to a POTW was
estimated to be 98% (7.7% of the 1,273 plants in the United States).
The EPA1s special treatment report for steam-electric power plants
[12,98] recommended the promulgation of pretreatment standards for all
existing dischargers to POTW's. The recommended standards are not so
stringent with regard to chemical parameters as to provide incentive for
increased recycle/reuse of water. The recommended maximum level for
Poly Chlorinated Biphenyls (PCB's) was "no discharge"; for copper, 1 mg/£.
and, for oil and grease, 100 mg/fc.
On June 26, 1978, the EPA revised its general pretreatment standards
such that they now apply to both new and existing sources. 40 CFR 128
was replaced by a new 40 CFR 403. These regulations do not list specific
parameters and associated concentrations and/or loadings of pollutants.
Such standards will be established separately. The June 26, 1978 regula-
tions do provide the rationale for subsequent establishment of industry-
specific standards — they will be technology based, i.e., best available
technology economically achievable. The general standards contain the
standard prohibitions against the discharge of waste which could create
a fire hazard, corrosion problems, obstruction problems, or POTW upsets.
These upsets are predominantly due to the inhibition of biological
treatment processes. Table 4.3 lists the threshold concentrations of
4-4
-------
Table 4.3
Threshold Concentrations of Pollutants That Are
Inhibitory to Biological Treatment Processes
Process
Pollutant
Ammonia
Arsenic
Borate (Boron)
Cadmium
Calcium
Chromium
(Hexavalent)
Chromium
(Trivalent)
Copper
Cyanide
Iron
Lead
Manganese
Magnesium
Mercury
Nickel
Silver
Sodium
Sulfate
Sulfide
Zinc
Phenols :
Phenol
Cresol
2-4 DinitrophenoH
Activated Sludge
(mg/H)
480
0.1
0.05-100
10-100
2,500
1-10
50
1.0
0.1-5
1,000
0.1
10
0.1-5.0
1.0-2.5
5
0.08-10
200
Aerobic Digestion Nitrification
(mg/2,) (rog/&)
1,500
1.6
2
0.02
1
50 0.25
50-500
1.0-10 0.005-0.5
4 0.34
5
0.5
1,000 50
1,365
0.25
3,500
500
50
5-20 0.08-0.5
4-10
4-16
150
Source: [99]
4-5
-------
several pollutants that may inhibit biological treatment processes.
Oil and grease, although not in this table, can also be inhibitory;
in excessive amounts, they can lower the density of floe in an activated
sludge wastewater system to the point where the sludge settling properties
are destroyed. A concentration of 50 mg/Jl of oil and grease in the
influent to an activated sludge system would probably not be inhibitory.
The June 26, 1978, general pretreatment regulations are sufficiently
flexible that local POTW's continue to have a major responsibility in
setting specific standards and enforcing them. Thus, the federal pre-
treatment standards provide little or no inducement for increased water
recycle and reuse. The fees charged by POTWs, often related to flows
and waste loads, are more likely to be an inducement to recycle. When,
and if, specific chemicals and concentrations are specified by EPA, it
is possible that some pressure for increased recycle and reuse will
result, since the cost for treatment for recycle could be lower than the
cost of pretreatment for discharge to a POTW.
4.1.3 Water Intakes
As required by Section 316(b) of the Federal Water Pollution Control
Act (FWPCA) Amendments of 1972, the EPA has required (40 CFR 402) that a
determination be made whether the location, design, construction, and
capacity of cooling water intake structures (for new sources) reflect the
best technology available for minimizing environmental impact. A key
concern is to minimize the entrainment and entrapment of fish and other
aquatic life. A Development Document covering this subject area has
been prepared by the EPA.
Even though the regulations issued on intake structures are broad
and non-specific, they were challenged by the industry. The industry
recently won a court-ordered remand (to the EPA for further consideratio \
but the impact of this is expected to be inconsequential because of;
• the nonspecificity of the initial regulations, and
• the flexibility available at the state and regional EPA office
for control of power plant designs and associated permits.
4-6
-------
There are, apparently, no plans at present by the EPA to revise and
reissue intake regulations in the near future.
It is not clear, at present, just how many new sources will be
forced to use a closed-circuit cooling system as a result of the 316(b)
regulations. It is likely to be a critical factor only in those cases
where an intake is to be located in important spawning areas. Even here,
an intake associated with a once-through system may be approved if it is
designed (as it is possible to do) to keep intake velocities below (0.5
to 0.8 ft/sec).
4.1.4 Remand Decision
The U.S. Court of Appeals for the Fourth Circuit reviewed petitions
by a number of utilities against certain aspects of EPA regulations con-
cerning aqueous effluents from power plants. On July 16, 1976, the Court
decided that the following regulations in Chapter 40 CFR should be set
aside and remanded to the EPA for further consideration:
• §423.12(a) effluent limitation variances for BATEA,
• §423.13(1)(m) thermal backfit requirements,
• §423.13(1) ban on cooling lakes in closed-cycle cooling systems,
• §423.40 through 423.43 rainfall runoff limitations for material
storage and construction site runoff, and
• §423.15(e) and 423.25(3) no-discharge limitation for fly ash
transport water.
In addition, the Court directed that the EPA reevaluate (a) its
requirements for closed-cycle cooling at generating units located along the
nation's coastlines, and (b) its refusal to create a subcategory for
AEC approved nuclear generating stations. They further direct the EPA
to include a variance provision for new sources in accordance with this
opinion.
The remand decision was based on the following considerations:
• that the EPA did not adequately consider the balance of costs and
environmental benefits of its thermal backfit requirements; EPA's
contention that such an analysis was beyond the state-of-the-art
was not accepted by the court;
4-7
-------
• that guidelines for granting of variances from the regulations
must include economic considerations and environmental issues
unrelated to water quality (cross media impacts);
• that the EPA should consider more thoroughly the impact of its
ban on cooling lakes with respect to the consumptive use of
water, particularly in arid regions;
• that the EPA had not presented sufficient data to show that its
recommended technology for the control of suspended solids in
runoff (settling ponds) would achieve the required effluent
concentration of 50 mg/Jl;
• and that the EPA had not presented sufficient data to demonstrate
that dry ash handling was an available technology.
The court ruled in favor of the EPA in its implementation of
Section 316(a) of FWPCA, finding that a demonstration of compliance
with state water quality standards was not sufficient to show assurance
of the protection and propagation of a balanced, indigenous population
of shellfish, fish and wildlife.
As a result of the Remand Decision and other factors (namely the
Consent Decree discussed in Section 4.1.5 and the Clean Water Act of
1977 discussed in Section 4.2.2) the Effluent Guidelines Division of
the EPA undertook additional studies and evaluation with the objective
of appropriately revising effluent guidelines for the steam electric
industry (SIC 4911). A Technical Report in support of such efforts was
issued in January 1979 [101]. Revisions to effluent guidelines for
this industry are anticipated late 1979.
Some potential developments on some aspects of the Remand Decision
are:
a. Dry Ash Handling. Dry ash handling is practiced at many
plants today. It may be possible to gather data on such
dry handling systems and if appropriate use the data base
to require dry ash handling for new plants. Some organi-
zations have found that dry ash handling for new plants
4-8
-------
may be the more economical choice if environmental
factors, cost of land, aesthetics and all other con-
siderations are included. It is noted that 68% of the
power plants have dry collection and unloading facilities
for fly ash [52].
b. Technology for Control of Suspended Solids in Runoff.
The 50 mg/2. limit for TSS may be a difficult one to
achieve; however, conventional collection and retention
basins for runoff and treatment of the latter to a
reasonable degree may be feasible.
4,1.5 Priority Pollutant Removal
In June 1976, the EPA entered into a settlement agreement (consent
decree) as the result of a court case by three public environmental
action groups. The case gave the EPA a mandate to regulate effluents
containing any of the agreed-upon priority pollutants. Steam-electric
power plants have a number two priority on the list of 21 industrial
categories to be regulated. In early 1979, the EPA was nearly on
schedule with regard to the schedule requirements of the agreement. The
Technical Report has been issued [101]. Revised effluent guidelines
setting limitations on the discharge of any consent-decree compounds
will be proposed by mid-1979.
Table 4.4 presents a list of priority pollutants potentially pre-
sent in utility effluents. Many of these are additives (e.g., biocides,
corrosion inhibitors), maintenance chemicals (e.g., cleaning solvents),
or derived from construction materials (e.g., asbestos, PCB's in trans-
formers). All of these chemicals might be eliminated from the effluent
by switching to other chemicals and construction materials. Most other
priority pollutants listed in Table 4.4 are "generated" by the pro-
cesses carried out by the plant; for example, heavy metals are derived
from the fly ash and bottom ash, from the corrosion of pipes, from the
cleaning of metal parts, and from the leaching of coal piles by rain
water. A variety of chemicals, including both organic and inorganic
priority pollutants, may enter wastewaters after being scrubbed from
4-9
-------
Table 4.4
Priority Pollutants Potentially Present in Utility Effluents
Sources
Toxic Substsnces Potentially
Present in Utility Effluents
Acroleln
Antimony and compounds
Arsenic and compounds
Asbestos
Bensene
Beryllium and compounds
Carbon tetrachlorlde
Chlorinated beaxeae*
Chlorinated ethanes
Chloroalkyl ethers
Chlorinated phenol*
Chloroform
Chromium and compounds
Copper and compounds
Cyanides
2 ,4-Diehlorophenol
Mercury sad compounds
naphthalene
Nickel snd compounds
lltrosmmlaes
Psntochlorophenol
Phmol
Polychlorlnated bipbenyla
Polychlorlnated aromatic hydrocarbon*
Selenium and compound*
Silver sad compound*
Thallium and compound*
Toluene
Zinc and compounds
1
1
u
Cooling system
X
8
2
;
"3
I Corrosion and s
X
X
n
2
•H
\ Corrosion Inhlb
X
8
fr
9
I Blocide - coolli
X
X
X
X
X
X
X
X
X
X
X
u
u
1
4J
2
X
i
a
9
1
3
X
X
X
X
•^•^
I Ash constituent
X
X
X
Jf
X
X
X
X
X
X
X
X
X
X
WH^
|
1 Construction ami
X
X
X
X
X
X
M^M^
3
M
S
1 Cooling tover mi
X
•mmmmmM
g
•H
U
X
^^MM
"3
•a
Maintenance mate
X
X
X
««M^
Transformer flul
X
•• ••
3
X
X
X
X
X
•"«•
i
4s)
a
*
*•»•
Source: [13, 15]
4-10
-------
the air in cooling towers. Particular emphasis may be placed on the
heavy metals since, in many cases, these pollutants are generated in
large quantities by the processes.
The overall magnitude of the metals problems was indicated in the
Development Document for Steam-Electric Power Plants. It was found
that effluents from steam-electric power plants contribute a signifi-
cant portion (14%) of the total national discharge of metals from
major industrial point sources, e.g., 50% of the chromium, 14% of the
copper, 10% of the iron, 21% of the zinc, and 14% of all metals as a
whole. Table 4.5 gives the estimated total and relative discharge of
a few heavy metals from steam electric power plants. The contribution
of ash ponds, boiler cleaning, and condenser cleaning represent the
major fraction of iron and copper discharges as shown in Table 4.6.
If the regulations resulting from the consent decree are stringent,
they will very likely prove to be a significant inducement for both
new and existing sources to increase the amount of water recycled and
reused. This will only happen, as previously stated, if the cost of
treatment associated with recycle is less than the cost of treatment
associated with discharge.
The EPA is also currently looking at other chemicals (i.e., other
than consent decree compounds) in wastewaters from steam-electric power
plants, and regulations on their discharge may eventually be promulgated.
,4.1.6 "Zero Discharge" Goal of PL 92-500
The Federal Water Pollution Control Act Amendments of 1972 (PL 92-500)
declared that "...it is the national goal that the discharge of pollu-
tants into the navigable waters (of the United States) be eliminated by
1985." While it has become increasingly clear since the passage of
this act that this goal may be very difficult to achieve there will
no doubt be continued pressure on both industry and municipalities to
reduce the discharge of pollutants to the absolute minimum. Moreover,
in recent years it is becoming clear that a power plant has many different
types of wastewater with different potential impacts. Zero discharge
may be a goal necessary and practicable for some streams like ash pond
4-11
-------
Table 4.5
Total Metals Discharged From Power Plants in the U. S. , 1973
Compared to Other Industrial Sources
(Includes Cooling Water Discharges)
Pollutant
Chromium
Copper
Iron
Zinc
Total
Discharges by Major
Steam Electric Power
Plants (Ib/day)
15,365
2,739
20,683
20,099
58,886
Percentage of
All Major
Dischargers
50
14
10
21
14
Source: [1]
Table 4.6
Total Iron and Copper Discharges from
Coal-Fired Power Plants in the U. S., 1973
Source
Ash Ponds
Boiler Cleaning
Condenser Cleaning
Total
Iron (Ib/day)
10,200
1,500
11,700
Copper
180
150
40
370
Source: [1]
4-12
-------
effluents. However, it may be quite difficult or impractical and
indeed unnecessary from the viewpoint of environmental impacts for
certain other effluents. At the same time, the importance of some
specific pollutants has come into sharper focus. Thus the thrust of
regulatory developments in the future may be increased to focus on
control of specific priority pollutants rather than a categorized em-
phasis on zero discharge.
4.1.7 Clean Water Act of 1977 (PL 95-217)
The Clean Water Act of 1977 incorporates the list of priority
pollutants from the 1976 consent-decree into specific portions of PL 92-
500. Section 301 of PL 92-500 now requires the EPA to set effluent
limitations for each pollutant based on best available technology econom-
ically achievable (BATEA). Point source discharges, other than (POTW's)
must comply with these limitations by July 1, 1984.
The priority pollutants were also included in Section 307 of PL 92-
500, which deals with "Toxic and Pretreatment Effluent Standards." The
limitations may be relaxed - in some cases - if the POTW removes all or
any part of the toxic pollutant.
It seems clear that the legislative mandate of PL 95-217 will,
when implemented, significantly help the control of toxic chemical dis-
charges and, in turn, put added pressure on industry for increased re-
cycle and reuse of its waters.
4.1.8 Resource Conservation & Recovery Act of 1976 (RCRA)
RCRA provides for regulation of the disposal of solid wastes by
governing the disposal practice and one of its principal impact (among
other objectives) is expected to be the prevention of groundwater con-
tamination by solid waste disposal. Proposal regulations have been
issued under the Act and indicate the following [102]:
• Any solid wastes including FGC wastes will be tested using
defined test procedures under Section 3001 of the Regulations.
4-13
-------
• If a waste passes these tests, then such solid wastes are
not governed by any federally-enforceable regulations. EPA
will issue regulations under Section 4004 for environmentally
sound disposal of non-hazardous solid wastes. States are
responsible for implementing and enforcing the requirements
of Section 4004.
• If a waste fails Section 3001 tests, it will be treated
as a hazardous waste under Section 3002, 3003 and 3004 and
a "special waste" category was created to cover large
volume wastes with potentially low hazard level. It is
proposed that FGC wastes if they fail Section 3001 tests
will be placed in this "special" category. Such special
wastes would be subject to environmental monitoring record keeping
and other requirements. However, the engineering standards
required for other hazardous wastes will not apply to FGC
wastes until EPA promulgates storage, treatment, and disposal
regulations specifically applicable to FGC wastes.
RCRA related matters are discussed further in Volume V. RCRA does
specify specific design criteria for surface improvements of basins
which are required to treat surface run-off and leachate. Further it
is noted that increasingly stringent effluent guidelines will encourage
conversion of many pollutants in effluents into solid wastes. Disposal
of such solid wastes on land will be constrained by RCRA regulations.
4.1.9 National Energy Act of 1978
In 1978 the National Energy Act (NEA) was passed by Congress and
encompasses five separate bills:
• National Energy Conservation Policy Act of 1978,
• Powerplant & Industral Fuel Use Act of 1978,
• Public Utilities Regulatory policy Act,
• Natural Gas Policy Act of 1978, and
• Energy Tax Act of 1978.
4-14
-------
At present, detailed regulations to implement the overall framework
of NEA are being worked out by the Department of Energy (DOE). The
regulations would promote the use of coal, renewable energy sources,
and other alternative fuels over oil and natural gas wherever possible.
While the full impact of NEA on utility and industrual power plants
needs further definition, the following appear to be indicated:
a. All new boilers, gas turbines and combined cycle units with
a capacity larger than 10 MW will be prohibited from using
oil or natural gas unless specifically exempted by DOE.
b. Existing facilities that are coal capable but not using
coal now may be required to switch to coal or an alter-
native fuel. Financial capability to use coal or alternate
fuels will be considered by DOE. DOE will consider whether
an existing boiler has furnace configuration and tube
spacing to burn coal. However, addition of particulate
and FGD systems may not be considered substantial modi-
fications preventing a switch to coal. Furthermore, derating
of less than 25% by switching to coal will not be con-
sidered substantial. These regulations will apply to
single units of 100 MBtu/hr or more or multiple units
in one site which is aggregate are by design capable of
a fuel input rate of 250 MBtu/hr or more.
It is anticipated that NEA will encourage use of coal over the
next twenty years. Additional solid wastes and wastewaters will be
generated by a switch to coal. Focus on these incremental problems
is essential.
4^2 Possible Future Regulations
4.2.1 A. Multimedia Approach May Be Required
Power plants generate wastes that are discharged to the air and
to the land as well as to the waters. And, in many cases, the relative
amounts of pollutants eventually discharged to the three media (air,
water, land) are interrelated. For example, control of air emissions
4-15
-------
may generate additional fly ash and SCL scrubber sludges which must be
disposed on land; also, a high level of wastewater treatment may require
the use of significant amounts of energy which, in turn, results in the
discharge of pollutants associated with the generation of that energy.
Thus, several questions are posed. Is the fragmented approach that
is sometimes taken to the control of industrial pollution being implemented
at cross purposes? What is the net environmental impact for disposal of
all effluents? Can the system be optimized to reduce emissions (to all
media) for maximum environmental protection? How site-specific would such
an optimization program be?
It should be noted that RCRA's approach is multimedia (air, water
land) and may be expected to provide useful inputs in this regard.
It is possible that, in the future, a multimedia approach will be
mandated for environmental assessments and control of all major point
sources of pollution. In this approach, the regulation of wastewater
discharges and the extent of water reuse will be intimately tied in with
the totality of all air, land, and water emissions; with the associated
energy and land use, and with other local factors that relate to envi-
ronmental protection.
4.2,2 Interrelationship of Toxics Controls and Water Reuse Technology
The sections above discussed the regulatory interrelationships
between the control of discharges of toxic chemicals in wastewaters and
pressures for increased recycle of water in steam-electric power plants.
Toxics need not necessarily need to be removed for recycle. However,
some additional Interrelationships may exist with regard to the techno-
logies required. The common ground lies primarily in those areas where
the toxics removal involves a substantial reduction in any parameter
that may be a problem for recycle. The parameter may be total dissolved
solids, hardness, acidity, oil and grease, suspended solids, or other
such parameters. In general, a wastewater treatment process that only
accomplished the removal or destruction of one (individual or class of
chemical) - e.g., the destruction of cyanides by alkaline chlorination -
4-16
-------
would do little for recycle potential. Where there is an interrelation-
ship of technologies, it is likely that economic considerations will
favor treatment for reuse over treatment for discharge, especially as
stricter limitations on the discharge of toxic chemicals are implemented.
4-17
-------
5.0 RECYCLE/REUSE OF WATER
5.1 General
As noted earlier, environmental regulations and constraints on
water supply have placed increasing emphasis on tighter water management.
While zero discharge and total reuse of water are not likely to be
achieved in the immediate future, recycle/reuse of water will play an
ever-increasing role in water management. In this section various ap-
proaches for recycle/reuse are discussed.
5.2 Combined Central Treatment
5.2.1 Wastewater Management
A power plant has many uses for water and the ranges of water quality
requirements for these uses are very broad. Hence, power plants 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 on the
order of 50 mg/£ for intermediate pressure plants and 2 mg/i, or less 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 are 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 may be suitable for makeup to the ash sluicing system,
or for plants using alkaline FGD streams as makeup to that system. Plants
located adjacent to mines (mine-mouth plants) often have additional require-
ments for low quality water for ore processing at the mine.
With such cascading water uses, it is frequently possible to manage
water systems in which there is minimal net effluent from the power plant.
These plants still have significant overall water requirements, but the
5-1
-------
water is used mainly consumptively for evaporation and drift in cooling
towers, for sulfur dioxide removal, or for ash handling and ore prepara-
tion. Such water management can play a major role in water reuse although
such procedures require very precise operating practices and controls.
Some plants which try for such zero discharge run into operating problem
[5].
Southern Services Company [62] has conducted computer based con-
ceptual studies to develop a plant profile for system-wide use including
water and waste management aspects related to a coal-fired plant.
Similarly, programs are available to predict and characterize cooling
water performance and optimize the required treatment. Radian [7] in
its work for the EPA employed a computer simulation package capable of
modeling the major water consumers (cooling tower, ash sluicing, FGD
systems) at coal-fired power plants. Such management studies can be
useful in planning engineering, construction, operation and maintenance
activities with increased recycle/reuse.
5.2.2 Treatment Technology
In addition to proper wastewater management, one can consider various
options to treat individual streams. In order to assess total potential
for water recycle/reuse, one needs to be cognizant of both common treat-
ment options and specific methods for each pollutant. Table 5.1 lists
treatment methods available, potential effluent reductions achievable and
present use in proven plants. Aspects regarding some of the technologies
were described earlier in Section 3.0.
5.2.3 Central Treatment System
Although power plants produce many wastewater streams with different;
pollutants and flow characteristics, the most feasible concept of treat-
ment consists of:
• Proper wastewater management practices in the whole plant
to minimize streams that need treatment,
• Combining all compatible wastewater streams with
appropriate equalization basins or tanks, and
5-2
-------
Table 5.1
Pollutant Parameter
COMMON;
pH
Dissolved Solids
Suspended Solids
SPECIFIC POLLUTANTS:
Aluminum/Zinc (Water
Treatment, Chemical
Cleaning, Coal Ash
Handling, Coal Pile
Drainage)
Control and /or
Treatment Technology
Neutralisation
with chemicals
1. Concentration and
evaporation
V
2. Reverse Osmosis
3. Distillation
1. Sedimentation
2. Chemical Coagulation
and Precipitation
3.' Filtration
1. Chemical Precipitation
2. Ion Exchange
3. Deep Well Disposel
Effluent
Reduction Utility Industry
Achievable Usage
Neutral pH Common
Complete
•
30-9SZ
60-90Z
90-95Z
95-99X
95Z
Removal
1.0 mg/1
Similar
Copper
Removal Not generally in
use - desaUnintion
technology
Limited uee - de-
sallnlsatlon technology
Not in use - desslin-
icatlon technology
Extensive
Moderate
Not generally practiced -
water treatnent technology
to Limited usage
" <
Treatment, Slowdown,
Chemical Cleaning.
Closed Cooling Water
Systems) *• Biological Nitrification
3. Ion Exchange
installations in sewage
treatment
Removal to 2 «t/l Not practiced for these
waste streams
80-931
Not practiced
BOD/COD (Sanitary
Wastes)
COD (Water Treatment,
Chemical Cleaning)
Chromium
(Cooling Tower)
Biological Treatment
1.
2.
3.
1.
2.
Chemical Oxidation
Aeration
Biological Treatnent
Reduction
Ion Exchange
83-95X
8S-95X
8S-95Z
8S-9SX
0.03 mg/1
w
Com* on practice
Limited usege
Not practiced
Not practiced
Limited usage
H M
Chlorine (Once-
through Condenser
Cooling)
Electrochemical
Substitute Chemicals
Control of Residual
Cl2 with Automatic
Instrumentation
Utilise mechanical
Cleaning i Chlorine
Control to Limited usage in the
0.2 mg/1 Industry - technology froe
sevage treatment practiced
in soae plants - all syster.s
Reduces Clj (r> not capable of being
Discharge converted to mechanical clean in
5-3
-------
Table 5.1 (Continued)
Treatment Technology for Wastewater in Power Plants
Munber
II
Pol lu tint Parameter
SPECIflC KH.M.TX'TTS
Chlorine
(Reclrculatlng)
Copper (One** through
Condenser Cooling)
Copper (slowdown,
Chenicsl Cleaning)
Control and/or
Treatnrnt Technology
(Cpnt'd)i
1. Control of Residual
Cl2 with Automatic
Instrumentation
2. Reduction of Cl, with
Sodim Bisulfite
1. Replace Crn^rnser Tubes
with Stainless Stetl or
Titanium
1. Cienlcal Coagulation
•nd Precipitation
Iffluent
(eduction
Achievable
Bclov Detect-
able Units
Ellnlnaiion of
Dleeharge
Renoval to
0.1 M/l
Utility Industry
I'sajje
Instilled In < new (nuclear)
fsclllty; heurvrr, excess
KlHSOj It discharged
Done In several pl»n:s
cr corroded - not done
for environoental reasons -
expensive
United usage
I. Ion Exchange
1. Deep Well Disposal
Renewal to Mot practiced
0.1 ng/1
~—— -As described shove——————
fluoride (Chenlcal
Cleaning)
Iron (Water Treat-
Bent. Cbsnlcal
Cleaning, Coal Aah
Handling, Coal Pile
Drainage)
luifate/Juitlt.
(Water Treatnent,
Chenlcal Cleaning.
Ash land ling. Coal
file Drainage. *0j
Renewal)
Oil (Chealcal Clean-
ing, Aah Handling.
floor 4 Tare Drains)
Oxidising Agents
(ChoBlcel Cleaning)
Phenols (Aeh-
•••dling. Coal Pile
•Yslnsge, fleer 4
Tart Drains)
•hoephete (slowdown,
Cnenical Cleening,
floor 4 Yard Drains.
Plant Laboratory 4
(•••ling)
Mercury (Coal Aah
Handling 4 Coal Pile
Drainage)
Vanadiun «I Rnoval
ReBoval to 1 Bg/1 Kot practiced In
(he industry
Reewval to «0.01 Mat practiced In
•(/I the Industry
ion oval to <0.01 Mot practiced in
nt/1 the industrv
BtTaWVal to 5 M/l ! *"* """"y P«cticed -
MUOUTU v« j nni>f water treatoant technology
Ultlnate Disposal Hot practiced
1. Reduction 4 Precipitation leneval to O.I ng/1 united uaege
2. Ion Exchange nenoval to 0.1 ng/1 »ot practiced
1. Adsorption nenoval to SO vg/1 Kot practiced
1. H2S Treatrent 4
Precipitation
1. Ion Exchange
Renoval of Low Not practiced
Concentrations
Difficult to Not practiced
Achieve
Source: [5, 12] and Arthur D. Little, Inc.
5-4
-------
• Central treatment for appropriate combinations of
such waste streams.
Central treatment, however, is often not practiced.
following waste streams [5]:
• Once-through cooling or cooling tower blowdown,
• Sanitary wastes,
• Roof and yard drains,
• Coal screen backwash,
• Non-circulating ash or FGD system wastes, and
• Recirculating bottom ash system (although in some
cases this can be included in central treatment).
The point to note is that proper wastewater management can and
should include the above wastes; however, a central treatment for
chemical wastes cannot handle the above wastes. Such total water
management is considered in greater detail in Section 5.3.
A typical system for central treatment is shown in Figure 5.1.
Capital and operating costs for such central treatment were estimated by
the EPA [5]. Updated versions (mid-1978 dollars) of these are presented
in Table 5.2.
5.3 Water Reuse Considerations
5.3.1 General
There are many opportunities in a power plant for wastewater
management via water recycle and reuse. The recycle/reuse options can
be categorized as follows:
• Individual wastewater stream basis, and
• Total plant basis.
Recycle/reuse on an individual stream basis entails makeup water
and/or en-of-pipe (blowdown) treatment. Such options include dewatering
of clarifier sludge and recycle of effluent, recycle of boiler blowdown
via feedwater ion exchange units, recycle of cooling tower and ash pond
blowdown after lime softening, etc. These options have been described
in Section 3.0.
5-5
-------
Ul
ON
Source: [5]
Figure 5.1 Coal-Fired Plant - Central Treatment of Wastewater
-------
Table 5.2
Capital and Operating Costs - Central Treatment
BASIS; 1. See Figure 5-1 for typical system
2. Costs in mid-1978 dollars, CE Index 218.8
3. Total Capital Costs (TCC) = Major equipment
+ 50% for installation - new source
+ 100% for installation - existing sources
+ 20% for instrumentation
+ 15% for engineering
+ 15% for contingency
4. Annualized Costs = Maintenance at 3% of TCC
+ Fixed charges at 15% of TCC
+ Chemicals + Labor + Power
Ui
Number Item
1 Total Capital Cost
($/kW)
2 Annualized Costs
(Total $)
Unit Cost, mills/kWh
Base load (0.7/ capacity factor)//
Cyclic (0.44 capacity factor)//
Peaking (0.09 capacity factor)//
100 MW
Retrofit New Sources
$ (1000) $ (1000)
372 288
(3.72) (2.88)
1000 .MW
Retrofit New Sources
$ (1000) $ (1000)
1211 936
(1.21) (0.94)
231
0.34
0.60
2.94
217
0.32
0.56
2.75
575
0.09
0.15
0.75
527
0.08
0.14
0.68
Source: [5] and Arthur D. Little, Inc. update.
-------
Recycle/reuse on a total plant basis is a more complex issue. It
involves among other things, utilizing more advanced treatment tech-
nologies for total dissolved solids (IDS) removal, balancing and inte-
grating all of the flows within the plant and being able to cope in
real time with variations in plant performance, power demand, climatic
variations, etc., so as to keep the entire system within balance. For-
tunately, on a total plant basis, it is possible to separate certain
wastes and cascade the water uses, so that it is not necessary to
treat all the wastes originating from the plant [5],
5.3.2 Technology for Reuse
Technologies for desalination including evaporation, membrane
processing, ion exchange, and chemical methods can be considered for
reusing water in a power plant. Some technologies have been used or
explored for power plant use and are as follows:
a; Employment of vertical tube vapor compression evaporation
system (Figure 5.2) as a brine concentrator has been studied
and piloted for cooling tower blowdown and ash sluice water.
Figure 5.3 shows an application on cooling towers. Potentially
such a system could be employed in boiler feedwater and
several other effluents from a power plant [5]. For a
Colorado River Basin power plant installation [64 ], such
a system:
• Reduced waste from the condensate mixed-bed polisher
by about 91%,
• Reduced the need for makeup water,
• Eliminated the need for cold lime softening and
reduced the demlneralizing requirement, and
• Reduced the generating system's overall liquid
3
waste output from 3.5m /minute (936 gpm) to only
3
0.07m /minute (19 gpm), cutting the pond requirement to 98%.
While both titanium and stainless steel 316 have demonstrated
satisfactory corrosion resistant properties in this applica-
tion, the use of titanium as primary material of construction
5-8
-------
Ul
i
FEED
FEED PUMP" T—
COMOEMSATE
J
HEAT EXCHANGER
VENT
DEAKRATpR] I
- .-.'". • ; -.
4
'.-.. -^
-
-
.^BRIN
^^HEA
^^- EVA
EFILM
' TRANSFER TUBES
EVAPORATOR BODY
WASTE
BRINE.
RECIRCULATION^ BRINE SUMP
PUMP
STCAM
COMPRESSOR
\PROOUCT
WATER PUMP
Source: [64]
Figure 5.2 Vapor Compression Evaporator
-------
POWER
PLANT
i EVAPORATION
LOSSES
COOLING
TOWER
MAKEUP
COOLING
TOWER
SLOWDOWN
156
50OO-8000
PRODUCT WATER
152.3 1O
RCC
BRINE
(CONCENTRATOR;
SYSTEM
CF = 4O
3.7 GPM
94,300-165,600 TDS
103,400-139,500 SS
EVAPORATION
POND
TDS = TOTAL DISSOLVED SOLIOES
ss= SUSPENDED SOLIDS
Source: [6, 65]
Figure 5.3 Vapor Compression Evaporator For
Typical Cooling Tower Slowdown Reuse
5-10
-------
will importantly promote longevity of the equipment.
For concentrating cooling tower blowdowns and other power
plant waste streams, the vapor-compression evaporate
requires 23 kWh/m (39 Btu/lb) of feed while recovering
95 to 98% of water for reuse.
3
A 7.6m /minute (2,000-gpm) system combining this technology
with reverse osmosis and sludge dewatering is currently being
installed at a Western power generating station [65, 66]. The
system is designed to process cooling towers and SO- scrubber
blowdowns, demineralizer regenerant and ash system wastes,
and other plant wastewater to achieve the objective of
zero liquid discharge while recovering 95% of wastewater.
The San Juan Station owned jointly by Public Service of
New Mexico and Tucson Gas & Electric utilizes the combina-
tion of reverse osmosis (RO) and vapor compression evap-
oration (VCE) for handling plant wastes (cooling tower
blowdown, FGD prescrubber wash stream since San Juan was
Wellman-Lord S0? recovery process, demineralizer wastes,
etc.) The following costs (in 1977 dollars) are reported [66]
• Capital $15/kWe
• Operating - RO = $1 to $1.2/1000 gals of treated water
RO + VCE = $1.7 to $1.8/1000 gals of treated water
Another reported study concerns electrodialysis systems
for cooling tower salinity control [67].
Evaporation ponds are in use at a number of steam electric
power plants to reduce waste streams to dryness. Provided
the plant is located in a net evaporation area, this is
certainly usable. However, since land area requirement is
determined by net annual evaporation, in many populated
areas, this may be impractical.
2
A specific plant is reported to use 9,380m (101,000 sq ft)
of line evaporation pond to evaporate a maximum flow of
5-11
-------
3
163m /day (43,000 gpd) of waste water to dryness [5].
Distillation or reverse osmosis techniques are practiced on
a large scale for seawater or brackish water desalination.
While present costs are high for use in most power plants
on economic basis alone, future potential does exist.
In a generic study on application of distillation and
crystallization methods, Awerbuch ot_ a^. [68] present cost
analysis on such waste concentration (in which the con-
centrated waste is a slurry) and conclude that:
• Addition of a process softener reduces costs since
the evaporator crystallizer design is simplified, and
• Waste heat utilization can reduce costs further.
Another system that has been studied for treatment of
wastewater, particularly cooling tower blowdown in
vertical tube foam evaporation (VTFE). In this method a
few pptn of a selected surfacant is added to the waste-
water stream and the resultant liquid is caused to flow as
a foamy layer over the vertical evaporating surface. As a
result of the foam layer, heat transfer is substantially
augmented [70,71]. Thus this method potentially can sub-
stantially improve the capabilities of vertical tube
evaporation (which is the basis of much of industrial
evaporators). Interface enhancement by foaming can improve
vertical tube evaporation (VTE) by:
• Reducing AP, and
• Increasing evaporation side heat transfer coefficient.
A study by the University of California at Berkeley [70]
concludes that:
1. Cooling tower blowdown can be renovated for reuse in
VTFE.
2. Upflow mode VTFE is more effective than downflow mode.
5-12
-------
3. Substantial capital and energy savings over
conventional VTE are offered by VTFE.
In the case of samples from Mohave Plant [70], a 30-fold
concentration of cooling tower blowdown was obtained at low
temperatures (61.6°C or 143°F) with high heat transfer
coefficients at a surfactant level of 15 mg/£. It is
reported [70] that the bulk delivery price of surfactants
is 25 cents per Ib (60% active solution) presumably in
1976 dollars.
The study led to the conclusion that larger scale testing
3
is worthwhile. A mobile pilot plant with a 190m /day
3
(50,000 gpd) VTFE unit and 19m /day (5,000 gpd) Evaporator
Crystallizer (EC) unit is being assembled with EPA funding
[72]. Recently EPRI [9,74] has decided to fund demonstra-
tion of this concept by testing the above mobile unit at
one or more utilities.
g. Bechtel [73] is also undertaking for the EPA an assessment
of VTFE reverse osmosis (RO) and vapor compression evapora-
tion (VCE). Bechtel will study energy requirements,
investment and operation costs for each of the systems.
h. Radian Corporation recently completed for the EPA bench-
scale tests on reverse osmosis, lime precipitation, carbon
absorption and vapor compression evaporation techniques
for treating various streams including ash pond effluents
and cooling tower blowdown [103]. Equipment employed in
bench-scale tests were small (up to 10 gpm) units. Appar-
ently, preliminary results indicate that heavy metals in the
final effluent are well below threshold levels of detection.
A draft report on this study is expected soon [103].
Hinman Associates, in assisting the EPA in preparing the technical
report for revision of effluent guidelines [101], undertook a survey of
effluent discharges at a number of plants. Results of their survey on
end of pipeline technology and water management are reported. In addition,
5-13
-------
guidelines for minimization of chemical additives, in particular chlorine
in cooling towers, is offered [101].
5.3.3 Reuse Schemes
A number of schemes have been reported in the literature for
recycle/reuse [5]. Water management for optimum reuse is highly site-
and system-specific; it can only be accomplished on a case-by-case
basis. Some examples are presented below to indicate broad approaches.
a. The system to achieve optimum reuse with no discharge of
pollutants at a 600 MW coal-fired plant [5,69] is shown in
Figure 5.4. This is achieved through the reuse of neutra-
lized demineralizer wastewater, boiler cleaning effluents,
floor drainage, boiler blowdovn, and evaporation blowdown
in the ash sluicing operation. Ultimate blowdown is
achieved through the moisture content (15-20%) of the
bottom ash discharged to trucks for off-site use. Fly ash,
handled dry, is also trucked to off-site uses. If one were
to update reported cost to mid-1978 levels, such a system
on a retrofit basis for a pond normally practicing pond
discharge may be $3.2 million. (Such costs are site- and
system-specific.) It is not clear whether this system
includes coal pile drainage treatment.
b. Other examples of recycle/reuse being followed in the
industry such as combinations of cooling tower blowdown
for ash sluicing and treated ash pond blowdown for con-
denser cooling, zero discharge for a plant being fed by
a coal slurry pipeline and equipped with an evaporation
pond, no discharge (except coal pile runoff) for a
mine-mouth plant, etc., are reported [5].
c. A number of conceptual schemes have also been proposed.
Figure 5.5 is an example proposed by TVA researchers [14],
This concept proposes the use of lime soda softening of a
slipstream from ash sluicing for scale control. In this
scheme, relatively small wastestreams, such as chemical
5-14
-------
EVAPORATION s. DRIFT LOSS
Ui
ALUM
T.OX
10
. _ . .
o coNi.il NOAH nrw I lnrcrNr««ANT». INEUTRALI/INGF
" QA^_Jt;'^°cri^'!j^^—H TANK |
njiciinic SODIUM
ACIO HVDMOXIOC
EVAPOMATOH • OOILLH BLOWOO*«N 270 C.rM
Source: [5]
Figure 5.4 Water Management at a 600-MW Coal-Fired Unit
-------
u«
miH
— r
! r-4 TV,
—
jat
«••*
niriEKuni
isncK
ttSMMM
CMCMCAI
OdwKC
vnsn
wot
nun
COtAU
MOT
-r-
f
1
•*
1
• 1
Source: [14]
Figure 5.5 Reuse of Water at a Typical Coal-Fired Power Plant
-------
cleaning waste, floor drains, treated sanitary waste, etc.
would be discharged into the closed-loop ash pond system.
The cooling tower blowdown would be the main source of
water to replenish the evaporative loss of water in the
ash ponds. The clarified effluent would be reused to dilute
the recycled water stream, thus avoiding the solubility
limit within the ash sluicing process. Part of the clari-
fied effluent could pass through a membrane process to pro-
duce cooling tower or boiler makeup water. This would
depend on the quality and quantity of the local water supply.
The waste from the first stage excess lime softening process
is primarily calcium carbonate, magnesium hydroxide, cal-
cium sulfate, and other solids, while the waste from the
secondary stage soda-ash process would be strictly calcium
carbonate. Both of these slurries could be mixed with
either cooling tower blowdown or recycled ash pond effluent
to be used as makeup water for a wet scrubber system,
which controls sulfur dioxide in the stack gas. If a
power plant had no scrubber system, these wastes could be
dewatered for recovery or ultimate disposal. Reportedly,
the authors tested actual ash pond effluents [14] at a
TVA plant and found good removal of turbidity, Ca, Mg, as
well as heavy metals like Cd, Cu, Fe, Pb, and Zn.
Another conceptual reuse scheme was included earlier in
Figure 3.4.
Radian [7] undertook (for the EPA) a study of water recycle/
reuse possibilities at five coal-fired utility power plants
listed in Table 5.3. These plants were selected based on
the criteria of location, availability, site characteristics
and project timing. As part of this study, the three major
water systems (cooling tower, ash sluicing, and S02/
particulate scrubbing) were evaluated at these five power
plants.
5-17
-------
Table 5.3
Radian Study for the EPA - Selected Plants for Water Recycle/Reuse Study
Oi
I
oo
Utility
Arizona Public
Service
Public Service of
Colorado
Georgia Power Co.
Pennsylvania Power
and Litftt
Montana Power Co.
Plant
Four
Corners
Cbsjencne
Bowen
Montxmr
Cols trip
Location
Psnington,
Hew Mexico
Pueblo.
Colorado
Taylorsvllle,
Georgia
Washing ton-
vllle,
Pennsylvania
Colatrip,
Montana
Capacity
(M»)
2,150
700
1.5955
1,500
700
Type
Cooling
CP
WCT
wcr
WCT
wcr
Ash
WSB
HSF
WSB6
WSB
WSF
WSP
WSB
WSB
WSF
Part. ,
Control
Cyclones.
ESP. venturi
ESP.
(Botside)
ESP
ESP
Venturi
S02 4
Control
UC
None
None
Hone
Liae/ alkaline
fly ash
scrubbing
- vet cooling tower, CP * ™»«i-t«g pond.
* wet sluicing of bottoa ash, WSF * vet sluicing of fly ash.
TESP * electrostatic precipltator.
4
DC * under construction.
T>lant capacity as reported in FPC Form 67 Data; present capacity is 3200 KW (4 units).
wry fly ash disposal.
Source: [7]
-------
Computer models were used to identify the degree of
recirculation achievable in each of the three water
systems without forming scale. The models were verified
using the results of one-day spot samples at the selected
plants. The results confirm that the recycle/reuse is
dependent upon the limiting scale forming species such as
CaCO_, CaSO^ • 2H20, Mg(OH>2, silica, etc. Besides the
inherent causes such as ash leaching, SO- scrubbing, and
evaporation in cooling tower on scale formation, the
external transfer of CO- to ash pond water is also studied
in this report. The report confirms that with increased
C02 transfer, CaCO. scale potential in recirculating ash
sluicing system increases, while Mg(OH)_ scale potential
decreases. Similarly, the study concludes that fly ash
sluicing water recirculation is possible using treatment
for scale control.
The conclusions on recycle/reuse options at the five plants
studied by Radian for the EPA are among the suggestions,
albeit of a preliminary nature, in the literature. These
are summarized in the following tables:
• Table 5.4 for Four Corners Plant
• Table 5.5 for Comanche Plant
• Table 5.6 for Bowen Plant
• Table 5.7 for Montana Plant
• Table 5.8 for Colstrip Plant
The reported cost data should be considered approximate and appear
to vary widely from 0.002 to 0.45 mills/kWh (in 1976 dollars).
f. Another conceptual scheme [5] involves three major process
units to provide a complete treatment of chemical wastes
for reuse within a power plant. These include a softener
and chemical feed system to reduce the hardness of the
cooling tower blowdown, a brine concentrator to preconcentrate
5-19
-------
Table 5.4
Radian Study for the EPA - Summary of Recycle/Reuse Options at Four Corners
Ui
i
KJ
O
Weight Percent Solids In
Thickener Bottoms
Hold Tank Volume,
•3(ti3)
Liquid to Gas Ratio,
t/fta3 (gal/scf)
Z Recycle fron the
Ash Pond
Oxidation, Z
Particulate Removal Prior
to Scrubber, Z
Scrubber Makeup Rate,
t/sec (gpm)
Coats1
Capital, 1976 $
Operating, 1976 $
(mills/kWh)
Existing
Condition
Case 1 Case 2
10 30
0 0
4.7 4.7
(35.2) (35.2)
0 0
98.6 98.6
None None
223 70.7
(3540) (1730)
— —
— —
Alternative
Two
Case 1
30
37,500
(1.33 x 106) (1
4.7
(35.2)
0
98.6
None
70.7
(1120)
3,334,000 4
628,000 1
(.128)
Case 2
30
37,500
.33 x 106)
10.0
(74.8)
0
98.6
Hone
70.7
(1120)
,275,000
,101,000
(.225)
Alternative
Three
Case 1
30
37,500
(1.33 x 106) (0
10.0
(74.8)
28
98.6
None
50.8
(805)
4,328,000 3
1,109,000
(.226)
Case 2
30
21,200
.75 x 106)
10.0
(74.8)
28
98.6
None
50.8
(805)
,317,000
958,000
(.195)
Alternative
Four
Case 1
30
8,900
(0.31 x 106)
10.0
(74.8)
0
98.6
60
41.0
(650)
3,385,000
968,000
• (.198)
These rough cost estimates were made to compare technically feasible options and do not
Include a "difficulty to retrofit" factor.
-------
Table 5.5
Radian Study for the EPA
Summary of Water Recycle/Reuse Options at Comanche
Existing
Conditioning
Alternative
One
Alternative
Two
Alternative
Three
Ul
i
to
Cooling Tower Makeup Source Softened River Water
Cycles of Concentration in
Cooling Towers 5.0
Cooling System Treatment
Fly Ash Disposal Method
Type, Z Solids Dry
Bottom Ash Disposal Method
Type, Z Solids Wet, 1Z
Recycle In Fly Ash
System, Z
Recycle in Bottom Ash
System, Z 0
Treatment in Ash Systems None
Plant Makeup Requirements
t/sec (CPM) 590 (9350)
Plant Discharge
t/sec (CPM) 156 (2470)
Costs
Capital Investment, 1976 $
Operating Expenditures, 1976 $/yr ..
(•ills/km)
Additional Cost to Treat Pond
Overflow for Zero Discharge
Capital, 1976 $
Operating, 1976 $/yr
(mllls/kWh)
Tocal Cose for Zero Discharge
Capital, 1976 $
Operating, 1976 $/yr
(mllls/kWh)
Softened River Water
5.0
(Sulfurlc acid and zinc polyphosphate
Wet, 10Z
Wet, 4Z
0
0
Rone
' 520 (8250)
65.4 (1040)
342,000
90,000
(0,02)
8,280,000
2,136,000
(0.43)
8,622,000
2,226,000
(0.45)
Softened River Hater
7.6
used for all conditions)
Wet, 10Z
Wet, 4Z
10Z
100Z
Brine Concentration
of Makeup (50Z)
455 (7210)
28.8 (460)
3,662,000
863,000
(0.18)
3,706,000
944,000
(0.19)
7,368,000
1,807,000
(0.37)
Softened River Water
8.4
Dry
Wet, 4Z
0
Rone
450 (7120)
30.2 (480)
3,883,000
989,000
(0.20)
3,883,000
989,000
(0.20)
The rough cost estimates were made to compare
technically feasible options and do not
Include "difficulty to retrofit" factor.
-------
Table 5.6
Radian Study for the EPA
Summary of Technically Feasible Options at Bowen
Ln
1
ro
N>
Cooling Tower Makeup Source
Cycles of Concentration In
Towers
Cooling Systea Treataent
Acid Addition Rate, kg/day
(Ib/day)
Ash Sluice Makeup Source
Recycle in Fly Ash
Systea
Recycle In Bottom Ash
Systea
Ash System Treataant
Plant Makeup Requirements,
(/sec (CPM)
Plant Discharge Rate,
(/sec (CPM)
Costs1
Capital, 1976 $
Operating, 1976 $/yr
(mlllBTkwn)
Existing Condition
Makeup Pond. Service Water
1.7
Hone
0 (0)
Cooling Tower Slowdown
0
0
Hone
3250 (51.500)
1600 (25,000)
—
Alternative One
Makeup Pond, Service Water
5.7
V°4
481 (1060)
Cooling Tower Slowdown
0
0
Hone
1880 (29.800)
255 (4050)
100,000
52,900
(.002)
Alternative Two
Makeup Pond, Service Water
15.
V°4
608 (1340)
Cooling Tower Slowdown
60
100
Recycle Softening
1670 (26.400)
41 (650)
1.223,000
402,000
(.018)
Alternative Three
Makeup Pond, Service Water
Brine Concentrator
Distillate
15.
H2804
608 (1340)
Cooling Tower Slowdown
60
100
Recycle Softening, Brine
Concentration of Fond
Overflow
1630 (25,800)
0 (0)
6.380.000
1.735.000
(.028)
Tliese rough cost estimates were made to
compare technically feasible options
and do not Include a "difficulty to
retrofit" factor.
-------
Table 5.7
Radian Study for the EPA
Summary of Technically Feasible Options at Montour
Ul
Existing
Condition
Cycles of Concentration
In Cooling Towers 1.5-2.0
Assumed Drift Rate in
Cooling Towers
/see (CPM) 62 (1,000)
Blovdovn from Cooling
Towers /see (CPU) 725 (11,500)
Z Recycle In Fly Ash
Sluicing Systea 0
Sluice System Makeup Cooling Tower
Source Slowdown
Total Makeup Water Bate,
t/see (CPM) 1.500 (24,000)
Ultiaate Efficient Bate,
1/iee (CPM) 500 (7.900)
Treatment Required Hone
Costs3
Capital, 1976 $ —
Operating, 1976 $/yr —
(mills/kwh)
Alternative
One
8
62 (1,000)
48 (760)
89
Cooling Tover-
Slowdown.
1,000 (16,000)
0
iUSO. (Cooling Tower)
Ma^COj (Pond Recycle)
640,000
123.000
(0.016)
Sulfurlc acid treai
it for CaCo3 scale control.
Sa2C03, softening for Ca reaoval.
These rough coat estimates were aade to covpare technically feasible
options and do not *iyli"*» a "difficulty to retrofit" factor.
Alternative
Two
20
401(650)
89
Cooling; Tower
BlovdmRt
950 (15.000)
(Cooling- Tower)
(Pond Recycle)
668,000
187,000
(0.018)
Alternative
Three
20
40 (650)
0
89
River Hater
985 (15,600)
(Cooling Tower)
3 (Pond Recycle)
622,000
169,000
(0.016)
Alternative
Poor
20
40 (650)
0
73
River Hater
(16.40O)
50 (800)
(Cooling Tower)^
485,000
103,000
(0.018)
-------
Table 5.8
Radian Study for the EPA
Summary of Water Recycle/Reuse Options at Colstrip
Existing
Conditions
Alternative
One
Alternative
Two
Ul
NJ
Cooling Tower Makeup
Source
Cycles of Concentration
in Cooling Towers
Cooling System Treatment
Treatment Rate,
fc/sec (gpm)
Cooling Tower Slowdown
Rate, A/sec (gpm)
Scrubber Makeup Source
Plant Makeup Rate,
£/sec (gpm)
Plant Discharge Rate,
fc/sec (gpm)
Costs:1
Capital, 1976 $
Operating, 1976 $/yr:
(mils/kWh)
Softened River Water
13.5
Makeup Softening
423 (6710)
23.6 (376)
Softened River Water,
Brine Concentrator
Distillate
423 (6710)
0.
Softened River Water
13.5
Makeup Softening
397 (6300)
23.6 (376)
Cooling Tower Slowdown,
Untreated River Water
423 (6710)
0.
159,000
-237,000
(-.046)
Untreated River Water
20
Slip-stream Softening
18 (284)
14.6 (230)
Cooling Tower Slowdown,
Untreated River Water
423 (6710)
0.
275,000
-217,000
(-0.44)
These rough cost estimates were made to compare technically feasible options
and do not include a "difficulty to retrofit" factor.
>
"Includes capital cost amortization at 15% per year.
-------
the blowdown brines resulting from the recirculating of
ash sluicing water, and an evaporator-dryer to finally
reduce the waste to a solid cake for disposal by landfill.
Figure 5.6 outlines this scheme.
g. Figure 5.7 shows a potential water management scheme at
a 1980 coal-fired power plant [101]. The major difference
between the scheme shown and a typical older plant is the
emphasis on recovery and reuse. It is anticipated that
1980 plants will be equipped with more sophisticated waste
control and treatment facilities to meet future water and
air quality standards. Every effort will be directed to
reuse waste materials.
In summary, among major water users in a power plant, the following
overall comments are pertinent:
• Cooling towers demand good quality water and have
substantial blowdown.
• FGD systems and ash handling could serve as water sinks
for other wastes, due to losses in evaporation and
occlusion with sludge wastes.
• Other streams can potentially be integrated with the
above three.
• Technology is broadly available for reuse, but economic
constraints in some cases are severe.
• In some cases technology demonstration would be necessary.
Updating an earlier EPA estimate (without independent cost esti-
mate or analysis), the capital costs, operating costs, and annual and
unit costs for a complete stabilizing system for aqueous chemical wastes
exclusive of once-through cooling water and rainfall run-off are esti-
mated in mid-1978 dollars [CE Cost Index 218.8) to be as follows [5]
and Arthur D. Little, Inc. Update]:
5-25
-------
1
.£«
MtINQ
TES
>GPV .
1
1
•OILER
PIKESIDE •
CLEANINO.
TOTAL Of
1*0.000 6PV
1
1
Am
PREHEATCR
CLfANINO
TOTAL Of
420.000 GPY
1
CONDEIWATE
AS MAKE UP
CLOSED WATER
COOLING SYSTEMS
120GPMINETI '
OR-
COOL-
INC
TOWER
MO
GPM
ASSUMPTIONS
INPUT:-10.S X 10* BTU PER MW
FOR COAL -1S.OOO BTU/LI
AIM Rf Q'D-7.5 LBytOMU BTU
WATER PRODUCED IM FLUE SASEJ-0 4 LB/10.00O BTU
IS* OF INPUT IS LOST TO FLUE OASES
SCRUBBER MAKE UP WATER -128 6PM
WATER
TREATMENT
CLARIFIER
ION EXCHANGE
EVAPORATOR
LKtUlO
WASTES
FROM ION
eXCHAN«E
ft EVAP OHLV
U.MOO «PO
(IOCPM)
BOILER MAKE UP
|~740PM)
o-
•OILER SYSTEM
NPUT:-
FLUE CASES
ir*f-^ > i— _
OEAERATION MEAT-IO.SX10*BTU/MR
OUTPUT HEAT BALANCE:
COAL W 800 LBmR, POWIR-S.4J X 10* BTU/MR
-FLUEQAS-I.M x to*
BTU/MR. '
JLECTHOSTATIC
—^RECIPtTATOR
(OPTIONAL)
fO
r
I ,
SOjSCRUBIfR
EVAPORATE
-12SCPMFQR
SATURATION
1
LIME
SCRUBBER
WATER
TREATMENT
^
SLUDGE FC
DISPOSAL (
1 FLUE GAS
I . I ATMOS. AFTER
| W.OOO SCFM Ib.d I* m»F (SAT.) * REMtAT^tF REQ'D.)
DRY f LV ASM
FOR DISPOSAL
COOLING TOWER
EVAPORATE 1000 GPM
(ASSUME NEGLIGIBLE
DRIFT LOSS)
MAKE UP-I.I X 1000 6PM ,
MAKE-UP FOR TOWER -1010 GPM \~
90OPM7J
95,000 0PM 1
OPERATION
CONTROLLED
DOSACEISIOF
CHLORINE
BASIN CLEANING
NET SLOWDOWN • loi-10 GPM
LIME/CAUSTIC
SOOA r
SOFTENER
SLOWDOWN
100 GPM
±
MAKE-UP
410,000 6PO.
ASH
SLUICING
SYSTEM
LOSStY
(VAPOR-
ATI ON
ASH SLUICING
SYSTEM
I I
NEUTRALIZATION
ft SEDIMENTATION
NET (LOWDOWN 0\0%
OF CENTRAL TREAT-
MENT PLANT FLOW
LEGEND
R[Q'D)OIL
SEPARATION*
TSS REMOVAL
J»H1
ICONCtt
CONCENTRATED
SLUDSE
(NET SLOW. 1
IDOWN 11.RGPMI
i
. » « •
, SLUDGE TO
ASH POND
CITY SEWERS
(IF ALLOWED)
. FLUE CASES
—. - QIL
LUDOE
-•-OPTIONAL ARR'OT.
116 I
NCENTRATOW
^RYEFf' ' *
MOIST SOLIDS
FOR DISPOSAL
Source: [5]
Figure 5.6 Water Rechcle/Reuse at a 1100-MW
Coal-Fired Plant (Conceptual)
-------
Ul
BOILER TUBE CLEANING,
FJRESIK » Aid PRE-
HEATED WASHINGS
TURBINE
GENERATOR
SANiTARr HASTES LABORATORY
I SAMPLING HASTES. INTAKE
SCREEN BACKWASH. CLOSED
COOLING HATER SIT Sit MS CON-
STRUCTION. ACTIVITY
SOLID WASTE FLOW *—
AIR EMISSIONS
CMCMICAU
,/•* COAL
Source: [101]
Figure 5.7 Water Management at a Typical 1980 Coal'-Fired Power Plant
-------
• Capital Cost 5-10 $/kW
• Operating Cost $1.6 $/kW
• Annualized Cost 1.6 - 5.0 $/kW
• Unit Costs 0.3 - 0.8 Mills/kWh (on base load)
5.3.4 Toxic Substances Control
The EPA's ongoing review of BAT and NSPS limits in effluents will
be focusing primarily on regulation of priority pollutants. The EPA
has initiated an effort to develop baseline information on priority
pollutants to support the establishment of effluent standards for these,
Results of studies on this will also provide useful information on
water recycle/reuse.
In order to carry out the requirements of the Consent Decree
(see Section 4.1.5), EPA collected additional information on the
production processes, raw waste loads, treatment methods, and effluent
quality associated with the steam electric industry. This information
was obtained pursuant to Section 308 of the Federal Water Pollution
Control Act Amendments of 1972. A total of 794 plants responded to
Section 308 letters. Eight of these plants were chosen for a screen
sampling program. Table 5.9 presents data on pollutants reported in
cooling towers. EPA's own screen sampling provides a detailed break-
down at eight plants [101].
It is noted in Table 5.9 that asbestos is also reported in cooling
systems. This is not unexpected since the fill material in natural
draft cooling towers is normally asbestos cement. Erosion of the fill
material can result in the discharge of asbestos from cooling water
blowdown. Ten of the 18 sites surveyed by the EPA contained detectable
concentrations of chrysotile asbestos at the time of sampling particu-
larly in basins. No asbestos was detected in the effluent to the
receiving water
5-28
-------
Table 5.9
Pollutants Reported in 308 Form for Cooling
Systems in Coal-Fired Power Plants
Total responding to 308 letters = 794
Number of plants
Compound name reporting presence
Antimony and compounds 3
Arsenic and compounds 2
Cadmium and compounds 3
Chlorinated phenols 7
chloroform 1
Chromium and compounds 140
Copper and compounds 8
EDTA 6
Lead and compounds 3
Mercury and compounds 2
Nickel and compounds 3
Pentachlorophenol 9
Phenol 2
Selenium and compounds 2
Silver and compounds 2
Thallium and compounds 2
Vanadium 2
Zinc and compounds 22
Note: In addition, acrolein and asbestos have also been reported,
Source: [101]
5-29
-------
Radian [13] in a study to assist the EPA's Effluent Guidelines
Division on priority pollutant control, evaluated the application of
carbon adsorption, lime precipitation, reverse osmosis, vapor compres-
sion distillation and evaporation ponds for priority pollutant control.
Tables 5.10 and 5.11 outline their basic results. Radian concludes that:
• Wastewater technologies mentioned above have high potential
for priority pollutant control.
• Vapor compression distillation and evaporation ponds are
used in the utility industry. However, their effectiveness
and secondary environmental impacts need better definition.
• Carbon adsorption has not been demonstrated in this industry.
Chemical precipitation and reverse osmosis have been used
but cannot be considered demonstrated for this purpose, but
have high potential.
At present, none of the control technologies have been adequately
studied for reasonably accurate cost estimates, but some preliminary
estimates were made by Radian [13]. Continuation of these and other
studies on technologies for priority pollutant control will provide
additional baseline data for potential water recycle/reuse consideration.
5.3.5 Dry Systems
The potential for water recycle/reuse within the context of con-
ventional consumptive use of water in a power plant has been discussed
in earlier parts of this section.
The need for higher quality boiler water and the increasingly strin-
gent environmental regulations will accelerate the improvements in treat-
ment technologies and the acceptance of recycle/reuse practices in the
utility industry. However, the plants will still require large quantities
of water because of the following consumptive uses.
• Evaporation and drift in cooling towers,
• Evaporation in FGD systems,
• Occlusion loss with ash, FGD and water treatment wastes, and
• Net evaporation from ash ponds to atmosphere (if applicable).
5-30
-------
Table 5.10
Priority Pollutant Removal on Selected Technologies
01
u>
CLASSES OF PRIORITY POLLUTANTS CONTROLLED
PROCESS
ACTIVATED CARBON
LIME PRECIPITATION
REVERSE OSMOSIS
VAPOR COMPRESSION
DISTILLATION
EVAPORATION PONDS
* Highly site-specific
1 Aeroleln
^
^
/
7
T
£
c
c
•a
e
4J
"§
'
'
/
/
0)
X
c
Arsenic & Compou
*
'
'
/
'
Benzene
/
^
x
/
09
•a
S
i
1 Beryllium & Comp
*
'
/
'
a
•s
1 Cadmium & Compou
^
'
•^
0)
•o
iH
1 Carbon Tetrachlo
/
^
/
/
1
00
a
§
Chlorinated Benz
'
'
/
/
n
0
C
I Chlorinated Etha
/
^
/
/
a
1 Chloroalkyl Ethe
/
•^
/
'
0
"c
| Chlorinated Phen
<
'
/
/
Chloroform
•^
^
/
/
09
X
Chromium & Compo
*
'
'
7
/
09
t)
§
0
h
a>
£
o
u
'
'
'
Cyanides
*
'
/
/
rH
O
2 ,4-Dlchlorophen
'
^
/
/
Lead & Compounds
^
'
'
ID
•C
C
1 Mercury & Cumpou
'
'
/
/
i
i-<
JC
4J
O.
SB
<
'
/
00
•o
Lckel & Compoun
z
'
^
/
•^
Ltrosamlnes
z
'
/
'
iH
intachloropheno
P.
^
^
^
'
a
tH
1
a.
BQ
>lychlorlnated
a*
'
'
/
/
u
•H
4-*
>lynuclear Arom
Hydrocarbons
P-
/
'
/
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CD
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Selenium & Compo
*
'
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•3
1 Silver & Compoun
<
'
/
•^
u
•a
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o
•£
r-(
^
^
/
/
iToluene
^
/
/
Zinc & Compounds
*
'
'
/
'
Note: This is an assessment of potential source application only.
Source: [13]
-------
Table 5.11
Comparison of Technologies for Priority Pollutants
Control Technology
Activated Carbon
Lime Precipitation
Reverse Osmosis
m Vapor Compression
1 lVfa1"M1j»ffnn
w u.u»i •••«•• u
NJ
Evaporation Ponds
Graded Media
Filter
Solid Waste
Disposal by
Landfill
*Site specific
Source:
Projected
Effectiveness
Good
Good for removal of heavy mstsls
ttftllllnSl '*rTI'%fM1t"t"—t1r'THI '"T
metals are l^ss than
.1 ppm
90-9BZ rejection of dissolved
solids; 95Z removal of
organlcs; 75Z -water
recovery
99. 9Z salt rejection;
901 water recovery
Seepage Is the only liquid
discharge from evaporation
ponds and Is dependent upon
the type of pond and liner.
Beaoves suspended solids in
the particle size range of
.1 to 50p.
Seepage is the only liquid
discharge from sludge ponds
and is dependent upon the
type of liner used and whether
the sludge is fixed or not
[13]
Estimated Sources
(kWh/1000 gal) Air
.35 From regenera-
tion step
8 — —
B-10
80-100 Vent fron
aerator
.3-. 5 Evaporation of
organlcs in the
feed water
• 3 • — -r
<2* Evaporation of
organlcs in
sludge
of Secondary Emissions
Water
Quench water
Liquid occluded
with solid
sludge
Concentrated
brine and mem-
brane backwash
Concentrated
brine Blurry
Seepage
Filter backwash
Seepage
Solid
Spent carbon if
no regeneration
is used
Sludge produced
from precipitation
— —
Solids in concen-
trated slurry
Precipitation
products produced
in pond
Solids in filter
backwash
-------
In other words, with optimum reuse in a conventional water system
at a power plant, the net consumptive requirement is considerable (about
3
56,850 m /day or 15 MGD for a 1,000-MW plant). An entirely different
approach to water management, however, is the use of dry systems. Such
systems would not employ water consumptively as a heat transfer or
materials handling medium. The three major areas of water use (condenser
cooling, ash handling and FGD) may be impacted by such potential dry
systeirs In the future.
a . Condenser Cooling
Condenser cooling is the largest consumptive use of water.
Because of constraints on water availability and environmental
regulations on thermal discharges, new condenser cooling concepts
using dry or hybrid wet/dry systems are being evaluated.
Dry systems have been described earlier. They require zero make-
up and are analogous in principle to automobile radiators. The
operating performance in Europe indicates that the plant reliability
is satisfactory with dry cooling towers [74], There is no baseline
data to corroborate in U.S. power plants. Many in-depth studies
have been done on dry tower economics [75]. In general, all dry
systems achieve zero makeup at a considerable cost penalty. A
recently completed report for ERDA indicates capital cost for dry
cooling tower system is four to five times greater than that for an
all wet cooling tower system in a 1,000-MW range plant [75].
An alternative approach would be to employ the combination
wet/dry condenser cooling system (i.e., a hybrid system)
to conserve makeup water, also described earlier. These
alternatives and the thermal performance of combined wet/
dry cooling tower systems have been reported in the literature
[76,77]. The analysis indicates that in principle, the
combination wet/dry condenser cooling systems can be used in
a power plant for cycle heat rejection. Costs data for wet/
dry cooling tower systems, were recently prepared under the
sponsorship of ERDA and EPRI [75], which confirm the high costs
associated with these systems (compared to wet cooling tower system)
5-33
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From the above discussion, it is apparent that there are
various new concepts possible for the condenser cooling
system which will substantially reduce the makeup water
requirements. However, it should be emphasized that the
principal impetus in this direction are thermal discharge
regulations(not effluent regulations). As the technology
improves: and the crunch for water supply increases, the
practical use of these new concepts in the utility indus-
try may impact on water utilization.
b. Flue Gas Desulfurization (FGD)
In wet FGD systems (recovery and nonrecovery), water is lost
by evaporation in saturating the flue gases. In nonrecovery
wet processes, water is also lost by occlusion with wastes.
In recovery wet processes, the water loss with the product
will depend upon whether elemental sulfur or sulfuric acid are
produced.
An alternative approach would be to utilize dry FGD systems.
These systems utilize various dry sorbent materials which
can be either carbonaceous types or non-carbonaceous types
(limestone, dolomite, alkalized aiiumina). The water loss
in these processes will depend upon the SO- recovery tempera-
ture (since partial cooling of flue gases by evaporation may
be necessary) and the type of product in dry recovery processes,
In general, the water consumption for the dry processes would
be less than that in wet processes. Advancements in fluidized
bed combustion technology (atmospheric and pressurized) may
also accelerate the technology of dry systems. The reader is
referred to Volume 3 for a discussion on dry sorbents.
At present, unlike the wet throwaway processes, both the
dry processes and wet recovery process have not been commer-
cialized to any great extent. Consequently, the impact on
water consumption, though anticipated to be beneficial, cannot
5-34
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be assessed at this time. However, in recent years, there
has been an upsurge of interest in dry sorbent systems.
In 1978 three commercial-size orders were placed for dry
sorbent FGD units which would be in operation by the
early 1980's.
Ash Handling
The most prevalent method of ash handling in coal-fired
power plants in the United States is by wet (hydraulic)
systems equipped with disposal ponds. Even if these
systems are adapted for water recycle, water will be lost
from these systems by occlusion with ash waste and in some
cases also by net evaporation to atmosphere.
An alternative approach would be to use dry (pneumatic)
ash handling systems. Besides decreasing water consumption
(compared to all wet systems) , such systems may offer
potential advantages for the ultimate ash disposal and
utilization. Certainly, if dry ash handling systems are
utilized, the recycle/reuse potential for other plant
streams will also be affected. For example, the cooling
tower could be operated under increased cycles of concen-
tration, thus reducing the flow to the brine concentrator.
While bottom ash handling is usually by wet sluicing, a
significant number of plants use dry fly ash handling.
Table 5.12 summarized the present situation.
Dry (pneumatic) fly ash handling systems can be of vacuum,
pressure, or a combination type [50]. Vacuum systems are
limited in length by the configuration and the plant altitude
above sea level and in such cases pressure systems can be
employed. Vacuum-pressure systems are usually economical
where a number of precipitator hoppers are employed and
where the length of conveying system exceeds the capability of
a vacuum system to attain a satisfactory conveying rate [50].
5-35
-------
Table 5.12
Summary of Fly Ash Handling Systems
Reported By Coal-Fired Steam Electric Power Plants
Dry 193
Wet (once-through) 164
Wet (recycled) 17
Not reported* 413
Total surveyed 787
Includes plants which did not report or other
systems not surveyed.
Source: [101]
5-36
-------
If the fly ash is to be removed from the plant in a dry state,
a minor quantity of water is sprayed on the collected fly
ash to prevent fugitive dust during transportation.
Cost estimates for dry ash handling systems are reported [5].
Updating these to mid-1978 levels, a dry ash handling system
for a new 1000-MW coal-fired plant (design capacity of 181
metric tons 200 short tons/hour of ash) may cost about $4.2
million installed ($0.42/kW).
Recently, a study was conducted by the utility industry to
evaluate the cost of dry vs. wet fly ash removal for new
power plants [107]. The study concludes that for a new
plant, dry handling is less expensive than wet. Estimated
costs for wet and dry handling systems are shown in Table
5.13. However, many site specific factors affect costs
and hence, this conclusion may need modification in
some cases.
The Remand Decision (Section 4.1.4) required that EPA
has to demonstrate dry fly ash handling in a viable
technology. At present there is substantial evidence
that this is so. An assessment of this question indicates
that in the future at least for new plants, dry fly ash
handling may be required.
5-37
-------
Table 5.13
Fly Ash Handling: Comparison of Wet and Dry System Costs
Basis: 1. 9.2 MM tons of dry ash over 35 years. Storage volute of 11.4 MM cu yd for vet, 9.08 MM cu yd
for dry. 5' water cover for dirt. l"-3" compacted soil for dry.
2. Costs In 1974-75 dollars.
Fly Ash Handl'ing Equipment $ 2.00C.OOO $2,000,000
Installation Cost (50%) .1,000,000 1.000,000
Return Line From Pond (Gravity) 750,000 —
Road Construction (Incl. Loading (T) 600,000
Area Collection Facilities)
Pond Construction 11,280,000 —
Disposal Site Preparation and
Rainfall Runoff Treatment Facility — 1,836,000
Total Construction Cost 15,030,000 5,436,000
Engineering £ 15% 2,250,000 815,000
Contingency @ 15% 2,250,000 815,000
Land Cost 9 $3,000/acre 1,020,000 720,000
Total Capital Cost 20,550,000 7,786,000
Fixed Charge @ 15% 3,082,500 1,168,000
Annual Operating Cost
Labor, Maintenance, Power on Equipment 136,000 115,000
Road Maintenance — 11,000
Hauling $ $l/yd3 — 325,000
Dozer Ope-ation @ $300/day, 5 day week, — 78,000
52 weeks/year
Total Annual Cost 3,218,500 1.697,000
Tons/Year 262,800 262,800
Cost/Ton 12.25 6.46
1 An access way is required for maintenance. Cost for this item is very site specific but
probably snail in comparison to other costs.
Source: [105]
-------
5.4 Overview on System Constraints
5.4.1 General
The factors that affect the extent and nature of water recycle/reuse
at power plants may vary from the relatively straightforward, such as the
limited availability of water supplies at the plant site to a complex
combination of factors such as effluent regulations, economic considera-
tions, energy usage, space requirements, and social considerations in-
cluding aesthetics as well as environmental factors. For each power
plant there is probably a unique combination of these various factors
that will be considered in arriving at the operational choices that
will determine the magnitude of water recycle/reuse. To the extent
possible in this area of shifting factors, some of the effects that
should be considered by the EPA in establishing a posture on recycle/
reuse by power plants are discussed in this section. The regulatory
considerations are discussed separately in Section 4.0.
5.4.2 Technology Considerations
The technologies for providing a water stream of virtually any
desired quality have been available for a long time. However, of
paramount consideration are the economic implications that the applica-
tion of these technologies might have on the electric power generating
industry. Historically, the application of available technologies has
been limited to specific areas such as boiler water treatment. As a
consequence, there are only a limited number of demonstrated processes
or systems of water recycle/reuse and these are predominantly, of course,
for the recirculation of cooling waters. The steam-electric generating
industry, like many other industries, is reluctant to concede to some
extent that technology transfer can be utilized in predicting the perfor-
mance of technologies in its industry. Consequently, virtually every
utility stresses the importance of projects for demonstration of tech-
nologies. While these demonstrations are necessary, especially in
showing the effectiveness of removal of trace constituents and defining
economics of the technology, the large-scale demonstrations of water
recycle/reuse technologies may not always be necessary from a technological
5-39
-------
basis. In fact, for the important parameters of a recycle/reuse system
such as chemical compositions, control of scaling and/or corrosion, total
dissolved solids content, and so on, the application of well-known prin-
ciples of chemistry coupled with limited amounts of field and laboratory
testing can result in development of broad .design and operational para-
meters for a water recycle/reuse system. However, engineering data including
kinetics and operational considerations are required for reliable design.
While the availability of technologies for effecting high degrees
of recycle/reuse of water is reasonably established, the availability
of information on the implication of these technologies on the power
plant design and operation has not been demonstrated to any significant
degree. Consequently, most of the data on the implication of water re-
cycle/reuse technologies on power plant design and operation must be
based on engineering studies. However because site-specific factors
such as the quality of makeup water, quality of water bodies receiving
discharges, and so on, have such unique effects on water recycle/reuse
systems, at least a preliminary engineering study is required for deter-
mining the magnitude of the effects. In general, as water is increasing-
ly recycled or reused, the quality not only deteriorates, but the inter-
relationship between controls of the water recycle system and the power
plant become increasingly significant. Consequently, in an industry
where past water usage has been largely on a once-through basis, the
introduction of requirements for controlling the quality of recycled
water and the engineering and operational aspects of water treatment
systems and controls would mandate a drastic change in operational phil-
osophies which, as in any situation, is often resisted as much on tech-
nological bases as on economics. Obviously, there will be significant
impacts on the power plant designs and operations as increasing amounts
of water are recycled or reused. In particular, the changes in the
quality of water, e.g., temperature, total dissolved solids, corrosivity
and so on, can be reflected in the need to change design and operations
with their concomitant effects on plant performance.
5-40
-------
As discussed earlier, there are many facets of water management
that are considered by the electric power generating industry, and,
consequently, there is no clear cut consensus. However, it appears
generally that the degree of recycle/reuse considered in the industry
is inversely related to the availability of a water supply of adequate
quality and quantity. It is apparent, also, that the degree of recycle/
reuse is, or will be, most affected by environmental regulations on
discharges. As these regulations approach the 1985 goal of PL 92-500,
the rate of water reuse throughout the industry will perforce increase
because the alternatives of technologies and economics will have com-
bined to force that position. (See Section 4.0.) Consequently, the
interrelationship between recycle/reuse, potential minimization of dis-
charge, and economics becomes increasingly strong. The elements of
the interrelationships will increasingly be concerned with the environ-
mental law so aptly stated by Barry Commoner, i.e., "there is no such
thing as a free lunch."
5.4.3 Economic Considerations
Because pollution is a diseconomy spread across the population and
environment in a manner often not readily perceived, i.e., the immediate
effects may be apparently limited to small areas while the subtle im-
pacts often take decades to be perceived, the costs of the environmental
impacts are not readily perceived nor precisely estimable. On the other
hand, the costs of recycle/reuse systems required to mitigate the envir-
onmental impacts are immediately perceivable in the form of increased
capital and operating costs by the management and increased electricity
costs by the consuming public. Consequently, the industry will be con-
tinually concerned with the costs of recycle/reuse while questioning
the benefits to be gained. On the other hand, the environmental activists
will be strongly concerned with the benefits gained. While it is rela-
tively easy to establish the costs of recycle/reuse systems, unfortunately
it is much more difficult to establish the benefits that accrue in areas
such as health, aquatic life, overall aesthetics and so on. Therefore,
it seems likely that there will be an increasing debate regarding the
cost/benefits of recycle/reuse systems.
5-41
-------
Increasingly stringent regulations on specific chemical species,
i.e., the toxic, hazardous, or priority pollutants, would be expected
to result in either elimination by replacement with other acceptable
substances, or the introduction of appropriate removal systems. Since
it appears that these priority pollutants will be principally organic
compounds, the allowable concentration levels in recycle systems will
probably be treatment of a small stream for their removal and either
returning this stream to the recycle loop or discharging it at permitted
levels of concentration. The cost of toxics removal from a once-through
water stream versus the costs for recycle and removal would be dependent
upon the particular toxic substance, the permitted concentration limits
in discharges, and the usual site-specific parameters.
The problems of capital acquisition and investment as well as the
increased operating and maintenance expenses incurred by installation
of recycle/reuse systems in the electric utility industry are unusual
in their magnitude, i.e., the large quantities of water that must be
handled and treated. In this regulated industry, the costs for water
handling systems in combination with air and solid waste pollution con-
trol systems will present the utility rate regulators with increasing
problems. It can be expected that passing these added costs on to the
public, will result in further increasing the intensity of the politicians
speaking out against rising energy costs. Since there are no simple
solutions—only hard choices—the environmental regulatory agencies will
be faced with increasing need to consider the total economic impact
of their regulations and must be alert to those economic considerations
if they are to maintain their credibility with the public.
5.A.4 Other Considerations
Energy Requirements
The utilization of increasingly higher rates of recycle/reuse in
consort with tightening regulations on emissions to the environment will
increase the energy requirements for support facilities, i.e., many of
which will be considered to be non-productive by industry operators.
It is axiomatic that these trends will increase energy usage either
5-42
-------
directly, e.g., through the need for more pumping of water streams, or
indirectly in the energy required to provide the materials of construc-
tion, the treatment chemicals, and so on. The magnitude of the energy
usage for pollution control systems varies widely and is principally
related to air pollution control. Depending upon the sulfur content
of the fuel, the energy usage for pollution control may be as great as
7% to 10% of the total energy content of the fuel for a high sulfur
content fuel.
Space Requirements
The type of recycle/reuse water system selected will be dependent
to a large degree upon the site situation. Where large land areas may
be available, the cooling pond seems to be the method of usual choice
while in more restricted areas the cooling towers find greatest use.
Of all of the recycle loops, the cooling loop and the ash-handling loops
are those having the greatest space requirements. For urban plants of
limited space, the decisions on recycle/reuse systems may be dictated
by the terrain, land availability, and atmospheric conditions.
Other Requirements
Other considerations such as aesthetics, e.g., the tall hyperbolic
cooling tower versus the cooling pond or forced draft cooling tower,
would have effects on the type of recycle/reuse systems employed. Many
of these limitations will probably be site-specific and highly dependent
upon the nature of the social pressures that might be generated at
specific locations. It is highly doubtful in our vocal and advocacy
oriented society that any clear cut consensus is likely to be attained
on the degree to which water recycle/reuse systems should be incorporated
into power plants.
5-43
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6.0 RECYCLE/REUSE VERSUS POTENTIAL IMPACT ISSUES
6.1 Overview of Impact Issues
The large volumes of water required for electric utility operation
result in a number of impact issues associated with such operation.
Major issues focused on in this section include those associated with
waste heat rejection and ash disposal (FGC wastes are considered separate-
ly in this report). The engineering basis for water use at various
points and water effluent generation have been discussed in Section 3.0.
In this subsection, the focus will be on the potential environmental
impact issues and how they may be altered by water recycle/treatment/
reuse. It may be noted that the principal focus of this R&D Report
±8 the chemical waste streams and not the thermal wastes. However,
insofar as the latter have chemical contamination they have been con-
sidered. These are reviewed in Table 6.1, noting that the degree of
impact potential is relative to system design and site-specific environ-
mental characteristics. Along with FGC waste systems, these represent
the major water use processes within utility operation.
Traditional cooling systems have utilized once-through cooling
whereby intake water is passed through condensers and returned to
surface waters. The large quantity effluent typically contains
corrosion products (metal oxides) and biocide treatment chemicals
(chlorine or hypocMarite) in addition to waste heat energy. The major
impacts associated with once-through cooling systems include:
• Potential for impingement and entrainment of aquatic
organisms at intake ports,
• Potential damage to aquatic systems due to large volume
heated effluents, and :
• Toxicity potential of discharged residual chlorine as well
as chlorinated compounds resulting from the mixture of
treatment chemicals with constituents in intake waters.
The degree of impact is related to design of intake and effluent
systems and the size and type of water body (e.g., lake, river estuary,
marine coastal) on which the facility is located. Where water supply
6-1
-------
Table 6.1
Potential Impact Issues for Coal-Fired Utility Cooling Systems and Ash Disposal Systems (See Key)
t/Dry
Cot Olapoaal
Svvtca
art Bl»»oa«l trataaa
ateyclo
Uapoatl
DTT BUiaaal
r*lulv« wilt*
a* IIM • •••li>|
»n 11 h»i/«aal»a
I
N3
(•iota)
Caallai Naur
(1000)'
Cool 104 MMUT
Iffluoat Tralelcr2'4
itnctloa.
(X>-90)
ortft aad.Man
UO-40)*
Mf' at ToxicltT
,«.*
Iff
:h»t*r^/T it" •"**-•
M,.,r««.2
•»»•*
IntralaaTarmc
tlflumt
J.4
latal
Urianu ToiUlty
,*•*
.*.»
1 Tfc*M *nalt«" art tymam •pacific aad *o[ for
-------
is limited, the impact potential of once-through cooling for large
facilities is severe. The more recent location of power plants near
large bodies of water reflects this, although concern over the cumulative
effect of increasing numbers of such facilities even on large water
bodies, such as the Great Lakes, has been noted [79],
An existing alternative focuses on reuse of water within the
utility system. Recirculation of cooling water is practiced at present
in approximately 40% of steam electric utilities [80]. In such system
design, far less intake water is required (needed for makeup water) with
effluent volumes, from blowdown of recirculating water, also signifi-
cantly reduced. Impacts associated with recirculating systems can
include large land areas where cooling ponds are used, increased potential
for makeup water treatment, and increased concentrations of water con-
stituents from water losses due to drift and evaporation during the
cycling process. Where blowdown water is utilized for fly ash transport
or bottom ash sluicing, additional toxic contaminants could be present
in the water finally discharged. Water quality in the effluent or re-
cycle blowdown is not only dependent upon system design, but also related
to intake water quality and "waste" water treatment capability [80]. In
addition, contaminants present in seepage from ponded areas or in tower
drift may represent impact issues.
Water requirements for ash disposal are at a maximum with once-
through sluicing systems, and essentially eliminated in dry systems
utilizing pneumatic transport. Contaminants present in discharge water
in hydraulic systems, along with potential seepage of contaminants from
ash ponds themselves, also represent impact issues. The degree of impact
is again, site-specific. In general, contaminant concentrations in coal
ash, coal ash leachate and supernatant water have a more significant
impact potential.
The discussion that follows focuses on major environmental impact
potential, in a generic sense, associated with water/recycle/reuse cool-
ing systems and ash disposal systems. It should be emphasized that the
purpose of this discussion (as well as summary Table 6.1) is not to
-------
represent a comparison of cooling system and ash disposal impact
potential, but rather to discuss the impact potential of various system
designs within each process. Where possible, some comparisons are made
to aid the reader in understanding relative degrees of impact potential.
However, site-specific considerations can make judgments of impact
potential inappropriate for such comparisons. Further, it should be
noted that certain system approaches represent recent technology or
technology where applicability to utility operations has not been demon-
strated. In such cases, the degree of impact potential is even more
difficult to define.
6.2 Mechanisms of Impact
6.2.1 Land Related
The most significant land related impact issue associated with
cooling water recycle/reuse is derived from the large land requirements
for systems utilizing cooling ponds. In one review, it was estimated
2
that large facilities may require 4.1 km (1,000 acres) of pond cooling
surface. In addition to siting considerations (land availability) and
economic feasibility (e.g., land purchase costs), major impact issues
concern implications for concentration and/or migration of contaminants.*
If zero discharge is chosen as a goal for a power plant, then on-
site disposal of brines and sludges becomes a major consideration. Con-
sidering the trend of environmental legislation, and the future develop-
ments on priority pollutants. This is especially important for new plants
Such impact potential would certainly be site specific, utility
design specific, and include:
• The type and amounts of chemical treatment additives in
the ponded cooling water;
• The site-related potential for leaching of contaminants
into groundwater supplies (based on soil/geology considera-
tions; also a water related issue);
Aesthetic/noise considerations are essentially site-specific impact
issues which, in some cases, can be significant.
6-4
-------
• The site-related potential for pond overflow dam failure
with subsequent surface water and land impacts;* (based
on topographic and location considerations; also a water
related issue); and
• The potential for contaminant build-up in pond bottoms
that could represent long-term contaminant sources, even
after closure of the site.
The types of chemical additives referred to in the above list are
discussed in further detail in the sub-section immediately below. In
addition, completely closed system impact issues may develop as a result
of land disposal of water treatment wastes. This potential would be
directly related to waste characteristics and disposal methods.
Similar impact issues also apply to ash disposal ponds. However,
land requirements are generally less, as pond surface area is not a
determining factor in pond design.
Impact issues related to contaminant concentrations are generally
far more significant for ash ponds. The high concentrations of con-
taminants (dissolved salts and trace metals are examples) in the ash
itself, associated supernatant and in leachate represent significant
impact potential. Contamination migration is a key issue associated
with ash disposal ponds. Site-specific soil or geological characteris-
tics may serve to contain seepage, but where such containment does not
exist, water related impacts may result. Post closure land use
potential of ash disposal ponds also represents a significant impact issue.
For example, revegetation may be difficult without a soil cover. Upward
migration of contaminants with subsequent incorporation of certain
toxicants into the food chain may represent health and environmental
Impact issues. (See Section 6.0.) Ash pond dam failure with subsequent
ash liquefaction, (an "abnormal event" impact issue) could result in
significant impacts to downstream land and water users. The impact
*Dam failure represents an "abnormal event" impact. The design of waste
pond dams is a well established engineering practice with risks of failure
fairly well understood. Cooling pond dams, where they exist, would fall
into this category.
6-5
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potential of ash pond failure would be dependent upon pond size and
site topography. Dam design would be similar to that utilized for
other types of disposal ponds and, as such, represents a developed
engineering practice with relatively well-defined risk potential.
6.2.2 Water-Related
The discussion of water-related impact issues associated with dry
or recycle systems for waste heat rejection and ash disposal are of
necessity generic in nature due to specific, site-related conditions and
operational practice.
6.2.2.1 Issues Associated with Cooling Systems
While much of the discussion in this section will focus on the
water-related impact potential of recycle/reuse cooling water systems,
it is important to note that such systems were designed to mitigate two
of the most significant impacts associated with once-through cooling
systems: namely, large volume water intakes and large volume heated
discharges.
Recycle/reuse technology significantly reduces net water intake re-
quirements, even though consumptive use may remain the same. Thus,
recycle/reuse reduces impacts associated with such requirements. The
degree of impact reduction is dependent upon system design and site
location. If cooling tower blowdown is discharged, water intake for
recycle systems can be reduced over an order of magnitude below once-
through cooling water requirements. (See Table 6.1.) In practice, the
reduction has been much less in many cases due to intake water quality
and subsequent cycles of concentration, along with other system operat-
ing design and parameters. Such reduction in water requirements is
especially significant in areas of limited water availability. Com-
pletely closed power plant recycle/treatment/reuse water systems could
potentially reduce net water intake requirements by over 95% of that
required or once-through cooling systems with further reduction in water
impacts; however, consumptive use remains the same.
Recycle cooling water systems also mitigate the impacts associated
with the large volume heated discharges of once-through systems. While
major reductions in impact potential are biological (discussed below),
problems such as decreased oxygen saturation levels and alterations in
6-6
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rates of chemical reactions in natural ecosystems are reduced signifi-
cantly with recycle/reuse systems.
Recycle systems do require makeup water and, depending upon the
source of that water, chemical treatment may be required. The concen-
tration of non-volatile dissolved solids increases with increasing numbers
of "cycles of concentration", the latter being based on intake water
quality (especially dissolved solids content) and system operating practice,
Chemical treatment is often required for:
• corrosion inhibition,
• scale control,
• biofouling control, and
• dispersal of suspended solids.
"Slowdown" is required in such systems to control concentrations of
impurities and contaminants in the condensers. As such, blowdown
water quality will be dependent upon:
• makeup water characteristics,
• chemical treatment(s) used,
• air-water contact in the cooling system, and
• cycles of concentration .
The impact potential of blowdown waste water streams is thus related to
these operating characteristics.
Table 6.2 lists the more typical chemical additives that may be
added for control of each of the noted operational problems in cooling
tower recycle systems (ponding recycle systems would be similar). It
should be noted that a selection, and not all of the listed additives
would be chosen.
Effluent concentrations of added constituents are difficult to
estimate without information concerning makeup water quality. Residual
chlorine levels themselves may be problematic, although most concern
over this contaminant is related to aquatic biota impacts [79]. The
formation of chlorinated hydrocarbons, because of their toxicity
potential, are receiving increasing attention. The amounts and types
formed are the result of intake water organic content, the nature and
types of organic additives, the level of chlorination used and resultant
6-7
-------
Table 6.2
Examples of Chemical Additives Characteristically Found in Cooling Tower
Slowdown as a Result of Makeup Water Treatment
No. Effluent Stream
Cooling Tower
Slowdown
i
oo
Process or
Operation
Corrosion Inhibi-
tion
Scale Control
Biological
Fouling (Algae
Slimes, Fungi)
Suspended Solids
Dispersion
Leaching of wood
preservatIves
from wood cool-
Ing towers
Chemical
Addttlve(s)
Chrornate
Zinc
Phosphate
Silicates
Proprietary Organics
Typic.iI Cone, of
Add it ivc or
Hoilutanc
10-50 mg/1 as CrO
8-35 mg/1 as Zn
15-60 mg/1 as PO
3-10 mg/1 as organic
2-5
Ri-siil t Ing Priority
Pollutant Expected
In Effluent
Chromium
Zinc
Expected Cone
of Pollutants
In Effluent
10-50 mg/1
8-35 mg/1
Comment 6
Acid (H SO )
Inorganic Polyphosphates
Cholatlng Agents
Polyelectrolyte 1-2 mg/1
Antipreclpltants
Organic/Polymer Dlspersants 20-50 mg/1
Chlorine
Hypochlorlte
Chlorophenates
Thlocyanates
Organic Sulfur Compound
^O.S.mg/1 residual
-30 mg/1 residual
concentrations
Tannins
Llgnins
Proprietary Organlcs/Polymers 20-50 mg/1
Polyelectrolytes/Monionlc
Polymers 1-5 mg/1
Acid Copper
Chromate
Chromated Copper
Arsenate
Creosote
Peneach lorophenol
Unknown
Unknown
Unknown
Unknown
Potential priority
organics
Chelates heavy
metals
Potential priority
organics
Chlorinated Phenols
Cycanlde
Potential Priority organics
Chromium
Arsenic
Pentachloroplienol
Organics can react with
residual chlorine to form
chlorinated compounds
Organics can react with
residual chlorine to form
chlorinated compounds
Supplies free chlorine fa-
reaction with organics to
form chlorinated organics
Organics can react with
residual chlorine Co forn
chlorinated compounds
-------
Table 6.2 (Continued)
Examples of Chemical Additives Characteristically Found in Cooling Tower
Slowdown as a Result of Makeup Water Treatment
No. Effluent Stream
Boiler Slowdown
Procesi or
Operation
Scale Control
Corrosion Control
pH Concrol
Solids Deposition
Chemical
Addttlve(t)
Typical Cone, of
Additive or
Pollutant
01 & Trl Sodium Phosphates 3-60 mg/1 of PO,
Ethylene
dlamlnetetracetlc acld(EDTA) 20-100 mg/1
Nltrolatriacetic acld(NTA) 10-60 mg/1
Alglnates 50-100 mg/1
Polyacrylates 50-100 mg/1
Polymethacrylatea 50-100 mg/1
Resulting Priority
Pollutant Expected
In Effluent
Chelates heavy
metals
Expected Cone.
of Pollutants
in Effluent
icnt s
Sodium Sulfite
Hydrazlne
Morpholine
Sodium Hydroxide
Sodium Carbonate
Ammonia
Morpholie
Hydrazlne
Starch
Alglnates
Polyacrylamldes
Polyacrylates
Tannins
Llgnln Derivatives
Polymethocrylates
'200 mg/1
5-45 mg/1
5-45 mg/1
variable added to adjust
pH to 8-11.0
20-50 mg/1
20-50 mg/1
20-50 mg/1
20-50 mg/1
<200 mg/1
^.200 mg/1
20-50 mg/1
Water Treatsent
Including
Slowdown Uaatea
Alua) Treatment and
PlltrMtlon
Ion Exchange
Water Treatment
Regenerant Solutions
added to reactivate bed
Priority pollutants
present In aource
water
Significantly higher
concentration* than
source water
-------
No. Effluent Stream
Ash Handling
Table 6.2 (Continued)
Examples of Chemical Additives Characteristically Found in Cooling Tower
Slowdown as a Result of Makeup Water Treatment
Process or
Operation
Coal Ash Slulc- Hone
ing
(fly ash and
bottom ash)
Chemical
Additlve(a)
Typical Cone, of
Additive or
Pollutant
Resul t injfr ^fi lorl tjr
Pollutant Expected
In Effluent
Expected Cone.
of Pollutants
in Effluent
Cements
Pollutants in »luic« In addition to
water before sluicing Source Hater:
Cadmium
Chromium
Copper
Lead
Trace metals In the cod
or oil are leached Into
the sluicing liquor
Nickel
PCD Systi
I
t-1
o
Miscellaneous
Lime/Limestone
Lime or Limestone
TDS-25.000 to 70,000
Cadmium
Arsenic
Mercury
tit IIP V»
Alkaline Fly Ash
Dual Alkali
Lab & Sampling Sanitary
Intake Screen Backwash
Auxiliary Cooling
Can be leached to
surface or ground-
water
? Chemical Cleaning
boiler waterside Acid Solvents and Toxic
cleaning and Solvents
condenser water-
side cleaning
boiler fireside Water or slightly alka-
line wash
Phosphates
Nickel
Zinc
Aluminum
Copper
Iron
nickel
chromium
vanadium
zinc
Heavy metals 'are
dissolved into the
cleaning solution
from equipment sur-
faces
Much of the prior-
ity pollutants con
from dissolution
of deposits on b *
boiler tube surfae
The deposits orig-
inate in the coal
or oil burned
-------
Table 6.2 (Continued)
Examples of Chemical Additives Characteristically Found in Cooling Tower
Slowdown as a Result of Makeup Water Treatment
No. Effluent Screen
Coal Storage fc
Handling
Process Spills
and Leak*
Process or
Operation
Rainfall/runoff
Floor & Yard
Drains
Chemical
Additlvc(s)
Typical Cone.
Addjtlve or
Pellutant
of
Accidents Involving
general plant operations
Resulting Priority
Pollutant Expected
in Effluent
Aluminum
Sulfates
Chlorides
Iron
Cadmium
Beryllium
Nickel
Chromium
Vanadium
Zinc
Copper
Expected Cone.
of Pollutants
in Effluent
Depends on Intake
water
Comments
Dissolution of
trace metals into
water
-------
residual chlorine content. Chloramines may also be problematic where
ammonia levels are sufficiently high in intake and/or receiving water,
or the potential exists for atmospheric scrubbing of ammonia. The
presence in effluents of present or future "priority" organic pollutants
due to additives is also receiving increasing attention.
Elevated levels of inorganics (some of which are also "priority
pollutants"), either due to cycles of concentration and/or added chemicals
have been examined. In one examination of blowdown water from 11 cooling
towers, 7 were from air conditioning plant towers, and 4 were from power
plant cooling towers. The following are some general observations made
from this sampling program [80].
• Zinc concentrations, where zinc was used for treatment,
were well in excess of currently acknowledged levels of
toxicity to aquatic organisms.
• Ammonia, in some situations, might not meet effluent
standards. Ammonia, along with nitrates and phosphates,
could be sufficiently high to stimulate eutrophic
conditions in certain nutrient-limited receiving waters.
• Concentrations of copper, iron, manganese, mercury,
nickel, and cadmium could exceed water quality criteria.*
• Chromium, where chromates are used, can be sufficiently
elevated to potentially produce adverse effects on
aquatic biota.
• Sulfates (where sulfate chemicals are used) may be in
excess of water quality objectives.
• Atmospheric scrubbing could potentially be the source
of lead, chromium, and other trace metals.
The above discussion does not assume treatment of blowdown waste streams,
hence identifying worse case type impact potential. Treatment technology
and specifically, toxic substances control were discussed in Section 6.2
above.
*It was noted that a significant source of mercury could well be intake
water. Atmospheric scrubbing or leaching of residual mercury from towers
where mercury-based biocides were previously employed were hypothesized
as potential sources.
6-12
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Water in cooling ponds would contain the same additives found in
blowdown water, although concentrations of specific parameters might
vary. Contaminant seepage from such ponds is a potential impact.
The degree of impact potential to groundwater systems is not well
defined as an issue, and would be site specific.
Several water-related impact issues remain. The first is the use
of alternatives in the treatment of cooling tower water. The problems
with residual chlorine*and the potential for formation of chloramines
and chlorinated hydrocarbons with the associated environmental impact
potential has led to a review of alternatives to present common
practice including: [81]
• More efficient chlorine use (e.g., serial dosing, use of
dechlorination chemicals, blowdown tinting control, and
chlorination by feedback control of chlorine residual);
• Chemicals other than chlorine; and
• Physical chemical methods.
The first example would reduce discharge of chlorine residuals,
thus reducing impact potential. It should be noted that while de-
chlorination chemicals could remove free chlorine, combined chlorine,
and are effective for chloramines, they are Ineffective in reduction
of other chlorinated organics . The degree of problem associated
with the latter compounds is dependent on intake water chemistry and the
other types of chemical treatment utilized. Bromine chloride, chlorine
dioxide and ozone have also been considered as alternative biocides, and
from one review, it would appear that water-related impacts would be
reduced with their use on a per water volume basis [81]. Ozonolysis
has not been utilized in cooling tower water systems in the past, and
while the technology and economics of generation of ozone have Improved,
lack of residual protection and field demonstration prevent analysis of
its use as a biofouling control agent as well as its water impact
potential [81]. Field scale use of both chlorine dioxide and
*Dechlorination chemicals are not presently utilized except in very few
power plants.
6-13
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bromine chloride is ongoing and indicate environmental improvements
over chlorination: Cl 09 does not react with aranonia, nitrogenous
compounds or most organic impurities before oxidizing them; the products
of chlorobromination containing ammonia or organic nitrogen are more
easily degraded, and less obnoxious than comparable byproducts of
chlorination. Physical-chemical methods of treatment (e.g., radiation)
have not been field tested and chemical additives may be required in
any case [81].
With the impact issues associated with the use of chromium compounds
or zinc/chromium compounds for corrosion protection in the condenser
system, several available options could be utilized. These include:
• Recycle of all cooling tower blowdown,
• Recovery and removal of chromium and zinc from the
effluent, or
• Non-chromate corrosion control and/or better materials
of construction to resist corrosion.
The first two are certainly directed toward elimination of potential
impacts due to zinc and/or chromium. Examples of non-chromate control
are listed on Table 6.2. The impact potential of such compounds
where blowdown water is discharged is dependent in part upon levels
occurring in the effluent. Organic corrosion inhibitors can be
chlorinated in chlorinated systems and could potentially be quite toxic.
Increased phosphated loading, where significant, can lead to increased
eutrophication.
The above discussion assumes direct discharge of blowdown water,
without contact with other operating systems within the power plant.
The design of water use in some facilities can include contact of blowdown
waste streams with fly ash and bottom ash wastes. In tliese situations,
the cooling tower waste stream is utilized for transport or sluicing
of ash. In such cases, additional toxicants (salts and trace metals,
for example) could be added to the waste stream in significant amounts.
Levels in discharge would certainly be system specific due to:
6-14
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• Makeup water and treatment for cooling tower use,
• The type of coal used, and
• Treatment of waste water stream prior to discharge.
The variables make it difficult to describe impact potential in the
generic sense.
Additional reductions in water requirements can be achieved with wet/dr
hybrid systems and dry cooling systems. The latter system type essentially
eliminates potential water-related impacts of the sort that have been
identified for wet systems.* Some makeup water is required for hybrid
systems, but amounts needed are at least an order of magnitude below
other recycle system requirements. • (See Table 6.1.)
6.2.2.2 Issues Associated with Ash Disposal
Several major water-related impact issues are associated with ash
disposal: water use for the disposal process, discharge of overflow or
blowdown, and seepage losses from disposal ponds.
In the United States, hydraulic conveyance of fly ash is a
common handling method: however, many plants do handle fly ash by
pneumatic means. Bottom ash may also be sluiced to an ash pond. Water
requirements for such disposal systems are may-timim with once-through
water use. While relative water requirements values used on Table 6.1
were computed for typical ash disposal and cooling systems separately,
and hence, cannot be directly compared, the numbers were computed in a
manner that allows relative order of magnitude comparison. Although
ash disposal is one of the major water use processes, once-through
systems do not approach water requirements for once-through cooling
systems. Recycling of sluicing water does not achieve the same
relative degree of water requirement reduction as is true for recycle
cooling systems because of water retention by ash and seepage losses.
In present practice, recycling is limited to bottom ash sluicing
water, while recycle of fly ash water is theoretically feasible,
it is far more difficult because of its dissolved solids content.
Constraints on such recycle systems are discussed below in Section 5.4.
Impacts related to abnormal events, such as spills from broken pipes
in dry cooling systems, are not normal operating impact issues.
6-15
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Pneumatic transport of ash for disposal, a dry system, is used by
European utilities and available in the U.S. This would essentially
reduce water requirements to zero (some wet down water for preventing
dust emissions might be required).
The second major water impact issue associated with ash disposal
is the discharge of pond overflow (or blowdown in recycled systems).
The degree of impact potential is dependent upon such site-specific
considerations as the size of receiving water body, and makeup water
source, as well as coal composition. Overflow water may contain
elevated levels of suspended solids, dissolved solids, trace metals,
and possibly radionuclides (depends upon coal burned) [82]. Levels
and types of organic compounds are not well documented [82], Use of
other waste streams, such as cooling tower blowdown, coal pile runoff
or cleaning wastes may significantly increase levels of oil and grease,
solids, organics, or trace metals in the ash handling waste stream.
Such discharges are not associated with dry systems.
The third major water issue associated with ash disposal systems
is seepage from ash ponds. The discussion here focuses on those ash
ponds where settling takes place, although the same issue applies to
final ash disposal, such as in a landfill. Up to 10% of fly ash can
be water soluble, thus the potential exists for leaching from ash ponds
(dry or wet). Trace metals and soluble species such as calcium,
magnesium, potassium, sulfate, and chlorides represent some of the
typical leachable constituents and the pH is typically in the alkaline
range. While the potential exists for migration into groundwater, site
specific soil and geological conditions are likely to determine the
degree of migration potential. Hence, the degree of groundwater Impact
potential of such seepage is not well established [82]. The potential
for upward and lateral migration of solutes is also an impact issue.
Groundwater levels, surface evaporation, soil cover, and rainfall play
roles in determining the relative degree of potential impact.
Additional water-related impact issues concern events that are
either less frequent or classified as abnormal. Dam failure .would be
6-16
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an example of the latter (see Section 6.2.1) with risks fairly well under-
stood and similar to those associated with dam construction for many types
of waste ponds. The potential for impact on surface water bodies, should
failure and ash liquefaction occur, could be great, but would depend upon
site-specific relative locations of ash ponds and such water bodies.
Depending upon local topography and pond construction, surface run-
off with precipitation events could also represent a potential for
impact to local surface waters. Concentrations of suspended and dis-
solved solids, trace metals, and other ash pond contaminants could
potentially be significant; but contents of such non-point source
additions to surface waters (or soils) are not well documented [82].
By one estimate, the quantity of elements discharged to slag and
fly ash ponds per year may be as high as or greater than 10Z of the
natural weathering rate for some elements. Such estimates pose the
issue of impact potential of increased mobilization on the ecosystem.
This is especially true for water systems, due to discharge, runoff,
seepage, and atmospheric fallout contributions.
6.2.3 Air-Related
Air-related impacts are not a direct issue in water usage in power
plants. They are briefly noted here because recycle system for cooling
water do create some air impact issues not present with once-through
cooling.
The key air-related issues associated with vet recycle cooling
systems concern the potential for cloud and/or fog formation (dependent
upon system design and climatic conditions) and water/contaminant losses
with drift. In both cases, the impact potential IB greatest with the
use of cooling towers. The significance of Impact potential associated
with local weather modifications (if and when they occur) would be related,
in part, to the density of surrounding development. Drift droplets can
potentially contain any of the constituents present In cooling water and
transfer them to points of deposition. Drift deposition may result in
accelerated corrosion in structures within drift transport range. Effects
of containment deposition on biota, soil, or water are also potential
6-17
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impact issues. Long-range transport and washout of major ionic species
including toxins that can alter the pH of rainfall may also be an issue.
6.2.4 Biota-Related
The major biological impact issues associated with water use for
electric power generation can be divided into three types of impacts:
• Direct effects on biological productivity.
• Acute and/or chronic toxicity.
• Long-term accumulation and/or food web effects.
Construction clearing, with associated losses of habitat, exist for all
cooling and ash systems. Impact potential is site-specific, being -
related to the size and biological significance of the area cleared.
The EPA sponsored or co-sponsored studies with the TVA include [90]:
• At the Colbert Steam Plant about two years ago, an FGD
sludge pond was vegetated with trees. Unfortunately the
leaves were burnt in areas that did not have soil cover.
The pond was about 9 meters (30 ft) in diameter or less
and no nutrients were added. In a section of the pond
(about half), about 150 millimeters (6 in.) of soil cover
was laid out.
• The TVA has a Rhizotron lysimeter [117]. In this system, oxidized
and unoxidized FGD wastes were placed and planted with
alfalfa for some time. Many wastes were ash free. The
sludges were placed in 150-millimeter (6-in.) layers plus
soil above and below. FGC wastes were also studied. To date
they have obtained several cuttings of alfalfa, including
that from controls using standard soils. While the study
is not complete yet, it appears that:
- The parts with both oxidized and unoxidized FGD
wastes did better than FGC wastes.
- The FGD waste plantings also did better than soil.
- FGC did the worst of all in such revegetation studies.
Roots simply could not penetrate such wastes.
Boron uptake in the above revegetation study was very high,
6-18
-------
but the amount of uptake was not exorbitant. Even so, the
uptake was considered enough to reach toxic levels of boron.
• Shawnee—The FGD waste pond [117] at Shawnee that is not being
used has been revegetated with a variety of trees and grasses.
Half of the area was vegetated with trees after placement of
sewage sludge and the other half with no cover. At present,
about 10 varieties have been planted; however, the survival
rate is not very high. This could be due to the lack of
moisture (no artificial watering was employed). Unfortunately,
there was no control plot to determine if drought alone killed
the trees or something in the wastes.
In 1979 the E and F ponds at Shawnee will be resloped and covered
with soil and seeded with grass. Utilities may not be able to
place 60 centimeters (2 ft) of soil cover inexpensively. However,
two different varieties of trees could still be planted over
lesser depths of soil cover to see if there is an optimum or
acceptable depth for soil cover for such revegitation. Control
plots will also be employed. Small seedlings will be used.
6.2.4.1 Issues Associated with Cooling Systems
Direct effects on biological productivity have traditionally been
associated with large-volume utility water intakes, especially impinge-
ment and entrainment of large numbers of aquatic organisms with sub-
sequent potential reductions in aquatic populations. In general, such
impact potential is associated with once-through cooling systems, and
is greater in smaller water bodies, and for organisms with long life
cycles (e.g., shellfish and finfish). Thus, the large reduction in
water requirements by recycle/reuse of cooling tower water can represent
a significant decrease in impact potential for aquatic organisms at some
sites. Total water management with even greater reductions in water
requirements would further mitigate biological impacts. Considering
the proliferation of plants using cooling systems, even on large bodies
of water, such reductions would appear to improve the problems of combined
impacts due to multiple sources.
6-19
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The Impacts associated with the discharge of cooling water effluents
are dependent upon the intake water treatment additives, receiving water
quality* and degree of water treatment utilized prior to discharge. For
large-volume once-through cooling discharges, the biological impact
issues have largely been associated with effluent temperatures and residual
chlorine levels [85]. Major impact potential associated with large-
volume heated effluents include increased mortality of aquatic biota,
altered population dynamics, and hence, community structure, and altered
metabolic rates and timing in reproductive cycles. Where large tempera-
ture gradients occur between effluent plumes and ambient water (as could
occur in colder climates during winter months) cold shock mortality and
gas bubble disease have been reported for finfish populations [86]. The
fact that some fish are attracted to discharge plumes can increase their
exposure to potential toxicants such as residual chlorine, chloramines,
zinc, etc., with toxic effects being associated with effluent levels,
temperature (in some cases) and fish residence time in the plume.
Recycle/reuse of cooling tower waters mitigates many of the problems
associated with the large water volume once-through cooling systems.
However, discharge blowdown contains increased types and concentrations
of potential toxicants. The toxicity of a large number of the more
common chemical additives has been documented for some aquatic species [87].
Considerations of alternatives to chlorination (such as the use of bromine
chloride) are due, in part, to the toxic potential exhibited by residual
chlorine and various reaction products [88, 89, 90]. The degree of
impact will depend upon the amount of blowdown water treatment, dilution
potential of the receiving waters, toxic species present and, in some
cases, the types of aquatic species present. Alterations in the more
sedentary bottom dwelling communities frequently serve as an indication
of toxic effects due to effluent discharge. While these organisms may
not be among the most sensitive to given toxicants, their exposure is
frequently of longer duration. Chronic or acute toxic effects to other
*
Low organic content woulc1 reduce some of the problems with residual chlorin
toxicity and also affect concentrations of toxic, persistent chlorinated
hydrocarbons. Chloramine levels can also be reflective of intake water
ammonia levels.
6-20
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aquatic species is also related to exposure time in addition to life
stage and degree of sensitivity but alterations in these populations
are not necessarily as readily observed in situ, especially where toxic
levels are in the chronic range. Furthermore, the toxic effects of
combined contaminants, including their antagonistic or synergistic
potential, are not at all well established. It should be emphasized
that for all types of discharges, the degree of impact is related to
ambient water quality, discharge diffuser design, receptor distribution,
and the dilution potential or size of the receiving water body.
The long-term fate and effects of discharged contaminants have
begun to receive more attention. The uptake potential and food chain
accumulative effects has been established for certain contaminants and
organisms (mercury, cadmium, PCB's, some pesticides are examples).
These effects are far less well documented for many of the contaminants
utilized in the cooling tower systems. Theoretical approximations
based on such characteristics as the octanol/water partition
coefficient are being utilized to approximate uptake for organic materials.
The problem is complicated by lack of extensive field data, the latter
being especially sparse for organic substances and for the long-term fate
of combinations of contaminants. The long-term degradation patterns and
effects of intermediate compounds or metabolites adds to the difficulty
in establishing impact potential of many organic contaminants. Established
laboratory procedures can provide estimates of acute and chronic toxicity,
while long-term effects levels require techniques such as in-situ bio-
assay, which are far less well established and considerably more difficult
to use. Field-scale verification of bioassay results is even less well
documented or non-existent for most of the chemicals considered here.
The potential does exist for increases of contaminants in surface
water, soils, and vegetation (hence, animals as well) with drift dis-
position of contaminants. The degree of impact potential is not at all
well established [82]. Impacts would probably be much less significant
for large water bodies, or atmospheric conditions promoting long range
transport.
6-21
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6.2.A.2 Issues Associated with Ash Disposal
The biological impact issues associated with ash disposal are of a
similar nature to those described above.
Impact potential associated with water use requirements are signifi-
cant to the degree that ash disposal water requirements are additive to
cooling water requirements (the latter generally being more significant).
Impingement/entrainment potential is related to velocity and volume of
intake water, thus once-through system ash disposal water requirements
are not very significant compared with once-through cooling requirements,
and more significant when added to requirements for recycle cooling
systems. Recycle of ash sluicing water and pneumatic transport reduce
this potential Impact on biota to an even greater degree.
The impact potential of ash pond overflow (or blowdown) is also of
the same nature as impacts associated with cooling system blowdown. The
degree of impact on aquatic biota is associated with, among other things:
• Size of receiving water body;
• Concentrations of dissolved solids, trace metals,
radionuclides, organics, and effluent pH;
• Distribution of aquatic organisms, in relation to
discharge, including resident time in that area; and
• Species and age group present (in some cases).
The potential for acute toxicity, chronic effects and bioaccumula-
tion are all potential issues considering the range of containment
species in the ash itself. Concentration/chemical availability in the
effluent* and dilution potential of the receiving water contribute
to the degree of issue significance. Although trace metals, radio-
nuclides and organic constituents represent classes of compounds toxic
to biota if present in sufficient concentrations, quantif1_ation of such
discharges is not available [82].
Surface runoff from ash ponds has a similar impact potential, in
terms of contaminant discharge. However, concentrations of contaminants,
hence biological impact potential, is even less well defined.
— .
Treatment is not assumed in this discussion.
6-22
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The major terrestrial biota impact issue associated with ash disposal
results from the potential for upward and lateral movement of soluble
contaminants. Soil accumulations of elements present in ash may be
toxic to vegetation, or accumulate in vegetation, leading to potential
toxic effects in animals.
6.3 Issue Definition Process
The key environmental impact issues surrounding recycle/reuse
technology are essentially defined by water availability, treatment
technology, the emerging regulatory climate, and economic considerations.
Primary in developing pressure for recycle/reuse systems over once-
through cooling or once-through ash disposal systems have been (1)
concern over water availability in certain parts of the country and
(2) the magnitude of water quality/biological Impact potentials of
power generation on small bodies of water. New once-through cooling
systems tend to be located on large bodies of water and intake and
discharge impacts can be mitigated by technical design (e.g., reduced
intake velocities and diffuser discharge configurations). However,
there does appear to be increasing concern over the large number of
such systems with a compounding of impacts, even on large water bodies.
Regulation of the "129 priority pollutants" in terms of discharge
limitations, while still an emerging issue, is likely to increase
effluent treatment requirements. Such developments, in conjunction
with increasing competition for water supply, will likely serve to
increase pressure toward recycle/reuse systems where very little, if any,
water is discharged. Here the economics and feasibility of treatment
for reuse versus treatment for discharge will be operative in the
decision process for system design. As understanding of biological
impacts of intakes and discharges improves, this too may play a role in
the decision-making process or in regulatory requirements. It is less
clear how such pressures will operate toward possible retrofit of water
reuse on existing once-through cooling systems and/or ash pond effluents,
certainly site- and facility-specific situations.
6-23
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Treatment of blowdown water and/or other recycled water for dis-
charge or reuse in the plant usually leads to the production of
additional solid wastes. Depending upon the extent that toxic substances
can be recovered from such waste waters and reused in plant operation, the
disposal could create additional impact issues. High levels of solu-
ble salts and trace metals would be problematic for land or water
disposal. In other words, some waste water discharge impacts could
become solid waste disposal issues. The question remains whether or
not such wastes would be considered hazardous under emerging Resource,
Conservation and Recovery Act regulations, and the implications for
disposal requirements. (See Section 4.0.)
The newest draft of Resource, Conservation and Recovery Act regula-
tions [102] places fly ash and bottom ash in a "special waste"
category, rather than on a list of hazardous materials. (See Section 6.1.)
One implication of such regulation, if promulgated (due to lack of con-
tainment requirements) could be reduced requirements for monitoring of
migration of contaminants.
In summary, the issues associated with power plant water use are
substantially defined by water supply constraints of environmental regula-
tion. System design and treatment technology further define environ-
mental impact issues.
6.4 Ongoing Investigations
At present, there are 19 ongoing EPA- or EPRI-funded programs
investigating aspects of water-related impact issues and principally
associated with cooling and ash disposal systems. Tables 6.3 and 6.4
list these programs, identifying the issues being investigated and
indicating which aspects of each impact issue are being covered.
As the above-mentioned tables illustrate, the emphasis of ongoing
programs includes:
• Plume behavior,
• Waste stream and seepage characterization,
• Treatment technology,
• Guideline development for water management systems,
6-24
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Table 6.3
EPA Projects Concerning Water Recycle/Treatment/Reuse in Power Plants
taala:
Only curren
production
atly ongoing (as of December 1978) projecte pertaining to cheml
are listsd. Further projects under EFA's Thermal Program* are
chemical waste stream
not listed here.
I
M
Project Title
Aasesssvnt of Technology for Control of
Hater and meats Pollution frai Combustion
Sourcea
meter Recycle/Rena* Alternatives in
Coal-Fired Steam Electric Power Plants
Characterisation of Effluence fr
Coal-Fired Utility toilers
Contractor
Arthur D. Little
Bsfll sn Corporstlon
Tennaasee Valley
Authority
Treatment of Power Plant Hastes
«rlth n-^..-— Technology
Aseasemmnt of Measurement Techniques
from Hazardous Pollution frosi Thenal
Coollnt Systems
ant of the Effects of
Chlorinated Sea Hater from Power
Plaate on Aquatic Organisms
(valuation of Lima Precipitation for
Treatmeot of toiler Tube Cleaning Haste
Comparative Merits of Reverse
iU. Vapor Compression Evaporation and
Vertical Tube faaai evaporation (Excluding
Softening, Thermal Softaming, and Multi-
stage FLuh) for Treatment of Cooling
Tower slowdowns
Characterization of Aah Pond Discharges
Valley
Authority
Lockheed Elec-
tronic* Company
(Northrop Corp.)
mi. Incorporated
Rlttmmn Associates,
Incorporated
Bechtel
Blttmen Associates,
Incorporated
Project Focus/Statue
Purpose Is to assemble, review, evaluate, and
report data from research, development, and demon-
stration activities pertaining to FCC waste disposal/
utilisation and power plant water recycle/treatment/
reuse .
Investigate water recycle/reuse alternatives for
coal-fired power plants employing cooling towers, ash
sluicing, and S02/particulate scrubbing systems, as
well as for combined systems develop rough cost
estimates for several selected alternatives which
would potentially minimise power plant water require-
ments and discharges.
The objectives of this project sre to (1) characterize
coal pile drainage; {2} assess the effect of pH
adjustment on ash pond effluent; (3) assess and then
design an effective program for monitoring ash pond
effluent; (4) evaluate chlorinated water effluent
quality from a once-through cooling system; (S) ssseas,
characterize and quantify coal aah leachate effects
on groundwater quality; and (6) study gaseoua and
paniculate emissions from several types ot boilers.
Investigate the feasibility of employing membrane
technology in the treatment of power plant waatewater.
Investigate the feasibility of ualng an organic snalyti-
cal technique to rapidly assess the effect of cooling
water effluents on the environment.
Characterisation and evaluation of the toxiclty of
compounds formed by chlorinstlon of ses water by pover
planta.
Perform bench scale studies to eveluate lime precipitation
•s a technology to control metal discharges in boiler water-
slde tube cleaning wastewaters. Dae of hydrochlorlde acid
copper chemicals, citric acid, hydroxy acltlc acid, and
EDTA may be considered later.
a) Monitoring of EPRI funded demonstration of vertical
tub* fon evaporation demonstration (VTFE-D)
b) Assess economic and energy efficiencies of VTFE.
Reverse osmosis and vapor compression evaporation.
For the EPA-Effluent Guidelines Division development
of industry wide data on ash pond discharges.
Reference
6
Issues Under Investigation (Aspects Covered)
Water Use
Hater Quality
Effluent Toxiclty
Water Quality
Seepage
Air Emissions
(Planning tool based on
available data.)
(Water management alt- r-
natives.)
(Coal Ash Enlsslona from
boilers being investi-
gated todate.)
Water Quality (A Treatment Technology.)
Water Quality (A theoretical study ,,f
effects on biota or
monitoring technique')
Water Quality (Literature review at
Effluent Toxlcity present.)
Water Quality (Treatment technology.)
Water Quality
Drift
(Treatment technology.)
Water Quality (Effluent Characteri-
zation. )
* Ongoing Projecte
Source: [6]
-------
Table 6.4
EPRI Projects Concerning Water Recycle/Treatment/Reuse in Power Plants
o>
i
NJ
Baals: 1. Only currently ongoing (as of November
2. Only project* pertinent to chemical wai
Ho. Project TltU
1 Development of Comprehensive Water
Hanagement Methodology
Trace Elevenc Removal by Adsorption
on Iron Hydroxide*
3 Fundamental Studies of Mechanisms
of Biofoulant File, Buildup and
Destruction
4 Numerical Modeling Techniques for
Three-Dimensional, Recirculating
Flows in the Near-Field of Cooling
Tower Flumes
5 Acceptance Test Methodology for
Cooling Towers
1978) projects are listed.
te streams are listed. Purely thermal studies ere not lifted.
Water Purification
AssocLste*
Stanford University
Rice University
Envirofidyne, Ltd.
Issues Dads* Investigatloo
Hater Us*
Project fpcms
Develop design and optimisation suidslimais
for an Integrated water esiiigimeait system in
fosell fuel power plants.
Demonstrate a novel insolubllixstlon process
ss a feasible first atep for trace metal
i limn ill from power plant discharge water streams.
Laboratory atudy of slims film buildup in con- In-System Water Quality
deneers and ite destruction; control by blocidal
agents, such aa chlorlnm.
Drift/Plume
of a general three-«ilmensiioeial,
nomericjil modsl for representing the near-field
behavior of coaling tower plume*.
Environmental Develop and demonstrate Instrumentation and Drift
Systems Corporation test procedures for performing definite accept- Water Dec
ance teats on large mechanical draft cooling Power Consumption
(Aspects Win* Covered)
(Guidelines for design.)
(Treatment technology.)
(Theoretical study,
not application.)
(Model.)
(Assessment technology.)
Validation of Cooling Tower Plume
and Drift Deposition Model*
Agricultural Waste Water for Fewer
Plant Cooling
Ozone Dosage and Contacting for
Condenser Bio-Fouling Control
9 Other Chemical Alternatives to
Chlorinatioi. for Bio-Fouling Control
10 Demonstration of Vertical Tube
Foam Evaporation for Slowdown Treat-
Argonne National
Laborar /
California Depart-
ment of Water
Resources
ble all available cooling tower plume
field data in a common format suitable for
model verification.
Develop an economical and reliable pretreatment
method for agricultural waatewater to reduce its
scale-forming tendencies, so as to make it
acceptable for power plant cooling.
Drift/Plume
Public Service Experimentally determine the dosage required and Water Quality
Electric & Gaa (N.JO the economic feasibility of using ozone to control
blofouling in model power plant condensers.
Northwestern
University
University of
California at
Berkeley
Assess other chemical alternatives to chlorln- Water Quality
at ion.
Demonstration of Vertical Tube Foam Evaporation Water Use /Drift
(VTTE-D) . Equipment involved is funded by
prior EPA study.
(Collection of existing
data.)
(Hew water sources.)
(Treatment technology.)
(Treatment technology.)
(Technology demonstration
see 18, Table 3.3-3)
Source: [8, 9]
-------
• Cost estimate development for selected water reuse
system alternatives, and
• Assessment of existing data on recycle/treatment/reuse
for use as a planning tool.
A number of impact issues do not appear to be under investigation
or are receiving less emphasis in these programs. Biological impact
issues do not appear as a focus of the 19 programs listed: contaminant
mobilization/migration, ecosystem fate and effects of contaminants, and
combined contaminant effects are some examples of such issues.
Characterization of surface runoff from ponded wastes and impact
potential do not appear to be covered by this ongoing research. Drift
deposition impacts are likely to represent local, if any significance,
but does not appear to be covered by these programs.*
Long-range transport and washout of contaminants are also not covered,
but more an exclusively air issue.
6-27
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7.0 INFORMATION AMD TECHNOLOGY GAPS
7.1 Categorization of Data Gaps
A survey of the broad area of water management in power plants
indicates that existing gaps of data or information could be broadly
classified into two categories:
• Information gaps. This refers to those questions or areas of
technology in which detailed design and economic information
are not readily available. A typical example of such an infor-
mation gap is ash handling systems. . A substantial amount of
information on the detailed design and economics of wet and dry ash
handling is available in various organizations active in designing or
building equipment for ash handling. But such information is
not readily accessible in the open literature.
• A larger concern is technology or data gaps. For example, the
disposal of ash, particularly in the dry state, on the large-scale
on-land may be considered an area where there is some technology
gap. Technology gaps in this sense should also include the
lack of reliable economic data for large-scale utilization of
a particular technology.
In this connection, it is also well to note that utility power
plant operations are on such a large scale that utilities have
traditionally been very reluctant to accept any economic esti-
mates except those obtained on demonstration-scale units
of such size that very reliable economic projections are
feasible. Given the regulated nature of utilities, their re-
luctance to accept any but the most reliable economic estimates
for any technology on water recycle/reuse is not unreasonable.
For this reason, the application of many technologies for total
water reuse in power plants at this stage may be considered a
technology gap. For example, reverse osmosis technology could
be potentially employed for reuse of water. But economic
estimates on any significant scale are sufficiently undetermined
at this time that it may be considered an area where additional
definition is necessary.
7-1
-------
A broad overview of the existing information in the entire field
of power plant water management indicates some specific areas where
either information gaps or technology gaps, as defined above, exist.
Tentatively, the major areas of concern are described below.
7.2 Information Gaps
The following are the major information gaps of significance in
the area of water recycle/reuse.
1. Disposal methods for fly ash. Ash handling collection methods
include dry, recirculating wet and once-through wet systems.
At present, the trend in the United States could be considered
to be towards dry fly ash systems. Dry fly ash systems have
been employed for many years in Europe and elsewhere. Recir-
culating wet systems are not usually employed for fly ash even
though they are common for bottom ash.
Some of the major organizations in the field have a substantial
amount of information in their files on dry handling of ash.
Typical examples of organizations with ash collection informa-
tion are Allen-Sherman-Hoff and United Conveyor.
However, it may be noted that if the trend towards dry ash
handling is based on water-related regulatory constraints, that
disposal of dry ash on the ground Jiay pose some environmental
questions on which data gaps may exist at present; such impacts
are determined by the method of disposal and site-specific
factors. This will be discussed later.
2. Treatment and reuse options, particularly for equipment cleaning
wastes, might be an area where there is some information gap in
the open literature. Again, some information may exist in the
possession of organizations active in designing and building
such facilities.
As part of its overall mission of preserving the quality of the
environment and encouraging increased focus on minimizing effluent dis-
charges, the EPA is vitally interested in potential measures to minimize
such information gaps. Such efforts will lead to easier acceptance of
7-2
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regulatory guidelines and the associated recycle/reuse technology by
industry.
It is noted that in the field of water recycle/treatment/reuse,
there is exchange of information in the published technical literature,
and at professional meetings and seminars for technical information ex-
change. However, there is no recognized forum for such technology
transfer specifically geared to water recycle/treatment/reuse in power
plants. The utility industry has unique constraints in terms of scale
of operation, economics, regulatory constraints, and potential energy
supply problems. Hence, such a forum for water recycle/treatment/
reuse in power plants might be of substantial value from several
viewpoints:
• It can serve as a technology clearinghouse.
• It can permit broad interaction of EPA technical staff with
utilities and industry on their respective perceptions on
technology and economics and subsequent impact on regulations.
• It may help focus on some of the interdisciplinary problems
associated with energy/environment/economics for the utility
industry. As part of fostering such technology transfer, the
EPA may consider an annual or biannual (every 2 years), state-of-
the-art assessment of technology for water recycle/treatment/
reuse at power plants. To be effective, any such technology
transfer needs the participation and/or cooperation of industry.
It is suggested that an extension of the periodic FGD Symposium to
include a separate one-half- or one-day session for water recycle/reuse
may be a worthwhile beginning.
7.3 Technology or Data Gaps
In some ways, technology gaps are more important. Potentially,
these require far more effort and funding to correct. As stated earlier,
technology gaps necessarily include gaps in reliable economic estimates
on the large scale; for this is a key factor in utility acceptance of
any environmentally desirable system or technology. In addition, it
should be noted that utilities correctly demand very high reliability
7-3
-------
of systems if it affects the performance of the power plant as a whole.
Hence, any assessment of technology should also emphasize the need for
extreme reliability before it can be considered in power plant applica-
tions.
Some of the major areas of technology gaps have been identified in
previous years, and the EPA has already initiated programs in those areas.
Some additional ones where some program planning might be useful are
considered below.
1. Ash Handling and Disposal - In the area of ash handling and
disposal, the following items require additional information:
Technology and constraints on recycle systems for fly ash.
The TVA [51], Radian [13] and other studies have offered
a beginning in this vital area. The ultimate emphasis
of water management in this field should be on water reuse.
- The technology for dry disposal of ash in landfill is known.
Moreover, regulatory constraints also encourage trend to
dry disposal. However, information on environmental impact
of dry disposal of ash can only be considered a data gap
at this time. Lacking such data, impact issue definition
would be difficult.
Development of optimum methods of disposal to minimize
runoff and methods to treat runoff. Work in this area is
very much needed and implementation of regulations includ-
the RCRA make this imperative.
Better definition of the overall impact of disposal of ash,
including dry ash, on groundwater and land utilization is
required. In the same context, the disposal method should
be optimized to minimize runoff and also include methods
to treat the runoff where necessary. Particularly because
of the significant presence of trace elements in ash, this
would be an important consideration. TVA's recent study [14,60]
may serve as a useful starting point on this issue.
7-4
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2. Chlorination and Potential Alternatives - Intermittent chlorina-
tion is widely practiced to control biofouling on the walls of
cooling system tubes. However, active chlorine is toxic to
aquatic biota. Hence, discharges should be regulated to protect
aquatic life in receiving waters.
The EPA has already initiated a substantial number of studies
on chlorination including a study of the magnitude of the
problems and various alternatives. Particularly with the trend
towards tightening of the water loop and ultimate reuse of all
the water, chlorination may have impacts quite different from
those of some years ago. As water is more and more reused at
the power plant, the net discharge is reduced, and hence the
discharge of residual chlorine in the effluent waters into the
surroundings may assume lesser importance. On the other hand,
the buildup of alternative chemicals within the power plant
water may require some further technological definition. Such
potential alternatives (which have been explored in earlier or
ongoing EPA programs) to chlorination are as follows:
a. Alternative chemical methods such as bromine
chloride, ozone, and chlorine dioxide.
b. Mechanical systems to control biofouling and thus,
eliminate chemicals.
c. Coating condenser tubes with appropriate material
to minimize or eliminate biofouling buildup. However,
in some cases, such coatings may themselves contribute
to reduction in heat transfer.
d. Use of surfactants to minimize chlorine requirements.
e. Dechlorination methods to ensure that residual
chlorine in the discharge is low.
f. Thermal heating methods to control biofouling. This
has been practiced in California for some years.
Evaluation of each of these methods should include
• Better assessment of the health and environmental
impacts of presently practiced chlorination techniques
7-5
-------
to provide baseline data.
• Assessment of the health and environmental impacts
of each of the above potential methods after defining
the technology involved.
Any alternative has to be assessed on a comparative engineering,
environmental, and economic basis against chlorination.
As discussed in Volume 1, the EPA and EPRI have initiated pro-
grams on various aspects of biofouling control and alternatives
to chlorination. Continuation of these and initiation of new
programs within the above framework may provide further data
to control toxicity effects of chlorine without impairing
engineering and economic efficiency required in biofouling
control.
3. Metal Cleaning Wastes - At present, metal cleaning wastewaters
are another significant source of potential pollution from
power plants. These are a major source of heavy metals in dis-
charges. Moreover, treatment of such wastes containing chelated
metal complexes is not well defined. Various options and re-
cycle of this water and use of cooling tower blowdown for metal
cleaning have been proposed. Furthermore, studies have been
conducted on the application of advanced technology for reuse
of metal cleaning wastes. In spite of these efforts, it is
noted that the technology definition and the large-scale
economic projections for reuse or treatment of metal cleaning
wastes require some further study. The EPA has an on-going
contract with Hittman Associates [58] on treatment of metal
cleaning wastes which would provide some basic information
on treating these streams.
4. Chemical Additives and their Environmental Impacts - In addition
to the use of chlorine in condenser biofouling control mentioned
above, various biocides and fungicides are used in the cooling
tower systems of power plants. These additives are often toxic.
With the EPA encouraging increasing use of cooling tower systems,
7-6
-------
the use of such biocides, fungicides, and other chemicals may
be expected to increase. An adequate environmental assessment
of such chemical additives is required. If such an assessment
indicates that environmental impacts may be at unacceptable
levels, alternative treatment technology should be explored
and developed.
The Remand Decision (see Section 4.1.4) has led to increased
attention by the EPA on cooling towers vis-a-vis other means
of thermal discharges. This issue, when resolved, will further
impact use of chemical additives.
5. Toxic Components in Effluents - Recently, EPA-sponsored studies
have focused on the application of advanced treatment techniques
to control priority toxic pollutants[13]. The methods
evaluated include: reverse osmosis, carbon adsorption, lime
precipitation, vapor compressor distillation, and evaporation
ponds. It may be noted that advanced technologies such as
carbon adsorption, reverse osmosis, vapor compression evapora-
tion, and lime precipitation are potentially applicable.
However, for reverse osmosis, carbon adsorption, and vapor
compression evaporation, specific information for applicability
in power plants, and the projections on large-scale economics
are somewhat limited. A beginning has certainly been made in
this area by a Radian study [13], Future Program planning in this
field should include broader technology assessment, including:
• Economic estimates and operational reliability of such
advanced water reuse in power plants.
• Environmental impacts of control of toxics.
6. Demonstration Program - A logical continuation of EPA-sponsored
studies on water recycle/reuse [7] would be a demonstration of
water recycle/treatment/reuse at a power plant. Such a
demonstration program can help define technology options and
economic considerations to an extent necessary in the utility
industry. The power plant for the demonstration program
7-7
-------
should be chosen after defining:
• a set of criteria for the power plant where demonstration
can be most useful in terms of generating data. The
generated data should be applicable to a broad segment of
the utility industry.
• Technology options to be studied.
• Other public policy considerations including the desire
or willingness of the utility involved to cooperate in
this effort with the EPA.
7-8
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REFERENCES
1. Geological Survey Circular 765. U.S. Geological Survey, Washington,
D.C., 1976.
2. Steam-Electric Plant Air and Quality Control Data for the Year
Ended December 31, 1975 - Summary Report - Federal Energy Regulatory
Commission,, Washington, D. C., January 1979.
3. The Nation's Water Resources, The Second National Assessment by
the U.S. Water Resources Council. Statistical Appendix, Volume A-2.
4. Water Consumption & Costs for Various Steam Electric Power Plant
Cooling Systems by M. C. Hu, G. F. Pavlinco & G. A. Englesson
(United Engineers & Constructors) Cameron Engineers, Denver,
Colorado, EPA 600/7-78-157, August 1978. U.S. EPA Office of
Research & Development, Washington, D.C. 20460.
5. Development Document for Effluent Limitation Guidelines and
New Source Performance Standards for Steam-Electric Power
Generating Point Source Category, EPA 440/1-74/029-a, Group I,
Environmental Protection Agency, Washington, D.C. 20460,
October 1974.
6. Jones, Julian W., Disposal of Power Plant Wastes. Presented
at The Third National Conference, Interagency Energy/Environment
R & D Program, Washington, D.C., June 1 & 2, 1978.
7. Water Recycle/Reuse Alternatives in Coal-Fired Steam Electric
Power Plants, Volume I, September 1977, Radian Corporation,
DCN #77-200-118-13. EPA Contract No. 68-03-2339, (Draft).
8. "Research & Development Project", Electric Power Research
Institute, Palo Alto, California 94302, May 4, 1978.
9. Personal Communication, Mr. John Maulbetsch, EPRI, October, 1978.
10. Steam - Its Generation and Use, The Babcock & Wilcox Company,
New York, N.Y.
11. Hollier, M., Experiences with Reverse Osmosis Demineralizing
for Boiler Feed Water, Industrial Water Engg., Spril 1978,
pp 20-21.
12. Supplement for Pretreatment to the Development Document for the
Steam Electric Power Generating, Point Source Category, April
1977, EPA 440/1-77/084, Environmental Protection Agency,
Washington, D.C., April 1977.
R-l
-------
13. Collay, J. D., C. A. Muela, M. L. Owen, N. P. Mesarole, J. B.
Riggs and J. C. Terry, Assessment of Technology for Control of
Toxic Effluents from the Electric Utility Industry, Radian
Corporation, EPA 600/7-78-090. National Technical Information
Service, Springfield, Va. 22161, June 1978.
14. Chu, T.-Y., J. Nicholas, W. R. Ruane, R. J., Complete Reuse of
All Pond Effluents in Fossil Fuel Power Plants, Water, 1976.
AIChE Symposium Series, pp 299-311. American Institute of Chemical
Engineers, 365, E. 47th St., New York, NY, 10017, 1377.
15. Power, Section 7, Volume 120, No. 4, April 1977.
16. Marshall, W. L., Cooling Water Treatment in Power Plants, Ind.
Water Eng., 9 (2), 38, 1972.
17. Rossie, J. P., and E. A. Cecil, Research on Dry Type Cooling
Towers for Thermal Electric Generation, Part I, Water Pollution
Control Research Series, Water Quality Office, Environmental
Protection Agency, Project 161 30 EES, Superintendent of
Documents, U.S. Government Printing Office, Washington, B.C.,
November 1970.
18. "Wet/Dry Cooling Systems for Fossil-Fueled Power Plants: Water
Conservation & Plume Abatement." M. C. Hu & G. A. Englesson,
United Engineers & Constructors, EPA 600/7-77-137 Environmental
Protection Agency, Office of Research & Development, Washington,
D.C. 20460, November 1977.
19. "Optimum Design of Dry/Wet Comination Cooling Towers for Power
Plants" V. C. Patel, T. E. Croley, II & M. S. Cheng. Cooling
Tower Environment - 1974. Office of Public Affairs, Energy
Research & Development Administration, Washington, D.C., 1975.
20. Donahue, J. M., Chemical Treatment; Ind. Water Eng. 7 (5), 35,
1970.
21. Krisher, A. S., Raw Water Treatment in the CPI; Chem. Engg.,
August 28, 1978, pp 78-98.
22. Aynsley, Eric and Meryl R. Jackson, Industrial Waste Studies:
Steam Generating Plants. Report under EPA Contract No. WQO
68-01-0032. Freeman Labs, Inc., Environmental Protection Agency,
Washington, D.C. 20460, 1971.
23. Glover, G. E., Cooling Tower Slowdown Treatment Costs; in
Industrial Process Design for Water Pollution Control, Vol. 2,
Proceedings of the Workshop, N.Y., AIChE, pp 74ff.
R-2
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24. "Alternatives to Chlorination for Control of Condenser Tube Bio-
fouling," H. H. S. Yu, G. A. Richardson, and W. H. Hedley,
Monsanto Research Corp., Dayton, Ohio, EPA Report No. EPA-GOO/7-
77-030, Environmental Protection Agency, Office of Research &
Development, Washington, D.C., March 1977.
25. Permissible Chlorine Concentrations in Effluents from New
Sources; Federal Register, Vol. 39, October 8, 1974.
26. Collins, H. F., Sewage Chlorination Versus Toxicity—A Dilemma;
Journal of the Environmental Engineering Division Proc. ASCE, 99,
No. EE6, 761-72 (1973), December.
27. Environmental Studies Board, National Academy of Sciences,
Water Quality Criteria 1972, EPA-R3-73-033.
28. Bromine Chloride - An Alternative to Chlorine for Fouling
Control in Condenser Cooling Systems, Bongers, L. H., and
T. P. O'Conner, Martin Marietta Corp., and D. T. Burton,
Academy of Natural Sciences of Philadelphia. EPA Report
EPA-600/7-77-053, Environmental Protection Agency, Office
of Research & Development, Washington, D.C. 20460, May 1977.
29. Mills, J. F., The Chemistry of Bromine Chloride in Waste-
water Disinfection. Presented at American Chemical Society
Meeting, Chicago, Illinois, August 1973.
30. Anonymous, Chemical & Engineering News, 56 (41), p 6,
October 9, 1978.
31. Anonymous, Chemical Engineering, 85 (25), p 71, November 6,
1978.
32. Principles of Industrial Water Treatment, Drew Chemical
Corporation, Boonton, N. J., 1977.
33. Gasper, K. E., Non Chromate Methods of Cooling Water Treat-
ment; Chem. Eng. Progress, March 1978, pp 52-56.
34. Hennings, J. C. Misenheimer and H. Templet, Proceedings
of the Cooling Tower Institute Annual Meeting, Houston,
Texas, January 31-February 2, 1977.
35. Lawlar, J. B., Proc. 37th Intl. Water Conference, Pittsburgh,
Pa., pp 21-6, October 26-28, 1976.
36. Donahue, J. M., Treatment of Cooling Tower Slowdown; Indus.
Water Engg. July/Aug. 1978, pp 8-13.
R-3
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37. Ellis, M. J. and R. Kunin, Proc. 37th Intl. Water Conference,
Pittsburgh, Pa., pp 41-8, October 26-28, 1976.
38. Boier, D. B., J. E. Levin and B. Baratz, Technical and Economic
Evaluation of Cooling Tower Slowdown Control Techniques,
EPA-660/2-73-026, Environmental Protection Agency, Washington,
D. C., November 1973.
39. Herman, K. W., Internal Boiler Water Treatment. Proceedings of the
38th International Water Conference, Pittsburgh, Pennsylvania,
Nov. 1-3, 1977.
40. Kenner, F. N., External Treatment for Industrial Boiler Systems,
ibid.
41. Krisher, A. S., Raw Water Treatment in the CPI, Chemical
Engineering, 85, No. 19, p 78, August 28, 1978.
42. Jackson, E. W., and J. N. Smith, Make-up Treatment Counter
Current Regeneration Experience in the United Kingdom. Proceedings
of the 38th International Water Conference, Pittsburgh, Pennslyvania,
Nov. 1-3, 1977.
43. Hazen, C. N., Ozone Treatment of Boiler Feedwater, ibid.
44. Sherm, M. and H. E. Mynhier, Experiences with Reverse Osmosis
in a Pilot-Scale Wastewater Renovation System, ibid.
45. Hollier, M. , Operating Experiences With Reverse Osmosis
Demineralizing for Boiler Feed Water and Make-up Treatment
Systems at Willo Glen Power Station, ibid.
46. Krol, C. A., et al, Operating Experience With a 'Zero' Dis-
charge Deionizer, ibid.
47. Wajer, C. W. and C. W. Smith, Operating Experience of a
Deep-Bed Condensate Polishing System, ibid.
48. Davenport, J. W., On-Site Pilot Tests of a SALA-MGMF Magnetic
Filter at New England Power Company, Brayton Point Station,
ibid.
49. Physical, Chemical and Biological Treatment Techniques for
Industrial Wastes. Report to U.S. EPA, Office of Solid
Waste Management Programs, Submitted by Arthur D. Little, Inc.,
November 1976.
50. A Primer on Ash Handling Systems, prepared by Allen-Sherman-
Hoff Co., a division of Ecolaire, Inc., Malvern, Pa. 19355,
1976.
R-4
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51. Nelson, G. R., "Water Recycle/Reuse Possibilities," Report No.
EPA 660/2-74-089, U. S. Environmental Protection Agency,
Washington, D. C., 20460, December 1974.
52. Ash at Work, Vol. X, No. 4, 1978, pp 1 & 4. National Ash
Association, Washington, D. C., 20006, 1978.
53. Tobstrick, R. L., L. J. Henson, and S. V. Tomlinson, Economic
Evaluation Techniques, Results and Computer Modelling for Flue
Gas Desulfurization. Presented at the FGD Symposium, Diplomat
Hotel, Florida, November 8-11, 1977.
54o Reuse of Power Plant Desulfurization Waste Water, Aerospace
Corporation. Prepared for Industrial Environmental Research
Lab., February 1976. U.S. Department of Commerce National
Technical Information Service No. PB-250-732, NTIS, Springfield,
Va.
55. Controlling SO^ Emissions from Coal-Fired Steam-Electric
Generators: Water Pollution Impact, Vol. I, Executive Summary,
Vol. II, Technical Discussions, Interagency R & D Program
Report, EPA-600/7-78-045a & b, March 1978 (Radian Corp.)
Environmental Protection Agency, Washington, D.C., 1978.
56. Weimer, Larry D., "Effective Control of Secondary Water
Pollution From Flue Gas Desulfurization Systems" by Resource
Conservation Co., EPA-600/7-77-106, Environmental Protection
Agency, Washington, D.C. 20460, September 1977.
57. Roebuck, A. H., Safe Chemical Cleaning-The Organic Way,
Chemical Engineering, pp 107, July 31, 1978.
58. Draft Work Plan - "An Evaluation of Lime Precipitation as a
Technique for Treating Boiler Tube Cleaning Wastes" EPA
Contract 68-02-2684 by Hittman Associates, Columbia, Md. 21045,
April 1978.
59. State and Local Pretreatment Programs, Volume I, EPA, Office
of Water Programs, Washington, D.C., Augsut 1975.
60. Cox, D. B., T.-Y. J. Chu, R. J. Ruane, Characterization of
Coal Pile Drainage, TVA, under Interagency Agreement D7-E7-21-BB,
Draft Report, Environmental Protection Agency, July 1978.
R-5
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61. Drummards, N. L., "Power Plant Water and Waste Management,"
Power Engineering 82_ (7), p 49, July 1978.
62. Anonymous, Chemical & Engineering News, 56 (45), p. 23,
November 6, 1978.
63. Puckorious, P. R., "Controlling Corrosive Microorganisms in
Cooling-Water Systems," Chemical Engineering, 85_ (23), p 171,
October 23, 1978.
64. Scale Free Vapor Compression Evaporation, Water Capsule Research
Report, OWRT-DOI, Washington, D.C. 20240, 1977.
65. Brine Concentration Application to Steam Electric Utility Waste
Streams. Comments by Resource Conservation Company to the
Environmental Protection Agency, June 1974.
66. Dascher, R. E. and R. Lepper, "Meeting Water-Recycle Require-
ments at a Western Zero-Discharge Plant," Power, 121 (8), p 23,
August 1977.
67. Wirth, Jr., L. and G. Westbrook, "Cooling Water Salinity & Brine
Disposal Optimized with Electrodialysis Water Recovery/Brine
Concentration System," Combustion, 48 (11), p 33, May 1977.
68. Averbuch, L., A. N. Rogers, and S. May, Evaporation of Slowdown
Water in Power Plants. Paper in WATER-1976, AIChE Symposium
Series, AIChE, New York, N.Y., 1977.
69. Goldman, E., and P. J. Kelleher, Water Reuse in Fossil Fueled
Power Stations, Paper at the National Conference on Complete
Water Reuse, April 1973.
70. "Renovation of Power Plant Cooling Tower Slowdown for Recycle
by Evaporation: Crystallization with Interface Enhancement."
H. D. Sephton, Univ of California at Berkeley, EPA-600/7-77-063,
Environmental Protection Agency, Office of Research & Develop-
ment, Washington, D.C. 20460, June 1977.
71. Sephton, Hugo H., "Interface Enhancement Applied to Evaporation
of Liquids" U.S. Patent 3,846,254, November 5, 1974.
72. "Power Plant Cooling Tower Slowdown Recycle by VTE vith
Interface Enhancement: Mobile Pilot Plant Construction &
Field Testing." H. E. Sephton, Univ of California, EPA
Contract 68-03-6781, EPA-IERL, June 1978.
R-6
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73. "Monitoring of VTFE-Demonstration and the Assessment of Various
Technologies for the Treatment of Cooling Tower Slowdown,"
E. H. Houle, Bechtel Corporation, EPA Contract No. 68-02-2616,
EPA-IERL, October 24, 1978.
74. Schwarzenbach, A., The Operation of Steam Turbines With Dry
Cooling Towers, Combustion 49_ (11), 33, May 1978.
75. Larinoff, M, W., Performance and Capital Costs of Wet/Dry
Cooling Towers in Power Plant Service, ibid, 9, May 1978.
76. Larinoff, M. W. and L. L. Forster, Dry and Wet-Peaking Tower
Cooling Systems for Power Plant Applications, Combustion, 48
(11), May 8, 1977.
77. Smith, E. C. and M. W. Larinoff, Alternative Arrangements and
Designs-Wet/Dry Cooling Towers for Power Plant Applications,
ibid, May 23, 1977.
78. Edsall, Thomas A., "Electric Power Generation and Its Influence
on Great Lakes Fish," in Proceedings of the Second Federal Con-
ference on the Great Lakes, Great Lakes Basin Commission, 1976.
79. Bongers, Leonard and Thomas P. Conner, Martin Marietta Corp.,
and Dennis T. Burton, Academy of Natural Sciences of Phila.,
"Bromine Chloride - An Alternative to Chlorine for Fouling
Control in Condenser Cooling Systems," EPA Contract No. 68-02-
2158, May 1977.
80. Stratton, Charles L. and G. Fred Lee, "Cooling Towers and Water
Quality," Journal WPC7. Vol. 47, No. 7, July 1975.
81. Yu, H. H. S., G. A. Richardson, and W. H. Hedley, Monsanto
Research Corporation, "Alternatives to Chlorination for Control
of Condenser Tube Bio-Fouling," EPA Contract No. 68-02-1320,
March 1977.
82. Van Hook, R. I., "Potential Health and Environmental Effects
of Trace Elements and Radionuclides from Increased Coal
Utilization," Environmental Science Division, Oak Ridge
National Laboratory, Draft, November 21, 1977.
83. Effects and Methods of Control of Thermal Discharges. Part 3,
Report to the Congress by the Environmental Protection Agency
in accordance with Section 104(E) of the Federal Water Pollu-
tion Control Act Amendments of 1972, November 1973.
R-7
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34. Bardarik, Daniel G., et al, Aquatic Ecology Associates, "A Study
of the Effects of the Operation of a Steam Electric Generating
Station on the Aquatic Ecology of Presque Isle Bay, Pennsylvania,"
for Pennsylvania Electric Company, April 1973.
85. Becker, C. D. and T. 0. Thatcher, Battelle Northwest Labs,
"Toxicity of Power Plant Chemicals to Aquatic Life," U.S.
Atomic Energy Commission, June 1973.
36. Bongers, Leonard and Thomas P. Conner, Martin Marietta Corp.,
and Dennis T. Burton, Academy of Natural Sciences of Phila.,
"Bromine Chloride - An Alternative to Chlorine for Fouling
Control in Condenser Cooling Systems," EPA Contract No. 68-02-2158,
May 1977.
87. Sung, R., D. Strehler, and C. Thorne, "Assessment of the Effects
of Chlorinated Seawater from Power Plants on Aquatic Organisms,"
Draft EPA Contract No. 68-02-2613.
83. Brungs, William A., "Effects of Wastewater and Cooling Water
Chlorination on Aquatic Life," EPA Environmental Research
Laboratory, Duluth, Minnesota, EPA-600/3-76-098, August 1976.
89. Roffman, Amiram, "Environmental, Economic, and Social Considera-
tions in Selecting a Cooling System for a Steam Electric Gen-
erating Plant," in Proceedings of Symposium Cooling Tower
Environment - 1974, March 4-6, 1974, published by ERDA, 1975.
90. Personal Communication from Mike Osbourne, Project Officer,
EPA-IERL to Chakra Santhanam, Arthur D. Little, Inc., November
1978.
91. Chu, T. -Y.J. and Ruane, R.J., "Wastewater Treatment for Coal-Fired
Electric Generating Stations," Proceedings of the 1978 WWEMA
Industrial Pollution Conference, St. Louis, Mo. April 11-13, 1978.
92. Theis, T.L., et al. "Sorbtive Characteristics of Heavy Metals in
Fly Ash-Soil Environments." Proceedings of the 31st Annual Purdue
Industrial Waste Conference, 1976.
93. Milligan, J.D., Cox, D.B., and Ruane, R.J., "Characterization of
Coal Pile Drainage and Ash Pond Leachate." Presented at the
49th Annual WPCF Conference, Minneapolis, Mn. October 3-8, 1976.
94. Steinei; G.R., Chu, T.-Y.J. and McEntyre, C.L. "Treatment of Chemical
Cleaning Wastes at TVA Fossil-Fueled Power Plants," Presented at
84th AIChE National Meeting, Atlanta, Georgia, February 26-March 1, 1978,
95. Sisson, A.B., and Lee, G.V. "Incineration Safety Disposes of Chemi-
cal Cleaning Solvents." Proceedings of American Power Conference.
1972. P. 757.
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96. Chu, T.-Y.J., Steiner, G. R. and McEntyre, C. L. "Removal of^
Complex Cooper-Ammonia Ions from Aqueous Wastes with Fly Ash,"
Proceedings of 32ud Annual Purdue Industrial Waste Conference. 1977
97. Cox, D.B., Chu, T.-Y.J., and Ruane, R. J. "Quality and Treatment of
Coal-Pile Runoff," Presented at NCR/BCR Coal Conference and EXPO IV,
Louisville, Kentucky, October 18-20, 1977.
98. "Information for Proposed General Pretreatment Regulations (40 CFR
403)", Office of Planning and Evaluation, EPA, Wash., D.C. March, 1977.
99. Steiner, G.R., McEntyre, C.L., and Chu, T.-Y.J. "Treatment of Metal
Cleaning Wastes at TVA Power Plants." Presented at the 84th Annual
Meeting of AIChE., Atlanta, Georgia, February 26-March 1, 1978.
1°°• "Annual Environmental Analysis Report." Prepared under ERDA Contract
EE-01-77-0135 by Mitre, Consad Research, Control Data and International
Research and Technology for the Department of Energy, Washington, D.C.,
September 1977.
101. "Technical Report for Revision of Steam Electric Effluent Limitation
Guidelines" EPA-Effluent Guideline Division, Washington, D.C., 20460.
Draft Report, September, 1978.
102. Hazardous Wastes — Proposed Guidelines and Regulations, and
proposal on Identification and Listing, Federal Register, Monday
December 18, 1978, Part IV, Pages 58946-59028.
103. Personal Communication, Michael Osborne of EPA-IERL to Chakra Santhanam
of Arthur D. Little, Inc., November, 1978.
104. Lewis, B.C., December, 1977. Asbestos in Cooling Tower Waters.
Report ANL/ES-63, Argonne National Laboratory, Argonne, Illinois.
105. Atwood, K.E. and W.R. Greenway. July, 1975. Fly Ash Handling Systems
Study Relating to Steam Electric Power Generating Point Source Category
Effluent Guidelines and Standards. Utility Water Act Groups, C.W, Rice
Division of NUS Corporation, Pittsburgh, Pennsylvania.
106. Jolley, R.L., G. Jones, W.W. Pitts, and J.E. Thompson, Chlorination of
Organics in Cooling Waters and Process Effluents. In: Proceedings of
the Conference on Environmental Impact, Oak Ridge National Labs, Energy
Research and Development Agency, pp. 27-43, 1975.
107. White, G.C., Chlorination and Dechlorination: A Scientific and Practical
Approach. Journal of the American Water Works Association, pp. 540-555,
1968. VV
108. Crawford, T.N., Dechlorination of Pacific Gas and Electric Company's
Power Plants; A System Description. The Pacific Gas and Electric
Company, pp. 9, 1977.
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109. Conger, H.C., "New Approach to Cooling Water Treatment," Hydrocarbon
Processing, January, 1979, pp. 119-122.
110. Chu, T-Y.J. et.al., Characterization and Reuse of Ash Pond Effluents
in Coal-Fired Power Plants, Forty-Ninth Annual Water Pollution Control
Federation Conference, TVA, Minneapolis, Minnesota, October 3-8, 1976.
111. EpA Utility FGD Survey — February, March, 1978, by FED Co.,
Environmental, Inc., EPA 600/7-78-OJIb, Environmental Protection Agency,
Washington, : D. C. , 20460, June, 1978.
112. Halker, W.A. , "Ash Basin Equivalency Demonstration,"
Company. Presented at the 39th Annual Meeting of the American Power
Conference, Chicago, Illinois, April 19, 1977.
113. "SO- Removal with Zero Discharge," Environ. Science and Technology,
l3, No.l, Jan, 1979, pp. 25-30
Berube, D. T. and Grimm, C. D., "Status and Performance of the
Montana Power Company's Flue Gas Desulfurication System," presented
at the EPA FGD Symposium, Hollywood, Florida, November 1977.
115. "Asbestos in Cooling Tower Waters," by Lewis, B.G9, Report No,
ANL/ES-63, Argonne National Laboratory, Argonne, Illinois,
December, 1977.
116. "Staff Report on Water Requirements for Power Plants with Wet
Cooling Towers," Nelson, Guy R. , EPA Pacific Northwest Environmental
Research Laboratory, March, 1974.
117. Personal Communication to Chakra Sant'ianam, Arthur D. Little, Inc.
October, 1978. *
118. Maurer, J. T., "Controlling Corrosion Problems with High Technology
Stainless Steels," Proc. of the 38th International Water
Conference, Pittsburgh, Pa., November 1-3, 1977.
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INDEX
Acid drainage from coal piles see Coal pile runoff
Activated carbon, use in water treatment 3-113
Agricultural runoff 3-55
Air preheater cleaning 3-7, 3-10, 3-138
Airborne particulates, in cooling tower blowdown 3-53
Alkaline fly ash scrubbing 3-117
Anion resins, use in water treatment 3-77, 3-78
Asbestos, in cooling tower blowdown 3-53
in cooling water blowdown 5-28
Ash
dewatering bins 3-88
disposal impacts 6-2, 6-15
distribution between fly and bottom 3-80 to 3-82
hydraulic transport of 3-84 to 3-89, 3-113
mechanical conveyors for 3-84
pneumatic transport of 3-84 to 3-89, 3-113
reactivity 3-99, 3-100
transportation velocities during handling 3-89, 3-90
water requirements for disposal 6-22
Ash disposal
cost of 5-3
dry methods 5-35 to 5-37
Ash handling
ash characteristics 3-79 to 3-82
metals in sluice water 3-13
sluicing water 3-5, 3-101 to 3-103
systems in use 3-82 to 3-87
waste streams 3-90 to 3-101
Ash ponds
discharge characteristics 3-97 to 3-99
flows 3-93, 3-96 to 3-99
trace metal leaching 3-96
use in power plant operation 3-90 to 3-101
Ash pond effluents
auxiliary cooling water systems 3-133, 3-135
effect of limiting scale forming species 5-19
quantity of 3-17
Biocides 6-13
Biological fouling control 3-11
alternatives to chlorination 3-40, 3-41
biocides, and additive concentrations in blowdown 3-20, 3-28
chlorine in blowdown 3-37
Biological impacts 6-18
Biological impact issues 6-27
Biological productivity 6-19
Biological treatment inhibition 4-5
R-ll
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Boiler blowdown
characterization and treatment 3-62, 3-66
composition of 3-2
purity of 1-2
reuse of 3-68, 3-69
Boiler fireside, cleaning operations 3-138
Boiler slag see Ash handling
Boiler tube cleaning 3-7, 3-10, 3-136
Boiler types 3-62
Bottom ash see Ash handling
Cation resins, use in water treatment 3-111
Central treatment of power plant waste water, operating and capital
costs 5-7
Chelating agents for scale control 3-137
Chemical additives
concentration in effluent streams 3-11 to 3-14
effect on the environment 7-6 to 7-7
impact on water reuse 1-3
need for in power plants 2-14, 3-36
used in treatment of cooling water and boiler feed water 2-22, 2-23
Chemical precipitation, use in water treatment 3-111
Chemical wastes, characterization 2-22, 2-24, 3-9 to 3-16
Chlorination 3-37 to 3-43, 3-46
alternatives 3-41 to 3-46, 7-5
effect on the environment 7-5 to 7-6
Chromium compounds, in cooling tower blowdown 3-44, 3-49 to 3-52
removal from blowdown 3-49 to 3-52, 3-58, 3-59
Clarification, use in water treatment 3-2, 3-70, 3-73, 3-75
Clean Water Act of 1977 4-13
Coal conversion 4-15
Coal pile runoff
characterization of 3-8, 3-10
composition of 3-148, 3-149
treatment of 3-150, 3-151
Condensate polishing
characterization 3-79
in water treatment 3-2, 3-76
Condenser cleaning 3-7, 3-10, 3-17, 3-138
Condenser cooling
dry systems 5-33 to 5-34
heat transfer in 3-17
system types 2-12 to 2-14, 3-1
waste streams from 2-26
water use in 2-1
wet/dry systems 5-33
Consent decree compounds 4-9
Contact cooling water waste streams 6-14
Contaminant fate 6-21
Contaminant migration 6-5, 6-13, 6-24
R-12
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Cooling
system types in use 2-15
use of in steam-electric power plants 1-1, 2-12
water flow rates in, by region 2-16
Cooling ponds
advantages over cooling towers 3-1
characterization of 3-17, 3-20
impact issues 6-13
trends 2-12 to 2-14
usage, by plant 2-20, 2-21
Cooling tower drift 6-17, 6-21
Cooling tower fog 6-17
Cooling towers
basins 3-139
basin cleaning 3-8, 3-10
blowdown, characterization 3-1, 3-11, 3-25, 3-36, 3-61, 6-8
blowdown, water quality 6-7, 6-12
characterization 3-1, 3-17, 3-21, 3-24 to 3-27
design parameters 3-60
generalized plant water balance 2-25
trends 2-12 to 2-14
usage, by plant 2-17 to 2-19
water recirculation 3-56, 3-61
Cooling ponds vs. cooling towers for power plants 5-43
Cooling systems
dry 3-21, 3-22
hybrid 3-22, 3-23
once through 3-17, 3-19, 3-20
recirculating 3-20 to 3-23
Corrosion, rate dependence upon control method 3-54
Corrosion inhibition
additive concentrations in blowdown 3-28, 3-32, 3-35
chromates 3-32, 3-33
chromium and zinc in blowdown 3-44
impact issues 6-14
non-chromate treatment 3-49, 3-53, 3-65
trace metals from 3-11
Dam failure, impact issues 6-16
Disposal methods for fly ash
information gaps 7-2 to 7-3 :
technology gaps 7-4
Double alkali scrubbing see Dual alkali scrubbing
Drainage 3-147 to 3-152
characterization 3-8, 3-10
Drift deposition 6-21
Dry cooling system impact issues 6-15
Dual alkali scrubbing 3-117, 3-124 to 3-128
Economic considerations
constraints on 1-4, 3-55
capital and operating costs for water treatment systems 3-59
R-13
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EDTA, use in water softening 3-31, 3-65, 3-137
Effluent Guidelines, for pollutant control 5-30
revisions 4-8
Electric Power Research Institute
sponsored studies in water management 2-26, 2-28
Entrainment/entrapment of fish 4-6
Environmental Protection Agency (EPA)
distinctions between chemical and thermal wastes 2-24
effluent guidelines 3-104
identification of chemical waste categories 3-9
sponsored studies
chlorination alternatives 3-39
cooling systems 3-23
water management 2-26, 2-27
water pollution impact of SO control 3-131
water reuse 3-56
Evaporation ponds at power plants 5-11
Evaporators, composition of blowdown 3-74, 3-75
Federal Power Commission (FPC) 2-14
Feedwater heaters, cleaning 3-138
FGD processes
demister washing 3-123, 3-124, 3-130
dewatering options 3-120
makeup water requirements 3-121 to 3-131
pump seals, water use for 3-123, 3-125, 3-130
solids precipitation in 3-120
water balance in 3-121 to 3-123, 3-125, 3-128, 3-129
water evaporation effects 3-126 to 3-128
water requirements, effect of boiler load on 3-128
FGD systems
characterization 3-5, 3-6, 3-114 to 3-133
dry scrubbing 5-34
metals in effluents 3-13
Filtration
composition of filter backwash 3-74
use in water treatment 3-2, 3-70
Floor and yard drains, water streams from see Drainage
Heavy metals discharge 4-11, 4-12
Hydraulic conveyance of fly ash, impact issues 6-15
Incineration of metal cleaning wastes 3-140
Ion exchange
in chromate removal 3-49, 3-51
in water treatment 3-2, 3-31, 3-74 to 3-78, 3-109
with cooling tower blowdown 3-47
with makeup water 3-70
Laboratory and sampling activities, water use in 3-133 to 3-135
Land related impacts 6-4
R-14
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Langelier Saturation Index 3-104, 3-106 to 3-108, 3-110
Lime scrubbing 3-114, 3-117
Limestone scrubbing 3-114, 3-117, 3-119
Makeup water treatment 3-29
Maintenance cleaning
characterization 3-7
metal additives 3-13
operations 3-136, 3-146
wastes, data gaps 7-6
Mechanical cleaning, as supplement to chlorination 3-41, 3-46
Metals, removed from maintenance cleaning wastes see Maintenance
cleaning
Miscellaneous operations 3-6, 3-7, 3-133 to 3-135
National Energy Act of 1978 4-14
National Pollution Discharge Elimination System (NPDES), guidelines
and standards 4-2
Neutralization in waste treatment 3-76
Once-through cooling impacts 6-1 to 6-21
Ozone
Impact issues 6-13
use as chlorine substitute 3-43
pH control in boiler blowdown 3-65
Pond overflow
impacts 6-22
issues 6-16
Post closure land use issues 6-5
Power cycle characterization 3-2, 3-3
Power generation
annual quantity by fuel 3-4
fuels use 2-7
power cycles 3-2
systems in use 2-1
trends 2-5, 2-7
Pretreatment standards 4-4
Priority pollutants 4-9, 4-10, 6-12
Protection of wildlife 4-8
Publicly Owned Treatment Works (POTW) 4-4
Recycle cooling system impacts 6-6
Regulations 4-1
Best Available Technology (BAT) guidelines 4-1, 4-2
EPA effluent guidelines for ash ponds 3-104, 3-105
federal legislation impacting water quality 1-1
multimedia approach 4-15
National Pollution Discharge Elimination System (NPDES) 4-2
New Source Performance Standards (NSPS) 4-1, 4-2
trends 1-4
R-15
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Remand decision for utility effluents 4-7
Residual chlorine 6-13
impacts 6-20
Resource Conservation and Recovery Act (RCRA) 4-14
Reverse osmosis, use in water treatment 3-2, 3-31, 3-75, 3-77, 3-109, 3-111
Sanitary facilities, water use in 3-133 to 3-135
Scale control 3-11, 3-28 to 3-32, 3-62 to 3-65, 3-66, 3-67, 3-123
acid treatment 3-29, 3-30, 3-137
Seepage, impact issues 6-16
Settling ponds see Ash ponds
Silica, concentration in boiler water 3-72
Sludge disposal impact issues 6-4
Softening, use of lime in 3-30, 3-47, 3-48, 3-61, 3-75, 3-109
use in water treatment 3-2
use of zeolites in 3-47, 3-48
Solids deposition in boiler tubes 3-66
Solid waste disposal issues 6-24
Sponsored studies, see also EPA, EPRI, TVA
EPA, water management 2-27, 2-28
EPA, water pollution from SO control 3-131 to 3-133
Stack cleaning 3-8, 3-10, 3-139
Steam-electric systems see Power generation
Steam generation
boiler blowdown from 3-62 to 3-69
power cycles in 3-2
quantity of power from 2-1, 2-4
Surface runoff, control under RCRA 4-14
impact issues 6-17, 6-22, 6-27
Suspended solids dispersion 3-11, 3-28
Tennessee Valley Authority, study of metal cleaning waste treatment 3-145
Thermal wastes 2-22
guidelines and standards 4-3
impacts 6-20
Toxic chemicals
impact issues 6-20
regulatory control 4-16
Trace metals
enrichment in fly ash 3-80
from chemical additives 3-11 to 3-14
in boiler blowdown 3-2
Treatment technology issue 6-23
Washing of intake screens, water use in 3-133, 3-134
Waste pond revegetation studies 6-18
Waste water treatment methods
distillation 5-12
reverse osmosis 5-12
vapor compression evaporation (VCE) 5-8 to 5-11
vertical tube foam evaporation (VTFE) 5-12
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Water availability for steam-electric power 2-6, 2-9, 6-23
Water balance in power plants 2-22
contribution of condenser cooling 3-1
general for cooling tower 2-25
schematic representation of recycle, treatment, reuse 3-15
typical flows 3-73
Water consumption for power plants 5-2, 5-33
Water recycle/reuse options
at Bowen plant 5-22
at Colstrip plant 5-24
at Comanche plant 5-21
at Four Corners plant 5-20
at Montour plant 5-23
Water recycle/reuse technologies
economic estimates for 7-1
effect on energy requirements for plants 5-42
effect on plant costs/benefits 5-41 to 5-42
effect on plant operations 5-40
effect on power plant design 5-40
for power plants 5-8 to 5-14
Water recycle/treatment/reuse, EPA projects 6-25
EPRI projects 6-26
Water requirements
impact issues 6-3, 6-6
of utilities, by states 2-2, 2-3
of utilities, by region 2-8
trends 2-6, 2-10 to 2-12
Water reuse
impact issues 6-3
impact of chemical additives on 1-3
overview of treatment in report 3-4
regulatory control 4-16
Water treatment
effluents from 2-1
of makeup water 3-27 to 3-35, 3-70
power plant streams entering 3-9
systems used 3-2, 3-69 to 3-79
Water use impacts 6-1, 6-2
Wet/dry hybrid system impacts 6-15
Wildlife protection 4-8
Wood preservatives leaching 3-11, 3-55
Zero discharge, recycle with 3-47, 3-48, 3-77, 3-79, 3-121
Zinc compounds in cooling tower blowdown 3-44
R-17
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1 REPORT NO.
EPA-600/7-80-012b
2.
3. RECIPIENT'S ACCESSION- NO.
4 TITLE AND SUBTITLE Waste and Water Management for
Conventional Coal Combustion Assessment Report-
1979; Volume II. Water Management
6. REPORT DATE
March 1980
6. PERFORMING ORGANIZATION CODE
7 AUTHOR(S)C j santhanam,R. R. Lunt,C. B. Cooper,
D.E.Klimschmidt.I.Bodek, and W.A. Tucker (ADL);
and C.R.Ullrich (tniv of Louisville)
B. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
EHE624A
9 PERFORMING ORGANIZATION NAME AND ADDRESS
Arthur D. Little, Inc.
20 Acorn Park
Cambridge, Massachusetts 02140
11. CONTRACT/GRANT NO.
68-02-2654
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND
Final; 9/77-8/79
PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTES IERL-RTP project officer is Julian W. Jones, Mail Drop 61, 919/
541-2489.
i«.ABSTRACT Thie report, the second of five volumes, describes water management for
conventional combustion sources and assesses the current status of various studies
and programs in water management and trends in water recycle/reuse. A coal-fired
boiler produces both chemical and thermal pollution; the report focuses on the for-
mer. Major uses for water, hence generation points for effluents, are of two types:
continuous (condenser cooling, steam generation, water treatment, ash handling,
FGD, and miscellaneous) and intermittent (maintenance cleaning and drainage). The
many uses of water in a power plant and the varying requirements of water quality in
those uses present major opportunities for water conservation and pollution control
through wastewater management, equalization, and treatment of appropriate waste
streams. While technology exists for zero discharge of water, economics often pre-
clude recycle/reuse beyond a certain point. Water management studies completed by
EPA and industry can serve as models for new facilities. Treatment systems to
maximize water reuse are being studied by the EPA, and improved evaporators ap-
pear promising. Effluent treatment to remove priority pollutants are also under
study. Important data gaps concern environmental impacts in particular due to pri-
ority toxics in effluents including ash disposal and cooling water chlorination.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. CQSATi Field/Group
Pollution
Coal
Combustion
Assessments
Management
Water
Pollution Control
Stationary Sources
13B
21D
21B
14B
C5A
07B
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report j
Unclassified
21. NO. OF PAGES"
315
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
•PA form 2220-1 («-73)
R-18
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