r/EPA
United States
Environmental Protection
Agency
Office of Solid Waste .
and Emergency Response
Washington, DC 20460
EPA/530-SW-88-OO2
February 1988
Solid Waste
Report to
Congress
Wastes from the Combustion
of Coal by Electric Utility
Power Plants
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UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON. D.C. 20460
MAR 8
THE ADMINISTRATOR
Honorable George Bush
President of the Senate
Washington, D.C. 20510
Dear Mr. President:
I am pleased to transmit the Report to Congress on
Wastes from the Combustion of Coal by Electric Utility
Power Plants. The report presents the results of
studies carried out pursuant to Section 8002 (n) of
the Resource Conservation and Recovery Act of 1976 as
amended (42 U.S.C. Section 6982 (n)).
The report provides a comprehensive assessment of the
management of solid wastes generated by the combustion of
coal from electric utility power plants. These wastes
account for approximately 90 percent of all wastes
generated from the combustion of fossil fuels. The
principal waste categories covered include fly ash,
bottom ash, boiler slag and flue gas emission control
waste.
The report and appendices are transmitted in two
separate volumes.
Sincerely,.
Lee M. Thomas
Enclosure
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f 22?
\
3 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
x WASHINGTON. D.C. 20460
•
MAR 8 1988
THE ADMINISTRATOR
Honorable James C. Wright
Speaker of the House
of Representatives
Washington, D.C. 20515
Dear Mr. Speaker:
I am pleased to transmit the Report to Congress on
Wastes from the Combustion of Coal by Electric Utility
Power Plants. The report presents the results of
studies carried out pursuant to Section 8002(n) of
the Resource Conservation and Recovery Act of 1976 as
amended (42 U.S.C. Section 6982(n)}.
The report provides a comprehensive assessment of the
management of solid wastes generated by the combustion of
coal from electric utility power plants. These wastes
account for approximately 90 percent of all wastes
generated from the combustion of fossil fuels. The
principal waste categories covered include fly ash,
bottom ash, boiler slag and flue gas emission control
waste.
The report and appendices are transmitted in two
separate volumes.
Lee M. Thomas
Enclosure
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TABLE OF CONTENTS
Page
EXECUTIVE SUMMARY ES-1
I. INTRODUCTION 1-1
1.1 Legislative History 1-1
1.2 Scope and Sources 1-7
1.3 Organization 1-9
II. OVERVIEW OF THE ELECTRIC UTILITY INDUSTRY 2-1
2.1 The Demand for Electricity 2-1
2.1.1 Structure of the U.S. Electric
Utility Industry 2-7
2.1.2 Economic and Environmental Regulation
of the Electric Utility Industry 2-11
2.2 Importance of Coal to Electric Utilities 2-14
2.3 Overview of Coal-Fired Power Plants 2-18
2.3.1 Regional Characteristics of Coal-Fired
Electric Generating Plants 2-18
2.3.2 Electricity Generating Technologies 2-21
2.4 Coal Constituents and By-Products 2-29
III. WASTES GENERATED FROM COAL-FIRED ELECTRIC UTILITY
POWER PLANTS 3-1
3.1 Overview of Electric Utility Wastes 3-1
3.2 High-Volume Wastes 3-3
3.2.1 Ash 3-3
3.2.2 FGD Sludge 3-21
3.3 Low-Volume Wastes 3-41
3.3.1 Boiler Slowdown 3-43
3.3.2 Coal Pile Runoff 3-45
3.3.3 Cooling Tower Slowdown 3-47
3.3.4 Demineralizer Regenerant and Rinses 3-50
3.3.5 Metal and Boiler Cleaning Wastes 3-52
3.3.6 Pyrites 3-57
3.3.7 Sump Effluents 3-60
3.4 Summary 3-62
IV. COAL COMBUSTION WASTE MANAGEMENT PRACTICES 4-1
4.1 State Regulation of Coal Combustion
Waste Disposal 4-1
4.1.1 State Classification of Coal Combustion
Wastes 4-2
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-2-
TABLE OF CONTENTS (cont'd)
Page
4.1.2 Requirements for Coal Combustion Waste
Disposal 4-6
4.1.3 Summary 4-9
4.2 Available Waste Management Methods and
Current Practices 4-10
4.2.1 Land Management of Coal Combustion Wastes 4-10
4.2.2 Alternative Waste Management Technologies 4-24
4.2.3 Ocean Disposal 4-44
4.2.4 Waste Utilization and Recovery of
Various Waste By-Products 4-45
4.3 Summary 4-53
V. POTENTIAL DANGERS TO HUMAN HEALTH AND THE ENVIRONMENT 5-1
5.1 RCRA Subtitle C Hazardous Waste Characteristics
and Listing Criteria 5-2
5.1.1 Corrosivity of Coal Combustion Wastes 5-4
5.1.2 Extraction Procedure Toxicity of Coal
Combustion Wastes 5-5
5.2 Effectiveness of Waste Containment at Utility
Disposal Sites 5-28
5.2.1 ADL Study of Waste Disposal at
Coal-Fired Power Plants 5-29
5.2.2 Franklin Associates Survey of State
Ground-Water Data 5-44
5.2.3 Envirosphere Ground-Water Survey 5-48
5.2.4 Summary 5-52
5.3 Evidence of Damage 5-53
5.3.1 Envirosphere Case Study Analysis 5-54
5.3.2 Dames & Moore Study of Environmental
Impacts 5-56
5.3.3 Case Studies of the Environmental
Impact of Coal Combustion By-Product
Waste Disposal ' 5-63
5.3.4 Summary 5-67
5.4 Factors Affecting Exposure and Risk at
Coal Combustion Waste Sites 5-68
5.4.1 Environmental Characteristics of
Coal Combustion Waste Sites 5-69
5.4.2 Population Characteristics of Coal
Combustion Waste Disposal Sites 5-83
5.4.3 Ecologic Characteristics of Coal
Combustion Waste Disposal Sites 5-89
5.4.4 Multivariate Analysis 5-93
5.5 Summary 5-95
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TABLE OF CONTENTS (cont'd)
Page
VI. ECONOMIC COSTS AND IMPACTS 6-1
6.1 Waste Disposal Costs Associated With
Current Disposal Methods 6-2
6.1.1 Costs of Waste Placement and
Disposal ..... 6-5
6.1.2 Costs Associated with Lined
Disposal Facilities 6-11
6.2 Costs of Alternative Disposal Options 6-12
6.2.1 Regulatory Alternatives Under
Subtitle C 6-13
6.2.2 Cost Estimates for Individual RCRA
Subtitle C Disposal Standards 6-17
6.2.3 Potential Costs to the Industry of RCRA
Subtitle C Waste Management 6-30
6.3 Impact of Regulatory Alternatives on
Utilization of Coal Combustion Wastes 6-33
6.4 Economic Impacts of Alternative Waste
Disposal Options 6-37
6.5 Summary 6-43
VII. CONCLUSIONS AND RECOMMENDATIONS 7-1
7.1 Scope of Report 7-1
7.2 Summary of Report 7-2
7.2.1 Location and Characteristics of Coal-
Fired Power Plants 7-2
7.2.2 Waste Quantities and Characteristics 7-3
7.2.3 Waste Management Practices 7-5
7.2.4 Potential Hazardous Characteristics 7-6
7.2.5 Evidence of Environmental Transport
of Potentially Hazardous Constituents 7-7
7.2.6 Evidence of Damage 7-9
7.2.7 Potential Costs of Regulation 7-9
7.3 Recommendations 7-11
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-4-
TABLE OF CONTENTS (cont'd)
Page
Bibliography
Glossary
Appendix A:
Appendix B:
Appendix C:
Appendix D:
Letter from Gary N. Dietrich, EPA, to Paul Emler, Jr.,
USWAG, January 13, 1981 and Memorandum from EPA
Headquarters to EPA Regional Directors, February
18, 1981
Methodology For Estimating Volume of Ash and FGD
Sludge Generation
Regulation of Coal Combustion Waste Disposal In
Seventeen High Coal-Burning States
Waste Fluid Studies
A-l
B-l
C-l
D-l
Appendix E: Arthur D. Little Study of Waste Disposal At Coal-Fired
Power Plants E-l
Appendix F: Data On Sample of Coal-Fired Combustion Waste Disposal
Sites F-l
Appendix G: Methodology For Calculating The Cost of Alternative
Waste Management Practices G-l
2923C
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INDEX OF EXHIBITS
Page
CHAPTER TWO
2-1 Growth in Electricity Demand - 1975-2000 2-2
2-2 Electricity Sales By Year and Class of Service 2-4
2-3 Electricity Demand by EPA Region: 1985 2-5
2-4 EPA Federal Regions 2-6
2-5 Generating Capacity in the United States 2-8
2-6 Electricity Generation by Primary Energy
Source: 1975-2000 2-15
2-7 Electric Utility Dependence on Coal by EPA Region: 1985 2-17
2-8 U.S. Coal Consumption by Sector: 1975-2000 2-19
2-9 Total Number and Average Size of Coal-Fired
Plants and Units 2-20
2-10 Range of Coal-Fired Power Plant Sizes 2-22
2-11 Process For Generating Electricity at Coal-Fired
Power Plants 2-23
2-12 Diagram of a Pulverized Coal Boiler 2-25
2-13 Diagram of a Cyclone Boiler 2-27
2-14 Characteristics of Various Types of Stokers 2-30
2-15 Diagram of a Spreader Stoker 2-31
2-16 Total Coal Boiler Capacity by EPA Region 2-32
2-17 Average Coal Boiler Size By Type of Boiler
and By EPA Region 2-33
2-18 Electric Utility Production of FGD Wastes: 1985 2-36
CHAPTER THREE '
3-1 Representative Ash Contents By Producing
Region and Coal Rank: 1985 3-9
3-2 Volume of Ash Generated by Coal-Fired Electric
Utility Power Plants -- 1975-2000 3-10
3-3 Average Ash Content of Coal Burned by Electric
Utility Power Plants in the U.S. -- 1975-2000 3-12
3-4 Representative Ranges of Values For the Physical
Characteristics of Fly Ash, Bottom Ash,
and Boiler Slag 3-14
3-5 Low and High Concentrations of Major Chemical
Constituents Found in Ash Generated by
Coal-Fired Power Plants 3-16
3-6 Element Concentrations In Ash From Three
Geographic Sources 3-18
3-7 Effect Of Geographic Coal Source On Ash
Element Concentration 3-19
3-8 Element Concentrations In Three Types Of Ash 3-20
3-9 Major Types of Flue Gas Desulfurization Systems 3-23
3-10 Flow Diagram of Wet Flue Gas Desulfurization System 3-25
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INDEX OF EXHIBITS
Page
CHAPTER THREE (Continued)
3-11 Flow Diagram of Spray-Drying Flue Gas Desulfurization
System 3-27
3-12 Flow Diagram of Dry Injection Flue Gas Desulfurization
System 3-28
3-13 Flow Diagrams of Recovery Flue Gas Desulfurization Systems 3-30
3-14 FGD Capacity and FGD Sludge Generation -- 1970-2000 3-32
3-15 Representative Ranges of Values for the Physical
Characteristics of FGD Sludge 3-36
3-16 Concentration of Major Chemical Constituents of Wet FGD
Sludge Solids by Scrubber System and Source of Coal 3-39
3-17 Concentration of Major Chemical Constituents of Wet FGD
Sludge Liquors by Scrubber System and Source of Coal 3-40
3-18 Concentration of Trace Elements Found in Wet-FGD Sludges 3-42
3-19 Annual Low-Volume Waste Generation At a Representative
Coal-Fired Power Plant 3-44
3-20 Characteristics of Boiler Slowdown 3-46
3-21 Characteristics of Coal Pile Runoff 3-48
3-22 Characteristics of Cooling Tower Slowdown 3-51
3-23 Characteristics of Spent Demineralizer
Regenerants 3-53
3-24 Reported Characteristics of Gas-Side Cleaning Wastes 3-55
3-25 Characteristics of Spent Water-Side Alkaline
Cleaning Wastes 3-56
3-26 Characteristics of Spent Water-Side Hydrochloric Acid
Cleaning Wastes 3-58
3-27 Characteristics of Spent Water-Side Alkaline Passivating
Wastes 3-59
3-28 Characteristics of Pyrites and Pyrite Transport Water 3-61
CHAPTER FOUR
4-1 State Regulations Governing Coal Combustion Waste Disposal 4-3
4-2 Typical Surface Impoundment (Pond) Stages 4-12
4-3 Diagrams of Active and Closed Landfills 4-15
4-4 Utility Waste Management Facilities By EPA Region 4-19
4-5 Location of Utility Waste Management Facilities:
On-site versus Off-site 4-21
4-6 Installation of Liners For Leachate Control at Utility
Waste Management Facilities 4-31
4-7 Summary of Current Handling, Treatment and Disposal
of Low-Volume Wastes 4-39
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INDEX OF EXHIBITS
Page
CHAPTER FIVE
5-1 Maximum Concentration of Contaminants For Characteristic
of EP Toxicity 5-6
5-2 Effect of Geographic Coal Source On Element
Concentration In Ash 5-10
5-3 Results of Tetra Tech Extraction Tests On Coal Combustion Ash .. 5-12
5-4 Results of Arthur D. Little Testing Showing
The Range of Concentration of Metals In
EP Extracts 5-17
5-5 EP Toxicity Analysis For Untreated and Treated Boiler
Chemical Cleaning Wastes 5-21
5-6 EP Toxicity Test Results For Liquid Low-Volume Wastes 5-23
5-7 Comparison of EP and TCLP Extractions For Low-Volume Sludge
Dredged From Wastewater Ponds 5-24
5-8 EP Toxicity Test Results of Low-Volume Wastes Before
and After Co-Disposal 5-26
5-9 Primary And Secondary Drinking Water Standards 5-30
5-10 Summary of Arthur D. Little's Ground-Water Quality
Data On Primary Drinking Water Exceedances 5-35
5-11 Summary of Arthur D. Little's Ground-Water
Quality Data on Secondary Drinking Water
Exceedances 5-37
5-12 Summary of Arthur D. Little's Surface-Water
Quality Data On Primary Drinking Water Exceedances 5-40
5-13 Summary of PDWS Exceedances in the Franklin
Associates Survey 5-46
5-14 Summary of SOWS Exceedances in the Franklin
Associates Survey 5-47
5-15 Summary of PDWS Exceedances in Envirosphere's
Ground-water Data 5-50
5-16 Summary of SOWS Exceedances in Envirosphere's
Ground-water Data 5-51
5-17 Distance Of Coal Combustion Waste Sites To Surface Water 5-72
5-18 Flow Of Nearest Surface-Water Body 5-74
5-19 Depth To Ground Water at Coal Combustion Waste Sites 5-77
5-20 Hydraulic Conductivity at Coal Combustion Waste Sites 5-78
5-21 Net Recharge at Coal Combustion Waste Sites 5-81
5-22 Ground-Water Hardness at Coal Combustion Waste Sites 5-82
5-23 Populations Within One Kilometer of Waste Sites 5-85
5-24 Populations Within Three Kilometers of Waste Sites 5-86
5-25 Populations Within Five Kilometers of Waste Sites 5-87
5-26 Populations Served By Public Water Systems Near Waste Sites .... 5-89
5-27 Ecological Status of Waste Sites 5-92
CHAPTER SIX
6-1 Overview of Waste Handling and Disposal Options
for Coal Ash 6-3
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INDEX OF EXHIBITS
Page
CHAPTER SIX (Continued)
6-2 Overview of Waste Handling and Disposal Options
for FGD Waste 6-4
6-3 Ranges of Average Capital Costs Associated With
Coal-Fired Electric Utility Waste Disposal 6-6
6-4 Ranges of Average Total Costs For Coal-Fired
Electric Utility Waste Disposal 6-7
6-5 Summary of Costs to Close Existing Waste Disposal
Facilities 6-23
6-6 Summary of Costs For Different Types of Lined
Waste Management Facilities 6-28
6-7 Costs to the Electric Utility Industry For Hypothetical
RCRA Compliance Strategies 6-29
6-8 Summary of Economic Impacts on By-Product Utilization
Under Different RCRA Regulatory Scenarios 6-36
6-9 Impact of Current Waste Disposal Costs on Total
Electricity Generation Costs 6-39
6-10 Impact of Alternative Disposal Options on Electricity
Generation Costs 6-40
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EXECUTIVE SUMMARY
The Environmental Protection Agency (EPA) has prepared this report on
fossil fuel combustion wastes pursuant to the requirements of Section 8002(n)
of the Resource Conservation and Recovery Act (RCRA), as amended in 1980.
These amendments to the Act added Section 8002(n), which directed the
Administrator of EPA to
conduct a detailed and comprehensive study and submit a
report on the adverse effects on human health and the
environment, if any, of the disposal and utilization of fly
ash waste, bottom ash waste, slag waste, flue gas emission
control waste, and other by-product materials generated
primarily from the combustion of coal or other fossil fuels.
Pending the completion of this study, fossil fuel combustion wastes were
exempted from the hazardous waste requirements established under RCRA. Under
Section 3001(b)(3)(A), EPA is prohibited from regulating these wastes until at
least six months after this report is submitted to Congress.
If EPA determines that fossil fuel combustion wastes are hazardous under
RCRA, and therefore subject to regulation under Subtitle C, EPA has some
flexibility to promulgate regulations that take into account the unique
characteristics of these wastes. Section 3004(x) states ...
If ... fly ash waste, bottom ash waste, slag waste and flue
gas emission control waste generated primarily from the
combustion of coal or other fossil fuels ... is subject to
regulation under this subtitle, the Administrator is
authorized to modify the requirements of subsections (c),
(d), (e), (f), (g), (o) and (u) and section 3005(j) ... to
take into account the special characteristics of such wastes,
the practical difficulties associated with implementation of
such requirements, and site-specific characteristics ... so
long as such modified requirements assure protection of human
health and the environment.
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ES-2
This report examines only those wastes generated from the combustion of coal
by the electric utility industry. These wastes account for approximately 90
percent of all wastes generated from the combustion of fossil fuels. EPA has
deferred study of the disposal of wastes generated by the combustion of other
fossil fuels and from coal combustion in industries other than the electric
utility industry until a later date.
Coal-fired power plants produce substantial quantities of wastes. In 1984
about 69 million tons of ash and 16 million tons of flue gas desulfurization
wastes were generated. Because of increasing reliance on coal for producing
electricity, by the year 2000 the amount of ash waste is expected to increase by
about 75 percent to about 120 million tons annually; production of FGD wastes is
expected to triple to about 50 million tons annually. In addition to the
high-volume ash and flue gas desulfurization wastes, coal-fired power plants
also generate several lower-volume waste streams as a result of equipment
maintenance and cleaning activities.
About one-fifth of all waste generated at coal-fired electric utility power
plants is currently reused; the remaining four-fifths are typically disposed in
surface impoundments or landfills. The recycled wastes, usually fly ash, bottom
ash, or boiler slag, have been used primarily as cement additives, high-volume
road construction material, and blasting grit. There is some potential for
increased use of these wastes in such applications. However, barring the
•*• It is possible that advances in coal combustion technology will alter
the amount and types of coal-combustion wastes produced in the future. An
analysis of these technological advances is beyond the scope of this report.
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ES-3
development of new utilization techniques, or major changes in combustion and
environmental control technologies, the proportion of coal combustion wastes
that are reused is unlikely to change significantly.
While utility waste management sites are currently exempt from RCRA
hazardous waste requirements, they are subject to state and local level solid
waste laws and regulations. There is substantial variation in the
state-mandated disposal requirements.
Most utility waste management facilities were not designed to provide a high
level of protection against leaching. Only about 25 percent of all facilities
have liners to reduce off-site migration of leachate, although 40 percent of the
generating units built since 1975 have liners. Additionally, only about 15
percent have leachate collection systems; about one-third of all facilities have
ground-water monitoring systems to detect potential leachate problems. Both1
leachate collection and ground-water monitoring systems are more common at newer
facilities.
The primary concern regarding the disposal of wastes from coal-fired power
plants is the potential for waste leachate to cause ground-water contamination.
Although most of the materials found in these wastes do not cause much concern
(for example, over 95 percent of ash is composed of oxides of silicon, aluminum,
iron, and calcium), small quantities of other constituents that could
potentially damage human health and the environment may also be present. These
constituents include arsenic, barium, cadmium, chromium, lead, mercury, and
selenium. At certain concentrations, these elements have toxic effects.
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ES-4
To assess the potential threat to health and the environment posed by these
wastes and to document any specific damage cases, EPA, other agencies, and
various private organizations sponsored several studies. The main research
efforts cited in this Report to Congress are a 1985 study by Arthur D. Little,
Inc. for EPA, which characterized the environmental effects of waste disposal at
several utility disposal sites, and a series of reports submitted to the Agency
in 1982 by the Utility Solid Waste Activities Group, the Edison Electric
Institute, and the National Rural Electric Cooperative Association.
The findings of these various research efforts indicate that most coal
combustion wastes do not exhibit any of the four hazardous characteristics
defined in RCRA Subpart C. The results of a substantial number of extraction
procedure tests were examined; these tests indicated that metals do not
generally leach out of coal combustion wastes at levels classified as hazardous
under RCRA. The only metals which were found in any ash or sludge samples at
"hazardous" levels were cadmium and arsenic. For boiler cleaning wastes,
chromium and lead were sometimes found at levels classified as hazardous under
RCRA. This waste stream was also found to be corrosive in a number of samples.
Results of EP Tests performed on co-disposed high and low volume wastes
indicate, however, that boiler cleaning wastes do not exhibit hazardous
characteristics when co-disposed with ash.
While most of the laboratory results indicated that coal combustion wastes
do not possess RCRA hazardous characteristics, in some instances, data on actual
field observations indicate that migration of potentially hazardous constituents
from utility waste disposal sites has occurred. For example, observed
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ES-5
concentrations of contaminants found in ground water downgradient from the sites
exceed the Primary Drinking Water Standards about 5 percent of the time.
Although the magnitude of the PDWS exceedances are typically not many times
greater than the standard, a large number of disposal facilities report at least
one PDWS exceedance at some time.
While a causal connection cannot always be made between the utility waste
disposal site and the presence of contaminants at concentrations in excess of
these standards, the available information indicates that some ground-water
contamination from utility disposal sites is indeed occurring. The actual
potential for exposure of human and ecological populations is likely to be
limited, however, since ground water in the vicinity of utility waste disposal
sites is not typically used for drinking water; the concentrations of
contaminants in the ground water also tend to be diluted in nearby surface water
bodies. These surface water bodies are typically used by electric utilities in
the power plants for cooling and other purposes.
The electric utility industry currently spends about $800 million annually
to dispose of its coal-fired combustion wastes. Under current practices, costs
for waste management at most basic facilities range from as little as $2 per ton
to as much as $31 per ton. Mitigative measures to control potential
leaching include installation of liners, leachate collection systems, and
ground-water monitoring systems and corrective action to clean up ground-water
contamination. These mitigative measures, which are currently used at some
utility waste disposal sites, may reduce the likelihood of ground-water
contamination, but may also substantially increase disposal costs. For example,
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ES-6
the incremental cost of new waste disposal practices, excluding corrective
action costs or higher recycling costs, could range up to $70 per ton, or $3.7
billion annually if all wastes were listed as hazardous. While substantial on a
total cost basis, these increases would be unlikely to significantly affect the
rate at which existing power plants consume coal. Due to the competitiveness of
alternative fuels for electricity generation at future power plants, however,
any increase in disposal costs could potentially slow the growth in electric
utility coal consumption in future years. Moreover, if new disposal standards
require corrective action measures as set forth in 40 CFR 264.100, the costs to
utilities could be extremely high and could have a substantial effect on the
utility industry.
Based on the findings from this Report to Congress, the Agency presents
three preliminary recommendations for those wastes included in the scope of this
study. The recommendations are subject to change based on continuing
consultations with other government agencies and new information submitted
through the public hearings and comments on this report. Pursuant to the
process outlined in RCRA 3001(b)(3)(C), EPA will announce its regulatory
determination within six months after submitting this report to Congress.
First. EPA has concluded that coal combustion waste streams generally do not
exhibit hazardous characteristics under current RCRA regulations. EPA does not
intend to regulate under Subtitle C fly ash, bottom ash, boiler slag, and flue
gas desulfurization wastes. EPA's tentative conclusion is that current waste
management practices appear to be adequate for protecting human health and the
environment. The Agency prefers that these wastes remain under Subtitle D
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ES-7
authority. EPA will use section 7003 of RCRA and sections 104 and 106 of CERCLA
to seek relief in any cases where wastes from coal combustion waste disposal
sites pose substantial threats or imminent hazards to human health and the
environment. Coal combustion waste problems can also be addressed under RCRA
Section 7002, which authorizes citizen lawsuits for violations of Subtitle D
requirements in 40 CFR Part 257.
Second. EPA is concerned that several other wastes from coal-fired utilities
may exhibit the hazardous characteristics of corrosivitv or EP toxicity and
merit regulation under Subtitle C. EPA intends to consider whether these waste
streams should be regulated under Subtitle C of RCRA based on further study and
information obtained during the public comment period. The waste streams of
most concern appear to be those produced during equipment maintenance and water
purification, such as metal and boiler cleaning wastes. The information
available to the Agency at this time does not allow EPA to determine the exact
quantity of coal combustion wastes that may exhibit RCRA Subtitle C
characteristics. However, sufficient information does exist to indicate that
some equipment maintenance and water purification wastes do occasionally exhibit
RCRA hazardous characteristics, and therefore, may pose a danger to human health
and the environment. These wastes are similar to wastes produced by other
industries that are subject to Subtitle C regulation, and waste management
practices for coal combustion wastes are often similar to waste management
practices employed by other industries. EPA is considering removing the
exemption for all coal-fired utility wastes other than those identified in the
first recommendation. The effect would be to apply Subtitle C regulation to any
of those wastes that are hazardous by the RCRA characteristic tests. EPA
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ES-8
believes there are various treatment options available for these wastes that
would render them nonhazardous without major costs or disruptions to the
utilities.
Third. EPA encourages the utilization of coal combustion wastes as one
method for reducing the amount of these wastes that need to be disposed to the
extent such utilization can be done in an environmentally safe manner. From the
information available to the Agency at this time, current waste utilization
practices appear to be done in an environmentally safe manner. The Agency
supports voluntary efforts by industry to investigate additional possibilities
for utilizing coal combustion wastes.
Through its own analysis, evaluation of public comments, and consultation
with other agencies, the Agency will reach a regulatory determination within six
months of submission of this Report to Congress. In so doing, it will consider
and evaluate a broad range of management control options consistent with
protecting human health and the environment. Moreover, if the Agency determines
that Subtitle C regulation is warranted, in accordance with Section 3004(x) EPA
will take into account the "special characteristics of such waste, the practical
difficulties associated with implementation of such requirements, and
site-specific characteristics . . .," and will comply with the requirements of
Executive Orders 12291 and 12498 and the Regulatory Flexibility Act.
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CHAPTER ONE
INTRODUCTION
This is the Environmental Protection Agency's Report to Congress on wastes
from fossil fuel combustion, as required by section 8002(n) of the Resource
Conservation and Recovery Act. It describes sources and quantities of utility
waste, current utilization and disposal practices and alternatives to these
practices, potential dangers to human health and the environment, and the costs
of current and alternative waste management practices. This report is based on
numerous literature reviews and contractor studies; EPA's RCRA Docket contains
copies of the source materials that the Agency used in preparing this report.
1.1 Legislative History
Because Congress has amended the Resource Conservation and Recovery Act >
several times and EPA's regulatory program continues to evolve in response to
these Congressional mandates and other additional information, a brief
legislative and regulatory history is provided below.
The Resource Conservation and Recovery Act (RCRA, or the Act) of 1976
(Public Law 94-580) substantially amended the Solid Waste Disposal Act of 1965
and authorized the U.S. Environmental Protection Agency (EPA) to establish and
enforce regulations concerning the identification, generation, transportation,
and management of hazardous waste. These regulations would accomplish the
Act's objectives of "...promote[ing] the protection of health and the
environment ... and conserve[ing] valuable material and energy resources...."^-
RCRA comprises several subtitles, including Subtitle C-- Hazardous Waste
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1-2
Management, and Subtitle D-- State or Regional Solid Waste Plans. The intent
of the regulations promulgated under Subtitle C of the Act is that wastes
identified as hazardous be properly managed from "cradle to grave," that is,
from the time they are generated, during transport, throughout their use in
various applications, and during disposal. As provided under RCRA Subtitle D,
other wastes not considered hazardous as defined under Subtitle C are subject
to State regulations.
On December 18, 1978, EPA proposed the first regulations to implement
Subtitle C. In the course of preparing these regulations, EPA recognized that
certain very large-volume wastes (e.g., wastes generated by utility power
plants) could require special treatment:
... The Agency has very little information on the
composition, characteristics, and the degree of hazard
posed by these wastes, nor does the Agency yet have data on
the effectiveness of current or potential waste management
technologies or the technical or economic practicability of
imposing the Subpart D standards [current RCRA section
3004--Standards applicable to owners and operators of
hazardous waste treatment, storage, and disposal
facilities] on facilities managing such waste.
The limited information the Agency does have indicates that
such waste occurs in very large volumes, that the potential
hazards posed by the waste are relatively low, and that the
waste generally is not amenable to the control techniques
developed in Subpart D.^
Thus, the Agency proposed a limited set of regulations for managing
large-volume wastes, pending an additional rulemaking. Until that rulemaking
was completed, EPA proposed exempting utility wastes from storage and disposal
regulations.
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1-3
On May 19, 1980, EPA promulgated the first regulations implementing
Subtitle C of RCRA. By then, Congress was debating RCRA reauthorization, and
both Houses had passed bills restricting EPA's ability to regulate utility
wastes. Anticipating the enactment of legislation amending RCRA Section 3001,
EPA excluded utility wastes from the promulgated regulations, writing in the
preamble:
The United States Senate and House of Representatives have
each recently passed a bill to reauthorize and amend RCRA
(S.1156 and H.R.3994). Both bills contain amendments to
Section 3001 which, if enacted, would repeal or temporarily
suspend EPA's authority to regulate certain utility and
energy development wastes as hazardous wastes under
Subtitle C. These bills are now awaiting action by a
conference committee. Because it appears likely that
Congress will act before November 19, 1980 [the end of the
six month comment period on the promulgated interim final
regulations and the date on which they would take effect]
to exempt these wastes, EPA has temporarily excluded them
from this regulation (see section 261.4(b)). This
exclusion will be revised, if necessary, to conform to the
legislation which is ultimately enacted.-^
In fact, Congress did act before November 19, 1980; the Solid Waste
Disposal Act Amendments (Public Law 96-482) were passed in October 1980.
As anticipated, the amendments temporarily exempted from regulation fly ash
waste, bottom ash waste, boiler slag waste, and flue gas emission control waste
generated primarily from the combustion of coal or other fossil fuels. In
section 8002(n), Congress directed EPA to produce a report on the kinds of
waste generated by the combustion of coal and other fossil fuels, which would
include an analysis of eight topics:
1. the source and volumes of such material generated
per year;
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1-4
2. present disposal and utilization practices;
3. potential danger, if any, to human health and the
environment from the disposal and reuse of such material;
4. documented cases in which danger to human health or the
environment from surface runoff or leachate has been
proved;
5. alternatives to current disposal methods;
6. the costs of such alternatives;
7. the impact of those alternatives on the use of coal and
other natural resources; and
8. the current and potential utilization of such
materials. ^
Finally, in section 3001(b)(3)(C), Congress directed that within six months
after submitting this report, EPA must conduct public hearings and decide
whether regulating the management of coal combustion wastes under Subtitle C is
warranted. Once the decision is made, the Administrator must publish the
Agency's regulatory determination in the Federal Register.
In a January 1981 letter,-' Gary Dietrich, then Associate Deputy Assistant
Administrator for Solid Waste, provided an interpretation of RCRA regulations
concerning the exemption from regulation of fossil fuel combustion waste.
(This letter, as well as a February 18, 1981 memorandum that enclosed it as
part of a mailing to EPA Regional Directors, is included as Appendix A.) The
letter noted that the beneficial use of hazardous waste as a fuel was not
subject to regulation, though it might well be subject to regulation in the
future. This meant that utilities could burn as fuel a combination of
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1-5
hazardous waste and coal, as long as more than 50 percent of the mixture was
comprised of coal. The letter also addressed disposal, noting that wastes
produced in conjunction with the burning of fossil fuels (e.g., cleaning and
other maintenance-related wastes) may be exempt from Subtitle C regulations
provided they are mixed and co-disposed or co-treated with fossil fuel wastes
and provided "there is no evidence of any substantial environmental danger from
these mixtures."' The letter concluded:
...Pending the completion of [further study on the hazards
posed by waste from coal-fired utility plants and the
collection of relevant data from the utility industry], EPA
will interpret 40 CFR 261.4(b)(4) to mean that the
following solid wastes are not hazardous wastes:
(a) Fly ash, bottom ash, boiler slag, and
flue gas emission control wastes
resulting from (1) the combustion
solely of coal, oil, or natural gas,
(2) the combustion of any mixture of
these fossil fuels, or (3) the
combustion of any mixture of coal and
other fuels, where coal makes up more
than 50 percent of the mixture.
(b) Wastes produced in conjunction with
the combustion of fossil fuels, which
are necessarily associated with the
production of energy, and which
traditionally have been, and which
actually are, mixed with and
co-disposed or co-treated with fly
ash, bottom ash, boiler slag, or flue
gas emission control wastes from coal
combustion.
This provision includes, but is not limited to, boiler cleaning solutions,
boiler blowdown, demineralizer reagent, pyrites, and cooling tower blowdown.
In November 1984, Congress reauthorized RCRA by passing the Hazardous and
Solid Waste Amendments (HSWA). These amendments restricted the land disposal
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1-6
of certain hazardous wastes without treatment, established minimum technology
requirements for landfills and surface impoundments, issued corrective action
requirements for continuing releases at permitted facilities, and established
interim status requirements for surface impoundments. Under this new
legislation, EPA was granted some flexibility to promulgate regulations that
take into consideration the unique characteristics of several types of
large-volume wastes, including wastes generated by utility power plants.
Specifically, if EPA determined that some or all of the wastes from fossil fuel
combustion were subject to regulation under Subtitle C, EPA was empowered to
modify the standards imposed by HSWA "...to take into account the special
characteristics of such wastes, the practical difficulties associated with
implementation of such requirements, and site-specific characteristics ... so
long as such modified requirements assure protection of human health and the
o
environment."0
The HSWA Conference Report accompanying H.R. 2867 (which in its final
amended form was passed by both Houses of Congress as Public Law 98-616)
provides clarification:
This Amendment recognizes that even if some of the special
study wastes [which include utility wastes as specified in
Section 8002(n)] are determined to be hazardous it may not
be necessary or appropriate because of their special
characteristics and other factors, to subject such waste to
the same requirements that are applicable to other
hazardous wastes, and that protection of human health and
the environment does not necessarily imply the uniform
application of requirements developed for disposal of other
hazardous wastes. The authority delegated to the
Administrator under this section is both waste-specific and
requirement-specific. The Administrator could also
exercise the authority to modify requirements for different
classes of wastes. Should these wastes become subject to
the requirements of Section 3005(j), relating to the
retrofit of surface impoundments, the Administrator could
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1-7
modify such requirements so that they are not identical to
the requirements that are applied to new surface
impoundments containing such wastes. It is expected that
before any of these wastes become subject to regulation
under Subtitle C, the Administrator will determine whether
the requirements of Section 3004(c), (d), (e), (f), (g) ,
(o), and (u), and Section 3005(j) should be modified."
1.2. Scope and Sources
This report addresses only the wastes generated by coal-fired electric
utility power plants. Because this industry generates the vast majority of all
fossil fuel combustion waste (nearly 90 percent), EPA decided to focus its
study in this area. This study does not address oil- and gas-fired electric
utility power plants or coal, oil and gas-fired industrial boilers.
A number of research projects were undertaken to provide data for this
report. EPA sponsored a major study of current coal ash and flue gas
desulfurization waste management practices at coal-fired electric utility power
plants. In this study comprehensive environmental monitoring was conducted1,
which included characterizing the wastes, soils, ground water, and surface
water at six disposal sites. The contractor (Arthur D. Little, Inc.) evaluated
the environmental effects of the disposal practices used at these six sites
and, by inference, what effects may be present at other utility waste disposal
sites. They also performed extensive engineering and cost evaluations of
disposal practices at the six sites.
EPA also sponsored a separate study effort to develop information on the
incidences of ground water contamination resulting from utility waste
12
management practices. In this study, contamination was defined as the
presence of hazardous constituents at levels above primary drinking water
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1-8
standards. The main source of information for this phase of the research was a
review of case files at the state offices having responsibility for such
matters.
In addition, the Agency also reviewed reports submitted by the Utility
Solid Waste Activities Group (USWAG), the Edison Electric Institute (EEI), and
13
the National Rural Electric Cooperative Association (NRECA). The reports
present information on the sources, volumes, and physical and chemical
characteristics of waste streams; ground-water monitoring results assembled
from various utility plants; damage case information from various sources;
costs of complying with hazardous waste regulations; and resource recovery
opportunities using utility wastes.
EPA also has incorporated findings from several documents prepared by the
14
Department of Energy (DOE) and the Electric Power Research Institute (EPRI).
These reports examined the chemical composition of utility wastes, technologies
for disposal and the costs associated with disposal, as well as results of
leaching tests performed on utility wastes.
Finally, EPA gathered information from the Utility Data Institute's Power
Statistics Database. This database contains information concerning the size
of utility power plants, location of power plants, the types of disposal
technologies employed by each power plant, and the amount of waste produced by
site and by region. The information on location of power plants was combined
with hydrogeologic, population, and ecological profiles of these locations to
analyze the potential for exposure to coal combustion wastes.
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1.3 Organization
The following chapters of this report address the eight issues (enumerated
earlier in this chapter) as required by Section 8002(n) as they apply to
coal-fired combustion wastes generated by electric utilities. Chapter Two of
this report provides an overview of the U.S. electric utility industry.
Chapter Three examines the amount and types of wastes that are generated.
Chapter Four discusses current waste management and disposal practices used by
the electric utility industry, as well as alternatives to these practices; a
review of applicable State regulations is included in this chapter. Chapter
Five reviews the potential and documented impact of these wastes on human
health and the environment, and Chapter Six evaluates costs associated with
current waste disposal practices' and additional costs that could be incurred
under a variety of alternative waste management practices. Finally, Chapter
Seven summarizes the conclusions contained in the previous chapters and
presents recommendations.
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CHAPTER ONE
NOTES
1 Resource Conservation and Recovery Act of 1976 (RCRA), Section 1003(a).
2 Federal Register. Volume 43, No. 243, December 18, 1978, pp.
58991-58992.
3 Federal Register. Volume 45, No. 98, May 19, 1980, p. 33089.
4 RCRA, Section 8002(n).
5 Letter of January 13, 1981, from Gary N. Dietrich, Associate Deputy
Assistant Administrator for Solid Waste, to Paul Elmer, Jr., Chairman of the
Utility Solid Waste Activities Group.
6 See 40 CFR 261.4.
7 Gary N. Dietrich, January 13, 1981, op. cit.: for further information,
see Congressional Record, February 20, 1980, p. H 1102, remarks of Congressman
Bevill; also see remarks of Congressional Record, February 20, 1980, p. H 1104,
remarks of Congressman Rahall.
8 RCRA, Section 3004(x)
9 H.R. Report 98-1133, pp. 93-94, October 3, 1984.
Most fossil fuel combustion wastes are generated from coal. For
example, as indicated in Physical-Chemical Characteristics of Utility Solid
Wastes (by Tetratech, Inc. for EPRI, September 1983), only about one percent of
utility wastes are generated from oil; the remaining 99 percent is largely
attributable to coal-fired electricity production. Of the coal consumed in the
U.S., electric utilities burn nearly 90 percent (excluding metallurgical coal,
which is not burned but is instead converted into coke primarily for making
steel).
Arthur D. Little, Inc., Full-Scale Field Evaluation of Waste Disposal
From Coal-Fired Electric Generating Plants. Prepared for EPA's Office of
Research and Development, EPA Contract #68-02-3167; June 1985.
12
Franklin Associates, Ltd., Survey of Groundwater Contamination Cases
at Coal Combustion Waste Disposal Sites, prepared for U.S. Environmental
Protection Agency, March 1984.
13
USWAG is an informal consortium of approximately 65 electric utility
operating companies, EEI, and NRECA. The primary source used in the
preparation of this report was Report and Technical Studies On The Disposal and
Utilization of Fossil-Fuel Combustion Bv-Products. USWAG, EEI, and NRECA,
October 26, 1982.
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14
For example, see Impacts of Proposed RCRA Regulations and Other Related
Federal Environmental Regulations on Utility Fossil Fuel-Fired Facilities:
Prepared by Engineering-Science for DOE, DOE Contract Number
DE-AC-01-79ET-13543, May 1983; Physical-Chemical Characteristics of Utility
Solid Wastes. EPRI, September 1983; Analytical Aspects of the Fossil Energy
Waste Sampling and Characterization Project. Prepared by Western Research
Institute, DOE Order Number DE-AP20-84LC00022, March 1984; and Environmental
Settings and Solid Residues Disposal in the Electric Utility Industry. EPRI,
July 1984. More sources are included in the Bibliography.
Utility Data Institute's Power Statistics Database was developed under
the auspices of the Edison Electric Institute to assist in their analysis of
issues affecting the electric utility industry.
-------
CHAPTER TWO
OVERVIEW OF THE ELECTRIC UTILITY INDUSTRY
This chapter provides a general overview of the U.S. electric utility
industry. Section 2.1 summarizes electricity demand and discusses the overall
structure of the electric utility industry. Section 2.2 focuses the
discussion on the role that coal plays in generating electricity. Section 2.3
provides details of coal-fired electric generating technologies and the
regional characteristics of coal-fired plants. The chapter concludes with a
discussion in Section 2.4 of the waste streams that are produced during coal
combustion.
2.1 THE DEMAND FOR ELECTRICITY
The generation, transmission, and distribution of electricity is one of
l
our nation's largest industries. With annual revenues in excess of $140
billion and assets of about $500 billion, the electric utility industry
provides vital services to nearly every person in the U.S.
Total demand for electricity in the U.S. has increased substantially in
recent decades and will likely continue to grow in coming years (see Exhibit
2-1). From the 1940's through the early 1970's, electricity demand grew at
about 7 percent per year, doubling approximately every ten years. This growth
slowed beginning with the 1973 OPEC oil embargo and subsequent changes in the
energy markets such as fuel price increases, shifts in the economy to markets
that require less electricity to meet their power needs, and energy
conservation measures. Since 1973, growth in electricity demand has averaged
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2-2
EXHIBIT 2-1
GROWTH IN ELECTRICITY DEMAND - 1975-2000
4000-
3600-
3200-
2800-
Electricity 240°-
Sales
(billions of 200°-
kilowatthours)
1600-
1200-
800-
400-
1975
1980
1985
1990
1995
2000
Forecast
Year
Sources: 1975-1985: Energy Information Administration, Electric Power
Monthly. DOE/EIA-0226 (85/12), December 1985, p. 39.
1985-2000: ICF Incorporated, Analysis of 6 and 8 Million ton and
30 Year/NSPS and 30 Year/1.2 Ib. Sulfur Dioxide Emission Reduction
Cases, Prepared for Environmental Protection Agency, February 1986.
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2-3
about three percent per year. Expectations are that electricity demand will
continue to grow at an average rate of about 2 to 3 percent per year over the
f\
next several years. *•
Every major segment of the U.S. economy relies on electricity to meet a
portion of its energy needs. As shown in Exhibit 2-2, the demand for
electricity is divided almost evenly between the industrial, commercial, and
residential sectors. This demand for electricity has continued to increase
over the last decade with total sales increasing from 1.7 million gigawatt-
hours (Gwh) in 1975 to 2.3 million Gwh in 1985.3 As demand has increased,
electricity sales patterns have remained relatively consistent. Industry
continues to be the largest consuming sector, although industry's fraction of
total sales has decreased by about 2.7 percent from 1975 to 1985, primarily
due to an increased market share for the commercial sector (i.e., stores,
office buildings, restaurants, etc.). Residential customers consume about
one-third of all electricity for basic necessities such as lighting, heating,
and electrical appliances.
Virtually every geographic area in the U.S. relies on electricity supplied
by the electric utility industry. As shown in Exhibit 2-3, electricity demand
is highest in the eastern half of the U.S., particularly in EPA Regions 3-6
(see Exhibit 2-4 for a map of these EPA Regions). This level of demand is not
surprising considering that these areas are the most heavily industrialized
and densely populated areas of the country.
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EXHIBIT 2-2
ELECTRICITY SALES BY YEAR AND CLASS OF SERVICE
(gigawatt-hours)
' 1975 SALES
Total Sales = 1.733,024 kWh
1980 SALES
Total Sales = 2,126,094 kWh
1984 SALES
Other
Total Sales = 2.285,532 kWh
Source: Edison Electric Institute, Statistical Yearbook of the Electric
Utility Industry/1985, December 1986.
^Includes street lighting, other public authorities, railroads and
interdepartmental transfers within utilities (i.e., use of electricity by the
utility itself).
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EXHIBIT 2-3
ELECTRICITY DEMAND by EPA REGION
1985
Millions of Percent
EPA Region Kilowatt Hours of Total
1 86,397 3.8
2 164,780 7.2
3 230,055 10.1
4 483,248 21.2 .
5 428,873 18.8
6 340,198 14.8
7 112,076 4.9
8 72,458 3.2
9 227,006 10.0
10 135,716 6.0
Total U.S. 2,280,585 100.0
Source: Edison Electric Institute, Statistical Yearbook of the Electric
Utility Industry/1985, December 1986.
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EXHIBIT 2-4
EPA FEDERAL REGIONS
Philadelphia
Washintlon D.C.
a.
to
I
ON
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2-7
2.1.1 Structure of the U.S. Electric Utility Industry
The U.S. electric power industry is a combination of private, Federal, and
public nonprofit organizations. The distribution•of capacity, generation,
revenue, and sales differs widely among these ownership groups since each
group has different obj ectives, organizational characteristics, and financing
methods. Private investor-owned utilities dominate the U.S. electric utility
industry as shown in Exhibit 2-5. Investor-owned utilities have historically
served large consolidated markets to take advantage of economies of scale.
Federal, municipal, cooperative, and other publicly-owned utilities have
generally served smaller markets where local governments or nonprofit
organizations have had access to limited supplies of less expensive Federal
power or to government-supplied capital for power plant construction. These
circumstances have allowed municipal, cooperative, or other publicly-owned
utilities to predominate in areas not traditionally served by investor-owned
utilities. A brief discussion of each type of organization is provided
below.
2.1.1.1 Investor-Owned Utilities
Investor-owned utilities account for about three-quarters of all U.S.
electric utility generating capacity, generation, sales, and revenue.
Investor-owned utilities are privately owned, profit-oriented businesses
granted service monopolies in certain geographic areas. As franchised
monopolies, they are obligated to provide service to all customers within
their geographic area. In providing this service, investor-owned utilities
are required to charge reasonable prices, to charge similar prices to similar
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EXHIBIT 2-5
GENERATING CAPACITY IN THE UNITED STATES
Kilowatts ^Millions)
Government and
Cooperatives
100
50
65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85
Source: Edison Electric Institute, Statistical Yearbook for the Electric
Utility Industry/1985, December 1986.
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2-9
customers, and to give customers access to services under similar conditions.^
Investor-owned utilities operate in all states except Nebraska (which depends
primarily on public power districts and rural electric cooperatives for
electricity). In 1984, consumers paid an average of 6.5 cents per
kilowatt-hour (kwh) for privately-produced power compared to the industry
average from all ownership groups of 6.3 cents per kilowatt-hour (an average
customer consumed 23,150 kwh in 1984).6
2.1.1.2 Federal Power
The U.S. Government is the second largest producer of electricity in the
United States with roughly 10 percent of total U.S. generation and generating
capacity. Consumers of Federal- power paid the lowest rate among the different
ownership groups -- only 3.5 cents per kwh on average in 1984, (compared to an
industry average of 6.3 cents per kwh).^ Federal power production is designed
to provide power at the lowest possible rate, with preference in the sale of
electricity given to public entities and cooperatives." In this role the
Federal Government is primarily a generator and wholesaler of electricity to
other organizations, rather than a direct distributor to electricity
o
consumers.?
2.1.1.3 Municipal Utilities
Municipal utilities are nonprofit local government agencies designed to
serve their customers at the lowest possible cost. Most municipal utilities
simply distribute power obtained from one of the other ownership groups (e.g.,
Federal facilities), although some larger ones also generate and transmit
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2-10
power. Municipally-owned electric utilities rank third in the amount of
installed capacity (5.5 percent of total generating capacity), but comprise
the single most numerous ownership group (1,811 utilities in 1984). Average
revenue per kwh sold in 1984 was 5.69 cents compared to an industry average of
6.3 cents per kwh. Municipal utilities are exempt from local, state, and
Federal taxes and have access to less expensive capital via public financing
and less expensive Federal power. As a result, municipal utilities can
generally afford to charge less than investor-owned utilities for the power
they produce.
2.1.1.4 Cooperatives
Rural electric cooperatives are owned by and provide electricity to their
members and currently operate in 46 states. They have the lowest amount of
installed capacity among all ownership categories (24.7 gigawatts in 1984 or
12
less than 4 percent of all capacity).
In 1984, average revenue for cooperatives from sales to consumers was 6.7
cents per kwh, the highest of all ownership types (the industry average was
6.3 cents per kwh). Large construction programs in the 1970's usually account
13
for the high rates.
2.1.1.5 Other Public Entities
There are a variety of other public organizations that provide electric
power, including public power districts, state authorities, irrigation
districts, and various other State organizations. These other public entities
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operated a combined total of 32.8 gigawatts in 1984, or about 5 percent of all
14
generating capacity in the U.S. The public power districts are concentrated
in five states -- Nebraska, Washington, Oregon, Arizona, and California. The
average price paid for electricity from all of these entities was 4.37 cents
per kwh in 1984, compared to an industry average of 6.3 cents per kwh.
2.1.2 Economic and Environmental Regulation of the Electric Utility
Industry
The electric utility industry is regulated by several different regulatory
bodies at both the Federal and State levels. According to the U.S. Department
of Energy: "The basic purpose of public utility regulation is to assure
adequate service to all public utility patrons, without discrimination and at
the lowest reasonable rates consistent with the interests both of the public
and the electric utilities." This regulation involves both economic and
environmental objectives. As natural monopolies, electric utilities are
regulated to ensure that adequate, reliable supplies of electric power are
available to the public at a reasonable cost. Additionally, since the
operations of electric utilities can affect environmental quality, they are
regulated to ensure the protection of the nation's air and water resources.
This section briefly reviews the main regulatory bodies that affect the
electric utility industry.
2.1.2.1 Federal Regulation
There are five major organizations at the Federal level that regulate some
aspect of the electric utility industry -- the Federal Energy Regulatory
Commission (FERC), the Economic Regulatory Administration (ERA), the
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2-12
Securities and Exchange Commission (SEC), the Nuclear Regulatory Commission
(NRC), and the Environmental Protection Agency (EPA).
• The Federal Energy Regulatory Commission (FERC) oversees
various aspects of the electric utility, natural gas,
hydroelectric, and oil pipeline industries. FERC approves
the rates and standards for wholesale interstate electricity
sales between investor-owned utilities and other
investor-owned utilities, municipals, or cooperatives (these
sales are about 15 percent of total U.S. electricity
sales). It determines whether these rates are reasonable
and non-discriminatory. FERC also oversees utility mergers
and the issuance of certain stock and debt securities,
approves the rates of Federal Power Marketing
Administrations, and administers agreements between
utilities concerning electricity transmission.
• The Economic Regulatory Administration (ERA) has several
responsibilities, including administering a program to
ensure that all future power plants have the potential to
burn coal, regulating international electricity transmission
connections, and licensing exports of power.
• The Securities and Exchange Commission (SEC) is an
independent regulatory agency established to regulate
interstate transactions in corporate securities and stock
exchanges. With respect to the electric utility industry,
the SEC regulates the purchase and sale of securities,
utility properties, and other assets.
• The Nuclear Regulatory Commission (NRC) is involved only in
the regulation of nuclear facilities owned and operated by
the utility industry. Its main responsibilities include
licensing the construction and operation of nuclear
facilities, licensing the possession, use, transportation,
handling, and disposal of nuclear materials, licensing the
export of nuclear reactors and the import and export of
uranium and plutonium, and regulating activities affecting
the protection of nuclear facilities and materials.
In addition to these regulatory bodies, the Environmental Protection
Agency (EPA) is the main Federal regulatory authority for protecting the
nation's air and water quality. As part of its overall authority, EPA sets
limits on the level of air pollutants emitted from electric power plants and
develops regulations to control discharges of specific water pollutants.
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Throughout this Report to Congress key regulations that affect the electric
utility industry are discussed. While EPA often takes the Federal lead when
these regulations are developed, the Agency also works closely with the States
since they often retain primary authority for implementing and enforcing
standards (for example, see Section 4.1 on state regulation of coal combustion
wastes).
2.1.2.2 State Regulation
States are also involved in the environmental and economic regulation of
the electric utility industry. As mentioned above, the States often share
regulatory authority with the various Federal organizations. For
environmental regulation the States often have their own environmental
protection agencies to implement and enforce State and Federal environmental
regulations. For example, they are responsible for drafting State
Implementation Plans (SIP) that must be approved by the U.S. EPA to attain
National Ambient Air Quality Standards (NAAQS). Similarly, as will be
discussed in greater detail in Chapter Four, the States have authority for
implementing and enforcing regulations concerning the disposal of solid wastes
under Subtitle D of RCRA. Environmental regulations for which the States
exercise regulatory authority are discussed throughout this Report to
Congress.
States are also very involved in the economic regulation of the electric
utility industry. The primary goals of state economic regulation is usually
to provide adequate nondiscriminatory service to electricity consumers at
19
reasonable prices. This is usually accomplished by state regulatory
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2-14
agencies such as public utility commissions. The amount of authority these
state regulatory agencies have can differ widely from state to state.
However, these agencies usually have the authority to approve electricity
price levels and the rates of return allowed for utility stockholders. State
regulators also approve the franchise under which the utility operates.
Licensing for construction and operation and approval of the sites at which
power plants will be built are also important functions of some state
regulatory commissions. Other areas into which some commissions have entered
to ensure that utility activities protect the public interest include setting
rules about when competitive bids are required, promulgating company
performance standards, deriving methods for allocating power during shortages,
20
establishing billing and safety rules, and promoting conservation.
2.2 IMPORTANCE OF COAL TO ELECTRIC UTILITIES
Electric utilities use many different technologies and energy sources to
generate electricity. At present, as shown in Exhibit 2-6, over 70 percent of
electricity in the U.S. is generated by the combustion of fossil fuels (coal,
oil and natural gas); most of the remaining 30 percent is generated by
hydroelectric plants and nuclear power plants. A small portion of electricity
demand is satisfied by alternative sources such as geothermal energy,
renewable resource technologies (e.g., wood, solar energy, wind), purchased
power from industrial and commercial cogeneration (cogeneration is the
simultaneous production of electricity and process steam; the electricity is
typically used by the cogenerator or sold to another industry while the steam
is used for various production processes), and power imports (primarily from
Canada).
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EXHIBIT 2-6
ELECTRICITY GENERATION BY PRIMARY ENERGY SOURCE
1975-2000
4000
Generation
(billions of
kilowatthours)
1975
Year
Forecast
Hydro &
Other
Nuclear
Oil & Gas
Coal
Source:
1975-1985: Energy Information Administration, Electric Power
Monthly DOE/EIA-0226 (85/12), December 1985, p. 10.
1985-2000: ICF Incorporated, Analysis of 6 and 8 million Ton
and 30 Year/NSPS and 30 Year/1.2 Ib. Sulfur Dioxide Emission
Reduction Cases. Prepared for Environmental Protection Agency,
February 1986.
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2-16
In 1984, coal accounted for more than half of all the electricity
21
generated in the U.S. The portion of electricity generated from coal is
expected to remain at about this level throughout the rest of the century
since coal-fired generation is expected to remain economically attractive.
The relative contribution to total generation made by other fossil fuels and
by hydroelectric power will likely continue to decline, while the contribution
made by nuclear power plants will likely increase for the next few years as
several new units come on-line. However, the addition of nuclear plants
beyond those now under construction will be minimal, leading to an eventual
decline in nuclear's relative contribution. Cogeneration, power imports, and
emerging technologies are expected to continue to grow, but their share of
total generation will remain small. As a result, coal will continue to be the
major fuel source for electricity generation.
The extent of the electric utility industry's dependence on coal varies
geographically. Exhibit 2-7 shows that coal accounts for over three-quarters
of electricity generation in some regions, but less than half in others. For
example, in the far West and southern Plains states, the local availability of
oil, gas, and hydroelectric power has limited regional dependence on coal. In
many of the eastern regions, where coal is relatively more accessible and less
costly than oil or gas, coal is significantly more dominant. Despite these
regional variations, however, coal-fired electricity generation is an
important source of electricity in most regions of the United States.
The use of coal by electric utilities has also made the coal and electric
utility industries highly interdependent; not only does coal-fired electricity
generation account for over half of the electricity produced in the U.S., but
-------
Coal
Percentages represent the proportion
of the total electricity generated in
the region by each type of fuel.
EXHIBIT 2-7
ELECTRIC UTILITY DEPENDENCE ON COAL
BY EPA REGION: 1985
33.4%
21.5%
4.8%
Source: Energy Information Administration, Electric Power
Annual 1985. DOE/EIA-0348(85), pp.17-30.
-------
2-18
the electric utility industry is the largest customer of the coal industry,
purchasing approximately three-quarters of all coal mined, as shown in Exhibit
2-8. This interdependence has increased as electric utility coal consumption
22
has grown from 406 million tons in 1975 to over 600 million tons in 1985.
Moreover, electric utility coal consumption is expected to continue to
increase to about 1 billion tons by the year 2000.
2.3 OVERVIEW OF COAL-FIRED POWER PLANTS
Coal-fired power plants can vary greatly in terms of their generating
capacity and the type of boiler technology they employ which, in turn, can
affect the amount and type of combustion wastes produced. This section
discusses the geographic differences in the size of plants and generating
units and describes the three main boiler types along with the regional
importance of each.
2.3.1 Regional Characteristics of Coal-Fired Electric Generating Plants
Coal-fired power plants can range in size from less than 50 MW to larger
than 3000 MW. In many cases, particularly at the larger power plants, one
power plant site may be the location for more than one generating unit (a
generating unit is usually one combination of a boiler, turbine, and generator
for producing electricity). Exhibit 2-9 shows the number of coal-fired power
plants and number of units in each EPA region and their average size in
megawatts. On average, each power plant site is comprised of about three
generating units. The average generating capacity of coal-fired power plants
in the U.S. is approximately 584 MW, with an average unit size of 257 MW.
-------
2-19
EXHIBIT 2-8
U.S COAL CONSUMPTION BY SECTOR
1975-2000
Consumption
T , ,. 1200-
Including
Exports _,
(miUions 100°-
of tons) 800-
1975
1980
1985
1990
Industrial &
Other
Exports
Metallurgical
Electric
Utilities
1995
2000
Year
Forecast
Sources: 1975-1985: Energy Information Administration, Annual Energy Review
1985. DOE/EIA-0384 (85), April 1985, pp. 167, 169.
1985-2000: ICF Incorporated, Analysis of 6 and 8 Million Ton and 30
Year/NSPS and 30 Year/1.2 Ib. Sulfur Dioxide Emission Reduction
Cases, Prepared for Environmental Protection Agency, February 1986.
-------
2-20
EXHIBIT 2-9
TOTAL NUMBER AND AVERAGE SIZE OF COAL-FIRED PLANTS AND UNITS
Number Average Size Number Average Size a/
EPA Region of Plants (MW> of Units a/ (MW)
1 6 374 18 158
2 17 297 39 138
3 57 753 144 308
4 93 799 295 301
5 171 492 492 185
6 39 852 87 580
7 66 400 149 186
8 48 454 109 250
9 13 603 34 383
10 4 479 11 382
U.S. Total 514 584 1378 257
Source: Utility Data Institute Power Statistics Database.
a/ The total amount of generating capacity indicated by multiplying the
number of units by their average size (e.g., 1378 units X 257 Mw - 354,146
Mw) is greater than the amount indicated by multiplying the number of
power plants by their average (e.g., 514 plants X 584 Mw - 300,176 Mw)
because the information in the UDI Power Statistics Database by generating
units includes units planned, currently under construction, etc. while the
information by power plants refers only to power plants currently
operating.
-------
2-21
Regional averages for power plant size range from 297 MW in Region 2 to 852 MW
in Region 6. Unit sizes range from an average of 138 Mw in Region 2 to 580 Mw
in Region 6. Individual power plants and units can be larger or smaller than
these averages indicate.
The majority of coal-fired plants (60%) are smaller than 500 MW, while
only about 4 percent of U.S. coal-fired power plants have a generating
capacity exceeding 2000 MW. Exhibit 2-10 shows the distribution of coal-fired
plant sizes across EPA regions.
2.3.2 Electricity Generating Technologies
The basic process by which 'electricity is produced with coal is shown in
Exhibit 2-11. When coal is burned to produce electricity, there are three key
components that are critical to the operation of the power plant: the boiler,
turbine, and generator. As coal is fed into the boiler, it is burned in the
boiler's furnace. In the boiler there are a series of water-filled pipes. As
heat is released during combustion, the water is converted to steam until it
reaches temperatures that can exceed 1000°F and pressures that approach 4000
pounds per square inch. This high pressure, high temperature steam is then
injected into a turbine, causing the turbine blades to rotate. The turbine,
in turn, is connected to a generator, so the mechanical energy available from
the rotating turbine blades is transformed into electrical energy. The
electricity produced by this process is distributed via transmission lines to
residential, commercial, and industrial end-users who rely on the power to
meet their electrical requirements. Although each step of this process is
critical to the production of electricity, this study focuses on boilers only
-------
2-22
EXHIBIT 2-10
RANGE OF COAL-FIRED POWER PLANT SIZES
(number of plants)
Power Plant Size
EPA Region
1
2
3
4
5
6
7
8
9
10
U.S. Total
<100
MW
1
6
6
15
63
10
25
18
5
2
101-500
MW
4
6
23
31
51
4
24
14
2
0
501-1000
MW
0
5
11
17
23
10
8
10
4
1
1001-2000
MW
1
0
14
23
29
12
7
4
1
1
>2000
MW
0
0
3
7
5
3
2
2
1
0
151
159
89
92
23
Total
6
17
57
93
171
39
66
48
13
4
514
Source: Utility Data Institute Power Statistics Database.
-------
EXHIE 2-11
PROCESS FOR GENERATING ELECTRICITY
AT COAL-FIRED POWER PLANTS
Flue Gases
Fly Ash
Steam
FGD Sludge
I .I*' >• .0- .? ..y .f -jV .-.V 0> AV rf'
>^vy7/^v^
•/',/././././././.// /
XX Turbine ^X/",
^•mM
•* Bottom Ash/Boiler Slag
I Generator!
Electricity
to Power Grid
to
Source: ICF Incorporated
-------
2-24
since it is in the boiler where the combustion wastes are produced as the coal
is burned.
There are three main types of boilers: (1) pulverizers, (2) cyclones, and
(3) stokers. As discussed below in greater detail, the key differences
between these boiler types are operating size and the procedures used for
handling and burning the coal. Pulverized coal boilers are so-named because
the coal is finely pulverized prior to combustion; most utility boilers are
this type. Cyclones have been used in past utility applications, but have not
been built recently. They are called cyclones because of the cyclone-like
vortex created by the coal particles in the furnace during combustion. Stoker
boilers are usually used when smaller capacities are required (e.g., 20-30 MW)
and burn coal in a variety of'sizes.
A brief description of each of these coal combustion technologies
23
follows.
2.3.2.1 Pulverized-Coal Boiler
Exhibit 2-12 shows a typical pulverized-coal boiler setup. In a
pulverized coal boiler, coal is ground to a fine size (about 200 mesh, which
is powder-like) in a pulverizer or mill. The pulverized fuel is then carried
to the burners by forced air injection and blown into the furnace, where it is
burned in suspension. Much of the ash remaining after combustion remains
airborne and is carried from the furnace by the flue gas stream (i.e., it
becomes fly ash; see Chapter Three for a more detailed discussion of types of
waste and how they are produced). Some ash is deposited on the furnace walls,
-------
2-25
EXHIBIT 2-12
DIAGRAM OF A PULVERIZED COAL BOILER
iiTi'iii'lVfii'iijiisiliJill'ii'lfici'Li -.."-i--?
^rtH^ff>
'?Ł>is^^&$$ x-1 n
Coal in
^ Pulverizer
Two-drum boiler direct-fired with pulverized coal.
Source: Babcock and Wilcox Co., Steam: Its Generation and Use, New York, NY
1978.
-------
2-26
where it agglomerates and may sinter or fuse. Ash that falls to the bottom of
the furnace is removed via an ash hopper. Ash deposits and slagging are more
of a problem in pulverized coal boilers than in stoker boilers.
Most modern pulverized-coal boilers have dry-bottom furnaces; that is, the
ash is intended to be removed as a dry solid before complete melting occurs.
As a result, for dry-bottom boilers, the ash-fusion temperature
(the melting point) of the coal must be high enough to prevent the ash from
becoming a running slag (i.e., a liquid form). Wet-bottom, or slag-tap,
pulverized-coal boilers are designed to remove the ash as a flowing slag.
These boilers depend on lower ash-fusion temperature coals so that the ash will
melt to form slag for easier removal.
2.3.2.2 Cyclones
The cyclone furnace consists of a water-cooled horizontal furnace in which
crushed coal is fired and heat is released at high rates, as shown in Exhibit
2-13. The temperature inside the furnace may reach 3000°F, which is sufficient
to melt the ash into a liquid slag that forms on the walls of the furnace. Air
circulation within the furnace typically creates a cyclone-like vortex that not
only helps the coal to burn in suspension but also causes many coal particles
to impinge upon the slag-covered walls of the furnace. This tendency for coal
particles to adhere to the walls of the cyclone boiler aids the combustion
process because the coal particles will burn more thoroughly before reaching
the bottom of the boiler. Most of the ash is retained in the slag layer, thus
minimizing the amount of fly ash that is carried out of the boiler. The slag,
-------
2-27
EXHIBIT 2-13
DIAGRAM OF A CYCLONE BOILER
Attimpcrator
Rtti«at
SuptrftMttr
»Gil Outlet
Air Inlit
Source: Babcock and Wilcox Co., Steam: Its Generation and Use. New York, NY,
1978.
-------
2-28
or melted ash particles, is typically removed at the bottom of the furnace.
The cyclone offers the advantage of being able to burn low ash-fusion coals
that create problems when burned in most conventional pulverized-coal
burners. The cyclone design also helps to minimize erosion and fouling
problems in the boiler. The smaller amounts of fly ash created compared to
other boiler types reduces the costs associated with particulate collection.
2.3.2.3 Stokers
Stokers are designed to mechanically feed coal uniformly onto a grate
within a furnace. Because most of the combustion takes place in the fuel bed,
not in suspension within the furnace, the heat release rate of this type of
boiler is lower than it is for pulverizers or cyclones. As a result, stokers
are generally designed for smaller-sized applications. In fact, this boiler
type is used by many manufacturing industries, but has seen only limited use by
electric utilities.
Stokers are classified by the method of feeding fuel to the furnace and by
the type of grate. The three most important stoker types include:
1) the spreader stoker, the most popular type of overfeed stoker,
2) other overfeed stokers, such as the chain-grate, travelling-grate
stoker, or the vibrating-grate stoker, and
3) the underfeed stoker.
-------
, 2-29
The major features of each are summarized in Exhibit 2-14. An illustration of
a spreader stoker is provided in Exhibit 2-15.
Use of the different boiler types varies by geographic region. As shown in
Exhibit 2-16, about three-fourths of all boiler capacity in the U.S. uses
pulverizers, with most of these dry-bottom pulverizers. Cyclones are the next
most prevalent boiler type, representing only about 8 percent of all boilers.
Stokers represent less than one-half of one percent of the total; due to their
size limitations stokers are used primarily in other industrial applications
for the production of steam.
Exhibit 2-17 shows the distribution of average capacity for each boiler
type by EPA region. The range in average sizes is most pronounced in dry
bottom boilers (127.8-610.0 MW), which reflects their substantial flexibility
in terms of size and dominance in electric utility applications. Stokers tend
to have the smallest capacities (an average of 14 MW nationwide), limiting
their usefulness in utility applications compared to all of the other boiler
types.
2.4 COAL CONSTITUENTS AND BY-PRODUCTS
Despite its attractiveness as a power plant fuel, coal has its drawbacks.
As a solid fuel, coal is often more difficult and more costly to transport,
store, and burn than oil or gas. Also, coal's many impurities require
environmental control at various stages of the fuel cycle.
-------
2-30
EXHIBIT 2-14
CHARACTERISTICS OF VARIOUS TYPES OF STOKERS
Stoker Type & Subclass
1. Spreader
- Stationary and
dumping grata
- Travailing grate
- Vibrating grate
2. Overfeed
- Chain grate and
travelling grate
- Vibrating grata
3. Underfeed
- Single or double
retort
- Multiple retort
Typical Maximum
Capacity Range
(pph atean) a/
30,000-150,000
20,000-30,000
Burning Hate
(Btu/hr/ft2) b/ Characteristics
20,000-80,000 420,000
100,000-400,000 750,000
20,000-100,000 400,000
20,000-100,000 600,000
400,000
400,000
Capable of burning a wide
range of coals, beat
ability to follow
fluctuating loads, high
fly ash carry over, low load
smoke.
Characteristics similar
to vibrating-grate stokers
except these stokers experience
difficulty in burning strongly
caking coals
Low maintenance, low fly ash
carry over, capable of
burning wide variety of weakly caking
coals, smokeless operation over
entire range.
Capable of burning caking
coals and a wide range of
coals (including anthracite),
high maintenance, low fly ash carry
over, suitable for continuous-load
operation.
a/ pph - pounds steam/hr; 1 pph • 1000 Btu/hr.
b/ Maximum amount of Btus consumed per hour for each square foot of grate in
the stoker.
Source: Meyers, Robert A. (Ed.), Coal Handbook. Marcel Dekker, Inc., New York,
NY, 1981.
-------
2-31
EXHIBIT 2-15
DIAGRAM OF A SPREADER STOKER
COAL HOPPER
FEEDER
OVERTHROW
ROTOR
Source: Meyers, Robert A. (Ed.)» Coal Handbook. Marcel Dekker, Inc., New
York, NY, 1981.
-------
2-32
EXHIBIT 2-16
TOTAL COAL BOILER CAPACITY BY EPA REGION
Pulverizers
EPA
U.S
Region
1
2
3
4
5
6
7
8
9
10
. Total
Dry Bottom
69.2
60.6
87.6
71.6
70. A
48.6
58.3
60.3
77.5
100.0
69.3
Wet Bottom
11.3
19.4
0.3
5.3
4.9
12.5
3.5
5.4
0.0
0.0
5.3
Cyclone Stoker Other a/ Total
16.7
5.0
2.8
5.2
14.0
0.0
19.2
10.6
0.0
0.0
8.3
0.0
2.7
0.0
0,
0.
0.0
1.0
1.1
0.0
0.0
0.4
0.0
16.7
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
a/ Includes unknown, or other boiler types.
Source: ICF Coal and Utilities Information System Database.
-------
2-33
EXHIBIT 2-17
AVERAGE COAL BOILER SIZE BY TYPE OF BOILER
AND BY EPA REGION
(MW)
Pulverizers
EPA Region
1
2
3
4
5
6
7
8
9
10
U.S. Total
Drv Bottom
210.2
127.8
297.6
249.3
185.0
522.7
162.5
234.2
388.3
610.0
231.8
Wet Bottom
102.7
137.7
136.0
147.4
117.0
489.0
148.3
141.7
N/A
N/A
162.9
Cyclone
228.0
143.5
195.3
342.6
222.6
N/A
243.2
322.8
N/A
N/A
243.2
N/A - Not applicable.
Source: ICF Coal and Utilities Information System Database.
Stoker
N/A
39.0
N/A
14.6
11.2
N/A
12.3
17.9
N/A
N/A
14.0
-------
2-34
These impurities are typically referred to as "ash", whether the reference
is to some of the constituents that compose the coal itself prior to combustion
or the waste products that result from its combustion. Some coal ash is
inherent to the coal seam, while other ash comes from non-coal strata near the
coal seam which are intermixed during mining. The coal consumed by electric
24
utilities is generally over 10 percent ash. At current rates of coal
consumption, about 70 million tons of ash pass through coal-fired power plants
each year.
The ash generated at utility power plants is produced inside the boiler
furnace from the inorganic components as the organic components of the coal
combust. The types of ash produced can vary -- some ash is swept through the
furnace with the hot flue gases to form fly ash, while some settles to the
bottom of the boiler as bottom ash or slag. The amount of each type of ash
produced depends upon the boiler configuration as described in Section 2.3 and
the characteristics of the coal (see Chapter Three for further discussion of ash
types).
Air quality regulations have long restricted the amount of fly ash that may
be released through a power plant's stacks. Primarily through the use of
electrostatic precipitators or bag houses, power plants collect fly ash
particles, leaving the flue gases nearly particulate-free as they are emitted
from the stack. As a result, the fly ash, bottom ash, and slag that is
collected during and after combustion is approximately equal to the amount of
ash in the coal prior to combustion.
-------
2-35
For many power plants constructed since the 1970's, additional
environmental controls also require that a portion of the sulfur oxides be
removed from the flue gases. The dominant technology for removing sulfur
oxides is known as flue gas desulfurization (FGD), in which alkaline agents,
usually in liquid slurry form, are mixed with the flue gases to convert the
sulfur into non-gaseous compounds. The resulting waste product is generally
referred to as FGD sludge and can amount to 25 percent or more of the volume of
f\ f
coal consumed at a given plant. In total, U.S. coal-fired power plants
produce about 85 million tons of ash and FGD sludge per year. By the end of the
century, this volume is expected to approximately double.
Exhibit 2-18 shows the number of coal-fired utility power plants and units
that produce FGD wastes in each EPA region as of 1985. Regions 6, 8, and 9 have
the highest proportion of both plants and units producing FGD wastes. For
example, more than half of the coal-fired units in region 9 produce FGD wastes.
The high proportion of FGD-producing plants in these regions is in part
attributable to the fact that many of the coal-fired plants in these regions are
relatively new and were required to incorporate scrubbers to meet air emission
regulations.
Plants and units producing FGD waste represent a smaller percentage in
other regions, primarily because these regions relied on coal-fired capacity for
a major portion of their generation before units with FGD technology were
installed. For example, the absolute number of both plants and units producing
FGD waste is greatest in Region 4, reflecting this area's reliance on coal for
generating electricity.
-------
2-36
EXHIBIT 2-18
ELECTRIC UTILITY PRODUCTION OF FGD WASTES: 1985
EPA Region
1
2
3
4
5
6
7
8
9
10
Total U.S.
# of Plants
Producing
FGD waste
0
3
5
11
10
8
6
9
3
_0
55
Percent of
Plants Producing
FGD Wastes
0.0
17.6
8.8
12.0
5.8
20.5
9.1
18.8
23.1
0.0
12.0
# of Units
Producing
FGD Wastes
0
3
13
26
16
23
11
25
12
_0
129
Percent of
Units Producing
FGD Wastes
0.0
14.4
Source: Utility Data Institute Power Statistics Database.
-------
2-37
Regions 1 and 10, at the other extreme, have no plants or units producing
FGD wastes. These regions (New England and the Pacific Northwest) are not
highly dependent upon coal and consequently, have relatively few coal-fired
plants.
Numerous other types of wastes are produced during normal operation and
maintenance at coal-fired power plants. These include, among others, boiler
blowdown, coal pile runoff, cooling tower blowdown, demineralizer regenerants
and rinses, metal and boiler cleaning wastes, pyrites, and sump effluents.
These wastes are usually small in volume relative to ash and FGD sludge, but
because they may have higher concentrations of certain constituents that may
cause environmental concern, they also require care in handling and disposal.
All of these wastes are discussed in greater detail in Chapter Three.
-------
-------
2-39
CHAPTER TWO
NOTES
1 Edison Electric Institute, 1985 Statistical Yearbook.
2 Energy Information Administration, Annual Energy Outlook 1985.
DOE/EIA-0383(85), p. 50.
^ A gigwatt-hour (Gwh) is one million kilowatt -hours; a kilowatt-hour is
the amount of electricity generated by 1 kilowatt of electric generating
capacity operating for one hour.
^ Energy Information Administration, Annual Outlook for U.S. Electric
Power . DOE/EIA-0474(86) , 1986.
5 Ibid.
6 Ibid.
7 Ibid.
8 Ibid.
9 Ibid.
10 Ibid.
11 Ibid.
12 Ibid.
13 Ibid.
14
15 Ibid.
The major portion of this discussion is taken from Annual Outlook for
U.S. Electric Power. DOE/EIA, 1986. See this document for further information.
17 Ibid., page 5.
18 Ibid.
19 Ibid.
20 Ibid.
21
Energy Information Administration, Electric Power Annual 1984.
DOE/EIA-0348(84), p. 24.
-------
2-39
22
Energy Information Administration, Electric Power Monthly.
DOE/EIA-0226(85/12), December 1985, p. 21.
23
For more detail, see Meyers, Robert A. (Ed.), Coal Handbook. Marcel
Dekker, Inc., New York, New York, 1981, pp. 378-431.
Energy Information Administration, Cost and Quality of Fuels for
Electric Utility Plants 1984. DOE/EIA-0191(84), July 1985, p. 6.
25
American Coal Ash Association.
26
For example, a coal with 2 percent sulfur would produce approximately
80 pounds sulfur dioxide per ton of coal consumed. A limestone scrubber
capturing 90 percent of the sulfur dioxide, assuming a stoichiometric ratio of
1.4 and a sludge moisture content of 50 percent, would product almost 500
pounds of FGD sludge per ton of coal consumed. See Appendix B for a detailed
discussion of the methodologies used to determine this calculation.
-------
CHAPTER THRKR
WASTES GENERATED FROM COAL-FIRED
ELECTRIC UTILITY POWER PLANTS
As part of EPA's responsibility under Section 8002(n) of RCRA, Congress
directed that the study of wastes from the combustion of fossil fuels should
include an analysis of "the source and volumes of such material generated per
year." In response to this directive, this chapter examines the physical and
chemical characteristics of the types and quantities of wastes that are
generated currently and likely to be generated in the future.
3.1 OVERVIEW OF ELECTRIC UTILITY WASTES
As discussed initially in Chapter Two, the noncombustible material that
remains after coal is burned is called ash. The proportion of noncombustible
material in coal is referred to as the ash content. There are four basic
types of wastes that can be produced directly from coal combustion: fly ash.
bottom ash, boiler slag, and flue gas desulfurization (FGD) sludge. The
smaller ash particles entrained by the flue (exhaust) gas are referred to as
fly ash and are produced in varying degrees by all plants. Larger ash
particles that settle on the bottom of the boiler will form either bottom ash
(if the particles have never completely melted) or boiler slag (if the ash
particles have melted), depending on the furnace design. Another waste
product, called FGD sludge, is generated when some of the sulfur dioxide
(formed when the sulfur present in the coal combines with oxygen during
combustion) is removed from other flue gases. This removal process is
required by the Clean Air Act Amendments of 1979, which revised the New Source
-------
3-2
Performance Standards for any electric utility boiler constructed after
September 1978. These plants are required to remove 90 percent of the sulfur
dioxide, which is usually accomplished with a flue gas desulfurization (FGD,
or scrubber) system. Because they are generated in very large quantities,
these four waste materials -- fly ash, bottom ash, boiler slag, and FGD sludge
-- are referred to by the industry as high-volume wastes. This term will be
used throughout this study to be consistent with the terminology that is
commonly used for these wastes.
Electric utility power plants also generate waste streams that the industry
typically calls low-volume wastes. which are formed during equipment
maintenance and water purification processes. Types of low-volume wastes
generated by coal-fired power plants include boiler blowdown, coal pile
runoff, cooling tower blowdown, demineralizer regenerants and rinses, metal
and boiler cleaning wastes, pyrites, and sump effluents. Because it is common
industry terminology, the term "low-volume wastes" will be used throughout
this report; however, some of these wastes (such as cooling tower blowdown)
can be generated in substantial quantities, although generally in smaller
quantities than high-volume wastes.
The remainder of this chapter describes each type of high-volume and
low-volume waste stream, the various methods of collection used for each, the
volumes produced, and the physical and chemical characteristics that determine
the waste's behavior during disposal and its potential to leach.
-------
3-3
3.2 HIGH-VOLUME WASTES
High-volume coal combustion utility wastes are those waste streams
generated in the boiler furnace -- fly ash, bottom ash, and boiler slag -- and
in the cleaning of coal combustion flue gas. The following sections describe
the volumes and the physical and chemical characteristics of these high-volume
waste streams.
3.2.1 Ash
The noncombustible waste material that remains after coal is burned is
referred to as ash. Some noncombustible materials are characteristic of the
coal itself, originating from the chemical elements in the plants from which
the coal was formed. These materials generally account for no more than two
percent of the ash content of the coal. Other noncombustible materials
extraneous to the coal, such as minerals lodged in the coal seam during or
after its geologic formation and rocks near the coal seam that are carried
away with the coal during mining, are burned during the fuel combustion
process along with the coal itself. These materials account for most of the
ash content.
3.2.1.1 How Ash is Generated
The type of ash produced from a boiler is determined by the type of coal
that is burned and the design of the boiler furnace. As discussed in Chapter
Two, the major types of boilers used by electric utilities are wet-bottom
pulverizers, dry-bottom pulverizers, cyclone-fired boilers, and stokers.
-------
3-4
Pulverizers are the most widely used boilers in the electric utility
industry because they can burn many different types of coal. Due to the very
fine consistency of the coal after it is pulverized, the ash particles are
easily carried out of the boiler along with the flue gases, resulting in a
relatively large proportion of fly ash.
The amount of fly ash that accumulates in a pulverizer depends on whether
it is dry-bottom or wet-bottom. In dry-bottom pulverizers, which constitute
the majority of electric utility boilers, ash particles in the coal generally
do not melt during the combustion process because the ash fusion temperature
(i.e., the melting point) is higher than the operating temperature in the
boiler. In dry-bottom pulverizers, therefore, about 80 percent of the fine
ash remains in the flue gas as fly ash. The remaining ash settles to the
bottom of the boiler (hence the term bottom ash) where it is collected at a
later time. In wet-bottom pulverizers, about 50 percent of the ash exits the
boiler as fly ash, while the other 50 percent remains in the furnace.
However, ash particles that remain in wet-bottom pulverizers become molten;
this boiler slag remains in a molten state until it is drained from the boiler
bottom.
Cyclone-fired boilers burn larger-sized coal particles than do
pulverizers, since partial crushing is the only preparation required prior to
injection into the furnace. The amount of fly ash that is generated in a
cyclone boiler is. less than that generated in a pulverizer because of the
larger-sized coal particles and the design of the cyclone boiler. Because the
air circulation within the boiler furnace is designed to create a cyclone-like
-------
3-5
vortex, the coal particles have a tendency to contact the boiler walls. The
operating temperature is high enough to melt the ash so that it adheres to the
furnace walls as liquid slag. Excess slag continually drains to the bottom of
the furnace, where it is removed for disposal. Only 20 to 30 percent of the
ash formed in a cyclone boiler leaves the boiler as fly ash.
A few older and smaller power plants have stoker-type boilers, in which
coal is burned on or immediately over a grate in the furnace. Stokers are
designed to burn coals that do not contain too many small particles (fines),
which can tend to smother the fire. Because there are fewer small particles,
the amount of fly ash is reduced. For example, in a spreader stoker, the most
common type of stoker boiler, the coal is uniformly fed over the fire in a
manner that enables suspension burning of the finer pieces, while heavier
pieces of coal fall onto the grate for further combustion. The large amount
of coal that is burned on the grate reduces the amount of fly ash; the ash
produced in a spreader stoker is generally about 50 percent fly ash and 50 '
percent bottom ash.
3.2.1.2 Methods of Ash Collection
As the flue gas leaves the boiler, it is passed through a mechanical ash
collector to remove some of the fly ash particles. A mechanical ash collector
operates by exerting centrifugal force on the fly ash particles, throwing them
to the outside wall of the collector where they can be removed. These
collectors are effective mainly for capturing the larger fly ash particles.
To remove the smaller particles, the flue gas must then pass through some
-------
3-6
other type of particulate control device, such as an electrostatic
precipitator, a baghouse, or a wet scrubber.
The electrostatic precipitator (ESP) is the most common device for fine
ash collection. ESPs operate by applying an electrical charge to the fly ash
particles. In the presence of an intense electrical field, the charged
particles are attracted to a grounded collection electrode. The collected
dust is then discharged to a storage hopper by a process called rapping that
dislodges the collected particles. ESPs are most efficient when coal with
high sulfur content is used because the sulfur dioxide in the flue gas helps
retain the electrical charge. When properly designed and maintained, an ESP
is capable of collecting over 99 percent of the ash present in the flue gas.
When coal with lower sulfur content is burned, baghouses (also called
fabric filters) are often more appropriate to use as fly ash collection
devices. If operated efficiently, they also can remove over 99 percent of the
ash from the flue gas. In this system, the flue gas passes through a filter
that traps the ash particles. The ash builds up on the filter, forming a
filter cake. As this process continues, the ash collection efficiency tends
to increase as it becomes more difficult for particles to pass through the
filter material. Periodically, the cake is dislodged from the filters, which
reduces efficiency until buildup occurs again.
Some power plants remove fly ash by the wet scrubbing method, in which
liquids are used to collect the ash. In one method, the ash particles are
removed from the flue gas stream by contacting them with a scrubbing liquid in
a spray tower. This process forms an ash slurry, which is then discharged.
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3-7
Alternatively, fly ash particles may be dislodged from the walls of the
scrubber by a liquid flushing of the scrubber. Because the operation of a
scrubber is very plant-specific, the collection efficiency of wet scrubbers
varies, though wet scrubbers are generally not as efficient as ESPs and
baghouses. The advantage of wet scrubbers, however, is that they can also be
used simultaneously to collect sulfur oxides from the flue gas system.
Ash particles that do not escape as fly ash become bottom ash or boiler
slag. In dry-bottom pulverizers and stokers, the temperatures are low enough
to allow the molten ash to cool and reform into dry, solid ash particles, or
bottom ash. In smaller boilers of this type, the ash falls onto a grate,
which then is opened, allowing the ash to drop into a flat-bottom hopper. The
large quantities of bottom ash produced in larger boilers often require
hoppers with sloped sides for self-feeding. Some hoppers may contain water to
quench the ash and to facilitate disposal.
In cyclone-fired boilers and wet-bottom pulverizers, the liquified ash
particles that fall to the bottom of the boiler during combustion remain in a
molten state and coalesce into large masses (called slag), which then drop
onto the boiler floor. The slag is tapped into a water-filled hopper, or slag
tank, which is periodically emptied and the slag disposed. Slag tanks for
cyclone-fired boilers are similar to those used for pulverizers but have a
higher relative capacity because a greater percentage of the ash in cyclones
becomes boiler slag.
-------
3-8
3.2.1.3 Quantities of Ash Generated
Nearly all of the noncombustible material in coal ends up as fly ash,
bottom ash, or boiler slag. As mentioned earlier, the coal industry and the
electric utility industry refer to this material as a coal's ash content. As
a result, the volume of ash generated is directly related to the amount of
coal consumed and the ash content of the coal. The ash content of coal will
vary according to several factors, including coal-producing region, coal rank
(i.e., bituminous, subbituminous, anthracite, or lignite), mine, seam, and
production method. Although the proportion of ash in coal may range from 3 to
30 percent, the industry-wide average for electric utility power plants is
10.1 percent.^ Exhibit 3-1 shows the average ash content of coal that was
delivered to coal-fired power plants in 1985 for some of the major
coal-producing regions.
In 1984, electric utilities generated about 69 million tons of coal ash.
Ash generation is expected to increase considerably, to about 120 million tons
in the year 2000, an increase of about 72 percent over 1984 levels. This
increase can primarily be attributed to the increase in the demand for coal by
electric utilities. While there is some uncertainty over the amount of coal
that will be consumed by electric utility power plants, coal-fired electricity
generation is likely to increase significantly. For example, one estimate
indicates that by the year 2000 electric utility power plants will burn over
one billion tons of coal to meet 61 percent of total electricity demand,-* an
increase of 70 percent over the 664 million tons consumed in 1984. Exhibit
3-2 shows historical and forecasted future ash generation by coal-fired
electric power plants.
-------
3-9
EXHIBIT 3-1
REPRESENTATIVE ASH CONTENTS BY PRODUCING
REGION AND COAL RANK: 1985
Coal Rank and Region Percent Ash
Anthracite
Northeastern Pennsylvania 29.4
Bituminous
Western Pennsylvania 10.9
Northern West Virginia 10.4
Ohio 11.3
Eastern Kentucky 9.9
Alabama 12.2
Illinois 9.7
Colorado 6.2
Utah 9.4
Arizona 8.9
Subbituminous
Wyoming 5.9
New Mexico 18.8
Lignite
Texas
North Dakota
U.S. Average 10.1
Source: Energy Information Administration, Cost and Quality of Fuels for
Electric Utility Plants 1985. DOE/EIA-0191(85), July 1986.
-------
3-10
EXHIBIT 3-2
VOLUME OF ASH GENERATED BY COAL-FIRED
ELECTRIC UTILITY POWER PLANTS
1975 - 2000
120
Ash Volume
Boiler Slag
Bottom Ash
Fly Ash
1975
1980
1985
1990
1995
2000
Estimated
Year
Sources: 1975-1984: American Coal Ash Association.
1985-2000: ICF Incorporated. See Appendix B for in-depth
discussion of the methodologies used to develop these estimates,
-------
3-11
The average ash content of coal burned by electric utilities has declined
from about 14 percent to slightly more than 10 percent over the past decade
(see Exhibit 3-3). To meet particulate emission standards and to lower
certain operating and maintenance costs, more electric utilities are now
choosing to burn coal with lower ash contents. Although some coals are
naturally low in ash, producers and/or utilities can also reduce ash content
by cleaning the coal.^ In some cases, cleaning can reduce ash content by as
much as 50 to 70 percent. At present, utilities clean about 35 percent of all
the coal they consume; most of the coal that is cleaned comes from eastern and
midwestern underground bituminous coal-mining operations. Another reason for
the increased use of coal with lower average ash content is the growth in
Western coal production, particularly in the Powder River Basin area of
Montana and Wyoming. These coals are naturally low in ash content, and little
ash is extracted during the mining process.
i
The quantity of fly ash and bottom ash produced is likely to increase
faster over time than the quantity of boiler slag because most new coal-fired
plants will employ dry-bottom pulverizer boilers, which generate fly ash and
bottom ash rather than boiler slag. Because dry-bottom pulverizers are
capable of burning coal with a wide range of ash fusion temperatures, they
are able to burn a greater variety of coals compared with cyclone boilers and
wet-bottom pulverizers. Another advantage of dry-bottom pulverizers is that
they produce less nitrogen oxide emissions than do other boiler types, which
enables electric utilities to meet requirements for nitrogen oxide emissions
control more easily.
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3-12
EXHIBIT 3-3
AVERAGE ASH CONTENT OF COAL BURNED
BY ELECTRIC UTILITY POWER PLANTS IN THE U.S.
1975 - 2000
Ash Content
(Percent)
1975
1980
1985
1990
1995
2000
Estimated
Year
Source: 1975-1984:
1985-2000:
Energy Information Administration, Cost and Quality of Fuels for
Electric Utility Plants.
ICF Incorporated. See Appendix B for in-depth discussion of the
methodologies used to develop these estimates.
-------
3-13
3.2.1.4 Physical Characteristics of Ash
The physical characteristics of coal combustion ash of interest are
particle size and distribution, compaction behavior, permeability, and shear
strength. Exhibit 3-4 provides representative ranges of values for these
characteristics of fly ash, bottom ash, and boiler slag.
The greater the assortment of particle sizes in the material, the more it
can be compacted to achieve greater density and shear strength and lower
permeability. Generally, fly ash is similar in size to silt. Most fly ash
particles are between 5 and 100 microns in diameter; within a single sample,
the largest particles may be 200 times larger than the smallest particles."
The size of bottom ash and boiler slag particles can range from that of fine
sand to fine gravel, or about 0.1 to 10 millimeters.
Compaction behavior refers to the amount of settling that takes place
after disposal and the rate at which such settling occurs. Compressibility,
density, and moisture content are factors affecting compaction behavior.
When compacted and dry, most fly ash and bottom ash behave very similarly to
cohesive soil.
Permeability reflects the rate at which water will seep through the waste
material in a given period of time and provides a good first estimate of the
rate and quantity of leachate migration. A number of factors can influence
the degree of permeability, such as the size and shape of the waste particles,
the degree of compaction, and the viscosity of the water. Properly compacted
fly ash often has low permeability, similar to that of clay, while the
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3-14
EXHIBIT 3-4
REPRESENTATIVE RANGES OF VAUDES
FOR THE PHYSICAL CHARACTERISTICS OF
FLY ASH, BOTTOM ASH, AND BOILER SLAG
Bottom Ash/
Fly Ash Boiler Slag
Particle Size (mm) 0.001-0.1 0.1-10
Compaction Behavior:
Compressibility (%) 1.8 1.4
Dry Density (lbs/ft3) 80-90 80-90
Permeability (cm/sec) 10~6-10*4 lO^-lO"1
Shear Strength
Cohesion (psi) 0-170 0
Angle of Internal Friction (°) 25-45 25-45
Sources: For compressibility values, Arthur D. Little, Full-Scale Field
Evaluation of Waste Disposal from Coal-Fired Electric Generating
Plants. Volume I, Prepared for U.S. Environmental Protection
Agency, June 1985, p. 3-29. For other values, Tetra Tech Inc.,
Physical-Chemical Characteristics of Utility Solid Wastes.
Prepared for Electric Power Research Institute, EPRI EA-3236,
September 1983, p. 3-3 - 3-8.
-------
3-15
permeability of bottom ash is usually slightly higher. Boiler slag is higher
still, having a permeability comparable to that of fine gravel.
Shear strength is an important determinant of the shape and structural
stability of wastes disposed in landfills; a strong material (i.e., one with
high shear strength) can form steep slopes and support heavy loads from above.
Two indicators of shear strength are cohesion, a measure of the attraction
between particles due to electrostatic forces, and the angle of internal
friction, an indicator of the friction between particles. Dry, nonalkaline
ash has no cohesion. Dry ash that is alkaline demonstrates some cohesion and,
when compacted, increases in strength over time. The angle of internal
friction associated with ash varies with the degree of compaction, although it
is similar to that for clean, graded sand.
3.2.1.5 Chemical Characteristics of Ash
The chemical composition of ash is a function of the type of coal that is
burned, the extent to which the coal is prepared before it is burned, and the
operating conditions of the boiler. These factors are very plant- and
coal-specific.
In general, over 95 percent of ash is made up of silicon, aluminum, iron,
and calcium in their oxide forms. Magnesium, potassium, sodium, and titanium
are also present to a lesser degree. Exhibit 3-5 shows the concentration of
these major elements typically found in fly ash, bottom ash, and boiler slag.
Ash also contains many other elements in much smaller quantities. The
types and proportions of these trace elements are highly variable and not
-------
3-16
EXHIBIT 3-5
LOW AND HIGH CONCENTRATIONS OF MAJOR CHEMICAL
CONSTITUENTS FOUND IN ASH GENERATED
BY COAL-FIRED POWER PLANTS
(parts per ni.lli.on)
Flv Ash Bottom
Aluminum
Calcium
Iron
Magnesium
Potassium
Silicon
Sodium
Titanium
Source :
Low
11,500
5,400
7,800
4,900
1,534
196,000
1,180
400
Utility Solid Waste
on the Disposal and
High
144,000
177,100
289,000
60,800
34,700
271,000
20,300
15,900
Activities Group,
Utilization of FOJ
Bv- Products. Appendix A, Submitted to
Low
88,000
8,400
27,000
4,500
7,300
180,000
1,800
3,300
Report
Ash/Boiler Slag
High
135,000
50,600
203,000
32,500
15,800
273,000
13,100
7,210
and Technical Studies
ssil-Fuel Combustion
the U.S
. Environmental
Protection Agency, October 26, 1982, p. 31.
-------
3-17
readily categorized. Concentrations for various trace elements in coal ash
are shown in Exhibit 3-6, which indicates the potential range of values and
median concentration for such trace elements for coals from different regions
of the U.S. A summary of how the concentration of elements in ash varies
according to coal source is shown in Exhibit 3-7. For example, Eastern and
Midwestern coal ashes usually contain greater amounts of arsenic, selenium,
chromium, and vanadium than do Western coal ashes, while Western coals have
larger proportions of barium and strontium. Coal mining and cleaning
techniques can reduce the amount of trace elements that are ultimately found
in the ash after combustion. For example, in some cases, coal cleaning can
remove more than half of the sulfur, arsenic, lead, manganese, mercury, and
selenium that is contained in the coal prior to combustion.
The proportions of elements contained in fly ash, bottom ash, and boiler
slag can vary. Exhibit 3-8 provides ranges and median values for element
concentrations in different types of ash -- bottom ash and/or boiler slag, and
fly ash. The concentrations of elements formed in fly ash are shown for two
types -- the larger particles removed from the flue gas by mechanical
collection and the smaller particles removed with an electrostatic
precipitator or a baghouse (see Section 3.2.1.2 for more detail on methods of
ash collection). For example, much higher quantities of arsenic, copper, and
selenium are found in fly ash than are found in bottom ash or boiler slag.
The distribution of elements among the different types of ash is largely
determined by the firing temperature of the boiler relative to the coal's ash
fusion temperature, which in turn affects the proportions of volatile elements
that end up in fly ash and bottom ash. Some elements, such as sulfur,
mercury, and chlorine, are almost completely volatilized and leave the boiler
-------
EXHIBIT 3-6
ELEMEHT CUNUJI1KATICHS IH ASH FBCM TUKKK GEOGBAFHIC SOUHCES
(•Ullgraaa per kilosran)*
Eastern Coal
Midwestern Coal
Western Coal
Element
Arsenic
Barium
Boron
Cadmium
Chromium
Cobalt
Copper
Fluorine
Lead
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Strontium
Thallium
Vanadium
Zinc
Range
2.0-279
52-2200
10.0-580
0.10-8.24
34-437
6.22-79
3.7-349
0.40-89
1.3-222
79-430
0.02-4.2
0.84-51
6.6-258
0.36-19.0
0.25-8.0
59-2901
7.0-28.0
110-551
16-1420
Median
75
892
121
1.59
165
40.6
136
8.8
18.0
190
0.192
15.0
78
8.05
0.695
801
25.0
269
163
Range
0.50-179
300-4300
10-1300
0.50-18
70-395
19-70
20-330
3.2-300
3.0-252
194-700
0.005-0.30
7.0-70
26-253
0.08-19
0.10-1.20
30-2240
2.0-42
100-570
20-2300
Median
54
905
870
2.6
172
35.7
125
75
149
410
0.044
43
121
7.0
0.39
423
16.0
270
600
Range
1.3-129
300-5789
41.9-1040
0.10-14.3
3.4-265
4.9-69
29-340
0.40-320
0.40-250
56.7-769
0.005-2.5
1.4-100
1.8-229
0.13-19.0
0.040-6.0
931-3855
0.10-3.50
11.9-340
4.0-854
Median
18
2700
311
1.01
45
13.0
74.8
50.1
26.1
194
0.067
12.0
38.0
LO
*•* M
0.26 °°
2300
1.06
94
71
* Values shown are for all types of ash combined.
Source: Tetra Tech Inc., Physical-Chemical Charaeteristica of Utility Solid Hastea. EPRI EA-3236, September 1983.
-------
3-19
EXHIBIT 3-7
EFFECT OF GEOGRAPHIC COAL SOURCE ON ASH ELEMENT CONCENTRATION
Element
Arsenic
Barium
Cadmium
Chromium
Mercury
Lead
Selenium
Strontium
Vanadium
Zinc
Concentration Pattern
low in western coal ash; eastern and midwestern coal
ashes indistinguishable
highest in western coal ash
most concentrated in midwestern coal ash
low in western coal ash; eastern and midwestern coal
ashes indistinguishable
highest in eastern coal ash; all distributions highly
skewed toward high concentrations
highest in midwestern coal ash
similar in eastern and midwestern coal ash; lower in
western coal ash
greater in eastern than in midwestern coal ash;
greater still in western coal ash
similar in eastern and midwestern coal ash; lower in
western coal ash
greater in eastern than in western coal ash; greater
still in midwestern coal ash
Source: Tetra Tech, Inc., Physical-Chemical Characteristics of Utility Solid
Wastes. EPRI EA-3236, September 1983, p. 3-30.
-------
EXHIBIT 3-8
ELEMENT LUTCEHIKATIOBS n THKEE TTPES OF ASH
(milligrams per kilogram)
Ply Aah
Bottom Ash/Boiler Slag
Element
Silver
Arsenic
Boron
Barium
Cadmium
Cobalt
Chromium
Copper
Fluorine
Mercury
Manganese
Lead
Selenium
Strontium
Vanadium
Zinc
Range
0.1-.51
.50-168
Al. 9-513
300-5789
0.1-4.7
7.1-60.4
3.4-350
3.7-250
2.5-104
0.005-4.2
56.7-769
0.4-90.6
.08-14
170-1800
12.0-377
4.0-798
Median
0.20
4.45
161
1600
0.86
24
120
68.1
50.0
0.023
297
7.1
0.601
800
141
99.6
Mechanical Hopper Ash
Range
0.08-4.0
3.3-160
205-714
52-1152
0.40-14.3
6.22-76.9
83.3-305
42.0-326
2.50-83.3
0.008-3.00
123-430
5.2-101
0.13-11.8
396-2430
100-377
56.7-215
Median
0.70
25.2
258
872
4.27
48.3
172
130
41.8
0.073
191
13.0
5.52
931
251
155
Fine Fly Ash
Range
0.04-8.0
2.3-279
10.0-1300
110-5400
0.10-18.0
4.90-79.0
3.6-437
33.0-349
0.40-320
0.005-2.50
24.5-750
3.10-252
0.60-19.0
30.0-3855
11.9-570
14.0-2300
Median
0.501
56.7
371
991
1.60
35.9
136
116
29.0
0.10
250
66.5
9.97
775
248
210
ro
o
Source: Tetra Tech. Inc.. Physical-Chemical Characteristics of Utility Solid Hastes. EHII EA-3236, September 1983. p. 3-24.
-------
3-21
in the flue gas rather than remaining in the bottom ash or boiler slag. Some
of these more volatile elements may condense on the surface of the fly ash
particles as the flue gas cools.
3.2.2 PGD Sludge
Another waste stream often generated in large volumes by coal-fired utility
power plants is FGD sludge, which is created when utilities remove sulfur
oxides from the flue gases. Emissions of sulfur oxides in the flue gases are
due to the oxidation of sulfur during coal combustion. State and Federal
regulations require power plants to control the amount of sulfur oxides
released through the stack. To meet the applicable requirements most power
plants use coals whose inherent sulfur content is low. If the sulfur content
is so low that additional sulfur dioxide removal is not needed, then FGD sludge
is not produced.
Present requirements for all new coal-fired plants, however, not only limit
the amount of sulfur oxides that can be emitted, but also mandate a percentage
12
reduction in the amount of sulfur dioxide emissions. This requirement will
substantially increase the number of sulfur dioxide control systems in use.
The primary method of sulfur dioxide control currently available is a flue gas
desulfurization (FGD) system through which the flue gases pass before being
emitted from the stack. The wastes produced by this system are called FGD
(scrubber) sludge. Other methods of control include newer technologies such as
fluidized bed combustion (FBC) and limestone injection multistage burners
(LIMB). The technical and economic feasibility of the latter two
technologies are currently under evaluation by private industry and the U.S.
-------
3-22
Department of Energy. If these technologies do become more widely available,
they also will produce substantial volumes of wastes.
3.2.2.1 Methods of PGD Sludge Collection
There are two major types of FGD (scrubber) systems. Non-recovery systems
produce a waste material for disposal. Recovery systems produce recyclable
by-products. Exhibit 3-9 illustrates the different types of FGD systems
currently in use. Non-recovery systems, which account for 95 percent of the
scrubber systems now in use by electric utilities, are further classified as
wet or dry systems. In wet non-recovery scrubber systems, the flue gas
contacts an aqueous solution of absorbents, thereby producing waste in a slurry
form. The wastes generated by dry non-recovery systems contain no liquids.
Direct lime and limestone FGD systems are the most common wet non-recovery
processes. With these systems, flue gases pass through a fly ash collection
device and into a contact chamber where they react with a solution of lime or
crushed limestone in the form of a slurry. The slurry circulates between the
contact chamber and a separate reaction tank, where the reagents are added.
From the reaction tank, the slurry is fed to a thickening and dewatering device
to be prepared for disposal. After dewatering, the resulting liquid is
recycled back to the reaction tank and the sludge solids are removed for
disposal. Under certain conditions, direct lime and limestone scrubbers have
14
been able to remove over 95 percent of the sulfur dioxide in the flue gas.
-------
3-23
EXHIBIT 3-9
MAJOR TYPES OF FLOE GAS DESTJLFURIZATION SYSTEMS
Non-Recovery
Wet
Direct Lime
Drv
Spray Drying
Direct Limestone Dry Sorbent
Injection*
Alkaline Fly Ash
Dual-Alkali
Recovery
Wet
Wellman-Lord
Magnesium Oxide
Drv
Alumina/Copper*
Sorbent
Activated Carbon*
Sorbent
*Systems are currently in development and testing phases, and are not as yet being
used commercially.
Source: Tetra Tech Inc., Physical-Chemical Characteristics of Utility Solid Wastes.
Prepared for Electric Power Research Institute, EPRI EA-3236, September
1983, pp. 4-1 - 4-4.
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3-24
A variation on the direct lime and limestone systems is the alkaline fly
ash scrubber. Several western power plants that burn coal containing
high-alkaline ash use these systems, which can improve sulfur dioxide
removal. Rather than being collected by a separate upstream device (such as an
ESP or baghouse), fly ash particles remain in the gas stream as it passes
through the scrubber. In the scrubber, the alkaline fly ash, augmented with an
alkaline lime/limestone slurry, acts to remove sulfur oxides. Alkaline fly ash
scrubbers are not as efficient as direct lime and limestone systems, removing
on average only about 40 percent of the sulfur dioxide.
Another wet non-recovery system is the dual-alkali process. These
scrubbers operate in much the same manner as the direct lime and limestone
scrubbers. However, dual-alkali systems use a solution of sodium salts as the '
primary reagent to which lime is added for additional absorption. The soluble
sodium salts are then recycled to the scrubber system and the insoluble portion
of the slurry is left to settle so that it can be collected and disposed. Like
direct lime and limestone systems, dual-alkali scrubbers remove up to 95
percent of the sulfur dioxide.
Exhibit 3-10 presents a diagram of the operations of a wet FGD system. The
flows shown for the flue gas, absorbent, slurry, and sludge are essentially the
same for direct lime, direct limestone, alkaline fly ash, and dual-alkali
systems.
At present, the two most popular methods of dry scrubbing under
investigation are spray-drying and dry sorbent injection, although only the
spray-drying process is now in commercial use at electric utility power plants.
-------
EXHIBIT 3-10
FLOW DIAGRAM OF WET FLUE GAS DESULFURIZATION SYSTEM
\Separale
ly Ash
Absorber
System
Spent
Slurry
Slurried
Primary
Absorbent
^ \flue Gas
r\Reheatef.
Cleaned Gas
to Stack
Recycled
Slurry
Reaction
Tank
Slurry
Bleed
Liquid
Thickening/
Dewatering
Sludge
_• -«»• __• ^
Disposal
Recycle
Key
o
RVV1
L
J
Inputs
Flue Gas Pathway
Liquid Pathway
Sludge Pathway
Optional Processes
Major Processes
10
Ln
Source: Tetra Tech Inc., Physical-Chemical Characteristics of Utility Solid
Wastes. Prepared for Electric Power Research Institute, September
1983, p. 4-3.
-------
3-26
A flow diagram of a spray-drying system is presented in Exhibit 3-11. With
this system, a fine spray of an alkaline solution is injected into the flue gas
as it passes through a contact chamber, where the reaction with the sulfur
oxides occurs. The heat of the flue gas evaporates the water from the
absorbent solution, leaving a dry powder. This powder is then collected
downstream of the contact chamber by a particulate collector, usually a
baghouse. Spray-drying typically removes about 70 percent of the sulfur
dioxide from the flue gas. Because of the relatively low percentage
reduction in sulfur dioxide achieved by spray-drying scrubbers compared with
other scrubber technologies, this dry-scrubbing method is most commonly used
for furnaces that burn lower sulfur coals.
Dry sorbent injection, illustrated schematically in Exhibit 3-12, is not
yet used commercially by electric utilities, although one utility is designing
a generating unit that will use this type of scrubber and which is due to begin
18
operation by 1990. This system involves the injection of a powdered sorbent,
either nacholite or trona, into the flue gas upstream of a baghouse. Sulfur
dioxide reacts with the reagent in the flue gas and on the surface of the
filter in the baghouse. The dry wastes, which form a filter cake, are then
removed during normal filter cleaning.
Dry injection offers several advantages over traditional wet scrubbing and
spray-drying techniques: the required equipment is smaller and less expensive,
no water is needed, flue gas reheating is not necessary, and sulfur dioxide and
fly ash are removed simultaneously. Potential drawbacks of this process are
the limited geographic availability of the sorbents and problems associated
with waste disposal. For example, the waste tends to be very water soluble,
-------
EXHIBIT 3-11
FLOW DIAGRAM OF SPRAY-DRYING FLUE GAS DESULFURIZATION SYSTEM
Spray
Absorber
Slurried
Absorbent
(Soda ash.
trona.lime)
Mixed
Slurry
+
Dust
Collector
Slurry
Tank
Partial
Solids Recycle
Cleaned Gas
to Slack
Dry Waste Removal
lor Processing or
Disposal
Key
ro
o
Inputs
Gas Pathway
Slurry or Wet
Solids Pathway
Dry Waste Output
Optional Processes
Major Processes
Source: Tetra Tech Inc., Physical-Chemical Characteristics of Utility Solid
Wastes. Prepared for Electric Power Research Institute, September
1983, p. 4-5.
-------
EXHIBIT 3-12
FLOW DIAGRAM OF DRY INJECTION FLUE GAS DESULFURIZATION SYSTEM
Dry Absorbent
(limestone, lime,
soda ash. nahoolile,
trona) added by
process AorB
Dry Sorbent
Injection
Dust
Collector
B
Filter
Precoat on
Baghouse
Cleaned Gas
to Stack
Dry Waste Removal
for Processing or
Disposal
(-0
I
ro
CO
Key
o
I
Inputs
Gas Pathway
Solids Pathway
Dry Waste Output
Optional Processes
Major Processes
Source: Tetra Tech Inc., Physical-Chemical Characteristics of Utility Solid
Wastes. Prepared for Electric Power Research Institute, September
1983, p. 4-6.
-------
3-29
and could potentially affect ground-water quality. Also, dry injection is most
effective when used for low-sulfur coals, achieving only 70 to 80 percent
sulfur dioxide removal in most cases, compared with up to 95 percent removal by
19
wet scrubbing systems.
Recovery systems are designed to produce a salable by-product such as
sulfur, sulfuric acid, or liquid sulfur dioxide; however, small amounts of
waste are still produced. A prescrubber is usually required upstream of the
main scrubber to filter out such contaminants as fly ash and chlorides.
Secondary waste streams formed by the oxidation of the absorbent are sometimes
present and, along with the prescrubber by-products, are the materials that
need to be disposed. Two recovery FGD systems presently used commercially, the
Wellman-Lord and Magnesium Oxide processes, are both based on wet scrubbing.
Diagrams of these systems are shown in Exhibit 3-13. Other recovery systems,
both wet and dry, have been developed, but are still in the testing phase.
i
3.2.2.2 Quantities of PGD Sludge Generated
There has been a large increase in the quantity of FGD sludge generated
over the past decade, as shown in Exhibit 3-14. This increase is due to the
i
more widespread use of scrubbers brought about by tightened state limits on
sulfur dioxide emissions, the Federal New Source Performance Standards (NSPS)
of the Clean Air Act of 1971, and the revisions to the NSPS in 1979. This
trend will continue as new power plants are equipped with scrubbers as required
under the NSPS. By the year 2000, scrubber capacity is likely to be several
times greater than at present.
-------
EXHIBIT 3-13
FLOW DIAGRAMS OF RECOVERY FLUE GAS DESULFURIZATION SYSTEMS
WELLMAN-LORD PROCESS
GAS —
FIOM BOILEI
P
WET
SCRUMER
1
ARTKULATI
DE
mrn^m
ES
SULFUR
nut t
IZED
Kit
S
\
»
AISO
it.
^r
V
"1
SI
N
J&
/
HER
A
y
C
JLUII
IN N
-«—
J~
ONEN
•NSO]
SOLUTION OF
RECYCLE ^^-X
COLO / >
SLURRY/ CH|UH
1 . CRYSTALLIZE
<9f ( ,
jcp vx
itFRICERANTT 1
H»2S04 SLURRY
RICKED
•
N.HSO
;
i
H
J joi
SCPAR
1_
i
PUI
jANDN.^,
S0|.r—
WATER 1
S^^
j| EVAPORAT
RECYCLE
HOT)
"T ^J^-
l/?
-------
EXHIBIT 3-13 (Continued)
FLOW DIAGRAMS OF RECOVERY FLUE GAS DESULFURIZATION SYSTEMS
MAGNESIUM OXIDE PROCESS
FLUE CAS CO
ELECTROSTAIC
PRECIPITATOR
CAS —
FROM ROM FR
VW
DRY ASH | 1 _J
-
I
MAKE UP^
WATER ^
WETASH 1 A« 1 11
SEPARATOR ~~
M«0 SLURRY
FROM ACID PLANT
LNUOR
Source: Federal Power Commission,
Applications in the Unitec
MTAWWC SO | AND SOME FLY ASH
I
S H
SCRUIIER-
AISOR1ER
STACE 1
' FLY ASH
•ocu ^ ,ilwyu )
\/ \ /
jf FLUICASCONTAIHIMCSO,
WATER. ASH
SCRUIIER-
^^^^^^^^^^, STACE II * riuf crifff
RECYCLE 1 10 , REMOVAL J
SLURRY >L /
s\ /
RLEEO STREAM Mrf0< MfSO, M,0
• * im int
/ TO ACID PLANT
The Status of Flue Gas Desulfurization
i States: A Technological Assessment,
CO
I
July 1977, pp. VII-27, VII-30.
-------
Gigawatts
(10 3 Megawatts)
3-32
EXHIBIT 3-14
FGD CAPACITY AND FGD SLUDGE GENERATION
1970-2000
200
FGD Capacity
1975 1980 1985 1990 1995 2000
Estimated
FGD Sludge Generation
Millions
of Tons
1970 1975 1980 1985 1990 1995 2000
Estimated
Source: 1970-1984: Energy Information Administration, Cost and Quality
of Fuels for Electric Utility Plants, and Arthur D. Little, Inc.,
Full Scale Field Evaluation of Waste Disposal from Coal-Fired
Electric Generating Plants. Vol. 1, June 1985.
1985-2000: ICF Incorporated. See Appendix B for in-depth
discussion of the methodologies used to develop
these estimates.
-------
3-33
The dramatic increase in scrubber capacity has a direct effect on the
amount of scrubber sludge produced. In 1984, about 16 million tons of scrubber
sludge were generated. By 2000, the annual amount of sludge produced is
estimated to be about 50 million tons, over three times the sludge generated at
«. 20
present.
All FGD sludge is comprised of spent reagent, which is made up of the
chemicals that result from the reaction of the absorbent with the sulfur oxides
in the flue gas, plus any unreacted portion of the absorbent. The sludge may
also contain water and fly ash. Several factors determine how much spent
reagent, water, and ash are present in the FGD sludge. These factors include
the type of scrubber system used, the characteristics of the coal, and the
sulfur dioxide emission limit that the power plant is required to meet by state
or Federal law.
The type of FGD system is an important determinant of the amount of spent
reagent, amount of water, and amount of ash present in the sludge. Reagents
used in different systems vary as to their absorbent utilization, or
"stoichiometry," which is the percentage of the reagent that reacts with the
sulfur oxides. A lower percentage implies more reagent is needed to remove a
given percentage of sulfur dioxide. Direct limestone systems have an average
absorbent utilization of 80 percent, while the direct lime and dual-alkali
processes both achieve higher utilization of 90 and 95 percent, respectively.
This results in the generation of about six percent more sludge by direct
21
limestone scrubbers compared to direct lime and dual-alkali processes.
-------
3-34
Wet systems, both non-recovery and recovery, employ aqueous solutions to
remove the sulfur oxides from the flue gas. Dry FGD systems use no water for
sulfur oxide removal, although dry FGD wastes may be mixed with water prior to
disposal, which increases the volume of sludge. Because of their dependency on
water, wet FGD systems generally produce larger volumes of wastes than do dry
systems.
Wet FGD systems can also be used as fly ash removal devices. The amount of
ash in the sludge depends on how much fly ash is generated by the boiler and
whether any other particulate control device is upstream of the scrubber. In
particular, alkaline fly ash scrubbers rely on the entrapment of ash to act as
their primary absorbent, and therefore their sludge contains large amounts of
ash. The collection of fly ash and wastes in a spray-drying system occurs
simultaneously by a baghouse; therefore, the wastes from these systems also
contain large proportions of ash. Recovery FGD systems often require
prescrubbers to remove fly ash. Although recovery systems produce only about
half the wastes of non-recovery systems, these wastes are predominantly made up
of ash.
Specific characteristics of the coal can have a large effect on the
quantity of sludge generated. For example, the higher the sulfur content, the
more reagent that must be used to achieve a certain level of sulfur dioxide
removal and, consequently, the more spent reagent in the sludge. The ash
content of the coal affects the amount of ash caught up in the sludge. Just as
using low-sulfur coal will reduce the amount of spent reagent, reducing the ash
content prior to combustion will greatly reduce the amount of fly ash that is
absorbed by wet scrubbers and thus the amount of sludge that must be disposed.
-------
3-35
The amount by which a power plant must reduce sulfur dioxide emissions also
affects the volume of sludge produced. To achieve a higher reduction,
the amount of reagent used in the scrubber needs to be increased, which will,
in turn, produce greater quantities of sludge.
3.2.2.3 Physical Characteristics of FGD Sludge
In general, the same physical properties important in determining the
disposal behavior of ash are also important determinants of the disposal
characteristics of FGD sludge. These physical characteristics -- particle
size, compaction behavior, permeability, and shear strength -- vary
considerably depending on the type of scrubber system and what (if any)
preparation is done prior to disposal. Exhibit 3-15 presents representative
ranges of values for these characteristics of FGD sludge.
j
Depending on the type of FGD system used, the particle size distribution of
FGD sludge can vary substantially. For example, sludge from wet scrubbers
tends to have a narrow range of particle sizes. The particles produced by
dual-alkali systems are finer than those produced by direct lime or limestone
scrubbers, while dry scrubbers generally produce sludge containing larger
particles.
The density of FGD sludge depends directly on the method of handling. Wet
sludge mixed with ash will have a higher density than untreated sludge, while
22
chemical fixation increases the density even more. The density of the
particles in dry sludge varies widely.
-------
3-36
EXHIBIT 3-15
REPRESENTATIVE RANGES OF VALUES FOR THE
PHYSICAL CHARACTERISTICS OF FGD SLUDGE
Wet Dry
Particle Size (mm) .001-.05 .002-.074
Density (g/cm3) 0.9-1.7 Variable
Optimum Moisture Content (%) 16-43 0
Permeability (cm/sec) 10"6-10"4 10~7-10"6
Unconfined Compressive Strength 0-1600 41-2250
(psi)
Source: Tetra Tech Inc., Physical-Chemical Characteristics of Utility
Solid Wastes, prepared for Electric Power Research Institute,
EPRI EA-3236, September 1983, pp. 4-8 - 4-15.
-------
3-37
The solids content of scrubber sludge is a function of many things,
including whether the sludge is treated prior to disposal, the size of the
particles in the sludge, the sulfur content of the coal, the amount of ash
present in the sludge, and the desulfurization process used. The percentage of
solids in untreated sludges usually ranges from 20 to 40 percent, although it
23
can be as high as 60 percent. Depending on the method of treatment used
before disposal (if any), the percentage of solids could be much higher. In
fact, some chemical fixation processes are designed to transform the sludge
into a cement-like product.
The permeabilities of untreated FGD sludges from wet scrubber systems
generally are very similar. Mixing the sludge with fly ash does not
necessarily change the degree of permeability, although if fly ash acts as a
fixative when added to the sludge, the mixed waste product will have a reduced
permeability. Chemical fixation also can decrease permeability. Sludge from
dry scrubber systems has low permeability relative to sludge from wet systems.
The shear strength of FGD sludge is referred to as "unconfined compressive
strength," which reflects the load-bearing capacity of the sludge. The
unconfined compressive strength of sludge is sensitive to the moisture content
and age of the sludge. Untreated wet sludge has no compressive strength and is
similar to toothpaste in this respect. Mixing with ash or lime increases
compressive strength, as does chemical fixation. Also, as the treated sludge
ages, its compressive strength becomes greater.
-------
3-38
3.2.2.4 Chemical Characteristics of FGD Sludge
The major constituents found in wet FGD sludge are determined by the
absorbent reagent used, the quantity of fly ash present, the sulfur content of
the coal, and whether or not forced oxidation is used.
Most wet FGD systems operate by causing the sulfur dioxide in the flue gas
to react with an absorbent reagent, such as lime or limestone, to form a
calcium compound, such as calcium sulfite (CaS03), calcium sulfate or gypsum
(CaS04), or calcium sulfite-sulfate (CaS03'CaS04), which can then be removed
from the system in the sludge. The ratio of calcium sulfate to calcium sulfite
is generally greater in sludge generated by direct limestone scrubber systems
than in that produced by direct lime systems.
Dual-alkali scrubber systems differ slightly in that they use absorbent
solutions containing sodium hydroxide (NaOH) or sodium sulfite (Na2S03) as well
as lime; sludges from these processes tend to have high levels of calcium
sulfite and sodium salts. Because these compounds are highly soluble and apt
24
to leach, they may pose problems as major components in a landfilled sludge.
Spray-drying scrubber systems produce particulates containing either sodium
sulfate (Na2S04) and sodium sulfite (Na2S03) or calcium sulfate (CaS04) and
calcium sulfite (CaS03), depending on whether the reagents are sodium- or
calcium-based.
Exhibits 3-16 and 3-17 show the major chemical constituents found in sludge
solids and sludge liquors. Oxides of calcium, silicon, magnesium, aluminum,
iron, sodium, and potassium can be found in most FGD sludge. The presence of
-------
3-39
EXHIBIT 3-16
CONCENTRATION OF MAJOR CHEMICAL CONSTITUENTS
OF WET FGD SLDDGE SOLIDS BY SCRUBBER SYSTEM
AND SOURCE OF COAL *
(percent of total)
Direct
East
15-19
13-69
Lime
West
17-95
2-11
Direct Limestone
East West
5-23 85
17-50 8
Dual-Alkali
East West
15-68 82
13-68 1
Alkaline
Flv Ash
West
20
15
Calcium Sulfate
(CaS04)
CaS03-l/2 H20
Calcium Sulfite
(CaS03) 1-22 0-3 15-74 6 8-10 11
Sodium Sulfate
(Na2S04-7H20) -- -- -- -- 4-7 4
Fly Ash 16-60 3-59 1-45 3 0-7 8 65
* Source of coal is categorized by Eastern producing regions (Northern
Appalachia, Central Appalachia, Southern Appalachia, Midwest, Central West,
and Gulf; i.e., Bureau of Mine (BOM) Districts #1-15, 24) and Western
producing regions (Eastern Northern Great Plains, Western Northern Great
Plains, Rockies, Southwest, and Northwest; i.e., BOM Districts #16-23).
Source: Tetra Tech Inc., Physical-Chemical Characteristics of Utility Solid
Wastes, prepared for Electric Power Research Institute, EPRI EA-3236,
September 1983, p. 4-18.
-------
3-40
EXHIBIT 3-17
CONCENTRATION OF MAJOR CHEMICAL CONSTITUENTS
OF VET FGD SLUDGE LIQUORS BY SCRUBBER SYSTEM
AND SOURCE OF COAL a/
Constituent b/
pH (units)
Total Dissolved
Solids
Chloride
Potassium
Sodium
Calcium
Magnesium
Sulfate
Sulfite
Direct Lime
East
8-9.4
2,800 -
10,260
1050-4900
11-28
36-137
660-2520
24-420
800-4500
0.9-2.7
Direct
East
5.5-8.4
5400
1000
24
12
1600
53
2500
160
Limestone
West
6.6-6.8
3300-
14,000
620-4200
8-28
370-2250
390-770
3-9
1360-4000
1-3900
Dual -Alkali
East
12.1
155,700
4900-5600
320-380
53,600-55,300
7-12
0.1
80,000-84,000
_ _
a/ Source of coal is categorized by Eastern producing regions (Northern
Appalachia, Central Appalachia, Southern Appalachia, Midwest, Central West,
and Gulf; i.e., BOM Districts #1-15, 24) and Western producing regions
(Eastern Northern Great Plains, Western Northern Great Plains, Rockies,
Southwest, and Northwest; i.e., BOM Districts #16-23).
b/ All constituent concentrations, unless noted, in milligrams per liter.
Source: Tetra Tech Inc., Physical-Chemical Characteristics of Utility Solid
Wastes, prepared for Electric Power Research Institute, EPRI EA-3226,
September 1983, p. 4-20.
-------
3-41
these compounds results from the presence of fly ash In the sludge, and they are
unreactive in FGD systems. In wet scrubbers that also serve as fly ash
collection devices, more than 50 percent of the sludge solids may be ash.
However, when an ESP or baghouse precedes the scrubber, ash may make up less
25
than 10 percent of the sludge solids.
The calcium sulfate/calcium sulfite ratio of the sludge solids is important
because sludge containing a greater proportion of sulfates has better disposal
properties due to its lower solubility. This ratio is usually higher in systems
scrubbing lower sulfur coals and in direct limestone systems. Many scrubber
systems add a forced oxidation step .to lower the calcium sulfite content of the
sludge, thereby lowering its solubility.
The concentration of trace elements in FGD sludge reflects the levels of
trace elements in the ash, the efficiency of the scrubber in capturing trace
i
elements in the flue gas, and the trace elements present in the reagent and in
the process makeup waters. Fly ash is the primary source of most of the trace
elements found in scrubber sludge. Some elements, such as mercury and selenium,
may be scrubbed directly from the flue gases and then captured in the scrubber
sludge. Exhibit 3-18 illustrates the concentrations at which major trace
elements are found in sludge from wet scrubber systems.
3.3 LOW-VOLUME WASTES
Low-volume utility wastes are those waste streams generated in the routine
cleaning of plant equipment and in purifying of water used in the combustion
process. The types and volumes of low-volume wastes vary among different power
-------
3-42
EXHIBIT 3-18
CONCENTRATION OF TRACE ELEMENTS FOUND IN WET-FGD SLUDGES
(Solids and Liquors)
Sludge Solids
Ranee
Low
&/
Arsenic
Boron
Cadmium
Chromium
Copper
Fluoride
Mercury
Lead
Selenium
Sludge
0
42
0
1
6
266
0
0
2
.8
.0
.1
.6
.0
.0
.01
.2
.0
High
52.0
530.0
25.0
180.0
340.0
1017.0
6.0
290.0
60.0
solid concentrations
a/
Median
12
14
10
15
17
625
0
2
.0
.6
.0
.5
.0
.4
.4
5.0
in milligrams
-LS
0.
2.
0.
0.
0.
0.
0.
0.
Sludge
Liauors b/
Range
iW
0004
1
002
0002
0045
2
00006
005
0.003
per kilogram
b/ Sludge liquor concentrations in milligrams per liter.
Source: Tetra Tech Inc.. Physical -Chemical Characteristics
Hi eh Median
0
76
0
0
0
63
0
0
1
.1
.0
.1
.3
.5
.0
.1
.5
.9
of Utility
0.03
14.9
0.02
0.02
0.03
2.3
0.005
0.03
0.18
Solid
Wastes, prepared for Electric Power Research Institute, EPRI EA-3226,
September 1983, p. 4-24.
-------
3-43
plants, depending on plant-specific factors such as the size of the plant, the
type of equipment, and the age of the equipment. Some low-volume wastes
commonly produced are:
• boiler blowdown.
• coal pile runoff.
• cooling tower blowdown.
• demineralizer regenerants and rinses.
• metal and boiler cleaning wastes.
• pyrites. and
• sump effluents.
Estimates of the total amount of low-volume wastes generated each year by
coal-fired power plants are not available. The frequency of generation and the
quantities generated vary widely from power plant to power plant, depending on
the maintenance requirements of the plant and operating conditions. Variations
also occur within the same power plant, according to its maintenance schedule
and operations. Exhibit 3-19 gives representative annual production figures
for low-volume wastes generated by a typical power plant.
This section presents for each type of low-volume waste a brief description
of how the waste is generated, typical quantities produced, and the physical
and chemical composition of the waste.
3.3.1 Boiler Blowdown
Boiler systems can be either a once-through (supercritical) type or a
-------
3-44
EXHIBIT 3-19
ANNUAL LOW-VOLUME HASTE GENERATION
AT A REPRESENTATIVE COAL-FIRED POWER PLANT *
Type of Waste
Boiler Slowdown
Coal Pile Runoff
Cooling Tower Slowdown
Demineralizer Regenerant
Gas-side Boiler Cleaning
Water-Side Boiler Cleaning
Pyrites
Average Annual Production
11 million gallons/year
20 inches/year
2.6 billion gallons/year
5 million gallons/year
700,000 gallons/year
180,000 gallons/year
65,000 tons/year
* Assuming a 500 megawatt power plant, operating at 70 percent capacity.
Sources: Envirosphere Company, Information Responding to EPA's Request
Regarding Burning and Co-Treatment/Co-Disposal of Low Volume Wastes
Generated at Fossil Fuel Fired Electric Generating Stations, prepared
for Utility Solid Waste Activities Group and Edison Electric
Institute, August 1981.
U.S. Environmental Protection Agency, Waste and Water Management for
Conventional Coal Combustion Assessment Report - 1979: Volume II:
Water Management. EPA-600/7-80-012b, March 1980.
-------
3-45
drum-type. In drum-type boiler systems, after steam passes through the
turbines, it is converted back to water in the condenser and is recirculated
through the boiler to produce steam again. In this process, impurities that
become concentrated in the feedwater periodically must be purged from the
system. This waste stream is known as boiler blowdown. A once-through system,
however, maintains pressurized "steam throughout the cycle, and thus does not
require the recirculation of water. These boiler types, therefore, do not
generate boiler blowdown.
Boiler blowdown is produced either in a continuous stream or intermittently
during the day. The flow is adjusted in order to maintain the desired water
quality in the boiler and is dependent on the quality of the feedwater and the
size and condition of the boiler. The average blowdown rate for a 500 megawatt
unit can range from 20 to 60 gallons per minute, or about 2 to 7 gallons per
O Ł
megawatt-hour.
Boiler blowdown is generally fairly alkaline with a low level of total
dissolved solids. The waste stream usually contains certain chemical additives
used to control scale and corrosion. Trace elements commonly found in boiler
blowdown are copper, iron, and nickel. The components and characteristics of
boiler blowdown are presented in Exhibit 3-20.
3.3.2 Coal Pile Runoff
Power plants typically maintain two types of coal storage piles in their
coal yards: an active pile to supply their immediate needs and an inactive or
long-term pile, which generally stores a 60- to 90-day supply of coal. Coal
-------
3-46
EXHIBIT 3-20
CHARACTERISTICS OF BOILER SLOWDOWN
a/
Range
Parameter Low High
pH (units) 8.3 12.0
Total Solids 125.0 1,407.0
Total Suspended Solids 2.7 31.0
Total Dissolved Solids 11.0 1,405.0
BODS 10.8 11.7
COD 2.0 157.0
Hydroxide Alkalinity 10.0 100.0
Oil and Grease 1.0 14.8
Phosphate (total) 1.5 50.0
Ammonia 0.0 2.0
Cyanide (total) 0.005 0.014
Chromium (total) 0.02 b/
Chromium (Hexavalent) 0.005 0.009
Copper 0.02 0.2
Iron 0.03 1.4
Nickel 0.03 b/
Zinc 0.01 0.05
a/ All concentrations, unless noted, in milligrams per liter.
b/ Data on these elements were limited.
Source: Envirosphere Company, Information Responding to EPA's Request
Regarding Burning and Co-Treatment/Co-Disposal of Low Volume
Wastes Generated at Fossil Fuel Fired Electric Generating
Stations, prepared for Utility Solid Waste Activities Group and
Edison Electric Institute, August 1981.
-------
3-47
piles are usually 25-40 feet high and can cover an area of up to 75 acres,
27
depending on the size and demands of the power plant. Inactive coal piles
are generally sealed with a tar spray to protect the coal against the weather;
active piles are usually open and exposed. Coal pile runoff is formed when
water comes into contact with the piles, whether from rainfall or snowfall,
during spraying for dust control, or from underground streams that surface
under the piles.
The quantity of coal pile runoff depends primarily on rainfall and, to a
lesser extent, the permeability of the soil. It has been estimated that, on
average, 73 percent of the total rainfall on coal piles becomes coal pile
-_ 28
runoff.
The composition of coal pile runoff is influenced by the composition of the
coal, the drainage patterns of the coal pile, and the amount of water that has
l
seeped through. Bituminous coals generate runoff that is usually acidic, with
the level of acidity depending on the availability of neutralizing materials in
the coal, while subbituminous coals tend to produce neutral to alkaline runoff.
Elements commonly found in high concentrations in coal pile runoff are copper,
zinc, magnesium, aluminum, chloride, iron, sodium, and sulfate. Exhibit 3-21
displays ranges of concentrations for these and other characteristics.
3.3.3 Cooling Tower Slowdown
Power plants need cooling systems to dissipate the heat energy that remains
29
after the production of electricity. The two major types of cooling systems
are once-through and recirculating. Cooling tower blowdown generally refers to
-------
3-48
EXHIBIT 3-21
CHARACTERISTICS OF COAL PILE RUNOFF
Ranee
Parameter
pH (units)
Acidity (as CAC03)
Total Dissolved Solids
Total Suspended Solids
Aluminum
Ammonia
Arsenic
Beryllium
Cadmium
Chloride
Chromium
Cobalt
Copper
Iron
Magnesium
Manganese
Mercury
Nickel
Nitrate
Phosphorus
Selenium
Sodium
Sulfate
Zinc
Low
2.1
300.0
270.0
8.0
20.0
0.0
0.005
0.01
0.001
3.6
0.005
0.025
0.01
0.1
0.0
0.9
0.0002
0.1
0.3
0.2
0.001
160.0
130.0
0.006
Hi eh
9.3 by
7,100.0
28,970.0
2,500.0
1,200.0
1.8
0.6
0.07
0.003
481.0
16.0
--
6.1
5,250.0
174.0
180.0
0.007
4.5
1.9
1.2
0.03
1,260.0
20,000.0
26.0
a/ All concentrations, unless noted, in milligrams per liter.
b/ Electric Power Research Institute, Manual For Management of Low-Volume
Wastes From Fossil-Fuel-Fired Power Plants, prepared by Radian Corporation,
Austin, Texas, July 1987.
Source: All information, unless noted otherwise, is from Envirosphere Company,
Information Responding to EPA's Request Regarding Burning and
Co-Treatment/Co-Disposal of Low Volume Wastes Generated at Fossil Fuel
Fired Electric Generating Stations, prepared for Utility Solid Waste
Activities Group and Edison Electric Institute, August 1981.
-------
3-49
the water withdrawn from a recirculating cooling system to control the
concentration of impurities in the cooling water; although once-through systems
also discharge water from the cooling system, this discharge is not typically
referred to as cooling tower blowdown. At present, about two-thirds of
electric utility power plants use a once-through cooling system. This
percentage may decrease, however, due to concern over water availability and
potential environmental concern over thermal discharges; consequently, future
plants may be built with recirculating systems that use cooling towers or
. . ,30
cooling ponds.
Once-through cooling systems are primarily used by power plants located
next to large bodies of water. After passing through the condenser, the
cooling water is discharged, usually into a river, lake, or pond. The quantity
discharged ranges from 26,000 to 93,000 gallons per megawatt-hour. For a 500
31
megawatt plant, this roughly equals 70-300 billion gallons per year. In most
instances, the chemical composition of the water remains the same after passing
through the condenser, but some changes may occur as the result of the
formation of corrosion products or the addition of biocides.
Recirculating cooling systems can use either cooling ponds or cooling
towers. In a cooling pond system, water is drawn from a large body of water,
such as a pond or canal. After it passes through the condenser to absorb waste
heat, the water is recycled back into the pond or canal. Cooling tower systems
operate by spraying the water through a cooling tower. About 80 percent of the
waste heat contained in the water is then released through evaporation. The
remainder of the water is recycled back through the cooling tower system.
Cooling tower blowdown is a waste stream bled off to control the concentrations
-------
3-50
of impurities and contaminants in the cooling system that could lead to scale
32
formation in the condenser.
The cooling tower blowdown rate is adjusted to maintain water quality in
the recirculating cooling system in order to prevent scale formation in the
condenser. The quantity of blowdown generated is a function of the quality of
the makeup water (the water added to the system to replace that which is lost
by evaporation and blowdown), the condition of the cooling system, and the
amount of water evaporated by the cooling tower. For a representative 500
megawatt unit, the blowdown rate varies between 2 and 30 cubic feet (15 to 225
gallons) per second.
The composition and quantity of cooling tower blowdown varies greatly from
plant to plant. It generally reflects the characteristics of the makeup waters
(e.g., fresh water versus brackish or saline water) and the chemicals added to
prevent the growth of fungi, algae, and bacteria in the cooling towers and to
prevent corrosion in the condensers. Some of these chemical additives are
chlorine, chromate, zinc, phosphate, and silicate. Ranges of concentration for
some of the characteristics and components of cooling tower blowdown are shown
in Exhibit 3-22.
3.3.4 Denineralizer Regenerant and Rinses
A power plant must treat water prior to its use as makeup water. The use
of demineralizers is the most common method of purification. During the
demineralization process, which may entail several rinses, high-purity process
water is provided for the boiler through an ion exchange process. The wastes
-------
3-51
EXHIBIT 3-22
CHARACTERISTICS OF COOLING TOWER SLOWDOWN
a/
Range
Parameter Low High
Alkalinity (as CaC03) 8.0 556.0
BOD -- 94.0
COD -- 436.0
Total Solids 750.0 32,678.0
Total Dissolved Solids 4.1 32,676.0
Total Suspended Solids 0.2 220.0
Ammonia (as N) 0.01 11.6
Nitrate (as N) 0.1 711.0
Phosphorus (as P) 0.1 17.7
Total Hardness (as CaC03) 84.0 2,580.0
Sulfate 7.2 20,658.0
Chloride 5.0 16,300.0
Fluoride b/ 0.3 33.0
Aluminum b/ 1,100.0 1,700.0
Boron b/ 0.5 1.0
Chromium (ug/1) 0.02 120.0
Copper (ug/1) 0.01 1,740.0
Iron (ug/1)) 0.1 1,160.0
Lead (ug/1) b/ 4.0
Magnesium (ug/1) 0.1 1,580.0
Manganese (ug/1) b/ 24.0 220.0
Mercury (ug/1) b/ 1.5
Nickel (ug/1) 0.03 150.0
Zinc (ug/1) 0.02 3,000.0
Oil & Grease 1.0 7.4
Phenols (ug/1) -- 72.0
Surfactants 0.2
Sodium 3.4 11,578.0
a/ All concentrations, unless noted, in milligrams per liter.
b/ Data on these elements were limited.
Source: Envirosphere Company, Information Responding to EPA's Request Regarding
Burning and Co-Treatment/Co-Disposal of Low Volume Wastes Generated at
Fossil Fuel Fired Electric Generating Stations, prepared for Utility
Solid Waste Activities Group and Edison Electric Institute, August
1981.
-------
3-52
produced in this process can be either acidic or alkaline. When sulfuric acid
is employed as the regenerant, calcium sulfate is precipitated in the waste
stream. Exhibit 3-23 presents ranges for the components of demineralizer
regenerants and rinses.
Regeneration of boiler makeup water by demineralizers is done on a batch
basis. The frequency with which the process occurs depends on the quality of
the incoming water, although for a 500 megawatt unit, regeneration usually
occurs every one to four days. A single regeneration requires approximately
30,000 gallons of water, which amounts to about 3-10 million gallons per
34
year.
3.3.5 Metal and Boiler Cleaning Wastes
This category of low-volume waste streams can be divided into two basic
types: gas-side cleaning wastes and water-side cleaning wastes. Gas-side
wastes are produced during maintenance of the gas-side of the boiler, which
includes the air preheater, economizer, superheater, stack, and ancillary
equipment. Residues from coal combustion (such as soot and fly ash), which
build up on these surfaces, must be removed periodically -- usually with plain
water containing no chemical additives.
Water-side wastes are produced during cleaning of the boiler tubes, the
superheater, and the condenser, which are located on the water-side or
steam-side of the boiler. The scale and corrosion products that build up on
these boiler parts must be removed with cleaning solutions containing chemical
additives.
-------
3-53
EXHIBIT 3-23
CHARACTERISTICS OF
SPENT DEMINERALIZER REGENERANTS
Parameter
Low
Range
High
Alkalinity (as CaC03)
BOD
COD
Total Solids
Total Dissolved Solids
Total Suspended Solids
Ammonia (as N)
Phosphorus (as P)
Turbidity (JTU)
Total Hardness (as CaC03)
Sulfate
Chloride
Boron
Chromium
Copper (ug/1)
Iron (ug/1)
Lead (ug/1) b/
Magnesium (ug/1)
Manganese (ug/1)
Mercury (ug/1)
Nickel (ug/1)
Zinc (ug/1)
Oil & Grease b/
Phenols (ug/1)
Surfactants b/
Nitrate as N
Algicides b/
Sodium
0.0
0.0
0.0
284.0
283.0
0.0
0.0
0.0
2.5
0.0
4.5
0.0
0.0
0.0
0.0
0.0
160.0
0.0
0.0
0.05
0.0
0.0
0.0
0.0
1.7
0.0
0.003
4.9
3,831.0
344.0
440.0
36,237.0
25,235.0
300.0 c/
435.0
87.2
100.0
8,000.0
9,947.0
20,500.0
0.1
2,168.0
3,091.0
2,250.0
37,500.0
753.0
3,100.0
560.0
4,500.0
24.5
303,000.0
118.0
30,000.0
a/ All concentrations, unless noted, in milligrams per liter.
b/ Data on these components were limited.
c/ Electric Power Research Institute, Manual For Management of Low-Volume
Wastes From Fossil-Fuel-Fired Power Plants, prepared by Radian Corporation,
Austin, Texas, July 1987.
Source: All data, unless noted otherwise, are from Envirosphere Company,
Information Responding to EPA's Request Regarding Burning and
Co-Treatment/Co-Disposal of Low Volume Wastes Generated at Fossil Fuel
Fired Electric Generating Stations, prepared for Utility Solid Waste
Activities Group and Edison Electric Institute, August 1981.
-------
3-54
The boiler and auxiliary equipment are cleaned intermittently, creating
large quantities of wastes in a short time. Gas-side boiler cleaning is done
approximately twice a year. The volume of the waste stream produced depends on
the size of the boiler and the number of rinses. For a typical plant, gas-side
cleanings can produce between 24,000 and 700,000 gallons of wastes. Water-side
equipment is cleaned less frequently, approximately once every three years. As
is true of gas-side cleaning, the volume of waste produced varies with the
number of rinses. A representative 500 megawatt unit generates about
35
120,000-240,000 gallons of wastewater per treatment.
Because no chemicals are used, the composition of the waste streams
associated with gas-side cleaning directly reflects the composition of the soot
and fly ash residues and, therefore, of the coal that is burned. Exhibit 3-24
shows two reported values for components and characteristics of gas-side
cleaning waste streams.
The particular solution used for the cleaning of the water-side of the
boiler varies depending on the equipment being cleaned and the type of scale
that needs to be removed. When the scale contains high levels of metallic
copper, an alkaline solution that contains ammonium salts, an oxidizing agent
such as potassium or sodium bromate or chlorate, and nitrates or nitrites is
used. Exhibit 3-25 presents some of the major characteristics associated with
these types of solutions and representative ranges of concentrations in which
they are found.
For the removal of scale caused by water hardness, iron oxides, and copper
oxide, an acid cleaning solution is needed. Usually hydrochloric acid acts as
-------
3-55
EXHIBIT 3-24
REPORTED CHARACTERISTICS OF GAS-SIDE CLEANING WASTES
Parameter
Cleaning Frequency (cycles/yr)
Batch Volume (1000 gallons)
Alkalinity
COD
Total Solids
Total Dissolved Solids
Total Suspended Solids
Turbidity (JTU)
Hardness
Ammonia
Chloride
Chromium (total)
Copper
Iron
Lead
Magnesium
Nickel
Nitrate
Phosphorus
Sodium
Sulfate
Vanadium
Zinc
Quantities Produced per Cleaning
fin Ibs. except as noted) a/
Source A Source B
2.0
720.0
0.0
1,134.0
40,861.0
35,127.0
3,823.0
476.0
35,409.0
1.5
0.0
0.03
900.0
11,949.0
30.0
14.7
11.1
0.0
11,949.0
28.7
8.0
24.0
6.0
19.0
,002.0
,002.0
119.1
98.0
791.4
0.4
18.0
1.0
0.3
30.0
190.3
0.7
0.3
9.0
299.4
2.0
a/ Quantities produced are shown for two different reported values.
Source: Envirosphere Company, Information Responding to EPA's Request
Regarding Burning and Co-Treatment/Co-Disposal of Low Volume
Wastes Generated at Fossil Fuel Fired Electric Generating
Stations, prepared for Utility Solid Waste Activities Group and
Edison Electric Institute, August 1981.
-------
3-56
EXHIBIT 3-25
CHARACTERISTICS OF SPENT HATER-SIDE
ALKALINE CLEANING WASTES
fi/
Range
Parameter Low High
Alkalinity (as CaC03) 20,200.0 25,700.0
NH3-N 4,280.0 6,360.0
Kjeldahl-N 5,190.0 7,850.0
Nitrate-N 1.0 193.0
Oil & Grease 7.9 10.3
BODS 5,820.0 8,060.0
COD 14,600.0 20,900.0
Total Suspended Solids 5,580.0 6,720.0
Total Dissolved Solids 10.0 400.0
TDS 22,100.0 32,300.0
Total Iron . 180.0 10,800.0
Silica 1.0 40.0
Chromium 0.2 7.7 b/
Copper 8.0 1,912.0
Lead 0.004 b/ 23.0 b/
Manganese 0.1 14.3
Nickel 2.5 130.0
Tin 2.0 20.7
Zinc 3.1 390.0
pH (units) 8.4 b/ 10.3 b/
a/ All concentrations, unless noted, in milligrams per liter.
b/ Electric Power Research Institute, Manual For Management of Low-Volume
Wastes From Fossil-Fuel-Fired Power Plants, prepared by Radian Corporation,
Austin, Texas, July 1987.
Source: All data, unless noted otherwise, are from Envirosphere Company,
Information Responding to EPA's Request Regarding Burning and
Co-Treatment/Co-Disposal of Low Volume Wastes Generated at Fossil Fuel
Fired Electric Generating Stations, prepared for Utility Solid Waste
Activities Group and Edison Electric Institute, August 1981.
-------
3-57
the solvent in these solutions, although sulfuric, phosphoric, and nitric acids
can also be used. Organic acids have been used increasingly as substitutes for
hydrochloric acid because of their lower toxicity. .For the removal of silica
deposits, hydrofluoric acid or fluoride salts are added to the cleaning
solution. Exhibit 3-26 presents the various characteristics of acid boiler
cleaning solutions.
Alkaline chelating rinses and alkaline passivating rinses are often used to
remove iron and copper compounds and silica and to neutralize any residual
acidity left over from acid cleaning. These solutions may contain phosphates,
chromates, nitrates, nitrites, ammonia, EDTA, citrates, gluconates, caustic
soda, or soda ash. Exhibit 3-27 gives representative ranges for these
components and others present in these rinses.
3.3.6 Pyrites
Pyrites are the solid mineral compounds, such as iron sulfides or other
rock-like substances, present in raw coal. Most pyrites are generally
separated out before coal is burned, usually at a preparation plant prior to
shipment to the power plant. Smaller quantities of pyrites are often removed
at the power plant just before the coal is pulverized. The size of the
deposits depends on the method by which they are separated from the coal.
The volume of pyrites collected at a power plant depends on the amount and
quality of the coal that is burned, which is determined by the source of the
coal and the preparation process, as well as by the coal pulverization process.
-------
3-58
EXHIBIT 3-26
CHARACTERISTICS OF SPENT WATER-SIDE
HYDROCHLORIC ACID CLEANING WASTES
Parameter
Low
Ranee
High
pH (units)
Total Suspended Solids
Silica
NH3-N
Nitrogen
Phosphorus
Sulfate
Aluminum
Arsenic
Barium
Beryllium
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Nickel
Potassium
Selenium
Silver
Sodium
Tin
Zinc
0.5
8.0
19.0
80.0
1.0
1.0
1.0
6.5
0.01
0.1
0.0
0.001
16.0
0.005
2.2
1125.0
0.01
5.7
6.9
0.0
3.0
1.4
0.002
0.02
9.2
1.0
0.9
3.3
2375.0
280.0
325.0
870.0
300.0
10.0
8.2
0.1
0.4
0.1
0.13 b/
980.0
16.8
960.0
6470.0
5.2
8.8
29.0
0.002
500.0
2.3
0.004
0.2 b/
74.0
7.3
840.0
a/ All concentrations, unless noted, in milligrams per liter.
b/ Electric Power Research Institute, Manual For Management of Low-Volume
Wastes From Fossil-Fuel-Fired Power Plants, prepared by Radian Corporation,
Austin, Texas, July 1987.
Source: All data, unless noted otherwise, are from Envirosphere Company,
Information Responding to EPA's Request Regarding Burning and
Co-Treatment/Co-Disposal of Low Volume Wastes Generated at Fossil Fuel
Fired Electric Generating Stations, prepared for Utility Solid Waste
Activities Group and Edison Electric Institute, August 1981.
-------
3-59
EXHIBIT 3-27
CHARACTERISTICS OF SPENT HATER-SIDE
ALKALINE FASSIVATING WASTES
Range*
Parameter
pH (units)
Total Suspended Solids
NH3-N
Kjeldahl-N
Nitrite -N
BODS
COD
TOG
Iron
Chromium
Copper
* All concentrations ,
Source: Envirosphere
Regarding Bur
Generated at
Low
9.2
13.0
15.0
97.0
7.0
40.0
98.0
16.0
7.5
0.0
0.1
unless noted, in milligrams per liter.
Company. Information Responding to EPA's
ning and Co-Treatment/Co-Disposal of Low
High
10.0
45.0
232.0
351.0
12.9
127.0
543.0
23.0
28.0
0.4
1.2
Request
Volume Wastes
Fossil Fuel Fired Electric Generating Stations, prepar
for Utility Solid Waste Activities Group and Edison Electric
Institute, August 1981.
-------
3-60
The amount of pyrites to be disposed at a power plant can vary considerably,
36
although coal typically contains up to 5 percent pyrites. A 500 megawatt
plant, depending on how often it operates and the quality of its coal, will
generate, on average, between 30,000 and 100,000 tons of pyrites per year. The
characteristics of pyrites and pyrite slurry transport water are shown in
Exhibit 3-28.
3.3.7 Sump Effluents
Floor and yard drains collect waste streams from a variety of sources at
power plants, such as rainfall, seepage from ground-water sources, leakage,
small equipment cleaning operations, and process spills and leaks. As a
result, the composition of drain effluents is highly variable. Depending on
the particular circumstances at the power plant, these waste streams may
contain coal dust, fly ash, oil, and detergents.
The frequency of sump effluent generation and quantities generated are very
plant-specific. The more efficient a plant's operating procedures, the smaller
this waste stream will be. Also, power plants located in dry areas of the
country will have relatively small amounts of wastes collected in yard drains.
3.4 SUMMARY
In the process of generating electricity, coal-fired utility power plants
produce a number of waste products. These wastes are produced in large
quantities and have widely varying physical and chemical characteristics.
-------
3-61
EXHIBIT 3-28
CHARACTERISTICS OF PYRITES AND
FYRITE TRANSPORT WATER
Parameter
Total Suspended Solids
Total Aluminum
Total Calcium
Total Iron
Total Magnesium
Sulfate
pH (units)
Arsenic
Chromium
Copper
Lead
Zinc
Manganese
Selenium
Silica
Silver
Cobalt
Nickel
Vanadium
Pvrite Slurry Water
1,700.0
93.3
134.0
220.0
13.6
177.0
7.7
0.1
0.1
0.1
0.3
212.0
Pyrites b/
Solid Form
500-5000
10-10,000
200-1000
500-10,000
10-5000
10-100
10-50
100-5000
10-1000
100-200
a/ All concentrations, unless noted, in milligrams per liter.
b/ All concentrations in parts per million.
Source: Envirosphere Company, Information Responding to EPA's Request
Regarding Burning and Co-Treatment/Co-Disposal of Low Volume Wastes
Generated at Fossil Fuel Fired Electric Generating Stations, prepared
for Utility Solid Waste Activities Group and Edison Electric
Institute, August 1981.
-------
3-62
Coal-fired electric utility power plants produce three
major forms of wastes:
1) Ash, formed from the noncombustible material
present in coal. There are three types of
ash -- fly ash, bottom ash, and boiler slag;
2) FGD sludge, produced by flue gas desulfurization
systems designed to remove sulfur oxides from
flue gas; and
3) Low-volume wastes, generated primarily from equipment
maintenance and cleaning operations.
In 1984, about 69 million tons of ash and about 16
million tons of FGD sludge were produced by coal-fired
electric utilities. By the year 2000, these wastes
are expected to increase to about 120 million and
50 million tons, respectively.
Several physical characteristics of utility waste
determine the waste's behavior during disposal and
the potential for leachate problems. These
characteristics vary a great deal among the different
types of ash and FGD sludge.
The chemical constituents of ash and FGD sludge
largely depend on the chemical components in the coal.
Other chemical compounds present in FGD sludge, primarily
calcium and sodium salts, are the result of the reactions
between the absorbent reagent used and the sulfur oxides
in the flue gas.
Compared with ash and FGD sludge, low-volume wastes are
generally produced in much smaller quantities. Many
of these wastes contain various chemicals from the
cleaning solutions used for power plant operations
and maintenance; potentially-hazardous elements in
these chemicals may be found at high concentrations
in the low-volume waste.
-------
CHAPTER THREE
NOTES
1 See Appendix B for a more in-depth discussion of boiler types and how
the type of boiler affects the types of waste that are generated.
2 Babcock & Wilcox, Steam: Its Generation and Use. New York: The Babcock
& Wilcox Company, 1978, p. 18-3.
3 Ibid.
Energy Information Administration, Cost and Quality of Fuels for
Electric Utility Plants-1985. DOE/EIA-0191(85), July 1986.
5 ICF Incorporated, Analysis of 6 and 8 Million Ton and 30 Year/NSPS and 30
Year/I.2 Pound Sulfur Dioxide Emission Reduction Cases, prepared for EPA,
February 1986. There are many factors that can affect the amount of coal
consumed, including electricity growth rates, oil and gas prices, types of
technology available, etc. Nevertheless, utilities will continue to burn
substantial amounts of coal in the foreseeable future.
^ Energy Information Administration, Electric Power Annual 1984.
DOE/EIA-0348(84), p. 45.
' There are presently over 500 coal cleaning plants in the U.S., the
majority of which are operated by coal companies and located at the mouth of
the mine. The type of cleaning method employed depends upon the size of the
coal pieces to be cleaned, a factor that can be controlled at the cleaning
plant.
The most widely used methods of coal cleaning are those that use specific
gravity, relying on the principle that heavier particles (i.e., impurities)
separate from lighter ones (i.e., coal) when settling in fluid. A common
method of cleaning coarse coal pieces is to pulse currents of water through a
bed of coal in a jig; impurities, such as shale and pyrite, sink, while the
coal floats on top. The heavy, or dense, media process is used for cleaning
coarse and intermediate-sized pieces. A mixture of water and ground magnetite,
having a specific gravity between that of coal and its impurities, acts as a
separating fluid. An inclined vibrating platform with diagonal grooves, known
as a concentrating table, also is used to clean intermediate-sized coal pieces.
Raw coal slurry is fed onto the high end of the table. As the slurry flows
down, the vibrations separate the coal from the refuse, allowing the lighter
coal to be carried along in the water, while the heavier impurities are trapped
in the grooves.
Because of their small size, fine coal particles are very difficult to
clean. Their recovery is important, however, because these particles can
provide up to 25 percent of the energy derived from raw coal. A popular method
of fine coal cleaning is froth flotation. The coal pieces are coated with oil
and then agitated in a controlled mixture of water, air, and reagents
until froth is formed on the surface. Bubbles tend to attach to the coal
pieces, keeping them buoyant, while heavier particles such as pyrite, shale,
and slate remain dispersed in the water. The coal can then be removed from the
-------
3-2
surface. For more information, see Coal Preparation. 4th edition, Joseph
Leonard, editor, American Institute of Mining, Metallurgical, and Petroleum
Engineers, Inc., 1979.
8 Ash melts when heated to a sufficiently high temperature. The
temperatures at which the ash changes forms -- e.g., melting from a cone shape
to a spherical shape to a hemispherical shape to a flat layer -- are referred
to as ash fusion temperatures.
^ Tetra Tech, Inc., Physical-Chemical Characteristics of Utility Solid
Wastes. EPRI EA-3236, prepared for Electric Power Research Institute, September
1983, p. 3-4. A micron is 0.001 millimeters.
10 Ibid.
The compressibility of a material is measured as the ratio of its
height at 50 psi to its original height at atmospheric pressure. The dry
density, the ratio of weight to unit volume of the material containing no
water, affects permeability and strength, which in turn determine the
structural stability of a landfill and the extent of leachate mobility. The
optimum moisture content is the moisture content, in percentage terms, at which
the material attains its maximum density.
12
In 1979 the New Source Performance Standards, part of the Clean Air Act
of 1971, were revised. The new regulations required that all coal-fired
electric utility units with capacity greater than 73 megawatts, whose
construction commenced after September 18, 1978, would not only have to meet a
1.2 pound sulfur dioxide per million Btu emission limit, but would have to do
so by a continuous system of emissions reduction. New power plants must reduce
sulfur dioxide emissions between 70 and 90 percent, depending on the type of
coal burned.
During fluidized bed combustion the sulfur oxides react with limestone
or dolomite to form calcium sulfate. In LIMB technology, limestone is injected
into the boiler, also forming calcium compounds.
14
Federal Power Commission, The Status of Flue Gas Desulfurization
Applications in the United States: A Technological Assessment. July 1977,
p. VII-15.
Ibid.. p. VII-18.
Tetra Tech, Inc., Physical-Chemical Characteristics of Utility Solid
Wastes. EPRI EA-3236, prepared for Electric Power Research Institute, September
1983, p. 4-4.
18 "Dry Capture of S02," EPRI Journal. March 1984, p. 21.
19 Ibid.. p. 15.
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3-3
20
ICF, op. clt. See Appendix B for a detailed explanation of how future
FGD sludge estimates were derived.
21
U.S. Environmental Protection Agency, Controlling S02 Emissions from
Coal-Fired Steam-Electric Generators: Solid Waste Impact. Volume I,
EPA-600/7-78-044a, March 1978, p. 23.
22
See Chapter Four for a detailed discussion of the methods of sludge
fixation.
03
Michael Baker, Jr., Inc., State-of-the-Art of FGD Sludge Fixation.
prepared for Electric Power Research Institute, January 1978, p. 2-25.
24
Tetra Tech, Inc., op. cit.. p. 4-17.
25 Ibid.
26
Envirosphere Company, Information Responding to EPA's Request Regarding
Burning and Co-Treatment/Co-Disposal of Low Volume Wastes Generated at Fossil
Fuel Fired Electric Generating Stations, prepared for Utility Solid Waste
Activities Group and Edison Electric Institute, August 1981, p. 26.
27
U.S. Environmental Protection Agency, Waste and Water Management for
Conventional Coal Combustion Assessment Report - 1979: Volume II; Water
Management. EPA-600/7-80-012b, March 1980, p. 3-146.
OQ
Ibid., p. 3-147.
29
Ibid.. p. 3-16. About 35 to 40 percent of the total heat input of a
power plant is converted to electricity, about 5 percent is lost in the stack,
gases, and the remaining 55 to 60 percent is rejected in the condenser.
30 Ibid.. p. 3-17.
31 Ibid.
32
The term "cooling tower blowdown" refers to the waste waters produced by
all recirculating cooling systems, whether they use a cooling pond or a cooling
tower.
33
U.S. EPA, Waste and Water Management, p. 3-19.
34
Envirosphere Company, Information Responding to EPA's Request Regarding
Burning and Co-Treatment/Co-Disposal of Low Volume Wastes Generated at Fossil
Fuel Fired Electric Generating Stations, prepared for Utility Solid Waste
Activities Group and Edison Electric Institute, August 1981, p. 27.
35 Ibid.. p. 27.
Ibid.. p. 28. The term "pyrites" is used to refer to a variety of
rock-like substances that may be found in raw coal; it does not just refer to
pyritic sulfur that is found in all raw coal, although pyritic sulfur is
typically part of the pyrites generated at a power plant.
-------
CHAPTER FOUR
COAL COMBUSTION WASTE MANAGEMENT PRACTICES
Under Section 8002(n) of RCRA, EPA is to analyze "present disposal and
utilization practices" and "alternatives to current disposal methods." This
chapter addresses these issues by first examining the various state regulations
that affect coal combustion disposal since these regulations set the context
for current practices. The following section describes coal combustion waste
management practices. First, three commonly employed types of land management
practices are described in detail. Next, this chapter describes additional
measures currently employed by some utilities; more widespread use of these
technologies could be employed as an alternative to current practices. Ocean
disposal, an alternative that is in the research and development stage, is also
addressed in this chapter. Finally, the extent of coal combustion waste
recycling as an alternative to disposal is described.
4.1 STATE REGULATION OF COAL COMBUSTION WASTE DISPOSAL
Since coal combustion wastes are currently exempt from Federal hazardous
waste regulation under RCRA., their regulation is primarily carried out under
the authority of state hazardous and solid waste laws. State solid waste laws
establish programs to provide for the safe management of non-hazardous solid
wastes. If solid wastes are considered hazardous, state hazardous waste laws
establish programs to provide for their safe management. To implement these
laws, state health or environmental protection agencies promulgate solid and
hazardous waste regulations. A 1983 report for the Utility Solid Waste
Activities Group (USWAG) surveyed these regulations; the USWAG report provided
-------
4-2
summaries of state regulations based on applicable state laws, regulations, and
interviews with state environmental officials.^- EPA updated the information
provided in the USWAG summaries for the purposes of this report.
Exhibit 4-1 lists the disposal requirements promulgated under each state's
solid waste (non-hazardous) regulations. (As will be discussed below, it is
very rare for coal combustion wastes to be regulated as hazardous under state
regulations.) The list of states is arranged in descending order according to
each state's share of national coal-fired generating capacity (Column 1 of
Exhibit 4-1). The information shown in the Exhibit is discussed in detail in
Sections 4.1.1 and 4.1.2.
4.1.1 State Classification of Coal Combustion Wastes
Forty-three states have exempted coal combustion wastes from hazardous
waste regulation. As a result, in these states the state solid waste laws,
which apply to non-hazardous wastes, regulate the disposal of these coal
combustion wastes. Column 2 of Exhibit 4-1 shows that: (1) in seven states,
coal combustion wastes are not exempt from hazardous waste regulation
(indicated by an entry of CH), which means that they are tested to determine
whether they will be regulated as solid or hazardous wastes; (2) in all but one
of the remaining states wastes are regulated by solid waste regulations
(indicated by an entry of SW); and (3) in the one remaining state, wastes are
exempt from both the hazardous waste and solid waste regulations (indicated by
an entry of EX).
-------
4-3
EXHIBIT 4-1
STATE
(1) (2)
X NATIONAL
COAL-FIRED CLASSIFICATION
CAPACITY
(7) (8) (9)
GROUND-HATER CLOSURE FINANCIAL
MONITORING CONDITIONS ASSURANCE
Texas
Indiana
Kentucky
Ohio
Pennsylvania
Illinois
West Virginia
North Carolina
Michigan
Georgia
Florida
Missouri
Alabama
Tennessee
Nevada
South Carolina
Wisconsin
Louisiana
Colorado
Iowa
Wyoming
Kansas
Arizona
New Mexico
Utah
Minnesota
Arkansas
Maryland
North Dakota
Oklahoma
New York
Virginia
Washington
Nebraska
Montana
Mississippi
New Jersey
Massachusetts
Oregon
Delaware
Maine
South Dakota
8.401
6.44Z
6.431
6.02Z
5. 711
5.461
3.87X
3.41Z
3.37Z
3.351
3.26Z
3.16Z
3.08Z
2.54Z
2.49Z
2.24Z
2.19Z
1.98Z
1.97Z
1.83Z
1.82Z
1.69Z
1.67Z
1.58Z
1.57Z
1.54Z
1.48Z
1.48Z
1.39Z
1.34Z
1.24Z
0.94Z
0.931
0.85Z
0.74Z
0.621
0.51Z
0.41Z
0.31Z
0.27Z
0.15Z
0.13X
sw
sw
CE
EX
SW
SW
SW
sw
sw
sw
sw
sw
sw
CH
sw
sw
sw
sw
sw
sw
sw
sw
sw
sw
sw
sw
sw
sw
sw
CH
sw
sw
CH
sw
sw
sw
CH
sw
sw
sw
CH
sw
OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
OFF SITE
OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
OFF SITE
ON & OFF SITE
OFF SITE
OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
NO
NO
YES
YES
NO
NO
YES
YES
NO
YES
YES
YES
YES
YES
YES
YES
YES
YES
NO
YES
YES
NO
NO
NO
YES
YES
NO
NO
YES
YES
NO
YES
NO
YES
NO
YES
YES
YES
YES
YES
NO
NO
NO
MAY
NO
NO
NO
NO
NO
NO
YES
NO
MAY
MAY
NO
NO
MAY
YES
YES
NO
NO
NO
NO
NO
NO
NO
NO
HO
NO
NO
MAY
NO
YES
NO
NO
MAY
NO
NO
NO
NO
YES
NO
NO
NO
YES
NO
NO
NO
NO
NO
NO
YES
MAY
NO
NO
NO
YES
MAY
YES
YES
MAY
NO
NO
NO
NO
NO
MAY
NO
YES
MAY
NO
MAY
NO
YES
MAY
NO
NO
NO
NO
NO
YES
YES
NO
MAY
MAY
MAY
MAY
NO
NO
YES
YES
NO
YES
NO
YES
MAY
NO
NO
MAY
YES
YES
NO
NO
MAY
NO
NO
NO
YES
NO
YES
YES
YES
YES
NO
YES
NO
NO
NO
YES
NO
MAY
YES
MAY
NO
YES
NO
YES
YES
YES
NO
YES
NO
NO
YES
YES
YES
YES
NO
YES
YES
YES
NO
NO
NO
YES
NO
NO
NO
YES
YES
NO
YES
YES
YES
NO
YES
NO
NO
YES
YES
NO
NO
YES
YES
YES
YES
NO
NO
YES
YES
NO
NO
HO
NO
YES
NO
NO
NO
NO
RO
YES
YES
NO
NO
NO
YES
NO
NO
NO
NO
YES
NO
YES
YES
NO
NO
NO
NO
NO
NO
YES
NO
YES
NO
NO
NO
-------
4-4
lUHIHIT 4-1 (continued)
STATE UHJlLATdmS GOVEKNIBG COAL OOMBDSTIOB HASTE DISPOSAL
STATE
Haw Hampshire
Alaska
California
Connecticut
Vermont
Rhode Island
Hawaii
Idaho
(1)
Z NATIONAL
COAL-FIRED
CAPACITY
0.121
0.01Z
O.OOX
O.OOX
O.OOZ
O.OOZ
O.OOZ
O.OOZ
(2)
CLASSIFICATION
SW
sw
CH
SW
SW
SW
SW
SW
(3)
(4)
SITE
PERMITS RESTRICTIONS
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
HO
YES
YES
YES
NO
YES
NO
NO
(5)
LINER
NO
NO
HO
NO
NO
NO
NO
NO
(6)
LEACHATE
CONTROL
NO
NO
YES
YES
NO
YES
NO
MAY
(7)
GROUND -HATER
MONITORING
YES
MAY
MAY
YES
NO
YES
NO
NO
(8)
CLOSURE
CONDITIONS
NO
HO
YES
YES
NO
NO
NO
NO
(9)
FINANCIAL
ASSURANCE
HO
no
YES
NO
NO
NO
NO
NO
NOTES
Column (1) Percent national coal-fired capacity: i.e., each state's share of total U.S. coal-fired generating capacity.
Column (2) Classification: SW - coal combustion waste is exempted from hazardous waste regulation and regulated as a solid
waste.
CH - coal combustion waste is not exempted from hazardous waste regulation and is tested for
hazardous characteristics (In practice, coal combustion wastes are rarely considered hazardous,
therefore columns 3-8 reflect solid, not hazardous, waste regulations).
EX - coal combustion waste is exempted from both solid and hazardous waste regulation.
Column (3) Permits: Permits are required for off-site facilities only, or for both on-site and off-site facilities.
Columns (4), (5), (6), (7), (8), (9): YES - the disposal standard is imposed by state regulations.
NO - the disposal standard is not imposed by state regulations.
MAY - the regulation states that a case-by-case investigation will determine whether the
disposal standard will be imposed.
Source: Wald, Harkrader & Ross, Survey of State Laws and Regulations Governing Disposal of Utility Coal-Combustion Byproducts.
prepared for the Utility Solid Waste Activities Group, September, 1983.
-------
4-5
Of the seven states that do not exempt coal combustion wastes from
hazardous waste regulation (indicated by a CH classification in Exhibit 4-1),
California burns little coal to produce electricity. The hazardous waste.
regulations of the six remaining states -- Kentucky, Tennessee, New Jersey,
Oklahoma, Maine, and Washington -- regard coal combustion wastes as
"characteristic" waste; that is, the wastes are tested for Extraction Procedure
(EP) toxicity (see Chapter Five for further discussion), and if the waste
proves to be toxic, some or all sections of state hazardous waste regulations
apply. In Kentucky, for example, hazardous waste standards concerning lining
and leachate control are enforced for coal combustion wastes that are found to
be toxic, but utilities are not required to participate in the hazardous waste
management fund established to ensure the long-term viability of disposal
facilities. Similarly, according to the hazardous waste regulations of
Tennessee and Oklahoma, if a waste is determined to be toxic, strict analysis
and monitoring requirements must be followed, but compliance with state
hazardous waste design and operating standards is not required. Officials from
these five states have indicated that it is very rare for a coal-burning
utility's waste to be classified as hazardous. Therefore, state solid waste
regulations, with only isolated exceptions, establish the standards applicable
to most coal combustion waste disposal activities.
Although solid waste regulations in most states do not differentiate
between coal combustion wastes and other solid wastes, solid waste regulations
in three states make specific reference to coal combustion waste disposal:
-------
4-6
• Ohio's solid waste regulations list "non-toxic fly
ash ... and slag ... that are not harmful or
inimical to public health" as wastes that are
exempt from solid waste regulation. Ash is
typically determined to be non-toxic, according to
the USWAG report.
• Maine's solid waste regulations provide a separate,
more stringent set of design and operating
requirements for the disposal of coal combustion
wastes. The requirements call for lining, leachate
control, and ground-water monitoring at coal
combustion waste sites. These standards do not
apply to other solid waste disposal facilities.^
• Pennsylvania has established industry-specific
waste disposal standards. Pennsylvania's
regulations for coal combustion waste disposal
exclude the leachate control systems and liner
requirements that apply to general solid waste
disposal facilities.
4.1.2 Requirements for Coal Combustion Waste Disposal
The solid waste regulations of every state require that off-site solid
waste disposal facilities be permitted or have some form of official approval.
In order to obtain a permit, the operator of a facility must meet the
requirements that are outlined in the regulations. These regulations are
listed in Exhibit 4-1 and described below:
The regulations in 41 states require permits for
both on-site and off-site facilities. Eight
states' regulations explicitly exempt on-site
disposal from the permit requirement (Ohio, which
exempts coal combustion wastes from solid waste
regulation, is not included among the eight
states). Column 3 of Exhibit 4-1 shows whether a
permit is required for the operation of on-site and
off-site solid waste disposal facilities.
-------
4-7
Site restrictions are included in the solid waste
regulations of 30 states. Examples of site
restrictions are prohibiting solid waste disposal
facilities from violating local zoning laws,
banning placement of a new facility in a 100-year
floodplain, and prohibiting waste placement unless
there is a minimum depth to ground water. Column
4, "site restrictions," shows whether a state's
regulations include restrictions on a disposal
facility's location.
Five states' regulations (Florida, Louisiana,
Colorado, Washington, and Maine) call for all solid
waste facilities to have a clay or synthetic liner.
In addition, six states' regulations (Kentucky,
Alabama, Tennessee, Wisconsin, New York, and
Mississippi) call for the state permitting
authority to determine, on a case-by-case basis,
whether a liner is required. Column 5, "liners,"
shows whether the state's regulations include a
requirement for liners at solid waste disposal
facilities.
Leachate control systems are collection devices
placed under wastes in landfills or impoundments to
collect waste leachate. Regulations in 12 states
call for leachate control systems in all solid
waste disposal facilities; the regulations of an
additional 8 states allow leachate control systems
to be required on a case-by-case basis. Column 6,
"leachate control systems," shows whether a state's
regulations include a requirement for leachate
control systems at solid waste disposal facilities.
The solid waste regulations of 17 states call for
ground-water monitoring systems at all solid waste
disposal facilities. The regulations of an
additional 11 states specify that ground-water
monitoring may be required on a case-by-case basis.
Column 7, "ground-water monitoring," shows whether
a state's regulations include requirements for
ground-water monitoring wells at solid waste
disposal facilities.
Twenty-six states have solid waste regulations that
call for closure and post-closure care. Column 8,
"closure conditions," shows whether a state's
regulations include requirements for closure and
post-closure care for disposal facilities that have
ceased operating.
-------
4-8
• Thirteen states have solid waste regulations that
include a financial assurance requirement. Column
9, "financial assurance," shows whether a state's
regulations include a requirement that a solid
waste facility operator post a bond or participate
in a waste management fund to ensure the long-term
viability of safe disposal facilities.
The management of waste in surface impoundments, a common practice for
coal-burning utility plants, is often only indirectly addressed by state solid
waste regulations. Only six states -- Louisiana, Colorado, New York,
Washington, Oregon, and New Hampshire -- have solid waste regulations that
include requirements exclusively for surface impoundments. The solid waste
regulations of Indiana, Tennessee, Kentucky, North Carolina, Georgia, and
Missouri exclude surface impoundments and defer to state water laws for
regulatory authority. The water regulations in these states do not include any
design and operating requirements for surface impoundments. However, according
to the USWAG report, the water agencies in Missouri do regulate the design and
operation of impoundments -- requiring lining and ground-water monitoring.
According to the same report, state water agencies in Pennsylvania also
regulate the design and operation of surface impoundments.
The regulatory requirements discussed above refer to regulations explicitly
promulgated by the states for waste disposal facilities. However, state solid
and hazardous waste regulations generally allow state authorities a large
degree of discretion in designing site-by-site disposal standards that are more
strict than those specified in the solid waste regulations. Many states'
regulations allow local governments to design their own waste disposal
regulations, provided that the standards set forth in the state solid waste
regulations are enforced. Interviews with several state environmental
-------
4-9
officials and the summaries in the USWAG report indicate that in some states
coal combustion utility wastes are regulated more stringently than what is
required by the solid waste regulations. For example, the solid waste
regulations in Texas have few design and operating requirements and exempt
on-site disposal from the permit requirement. It is, however, the policy of
the state environmental agency to provide guidelines for on-site facilities as
well as off-site facilities, and to require ground-water monitoring. (For more
information on individual state regulations, see Appendix C.)
4.1.3 Summary
The regulation of coal combustion waste is generally carried out under
state solid, not hazardous, waste regulations. These solid waste regulations
vary from state to state. Based on the requirements included under each
state's solid waste regulations (as shown in Exhibit 4-1), it is difficult to
generalize about the extent of state regulation of coal combustion wastes; some
states have very stringent regulations and/or policies, such as those that
impose design and operating standards and on-site and off-site permit
requirements, whereas other states have few requirements or exempt on-site
disposal from regulation. For a number of states, requirements are determined
on a case-by-case basis. This allows the states to take climatic, geologic,
and other site-specific characteristics into account for each waste management
facility.
-------
4-10
4.2 AVAILABLE WASTE MANAGEMENT METHODS AND CURRENT PRACTICES
There are a variety of methods available for managing coal combustion
wastes. Wastes may be land managed in impoundments, landfills, mines, and
quarries or may be reused for various purposes. This section describes types
of land management of coal combustion wastes and their prevalence within the
ten EPA-designated regions of the United States. The second part of the
section reviews available waste management technology alternatives (such as
lining, leachate collection, and pre-disposal treatment), and explores how
these different technologies are currently used in different parts of the U.S.
and how these technologies have changed over time. The third part of this
section describes the potential for ocean disposal to be used to manage coal
combustion wastes. The final section describes coal combustion waste
recycling. The waste management methods discussed in this section apply to
high-volume and low-volume utility waste streams since these wastes are often
co-disposed in the same facility.^
4.2.1 Land Management of Coal Combustion Wastes
80 percent of coal combustion waste is treated, stored, and/or disposed by
means of land management, with the remaining 20 percent recycled (see Section
4.2.4). This section describes three common methods of land management
currently used for coal combustion wastes. It also presents data on use of
these management methods geographically and how land management practices have
changed over time.
-------
4-11
4.2.1.1 Types of Coal Combustion Waste Land Managenent
Three types of utility waste land management facilities are commonly used
today:7
• Surface Inpoundnents -- often called wet ponds, in
which coal combustion wastes are disposed as a
slurry or sludge, allowing solids to settle and
accumulate at the bottom of the pond.
• Landfills -- facilities used for disposing of dry
or dewatered coal combustion wastes; landfills are
typically managed like an earth-moving operation in
which the wastes are disposed in the excavated
area.
• Mines and Quarries -- abandoned pits in which wet
or dry wastes are disposed.
Surface Impoundnents
J
Surface impoundments are used to treat, store, and dispose of coal
combustion wastes. Slurried coal ash and other wastes are introduced into the
impoundment; the solids settle out and gradually accumulate at the bottom of
the pond, leaving relatively clear water at the surface, which is often
discharged to surface water. By using this method, certain types of waste
treatment, such as neutralization of acids, can be accomplished concurrently
with disposal. Exhibit 4-2 illustrates the different stages in the life of a
typical impoundment.
Historically, wet ponding has been one of the most widely used disposal
methods for coal ash and FGD wastes because it is simple and easily
implemented. In 1983, about 80 percent of the waste management facilities used
-------
4-12
EXHIBIT 4-2
TYPICAL SURFACE IMPOUNDMENT (POND) STAGES
SLURRIED =
COAt WASTE
ACTIVE POND
EFFLUENT
CLOSED STORAGE POND
(with wastes removed)
X"
(*r
CLOSED DISPOSAL F3OND
(with wastes remaining)
-------
4-13
by utilities employed some type of sedimentation treatment pond; most of these
treatment ponds were used directly as final disposal impoundments (about 45
percent of all facilities; see section 4.2.1.2). The remainder of the
impoundments were used only for treatment and temporary storage of waste, in
part to comply with the National Pollutant Discharge Elimination System
established in Section 402 of the Clean Water Act.** In recent years, some
state and local regulations concerning wet ponds have become more restrictive,
requiring liners and ground-water monitoring at these facilities. These types
of restrictions will tend to increase wet ponding costs, making it less
attractive as a disposal option.
Utilities may use a single pond or a series of ponds to facilitate the
settling of solids. Chemicals or different wastes can be added at different
points in the ponding system to produce desired chemical reactions, such as
metals precipitation or neutralization. Fly ash, bottom ash, and FGD wastes
are usually sluiced with water to the impoundments. The ash solids may be
allowed to accumulate in a pond until it is full, or the pond may be drained
and the solids dredged periodically and taken to an alternative disposal site,
such as a landfill.
Pond designs vary widely depending upon local site conditions, the
regulations that govern design of the impoundment, and whether bottom ash,
fly ash, FGD wastes, or a combination of wastes are to be disposed and/or
treated in the ponds. Because utility wastes are generated in large volumes, a
pond's total surface area may cover up to several hundred acres, and the
initial depth of a pond may be anywhere between 10 and 100 feet. The total
-------
4-14
volume of an impoundment system depends on several factors, including the total
quantity of ash to be disposed (both dry and slurried volumes), the liquid and
solid retention times, the type and degree of treatment performed, and the
desired quality of the discharge or effluent. The number of ponds in a system
and the specific uses to which each is put can also influence the total volume
required for wet ponding.
Landfills
Landfills are used to dispose of coal combustion wastes such as fly ash,
bottom ash, and FGD sludges when they are produced or after they are dredged
from surface impoundments that are used as interim treatment facilities. The
typical design of a landfill during its active stage and after closure is
depicted in Exhibit 4-3.
Landfills are constructed in a somewhat similar fashion to surface
impoundments. Excavation is required in both cases, but may be ongoing
throughout a landfill's active life because most large landfills are divided
into sections, or cells, of which only one or two may be active at any given
time. A landfill cell is defined as the area (up to several hundred square
feet) over which waste is placed to a depth ranging from one to ten feet
(industry practice refers to each layer of cells as a lift). Several lifts may
be stacked atop one another in the landfill. A cell may be open for periods
ranging from a day to a few weeks, after which it is usually covered with six
inches to several feet of soil. The waste and soils are often sprinkled with
water throughout the fill operation to mitigate potential dust problems.
-------
4-15
EXHIBIT 4-3
DIAGRAMS OF ACTIVE AND CLOSED LANDFILLS
ACTIVE LANDFILL
Cells
'LA WASTE
SOILS
CLOSED LANDFILL
-------
4-16
Excavation may be initiated in phases; for example, as one cell is filled,
another is prepared for waste placement, while yet another is being excavated.
Roads are built in to provide access for waste-hauling equipment as well as for
the earth-moving and earth-compacting equipment that prepares the waste after
it has been placed in the landfill cell. After a cell is filled, the access
road frequently becomes part of the containment system as a wall separating one
cell from the next.
Landfilling of coal ash and FGD sludges has increased over the past few
years as the costs of wet ponding have increased (see section 4.2.1.2). Most
electric utilities that use landfills currently dispose their high-volume
wastes in Subtitle D (non-hazardous waste) landfills. Landfills in compliance
with RCRA Subtitle C standards may be used occasionally for disposal of small
quantities of hazardous waste.
Mine and Quarry Disposal
Some utilities use abandoned mines or quarries as ash and FGD sludge
disposal sites. Abandoned mine disposal includes the use of mine shafts as
well as strip-mined areas. Wastes disposed to abandoned mine shafts can be
dumped into the shaft or carefully placed within the mine to fill the areas
remaining after the coal or other material has been removed. Strip-mined areas
may be filled like a landfill. Regulatory agencies may consider wastes
disposed in this manner to pose less of a threat than the runoff and potential
12
contamination from the abandoned mine itself. In some cases, a chemical
reaction between the waste and the mine runoff and leachate might actually
-------
4-17
reduce the toxicity of the runoff (for example, an alkaline sludge could
neutralize acid mine drainage). However, the likelihood of such a mitigative
effect is very site-specific and would not necessarily occur uniformly
throughout any given mine disposal site.
In a few cases, utility wastes, particularly acidic wastes, have been
disposed in quarries. Limestone quarries are considered the best setting for
this type of disposal because they provide a natural acid buffering capacity
and the capacity for the metals present in the waste to be attenuated by
chemically combining with materials.in the quarry. Quarry disposal of wastes
works well for lime or limestone slurry wastes, which harden to form a
concrete-type floor at the bottom of the quarry, thereby plugging any potential
leakage paths. The probability of achieving success with this method must be
evaluated on a case-by-case basis prior to its use.
i
4.2.1.2 Prevalence of Various Land Management Methods
Use of the waste management methods described above can vary from plant to
plant and, in some cases, among individual generating units at a single power
plant. This section presents information on how these utility waste management
methods are employed nationwide and within EPA regions. It also discusses how
these utility waste management methods have changed over time. The emphasis is
on surface impoundments and landfills because these two waste management
methods are the most commonly-used utility waste management practices in the
United States.
-------
4-18
The information presented in this section was derived from the Edison
Electric Institute Power Statistics Database, currently maintained by the
Utility Data Institute. This database contains information on power plant
characteristics for all electric utility generating plants in the U.S. These
data include number of power plants, number of generating units at each power
plant site, type of fuel, plant capacity, as well as other information. It
also contains information on the type of waste management methods currently
used by power plants throughout the country, including type of disposal
facility and whether the wastes were disposed at the power plant or in off-site
facilities. Because each generating unit at a power plant may have its own
waste management practice, the database gives waste disposal information for
all generating units.
Data were not available for all generating units in the database. When
information is not available, the extent of data coverage is indicated. In
some instances the number of generating units on which no information was
available was quite high. Although EPA recognizes the possibility of some
statistical bias due to lack of data on some generating units, this database is
the most comprehensive source available on utility waste management practices.
EPA has no reason to believe that such bias is serious enough to call into
question conclusions drawn in this analysis.
Exhibit 4-4 displays, for each of the ten EPA regions of the U.S. (see
Exhibit 2-4 for a map of these regions), the number of generating units whose
waste is managed in surface impoundments, in landfills, or mines. The most
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4-19
EXHIBIT 4-4
UTILITY HASTE MANAGEMENT FACILITIES BY EPA REGION
(number of generating units) a/
EPA Region
Surface
Impoundments
Other/
Landfills Minefills Unknown
Total
1
2
3
4
5
6
7
8
9
10
1
0
33
195
160
19
55
9
11
0
10
22
103
55
198
48
61
56
16
9
0
0
1
0
4
2
1
23
0
2
U.S. Total 483
578
33
7
17
7
45
130
18
32
21
7
0
284
18
39
144
295
492
87
149
109
34
11
13~78
Source: Utility Data Institute Power Statistics Database
a/ The data are provided by generating unit because each generating unit at
a power plant may have its own management facility. A generating unit
typically refers to a single boiler, turbine, and generator set at a
power plant. A power plant may have more than one generating unit at
the site. For the database used here, data were available for 1,378
generating units located at 514 power plants.
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4-20
common types of facilities used by the electric utility industry are
surface impoundments and landfills:
• Landfills are the most common type of disposal facility
used. Of the 1,094 generating units for which data were
available (for 284 units,type of waste disposal method
was unknown), 578 units (about 53 percent) used
landfills for waste disposal. Landfills are used
throughout the United States, with the largest number
(over one-half of all landfills) located in the high
coal-consuming, industrialized areas of the East and
Midwest (Regions 3 and 5).
• Surface impoundments are also commonly used;
approximately 44 percent of the generating units (483
out of 1,094) used this type of management facility. Of
the 483 generating units that place wastes in surface
impoundments, nearly 75 percent are located in Regions 4
and 5. (In the past, access to abundant, inexpensive
supplies of water in these Regions often made it
economical to use this management option.)
• Mine disposal is used for about three percent of all
generating units (33 units out of 1,094). This disposal
technique is used most frequently in the western U.S.,
particularly Region 8. Power plants in this area are
often located at or near the coal mine that is supplying
the plant. Since the coal mine is located nearby,
disposal of waste in the mine is often economic.
When managing coal combustion wastes, electric utilities may treat,
store, or dispose of the wastes at the power plant or at facilities
located off-site. EPA could not determine from the data available how far
the wastes are transported when managed off-site, although the cost of
transporting the wastes would tend to encourage disposal near the power
plant. A summary of industry practices is provided in Exhibit 4-5, which
shows for each EPA region, by type of facility, whether the wastes are
managed on-site or off-site.
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4-21
EXHIBIT 4-5
LOCATION OF UTILITY WASTE MANAGEMENT FACILITIES:
ON-SITE VERSUS OFF-SITE
(number of generating units)*
EPA Region
On-Site
Off-Site
Unknown
Total
Surface Impoundments
Landfills
Other/Unknown
Total
1
0
0
0
8
0
0
2
Surface Impoundments
Landfills
0 the r/Unknown
Total
0
3
0
0
18
0
18
0
1
J2
18
Surface Impoundments
Landfills
0 the r/Unknown
Total
5
4
_7
16
144
Surface Impoundments
Landfills
0 the r/Unknown
Total
4
8
0
12
Surface Impoundments
Landfills
0 the r/Unknown
Total
141
41
0
182
5
140
6
151
14
17
128
159
160
198
J.34
492
Surface Impoundments 18
Landfills 36
Other/Unknown 0
Total 54
0
3
19
48
_20
87
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4-22
EXHIBIT 4-5 (continued)
LOCATION OF UTILITY WASTE MANAGEMENT FACILITIES:
ON-SITE VERSUS OFF-SITE
(number of generating units)*
EPA Region
On-Site
Off-Site
Unknown
Total
Surface Impoundments 42
Landfills 20
Other/Unknown 7
Total 69
13
15
25
53
Surface Impoundments 6
Landfills 28
Other/Unknown 2
Total 36
Surface Impoundments 9
Landfills 16
Other/Unknown 0
Total 25
2
0
0
0
_7
7
10
Surface Impoundments
Landfills
Other/Unknown
Total
0
5
0
0
4
_2
6
0
0
_0
0
Total U.S.
Surface Impoundments
Landfills
Other/Unknown
Total
428
237
__9
674
16
255
39
310
39
86 .
269
394
483
578
_317
1378
The data are provided by generating unit because each generating unit
at a power plant may have its own management facility. A generating
unit typically refers to a single boiler, turbine, and generator set
at a power plant. A power plant may have more than one generating
unit at the site. For the database used here, data were available for
1,378 generating units located at 514 power plants.
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4-23
Nearly 70 percent of all generating units in the U.S.
manage their coal combustion wastes on-site (based on
information for 984 units, 674 units dispose on-site).
About two-thirds of the on-site facilities are surface
impoundments; most of the other on-site facilities are
landfills.
Landfills are used for about 95 percent of all
off-site disposal in the U.S. This is not surprising
considering that surface impoundments are typically
used when wastes are transported as a wet slurry; the
cost of disposal could become prohibitive if a utility
transported the slurry off-site.
Coal combustion waste management practices also differ
by region:
In the Northeast (Regions 1 and 2), where
few coal-fired generating units are located,
management tends to occur off-site in
landfills.
The highest percentage of on-site management
is found in the South (Region 4), where
about 95 percent of all units manage their
waste on-site (212 units, based on
information from 224 units). On-site
management is common because utilities in
this region often use surface impoundments,
which are typically located at the power
plant.
In the Rockies and northern Great Plains
area (Region 8), most of the off-site
disposal (23 of 36 units) occurs in mines
that are generally adjacent to the power
plant.
These trends in utility waste management methods have been changing
in recent years, with a shift towards greater use of disposal in landfills
located on-site. For example, for generating units built since 1975,
nearly 65 percent currently dispose of coal combustion wastes in
landfills, compared with just over 50 percent for units constructed before
1975. Similarly, over 80 percent of all units built since 1975 use
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4-24
on-site management facilities, compared with just under 65 percent of all
units built before 1975 that manage wastes on-site.
4.2.2 Alternative Waste Management Technologies
Section 4.2.1 described the types of land management facilities used
by utilities and patterns of use. This section describes the additional
technologies that utilities may employ at the facilities described above
in order to reduce potential environmental risk associated with waste
management. For example, some utilities use liner systems for
impoundments and landfills, leachate collection systems, and ground-water
monitoring systems to control and monitor waste constituent migration.
Pre-treatment technologies, by altering physical and chemical properties,
can also render wastes more amenable for certain disposal methods. This
section also presents data on the prevalence of these various
technologies. The alternative technologies discussed in this section,
although not necessarily the same as technologies required for RCRA
Subtitle C facilities, may be required by current state regulations
(described in Section 4.1) and could be more widely used in the future to
further mitigate potential environmental impacts at utility waste disposal
sites not currently employing these technologies.
4.2.2.1 Installation of Liners
Until recently, most surface impoundments and landfills used for
utility waste management have been simple, unlined systems. Lining is
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4-25
becoming a more common practice, however, as concern over potential
ground-water contamination from "leaky ponds" and, to a lesser extent,
from landfills has increased. Some waste management facilities use one or
more impermeable synthetic liners; some are lined with one or more layers
14
of low-permeable clay ; and some use a combination of clay and synthetic
liners.
Synthetic Liners
Several dozen manufacturers and distributors supply impermeable
synthetic liners. The most common materials of construction for these
liners include polyvinyl chloride (PVC) and high-density polyethylene
(HDPE), although several other impermeable synthetics have also been used.
Liners may be reinforced with fibers to increase strength and decrease the
likelihood of punctures. The liners can be purchased in standard
thicknesses that range from 10 mils to 100 mils, or can be made to
order. Most liner installations will include protective geotextile fabric
above and/or below the impermeable synthetic liner to minimize further the
potential for puncture.
Preparation of the site prior to installation of a synthetic liner is
similar to that which occurs before clay liner construction. However,
more care must be taken to smooth out the surfaces to eliminate any peaks
and cavities on the disposal facility floor that could cause a puncture of
the liner material. Consequently, surface preparation costs are greater
than those for clay liners. Excavation costs are usually less, however,
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4-26
because the thinner synthetic liners allow shallower excavation (i.e., the
additional excavation required to install a clay liner that is several
feet thick can be avoided if a much thinner synthetic liner is installed).
The liner itself, which comes rolled or folded in large pieces, is
laid in the field and sealed along the seams by heat or solvent fusion
techniques; the seams may be field tested at spot checkpoints. The liner
is usually covered with a foot or more of soil to protect it from puncture
and to keep it in place during construction of the disposal facility. The
edges of the liner at the tops of the dikes or landfill cell walls must be
well secured to prevent the liner from pulling out and shifting due to the
mass of the wastes placed in the impoundment or landfill. Some facilities
are double lined and often contain a leachate collection system located in
a soil or sand layer between the two liners.
Among the limitations to the use of synthetic liners is their
susceptibility to tear and puncture. This is of particular concern in a
single-lined impoundment because of the opportunity for liquids to seep
through a single tear. Synthetic liners are also susceptible to
degradation by certain waste materials. Acidic wastes, for example, can
degrade some synthetic liner materials. As with clay liners, waste/liner
compatibility testing should be performed to ensure that the disposed
wastes will not weaken or permeate the liner. Additionally, because the
seams of a synthetic liner are frequently weaker than the liner itself,
they may pull apart under stress (e.g., large mass loadings or wave
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4-27
action). Finally, dredging of synthetically-lined impoundments must be
done cautiously, sometimes at very significant expense.
Synthetic liners, unlike clay liners (described below), are
impermeable. Another advantage is the ease of repairing an exposed,
damaged impoundment liner. A tear or puncture can be patched and seamed,
and an impoundment put back into service, relatively quickly. (To repair
subsurface damage, however, the impoundment must be wholly or partially
drained.) Another advantage to using synthetic liners is that because of
manufacturer quality control, a facility owner can be fairly certain that
each liner sheet is as impermeable as the next. Clay is expensive to
transport and in areas of the country where clay soils are scarce, a
synthetic liner system may prove to be the less expensive option.
Clay Liners
The installation of a clay liner in a surface impoundment or landfill
entails several steps. First, the site must be excavated or graded to a
level below the design elevation of the facility floor. Many facilities
take advantage of natural low areas or abandoned ponds to minimize
excavation costs. The excavated earth can be used to build up the dike
walls for the impoundment or to build containing berms within the
landfill. Occasionally, soil must be brought to the construction site to
raise the dikes to the design height.
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4-28
Once the floor and dikes or berms have been prepared, the clay liner
is laid in 6- to 9-inch lifts; its final thickness will be between 1 foot
and 8 feet. Each lift is individually compacted before the next one is
laid, thereby providing effective compaction and minimizing leakage
potential. Field testing of the clay for permeability and other pertinent
characteristics is sometimes performed during construction to provide
quality assurance. Before the impoundment or landfill can be used, the
liner is visually inspected for flaws; non-contaminated water may also be
piped to the pond to assure that the liner is sufficiently impermeable.
One of the primary concerns about the use of clay liners is whether
the entire clay liner meets thickness and permeability requirements. If
weather conditions during liner construction are arid and hot, the liner
may dry out and crack, causing localized areas of leakage. If conditions
are wet or the clay is too moist, clay compaction may never be sufficient
to achieve the necessary low permeability. The clays used as liner
materials vary in the degree to which they are compatible with the wastes
placed in the facility. Laboratory tests, in which the proposed liner
material is exposed to the wastes intended for management, should be
conducted for each facility to ensure that components of the waste
material will not unduly alter the permeability of the clay used as liner
material. If the chemical characteristics of the generated waste were to
change over time, then the tests would need to be repeated to determine
what effect the altered waste stream would have on the clay liner.
-------
4-29
An advantage of clay liners is their potential for chemical,
particularly cation, attenuation. The chemical structure of clay allows
its use as an exchange site for metallic cations and other ions that might
gradually seep out of the facility. Such exchange further reduces the
opportunities for migration of waste constituents to the ground water.
For facilities with fairly ready access to clays, the capital and
construction costs associated with the use of a clay liner, even one that
is several feet thick, may he substantially lower than those associated
with the use of a synthetic liner.
Composite Liners
Many waste management facilities in industries currently subject to
RCRA Subtitle C requirements are installing liner systems that combine
both clay liner and synthetic liner technologies. Most commonly, an
impoundment or landfill will be lined with 2-4 feet of impermeable clay,
which is then prepared for placement of a synthetic liner. The synthetic
liner may be covered with 1-2 feet of sand to serve as drainage for a leak
detection system. Some facilities may then add another 1- to 2-foot layer
of clay, which is again prepared for placement of the upper synthetic
liner. In landfills, another leachate collection system is usually placed
above this upper liner.
The composite synthetic/clay liner system offers a combination of
advantages over single-material liners. A composite liner has some of the
advantages provided by synthetic liners, such as factory quality control
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4-30
and ease of repair (for the upper liner), as well as the advantage of
clay's propensity for attenuating escaped ions. Furthermore, use of
multiple-liner materials reduces the likelihood that waste material will
leak into the ground water because of chemical incompatibility between a
waste and a single liner material. In general, the more layers of
impermeable liner material that are used, the more efficient containment
of liquids will be, thus reducing the likelihood of a release of waste
material.
The biggest drawback of the composite synthetic/clay liner system is
the cost of installation. Utility waste landfills are very large (up to
100 acres or more), and a liner large enough to cover such a area could be
very expensive. In areas where labor costs are high and clay is
unavailable locally and must be transported long distances, these costs
would be magnified.
Frequency of Liner Use
Some electric utilities have installed liners to retard the flow of
leachate from the waste disposal facility to the surrounding area.
Exhibit 4-6 shows the extent to which electric utilities are currently
using this technology.
About 25 percent of all generating units in the U.S.
for which data were available (139 of 580 units) have
installed some type of liner. There are no available
data on the material used to construct these liners or
if more than one liner has been installed at the
disposal facility.
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4-31
EXHIBIT 4-6
INSTALLATION OF LINERS FOR LEACHATE CONTROL
AT UTILITY WASTE MANAGEMENT FACILITIES
(number of generating units)*
EPA Region Unlined Lined Unknown
1
Surface Impoundments 001
Landfills 0 0 10
Other/Unknown 0 0 ~]_
Total 0 0 18
2
Surface Impoundments 0000
Landfills 1-14 7 22
Other/Unknown 0 0 17 17
Total 1 14 24 39
3
Surface Impoundments 17 2
Landfills 17 7
Other/Unknown 0 0
Total 34 9
4
Surface Impoundments 153 3
Landfills 14 7
Other/Unknown 0 0
Total 167 10
5
Surface Impoundments 90 20 50 160
Landfills 64 31 103 198
Other/Unknown 0 4 130 134
Total 154 55 283 492
6
Surface Impoundments 7 7 5 19
Landfills 11 17 20 48
Other/Unknown 0 0 20 20
Total 18 24 45 87
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4-32
EXHIBIT 4-6 (continued)
INSTALLATION OF LINERS FOR LEACHATE CONTROL
AT UTILITY WASTE MANAGEMENT FACILITIES
(number of generating units)*
EPA Region
Unlined
Lined
Unknown
Total
Surface Impoundments
Landfills
Other/Unknown
Total
4
4
_0
8
21
50
_2Z
98
Surface Impoundments
Landfills
Other/Unknown
Total
0
6
_Q
6
5
38
44
87
Surface Impoundments
Landfills
Other/Unknown
Total
2
2
10
Surface Impoundments
Landfills
0 the r/Unknown
Total
0
4
0
0
0
_0
0
0
5
0
9
_2
11
Total U.S.
Surface Impoundments 303
Landfills 132
Other/Unknown 6
Total 441
45
90
_A
139
135
356
307
798
483
578
_312
1378
The data are provided by generating unit because each generating unit
at a power plant may have its own waste management facility. A
generating unit typically refers to a single boiler, turbine, and
generator set at a power plant. A power plant may have more than one
generating unit at the site. For the database used here, data were
available for 1378 generating units located at 514 power plants.
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4-33
Based on the information available, landfills are more
likely to be lined than surface impoundments. Of the
222 generating units that use landfills and that
indicated whether the disposal facility was lined or
not, about 40 percent (90 units) have lined disposal
facilities. Only 13 percent of surface impoundments
have liners installed (based on information from 348
of the 483 units).
The information in Exhibit 4-6 should be interpreted cautiously since
data were available for only 42 percent of the population (580 units of
1,378 units). One of the reasons this information is unavailable is due
to the number of electric utilities that dispose of coal combustion wastes
off-site. In many of these cases, the utility does not know whether the
off-site disposal facility is lined or not since the utility does not run
the disposal operation.
Liner use has been increasing in recent years. Before 1975, less than
20 percent of all generating units managed their coal combustion wastes in
lined facilities. For units constructed since 1975, however, this
percentage has increased to over 40 percent. The proportion of lined
management facilities is particularly high at generating units that
produce FGD sludge; since 1975 about 60 percent of management facilities
containing these wastes have been lined.
4.2.2.2 Leachate Collection and Ground-Water Monitoring
Any lined management facility may have a leachate collection system
and any facility (lined or unlined) may be equipped with a ground-water
monitoring system. Leachate collection systems are used to prevent the
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4-34
migration of contamination from a landfill or impoundment. Both systems
can be used to monitor the rate and extent of contaminant migration. The
design and placement of ground-water monitoring and leachate collection
systems should take into account the manner in which a landfill or
impoundment might potentially interfere with natural ground-water flow and
usage patterns.
In surface impoundments, the leachate collection system(s) can be
placed below the entire liner system or it can be placed between any two
liners. Leachate collection systems typically consist of a drainage media
(coarse sand and/or gravel) and perforated pipes (called riser pipes) that
slope toward a collection sump. The collected leachate is pumped out via
these riser pipes to the surface for treatment and/or disposal. If the
riser pipes through which the leachate is pumped perforate the synthetic
or clay liner, tight seals are necessary to ensure that the leachate does
not escape through the perforation.
In landfills, leachate control systems can be installed below all
liners (this is usually called a pressure relief system), between liners
(the inter-liner leachate control system), and/or above the upper liner.
The floors of a landfill cell are designed to slope to the leachate
collection sumps and are usually covered with a drainage media such as
sand or gravel. Each leachate control system has its own collection sump,
which is emptied through riser pipes so that the leachate can be treated
or disposed appropriately. As with impoundment liner systems, riser
pipes, if they pierce the liners, must be sealed to prevent leakage.
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4-35
Ground-water monitoring wells are placed at strategic locations to
facilitate early detection of any contaminants that escape the facility
and migrate to the ground water. The design and placement of the
monitoring wells is based on site-specific hydrogeological assessments,
soil chemistry, specific regulatory directives, and other physical and
chemical factors. Downgradient wells typically are used to monitor the
extent of contamination arising from a facility, and upgradient
"background" wells are installed to serve as controls.
Most newer utility waste management facilities have ground-water
monitoring systems, and many also have leachate collection systems. In
other industries, permitted facilities subject to Subtitle C regulations
are required by law to have both ground-water monitoring and leachate
collection systems. For utility waste disposal sites, it is estimated
that about 15 percent of all facilities have leachate collection systems
and about 35 percent have ground-water monitoring systems.
4.2.2.3 Pre-disposal Treatment
Facilities employ a variety of waste treatment processes to alter the
physical or chemical characteristics of wastes so that they will be
compatible with the disposal method used. Treatment methods may also be
employed to comply with the effluent limitations established under the
Clean Water Act.
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4-36
Sludge Devatering
The most commonly used pre-disposal treatment process is sludge
dewatering. This process is often necessary so that the sludge can be
more easily handled and of a consistency suitable for landfill disposal.
This procedure can also be used for any wet coal ash or combined coal
ash/FGD sludge wastes. Most frequently, sludge dewatering is accomplished
by sedimentation of the suspended solids in surface impoundments or, in
some cases, in clarification tanks. This type of dewatering is carried
18
out at 80 percent of the utilities.
After the waste solids have had sufficient time to settle, the water
layer is drawn off the tank or impoundment and is either discharged
subject to National Pollutant Discharge Elimination System (NPDES) permits
or recycled back to the plant as sluice or cooling water. The sludge
layer containing the solid ash and other particles is allowed to
accumulate for several months (or longer), and is finally dredged after
the pond is drained. With this process, the solids content (initially
between 5 and 15 percent by weight) can be increased to between 30 and 60
percent. The final solids content in the sludge is affected by the
sedimentation impoundment or tank design, the initial solids content, the
liquid and solids retention times, and the physical and chemical
characteristics of the solid particles.
Even after dewatering, the settled sludges often have a mud-like
consistency and still contain so much free liquid that they are
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4-37
inappropriate for landfill disposal. In this case, the sludge may be
further dewatered by natural or mechanical processes. In arid and
semi-arid areas, the sludges may be retained in the impoundments until
natural evaporation removes still more water. Sludges may also be placed
on drying beds made of screens, sand, or other drainage media designed to
allow water to percolate out by gravity, while the solids are retained.
In mechanical sludge dewatering, belt or vacuum filters, filter presses,
thermal dryers, or other processes are used. Ten percent of the utilities
19
use some sort of filtration to dewater sludges. For high-volume
sludges, however, mechanical dewatering equipment may be expensive and
inconvenient to operate.
Reagent Addition
Most FGD sludges and some other wet sludges can be rendered less
chemically reactive and/or more structurally stable by adding
solidification, stabilization, or fixation reagents. This practice is not
widespread; less than 10 percent of the utilities report using these
20
processes. Solidification agents, such as sawdust or soil, absorb the
liquid in a sludge but do not chemically react with the sludge.
Stabilization and fixation reagents chemically react with some portion of
the sludge -- either the water, the dissolved solids, the particulate
solids, or some combination of the three-- and, in some cases, may render
potentially hazardous material non-hazardous as a result. All of these
processes result in an increased volume of waste that contains less free
water and is easier to handle than the original waste stream. An
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4-38
additional benefit is an increase in the structural integrity (shear
stress and load-bearing potential; see Chapter Three for discussion of
these characteristics) of the waste material so that it may be placed in
deeper disposal facilities and covered with more material.
Low-volune Waste Treatment
The major methods available for low-volume waste management and
treatment include:
• co-disposal;
• contract disposal;
• evaporation;
• incineration;
• neutralization;
• physical/chemical treatment; and
• recycle/reuse.
The type of waste management method used most often depends on the
type of low-volume waste stream. Exhibit 4-7 shows the treatment process
commonly used for each low volume waste stream. Each of these treatment
processes is discussed briefly below.
-------
4-39
EXHIBIT 4-7
SUMMARY OF CURRENT HANDLING, TREATMENT AND
DISPOSAL OF LOW VOLUME BASTES
Low Volume
Waste
Treatment
Predominant Disposal
Method
Waterside If organic chelating agents are used,
Cleaning this stream can be incinerated. If
Waste acids are used, the stream is often
neutralized and precipitated with
lime and flocculants.
Co-disposal with high
volume wastes in pond
or landfill following
treatment.
Disposal by paid
contractor.
Fireside
Cleaning
Waste
Air Preheater
Cleaning
Waste
Coal Pile
Runoff
Sometimes neutralized and precipi-
tated. For coal-fired plants most
often diverted to ash ponds with-
out treatment. If metals content
is high, chemical coagulation and
settling is used.
Settling in ash pond; neutralized
and coagulated if combined with
other streams before treatment.
Co-disposal with high
volume wastes in pond
without treatment.
Ponding following
treatment.
1. Co-disposal in pond
without treatment.
2. Ponding with treat-
ment .
Neutralized by diverting to 1. Co-disposal of
alkaline ash pond. Fine coal material sludge in landfill
caught in perimeter ditch is often after treatment.
diverted back to coal pile. 2. Co-disposal in ash
pond.
Wastewater
Treatment
Make-up Water
Treatment
Cooling Tower
Basin Sludge
Usually ponded with ash or as a
separate waste. Sometimes solids
co-disposed with bottom ash.
usually co-disposed in ash pond.
Very little survey or literature
information; infrequent stream.
Sludge comingled with wastewater
treatment sludge.
1. Ponding
2. Landfilling
1. Co-disposal in pond.
1. Landfilling
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4-40
EXHIBIT 4-7 (Continued)
SUMMARY OF CURRENT HANDLING, TREATMENT AND
DISPOSAL OF LOW VOLUME BASTES
Low Volume
Waste
Treatment
Predominant Disposal
Method
Demineralizer
Regenerants
Pyrite Wastes
Equalized in tanks, then comingled
into ash ponds.
Disposed in landfills with bottom
ash or diverted to ash pond
1. Ponding
1. Ponding
2. Landfilling
Source: EPRI, Characterization of Utility Low-Volume Wastes, prepared by
Radian Corporation, Austin, Texas, May 1985.
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Co-Disposal
Co-disposal of low-volume wastes with high-volume wastes into landfills and
surface impoundments is commonly used in the utility industry. A January 1981
EPA letter (the Dietrich memorandum) currently allows co-disposal of low-volume
21
wastes with high-volume wastes in landfills and surface impoundments. In a
1985 EPRI study on low-volume waste management, about three-fourths of the power
plants interviewed co-disposed some low-volume wastes in a surface impoundment or
22
landfill. The amount of treatment necessary before co-disposal varies with the
waste stream. Solid wastes are typically disposed directly into the waste
management facility. Liquid wastes are often routed to an interim treatment
surface impoundment. Once in the surface impoundment, evaporation occurs and the
remaining sludge is landfilled. If the liquid waste is chemically treated before
ponding, heavy metals are often removed in a treatment facility; the treated
liquid may then be reused or diverted to a surface impoundment while the residue
from the treatment process is disposed in a landfill.
Contract Disposal
Many utilities hire outside contractors to treat and dispose of low-volume
wastes. Contract disposal is most common for low-volume waste streams produced
intermittently that are difficult to treat on-site. For example, hydrochloric
acid boiler cleaning waste typically requires neutralization with high dosages of
a caustic material. Construction of an on-site treatment system for this waste
stream requires a large capital investment, although boiler cleaning wastes are
produced only over a few hours once every two to five years. As a result, some
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utilities (7 of 22 power plants surveyed in EPRI's 1985 study) employ outside
23
contractors when boiler cleaning is required. The treated boiler cleaning
waste is then co-disposed on-site or disposed of off-site.
Contract disposal is also a common waste management practice for
spent ion exchange resin. In EPRI's 1985 study, of five power plants
responding, four plants hauled these wastes off-site while one power plant
24
co-disposed the waste on-site.
Evaporation
Evaporation ponds are used to dispose of high concentration, low-volume
liquid wastes. Prior to final disposal, liquid wastes are diverted to an
evaporation pond, generally shallow ponds with a large surface area. The
sludge remaining after most of the water evaporates is then dredged and '
disposed of in a landfill.
Incineration
Incineration of low-volume wastes includes injection into the boiler or
mechanical evaporation. This method of disposal is most common with organic
cleaning wastes (Ethylenediamide tetracedic acid (EDTA) or citrate waste).
25
A 1987 EPRI study examined the effect of incinerating EDTA and citrate
wastes in a utility boiler. The findings showed that the additional metals
contributed were minimal compared to the amount contributed by the coal.
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Two of the twenty-two power plants interviewed in EPRI's 1985 study use this
r\f
method of waste disposal.
Neutralization
Acidic or alkaline wastes can be treated with either strong bases or
acids, respectively, to produce a near neutral stream. For example,
wastewaters, demineralizer regenerant, and coal pile runoff must typically
be within a pH range of 6.0 to 9.0 to meet Clean Water Act (CWA) and
National Pollutant Discharge Elimination System (NPDES) limits.
Neutralization can be used to achieve these levels. Similarly, hydrochloric
acid boiler cleaning waste, which may have a ph below 2.0, can undergo
neutralization to raise the ph above RCRA corrosivity guidelines (ph values
27
between 2.0 and 12.5 are not considered corrosive under RCRA).
Other Physical/Chemical Treatment
Physical and/or chemical treatment systems can be used for reducing and
removing dissolved and suspended contaminants from aqueous streams. The
most prevalent treatments incorporate pH adjustment (i.e., addition of basic
or acidic materials), precipitation (i.e., separating solids from solution
or suspension), flocculation (i.e., aggregation of fine suspended
particles), clarification (i.e., separating liquid and suspended solids) and
filtration (i.e., trapping suspended solids). The continuous waste streams
are treated to allowable levels. Boiler chemical cleaning and fireside
cleaning wastes require higher reagent doses and occasionally additional
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processing to meet Clean Water Act (CWA) and National Pollutant Discharge
Elimination System (NPDES) discharge limits for metals. Ten of the 15 power
plants questioned in EPRI's 1985 study route boiler cleaning wastes through
28
physical and/or chemical treatment systems prior to discharge.
Reuse
Reuse is a common practice for many water-based low volume wastes,
especially in water-limited regions of the country. For example, less
contaminated streams (boiler blowdown, yard drains) can be used without
treatment in cooling towers, ash handling systems, and flue gas
desulfurization systems. Other wastes, such as boiler cleaning wastes and
coal pile runoff, cannot easily be reused because they require extensive
treatment prior to reuse. If a power plant does decide to treat these waste
streams, the liquid portion of treated waste may be reused while the sludges
produced during treatment are typically landfilled.
4.2.3 Ocean Disposal
Many different types of wastes, including industrial and municipal
wastes, have been disposed at sea in the past, although the use of this
method for disposing coal combustion wastes is only in the research and
development phase. Typically, industrial and municipal wastes are shipped
out to sea and disposed at any of several regulated dump sites, which are
located anywhere from 20 miles to over 100 miles off the shore line.
Another method of ocean disposal (seldom used, however) involves pumping or
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gravity feeding wastes through a pipeline that feeds directly from the
land-based waste generating site or dump site into the ocean. When the
wastes reach the final oceanic disposal site, they either dissolve and
disperse or form a manmade reef.
The 1972 Marine Protection Research and Sanctuaries Act (MPRSA), EPA
29
regulations regarding ocean disposal, and the London Dumping Convention
currently regulate ocean dumping with respect to the solids content, metals
content, and toxicity of wastes considered for this method of disposal.
4.2.4 Waste Utilization and Recovery of Various Waste By-Products
Although the majority of the waste generated by coal-fired electric
utilities is land disposed, a substantial percentage is recovered and
reused. From 1970 to 1980, an average of 18 percent of all coal ash
generated annually was utilized; from 1980 to 1985, the average coal ash
utilization rate exceeded 22 percent, with utilization in 1985 over 27
percent of all coal ash produced. The amount of FGD sludge waste utilized
is less than one percent of the total volume of FGD waste generated,
although more efficient FGD sludge recovery and utilization processes
currently being developed by the utility industry may increase this use.
The combined utilization rate for all high-volume coal combustion wastes,
i.e., fly ash, bottom ash, boiler slag, and FGD sludge, was about 21 percent
in 1985.
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The recovery processes are usually performed at the power plant. Use of
the recycled waste may occur on-site or the recycled product may be sold for
off-site use. Like any industrial product, the wastes to be recycled may be
accumulated on-site prior to sale and delivery.
The recovery processes and the uses for waste by-products are numerous
and quite varied:
Bottom ash currently has the highest rate of utilization
at 33 percent. It is used as blasting grit, road and
construction fill material, for roofing granules, and has
other miscellaneous uses.
Fly ash utilization is substantial. About 17 percent of
fly ash production is used for concrete admixture, cement
additives, grouting, road and construction fill material,
and for miscellaneous other uses.
FGD wastes are not heavily utilized in the industry (less
than 1 percent), but some utilities have the capacity to
recover sulfur,_sulfuric acid, or other sulfur products
from the waste.
Some low-volume wastes (particularly solvents) that are
segregated from the high-volume waste streams are
potentially recoverable or available for other uses.
Numerous other recovery processes and utilization
techniques are currently in the research and development
phase. At this time, however, the Agency is unaware of
any advances in recovery processes that will significantly
change the proportion of coal combustion wastes that are
disposed.
Coal Ash
There are a variety of different options currently available for the
utilization of fly ash, bottom ash, and boiler slag from coal-fired electric
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utilities. All types of coal ash are appropriate for use as construction
materials, as cement additives, and for several other uses. Coal ash
utilization is primarily centered in the southeast and north central United
States.35
Most fly ash and some bottom ash exhibit pozzolanic (bonding) properties
-- that is, the dried materials are cohesive and exhibit high shear strength
and compressive load-bearing characteristics. These properties make ash an
appropriate substitute for portland cement for many applications, including
concrete production, standard cement production, and for special uses such
as for the production of road base cement or even grouting.
Cement made with fly ash may be preferable to regular portland cement
for some applications. One of the key benefits is the absence of heat
release while the concrete or cement mixture cures; this absence of heat
generation means that the design structural strength is more likely to be
achieved. However, the use of fly ash and bottom ash as cement substitutes
is limited because of the wide variability in ash composition, even in ash
originating from the same coal supply or utility. The presence of metals in
the ash can reduce the structural integrity of the final concrete by
preventing the necessary chemical bonding. The presence of large quantities
of sulfates or nitrates will also interfere with the pozzolanic properties.
Because of this bonding interference, fly ash and bottom ash are thought to
be able to replace no more than 20 percent of the cement used (or about 15
million tons of ash annually). Improvements in utilization techniques may
reduce the bonding interference and increase the reutilization potential of
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fly ash; however, the Agency is unaware of technical advances at this time
that will allow substantially greater utilization in cement applications.
Fly ash and bottom ash are also commonly used as high-volume fill for
various construction materials. The pozzolanic properties of these
materials facilitate soil stabilization, making them desirable as fill
additives. Coal ash has been used as fill in asphalt, road bases, parking
lots, housing developments, embankments, and to line on-site disposal
facilities at the utilities. In the future, numerous other construction
applications may use coal ash as fill, particularly if the ash is available
at lower cost than standard fill materials. However, the use of ash as fill
is limited somewhat because of the variability of the ash composition.
Bottom ash and boiler slag have been used as substitutes for sand in
sand-blasting operations and road de-icing. Ash and slag particles are J
similar in size and density to sand particles. In areas where sand is
costly to transport, these wastes can be economical substitutes. Ash is
less corrosive than salt and could therefore be a preferable de-icing
material, although in some municipalities the use of ash for de-icing has
been prohibited due to public concern over aesthetics (e.g., ash residue on
cars).
A variety of minor uses for fly ash and bottom ash have been considered,
some of which have already been implemented at a small number of utilities.
For example, bottom ash has been used for granular roofing material. Fly
ash has been used by some facilities as a stabilization reagent for acidic
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aqueous or semi-solid hazardous wastes: the high-pH fly ash reacts with
other, low-pH waste to generate a neutral solution and to simultaneously
precipitate dissolved metals as oxides and hydroxides. Because the fly ash
exhibits pozzolanic properties, the ultimate waste product, when dried,
often resembles concrete. The metals from the original waste stream are
usually so strongly bound within the chemical structure of the final waste
product that they will not leach out, even under acidic conditions.
Because fly ash has some of the same physical characteristics as a silty
clay, fly ash may be used as an additive to clay liners for waste management
facilities, particularly for impoundments. Fly ash is cohesive and fairly
impermeable when properly compacted, and mixes well with some of the clays
used in impoundment liners. However, because chemical composition of fly
ash is variable, its utilization as liner material may be limited. If
methods are improved to be sure that minimum permeability and shear strength
requirements could be maintained over time, then the use of fly ash as an
impoundment liner material may increase.
Fly ash has been used occasionally as a soil conditioner to increase the
pH of acidic soils, thereby enhancing crop growth. Fly ash can also
contribute minerals to the soil. However, soil conditioners in common use
today, mostly agricultural limestones, are so inexpensive and easy to obtain
that it would be difficult to penetrate this market with a fly ash product.
There are few processes currently available for recovery of materials
from coal ash. One facility has had some commercial success at producing
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37
magnetite from fly ash. Magnetite recovered from fly ash actually
contains a higher percentage of magnetics than does natural magnetite,
making it a more efficient coal cleaning agent. This particular technology
shows some promise of expanding; other processes, mostly for metals
recovery, are in the development stage. Recovery processes for alumina and
titanium are at an advanced stage of development. However, while both these
technologies have been proven feasible, neither is currently economically
competitive with ore-processing technologies. Another potential metal
recovery process, dubbed the DAL process and still in the research stage,
involves a series of relatively simple operations that can be performed with
commercially available process equipment to recover various metals from fly
ash. Theoretically, this process could show a substantial return on
38
investment soon after the recovery facility began operating.
There is little information available to the Agency on the environmental
effects of utilization of coal combustion wastes. For many applications,
such as the use of coal ash in cement and concrete products, it would appear
that any adverse environmental impacts would be minimal. To the extent that
coal combustion wastes can be recycled in an environmentally acceptable
manner, utilization would help to reduce the amount of waste disposed. The
Agency is very interested in reducing the amount of waste that needs to be
disposed by the utility industry; however, barring major breakthroughs in
recycling techniques, it appears the potential for significantly increasing
39
the amount of waste utilization may be limited. Given current utilization
techniques, the Agency expects that the major portion of coal combustion
wastes will continue to be land disposed.
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FGD Wastes
The prospects for utilization of FGD sludge are less promising than
those for ash utilization. FGD sludge is not structurally stable or strong
enough to serve as a construction material, nor does it show the pozzolanic
properties required for a cement substitute. Current research in the field
of FGD sludge utilization is focusing on a dry scrubber method in which
reagents will be used to precipitate the FGD waste streams as dry gypsum
powder. Gypsum is sold for use in wallboard; however, there is currently a
glut on the market, and in any case, other sources of gypsum may be
preferred because the gypsum produced from FGD is often of lesser quality.
Some researchers are making an effort to find a reagent that will
precipitate a dry powder which, when mixed with water, will exhibit
pozzolanic properties and will harden to a concrete-like material. No
testing has been done, however, as the research is still in the conceptual
stage.
Although by-product utilization of FGD sludges comprises less than one
percent of total sludge production, a much greater percentage of FGD
by-products may be recoverable in the very near future since two full-scale
recovery processes and one test-scale recovery process for FGD by-products
are currently under development. Of the two full-scale processes, the
Wellman-Lord process recovers both sulfuric acid and elemental sulfur from
the waste stream, while the magnesium oxide scrubber process recovers only
40
sulfuric acid. The citrate scrubbing process, currently in the testing
phase, recovers elemental sulfur. FGD recovery processes currently in the
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research stage will be used to recover elemental sulfur, sulfuric acid, and
gypsum from the FGD process, and should be available for full-scale use
41
within the next decade. All recovery processes for FGD wastes general
both a by-product stream and a waste stream that must be disposed.
Lov-Volune Utility Wastes
EPA currently assumes that most low-volume utility wastes are
co-disposed with the high-volume wastes or, in some instances, burned in the
boiler at the power plant, although little data exist that accurately
42
describe industry-wide practices on low-volume waste disposal. Since
co-disposal is a common industry practice, low-volume wastes do not have
specific processes associated with their recovery or utilization. Although
this practice of co-disposal (or burning) may continue into the future,
certain waste streams, such as spent cleaning solvents, might be recovered
by distilling and collecting the solvents at high temperature, which would
leave a low-volume residue to be disposed. The recovered solvent could then
be reused on-site as a cleaning solvent or sold to another facility. If an
organic solvent were contaminated in such a way that contaminant removal
were difficult or impossible, the contaminated solvent could be burned. For
low-volume waste streams burned in the boiler, these wastes could be
transported to an off-site facility that would burn them as fuel. If
low-volume wastes were considered hazardous, regulations might restrict the
43
burning of these wastes, potentially making this option infeasible.
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Other recovery schemes for individual low-volume waste streams may be
developed if these streams are segregated from the high-volume wastes. At
this time, however, few recovery processes and utilization techniques have
been considered separately for low-volume utility wastes.
Recycled Effluent
Approximately 25 percent of the utilities that utilize surface
44
impoundments recycle some of their pond effluent back to the plant. If
the recycled effluent is used as sluice water, the system pH may increase to
values well above 10. The recycled effluent may also be used as cooling
water prior to ultimate discharge. Although effluent recycling is not a
waste recovery or utilization technique, it can affect the chemical
characteristics of the solid wastes that may come into contact with the
recycled water.
4.3 SUMMARY
Coal combustion waste management practices by electric utilities vary
widely across the industry. State regulation, regional factors such as land
availability and water availability, and age of the power plant all have an
effect on the type of waste management practices that are employed.
Alternative practices, such as ground-water monitoring and leachate
collection, are used by some utilities, and in some states are mandated by
regulation. A significant portion of coal combustion by-products are
recovered and utilized for various purposes.
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All but one state regulates the disposal of coal
combustion wastes under their hazardous or solid waste
disposal regulations. One state exempts these wastes from
regulation.
State solid waste regulations applicable to coal
combustion wastes vary widely across the country.
Generally, solid waste regulations require that disposal
facilities have permits; location restrictions and
standards related to liners, leachate control, and
ground-water monitoring are applied on a case-by-case
basis.
Currently, about 80 percent of all coal-fired power plant
wastes are land managed; the remaining 20 percent are
recycled or recovered. The most common types of disposal
facilities used by utilities generating coal-fired wastes
are surface impoundments, landfills, and abandoned mines.
Currently, about 25 percent of utility treatment, storage,
and disposal facilities that receive combustion waste are
lined. About 15 percent of all facilities have leachate
collection systems, and 35 percent have ground-water
monitoring.
Newer facilities are more likely to be lined, have
leachate collection systems, and ground-water monitoring
systems. More than 40 percent of all generating units
constructed since 1975 use lined disposal facilities.
About 20 percent of all high-volume combustion wastes,
particularly fly ash and bottom ash, are recycled,
primarily as cement additives, high-volume road
construction material, or blasting grit.
About 99 percent of FGD wastes are currently disposed;
however, recovery of sulfur and sulfur products from FGD
wastes is a developing and promising technology.
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CHAPTER 4
NOTES
* Wald, Harkrader & Ross, Survey of State Laws and Regulations
Governing Disposal of Utility Coal-Combustion Byproducts, for the Utility
Solid Waste Activities Group (USWAG) , 1983.
2 States have probably followed U.S. EPA's lead in exempting coal
combusting wastes. Many states' regulations explicitly refer to 40 CFR 261.4,
or use the clause's exact wording.
^ The following State officials were interviewed: Brett Bettes, Solid
Waste Division, Washington Department of Ecology, January 6, 1987; Ken Raymond,
Industrial and Solid Waste Division, Oklahoma Department of Health, December
31, 1986; Dwight Hinch, Division of Waste Management, Tennessee Department of
Health, December 31, 1986; Shelby Jett, Division of Waste Management, Kentucky
Department of Environmental Protection, January 6, 1987; Vincent Nikle,
Assistant Liaison's Office, New Jersey Department of Environmental Protection,
December 17, 1986.
^ According to Maine's Solid Waste Management Regulations: "More
Stringent Criteria for Large-Scale Disposal of Oil, Coal and Incinerator Ash:
Because of the concentration of heavy metals in residues from the combustion of
municipal solid waste or the combustion of oil or coal, including bottom ash
and fly ash, disposal of such ashes when they occur in amounts that exceed a
total accumulation of 20 cubic yards of coal ash . . . per week over any
one -month period shall be confined to a secure landfill. For the purposes of
these rules, a secure landfill shall mean a landfill with a liner and a
leachate management system." (Maine's Solid Waste Management Regulations,
Chapter 401.2.3.).
^ The exhibit assumes that both on-site and off-site permits are required
unless the regulations explicitly state otherwise.
° See Chapter One for discussion of the regulation of low-volume utility
waste streams.
' Waste piling, a method occasionally employed by utilities, is not
discussed in this report. Waste piles are mounds of ash placed on the ground
and covered with soil.
° U.S. Department of Energy, Impacts of Proposed RCRA Regulations and
Other Related Federal Environmental Regulations on Utility Fossil Fuel -Fired
Facilities. Volume II. 1983.
* See Chapter 6 for a discussion of disposal costs.
10 Haller, W.A. , J.E. Harwood, S.T. Mayne, and A. Gnilka, "Ash Basin
Equivalency Demonstration (for treatment of boiler cleaning wastes containing
heavy metals)," Duke Power Company, 1976.
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-2- ;
Envirosphere Company, Environmental Settings and Solid Residues
Disposal in the Electric Utility Industry. EPRI Report EA-3681, 1982.
12 Ibid.
13 Ibid.
14
A low-permeable clay is one that has been determined in laboratory
testing to have a permeability coefficient, K, of 10 cm/sec or less.
There are one thousand mils per inch.
16 See 40 CFR 264.
Engineering-Science, Background Data on Utility Fossil Fuel-fired
Facilities, prepared for USDOE, Office of Fossil Energy, 1983.
18 Ibid.
19 Ibid.
20
EPRI Journal, 1985, cja. cit.
21
EPRI, Manual for Low-Volume Wastes From Fossil-Fuel-Fired Power Plants.
prepared by Radian Corporation, Austin, Texas, July 1987.
22
EPRI, Characterization of Utility Low-Volume Wastes, prepared by Radian
Corporation, Austin, Texas, May 1985.
23 Ibid.
24 Ibid.
25 EPRI, 1987.
26 EPRI, 1985.
27 EPRI, 1987.
9fi
EPRI, 1985.
29
40 CFR 228, Criteria for the Management of Ocean Disposal Sites for
Ocean Dumping.
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-3-
30
Envirosphere Company, "Economic Analysis of Impact of RCRA on Coal
Combustion By-Products Utilization" in Report and Technical Studies on the
Disposal and Utilization of Fossil-Fuel Combustion Bv-Products. Appendix G,
prepared for Utility Solid Waste Activities Group (USWAG), October 1982.
31
Information compiled by the American Coal Ash Association on 1985 ash
utilization, August 1, 1986.
32 EPRI Journal. 1985. OŁ. cit.
33
" Ibid.
34
Ibid.
35 USWAG, 1982.
36 EPRI Journal. 1985. o^. cit.
37 USWAG. 1982. OE. cit.
38
Ibid.
39
For example, see comments by Garry Jablonski, section manager of ash
utilization for the American Electric Power Company, "Coal Ash Market Report,"
Vol. 1, No. 9, July 15, 1987.
A.O
EPRI, State-of-the-Art of FGD Sludge Fixation. 1978.
41 Ibid.
42
Envirosphere Company, Information Responding to EPA's Request Regarding
Burning and Co-Treatment/Co-Disposal of Low Volume Wastes Generated At Fossil
Fuel Electric Generating Stations, prepared for USWAG and Edison Electric
Institute, August 1981.
43
The economics of burning these wastes would depend on the applicable
regulations. Regulations concerning the burning of hazardous wastes are
currently being developed and are scheduled for final promulgation in mid-1987.
44
U.S. Department of Energy. 1983. Op. cit.
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CHAPTER FIVE
POTENTIAL DANGERS TO HUMAN HKAT.TH AND THE ENVIRONMENT
Under Section 8002(n) of RCRA, EPA is to analyze the "potential danger, if
any, to human health and the environment from the disposal and reuse" of coal
combustion wastes and "documented cases in which danger to human health or the
environment from surface runoff or leachate has been proved." This chapter
examines potential and documented dangers to human health and the environment
caused by wastes generated from the combustion of coal at electric utility
power plants.
As described in Chapter One, special large volume wastes, including coal
combustion wastes, are to be treated differently under RCRA than other
industrial wastes. Due to the extremely large volume of coal combustion waste
and the expectation of relatively low risk from its disposal, Congress directed
EPA to evaluate all the factors in 8002(n) of RCRA in determining whether
Subtitle C regulation is warranted. The danger from coal combustion waste
management is only one of the factors EPA must consider. In order to provide a
starting point for evaluating the potential danger from coal combustion waste
management, this chapter begins by providing the reader with background
information on the characteristics that an industrial solid waste must exhibit
to be considered hazardous under RCRA, and then looks at which of these
characteristics apply to coal combustion wastes. The next section analyzes
several studies that monitored ground-water and surface-water concentrations in
and around coal combustion waste disposal sites and documented the number of
times that drinking water standards were exceeded. The third section of this
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5-2
chapter reviews studies that compiled and evaluated reported incidences of
contamination to ground water and surface water due to the disposal of coal
combustion wastes. Finally, the fourth section analyzes the factors affecting
the exposure of humans, animals, and plants to contaminants from coal
combustion waste by examining environmental setting and population data for a
random sample of 100 coal-fired utility power plants.
5.1 RCEA SUBTITLE C HAZARDOUS WASTE CHARACTERISTICS
AND LISTING CRITERIA
Under RCRA, solid wastes are classified as hazardous if they exhibit
characteristics of ignitibility, corrosivity, reactivity, and/or EP toxicity as
defined by RCRA or if they are listed as hazardous by the Administrator.
Ignitibility refers to the tendency of a substance to
catch fire. A liquid waste is ignitable if it has a
flash point less than 60°C, as determined by
EPA-specified test protocols. A non-liquid waste is
ignitable if, under standard temperature and pressure, it
is capable of causing a persistent, hazardous fire _._
through friction, absorption of moisture, or spontaneous
chemical change.^
Corrosivity of waste is determined by measuring the
waste's pH, the value used to express relative acidity or
alkalinity. A pH value of 7.0 is neutral; substances
with a pH less than 7.0 are acidic, while those with a pH
greater than 7.0 are alkaline. A waste is corrosive, and
therefore hazardous, if it is aqueous and has a pH less
than or equal to 2.0 or greater than or equal to 12.5. A
waste is also corrosive if it is liquid and corrodes
steel at a rate greater than 6.35 mm per year. The pH
measurements and the corrosion rate must be determined
using EPA-approved methods.-*
Reactivity refers to the stability of a substance.
Wastes that are highly reactive and extremely unstable
tend to react violently or explode. A waste is reactive
if it undergoes violent physical change without
detonating, if it reacts violently with water, if it
forms a potentially explosive or toxic mixture with
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5-3
water, or if it is capable of detonating or exploding at
standard temperature and pressure.
Extraction Procedure (EP) Toxicity is determined from a
laboratory procedure designed to simulate leaching from a
disposal site under actual disposal conditions.^
Concentrations in the effluent from this test are
compared with the Primary Drinking Water Standards (PDWS)
of eight constituent metals to determine whether a waste
is hazardous. A waste is EP toxic if it produces a
leachate using an EPA-approved procedure that has
concentrations of contaminants that are 100 times the
PDWS.6
Wastes are also regulated as hazardous wastes under Subtitle C if the
Administrator lists them in 40 CFR 261.31-261.33. The Administrator may list
wastes using several criteria:
if they are ignitable, corrosive, reactive, or EP toxic
as described above.
if they have been found to be fatal to humans in low
doses, or, in the absence of data on human toxicity,
fatal to animals in laboratory tests (these wastes are
designated Acute Hazardous Wastes).'
if they contain any of the toxic constituents listed in
Appendix VIII of 40 CFR 261, unless the Administrator,
after considering the factors contained in 40 CFR
261.11(a)(3), concludes that "the waste is not capable of
posing a substantial present or potential hazard to human
health or the environment when improperly treated,
stored, transported or disposed of, or otherwise
managed." The factors that the Administrator may
consider include the toxicity of the constituent, the
concentration of the constituent in the waste, the
potential for degradation, the degree of bioaccumulation
to be expected from the constituent, and the quantities
of the waste generated. These wastes are designated
Toxic Wastes.
Determining whether coal combustion wastes show any of the hazardous
characteristics is important in analyzing potential danger to human health and
the environment. In general, most coal combustion wastes, such as ash and FGD
sludge, are not ignitable. Reactivity is also generally not a characteristic
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5-4
of concern for coal combustion wastes. The chemical and physical
characteristics of most coal combustion wastes identified in Chapter Three
indicate that these wastes are very stable and will likely not react with other
substances in their disposal area. The remainder of this section will analyze
data on coal combustion wastes to see if these wastes exhibit the
characteristics of corrosivity and/or EP toxicity.
5.1.1 Corrosivity of Coal Conbustion Wastes
Under current RCRA regulations, only liquid wastes can be considered
corrosive. Coal combustion ash, therefore, could not by itself be considered
corrosive, even if it generates a corrosive leachate.
For wastes that are aqueous, a waste is corrosive if its pH is less than or
equal to 2.0 or greater than or equal to 12.5. Available data indicate that the
pH values of most waste streams of coal-fired power plants do not fall within
these ranges; in fact, the only wastes that may be classified as corrosive
according to the above definition are water-side, hydrochloric acid-based
cleaning wastes, which have had measured pH as low as 0.5 (see Exhibit 3-26).
In an EPRI report on low volume wastes (see section 5.1.2) three samples of
hydrochloric acid-based boiler cleaning waste all had pH levels less than 2.
However, these wastes are often neutralized before disposal. Several other
waste streams have pH levels which fall very near the corrosive ranges. Most of
these are also low volume wastes. Boiler blowdown has measured pH as high as
12, with a range of 8.3-12 (see Exhibit 3-20), and coal pile runoff has measured
pH as low as 2.1, with a range of 2.1-6.6 (see Exhibit 3-21). Sludge from
dual-alkali FGD processes using eastern coal is a high volume waste with
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5-5
measured pH of approximately 12.1 (see Exhibit 3-17). Chapter Three contains a
complete description of these wastes.
Several studies of coal combustion waste streams surveyed in this chapter
indicate that the alkalinity or acidity of coal combustion wastes, while not
necessarily falling in the RCRA corrosive ranges, may occasionally reach levels
of potential concern. For example, pH readings of waste fluids taken during a
study by Arthur D. Little were as high as 11.4 (see Section 5.2.1). Three case
studies described in Appendix D (a study of 12 Tennessee Valley Authority power
plants, an individual study at the Bull Run Power Plant, and a study of the
Savannah River Project) showed pH readings of waste fluids at 2.0, 3.5, and 2.9,
respectively. Section 5.3.1 describes a documented case in which highly
alkaline coal combustion waste (pH 12.0) caused substantial harm to aquatic life
after it accidentally spilled into Virginia's Clinch River in 1967.
5.1.2 Extraction Procedure (EP) Toxicity of Coal Combustion Wastes
• ^ '' '
Current RCRA regulations (40 CFR 261.24) specify that if a leachate';.,
extracted using an EPA-.approved extraction procedure contains any of the metals
shown in Exhibit 5-1 at concentrations equal to or greater than the given limit,
the waste is classified as EP toxic and, unless otherwise exempted, will be
subject to Subtitle C regulation.' The concentrations shown in Exhibit 5-1 are
100 times the current Primary Drinking Water Standards (PDWS) established by the
Safe Drinking Water Act for those constituents.
Waste extraction tests are used to predict the type and concentration of
constituents that may leach from a waste disposal site under field conditions.
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5-6
EXHIBIT 5-1
MAXIMUM CONCENTRATION OF CONTAMINANTS FOR
CHARACTERISTIC OF EP TOXICITY
Contaminant Level
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
5.0
100.0
1.0
5.0
5.0
0.2
1.0
5.0
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
Source: 40 CFR 261.24, January 16, 1987.
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5-7
Host extraction tests are conducted by mixing or washing a waste sample with a
water-based solution of a specified composition for a specified length of time.
The resulting leachate solution is then separated from the solids and tested for
constituent concentrations.
5.1.2.1 Types of Extraction Procedures
Several different types of waste extraction procedures are described in
detail below. Although under current regulations only the Extraction Procedure
(EP) toxicity test is used to determine whether a waste is EP toxic, EPA has
recently proposed a new procedure, the Toxic Characteristic Leaching Procedure
(TCLP), to replace the EP test (see Federal Register, Volume 51. No. 114, June
13, 1986, p. 21648). Furthermore, in the period since EPA has promulgated the
Extraction Procedure (EP) toxicity test, many people have alleged that the EP
provides an inappropriate measure of leaching under field conditions. For these
reasons, EPA has reviewed the results of other extraction procedure tests as
well as the EP. To the extent that the results of these other procedures on
coal combustion wastes are generally consistent with the EP results, the debate
over whether the EP test is appropriate or not is moot. Three of the extraction
tests described below (EP, TCLP, and ASTM) are batch leaching tests. Batch
tests are conducted by placing a waste sample in a water-based solution for a
specified period of time. The fourth procedure, the column test, passes a
solution through the waste.
• The procedure for the standard EPA extraction test, the
Extraction Procedure (EP) toxicity test. requires
obtaining a waste sample of at least 100 grams and then
separating the liquids from the solids. The solid
portion is placed in a container along with 16 times its
weight in deionized water, and continually agitated at
20-40°C. Throughout the test, the pH of the batch
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5-8
mixture is monitored. If the solution remains above pH
5.0, acetic acid is added to maintain a pH of 5.0. If
the solution is less than pH 5.0, no acetic acid is
added. If the pH of the batch solution is not below 5.2
after the initial 24-hour agitation period, the pH is
adjusted to 5.0 + 0.2 at the beginning of each hour
during an additional 4 hour agitation period. After
agitation, the leachate solution is then separated from
the solid portion, and the liquid extracted from the
original waste sample is added to the leachate solution.
These combined liquids are then tested for constituent
concentrations.
Toxic Characteristic Leaching Procedure (TCLP), which EPA
has proposed as a replacement for the EP, uses a
different leaching solution depending on the nature of
the waste being tested. For wastes of low alkalinity, a
pH 5.0 acetic acid/sodium acetate buffer is used for
extraction. If the waste is more alkaline, a normal
acetic acid solution is used. Unlike the EP toxicity
test, the TCLP can be used for volatile waste
constituents.
The American Society for Testing and Materials (ASTM)
developed the ASTM A procedure, which requires 48-hour
agitation of a 1:4 mixture of waste to distilled
deionized water. Another test, ASTM B, involves the
extraction of waste constituents in a buffered acetic
acid solution of pH 4.5. ASTM D, similar to ASTM A,
involves the 48-hour agitation of a 350-gram sample with
1400 milliliters of deionized distilled water, and the
filtering of the aqueous phase, after agitation, with a
0.45 micron filter.
Unlike the batch testing methods described above, the
column test is conducted by passing a solution through
the waste. This test process simulates the migration of
leachate and ground water through waste, but still cannot
duplicate field conditions perfectly. Because there is
no standard column test procedure, column tests are
described individually in the studies reviewed in the
next section of this chapter.
The results of various studies (conducted with the above-mentioned
extraction tests) on the leaching of constituents from coal combustion wastes
are discussed below.
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5-9
5.1.2.2 Results of Extraction Tests
Tetra Tech Study
In 1983 Tetra Tech conducted a literature review for the Electric Power
Research Institute (EFRI) and reported results from a number of leachate
extraction studies. An examination of the results of various leaching tests
(EF toxicity test, ASTM A, and ASTM B) on coal ash and flue gas desulfurization
(FGD) sludge revealed that results differed by waste type and were ultimately
dependent upon the source of the fuel (see Exhibit 5-2) and the mechanics of
combustion. The study results were presented separately for ash and FGD sludge.
Results of the batch leaching tests (EP, ASTM A, and ASTM B) reported in the
studies reviewed by Tetra Tech were presented as averages of the element
concentrations found in numerous runs of one type of extraction test. Ranges of
the concentrations were sometimes presented as well. Depending on the
laboratory that ran the test, EP, ASTM A, and ASTM B batch leaching tests were
run on as few as 3 and as many as 62 samples.
Tetra Tech reviewed 457 EP tests on various types of ash. Results from
these EP tests show a geometric mean concentration for selenium equal to its
PDWS. Geometric mean concentrations for the other 7 metals were below their
respective PDWS. The maximum concentrations were 4 times the PDWS for silver,
29 times for arsenic, 8 times for barium, 140 times for cadmium, 14 times for
chromium, 4 times for mercury, 5 times for lead, and 17 times for selenium.
Tetra Tech also reported results from 202 ASTM A tests on ash. Selenium was
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5-10
EXHIBIT 5-2
EFFECT OF GEOGRAPHIC COAL SOURCE
ON ELEMENT CONCENTRATION IN ASH
Element
Arsenic
Barium
Cadmium
Chromium
Mercury
Lead
Selenium
Strontium
Vanadium
Zinc
Geographic Variation
low in western coal ash; difference in
concentration between eastern coal and
midwestern coal ashes indistinguishable
highest in western coal ash
most concentrated in midwestem coal ash
low in western coal ash; difference in
concentration between eastern and
midwestern coal ashes indistinguishable
highest in eastern coal ash; all
distributions highly skewed toward high
concentrations
highest in midwestern coal ash
similar in eastern and midwestern coal
ash; lower in western coal ash
highest in western ash; lowest in
midwestern ash
similar in eastern and midwestern coal
ash; lower in western coal ash
highest in midwestern ash; lowest in
western ash
Source: Tetra Tech, Inc., Physical-Chemical Characteristics of Utility Solid
Wastes, prepared for Electric Power Research Institute, EA-3236,
September 1983.
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5-11
the only constituent with a geometric mean concentration greater than the PDWS,
at a level approximately 2 times the PDWS. The maximum concentrations were less
than the PDWS for silver and mercury. For the other elements, the maximum
concentrations from the ASTM-A procedure were 7 times PDWS for arsenic, 4 times
for barium, 1.3 times for cadmium, 10 times for chromium, 5 times for lead, and
48 times for selenium.
Cadmium was the only constituent in fly ash leachate extracted using the EP
for which there was a maximum concentration over 100 times the PDWS (and
therefore above the EP toxicity level). The EP produced a leachate that had a
maximum cadmium concentration 140 times the PDWS. However, the average cadmium
concentration for the 62 EP samples was only half the PDWS. Tetra Tech did not
report the percentage of samples whose cadmium concentration exceeded 100 times
the PDWS. In general, the more acidic or alkaline the leaching solution, the
higher the concentrations of leached constituents. Tetra Tech concluded that
the geometric mean concentrations from the EP and ASTM-A tests were similar.
The results of the EP and ASTM-A tests are presented in Exhibit 5-3.
Tetra Tech also reviewed data from a number of column tests on coal ash.
The test results did not show any concentrations greater than 100 times the PDWS
for any element tested. One test was conducted during a two-year period using a
continuous-flow method to produce leachate from fly ash. In another test, fly
ash and bottom ash were packed separately in glass columns, each of which was
leached for 27 days with 200 milliliters per day of either distilled water,
dilute base, or dilute acid. For a third test, fly ash and bottom ash were
packed in water-saturated glass columns. At one-week intervals, the columns
were flushed from below at a moderate rate for two hours. This test was
-------
EXHIBIT 5-3
RESULTS GF TETHA TECH EXTRACTION TESTS OH COAL OOMBUSTICB ASH
EP Test Results
ASTH A Test Results
Primary
Drinking Hater
Constituent
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
Standard
(nw/1)
.05
1.0
.01
.05
.05
.002
.01
.05
Range
<.004- 1.46 mg/1
.003- 7.6 mg/1
.0001- 1.4 mg/1
.001- 0.68 mg/1
<. 0001-0. 25 mg/1
<.0001- .007 mg/1
<. 0001-0. 17 mg/1
<. 0001-0. 20 mg/1
Geometric Mean
.012 mg/1
0.222 mg/1
.0047 mg/1
.036 mg/1
.005 mg/1
.00042 mg/1
.01 mg/1
.00064 mg/1
Maximum
Exeeedance
29 X PDWS
8 X PDWS
140 X PDWS
14 X PDWS
5 X FDWS
4 X PDWS
17 X PDWS
4 X PDWS
Range
<. 0005-0. 37 mg/1
.0004-3.8 mg/1
.0001-. 013 mg/1
.0005-0.5 mg/1
<. 0001-0. 25 mg/1
<.0001-.0012 mg/1
.0005-0.48 mg/1
<.0001-.03 mg/1
Geometric Mean
.0072 mg/1
0.208 mg/1
.00039 mg/1
.047 mg/1
.0025 mg/1
.00027 mg/1
.019 mg/1
.0007 mg/1 •
Maximum
Exceedanee
7 X PDWS
4 X PDWS
1.3 X PDWS
10 X PDWS
5 X PDWS
0.6 X PDWS
48 X FDWS
0.6 X FDWS
Source: Tetra Tech, Inc., Physical-Chemical Characteristics of Utility Solid Wastes, prepared for Electric Power Research Institute,
EA-3236, September 19S3.
Ui
I-1
ro
-------
5-13
intended to simulate the intermittent wetting to which some ash disposal sites
are subject.
Partly because flue gas desulfurization (FGD) technologies have only
achieved widespread commercial usage in recent years, FGD sludge has not been as
thoroughly characterized as coal ash. However, the Tetra Tech study reported
the results of tests performed on sludges from a number of scrubber processes,
including the lime/limestone/alkaline fly ash process, the dual alkali/sodium
carbonate process (both these processes produce "lime sludge" and are the main
technologies currently in use), and the spray drying process (this process
produces calcium-based dry scrubber sludge and may be used more extensively in
the future).
Results from EP tests on calcium-based dry scrubber sludge showed a maximum
concentration of cadmium that was 150 times the PDWS, above the EP toxic level.
Arsenic and selenium were also analyzed using the EP test; the maximum arsenic
concentration was 32 times the PDWS and the maximum for selenium was 1.8 times
the PDWS. No other constituents were tested for this waste stream. (Results
from the EP studies on calcium-based dry scrubber sludge were not averaged but
reported as ranges - the number of tests performed was not given).
Tetra Tech also presented results of EP tests on lime sludge. These tests
measured concentrations of all EP toxicity constituents, and none were found to
be at EP toxic levels.
Tetra Tech also reported on column tests performed on FGD sludge. In one
column test, calcium-based dry scrubber sludge was leached with deionized water
-------
5-14
for 11 months. In another, various proportions of fly ash, wet calcium sulfate
(i.e., gypsum), calcium sulfite precipitate, and calcium oxide (lime) were
mixed, cured for 500 days, and leached with deionized water that was forced
through the waste columns. The leaching test results (reported in a manner
similar to that for reporting results of coal ash leaching studies) indicated,
on the basis of an unreported number of tests, that PDWS constituents in lime
sludge and calcium-based dry scrubber sludge leached at concentrations that
exceeded their PDWS by multiples of less than 5 for silver, 32 for arsenic, 2
for barium, 30 for chromium, 10 for lead, and 15 for selenium; the concentration
of mercury found in sludge leachate matched its PDWS. No constituents were at
concentrations above 100 times the PDWS.
In summary, none of the coal ash or FGD sludge leaching studies reviewed by
Tetra Tech showed constituent concentrations greater than 100 times the PDWS,
with the exception of cadmium from calcium-based dry scrubber FGD sludge and
from coal ash. Both results were from EP toxicity procedure tests. The
behavior of these wastes primarily depended on the source of the fuel and the
mechanics of combustion. Tetra Tech concluded that there were gaps in the
characterization of these wastes that made definitive conclusions difficult to
reach.
Departnent of Energy Study
The Department of Energy (DOE) conducted a compilation study of leaching
test results, Analytical Aspects of the Fossil Energy Waste Sampling and
14
Characterization Project. for the purpose of generating a data base on the
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5-15
leaching characteristics of coals and their combustion wastes. The EP test was
compared to a water leach test developed by ASTM (this test later became ASTM D)
and evaluated to determine the precision of the EP toxicity method when applied
to coal wastes. In their summary of the collected data, DOE reported that for
six of the analyzed constituents there were no significant differences between
the testing results derived from the two methods. The results of 2492 separate
extraction tests for the eight PDWS constituent metals (arsenic, barium,
cadmium, chromium, lead, mercury, selenium and silver) indicated that none of
the metals leached at concentrations that exceeded the PDWS by 50 times, and
most leached at concentrations less than 10 times the PDWS. This was true for
both the EP test and the ASTM test.
Arthur D. little Study
EPA sponsored a study by Arthur D. Little, Inc. (see Section 5.2.1) which
included EP Toxicity tests on 20 fly ash samples from 16 power plants and 3 FGD
waste samples from 3 power plants. The names of the plants from which the
samples were taken were not revealed because Arthur D. Little did not consider
the single "grab" samples obtained for testing to be representative. The EP
test results showed no EP toxic levels in the extracted leachates of any
samples. Silver and mercury concentrations were below the reported detection
limits of .001 mg/1 and .002 mg/1, respectively, for all samples. Lead was
detected in only three out of seventeen samples. Other PDWS constituents
(arsenic, cadmium, chromium, selenium, and barium) were detected, but all were
found at concentrations less than 100 times the PDWS. In contrast to the Tetra
Tech study reported above, leachates extracted from FGD samples had
concentrations of PDWS constituents that tended to be lower than the
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5-16
concentrations in leachates extracted from fly ash samples, whereas the Tetra
Tech report indicated that, in general, higher concentrations of PDWS
constituents were leached from FGD sludges than from coal ash. This discrepancy
may be due to variations in the wastes themselves, which, in turn, are due to
differences among coals derived from different sources. Results of the Arthur
D. Little study are presented in Exhibit 5-4.
Battelle Pacific Northwest Study
In another study for the Electric Power Research Institute (EPRI), Battelle
Pacific Northwest reviewed data developed during a round-robin study that
compared results from three laboratories performing both the EP and TCLP
tests. Battelle Northwest compared the two extraction procedures by looking
at the ratio of the mean TCLP concentrations to the mean EP concentrations for
each element. These ratios fell within the range of 0.8 to 1.2 about 60 percent
of the time. Only 15 percent of the ratios exceeded 2.0. In 83 percent of the
comparisons, the TCLP test leachate contained greater concentrations of the PDWS
constituents than the EP test leachate.
Battelle compared the maximum mean concentration of each compound (taken
from the pool of averaged results for each constituent from both EP and TCLP
testing of all the waste samples) with the corresponding PDWS. This comparison
indicated that for both the EP and the TCLP procedures, concentrations of
silver, barium, and mercury were less than the established PDWS for those
metals, whereas the concentration of arsenic was 21 times the PDWS; cadmium, 25
times; chromium, 13 times; lead, 4 times; and selenium, 14 times.
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5-4
RESULTS OF AKIUUK D. LITTLE itsiiBL. SBDHIH3 THE
BARGE OF OOHCENTRATICH OF METALS IR EP EXTRACTS a/
Metal
Arsenic
Barium
Cadmium
Chromium (CrVI) b/
Lead
Mercury
Selenium
Silver
(A)
Overall
Average Values
Fly Ash
.08
.34
.03
.16
.01
<.002
.05
<.001
FGD Haste
0.20
.18
.01
.02
.01
<.002
.020
<.001
Range Observed (mg/1)
Fly Ash
0.002-.410
0.1-0.7
0.002-0.193
0.008-0.930
0.003-0.036
<0.002
.002-0.340
<0.001
FGD Haste
0.002-0. 065
0.15-0.23
0.002-0.020
.011-0.026
0.005
<0.002
0.008-0.049
<0.001
(B)
Primary Drinking
Hater Standards
.05 mg/1
1.0 mg/1
0.01 mg/1
0.05 mg/1
0.05 mg/1
0.002 mg/1
0.01 mg/1
0.05 mg/1
Ratio of Observed
Range to
Fly Ash
0.04-8.2
0.1-0.7
0.2-19.3
0.16-18.6 c/
0.06 to 0.72
<1
0.2 to 34
<0.02
PDHS (A/B)
FGD Haste
0.04-1.30
0.15-0.23
0.2-2
0.22-0.52
0.1
<1
0.8-4.9
<0.02
a/ Ranges are shown for fly ash and FGD samples; comparisons are made to the Primary Drinking Hater Standards.
b/ The Arthur D. Little study tested the concentration of Cr(VI), an ion of chromium.
c_/ Since total chromium values are measured by the graphite furnace atomic absorption analysis method, these are upper limits
for the Cr(VI) values.
I
l->
*J
Source: Arthur D. Little, Inc., Full-Scale Evaluation of Haste Disposal from Coal-fired Electric Generation Plants, prepared for
the Air and Energy Research Laboratory of the U.S. Environmental Protection Agency, for the Office of Solid Haste,
EPA-600-7-85-028, June 1985.
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5-18
University of Alberta Study
The University of Alberta conducted a study for EPRI that involved passing a
water-based solution through a series of columns with increasing ash
1 R
concentrations. The study results indicate that while some constituent metals
were initially released or mobilized from the wastes using this method, these
same constituents were attenuated in columns further along in the series.
Boron, selenium, and arsenic were initially mobilized, but only boron remained
mobilized to a significant extent. Arsenic and selenium interacted in
successive columns such that the movement of arsenic and selenium through the
system was retarded.
In addition to studying the test leachates, the University of Alberta
researchers studied the fly ash itself to determine the processes that affect
the migration of metal constituents. The study results indicated that some
constituents are not uniformly distributed within the fly ash particles. The
fly ash particles typically consist of an interior "glass" matrix covered by a
relatively reactive and soluble exterior coating. The study found that arsenic
and selenium were concentrated almost exclusively in the coating of the fly ash
particles and thus were readily leached; the barium concentration was split
evenly between the interior and exterior of the particles; about 75 percent of
the cadmium and chromium were concentrated in the interior glass matrix; and
almost all the lead was concentrated in the interior glass matrix and was,
therefore, not readily mobilized.
The study attributed the uneven concentration of constituents in the fly ash
particles to the vaporization of relatively volatile constituents during
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5-19
combustion, followed by the condensation of these constituents on the exterior
of fly ash particles entrained in the flue gas. However, this study reported
that lead was contained within the interior glass matrix of the fly ash
particles, while the Tetra Tech study discussed earlier reported that lead was
volatile and thus likely to be found on the surface of fly ash particles. Both
studies reported that arsenic and selenium were found on the surface of the fly
ash particles. The University of Alberta concluded that the physical and
chemical characteristics of the fly ash were determined by both the chemical
composition of the coal from which it came and the mechanics of fly ash
formation during combustion.
The difference between the University of Alberta study and the standard
leaching test studies is that the mobility of constituents was observed under a
variety of conditions. A number of waste concentrations could be tested in the
columns to imitate specific field conditions. (Single column extractions also
possess such flexibility, but to a lesser degree.) The University of Alberta
study simulated landfill conditions by allowing the laboratory leachate solution
to continually change as it migrated through multiple waste columns, whereas in
batch extraction tests the laboratory leachate solution is allowed to come into
contact with only one ash sample.
Battelle Chemical Characterization Study
Battelle Pacific Northwest Laboratories recently completed a study for EPRI
19
on chemical characteristics of fly ash, bottom ash, and FGD sludge. As part
of this study, Battelle performed a comparison of the EP Toxicity Test and the
TCLP test. While most of the results of the two procedures were consistent,
-------
5-20
differences were observed with acidic samples. One acidic fly ash EP sample had
both arsenic and chromium above RCRA limits. Another acidic fly ash sample also
exhibited elevated levels of arsenic and chromium, but not at levels exceeding
RCRA limits. The study found, however, that the two samples showed considerably
less leachability for arsenic and chromium with the TCLP, while other elements
tested showed similar results from the two testing procedures. The study
concluded that the difference between the two types of tests resulted from the
acidic character of the samples.
Radian Corporation Study
The Radian Corporation conducted two studies for EPRI that involved testing
various low-volume waste streams. In the first of these studies (published in
20
May 1985), Radian Corporation collected thirty-two samples on eight types of
low volume wastes. These samples were tested using the EP toxicity test as well
as some other testing procedures. The results of the EP toxicity test showed
that the only waste stream Radian tested that exceeded the EP toxicity limits in
the 1985 Radian study was untreated boiler chemical cleaning waste. Exhibit 5-5
presents the results for three samples of untreated boiler cleaning wastes. All
three samples had elevated levels of chromium and cadmium, including exceedances
of EP toxicity limits, and two samples of boiler cleaning wastes had elevated
concentrations of lead, including an exceedance of EP limits. This study also
performed EP tests on boiler cleaning wastes after neutralization in a plant
treatment system. As shown in Exhibit 5-5, the two samples of treated boiler
cleaning waste did not exceed EP toxicity limits for any metals.
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5-21
EXHIBIT 5-5
EP TOXICITY ANALYSIS FOR UNTREATED
AND TREATED BOILER CHEMICAL CLEANING HASTES a/
(concentrations in ng/1)
Untreated Boiler Cleaning Waste Type
Metals
Silver
Barium
Cadmium
Chromium
Arsenic
Mercury
Lead
Selenium
Maximum
Allowable
EP Toxicity
Limits
5.0
100.0
1.
5.
.0
.0
5.0
0.2
5.0
1.0
Ammoniated
EDTA with
Inhibitor
0.002 b/
0.76
1x0
4.7
0.006
0.0002 b_/
3.6
0.002 b/
Oxidizer
0.002 b/
0.67
4.7
0.002 b/
0.0002 b/
0.002 b/
Hydrochloric
Acid
0.007
0.91
0.64
20.0
0.051
0.0042
0.002 b/
0.003 b/
Treated Boiler Cleaning Waste Type
Metals
Silver
Barium
Cadmium
Chromium
Arsenic
Mercury
Lead
Selenium
Maximum
Allowable
EP Toxicity
Limits
5.0
100.0
0.2
5.0
1.0
HC1+
Inhibitor,
Chelant
0.042
0.40
0.002 b/
0.001 b/
0.002 b/
0.0002 b/
0.002 b/
0.002 b/
Hydrochloric
Acid
0.033
0.25
0.012
0.099
0.002 b/
0.0002 b/
0.002 b/
0.002 b/
a/ All underlined values exceed maximum allowable limits under current RCRA
regulations for hazardous wastes.
b/ Values shown are detection limits. Actual values could be less than, but no
greater than, the indicated value.
Source: Electric Power Research Institute, Characterization of Utility
Low-Volume Wastes. Radian Corporation, May 1985.
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5-22
In Radian Corporation's second study of low-volume wastes (published in July
21
1987), they collected additional data on certain low-volume waste streams that
the first study indicated might have high concentrations of metals. As shown in
Exhibit 5-6, eight of twenty-one samples of low-volume liquid wastes from
coal-fired plants were found to exceed EP toxicity limits. For boiler chemical
cleaning wastes, 7 of 10 samples exceeded EP toxicity limits for at least one
constituent. Six of the boiler chemical cleaning waste exceedances were for
chromium and the remaining exceedance was for lead. One wastewater brine sample
out of five tested samples exceeded the EP limits for selenium. There were no
reported EP exceedances for waterside rinses or coal pile runoff.
Radian Corporation also conducted EP Toxicity tests on low-volume waste
sludges. None of the three samples from coal-fired power plants were considered
EP Toxic, including a boiler chemical cleaning waste sludge. For the two
wastewater pond sludges, the study compared the EP and TCLP testing procedures.
Results of the EP and TCLP tests are shown in Exhibit 5-7. The two extraction
procedures produced nearly identical concentrations of metals in their extracts.
As in their first study, the Radian Corporation also sampled low-volume
wastes that had been treated. This study found significant reductions in
concentrations of chromium, copper, iron, nickel and zinc after hydrochloric
acid boiler cleaning waste was neutralized.
The study also examined the treatment effectiveness of co-disposal of
low-volume wastes with high-volume wastes. Results of EP toxicity tests on
co-disposal mixtures found that co-disposal significantly reduced concentrations
of contaminants in the co-disposed mixture. Results of the EP tests are
-------
EXHIBIT 5-6
ELEMENT
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
ph (units)
EP
Toxicity
Limit
5.0
100.0
1.0
5.0
5.0
0.2
1.0
5.0
2
-------
5-24
EXHIBIT 5-7
COMPARISON OF EP AND TCLP EXTRACTIONS FOR
LOW-VOLUME SLUDGE DREDGED FROM WASTEWATER PONDS
(ag/D
EP Test
ELEMENT
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
Source:
RCRA
Limit
5.0
100.0
1.0
5.0
5.0
0.2
1.0
5.0
Manual for
Fuel -Fired
# of
Tests
2 0
2 0
2 0
2 0
2 0
2
2
2 0
Management of
Power Plants.
Range
.002-0.015
.045-0.12
.002-0.002
.01-0.011
.002-0.006
0002-0.0002
003-0.0003
.002-0.004
Low -Volume
Mean
0.0085
0.0825
0.002
0.0105
0.004
0.0002
0.003
0.003
Wastes
TCLP Test
Range
0.004-0.016
0.07-0.089
0.002-0.002
0.018-0.023
0.002-0.16
0.0002-0.0002
0.003-0.03
0.009-0.012
From Fossil-
Electric Power Research Institute
Mean
0.010
0.080
0.002
0.021
0.081
0.0002
0.017
0.011
1
prepared by Radian Corporation, Austin, Texas, July 1987.
-------
5-25
presented in Exhibit 5-8 for co-disposal with fly ash from three geographic
areas.
5.1.2.3 Summary of Extraction Test Results
In conclusion, the results of these studies indicate that coal combustion
utility wastes may leach several elements, including PDWS constituents. While a
variety of extraction procedures were used in these studies, and questions have
been raised about the applicability of certain testing methods to coal
combustion wastes (which are generally disposed on-site in monofills), all of
the extraction procedures used in the studies (EP, TCLP, ASTM, and column)
produced average concentrations of constituents that were below the EP toxic
level for all waste streams except untreated boiler cleaning waste. In the 1987
Radian Corporation study, untreated boiler cleaning wastes had a mean
concentration 169 times the PDWS for chromium using the EP Toxicity test.
For the high-volume waste streams, cadmium, arsenic, and chromium were the
only elements for which a maximum concentration was found that was over 100
times the PDWS. Arsenic and chromium were above EP toxicity limits based on EP
tests for one acidic fly ash sample in the Battelle chemical characterization
study. These were the only exceedances based on 23 samples. Cadmium was found
at a concentration 150 times the PDWS in calcium-based dry scrubber sludge
leachate and at a concentration 140 times the PDWS in some coal ash leachate as
reported in the Tetra Tech study; these leachates were extracted using the EP
test method. For both types of waste, however, the exceedances represented the
maximum concentrations; all averages of cadmium concentration levels were below
100 times the PDWS. In fact, the geometric mean of cadmium in coal ash
-------
EXHIBIT 5-8
EP TLOClClTX TEST RESULTS OP LOW VDUMK
HASTES BEFORE AND AFTER CO-DISEOSAL*
(BR/L)
Midwestern Bituminous Coal Fly Ash
ELEMENT
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
RCRA
Limit
5.0
100.0
1.0
5.0
5.0
0.2
1.0
5.0
Fly Ash Haste
0.006
0.006
0.02
0.01
0.002
0.0002
0.028
0.02
EDTA
Waste
0.006
0.76
3
A. 7
3.6
0.0002
0.002
0.002
EDTA Waste
Co-disposed
With Ash
0.026
0.23
0.02
0.01
0.008
0.0002
0.006
0.02
Citrate
Waste
0.21
1.6
0.64
3.9
0.002
0.0002
0.003
0.006
Citrate' Waste
Co-disposed
With Ash
0.037
0.006
0.02
0.01
0.002
0.0002
0.002
0.02
General
Wastewater
0.003
1.2
0.008
0.11
0.002
0.0002
0.003
0.009
Wastewater
Co-disposed
With Ash
0.031
0.17
0.02
0.01
0.002
0.0002
0.002
0.02
Southeastern Bittrainoua Coal Fly Ash
0*
ELEMENT
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
RCRA
Limit
5.0
100.0
1.0
5.0
5.0
0.2
1.0
5.0
Fly Ash Waste
0.037
N/A
0.02
0.036
0.002
0.0002
0.003
0.02
EDTA
Waste
0.006
0.76
3
4.7
3.6
0.0002
0.002
0.002
EDTA Waste
Co-disposed
With Ash
0.036
0.33
0.02
0.01
0.002
0.0003
0.015
0.02
Citrate
Waste
0.21
1.6
0.64
3.9
0.002
0.0002
0.003
0.006
Citrate Haste
Co-disposed
With Ash
N/A
0.006
0.02
0.15
0.004
0.0002
0.082
0.02
General
Hastewater
0.003
1.2
0.008
0.11
0.002
0.0002
0.003
0.009
Wastewater
Co-disposed
With Ash
0.042
0.47
0.085
0.01
0.023
0.0002
0.003
0.02
-------
EXHIBIT 5-8 (Continued)
ELEMENT
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
RCRA
Limit
5.0
100.0
1.0
5.0
5.0
0.2
1.0
5.0
Fly Ash Waste
0.006
0.94
0.02
0.01
0.002
0.0002
0.034
0.02
EDTA
Waste
0.006
0.76
3
4.7
3.6
0.0002
0.002
0.002
> TUKICITY TEST KESULTS OF LOW VOLUME
HASTES BKVUtK AID AFTER CODISPOSAL
(•C/L)
Western SubbituBinooa
EDTA Haste
Co-disposed
With Ash
0.08
0.7
0.02
0.01
0.041
0.0002
0.026
0.02
Coal Fly Ash
Citrate
Waste
0.21
1.6
0.64
3.9
0.002
0.0002
0.003
0.006
Citrate Waste
Co-disposed
With Ash
0.45
0.43
0.02
0.01
0.002
0.0002
0.031
0.02
General
Wastewater
0.003
1.2
0.008
0.11
0.002
0.0002
0.003
0.009
Wastewater
Co-disposed
With Ash
0.005
0.8
0.02
0.01
0.002
0.0002
0.003
0.02
N>
*A11 underlined values indicate an exceedance of the current RCRA limit for hazardous wastes.
Source: Manual for Management of Low-Volume Wastes From Fossil-Fuel-Fired Power Plants. Electric Power Research Institute,
prepared by Radian Corporation, Austin, Texas, July 1987.
-------
5-28
leachates in the Tetra Tech study was just under 0.5 of the PDWS.
For the low-volume waste streams, the only exceedance of EP toxicity limits
for wastes other than boiler cleaning waste was one wastewater brine sample that
had selenium at 150 times the PDWS. The mean concentration of selenium in the
wastewater brine samples was below EP toxicity limits. While untreated boiler
cleaning wastes had exceedances of EP toxicity limits for chromium and lead, as
noted above, EP toxicity tests on neutralized boiler cleaning wastes and on
boiler cleaning wastes co-disposed with fly ash showed no exceedances of EP
limits.
5.2 EFFECTIVENESS OF WASTE CONTAINMENT AT UTILITY DISPOSAL SITES
Coal combustion wastes contain trace elements that at certain levels could
pose a potential danger to human health and the environment if they migrate from
the disposal area. The extraction procedure tests described in Section 5.1.2
indicate that these trace elements may leach out of disposed wastes, although
rarely at concentrations greater than 100 times the PDWS. This section of the
report analyzes studies of ground-water and surface-water quality at and around
utility disposal sites to ascertain whether potentially hazardous constituents
that leach out of the waste migrate into surrounding ground water or surface
water. The studies discussed in this section use as a measure of water quality
the concentration of Primary Drinking Water Standards (PDWS) and Secondary
Drinking Water Standards (SOWS) constituents in the water around utility waste
disposal sites. Primary and Secondary Drinking Water Standards were established
in the Safe Drinking Water Act. Primary Drinking Water Standards establish
concentration limits for toxic constituents. Secondary Drinking Water Standards
-------
5-29
are based on aesthetic characteristics such as taste, color, and odor. Exhibit
5-9 shows the current PDWS and SDWS. If ground water and surface water
downgradient from waste disposal sites have concentrations of constituents in
excess of PDWS or SDWS, and upgradient concentrations are below the standards or
are lower than the downgradient concentrations, the coal combustion waste could
be one of the sources contributing to ground water or surface water
contamination.
EPA has conducted a number of studies on the quality of ground water in the
immediate vicinity of utility disposal sites. Arthur D. Little performed
extensive ground-water monitoring at six utility disposal sites. In a second
study, Franklin Associates compiled data from state records on ground-water
quality in the vicinity of 66 utility disposal sites. This section also reviews
and evaluates a study conducted by Envirosphere for USWAG on available data on
ground-water quality at 23 electric utility sites to evaluate whether and to
what extent occurrences of ground-water contamination have resulted from the
disposal of coal combustion wastes.
5.2.1 ADL Study of Waste Disposal at Coal-Fired Power Plants
Arthur D. Little, Inc. (ADL), conducted a three-year study for EPA's Office
of Research and Development to assess the environmental effects and engineering
costs associated with coal ash and flue gas desulfurization waste disposal
22
practices at six coal-fired power plants. Appendix E contains a detailed
discussion of the study, including how the six sampled sites were selected, the
study approach, and results for each site. A summary of the six sites is
presented below:
-------
5-30
EXHIBIT 5-9
PRIMARY DRINKING WATER STANDARDS
Concentration
Contaminant
Arsenic •
Barium
Cadmium
Chromium
Fluoride
Lead
Mercury
Nitrate (as N)
Selenium
Silver
0.
1.
.05
.0
0.01
0.05
4.0
0.05
0.002
10.0
0.01
0.05
SECONDARY DRINKING WATER STANDARDS
Contaminant
Chloride
Color
Copper
Corrosivity
Foaming Agents
Iron
Manganese
Odor
PH
Sulfate
Total Dissolved Solids
Zinc
Level
250 mg/1
15 color units
1.0 mg/1
Noncorrosive
0.5 mg/1
0.3 mg/1
0.05 mg/1
3 Threshold odor number
6.5 - 8.5
250 mg/1
500 mg/1
5.0 mg/1
Source: 40 CFR 141 and 143, September 1, 1986.
-------
5-31
The Allen Plant in North Carolina disposed of a mixture
of fly ash and bottom ash in two unlined disposal ponds,
one closed and one in active use. Intermittent waste
streams, such as boiler wastes and coal pile runoff, were
also disposed in the ponds. While concentrations of
trace elements in downgradient ground water were higher
than upgradient concentrations, exceedances of the
Primary Drinking Water Standards were not found.
Elevated concentrations of arsenic (up to 31 times the
PDWS) were found in fluids within the active ash pond.
Attenuation tests indicated that the arsenic
concentrations would be chemically attenuated by iron and
manganese in the soils beneath and surrounding the site.
Ground-water contamination, particularly from arsenic,
could have resulted if these attenuative soils had not
been present. Secondary Drinking Water Standards were
exceeded in both the upgradient and downgradient ground
water for manganese and in the downgradient ground water
for iron. This was attributed to high concentrations of
these elements present in the soils of the site.
Steady-state conditions have probably not been achieved
at the Allen site; increases in downgradient ground-water
concentrations of non-attenuated contaminants may be
expected in the future.
The Elrama Plant in western Pennsylvania disposed a
fixated FGD sludge-fly ash mixture, along with small
volumes of bottom ash and sludge from coal pile runoff
treatment ponds, in an abandoned coal-mining area 12
miles from the plant. Part of the landfill is underlain
by acid-producing spoils from the strip mining of coal.
Cadmium was found in concentrations exceeding the Primary
Drinking Water Standard by as much as 20 times in
downgradient ground water; the highest concentration was
found in the well closest to the landfill. There were no
upgradient exceedances for cadmium. Steady-state
conditions did not appear to have been achieved at the
site, so that effects of leachate from the landfill may
be expected to increase with time. Secondary Drinking
Water Standards (for pH, manganese, sulfate, and iron)
were exceeded at the site in both upgradient and
downgradient ground water. These exceedances probably
occurred because of characteristics of the disposal area
and because ground water was already contaminated from
acid mine drainage. Test results indicated that any
constituent migration from the landfill did not
measurably affect the water quality of the nearby
Youghiogheny River.
Arsenic was repeatedly detected at levels three to five
times the Primary Drinking Water Standard in pond
liquors, but appeared to be attenuated by soils at the
site. This suggests the possibility that similar wastes
-------
5-32
at other sites could leach arsenic at higher levels if
arsenic were not attenuated by surrounding soils or
diluted before reaching drinking water.
The results discussed above indicate that the fixated
FGD/fly ash wastes have been, and will continue to be, a
source of contamination at the site. Because
exceedances for many contaminants were probably due to
concurrent contamination from acid mine drainage,
leachate from coal combustion waste may have only a small
incremental impact on water quality.
The Dave Johnston plant in Wyoming is located in an arid
region with little ground-water recharge. The plant is
the oldest of the six sites, and burns low-sulfur western
coal. There are a number of disposal areas at the site;
the ADL study investigated two unlined fly ash landfills,
one active and one closed. Exceedances of the Primary
Drinking Water Standards for cadmium (up to 3 times the
PDWS) were found in ground water upgradient and
downgradient of the site. .Cadmium was found at elevated
concentrations in pond liquors and ground water beneath
the wastes. Exceedances of Secondary Drinking Water
Standards for manganese and sulfate were also observed in
downgradient and upgradient ground water. These two
contaminants and boron were found in elevated
concentrations in ground water beneath the waste and in
pond liquors. No samples were analyzed for the presence
of arsenic in the pond liquors. Chemical attenuation by
soils at the site was found to be low for trace metals
such as arsenic.Interpretations of the sampling results
were difficult to make because other potential
contamination sources exist, such as other waste disposal
areas at the site (the location and ages of which are
uncertain) and contaminants naturally occurring in the
soil, which is highly mineralized around the Johnston
site; and uncertainties with regard to what degree
leachate from the two landfills had reached the
downgradient wells. Contamination from the site could
possibly increase until steady-state concentrations are
reached.
The Sherburne County Plant in central Minnesota disposed
of fly ash and FGD waste in one clay-lined pond and
bottom ash in an adjacent clay-lined pond. Exceedances
of the Primary Drinking Water Standards were observed in
both upgradient and downgradient ground water for cadmium
(up to 2 times the PDWS for both) and for nitrate, and in
downgradient ground water for chromium (up to 1.2 times
the PDWS). Pond liquors were found to exhibit high
concentrations of several constituents, including cadmium
(up to 30 times the PDWS), chromium (up to 16 times the
PDWS), fluoride, nitrate, lead (up to 28 times the PDWS),
and selenium (up to 25 times the PDWS). While the pond
-------
5-33
liquors exhibited high concentrations of contaminants,
leachate from these wastes did not appear to have
migrated into and mixed with ground water to a great
extent. Ground-water samples collected at the site
seemed to indicate that a few constituents (sulfate and
boron) had migrated from the wastes, but not at levels
exceeding SOWS. The clay liner appeared to have
significantly reduced the rate of release of leachate
from the disposal ponds, precluding the development of
elevated trace metal concentrations at downgradient
wells. Over time, downgradient wells will likely show
increased levels of contamination, since steady-state
conditions had not been achieved between leachate from
the landfill and the ground water. Without the clay
liner, the leachate seepage rate would probably have been
much greater. Since the surrounding soils may not
chemically attenuate selenium, this contaminant might
cause PDWS exceedances once steady-state concentrations
in ground water are reached.
The Powerton Plant disposed fly ash, bottom ash, and slag
in an older landfill approximately one mile south of the
site. In a newer portion of the landfill, disposal
operations consisted of disposing intermixed fly ash and
slag. The newer landfill and part of the older one are
underlain by a liner consisting of ash and lime. The
downgradient ground-water wells exhibited levels of
cadmium up to three times the Primary Drinking Water
Standard and, in one sample, lead at four times the PDWS.
An upgradient well, located on the border of the landfill
wastes, exhibited a concentration of cadmium at the level
of the Primary Drinking Water Standard. Secondary
Drinking Water Standards for iron, manganese, and sulfate
were exceeded in downgradient wells, and for manganese in
an upgradient well (but at a level of exceedance lower
than the downgradient measurements). These results
indicate that leaching and migration of ash wastes had
occurred at the site, but it was difficult to determine
the effect the leachate had, or will have, on
ground-water quality. Dilution and chemical attenuation
may have prevented the buildup at downgradient locations
of significant concentrations of trace metals such as
arsenic and selenium. The degree to which Lost Creek, a
nearby downgradient stream, was diluting waste
constituents that reach it may be significant.
The Lansing Smith plant in southern Florida disposed a
mixture of fly ash and bottom ash in an unlined disposal
pond located in a coastal area. Concentrations greater
than the Primary Drinking Water Standards were observed
for cadmium (up to five times the PDWS), chromium (up to
four times the PDWS), and fluoride in the downgradient
ground water at the site and, with the possible exception
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5-34
of fluoride, appeared to be due largely to the leaching
of the ponded ash wastes. Exceedances of Secondary
Drinking Water Standards for sulfate, chloride,
manganese, and iron were also observed in downgradient
ground water. However, most of these contaminants are
seawater-related and their reported concentrations
appeared to be influenced by the use of seawater in plant
operations and infiltration of estuarine (saline) water
at the site. The leachate generated migrates to a
shallow, unused, tidal aquifer. These results indicate
that ash disposal at this site appears to have had a
measurable impact on ground-water quality. Health risks
at this particular site, however, were probably minimal
since the ground water and surface water were not used as
a source of drinking water.
5.2.1.1 Ground-water Sanpling
Exhibits 5-10 and 5-11 summarize the results of the ADL ground-water quality
data at the six disposal sites for constituents with established Primary and
Secondary Drinking Water Standards, respectively. As can be seen from Exhibit
5-10:
One site had no exceedances of PDWS constituents, either
upgradient or downgradient.
One site had PDWS exceedances for cadmium only, with the
same maximum PDWS exceedance upgradient and downgradient.
One site had downgradient PDWS exceedances for cadmium,
chromium, and nitrate, but for cadmium and nitrate the
upgradient exceedances were at least as large as the
downgradient exceedances. There were no upgradient
exceedances of chromium; the one downgradient exceedance
was 1.2 times PDWS.
The three remaining sites had downgradient PDWS
exceedances for cadmium that were more frequent and
larger than upgradient exceedances. The largest
downgradient exceedance for cadmium at any of the six
sites was 20 times the PDWS.
There were no upgradient chromium exceedances and only
three exceedances out of 94 downgradient observations.
Two of the downgradient exceedances were 1.2 times the
PDWS and one was 4 times the PDWS. These three
exceedances were at three different sites.
-------
5-35
EXHIBIT 5-10
SUMMARY OF ARTHUR D. LITTLE'S GROUND-WATER
QUALITY DATA ON PRIMARY DRINKING WATER EXCEEDANCES
Units = pprn
PDWS
••
2/ Drinking
Contain. Water
Standard
Arsenic 0.05
(liq.)
Barium 1
Cadmium 0.01
Chromium 0.05
(Cr VI)
Fluoride 4.0
Lead 0.05
Mercury 0.002
Nitrate 5/ 45
Selenium 0.1
(liq.)
Silver 0.05
Allen Site
V
Downgrade ent
(11 wells)
3/ 4/
Exceed./ Max.
Total Exceed.
—
0/12
0/31
0/31
0/31
0/34
0/31
0/0
0/34
0/5
0/31
V
Upgradient
(1 well)
...............
3/ 4/
Exceed./ Max.
Total Exceed.
0/2
0/3
0/3
0/3
0/4
0/3
0/0
0/4
0/2
0/3
New Elrama Site
V
Downgradient
(5 wells)
3/ 4/
Exceed./ Max.
Total Exceed.
0/1
0/19
3/19 20
1/19 1.2
0/21
0/19
0/0
0/20
0/1
0/19
V
Upgradient
(1 well)
...............
3/ 4/
Exceed./ Max.
Total Exceed.
0/2
0/4
0/4
0/4
0/4
0/4
0/0
0/4
0/2
0/4
Dave Johnston S
V
Downgradient
(3 wells)
1...............
3/ 4/
Exceed./ Max.
Total Exceed.
0/2
0/9
6/9 3
0/9
0/12
0/9
0/0
0/12
0/2
0/9
'te
V
Upgradient
(2 wells)
I...............
3/ 4/
Exceed./ Max.
Total Exceed.
0/3
0/6
3/6 3
0/6
0/8
0/6
0/0
0/8
0/3
0/9
V For specific site descriptions, including lists and maps of wells used for data,
see Appendix E.
2/ Where the reported detection limit for a contaminant was greater than the drinking
water standard and the sample contained less contaminant than the reported detection
limit, the sample is tabulated as being below the drinking water standard. For a more
detailed explanation, see Appendix E.
3/ The number of samples with reported concentrations above the drinking water standard (slash)
the total number of samples.
4/ Max. Exceed, is the concentration of the greatest reported exceedance divided
by the drinking water standard for that particular contaminant.
5/ The PDWS for nitrate measured as N is 10 ppm.
-------
5-36
EXHIBIT 5-10 (Continued)
SUMMARY OF ARTHUR D. LITTLE'S GROUND-WATER
QUALITY DATA ON PRIMARY DRINKING WATER EXCEEDANCES
Units z ppm
PDUS
2/ Drinking
Contain. Water
Standard
Arsenic 0.05
(liq.)
Bar inn 1
Cadmiun 0.01
Chromium 0.05
(Cr VI)
Fluoride 4.0
Lead 0.05
Mercury 0.002
Nitrate 5/ 45
Selenium 0.1
(liq.)
Silver 0.05
Sherburne Count'
I/
Downgradient
(3 wells)
3/ 4/
Exceed./ Max.
Total Exceed.
0/3
0/12
2/12 2
1/12 1.2
0/12
0/12
0/0
2/12 1.1
0/3
0/12
f Site
I v
Upgradient .
(2 wells)
3/ 4/
Exceed./ Max.
Total Exceed.
0/3
0/8
2/8 2
0/8
0/8
0/8
0/0
2/8 27
0/3
0/8
Powerton Statioi
I
V
Downgradient
(3 wells)
3/ 4/
Exceed./ Max.
Total Exceed.
0/8
0/9
8/9 3
0/9
0/9
1/9 4
0/0
0/9
0/8
0/9
i Site
1 v
Upgradient
(1 well)
1
3/ 4/
Exceed./ Max.
Total Exceed.
0/2
0/4
2/4 1
0/4
0/4
0/4
0/0
2/4 1.1
0/2
0/4
Lansing Smith S
I
V
Downgradient
(5 wells)
3/ 4/
Exceed./ Max.
Total Exceed.
0/5
0/14
10/14 5
1/14 4
5/14 13.5
0/14
0/0
0/0
0/5
0/14
team Plant
I v
Upgradient
(3 wells)
3/ 4/
Exceed./ Max.
Total Exceed.
0/4
0/6
2/6 2
0/6
0/6
0/6
0/0
0/0
0/4
0/6
1/ For specific site descriptions, including lists and maps of wells used for data,
see Appendix E.
2/ Where the reported detection limit for a contaminant was greater than the drinking
water standard and the sample contained less contaminant than the reported detection
limit, the sample is tabulated as being below the drinking water standard. For a more
detailed explanation, see Appendix E.
3/ The number of samples with reported concentrations above the drinking water standard (slash)
the total number of samples.
4/ Max. Exceed, is the concentration of the greatest reported exceedance divided
by the drinking water standard for that particular contaminant.
5/ The PDWS for nitrate measured as N is 10 ppm.
-------
5-37
EXHIBIT 5-11
SUMMARY OF ARTHUR D. LITTLE'S GROUND-WATER QUALITY
DATA ON SECONDARY DRINKING WATER EXCEEDANCES
Units = ppm
SOWS
2/ Drinking
Contain. Water
Standard
Chloride 250
Copper 1
Iron 0.3
Manganese 0.05
Sulfate 250
Zinc 5
pH Lab 5/ <=6.5
>=8.5
pH Field 5/ <=6.5
>=8.5
Allen Site
V
Downgradient
(11 wells)
3/ 4/
Exceed./ Max.
Total Exceed.
0/34
0/31
7/31 82
19/31 102
0/34
0/31
10/10 4.7
0/10
21/28 4.4
0/28
V
Upgradient
(1 well)
3/ 4/
Exceed./ Max.
Total Exceed.
0/4
0/3
0/3
1/3 1.4
0/3
0/3
1/1 5.9
0/1
2/3 6.2
0/3
New Elrama Site
V
Downgradient
(5 wells)
3/ 4/
Exceed./ Max.
Total Exceed.
0/21
0/19
0/19
19/19 456
9/19 4.7
0/19
0/0
0/0
9/14 5.2
0/14
v
Upgradient
(1 well)
3/ 4/
Exceed./ Max.
Total Exceed.
0/4
0/4
1/4 1.8
4/4 197
3/4 1.5
0/4
0/0
0/0
2/2 4.5
0/2
Dave Johnston S
V
Downgradient
(3 wells)
. .............
3/ 4/
Exceed./ Max.
Total Exceed.
0/12
0/9
0/9
1/9 3.2
12/12 5.8
0/9
0/0
0/0
0/9
0/9
te
v
Upgradient
(2 wells)
...............
3/ 4/
Exceed./ Max.
Total Exceed.
0/8
0/6
0/6
1/6 4.6
4/8 5.1
0/6
0/0
0/0
0/6
0/6
V For specific site descriptions, including lists and maps of the wells used for data,
see Appendix E.
2/ Where the reported detection limit for a contaminant was greater than the drinking
water standard and the sample contained less contaminant than the reported detection
limit, the sample is tabulated as being below the drinking water standard. For a more
detailed explanation, see Appendix E.
3/ The number of samples with reported concentrations above the drinking water standard (slash)
the total number of samples.
4/ Max. Exceed, is the concentration of the greatest reported exceedance divided
by the drinking water standard for that particular contaminant. The only
exception is for pH, where Max. Exceed, is the actual measurement.
5/ As indicated in footnote 15, the Max. Exceed column for the reported pH measurements
is a tabulation of the actual measurements, not the maximum exceedance divided by
the drinking water standard.
-------
5-38
EXHIBIT 5-11 (Continued)
SUMMARY OF ARTHUR D. LITTLE'S GROUND-WATER QUALITY
DATA ON SECONDARY DRINKING WATER EXCEEDANCES
Units = ppm
SOWS
2/ Drinking
Contain. Water
Standard
Chloride 250
Copper 1
Iron 0.3
Manganese 0.05
Sulfate 250
Zinc 5
pH Lab 5/ <=6.5
>=8.5
pH Field 5/ <=6.5
>=8.5
Sherburne Count)
V
Downgradient
(3 wells)
...............
3/ 4/
Exceed./ Max.
Total Exceed.
0/12
0/12
0/12
2/12 22
0/12
0/12
0/0
0/0
0/8
0/8
f Site
v
Upgradient
(2 wells)
3/ 4/
Exceed./ Max.
Total Exceed.
0/8
0/8
1/8 1.9
1/8 1.4
0/8
0/8
0/0
.
0/0
0/6
0/6
Powerton Statior
V
Downgradient
(3 wells)
...............
3/ 4/
Exceed./ Max.
Total Exceed.
...............
0/9
0/9
4/9 42
9/9 194
6/9 2.7
0/9
0/0
0/0
1/9 6
0/9
i Site
v
Upgradient
(1 well)
...............
3/ 4/
Exceed./ Max.
Total Exceed.
0/4
0/4
0/4
2/4 11
0/4
0/4
0/0
0/0
0/3
0/3
Lansing Smith S
V
Downgradient
(5 wells)
...............
3/ 4/
Exceed./ Max.
Total Exceed.
14/14 22.4
0/14
14/14 118
13/14 17.2
8/14 8.4
0/14
4/6 4.4
0/6
10/13 2.9
0/13
team Plant
V
Upgradient
(3 wells)
...............
3/ 4/
Exceed./ Max.
Total Exceed.
0/6
0/6
6/6 37
2/6 1.4
0/6
0/6
1/2 6.5
J
0/2
4/6 6
0/6
I/ For specific site descriptions, including lists and maps of the wells used for data,
see Appendix E.
21 Where the reported detection limit for a contaminant was greater than the drinking
water standard and the sample contained less contaminant than the reported detection
limit, the sample is tabulated as being below the drinking water standard. For a more
detailed explanation, see Appendix E.
3/ The number of samples with reported concentrations above the drinking water standard (slash)
the total number of samples.
4/ Max. Exceed, is the concentration of the greatest reported exceedance divided
by the drinking water standard for that particular contaminant. The only
exception is for pH, where Max. Exceed, is the actual measurement.
5/ As indicated in footnote 15, the Max. Exceed column for the reported pH measurements
is a tabulation of the actual measurements, not the maxinun exceedance divided by
the drinking water standard.
-------
5-39
• One site had downgradient PDWS exceedances for fluoride
in 5 of 14 samples. The maximum exceedance was 13.5
times the PDWS. There were no upgradient PDWS
exceedances for fluoride at any of the six sites.
• There were no lead exceedances upgradient and only one
PDWS exceedance out of 94 downgradient observations at 4
times the PDWS.
• The contaminants of most concern at the six sites appear
to be cadmium and, to a lesser extent, chromium. For
both of these contaminants, three sites had exceedances
of the PDWS in downgradient ground water at levels higher
than were found in upgradient ground water.
For constituents for which there are Secondary Drinking Water Standards,
exceedances in downgradient ground water generally were higher than levels
observed in upgradient wells. Results are shown in Exhibit 5-11.
5.2.1.2 Surface Water Sampling
Exhibit 5-12 summarizes the results of surface-water quality data obtained
by ADL at background, peripheral, and downstream locations at three of the study
sites -- Elrama, Powerton, and Lansing Smith -- for constituents with
established Primary and Secondary Drinking Water Standards. Examination of
these results for PDWS constituents indicates that:
At the Lansing Smith site, downgradient and peripheral
surface water samples showed cadmium concentrations up to
5 times the PDWS, chromium concentrations up to 1.2 times
the PDWS, and fluoride concentrations up to 20 times the
PDWS. No upgradient samples were collected at the
Lansing Smith site.
Exceedances were found for cadmium (up to 2 times the
PDWS) and nitrate (up to 1.2 times the PDWS) in both
upgradient and downgradient surface water at the Powerton
site. The exceedances were similar in upgradient and
downgradient samples both in terms of the proportion of
samples in which exceedances were found and the magnitude
of the exceedances.
-------
5-40
EXHIBIT 5-12
SUMMARY OF ARTHUR D. LITTLE'S SURFACE-WATER QUALITY DATA
ON PRIMARY AND SECONDARY DRINKING HATER EXCEEDANCES
Units - ppn |New Elrama Site
(Powerton Station Sit*
(Lansing Smith Steam Plant
POWS
2/ Drinking
Contan. Water
Standard
Arsenic 0.05
(liq.)
Barium 1
Cadmium 0.01
Chromium 0.05
(Cr V!)
Fluoride 4.0
Lead 0.05
Mercury 0.002
Nitrate 5/ 45
Selenium 0.1
(liq.)
Silver 0.05
V
Downgradient
(4 stations)
3/ 4/
Exceed./ Max.
Total Exceed.
..........
0/1
0/7
0/7
0/7
0/7
0/7
0/0
0/7
0/1
0/7
V
Upgradient
(1 station)
3/ 4/
Exceed./ Max.
Total Exceed.
...............
0/1
0/3
0/3
0/3
0/3
0/3
0/0
0/3
0/1
0/3
»/
Downgradient
(1 station)
3/ 4/
Exceed./ Max.
Total Exceed.
...
0/1
0/3
2/3 2
0/3
0/3
0/3
0/0
1/3 1.1
0/1
-
0/3
V
Upgradient
(3 stations)
3/ 4/
Exceed./ Max.
Total Exceed.
0/2
0/8
5/8 2
0/8
0/8
0/8
0/0
3/7 1.2
0/2
0/8
V
Downgradient
(6 stations)
3/ 4/
Exceed./ Max.
Total Exceed.
0/2
0/13
10/13 5
0/13
5/13 6.5
0/13
0/0
0/0
0/2
0/13
V
Peripheral
(3 stations)
""
3/ 4/
Exceed./ Max.
Total Exceed.
0/1
0/8
4/8 4
0/8
2/8 2
0/8
0/0
0/0
0/1
0/8
V
Downgradient
Saline
(2 stations)
3/ 4/
Exceed./ Max.
Total Exceed.
0/3
0/5
5/5 4
1/5 1.2
2/5 20
0/5
0/0
0/0
0/3
0/5
I/ For specific site descriptions, including lists and maps of the stations used for data,
see Appendix E. Peripheral stations are neither upgradient nor downgradient of the site.
These stations are located across the gradient from the site, and may become contaminated
by lateral dispersion of waste constituents.
2/ Where the reported detection limit for a contaminant was greater than the drinking
water standard and the sample contained less contaminant than the reported detection
Unit, the sample is tabulated as being below the drinking water standard. For a more
detailed explanation, see Appendix E.
3/ The number of samples with reported concentrations above the drinking water standard (slash)
the total nurter of samples.
4/ Max. Exceed, is the concentration of the greatest reported exceedance divided
by the drinking water standard for that particular contaminant.
5/ The PDUS for nitrate measured as N is 10 ppn.
-------
5-41
EXHIBIT 5-12 (Continued)
SUMMARY OF ARTHUR D. LITTLE'S SURFACE-WATER QUALITY DATA
ON PRIMARY AND SECONDARY DRINKING HATER EXCEEDANCES
Units « ppm (New Elrama Site
|Pow*rton Station Site
|Lansing Smith Steam Plant
SOUS
if Drinking
Contain. Water
Standard
Chloride 250
Copper 1
Iron 0.3
Manganese 0.05
Sulfate 250
Zinc 5
pH Lab 5/ «6.5
>-8.5
pti Field 5/ «6.5
>«8.5
V
Downgradient
(4 stations)
3/ 4/
Exceed./ Max.
Total Exceed.
0/7
0/7
0/7
7/7 7.4
0/7
0/7
0/0
0/0
4/7 6.1
0/7
I V
Upgradient
(1 station)
3/ 4/
Exceed./ Max.
Total Exceed.
0/3
0/3
0/3
3/3 4.2
0/3
0/3
0/0
0/0
2/3 6
0/3
1
V
Downgradient
(1 station)
3/ 4/
Exceed./ Max.
Total Exceed.
0/3
0/3
0/3
2/3 2.2
0/3
0/3
0/0
0/0
0/3
1/3 8.5
V
Upgradient
(3 stations)
...............
3/ 4/
Exceed./ Max.
Total Exceed.
0/8
0/8
0/8
2/8 1
0/8
0/8
0/0
0/0
0/8
2/8 8.5
V
Downgradient
(6 stations)
...............
3/ 4/
Exceed./ Max.
Total Exceed.
13/13 11.9
0/13
11/13 370
11/13 64
12/13 7.5
0/13
5/6 3.3
0/6
5/10 4.1
0/10
V
Peripheral
(3 stations)
3/ 4/
Exceed./ Max.
Total Exceed.
5/8 10
0/8
6/8 34
6/8 4.8
4/8 3.4
0/8
2/3 3.8
0/3
4/7 3.4
0/7
VI
Doungradfent
Saline
(2 stations)
3/ 4/
Exceed./ Max.
Total Exceed.
...... — ......
5/5 58
0/5
0/5
0/5
5/5 9.9
0/5
0/1
0/1
0/5
0/5
I/ For specific site descriptions, including lists and maps of the stations used for data,
see Appendix E. Peripheral stations are neither Upgradient nor downgradient of the site.
These stations are located across the gradient from the site, and may becom contaminated by
lateral dispersion of waste constituents.
21 Where the reported detection limit for a contaminant was greater than the drinking
water standard and the sample contained less contaminant than the reported detection
limit, the sample is tabulated as being below the drinking water standard. For a more
detailed explanation, see Appendix I.
3/ The number of samples with reported concentrations above the drinking water standard (slash)
the total number of samples.
4/ Max. Exceed, is the concentration of the greatest reported exceedance divided
by the drinking water standard for that particular contaminant. The only
exception is for pN, where Max. Exceed, is the actual measurement.
5/ As indicated in footnote 10, the Max. Exceed, column for reported pM measurements
is a tabulation of the actual measurements, not the maximum exceedance divided by
the drinking water standard.
-------
5-42
No exceedances of PDWS were found upgradient or
downgradient at the Elrama site, although there had been
downgradient exceedances at Elrama in ground water for
cadmium and chromium.
5.2.1.3 Waste Fluid Sampling
In addition to ground-water monitoring, waste fluid samples were
collected from the waste ponds at the Allen, Sherburne County, and Lansing
Smith sites, and from dry fly ash landfills at the Dave Johnston site.
Water from within and beneath FGD sludge and fly ash waste mixtures were
collected from the Elrama landfill. No waste fluid samples were obtained
at the Powerton site. Key observations are presented below.
Arsenic was present in the waste fluids at elevated
concentrations (up to 31 times the Primary Drinking Water
Standard) at two of the five sites sampled. At these
sites (Allen and Elrama), arsenic may be attenuated by
soils at the site; attenuation tests indicate the soils
had a moderate to high attenuation capacity, and no
exceedances for arsenic were observed in ground water at
the sites. The Dave Johnston site was the only disposal
area where soils were found to have low attenuation
capacities for arsenic; however, there are no data
pertaining to waste fluids at this site, and exceedances
for arsenic in the ground water were not observed. These
results indicate that, depending on the coal source,
arsenic may occur at elevated concentrations in waste
fluids, but can be attenuated by soils within and
surrounding a coal combustion waste disposal site. If
the soils at a disposal site have low attenuation
capacities for arsenic, this element may be of concern
with regard to ground water and surface water
contamination.
Cadmium is present at elevated concentrations (up to 30
times the Primary Drinking Water Standard) in the waste
fluids at all five sites. At Powerton, although no waste
fluid samples were taken, ground-water samples obtained
from directly beneath the wastes also exhibited elevated
concentrations of cadmium. These results support the
conclusion that elevated concentrations of cadmium
observed in downgradient ground water may be attributable
to coal combustion wastes.
-------
5-43
Chromium is present at elevated concentrations (up to 21
times the Primary Drinking Water Standard) in the waste
fluids at two of the five sites. At these sites, higher
chromium concentrations were found in downgradient ground
water than were found in upgradient ground water. These
observations suggest that ground-water contamination by
chromium at these two study sites may be attributable to
the coal combustion wastes. At a third site at which
downgradient exceedances of chromium in ground water were
observed, waste fluid samples were mixed with ground
water occurring beneath the wastes during collection,
which may account for lower waste fluid concentrations at
this site.
Other constituents that were found at elevated
concentrations within the waste fluids include fluoride
at all five sites (up to 10 times the PDWS); lead at one
of five sites (up to 28 times the PDWS); nitrate at one
of five sites (up to 7 times the PDWS); and selenium at
one of four sites (up to 25 times the PDWS).
Constituents for which Secondary Drinking Water Standards
are established were found at the following elevated
concentrations: chloride at three of five sites (up to
61 times the SOWS); iron at two of five sites (up to 221
times the SDWS); manganese at four of five sites (up to
466 times the SDWS); and sulfate at four of five sites
(up to 42 times the SDWS). Exceedances of pH standards
were found in the waste fluids at two of three sites
tested. At these two sites, both acidic (as low as pH
5.9) and alkaline (as high as pH 11) conditions were
found to exist. Average pH values measured in these
waste fluids indicated that they were generally alkaline.
Results of waste fluid sampling at the Sherburne County
site showed exceedances of Primary Drinking Water
Standards for cadmium (up to 30 times PDWS); chromium (up
to 16 times the PDWS); fluoride (up to 13 times the
PDWS); lead (up to 28 times the PDWS); nitrates (up to
6.9 times the PDWS); and selenium (up to 25 times the
PDWS). Measurements also showed maximum exceedances of
Secondary Drinking Water Standards for chloride (up to
1.9 times the SDWS); iron (up to 6.1 times the SDWS);
manganese (up to 316 times the SDWS); and sulfate (up to
42 times the SDWS). This was the only site where
disposal areas or ponds were completely lined. The clay
liner appeared to have reduced the release of leachate,
thereby concentrating waste constituents.
-------
5-44
Results from waste fluid studies conducted by other organizations are
described in Appendix D.
5.2.1.4 Sumary
Results from the Arthur D. Little study suggest that under the waste
management procedures used by the facilities studied, some coal combustion waste
leachate was migrating into ground water beneath and downgradient from disposal
sites. Five sites had concentrations of cadmium in downgradient ground water
that exceeded the PDWS. Two of these five had maximum upgradient exceedances at
the same level as the maximum downgradient exceedance, and two of the sites had
upgradient concentrations that were equal to or above the PDWS, although the
maximum concentration was less than the downgradient concentrations. One of the
five sites had upgradient measurements of cadmium that were below the PDWS.
Exceedances of chromium were detected in a few ground-water samples downgradient
of three sites; there were no chromium concentrations above the PDWS in the
upgradient ground water of any site. There were no detected exceedances of
arsenic, barium, mercury, selenium, or silver in the ground water or surface
water at any of the six sites. In total, approximately 5 percent of the
downgradient observations exceeded the PDWS.
5.2.2 Franklin Associates Survey of State Ground-Water Data
EPA commissioned Franklin Associates to gather data from state regulatory
agencies on the quality of ground water at or near coal-fired electric utility
23
fly ash disposal sites. The objective of this survey was to determine the
level of ground-water contamination in the vicinity of disposal sites. However,
-------
5-45
according to the Franklin Associates report: "No attempt was made to determine
what monitoring wells might be up gradient, or what wells might be down
gradient, or even as to whether specific ash disposal sites were in fact
contributing specific pollutants."
Franklin Associates contacted 44 states in which coal-fired facilities were
located; of these 44 states, 13 provided data. The data base that was developed
included data from more than 4700 well samples taken from 66 sites.
Analysis of these samples revealed 1129 exceedances of the PDWS out of more
than 15,000 observations, as shown in Exhibit 5-13. Ninety-two percent of the
exceedances were less than ten times the PDWS; eight of the exceedances were 100
times greater than the PDWS.
There were 5952 exceedances of the SOWS out of nearly 20,000 observations as
shown in Exhibit 5-14. These secondary standards were exceeded more frequently
than the primary standards, and exceedances were usually greater. For example,
about 77 percent of the SOWS exceedances were less than 10 times the standard
(compared with 92 percent for PDWS exceedances), whereas 4 percent of the
exceedances were greater than 100 times the SOWS (compared with less than one
percent for PDWS exceedances).
Since this study did not compare upgradient and downgradient concentrations,
it is not possible to determine whether occurrences of contamination at
particular sites are the result of utility waste disposal practices or
background levels of contaminants.
-------
5-46
EXHIBIT 5-13
SUMMARY OF FDWS EXCEEDANCES IN THE FRANKLIN ASSOCIATES SURVEY
Total
Number of Observations
Exceeding PDWS Bv
Highest Exceedance
Constituent
Arsenic
Barium
Cadmium
Chromium
Fluoride
Lead
Mercury
Nitrate
Selenium
Silver
TOTAL
Observations
1995
1353
1733
1863
995
1722
1282
1432
2453
530
15,358
Source: Franklin Associates,
at Coal Combustion W;
1 X
94
108
126
92
28
243
30
204
196
8
1129
Ltd. . Summarv
aste Disposal
10 X
0
9
16
5
3
20
8
0
30
0
100 X
0
0
1
0
0
1
5
0
1
0
CX. PDWS1)
9.8
44.0
531.0
50.2
19.3
182.0
500.0
7.3
100.0
8.0
81 8
of Ground-water Contamination Cases
Sites.
prepared for
the U.S.
Environmental Protection Agency, March 1984.
-------
5-47
EXHIBIT 5-14
SUMMARY OF SDWS EXCEEDANCES IN THE FRANKLIN ASSOCIATES SURVEY
Total
Number of Observations
Exceeding SDWS Bv
Highest Exceedance
Constituent
Chloride
Copper
Iron
Manganese
pH
Sulfate
IDS
Zinc
TOTAL
Observations
2921
650
3140
1673
4107
4378
1925
1175
19,969
Source: Franklin Associates ,
at Coal Combustion W<
1 X
109
1
1942
1050
843
1059
920
5952
Ltd. . Summary
iste Disposal
10 X
14
0
862
467
-
13
24
100 X
0
0
149
80
-
0
0
rx sows}
42.0
1.2
4,000.0
2,400.0
-
23.2
28.7
4 Q 46.0
1384 229
of Ground-water Contamination Cases
Sites, prepared for
the U.S.
Environmental Protection Agency, March 1984.
-------
5-48
5.2.3 Envirosphere Ground-Water Survey
In response to the temporary exemption of utility wastes from regulation
under Subtitle C of RCRA, the Utility Solid Waste Activities Group (USWAG)
commissioned Envirosphere, Inc., to review information available from electric
24
utilities on the quality of ground water at utility waste disposal sites.
Envirosphere solicited information from 98 utilities on the number and type of
constituents they monitored, the frequency with which measurements were taken,
and the period of time for which they had collected ground-water monitoring
data. Ninety-six of the contacted utilities responded to the request for
information. From these 96 utilities, Envirosphere selected for further study
those that appeared to have adequate data on ground-water quality. These
utilities were contacted and asked to provide their available data for use in
Envirosphere's study. The participating utilities (the exact number of
utilities was not provided) forwarded the requested information to Envirosphere
on the 28 disposal facilities they operated. The utilities chose to withdraw
three of the 28 disposal sites from the study subsequent to the analysis of the
data, leaving 25 disposal sites in the data pool.
In order to analyze the data, Envirosphere paired the measurements taken at
upgradient and downgradient wells at approximately the same time and in the same
25
aquifer. These data were then compared to the applicable drinking water
standards to determine whether the standards had been exceeded. Two disposal
sites were then eliminated from further consideration because no upgradient
wells could be identified. The remaining 23 disposal sites produced a total of
9,528 paired measurements of upgradient and downgradient ground-water
concentrations.
-------
5-49
Exhibit 5-15 summarizes the information from the Envirosphere data base for
those cases where the Primary Drinking Water Standards (PDWS) were exceeded by
the downgradient measurement. The most obvious indication that a waste facility
is contributing to a PDWS exceedance is a measurement indicating downgradient
values higher than the PDWS and upgradient values lower than the PDWS.
According to Envirosphere's report, about 1.7 percent of the data fell into this
t\f
category. For those cases in which both the upgradient and downgradient
values were exceeded, Envirosphere argued that it was difficult to attribute the
exceedances to the disposal facility without further site-specific analysis.
About 5 percent of the measurements fell into this category, with 60 percent of
these indicating upgradient values equal to or greater than the downgradient
values.
Maximum concentrations of several substances significantly exceeded the PDWS
in downgradient wells: arsenic, 560 times the PDWS; lead, 480 times the PDWS;
mercury, 235 times the PDWS, and selenium, 100 times the PDWS. These values
must be compared to the maximum upgradient reading since some of the
contamination may be unrelated to the disposal facility. As shown in Exhibit
5-15, the downgradient concentration was sometimes higher than the upgradient
value even when the upgradient value exceeded the PDWS. However, exceedances of
the magnitudes shown in Exhibit 5-15 comprised a small fraction of the total
measurements in the Envirosphere data base.
The Envirosphere data also included information regarding exceedances of the
Secondary Drinking Water Standards (SOWS). A summary of these data is shown in
Exhibit 5-16. The data indicate that in 8.2 percent of the cases the
-------
5-50
EXHIBIT 5-15
SUMMARY OF PDWS EXCEEDANCES IN ENVIROSPHERE'S GROUND-HATER DATA
Downgradient Observations a/
Constituent
Arsenic
Barium
Cadmium
Total
Observations
588
298
571
Exceeding PDWS When:
Upgradient Does
Not Exceed Uogradient
Number % Number
710
000
59 10 9
Exceeds
_a_
0
0
2
Maximum
Downgradient
Observation
CX. PDWS} b/
560 (192)
1 (3)
6 (1)
Chromium
658
20
10
20
(76)
Lead
Mercury
Selenium
639
575
489
29
8
5
5
1
1
67
2
34
10
Ł/
7
480
235
100
(220)
(9)
(100)
Silver
TOTAL
261
4079
(0.2)
128
3 d/ 122
3 d/
a/ Envirosphere classified measurements by comparing downgradient values with
upgradient values. When the downgradient value exceeded the PDWS, classi-
fication depended on whether the upgradient value also exceeded the PDWS.
Both categories of measurements are shown here, although Envirosphere
focused primarily on pairs of measurements in which the downgradient value
exceeded the PDWS but the upgradient value did not.
b/ Maximum downgradient value observed in the Envirosphere data base. The
corresponding paired upgradient concentrations are not available. The
maximum upgradient value of all measurements at the same facility is shown
in parentheses.
c/ Less than 0.5 percent.
d/ These percentages apply to the total number of observations. Envirosphere
"normalized" the data to correct for sites that had a high proportion of
data points so that one site would not be overly represented; these
normalized values are noted in the text of the report.
Source: Envirosphere Company, "Report on the Ground-water Data Base
Assembled by the Utility Solid Waste Activities Group," in USWAG,
Report and Technical Studies on the Disposal and Utilization of
Fossil-Fuel Combustion Bv-Products. October 26, 1982, Appendix C.
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EXHIBIT 5-16
SUMMARY OF SDWS EXCEEDANCES IN ENVIROSPHERE'S GROUND-HATER DATA
Total
Downgradient Observations a/
Exceeding SDWS When:
Upgradient Does
Not Exceed
Constituent Observations Number
Chloride
Copper
Iron
Manganese
Sulfate
Total Dissolved
Solids
Zinc
TOTAL
502
452
964
487
1028
4
9
60
157
289
159
Upgradient Exceeds
Number %
681
1
2
6
32
28
18
JL
14 c/
7
0
376
143
57
292
3
875
1
0
39
29
6
Maximum
Downgradient
Observation
(X SDWS^ by
22 (5)
2 (0.02)
3458 (2)
474 (5)
32
(8)
32
JL
19 c/
31 (2)
1 (0.1)
a/ Envirosphere classified measurements by comparing downgradient values with
Upgradient values. When the downgradient value exceeded the SOWS,
classification depended on whether the Upgradient value also exceeded the
SOWS. Both categories of measurements are shown here, although Envirosphere
focused primarily on pairs of measurements in which the downgradient value
exceeded the SOWS but the upgradient value did not.
b/ Maximum downgradient value observed in the Envirosphere data base. The
corresponding (paired) upgradient concentrations are not available. The
maximum upgradient value of all measurements at the same facility is shown
in parentheses.
c/ These percentages apply to the total number of observations. Envirosphere
"normalized" the data to correct for sites that had a high proportion of
data points so that one site would not be overly represented; these
normalized values are noted in the text of the report.
Source: Envirosphere Company, "Report on the Ground-water Data Base Assembled
by the Utility Solid Waste Activities Group," in USWAG, Report and
Technical Studies on the Disposal and Utilization of Fossil-Fuel
Combustion By-Products. October 26, 1982, Appendix C.
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5-52
downgradient value exceeded the SDWS while the upgradient value did not. In
some cases the exceedances were substantially greater than the SDWS; e.g., the
maximum observation for iron was 3458 times greater than the SDWS and manganese
was 474 times greater.
In summary, the Envirosphere ground-water data show that Primary and
Secondary Drinking Water Standards were exceeded in ground water downgradient
from utility waste disposal facilities. However, the percentage of cases in
which constituent concentrations in downgradient wells exceeded the standards
when those in upgradient wells did not was small. There are limitations in the
data, due in part to the way in which they were collected (e.g., only data from
those utilities that voluntarily submitted data are included in the report).
There is also a limited amount of information regarding the extent to which
site-specific factors, such as environmental setting characteristics or other
possible sources of contamination, could have had an effect on ground-water
contamination.
5.2.4 Sunrmary
The studies described in this section demonstrate that downgradient
ground-water and surface-water concentrations exceeded the PDWS and SDWS for a
few constituents. In some of these downgradient exceedances, corresponding
upgradient exceedances also occurred, suggesting that the contamination was not
necessarily caused by the waste disposal sites. For cases in which the
downgradient ground water had constituent concentrations higher than the
corresponding upgradient concentrations, the PDWS exceeded most often were those
for cadmium, chromium, lead, and to a lesser extent, arsenic.
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Some PDWS exceedances were quite high, e.g., up to 560 times for arsenic and
480 times for lead (see Exhibit 5-15). However, the frequency of PDWS
exceedances for downgradient ground water and surface water is rather low. For
example, 3.7 percent of the Envirosphere data had downgradient ground-water
concentrations of PDWS higher than those measured in upgradient wells. Three of
the six Arthur D. Little sites had downgradient ground water with concentrations
of constituents that were both above the PDWS and above corresponding upgradient
concentrations. Although the Arthur D. Little pond liquor data show high
concentrations of PDWS and SOWS constituents, in most cases the constituents
appeared to be contained within the disposal area or attenuated in the
surrounding soils. This is particularly true for the case of arsenic, which was
detected in the waste fluids at a level 31 times the PDWS, but was not found at
elevated levels in ground water or surface water. There were no exceedances of
arsenic, barium, mercury, selenium, or silver in downgradient ground water at
any of the six Arthur D. Little sites. The Envirosphere study detected no
exceedances of barium or silver.
5.3 EVIDENCE OF DAMAGE
This section examines documented cases in which danger to human health or
the environment from surface runoff or leachate from the disposal of coal
combustion wastes has been proved. The first part of this section reviews two
major studies conducted for the Utility Solid Waste Activities Group (USWAG): a
1979 Envirosphere, Inc., study and a 1982 Dames and Moore study. To supplement
these two major studies, in 1987 EPA conducted a literature review of all
readily-available sources, which revealed only two additional case studies on
proven damages occurring in 1980 and 1981. The Agency has not identified any
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proven damage cases in the last seven years; however, no attempt was made to
compile a complete census of current damage cases by conducting extensive field
studies.
As with all damage cases, it is not always clear whether damages could occur
under current management practices or whether they are attributable to practices
no longer used. As described in Chapter Four, there has been an increased
tendency in recent years for utilities to utilize mitigative technologies,
including a shift to greater use of landfills rather than surface impoundments
and an increased use of liners.
5.3.1 Envirosphere Case Study Analysis
The Utility Solid Waste Activities Group (USWAG) and the Edison Electric
Institute (EEI) commissioned the Envirosphere Company in 1979 to investigate and
document available information on the nature and extent of the impact of utility
27
solid waste disposal on public health, welfare, and the environment. To
conduct this analysis, Envirosphere reviewed various reports, including EPA's
damage incident files, environmental monitoring studies at utility disposal
sites, and other research and studies as available; they contacted state
regulatory agencies to determine what information was available in state files.
From its review of the available data, Envirosphere found few documented
cases where utility solid waste disposal had potentially adverse environmental
effects. They identified nine cases from EPA's damage incident files that
appeared to show damage to the environment. Envirosphere reviewed data from
environmental monitoring studies at the utility disposal sites and other
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available research, and noted that the information available on the potential
impacts of utility waste disposal was inconclusive. Some data indicated "... -
that elevated levels of some chemical parameters have occurred at locations
downgradient of some utility solid waste disposal sites." Envirosphere
concluded, however, that it was not clear to what extent these impacts could be
attributed to utility solid waste disposal practices.
Some of the specific cases from Envirosphere's sources are summarized below:
• Texas. 1977. A clay liner was improperly installed in a
14.3 acre disposal pond for metal cleaning solutions.
The liner dried and cracked before wastes were introduced
into the facility. After the pond was put in service,
ground-water monitoring wells detected contaminant
migration. Levels of selenium and chromium occasionally
exceeded the PDWS for these elements, and several SDWS
were exceeded. The pond was taken out of service, the
liner was saturated with water, and the pond was put back
into operation.
• Indiana. 1977. Envirosphere found that leaching from two
large, unlined ash disposal ponds was contributing to
ground-water contamination. Arsenic and lead were found
in downgradient ground water at concentrations about two
times the PDWS, while concentrations of selenium were
about four times the PDWS.
• Pennsylvania. 1975. A private waste handler illegally
disposed fly ash in a marsh located in a tidal wetland
area. Visual inspections by the state indicated marsh
contamination due to fly ash leachate. When ordered to
stop the dumping and clean up the site, the handler
declared bankruptcy, and the ash remained in the marsh.
Detailed analysis of any potential impacts has not -been
conducted.
• Connecticut. 1971. A municipal landfill, which was
located in a marsh, accepted many substances, including
large quantities of fly ash. Surveys revealed numerous
SDWS contaminants, some of which appeared to be related
to the ash. The site, considered unsuitable for disposal
of solid waste, was closed and turned into a state park.
• Virginia. 1967. A dike surrounding a fly ash settling
lagoon collapsed, and 130 million gallons of caustic
solution (pH 12.0) were released into the Clinch River.
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Large numbers of fish were killed over a distance
extending 90 miles from the spill site. Surveys
conducted 10 days after the spill showed dramatic
reductions in bottom dwelling fish food organisms for 77
miles below the release site. Virtually all such
organisms were eliminated for a distance of 3 to 4 miles.
The waste was eventually diluted, dispersed, and
neutralized by natural physical/chemical processes. Two
years after the spill, however, the river had not fully
recovered.
5.3.2 Dames & Moore Study of Environmental Impacts
Dames & Moore, in a study for USWAG, conducted a survey of existing data and
literature to document instances in which danger to human health and the
environment was found to have occurred because of the disposal of coal
28
combustion wastes. Dames & Moore established criteria by which to evaluate
whether a given record of a contamination incident could be considered
"documented" evidence proving danger to health or the environment: 1) the
report must exist in the public record; 2) the case must involve high-volume
(utility) wastes; 3) information must exist to permit determination of possible
health or environmental risks; and 4) the possible risks may have been caused by
leachate migration or runoff from utility disposal sites.
The danger to health and the environment was examined by accounting for the
types, concentrations, and locations of constituents shown to be present that
could have harmful effects. In addition, Dames & Moore considered both the
potential for public access to utility waste constituents and any observed
effects on the population or environment. The three major data sources
providing information reviewed in this study were computer data bases used to
search for publicly available references; Federal Government agencies such as
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5-57
EPA, U.S. Geological Survey, and the Tennessee Valley Authority; and 12 state
environmental, natural resource, health or geological agencies.
Using information from these sources, Dames & Moore identified seven cases
that presented a potential danger to human health and the environment. Six of
the seven cases involved potential impacts from ground water and one case
involved surface water. Dames & Moore concluded that none of these cases
represented a "documented" case of such danger. However, Dames & Moore
eliminated several sites from the documented category because they believed
sufficient data from the sites were unavailable or did not meet the selection
criteria described above. Dames & Moore evaluated in detail the seven sites at
which there existed a potential for adverse environmental and health effects.
Their findings are summarized below.
Chisman Creek Disposal Site. York County. Virginia. The
Chisman Creek disposal area was an inactive site with
four separate fly ash disposal pits on both sides of
Chisman Creek. An electric utility hired a private
contractor to transport and dispose of fly ash and bottom
ash from petroleum coke (a residual product of the oil
distillation process) and coal combustion. The site was
active from the late 1950's to 1974. In 1980, nearby
residential drinking water wells became green from
contamination of vanadium and selenium and could no
longer be used. The site is currently on the CERCLA
(Superfund) National Priorities List. A minimum of 38
domestic wells and 7 monitoring wells near the four
disposal sites were sampled over time. Two off-site
domestic wells located 200 feet from the disposal area
had elevated concentrations of vanadium, selenium, and
sulfate. One of these two wells was sampled four times.
Three of the four measurements exceeded the PDWS for
selenium up to 2 times. Another domestic well contained
0.11 mg/1 of vanadium. (EPA has not established
concentration limits for vanadium.) At both wells,
sulfate concentrations exceeded the SOWS. In addition,
samples from six of the seven monitoring wells exhibited
increased concentrations of sulfates. The highest
concentrations of selenium and vanadium that were
observed in monitoring well samples were 0.03 (3 times
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5-58
the PDWS) and 30 mg/1, respectively. The high
concentrations of selenium and vanadium were noticed in
monitoring wells that were drilled directly through the
disposal pits.
The Virginia State Water Control Board (SWCB) conducted
the initial study at this site. The SWCB concluded that
the quality of ground water immediately beneath and down-
gradient from the site had been affected. Moreover, the
SWCB stated that the water in the two domestic wells had
elevated concentrations of selenium and vanadium because
of the disposal of the fly ash. Dames & Moore was
critical of the conclusions reached by the SWCB because
of what they termed "significant data gaps." Dames &
Moore cited a lack of background water quality
information and a general lack of information on the well
installation, sample collection procedures, and other
possible sources of contamination, such as the York
County landfill which is adjacent to one of the ash
disposal areas. The two contaminated off-site domestic
wells identified by the SWCB, however, were over 2,000
feet from the county landfill but within a couple of
hundred feet from the ash disposal areas. Additionally,
monitoring wells located between the landfill and the
affected domestic wells did not register the same
elevated concentrations of selenium. Residents in the
area no longer rely on ground water for their drinking
water.
Pierce Site. Wallingford. Connecticut. Coal fly ash had
been deposited at the Pierce Site since 1953. In 1978,
the United States Geological Survey (U.S.G.S.) collected
ground-water quality data from three on-site wells - one
upgradient and two downgradient. The U.S.G.S. took
samples from the wells on three days over a period of two
months. One sample from one downgradient well showed a
concentration of chromium that exceeded the PDWS by a
multiple of 1.6. Concentrations of cadmium, manganese,
zinc, and sulfate were higher in the downgradient wells
than in the upgradient well.
According to Dames & Moore, there were not enough data at
this site to state conclusively whether or not the ground
water had been adversely affected by the fly ash pit. To
determine potential damage to ground water quality, Dames
ft Moore stated that EPA recommends a minimum of three
downgradient wells and one upgradient well. In this
case, there were only two downgradient wells. Three
samples over a period of two months were not considered
sufficient because naturally occurring temporal changes
in the area were believed to render comparisons invalid.
The Pierce disposal site is situated on a deposit of
thick, stratified sediments composed of particles that
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5-59
range in size from clay to coarse sand. The disposal
site is located within a few hundred feet of the
Quinnipiac River, and the ground water flows from the
site to the river, which diluted contaminants in the
ground water. Although there are residences within a few
blocks of the power plant, they do not use local ground
water for drinking supplies.
Michigan City Site. Michigan City. Indiana. The Michigan
City site, situated on the shore of Lake Michigan,
contained two fly ash disposal ponds. Ground-water flow
at the site was towards Lake Michigan, facilitated by the
porous sand that underlies the site. Twenty-one
monitoring wells were installed at this site. Two of
these were placed upgradient from the site outside the
site boundaries; the remaining 19 wells were established
within the boundaries of the facility and downgradient
from the disposal areas.
Monitoring of the wells (which took place periodically
over a one-year period) indicated that trace metals
migrated from the disposal sites and that certain
constituents had elevated ground-water concentrations.
Arsenic and lead were observed in concentrations that
exceeded their PDWS. Seven samples collected from three
downgradient monitoring wells had arsenic concentrations
that exceeded the standard - - up to 100 times the PDWS.
All of the samples taken from the upgradient off-site
monitoring wells contained arsenic at concentrations
below the PDWS. Five of the downgradient monitoring
wells contained lead concentrations which exceeded the
PDWS, with the highest exceedance 7 times the PDWS.
Three samples from the two upgradient monitoring wells
also had lead concentrations in excess of the standard,
with the highest exceedance 3 times the PDWS.
Dames & Moore concluded that effects on ground water
appeared to be limited to areas within the facility
boundaries because of attenuation mechanisms operative at
the site -- absorption, dilution, precipitation, and a
steel slurry wall installed between the disposal site and
Lake Michigan. However, no downgradient monitoring wells
were situated off-site. Based on the locations of the
waste disposal sites and the monitoring wells, it appears
that the ash ponds are responsible for arsenic concen-
tration above the PDWS in the ground water within the
site boundaries. Because high lead concentrations were
observed in some of the upgradient background wells, it
is impossible to state with certainty that the high lead
concentrations in the ground water are attributable to
the disposal sites. Dames and Moore noted that nearby
residents do not use the ground water for their water
supply.
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Baillv Site. Dune Acres. Indiana. The Bailly site is
located near the Indiana National Lakeshore on Lake
Michigan in a highly industrialized area. Fly ash at
this site has been slurried to interim settling ponds,
which are periodically drained. The drained ash is then
disposed in an on-site pit. Two aquifer units,
designated Unit 1 and Unit 3, underlie the site. Unit 1
contains fine-to-medium sand and some gravel, while Unit
3 is composed of sand with overlying layers of varying
amounts of sand, clay and gravel.
Ground-water samples from Unit 1 were collected from an
upgradient well and from several wells downgradient from the
ash settling ponds. Samples from Unit 3 were collected
upgradient and from one well downgradient from the ash ponds.
These wells were sampled at five-week intervals between
September 1976 and May 1978.
In samples from Unit 1, arsenic, cadmium, fluoride, and
lead occasionally exceeded the PDWS. Upgradient
concentrations of arsenic never exceeded the PDWS,
whereas the maximum downgradient concentration for
arsenic was 4.6 times the PDWS. Downgradient on-site
concentrations of cadmium exceeded the PDWS at one well
by 25 times, while the maximum upgradient concentration
of cadmium exceeded the PDWS by 22 times. One
downgradient well measurement indicated lead
concentrations that exceeded PDWS by 1.26 times.
All of the above-mentioned exceedances were observed in
Unit 1. None of the samples from Unit 3 contained
constituents at concentrations that exceeded the PDWS.
Aluminum, boron, iron, manganese, molybdenum, nickel,
strontium, and zinc all increased in concentration
downgradient from the disposal areas, though not in
levels exceeding the SOWS.
Leachate from the ash disposal ponds is the most probable
contributor to the increased concentrations of arsenic
and lead observed in the aquifer samples taken from the
on-site wells. Cadmium was the only constituent whose
downgradient off-site concentration was observed to
exceed the PDWS. However, because elevated cadmium
concentrations were also found in samples taken from the
background well, the elevated concentrations of cadmium
may not have been caused by the leachate from the coal
ash. Dames and Moore noted that ground water at this
site flows away from the nearest residential area.
Zullineer Quarry Flv Ash Disposal Site. Franklin County.
Pennsylvania. The Zullinger quarry was situated in a
limestone formation in south-central Pennsylvania. The
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5-61
quarry was excavated to 40 feet below the water table.
Fly ash was deposited in the quarry from 1973 to 1980
with no attempt to dewater the quarry prior to placement
of the fly ash.
The site operator, consultants, and the Pennsylvania
Department of Environmental Resources (DER) have been
independently involved in water quality investigations at
the site. Initially, six monitoring wells were
established onsite. Later, several existing off-site
domestic wells were added to the sampling program. Two
of the monitoring wells were installed upgradient to
provide background constituent concentrations. The other
monitoring wells, and the domestic wells in the sampling
program, were downgradient from the fly ash deposited in
the quarry.
Lead was found to exceed its PDWS by up to eight times in
eight out of over 100 samples. Six of these eight
exceedances occurred in two on-site monitoring wells,
while the seventh (2.6 times PDWS) was found in an
off-site domestic well. Another exceedance (1.5 times
PDWS) was found in the background well.
Several constituents for which there are secondary
drinking water standards were found in elevated
concentrations downgradient from the ash disposal site.
Sulfate concentrations increased dramatically during the
first few years of quarry filling, then began to sharply
decline in 1976 when the fly ash had filled the quarry.
From 1976 until deactivation of the disposal site in
1980, the fly ash was deposited above the water table.
Zinc and iron were also found in elevated concentrations.
Elevated levels of sulfate, zinc, and iron are probably
attributable to leachate from the fly ash, as are the
lead levels in excess of the PDWS. Most of the trace
metals appear to be attenuated onsite by the limestone
formation.
Conesville Site. Conesville. Ohio. Various types of coal
combustion waste had been deposited at the Conesville
site in central Ohio. The monitoring program at the
Conesville site was established to determine the ability
of an FGD sludge fixation process (Poz-0-Tec, a solid
material produced by mixing FGD sludge with fly ash and
lime) to stabilize and thus immobilize potential
contaminants. The stabilized FGD sludge has been
deposited next to a fly ash pond. Permeable sand and
gravel underlie the Muskingum River flood plain on which
the Conesville site is located.
A total of 34 monitoring wells were installed at the
Conesville site. Two of the wells were situated
upgradient from the disposal area to provide the
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5-62
necessary background water quality data. Two sets of
water quality data were taken, the first between February
27 and April 12, 1979, and the second between December 4,
1979, and July 10, 1980.
Some samples from the first set of data contained
constituents at concentrations that exceeded the PDWS.
Lead concentrations exceeded the PDWS in two on-site
wells by up to 3 times and three off-site wells by up to
2 times. The concentration of mercury found in one
sample from an on-site well exceeded the PDWS by 1.4
times; however, this exceedance could not be attributed
to the fly ash. One of the fourteen background
measurements had the highest observed concentration of
selenium, 6 times the PDWS. Thus, selenium appears to be
leaching from indigenous sediments rather than from the
FGD waste and fly ash deposited at the site. The first
set of data also showed the SOWS constituents of calcium,
magnesium, total dissolved solids, sulfate, and iron, had
increased in those wells located on the site property and
just across the property boundaries.
Measurements taken between December 1979 and July 1980
showed increases in calcium, magnesium, total dissolved
solids, and sulfate relative to those measurements taken
in the first data collection period. Concentrations'in
excess of the PDWS were found for selenium (several
wells), arsenic (one sample), cadmium (four samples), and
chromium (five samples). Two of the chromium exceedances
were found in on-site wells, while three occurred in
off-site wells, with concentrations ranging up to 16
times the PDWS on-site and 2 times the PDWS off-site.
Background wells also had elevated levels of selenium.
The single arsenic exceedance (2.4 times the PDWS) and
all of the cadmium exceedances (up to 12 times the PDWS)
were detected in on-site wells. In contrast to the first
round of sampling, lead was not detected in concentra-
tions greater than the PDWS. The only constituents that
appear to be migrating offsite are lead and chromium.
Based on the data collected, it appears there may be a
temporal variation in the water quality at this site.
Dames and Moore noted that the town of Conesville is
downgradient from the site but on the other side of the
river, which would tend to mitigate potential adverse
impacts.
Hunts Brook Watershed. Montville-Waterford. Connecticut
The electric utility hired a private contractor to
transport and dispose of fly ash in three separate sites
(Chesterfield-Oakdale, Moxley Hill, and Linda Sites)
along three different tributaries to Hunts Brook.
Disposal of fly ash in this area began in the mid 1960's
and ended in 1969. The surface-water quality studies
that took place in this area focused on pH, iron,
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5-63
sulfate, and total dissolved solids (IDS). No analyses
were performed for any of the PDWS constituents.
Upstream surface water samples were compared to
downstream samples to determine if the surface water
quality had been degraded at any of the sites.
At the Chesterfield-Oakdale site, concentrations of iron
in the surface water increased from less than the SDWS to
more than 100 times the SDWS between the upstream and
downstream sampling points. Sulfate concentrations
increased by over an order of magnitude, from 20 to 299
mg/1, (at 299 mg/1, still only 1.2 times the SDWS)
between the upstream and downstream sampling positions,
while IDS increased from less than the SDWS to 44 times
the SDWS. At another sampling point approximately 1.2
miles downstream from the site, the measured parameters
had all returned to levels close to the upstream values.
At the Moxley Hill Site, the pH and iron concentrations
remained relatively constant between the upstream and
downstream sampling points;, median sulfate values
increased, although not to levels exceeding the SDWS.
The elevated concentrations of sulfate and TDS had been
significantly attenuated at another point three-quarters
of a mile downstream.
At the Linda Site, no upstream data were collected. It
is therefore impossible to quantify the potential effects
of fly ash deposition on the water quality.
1
5.3.3 Other Case Studies of the Environnental Inpact of Coal
Combustion By-Product Waste Disposal
This section presents a review of two independent case studies of
ground-water contamination at utility disposal sites.
Cedarsauk Site, Southeastern Wisconsin
The Cedarsauk site is a fly ash landfill in southeastern Wisconsin. At the
29
time of this study, fly ash had been deposited at the site into an abandoned
sand and gravel pit over a period of eight years. Part of the pit is in direct
contact with an aquifer composed mainly of sand and gravel with some clay. This
upper aquifer is approximately 15 to 20 meters thick with a permeability of 10
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5-64
_2
to 10 cm/sec. Soluble carbon aqueous material comprises about 35 percent of
the aquifer. The upper sandy aquifer overlies another aquifer consisting of
fractured dolomite-bedrock.
A water quality study of the area was undertaken in 1975. This study
eventually included 35 monitoring wells and seven surface-water sampling sites.
Twenty of the wells were placed upgradient of the site to provide background
water quality information, while the remaining wells were positioned
downgradient. Sampling was performed on a monthly basis. Most of the
ground-water flow beneath the site surfaced in a marsh directly east of the asb
disposal area.
The monitoring results showed that downgradient ground water had SDWS
exceedances. Background levels of total dissolved solids (TDS) were below 500
mg/1, while the levels in the ground water downgradient from the disposal site
exceeded 800 mg/1, or 1.6 times the SDWS. After eight years of disposal, .tie
contaminant plume appeared to stabilize approximately 200 meters downgradient
from the ash disposal site. The stabilization of the constituent plume appeared
to be due to dilution and the ability of the materials in the aquifer to
attenuate contaminants. Only iron, manganese, and zinc were found in detectable
quantities in the downgradient off-site wells.
The maximum detected iron concentration was more than 33 times the SDWS,
while the maximum manganese concentration reached 30 times the SDWS. Neither
iron nor zinc could be detected 200 meters downgradient from the disposal site.
Another contributor to ground-water contamination at this site was sulfate.
Background concentrations of sulfate varied between 20 and 30 mg/1 (well below
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5-65
The SDHS) , while the concentrations of sulfate in the contaminant plume achieved
levels approximately 3. -4 times the BBSS. Other trace metals for which analyses
•were performed, such as copper, molybdenum, nickel, lead, and titanium, were not
detected.
-As the I'gg^h^fff ronracf pd -t-h* cfri-i-mgni-c -in i-fw> aipii-fjor^ jt- uac neutralized
from an initial pH -ralue of 4.5 TD ^rumid ueul.iHl pfl levels (i.e. , about 7.0) .
^»T« change in pH pTTAaAly fan-mod -Hw* pra»r* jpf •t-at-i tm nf tnony r\f the trace Dietal
and other constituents in the leacliate. In addition, adsorption- reactions
t>etween tiie clay in the sediments and tne i-mn.Hn«»rYt^ probably .attenuated the
leachate concentrations of many of the potential contaminants observed in the
leachate .
Center Mine. Center, Harib Dakota
Fly agh at f-his site had been deposited on a ™JTM» pit .and between mine ash
piles. A study was conducted to determine the potential effects of FGD and fly
ash disposal on ground vater quality at the surface mining site. This
investigation used field monitoxing and laboratory column leaching experiments
dn conjunction with geochemical computations. By collecting both field and
laboratory data, the investigators hoped to test the applicability of laboratory
column experiments to field situations. Roughly 150 veils were placed both in
the vicinity of the waste disposal sites and in unaffected areas.
Ground-water concentrations were generally within drinking water standards
in the background wells. However, selected constituents were higher than the
drinking water standards. For instance, sulfate concentrations tended to exceed
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5-66
the SDWS by a factor of 2 to 4. The maximum iron concentration was 4.3 times
the SDWS. Manganese concentrations were all above the SDWS, varying from 0.06
to 2.75 mg/1, or 1.2 to 55 times the SDWS.
Samples collected from wells located adjacent to the FGD waste site
indicated that none of the PDWS constituents exceeded the standards. For the
SDWS constituents, molybdenum concentrations fluctuated between 0.070 and 4.850
mg/1, and sulfate concentrations reached a high of 9,521 mg/1, or 38 times the
SDWS. (EPA has not established maximum concentration levels for molybdenum.)
Ground water in areas that appear to be affected by leachate from the fly
ash disposal sites had sulfate concentrations ranging from 21.7 to 211 times the
SDWS. Higher values were obtained immediately below recent deposits of fly ash,
while lower values were observed at older sites or at greater distances from the
disposal area. Arsenic and selenium concentrations in the ground water were as
high as 0.613 mg/1 (12 times the PDWS) and 0.8 mg/1 (80 times the PDWS),
respectively. The highest arsenic and selenium concentrations were associated
with higher pH values. Ground-water pH values for samples in the area of the
fly ash ranged from 6.95 to 12.1. (The Secondary Drinking Water Standard for pH
is 6.5 to 8.5). Iron and manganese concentrations were also high in samples
taken from around the fly ash disposal site. The maximum concentration of iron
was 8.6 times the SDWS; the maximum concentration of manganese was 130 times the
SDWS.
Leachates from the fly ash of western coals are often characterized by a
high pH that tends to cause many potentially harmful constituents to be
released. The pH-dependent solubility of many trace elements, as apparently
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5-67
observed at this site, demonstrates the importance of neutral pH values that are
conducive to contaminant attenuation.
5.3.4 Sumaxy
The studies reviewed in this section indicate that constituents from
coal-combustion waste disposal sites have been detected in both on-site and
off-site ground and surface water. However, those constituents that did exceed
the drinking water standards seldom exceeded these standards by more than ten
times. Moreover, the total number of exceedances is quite small compared to the
total number of monitoring wells and samples gathered. The contaminant
exceedances that do occur appear to be correlated to some extent with acidic or
alkaline pH levels. At fly ash disposal sites, pH values between 2 and 12 have
been measured. High and low pH values can contribute to metal solubility in
ground water.
There are two documented cases of coal combustion waste disposal sites
causing significant harm to the environment. Drinking water wells around the
Chisman Creek fly ash disposal site in Virginia (which was closed in 1974) were
contaminated with high concentrations of vanadium and selenium. Concentrations
of these elements at this site were also due to petroleum coke waste (a product
of oil combustion, not coal combustion). The site has been placed on the CERCLA
National Priority List. In 1967, a dike failed at a utility waste disposal site
on the banks of the Clinch River in Virginia, causing waste to spill into the
river. This accident caused substantial damage to the biotic life in the river.
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5-68
5.4. FACTORS AFFECTING EXPOSURE AND RISK AT COAL
COMBUSTION WASTE SITES
The previous sections analyzed the constituents of coal combustion waste
leachates and the quality of the ground water and surface water surrounding
disposal sites. However, this is only part of determining the potential dangers
that the wastes pose to human health and the environment. Exposure potential,
the degree to which populations could be expected to be exposed to potentially
harmful constituents, must also be analyzed. Exposure potential is determined
by a variety of factors. Hydrogeologic characteristics of a site will affect
the migration potential of waste constituents. Proximity of sites to drinking
water sources and to surface-water bodies will determine potential for exposure
to populations using the water sources.
In order to address this issue of exposure, EPA collected a wide variety of
data on a random sample of 100 coal-fired utility plants around the country.
The sample was taken from the Utility Data Institute Power Statistics Database,
which contains information on every coal-fired electric utility plant in the
country. Most plants dispose of their waste on-site, and in these cases
information was collected on the plant location given by the data base. If the
plant disposed off-site, data were collected on that off-site location. EPA
assumed that off-site disposal took place at the nearest municipal landfill,
unless additional information indicated otherwise. Characteristics such as
depth to ground water, hydraulic conductivity, distance to surface water,
location of private and public drinking water systems, type of surrounding
natural ecosystems, and location of human population were obtained from a wide
variety of sources. This simple aggregation of the individual factors affecting
exposure at coal combustion waste sites provides a qualitative perspective on
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5-69
the potential risk that coal combustion waste sites pose, and is presented in
Sections 5.4.1-5.4.3. Appendix F displays the data for each coal combustion
waste site in the random sample.
5.4.1 Environmental Characteristics of Coal Combustion Waste Sites
Environmental characteristics of coal combustion utility waste sites will
have a significant effect on the potential for the waste constituents to travel
and reach receptor populations. Key environmental characteristics are:
• Distance to surface water - The distance between a coal
combustion waste disposal site and the nearest surface
water body. Proximity to surface water would decrease
the possible health effects of ground-water contamination
due to the fact that there would be fewer opportunities
for drinking water intakes before the ground water
reached the surface water body; once the plume reached
the surface water, contamination would be diluted.
However, proximity to surface water would possibly
increase danger to aquatic life because less dilution of
the contaminant plume would occur before the plume
reached the surface water body.
• Flow of surface water - A high surface water flow will
increase the dilution rate of coal combustion
constituents that may enter the surface water, thereby
reducing concentrations in the surface water.
• Depth to ground water - The distance from ground level to
the water table. A larger depth to ground water will
increase the time it takes for waste leachates to reach
the aquifer; it also allows more dispersion of the
leachate before it reaches the aquifer so that once the
leachate reached the aquifer, concentrations of metals
would be decreased.
• Hydraulic conductivity - This factor is an indication of
the rate at which water travels through the aquifer. A
high hydraulic conductivity indicates that constituents
will travel quickly through the ground water and possibly
more readily reach drinking water wells, although high
conductivity also indicates a more rapid dilution of
constituent concentration.
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5-70
Net recharge - This factor is a measure of net
precipitation of a site after evapotranspiration and
estimated runoff is subtracted. Recharge is calculated
in order to determine the amount of rainfall annually
absorbed by the soil. A high net recharge indicates a
short period of time for contaminants to travel through
the ground to the aquifer, but will also indicate a
higher potential for dilution.
Ground-water hardness - This factor is a measure of the
parts per million (ppm) of calcium carbonate (CaC03) in
the aquifer. Ground water with over 240 ppm of CaCOS is
typically treated when used as a public drinking water
supply. This treatment of the hard ground water has an
indirect mitigative effect on exposure because treatment
of the ground water will tend to remove contamination
from other sources.
To conduct this exposure analysis, environmental data on the 100 randomly
selected coal combustion waste sites were gathered using a number of sources.
These data were then aggregated in order to present an overview of the
environmental characteristics that contribute to exposure. The data collected
on the sample of coal combustion waste sites were compared to information
presented in a study by Envirosphere for the Electric Power Research
31
Institute. The Envirosphere report gave detailed information on the
hydrogeologic settings of 450 operating utility plants. The information
provided by the exposure analysis on the sample of 100 plants corresponded
fairly closely with the settings described in the Envirosphere report.
The following sections summarize the data that were collected and the
relationship of the various characteristics to potential exposure.
5.4.1.1 Distance to Surface Water and Surface-Water Flow
The proximity of a waste site to surface water affects exposure potential in
several ways. If the site is very near a surface-water body, there is less
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5-71
opportunity for humans to use contaminated ground water as a source of drinking
water. However, sites that are close to surface water can more easily
contaminate the surface-water body, although waste constituents will be more
quickly diluted if the flow of the surface water is high.
Distance to the nearest surface-water body, e.g., creek, river, lake, or
swamp, was determined from measurements obtained using United States Geologic
Survey (U.S.G.S.) maps. The sample of coal combustion waste sites was located
on 7-1/2 or 15 minute maps, and the distance between the site and nearest
surface water body was calculated.
When the boundaries of the plant or waste site were marked on the maps, the
reference point was the downgradient boundary of the site. If the boundaries
were not marked, the latitude and longitude points for the sites provided by the
Utility Data Institute Power Statistics Database were used.
The average distance from the sample of coal-burning waste sites to
surface-water body is 1279 meters. Distances range from 10 to 18,000 meters.
Over 50 percent of the disposal sites are within 500 meters of surface water;
more than 70 percent are within 1,000 meters of surface water. Exhibit 5-17
provides the number and percentage of sites within specified distances of
surface water.
Since most sites are located somewhat near surface-water bodies, the
potential for human exposure to contaminated ground water seems to be low. The
proximity of the sites to surface water could, however, pose a threat to
aquatic life and to humans using the surface water if contaminants are entering
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EXHIBIT 5-17
DISTANCE OF COAL COMBUSTION WASTE SITES TO SURFACE WATER
CO
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80%
70% -
60% -
50%
40%
30%
20%
10%
0-500
500-1000
1000-3000
3000-5000
5000-9000
DISTANCE (METERS)
SOURCE: ICF Inc. based on USGS data
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5-73
the surface water. The concentration in surface water will be less, however,
if the surface-water body close to the site has a high flow.
Flow data on surface-water bodies near the sample of 100 sites were
obtained from U.S.G.S. data. Flow is expressed in terms of cubic feet per
second (cfs), and given for minimum and maximum average flow for one-month
periods. In order to obtain a conservative estimate of exposure (i.e., one
that does not understate exposure) this report used estimates for the month
with the minimum monthly flow. The results are presented in Exhibit 5-18.
Exhibit 5-18 shows that 19 percent of the sites have a flow of zero. A •
zero flow generally indicates that the body of water is a lake, swamp, or marsh
that does not have any continual flow of water, although this category could
include a seasonal stream. For surface-water bodies with zero flow, dilution
of potential contamination would occur because of the volume of water in the
surface-water body, but there would not be any additional dilution as water
flowed away from the source of contamination. Forty-one percent of the
surface-water bodies have a flow of 1-1000 cubic feet per second, 21 percent
have a flow of 1,000-10,000 cfs, and 18 percent have a flow of over 10,000 cfs.
5.4.1.2 Hydrogeologic Measurements
The hydrogeologic measurements of depth to ground water, hydraulic
conductivity, and net recharge were determined through the use of information
provided by the DRASTIC system. The DRASTIC system, developed by the National
Well Water Association, categorizes aquifers on the basis of geographic region
and subregion. Each site was located on a 7 1/2 or 15 minute U.S.G.S. map that
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EXHIBIT 5-18
FLOW OF NEAREST SURFACE-WATER BODY
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1-1000
1000-10,000
10,000.
FLOW (CUBIC FEET/SECOND)
SOURCE: ICF Inc. based on USQS data
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was then compared with a map on which the 11 major DRASTIC regions had been
outlined. The topography and geology of the sites, which were determined from
looking at the U.S.G.S. maps, were assessed in order to further classify
thesites into DRASTIC subregions. Subregions are defined by hydrogeologic
characteristics and vary in size from a few acres to hundreds of square miles.
Measurements for depth to ground water, hydraulic conductivity, and net
recharge of the sites were taken largely from A Standardized System for
Evaluating Ground-water Pollution Potential Using Hvdrogeologic Settings. by
the National Well Water Association, which presents a range of values for each
32
of these hydrogeologic properties for each subregion. The ranges were
compared with characteristics that could be observed by studying U.S.G.S. maps,
and, when necessary, they were modified accordingly.
Depth to Ground Water
A small depth to ground water indicates a higher potential for waste
constituents to reach the ground water at harmful concentrations than if the
distance to ground water were greater, thereby increasing the chance of
ground-water contamination. Depth to ground water was generally based on
DRASTIC region and subregion, but was modified when the topography or site
characteristics indicated a depth different from that provided by the DRASTIC
system. For example, if the DRASTIC subregion indicated that there was a high
depth to ground water range, but a particular site was located very near a
surface-water body, the Agency used a smaller depth to ground water than the
DRASTIC range indicated.
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5-76
Exhibit 5-19 provides the number and percentage of sites within each range
of depth to ground water. Depth to ground water is calculated in feet and
based on 10 ranges. In over 80 percent of the sites depth to ground water is
less than 30 feet, indicating a reasonably high potential that leachate from
the disposal site would reach the ground water.
*
Hydraulic Conductivity
Hydraulic conductivity is an indication of the ease with which a
constituent may be transported through the ground water. Conductivity is also
based on the site's DRASTIC region and subregion, and is measured in gallons
per day per square foot and grouped into six ranges.
Hydraulic conductivity is one of the factors used to calculate ground-
water velocity, or volumetric flow of the water table. Velocity has a direct
bearing on the degree to which leachate constituents are diluted once they
reach the ground water and travel to a point of exposure (i.e., human drinking
water source). High ground-water conductivity signifies high velocity and
therefore a high dilution potential.
Exhibit 5-20 provides the number and percentage of sites falling into each
hydraulic conductivity range. Thirty-three percent of the sites show a
hydraulic conductivity of 700-1,000 gallons per day per square foot; 27 percent
have a conductivity of 1,000-2,000 gallons per day per square foot. There is
a wide spread of conductivity values -- indicating hydrogeologic diversity
among sites.
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EXHIBIT 5-19
DEPTH TO GROUND WATER
AT COAL COMBUSTION HASTE SITES
60%
50% -
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30% -
20% -
10%
0-5 0-10 5-15 10-20 15-30 30-50 50-75 50-100 75-100
EXPECTED DEPTH (FEET)
SOURCE: ICF Ine, based on DRASTIC
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EXHIBIT 5-20
HYDRAULIC CONDUCTIVITY
AT COAL COMBUSTION HASTE SITES
100%
OT
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90% -
eo% -
70% -
60% -
60% -
40% -
30% -
33%
27%
0%
1-100 100-300 300-700 700-1000 1000-2000
HYDRAULIC CONDUCTIVITY (GAL/DAY/SQ.FT)
SOURCE: ICF Inc, based on DRASTIC d»tt
2000»
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5-79
While ground-water velocity gives an indication of how fast contamination
may travel in the ground water, contaminants do not move at the same velocity
as the ground water. This is because of basic interactions between
contaminants and soil that retard the movement of the contaminants. There are
three different mechanisms that affect the retardation of contaminant movement
-- exchange on soil particle sites (ion exchange), adsorption onto soil
particle surfaces, and precipitation. The exchange and adsorption mechanisms
will retard the movement of contaminants but will not eliminate the movement of
all contaminants due to limited soil attenuation capacity.
As with the diversity among sites in terms of hydraulic conductivity and
ground-water velocity, the various attenuation mechanisms differ among sites.
To determine the attenuation potential at a site requires detailed data inputs
on water chemistry on a site-specific basis.
Net Recharge
Net recharge indicates how much water is annually absorbed into the ground.
It is measured by subtracting evapotranspiration (the amount of rainfall that
evaporates and transpires from plant surfaces) and estimated runoff from total
precipitation at a site. It affects exposure potential in a number of ways.
Low recharge will result in smaller volumes of more concentrated leachate, but
if the aquifer is deep and/or has a high velocity, it will quickly dilute the
leachate. High recharge produces more leachate, but may also indicate that the
area has higher ground-water flow.
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Exhibit 5-21 shows the number and percentage of sites that fall into each
range. Recharge is measured in inches and is grouped into five ranges.
Although a wide variety of net recharge ranges is represented by the sample,
the recharge of sites generally falls into the higher ranges of 4-7 inches,
7-10 inches, and over 10 inches. For example, more than 80 percent of the
sites have a net recharge of over 4 inches and over 50 percent have a recharge
of over 7 inches. This implies that leachate constituents will be more quickly
carried to the water table but the higher recharge rate will also result in
greater dilution of the leachate.
Ground-water Hardness
The hardness of the ground water near coal combustion waste sites will have
an effect on potential exposure through drinking water since excessive hardness
is typically treated in a public drinking water system. Treatment would lessen
the exposure potential to humans.from contaminants in the ground water from
other sources (such as coal combustion wastes). Measurements for ground-water
hardness were obtained by locating the sites on maps provided in Ground-water
33
Contamination in the United States (Pye, Patrick, and Quarles).
As shown in Exhibit 5-22, ground-water hardness is measured in parts per
million (ppm) of calcium carbonate (CaC03) and grouped into five ranges.
Ground water with a hardness of over 240 ppm of calcium carbonate is typically
treated if used in a public drinking water system. In this sample, 45 percent
of the sites show ground-water hardness in this range. Ground water with a
hardness of 180-240 ppm of calcium carbonate may also be treated, although
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EXHIBIT 5-21
NET RECHARGE
AT COAL COMBUSTION HASTE SITES
80%
50% -
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30% -
20% -
10%
0-2 2-4 4-7 7-10
NET RECHARGE (INCHES)
SOURCE: ICF Inc. bistd on DRASTIC
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EXHIBIT 5-22
GROUND-WATER HARDNESS
AT COAL COMBUSTION BASTE SITES
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SOX -
40X -
30X -
20* -
10X
.80 80-120 120-180 180-240
HARDNESS (PPM CaCO3)
•240
SOURCE: ICF Inc. b«»«d on Py», *t »l, Groundw»t«r Contamlnitlon In U.S.
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5-83
treatment is much less likely. An additional 22 percent fall in the 180-240
ppm range.
The high levels of calcium carbonate found in the ground water near coal
combustion waste disposal sites suggest that if a drinking water supply is in
the vicinity, the water would often require treatment before being used.
Therefore, contamination that might exist in the drinking water from other
sources would be mitigated due to the treatment process since trace
constituents tend to be removed during the treatment process.
5.4.2 Population Characteristics of Coal Combustion Waste Sites
Environmental characteristic's, such as distance and flow of surface water
and hydrogeologic measurements, are only one part of the analysis of exposure
potential. Opportunities for human exposure to coal combustion waste
constituents depend in part on the proximity of coal combustion waste disposal
sites to human populations and to human drinking water supplies. Census data
(1980) provide information about the number of people living within specified
distances from the coal combustion waste sites. This information is obtained
through the CENBAT program, part of the Graphic Exposure Modeling System
developed by EPA's Office of Solid Waste. The Federal Reporting Data System
(FRDS) data base, developed by EPA's Office-of Drinking Water, provides
estimates of the number of public water supply systems and the size of the
populations using them.
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5.4.2.1 Proxinity of Sites to Human Populations
CENBAT provides information on the number of people living within specified
distances around designated locations. The sites were defined by latitude and
longitude coordinates. Populations were analyzed for areas within 1-, 2-, 3-,
4-, and 5-kilometer radii of the waste disposal sites.
Exhibit 5-23 shows the distribution of population within one kilometer of
the waste disposal sites. The CENBAT results show that most sites, 71 per-
cent, do not have any population within a one-kilometer radius. Overall, the
population range within a one-kilometer radius is 0 - 3708 people, with an
average of 359 people.
Exhibit 5-24 shows the population characteristics for the sample of coal
combustion waste sites at a three-kilometer radius. When the search distance
is increased to three kilometers, the percentage of sites that have no people
within a three-kilometer radius decreases to 32 percent. Average population
within three kilometers is 3,737, and the range is 0 - 35,633 people. There is
a large degree of diversity of populations at this distance. For example,
while 32 percent of the sites have zero population, the same percentage has
populations over 2,000.
Exhibit 5-25 shows the distribution of populations within a five-kilometer
radius. Only 10 percent of the sites do not have any population living within
this distance. The average population is 12,128 people, with a range from 0 to
123,160. The diversity among coal combustion waste disposal sites is even more
apparent at this distance. While 20 percent of the sites have populations
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EXHIBIT 5-23
POPULATIONS WITHIN ONE KILOMETER OF WASTE SITES
100%
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Ul
Q.
90% -
80% -
70%
60%
50%
40%
71%
30%
20%
10%
0%
0%
r»ro 1-900 501-2000 2001-10,000 10,001-25,000
POPULATION RANGES
SOURCE: ICF Inc, based on CENBAT data
25000-
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EXHIBIT 5-24
POFDIATIONS WITHIN THREE KILOMETERS OF WASTE SITES
100%
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0.
90% -
80% -
70% -
60% -
50% -
40% -
30%
20%
32%
10%
20%
zero 1-500 501-2000 2001-10,000 10,001-25,000
POPULATION RANGES
SOURCE: ICF Inc., based on CENBAT data
25000*
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EXHIBIT 5-25
POPULATIONS WITHIN FIVE KILOMETERS OF WASTE SITES
100%
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90% H
80% H
70% H
60% H
50% H
40% H
30% H
20% -
10%
31%
14%
Ztro 1-500 501-2000 2001-10,000 10,001-25,000
POPULATION RANGES
SOURCE: ICF Inc., based on CENBAT
25000*
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5-88
within a five-kilometer radius of fewer than 500 persons, 29 percent have
populations over 10,000.
The CENBAT results indicate that density increases on average with distance
from the disposal site. Many waste sites appear to be located on the outskirts
of populated areas, with fairly low population immediately adjacent to the
site, but with significant populations within a five-kilometer radius.
5.4.2.2 Proximity of Sites to Public Drinking Water Systems
If coal combustion waste sites are close to public drinking water systems,
there may be potential for human exposure through drinking water supplies. The
location of public water supplies was determined through the use of the Federal
Reporting Data System (FRDS), developed by EPA's Office of Drinking Water.
The FRDS data base provides the number of public water supply systems
located within specified distances from a site and the populations using the
systems. It should be noted that the FRDS data base locates water systems
based on the centroid of the zip code of the mailing address of each utility
and that the actual location of the intake or well may be different. This can
cause some inaccuracy in the calculation of the distance and location of public
drinking water supplies in relation to the waste site. In order to remedy
potential inaccuracies and omissions, the locations of public water systems
that appeared on topographical maps but were not reported by FRDS are also
recorded.
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5-89
Exhibit 5-26 shows the population served by public water systems located in
the downgradient plume from the sites and within a five-kilometer radius. The
exhibit also shows how many sites have no public water systems within a
five-kilometer radius. Sixty-six percent of the sites have no public water
systems within a five-kilometer radius. Fifteen percent of coal combustion
sites have public water systems located within a five-kilometer distance and
had systems which served over 5,000 people, and 19 percent have public water
systems that serve fewer than 5,000 people.
The population data indicate that while there are often quite large
populations in the vicinity of coal combustion waste sites, only 34 percent of
the sites have public drinking water systems downgradient from the site.
5.4.3 Ecologic Characteristics of Coal Conbustion Waste Sites
Ecological data on endangered, threatened, or unique plants and animals is
available through state Heritage Programs. The Nature Conservancy established
the Heritage Programs, which now usually function as offices of state
governments. The Heritage Programs develop and maintain data bases that
describe jeopardized species and rare ecosystems within each state. It should
be noted that there can be substantial variation in the completeness of data
available from different states; some state Heritage Programs are fairly new,
and basic data collection is still in its preliminary stages.
While it may not currently be possible to quantitatively model risk to
ecosystems from coal combustion waste, the information provided by the Heritage
Programs can indicate whether there are any jeopardized species near a specific
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5-90
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EXHIBIT 5-26
POPULATIONS SERVED BY PUBLIC HATER SYSTEMS NEAR HASTE SITES
90%
80% -
70% -
60% -
50% -
40% -
30% -
20% -
10%
1-1000
1000-5000 >5000
POPULATION
NO PUBLIC WATER SYSTEM
WITHIN FIVE KILOMETER RADIUS
SOURCE: ICF, bated on FRDS data
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5-91
waste site. If potentially hazardous constituents of coal combustion waste do
migrate and produce environmental contamination, it could affect species and
natural communities that are particularly vulnerable, thereby lessening
ecosystem diversity.
EPA provided Heritage Program staff with latitudes and longitudes for the
sampled sites in states that had such programs. Using these coordinates, the
Heritage Program staff performed a search of their data bases for rare or
endangered species within a five-kilometer radius from the site.
The sample sites were grouped into four categories based on the results
obtained from the Heritage Program. Category 1 includes sites having Federally
designated threatened or endangered species within the five-kilometer radius.
Category 2 includes sites that have no Federally designated threatened or
endangered species within the five-kilometer distance, but which do contain
species or natural communities designated by state Heritage Offices as
critically endangered in that state. Category 3 contains sites for which there
are species or natural communities of concern in the area. For sites in
Category 4, there is no record of the existence of species of concern in the
five-kilometer area.
Information was available on 85 of the 100 coal combustion waste sites in
the sample. Exhibit 5-27 presents the breakdown of sites according to the
categories described above. Twelve percent of the sites fall into Category 1,
29 percent in Category 2; 32 percent in Category 3; and 12 percent in Category
4 (no information was available for 15 percent).
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EXHIBIT 5-27
ECOLOGICAL STATUS OF WASTE SITES
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Q.
2 CATEGORY '
Category 1: Federally designated plants or anlmalt within a five Km. radius
Category 2: Species of priority state concern within five km. radius
Category 3: species of concern to state environmental offices
Category 4: no data on ecosystem surrounding the site
SOURCE: ICF inc., based on State Heritage Data
-------
5-93
Given the high percentage of sites that have rare plant and animal
communities within a five-kilometer radius supplies, and the proximity ;.
discussed earlier of waste disposal sites to surface-water bodies (which
provide animals with drinking water), there could be a high potential for
species exposure to coal combustion constituents.
5.4.4 Multivariate Analysis
The previous sections of this exposure analysis presented independent
analyses of the population, environmental, and ecological characteristics of
coal combustion waste sites. This section examines a number of these factors
simultaneously in order to determine interactions that affect the overall
potential for exposure from coal combustion waste sites.
As mentioned previously, only 34 percent of coal combustion waste sites
j
(based on a random sample of 100 sites) have public drinking water systems in
the downgradient plume within 5 kilometers of the waste site. Some of these
public drinking water systems may use ground water that is currently treated
before it is used as drinking water, indicating that human populations are
unlikely to be directly exposed to any water that may be contaminated from coal
combustion waste constituents. As discussed earlier, one reason for treating
the water is ground-water hardness. Ground water that has a hardness greater
than 240 ppm CaC03 is likely to be treated if it is used as a drinking water
source. Of the 34 percent of the sites in the sample that have public water
systems in the downgradient plume within 5 kilometers of the waste site, just
under one-half of these sites have ground water with a hardness over 240 ppm
CaC03. These results show that the potential for human exposure through
-------
5-94
drinking water is likely to be less than the proximity to public drinking water
systems (FRDS data) indicates. Of all the sites sampled, only 18 percent have
public drinking water systems within 5 kilometers and ground water under 240
34
ppm CaC03.
The potential for human exposure through drinking water can be further
evaluated by comparing the FRDS and ground-water quality characteristics with
the hydrogeologic factors of net recharge and depth to ground water. Sites
with a net recharge greater than 7 inches and a depth to ground water of
fifteen feet or less are more likely to develop ground-water contamination due
to waste leaching since water has a greater likelihood of contacting the coal
combustion wastes. Of the 18 percent of the sites that have public water
supplies and ground-water hardness below 240 ppm CaCOS, two-thirds have a net
recharge greater than 7 inches as well as a depth to ground water of 15 feet or
less. Therefore, only 12 percent of the sites in the sample (18 percent x 2/3)
have ground water that is likely to be used without treatment and hydrogeologic
characteristics that indicate high potential for leachate migration.
This multivariate analysis of the factors affecting exposure at coal
combustion waste sites illustrates the limited potential for human health risk
through drinking water. Only 34 percent of the sites have public water systems
within five kilometers and many of these public water systems are likely to
treat the ground water due to hardness.
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5-95
5.5 SUMMARY
This chapter has reviewed available information on the potential for
coal-fired combustion wastes from electric utility power plants to affect human
health and the environment. First, data on the potential corrosivity and EP
toxicity of utility wastes was reviewed. After determining that coal
combustion leachate sometimes contains hazardous constituents at levels above
drinking water standards, the potential for this leachate to migrate from waste
disposal sites was examined. Results of ground-water monitoring in several
studies were interpreted and a number of compilations of "documented" damage
cases were evaluated. After describing instances in which trace elements in
coal combustion leachate have migrated from waste disposal sites, the potential
effect of these migrations was examined. A sample of 100 utility waste
disposal sites was selected, and these sites were evaluated in terms of
population, environmental, and ecological characteristics to assess the
potential for leachate migration and exposure of human and ecological
populations.
Based on these data and analyses, several observations relating to
potential dangers to human health and the environment can be made:
• If the current exemption from Subtitle C regulation
were lifted for coal combustion wastes and these
wastes were required to be tested for corrosivity or
EP toxicity, most current waste volumes and waste
streams would not be subject to hazardous waste
regulation. The only waste stream which has had
corrosive results is boiler cleaning waste. (Since
coal ash is not aqueous, it cannot be corrosive.)
For the other waste streams, available data indicate
that while some of these waste streams could have
high or low pH levels, they are not likely to fall
under the RCRA definition of corrosive waste.
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5-96
Similarly, while a few high-volume waste samples did
exceed the EP toxicity limits for cadmium, chromium,
and arsenic, this was limited to a few waste streams
and represented only a small fraction of the samples
for these waste streams (the chromium and arsenic
exceedances were from only one fly ash sample).
Available data on low-volume wastes showed that the
only waste stream with significant RCRA exceedances
was boiler cleaning waste, which had exceedances for
chromium and lead. Wastewater brines were shown to
exceed the RCRA standard for selenium in one sample.
Results of EP tests on co-disposed wastes indicate
that boiler cleaning wastes may not possess
hazardous characteristics when co-disposed with ash.
Results for all other waste streams and all other
constituents were below EP toxicity limits.
Results available from ground-water monitoring
studies and documented cases of ground-water or
surface-water contamination show some migration of
PDWS constituents from utility waste disposal sites.
In the most comprehensive and systematic of these
studies, the Arthur D. Little survey of six utility
sites, evidence of constituent migration downstream
from the waste sites was conclusive only for
cadmium. The Envirosphere ground-water study showed
that only 3.7 percent of the samples showed
downgradient concentrations of PDWS constituents
that were higher than the concentrations of
upgradient constituents (indicating that some
contaminants are migrating from the site). This
tends to support the results of the waste extraction
tests. For the one utility disposal site on the
National Priorities List, a site currently inactive
since it was closed in 1974, the major ground-water
contaminants were vanadium and selenium. However,
this site differs from some other sites for which
ground-water quality data are available in that
wastes are from both coal and petroleum coke
combustion.
Although coal combustion waste leachate has the
potential to migrate from the disposal area, the
actual potential for exposure of human and
ecological populations is likely to be limited.
Because utility plants need a source of water to
operate, most of the disposal sites are located
quite close to surface water. Fifty eight percent
of the 100 sample sites were within 500 meters of
surface water. It is not common for drinking water
wells to be located between the disposal site and
the nearest downgradient surface water body. The
effect of this proximity to surface water is that
only 34 percent of the sampled sites had drinking
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5-97
water intakes within five kilometers. Furthermore,
the flow of the surface water will tend to dilute
the concentrations of trace metals to levels that
satisfy drinking water standards.
Simultaneously examining the environmental and
population characteristics of coal combustion waste
sites shows even less potential for exposure to
human populations. 12 percent of the sites in the
sample have public water systems within five
kilometers of the site' where the ground water may
not be treated (i.e., ground-water hardness below
240 ppm CaCOS) and hydrogeologic characteristics
that indicate high potential for leachate migration.
-------
CHAPTER 5
NOTES
*- See 40 CFR 261.21.
2 See 40 CFR 261.22. In using pH to determine corrosivity, EPA explained
that "wastes exhibiting low or high pH can cause harm to human tissue,
promote the migration of toxic contaminants from other wastes, and harm
aquatic life."
3 These methods are set forth in 40 CFR 260.21 and 260.22.
4 See 40 CFR 261.23.
5 See 40 CFR 261.24.
6 See 40 CFR Part 261, Appendix II.. These procedures for testing and the
limits allowed for determining whether a waste is hazardous or not are
currently under review.
' A waste would be considered hazardous if it has been shown to have an oral
ID 50 toxicity to rats of less than 50 mg/kg, an inhalation LC toxicity to
rats of less than 2 mg/1, or a dermal ID 50 toxicity to rabbits of less
than 2000 mg/kg.
8
See 40 CFR 261.11.
9 See CFR 40 Section 261.24. RCRA also establishes EP toxicity limits for
six pesticides.
See CFR 40 Section 261, Appendix II.
11 Federal Register, Volume 51, No. 114, Friday, June 13, 1986, p. 21648.
12
Since the completion of the ASTM B tests discussed in this section, ASTM
has dropped this extraction test (EPRI 1983).
13
Tetra Tech, Inc., Physical-Chemical Characteristics of Utility Solid
Wastes. prepared for Electric Power Research Institute, EA-3236, September
1983.
14
Jackson, L. and Moore, F., Analytical Aspects of the Fossil Energy Waste
Sampling and Characterization Project, prepared for the U.S. Department of
Energy, Office of Fossil Energy, DOE/LC/00022-1599 (DE84009266), March
1984.
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-2-
Arthur D. Little, Inc., Full-Scale Field Evaluation of Waste Disposal from
Coal-fired Electric Generation Plants, prepared for the Air and Energy
Engineering Research Laboratory of the U.S. Environmental Protection Agency
for the Office of Solid Waste, EPA-600-7-85-028, June 1985.
Mason, B.J., and Carlile, D.W., draft report of Round Robin Evaluation for
Selected Elements and Anionic Species from TCLP and EP Extractions.
prepared by Battelle Pacific Northwest Laboratories, for the Electric Power
Research Institute, EPRI EA-4740, April 25, 1986.
Battelle's test varied from standard TCLP procedure by allowing 14 days,
rather than the normal 7, for the completion of the test.
18
Electric Power Research Institute, "Mobilization and Attenuation of Trace
Elements in an Artificially Weathered Fly Ash," prepared by the University
of Alberta, Edmonton, Canada, EPRI EA-4747, August 1986.
19
Battelle Pacific Northwest Laboratories, Chemical Characterization of
Fossil Fuel Combustion Wastes, prepared for the Electric Power Research
Institute, September 1987.
on
Radian Corporation, Characterization of Utility Low-Volume Wastes, prepared
for the Electric Power Research Institute, May 1985.
21
Radian Corporation, Manual For Management of Low-Volume Wastes From
Fossil-Fuel-Fired Power Plants, prepared for the Electric Power Research
Institute, July 1987.
22
Arthur D. Little, Inc., Full-Scale Field Evaluation of Waste Disposal from
Coal-fired Electric Generation Plants, prepared by the Air and Energy
Engineering Research Laboratory of the U.S. Environmental Protection
Agency, for the Office of Solid Waste, EPA-600-7-85-028, June 1985.
23
Franklin Associates, Ltd., Survey of Ground-water Contamination Cases at
Coal Combustion Waste Disposal Sites, prepared for U.S. Environmental
Protection Agency, March 1984.
24
Envirosphere Company, "Report on the Ground Water Data Base Assembled by
the Utility Solid Waste Activities Group," in Utility Solid Waste
Activities Group (USWAG), Report and Technical Studies on the Disposal and
Utilization of Fossil-Fuel Bv-Products. October 26, 1982, Appendix C.
25
It is not necessarily true that measurements taken from upgradient and
downgradient wells at approximately the same time yield comparable
measurements. In fact, due to migration time, there will be a lag
between the time of comparable upgradient and downgradient
measurements.
-------
-3-
26
Envirosphere Company, Op. cit.. p. 38. These percentage numbers do not
correspond precisely to the data in Exhibit 5-11 because Envirosphere
normalized the data it received from the utilities so that each facility
would be weighted evenly (i.e.,, a facility with many more measurements '
would not be weighted excessively). Envirosphere reports that 1.7 percent
of the normalized data had upgradient measurements lower than the PDWS and
the downgradient higher than the FDVS; 5 percent of the data indicated that
both values exceeded the standard.
27
Envirosphere Company, Environmental Effects of Utility Solid Waste
Disposal, prepared for Utility Solid Waste Activities Group and Edison
Electric Institute, July 1979.
O Q
Dames ft Moore, "Review of Existing Literature & Published Data to Determine
if Proven Documented Cases of Danger to Human Health and the Environment
Exist as a Result of Disposal of Fossil Fuel Combustion Wastes", in Utility
Solid Waste Activities Group (USWAG), Report and Technical Studies on the
Disposal and Utilization of Fossil-Fuel Combustion By-Products. October 26,
1982, Appendix B.
09
Cherkauer, D. S. "The Effect of Fly Ash Disposal on a Shallow Ground-Water
System." Ground Water. Vol. 18, No. 6, pp. 544-550, 1980.
Groenewold, G. H., and B. W. Rehm. "Applicability of Column Leaching Data
to the Design of Fly Ash and- FGD Waste Disposal Sites in Surface- Mined
Areas." In Proceedings of the Low-Rank Coal Technology Development
Workshop. comp. Energy Resources Company, Inc., DOE/ET/17086-1932,
CONF-8106235; Washington, D.C., U.S. Department of Energy, Technical
Information Center, pp. 3-79 - 3-95, 1981.
Envirosphere Company, Environmental Settings and Solid-Residues Disposal in
the Electric Utility Industry: prepared for the Electric Power Research
Institute, August 1984.
32
Linda Aller, Truman Bennet, Jay H. Laher, Rebecca J. Betty, A Standardized
System for Evaluating Ground Water Pollution Potential Using Hydrologic
Settings, prepared by the National Well Water Association for U.S. EPA
Office of Research and Development, Ada, OK, May 1985. EPA 600-285-018.
Veronica T. Pye, Ruth Patrick, John Quarles, Ground Water Contamination in
the United States. Philadelphia: University of Pennsylvania Press, 1983.
34
Ground water over 180 ppm CaC03 may also be treated. Of the 34 percent of
the sites in the sample that have public water systems in the plume
downgradient from the site within 5 kilometers, 73 percent have ground
water with a hardness over 180 ppm CaC03. Therefore, only 9 percent of the
sites in the sample have both public water systems within 5 kilometers and
ground water under 180 ppm CaC03. Since many public water systems may not
treat water in the range of 180-240 ppm CaC03, the discussion in the report
focuses only on ground water in excess of 240 ppm CaC03. This is a
conservative assumption since the water may be treated, either by the
public authority or the private homeowner. In all cases, the extent of
exposure through private wells would have to be evaluated on a site-by-site
basis.
-------
CHAPTER SIX
ECONOMIC COSTS AND IMPACTS
Section 8002(n) of RCRA requires that EPA's study of coal combustion wastes
examine "alternatives to current disposal methods," "the costs of such
alternatives," "the impact of those alternatives on the use of coal and other
natural resources" and "the current and potential utilization of such
materials." In response to these directives this chapter examines the
potential costs to electric utilities if coal-fired combustion waste disposal
practices are regulated differently than they are currently.
The first section of this chapter (Section 6.1) examines the costs incurred
by electric utilities using current disposal methods for coal combustion
wastes.1 Section 6.2 follows with a discussion of the costs that could be
incurred if coal combustion wastes were regulated differently than they are
today. These costs include the costs of implementing alternative waste
management practices and the costs of additional administrative
responsibilities that would be incurred. Section 6.3 examines how new
regulations might affect the cost of utilizing coal combustion wastes in
various by-product applications. The last section of this chapter (Section
6.4) considers how energy use patterns in the electric utility industry might
change if alternative waste management practices that significantly affect the
cost of generating electricity with coal were imposed.
-------
6-2
6.1 HASTE DISPOSAL COSTS ASSOCIATED WITH CDRREHT DISPOSAL METHODS
The management of utility wastes comprises a series of activities -- from
initial waste collection to disposal. These current waste management
activities can be classified into five basic components.
1. Waste Han AT jTig and Processing. This is the initial phase of
the disposal process, involving collection of the various
waste products after they have been generated and initial
treatment of the wastes to prepare them for final disposal.
2. Interim Waste Storage at the Plant. Some waste products that
are dry when produced, such as fly ash or flue gas
desulfurization (FGD) wastes from dry scrubbers, often
require interim storage prior to final disposal.
3. Raw Materials Handling and Storage. Some disposal processes
involve stabilization or chemical fixation of the waste to
prepare it for disposal. The raw materials used for this
phase, including additives such as lime, Calcilox, and basic
fly ash, often require special handling and storage
facilities.
4. Waste Transport to a Disposal Facility. Environmentally
sound disposal requires careful transportation of the waste
to the disposal site. Many modes of transportation can be
used, including trucks, railroads, barges, pipelines, and
conveyor systems.
5. Waste Placenent and Disposal. This is the final stage of the
waste disposal chain. It involves placing the waste in a
suitable waste management facility (usually a surface
impoundment or landfill) and all activities required after
the facility is closed. Alternatively, the final disposition
of a waste product may entail utilization of the waste in
various applications (such as cement production or
sandblasting operations).
Exhibit 6-1 presents a schematic illustration of the current waste
management and disposal options for coal ash; Exhibit 6-2 illustrates the
options available for FGD wastes. The waste management costs discussed in this
-------
Exhibit 6-1
Overview of Waste Handling and Disposal Options for Coal Ash
COAL ASH HANDLING
AND PROCESSING
COAL ASH
| STORAGE
RAW
COAL ASH MATERIALS COAL ASH PLACEMENT
TRANSPORT | HANDLING | AND DISPOSAL
1
1
•
1
1
•
L
I*
FLY ASH 1
COLLECTED BYJ
ESPs AND 1
MECHANICAL 1
•
FLY ASH 1
COLLECTED BYI
UJ C T 1
SCRUBBERS 1
1
1
•
BOTTOM ASH/ j
SLAG 1
•
••»
-»
•»•
-»•
Vacuum
Pneumatic
Conveying
Pressure
Conveying
Vacuum/
Pressure
Conveying
Wel
Handling
Wel
Handling
Wel
»•
»•
•»
— »•
»•
L»
*
Interim
.
Dewalering
No
Dewalering
Bins
1
•
1
1
1.
1
•
I
+*
•
1
•
1
1
•
I»
*
•
i
fc
Storage
Silo
No
Storage
No
Q.
Storage
Landfill
Disposal
Utilization!
Source: Arthur D. Little, Inc., Full-Scale Field Evaluation of Waste Disposal From Coal-Fired
Electric Generating Plants, June 1985.
-------
Exhibit 6-2
Overview of Waste Handling and Disposal Options for FGD Waste
FQD WASTE
FROM WET
SCRUBBERS
FQO WASTE
WITHIN THE
SCRUBBER LOOPI FGD WASTE HANDLING AND PROCESSING
FGD WASTE
TRANSPORT | FGD WASTE DISPOSAL
Forced
Oxidation
No
Forced
Oxidation
Blending
with
Soil
Stabilization
with
Fly Ash
Ichem
Flxa
Chemical
lion
No
Treatment
No
Dewalering
Conveyor
Truck
Rail
Barge
Ulllliallon
Landfill
Disposal
Mine
DUpotal
Ocean
DUpotal
Pipeline
H
Pond
Dlapoaal
Interim
Ponding
o\
i
Utilization
i
Landllll
Dlapoaal
Source: Arthur D. Little, Inc., Full-Scale Field Evaluation of Waste Disposal From Coal-Fired
Electric Generating Plants, June 1985.
-------
6-5
chapter are those associated with the last component of waste management (i.e.,
waste placement and disposal). These are the costs associated with actual
construction of the waste management facility and placement of the wastes into
the facility. If current practices for managing coal-fired wastes from
electric utilities are altered, it is this final stage in waste management that
would probably be most affected. However, as will be explored later in this
chapter, some regulatory alternatives may affect other aspects of waste
management.
6.1.1 Costs of Waste Placement and Disposal
The wastes from coal-fired combustion at electric utility power plants are
often mixed together in the same waste management facility, typically a surface
impoundment or landfill. Although surface impoundments were once the preferred
method, and are still widely used, landfilling has become the more common
practice because less land is required, and it is usually more environmentally
sound (because of the lower water requirements, reduced leaching problems,
etc.).
The costs of waste disposal can vary substantially. Exhibit 6-3 shows
representative capital costs associated with constructing surface impoundments
and landfills for coal-fired electric utility wastes. Exhibit 6-4 shows total
costs (i.e., annualized capital costs plus operation and maintenance
expenses). Costs are shown for power plants that range in size from 100 to
3000 megawatts (Mw); power plants that fall outside of this range may incur
-------
6-6
EXHIBIT 6-3
RANGES OF AVERAGE CAPITAL COSTS ASSOCIATED WITH
COAL-FIRED ELECTRIC UTILITY WASTE DISPOSAL
(4th quarter 1986 dollars per kilowatt)
Size of Power Plant
Type of Waste
Landfills
Fly Ash
Bottom Ash
FGD Waste
Surface Impoundments
Fly Ash
Bottom Ash
FGD Waste
100 MW
9-14
2- 5
6-13
27-50
10-20
14-30
500 MW
4-7
2-3
4-7
15-27
6-11
10-19
1000 MW
3-5
1-2
3-6
13-23
5- 9
9-17
3000 MW
2-3
1-1.3
2-4
10-18
3- 6
7-14
Source: Arthur D. Little, Inc., Full-Scale Field Evaluation of Waste Disposal
From Coal-Fired Electric Generating Plants. EPA 600/7-85-028, June
1985.
-------
6-7
EXHIBIT 6-4
RANGES OF AVERAGE TOTAL COSTS FOR COAL-FIRED ELECTRIC
UTILITY HASTE DISPOSAL
(4th quarter 1986 dollars per ton)*
Size of Power Plant
Tvoe of Waste 100 MW 500 MW 1000 MW 3000 MW
Landfills
Fly Ash 9-18 6-11 5-9 2-6
Bottom Ash 10-16 5-9 4-8 2-6
FGD Waste 4-10 4-7 3-6 2-4
Surface Impoundments
Fly Ash 17-31 9-17 8-14 5-8
Bottom Ash 11-26 8-15 7-13 5-8
FGD Waste 8-17 7-13 6-10 5-7
* Dollar per ton estimates are based on the amount of waste produced
each year. For purposes of this illustration, a power plant is
assumed to generate annually 308 tons of fly ash per megawatt (MW), 77
tons of bottom ash per MW, and 264 tons of FGD waste per MW. Amounts
will vary depending on coal quality, FGD technology, and boiler type,
among other factors.
Source: Arthur D. Little, Inc., Full-Scale Field Evaluation of Waste Disposal
From Coal-Fired Electric Generating Plants. EPA 600/7-85-028, June
1985.
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6-8
different waste management costs. Both capital costs and total costs are shown
for unlined facilities without ground-water monitoring or leachate control
systems. The major factors affecting the cost of waste management are discussed
below.
The amount of capital costs for a waste management facility can be
attributed primarily to three factors: site preparation, excavation, and
construction of containment structures.^ Capital costs can be substantially
reduced if the amount of earthwork can be minimized. Capital costs for surface
impoundments, for example, increase significantly if dike construction or
excavation is required. However, if existing site features can be used, such
as valleys or abandoned pits, capital costs will be lower. Similarly, capital
costs for landfills that require little excavation are lower than for those
sites requiring extensive earthwork.
As Exhibit 6-3 illustrates, landfills are far less capital intensive than
surface impoundments. For example, capital costs for fly ash placement in a
surface impoundment at a 500 MW power plant would range from approximately $15
to $27 per kilowatt. In contrast, capital costs for landfills range from
about $4 to $7 per kilowatt. Landfills tend to cost less than impoundments
primarily because the area required for a given amount of waste is less, and
neither dikes nor piping and pumping systems are necessary.
Annual costs for landfills (see Exhibit 6-4) also tend to be less than
those for surface impoundments primarily because landfills tend to be far less
capital intensive. For example, costs for fly ash management at a 500 MW power
plant range from about $9 to $17 per ton when the wastes are placed in surface
-------
6-9
impoundments, while the comparable range at a landfill is about $6 to $11 per
ton. Similarly, the cost for bottom ash disposal at an impoundment for a 500
MW power plant ranges from $8 to $15 per ton, while the costs to dispose in a
landfill range from about $5 to $9 per ton.
Other factors that affect the cost of utility waste disposal include
• Size of the Power Plant. Because larger power plants
consume more coal than smaller facilities, they generate
more waste material. However, more efficient operating
procedures allow a larger disposal site to realize
economies of scale not available at smaller sites; thus,
the cost per ton of waste disposed is typically less.
• Rate of Operation. The number of hours that a coal-fired
power plant operates varies from plant to plant, ranging
from fewer than 3,500 hours per year to more than 6,500
hours. As operating levels increase, the amount of waste
generated will increase as more coal is burned to meet the
higher generation load.
• Type of Coal. The quantity of ash produced is proportional
to the ash content of the coal, which ranges from 5 to 20
percent on average. Also, the grade of coal and boiler
design will affect the relative proportions of fly ash and
bottom ash (see Chapter Three for a discussion of the
impact of boiler design on types and amount of wastes
generated).
• FGD Equipment. Because of the additional materials used in
flue gas desulfurization, a power plant that uses this
process to remove sulfur dioxide generates substantially
more waste than does a power plant with no sulfur dioxide
controls. The amount of waste generated also varies from
one FGD operation to the next, primarily because of
differences in sulfur content among the various coals and,
to a lesser extent, because of the type of FGD process
employed.
For the few power plants currently disposing their waste in mines or
quarries, this disposal method has been economic because of convenient access to
the disposal site. Since much of the excavation normally required at a disposal
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6-10
site has already been performed as a result of the mining or quarrying
operation, waste disposal costs can be quite competitive with costs associated
with more traditional methods of disp9sal. The cost of disposing in mines or
quarries for power plants that do not have easy access to the mine or quarry
could quickly become prohibitive due to the costs of arranging for disposal at a
remote site and of transporting the waste. Costs are also affected by whether
or not the mine or quarry is still operating, whether the mining was surface or
underground, and the amount of additional preparation required to dispose of the
wastes, among other factors.
The costs of ocean disposal are not well known because there has been
limited experience with this disposal method. Ocean disposal has been
considered for unconsolidated waste (i.e., waste material that has not been
physically or chemically altered prior to disposal)^ and for more stabilized
forms of waste, such as blocks for artificial reef construction, however, this
method has been attempted only for projects such as artificial reef
construction, and then only on a trial basis. The most critical factors that
would affect the magnitude of costs for ocean disposal are the availability of
ash-handling facilities to load ocean-going vessels, the ability to gain easy
access to the necessary waterways, and the physical characteristics of the
wastes intended for disposal.
Because neither ocean disposal nor mine or quarry disposal is likely to be
used on a widespread basis, they have been discussed here only briefly; see
Chapter Four for a more detailed discussion of these two disposal options.
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6-11
6.1.2 Costs Associated with lined Disposal Facilities
The waste management costs presented above for surface impoundments and
landfills do not include the cost of natural or synthetic liners to control the
flow of leachate from the disposal area. Traditionally, most waste management
sites, both surface impoundments and landfills, have not been lined to retard
leaching, although this practice has become more widespread in recent years (see
Chapter Four for a detailed discussion of liners). Currently, about 25 percent
of all coal combustion waste management sites employ some type of liner system.
Host liners are made of clay, synthetic materials, or stabilized utility waste.
Clay is used as a liner material because it is not very permeable, although
its permeability will vary depending on the nature of the clay and the degree of
compaction. Because clay is expensive to transport, the costs of the various
clays used for liner material are directly related to the local availability of
the clay. The installed cost of clay liners can range from $4.45 to $15.75 per
P
cubic yard. For a liner 36-inches thick, (liner thicknesses do vary), this
results in a cost range of $21,000 to $75,000 per acre, or about $0.70 to $2.55
per ton of waste disposed in a landfill and $2.25 to $8.20 per ton for waste
placed in an impoundment for a 500 MW power plant.*
Synthetic liner materials come in two basic varieties--exposable and
unexposable. The membranes of exposable liners are resistant to degradation
from exposure to the elements even if the liner is left uncovered. The
membranes of unexposable liners will not function properly if the liner is
exposed. Costs for installing exposable liners range from $43,000 to $113,000
per acre, or $1.45 to $3.85 per ton of waste disposed in landfills and from
-------
6-12
$4.70 to $12.35 per ton of waste placed in surface impoundments. Costs to
install unexposable liners range from $59,000 to $123,000 per acre, or $2.00 to
$4.15 per ton of waste disposed in landfills and $6.45 to $13.45 per ton placed
in impoundments. The ranges of costs are due primarily to differences in the
cost of the material, differences in liner thickness, and allowances for various
site-specific costs.
Stabilized utility waste, made from combinations of various ash wastes (such
as fly ash or bottom ash), FGD waste, and lime, may be used as liner material
when the required materials are available at the plant site. At an installed
cost of about $13.70 per cubic yard, liners ranging from 3 feet to 5 feet in
12
thickness can be constructed for $66,000 to $110,000 per acre, which
corresponds to total capital costs of $3.0-$5.0 million at a landfill, or about
$2.25 to $3.75 per ton of disposed waste from a 500 Mw power plant. Total
capital costs at impoundments would be $9.6-$16.0 million, or $7.20-$12.00 per
13
ton of waste managed.
6.2 COSTS OF ALTERNATIVE DISPOSAL OPTIONS
As described above, coal-fired utility wastes are currently exempt from RCRA
Subtitle C waste management requirements. In the interim, coal combustion
wastes are regulated under state statutes and regulations (see Chapter Four).
If these wastes are subject to Subtitle C regulation, the incremental costs will
depend on the regulatory option(s) ultimately selected. Section 6.2.1 outlines
the major regulatory alternatives and discusses the flexibility allowed EPA
under RCRA to promulgate regulations that account for the special nature of coal
combustion wastes. Section 6.2.2 presents cost estimates for individual
-------
6-13
Subtitle C disposal requirements, and Section 6.2.3 presents cost estimates for
three regulatory scenarios if coal combustion wastes are regulated under
Subtitle C.
6.2.1 Regulatory Alternatives under Subtitle C
As described in Chapter Five, there are two ways in which coal combustion
wastes could be identified as hazardous and thus subject to requirements
outlined in Part 264 of RCRA: the characteristic procedure and the listing
procedure.
• Regulation As Characteristic Waste. Unless otherwise
exempted, solid wastes are hazardous under RCRA if
they display any of four characteristics:
ignitibility, corrosivity, reactivity, or EP toxicity.
Coal combustion wastes are unlikely to be ignitable or
reactive, but could be corrosive (for aqueous wastes)
or EP toxic. Subtitle C regulations would apply only
to those waste streams that exhibited any of the
hazardous characteristics. As discussed in Chapter
Five, it is likely that only a small percentage of all
waste generated would be hazardous. However, since
some low volume wastes may be corrosive, this could
have an impact on utilities that currently co-dispose
high- and low-volume wastes. In these cases, the
utility could either stop co-disposing or the landfill
would have to conform to Subtitle C standards. In the
case of surface impoundments, it might still be
possible to co-dispose high- and low-volume wastes if
the disposal impoundment met the requirements for a
neutralization surface impoundment as set forth in 47
FR 1254, January 11, 1982.
• Regulation as Listed Waste. In addition to regulation
under Subtitle C as characteristic waste, the
Administrator may list a waste as hazardous under RCRA
if it meets any of the three criteria contained in 40
CFR 261.11: (1) the waste exhibits any of the four
characteristics described above; (2) it has been found
to be fatal to humans in low doses or is otherwise
measured as acutely hazardous; or (3) it contains any
of the toxic constituents listed in Appendix VIII of
Part 261. The Administrator does not have to list a
-------
6-14
waste that contains any of the toxic constituents
listed in Appendix VIII if the Agency concludes that
"the waste is not capable of posing a substantial
present or potential hazard to human health or the
environment when improperly treated, stored,
transported or disposed of, or otherwise managed".
The Administrator could decide to list as hazardous
all coal combustion waste streams or only selected
ones.
If Subtitle C regulation is warranted for coal combustion wastes, all the
requirements for hazardous waste treatment, storage, disposal, and recycling
facilities in 40 CFR 264 could be applied to the wastes from coal-fired power
plants. Since coal combustion waste is mainly managed in surface impoundments
and landfills, the requirements of Subparts A-H, K, and N would apply. In
general, the required activities include the following:
General Facility Standards. Facilities must apply for
an identification number, prepare required notices
when necessary, perform general waste analysis, secure
the disposal facility to prevent unauthorized entry,
comply with general inspection requirements, provide
personnel training, and observe location standards
(these include a provision that facilities located in
a 100-year flood plain must be designed, constructed,
operated, and maintained to prevent washout of any
hazardous waste by a 100-year flood). (40 CFR 264
Subpart B)
Preparedness and Prevention. Hazardous waste facility
operators must design and operate facilities to
minimize the possibility of fire or explosion, equip
the facility with emergency equipment, test and
maintain the equipment, and provide EPA and other
government officials access to communications or alarm
systems. (40 CFR 264 Subpart C)
Contingency Plan and Emergency Procedures. The
facility operators must have a contingency plan to
minimize hazards to human health or the environment in
the event of fire or explosion. (40 CFR 264 Subpart D)
-------
6-15
• Manifest System, Recordkeeping, and Reporting.
Hazardous waste facility operators must maintain a
manifest system, keep a written operating record, and
prepare a biennial report. (40 CFR 264 Subpart E)
• Ground-water Protection. Unless a,waste management
facility meets certain standards, a Subtitle C
facility is required to comply with requirements to
detect, characterize, and respond to releases from
solid waste management units at the facility. These
requirements include ground-water monitoring and
corrective action as necessary to protect human health
and the environment. (40 CFR 264 Subpart F)
• Closure and Post-closure. Subtitle C facilities must
comply with closure and post-closure performance
standards to minimize the risk of hazardous
constituents escaping into the environment. (40 CFR
264 Subpart G)
• Financial Requirements. Subtitle C facilities must
establish a financial assurance plan for closure of
the facility and for post-closure care. Possible
methods of financial assurance include a closure trust
fund, surety bonds, closure letter of credit, closure
insurance,-or financial test and corporate
guarantee. (40 CFR 264 Subpart H)
• Design and Operating Requirements. Unless granted an
exemption, new surface impoundments or landfills or
new units at existing impoundments or landfills must
install two or more liners and a leachate collection
system between the liners. (40 CFR 264 Subparts K
and H)
In recognition of the special nature of coal combustion wastes, Congress
afforded EPA some flexibility in designing regulations for coal combustion
wastes if they are subject to regulation under Subtitle C. This flexibility
allows EPA to exempt electric utilities from some regulations imposed on owners
and operators of hazardous waste treatment, storage, and disposal facilities by
the Hazardous and Solid Waste Amendments of 1984. Specifically, section 3004(x)
of RCRA allows the Administrator to modify the following requirements when
promulgating regulations for utility waste.
-------
6-16
• Section 3004 (c) prohibits the placement of uncontained
liquids in landfills;
• Section-3004 (d) prohibits the land disposal of specified
wastes;
• Section 3004 (e) prohibits the land disposal of solvents
and dioxins;
• Section 3004 (f) mandates a determination regarding
disposal of specified wastes into deep injection wells;
• Section 3004 (g) mandates determinations on continued land
disposal of all listed hazardous wastes;
• Section 3004 (o) lists minimum technical requirements for
design and operation of landfills and surface impoundments,
which specify the installation of two or more liners, a
leachate collection system, and ground-water monitoring;
• Section 3004 (u) requires the Administrator to promulgate
standards for facilities that burn hazardous waste as fuel;
and
• Section 3005 (j) provides that interim-status surface
impoundments must also meet minimum technical requirements
specified in section 3004 (o).
In addition to the flexibility afforded by 3004 (x), it is possible for EPA
to modify any of the standards applicable to waste treatment and disposal
facilities if lesser standards are protective of human health and the
environment. Section 3004 (a) states "... The Administrator shall promulgate
regulations establishing such performance standards, applicable to owners and
operators of facilities for the treatment, storage, or disposal of hazardous
waste identified or listed under this subtitle, as may be necessary to protect
human health and the environment."
There remains substantial uncertainty, however, about the extent to which,
in practice, the statutory language of Subtitle C would provide sufficient
flexibility to design a waste management program appropriate for high-volume,
-------
6-17
low-toxicity coal combustion wastes. EPA may also consider waste management
requirements, as needed, under the current Subtitle D provisions for solid
wastes, or may seek appropriate additional authorities.
6.2.2 Cost: Estimates for Individual RCRA Subtitle C Disposal Standards
If EPA determines that Subtitle C regulation is warranted for coal
combustion wastes, there is a wide range of regulatory options that could be
undertaken. Required activities could consist of some, all, or variations of
the requirements listed in 40 CFR Subparts B-H (and described briefly in Section
6.2.1). This section presents estimates for the costs that would be associated
with compliance with individual Subtitle C requirements.
6.2.2.1 General Facility Standards; Preparedness and Prevention;
Contingency Plan and Emergency Procedures; and Manifest
Systen
Subparts B through E in Part 264 of the RCRA regulations list general
requirements for such activities as preparing written notices and plans for
submission to EPA; conducting waste analyses; providing security at the disposal
site; and recordkeeping and reporting. Many of these activities would be
undertaken during the permitting process, which is set forth in Part 270 of
RCRA.
The Part B application must contain the technical information listed in Part
264 B through E. The cost to the electric utility industry to prepare a Part B
permit application was estimated in a study done for the Utility Solid Waste
Activities Group (USWAG), which calculated that the total cost of submitting
-------
6-18
Part B permit analyses would be $721,000 per plant, or about $0.55 per ton of
waste disposed. The industry cost, if all power plants filed Part B
applications, would be about $370 million, or about $54 million in annualized
costs.
Location standards are also specified under Subpart B of Part 264 of RCRA.
One such standard is for facilities located in a 100-year flood plain. Part
246.16(b) requires protective measures to prevent washout from flooding.
USWAG estimated the costs for protecting waste disposal facilities located
within a 100-year flood plain to be about $740 per acre for surface impoundments
18
and about $1,100 per acre for landfills on an annualized basis. This
corresponds to waste management costs of approximately $0.55 per ton of waste at
19
surface impoundments and $0.25 per ton at landfills. Industry-wide costs for
flood protection at all impoundments are estimated to be about $92 million for
capital expenditures (about $13 million in annualized costs); costs for flood
protection at all landfills would be about $146 million for capital expenditures
20
(about $20 million in annualized costs).
6.2.2.2 Ground-water Protection
Subpart F of 40 CFR Part 264 lists requirements for ground-water monitoring
systems. The costs of installing and maintaining an acceptable ground-water
monitoring program are dependent on the number of monitoring wells required and
the frequency of testing. The study conducted by Arthur D. Little for EPA
estimated that capital costs for installing six monitoring wells at a facility
21
would range from $18,000 to $25,000. At a sampling frequency of four times
-------
6-19
per year, annual operating and maintenance costs would be $10,000 to $14,500.
Total ground-water monitoring costs would range from $0.06 to $0.10 per ton of
managed waste. In another study conducted for USWAG by Envirosphere, which used
different well configurations and cost parameters, somewhat higher costs
22
($0.10-$0.12 per ton of waste managed) were estimated.
It is not known how many coal-fired power plants currently have adequate
ground-water monitoring systems in place. To estimate industry-wide costs, EPA
has conservatively assumed that all power plants would be required to install
new ground-water monitoring systems. Using the costs developed in the Arthur D.
Little study, EPA calculated that total capital costs would be about $9.3 to
$12.8 million. Total annualized costs would range from $6.5 to $9.3 million.
6.2.2.3 Corrective Action
Subpart F of 40 CFR Part 264 also lists requirements for corrective action.
A variety of actions may be undertaken to correct ground-water contamination
problems caused by a hazardous waste disposal facility. The facility owner or
operator would need to conduct a site-specific investigation to ascertain the
potential degree of contamination and the appropriate response that would be
most effective in remedying the situation. Types of remedial responses that
might be required would be placing a cap (made of either a clay or synthetic
material) on the disposal unit, counter-pumping the ground water to retard
contaminant migration, excavating the disposal area and removing the wastes to a
Subtitle C landfill, or installing an impermeable curtain around the disposal
area to prevent ground-water flow into or out of the disposal area. As one
example of the potential magnitude of corrective action costs, this section
-------
6-20
evaluates the cost to excavate the existing disposal areas and transfer the
wastes to RCRA Subtitle C-approved facilities.
EPA developed the following formula to calculate total excavation costs for
Subtitle C units, (including closure of the existing site and removal of the
wastes to a Subtitle C facility):
Cost - [(Surface Area x $45) + (Volume x $187)] x 2.16
where the surface area is measured in square meters, and volume is measured in
cubic meters.
For a power plant of average size (500 MW), it has been assumed that a
45-acre landfill would be required, or about 182,000 square meters, with a
capacity of approximately 5 million cubic meters. Based on the cost equation
listed above, costs for excavation and waste transfer for a landfill site would
24
be about $2.0 billion. For surface impoundments, the appropriate parameters
are 145 acres, or about 587,000 square meters, and a volume of about 5 million
cubic meters, which works out to about $2.1 billion for the same type of
corrective action. If this type of corrective action were required at all power
plants, compliance costs for the industry would be enormous. At a cost of about
$2 billion per plant, industry-wide costs would exceed one trillion dollars.
6.2.2.4 Closure and Post-closure
Subpart G of 40 CFR 264 specifies general closure and post-closure
requirements for Subtitle C facilities and 40 CFR 264(K) and (N) list specific
-------
6-21
requirements for closure and post-closure care of surface impoundments and
landfills, respectively. These requirements, as applied to coal combustion
wastes, would require the dewatering of ash ponds, installation of a suitable
cover liner made of synthetic materials, application of topsoil to support
vegetation, seeding and fertilizing, installation of security fencing, and
long-term ground-water monitoring. USWAG estimates that capital costs for
closing a waste management facility range from $39,000 to $128,000 per acre for
25
surface impoundments and from $55,000 to $137,000 per acre for landfills.
Once the facility is closed, additional costs would be incurred for post-closure
care -- about $1,050 per acre annually. Total annual costs for closure of a
surface impoundment would range from about $1.0 to $2.8 million for a typical
500 Mw power plant, or $5.00 to $14.75 per ton of waste managed. For a
landfill, total annual costs would range from $0.4 to $0.9 million, or $2.10 to
07
$4.90 per ton.
i
An owner or operator that chooses to close a facility in the event that coal
combustion wastes are brought under Subtitle C regulation would not necessarily
have to follow the closure and post-closure requirements for hazardous waste
facilities listed in 40 CFR Part 264. If regulations are proposed, there would
28
be some period of time before final regulations take effect. If the disposal
facility is closed during this interim period, the closure standards that would
apply would be those required under state regulations, not Subtitle C
regulations.
A facility that closes after the new regulations take effect, however, is
subject to Subtitle C closure and post-closure requirements. The USWAG study
provides an estimate of the total costs of closing all existing coal combustion
-------
6-22
waste disposal facilities and of the costs of closing only unlined facilities
(See Exhibit 6-5). Total capital costs required to close all unlined landfills
and impoundments would range from $3.5 billion for clay-capped facilities to
$9.7 billion for synthetic-capped facilities. If all facilities closed under
Subtitle C regulation, total capital costs would be about $4.3 billion for
09
clay-capped closure and $12.0 billion for synthetic-capped closure. Total
annualized costs to close only unlined facilities would range from about $575
million for closure with clay caps to about $1.5 billion for synthetic caps. If
all current waste management facilities were closed, annualized costs would be
about $700 million for clay caps to $1.8 billion for synthetic caps.
6.2.2.5 Financial Responsibility
Subpart H of 40 CFR 264 sets forth requirements for financial responsibility
for closure and post-closure care of hazardous waste facilities. A facility
owner may use several different financial mechanisms to demonstrate financial
responsibility, including purchasing a letter of credit, posting a surety bond,
establishing a trust fund, purchasing an insurance policy, providing a corporate
guarantee, or passing a financial test. Financial responsibility could be
required for closure/post-closure costs or corrective action costs. The
magnitude of the costs can vary considerably depending on the financial
mechanism that is used and the type of activity for which financial assurance is
required. For example, costs to provide a corporate guarantee or pass a
financial test may be on the order of a few hundred dollars per facility; on the
other hand, annual costs to obtain a letter of credit or to establish a trust
fund are often based on some percentage (e.g., one to two percent) of the total
-------
6-23
14
12-
10-
8-
Capital Costs
(10'Dollars) 6'
4-
2-
EXHIBIT 6-5
SUMMARY OF COSTS TO CLOSE
EXISTING WASTE DISPOSAL FACILITIES
Clay Synthetic
Cap Cap
Impoundments
Only
Clay Synthetic
Cap Cap
Landfills
Only
Clay Synthetic
Cap Cap
Impoundments
And Landfills
Close
all Facilities
Close Only
Unlined Facilities
Clay Synthetic
Cap Cap
Impoundments
Only
Clay Synthetic
Cap Cap
Landfills
Only
/uuu-
1800-
1600-
1400-
Annualized 1200-
Costs
Including innn
f\ p Ttif AVv/V"
M 0 T")n11sirO ft/\/\
^ i \j j_/uuai sj 800-
600-
400-
o f\f\
200-
0-
''''* *'**! ''
\v<
\,SN
\X\
^SN
v\\
•,\\
0\\
•;\\
<^
>\\"
\v
\ \ •
^N
'«'%/%.
\ \ "'
\\\
r'/\\
\'\\
''i '\ '\
'» \ \
^J
*% \ ''
>NX''
> *\ '% J
\ \ ''
'\''V'
\"v\
^SN
^
>^
^
''/, \ '''/
''* \ \
», '\ X
\N>
^,\\
'•., \
v ^ '
Clay Synthetic
Cap Cap
Impoundments
And Landfills
Close
all Facilities
Close Only
Unlined Facilities
Source: Envirosphere Company, "Report on the Costs of Utility Ash and FGD Waste Disposal,'
in USWAG, Report on the Costs of Utility Ash and FGD Waste Disposal, Appendix F
Part 2, October 19, 1982.
4/87
-------
6-24
costs of the closure/post-closure or corrective action activity to be
i 30
undertaken.
6.2.2.6 Design and Operating Requirements for Landfills and Surface
Inpoundnents
The level of effort required to come into compliance with Subtitle C design
and operating requirements will depend on many site-specific considerations. In
some cases, it may be possible to seal off the portion of the existing disposal
site that has been in use and upgrade the remaining portion by installing a
liner. In other situations the required changes may be sufficiently different
from existing disposal practices that the most cost-effective action may be to
open an entirely new disposal facility.
Given the variety of site-specific situations that may arise, and given the
regulatory flexibility EPA has in designing coal combustion waste management
standards, it is not feasible to estimate how many utility waste management
facilities may be affected or what type of waste management measures may be
required without conducting site-specific investigations. Nevertheless, to
indicate the approximate magnitude of costs that may be involved for different
waste management practices, the costs for three management options --
single-lined landfills, single-lined surface impoundments, and double-lined
surface impoundments -- are presented below.
Landfills
As noted earlier, single clay liners can be installed in a landfill for
-------
6-25
about $0.70 to $2.55 per ton of disposed waste and single synthetic liners for
about $1.45 to $4.15 per ton of disposed waste. The costs presented in Exhibit
6-4 indicate that waste disposal costs at a representative 500 Hw power plant
with no flue gas desulfurization equipment would average about $5 to $11 per ton
of disposed waste for a landfill operation. Adding a single clay liner to the
landfill would increase total costs to $5.70 to $13.55 per ton of disposed
waste; adding a single synthetic liner would increase costs to $6.45 to $15.15
per ton of disposed waste.
These estimates appear to be similar in magnitude, although somewhat lower
than costs estimated in another study of utility waste disposal costs conducted
for the Utility Solid Waste Activities Group (USWAG) by Econometric Research,
Inc. That study estimated that total costs for complying with requirements
related to the construction, operation, and maintenance of a single-lined
landfill would range from about $15 to $24 per ton of waste, depending on the
31
type of liner.
The study for USWAG also analyzed the total costs to the electric utility
industry if all power plants currently using landfills were required to
construct new landfills with single liners. For this scenario, USWAG assumed
that existing facilities, even if lined, would have to be replaced to comply
with new requirements. Total capital costs for this alternative would range
from $2.6 billion for landfills with one synthetic liner to $4.0 billion for
32
landfills with a single clay liner. Estimated annualized costs were about
$400 million for installing a single synthetic liner at all landfills and about
33
$600 million for installing a single clay liner.
-------
6-26
Surface Inpoundaents
The costs presented in Exhibit 6-4 for onlined surface impoundments
indicated that waste managed at a representative 500 Mw power plant with no FGD
waste production would cost about $8 to $17 per ton of waste. Using the cost
estimates for liners noted earlier (see Section 6.1.2), adding a single clay
liner would increase total management costs to about $10.25-$25.20 per ton of
waste, and adding a synthetic liner would increase costs to $12.70-$30.45 per
ton of waste.
These cost estimates for single-lined impoundments appear to be reasonably
consistent with other estimates. Studies for USWAG indicated that management
costs for impoundments with a single synthetic liner were about $19 per ton of
34
waste and $30 per ton of waste for impoundments with a single clay liner.
The USWAG report also estimated the total costs to the electric utility
industry to construct new impoundments with single liners (i.e., all power
plants currently using surface impoundments would be required to construct new
facilities to meet disposal requirements even if the current impoundment is
already lined). For this alternative total capital costs would range from $5.8
billion for impoundments with single synthetic liners to $9.5 billion for
35
impoundments with single clay liners. Annualized costs would range from $850
million for single synthetic liners at all impoundments to $1.4 billion for
single clay liners.
The study for USWAG also estimated management costs for surface impoundments
with two different types of double liners --a double synthetic liner (each with
-------
6-27
a 30 mil thickness) and a double liner system consisting of one synthetic liner
(30 mil) and a clay liner (36 inches). Total management costs for double-lined
surface impoundments would range from about $29 per ton of waste for a site with
two synthetic liners to $36 per ton of waste for a site with one synthetic liner
and one clay liner.
Industry-wide costs were also estimated for the installation of new
double-lined surface impoundments at all power plants currently using surface
impoundments. Total capital costs for installing a double-lined impoundment
ranged from $9.3 billion for a double synthetic liner to $11.6 billion for one
38 .
clay and one synthetic liner. Total annualized costs were estimated at $1.4
billion for all impoundments with a double synthetic liner and $1.7 billion for
all impoundments with one clay liner and one synthetic liner. A summary of the
costs for the various types of lined disposal facilities discussed herein is
presented in Exhibit 6-6.
6.2.2.7 Summary of Costs for Various Waste Management Alternatives
Exhibit 6-7 summarizes the costs to the electric utility industry of each of
the waste management options previously discussed. The exhibit presents cost
estimates for the total amount of capital required for each waste management
standard and for the total amount of annualized costs (i.e., annual capital,
operation, and maintenance costs) that would be incurred in order to comply with
each requirement if coal-fired combustion wastes were regulated as hazardous
wastes.
-------
6-28
EXHIBIT 6-6
SUMMARY OF COSTS FOR DIFFERENT TYPES
OF LINED WASTE MANAGEMENT FACILITIES
Landfills
Basic Practice--Unlined
Single Clay Liner
Single Synthetic Liner
Surface Impoundments
Basic Practice--Unlined
Single Clay Liner
Single Synthetic Liner
Double Synthetic Liners
Double Liners:
1 Synthetic and 1 Clay
Cost per ton
$ 5.00-$11.00
$ 5.70-$13.55
$ 6.45-$15.15
$ 8.00-$17.00
$10.25-$25.20
$12.70-$30.45
$29.00
$36.00
Total Annual Costs
for the industry a/
(millions of dollars)
N.A.
600
400
N.A.
1,380
865
1,360
1,680
a/ Total annual costs refer to annualized costs that capture capital,
operation, and maintenance expenses. Since these costs were calculated by
assuming that the utility industry would have to construct new facilities to
comply with hypothetical alternative regulations, these costs are in-addition
to the current management costs incurred by the industry.
Source: Envirosphere Company, "Report on the Costs of Utility Ash and FGD
Waste Disposal." In USWAG, Report and Technical Studies on the Disposal and
Utilization of Fossil-Fuel Combustion By-Products. October 19, 1982.
-------
Preparation of Part B Permit
Construction of New Disposal
Facilities
Landfills
- Single clay liner
- Single synthetic liner
Surface Impoundments
- Single clay liner
- Single synthetic liner
- Double liner
- clay/synthetic
- two synthetic
Closure of Existing Disposal
Facilities
Only Unlined Facilities Close
- Clay cap
- Synthetic cap
All Facilities Close
- Clay cap
- Synthetic cap
Installation of Leachate
Collection Systems
Provisions for Flood Protection
Landfills
Impoundments
Ground-water Monitoring Systems
Excavate Existing Facilities,
Removing Waste to Subtitle C Facilities
2.6
9.5
5.8
11.6
9.3
3.5
9.7
4.3
12.0
1.2
0.15
0.09
0.009-0.013
1028.0 a/
14Uu
850
1700
1400
575
1500
700
1800
460
20
13
6-9
NA
a/ Costs shown are for capital, operation, and maintenance costs for the
entire industry since the amount of capital required was not readily available.
-------
6-30
A combination of compliance alternatives could occur (e.g., closing
existing disposal facilities and constructing new facilities with leachate
collection and ground-water monitoring systems). The actual cost to the
electric utility industry for complying with RCRA Subtitle C requirements would
depend on the regulatory actions taken by the Agency if the temporary exemption
under Section 3001 of RCRA is removed. Three possible regulatory scenarios are
discussed in the following section.
6.2.3 Potential Costs to the Industry of RCRA Subtitle C Waste Management
Section 6.2.2 presented cost estimates for individual regulatory
requirements that could be imposed on utilities if EPA determines that Subtitle
C regulation is warranted for coal combustion wastes. In this section, three
possible regulatory scenarios are examined to quantify the range of incremental
costs that could result from various regulatory options. In the first scenario,
the incremental costs of regulating a portion of low volume wastes under
Subtitle C are presented. The second scenario assumes that all coal combustion
waste would be subject to Subtitle C requirements. The third scenario assumes
that high volume coal combustion wastes would be tested for RCRA hazardous
characteristics and that a small portion of the waste would be classified as
Subtitle C characteristic waste. For all three regulatory scenarios, costs are
shown only for bringing all existing power plants into compliance with the
assumed RCRA Subtitle C management regulations.
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6-31
Low Volune Waste Scenario
This scenario evaluates the costs to the utility industry if some low volume
waste streams are classified as hazardous wastes under Subtitle C. As discussed
in Chapter Three, some of these wastes can exhibit hazardous characteristics
such as corrosivity. The information available to EPA at this time does not
permit the Agency to quantify the amount of low volume wastes that may exhibit
hazardous characteristics. In this scenario, EPA has assumed that all
water-side boiler cleaning wastes are regulated as hazardous wastes since these
waste streams may exhibit corrosive characteristics. These waste
streams are assumed to be hazardous to provide an approximate estimate of the
costs to the industry if some low volume wastes display RCRA hazardous
characteristics. That is, both high-volume and low-volume wastes could be
tested for RCRA hazardous characteristics, but only a small portion of the
low-volume wastes (as represented by all water-side boiler cleaning wastes)
would need to be treated as hazardous.
As shown in Exhibit 3-19, a representative power plant generates about
180,000 gallons per year of water-side boiler cleaning wastes. The cost to
dispose of these wastes as hazardous liquids can vary depending on waste stream
variability, regional differences in disposal costs, and quantity to be
39
disposed, among other factors. For purposes of this analysis, an incremental
cost of $2 per gallon (including transportation) has been assumed based on a
40
1985 survey of hazardous waste management prices. With 180,000 gallons
generated per year at a representative power plant, annual disposal costs would
be about $360,000 per power plant. Since there are 514 power plants in the
U.S., annual disposal costs to the utility industry would be about $185 million.
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Full Subtitle G Regulation Scenario
If EPA lists high volume coal combustion waste streams in 40 CFR
261.31-261.33, all utilities will be affected. Utilities would be required to
manage all coal combustion wastes in Subtitle C permitted facilities. To
estimate the incremental costs to the industry of this regulatory scenario, the
Agency assumed that all utilities would close existing facilities and open new
waste management facilities that complied with Subtitle C standards. This
scenario assumes that the costs of managing wastes off-site will equal the costs
of managing wastes on-site and that existing facilities would be closed in the
six months before Subtitle C regulation took effect, thereby avoiding Subtitle C
closure and post-closure requirements.
Under existing state regulations, a clay cap is assumed to be adequate to
close existing waste management facilities. The total annual costs of closing
all existing facilities with a clay cap would be $700 million. For the new
facilities, EPA assumed utilities would prepare a Part B permit application,
construct new landfills and surface impoundments with clay/synthetic double
liners, install leachate collection systems, make provisions for flood
protection, and install ground-water monitoring systems. To determine
incremental costs for the industry, EPA assumed that the current proportions of
waste management facilities that were landfills and surface impoundments would
remain unchanged under Subtitle C regulation. As summarized in Exhibit 6-7,
total annual costs of the new Subtitle C facilities would be $54 million for
Part B permit applications, $725 million for new double lined landfills, $1700
million for new double lined surface impoundments, $460 million for leachate
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collection systems, $33 million for flood protection, and $9 million for
ground-water monitoring. Total incremental costs for this regulatory scenario
42
would be $3.7 billion annually.
High Volune Characteristic Waste Scenario
If coal combustion wastes were not exempt from RCRA Subtitle C regulation,
utilities would have to test high-volume and low-volume coal combustion wastes
for RCRA hazardous characteristics. Based on the RCRA characteristic results
in Chapter Five, it appears that only a small portion of coal combustion wastes
possess the hazardous characteristics of EP Toxicity or corrosivity. For
purposes of this scenario, the Agency assumed that five percent of the wastes
generated by utilities would need to be disposed in Subtitle C permitted
facilities. The Agency does not have sufficient information to know exactly the
amount of coal combustion waste that would exhibit RCRA hazardous
i
characteristics. EPA believes that coal combustion wastes generally would not
fail the RCRA hazardous characteristic tests. Based on limited information
presented in Chapter Five that indicate about five percent of all ground-water
observations at utility sites exceed the Primary Drinking Water Standards, the
Agency assumed that five percent of all wastes would require Subtitle C
treatment. The total annual cost to the industry if utilities close existing
facilities and construct new double lined facilities for five percent of all
coal combustion wastes would be $185 million.
6.3 IMPACT OF REGDIATORY ALTERNATIVES ON UTILIZATION OF COAL
COMBUSTION WASTES
As discussed in Chapter Four, coal-fired utility wastes have been used in a
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variety of applications by electric utilities and other industries to replace
other types of material. The use of utility wastes as a replacement for other
materials has reduced the amount of wastes utilities have had to dispose, while
correspondingly reducing the resource requirements of other industries that have
managed to find a productive use for the waste material.
In the event that some or all of these wastes were declared hazardous, it is
possible that the amount of by-product utilization of coal-fired utility wastes
would decline as a result of increased costs for their use and the potential for
outright prohibition of their use in some applications. On the other hand, it
is possible that certain forms of utilization (e.g., the use of fly ash in
cement) may be deemed environmentally acceptable practices if the wastes would
be unlikely to pose an environmental threat when used for such purposes. Since
costs for other forms of disposal may increase, utilization may also increase.
However, for discussion purposes, this section assumes that designation as a
hazardous waste would tend to discourage by-product utilization.
The costs that would be incurred as a result of environmental concerns over
the utilization of coal-fired utility wastes would depend on the regulatory
requirements that would have to be followed to use the wastes. The more
stringent the additional regulatory burden imposed, the greater the impact on
by-product utilization due to the higher costs of using the wastes.
In the USWAG study referenced above, the potential range of costs associated
with reduced use of coal combustion by-products was also evaluated. Three
43
different regulatory scenarios were analyzed.
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• The transportation of coal-fired utility wastes is
regulated as hazardous waste transportation under Subtitle
C of RCRA; use or disposal of the wastes would not be
regulated.
• All activities associated with reuse of coal combustion
by-products is regulated, and the regulations affect both
the transporter and owner/operator of a Subtitle C
hazardous waste management facility.
• Reuse of coal combustion by-products is prohibited.
There would be three types of costs incurred under these regulatory
scenarios: (1) replacement costs to the end-users who would no longer find
it economic to utilize the coal combustion by-products, (2) costs to
utilities to dispose of wastes no longer reused by other industries, and
(3) additional costs to the utility industry for replacement and disposal
of wastes that could no longer be used on-site. A summary of the costs
44
associated with each scenario is provided in Exhibit 6-8.
If the transportation of coal combustion by-products were subject to
increased regulation under Subtitle C, the USWAG report estimated that the
use of these by-products would decline by nearly 40 percent, increasing
45
overall disposal volumes by about 8 percent. The industries that would
be affected the most would be the roofing granules industry (conventional
roofing granules would replace bottom ash and boiler slag at a cost of
about $115 million in annual costs) and the concrete industry (portland
cement would replace fly ash at a cost of about $40 million in annual
«- N 46
costs).
If all activities pertaining to reuse of coal combustion wastes were
subject to Subtitle C regulations, utilization of coal combustion
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EXHIBIT 6-8
Summary of Economic Impacts on By-Product
Utilization under Different RCRA Regulatory Scenarios*
Cost
(106 dollars)
2700
2400
2100
1800
1500
1200
900
600
300
Utility Costs—Changes in
On-Site Practices
Utility Costs—Disposal of Wastes
no Longer Reused
Replacement Costs to End-Users
Reuse
Transportation
Regulated
All Reuse
Activities
Regulated
Reuse
Prohibited
*A11 costs are annualized based on impacts estimated from 1984-2000.
Source: USWAG, Report and Technical Studies on the Disposal and Utilization of Fossil-Fuel
Combustion Bv-Products. Appendix G, October 26, 1982
6/87
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by-products was estimated to decline by about 75 percent, increasing
47
overall disposal volumes by about 14 percent. The greatest impact would
be on the concrete industry, which would spend about $270 million annually
to replace fly ash with portland cement.
If all reuse of coal combustion by-products were prohibited, industries
using these by-products would have to find suitable replacements; total
49
disposal volumes would increase by nearly 20 percent. The largest
impacts would be on the asphalt industry, which would be forced to replace
ash with asphalt at a cost of approximately $250 million annually, and the
concrete industry, which would replace fly ash with portland cement at a
cost of about $270 million annually.
6.4 ECONOMIC IMPACTS OF ALTERNATIVE HASTE DISPOSAL OPTIONS
Since many alternative disposal practices discussed in this chapter
could impose additional costs on the electric utility industry, this
section evaluates the effect that these increased costs might have on
electricity generation costs and U.S. coal consumption. This study employs
three measures to determine the potential economic impact of alternative
disposal practices:
1. Average increase in electricity generation costs at existing
coal-fired power plants,
2. Average increase in electricity generation costs at coal-fired
power plants yet to be constructed, and
3. Impact on the electric utility industry's consumption of coal.
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Exhibit 6-9 summarizes the cost of generating electricity at both existing
and yet-to-be-constructed power plants (see Appendix G for a detailed discussion
of the assumptions used to determine these generation costs). Disposal costs
average about 3-5 percent of total generation costs at existing coal-fired power
plants, but only about 1-3 percent at future power plants. Although the actual
costs of disposal at existing and future power plants are similar, the
percentages are different because total generation costs at future power plants
are higher than generation costs at existing power plants (resulting in a lower
overall percentage for disposal costs at future power plants). Total generation
costs are higher at future power plants because they include capital, operation
and maintenance, and fuel costs, while the generation costs for existing power
52
plants include operation and maintenance and fuel costs only.
Based on the cost assumptions used to develop Exhibit 6-9, coal-fired
53
electricity generation at both new and future baseload power plants is less
54
expensive than generation with natural gas.
The economic impacts likely to result from the use of alternative coal-fired
utility waste disposal practices will depend upon several factors, including
which disposal options are required, how much the cost of coal-fired electricity
generation changes, and whether these changes affect the relative
competitiveness between coal and other fuels. To indicate the potential
magnitude of these impacts, Exhibit 6-10 summarizes the potential cost impacts
on electricity generation rates due to the alternative waste disposal options
discussed earlier in this chapter.
As indicated in Exhibit 6-10, some alternative disposal options could
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6-39
EXHIBIT 6-9
IMPACT OF CURRENT WASTE DISPOSAL COSTS
ON TOTAL ELECTRICITY GENERATION COSTS*
60
50
40-
Generation 30
Costs
(Mills Per
Kilowatt-Hour)
20-
10-
Coal
Gas
Low
Sulfur
Coal
High
Sulfur
Coal
Gas
Existing Power Plant
Future Power Plant
!HHi Disposal Cost
Fuel
Operation and Maintenance
Capital
* Generation costs are based on typical 500 Mw
power plant in the midwest operating at 70
percent utilization rate. Regional costs will vary
depending on fuel price and availability, among
other factors.
Source: Generation cost estimates are from ICF Incorporated. Waste disposal costs are taken from
Arthur D. Little, Inc., Full-Scale Field Evaluation of Waste Disposal From Coal-Fired
Electric Generating Plants. June 1985.
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6-40
Btninn Ł-10
IMPACT OF ALTEBUIIVE DISPOSAL (UTIUCi OH KLH.THIUTX
Impact On
Option
Fart B Permit
Existing Landfills b/
Single Clay Liner
Single Synthetic Liner
Incremental Cost
($/ton of
disposed waste)
$0.55
$0.70-$2.55
$1.45-$4.15
a/
mills/lcilowatt-hour
0.03
0.04-0.16
0.09-0.26
GEnuATIjOiI (XJfriTK
Generation Costs
X of Total Generation Costa
Existing Plant Future Plant
0.2 0.1
0.2-0.9 0.1-0.3
0.5-1.4 0.2-0.6
Existing Surface Impoundments
Single Clay Liner
Single Synthetic Liner
Hew Landfills
Single Clay Liner
Single Synthetic Liner
New Surface Impoundments
Single Clay Liner
Single Synthetic Liner
Double Synthetic Liner
Double Synthetic/
Clay Liner
Site Closure
Leachate Control
Flood Protection
Ground-water Monitoring
Utilization
Transportation
Regulated
All Activities
Regulated
Reuse Prohibited
$2.2S-$8.20
$4.70-$13.45
$ 5.70-S12.55
$ 6.45-S15.15
$10.25-$25.20
$12.70-$30.45
$29.00
$36.00
$2.10-$14.75
$4.70
$0.25-$0.55
$0.06-$0.10
$3.00
$13.20
$18.75
0.14-0.51
0.30-0.84
0.36-0.79
0.40-0.95
0.64-1.58
0.80-1.91
1.82
2.26
0.13-0.93
0.30
0.02-0.03
0.004-0.006
0.19
0.83
1.18
0.8-2.8 0.3-1.1
1.7-4.7 0.6-1.8
2.0-4.4 0.8-1.7
2.2-5.3 0.9-2.0
3.6-8.8 1.4-3.4
4.4-10.6 1.7-4.1
10.1 3.9
12.6 4.8
0.7-5.2 0.3-2.0
1.7 0.6
0.1-0.2 c/
Ł/ Ł/
1.1 0.4
4.6 • 1.8
6.6 2.5
a/ Based on a representative 500 Mw plant operating at a 70 percent utilization rate. Costs are
incremental costs only; that is, cost impact of new disposal facilities is only that portion of
costs in excess of current disposal costs (see Exhibit 6-4 for these costs). A mill is
one-tenth of a cent ($0.001).
b/ Costs for existing waste disposal facilities refer only to the cost of liner installation.
Costs for new waste disposal facilities refer to all the costs for site construction and liner
installation.
Ł/ Less than 0.1 percent.
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6-41
increase electricity generation costs at existing power plants by several
percent. In some cases the cost impact could be substantial if several options
were combined as part of an integrated waste management strategy. For example,
if new waste management regulations led to closure of the current disposal site
and the construction of a new lined facility with a leachate control system,
flood protection, and ground-water monitoring system, coal-fired generation
costs at existing coal-fired power plants could increase by nearly 20 percent
(roughly 3.5 mills/kilowatt-hour).
Generation cost increases of this magnitude have the potential to reduce
coal consumption at existing coal-fired power plants if these cost increases
make it more expensive to generate electricity with coal than with other fuels.
A utility decides how much electricity to generate at any existing power plant
primarily by comparing the operation and maintenance costs (including fuel)
associated with generating electricity at all of its power plants. Power plants
with the lowest generation costs will be operated first. Generally, it is less
expensive to generate electricity with coal than with other fuels such as oil or
gas, but oil-fired electricity generation can be competitive with coal when the
price of oil is approximately $10-$15 per barrel. However, whether and to
what degree electric utilities would shift away from the use of coal would
depend on several factors, including the relative price of coal compared with
the price of other fuels, the magnitude of the increase in generation costs if
disposal practices were altered, and the overall efficiency of competing power
plants.
For power plants yet to be constructed, the impact of higher disposal costs
on coal consumption could be more substantial, with possible generation cost
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increases approaching 8-10 percent if several options are combined. Generation
cost increases of this magnitude could have a substantial effect on the amount
of coal consumed at future power plants since many utilities may decide not to
build coal-fired power plants. Although currently coal-fired electricity
generation may be a more economic option than oil-fired or gas-fired generation
at plants yet to be constructed, this situation could change if more expensive
disposal practices were required for coal combustion wastes. This is because
the higher capital costs of coal-fired electricity generation, compared with
oil- or gas-fired generation, reduces the overall cost differential between the
use of coal and the use of oil or gas at future power plants (compared to the
cost differential between coal and oil or gas at existing power plants). As a
result, coal is more likely to be replaced by alternative fuels at future power
plants than it is at existing power plants.
In fact, since oil prices dropped below $20 per barrel in early 1986, many
utilities have been seriously evaluating the feasibility of building oil- or
gas-fired generating capacity in lieu of coal-fired units. As a result, in some
instances even an increase of a few percent in coal-fired generation costs could
be sufficient to tip the balance in favor of using natural gas or oil to fuel
power plants that have not yet been constructed. If increased disposal costs do
promote such competition, growth in future U.S. consumption of coal would
probably decline. The exact magnitude of this decrease in future coal
consumption would depend on many factors, including the type of new waste
disposal practices adopted and the price of alternative fuels in different
regions of the country. An in-depth analysis of the potential impact of
alternative waste management scenarios on electric utility generation practices
and investment decisions and, as a result, the level of coal consumption, is
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beyond the scope of this Report to Congress. However, EPA intends to seek more
information and analysis on the issue of economic impacts through the public
hearing process and through its own additional investigations. As required by
law EPA will conduct the appropriate regulatory impact analyses, including the
economic impact analysis, during the six month public review period following
submission of this report to Congress if it is determined that current utility
waste management practices for coal-fired combustion wastes are inadequate and
additional regulations are warranted.
6.5 SUMMARY
The cost to manage coal combustion waste in basic waste management
facilities currently ranges from as little as $2 to as much as $31 per ton. The
wide range in management costs is primarily due to differences in (1) the type
of facility, (2) the size of the facility and (3) the characteristics of the
waste.
• Some facilities currently incur additional costs because
they have undertaken additional safeguards against
leaching, including liner installation, leachate collection
and treatment, and ground-water monitoring.
• Management costs at surface impoundments tend to be greater
than those at landfills because of the higher costs of site
preparation at impoundments.
• The size of larger waste disposal facilities allows them to
operate more efficiently, which tends to reduce the cost
per ton of waste management.
• Fly ash is typically more expensive to manage than bottom
ash or FGD waste because of additional requirements for
collection, handling, and treatment prior to disposal.
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If additional regulations are promulgated requiring
electric utilities to alter the current methods by which
they manage coal-fired wastes, additional costs may be
incurred by the industry as it complies with the new
requirements.
The most common practice for controlling leaching at a
waste management site is installation of a liner prior to
placement of the waste. Liners are usually made of low
permeable clay or a synthetic material and can be installed
in one or more layers. The cost of installing a liner
ranges from $0.70 to $8.20 per ton of waste for clay liners
and $1.45 to $13.45 per ton for synthetic liners. Total
disposal costs for single-lined landfills range from about
$6 to $15 per ton of waste, while costs for single-lined
surface impoundments range from $10 to $30 per ton.
Industry-wide costs to construct and install lined
management facilities could range from $0.4 to $1.7 billion
on an annualized basis, depending on type of facility, type
of liner material, and number of liners installed.
Installation of leachate collection systems to control
potential environmental problems that might result from
substances leaching from a waste management site could cost
about $4 to $5 per ton of waste. Total costs to the
utility industry to install leachate collection systems
could be $1.2 billion in capital costs, or about $460
million in annualized costs.
The cost of installing a ground-water monitoring system to
detect the presence and concentration of various waste
constituents in the ground water surrounding a waste
management facility is generally less than $0.25 per ton of
waste. Total capital requirements to the industry would
likely range from $9 to $13 million, with annual costs of
$6 to $9 million.
If-coal combustion wastes were regulated under Subtitle C
of RCRA, costs to the utility industry could approach $3.7
billion annually if all wastes were listed as hazardous.
Costs would be substantially lower than $3.7 billion
annually if coal combustion wastes were tested for
hazardous characteristics since only a small portion of
coal combustion wastes would be likely to fail the RCRA
hazardous characteristic tests. These costs to comply with
Subtitle C do not include corrective action costs or the
higher costs that may be associated with recycling coal
combustion wastes; these costs to the utility industry
could be very high.
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6-45
New waste management practices could increase the cost of
generating electricity at existing coal-fired power plants
by nearly 20 percent in some cases. Although coal is
generally the preferred boiler fuel at existing power
plants, an increase of this magnitude could cause a decline
in the amount of coal consumed at these power plants if
alternative fuel prices were reasonably competitive.
If new management practices are required at future power
plants, the increase in generation costs is unlikely to
exceed 10 percent. Although on a percentage basis this
increase would be less than the percentage increase
possible at existing power plants, the choice of fuels at
future power plants is much more competitive (due to the
capital costs that must be included in the costs of a
future power plant). In some instances this could lead to
a decrease in coal consumption if the use of alternative
fuels is found to be more cost effective since many
utilities may decide not to build coal-fired power plants.
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^ In one study, the cost of building and operating an artificial reef
construction system was estimated to be about $50 per ton, roughly double the
amount estimated by the study authors for more conventional waste disposal. In
those situations where space constraints or other factors would substantially
increase the costs for conventional disposal, ocean disposal through reef
construction was seen as an economically viable option. See J.H. Parker,
P.M.J. Woodhead, and I.W. Dued all, "A Constructive Disposal Option for Coal
Wastes - - Artificial Reefs," in Proceedings of the Second Conference on
Management of Municipal. Hazardous, and Coal Wastes. S. Sengupta (Ed.),
September 1984, p. 134.
8 Arthur D. Little, p. 6-132. "Installed cost" of a liner (expressed in
terms of cost per ton of disposed waste) refers to the increase in the cost of
disposing of one ton of waste as a result of adding a liner to an unlined
landfill or surface impoundment.
^ Ibid. The costs in the Arthur D. Little report were presented for an
18-inch clay liner. Costs were doubled to approximate the costs for installing
a 36-inch clay liner, which is currently a more common practice. The dollar
per ton estimate was derived by multiplying total capital costs by a 14.5
percent capital recovery factor to determine annual capital charges. Assuming
that a 500 Mw power plant has a 45 acre landfill disposal site, total capital
charges would range from $945,000 to $3.4 million, or about $140,000 to
$490,000 in annualized charges. Assuming that a 500 Mw power plant would need
a 145-acre wet surface impoundment, total costs would range from $3.0 to $10.9
million, or $440,000 to $1.6 million in annualized costs. These annualized
charges were then divided by the amount of waste produced annually by a 500 Mw
power plant with no FGD process, (i.e., 192,500 tons) to determine the dollar
per ton cost. This approach is used throughout the report to calculate dollar
per ton estimates. See Appendix G for more detail on this methodology.
Ibid. For landfills, total installed costs would range from $1.9 to
$5.1 million per plant, assuming a 45-acre disposal site. Annual costs would
range from about $280,000 to $740,000. Based on 192,500 tons of waste, the
cost is $1.45-$3.85 per ton. For ponds (i.e., impoundments), total installed
costs would be $6.2-$16.4 million, or $900,000-$2.4 million annualized. On a
dollar per ton basis, this range is $4.70-$12.35.
Ibid. For landfills total installed costs would range from $2.7-$5.5
million, or about $385,000-$800,000 in annual costs per ton. This corresponds
to $2.00-$4.15 per ton. Total installed costs for ponding operations are
$8.6-$17.8 million, or $1.2-$2.6 million annualized. This corresponds to
$6.45-$13.45 per ton.
12 Ibid.
Total capital costs for landfills of $3.0 to $5.0 million correspond
to annual charges of about $430,000 to $720,000. Assuming 192,500 tons of
waste, the per ton cost is $2.25 to $3.75. Using the same approach to derive
disposal costs at a 145-acre lined impoundment yields $7.20 to $12.00 per ton.
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14
A waste management unit is not subject to regulation under Section
264.1 if the Regional Administrator finds that the unit (1) is an engineered
structure, (2) does not receive or contain liquid waste or waste containing
free liquids, (3) was designed and is operated in such a way to exclude
liquids, precipitation, and other run-on and run-off (4) has both inner and
outer layers of containment enclosing the waste, (5) has a leak detection
system built into each containment layer, (6) will have continuing operation
and maintenance of these leak detection systems during its active life and
throughout the closure and post-closure care periods, and (7) is constructed in
such a way that, to a reasonable degree of certainty, hazardous constituents
will not migrate beyond the outer containment layer prior to the end of the
post-closure care period. (40 CFR 264.90(b)(vii).
15 See 40 CFR 246.143.
These specified wastes are liquid hazardous wastes that have a pH less
than or equal to 2.0 and/or (1) free cyanides at concentrations greater than or
equal to 1,000 mg/1, (2) arsenic and/or arsenical compounds at concentrations
greater than or equal to 500 mg/1, (3) cadmium and/or cadmium compounds at
concentrations greater than or equal to 100 mg/1, (4) chromium and/or chromium
compounds at concentrations greater than or equal to 500 mg/1 (5) lead and/or
lead compounds at concentrations greater than or equal to 500 mg/1, (6) nickel
and/or nickel compounds at concentrations greater than or equal to 134 mg/1,
(7) mercury and/or mercury compounds at concentrations greater than or equal to
20 mg/1, (8) selenium and/or selenium compounds at concentrations greater than
or equal to 100 mg/1, (9) thallium and/or thallium compounds at concentrations
greater than or equal to 130 mg/1, (10) polychlorinated biphenyls at
concentrations greater than or equal to 50 mg/1, (11) halogenated organic
compounds at concentrations greater than or equal to 1,000 mg/kg.
Envirosphere Company, "Report on the Costs of Utility Ash and FGD Waste
Disposal", in USWAG, Report and Technical Studies on the Disposal and
Utilization of Fossil-Fuel Combustion Bv-Products. October 19, 1982, p. 21,
Appendix F, part 2. Dollar per ton estimates were determined by calculating
annual costs ($721,000 x 14.5 percent capital recovery factor - $104,500). The
capital recovery factor was applied to all costs since a breakdown of different
types of costs required for a Part B permit was not available.
18 Ibid, p. 18.
19
Assuming a 145-acre impoundment site, costs would be about $107,000.
On a per ton basis, this corresponds to about $0.55. For a 45-acre landfill
with costs of $1100 per acre, total costs would be about $50,000, for a per ton
cost of $0.25.
20
Envirosphere, in USWAG, Appendix F, Part 2, p. 27, 32.
21
Arthur D. Little, p. 6-133. On an annualized basis, capital costs
would range from about $2,650 to $3,550.
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22
Envirosphere Company, in USWAG, Appendix F, Part 2, p. 37.
Envirosphere estimated that about four wells, one upgradient from the site and
three downgradient, would be required for each 100 acre disposal site (or about
six wells for a site of 145 acres) at a capital cost of approximately $6,000
per well. Total capital costs for six wells would be $36,000, which is about
$5,200 on an annualized basis. It was assumed that the wells would be sampled
quarterly the first year, then semi-annually thereafter. The operation
and maintenance costs would average about $2,500 to $3,000 per well, for
facility costs (assuming six wells) of $15,000 to $18,000 per year. Total
annualized costs, therefore, would range from $20,200 to $23,200, or $0.10 to
$0.12 per ton of waste disposed.
23
For a more complete discussion, see ICF Incorporated, Liner Location
Risk and Cost Analysis Model. Draft Phase II Report, Appendix F-2, Office of
Solid Waste, U.S. Environmental Protection Agency, March 1987.
The cost equation on which this cost estimate is based was developed
for typical RCRA Subtitle C landfills. Since these facilities tend to be much
smaller than the size of utility disposal areas, extrapolating the cost
equation for larger sizes may introduce some errors. Nevertheless, these cost
estimates do indicate the approximate magnitude of corrective action costs that
would likely be incurred.
25
Econometric Research, "The Economic Costs of Potential RCRA Regulations
Applied to Existing Coal-Fired Electric Utility Boilers," in USWAG, Report and
Technical Studies on the Disposal and Utilization of Fossil-Fuel Combustion
Bv-Products. October 26, 1982, p. 15, Appendix F, part 1.
26 Ibid, p. 15.
27
Ibid, p. 18. On a per acre basis, total annual costs range from $6,700
to $19,600 for surface impoundments and $9,000 to $21,000 for landfills. For a
145-acre impoundment, this corresponds to $1.0 to $2.8 million in total annual
costs, or $5.00 to $14.75 per ton of waste. For landfills the per ton cost
would be $2.10 to $4.90 based on total annual costs of $0.4 to $0.9 million.
28
See Administrative Procedure Act, U.S. Code 5 Sec. part 551.
29
Ibid, see pages 26 and 31 of the Econometric report for all closure
costs.
30
For further discussion of the potential magnitude of these costs, see
ICF Incorporated, Flexible Regulatory and Enforcement Policies for Corrective
Action, prepared for U.S. Environmental Protection Agency, September 12, 1985.
Econometric Research, in USWAG, Appendix F, Part 1, p. 15. Econometric
Research used capital costs for disposal of about $5.20 per ton of waste
produced over a 20-year life of the facility for synthetic liners and about
$8.10 per ton for clay liners, plus about $0.06 per ton per year for operation
and maintenance costs. Total initial capital outlays would then be $104 per
ton ($5.20 per ton times 20 years) for synthetic liners, or about $15.08 per
ton on an annualized basis, and $162 per ton ($8.10 per ton times 20 years) for
clay liners, or $23.49 per ton on an annualized basis. With the addition of
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the $0.06 per ton for operation and maintenance costs, total costs would range
from $15.14 per ton for synthetic liners and $23.55 per ton for clay liners for
each ton of waste produced annually.
32
Ibid.. p. 27. Total capital costs for existing power plants were
assumed to be $2.1 billion for single synthetic liners and $3.2 billion for
single clay liners. Since these cost estimates were based on a universe of 412
power plants, costs were adjusted upward by 514/412 to approximate total
industry costs for the number of power plants estimated at the time of this
study -- 514 power plants. This adjustment was made for all industry-wide
costs cited from the USWAG report.
33 Ibid.. p. 32.
34
Ibid.. p. 18. Econometric Research, Inc., calculated that disposal
costs for an impoundment with a single synthetic liner were about $0.95 per ton
of waste over the life of the facility and about $1.50 per ton of waste for
clay-lined impoundments. For a plant generating 192,500 tons each year for 20
years (or 3.85 million tons), that corresponds to 3.85 million tons x $0.95 per
ton - $3.7 million for an impoundment with a single synthetic liner (or about
$19 per ton based on $3.7 million divided by 192,500 tons of waste annually)
and 3.85 million tons x $1.50 per ton - $5.8 million for an impoundment with a
single clay liner (or about $30 for each ton of waste disposed in a year).
Ibid, p. 26. The costs in the USWAG report were adjusted by 514/412 to
account for the 514 power plants estimated at the time of this study compared
to the 412 power plants assumed in the USWAG report.
37
Ibid, p. 18. The double synthetic liner disposal system averages about
$1.45 per ton over the life of the facility and a system with one synthetic
liner and one clay liner costs about $1.80 per ton. At 3.85 million tons of
waste over a 20 year facility life, that is $5.6 million for a double synthetic
liner (or about $29 for each ton disposed in a year). For a combination
synthetic/clay liner system, 3.85 million tons x $1.80 per ton - $6.9 million
(or about $36 per ton).
39
ICF Incorporated, 1985 Survey of Selected Firms In The Commercial
Hazardous Waste Management Industry. Prepared for U.S. Environmental Protection
Agency, November 6, 1986.
40 TWH
Ibid.
41
To develop a cost estimate for landfills constructed with clay/
synthetic double liners, the ratio of the cost of single clay and synthetic
liners at landfills in Exhibit 6-7 to the cost of single clay and synthetic
liners at surface impoundments was multiplied by the cost of clay/synthetic
liners at surface impoundments.
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42
The costs to close and cap existing facilities have been included in
this estimate, while corrective action costs have not been included. Although
closure costs will be incurred eventually by the industry, in most cases they
would not be incurred for many years to come. To be conservative, EPA has
included closure costs as part of potential RCRA Subtitle C compliance costs.
43
Envirosphere Company, "Economic Analysis of Impact of RCRA On Coal
Combustion By-Products Utilization." In USWAG, Report and Technical Studies On
the Disposal and Utilization of Fossil-Fuel Combustion By-Products. October 26,
1982, Appendix G.
44
Envirosphere Company, in USWAG, Appendix G. The costs in Exhibit 6-8
are based on estimated impacts between 1984 and 2000 and adjusted by a capital
recovery factor of 14.5 percent to annualize the costs (total capital
requirements were not identified). It was estimated that about 203 million
tons of coal combustion by-products would be used over this period, with a
similar amount used on-site by the utilities. That is, the costs assume that
the amount of by-products utilized would have increased over time.
45
Ibid.. p. 89. Total ash generation in 2000 was assumed to be 169.5
million tons, with about 27.3 million tons utilized and therefore, 142.2
million tons destined for disposal areas. Utilization was estimated to decline
about 11.5 million tons, so the total amount of waste to be disposed would
increase to 153.7 million tons.
46 Ibid.
47
Ibid.. p. 91. Total utilization was assumed to decline by about 20.3
million tons in 2000. Therefore, the total amount of waste disposed would
increase from 142.2 million tons to 162.5 million tons.
48 Ibid.
49
Total utilization was assumed to be 27.3 million tons in 2000, thereby
increasing total disposal volume from 142.2 million tons to 169.5 million tons.
Envirosphere Company, in USWAG, Appendix G, p. 93.
To estimate the potential impact of alternative disposal practices on
electricity generation costs, the first step was to calculate the approximate
portion of generation costs due to current basic disposal practices. Current
basic disposal practices for coal-fired utility wastes were assumed to be
disposal in either an unlined pond or landfill, although other practices are
sometimes followed. Generation costs for a typical coal- and gas-fired power
plant are shown to indicate the relative competitiveness of these two fuels
when current disposal practices for coal-fired utility wastes are followed.
See Appendix G for a detailed discussion of the assumptions used to determine
these generation costs.
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52
Capital costs are not included in the cost estimates for existing power
plants because these are "sunk" costs, i.e., they have already been spent. As
a result, the percentage impact on total generation costs at existing power
plants is larger because the cost base is smaller compared to future power
plants.
Baseload refers to power plants that are operated as much as possible
to maximize the amount of electricity these plants can generate. For this
analysis a.baseload power plant is assumed to operate 70 percent of the time.
54
The generation costs in Exhibit 6-9 are intended to be representative
of typical power plants. However, the actual cost of generation and the
relative competitiveness between coal and gas depends on many factors,
including plant size, utilization rate, and delivered fuel cost.
This price range is only intended to illustrate the approximate range
at which oil becomes competitive with coal at existing power plants. The
actual level at which coal might begin to lose market share depends on many
factors, including relative price differentials, fuel availability, gas prices
vis-a-vis oil prices, types of power plants (i.e., overall plant efficiency),
etc.
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CHAPTER SEVEN
CONCLUSIONS AND RECOMMENDATIONS
This chapter concludes the Environmental Protection Agency's Report to
Congress on fossil fuel combustion wastes. Pursuant to the requirements of
Section 8002(n) of the Resource Conservation and Recovery Act (RCRA), the
Report addresses the nature and volumes of coal combustion wastes, the
environmental and human health effects of the disposal of coal combustion
wastes, present disposal and utilization practices, and the costs and economic
impacts of employing alternative disposal and utilization techniques. A
statement of the scope of the report and a summary of the report's findings
are presented below, followed by the Agency's recommendations.
7.1 SCOPE OF REPORT
As discussed in Chapter One, this Report to Congress covers the generation
of coal-fired combustion wastes by the electric utility industry. Other
fossil fuel combustion wastes not discussed in this report include coal, oil
and gas combustion wastes from other industries and oil and gas combustion
wastes from electric utilities. Overall, coal combustion by electric
utilities accounts for approximately 90 percent of all fossil fuel combustion
wastes that are produced. Moreover, this percentage is likely to increase in
the future since coal consumption by the electric utility industry is expected
to increase substantially while coal use by other sectors remains relatively
constant. Electric utility coal consumption will grow as new coal-fired power
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plants are constructed to meet increasing electricity requirements in the
United States.
7.2 SUMMARY OF REPORT
The Agency's conclusions from the information presented in this report are
summarized under seven major groupings paralleling the organization of the
report: 1) Location and Characteristics of Coal-Fired Power Plants, 2) Waste
Quantities and Characteristics, 3) Waste Management Practices, 4) Potential
Hazardous Characteristics, 5) Evidence of Environmental Transport of
Potentially Hazardous Constituents, 6) Evidence of Damage, and 7) Potential
Costs of Regulation.
7.2.1 Location and Characteristics of Coal-Fired Power Plants
1. There are about 500 power plant sites in the United States that
consume coal to generate electricity. Each power plant may be the
location for more than one generating unit; at these 500 power plants
there are nearly 1400 generating units.
2. The size of coal-fired power plants can vary greatly. The size of a
power plant is typically measured by the number of megawatts '(Mw) of
generating capacity. Coal-fired power plants can range in size from
less than 50 Mw to larger than 3000 Mw.
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3. Coal-fired power plants are located throughout the United States.
Coal is used to generate electricity in every EPA region; almost
every state has some coal-fired generating capacity.
4. More coal-fired power plants will be built as the demand for
electricity increases. Coal is a fuel often used by the electric
utility industry to generate power. This reliance on coal is
unlikely to change for many years to come in the absence of greatly
increased costs for coal-fired electricity.
5. Coal-fired power plants are located in areas of widely-varying
population density. Some power plants are located in remote rural
areas, whereas others are located in urban environments. They are
usually, although not always, located at least a couple of kilometers
from major population concentrations. In general they are located
near a major body of surface water such as a lake, river, or stream.
7.2.2. Waste Quantities and Characteristics
1. The amount of wastes generated annually by coal-fired power plants is
large by any standard. About 84 million tons of high-volume wastes
-- fly ash, bottom ash, boiler slag, and FGD sludge -- are generated
annually. The total amount of low-volume wastes generated from
equipment maintenance and cleaning operations is not known precisely,
but is also substantial.
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2. Quantities of waste produced will increase significantly as more
electricity is generated by coal. The amount of high-volume wastes
produced annually could double by the year 2000. In particular, the
amount of FGD sludge produced will triple (to about 50 million tons)
as newly-constructed power plants install FGD equipment to remove
sulfur dioxide from the flue gases.
3. Coal combustion wastes are a common by-product from the generation of
electricity. The noncombustible materials are present in the coal as
a result of geologic processes and mining techniques. Given current
technologies for generating electricity, wastes from coal combustion
will continue to be produced in significant quantities.
4. High-volume coal combustion wastes do contain elements that in
sufficient concentrations can pose a potential danger to human health
and the environment. Most elements in coal are not hazardous.
However, trace elements typically found in coal become concentrated
as a result of the combustion process. Certain elements known to
pose health risks can be found in the wastes at hazardous levels.
5. Although most low-volume wastes do not appear to be hazardous. there
are some waste streams from cleaning that could potentially be
hazardous. The waste streams of most concern are water-side boiler
cleaning solutions, which may be corrosive or toxic. Because the
amount and type of low-volume wastes produced can vary substantially
from one power plant to the next, not as much is known about
low-volume wastes compared to high-volume wastes.
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7.2.3 Waste Managenent Practices
1. Most coal combustion wastes are typically disposed in landfills or
surface impoundments. with recent trends toward increased reliance on
landfills. Although some disposal does occur off-site, most wastes
are disposed on-site; it is likely that most power plants built in
the future will dispose on-site in a landfill.
2. Typical industry practice is to co-dispose low-volume wastes with
high-volume wastes or. in some instances, to burn the low-volume
wastes in the utility boiler. There are many other types of waste
management practices that are also used to alter the physical and
chemical characteristics of low-volume wastes prior to disposal.
These practices vary widely from plant to plant. There are no
reliable data sources that accurately describe the types of
low-volume disposal practices used at each power plant.
3. The potential for increased waste utilization as a solution to waste
management in the utility industry appears to be limited. About 21
percent of all high-volume wastes are currently recycled; some
opportunities appear to exist to increase utilization, but not in a
major way.
4. Coal combustion wastes are typically regulated under state solid
waste laws, which treat these wastes as non-hazardous materials. The
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extent of state regulation can vary significantly from one state to
another.
5. Many waste management practices applied to hazardous waste in other
industries, such as liners, have only seen limited use for coal
combustion waste management. In recent years, some of these
practices, including liners and leachate collection systems, have
become more common. There is an increasing tendency to manage coal
combustion wastes by disposing on-site (at the power plant) in
landfills.
6. There are few major innovations under development that would lead to
major changes in waste management practices.
7.2.4 Potential Hazardous Characteristics
1. The RCRA hazardous characteristics of most concern are corrosivity
and EP toxicitv. Coal combustion wastes are generally not ignitable
or reactive.
2. Most waste streams would not be considered corrosive under RCRA
definitions. Only aqueous wastes, which most coal combustion wastes
are not, are considered corrosive under RCRA. There are some aqueous
coal combustion waste streams that are very near corrosive levels,
particularly low volume wastes such as boiler blowdown or coal pile
runoff. In some instances, boiler cleaning wastes may be corrosive,
particularly those that are hydrochloric acid-based.
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3. Coal combustion wastes generally are not EP toxic, although there are
some exceptions. It is rare for coal combustion wastes to fail the
EP test (or the TCLP test developed more recently) . Extract
concentrations in excess of 100 times the Primary Drinking Water
Standards have been found only for the elements cadmium, chromium,
and arsenic from some FGD sludges and coal ash samples, although
these levels are quite rare -- average levels are substantially below
100 times the PDWS.
4. There are insufficient data to determine a priori which waste streams
at a power plant will exhibit RCRA hazardous characteristics.
Accurate determinations could only be made if site-specific analyses
were conducted.
7.2.5 Evidence of Environnental Transport of Potentially
Constituents .
1. Migration of potentially hazardous constituents has occurred from
coal combustion waste sites. From the limited data available,
exceedances of the Primary Drinking Water Standards have been
observed in the ground water for several elements, including cadmium,
chromium, lead, selenium, and arsenic.
2. Ground-water contamination does not appear to be widespread. Only a
few percent of all ground-water quality observations indicate that a
PDWS exceedance has occurred, although many utility waste management
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sites at which ground-water monitoring has been done have had at
least one exceedance. However, the observed contamination may not
necessarily be chronic since sites at which exceedances have been
noted do not consistently register in excess of the PDWS.
3. When ground-water contamination does occur, the magnitude of the
exceedance is generally not large. Most PDWS exceedances tend to be
no more than 10 or 20 times the PDWS, although a few observations
greater than 100 times the PDWS have been noted.
4. Human populations are generally not directly exposed to the
groundwater in the vicinity of utility coal combustion waste
management sites. Public drinking water intakes are usually at least
a few kilometers away. Also, most power plants are located near
surface water bodies that dilute the concentration of any elements
found in the ground water.
5. Because high-volume and low-volume waste streams are often
co-disposed, it cannot be determined if one specific waste stream was
the source of contamination.
6. The ground-water quality information on which this evidence is based
is limited. Data were only available from a small number of utility
waste management sites; no comprehensive database on ground-water
contamination potentially attributable to coal combustion wastes
exists.
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7.2.6 Evidence of Danage
1. There are few cases considered to be documented evidence of
from coal combustion wastes. Among these cases there is some dispute
whether any observed damage can be attributed to the utility waste
management facility.
2. Damage cases are dominated by chronic incidents (seepage, periodic
runoff) as opposed to catastrophic incidents (sudden releases.
spills). although one documented damage case was due to structural
failure of a surface impoundment.
3. Documented damage typically involves physical or chemical degradation
of ground water or surface water, including fish kills or reduction
in biota, but seldom involves direct effects on human health because
the water is not consumed for drinking water purposes. Much of the1
damage has occurred in the immediate vicinity of the waste management
site; drinking water intakes are generally far enough away such that
any contaminated water is not being directly used for human
consumption.
7.2.7 Potential Costs of Regulation
1. If additional regulations are promulgated for utility waste
management, the total costs incurred by the industry could vary
considerably depending on the extent of the additional regulations.
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For example, total annual costs to install and operate ground-water
monitoring systems would be unlikely to exceed $10 million. On the
>
other hand, total annual costs for the industry could approach $5
billion if all existing facilities were capped and closed and new
facilities were constructed with liners, leachate collection systems,
flood protection, and ground-water monitoring. (Corrective action
costs, such as excavating all existing facilities for removal of the
wastes to RCRA Subtitle C facilities, are not included in this
estimate; such costs would be extremely high.)
2. Regulation of utility coal combustion wastes under full RCRA Subtitle
C requirements could halt all recycling of coal combustion wastes if
recycling was also subject to Subtitle C requirements. Total costs
to the industry could approach $2.4 billion annually. If recycled
wastes were not subject to Subtitle C disposal requirements, it is
possible the amount of recycling could increase as the utility
industry increased waste utilization to avoid full Subtitle C
disposal costs.
3. The costs to the utility industry for full RCRA Subtitle C compliance
could decrease the amount of coal consumed in coal-fired power
plants. The costs of generating electricity with coal could increase
by several percent (depending on the extent of additional
regulations), making it economic to generate electricity with other
fuels. These impacts could be felt in two ways: 1) lower coal
consumption at existing power plants and 2) construction of fewer
coal-fired power plants in the future.
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7.3 RECOMMENDATIONS
Based on the findings from this Report to Congress, this section presents
the Agency's preliminary recommendations for those wastes included in the
scope of this study. The recommendations are subject to change based on
continuing consultations with other government agencies and new information
submitted through the public hearings and comments on this report. Pursuant
to the process outlined in RCRA 3001(b)(3)(C), EPA will announce its
regulatory determination within six months after submitting this report to
Congress.
First. EPA has concluded that coal combustion waste streams generally do
not exhibit hazardous characteristics under current RCRA regulations. EPA
does not intend to regulate under Subtitle C flv ash, bottom ash, boiler slag.
and flue gas desulfurization wastes. EPA's tentative conclusion is that
current waste management practices appear to be adequate for protecting human
health and the environment. The Agency prefers that these wastes remain under
Subtitle D authority. EPA will use section 7003 of RCRA and sections 104 and
106 of CERCLA to seek relief in any cases where wastes from coal combustion
waste disposal sites pose substantial threats or imminent hazards to human
health and the environment. Coal combustion waste problems can also be
addressed under RCRA Section 7002, which authorizes citizen lawsuits for
violations of Subtitle D requirements in 40 CFR Part 257.
Second. EPA is concerned that several other wastes from coal-fired
utilities may exhibit the hazardous characteristics of corrosivitv or EP
toxicitv and merit reeulation under Subtitle C. EPA intends to consider
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whether these waste streams should be regulated under Subtitle C of RCRA based
on further study and information obtained during the public comment period.
The waste streams of most concern appear to be those produced during equipment
maintenance and water purification, such as metal and boiler cleaning wastes.
The information available to the Agency at this time does not allow EPA to
determine the exact quantity of coal combustion wastes that may exhibit RCRA
Subtitle C characteristics. However, sufficient information does exist to
indicate that some equipment maintenance and water purification wastes do
occasionally exhibit RCRA hazardous characteristics, and therefore, may pose a
danger to human health and the environment. These wastes are similar to
wastes produced by other industries that are subject to Subtitle C regulation,
and waste management practices for coal combustion wastes are often similar to
waste management practices employed by other industries. EPA is considering
removing the exemption for all coal-fired utility wastes other than those
identified in the first recommendation. The effect would be to apply Subtitle
C regulation to any of those wastes that are hazardous by the RCRA
characteristic tests. EPA believes there are various treatment options
available for these wastes that would render them nonhazardous without major
costs or disruptions to the utilities.
Third. EPA encourages the utilization of coal combustion wastes as one
method for reducing the amount of these wastes that need to be disposed to the
extent such utilization can be done in an environmentally safe manner. From
the information available to the Agency at this time, current waste
utilization practices appear to be done in an environmentally safe manner.
The Agency supports voluntary efforts by industry to investigate additional
possibilities for utilizing coal combustion wastes.
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Through its own analysis, evaluation of public comments, and consultation
with other agencies, the Agency will reach a regulatory determination within
six months of submission of this Report to Congress. In so doing, it will
consider and evaluate a broad range of management control options consistent
with protecting human health and the environment. Moreover, if the Agency
determines that Subtitle C regulation is warranted, in accordance with Section
3004(x) EPA will take into account the "special characteristics of such waste,
the practical difficulties associated with implementation of such
requirements, and site-specific characteristics . . .," and will comply with
the requirements of Executive Orders 12291 and 12498 and the Regulatory
Flexibility Act.
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GLOSSARY
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acidity - the amount of free carbon dioxide, mineral acids and salts
(especially sulfates or iron and aluminum) which hydrolyze to give hydrogen
ions in water and is reported as milli-equivalents per liter of acid, or ppm
acidity as calcium carbonate, or pH the measure of hydrogen ions
concentration. Indicated by a pH of less than 7.
adninistrator - the Administrator of the United States Environmental
Protection Agency, or his/her designee.
alkaline cleaning solution wastes - water-side cleaning waste resulting from
the removal of high copper content scale from the utility boiler.
alkaline passivating waste - water-side cleaning waste resulting from the
removal of iron and copper compounds and silica to neutralize acidity after
acid cleaning.
alkalinity - the amount of carbonates, bicarbonates, hydroxides and
silicates or phosphates in the water and is reported as grains per gallon, pH,
or ppm of carbonate. Indicated by a pH of greater than 7.
alkaline fly ash scrubber - a flue gas desulfurization system in which flue
gas reacts with alkaline fly ash that is augmented with a lime/limestone
slurry.
anthracite - a high ASTM ranked coal with dry fixed carbon 92% or more and
less than 98%; and dry volatile, matter 8% or less and more than 2% on a
mineral-matter-free basis.
aquifer - a water-bearing bed or structure of permeable rock, sand, or gravel
capable of yielding quantities of water to wells or springs.
ash - the incombustible solid matter in fuel.
ash fusion - the temperatures at which a cone of coal or coke ash exhibits
certain melting characteristics.
attenuation - a process that slows the migration of constituents through the
ground.
baghouse - an air pollution abatement device used to trap particulates by
filtering gas streams through large fabric bags usually made of glass fibers.
base load - base load is the term applied to that portion of a station or
boiler load that is practically constant for long periods.
batch test - a laboratory leachate test in which the waste sample is placed
in, rather than washed with, leachate solution.
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bituminous coal - ASTM coal classification by rank on a mineral/matter-free
basis and with bed moisture only.
low volatile; dry fixed carbon 78% or more and less than 86%; and
dry volatile matter 22% or more and less than 14%.
medium volatile: dry fixed carbon 69% or more and less than
78%; and dry volatile matter 22% or more and less than 31%.
high volatile (A): dry fixed carbon less than 69% and dry
volatile matter more than 31% - Btu value equal to or greater
than 14,000 moist, mineral-matter-free basis.
high volatile (B): Btu value 13,000 or more and less than 14,000
moist, mineral-matter-free basis.
high volatile (C): Btu value 11,000 or more and less than 13,000
moist, mineral-matter-free basis commonly agglomerating, or 8,300
to 11,500 Btu agglomerating.
blower - the fan used to force air through a pulverizer or to force primary air
through an oil or gas burner register.
boiler - a closed vessel in which water is heated, steam is generated, steam is
superheated, or any combination thereof, under pressure or vacuum by the
application of heat.
boiler blovdown - removal of a portion of boiler water for the purpose of
reducing solid concentration or discharging sludge.
boiler cleaning waste - waste resulting from the cleaning of coal combustion
utility boilers. Boiler cleaning wastes are either water/side or gas-side
cleaning wastes.
boiler slag - melted and fused particles of ash that collect on the bottom of
the boiler.
boiler water - a term used to define a representative sample of the boiler
circulating water. The sample is obtained after the generated steam has been
separated and before the incoming feedwater or added chemical becomes mixed
with it so that its composition is affected.
bottom ash - large ash particles that settle on the bottom of the boiler.
British Thermal Unit (Btu) - the mean British Thermal Unit is 1/180 of the
heat required to raise the temperature of 1 pound of water from 32°F to 212°F
at a constant atmospheric pressure. It is about equal to the quantity of heat
required to raise 1 pound of water 1 degree F.
capacity factor - the total output over a period of time divided by the product
of the boiler capacity and the time period.
CERC1A - The Comprehensive Environmental Response, Compensation, and
Liability Act, commonly referred to as Superfund.
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cell - a section of a landfill, or the size of that section. Usually only a
few cells of a landfill are open to accept waste at a time.
chain grate stoker - a stoker which has a moving endless chain as a grate
surface, onto which coal is fed directly from a hopper.
coal pile runoff - surface runoff from a plant's coal pile.
cogeneration - the production of steam (or hot water) and electricity for use
by multiple users generated from a single source.
colunn test - a leachate extraction procedure that involves passing a solution
through the waste material to remove soluble constituents.
contingency plan - a document setting out an organized, planned, and
coordinated course of action to be followed in case of a fire or explosion or a
release of hazardous waste constituents into the environment.
cooling tower blowdovn - water withdrawn from the cooling system in order to
control the concentration of impurities in the cooling water.
cyclone furnace - specialty furnace for high intensity heat release. So named
because of its swirling gas and fuel flows.
demineralizer regeneration and rinses waste - a low volume wastewater
generated from the treatment of water to be used at the plant.
direct lime flue gas desulfurization - see lime/limestone FGD process.
direct linestone flue gas desulfurization - see lime/limestone FGD process.
disposal - the discharge, deposit, injection, dumping, spilling, leaking, or
placing of any solid waste or hazardous waste into or on any land or water such
that any constituent thereof may enter the environment or be emitted into the
air or discharged into any waters, including ground waters.
dry-botton furnace - a pulverized-fuel furnace in which ash particles are
deposited on the furnace bottom in a dry, non-adherent condition.
dry scrubber - an FGD system for which sulfur dioxide is collected by a solid
medium; the final product is totally dry, typically a fine powder.
dry sorbent injection - an FGD system in the research and development stage
for which a powdered sorbent is injected into the flue gas before it enters the
baghouse. Sulfur dioxide reacts with the reagent in the flue gas and on the
surface of the filter in the baghouse.
dual alkali fly ash scrubber - a flue gas desulfurization system similar to
the lime/limestone process, except that the primary reagent is a solution of
sodium salts and lime.
-A-
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effluent - a waste liquid in its natural state or partially or completely
treated that discharges in to the environment from a manufacturing or treatment
process.
electrostatic precipitator - an air pollution control device that imparts
an electrical charge to particles in a gas stream causing them to collect on an
electrode.
evapotranspiration - the combined process of evaporation and transpiration.
fabric filter - a cloth device that catches dust and particles from
industrial or utility emissions.
flash point - the lowest temperature at which vapors above a volatile
combustible substance ignite in air when exposed to flame.
flue gas - the gaseous products of combustion in the flue to the stack.
flue gas desulfurization (FGD) sludge - waste that is generated by the
removal of some of the sulfur compounds from the flue gas after combustion.
fly ash - suspended ash particles carried in the flue gas.
furnace - the combustion chamber of a boiler.
gas-side cleaning waste - waste produced during the removal of residues
(usually fly ash and soot) from the gas-side of the boiler (air preheater,
economizer, superheater, stack, and ancillary equipment).
ground water - water found underground in porous rock strata and soils.
ground water monitoring well - a well used to obtain ground-water samples for
water-quality analysis.
hazardous waste - a solid waste, or combination of solid wastes, which,
because of its quantity, concentration, or physical, chemical, or infectious
characteristics, may (1) cause, or significantly contribute to, an increase in
serious irreversible, or incapacitating reversible illness; or (2) pose a
substantial present or potential hazard to human health or the environment when
improperly treated, stored, transported, disposed of, or otherwise managed.
hard water - Water that contains sufficient dissolved calcium and magnesium to
cause a carbonate scale to form when the water is boiled or to prevent the
sudsing of soap in the water.
high volume waste - fly ash, bottom ash, boiler slag, and flue gas
desulfurization sludge.
hydraulic conductivity - the quantity of water that will flow through a unit
cross-sectional area of a porous material per unit of time.
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hydrochloric acid cleaning waste - wastes from the cleaning of scale caused
by water hardness, iron oxides, and copper.
land disposal - the placement of wastes in a landfill, surface impoundment,
waste pile, injection well, land treatment facility, salt dome formation, salt
bed formation, or underground mine or cave.
landfill - a disposal facility or part of a facility where hazardous waste
is placed in or on land and which is not a land treatment facility, a surface
impoundment or injection well.
leachate - the liquid resulting from water percolating through, and
dissolving materials in, waste.
leachate extraction test: - a laboratory procedure used to predict the type
and concentration of constituents that will leach out of waste material.
leachate collection, removal, and treatment systems - mitigative measures
used to prevent the leachate from building up above the liner.
lift - the depth of a cell in a landfill.
lignite - a coal of lowest ASTM ranking with calorific value limits on a
moist, mineral-matter-free basis less than 8,300 Btu.
line - calcium oxide (CaC03), a chemical used in some FGD systems.
limestone - calcium carbonate (CaOH2), a chemical used in some FGD systems.
lime/limestone FGD process - form of wet non-recovery flue gas
desulfurization system in which flue gases pass through a fly ash collection
device and into a contact chamber where they react with a solution of lime or
crushed limestone to form a slurry which is dewatered and disposed.
liner - a mitigative measure used to prevent ground-water contamination in
which synthetic, natural clay, or bentonite materials that are compatible with
the wastes are used to seal the bottom or surface impoundments and landfills.
low volume waste - wastes generated during equipment maintenance and water
purification processes. Low volume wastes include boiler cleaning solutions,
boiler blowdown, demineralizer regenerant, pyrites, cooling tower blowdown.
mechanical stoker - a device consisting of mechanically operated fuel feeding
mechanism and a grate, and is used for the propose of feeding solid fuel into a
furnace, and to distribute it over a grate, admitting air to the fuel for the
purpose of combustion, and providing a means for removal or discharge of
refuse.
net recharge - the amount of precipitation absorbed annually into the soil.
off-site - geographically noncontiguous property, or contiguous property that
is not owned by the same person. The opposite of on-site.
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em-site - the same or geographically contiguous property which may be divided
by public or private right(s)-of-ways, provided the entrance and exit between
the properties is at across-roads, intersection, and access is by crossing as
opposed to going along the right(s)-of-way. Noncontiguous properties owned by
the same person but connected by a right-of-way which the person controls and
to which the public does not have access, is also considered on-site property.
Part A - the first part of the two part application that must be submitted by a
TSD facility to receive a permit. It contains general facility information.
Fart B - the second part of the two part application that includes detailed and
highly technical information concerning the TSD in question. There is no
standard form for the Part B, instead the facility must submit information
based on the regulatory requirements.
particulates - fine liquid or solid particles such as dust, smoke, mist,
fumes, or smog, found in the air or emissions.
permeability (1) - the ability of a geologic formation to transmit ground water
or other fluids through pores and cracks.
pemeability (2) - the rate at which water will seep through waste material.
petroleum coke - solid carbaceous residue remaining in oil refining stills
after distillation process.
pH - a measure of the acidity or alkalinity of a material, liquid or solid.
pH is represented on a scales of 0 to 14 with 7 being neutral state, 0 most
acidic and 14 most alkaline.
plume - a body of ground water originating from a specific source and
influenced by such factors as the local ground-water flow pattern and character
of the aquifer.
pond liquors - waste fluid extracted from a surface impoundment or landfill.
pozzolanic - forming strong, slow-hardening cement-like substance when mixed
with lime or other hardening material.
PDVS - Primary Drinking Water Standards established by the Safe Drinking
Water Act.
pulverizer - a machine which reduces a solid fuel to a fineness suitable for
burning in suspension.
pyrites - solid mineral deposits of raw coal that are separated from the coal
before burning.
reagent - a substance that takes part in one or more chemical reactions or
biological processes and is used to detect other substances.
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recharge - the replenishment of ground water by infiltration of precipitation
through the soil.
RCRA - Resource Conservation and Recovery Act, as amended (Pub. L. 94-580).
The legislation under which EPA regulates solid and hazardous waste.
RCRA Subtitle C Characteristics - criteria used to determine if an unlisted
waste is a hazardous waste under Subtitle C of RCRA.
- corrosivity - a solid waste is considered corrosive if it is
aqueous and has a pH less than or equal to 2 or greater than or
equal to 12.5 or if it is a liquid and corrodes steel at a rate
greater than 6.35 mm per year at a test temperature of 55°C.
- EP toxicitv - a solid waste exhibits the characteristic of EP
(extraction procedure) toxicity if, after extraction by a prescribed
EPA method, it yields a metal concen- tration 100 times the
acceptable concentration limits set forth in EPA's primary drinking
water standards.
- ignitability - a solid waste exhibits the characteristic of
ignitability if it is a liquid with a flashpoint below 60°C or a
non-liquid capable or causing fires at standard temperature and
pressure.
- reactivity - a waste is considered reactive if it reacts violently,
forms potentially explosive mixtures, or generates toxic fumes when
mixed with water, or if it is normally unstable and undergoes violent
change without deteriorating.
SDVS - Secondary Drinking Water Standards established by the Safe Drinking
Water Act.
settling lagoon - surface impoundment.
shear strength - the resistance offered by a material subjected to a
compressive stress created when two contiguous parts of the material are forced
in opposite parallel directions.
slag - molten or fused solid matter.
sludge - a soft water-formed sedimentary deposit that is mud-like in its
consistency.
slurry - a mixture of insoluble mater in a fluid.
solid waste - As defined by RCRA, the term "solid waste" means any garbage,
refuse, sludge from a waste treatment plant, water supply treatment plant, or
air pollution control facility and other discarded material, including solid,
liquid, semisolid, or contained gaseous material resulting from industrial,
commercial, mining, and agricultural operations, and from community activities,
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but does not include solid or dissolved material in domestic sewage, or solid
or dissolved materials in irrigation return flows or industrial discharges
which are point sources subject to permits under the Clean Water Act, or
special nuclear or byproduct material as defined by the Atomic Energy Act of
1954.
spray drying process - a flue gas desulfurization system in which a fine spray
of alkaline solution is injected into the flue gas as it passes through a
contact chamber, where the reaction with the sulfur oxides occurs. The heat of
the flue gas evaporates the water in the solution, leaving a dry powder, which
is collected by a particulate collector.
stabilization - making resistant to physical or chemical changes by treatment.
steady state - an adjective that implies that a system is in a stable dynamic
state in which inputs balance outputs.
stoker - see mechanical stoker.
storage - the holding of waste for a temporary period, at the end of which the
hazardous waste is treated, disposed of, or stored elsewhere.
subbituninous coal - An intermediate rank coal between lignite and bituminous
with more carbon and less moisture than lignite.
sunp effluent - waste from sumps that collect floor and equipment drains.
surface inpoundment - a facility which is a natural topographic depression,
artificial excavation, or diked area formed primarily of earthen materials
(although it may be lined with artificial materials), which is designed to hold
an accumulation of liquid wastes or wastes containing free liquids.
surface water - water that rests on the surface of the rocky crust of the
earth.
traveling grate stoker - a stoker similar to a chain grate stoker except that
the grate is separate from but is supported on and driven by chains.
trace element - An element that appears in a naturally-occurring
concentration of less than 1 percent.
treatment - any method, technique, or process, including neutralization,
designed to change the physical, chemical, or biological character or
composition of a waste so as to neutralize it, recover it, make it safer to
transport, store or dispose of, or amenable for recovery, storage, or volume
reduction.
TSD facility - waste treatment, storage, or disposal facility.
utility boiler - a boiler which produces steam primarily for the production
of electricity in the utility industry.
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volatile - A volatile substance is one which tends to vaporize at a
relatively low temperature.
water-side cleaning waste - waste produced during the removal of scale and
corrosion products from the water side of the boiler (i.e., the piping systems
containing the steam or hot water).
wet botton furnace - a pulverized fuel fired furnace in which the ash
particles are deposited and retained on the floor thereof and molten ash is
removed by tapping either continuously or intermittently, (also called a slag
tap furnace)
wet scrubber - a device utilizing a liquid, designed to separate particulate
matter or gaseous contaminants from a gas stream by one or more mechanisms such
as absorption, condensation, diffusion, inertial impaction.
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