United States
Environmental
Protection Agency
Office of Solid Waste and
Emergency Response
Washington, DC 20460
EPA530-R-99-010
March 1999
Solid Waste
4>EPA Report to Congress
Wastes from the Combustion
of Fossil Fuels
Volume 2 - Methods, Findings,
and Recommendations
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Report to Congress on Wastes from the Combustion of Fossil Fuels
TABLE OF CONTENTS
Page
1.0 INTRODUCTION 1-1
1.1 BACKGROUND OF REPORT 1-1
1.2 PURPOSE AND SCOPE OF REPORT 1-1
1.3 CONTENTS AND ORGANIZATION OF REPORT 1-2
1.4 GENERAL METHODS AND INFORMATION SOURCES 1-3
1.4.1 Industry Overview, Waste Generation, and Current Management Practices .... 1-3
1.4.2 Waste Characterization 1-4
1.4.3 Overview of Risk Assessment Methodology and Results 1-4
1.4.4 Damage Analysis 1-8
1.4.5 Existing Regulatory Controls Analysis 1-9
1.4.6 Waste Management Alternatives 1-10
1.4.7 Cost and Economic Impact Analysis 1-11
1.5 DECISION-MAKING PROCESS 1-11
2.0 INDUSTRY OVERVIEW 2-1
2.1 DESCRIPTION AND COMPARISON OF INDUSTRY SECTORS 2-1
2.2 TRENDS 2-2
2.3 ENVIRONMENTAL JUSTICE 2-5
3.0 COMANAGED WASTES AT COAL-FIRED UTILITIES 3-1
3.1 WASTE GENERATION 3-1
3.1.1 Boiler Technology 3-4
3.1.2 Air Pollution Control Technologies 3-6
3.1.3 Fuel Types 3-6
3.1.4 Supporting Processes 3-9
3.2 WASTE CHARACTERISTICS 3-12
3.2.1 Large-Volume and Low-Volume Utility Coal Combustion Wastes as
Generated 3-12
3.2.2 Comanaged Utility Coal Combustion Wastes 3-15
3.2.3 Wastes from Coburning Coal and Other Fuels 3-20
3.3 CURRENT MANAGEMENT PRACTICES 3-21
3.3.1 Unit Types and Location 3-21
3.3.2 Types of Waste Managed 3-23
3.3.3 Unit Size 3-28
3.3.4 Environmental Controls 3-28
3.3.5 Beneficial Uses 3-34
3.4 POTENTIAL AND DOCUMENTED DANGERS TO HUMAN HEALTH AND THE
ENVIRONMENT 3-38
3.4.1 Potential Ground-Water Risks to Human Health 3-38
3.4.2 Potential Above-Ground Multi-Pathway Risks to Human Health and the
Environment 3-43
3.4.3 Documented Damages to Human Health and the Environment 3-47
3.4.4 Compliance History of the Fossil Fuel Electric Power Industry 3-50
3.4.5 Minefill Risks 3-51
3.5 EXISTING REGULATORY CONTROLS 3-53
3.5.1 Regulations Addressing Air Pollution 3-53
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3.5.2 Regulations Addressing Water Pollution 3-56
3.5.3 Regulations Addressing Solid and Hazardous Waste 3-58
3.6 WASTE MANAGEMENT ALTERNATIVES 3-62
3.7 COMPLIANCE COSTS AND ECONOMIC IMPACTS 3-63
3.7.1 Overview and Methodology 3-63
3.7.2 Incremental Compliance Cost 3-66
3.7.3 Compliance Cost Impact on Plants as a Function of Plant Size 3-66
3.7.4 Industry Impacts 3-68
3.8 FINDINGS AND RECOMMENDATIONS 3-69
3.8.1 Introduction 3-69
3.8.2 Findings 3-69
3.8.3 Recommendations 3-73
4.0 NON-UTILITY COAL COMBUSTION WASTES 4-1
4.1 WASTE GENERATION 4-3
4.1.1 Boiler Technology 4-4
4.1.2 Air Pollution Control Technologies 4-5
4.1.3 Fuel Usage 4-7
4.1.4 Supporting Processes 4-8
4.2 WASTE CHARACTERISTICS 4-9
4.3 CURRENT MANAGEMENT PRACTICES 4-10
4.3.1 Unit Types and Location 4-11
4.3.2 Types of Waste Managed 4-11
4.3.3 Environmental Controls 4-12
4.3.4 Beneficial Uses 4-14
4.4 POTENTIAL AND DOCUMENTED DANGERS TO HUMAN HEALTH AND THE
ENVIRONMENT 4-15
4.4.1 Potential Ground-Water Risks to Human Health 4-15
4.4.2 Potential Above-Ground Multi-Pathway Risk to Human Health and the
Environment 4-17
4.4.3 Documented Damages to Human Health and the Environment 4-17
4.5 EXISTING REGULATORY CONTROLS 4-18
4.5.1 Regulations Addressing Air Pollution 4-19
4.5.2 Regulations Addressing Water Pollution 4-21
4.5.3 Regulations Addressing Solid and Hazardous Waste 4-23
4.6 WASTE MANAGEMENT ALTERNATIVES 4-26
4.7 COMPLIANCE COSTS AND ECONOMIC IMPACTS 4-26
4.7.1 Overview and Methodology 4-27
4.7.2 Incremental Compliance Cost 4-27
4.7.3 Compliance Cost Impact on Facilities as a Function of Size 4-28
4.7.4 Industry Impacts 4-30
4.8 FINDINGS AND RECOMMENDATIONS 4-30
4.8.1 Introduction 4-30
4.8.2 Findings 4-31
4.8.3 Recommendations 4-33
5.0 FLUIDIZED BED COMBUSTION WASTES 5-1
5.1 WASTE GENERATION 5-1
5.1.1 Fluidized Bed Combustion Technology 5-3
5.1.2 Air Pollution Control Technologies 5-5
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5.1.3 Fuel and Sorbent Use 5-6
5.1.4 Supporting Processes 5-8
5.2 WASTE CHARACTERISTICS 5-9
5.2.1 Physical Characteristics 5-9
5.2.2 Chemical Characteristics 5-9
5.3 CURRENT MANAGEMENT PRACTICES 5-12
5.3.1 Unit Types and Locations 5-13
5.3.2 Types and Volumes of Wastes Managed 5-13
5.3.3 Unit Size 5-14
5.3.4 Environmental Controls 5-14
5.3.5 Beneficial Uses 5-16
5.4 POTENTIAL AND DOCUMENTED DANGERS TO HUMAN HEALTH AND THE
ENVIRONMENT 5-17
5.4.1 Potential Ground-Water Risks to Human Health 5-17
5.4.2 Potential Above-Ground Multi-Pathway Risks to Human Health and the
Environment 5-19
5.4.3 Documented Damages to Human Health and the Environment 5-20
5.5 EXISTING REGULATIONS 5-20
5.5.1 Regulations Addressing Air Pollution 5-21
5.5.2 Regulations Addressing Water Pollution 5-23
5.5.3 Regulations Addressing Solid and Hazardous Waste 5-25
5.6 WASTE MANAGEMENT ALTERNATIVES 5-28
5.7 COMPLIANCE COSTS AND ECONOMIC IMPACTS 5-28
5.7.1 Overview and Methodology 5-28
5.7.2 Incremental Compliance Cost 5-30
5.7.3 Compliance Cost Impact on Facilities as a Function of Size 5-30
5.7.4 Industry Impacts 5-32
5.8 FINDINGS AND RECOMMENDATIONS 5-32
5.8.1 Introduction 5-32
5.8.2 Findings 5-33
5.8.3 Recommendations 5-35
6.0 OIL COMBUSTION WASTES 6-1
6.1 WASTE GENERATION 6-3
6.1.1 Combustion Technology 6-5
6.1.2 Air Pollution Control Technologies 6-6
6.1.3 Fuel Usage 6-7
6.1.4 Supporting Processes 6-10
6.2 WASTE CHARACTERISTICS 6-10
6.2.1 Physical Characteristics 6-10
6.2.2 Chemical Characteristics 6-11
6.2.3 Leaching and Hazardous Waste Characteristics 6-11
6.3 CURRENT MANAGEMENT PRACTICES 6-14
6.3.1 Facilities Generating OCWs Only 6-15
6.3.2 Facilities Generating Both OCWs and Coal Combustion Wastes 6-18
6.3.3 Beneficial Uses 6-19
6.4 POTENTIAL AND DOCUMENTED DANGERS TO HUMAN HEALTH AND THE
ENVIRONMENT 6-20
6.4.1 Potential Ground-Water Risks to Human Health 6-20
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6.4.2 Potential Above-Ground Multi-Pathway Risks to Human Health and the
Environment 6-22
6.4.3 Documented Damages to Human Health and the Environment 6-22
6.5 EXISTING REGULATORY CONTROLS 6-23
6.5.1 Regulations Addressing Air Pollution 6-23
6.5.2 Regulations Addressing Water Pollution 6-26
6.5.3 Regulations Addressing Solid and Hazardous Waste 6-28
6.6 WASTE MANAGEMENT ALTERNATIVES 6-30
6.7 COMPLIANCE COSTS AND ECONOMIC IMPACTS 6-30
6.7.1 Overview and Methodology 6-31
6.7.2 Incremental Compliance Cost 6-32
6.7.3 Compliance Cost Impact on Plants as a Function of Plant Size 6-33
6.7.4 Industry Impacts 6-34
6.8 FINDINGS AND RECOMMENDATIONS 6-34
6.8.1 Introduction 6-34
6.8.2 Findings 6-35
6.8.3 Recommendations 6-37
7.0 NATURAL GAS COMBUSTION WASTES 7-1
7.1 TECHNOLOGY 7-1
7.2 FINDINGS AND RECOMMENDATIONS 7-2
7.2.1 Introduction 7-2
7.2.2 Findings 7-2
7.2.3 Recommendations 7-2
REFERENCES R-l
GLOSSARY G-l
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LIST OF FIGURES
Figure 1-1. Exposure Pathways for Human Receptors 1-5
Figure 1-2. Exposure Pathways for Ecological Receptors 1-6
Figure 2-1. Relative Size of Fossil Fuel Combustion Industry Sectors 2-2
Figure 2-2. FFC Waste Generation Compared to Other Wastes 2-3
Figure 2-3. Projected Utility Generating Capacity 2-4
Figure 2-4. Projected Fuel Consumption by Fossil Fuel Combustion Industry Sectors 2-5
Figure 3-1. Number of Coal-Fired Utility Power Plants by State 3-2
Figure 3-2. Approximate Ash Distribution by Coal Combustion Technology 3-5
Figure 3-3. Air Pollution Control Technologies Used at Coal-Fired Utilities 3-8
Figure 3-4. Trend in Utility Coal Combustion Waste (UCCW) Management Unit Type 3-23
Figure 3-5. Geographic Distribution of Utility Coal Combustion Waste (UCCW) Management
Units 3-24
Figure 3-6. Comanagement Volumes in Units Responding to EPRI Survey 3-26
Figure 3-7. Size Distribution of Management Units for UCCW 3-29
Figure 3-8. Trend in Liner Utilization in Comanagement Units 3-31
Figure 3-9. Liner Types for Comanagement Units 3-32
Figure 3-10. Comanagement Unit Cover Types 3-33
Figure 3-11. Trend in Comanagement Unit Ground-Water Monitoring 3-35
Figure 4-1. Non-Utility Fossil Fuel Combustion Sector by Fuel Type 4-1
Figure 4-2. Number of Non-Utility Coal Combustors by State 4-2
Figure 4-3. Comparison of Utility and Non-Utility Conventional Coal Combustion Technologies ... 4-5
Figure 4-4. Distribution of Coal-Fired Boilers by Capacity 4-6
Figure 4-5. Particulate Control Technologies Used at Coal-Fired Non-Utilities 4-7
Figure 4-6. Comparison of Leachate Characteristics of Utility and Non-Utility Wastes 4-10
Figure 4-7. Combined Management of CCWs with Other Wastes at Non-Utilities 4-12
Figure 4-8. Types of Liners at Non-Utility CCW Landfills 4-14
Figure 5-1. Number of Fluidized Bed Combustion Facilities 5-2
Figure 5-2. Capacities of Conventional and FBC Boilers 5-5
Figure 5-3. Capacities of Utility and Non-Utility FBC Units 5-6
Figure 5-4. Particulate Control Technologies Used at FBC Facilities 5-7
Figure 5-5. FBC Landfill Liner Types 5-16
Figure 6-1. Number of Utility Power Plants Burning Oil 6-2
Figure 6-2. Capacity of Utility Oil-Fired and Coal-Fired Boilers 6-6
Figure 6-3. Particulate Control Technologies at Oil-Fired Utilities 6-7
Figure 6-4. Oil Consumption by Utilities and Non-Utilities 6-9
Figure 7-1. Number of Gas-Fired Power Plants by State 7-1
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LIST OF TABLES
Table 3-1. Total Generation of Large-Volume Utility Coal Combustion Waste (UCCW) 3-3
Table 3-2. Low-Volume Waste Generation Rates at Coal-Fired Utilities 3-4
Table 3-3. Distribution of Utility Conventional Coal Combustion Technologies 3-6
Table 3-4. Ash Content and Fuel Usage by Coal-Fired Utilities 3-8
Table 3-5. General Composition of Selected Low-Volume Wastes 3-14
Table 3-6. Total Concentration Data for Coal Mill Rejects (ppm) 3-15
Table 3-7. Summary of Hazardous Waste Characteristics for Low-Volume Wastes 3-16
Table 3-8. Facility Average Concentrations of Trace Constituents in Comanaged Wastes 3-17
Table 3-9. Facility Average Leachate Concentrations for Comanaged Wastes 3-19
Table 3-10. Fuel Mixtures with Waste Characterization Data Available for Comparison to UCCWs 3-20
Table 3-11. Unit Type by Power Generating Capacity for Utility Coal Combustion Waste (UCCW)
Management 3-25
Table 3-12. Low-Volume and Large-Volume Waste Compared by Management Unit 3-27
Table 3-13. Low-Volume Wastes Most Commonly Comanaged 3-27
Table 3-14. Management Unit Size for UCCW 3-28
Table 3-15. Environmental Controls at UCCW Comanagement Units 3-30
Table 3-16. Beneficial Use of Utility Coal Combustion Wastes in 1997 3-36
Table 3-17. Constituents Remaining after Screening Analysis for Coal-Fired Utility Comanaged
Wastes 3-41
Table 3-18. Comparison of Deterministic and Monte Carlo Risk Model Results for Comanaged
Waste Ground-Water Pathway Scenarios 3-42
Table 3-19. Comparison of Adult and Child Risk Model Results for Comanaged Waste Ground-
Water Pathway Scenarios 3-43
Table 3-20. Comparison of Adult and Child Risk Model Results for Comanaged Waste Above-
Ground Ingestion 3-45
Table 3-21. Summary of Ecological Risk Results for Comanaged Waste Impoundments 3-47
Table 3-22. Damage Cases 3-48
Table 3-23. State Regulatory Controls on UCCW Landfills 3-59
Table 3-24. Current State Regulatory Controls on CCW Surface Impoundments 3-59
Table 3-25. State Waste Management Requirements Applicable to UCCWs in Selected States .... 3-60
Table 3-26. Management Alternatives for Coal-Fired Utility Comanaged Waste and Segregated Mill
Rejects 3-63
Table 3-27. Cost Components Included in Landfill and Impoundment Designs 3-64
Table 3-28. Design Parameters Assumed for Small, Medium, and Large Landfills and
Impoundments 3-65
Table 3-29. Plant-Level Impact of Incremental Compliance Costs 3-67
Table 3-30. Incremental Compliance Cost by Plant Size 3-68
Table 3-31. Industry Economic Impacts, Coal-Fired Utility Comanaged Wastes 3-69
Table 4-1. Fuel Usage by Coal-Fired Non-Utilities 4-7
Table 4-2. Types of Wastes Comanaged with Non-Utility CCWs 4-13
Table 4-3. Environmental Controls at Non-Utility CCW Landfills 4-13
Table 4-4. Non-Utility FFC Waste Beneficial Uses 4-15
Table 4-5. Comparison of Deterministic and Monte Carlo Risk Model Results for Non-Utility Coal
Combustion Waste Ground-Water Pathway Scenario 4-16
Table 4-6. Comparison of Adult and Child Risk Model Results for Non-Utility Coal Combustion
Waste - Ground-Water Pathway Scenario 4-16
Table 4-7. Potential Damage Cases 4-18
VIM
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Table 4-8. State Regulatory Controls on Non-Utility Coal Combustion Waste Landfills 4-24
Table 4-9. State Waste Management Requirements Applicable to Non-Utility CCWs in Selected
States 4-24
Table 4-10. Management Alternatives for Non-Utility Coal Combustion Waste 4-26
Table 4-11. Design Parameters Assumed for Small, Medium, and Large Landfills 4-28
Table 4-12. Cost Estimates for Non-Utility CCW 4-29
Table 4-13. Facility-Level Economic Impacts, Non-Utility CCW 4-30
Table 4-14. Industry-Level Economic Impacts, Non-Utility CCW 4-31
Table 5-1. Primary Fuels Used by FBC Facilities 5-7
Table 5-2. Sorbent and Bed Materials Used at FBC Facilities 5-8
Table 5-3. Facility Average Concentrations of Trace Constituents in FBC Wastes 5-10
Table 5-4. Facility Average TCLP Results for FBC Wastes 5-11
Table 5-5. FBC Waste Management Unit Sizes 5-14
Table 5-6. Environmental Controls at FBC Waste Management Units 5-15
Table 5-7. Beneficial Uses of FBC Wastes 5-17
Table 5-8. Comparison of Deterministic and Monte Carlo Risk Model Results for FBC Waste
Ground-Water Pathway Scenario 5-19
Table 5-9. Comparison of Adult and Child Risk Model Results for FBC Waste Ground-Water
Pathway Scenario 5-19
Table 5-10. Current State Regulatory Controls on FBC Landfills 5-27
Table 5-11. State Waste Management Requirements Applicable to FBC Wastes in Selected States . 5-27
Table 5-12. Management Alternatives for Non-Utility CCW 5-28
Table 5-13. Design Parameters Assumed for Small, Medium, and Large FBC Landfills 5-29
Table 5-14. Plant-Level Impact of Incremental Compliance Costs 5-31
Table 5-15. Industry-Level Economic Impacts (FBC Wastes) 5-32
Table 6-1. Locations of Utilities with Oil-Fired Baseload Units 6-2
Table 6-2. Particulate Control by Size of Utility Oil Combustion Unit 6-7
Table 6-3. Relative Removal Efficiencies of Particulate Control Technologies 6-8
Table 6-4. Relative Ash Content by Weight 6-8
Table 6-5. Facility Average Concentration of Selected Constituents in OCWs 6-12
Table 6-6. Facility Average TCLP Results for OCWs 6-13
Table 6-7. Frequency of Toxicity Characteristic Exceedences for OCWs 6-14
Table 6-8. Combinations of OCW Managed 6-15
Table 6-9. Comanagement of OCWs and Low-Volume Wastes 6-16
Table 6-10. OCW Management Surface Impoundment System Sizes 6-17
Table 6-11. Comparison of Deterministic and Monte Carlo Risk Model Results for Oil Combustion
Waste - Ground-Water Pathway Scenarios 6-21
Table 6-12. Predicted Time to Reach Risk for Oil Combustion Waste - Deterministic Scenarios . . . 6-21
Table 6-13. Comparison of Adult and Child Risk Model Results for Oil Combustion Waste -
Ground-Water Pathway Scenarios 6-22
Table 6-14. Potential Damage Cases 6-23
Table 6-15. State Waste Management Requirements Applicable to OCWs in Selected States 6-29
Table 6-16. Management Alternatives for OCW 6-31
Table 6-17. Cost Components Included in OCW Solid Settling Basin Designs 6-32
Table 6-18. Design Parameters Assumed for Small, Medium, and Large OCW SSBs 6-32
Table 6-19. Plant-Level Impact of Incremental Compliance Costs 6-33
Table 6-20. Incremental Compliance Cost by Plant Size 6-34
Table 6-21. Industry Economic Impacts, Oil Combustion Wastes 6-34
Table 7-1. Natural Gas-Fired Generating Capacity 7-2
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Report to Congress on Wastes from the Combustion of Fossil Fuels
LIST OF BOXES
Box 3-1. Conventional Coal Combustion Technologies 3-5
Box 3-2. Air Pollution Control Technologies 3-7
Box 3-3. Types of Waste Management Units 3-22
Box 3-4. Environmental Control Technologies 3-30
Box 5-1. Fluidized Bed Combustion (FBC) Technology 5-4
Box 5-2. Environmental Control Technologies 5-15
Box 5-3. Beneficial Uses of FBC Wastes 5-18
Box 6-1. Oil-Fired Steam Electric Boiler Technology 6-5
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Report to Congress on Wastes from the Combustion of Fossil Fuels
1.0 INTRODUCTION
1.1 BACKGROUND OF REPORT
Section 3001(b)(3)(A)(I) of the Resource Conservation and Recovery Act (RCRA) excludes
certain large-volume wastes generated primarily from the combustion of coal or other fossil fuels from
being regulated as hazardous waste under Subtitle C of RCRA, pending completion of a Report to
Congress required by Section 8002(n) and a determination by the U.S. Environmental Protection Agency
(EPA) Administrator either to promulgate regulations under Subtitle C or to deem such regulations as
being unwarranted.
In 1988, EPA published the required Report to Congress on wastes from the combustion of coal
by electric utility power plants (EPA, 1988). In the Report to Congress, EPA responded to one of the
requirements of Section 8002(n) of RCRA. The report, however, did not address the following:
Wastes generated by utilities burning fossil fuels other than coal
Wastes from non-utility boilers burning any type of fossil fuel.
In 1991, a suit was filed on behalf of the Bull Run Coalition (an Oregon citizens group) based on
the absence of a final ruling by EPA on the wastes studied in the 1988 Report to Congress and on other
large-volume wastes generated primarily from the combustion of coal or other fossil fuels. As a result,
the Agency entered into a Consent Decree (Civil Action 91-2345, D.D.C. June 30, 1992), which
established a schedule for EPA to complete the regulatory determinations for all fossil fuel combustion
(FFC) wastes. FFC wastes were divided into two categories: (1) fly ash, bottom ash, boiler slag, and
flue gas emission control waste from the combustion of coal by electric utilities and independent
commercial power producers, and (2) all remaining wastes subject to RCRA Sections 3001(b) and
8002(n). On August 9, 1993, EPA published a determination for the first category of wastes, concluding
that regulation under Subtitle C for these wastes was not warranted. To make an appropriate
determination for the second category or "remaining wastes," EPA decided that additional study was
necessary. Under the current court-ordered deadlines, the Agency must publish this Report to Congress
by March 31, 1999, and issue a regulatory determination by October 1, 1999.
1.2 PURPOSE AND SCOPE OF REPORT
EPA presents this Report to Congress on Wastes from the Combustion of Fossil Fuels as a
complement to the 1988 Report to Congress. This report was prepared in response to the requirements of
Section 8002(n) of RCRA, which directs EPA to provide a detailed and comprehensive study on the
sources and quantities of certain large-volume wastes generated primarily from the combustion of coal or
other fossil fuels, potential human health and environmental impacts posed by the management of these
wastes, alternatives to current practices, and costs of such alternatives. This report also prepares EPA for
its regulatory determination on the remaining wastes, scheduled to be completed by October 1, 1999.
This report addresses the remaining wastes from FFC only. As defined in the 1992 Consent
Decree, remaining wastes comprise the following:
Fly ash, bottom ash, boiler slag, and flue gas emission control wastes from the combustion
of coal by electric utility power plants, when such wastes are mixed with, codisposed,
cotreated, or otherwise comanaged with other wastes generated in conjunction with the
combustion of coal or other fossil fuels
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Any other wastes subject to Section 8002(n) of RCRA, except fly ash, bottom ash, boiler
slag, and flue gas emission wastes from coal combustion by electric utilities.
For the purposes of this report, EPA has termed the first category of remaining wastes listed
above as "comanaged utility coal combustion wastes" ("comanaged wastes" for short). EPA further
subdivided the second category of remaining wastes as follows:
Wastes from the combustion of mixtures of coal and other fuels ("coburning") by utilities
Wastes from the combustion of coal by non-utilities
Wastes from fluidized bed combustion of fossil fuels (by utilities and non-utilities)
Wastes from the combustion of oil (by utilities and non-utilities)
Wastes from the combustion of natural gas (by utilities and non-utilities).
In this study, EPA presents its current understanding of the generation, management, disposal,
and reuse of these remaining wastes from FFC. EPA addresses the following eight study factors required
by Section 8002(n) of RCRA:
1. The source and volumes of such materials generated per year
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 impacts of those alternatives on the use of coal and other natural resources
8. The current and potential utilization of such materials.
1.3 CONTENTS AND ORGANIZATION OF REPORT
The report is organized into seven chapters that address the study factors required under Section
8002(n) of RCRA. Chapter 2 provides an overview of FFC in the United States, including a brief
description of the utility and non-utility sectors and a discussion of projected trends for the industry.
Chapters 3 through 7 parallel the categories of remaining wastes listed above in Section 1.2. Chapter 3
focuses on comanaged utility coal combustion waste and also covers coburning by utilities. Chapter 4
examines non-utility coal combustion waste. Chapters 5 and 6 discuss fluidized bed combustion wastes
and oil combustion wastes, respectively. Chapter 7 focuses on natural gas combustion wastes. Chapters
3 through 6 each provide overviews of their relevant sectors; describe the wastes generated, their
characteristics, and volumes; and examine current waste management practices, potential and
documented dangers to human health and the environment, existing regulatory controls, waste
management alternatives, and costs and economic impacts. Chapter 7 presents a brief overview of
natural gas combustion technology (additional discussion of natural gas combustion wastes is not
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Report to Congress on Wastes from the Combustion of Fossil Fuels
warranted because of minimal waste generation). Finally, each of the chapters presents the Agency's
findings and tentative recommendations for the regulatory determination.
1.4 GENERAL METHODS AND INFORMATION SOURCES
1.4.1 Industry Overview, Waste Generation, and Current Management Practices
The introductory, waste generation, and current management practices sections of this report
provide a general overview and background on the FFC industry. Much of the descriptive information in
these sections was adapted from the standard industry texts and other references listed at the end of this
report. Statistical data describing the industry, combustion technologies, waste generation rates, and
waste management practices were derived from several major sources, including the following:
1. The 1994 Edison Electric Institute (EEI) Power Statistics Database (EEI, 1994), which
incorporates the 1993 Energy Information Administration (EIA) 767 Database
2. The 1990 U.S. EPA National Interim Emission Inventory (EPA, 1990)
3. The 1997 Council of Industrial Boiler Owners (CIBO) Non-Utility Survey (CIBO, 1997a)
4. The 1997 CIBO Fluidized Bed Combustion (FBC) Survey (CIBO, 1997b)
5. The 1997 Electric Power Research Institute (EPRI) Comanagement Survey (EPRI, 1997a)
6. EPRI's report summarizing results of the Comanagement Survey (EPRI, 1997b)
7. EPRI's report, Oil Combustion By-Products: Chemical Characteristics, Management
Practices, and Groundwater Effects (EPRI 1998a)
8. CIBO's report, Report to the U.S. Environmental Protection Agency on Fossil Fuel
Combustion Byproducts from Fluidized Bed Boilers (CIBO, 1997c)
9. The U.S. Department of Energy's (DOE) Coal Combustion Waste Management Study
(DOE, 1993).
Publications 6 through 9 are available in the EPA docket. Although the electronic databases (1 through
5) are not in the docket, EPA's methodology for analyzing these databases and the results of these
analyses are presented in EPA documents prepared in support of this study (i.e., the Technical
Background Document for the Report to Congress on Remaining Wastes from Fossil Fuel Combustion:
Industry Statistics and other documents). These documents can be found in the EPA docket.
The waste management sections of this report also describe current beneficial uses of FFC
wastes. To characterize the prevalence, methods, and effects of beneficial use of FFC wastes, EPA
compiled and reviewed a variety of publicly available information. The purpose of this review was to
identify (1) those uses with the potential to expand as alternatives to current management practices, and
(2) those uses with the potential for environmental impacts worthy of further consideration in the risk
assessment portion of this study. Literature reviewed by EPA included descriptions of existing and
emerging uses, feasibility studies, environmental performance studies, economic evaluations, reviews of
regulatory requirements, case studies, and usage statistics. The specific sources reviewed are identified
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Report to Congress on Wastes from the Combustion of Fossil Fuels
in the Technical Background Document titled Beneficial Use of Fossil Fuel Combustion Wastes,
available in the EPA docket.
1.4.2 Waste Characterization
To describe the physical, chemical, and leachate characteristics of FFC wastes, EPA relied upon
analytical data submitted voluntarily by the industry. In summarizing and performing statistical analyses
of these data, EPA used several standard procedures. First, values reported as below a detection limit
were assigned a value equal to one-half the detection limit for purposes of statistical analysis. Second,
because the Agency was more interested in variation between facilities than variation within individual
facilities, much of the characterization was performed using facility-averaged values. That is, multiple
measurements from a single site were averaged, and the resulting population of facility averages was
used to generate summary statistics.
Major sources used to characterize FFC wastes include the following:
1. EPRI site reports for coal-fired utilities comanaging wastes (EPRI, 1991, 1992, 1994a,
1994b, 1996a, 1996b, 1997c, 1997d, 1997e, 1997f, 1997g, 1997h, 1997i, 1997J, 1997k,
19971)
2. EPRI's Guidance for Comanagement of Mill Rejects at Coal-fired Power Plants (EPRI,
1999)
3. EPRI's PCDDs andPCDFs in Coal Combustion By-Products (EPRI, 1998b)
4. EPRI's Characterization of Byproducts from Coburning with Coal in Utility Boilers (EPRI,
1997m)
5. EPRI's oil combustion byproducts database (EPRI, 1997n)
6. Characterization data submitted in response to CIBO's FBC Survey (CIBO, 1997b)
7. Summary data for coal-fired stoker boilers provided by CIBO (CIBO, 1998).
Publications 1 through 4 are available in the EPA docket. Although the electronic databases (5 through
7) are not in the docket, EPA's methodology for analyzing these databases and the results of these
analyses are presented in EPA documents prepared in support of this study (i.e., the Technical
Background Document for the Report to Congress on Remaining Wastes from Fossil Fuel Combustion:
Waste Characterization and other documents). These documents can be found in the EPA docket.
1.4.3 Overview of Risk Assessment Methodology and Results
EPA conducted a very comprehensive multi-pathway risk assessment for this report. For both
human health and ecological risk, a wide range of exposure paths, exposure routes, and receptors was
considered. Figures 1-1 and 1-2 depict the full range of such combinations. This comprehensive
approach reflects advances in risk assessment techniques made since the previous fossil fuel combustion
Report to Congress (1988) and the previous Regulatory Determination (1993).
1-4 March 1999
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Figure 1-1. Exposure Pathways for Human Receptors
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Deposition
Surface Water/
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Dairy Farmer: Adult and Child
Fisher: Adult and Child
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Direct Placement includes on-site contact
and agricultural application scenarios.
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Figure 1-2. Exposure Pathways for Ecological Receptors
Waste Management Unit
- Landfill
-Surface Impoundment
Surface Water/
Sediment
Concentration
Bioaccumulation
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Benthic Communities
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Reptiles
1 Direct Placement includes on-site contact and
agricultural application scenarios.
! Standing water refers to impoundments only
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Report to Congress on Wastes from the Combustion of Fossil Fuels
The methodology involved, first, preliminary "screening" to determine if "worst-case"
contaminant levels (measured levels close to or within the source) present a threat to human health, and
second, if a potential threat was determined in the "screening" phase, fate and transport modeling to
determine exposure to a receptor. For ecological risk assessment, the emphasis was on modeling to
determine exposure and risk to any of the multitude of possible receptors (see Figure 1-2).
As part of the risk assessment process for this study, EPA submitted the multi-pathway risk
assessment to external peer review. The human health ground-water risk assessment and non-ground-
water risk assessment were reviewed by two primary peer reviewers, and the ecological risk assessment
was reviewed by two different primary peer reviewers. Subsequent to peer review, EPA performed a
variety of sensitivity and uncertainty analyses to derive a best estimate of risks for each of the scenarios
modeled. Peer review comments and sensitivity and uncertainty analyses can be found in the docket.
The "screening" phase of the analysis was purposely structured to avoid the likelihood of
removing from further analysis any contaminant that might pose a threat. While the 1993 screening
analysis prescribed for ground water that measured contaminant levels exceed selected health-based
numbers by a factor of 10, and that at least 10 percent of samples must show such an exceedance, this
risk assessment prescribed no such threshold. Even one health-based number exceedance for a reported
maximum concentration level required modeling. This was a very conservative approach; in essence,
modeling dictated that very few chemicals were screened out. The same approach guided the non-
ground-water human health assessment (no non-ground-water modeling was accomplished in 1993).
The primary ground-water model utilized by EPA's Office of Solid Waste (OSW), known as
EPACMTP (see Section 3.4), provided the basis for the risk results denoted. This model has been peer
reviewed as well as reviewed by EPA's Science Advisory Board. In an effort to confirm general trends
and results, and to provide further insight into the sensitivity of results to changes in significant input
variables, the electric power industry's MYGRT model was run in selected cases. While there were
differences in modeled results, general confirmation of times to peak concentration were found. The
methodology used for the non-ground-water analysis, for both human health and ecological risk, involves
a complex series of linked spreadsheets embodying a multitude of input variables; as noted, all modeling
procedures are described in detail in Sections 3.4, 4.4, 5.4, and 6.4, and in the documents found in the
docket in support of this Report to Congress.
Under RCRA, EPA's OSW is required to conduct nationwide risk assessments. Where disposal
facilities are located regionally, the analysis is of course tailored to regional conditions. For this report,
the four industry segmentscoal-fired utilities, oil-fired utilities, combustors utilizing fluidized bed
technology (FBCs), and the amorphous collection of "all other" burners of any fossil fuelpresented
different modeling problems. For the essentially nationwide sets of coal-fired utilities and the "all other"
collection, EPA used a nationwide environmental data set; for both the FBC facilities and the oil-fired
utilities, the data sets were tailored as much as possible to the regions where these units are found.
All data for the risk assessments but for basic nationwide or regional descriptive environmental
data (which were taken from existing EPA data bases) were provided voluntarily by the industry
potentially to be regulated. As noted in the documents provided for the docket, the industry-provided
data varied in their representativeness. For the oil-fired utilities and the FBC facilities, some 30 percent
of the sites were well represented. For the coal-fired utilities, fewer than 1 percent of landfills were
represented in industry-collected samples, and some 3 percent of impoundments were so represented.
However, previously existing leachate data were used to supplement the industry samples.
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Report to Congress on Wastes from the Combustion of Fossil Fuels
In essence, a great deal of judgment had to be exercised to provide any assurance that the
contaminant data provided by industry were sufficient for analysis. A very extensive sensitivity analysis
was performed to aid in this process (for details, see in particular the documents provided in the docket
supporting this Report to Congress). All modeling input variables of known modeling significance were
varied alone and in combinations of up to three at a time to test for uncertainty. Still, industry-provided
contaminant data presented a problem. EPA tested these at up to three times reported levels but did not
test for the possibility that even higher levels might exist. Uncertainty still exists as to the nationwide
representativeness of this key input variable.
For minefills, wherein ash wastes are disposed, EPA is continuing its analysis. This includes
both surface and deep mines. While surface minefills may be simulated much like landfills, deep
minefills present many complex problems. Also, the industry, depending on the particular siting issues,
has many mitigating options available. A discussion of this issue is found in Section 3.4 of this Report to
Congress.
1.4.4 Damage Analysis
In its evaluation of remaining FFC wastes, EPA evaluated damage cases in the same way as in
previous Reports to Congress for RCRA §8002 wastes (i.e., the 1993 Report to Congress on Cement Kiln
Dust and the 1990 Report to Congress on Special Wastes from Mineral Processing). Specifically, EPA
used a "test of proof' in these reports to identify documented damage cases. As discussed in later
sections of this Report to Congress, EPA identified a number of cases in which contaminants are present
in environmental media surrounding FFC sites, but the available data were insufficient to qualify the sites
as documented damage cases based on the "test of proof' described below.
Section 8002(o)(4) of RCRA requires that EPA's study of remaining FFC wastes examine
"documented cases in which danger to human health or the environment has been proved." To address
this requirement, EPA defined danger to human health or the environment in the following manner.
First, danger to human health includes both acute and chronic effects (e.g., directly observed health
effects such as elevated blood-lead levels). Second, danger to the environment includes the following
types of impacts: (1) significant impairment of natural resources (e.g., contamination of any current or
potential source of drinking water with contaminant concentrations exceeding drinking water and/or
aquatic ecological standards), (2) ecological effects resulting in degradation of the structure or function
of natural ecosystems and habitats, and (3) effects on wildlife resulting in damage to terrestrial or aquatic
fauna (e.g., reduction in species' diversity or density, or interference with reproduction).
As stipulated in RCRA §8002(o)(4), EPA is statutorily required to examine proven cases of
danger to human health or the environment. Accordingly, EPA developed "tests of proof' for the above-
mentioned Reports to Congress to determine if documentation available on a case provides evidence that
danger or damage has occurred, and uses the same methodology here. These "tests of proof' comprise
three separate tests; a case that satisfies one or more of these tests is considered "proven." The tests are
as follows:
Scientific investigation. Damages are found to exist as part of the findings of a scientific
study. Such studies should include both formal investigations supporting litigation or a state
enforcement action, and the results of technical tests (such as monitoring of wells).
Scientific studies must demonstrate that damages are significant in terms of impacts on
human health or the environment. For example, information on contamination of a drinking
water aquifer must indicate that contaminant levels exceed drinking water standards.
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Administrative ruling. Damages are found to exist through a formal administrative ruling,
such as the conclusions of a site report by a field inspector, or through existence of an
enforcement action that cited specific health or environmental damages.
Court decision. Damages are found to exist through the ruling of a court or through an out-
of-court settlement.
For many sites studied for this report, EPA employed a fourth "test." Specifically, damages must
be attributable to FFC wastes. The non-utility universe encompasses many types of facilities. EPA
found that FFC wastes could be found at many industrial sites at which damages have occurred.
However, the observed damages were generally unrelated to FFC wastes. Therefore, to be considered a
proven damage case, EPA required sufficient information to determine that FFC wastes were not only
present, but clearly implicated, in the reported damage.
1.4.5 Existing Regulatory Controls Analysis
This report characterizes regulations addressing air pollution, water pollution, and solid and
hazardous waste. Air regulations were analyzed primarily for their historical and potential future impact
on waste generation. The analysis focused on federal programs and was based on a review of the
relevant regulations and experience with the application of these programs to the FFC universe.
Water regulations were analyzed to provide background on their impact on waste management
practices and because of their potential for controlling direct release of FFC wastes to surface water.
Because state programs implement and must be at least as stringent as the federal program, the analysis
focused on federal requirements as a lowest common denominator. As for air regulations, the analysis
was based on a review of the relevant regulations and experience with the application of these programs
to the FFC universe.
The analysis of solid and hazardous waste regulations focused on state implementation of solid
waste controls on FFC wastes under Subtitle D of RCRA. State solid waste management regulations
were analyzed first on a nationwide scale, using survey data for all 50 states, and second on a more
detailed level, using case studies of selected states.
For analysis on a nationwide scale, data on state solid waste management regulations in all 50
states were compiled from four sources, all of which are available in the EPA docket:
1. The Association of State and Territorial Solid Waste Management Officials' (ASTSWMO)
Non-municipal, Subtitle D Waste Survey (ASTSWMO, 1996)
2. EPA's State Requirements for Industrial Non-Hazardous Waste Management Facilities
(EPA, 1995b)
3. A survey of state waste management controls conducted as part of CIBO's Report to the
U.S. Environmental Protection Agency on Fossil Fuel Combustion Byproducts from
Fluidized Bed Boilers (CIBO, 1997c)
4. The American Coal Ash Association's (ACAA) State-by-State Summaries of Solid Waste
Regulations (ACAA, 1996).
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Report to Congress on Wastes from the Combustion of Fossil Fuels
The ACAA summaries were used to characterize the exemption status of FFC wastes in all 50
states. The ASTSWMO and CIBO survey results were combined to characterize the types of regulatory
controls imposed on FFC waste management units. The EPA review data were used to describe daily
cover/fugitive dust controls (not surveyed by ASTSWMO) to confirm the other survey data for the states
with the largest capacity in each generating sector, and to provide additional descriptive information.
The ASTSWMO and CIBO results agreed in the majority of cases. In cases in which the two
sources disagreed, the ASTSWMO data were used because the results were more detailed and better
documented. In the analysis, the combined data were used to generate summary statistics on the nature
and stringency of state solid waste management controls in all 50 states. In the case of coal combustion
wastes, these data also were compared to historical data from the 1988 Report to Congress (EPA, 1988)
to draw conclusions about trends in state regulation.
To further characterize state implementation, EPA examined in detail programs in several (two to
five) selected states for each FFC waste sector. The specific states were selected to maximize the
percentage of generating capacity covered in each sector while making efficient use of available
resources. For example, much of the regulatory controls information was collected during visits to state
agencies to collect waste management and damage case information. The analysis of each state included
review of regulations, discussions with state officials, comparison with observed management practices,
and review of published summary information, including that which can be found in the CIBO report and
the survey publications cited above. The results of this detailed analysis are summarized here and
presented in more detail in the supporting documents contained in the EPA docket.
1.4.6 Waste Management Alternatives
Because the risk assessment identified potential risks from unlined waste management units and
in certain other situations as noted below, EPA considered alternative risk mitigation strategies. The
alternative management practices considered depended on the waste and the current practice for which
potential risk was found. The appropriate chapters of this report discuss these alternatives in detail.
They may be summarized as follows:
The ground-water risk assessment identified potential risk for comanaged waste from coal-
fired utilities managed in landfills and surface impoundments, non-utility coal combustion
waste managed in landfills, fluidized bed combustion waste managed in landfills, and oil
combustion waste managed in landfills and solids settling basins. The risk mitigation
alternatives for these cases are consistent with the design requirements for municipal solid
waste landfills under Subtitle D of RCRA. The alternatives are, in fact, similar to current
management practices at some FFC facilities (e.g., facilities with lined waste management
units). Thus, the alternatives considered would reflect a change in management practices
only for part of the FFC universe (e.g., that part using unlined disposal).
The above-ground risk assessment identified potential risk for comanaged waste from coal-
fired utilities, non-utility coal combustion waste, and fluidized bed combustion waste when
used in agricultural applications. For these cases, a variety of management alternatives was
considered, ranging from a ban to a concentration-based limit on wastes intended for
agricultural use.
The ecological risk assessment identified potential risk from immersion in surface
impoundments containing comanaged waste from coal-fired utilities. This report does not
suggest specific mitigation alternatives for this ecological risk.
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Report to Congress on Wastes from the Combustion of Fossil Fuels
EPA identified comanagement of mill rejects (specifically, their pyrite component) with
coal combustion wastes as a practice of potential concern. Because the Agency currently is
evaluating a voluntary industry proposal for mill reject management, this report does not
consider specific mitigation alternatives for mill rejects.
EPA identified minefilling of FFC wastes as a practice of potential concern. The Agency
currently is seeking more information on this practice.
1.4.7 Cost and Economic Impact Analysis
For FFC wastes disposed in landfills and impoundments/basins, EPA analyzed the costs for
economic impacts of the alternative Subtitle D management practices as follows:
The Agency estimated the incremental compliance costs associated with Subtitle D
compliance. The calculation of incremental cost made allowances for those sites already in
compliance. (EPA is aware that some combustors have undertaken a liner program in
conjunction with state programs.)
Based on the incremental compliance costs, EPA analyzed economic impacts at the firm
level.
Finally, based on the incremental compliance costs, EPA assessed economic impacts at the
industry level.
This analysis was very detailed, as discussed in Sections 3.7, 4.7, 5.7, and 6.7.
For pyrite management and for agricultural use alternatives, the Agency has not as yet conducted
a cost and impact analysis. The pyrite management proposals are the industry's, voluntarily submitted
for Agency review, while the costs associated with agricultural use alternatives are expected to be very
low in view of the very limited and competitive market for such materials. (The small amounts of ash
going to agricultural use can be accommodated easily by other disposal practices. Also, it should be kept
in mind that the utility industry alone generates more than $200 billion in annual sales; the agricultural
use market, to the extent that it exists at all as a viable market, pales in comparison.)
At the time of publication of this Report to Congress, both risk assessment and potential risk
mitigation issues relating to minefill disposal remain unresolved. With respect to surface mines, EPA is
considering, subject to stakeholder comment, requiring risk mitigating actions as discussed in Section 3.4
of this report. In many cases, these are already practiced. With respect to underground mines, EPA is
also considering requiring certain risk mitigating actions, as denoted in Section 3.4. Cost and economic
impact analysis will be conducted as these issues are clarified.
No cost or economic analysis was conducted for mitigating the potential ecological risk. This is
not to suggest that EPA believes the analysis to be without merit; such risks have also been reported in
prior studies. Stakeholder comment is invited on this issue.
1.5 DECISION-MAKING PROCESS
In the Agency's part 1 fossil fuel combustion regulatory determination (58 FR 42466, 8/9/93), the
Agency applied a three-step decision-making process. Under this procedure, the Agency first considers
the potential impacts of the wastes in question on human health and the environment. If EPA finds there
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Report to Congress on Wastes from the Combustion of Fossil Fuels
may be significant impact, the Agency next considers whether there is a need for regulation under RCRA
Subtitle C in light of existing waste management practices and existing regulatory controls imposed by
states under authorities other than Subtitle C. The Agency also considers whether Subtitle C would
effectively address problems associated with the waste without imposing significant unnecessary
controls. Finally, if the Agency concludes that additional regulation under Subtitle C is warranted, EPA
considers the potential economic impacts and affects on operations and beneficial uses of the wastes
from such regulation on the industry.
In this report, EPA has continued to consider the factors previously utilized in the three-step
decision-making process, since the Agency believes that these factors appropriately reflect the statutory
criteria in Section 8002 of RCRA that EPA must consider in issuing this report. The Agency has
modified somewhat, however, how those factors are considered in formulating its recommendations.
Rather than apply the statutory criteria in rigid, stepwise fashion, EPA has considered the totality of the
relevant factors (i.e., the potential environmental and human health impacts, the need, if any, for
additional regulation and, finally, the potential impacts of imposing regulation under subtitle C in
developing the report's recommendations). The step-wise approach to making regulatory determinations
assumes that it is possible to reach readily discernable, yes-or-no decisions regarding each step in the
decision-making process. As we gain experience in evaluating Bevill wastes, however, we have learned
that such clear-cut answers may not be possible for each individual decision-making criterion, and that it
may be necessary to balance all the relevant factors to reach the appropriate recommendation. For
example, where a particular waste poses some potential risk, but existing controls are wholly inadequate
and regulation under subtitle C would not cause severe economic dislocation, a determination to regulate
the waste may be appropriate. Conversely, where a waste poses more substantial risks but existing
controls are generally adequate and the costs of subtitle C controls would be substantial, continuing the
exemption might be the appropriate outcome. In both cases, each individual decision criterion may not
yield a definitive regulatory determination. Instead, considering the totality of the relevant factors would
be most likely to yield a rational conclusion consistent with our statutory mandate. Thus, EPA will take
this approach in this report and the regulatory determination to follow, which the Agency believes is
consistent with the broad decision-making discretion that Congress intended EPA to exercise in making
regulatory determinations for Bevill wastes.
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Report to Congress on Wastes from the Combustion of Fossil Fuels
2.0 OVERVIEW OF INDUSTRIES USING FOSSIL FUEL COMBUSTION
This chapter provides an overview of the fossil fuel combustion (FFC) in the United States,
compares in general terms the industry sectors covered by this report, and discusses future trends for the
industry. This chapter also addresses discusses generic issues, such as environmental justice, that are not
specific to the waste type categories that are the subject of the remaining chapters of this report.
2.1 DESCRIPTION AND COMPARISON OF INDUSTRY SECTORS
In 1997, the United States produced more than 72 quadrillion British thermal units (Btu) of
energy. More than 80 percent of this total was produced from fossil fuels, primarily coal, natural gas,
and oil. The United States also consumed more than 25 quadrillion Btu of imported energy, nearly all of
it in the form of oil or natural gas. After accounting for exports, total U.S. energy consumption in 1997
was 94.2 quadrillion Btu, with the majority of consumption in fossil fuels (EIA, 1997e). A substantial
portion of these fossil fuels were combusted by entities in two major categories: utilities and non-
utilities.
Utilities combust fossil fuels to produce electricity, which is then sold to end users. For purposes
of this report, the utility sector comprises both traditional electric utilities and independent power
producers that are not engaged in any other industrial activity. Utilities include private investor-owned
operations and public nonprofit organizations. Using a variety of fuels and technologies, the utility
sector accounts for the majority of electricity generated in the United States. This electricity is produced
not only by FFC, but also by nuclear power plants, hydroelectric facilities, and alternative sources (e.g.,
solar and geothermal). FFC, however, is the most significant of these sources, accounting for nearly 67
percent of the electricity produced in 1997. Coal is the most significant of the fossil fuels, accounting for
more than 50 percent of electricity produced (EIA, 1998a).
Electricity production is not the primary industrial activity of non-utility FFCs. The non-utility
sector encompasses a wide variety of industrial, commercial, and institutional facilities with varying
environmental and economic characteristics. Industrial facilities combust fossil fuels to generate power,
heat, or steam for use in manufacturing processes. Many of these industrial non-utilities are found in the
chemical manufacturing, pulp and paper, food products, and metals industries (EPA, 1990). Commercial
facilities include retail, assembly, warehouse, and office establishments that combust fossil fuels for uses
including heating, cooling, ventilating, lighting, cooking, refrigeration, and powering office equipment.
Institutional facilities include educational, health care, government, and other public buildings that
combust fossil fuels for uses similar to those at commercial facilities. Combustion of fossil fuels
accounts for more than 70 percent of the energy delivered to non-utilities. Electricity purchased from
utilities accounts for most of the rest (EIA, 1998a).
For purposes of this report, the utility and non-utility FFC industry is divided into the following
sectors:
Coal-fired utilities (including utilities that coburn coal and other fuels)
Coal-fired non-utilities
Fluidized bed combustion facilities, both utility and non-utility
Oil-fired facilities, both utility and non-utility
Natural gas-fired facilities, both utility and non-utility.
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Figure 2-1 compares the relative size of each of these sectors, both in terms of equivalent
electricity generating capacity and FFC waste generation. Coal-fired utilities dominate the industry in
terms of electrical generating capacity and quantity of waste generated. For purposes of this study, large-
volume wastes from coal-fired utilities are relevant only when they are comanaged with low-volume
combustion wastes. As discussed in Chapter 3, however, the majority of utility coal combustion wastes
are comanaged. Therefore, the share of waste generation shown in Figure 2-1 for coal-fired utilities
generally represents comanaged coal combustion waste.
Figure 2-1. Relative Size of Fossil Fuel Combustion Industry Sectors*
Equivalent Electrical Generation Capacity
Non-Utility Natural Gas 8%
Waste Generation
Utility Coal 53%
Utility Coal 87%
Utility Natural Gas 17%
Non-Utility Oil
Utility Oil 7%
Fluidized Bed 1%
Non-Utility Coal 5%
Non-utility Coal 5%
Fluidized Bed 8%
Utility & Non-Utility Oil <1%
* Percentages shown are estimates only.
Sources: EEI, 1994; EPA, 1990; CIBO, 1997c (for waste generation, see Chapters 3-7)
While coal accounts for a relatively smaller share of non-utility electricity generating capacity,
coal-fired non-utilities still generate a significant quantity of waste. Fluidized bed combustion facilities
account for only a fraction of electrical generating capacity, but generate a relatively large quantity of
waste. Oil-fired facilities, in spite of their share of generating capacity, generate relatively small amounts
of waste. Natural gas combustion generates virtually no solid waste.
For additional perspective, Figure 2-2 compares FFC waste generation to the generation of other
types of waste in the United States. This figure shows the relatively large quantity of waste generated by
FFC and emphasizes the significance of coal combustion as a contributor to the quantities generated.
2.2 TRENDS
The U.S. Department of Energy's Energy Information Administration (EIA) projects that total
U.S. energy consumption will increase from 94 to 119.9 quadrillion Btu between 1997 and 2020, an
average annual increase of 1.1 percent. This growth in consumption is expected to include increasing
demand for electricity from utilities as well as increasing consumption of fossil fuels at non-utilities
(EIA, 1998a).
2-2
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Figure 2-2. FFC Waste Generation Compared to Other Wastes
200000
I
b.
& 150000
2
3
c 100000
50000
Cement Kiln Dust
Fossil Fuel Combustion Waste
Municipal Solid Waste
Waste Type
Construction & Demolition Debris
Hazardous Waste
Other Wastes
Non-Utility Coal
Utility & Non-Utility ON
Utility Coal
Fluldlzed Bed
Sources: EPA, 1993a; EPA, 1998a; EPA, 19987b; EPA, 1997a
While this represents a decrease in the rate of growth of demand for electricity, new utility
generation capacity still will be needed to meet the additional demand and to replace retiring units
(including units representing half of current nuclear capacity). The EIA projects that 363 gigawatts of
new generation capacity, representing more than 1,000 new plants, will be needed by 2020 (EIA, 1998a).
This new capacity will drive a gradual change in the fuels used by the utility sector. Changes in
power plant technology and economics, along with recent changes in environmental regulations, will
limit the construction of new coal-fired utility plants (EIA, 1998a). In estimating the impact of recently
proposed new air emissions regulations, EPA predicted that coal-fired capacity would not increase
through 2010 (EPA, 1997b). The EIA similarly predicts only limited additions to coal-fired capacity
through 2010. Instead, utilities will invest in combined-cycle or combustion turbine technology fueled
by natural gas or both oil and gas. Between 2010 and 2020, however, the EIA projects increasing
demand for new coal-fired plants due to increasing natural gas costs and nuclear retirements. As a result
of increasing oil prices, oil-fired steam plants are expected to be replaced by turbine technologies through
2020 (EIA, 1998a). Figure 2-3 shows the EIA's projections for utility capacity reflecting these changes.
Although limited new coal-fired capacity is expected through 2020, coal consumption by utilities
is expected to increase due to increased utilization of existing generating capacity. This increase in coal
consumption is not expected to match the rate of increase in previous decades, however. Natural gas
consumption is expected to increase dramatically, consistent with the addition of new gas-fired capacity.
Oil consumption by utilities is expected to fall significantly as a result of expected increases in oil prices
(EIA, 1998a).
For non-utilities, the EIA projects modest growth in energy use. In the industrial sector,
increasing energy demand associated with increasing industrial output will be moderated by more energy
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Figure 2-3. Projected Utility Generating Capacity
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Nuclear power
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2015 2020
Source: EIA, 1998a
efficient technologies and relatively low growth in energy-intensive industries. In this sector, modest
growth in coal use for boiler fuel is expected, with more significant growth in oil and natural gas
consumption. Slow growth is expected in the commercial sector due to increased efficiency standards
and declining growth in commercial floor space compared to previous decades. The relative share of
individual fossil fuels is not expected to change dramatically for commercial uses (EIA, 1998a).
Based on the trends discussed above, Figure 2-4 adapts EIA data to the sectors discussed in this
report. Figure 2-4 shows expected trends in FFC for each sector. Note that for oil, Figure 2-4 shows
residual oil use only, since this is expected to account for nearly all oil combustion waste generation.
Forecasts for 1997 through 2020 show the following:
A moderate increase in the consumption of coal by utilities (26 percent)
A less significant increase in the consumption of coal by non-utilities (16 percent)
A decline in the consumption of residual oil by utilities and non-utilities (13 percent)
A large increase in the consumption of natural gas by utilities and non-utilities combined
(55 percent).
Separate forecasts are not available for the fluidized bed combustion sector. Most of the use of
this technology is reflected in the consumption of coal by utilities and non-utilities. Because of the fuel
flexibility, efficiency, and emissions characteristics of fluidized bed combustion units, EPA projects that
use of the technology has the potential to increase at a rate greater than that of conventional coal
combustion. The potential impacts of these changes in fuel consumption on waste generation are
discussed in appropriate chapters of this study.
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Figure 2-4. Projected Fuel Consumption by Fossil Fuel Combustion Industry Sectors
30
= 10-
1995 2000
Utility Coal
Natural Gas (utility and non-utility)
2005
2010
2015
2020
Non-Utility Coal (excludes metallurgical coal)
Oil (utility and non-utility) (residual oil only)
Source: EIA, 1998a, Appendix A
2.3 ENVIRONMENTAL JUSTICE
In addition to the eight study factors specifically identified in Section 8002(n) of RCRA, EPA is
interested in determining whether there are environmental justice issues associated with the management
of the remaining wastes from FFC. The Agency's risk modeling results indicate that subsistence farmers
and their children may face potential health risks from the management of FFC wastes. The prospect that
subsistence farmers may be of low-income or minority status suggests that there might be environmental
justice issues associated with FFC waste management. Subsistence farmers, however, are hypothetical,
highly exposed receptors modeled as part of the above-ground multimedia risk assessment. The
prevalence of subsistence farming around existing FFC sites is not known. The Agency is interested in
receiving additional information regarding the extent to which subsistence farming actually occurs near
these facilities. EPA also is interested in learning of concerns related to environmental justice (i.e., the
fair treatment of people of all cultures, incomes, and educational levels with respect to environmental
hazards) associated with the management of FFC wastes.
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3.0 COMANAGED WASTES AT COAL-FIRED UTILITIES
In its 1993 Regulatory Determination (58 FR 42466, 8/9/93), EPA retained the exclusion from
hazardous waste regulation under Subtitle C of the Resource Conservation and Recovery Act (RCRA) for
four large-volume coal combustion wastes from utilities and independent power producers when
managed alone. These wastes are fly ash, bottom ash, boiler slag, and flue gas desulfurization (FGD)
wastes. These four large-volume utility coal combustion wastes (UCCWs) are relevant for purposes of
this study when they are comanaged with low-volume combustion wastes. Comanagement occurs when a
waste management unit receives both large-volume UCCWs and other wastes that are generated ancillary
to, but as a necessary part of, the combustion and power generation processes. These other wastes are
termed "low-volume" wastes to distinguish them from the four high-volume UCCWs. Chapter 3 focuses
on these low-volume combustion wastes and the practice of comanaging these wastes with large-volume
UCCWs. This chapter also considers wastes from the combustion of mixtures of coal and other fuels
("coburning") by utilities.
SECTOR OVERVIEW
EPA described the coal-fired utility sector in great detail in the 1988 Report to Congress. Coal
remains the primary fossil fuel used by electric utilities in the United States. In 1997, coal accounted for
more than half of the electricity generated in the United States (EIA, 1997e). The Edison Electric
Institute Power Statistics Database (EEI, 1994) identifies 440 coal-fired utility power plants in the United
States operating more than 1,200 individual boilers. As discussed in Chapter 2, EPA expects little
increase in coal-fired generating capacity through the year 2010. Some growth in coal consumption by
utilities is expected due to increased utilization of existing generating capacity (EIA, 1998).
As shown in Figure 3-1, the electrical generating capacity of coal-fired utilities is concentrated in
the Northeast and Midwest. While the largest numbers of facilities are located in these regions, coal-
fired utility power plants are found in nearly every state. Within states, facility sites vary from urban to
rural. Because of the large volume of waste generated, onsite waste management is typical. As
discussed in detail in Section 3.3, comanagement is practiced at the majority of coal-fired utilities.
Therefore, the geographic distribution of power plants presented in Figure 3-1 also is generally
descriptive of the universe of comanaged waste sites that are the subject of this study.
3.1 WASTE GENERATION
Coal-fired utilities may generate as many as four large-volume UCCWs and a variety of low-
volume wastes. The generation of large-volume UCCWs depends upon boiler technology (see Section
3.1.1), air pollution control technology (see Section 3.1.2), and fuel type (see Section 3.1.3). Large-
volume UCCWs include:
Fly ash. The uncombusted material carried out of the boiler along with the flue gases.
Bottom ash. Uncombusted material that settles to the bottom of the boiler. Bottom ash
does not melt and, therefore, remains in the form of unconsolidated ash.
Boiler slag. Uncombusted material that settles to the bottom of the boiler. Slag, unlike
bottom ash, forms when operating temperatures exceed ash fusion temperature and remains
in a molten state until it is drained from the boiler bottom.
Flue gas desulfurization waste. Waste produced during the process of removing sulfur
oxide gases from the flue gases.
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Figure 3-1. Number of Coal-Fired Utility Power Plants by State
*, ^
Source: EEI, 1994
Percent of national coal-fired utility capacity:
2-4%
1(MA)
1(NJ)
1(DE)
5(MD)
1(DC)
Low-volume wastes are generated as a result of supporting processes (see Section 3.1.4) that are
ancillary to, but a necessary part of, the combustion and power generation processes. Low-volume
wastes include the following:
Coal pile runoff. Runoff and drainage produced by precipitation falling on coal storage
areas.
Coal mill rejects/pyrites. Waste produced by onsite processing of coal prior to use.
Boiler blowdown. Waste continuously or intermittently removed from boilers that
recirculate water to maintain water quality.
Cooling tower blowdown and sludge. Wastes removed periodically from recirculating
cooling tower systems to maintain water quality.
Water treatment sludge. Wastes resulting from treatment of makeup water for the steam
cycle or for non-contact cooling. Treatment processes resulting in sludge generation may
include settling, flocculation, softening, filtration, and reverse osmosis.
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Regeneration waste streams. Wastes resulting from periodic cleaning and regeneration of
ion exchange beds used to remove mineral salts from boiler makeup water.
Air heater and precipitator washwater. Wastes resulting from the periodic cleaning of
the outside (fireside) of heat exchanging surfaces (i.e., the side exposed to hot combustion
products).
Boiler chemical cleaning waste. Wastes resulting from periodic cleaning of the inside
(waterside) of boiler tubes with chemical solutions.
Floor and yard drains and sumps. Wastewaters collected by drains and sumps, including
precipitation runoff, piping and equipment leakage, and wash water.
Laboratory wastes. Wastes generated in small quantities during routine analysis of coal,
intake water, wastes, and other samples at a plant site.
Wastewater treatment sludge. Sludge generated from the treatment in settling basins or
other treatment facilities of any or all of the liquid waste streams described above.
Table 3-1 reports the quantity of each large-volume UCCW generated in 1997. The total
quantity generated has increased steadily over the last decade (ACAA, 1996b; ACAA, 1998). Projected
future increases in the consumption of coal by utilities (see Chapter 2) also are expected to result in
increases in ash generation, albeit at a slower rate than in past decades.
The relative contribution of each waste type has changed overtime. For example, since 1994,
the quantity of boiler slag has decreased, while the quantity of FGD waste has increased dramatically
(ACAA, 1996b; ACAA, 1998). These changes in relative share are likely due to changes in use of
combustion technology, fuel, and pollution control technology. Each of these factors is discussed in
greater detail below. The increase in FGD waste generation has been driven, in part, by the requirements
of Title IV of the Clean Air Act (see Section 3.5). Recent and forthcoming regulatory developments
(see Section 3.5) are expected to result in continued increases in the generation of FGD waste.
Table 3-1. Total Generation of Large-Volume Utility Coal Combustion Waste (UCCW)
UCCW Type
Fly Ash
Bottom Ash
Boiler Slag
FGD Waste
Total
Tons Generated in 1997
60,264,791
16,904,663
2,741,614
25,163,394
105,074,462
Percent
57%
16%
3%
24%
100%
Source: ACAA, 1998
Table 3-2 lists typical facility-level generation rates for those low-volume wastes for which data
are available. No comprehensive data exist on the total quantities of low-volume wastes generated in the
United States. For purposes of this study, however, the total quantities generated are less significant than
the quantities that are comanaged with large-volume UCCWs. Section 3.3 presents the available data on
the quantities of waste comanaged and the frequency with which comanagement occurs.
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Table 3-2. Low-Volume Waste Generation Rates at Coal-Fired Utilities
Low-Volume Waste
Coal Pile Runoff
Coal Mill Rejects
Boiler Slowdown
Cooling Tower Slowdown and Sludge
Water Treatment Sludge
Regeneration Waste Streams
Air Heater and Precipitator Washwater (includes other
fireside washwaters)
Boiler Chemical Cleaning Waste
Floor and Yard Drains and Sumps, Laboratory Wastes
Wastewater Treatment Sludge
Typical Generation Rate
Variable depending on rainfall
7.5 to 12 tons per year per megawatt capacity (plants burning high-
sulfur eastern coal)
0.1 to 1 percent of steam flow; 148 to 290 gallons per day per
megawatt (recirculating steam systems only)
20 to 65 percent of cooling water flow; 1 to 30 gallons per day per
megawatt (recirculating cooling systems only)
Variable depending on treatment technology and water intake rates
40 to 104 gallons per day per megawatt
3 to 18 gallons per day per megawatt capacity
125 gallons per megawatt, once every 2 to 5 years
30 to 100 gallons per day per megawatt
Variable depending on treatment technology and discharge rates
Sources: EPA, 1992, 1996; EPRI, 1997b; VDEQ, 1994
3.1.1 Boiler Technology
The quantities of ash and slag generated depend in part on the combustion technology used.
Currently, three conventional technologies for coal combustion are in use: pulverized coal (PC) boilers,
stokers, and cyclones. All three conventional technologies involve combustion of coal in a boiler to heat
water and produce steam. The steam is then used to generate electricity; in some cases, a portion of the
steam may be used to provide heat. The three conventional technologies differ in design, particularly in
the type and the size of the coal particle to be burned, fuel delivery mechanisms, and the combustion
conditions inside the boiler furnace. The 1988 Report to Congress described each of these technologies
in detail. Box 3-1 provides an overview description of these technologies and their waste generation
implications.
Figure 3-2 shows how combustion technology affects the distribution of ash and slag.
Table 3-3 shows how the capacity of utility conventional coal combustion is distributed among
boiler technologies. Because of their efficiency, PC boilers are the most common technology used by
utilities. PC technology is well suited to large capacity applications where high efficiency is desired.
The dominance of PC technology contributes to the large percentage of fly ash generated by utilities.
EPA is aware that there are other emerging technologies for combustion coal and other fossil
fuels (for example, pressurized fluidized bed combustion, discussed briefly in Chapter 5) that may have
different effects on waste generation and characteristics. Because of data availability issues, however,
this chapter focuses on technologies in current commercial application.
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Box 3-1. Conventional Coal Combustion Technologies
Pulverized Coal (PC) Boilers. PC boilers, also known as pulverizers, burn finely ground coal suspended in air.
Because of the large surface area created by pulverizing the coal and the air turbulence created in PC boilers, the
coal burns very efficiently and completely. The efficiency of combustion in a PC boiler affects the relative
quantity of waste generated. These boilers generally achieve more complete combustion of coal constituents than
do stokers. As a result, there is less unburned carbon in PC boiler ash and, in turn, a lower volume of waste
generated, all else being equal.
Because of the small fuel size and the suspended combustion process, most of the ash remaining after combustion
in a PC boiler is entrained in the furnace exit gas, becoming fly ash. The remainder of ash falls to the bottom of
the furnace as bottom ash. In most pulverizers, referred to as dry-bottom furnaces, bottom ash remains in a dry,
free-flowing ash form. Pulverizers burning coal with lower ash fusion temperatures, however, are designed as
wet-bottom or slag-tap furnaces. In these units, bottom ash flows out of the furnace in molten form and cools into
a slag. The proportion of bottom ash generated is greater in wet-bottom designs.
Stokers. Stoker technology feeds coal mechanically onto a grate within a furnace. Stoker feed and grate systems
include a variety of designs, with the three major categories being underfeed, overfeed (or mass fed), and spreader
stokers. The categories differ in the location and method of coal feeding and the design of the grate (moving,
vibrating, or stationary).
Spreader stokers, which are the most common type, generate 40 to 65 percent bottom ash. The bottom ash may be
a free-flowing ash or a fused clinker. Fly ash comprises the remaining 35 to 60 percent of spreader stoker waste.
By comparison, overfeed and underfeed stokers do not incorporate suspension burning and have lower air
velocities than spreader stokers. Therefore, they generate a lower proportion of fly ash, about 10 percent. The
bottom ash from overfeed stokers can range from free-flowing ash to fused slag, while that from underfeed
stokers is typically clinker or slag.
Cyclones. Cyclones burn crushed coal in a horizontal cylindrical barrel attached to the side of the boiler furnace.
The cyclone design was developed to burn low ash-fusion temperature coals (i.e., slagging coals) without the
need for pulverization and with slightly more flexibility in fuel feed characteristics than pulverizers. This
technology creates a cyclone-like air circulation pattern that causes smaller particles to burn in suspension, while
larger particles adhere to a molten layer of slag that forms on the barrel walls. Because they are designed
specifically to generate a layer of molten slag, most of the waste generated by cyclones is in this form. Molten
slag flows out of the cyclone barrel through a slag tap and through the furnace bottom where it typically is cooled
in a tank.
Sources: CIBO, 1997c; Stultz and Kitto, 1992; Elliott, 1989
Figure 3-2. Approximate Ash Distribution by Coal Combustion Technology
Dry-Bottom
PC Boilers
Wet-Bottom
80% Fly Ash
20% Bottom Ash
50% Fly Ash 50% Slag
Spreader 35-60% Fly Ash 40-50% Bottom Ash & Slag
Stokers
Other
10% Fly Ash 90% Bottom Ash & Slag
Cyclones
30% Fly Ash
70% Slag
Sources: CIBO, 1996c; Stultz and Kitto, 1992; and Elliot, 1989
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Table 3-3. Distribution of Utility Conventional Coal Combustion Technologies
Combustion Technology
Pulverized Coal Boilers
Stokers
Cyclones
Total
Number of Boilers
1,068
94
89
1,251
Capacity
(megawatts equivalent)
294,035
1,077
25,727
320,839
Percent of Capacity
92%
<1%
8%
100%
Source: EEI, 1994
3.1.2 Air Pollution Control Technologies
Air pollution control (APC) technologies used to meet the needs of coal-combustion facilities
may be broadly categorized as particulate controls and flue gas controls. The technologies of most
relevance in the latter category are those for control of sulfur oxide emissions. The capture of fly ash is
governed by the particulate control technology usedfly ash leaving the boiler must be removed from
the gas stream in which it is entrained or it will be released to the atmosphere. When high sulfur coal is
burned, utilities sometimes apply desulfurization technologies to remove sulfur dioxide from the flue gas
to meet Clean Air Act requirements (see Section 3.5). The 1988 Report to Congress described both
particulate control and desulfurization technologies in detail. Box 3-2 provides an overview description
of these technologies.
Figure 3-3 shows the frequency with which coal-fired utilities utilize each type of APC
technology. Overall, nearly all coal-fired utilities incorporate some type of particulate control, primarily
because this is the most economical way to meet air quality regulations (see Section 3.5). ESPs are most
common because this is the primary APC technology used at PC boilers. Mechanical collectors are most
common for stokers, which generate the larger fly ash particles for which mechanical collection is
efficient. Stokers and some other units sometimes use combination systems in which a mechanical
collector is followed by an ESP or fabric filter. The types of APC technologies used have high removal
efficiencies, as discussed in Box 3-2. The prevalence of particulate control, combined with these high
removal efficiencies, results in a high percentage of fly ash capture at coal-fired utilities.
Desulfurization technology is not as common as particulate control but still is prevalent enough
that a significant quantity of FGD waste is generated. The percentages shown in Figure 3-3 are based on
1994 data. Since that time, several large facilities have added desulfurization units in response to Title
IV of the Clean Air Act (see Section 3.5), contributing to recent increases in FGD waste generation.
Recent and forthcoming regulatory developments (see Section 3.5) are expected to result in increased use
of FGD technology and an associated increase in quantities of FGD waste. These developments also are
expected to increase the use of low sulfur coal, discussed in the next section.
3.1.3 Fuel Types
Coal burned by utilities in the United States is classified by rank: anthracite, bituminous,
subbituminous, and lignite. These ranks reflect the degree of metamorphism of the coal and typically
correspond to the geologic age of the coal deposit and to the heating value of the coal. Anthracite coal is
the oldest rank and has the highest heating value, while lignite is the youngest and has the lowest heating
value (Stultz and Kitto, 1992). Table 3-4 shows the usage of each rank by utilities in 1997, along with
typical ash content. The quantity of ash and slag generated is affected by the ash content of the fuel.
Ash content is, in part, determined by the rank of the coal.
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Box 3-2. Air Pollution Control Technologies
Participate Control Technologies
Electrostatic Precipitators (ESPs). ESPs are the most common particulate control technology used by coal-fired
utilities. An ESP generates a high intensity electrical field that causes ash particles to acquire an electrical
charge and migrate to an oppositely charged collecting surface. For typical coal-fired utilities, this process
results in a collection efficiency of greater than 99 percent.
Fabric Filters. Fabric filters, also known as baghouses, capture ash as the exit gas passes through a series of
porous filter bags. Baghouses have an efficiency of greater than 99 percent.
Mechanical Collectors. Mechanical collectors, most commonly known as cyclones or multicyclones, force a
cyclonic flow of the exit gas. This flow causes ash particle to be thrown against the walls of the collector and
drop out of the gas. Cyclones are most effective for larger particles; collection efficiency drops well below 90
percent for the smallest particles.
Scrubbers. Wet scrubbers are the least common particulate control technology. In scrubbers, water is used to
trap particulates entrained in the flue gas. Scrubbers can collect large particles at efficiencies greater than 99
percent, but efficiency may be less than 50 percent for particles smaller than 1 or 2 micrometers. Scrubbers also
demand high energy consumption for high efficiency and produce a wet effluent to be disposed.
Desulfurization Technologies
Desulfurization technologies are categorized as recovery systems and non-recovery systems. Recovery systems
are those that produce FGD wastes that are suitable for reuse, for example, in wallboard (see Section 3.6.2 for
discussion of use in wallboard). Non-recovery systems produce FGD waste that must be disposed. Non-
recovery systems are further classified as wet and dry systems. Wet systems scrub and saturate flue gas with a
slurry of water and a sorbent (usually lime or limestone) that reacts to remove sulfur from the gas in the form of
a sludge. Dry systems typically contact flue gas with a sorbent slurry in a spray dryer without saturating the gas
with water. The dry reaction product is then collected along with fly ash in a fabric filter or ESP. Wet systems
are more effective at removing sulfur dioxide and, therefore, are used by a larger proportion of generators.
However, because of their use of liquids, wet systems produce more waste than do dry systems.
Sources: Stultz and Kitto, 1992; EPA, 1998c; Elliott, 1989; DOE, 1993
In addition to coal rank, ash content depends on the specific coal producing region, mine, seam,
and production method. To reduce maintenance and waste management costs and to meet particulate
emissions standards, utilities have, over time, increased their use of coal with a lower ash content. Over
the past two decades, the average ash content of coal used by U.S. utilities has decreased consistently,
from 13.5 percent in 1975 (DOE, 1993) to 9.22 percent in 1996 (EIA, 1996f). This reduction
corresponds to the increased use of coal from Wyoming, which has a relatively low ash content (EIA,
1996f). In addition, coal characteristics can be, and often are, changed prior to combustion through
cleaning. Approximately 70 percent of coal used by electric utilities is cleaned in some way. In some
cases, these cleaning processes can reduce ash content by as much as 50 to 70 percent (Stultz and Kitto,
1992). In part because of the trend toward lower ash content, the increase in ash generation over time has
not kept pace with the general increase in coal use.
The type of coal burned also affects the distribution of the ash and slag waste streams generated
by combustion. For example, because softer lignite coals tend to have a lower ash fusion temperature,
they tend to generate boiler slag rather than bottom ash.
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Figure 3-3. Air Pollution Control Technologies Used at Coal-Fired Utilities
Particulate Control
None1% .Scrubber2%
Combination* 11%
Mechanical 4%
Fabric Filter 6%
Desulfurization
ESP 76%
None 85%
Non-Recovery Wet 13%
Non-Recovery Dry 1%
Recovery 1%
* Mechanical collector followed by fabric filter or ESP.
Source: EEI, 1994
Table 3-4. Ash Content and Fuel Usage by Coal-Fired Utilities
Coal Class
Anthracite
Bituminous
Subbituminous
Lignite
Ash Content
4 to 19%
3 to 32%
3 to 16%
4 to 19%
Total
Utility Usage in 1997 (1,000 tons)
1,013
821,823
77,524
900,360
Percent of Total Usage
<1%
91%
9%
100%
Sources: Ash content CIBO, 1997c; fuel usage EIA, 1998b
Because FGD waste is generated in removing sulfur oxide gases from the flue gas stream, the
amount of FGD waste generated depends on the sulfur content rather than the ash content of the fuel.
Furthermore, when utilities burn low sulfur coal, they often can meet regulatory requirements without the
application of desulfurization technology and, therefore, without generating FGD waste.
The sulfur content of coal varies geographically across the United States. Some Iowa coals
contain as much as 8 percent sulfur by weight, while western coal deposits (e.g., Montana and Wyoming)
average less than 1 percent sulfur (Stultz and Kitto, 1992). The sulfur content of coal also can be
reduced through cleaning to remove pyrites (iron sulfide minerals that are oxidized to produce sulfur
oxide gases during the combustion process). The average sulfur content of coal burned by electric
utilities in 1996 was just over 1 percent by weight but ranged from more than 3 percent in states relying
on Midwestern coal to less than 0.5 percent in some western states (EIA, 1996f). A number of utilities
recently have switched to low-sulfur coal in response to regulatory requirements (EIA, 1997f). Recent
and forthcoming regulatory developments (see Section 3.5) are expected to result in increased use of low-
sulfur coal in the future.
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In addition to coal, coal-fired utilities sometimes combust other fuels in combination with coal.
This practice of mixing fuels is known as "coburning." Wastes from mixtures of coal and other fuels
containing up to 50 percent other fuels are considered remaining wastes subject to this study. The types
of materials that have been coburned in such mixtures include (EPRI, 1997m; IEA, 1996):
Agricultural refuse
Auto shredder fluff
Bark and other wood
Biomass
Boiler cleaning wastes
Contaminated soils and other wastes from manufactured gas plant sites
Mill rejects
Oil combustion wastes
Paper mill sludges
Peat
Petroleum coke and petroleum coke/limestone blends
Railroad ties
Refuse derived fuel
Regeneration waste streams
Sewage sludge
Straw
Tire derived fuel
Used oil.
In addition, EPA is aware that ongoing technological advancement has developed the potential
for combusting other coal-fuel mixtures and other non-coal fossil fuels (for example, Orimulsion fuel,
discussed briefly in Chapter 6). Because of data availability issues, however, this chapter focuses on
fuels burned in current commercial application.
3.1.4 Supporting Processes
The generation of low-volume wastes primarily is associated with processes that support the
combustion process or make use of the products of combustion. These supporting and enabling
processes accompany combustion at all coal-fired utilities. The following common supporting processes
can be significant with respect to low-volume waste generation:
Coal storage
Coal processing
Steam generation
Cooling
Water treatment
Cleaning and maintenance
Wastewater treatment.
The paragraphs below describe these processes and their waste generation aspects. The large
number and wide variety of low-volume wastes generated at coal-fired utilities correspond to the variety
of these processes.
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Coal Storage
The low-volume waste, coal pile runoff, is associated with coal storage. The coal utilized at
utilities is usually stockpiled onsite to ensure an adequate supply. The amount of fuel stored is generally
proportional to the capacity of the combustion process. Particularly for large capacity utilities, the
amount required may be quite large. In fact, regulations for some public utilities require that a minimum
60- to 90-day supply be stored at the plant (Stultz and Kitto, 1992). A 90-day reserve of coal amounts to
600 to 1,800 cubic meters of storage capacity per megawatt plant capacity (EPA, 1996).
Typically, storage of such large volumes of coal is in open stockpiles, as this has proven to be the
most economically efficient storage method. These piles usually are uncovered and exposed to
precipitation, resulting in the potential intermittent generation of runoff. Coal pile runoff typically must
be collected to prevent contamination of the local environment. The characteristics of the runoff depend
upon the type and age of the coal, the pile shape, and the precipitation characteristics. Waste generation
rates vary depending on the footprint of the pile (i.e., the basal area) and the local precipitation.
Coal Processing
Coal usually is delivered to utilities in large pieces and must, at a minimum, be reduced in size
prior to combustion. The extent and nature of additional processing will depend on the desire of the user
to reduce ash and sulfur content and upon the size and feed characteristics requirements of the
combustion technology. Coal processing results in the removal of various materials, commonly termed
coal mill rejects, that may include rocks, metal fragments, hard coal, and other minerals, such as pyrites.
The quantity of these low-volume wastes will be highly variable depending on the coal source and
processing technology (EPRI, 1997b). An important component of the rejects wastestream is pyrite, a
hard iron sulfide (FeS2). As will be discussed in subsequent sections, these pyrites are associated with
acid generation concerns within waste management areas, often requiring isolation from water and
oxygen in order to minimize those concerns.
Steam Generation
The steam generation process can entail the generation of the low-volume waste called boiler
blowdown. All of the fossil fuel combustion technologies described in this report are used to heat water
and generate steam, which in turn is used to generate electricity. In the steam generation process,
products of combustion often travel from the boiler into a series of other components, such as
superheaters, economizers, and/or air heaters. There are a variety of boiler and system designs; all serve
the purpose of absorbing heat from combustion and converting water into steam (Stultz and Kitto, 1992).
After the high-temperature, high-pressure steam generated in the boiler components is used to
generate electricity or for other industrial use, a large volume of low-pressure "dead" steam remains.
This steam typically is condensed into water to be recirculated back through the boiler in a closed loop
(EPA, 1996). Dissolved solids and suspended salts in the boiler water increase with continued
circulation through the steam cycle. To prevent excessive buildup of these constituents, some water is
removed, either periodically or continuously, and replaced with purified feed water (EPRI, 1997b). This
bleed waste stream, commonly referred to as boiler blowdown, may contain contaminants built up during
the steam cycle, precipitated solids, corrosion products, and chemical additives. The volume of boiler
blowdown can range from 0.1 to 10 percent of the total steam flow, depending on boiler design.
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A few plants (less than 10 percent of the coal-fired utility population, according to the 1994
Edison Electric Institute [EEI] database) do not recirculate boiler water, instead using a once-through,
non-recirculating steam system. These systems do not generate boiler blowdown (EPA, 1996).
Cooling
Cooling processes can result in the generation of low-volume wastes, such as cooling tower
blowdown and sludge.1 In plants with a recirculating steam system, condensation of "dead" steam occurs
by transferring heat to cooling water. This cooling water does not directly contact the steam but takes on
the waste heat by flowing through a heat exchanger called a condenser. This process requires a constant
flow of large volumes of chilled cooling water, which itself may be supplied in either a once-through or
recirculating system. More than 70 percent of coal-fired utilities reporting cooling system information in
the 1994 EEI database use recirculating cooling systems. To control bacterial growth, utilities sometimes
add biocides, such as chlorine compounds, to their cooling water systems. The use of chlorine
compounds can cause toxic chlorinated organic byproducts to form in discharges from cooling water
systems. Because of concerns about these compounds, there has been an increasing trend in the use of
alternative biocides (e.g., bromine and nonoxidizing biocides, such as quaternary ammonium compounds
and bromonitrostyrene) that do not form highly toxic byproducts (EPA, 1996).
In recirculating cooling water systems, heat picked up in the condenser must be transferred to the
atmosphere by means of cooling towers, cooling ponds, or spray canals before the water is returned to the
system. Cooling towers and spray canals or ponds promote evaporative cooling. As a result, some water
must be removed and replaced with fresh water to prevent impurities from becoming concentrated in the
recirculating cooling system. The quantity removed can range from 20 to 65 percent of the cooling water
flow rate (EPA, 1996). The water removed is referred to as cooling tower blowdown. Also, over time,
solids can collect in the bottom of cooling towers. This cooling tower sludge is periodically removed and
disposed (EPRI, 1997b).
Water Treatment
Treatment of water prior to use in a fossil fuel combustion system may generate low-volume
wastes, including treatment sludges and regeneration wastes. Losses of water from within the steam
cycle typically require that operators use makeup water in the system. In addition, closed-loop, non-
contact cooling systems may require makeup water. The makeup water usually must be treated to
remove dissolved gases, suspended solids, and dissolved chemical salts that would negatively impact the
efficiency of the operation. Required treatment processes may include clarification, filtration, reverse
osmosis, and/or lime softening. These operations will usually generate water treatment wastes, such as
sludges. The characteristics of this treatment sludge will depend upon the source water characteristics
and the treatment process used.
Another type of makeup water treatment is the use of an ion exchange process to remove mineral
salts. The ion exchange beds are a resin that requires periodic rinsing with an acidic or basic solution to
regenerate the resin (i.e., remobilize and backflush the contaminants removed by the resin). These waste
1 Large-volume UCCWs transported/mixed with certain non-contact cooling waters fell within the scope of
EPA's 1993 Regulatory Determination (58 FR 42466). Because of the continuous use of these process waters, the
Agency does not consider them wastes and they are outside the scope of this study. However, discussion of the
generation and characteristics of these waters is relevant because effluent and sludge from treatment of these and
other plant wastewaters do fall within the definition of low-volume waste.
March 1999 3-11
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Report to Congress on Wastes from the Combustion of Fossil Fuels
streams are commonly referred to as regenerant solutions (EPA, 1996). Furthermore, when regeneration
of the resin is no longer possible, the spent resin is disposed and may be comanaged (EPRI, 1997b).
Cleaning and Maintenance
Cleaning processes intermittently generate low-volume wastes, including air heater and
precipitator washwater and boiler chemical cleaning waste. The heat exchanging surfaces of steam
generating systems require periodic cleaning to remove deposits and maintain efficiency. The fireside
surfaces (i.e., the side exposed to hot combustion products) of components, including boilers,
superheaters, economizers, and precipitators, collect ash, dust, and corrosion products. These surfaces
are cleaned using steam, water, or an alkaline solution. Hardened deposits may require mechanical
removal (EPRI, 1997b). The fireside surfaces of air heaters (which use flue gases to preheat combustion
input air) also collect ash and dust. These surfaces are cleaned with water or an alkaline solution, often
more frequently than other fireside surfaces (EPA, 1996). The resulting washwaters are low-volume
wastes.
The waterside surfaces of boiler tubes collect scale in the form of precipitated salts and corrosion
products. Chemical solutions must be used infrequently to remove this scale and prevent restriction of
water flow. Depending on the boiler contaminants present, cleaning solutions may include alkalis, acids,
and chelants. There is some evidence of a trend by utilities toward using less toxic cleaning solutions.
For example, one utility reported switching from hydrochloric acid to citric acid in 1995 (EPRI, 1992).
The waste resulting from chemical cleaning is commonly termed boiler chemical cleaning waste. Both
boiler chemical cleaning wastes and fireside cleaning wastes are sometimes termed metal cleaning wastes
(EPRI, 1997b).
Wastewater Treatment
At fossil fuel combustion facilities, a variety of liquid streams (including low-volume wastes, ash
handling waters, and site runoff) may require treatment prior to discharge. Required treatment processes
will vary depending on the combination of streams treated and on discharge requirements. These
operations will usually generate treatment wastes, such as sludges. The characteristics of this treatment
sludge will depend upon the source water characteristics and the treatment process used.
3.2 WASTE CHARACTERISTICS
By definition, comanaged wastes consist of one or more low-volume wastes in combination with
one or more large-volume UCCWs. Therefore, this section briefly describes the characteristics of low-
volume wastes and UCCWs as generated prior to discussing the characteristics of comanaged wastes.
The section concludes with a discussion of the available data on wastes from coburning by utilities.
3.2.1 Large-Volume and Low-Volume Utility Coal Combustion Wastes as Generated
As part of its 1988 Report to Congress (EPA, 1988) and 1993 Regulatory Determination (58 FR
42466), EPA presented substantial data characterizing large-volume UCCWs and certain low-volume
wastes. Detailed characterization is not included here. Instead, this section presents an overview of
earlier characterization efforts, along with analyses based on more recent data for selected wastes.
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Physical and Chemical Characteristics
Each of the large-volume wastes can exist as a dry solid or wet slurry, depending on collection
and management technology. Other physical characteristics vary from waste type to waste type. Fly ash
is typically generated and collected as a solid but may be transported by sluicing. This type of waste
consists primarily of particles between 5 and 100 microns (EPA, 1988). Fly ash typically has a round
shape resulting from the high temperatures used in a pulverized coal boiler (CIBO, 1997c). Bottom ash
and slag can be generated from a wet-bottom or dry-bottom pulverized-coal boiler. The bottom ash
collected from a dry-bottom system can be transported in a dry state or sluiced. Bottom ash and boiler
slag consist of larger particles than fly ash, ranging from 0.1 millimeter (100 microns) to 10 millimeters
in diameter (EPA, 1988). Bottom ash has a coarse angular structure, while boiler slag consists of angular
particles with a glassy appearance (CIBO, 1997c). FGD waste can be generated from a dry sorbent
system or a wet scrubber system. Wet systems generate waste with slightly smaller particle size (0.001 to
0.05 millimeters) than dry systems (0.002 to 0.074 millimeters). Wet systems also generate a filter cake
or similar wet solid (16 to 43 percent moisture), while waste from dry systems contains no liquids
(USDA, 1998).
Oxides of silicon, iron, aluminum, and calcium compose 95 percent of the weight of both bottom
and fly ash. These constituents also are present in significant quantities in boiler slag (EPA, 1988).
Calcium sulfate is the principal constituent of limestone-based FGD waste. Large-volume wastes also
contain trace metals. Mean concentrations of arsenic, barium, beryllium, boron, copper, and vanadium
are highest in fly ash. Bottom ash has mean contaminant levels lower than fly ash for most constituents.
Mean concentrations of antimony, lead, mercury, selenium, and zinc are highest in FGD waste.
Several studies have included testing of organic constituents in large-volume UCCWs, including
polynuclear aromatic hydrocarbons (PAHs) and dioxins. Although an exhaustive review of organics data
has not been conducted, based on available information, total and leachable organics are generally
reported to be at or below analytical detection limits (EPRI, 1987; EPA, 1982).
Because low-volume wastes are generated throughout the combustion process and its ancillary
activities, the characteristics of these wastes are extremely variable. EPA does not have comprehensive
data characterizing every type of low-volume waste that might be comanaged with large-volume coal
combustion wastes. Table 3-5 presents the principal physical and chemical characteristics of several
major types of low-volume waste.
EPA has identified coal mill rejects (and particularly their pyrite component) as a low-volume
waste of particular concern. If mismanaged, these materials have the potential to oxidize and generate
acids that could leach metals from surrounding materials to ground and surface waters. Table 3-6
presents recent characterization data for coal mill rejects.
Leaching and Hazardous Waste Characteristics
In the 1988 Report to Congress and 1993 Regulatory Determination, EPA evaluated whether
large-volume wastes exhibited any of the four characteristics of hazardous waste: corrosivity, reactivity,
ignitability, and toxicity. EPA determined that large-volume UCCWs are unlikely to be corrosive,
reactive, or ignitable. EPA also found that metals generally are not found in leachate above the toxicity
characteristic (TC) levels. Only three metalscadmium, chromium, and arsenicwere detected in any
ash or sludge samples above the TC levels and then only infrequently. Other constituents of large-
volume UCCW not on the EPA toxicity characteristic list (e.g., boron, copper, nickel, vanadium, and
March 1999 3-13
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Table 3-5. General Composition of Selected Low-Volume Wastes
Low-Volume Waste
Coal Pile Runoff
Coal Mill Rejects
Boiler Slowdown
Cooling Tower Slowdown and
Sludge
Water Treatment Sludge
Regeneration Waste Streams and
Other Water Treatment Wastes
Air Heater and Precipitator
Washwater
Boiler Chemical Cleaning Waste
Floor and Yard Drains and Runoff
Laboratory Wastes
Wastewater Treatment Sludge
Principal Physical or Chemical Characteristics
Acidic or alkaline solution (depending on coal type) with uncombusted coal particles.
May contain calcium, metals, silica, chloride, sulfate, and dissolved and suspended
solids.
Hard coal, quartz, and iron sulfides (pyrites) that cannot be ground by mills.
Alkaline solution of boiler feed water with low dissolved solids. May contain chlorides,
sulfates, calcium and magnesium salts, precipitated solids, corrosion products, and
chemical additives, such as phosphates, sodium hydroxide, sodium sulfite, hydrazine,
and chelating agents.
Similar to makeup water, with biocides, anti-corrosives, and other additives. Sludge
contains settled solids. Contaminants may include calcium and magnesium salts, metal
oxides, asbestos, biofouling inhibitors, zinc, phosphonates, sulfuric acid, chlorine, wood
preservatives, suspended solids, carbonates, nitrates, and sulfates.
Sludge from the treatment of makeup water.
Strong acid and base regeneration solutions, with concentrated makeup water
contaminants. May contain calcium, metals, sodium, chlorides, sulfates, and organics.
Aqueous solution with suspended ash from fireside cleaning. May include a source of
alkalinity for pH control. May contain metals, dissolved or suspended solids, and
polynuclear hydrocarbons from soot deposits.
Aqueous weak acid or base solution containing residual cooling system additives. May
contain ammonium sulfate, ammonium carbonate, oxidizing agents, metals, hydrochloric
or other acids, phosphates, fluorides, organic compounds, caustics, and silica.
Low solids aqueous waste with soil, ash, some uncombusted coal, oil and grease, and
phosphates and surfactants.
Miscellaneous aqueous wastes expected to be represented by above. May be acidic or
alkaline and may contain methylene chloride, phthalates, silica, phosphorous, hydrazine,
and sodium.
Sludge from management of several of the above wastes.
Sources: EPA, 1988, 1996; EPRI, 1991, 1992, 1994a, 1994b, 1996a, 1996b, 1997b, 1997c, 1997d, 1997e, 1997f, 1997g, 1997h, 19971,
1997J, 1997k, 19971, and 1999
zinc) were evaluated for potential risks to human health and the environment in 1988 and 1993. In
particular, boron was cited as a cause of vegetative damage in the 1993 Regulatory Determination.
Based on available information and engineering judgment, EPA does not expect any low-volume
waste to be ignitable, and EPA does not expect low-volume wastes other than mill rejects (potentially) to
be reactive. Table 3-7 summarizes the results of this analysis. Because of the variable physical
characteristics of these wastes, the data represent a combination of analysis methods: toxicity
characteristic leaching procedure (TCLP) or extraction procedure (EP) leachate data for solid wastes
and sludges, and measurement of dissolved analytes for aqueous wastes.
Table 3-7 shows that certain low-volume combustion wastes sometimes display the RCRA
characteristics of toxicity and/or corrosivity. Specifically, boiler chemical cleaning wastes, coal pile
runoff, and demineralizer regeneration wastes displayed hazardous characteristics in at least one analyzed
sample. Table 3-7 shows that no samples of coal mill rejects as generated exhibited the characteristics of
toxicity or corrosivity. However, EPA believes that coal mill rejects containing significant levels of
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March 1999
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Table 3-6. Total Concentration Data for Coal Mill Rejects (ppm)
Constituent
Major Constituents
Calcium
Iron
Magnesium
Manganese
Potassium
Mean
Range
maximum concentration greater than approximately 1 percent)
91,700
132,400
14,200
8,500
6,100
6,700-267,000
9,500-357,300
1,800-60,300
100-146,100
50-19,100
Trace Constituents
Arsenic
Barium
Cadmium
Chromium
Copper
Lead
Mercury
Nickel
Selenium
Silver
Zinc
104
370
3.78
64.8
23.5
18.4
0.35
48.3
11.1
12.6
23.05
1.50-447
48.0-1,070
3.5-9
9-3,380*
4.5-69
4.5-121
0.04-0.88
9-464
2.5-50
4.5-41
4.5-225
* Considered to be an outlier; not included in calculation of mean
Note: Values below the detection limit were treated as one-half the detection limit.
Source: EPRI, 1999
pyrites may be reactive, due to their reactive sulfide content. Because of the low number of samples
available (between 2 and 15 samples for each waste type), no attempt was made to extrapolate the
frequency of RCRA characteristic exceedences to the population as a whole.
3.2.2 Comanaged Utility Coal Combustion Wastes
Physical and Chemical Characteristics
From a physical standpoint, comanaged wastes are similar to large-volume UCCWs, especially in
cases where the UCCWs are managed with low-volume aqueous wastes or only small quantities of low-
volume solid wastes. For example, a solid sample of comanaged ash managed under these conditions has
a similar particle size and gross physical characteristics (e.g., oxides of aluminum, silicon, iron, and
calcium) as the ash when generated.
Differences in physical properties between comanaged wastes and high-volume wastes can be
apparent in localized areas of a waste management unit. Comanaged wastes generally show some
March 1999
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Table 3-7. Summary of Hazardous Waste Characteristics for Low-Volume Wastes
Low-Volume Waste
Coal pile runoff
Coal mill rejects
Boiler blowdown
Cooling tower blowdown and sludge
Regeneration waste streams and other water treatment
wastes
Air heater and precipitator washwater
Boiler chemical cleaning waste
Floor and yard drains and runoff
Exceedences of RCRA Characteristics
Exceedences for cadmium, chromium, lead, selenium, and silver
in one or more samples
No exceedences; potentially reactive when significant levels of
pyrites are present
No exceedences
No exceedences
Exceedences for pH, chromium, and lead in one or more samples
No exceedences
Exceedences for pH, chromium, and lead in one or more samples
No exceedences
Sources: EPA, 1988; EPRI, 1991, 1992, 1994a, 1994b, 1996a, 1996b, 1997c, 1997d, 1997e, 1997f, 1997g, 1997h, 19971, 1997J, 1997k,
and 19971
properties of each material. For example, comanagement of fly ash in a section of a pond receiving coal
pile runoff results in a mixture resembling combusted and uncombusted coal particles, while
comanagement of coal mill rejects and bottom ash results in a mixture resembling a coarse angular and
glassy material with oxidized iron (EPRI 1991, 1992, 1994a, 1994b, 1996a, 1996b, 1997c, 1997d, 1997e,
1997f, 1997g, 1997h, 1997i, 1997J, 1997k, and 19971).
The chemical characteristics of comanaged wastes are dependent on the type and quantity of
low- and large-volume wastes present. EPA has characterized comanaged waste using "as managed"
samples from 17 comanaging utility sites. The Agency has compared the comanagement practices at
these facilities to industry-wide practices as described by EPRI comanagement survey results. Based on
this comparison, EPA concluded that comanagement practices at sampled sites are similar to industry-
wide practices or reflect a greater degree of comanagement than at the sites in the general population.
Therefore, the characterization data presented here are considered representative of the range of waste
combinations that are managed by the industry.
Table 3-8 presents waste characterization data for comanaged wastes in impoundments and
landfills. Of constituents of potential concern, barium, strontium, and manganese are present in the
highest concentrations. These findings are similar to the characteristics of large-volume UCCWs as
presented in the 1988 Report to Congress. Additionally, Table 3-8 shows that the characteristics of
comanaged wastes collected from landfills and impoundments are generally within an order of magnitude
of each other. A much smaller number of landfills are represented in the data, which may contribute to
uncertainty in those results.
As discussed in the previous section, EPRI has provided a limited quantity of data on organic
constituents in comanaged wastes. The data generally indicate that these constituents are not present at
levels above detection limits. EPA evaluated the data available on the presence of dioxins and furans in
comanaged wastes. Very few samples had concentrations of individual compounds above detection
limits. The most toxic compound, 2,3,7,8-TCDD, was not detected in any of the 17 samples from 11
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March 1999
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Table 3-8. Facility Average Concentrations of Trace Constituents in Comanaged Wastes
(parts per million) (whole waste)*
Constituent
Arsenic
Barium
Beryllium
Boron
Cadmium
Chromium
Cobalt
Copper
Lead
Manganese
Nickel
Selenium
Silver
Thallium
Strontium
Vanadium
Zinc
Managed in Surface Impoundments
Mean
40
1,600
8.4
190
6
85
29
78
42
280
68
37
5.2
27
1,040
120
150
Range
6.7-150
150-8,400
0.88-16
0.03-420
0.20-24
5.7-290
4.7-42
2.2-150
5-150
55-660
1.5-160
0.025-320
0.03-14
10.6-48
1-4,800
20-350
17-860
Managed in Landfills
Mean
20
2,900
n/a
n/a
n/a
50
n/a
105
17
460
51
14
n/a
n/a
2,100
86
84
Range
6.2-38
1,800-3,800
n/a
n/a
n/a
35-78
n/a
97-120
6.5-29
200-820
33-65
0.8-32
n/a
n/a
1,100-2,650
23-160
35
*AII measurements identified as below detection limit were assigned a value equal to one-half the detection limit for use in the calculations.
All concentrations are facility-averaged; i.e., multiple measurements from a single site are averaged, and the resulting population of facility
averages used to generate the statistics in this table.
n/a = data not available
Sources: EPRI, 1991, 1992, 1994a, 1994b, 1996a, 1996b, 1997c, 1997d, 1997e, 1997f, 1997g, 1997h, 19971, 1997J, 1997k, and 19971
sites. Compositing the concentrations of all compounds of interest using their respective 2,3,7,8-TCDD
equivalency factors, the samples displayed 2,3,7,8-TCDD equivalent concentrations from below
detection to 2.1 ng/kg (approximately one order of magnitude above typical detection limits). By
comparison, a reference sample of municipal waste incinerator fly ash had a 2,3,7,8-TCDD equivalent
concentration of 1,460 ng/kg (parts per trillion) (EPRI, 1998b).
Coal contains and emits low levels of naturally occurring radiation (Radian, 1988).
Concentrations of radionuclides in coal vary with coal rank and origin. For example, uranium and
thorium concentrations in U.S. coals range from below 0.01 parts per million (ppm) to roughly 75 ppm,
based on analyses of more than 6,000 samples (EPA, 1995c). However, the geometric mean
concentrations of uranium and thorium for the same sample population are 1.2 ppm and 2.2 ppm,
respectively. These concentrations correspond to activities of roughly 0.41 pCi/g and 0.24 pCi/g,
respectively. Because they do not volatilize, these elements generally concentrate in coal ash, such that
activity levels in the ash increase relative to the radioactivity in source coal (EPA, 1989a). EPA
estimates an average increase of roughly 10x, such that average activity levels for curanium and thorium
are 4 pCi/g and 2.4 pCi/g, respectively.
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EPA has reviewed radionuclide concentrations in coal and ash in connection with other
regulatory programs (EPA 1989a, 1989b, 1995c). One of these studies examined potential exposures of
worker and nearby resident to radioactivity from ash released from coal pile through wind and runoff
erosion. Exposure from direct contact, inhalation, and ingestion were estimated to fall below natural
background radiation exposure levels even for a worker standing on the ash pile (EPA, 1989a). In
addition, EPA is currently studying coal combustion wastes as part of a larger study of naturally
occurring radioactive materials (NORM). The report from this NORM study is expected to be published
later in 1999. Due to the low expected risks associated with radionuclides in coal ash, and to prevent
duplication of effort with the NORM study, EPA eliminated radionuclides from further consideration in
this study.
Based on these characterization results, EPA concludes that metals are the class of constituents
potentially of concern in comanaged wastes. Section 3.4 discusses the potential risks of metals in these
wastes to human health and the environment.
Leaching and Hazardous Waste Characteristics
EPA evaluated whether comanaged waste exhibited any of the four characteristics of hazardous
waste: corrosivity, reactivity, ignitability, and toxicity. Based on available information and professional
judgment, EPA does not expect any comanaged wastes to be ignitable or reactive. To evaluate
corrosivity, EPA examined pH data from pore waters (i.e., interstitial water from borings of waste
managed in surface impoundments that represents leachate from the solid wastes and liquids from the
comanaged liquid low-volume wastes). None of these samples exceeded the limits for corrosivity (pH
less than or equal to 2 or greater than or equal to 12.5).
EPA evaluates the characteristic of toxicity using TCLP results. Examining available TCLP
results for comanaged wastes, the Agency found that none of the 27 samples exhibited leachate
concentrations in excess of the regulatory standard. Thus, comanaged wastes are not expected to exhibit
the RCRA characteristic of toxicity.
EPA does not conclude from these TCLP results, however, that comanaged wastes are incapable
of mobilizing constituents at levels of concern. Specifically, pore water (i.e., interstitial water from
borings) from some comanaged wastes shows concentrations above the TCLP regulatory limits. EPA
used pore waters from impoundments to represent the range of concentrations of potentially hazardous
constituents mobilized in comanaged wastes. These data were used instead of TCLP data for evaluating
impoundment leachate because (1) they represent actual leachate conditions at the sampled sites, and
(2) a larger and more representative database exists for pore water analyses than for TCLP analyses. On
the other hand, the TCLP data are believed to better represent leaching conditions at landfills than would
pore water data from impoundments.
Therefore, the leachate data in Table 3-9 use pore water data to represent leachate from
impoundments and TCLP data to represent leachate from landfills. To maximize the sample size, the
table includes TCLP results from wastes managed in both impoundments and landfills in the column
representing landfills. Evaluation of the pore water data shows that the highest concentrations of arsenic
are associated with a site with significant quantities of coal mill rejects comanaged with fly and bottom
ash. One other facility contributed high arsenic values, but it is not evident that mill rejects are
comanaged in significant quantities at that site. No other significant effects from comanagement are
evident from the data.
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Table 3-9. Facility Average Leachate Concentrations for Comanaged Wastes (mg/l)
Constituent
RCRA
Standard
Managed in Surface Impoundments"
Mean
Range
Managed in Landfills
Mean
Range
RCRA Toxicity Constituents
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
5.0
100.0
1.0
5.0
5.0
0.2
1.0
5.0
1.57
2.1
0.0341
0.175
0.0838
0.00080
0.214
0.0075-9.64
0.001-27.4
0.00099-0.250
0.00075-0.746
0.000766-0.468
0.00080-0.00080
0.00325-1.03
Not calculated c
0.0382
1.06
0.00542
0.0211
0.00365
0.00005
0.0686
0.00134
0.000875-0.236
0.114-3.63
0.00015-0.0443
0.00067-0.0589
0.00106-0.00675
0.000005-0.000118
0.00483-0.440
0.0006-0.00225
Non-RCRA Constituents
Aluminum
Antimony
Beryllium
Boron
Calcium
Cobalt
Copper
Iron
Magnesium
Manganese
Nickel
Potassium
Sodium
Sulfate
Thallium
Vanadium
Zinc
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
Not calculated c
Not calculated c
n/a
n/a
n/a
n/a
Not calculated c
0.131
n/a
n/a
n/a
0.701
n/a
n/a
n/a
0.00085-0.67
n/a
n/a
n/a
0.005-8.328
n/a
n/a
n/a
Not calculated c
0.242
1.65
0.01195-0.800
0.0121-2.31
3.69
0.00431
0.00151
3.26
549
0.00758
0.0307
1.09
48.5
0.766
0.0253
5.44
1379
479
0.00528
0.0399
0.192
0.155-11.7
0.00105-0.0125
0.00005-0.00675
0.103-9.63
44.9-1,110
0.00192-0.0167
0.00105-0.087
0.0058-10.75
2.71-184
0.0444-2.23
0.0066-0.0508
2.33-10.9
1,253-1,545
14.0-2,025
0.00185-0.0152
0.0054-0.122
0.018-1.16
a Leachate represented by pore water samples; i.e., the laboratory-extracted interstitial waters from borings of waste managed in surface
impoundments.
b TCLP results for samples of waste managed in both surface impoundments and landfills.
c The constituent was not detected in any samples, or detected in a small number of samples, and therefore meaningful statistical values
cannot be calculated.
All measurements identified as below detection limit were assigned a value equal to one-half the detection limit. All concentrations are
facility-averaged: i.e., multiple measurements from a single site are averaged, and the resulting population of facility averages used to
generate the statistics in this table.
n/a = data not available
Sources: EPRI, 1991, 1992, 1994a, 1994b, 1996a, 1996b, 1997c, 1997d, 1997e, 1997f, 1997g, 1997h, 19971, 1997J, 1997k, and 19971
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Table 3-9 includes the eight RCRA-regulated metals plus other constituents of comanaged
wastes. Of these, the eight RCRA-regulated metals plus antimony, beryllium, boron, cobalt, copper,
manganese, nickel, thallium, vanadium, and zinc are considered further in Section 3.4 for their potential
risk to human health and the environment.
3.2.3 Wastes from Coburning Coal and Other Fuels
EPRI provided a summary of characterization data for wastes from the combustion of a variety of
fuels and fuel mixtures that are sometimes coburned with coal (EPRI, 1997m). The data included both
TCLP and total concentration analyses and comprised a small number of samples of wastes derived from
each variety of different fuel mixtures. EPA compared the EPRI data to the data for UCCWs collected
for the 1993 Regulatory Determination. Because of the small number of samples available for most
individual fuel mixtures, EPA pooled the data reflecting samples of mixtures with similar components
and similar characteristics into categories for comparison. Table 3-10 shows the specific fuel mixtures
included in each category.
Table 3-10. Fuel Mixtures with Waste Characterization Data Available
for Comparison to UCCWs
Category
Wood and Biomass
Mixed Plastics
Peat Mixtures
Oil Combustion Wastes
Refuse Derived Fuel (RDF) Mixtures
Manufactured Gas Plant (MGP) Wastes
Petroleum Coke Mixtures
Tire Derived Fuel (TDF) Mixtures
Specific Mixtures Included in Category
Total Concentration Data
wood, biosludge/wood, railroad ties
mixed plastics/coal, mixed
plastics/coal/lime
peat, peat/coal, peat/RDF,
peat/coal/RDF, peat/coal/RDF/lime,
peat/coal/packaging material,
peat/coal/mixed plastics/lime
oil ash/coal
(limited number of constituents)
RDF/lime, RDF/wood chips
MGP holder material/coal, MGP
contaminated soil/coal
petroleum coke/coal, petroleum
coke/coal/MGP contaminated soil
TDF/coal
(limited number of constituents)
TCLP Data
wood
mixed plastics/coal,
mixed plastics/coal/lime
peat, peat/RDF
none
RDF/wood chips
MGP holder material/coal,
MGP-contaminated soil/coal,
spent oxide box wastes/coal
petroleum coke/coal
TDF/coal
Comparing total concentration data, EPA found that some types of fuel mixtures resulted in
wastes with potentially higher levels of metals than UCCWs. Comparing TCLP data, EPA found that
results were similar or below those for UCCW, with a few exceptions. Based on these comparisons, the
available data indicate that, while leachate levels generally appear similar, coburning certain fuel
mixtures may result in higher concentrations of some metals in the whole waste. This observation,
however, is based on a limited number of samples for the wastes for coburning. The available data are
not sufficient to draw statistically significant conclusions. The available data also do not indicate the
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Report to Congress on Wastes from the Combustion of Fossil Fuels
percentages of each fuel component associated with the various mixtures sampled. Finally, data are not
available on the chemical composition of the individual components of each mixture. Therefore, it is not
possible to determine the source of elevated metals concentrations (i.e., it is not possible to say with
certainty if the elevated concentrations result from the coal or the other fuels in the mixtures).
In addition to providing data on the inorganic constituents discussed above, EPRI's report on
coburning (EPRI, 1997m) discusses organic constituents in combustion wastes from the various fuel
mixtures. According to EPRI, most leachate and total composition analyses were below detection levels
for organics. Fuel mixtures with some detected values included petroleum coke, mixed plastics, peat
mixtures, RDF mixtures, MGP waste mixtures, and TDF mixtures. Detected organics included benzene,
cyanide, dioxins, furans, PCBs, chlorobenzene, chlorophenol, and polycyclic aromatic hydrocarbons.
Complete data on organics, however, are not presented in the report.
3.3 CURRENT MANAGEMENT PRACTICES
EPA used three sources of data to characterize UCCW comanagement practices:
The 1994 EEI Power Statistics Database (EEI, 1994)
The 1993 DOE study (DOE, 1993)
The 1997 EPRI comanagement survey (EPRI, 1997a).
The EEI and DOE data cover the entire utility population. Because the majority of utilities
comanage large-volume and low-volume wastes, data from these sources are believed to be
representative of comanaging utilities as well. The EPRI comanagement survey specifically collected
information on comanagement practices. The survey was voluntary and did not cover the entire utility
population. However, the EPRI survey sample encompasses the majority of large-volume UCCW
disposed in terms of volume (two thirds of the total generated in 1995). Based on comparison with data
from the other sources, the EPRI sample appears representative of the population of UCCW management
units in terms of the types of units included.
3.3.1 Unit Types and Location
Waste management units common at utility coal combustion facilities include landfills and
surface impoundments. Box 3-3 defines these units. UCCWs at a facility may be managed together in
the same waste management unit, or different UCCWs may be disposed in separate units. For example,
fly ash may be sluiced to one surface impoundment, while bottom ash is managed in another. Also,
different waste management units may service separate combustion units at an individual facility.
Finally, as described above, UCCWs initially may be managed in a surface impoundment (or series of
impoundments) and then dredged for placement in a landfill. As a result of these practices, a given
combustion facility may have more than one waste management unit. The 1993 DOE study found 618
management units at 450 U.S. coal-fired power plants. The EEI Power Statistics database reports 561
units serving 440 facilities. Responses to the EPRI comanagement survey cover 323 UCCW
management units serving 238 power plants.2
2 The EPRI comanagement survey was voluntary and, thus, a complete population count was not expected.
This explains the smaller number of power plants covered by the survey.
March 1999 3-21
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Box 3-3. Types of Waste Management Units
Surface impoundments are natural depressions, excavated ponds, or diked basins that typically contain a
mixture of liquids and solids. UCCWs managed in surface impoundments typically are sluiced with water from
the point of generation to the impoundment. The solid UCCWs gradually settle out of this slurry, accumulating at
the bottom of the impoundment. This process leaves a standing layer of relatively clear water at the surface,
which is commonly termed "head." The distance between the surface of the head and the top edge of the
impoundment is known as "freeboard" and indicates the remaining capacity of the impoundment. The amount of
freeboard in an impoundment may fluctuate as wastes are added, rainfall accumulates, and liquids are removed
for discharge to surface water or recirculated to sluicing operations. Solids that accumulate at the bottom of a
surface impoundment may be left in place as a method of disposal. The impoundment also may be periodically
dewatered and the solids removed for disposal in another unit, such as a landfill.
Landfills are facilities in which wastes are placed for disposal on land. Landfills usually are constructed in
sections called "cells." Wastes are placed in the active cell and compacted until the predetermined cell area is
filled. Completed cells are sometimes covered with soil or other material, and then the next cell is opened. Cells
may be constructed on top of a layer of previously completed cells, called a "lift." Landfills are usually natural
depressions or excavations that are gradually filled with waste, although construction of lifts may continue to a
level well above the natural grade. UCCWs managed in landfills may be transported dry from the point of
generation, or they may be placed after dredging from a surface impoundment. Some residual liquids may be
placed along with the dredged solids. Also, liquids may be added during the construction of the landfill for dust
control purposes.
Source: EPA, 1988
The three data sources show nearly equal numbers of surface impoundments and landfills. While
slightly more than half of the units in the DOE study and EEI database are surface impoundments, just
under half of the EPRI survey units are surface impoundments.
The population of units that comanage large-volume and low-volume wastes differ little from
those of the UCCW management unit population as a whole. Slightly more than half (54 percent) of the
206 comanagement units in the EPRI survey are surface impoundments. This proportion is similar to the
proportion of impoundments in the EPRI survey population as a whole. Furthermore, it is similar to the
proportion of impoundments found in the other sources describing the population of UCCW management
units.
Although each source shows a similar proportion of unit types, there appears to be a general
trend toward the increasing use of landfills. Figure 3-4 shows that the proportion of landfills among new
units has increased over time, based on the opening dates of the units in the EPRI comanagement survey.
Units opened since 1970 are more likely to be landfills than surface impoundments.
Three factors may contribute to the trend toward the increasing use of landfills. First, space
constraints at existing utility facilities favor the use of landfilling when new units are required. As
discussed below, because of their greater height and material compaction, landfills can provide greater
UCCW management capacity in smaller areas than surface impoundments. Furthermore, when space
constraints are extreme, utilities must locate new UCCW management units offsite. When located
offsite, landfills may be the preferred unit type because of the lower cost of transporting dry UCCW as
opposed to wet UCCW. Second, New Source Performance Standards (NSPS) under the Clean Water Act
require zero discharge of fly ash handling water (see Section 3.5.2). These requirements encourage the
use of dry ash handling systems and, therefore, landfilling for new generating units. Third, there is an
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Figure 3-4. Trend in Utility Coal Combustion Waste (UCCW) Management Unit Type
50%
40% -
«
s.
! 30%
i
; 20%
10%
0%
1960
Source: EPRI, 1997a
1965 1970 1975 1980
Year
1985
1990
1995
increasing trend toward dry ash handling in general due to a steady increase in beneficial use applications
(see Section 3.6.2), which favor dry ash collection and management.
Figure 3-5 identifies the geographic distribution of UCCW management units in the EEI Power
Statistics database. The map shows the greatest number of units in the upper Midwest and fewer units in
the far west and New England. This is consistent with geographic distribution of coal-fired utilities. Of
more significance, Figure 3-5 indicates that surface impoundments outnumber landfills in the Southeast
and some Midwestern states, while landfills outnumber surface impoundments in Texas and the
Southwest.
Based on data from the DOE study and EEI, the majority of UCCW management units are
located at the generating site. Surface impoundments are almost exclusively found at the generating site
(94 to 95 percent), while approximately half of landfills (49 to 59 percent) are onsite units. The
extensive use of onsite management units likely is due to the large volume of waste generated. Offsite
transportation costs can make onsite disposal more economical.
Power plants with the smallest generating capacity are more likely to use offsite units for UCCW
disposal than are the largest power plants. As discussed above, the majority of offsite units are landfills.
Thus, smaller generating facilities tend to favor offsite landfilling. Table 3-11 shows the trend toward
offsite disposal for smaller facilities, probably due to space constraints and lower transportation costs for
the smaller volumes of waste generated.
3.3.2 Types of Waste Managed
Individual waste management units at utilities may contain one or more of the large-volume
UCCWs. Nearly 70 percent of the waste management units responding to the EPRI comanagement
survey combine two or more large-volume UCCWs. The most common scenario is the combined
March 1999
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Figure 3-5. Geographic Distribution of Utility Coal Combustion Waste (UCCW)
Management Units
Ratio Landfills to Surface Impoundments greater or equal to 2/1
_ Ratio Landfills to Surface Impoundments less than or equal to 1/2
Note: Numbers shown are number of landfills/number of surface impoundments.
Source: EEI, 1994
management of fly ash and bottom ash in a single unit, which is practiced in nearly half of the waste
management units.
In addition to combining large-volume UCCWs, comanagement with low-volume wastes is a
common practice at utilities. Comanagement, in fact, is practiced at the majority of utilities. Of the 253
active UCCW management landfills and surface impoundments in the EPRI survey, 206 (or 81 percent)
comanaged large-volume wastes with at least one low-volume waste. These 206 comanagement units
accounted for nearly 53 million tons (84 percent) of the 63 million tons per year of large-volume UCCW
reported by all active units in the survey.
Both landfills and surface impoundments can comanage large-volume UCCWs and low-volume
wastes. Solid low-volume wastes may be disposed directly in UCCW landfills or sluiced to UCCW
surface impoundments. Liquid low-volume wastes may be sent to UCCW surface impoundments, either
directly, following mixture with other low-volume liquids, or following some form of treatment. Solids
settled from liquid low-volume wastes may be dredged and placed in UCCW landfills. Liquid low-
volume wastes also may be managed in landfills when they are used for dust suppression and ash
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March 1999
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Table 3-11. Unit Type by Power Generating Capacity for
Utility Coal Combustion Waste (UCCW) Management
Generating Capacity
0-100MW
101 -300 MW
301 -600 MW
601 -900 MW
901-1.450MW
>1,450MW
Total
Number of
Plants
65
83
93
60
65
74
440
Onsite Units
Number
48
65
79
64
73
101
430
Percent
64%
72%
72%
77%
84%
87%
77%
Offsite Units
Number
27
25
31
19
14
15
131
Percent
36%
28%
28%
23%
16%
13%
23%
Source: EEI, 1994
conditioning. In addition to these direct forms of comanagement, liquid low-volume wastes may be
comanaged indirectly, for example, by using them as sluice water for ash or as makeup water in wet FGD
systems. These latter practices represent comanagement, as the low-volume wastes end up in the same
management unit as the large-volume UCCWs.
The EPRI comanagement survey collected data on the comanagement of all of the low-volume
wastes described in Section 3.1 with UCCWs. It also collected data on commingling of UCCWs with
other, more generic waste streams, such as municipal wastes, asbestos, and contaminated soils.
Low-volume wastes can, in fact, be comanaged in very large volumes. This is particularly true
for liquid wastes, some of which can be generated at an individual facility at rates of millions of gallons
per day. Based on EPRI comanagement survey data, solid low-volume wastes are managed in similar
quantities in both surface impoundments and landfills. Much larger quantities of liquid low-volume
wastes are managed in surface impoundments than in landfills. Figure 3-6 compares the volumes of
large-volume and low-volume waste managed in the units responding to the EPRI comanagement survey.
Based on Figure 3-6, the volume of low-volume waste is nearly 20 times the volume of large-
volume waste managed. The majority of this waste is low-volume liquid waste managed in surface
impoundments. This seems plausible given the relatively large amounts of liquid used for sluicing ash to
impoundments. A large quantity of low-volume liquid wastes was reported to be disposed of by a few
landfills. This appears to be due to reporting errors in the survey responses. The estimate shown in
Figure 3-6 assumes the median percentage of low-volume liquids reported by landfills is more
representative of the population. Based on this estimate, the total quantity of low-volume waste (solid
and liquid) disposed of in landfills is expected to be less than the quantity of large-volume waste
disposed in these units.
Table 3-12 compares low-volume and large-volume waste quantities on an individual
management unit basis. This table shows that the quantity of comanaged low-volume waste can range
from an insignificant amount compared with large-volume UCCW, to a volume many times larger. In
surface impoundments, the quantity of low-volume waste typically is many times that of large-volume
waste, primarily due to the large quantity of liquids managed in these units. In landfills, the median
value shows that the quantity of low-volume waste is a fraction of that of large-volume waste in many
units.
March 1999
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Figure 3-6. Comanagement Volumes in Units Responding to EPRI Survey*
800
700
600
I
S.
_o
o
o
I 300
£200
100
I I
Surface Impoundments Landfills
Waste Management Unit
Total
Low-Volume Solid
Low-Volume Liquid
Large-Volume
* 94 surface impoundments and 57 landfills provided waste quantity data. Assumes 1.3% solids content of liquid wastes.
Note: A large quantity of low-volume liquids was reported by a few landfills. This is believed to be the result of survey reporting errors. The
estimate shown assumes the median value for the period of landfilled waste that is low-volume liquid.
Source: EPRI, 1997a
Individual surface impoundments and landfills may comanage as many as 15 different low-
volume waste streams. Surface impoundments typically comanage more different waste types (a median
of eight) than do landfills (a median of four). Also, the wastes most frequently comanaged differ for
each type of management unit. Table 3-13 shows the frequency with which comanagement units receive
each type of low-volume waste.
As noted above, facilities may indirectly comanage liquid low-volume wastes by using them
as sluice water for high-volume UCCWs or as makeup water in wet FGD systems. The EPRI
comanagement survey requested information on these practices. Of the 139 respondents that provided
information about UCCW sluice water, 85 do not use low-volume wastes (i.e., they use only lake or river
water or use recirculated pond water, which may not contain low-volume waste). Fifty-four respondents
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March 1999
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Table 3-12. Low-Volume and Large-Volume Waste Compared by Management Unit
Number of Units
Minimum
Maximum
Median
Mean
Low-Volume Waste/Large-Volume UCCW
Landfills
57
0%
a
3.9%
4,21 4%b
Surface Impoundments
94
0%
248,650%
3,361%
12,646%
a The maximum value reported for a landfill is believed to be the result of a survey reporting error and is not presented here.
b The mean value calculated for a landfill incorporates a number of values believed to be reporting errors and, thus, is not considered
representative of most landfills.
Note: Percentages shown are a comparison of low-volume waste with large-volume waste on an individual management unit basis.
Source: EPRI, 1997a
Table 3-13. Low-Volume Wastes Most Commonly Comanaged*
Waste
Coal Pile Runoff
Coal Mill Rejects/Pyrites
Boiler Slowdown
Cooling Tower Slowdown
Water Treatment Wastes
Regeneration Waste Streams
Air Heater or Precipitator Washes
Boiler Chemical Cleaning Wastes
Waste from Floor Drains and Sumps
Other Site Runoff
Miscellaneous Plant Wastes
Percent of Landfills
(95 units)
39%
64%
31%
23%
39%
34%
38%
32%
39%
33%
25%
Percent of Surface Impoundments
(111 units)
67%
70%
67%
26%
58%
74%
68%
54%
79%
60%
39%
* Frequencies shown include direct comanagement and indirect comanagement through use as sluice water or FGD makeup water.
Source: EPRI, 1997a
(or 39 percent) use at least one low-volume waste as sluice water. These respondents may use as many
as 10 different low-volume wastes as sluice water, although the median is one low-volume waste. Of the
47 respondents that provided information about FGD makeup water, 14 do not use low-volume wastes
(i.e., they use only lake or river water or use recirculated pond water). Thirty-three respondents (or
70 percent) use at least one low-volume waste as FGD makeup. These respondents may use as many as
10 different low-volume wastes as FGD makeup, although the median is two low-volume wastes.
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3.3.3 Unit Size
Table 3-14 presents summary statistics on the capacities and dimensions of UCCW management
units included in the EPRI survey. As shown in the table, landfills as a group have larger capacities than
surface impoundments. This is because surface impoundment capacities are limited by their excavated
depth or the height of their berms, whereas landfill lifts can continue to be constructed above grade,
providing greater ultimate disposal capacity. The units in the EPRI comanagement survey have greater
average capacities than units in the EEI database. This result may be because the EEI database includes
more small generators than the EPRI comanagement survey.
Table 3-14. Management Unit Size for UCCW
Minimum
Maximum
Median
Mean
Landfills (110 units)
Capacity
(cubic yards)
2,700
82,000,000
3,850,000
7,434,852
Area
(acres)
2.6
900
66
116
Height
(feet)
0.36
150a
31
43
Surface Impoundments (107 units)
Capacity
(cubic yards)
115,000
63,000,000
3,400,000
6,507,405
Area
(acres)
5
1,500
90
149
Depth
(feet)
1
200b
20
36
a One landfill yielded an estimated height of 356 feet and was omitted from this table. The data did not influence the calculated median
value.
b One surface impoundment yielded 697 feet and was omitted from this table. The data did not influence the calculated median value.
Source: EPRI, 1997a. Height and depth data are derived from the reported capacity and area for each unit.
As shown in Table 3-14, the range of sizes for each type of UCCW management unit is great.
Comparing the mean and median values for each unit type suggests that units are not distributed evenly
throughout this range. Figure 3-7 graphically presents the size distribution of UCCW landfills and
impoundments. Approximately 60 percent of units are less than 4 million cubic yards in capacity.
Another 20 percent fall between 4 million and 8 million cubic yards. The remaining units are distributed
over a broad range.
3.3.4 Environmental Controls
The EPRI comanagement survey collected information on the use of environmental control
technologies, including liners, covers, leachate collection systems, and ground-water monitoring systems,
at comanagement units. Box 3-4 provides a general description of each of these technologies. The EPRI
comanagement survey also collected information on the types of regulatory permits and ground-water
standards applied to comanagement units. While not control technologies in themselves, permits and
standards are techniques used to ensure environmental control of waste management practices. For
example, permits can dictate the use of specific operating practices and control technologies. Table 3-15
summarizes the use of environmental controls in UCCW comanagement units. The paragraphs below
provide additional details and discussion of each type of environmental control.
An examination of the geographic distribution of new, lined surface impoundments suggests
that liner requirements in several states have changed. The change from unlined to lined surface
impoundments appears concentrated in the states of Georgia, Illinois, Indiana, Kentucky, Missouri, and
Texas. These states account for 44 percent of the active comanagement surface impoundments in the
EPRI survey. In these six states, only six (or 15 percent) of the impoundments opened before 1982 are
lined. On the other hand, all of the impoundments opened since 1982 are lined. Data are available on
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Figure 3-7. Size Distribution of Management Units for UCCW
50^
40
£
^30-
"o
18 million
<2 million 4-6 million 8-10 million 12-1 4 million 16-1 8 million
Cubic Yards
Surface Impoundment Capacity
i 1 1 1 i 1
2-4 million 6-8 million 10-12 million 14-16 million >18 million
<2 million 4-6 million 8-10 million 12-14 million 16-18 million
Cubic Yards
Source: EPRI, 1997a
impoundment requirements in five of these six states (Georgia, Illinois, Indiana, Kentucky, and Texas)
(CIBO, 1997c and EPA's review of requirement in Indiana). According to these data, these five states
currently determine liner requirements for surface impoundments on a case-by-case basis. Therefore, if
the trend in liner usage is driven by regulatory agencies in these states, it appears to result from a change
in permitting policies rather than written regulations.
Liners
Table 3-15 presents liner data from the EPRI comanagement survey. The DOE study and the EEI
Power Statistics database are in close agreement on the percentages of surface impoundments and
landfills with a liner present. All three sources show that landfills are more frequently lined than surface
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Box 3-4. Environmental Control Technologies
Liners. A liner is a barrier placed underneath a landfill or on the bottom and/or sides of a surface impoundment.
Depending on their construction, liners can slow or prevent the release of leachate from a landfill or liquids from
a surface impoundment to underlying soils and ground water. Liners can consist of compacted soil, compacted
clay, a synthetic material or membrane, or a combination of barrier types.
Covers. A cover, or cap, is a barrier placed over the top of a waste management unit. Covers can prevent
precipitation runoff from becoming contaminated by contact with waste, prevent or slow percolation of
precipitation into the unit, and prevent windblown transport of waste. Like liners, covers can consist of
compacted clay, synthetic materials or membranes, or a combination of materials. Covers also may be a layer of
soil or sand. Final covers are those placed upon closure of a unit. Intermediate covers also may be placed on
closed or inactive portions of a unit, particularly completed cells of a landfill. Daily covers are sometimes
placed at landfills at the end of a day's operation.
Leachate Collection Systems. A leachate collection system is a series of drains placed beneath a unit, typically
a landfill. These systems collect leachate for treatment or disposal, thus preventing it from reaching soils,
ground water, or surface water.
Ground-Water Monitoring Systems. Ground-water monitoring systems consist of one or several wells drilled
in the vicinity of a unit. Samples from these wells are periodically collected and analyzed. Ground-water
monitoring is not strictly an environment control but rather a warning system. Ground-water samples that
display contamination may trigger regulatory requirements to mitigate or eliminate the source of contamination.
Table 3-15. Environmental Controls at UCCW Comanagement Units
Environmental Control
Liner
Cover
Leachate Collection
Ground-Water Monitoring
Ground-Water Performance Standards
Regulatory Permits
Landfills
Number
Reporting Data
94
72
95
95
94
94
Percent
with Control
57%
94%
43%
85%
77%
94%
Surface Impoundments
Number
Reporting Data
111
47
111
111
107
110
Percent
with Control
26%
30%
1%
38%
48%
85%
Source: EPRI, 1997a
impoundments. This difference may be the result of two factors. First, state solid waste management
regulations are more likely to mandate liners for landfills. As discussed in Section 3.5, many states do
not impose specific design requirements (such as liners) on surface impoundments. When requirements
are imposed, they typically are determined on a case-by-case basis. Second, as discussed above, newer
units are more likely to be landfills than surface impoundments. These newer units would also be more
likely to incorporate the latest environmental controls and regulatory requirements, such as liners.
For both landfills and surface impoundments, there is an increasing trend in the use of liners in
newer units, as shown in Figure 3-8. This trend is consistent with the fact that liners are a modern
development in the design of waste management units. This trend also may be the result of changing
state regulations or permitting policies. As discussed in Section 3.5, new regulations or policies
requiring liner usage typically affect only new units and do not apply retroactively to existing units.
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Figure 3-8. Trend in Liner Utilization in Comanagement Units
Landfills
60%
§ 50%
c
w 40% -
ra 30%
S 20%
10%
0%
1970
1975
1980
1985
1990
1995
Year
Surface Impoundments
60%
.2 50%
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Figure 3-9. Liner Types for Comanagement Units
Landfills
Double 1%
Composite*9%
None/Soil 43%
Surface Impoundments
None/Soil 74%
Geosynthetic11%
Compacted Clay 29%
Compacted Ash 9%
Compacted Clay 22%
Composite* 2%
Geosynthetic 3%
'Composite liners include clay and synthetic layers.
Note: Percentages may sum to greater than 100 percent due to rounding.
Source: EPRI, 1997a
the units are closed. The results for landfills likely reflect interim cover on completed cells or daily
cover used in active cells. Active landfills most commonly use sand, soil, or compacted clay for these
purposes. Some active surface impoundments also use covers, usually soil or sand. The results for
surface impoundments probably reflect cover placed on closed or full sections of active impoundments.
Interpreting the percentages shown for impoundments is difficult. It is unclear whether the 70 percent of
facilities answering "none" have closed, uncovered sections, or if their answer was intended to indicate
that they have no closed sections.
Examining cover types used on currently closed units can provide a better sense of the types of
final cover that will be applied to currently active comanagement units at the end of their useful life.
Because of the design of the survey, the closed units were not required to indicate whether they
comanaged low-volume waste. Three of the 57 closed units, however, did respond that they comanaged.
All three of these are surface impoundments, two of which have compacted clay covers. The remaining
surface impoundment did not provide cover information. An examination of all closed units provides a
larger sample of cover information. Given the prevalence of comanagement, it is likely that many of
these units comanaged low-volume waste at some time. Figure 3-10 shows cover types for closed units
included in the EPRI survey. The survey responses, other than for the three surface impoundments
discussed above, did not indicate whether closed units were surface impoundments or landfills. Of the
53 closed units that provided cover information, 81 percent used some type of cover. The most common
type is soil or sand, although almost a quarter used compacted clay.
Leachate Collection
As shown in Table 3-15, 43 percent of the comanagement landfills in the EPRI survey include a
leachate collection system. Very few surface impoundments (1 percent) have leachate collection. This
difference may result from the difficulty of incorporating leachate collection systems into an
impoundment design. It may also be the result of state solid waste management regulations dictating
collection systems for landfills but not surface impoundments. As discussed in Section 3.5, many states
3-32
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Figure 3-10. Comanagement Unit Cover Types
Active Landfills
Active Surface Impoundments
None 6%
Soil/Sand 45%
Soil/Sand and Fly Ash 1%
Soil/Sand and Geosynthetic 1%
Soil/Sand and Compacted Clay 10%
Geosynthetic 1%
None 70%
Compacted Clay 35%
Soil/Sand 23%
Compacted Clay 6%
Closed Comanagment Units
Other 2%
Compacted Clay and Geosynthetic 2%
Soil/Sand and Compacted Clay 2%
Geosynthetic 2%
None 19%
Compacted Clay 24%
Soil/Sand 49%
Note: Percentages for active landfills and active surface impoundments do not sum to 100 percent due to rounding.
Source: EPRI, 1997a
do not impose specific design requirements (such as leachate collection systems) on surface
impoundments. When requirements are imposed, they typically are determined on a case-by-case basis.
Because a leachate collection system, like a liner, is an environmental control that is usually part
of the initial design and construction of a unit, increasing use of these systems in newer units might be
expected. Examination of the EPRI data, however, shows no such trend. Leachate collection appears to
have been a part of comanagement unit design since the early 1960s, with new units no more likely than
their predecessors to incorporate this control.
March 1999
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Ground-Water Monitoring
As shown in Table 3-15, 85 percent of landfills have some form of ground-water monitoring,
compared with 38 percent of surface impoundments. This difference may be the result of state solid
waste management regulations dictating ground-water monitoring for landfills but not surface
impoundments. As discussed in Section 3.5, many states do not impose specific requirements on surface
impoundments.
When requirements are imposed, they typically are determined on a case-by-case basis. Figure
3-11 shows an increasing trend in the use of ground-water monitoring at newer comanagement units.
The trend appears particularly noticeable for surface impoundments. Although ground-water monitoring
can be implemented at any point in the life of a waste management unit, it may be more likely in newer
units because of more recent changes in state regulations or permitting policies. The operating permits
for newer units may reflect new state ground-water monitoring requirements, whereas those for older
units may not.
Ground-Water Performance Standards
As shown in Table 3-15, ground-water performance standards apply to 77 percent of
comanagement landfills but only 48 percent of surface impoundments. The types of standards applied
include numerical water quality standards, such as federal maximum contaminant limits (MCLs), and
nondegradation standards under which current conditions are compared with past measurements. Some
units, particularly landfills, have standards tailored for the particular site. The EPRI survey did not
identify the consequences if ground-water standards were exceeded. Thirty-one of the units subject to
ground-water performance standards (25 of them surface impoundments) do not have to monitor ground
water. Therefore, it is unlikely that exceedences would be detected at these facilities.
Regulatory Permits
The EPRI comanagement survey collected information on whether units were covered by a
regulatory permit and on the nature of the permitting agency (i.e., state, federal, or local). As shown in
Table 3-15, the majority of comanagement facilities operate under a permit. Landfills are slightly more
likely to face permitting requirements than are surface impoundments. In most cases, the permitting
agency is a state government. Fourteen units (seven each of landfills and surface impoundments) are
subject to the requirements of more than one permitting authority. Information on the degree of
environmental protection required by these permits was not collected in the EPRI survey.
3.3.5 Beneficial Uses
In addition to traditional waste management in landfills and surface impoundments, UCCWs can
be used in a variety of applications. Table 3-16 shows that substantial quantities of UCCWs currently are
diverted from traditional management into beneficial use. An examination of historical data indicates
that beneficial use of UCCWs has increased steadily over the past three decades (ACAA, 1996b; ACAA,
1998). Given the prevalence of comanagement, EPA believes that the quantities of UCCW used in some
of these applications include comanaged wastes.
Categories of beneficial use include cement and concrete products, construction fills (including
structural fill, flowable fill, and road base), agricultural uses, waste management applications, mining
applications, and incorporation into other products. These beneficial uses are in varying stages of
development. Some, such as minefilling and use in cement, have received widespread acceptance.
Others are at the stage of pilot testing or bench-scale examination.
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Figure 3-11. Trend in Comanagement Unit Ground-Water Monitoring
O)
i
o
£
*j
I
O)
i
o
£
*J
I
100%^
80% -
60% -
40%
20% -
n%
u /o
19
100%^
80% -
60% -
Ar\o/n
t\J /O
20% -
no/.
Landfills
'
^^ ~"
-- -- **
ill
75 1980 1985 1990 1995
Year
Surface Impoundments
, -^
U /O | |
1975 1980 1985 1990 1995
Year
Source: EPRI, 1997a
The paragraphs below discuss the extent to which comanaged wastes may be amenable for these
beneficial uses. Box 3-5 describes some of the major uses that may be potential management alternatives
for comanaged wastes.
The extent to which comanaged wastes are amenable to beneficial use depends upon the specific
use being considered. Some of the most developed uses, particularly in cement and waste stabilization,
have met with success because of the pozzolanic or cementitious properties of some UCCWs (meaning
that these wastes react with lime and water or water alone to form a hard matrix). Other uses, such as
structural fill, snow and ice control, and blasting grit, take advantage of the physical properties (size
and shape) of UCCWs. Agricultural uses have received some attention because of UCCW chemical
properties (lime content and the presence of trace metal nutrients). The differences between comanaged
March 1999
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Table 3-16. Beneficial Use of Utility Coal Combustion Wastes in 1997
Beneficial Use
Cement and Concrete Products
Structural Fill
Waste Stabilization/Solidification
Road Base/Subbase
Blasting Grit/Roofing Granules
Mining Applications
Wallboard
Snow and Ice Control
Mineral Filler
Flow/able Fill
Agriculture
Other
Total Use
Total Generation
Percent of Generation Used
Volume in Tons
Fly Ash
9,421,903
2,877,535
3,117,947
1,417,600
0
1,413,567
0
0
285,580
386,158
34,571
362,501
19,317,362
60,264,791
31.5%
Bottom
Ash
604,705
1,384,327
206,368
1,286,585
159,749
162,638
0
723,615
130,888
15,260
8,197
414,572
5,096,905
16,904,663
27.7%
Boiler Slag
10,755
84,669
0
792
2,288,581
0
0
56,057
108,796
0
0
29,200
2,578,851
2,741,614
92.9%
FGD Waste
202,423
91
15,428
17,797
0
104,690
1,603,762
0
0
0
55,644
183,527
2,183,360
25,163,394
7.9%
All Wastes
10,239,786
4,346,622
3,339,743
2,722,774
2,448,330
1,680,895
1,603,762
779,672
525,264
401,418
98,412
989,800
29,176,482
105,074,462
26.8%
Percent of
Generation
9.7%
4.1%
3.2%
2.6%
2.3%
1.6%
1.5%
0.7%
0.5%
0.4%
0.1%
0.9%
26.8%
100.0%
Note: Individual values may not sum to totals due to rounding.
Source: ACAA, 1998
UCCWs and UCCWs managed alone may be of less concern when the comanaged wastes are used in
applications solely to enhance the physical characteristics of a material (i.e., flowability, compressibility,
and unit weight). However, changes in the chemical composition of UCCWs when comanaged may
affect their advantageous pozzolanic or cementitious properties, particularly in applications benefitting
from the incorporation of fly ash. Also, the management of UCCWs prior to their use can affect the
types of uses for which they are amenable. According to the American Coal Ash Association's (ACAA)
statistics, when UCCWs are managed in a surface impoundment prior to use, they are much less likely to
be used for cement or concrete products and much more likely to be used in structural fills, mining
applications, or as blasting grit (ACAA, 1998).
Comanagement may have a particular impact on cement and concrete applications. As shown in
Table 3-16, the major application of fly ash, and that of UCCWs taken together, is in the production of
cement and concrete products. When used alone, fly ash imparts added flowability to fresh concrete due
to its spherical shape and fineness. Additionally, the pozzolanic properties of fly ash increase the
comprehensive strength and the durability of the final concrete product. Excessive amounts of unburned
carbon, high moisture, and low amounts of silicon, aluminum, and iron oxides in fly ash when improperly
managed or when comanaged can increase its variability and interfere with the chemical reactions,
ultimately degrading the quality of the cement or concrete product. This is of particular concern in
structural grade concrete. Therefore, the American Society for Testing and Materials (ASTM) has
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Box 3-5. Potential Beneficial Uses for Comanaged Wastes
Construction Fills. Construction fills include structural fills, flowable fills, and road base and subbase
applications. Most of the bottom ash and a considerable portion of the fly ash utilized are applied in
construction fills. This application of UCCWs ranks second following the use of UCCWs in concrete and
cement products. In structural fills (e.g., backfills, embankments, area fills), fly ash and bottom ash replace
natural materials and provide additional benefits not obtained with conventional fill materials, such as low
compressibility, light unit weight, high shear strength, and pozzolanic properties. Unlike structural fills,
flowable fills, such as backfills and grouts, are placed in slurried form and, therefore, benefit from the added
flowability and strength development imparted by UCCWs. In road bases and subbases, the addition of UCCWs
allows for greater long-term strength development.
Waste Stabilization/Solidification. Because of their alkalinity and presence of solids, UCCWs are used to
chemically fix potentially hazardous wastes in a solid matrix. Through stabilization, hazardous organic and
inorganic constituents are immobilized and prevented from being released to the environment. Stabilization may
occur with or without solidification. Solidification consists, primarily, of converting soils, liquids, and sludges
into a solid, structurally sound material prior to disposal or further utilization of the material. Waste stabilization
and solidification represent the third largest beneficial use of UCCWs.
Blasting Grit/Roofing Granules. More than 2 million tons of UCCW, including almost all of the boiler slag
and some bottom ash generated in 1997, were used as blasting grit and roofing granules. Like sand, boiler slag
particles are used in sand-blasting operations and as roofing granules.
Mining Applications. Mining applications of UCCWs include controlling acid mining drainage, backfilling,
blending mine soils and spoils, and revegetation. UCCWs are used in remediation activities at coal mines
primarily because of their ability to neutralize the effects of acid drainage from mines and associated wastes.
Mine subsidence problems from abandoned underground mines also are remediated by the use of these wastes as
backfills. In addition, UCCWs are applied at the surface to promote vegetative growth and serve as a soil cover
to prevent water infiltration to mine wastes.
Snow and Ice Control. Bottom ash and boiler slag are used as a substitute of salt for road de-icing operations.
Approximately 780 thousand tons were used in 1997.
Mineral Fillers. Mineral fillers include a variety of fine particles that are incorporated into a broad range of
industrial products. UCCWs have been used or evaluated for use as substitutes for commercial fillers in asphalt
products, plastics, metal alloys, and fertilizers. The uses receiving the most attention are fly ash and boiler slag
in asphalt and plastics. Fly ash also has been proposed as a mineral filler in carpet backing, vinyl flooring,
joining and caulking compounds, industrial coatings and paints, and insecticides and pesticides. FGD sludges
may have some potential as mineral fillers but have received little detailed scientific or engineering evaluation.
Finally, because natural gypsum filler products have attained some commercial acceptance, FGD gypsum also
has been considered for use as a filler, particularly in coated paper and joining compounds.
Agriculture. Fly ash, bottom ash, and FGD sludge are used for agricultural soil amendment. In general, these
wastes can benefit agricultural systems by changing physical and chemical characteristics of soils, thus
improving crop yield. UCCWs affect the chemical properties of soils by supplying essential plant nutrients for
crop production and by modifying the soil to create a more favorable medium for plant growth. Physical
changes brought about by UCCW amendments include reduced bulk density and increased aeration and water
filtration. The potential benefits of using UCCWs in agriculture include alleviating soil trace elemental
deficiencies, modifying soil pH, and increasing levels of needed calcium (Ca) and sulfur (S), infiltration rates,
depth of rooting, and drought tolerance.
Sources: ACAA, 1996b; ACAA, 1998; EPA, 1998h
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Report to Congress on Wastes from the Combustion of Fossil Fuels
developed standard specifications for fly ash used as a mineral admixture in Portland cement concrete.
Guided by these requirements, generators may use specialized fly ash management practices when use in
concrete is intended. These practices include segregating fly ash, as well as processing or cleaning the
waste, prior to its use. In many cases, these standards and preprocessing operations may preclude the use
of comanaged fly ash.
Another beneficial application considered waste-specific and, consequently, not suitable for
comanaged waste utilization is wallboard production. Because of its similarities to natural gypsum,
gypsum produced from FGD sludge is used as a substitute for the former in the manufacture of
wallboard. The strength per unit weight provided by FGD gypsum greatly depends on its purity.
Impurities such as fly ash, as well as lime and limestone found in FGD gypsum, could adversely affect
the quality of the raw material and the final wallboard product.
The potential for beneficial use of comanaged wastes may be greatest in lower technology
applications with less stringent specifications and where large volumes of material are needed. The
feasibility of any specific use, of course, should be based on a detailed evaluation of the specific waste
and its potential impacts in application.
3.4 POTENTIAL AND DOCUMENTED DANGERS TO HUMAN HEALTH AND THE
ENVIRONMENT
Because of data limitations, EPA could not evaluate the site-specific potential for and historic
occurrence of damages throughout the universe of existing coal-fired utility comanaged waste sites.
Instead, EPA developed a methodology for estimating the potential risks associated with comanaged
wastes relying on limited site-specific and industry-wide data, together with appropriate nationwide
modeling techniques. Site-specific and regional data provided for this analysis to EPA were combined
with nationwide environmental modeling data available to EPA from other modeling studies and from
EPA's nationwide modeling database. EPA developed waste management scenarios representative of
industry practices and environmental settings. To provide confidence in its model results, EPA
conducted sensitivity analyses focusing on the driving model variables, and particularly on parameters
for which only limited data were available. EPA also examined a wide range of state agency and EPA
information sources to determine the past occurrence of damages at comanaged waste sites.
Previous work by EPA concluded that the greatest potential for harm from FFC wastes was
associated with the potential for ground-water contamination (EPA, 1988; EPA, 1993b). Current EPA
risk assessment policy also requires consideration of comprehensive human health risk (ground water and
non-ground water) and ecological impacts. Accordingly, this FFC waste risk assessment included two
components: the ground-water pathway human health risk assessment and the above-ground multi-
pathway human health and ecological risk assessment. Section 3.4.1 presents the technical approach to
and results of the ground-water pathway human health risk assessment for comanaged wastes. Section
3.4.2 presents the results of the above-ground multi-pathway risk assessment, which was conducted in
close coordination with the ground-water study. Section 3.4.3 discusses potential and documented
damage cases.
3.4.1 Potential Ground-Water Risks to Human Health
This section summarizes EPA's approach to and findings of its ground-water risk assessment
efforts. Results of this study were originally presented in the Technical Background Document for the
Supplemental Report to Congress on Remaining Fossil Fuel Combustion Wastes, Revised Draft Final
(EPA, 1998d). EPA received peer reviewer and industry comment on the June 1998 study (Peer Review
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Report to Congress on Wastes from the Combustion of Fossil Fuels
of Fossil Fuel Combustion Risk Assessments: Original Comments from Peer Reviewers, July 1998) and
developed revised results in the October 1998 Fossil Fuel Combustion Waste Risk Assessment: Revised
Groundwater Analysis and Sensitivity Results (EPA, 1998f). Original reports and comments are
available in the docket supporting this report.
Overview of Approach
EPA followed a multistep assessment process including screening, deterministic modeling, and
probabilistic modeling to determine the nationwide potential for risks to human health from ground-water
contamination. EPA considered three individual receptors: an adult resident, a young child resident
(age 1-10), and a child resident (age 1-19). For each receptor, EPA developed separate risk estimates
for two waste scenarios: surface impoundments and landfills. See Chapter 2 of the Technical
Background Document for the Supplemental Report to Congress on Remaining Fossil Fuel Combustion
Wastes, Revised Draft Final (June 1998), available in the docket, for further discussion of the overall
approach.
To identify the waste constituents of potential concern, EPA first performed a "screening-level"
assessment. Screening involves comparing waste leachate concentrations with human health-based
concentrations (toxicity levels) to identify and eliminate from consideration those leachate constituents
too dilute to present risk even before transport in ground water to a receptor. The data provided to EPA
indicated that no organic compounds of concern are present in the ash. EPA found that many metals of
concern may be present in FFC waste leachates at concentrations greater than the corresponding health-
based benchmarks. Therefore, EPA focused its screening efforts on the following: antimony, arsenic,
barium, cadmium, chromium,3 lead, mercury,4 nickel, selenium, silver, thallium, vanadium, and zinc. For
screening purposes, no dilution factor was assumed; leachate concentrations were compared directly with
toxicity levels.5
EPA selected the Composite Model for Leachate Migration with Transformation Products vl.2
(EPACMTP) to model the movement in ground water of metals of concern released from waste landfills
and surface impoundments. Waste management scenarios were developed for use with EPACMTP using
site-specific, industry-wide, and general nationwide information to estimate values for parameters
describing waste and management unit properties (e.g., unit size, waste density), unit environmental
settings (e.g., recharge rate, soil properties, ground-water velocity), and contaminant properties (e.g.,
retardation factors). Each scenario was used to predict the peak metals concentrations expected to occur
in a nearby drinking water well during a 10,000-year study period. Comparing the predicted peak
concentration with the health-based benchmarks, EPA estimated the risk to an individual receptor
exposed through ingestion of the contaminated drinking water.
EPA calculated estimated risks for each scenario by selecting combinations of variables most
likely to produce high-end (to include the 95th percentile of all possible risks) results. EPA then
performed probabilistic modeling to determine where the deterministic results fell within a distribution of
3 Available chromium data for comanaged wastes were limited to total chromium, which were used as a
conservative estimate of hexavalent chromium (CrVI) for screening purposes.
4 Only two samples of comanaged waste leachate showed mercury concentrations above detection levels.
Despite the low frequency of detection, mercury was carried forward in the analysis.
5 This is in contrast with earlier FFC Waste (1993), Cement Kiln Dust, and Mineral Processing Waste
studies, in which a dilution factor of 10 was assumed to reflect a 10:1 dilution of leachate in ground water.
March 1999 3-39
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Report to Congress on Wastes from the Combustion of Fossil Fuels
estimated risks. Finally, EPA performed sensitivity analyses to improve its confidence in the overall
estimate of risks. EPA varied individual variables and combinations of variables throughout wide ranges
of values, finding that model results changed very little except in response to the most sensitive
parameters (e.g., waste management unit size, waste concentration, receptor well location, contaminant
retardation rate). As part of the sensitivity analysis, EPA compared EPACMTP model results with the
output of an industry-sponsored model, MYGRT v 2.0, and found general agreement between the models
with respect to predicted down-gradient concentration and time to reach risk when similar input values
were used.
Calculation of Benchmarks
The starting point for the ground-water pathway risk assessment was the calculation of health-
based benchmark concentrations ("health-based levels" [HBLs] sometimes referred to as health-based
numbers or HBNs). Each HBL represents the concentration of a contaminant in drinking water to which
a specified receptor is exposed above which adverse health effects may be expected to result. The value
is calculated from a combination of toxicological information, ingestion rate, frequency and duration, and
receptor body weight.
Screening Assessment Results
As discussed in Section 3.2, EPA developed a profile of comanaged waste characteristics using
industry-provided data collected from comanaged waste landfills and impoundments. For
impoundments, EPA relied upon in situ pore water samples taken from waste drill cores. For landfills,
EPA used both laboratory leachate tests developed using the TCLP, and industry-provided water extract
data from in situ solids samples collected from several landfills. EPA calculated the 95th percentile waste
concentration for each metal of concern in comanaged wastes and compared it to the corresponding
HBL.6 The results of the screening exercise, shown in Table 3-17, determined those constituents that
could be eliminated from further consideration, and those constituents warranting additional
consideration.
In the table that follows, and for all subsequent risk discussions, screening and modeling results
are expressed in terms of cancer risk or hazard quotients (HQ). Cancer risk, always expressed in powers
often, refers to the incremental individual lifetime risk of developing cancer. For this study, arsenic is
the only known carcinogen for which risks were calculated. For all other constituents of concern, results
are expressed as HQ. An HQ equals the modeled concentration level divided by the HBL.
It is important to note that the screening approach employed did not rule out many metals of
potential concern. In fact, the HQ for most metals was less than 10, such that employing a fixed ground-
water dilution factor at this step would have eliminated many more metals from additional consideration.
However, because preliminary modeling indicated that the predicted dilution factors might sometimes be
less than 10, EPA elected to adopt the more conservative approach described here.
Modeling Scenarios Considered
EPA developed contaminant transport model scenarios to estimate the level of ground-water
contamination that might result from the release of comanaged waste leachate from management units.
6 Note that since the number of values available for each constituent was generally less than 20, the 95th
percentile value generally was set equal to the maximum value observed.
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Table 3-17. Constituents Remaining after Screening Analysis
for Coal-Fired Utility Comanaged Wastes
Constituent
Observed 95th Percentile
Concentration (mg/L)
Screening Result
Wastes Managed in Surface Impoundments
Arsenic
Cadmium
Chromium (as VI)
Lead
Nickel
Selenium
Vanadium
Zinc
9.64
0.156
0.746
0.468
8.33
1.03
0.8
23.1
Risk = 3.3x1 02
HQ = 6.0
HQ = 5.0
31 times action level
HQ = 8.1
HQ = 4.0
HQ = 2.2
HQ = 1.5
Wastes Managed in Landfills
Arsenic
Barium
Cadmium
Selenium
Thallium
0.24
3.6
0.044
0.44
0.015
Risk = 8.3x10"
HQ = 1.0
HQ = 1.7
HQ = 1.7
HQ = 3.7
Notes: Constituents were evaluated at their high-end (95th percentile) concentration. Constituents that screen out are as follows: antimony,
barium, copper, mercury, and silver for surface impoundments; antimony, chromium, copper, lead, mercury, nickel, silver, and zinc for
landfills. Landfill data are calculated as presented in the October 10, 1998, Sensitivity Analysis.
Source: EPA, 1998d (Chapter 5)
Waste management scenarios were developed for use with EPACMTP using site-specific and industry-
wide information to estimate values for parameters describing the following:
Waste and management unit properties (e.g., unit size, saturated hydraulic conductivity)
Unit environmental settings (e.g., weather, soil properties, ground-water velocity and
volume)
Contaminant properties (e.g., retardation factors).
EPA developed a central tendency scenario by setting all EPACMTP model parameter input
values at or near the midpoint of the range of values for the industry. EPA also developed a high-end
scenario by setting the two most significant parameters (waste concentration and receptor well location)
at their respective high ends. In addition to the high-end deterministic scenario, EPA used the Monte
Carlo capabilities of EPACMTP to perform a probabilistic assessment of risk for each waste management
scenario. The Monte Carlo analysis resulted in a distribution of risk estimates from 2,000 model runs in
which each of the model's input parameters was allowed to vary independently. In accordance with
EPA's current policy, with respect to measuring occurrence of risk, high-end risks and Monte Carlo
results are emphasized.
For comanaged utility wastes, EPA modeled landfills and surface impoundments. Risks from
minefills were evaluated using other analytical techniques primarily, as discussed below, due to
difficulties in modeling the movement of water through mining disturbed strata. (As noted in the
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Report to Congress on Wastes from the Combustion of Fossil Fuels
discussion of minefills, it is possible to approximate surface mine transport using the landfill scenario,
under certain conditions. The landfill scenario can not be used to approximate underground mine
transport, however.) Risk from agricultural application of comanaged waste is discussed in the non-
ground-water section below.
A complete listing of model input values is presented in the June 1998 Technical Background
Document for the Supplemental Report to Congress on Remaining Fossil Fuel Combustion Wastes,
Revised Draft Final (EPA, 1998d) and the October 1998 Fossil Fuel Combustion Waste Risk Assessment:
Revised Groundwater Analysis and Sensitivity Results (EPA, 1998f). All the above may be found in the
docket supporting this report.
Modeling Results
Table 3-18 summarizes selected results from the deterministic and probabilistic analyses of risk
from comanaged wastes for the adult receptor. Overall, EPA found that the risks associated with all
modeled constituents of concern, except for arsenic, fell below an HQ of 1 or a lifetime cancer risk of
1 x 10~6. Potential risks associated with arsenic in both the landfill and the surface impoundment high-end
deterministic scenarios exceeded lxlO~6.
Comparison of the deterministic and Monte Carlo results reveals that the deterministic results
always exceeded the 95th percentile Monte Carlo result. For example, none of the 2,000 Monte Carlo
simulation combinations of parameter values performed for arsenic for the surface impoundment scenario
yielded a risk estimate as high as the high-end deterministic result. Similarly, the high-end risk for
arsenic, chromium, nickel, and selenium from the comanaged waste landfill exceeded 99 percent or more
of the corresponding Monte Carlo simulation results. At the 95th percentile level, the arsenic risks
predicted by the Monte Carlo simulations of the landfill and surface impoundment scenarios were
roughly 1 order of magnitude or more below the corresponding risks estimated for the high-end
scenarios.
Table 3-18. Comparison of Deterministic and Monte Carlo Risk Model Results for
Comanaged Waste Ground-Water Pathway Scenarios
Scenario
csb
CLb
Constituent"
Arsenic
Arsenic
Chromium
Nickel
Selenium
Deterministic
Risk, Central
Tendency
3x1 Q-6
4x1 (T7
HQ<1
HQ<1
HQ<1
Deterministic
Risk, High-End
5x10-"
3x10-"
HQ = 0.2
HQ <0.1
HQ = 0.8
Corresponding
Monte Carlo
Percentile
>100
>99.9
>99.4
>100
>100
Monte Carlo
95th Percentile
1.6x1(T5
4.3x1(T5
HQ = 0.1
HQ = 0.01
HQ = 0.1
a All other metals modeled resulted in HQ <1
b CS = comanaged waste impoundment; CL = comanaged waste landfill
Note: Results shown are those from the October 10, 1998 Sensitivity Analysis
EPA also considered the time at which risks were predicted to result from the release of
constituents of concern in each of the scenarios. EPA found that the concentration of arsenic in ground
water at the receptor well would not reach the HBL for arsenic (e.g., achieve a risk level of 1 x 10~6) for
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Report to Congress on Wastes from the Combustion of Fossil Fuels
roughly 500 years.7 For the landfill, the predicted time to reach a risk of 1 * 10 6 or more was found to
exceed 3,500 years.8
Table 3-19 summarizes the estimated risks to adult and child receptors for the high-end
deterministic scenarios for comanaged wastes. Overall, the results show that for noncarcinogens the
risks for young children increased roughly twofold compared to the adult receptors. For arsenic, the risk
for young children increased roughly 25 percent compared to the adult receptors.
Table 3-19. Comparison of Adult and Child Risk Model Results
Comanaged Waste Ground-Water Pathway Scenarios
for
Scenario
csb
CLb
Constituent"
Arsenic
Arsenic
Chromium
Nickel
Selenium
High End Deterministic Risk
Adult
5x10-"
3x10-"
HQ = 0.2
HQ = 0.1
HQ = 0.8
Young Child
6.3x10-"
3.8x10-"
HQ = 0.35
HQ = 0.2
HQ = 1.4
Child
4.4x10-"
2.6x10-"
HQ = 0.22
HQ = 0.1
HQ = 0.9
a All other modeled metals yielded HQ <1
b CS = comanaged waste impoundment; CL = comanaged waste landfill
Note: Results shown are from the October 10, 1998, Sensitivity Analysis.
3.4.2 Potential Above-Ground Multi-Pathway Risks to Human Health and the
Environment
Human Health Risks
This section summarizes EPA's approach to and findings of its above-ground human health risk
assessment efforts. Results of this study were originally presented in Non-groundwater Pathways,
Human Health and Ecological Risk Analysis for Fossil Fuel Combustion Phase 2 (EPA, 1998e). EPA
received peer reviewer and industry comment on the June 1998 study (Peer Review of Fossil Fuel
Combustion Risk Assessments: Original Comments from Peer Reviewers, July 1998) and subsequently
developed revised results. Original reports and comments are available in the docket supporting this
report.
Overview of Approach
As in the case for the ground-water risk assessment (Section 3.4.1), EPA conducted a broad
above-ground risk assessment to estimate potential risks associated with direct and indirect exposure to
wastes and waste contaminated media. EPA employed the Indirect Exposure Methodology (IEM) used in
several previous Office of Solid Waste (OSW) risk assessments (e.g., Cement Kiln Dust, Hazardous
7 See EPA, 1998d, page 5-33.
8 Ibid. The value shown here is for the FBC landfill. Based on sensitivity analyses and the change from
porewater to TCLP concentrations for landfill waste characterization, the time to reach peak will equal or exceed the
value reported for the FBC landfill.
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Waste Identification Rule). Using IBM, EPA estimated the concentration of constituents of concern in
air, soils, and plant and animal tissues resulting from airborne and waterborne releases of comanaged
wastes. EPA then estimated the human health risks associated with exposure to the contaminated media
for a wide range of exposure scenarios. To provide confidence in its model results, EPA conducted
sensitivity analyses for each scenario, constituent, and receptor, focusing in particular on those driving
parameters for which only limited information was available.
IEM considers two major release mechanisms: wind erosion and surface water erosion and
runoff. EPA concluded that these releases may occur in three comanaged waste scenarios: active
landfills, dewatered surface impoundments without cover, and agricultural application projects where
comanaged wastes are employed as soil amendment. Estimation of waste management unit sizes and
waste characteristics for these scenarios was coordinated with the ground-water risk assessment for
consistency. For each scenario, EPA considered the following transport pathway and exposure routes:
Inhalation of contaminants transported through air emission and dispersion. Only
concentrations of respirable PM 10 were considered for the inhalation exposure route.
Ingestion of soil contaminated through deposition of air emissions and contaminated runoff.
For the soil amendment scenario, soil was contaminated by intended application of the
waste product.
Ingestion of fruits and vegetables contaminated through direct deposition to the plant and
deposition to soil with subsequent plant uptake. For root vegetables, contamination results
from deposition to soil followed by root uptake.
Ingestion of beef and dairy products contaminated through cows' ingestion of contaminated
soil, grain, forage, and silage. These media are contaminated via the same mechanisms
stated above.
Ingestion offish taken from an effected stream located near a waste management unit or
agricultural field, and contaminated by runoff, erosion, or direct deposition.
For each release pathway and exposure route, EPA considered a variety of receptors. These
included an adult and child resident near the waste management unit, a subsistence farmer and child of
subsistence farmer for the agricultural application scenario, and a subsistence fisher.
For each receptor, EPA calculated risk based on toxicological information, receptor-specific
exposure assumptions, and the predicted concentration of constituents of concern in the contaminated
media. EPA calculated central tendancy risks by setting all IEM model parameter input values at or near
the midpoint of the range of values for the industry. EPA also calculated high-end risks determining the
pair of parameters that, when placed at their respective high-end values, yield the highest estimate of risk
for the specific scenario.
Overview of Modeling Results
In essence, no risks from the ingestion exposure route were found in excess of 1CT6 (cancer), or
with HQs in excess of 1, except for arsenic in the case of agricultural applications and when managed in
an onsite active landfill. For both the landfill and the impoundment, for arsenic, ingestion risks were
found at the 10~6 level for both the farmer and the child of the farmer. In the agricultural use scenario,
EPA found arsenic risks from this composite and complex pathway to be at five times the 10~5 level (a
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level consistent with the findings of EPA's ongoing cement kiln dust evaluation in which the arsenic
waste concentrations were similar to, but slightly below on average, those of FFC total wastes). While
some other risks at the "1CT6 or hazard quotient of 1" margin were found, the very conservative nature of
the analysis combined with the intrinsic cementitiousness of the ash (meaning it will harden and not
blow, erode, or runoff as readily as otherwisea consideration difficult to simulate) together lead EPA
to conclude, with the same data sufficiency caveat as for ground water, that only the agricultural use non-
ground-water pathway poses meaningful risk.
Table 3-20 summarizes the differences between adult and children's above-ground risk where the
risk exceeded 10~6.
Table 3-20. Comparison of Adult and Child Risk Model Results for
Comanaged Waste Above-Ground Ingestion
Scenario
Utility Coal Landfill
Utility Coal Dewatered
Impoundment
FBC Waste Landfill
Constituent
Arsenic
Arsenic
Arsenic
High End Deterministic Risk
Adult*
2.5x1(T6
2.1 x106
1.0x10*
Child
1.7x1Q-5
2.0x1 Q-6
8.2x106
* High-end deterministic risk from ingestion. The very slight differences for the landfills are not considered significant, primarily due to the
cementitiousness of the ash.
Risks in the 10 6 range were found for inhalation exposure route for chromium. It should be
noted that only total chromium was reported. For this assessment chromium was modeled as the more
toxic chromium VI valencea conservative assumption. This, coupled with other conservative
assumptions (including the cementitiousness issue) leads EPA to believe that there are no plausible
excess risks from the inhalation exposure route.
Ecological Risks
EPA has developed explicit guidelines to evaluate the ecological risks associated with chemical
and non-chemical stressors (see EPA, 1998g). Consequently, EPA developed a technical approach that
was consistent with the guidelines and addressed the management goal for the ecological risk analysis,
succinctly stated as follows: "to evaluate the potential for adverse ecological effects associated with the
management and/or use of comanaged FFC residuals anywhere within the contiguous United States."
The Guidelines (EPA, 1998g) describe the three basic phases that frame the ecological risk
assessment process: problem formulation, analysis, and risk characterization. In brief, these phases may
be summarized as follows:
Problem formulation phase. During this phase, the problem statement is developed within
the context of stated management goals and constraints on resources and timeframe. The
endpoints for the analysis are selected, a conceptual model is developed, and an analysis
plan is prepared for estimating exposure concentrations and risks. The conceptual model
identifies ecological receptors potentially at risk and relevant exposure pathways. For
rulemakings intended to be national in scope, assessment endpoints and measures of adverse
effects are often chosen to be broadly applicable across the United States.
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Analysis phase. The analysis phase involves the use of simulation models to predict
constituent concentrations in the environment to which ecological receptors are exposed
(i.e., exposure profile). In addition, this phase describes how ecotoxicological data are used
to develop appropriate measures of adverse effects to various ecological receptors (i.e.,
stressor-response profile). The simulation models are mathematical constructs that
represent fate and transport processes from source releases into various environmental
media where they may be taken up by plants and animals.
Risk characterization phase. Characterizing ecological risks often involves the
comparison of predicted exposure concentrations to chemical stressor concentration limits
(CSCLs) for soil, sediment, and surface water intended to represent de minimus risks to
wildlife. The comparison of predicted exposure concentrations to CSCLs is generally
referred to as the HQ approach and provides a quantitative indication of the potential for
adverse ecological effects. The HQ results are accompanied by a narrative explanation of
the assumptions, limitations, and uncertainties inherent in the assessment. The relevance of
the findings to the management goals and the ecological significance of potential effects (as
indicated by the HQ values) also are discussed.
The ecological risk analysis was implemented using a tiered approach that proceeded from
conservative onsite screening evaluations to increasingly detailed assessments of representative
ecological receptors exposed to chemical releases simulated from comanagement facilities (e.g., surface
impoundments, landfills). Chemical concentrations in comanagement facilities were identified from
available data distributions and high-end (approximating the 95th percentile) and central-tendency
(approximating the 50th percentile) concentrations were simulated. The same fate and transport models
used to simulate chemical movement through the environment and resulting human exposures also were
used to predict ecological exposures. In essence, the similarity in exposure pathways for human and
ecological receptors allows similar fate and transport models to be used for both components of the
analysis.9 The exposure concentrations predicted for environmental media in generalized freshwater and
terrestrial habitats were compared to the CSCLs for representative ecological receptors, including species
of mammals, birds, and amphibians, as well as collections of soil, sediment, and surface water organisms.
Because the intent of this analysis was to identify the potential for adverse ecological effects,
conservative benchmarks for "no adverse response" were chosen whenever they were available. These
benchmarks often are based on subchronic studies at low chemical concentrations for sensitive endpoints,
such as developmental effects. For amphibians, however, the adverse effects benchmarks were based on
relatively high levels of lethality (typically 50-percent lethality).
The risk estimates (i.e., HQ results) for landfills and land application units suggest that
ecological risks associated with the release and surface transport of chemicals of concern are not likely to
be significant for these management/use practices. Because these results are generally based on no
effects levels for mammals and birds, it is expected that even threatened and endangered mammalian and
avian species are unlikely to receive exposures that would warrant concern. It is difficult, however, to
provide unequivocal support to that assertion without the benefit of a more site-based analytical
framework. In addition, the subsurface pathway was not evaluated in this analysis, and there is some
concern that this pathway may be significant in areas with high water tables that intersect critical
wetlands and estuarine systems.
9 Resource constraints, in combination with analytical difficulties associated with estuaries, did not permit
specific estuarine analysis.
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The risk estimates for comanaged coal ash surface impoundments and associated drainage
systems indicate that this scenario is of special concern. Wildlife frequently utilize surface
impoundments and nearby wetlands as part of their habitat and, in particular, the HQ ratios for
amphibians indicate that the chemical concentrations in surface impoundments may be associated with
high levels of lethality (i.e., the CSCLs for amphibians correspond to 50-percent lethality). Amphibian
sensitivity to these trace metals has been demonstrated in case studies on FFC residuals, and selenium
and aluminum are believed to be particularly toxic to amphibian species. In contrast, the risk estimates
shown for mammals and birds may predict more subtle effects on reproductive capacity and the HQ
ratios are based on no adverse response levels. In addition, the probability of wildlife being directly
exposed to surface impoundment water will vary depending on the surrounding habitat and the location
of the impoundment, so there is considerable uncertainty associated with these risk estimates. The most
likely receptor to be exposed would be avian species that are able to circumvent barriers to forage or nest
in pond areas. Transitory exposures to migratory birds are possible during seasonal migrations and
longer-term exposures are possible depending upon the nesting behavior of a given species. Although
this exposure scenario may affect relatively few species, the local effects on a particular species or
habitat may be undesirable. Table 3-21 summarizes the HQ results for surface impoundments for high-
end and central-tendency chemical concentrations.
Table 3-21. Summary of Ecological Risk Results for Comanaged Waste Impoundments3
Constituent
Aluminum
Arsenic
Boron
Selenium
High-End HQ
10
19
16
29,622
5
Central Tendency HQ
1
<1
<1
153
<1
Receptor Group
Amphibians
Birds
Amphibians
Mammals
Amphibians
a For this pathway, standing water samples collected from surface impoundments were used to represent media
concentrations. No fate and transport modeling was conducted.
3.4.3 Documented Damages to Human Health and the Environment
Summary of Findings
EPA identified a total of six sites at which comanagement of coal combustion wastes has
occurred and which meet the "test of proof' for damage cases (see Section 1.4.3). Five of these sites
were previously identified in the 1988 Report to Congress and the 1993 Regulatory Determination (58
FR 42473, 8/9/93). A sixth site was more recently identified by EPA. Detrimental effects from these
sites included the presence of contaminants in drinking water wells above MCLs and vegetative damage
in wetlands or streams.
EPA finds that most of the sites showing damages are older unlined units. In most cases, the
units are closed and stopped receiving wastes in the 1980s and may not have used management practices
similar to those used today. At the same time, the damage cases demonstrate the potential for comanaged
wastes to present a danger to drinking water supplies or the environment.
Based on information available and consideration of EPA's "tests of proof," EPA identified the
cases in Table 3-22 as potential damage cases.
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Table 3-22. Damage Cases
Damage Case
Wastes Present
Event
Test of Proof
Comment
Coal-Fired Utility Comanaged Wastes
Chisman Creek (VA)
(88)
Faulkner Offsite
Disposal Facility (MD)
DPC-OldEJ.
Stoneman Ash Pond
(Wl)
Basin Electric WJ.
Neal Station (ND)
VEPCO - Possum
Point (VA)
Petroleum coke and
coal ash landfill
Coal ash and pyritic mill
rejects
Coal ash, demineralizer
regenerant, other water
treatment wastes
Coal ash and sludge;
comanaged wastes
probable
Coal ash, pyrites, oil
ash, water treatment
wastes, and boiler
cleaning wastes
Vanadium, selenium, and
sulfate in ground-water
wells
Landfill and collection
pond seepage and
discharges resulted in
plant and fish impacts to
adjacent wetlands; pH
the major COC
'Gross contamination' by
pond cited by State -
MCL exceedences of Cd,
Cr, Zn, and sulfate; B
near 5 mg/L in private
well
Cr and other metals
detected in downgradient
sediments, ground water
Ground water
contaminated with Cd
and Ni, attributed to
pyrites and oil ash
Scientific/
Administrative
Scientific/
Administrative
Administrative
Administrative
(limited information
available)
Administrative
Other possible sources
of contamination; 1 of 2
major cases cited in
Report to Congress
Remediation included
pond liners, landfill
cover, and sequest-
ration of pyrites
Closure plan required
relocating town water
supply well
Site closed and capped
and pending NFRAP
(No Further Remedial
Action Planned)
Response included
sequestration of oil ash,
pyrites, and metal
cleaning wastes to
separate lined units.
Damages from Comanaged Wastes Identified in the 1988 Report to Congress and 1993
Regulatory Determination
In the 1988 Report to Congress, EPA identified two sites that meet the "test of proof' criterion
for damage cases. In preparing the 1993 Regulatory Determination, EPA identified four additional sites
meeting the test of proof. EPA determined that four of these six damage cases were associated with
comanagement. These findings were presented in the 1993 Regulatory Determination. With the
exception of one site (i.e., Faulkner), EPA did not conduct further research or investigation of these
sites beyond what was presented in the record for the 1993 Regulatory Determination. The four
comanagement sites are discussed below.
Chisman Creek, Virginia (described in the 1988 Report to Congress). Fly ash and bottom
ash from the burning of coal and petroleum coke were managed in a disposal pit. The site
was on the National Priority List as of 1988. Drinking water wells became green from
vanadium and selenium contamination, and contained selenium above the primary MCL and
sulfate above the secondary MCL.10
10 Based on the limited data discussed in Section 3.2.3, waste from coburning coal and petroleum coke may
be higher in vanadium on average than UCCWs. Therefore, ash from petroleum coke may be a more likely source
of vanadium than ash from coal combustion.
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Possum Point, Virginia (described in the 1993 Supplemental Analysis). At this site, oil
ash, pyrites, boiler chemical cleaning wastes, coal fly ash, and coal bottom ash were
comanaged in an unlined pond, with solids dredged to a second pond. Levels of cadmium
above 0.01 mg/L were recorded priorto 1986 (the primary MCL is 0.005 mg/L). After that
time, remedial actions were undertaken to segregate wastes (oil ash and low volume wastes
were believed to be the source of contamination). Following this action, cadmium
concentrations were below 0.01 mg/L.
Faulkner, Maryland (initially described in the 1993 Supplemental Analysis). Pyrites, fly
ash, and bottom ash were comanaged in unlined landfills. In 1991, the state of Maryland
found that water quality in a nearby stream and creek were degraded by landfill leachate,
with effects including orange staining from iron precipitation and low pH (3 to 4).
Vegetative damages also were observed. An underlying aquifer was found to be affected by
the landfill leachate. The acidic leachate was believed to have resulted from pyrite
oxidation. Remedial measures at the site included closure and capping of older units,
installation of liners in newer units, and discontinuing mill reject comanagement at the
facility.
Old E.J. Stoneman Ash Pond, Wisconsin (described in the 1993 Supplemental Analysis).
Ash, demineralizer regenerant, and sand filter backwash were managed in an unlined pond
from the 1950s to 1987. Nearby private drinking water wells had elevated levels of sulfate
and boron relative to background. Monitoring wells installed around the pond showed
exceedences of the primary MCL for cadmium and chromium, but these constituents were
not detected in the drinking water wells. As a result of the presence of indicator parameters
in the drinking water wells, the state concluded that other parameters may reach the wells in
the future and therefore required the operator to close the site and provide alternative
drinking water to the affected residences.
Additional Damages Identified Since 1993
Since 1993, EPA has become aware of additional candidate damage cases involving comanaged
wastes. EPA used information supplied by EPPJ regarding 14 comanagement sites, as well as other case
study reports, and conducted a search of the Comprehensive Environmental Response, Compensation,
and Liability Act of 1980 (CERCLA) Information System. In a number of cases, EPA found that
comanagement units have affected ground-water quality, a conclusion which is supported by EPRI's
work. Only one of the cases reviewed by EPA, however, meets the Agency's "test of proof' to be
considered a damage case for purposes of this investigation. This case, the Basin Electric Surface
Impoundment (BESI) site, was identified through the CERCLA information system. Significant findings
regarding this site are summarized below.
The BESI site at the WJ Neal Station in Velva, North Dakota, is an unlined, diked impoundment
that received various construction debris and ash from the burning of sunflower seed hulls as well as fly
ash and sludge from a nearby coal-fired power plant from the 1950s until the late 1980s. A site
inspection report and power cooperative records from BESI confirmed that fly ash and sludge from
BESFs coal-fired power plant were deposited in the impoundment. Monitoring efforts and negotiations
for plant closure began in 1982 after chromium was found at 8.15 parts per million (ppm) in the sludge
pond, in excess of the standard for chromium. A Preliminary Assessment in 1989 indicated migration of
contaminants into the underlying aquifer that supplies Velva with drinking water, although sampling data
were not provided. Areas of soil contamination within the impoundment were consolidated and the
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impoundment was capped when the site was closed in 1990. EPA has concluded the contamination was
a result of activity that occurred before the cap was in place.
3.4.4 Compliance History of the Fossil Fuel Electric Power Industry
To further characterize the environmental impacts of the fossil fuel electric power generation
sector, EPA examined the sector's compliance, enforcement, and legal history. The data utilized in this
section were gathered from the 1997 Fossil Fuel Electric Power Generation Sector Notebook (EPA,
1997c), which obtained data from EPA's Integrated Data for Enforcement Analysis (IDEA) database
system. Since the IDEA system accesses data through Standard Industrial Classification (SIC) codes,
information in the Sector Notebook deals only with those facilities whose primary SIC codes indicate the
potential for power generation activities.
A review of the compliance history of the industry in the 5 years from 1992 to 1997 indicates the
following:
Of the 3,270 facilities identified as power generators, approximately 66 percent (2,166)
were inspected during the 5-year period.
The 14,210 inspections conducted during the 5-year period lead to 403 facilities having 789
enforcement actions taken against them.
The sector had an average enforcement-action-to-inspection ratio of 0.06 during this 5-year
period.
A comparison with other sectors identified by the Sector Notebook project revealed the
following:
When compared to sectors with similar number of facilities, a much higher percentage of
facilities in the power generation sector were inspected during this 5-year period.
Moreover, the number of inspections during the 5 years for the fossil fuel electric power
generation sector is more than three times the number conducted in most other sectors.
The enforcement-action-to-inspection ratio of 0.06 during the 5-year period is one of the
lower rates of the listed sectors.
In addition, a comparison of the data across sectors by environmental statute indicates that both
inspections and enforcement actions at electric power facilities are driven by air regulations. The
majority of electric power facility inspections (57 percent) and enforcement actions (59 percent) are
under the Clean Air Act (CAA).
Lastly, the number of major environmental cases to affect the fossil fuel electric power industry
is small. Even though there were 789 total enforcement actions between 1992 and 1997, there were few
major cases involving fossil fuel electric power generation facilities. Since 1992, there have been at least
13 such actions. None of the cases were for violations of regulations directly related to the management
of solid or hazardous wastes. The 13 cases were broken out as follows:
Six cases under the CAA (emissions standards for asbestos, nitrogen oxide monitoring
violations, and sulfer dioxide violations)
Two cases under the Clean Water Act (CWA) (discharge permit violation, wetlands)
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Two cases under the Toxic Substances Control Act (TSCA) (polychlorinated biphenhyls, or
PCBs)
Two cases under the Emergency Planning and Community Right-to-Know Act (EPCRA)
(release in excess of reportable quantities)
One multimedia case (CWA, EPCRA, and TSCA).
The average penalty associated with these cases was more than $150,000.
The two most significant cases against fossil fuel electric power generation facilities included
CWA violations by Potomac Electric Power Company (PEPCO) and CAA violations by Public Service
Electric & Gas (PSE&G). In the PEPCO case, the violations occurred between 1988 and 1993, during
which time a site supervisor either pumped or oversaw the pumping of polluted water from holding
ponds into an adjacent swamp. PEPCO discovered the illegal discharge and informed EPA. The consent
decree provides for a penalty of $975,000. Because the violation was self-disclosed, no criminal charges
were brought against the company or its officers.
In United States v. Public Service Electric & Gas, PSE&G was charged with violating the CAA,
specifically the National Emissions Standards for Hazardous Air Pollutants (NESHAP) for asbestos. An
off-duty EPA inspector noticed a pile of old pipes in a yard. A subsequent inspection of the old gas-
cracking operation revealed the NESHAP violations. PSE&G was required to pay a civil penalty of
$230,000 and complete an extensive worker training and notification program.
3.4.5 Minefill Risks
EPA has found that operators may use or dispose of UCCWs in a variety of mining applications.
Ash has been used for surface mine reclamation, mine subsidence control, mine water management,
waste stabilization, and other applications. In addition, surface and underground mines have been used
for locating ash and/or sludge landfills. While currently available statistics indicate that beneficial use in
mine environments accounts for less than 2 percent of large volume wastes generated (ACAA, 1998),
EPA believes that mine use and disposal of FFC wastes may increase.
EPA believes that, under ideal circumstances, placement of wastes in mines should present no
increased risks to human health and the environment relative to conventional landfills. In fact, minefills
could result in net environmental benefits relative to conventional landfills through avoided development
of Greenfield space for UCCW disposal, improvement of disturbed mine lands through contouring,
revegetation and reduced infiltration to mine workings, and abatement of acid mine drainage through
neutralization and diversion. Both surface and underground minefills, however, may present existing or
potentially emerging conditions that are quite distinct from ideal landfill conditions with respect to
environmental risks. Some potential minefill conditions are introduced below.
Fractured flow. Many surface mines are characterized by underlying fractured
hydrogeologic formations that may permit channel flow of contaminated ground water.
Moreover, underground mines may present channels for mine water movement that extend
for miles. Fractured flow conditions present the possibility that contaminated ground water
can move considerable distances to reach potential receptors.
Acid mine drainage. Many coal mine environments, particularly in the eastern United
States, are impacted by acid mine drainage (AMD), in which sulfide minerals associated
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with the coal seam oxidize in the presence of air and water to produce sulfuric acid. The
resulting acidic leachate can mobilize constituents of concern from surrounding host rock.
Some mine reclamation projects rely on the available alkalinity of UCCWs to reduce the
potential for generation of acid from sulfide minerals in mine spoils. In other cases, the
hope is that alkaline UCCWs will neutralize mine waters already impacted by pyrite
oxidation. If the available alkalinity in UCCWs is consumed by AMD, however, continued
leaching may mobilize the constituents of the ash or sludge.
Intersection with ground water. Many surface and underground mines are completed
below the natural level of ground water surrounding the excavation. During active
operations, mine water must be pumped from the mine pit or void to allow access to the
resource. In such instances, mine water will flood the mine workings once active operations
cease. Some mine placement projects rely on the self-cementing or augmented cementing
properties of UCCWs to seal mine workings and limit mine water intrusion. Other projects
have demonstrated that, once placed, UCCWs may harden to form mine water diversions.
Placement of UCCWs in mines completed below the water table will result in inundation of
the wastes. Inundation may result in continued leaching of constituents of concern from the
wastes.
EPA intends to evaluate the risks associated with mine placement of FFC wastes. Gaps in
currently available information and modeling complications prevented EPA from completing its
evaluation of minefill risks for this report.
Case studies, when available, are preferable to modeling; however, EPA does not have detailed
case studies that present sufficient information to evaluate the performance of minefill projects. Many of
the sites for which the Agency does have information lack background characterization and well location
information such that pre- and post-placement conditions cannot be compared and conditions below the
fill cannot be related to the fill activities.
EPA currently lacks sufficient information to generalize about the background conditions at mine
sites. The potential transport of constituents of concern depends in part on the geochemical conditions of
receiving waters. Background pH plays an especially important role in precipitation/dissolution
chemistry as leachate enters ground water. EPA has demonstrated the sensitivity of EPACMTP to
changes in pH for some metals of concern; however, the Agency has insufficient information to
characterize the background conditions in ground waters at surface and underground coal mines.
Background characterization is especially important in minefill evaluation because many mine sites are
characterized by very poor existing ground-water quality, including low pH.
Another important consideration is depth to ground water. The depth to ground water can play
an important role in attenuating constituents of leachate released from waste management units. EPA is
aware that some states restrict the placement of UCCWs in beneficial use projects from placement within
some minimum distance above ground water. Most of the site-specific information that EPA has
obtained to date, however, does not indicate the depth to ground water.
EPA also has insufficient information on the design of actual minefill projects. The Agency has
reviewed limited technical information on a variety of minefill projects, but lacks sufficient information
to generalize about the size, depth, and environmental controls (e.g., liners, covers, monitoring)
characterizing minefill projects nationwide. EPA is aware that some operators amend existing mine
spoils with UCCWs in conjunction with reclamation plans. EPA is unaware of typical mixing ratios in
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such projects. Similarly, the Agency needs information about typical resulting permeability ranges for
combined ash and spoils or other fill materials.
Minefill scenarios present significant modeling challenges as well. First, EPACMTP does not
accommodate fractured flow conditions. As a result, underground and some surface mine situations
cannot be modeled using this tool. Further, EPA has not developed or identified a model suitable for
predicting the emergence of acid generating conditions within UCCW minefills. Of equal importance,
EPA has not identified a model suitable for predicting the consumption of alkalinity in UCCW materials
by AMD intrusion into the fill.
3.5 EXISTING REGULATORY CONTROLS
EPA's objective in this section was to identify and evaluate the existing regulatory controls that
pertain to the comanagement of UCCWs. The regulatory analysis is directed toward addressing the
question of whether existing regulations are adequately protecting human health and the environment.
The analysis also is helpful in understanding waste generation and current management practices.
The sections below discuss regulations addressing air pollution, water pollution, and solid and
hazardous waste, respectively. Air regulations are relevant primarily because of their effect on waste
generation. Water regulations have an influence both on waste generation and management and, in
particular, address the impact of UCCWs on surface waters. Solid and hazardous waste regulations are
of the greatest interest because they directly govern waste management practices.
The sections below describe federal regulations in each of these areas. In many cases, the
implementation of these federal programs is carried out by the states; therefore, where appropriate,
aspects of state implementation also are discussed. Because the nuances of state implementation are of
particular importance with respect to solid waste regulation, that section discusses state programs in
detail. Where appropriate, that section also describes state control on two beneficial uses of concern to
EPA: minefilling and soil amendment.
3.5.1 Regulations Addressing Air Pollution
The CAA is intended to protect and enhance the quality of the nation's air resources. The most
relevant of the CAA requirements include the following:
National Ambient Air Quality Standards (NAAQS) for particulate matter (PM)
NAAQS for sulfur dioxide
Title IV acid rain provisions
NAAQS for ozone
National Emissions Standards for Hazardous Air Pollutants (NESHAP).
Historically, CAA requirements have been a significant factor affecting the generation and
collection of certain large-volume UCCWs (specifically fly ash and FGD waste). Recent and
forthcoming changes in these requirements also may impact waste generation or characteristics, as
discussed below.
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NAAQS for Particulate Matter
The NAAQS for PM establish maximum concentrations of PM with diameter less than or equal
to 10 micrometers (PM10) in the ambient air. These standards are among the factors motivating the use
of particulate control technologies at coal-fired utilities. EPA recently proposed to lower the size
criterion to 2.5 micrometers, which may affect the volume of fly ash collected and selection of control
technology; however, final standards will not be issued for at least 5 years, so the impact of the new size
criterion is difficult to predict at this time.
The NAAQS for PM are implemented through New Source Performance Standards and State
Implementation Plans.
New Source Performance Standards (NSPS). The NSPS subject newly constructed or
modified units to specific PM emissions limits. These limits may be met by changing fuel types,
modifying combustion conditions, or installing control devices. The applicability of the NSPS and the
specific limits imposed vary with the age and size of the combustion unit, with older and smaller units
less likely to be subject to the NSPS. Specifically, the regulation of facilities can be considered in the
following four categories.
40 CFR 60 Subpart D governs the standards of performance for new fossil fuel-fired steam
generators that were constructed or underwent major modification after August 17, 1971.
Subpart D affects only units that are capable of burning fossil fuels at greater than 73
megawatts (MW) of heat input rate.
Subpart Da affects utility units with the capacity to fire fuel at greater than 73 MW heat
input rate that commenced production or major modification after September 18, 1978.
Subpart Db affects coal-fired units with the capacity to fire fuel at greater than 29 MW of
heat input rate that commenced construction or modification after June 19, 1984.
Subpart DC governs coal-fired units constructed or modified after June 9, 1989, with
capacity to fire fuel at less than 29 MW but greater than 8.7 MW of heat input rate.
Under the NSPS regulations, facilities that were in operation before the dates stated in each of
the four subparts are considered "grandfathered" and would not be subject to the newer standards, unless
they underwent a major modification.
State Implementation Plans (SIPs). The performance standards above can be enforced by a
federal, state, or local regulatory agency. There are additional CAA regulations that could require a coal-
fired unit to install a particulate removal device notwithstanding the grandfather clause in Subparts D,
Da, Db, and DC. SIPs may impose, on a state-by-state basis, PM controls of varying stringency on
specific sources or categories of sources, including coal-fired utilities. Such controls are required under
Title I of the CAA if a particular area is in nonattainment for the NAAQS for a criteria pollutant such as
PM. For this reason, SIP controls will generally be more stringent in such nonattainment areas. In
attainment areas, the prevention of significant deterioration (PSD) program requires new sources to apply
Best Available Control Technology (BACT), which must be at least as stringent as NSPS.
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NAAQS for Sulfur Dioxide and Title IV Acid Rain Requirements
Together, the NAAQS for sulfur dioxide and the Title IV Acid Rain Requirements are a factor in
the use of FGD technology at coal-fired utilities. Like the NAAQS for PM, the NAAQS for sulfur
dioxide establish a maximum concentration of sulfur dioxide in the ambient air. The NAAQS for sulfur
dioxide are implemented through NSPS and SIPs. The functioning and applicability of the sulfur dioxide
NSPS requirements are similar to those for PM, although there is less variation based on age and size.
Each of the four categories of coal-fired utilities regulated under Subparts D, Da, Db, and DC is
subject to the same requirement: sulfur dioxide emissions must be less than 520 nanograms per joule
(ng/J) of heat input. Facilities with greater than 22 MW of heat input capacity generally also must
achieve a 10 percent reduction in their sulfur dioxide emissions, based on the potential concentration in
fuel. An additional category of coal-fired facilities, those constructed or modified after June 9, 1989, and
between 2.9 and 8.7 MW heat input capacity, also must meet the 520 ng/J standard, but may do so based
on certification from the fuel supplier that the sulfur content of the fuel is low enough to meet the
standards.
In addition to NSPS, states may impose controls through their SIPs to meet the sulfur dioxide
NAAQS. These controls may vary in stringency depending on attainment status and may be placed on
specific sources or categories of sources, including coal-fired utilities.
The Title IV acid rain provisions provide additional impetus for the application of FGD
technology at coal-fired utilities. These provisions require specific reductions of sulfur dioxide
emissions via the following:
Installing FGD equipment
Switching to low sulfur fuel
Purchasing emissions allowances from other sources that have exceeded their reduction
requirements.
Affected sources are allowed complete flexibility in choosing among these options. The current
phase of the Title IV program affects several hundred of the largest generating units at utilities. Between
1992 and 1996, more than half of the affected facilities chose to switch to low sulfur coal in response to
the requirements; however, 16 utilities chose to install FGD equipment at 27 generating units accounting
for 14,101 MW of capacity (about 5 percent of 1997 utility coal-fired capacity) (EIA, 1997 f). This
decision contributed to the growth in generation of FGD waste during the period.
EPA is currently evaluating further requirements for lower sulfur dioxide standards and
emissions that could increase desulfurization waste generation and/or continue to increase the use of low
sulfur coal. EIA projects that an additional 26,400 MW of capacity (about 9 percent of 1997 capacity)
will be retrofit with FGD technology in response to the next phase of requirements (EIA, 1998a). FGD
waste generation would increase as a result of these retrofits.
NAAQS for Ozone
The NAAQS for ozone establish a maximum concentration of ozone in the ambient air. EPA
recently lowered this concentration from 0.12 ppm to 0.08 ppm. The new standard allows four
exceedences of the maximum in a region over a 3-year period. EPA expects states will meet the new
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standard by amending their SIPs to limit nitrogen oxide emissions at utilities. In proposing the new rule,
EPA published a Regulatory Impact Analysis (RIA) forecasting changes in the operating practices of
utilities that could result from these SIP modifications (EPA, 1997b).n As a result of the new regulations,
utilities are expected to invest in new combined cycle gas-fired units and oil- or gas-fired combustion
turbines rather than coal-fired plants to provide new capacity. Coal-fired capacity is not expected to
increase through 2010 (EPA, 1997b). EIA similarly predicts only limited additions to coal-fired capacity
through 2010 (EIA, 1998a). Therefore, utility generation of ash is expected to increase more slowly than
in the past, even with continued growth in the utility industry.
The RIA also estimates that some existing coal-fired plants will retrofit scrubbers to comply with
the regulations. This could result in an increase in FGD waste generation. Also, plants that add
scrubbers are expected to switch from low-sulfur Western coal to less expensive Eastern coal, which
could result in some changes in waste characteristics (EPA, 1997b).
NESHAP
Under the NESHAP, EPA is required to establish technology-based standards for 189 hazardous
air pollutants (HAPs). These standards are to be set on an industrial category basis and will apply to
facilities (major sources) that emit greater than 10 tons/year of any one HAP or greater than 25 tons/year
of any combination of HAPs.
EPA has studied HAP emissions from utility coal-fired steam generating units and found that
mercury from coal-fired utilities is the HAP of greatest concern. Dioxins and arsenic (primarily from
coal-fired plants) also are of potential concern. EPA has deferred any determination as to whether
regulations to control HAP emissions from utilities are appropriate and necessary. EPA is continuing to
collect data on mercury emissions from coal-fired plants (EPA, 1998c). If HAP regulations are
promulgated in the future, they could affect the characteristics or quantity of FFC solid wastes.
3.5.2 Regulations Addressing Water Pollution
Under the CWA, the National Pollutant Discharge Elimination System (NPDES) controls
discharges to waters of the United States. The controls required under NPDES affect the collection and
management of UCCWs. In states authorized by EPA, these controls are implemented through state
programs (often termed State Pollutant Discharge Elimination Systems, or SPDES). Because state
programs must be at least as stringent as the federal program, the discussion here focuses on federal
requirements as a lowest common denominator. NPDES requirements apply differently to two categories
of discharges: process wastewaters and stormwater runoff.
NPDES Requirements for Process Wastewaters
The NPDES requirements that apply to process wastewaters from coal-fired utilities are those for
the steam electric point source category under 40 CFR Part 423. These requirements apply to facilities
"primarily engaged in the generation of electricity for distribution and sale" (i.e., utilities). Under these
requirements, each discharge requires an individual NPDES permit with numeric limitations based on
Best Practicable Control Technology Currently Available (BPT), Best Available Technology
11 The RIA was based on a slightly more stringent ozone standard that allowed only three exceedences over
a 3-year period and also incorporated the impacts of proposed changes to the PM standard that have not yet been
finalized. Still, the general trends forecast by the RIA are expected to be valid for purposes of this analysis.
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Economically Achievable (BAT), or New Source Performance Standards (NSPS). Facilities that
discharge to publicly owned treatment works (POTWs) rather than directly to surface waters face
Pretreatment Standards for Existing Sources (PSES) similar to BAT or Pretreatment Standards for New
Sources (PSNS) similar to NSPS.
For the steam electric point source category, the NPDES process wastewater requirements most
relevant to collection and management of large-volume UCCWs are total suspended solids (TSS) limits
placed on fly ash handling and bottom ash handling waters. When these UCCWs are managed wet,
facilities may have to settle or otherwise remove a certain amount of UCCW from the handling water to
meet the TSS limits prior to discharge. Thus, the requirements control the direct release of fly ash and
bottom ash to surface waters. In addition, the NSPS include a zero discharge requirement for fly ash
handling water. As discussed in Section 3.3, this requirement may be partially responsible for the trend
toward dry ash management in newer units.
The NPDES requirements for process water also have elements that are relevant to low-volume
combustion wastes. These requirements include technology-based limits on the following waste streams:
all waste streams (PCBs and pH); all low-volume wastes (TSS and oil and grease); chemical metal
cleaning waste (TSS, oil and grease, copper, iron); once-through cooling water (chlorine); cooling tower
blowdown (chlorine, chromium, zinc, 126 priority pollutants); and coal pile runoff (TSS). These
requirements control the release of the indicated constituents from management units to surface waters.
To meet these limits, facilities may have to treat their low-volume wastes either prior to comanagement
or in the comanagement unit.
EPA has reserved NPDES limitations on non-chemical metal cleaning wastes and FGD waters
for future rulemakings. Future requirements may affect the characteristics of the low-volume wastes as
managed or of the combined wastes.
NPDES Requirements for Stormwater
NPDES Stormwater requirements apply to Stormwater runoff from FFC facilities (e.g., runoff
from operating areas, ash handling areas, waste management units). Facilities can meet these
requirements by including Stormwater in their individual NPDES permit or seeking coverage under a
general permit by submitting a Notice of Intent (NOI). When Stormwater discharges are covered under
an individual permit, control and monitoring requirements will be facility-specific, subject to the
judgment of the permit writer.
When covered by a general Stormwater permit, requirements include implementation of a
Stormwater pollution prevention plan, "reasonable and appropriate" control measures, and 1 or 2 years of
monitoring and reporting. No site visit by regulators is required under the general permit. Under the
general permit approach, coal-fired utilities have a great deal of flexibility in selecting appropriate
control measures for runoff that may have contacted large-volume CCWs. The general permit
requirements include recommended best management practices for Stormwater at steam electric facilities,
landfills, treatment works, and construction areas greater than 5 acres. The requirements are additive
across industrial sectors. For example, a utility with an onsite ash landfill must meet both steam electric
and landfill requirements.
Because the Stormwater program is relatively new and managed only by authorized NPDES
states, the number of facilities with general versus individual permits is not known. EPA handles NOIs
for 10 nonauthorized states. In these states, 700 steam electric facilities (including non-utility
combustors) have filed for general permits.
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3.5.3 Regulations Addressing Solid and Hazardous Waste
EPA regulates the management of solid and hazardous waste through Subtitles C and D of
RCRA. Subtitle C of RCRA establishes a "cradle-to-grave" management system for wastes that are
considered hazardous because they fail tests based on physical and chemical characteristics (i.e., toxicity,
corrosivity, ignitability, and reactivity) or because they are listed as hazardous by EPA. Federal
regulations establish stringent environmental and administrative controls that must be applied to
management of these wastes. Coal-fired utility comanaged wastes are currently exempt from federal
regulation as hazardous waste under Subtitle C pending this Report to Congress and the subsequent
regulatory determination. Therefore, these wastes are subject to the requirements of Subtitle D of the
RCRA as nonhazardous solid waste.
Implementation of Subtitle D is the responsibility of individual states, but nothing prevents states
from imposing stringent requirements (including hazardous waste requirements) on FFC wastes.
Currently, 44 states (representing 96 percent of utility coal-fired generating capacity) duplicate the
federal policy exempting UCCWs from hazardous waste regulations. The other six states (Kentucky,
Tennessee, Washington, New Jersey, Maine, and California) do not exempt UCCWs from hazardous
waste regulation. In these states, any UCCWs that fail the hazardous waste characteristic tests would be
subject to state hazardous waste requirements and managed in units that meet permitting, design,
operating, corrective action, and closure standards.
As discussed in Section 3.2, UCCWs seldom fail the hazardous waste characteristic tests.
Therefore, the majority of UCCWs would be subject to state requirements under Subtitle D because they
do not fail the hazardous waste characteristic tests and/or are generated in the 44 states that duplicate the
federal exemption. The 1988 Report to Congress presented data on such state regulations from a 1983
Utility Solid Waste Activities Group survey. Under 1983 regulations, most states required permits for
landfills managing UCCWs, at least on a case-by-case basis; however, a smaller percentage of states had
the authority to impose physical controls or monitoring requirements on these landfills (see Table 3-23).
The 1988 Report to Congress also found that state regulations only "indirectly addressed" waste
management in surface impoundments.
More recent data (CIBO, 1997c; EPA, 1995b; ASTSWMO, 1995; ACAA, 1996a) show that the
majority of states now have authority to impose physical controls and monitoring requirements on
UCCW landfills, at least on a case-by-case basis. Table 3-23 compares state regulatory authority with
respect to UCCW landfills reported in the 1988 Report to Congress to current data. Table 3-24 shows
data on current state regulatory authority with respect to surface impoundments. No earlier data
comparable to that for landfills in the 1988 Report to Congress was available for surface impoundments.
Comparing current regulations for surface impoundments with those for landfills, the percentage of states
with at least case-by-case regulatory authority is similar for both types of units; however, EPA's
examination of case study states, discussed below, found that when states impose requirements on
impoundments, they typically do so on a case-by-case basis.
The data in Tables 3-23 and 3-24 show that states currently have more authority to impose
controls on UCCW management units than in previous years. In addition to regulatory permits, the
majority of states are now able to require siting controls, liners, leachate collection systems, ground-
water monitoring, closure controls, daily (or other operational) cover, and fugitive dust controls. EPA
believes that the use of such controls has the potential to mitigate risks, particularly ground-water
pathway risks, from comanaged waste disposal. The adequacy of this mitigation depends on the extent to
which states are exercising their authority in situations in which climate, geology, site-specific
conditions, and waste characteristics justify it.
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Table 3-23. State Regulatory Controls on UCCW Landfills
HW Exemption3
Permit Onsite
Permit Offsite
Siting Controls
Liner
Leachate Collection Systems
Ground-Water Monitoring
Closure Controls
Cover and/or Dust Controls
1988 Report to Congress
Number of
States"
43
41
49
30
11
20
28
27
Percent of
States0
86%
82%
98%
60%
22%
40%
56%
54%
Percent of
Capacity
88%
75%
94%
54%
24%
31%
60%
59%
Not surveyed
Current
Number of
Statesb
44
41
48
46
43
42
46
45
49
Percent of
States0
88%
82%
96%
96%
86%
84%
92%
90%
98%
Percent of
Capacity
96%
77%
95%
92%
87%
79%
89%
91%
96%
a Exemption from state hazardous waste regulations for CCWs
b Number of states with authority to impose the indicated requirement, either by regulation or on a case-by-case basis
c Percent of surveyed states with authority
d Percent of surveyed utility generating capacity represented by states with authority
Sources: EPA, 1988; CIBO, 1997c; ASTSWMO, 1995; EPA, 1995b; and ACAA, 1996a
Table 3-24. Current State Regulatory Controls on CCW Surface Impoundments
Hazardous Waste
Hazardous Waste Exemption3
Permit Onsite
Permit Offsite
Siting Controls
Liner
Leachate Collection Systems
Ground-Water Monitoring
Closure Controls
Number of States"
44
45
45
41
45
33
44
43
Percent of States0
88%
92%
94%
87%
92%
73%
96%
91%
Percent of Capacity
96%
87%
88%
81%
91%
68%
94%
88%
a Exemption from state hazardous waste regulations for CCWs
b Number of states with authority to impose the indicated requirement, either by regulation or on a case-by-case basis
c Percent of surveyed states with authority
d Percent of surveyed utility generating capacity represented by states with authority
Note: No earlier base year data (similar to that from the 1988 Report to Congress for landfills) were available for surface impoundments.
Sources: CIBO, 1997c; ASTSWMO, 1995; ACAA, 1996a
Section 3.3 of this report found that nearly all of the active UCCW comanagement landfills
surveyed are subject to regulatory permits and ground-water monitoring requirements. Just more than
half of the surveyed landfills are lined and just under half have leachate collection systems. A lesser
percentage of active UCCW comanagement surface impoundments have similar controls. These
statistics suggest that states have exercised their authority to impose controls at landfills, and to a lesser
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extent at surface impoundments. Furthermore, Section 3.3 found increasing trends in the use of liners
and ground-water monitoring at newer units, both landfills and surface impoundments. This finding
suggests that states are increasingly applying their regulatory authority as new units are introduced. To
further examine state implementation of solid waste requirements on UCCW comanagement units, EPA
examined in greater detail the regulations applicable in five states: Indiana, Pennsylvania, North
Carolina, Wisconsin, and Virginia. These five states account for almost 20 percent of coal-fired utility
electrical generation capacity. Table 3-25 summarizes the requirements in each of these five states.
Table 3-25. State Waste Management Requirements Applicable to UCCWs
in Selected States
Indiana
Landfill
Requirements
Impoundment
Requirements
Grandfather
Clause
Landfills are classified according to TCLP results for the wastes to be disposed. Specific design
requirements depend on the class of the landfill. Based on available characterization data, most
comanaged wastes would be subject to Type III landfill requirements. Requirements for these include
clay liner (thickness of 3 feet), siting restrictions, fugitive dust control, weekly cover, soil erosion control,
2-foot clay cap at closure, and revegetation at closure. Leachate collection systems are not required
but may be used in some cases to relax the liner thickness requirements. Type 1 and II landfill
requirements are more stringent. Type IV landfills, with less stringent requirements, may receive
wastes with leachate concentrations below MCLs.
Regulations do not dictate any specific design, operating, or ground-water monitoring requirements.
Requirements may be imposed on a case-by-case basis in individual permits.
Facilities that existed prior to September 1989 may continue to operate, but any expansions at these
facilities must comply with the requirements above.
Pennsylvania
Landfill
Requirements
Impoundment
Requirements
Grandfather
Clause
Minefill
Requirements
Soil Amendment
Requirements
Landfills are classified according to TCLP results for the wastes to be disposed. Specific design
requirements depend on the class of the landfill. Based on available characterization data, most
comanaged wastes would be amenable to Class III landfills. Requirements for these include siting
restrictions, a 4-foot attenuating soil base (or 1 foot per 4 feet of waste), fugitive dust control, daily
cover, soil erosion control, ground-water monitoring, 2-foot clay cap at closure, and revegetation at
closure. Class I and II landfill requirements are more stringent.
Surface impoundments (including those that store waste for less than 1 year) are classified according
to TCLP results for the wastes to be disposed. Specific design requirements depend on the class of
the impoundment. Based on available characterization data, most comanaged wastes would be
subject to Class II requirements. Requirements for these include siting restrictions, composite liner,
leachate detection system, leachate collection system, minimum freeboard requirements, structural
integrity requirements, ground-water monitoring, 2-foot clay cap at closure, and revegetation at closure.
Units permitted prior to July 4, 1992, were required to modify their operations to comply with the above
requirements by July 4, 1997. Liner and leachate collection requirements may be modified if the
operator could demonstrate that the unit had not caused unacceptable ground-water degradation.
UCCWs must meet TCLP limits for disposal at a Class III landfill. Ground-water monitoring is required.
UCCWs must meet pH limits. State agency notification and runoff and erosion controls required.
There are siting limitations.
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North Carolina
Landfill
Requirements
Impoundment
Requirements
Grandfather
Clause
Industrial waste landfills must demonstrate that their design will ensure that the state ground-water
standards are not exceeded at the compliance boundary. The design criteria for demonstrating this
include a composite liner, leachate collection system, and cap at closure. Alternatively, the operator
may submit ground-water modeling results that demonstrate, based on hydrologic and climatic
conditions and waste characteristics, that the standards will be met.
Regulations do not dictate any specific design, operating, or ground-water monitoring requirements.
Requirements may be imposed on a case-by-case basis in individual permits.
To continue operating after January 1 , 1 998, landfills operating prior to October 1 , 1 995, must
demonstrate that their original design or proposed design changes will meet the ground-water
standards. State has the authority to require design modifications if ground-water modeling methods or
results are inadequate.
Wisconsin
Landfill
Requirements
Impoundment
Requirements
Grandfather
Clause
Requirements include clay or composite liners, leachate collection systems, fugitive dust controls,
2-foot clay cap at closure, revegetation at closure, and ground-water monitoring. State may modify the
requirements for landfills designed to receive "high-volume" industrial waste, specifically coal ash
waste, on a case-by-case basis.
Surface impoundments must meet siting requirements and have leachate collection systems and liners,
unless an exemption is granted by the state. Ground-water monitoring of surface impoundments is
optional.
Landfills with plan of operations approved prior to July 1, 1996, are exempt from liner and leachate
collection requirements. For landfills constructed prior to February 1, 1988, the state may require
ground-water monitoring on a case-by-case basis.
Virginia
Landfill
Requirements
Impoundment
Requirements
Grandfather
Clause
Minefill
Requirements
Soil Amendment
Requirements
For comanaged wastes, industrial landfills must characterize the wastes entering the unit and submit
and abide by a management plan for commingling the wastes. Design requirements include leachate
collection systems, run-on controls, liner (1 foot of compacted clay or equivalent), cap at closure,
fugitive dust controls, ground-water monitoring. A double liner system in which the primary liner is
synthetic may be used in lieu of ground-water monitoring. For fly ash and bottom ash from the
combustion of fossil fuels, periodic cover or dust control measures such as surface wetting or crusting
agents are required. Industrial landfills must conduct ground-water monitoring.
Monitoring required. No other specific design or operating requirements. Requirements may be
imposed on a case-by-case basis in individual permits. Impoundments may be closed with waste in
place only if the closure requirements are established in the facility's permit. Otherwise, regulations
require (1) removal of all liquids, wastes, and system components at closure, or (2) stabilization of
remaining wastes, installation of a cover, and post-closure ground-water monitoring.
Landfills permitted prior to 1988 must submit a monitoring plan but may continue operating without
retrofits as long as they do not expand.
Use in structural fills, mine reclamation, or mine refuse disposal requires notification and development
of design, operation, and closure plans. UCCWs thus used must not exceed the toxicity characteristic
levels for metals. Fugitive dust and run-on and runoff controls and 18 inches of cover at closure
required.
Agricultural uses of CCW are exempt from the solid waste regulations provided they meet the
requirements of the Virginia Department of Agriculture and Consumer Services.
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Based on this analysis, it appears that state requirements have become increasingly stringent over
time. States vary in their approaches to regulating UCCW landfills. For example, the Indiana and
Pennsylvania programs impose requirements tailored to the characteristics of the waste. North Carolina
may impose requirements based on site-specific modeling. In Virginia, requirements apply generically to
all industrial wastes. Wisconsin may modify its requirements specifically for landfills designed to
receive coal combustion ash. In several of the states studied, UCCWs may be disposed of in landfills that
are "grandfathered" out of requirements imposing design requirements such as liners. Regulations in
many of the states studied do not impose specific design requirements on surface impoundments that
comanage UCCWs. When these states impose requirements on impoundments, they typically do so on a
case-by-case basis.
3.6 WASTE MANAGEMENT ALTERNATIVES
Comanaged Wastes in General
The risk assessment in Section 3.4 identified potential ground-water pathway risks to human
health from comanaged waste in unlined management units. Mitigation of these potential risks might be
accomplished through the use of technologies that prevent or contain and collect leachate from
comanaged waste landfills and surface impoundments. Specifically, EPA identified the combination of
technologies in Table 3-26 as an alternative that would be practical and effective to target and mitigate
the potential ground-water risk. The technologies identified in the table are considered further in the cost
and economic impact analysis. These technologies also are consistent with those required under
Subtitle D of RCRA. Other risk mitigation approaches (not considered in Section 3.7) might incorporate
different design and operating standards for existing landfills and surface impoundments different from
those established for new landfills and surface impoundments containing the same wastes. Also, such
approaches might include an exemption for certain units that can demonstrate they pose no threat to
human health or the environment. For example, when EPA implemented design-based standards for
Subtitle C hazardous waste surface impoundments, an exemption was allowed for certain surface
impoundments, provided that these impoundments could demonstrate that alternative design and
operating practices, together with location characteristics, would prevent the migration of hazardous
constituents into ground or surface water at least as effectively as liners and leachate collection systems.
Comanaged Mill Rejects/Pyrites
Coal mill rejects (and particularly their pyrite component) have been identified as a low-volume
waste of particular concern (see Sections 3.1, 3.2, and 3.4.3). Because EPA currently is evaluating
voluntary industry guidance for mill rejects management, alternatives for this waste stream are not
evaluated here.
Agricultural Use and Minefilling
Of the beneficial uses discussed in Section 3.3.5, agricultural use may be of environmental
concern, based on the non-ground-water risk assessment that found potential arsenic risks to human
health from this practice. An approach for mitigating this potential risk might include a standard limiting
the arsenic concentration in wastes intended for this use. Because of the small quantity of waste that
would be affected by such an alternative, EPA has not estimated cost for such an approach. Minefilling
also may be of concern, particularly when wastes are placed below the water table. EPA is seeking
further information on this practice.
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Table 3-26. Management Alternatives for Coal-Fired Utility Comanaged Waste and
Segregated Mill Rejects
Landfill
Impoundment
Comanaged Waste
Design includes filter fabric, 1' sand layer, 2' clay liner,
synthetic liner (high-density polyethelene [HOPE]), leachate
collection system, and ground-water wells.
Operation includes environmental monitoring, leachate
collection and treatment.
Closure requirements include 6" topsoil and vegetation, filter
fabric, 1.5' sand layer, 2' clay layer, synthetic liner, and a
cover drainage system.
Post-closure includes environmental monitoring, landscape
maintenance, slope maintenance, inspection, and
administration.
Design includes filter fabric, 1' sand layer, 2' clay liner,
synthetic (HOPE) liner, leachate collection system, and
ground-water wells.
Operation includes environmental monitoring, leachate
collection and treatment.
Closure requirements include 6" topsoil and vegetation, filter
fabric, 1.5' sand layer, 2' clay layer, synthetic (HOPE) liner,
added fill to achieve slope, and cover a drainage system.
Post-closure includes environmental monitoring, landscape
maintenance, slope maintenance, inspection, and
administration.
3.7 COMPLIANCE COSTS AND ECONOMIC IMPACTS
This section discusses the costs and economic impacts of risk mitigation alternatives for coal-
fired utility comanaged wastes. Details of this analysis, together with a background describing this
complex industry, are documented as part of the EPA docket.
3.7.1 Overview and Methodology
In estimating costs and economic impacts for comanaged waste at coal-fired utilities, EPA relied
on the descriptive information for this sector presented previously in this chapter. Salient features are
reviewed below. It is important to bear in mind as these costs and impacts are reviewed that this industry
is large, generating more than $200 billion in sales annually.
EPA's analysis began with the 353 coal-fired plants identified in the 1993 U.S. Department of
Energy (DOE) Energy Information Administration (EIA) 767 database that have electrical generation
capacities of at least 10 MW. This was supplemented by data (e.g., the frequency of comanagement, the
frequency of landfills and impoundments, waste generation rates) provided by the industry and discussed
in previous sections of this chapter. The Agency recognizes that there are uncertainties in working with a
database of this magnitude; the cost uncertainty discussed below reflects this.
EPA estimated the incremental compliance cost of the risk mitigation alternative for comanaged
waste described in Section 3.6.12 As described in that section, this requires generators to construct
composite-lined landfills and impoundments for comanaged wastes. The cost estimate summed the costs
of five categories: initial capital costs, recurring capital costs, annual operating and maintenance costs,
closure costs, and annual post-closure costs. Table 3-27 identifies the specific components included in
each cost category.
12 Because the Agency currently is evaluating a voluntary industry proposal for mill reject management,
costs for mill rejects alternatives are not considered here.
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Table 3-27. Cost Components Included in Landfill and Impoundment Designs
Category
Initial Capital Costs
Recurring Capital Costs (5-yrs)
Annual O&M Costs
Closure Costs
Annual Post-Closure Costs
Landfill Cost Components
Land purchase
Site development
Excavation
Filter fabric
1 ' sand
2' clay liner
Synthetic (HOPE) liner
Leachate collection
Ground-water wells
Indirect capital costs
Heavy equipment (dump truck, bulldozer,
sheepsfoot roller, water truck)
Indirect capital costs
Heavy equipment operation
Environmental monitoring
Leachate collection and treatment
6" topsoil and vegetation
Filter fabric
1.5' sand
2' clay
Synthetic (HOPE) liner
Cover drainage system
Indirect closure costs
Environmental monitoring
Landscape maintenance
Slope maintenance
Inspection
Administration
Impoundment Cost Components
Land purchase
Site development
Excavation
Filter fabric
1 ' sand
2' clay liner
Synthetic (HOPE) liner
Leachate collection
Ground-water wells
Indirect capital costs
Not applicable
Environmental monitoring
Leachate collection and treatment
6" topsoil and vegetation
Filter fabric
1.5' sand
2' clay
Synthetic (HOPE) liner
Added fill to achieve slope
Cover drainage system
Indirect closure costs
Environmental monitoring
Landscape maintenance
Slope maintenance
Inspection
Administration
For these comanaged utility wastes, the cost estimate was based on opening new management
units to replace existing landfills and impoundments that currently do not meet the requirements
described in Section 3.6. Because of this, the estimate included the costs of the purchase of land to site
new units where required.
Variations on this approach might substantially reduce the total costs incurred. For example,
EPA might allow existing impoundments to be used as is for a period (say, 10 years) and only then
drained, dredged, and lined in place. Such approaches would reduce the total (discounted) compliance
cost by both deferring cost and reducing the number of units above baseline to be lined. The Agency has
not yet estimated the cost of such variations, but anticipates a significant reduction below the $800 to
$900 million annual total shown below (possibly by some 50 percent).
The cost estimate utilized unit cost data from engineering cost literature and vendor quotation
to develop costs for three different landfill and impoundment sizes. The three sizes were defined to
characterize the range of management unit sizes (i.e., capacity, area, depth) observed in practice.
Table 3-28 provides insight into design features that underlie this costing.
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Table 3-28. Design Parameters Assumed for Small, Medium, and Large
Landfills and Impoundments
Parameter
Sizes small
(tons/year) medium
large
Depth
(feet) small
medium
large
small
medium
large
Height
(feet) small
medium
large
small
medium
large
Area
(acres) small
medium
large
small
medium
large
Landfill
9,650
96,500
965,000
Pile design
1.0
1.0
3.0
Combination fill design
10.0
31.0
58.6
Pile design
25.0
30.5
79.4
Combination fill design
14.8
40.5
79.4
Pile design
13.5
239.1
479.2
Combination fill design
13.0
44.1
228
Impoundment
7,220
72,200
722,000
10.0
20.0
20.0
0
0
0
21.4
106.3
1,023
Note: Landfill designs considered include a "pile design" constructed primarily above grade and a "combination fill design" constructed both
above and below grade.
Using regression analysis, these were converted to data supporting a single cost equation.
Annualized costs were then estimated as a function of waste generation rate on a plant-specific basis.
Total industry costs were derived by summing the plant-specific cost estimates derived for the 353
identified coal-fired plants.
Using the methodology described above, the Agency developed costs and economic impacts as
set forth in the following three sections: incremental compliance cost, compliance cost impact on plants
as a function of plant size, and industry impact. Incremental compliance costs are the costs of risk
mitigation practices over and above the cost of current management practices. (Thus, for those facilities
currently meeting the requirements described in Section 3.6, incremental costs are zero.) Using
incremental compliance costs as an indicator of potential cost burden, the analysis examined impacts on
individual plants as a function of plant size. This was performed using pro forma financial statements for
three representative plant sizes as a basis against which to compare incremental compliance costs. For
industry impact evaluation, the use of econometric models to perform the analysis was considered and
rejected. The primary reason for this was that partial equilibrium analysis at this time would imply a
level of precision that cannot be supported, given the uncertainty surrounding ongoing deregulation of
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the industry. The industry-level analysis thus focuses on two measurements to assess economic impact:
the number of affected facilities and the magnitude of incremental compliance costs relative to the value
of electricity sales. These are used to build to an indication of the effect on supply and demand
relationships and possible impact on price.
3.7.2 Incremental Compliance Cost
Key variables in estimating incremental compliance cost were the number of affected plants,
current management practices (i.e., the number currently meeting the requirements described in
Section 3.6), estimated waste generation quantities, and costs of key components (e.g., liners). All of
the estimates shown assume a 40-year operating life for management units.
EPA's estimate of incremental compliance cost is some $860 million per year, using the most
likely values for all the input variables. If all variables were to combine at either the high or low end, a
much wider range of incremental compliance cost would result. It is EPA's judgment, however, that the
likely range would be $800 to $900 million per year, based on reasonable estimates of uncertainty in the
input variables and the low probability that all variables would combine at either their high- or low-end
values.
In the estimates above, liner construction accounts for most of the estimated cost. Liner
construction costs are driven by the area to be covered, which makes the incremental unit costs for
impoundments higher because of their large area-to-depth ratio. Also, the smaller percentage of
impoundments currently estimated to be lined (see Section 3.3.4) increases the total incremental cost for
impoundments.
Note that the costs above are incremental (above current costs). Annual costs were discounted at
7 percent to 1998 dollars based on Office of Management and Budget (OMB) guidance, with no inflation
built into out-year estimates. Also, it was presumed that compliance would be required immediately, and
that amortization would take place over 40 years for both landfills and impoundments.
3.7.3 Compliance Cost Impact on Plants as a Function of Plant Size
A full analysis of the potential for deregulation to affect this analysis was considered but not
undertaken because of resource limitations and the high degree of uncertainty associated with
deregulation. EPA recognizes that such an analysis might show impacts different from those presented
below.
EPA believes that the ability of industry to pass through cost increases will be limited for two
general reasons. First, large portions of the electric power generation industry would not be directly
affected (e.g., nuclear power plants) and thus opportunities to pass on costs will be limited. Second, the
electric utility industry is rapidly changing from a regulated, regional market structure to an open and
presumably competitive multiregional (if not national) market. This may reduce the potential to pass on
increased costs. Therefore, this analysis includes no analytical consideration of price effects.
Economic impacts at the plant level will depend on several major factors, including quantity of
fuel used, quality of fuel, profitability, and production technology. To assess these impacts across the
range of plants, EPA estimated financial data for model plants representing three size ranges: large
(burning greater than 1.5-million tons of coal per year), medium (burning between 750,000 and 1.5-
million tons of coal per year), and small (burning less than 750,000 tons of coal per year). The large and
medium model facilities are representative of investor-owned utilities and the small facility is more
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representative of a publicly owned utility. Table 3-29 compares incremental compliance costs to
revenues and net income for these three model plants. The incremental compliance costs used in this
analysis reflect EPA's best estimate based on most likely values of the relevant input variables.
Table 3-29. Plant-Level Impact of Incremental Compliance Costs
Revenues from Electricity
Baseline Before Tax Net Income
Expected Incremental Compliance Costs
(replace unlined management unit with
composite-lined unit)
Expected Post-Compliance Net Income
Large Coal Plant
Investor-Owned Utility
$1,000's
426,000
55,380
6,165
49,215
Percent of
Revenues
100%
13.0%
1.5%
77.5%
Medium Coal Plant
Investor-Owned Utility
$1,000's
142,000
18,400
2,197
16,203
Percent of
Revenues
100%
13.0%
1.6%
77.4%
Small Coal Plant
Publicly Owned Utility
$1,000's
60,000
5,400
1,285
4,115
Percent of
Revenues
100%
9.0%
2.1%
6.9%
The incremental compliance cost for comanaged wastes should not impact the financial viability
of coal-fired plants. This appears true even for plants transitioning from the worst case unlined
management unit to a composite-lined unit. For example, a large, investor-owned utility (IOU) coal-fired
plant with more than 1,000 MW of generating capacity is estimated to comply for about $6.16 million per
year (or about $16 per ton of waste). Based on typical annual revenues and cost, compliance costs would
increase overall costs by 1.5 percent of revenues. Without any price adjustments, net income before
taxes for this investor-owned plant would be reduced from about 13 to 11.5 percent and remain at more
than $49 million per year. EPA recognizes that such profit margin reductions may be considered
significant by the individual utility.
Financial impacts on a medium-sized IOU coal-fired plant with about 370 MW of generating
capacity suggest it should also remain financially viable. Costs would increase by about 1.6 percent of
revenues, with profitability (before tax) at about 11.4 percent of revenue, with net income after
compliance of more than $16 million per year. (Incremental compliance costs are estimated at about
18.31 per ton of comanaged waste, or about $2.2 million per year.)
Because of higher unit compliance costs and lower net income margins, smaller, publicly owned
coal-fired plants would incur relatively higher impacts. For example, an average small publicly owned
plant with about 180 MW of capacity is estimated to comply for about $1.3 million per year (about
$25.70 per ton of comanaged waste). Based on typical revenues and costs, compliance costs for a small
coal-fired utility would increase overall costs about 2.1 percent. This would reduce net income, without
price adjustments, from about 9 percent to 6.9 percent of revenue, or to about $4 million per year.
Table 3-30 shows how the estimated population of affected facilities breaks down by the three
size categories represented by the model plants. It also compares the incremental compliance costs
estimated for the model plants to average sales for individual plants in each size category. As noted
above, incremental compliance costs range from 1.5 percent of sales for large plants to 2.1 percent of
sales for small plants.
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Table 3-30. Incremental Compliance Cost by Plant Size
Size Category
Large (>1 .5-million tons/year of coal)
Medium (750,000 to 1 .5-million tons/year of coal)
Small (<750,00 tons/year of coal)
Number
of Plants
148
61
144
Percent
of Plants
42%
17%
41%
Plant Sales
($million/year)
$426
$142
$60
Compliance Cost
($million/year)
$6.2
$2.2
$1.3
Percent
of Sales
1.5%
1.6%
2.1%
3.7.4 Industry Impacts
As noted, the U.S. electric power industry is entering an era of major restructuring. Given the
uncertainty surrounding this restructuring, the use of econometric models to perform the industry impact
analysis was rejected. Partial equilibrium analysis at this time would imply a level of precision that
cannot be supported, given the uncertainty surrounding ongoing deregulation of the industry. The total
cost of compliance compared to total industry sales, however, should still serve as a good proxy for
estimating industry effects.
The electric power generating industry, including fossil fuel, hydroelectric, nuclear, and other
fuel sources, was a $212 billion per year industry in 1996. To provide perspective on the possible
incidence of compliance cost, the following characteristics of the electric utility industry are noted:
An average price to consumers of 6.86 cents per kilowatt hour (kWh) in 1996, which can
vary from less than 3 cents per kWh for industrial customers of a federal utility to more than
15 cents per kWh for residential customers of a northeastern investor-owned utility
Annual electricity consumption of 3,120 billion kWh (1997) or 11,860 kWh per capita
Approximately 3,200 entities selling electricity with industry ownership, including the
following:
- 243 investor-owned utilities (7.6 percent of all utilities) producing 76 percent of U.S.
electricity sales (2,343 billion kWh and $167 billion or $687 million per entity)
- 2,014 smaller public utilities (mainly municipalities and other local government entities
and 63 percent of all utilities) producing only 14.5 percent of the electricity sales (451
billion kWh and $27 billion or $ 13 million per entity)
- 932 cooperatives (29 percent of all utilities) producing 8 percent of industry sales (241
billion kWh and $17 billion or $18 million per entity)
- 10 federal utilities (0.3 percent of all utilities) accounting for 0.6 percent of electricity
sales (50 billion kWh and $1.3 billion or $130 million per federal utility)
Increasing trends in the use of coal and declining trends in the use of oil, as discussed in
Chapter 2 of this report.
Based on the best estimate of costs presented above, the electric utility industry would incur
about $860 million in incremental annualized compliance costs. As shown in Table 3-31, this would
represent 0.4 percent of the industry's value of shipments. It would be concentrated in the coal-fired
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utility component, which accounts for about 56 percent of all electricity generated in the United States.
Individual operators likely would take this effect into consideration, along with several other factors, in
assessing how soon to close marginal coal plants and what type of new plants to build. This implies that
a possible effect of the identified risk mitigation alternative would be a shift to alternative energy
sources.
Table 3-31. Industry Economic Impacts, Coal-Fired Utility Comanaged Wastes
Industry Sales ($ million/year)
$212,000
Compliance Cost ($ million/year)
$862.4
Percent of Sales
0.4%
The high cost of compliance reflecting this mitigation action is but a very small percentage of
revenues. If, as noted at the start of Section 3.7, above, a risk mitigation strategy embodying allowance
for continuing but phased-down utilization of existing impoundments and landfills is considered, this
percentage of revenues would be driven even lower; perhaps down to as low as 0.2.
Coal-fired plants might attempt to pass costs to consumers in the form of higher prices. This
would be restricted by competition from unaffected plants (i.e., hydroelectric and nuclear). Investor-
owned utilities, representing only about 8 percent of utility operators, would be the major determinants of
price effects as they control about 80 percent of electric energy sales (as well as the majority of large
coal-fired plants). Investor-owned utilities also are merging and consolidating operations rapidly and
will be the primary players in a more open and national electricity market.
3.8 FINDINGS AND RECOMMENDATIONS
3.8.1 Introduction
Based on the information collected for this Report to Congress, this section presents a summary
of the Agency's main findings presented under headings that parallel the organization of this chapter. It
then presents the Agency's tentative conclusions concerning the disposal and beneficial uses of
comanaged wastes generated at coal-fired utilities, including wastes from the burning of petroleum coke
and the coburning of other fuels with coal as identified in this chapter.
3.8.2 Findings
Sector Profile
There are about 450 coal-fired power plants located throughout the United States. Most
states have at least one coal fired utility plant. The eastern United States has a larger
concentration of plants than the western United States.
There are approximately 1,250 coal-burning boilers in operation at coal-fired power plants.
A particular plant can have multiple boiler (generating) units.
Coal-fired power plants account for more than 50 percent of the electricity produced in the
United States. There is a wide range of electrical generating capacity represented in the
population of power plants. Coal-fired plants can range in size from less than 50 megawatts
(MW) to more than 3,000 MW. The amount of wastes generated at these plants is generally
proportional to the amount of electricity generated.
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Coal-fired power plants are located in diverse environments. Power plants are located in
areas that vary widely in population density, geography, precipitation, and general climate.
Two common factors in siting coal-fired plants are (1) location near a major body of surface
water, such as a lake or river as a source of cooling water, and (2) locating to accommodate
economical transport of the large amounts of coal required to generate electricity.
Waste Generation and Characteristics
About 105-million tons of large volume coal combustion wastes (i.e., fly ash, bottom ash,
boiler slag, flue gas desulfurization [FGD] sludge) are generated annually at coal-fired
power plants.
Utilities generate a variety of low-volume wastes that result from supporting processes that
are ancillary to, but a necessary part of, the combustion and power generation process.
Examples include coal pile runoff, boiler blowdown, and boiler chemical cleaning wastes.
The total amount of the numerous low-volume wastes generated at these plants is not well
established, but estimates vary from less than one-half to several times the amount of large-
volume wastes. Most of the low-volume wastes are aqueous. Water comprises a substantial
portion of the aqueous low-volume wastes.
The constituents of concern in the large-volume wastes are trace elements, metals in
general, and the eight RCRA metals in particular. No organic constituents, including
dioxins, and no radionuclides were identified at potential levels of concern in these wastes.
The large-volume and low-volume wastes are managed in many different combinations.
Metals are the only class of constituents of concern in the comanaged wastes.
A few of the individual low-volume wastes, such as boiler chemical cleaning wastes and
demineralizer regenerant, occasionally test as characteristically hazardous for toxicity
and/or corrosivity; however, none of the comanaged waste mixtures tested characteristically
hazardous for corrosivity, reactivity, or ignitability. There were no toxicity characteristic
exceedences observed in TCLP samples of comanaged wastes, although there were
infrequent exceedences observed in some in situ pore water samples.
Waste Management Practices
An estimated minimum of 80 percent of the large-volume wastes are comanaged with low-
volume wastes. (The comanaged wastes are the subject of this chapter.)
The most frequent industry practice for comanaged wastes is disposal in landfills or surface
impoundments. There are approximately 600 of these waste management units serving coal-
burning power plants, with nearly equal numbers of landfills and impoundments. Most
impoundments and about half of the landfills are located at the generating site.
The waste management units are large in scale, typically 60 acres for a landfill and 90 acres
for an impoundment. There is an increasing industry trend to use landfills instead of
impoundments for disposal, due partly to Clean Water Act new source regulations that
encourage dry handling of fly ash by setting a zero wastewater pollutant discharge standard.
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The utility sector in recent years has increasingly installed more environmental controls for
comanaged waste facilities. Prior to 1975, fewer than 20 percent of the waste management
units (landfills and impoundments) were lined. Today, more than one-half of the landfills
and one quarter of the impoundments are lined. Other examples of in-place controls include
leachate collection, ground-water monitoring, and operation under regulatory permits, each
of which has a high rate of implementation at landfill management units, and significant
implementation at surface impoundment management units.
A significant portion of these wastes are reused. Nearly 27 percent of the large-volume
wastes are currently managed through beneficial uses. Some portion of these reused wastes
are actually comanaged wastes. The potential for increased reuse of these wastes currently
appears to be limited, based on demand for the products and services where the wastes are
used.
Potential Risks and Damage Cases
EPA conducted a risk assessment that found a lack of potential human health risk for
virtually all waste constituents. Arsenic was the one constituent for which the Agency
identified potential human health risks via the ground-water pathway where these wastes are
managed in unlined landfills and surface impoundments. The identified risk is based on
high-end risk scenarios in EPA's risk modeling analysis for human ingestion of well water
influenced by releases from the waste management unit. The time to reach the health-based
level for arsenic in ground water at the receptor well is about 500 years for the modeled
surface impoundment case and in excess of 3,500 years for the modeled landfill case.
EPA conducted a risk assessment that found a lack of potential human health risk for
virtually all waste constituents. Arsenic was the one constituent for which the Agency
identified potential human health risks via non-ground-water pathways where these wastes
are used as soil amendments for agricultural purposes. The identified risk is based on high-
end risk scenarios in EPA's risk modeling analysis, for human ingestion exposure routes.
Based on hypothetical exposure scenarios, the Agency identified potential ecological risks
where these wastes are managed in surface impoundments from selenium (mammals),
although potential risks were also found from arsenic (birds), aluminum (amphibians), and
boron (amphibians). This is based on direct exposure of the receptors to the waters in
surface impoundments.
The Agency identified a total of six damage cases associated with management of these
wastes. Each case involved older, unlined waste management units. The releases in these
cases were basically confined to the vicinity of the facilities and did not affect human
receptors. None of the damages caused effects on human health.
Damage cases and other problem management cases are dominated by chronic incidents,
such as leaks and occasional runoff as opposed to catastrophic incidents, such as sudden
releases or spills.
If not managed properly, pyritic wastes (in mill rejects) have the potential to generate acid
that can mobilize constituents in the comanaged wastes and contribute to risk.
The Agency has very limited information with which to conduct a risk assessment on the
practice of minefilling the comanaged wastes and, therefore, cannot quantify the risks
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associated with this practice at this time. Minefilling includes disposal of wastes by
placement in mine voids and placement of wastes in mine voids for reclamation purposes.
Some natural arsenic levels in U.S. soils have the potential to pose higher risks than the risk
identified with the level of arsenic that may be contributed by these wastes for non-ground-
water pathways.
Existing Regulatory Controls, State and Federal Requirements
The utility industry has a significant level of installed environmental controls for these
wastes, and is increasingly implementing control measures that mitigate the potential human
health risks identified in this study.
States increasingly have begun to impose controls on coal combustion waste management
units. The majority of states now have regulatory permit programs (45 states) as well as the
authority to require siting controls (41), liners (45), leachate collection systems (33),
ground-water monitoring (44), and closure controls (43) for management of these wastes.
Many states also have authority to require daily or other operational cover and fugitive dust
controls.
There are significant existing federal environmental controls that affect waste management
practices in this sector. These include new source performance standards under the Clean
Water Act that encourage dry fly ash handling, which has likely contributed to the recent
industry trend away from the use of wet ash handling (sluicing ash) to impoundments.
Significant federal authorities also exist to address site-specific problems and damages at
existing waste management sites under RCRA Section 7003 and CERCLA Sections 104 and
Section 106, when situations pose threats to human health and the environment.
The rate of environmental compliance inspections at fossil fuel electric power generation
facilities is among the highest for any industrial sector. Moreover, the rate of enforcement
actions compared to the inspection rate is among the lowest for any industrial sector. Since
1992, there have been about 13 major environmental cases involving fossil fuel electric
power generating facilities, none of which was for violations directly related to management
of solid or hazardous wastes.
Potential Costs and Impacts of Regulation
The Agency estimates that the total annual incremental compliance costs for mitigation of
the potential arsenic risks identified in this study would be between $800 and $900 million
(1998$). These costs represent replacement of existing unlined management units with
lined management units, and implementing ground-water monitoring and leachate collection
and treatment. These measures do not represent implementation of full Subtitle C
requirements, but rather modifications of such requirements that could potentially be
adopted under Section 3004(x) of RCRA.
If these wastes were to be regulated under full Subtitle C, virtually all existing facilities
would be required to invest substantial funds and resources to modify existing management
practices. The total annual cost of full Subtitle C requirements would considerably exceed
the $800-to $900-million (1998 $) estimate above.
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If beneficial uses of these wastes were subject to any regulation under Subtitle C, possibly
all beneficial use practices and markets would cease.
The cost of compliance with RCRA Subtitle C by coal-burning power producers could
reduce the amount of coal consumed in favor of other fuels. Depending on the extent of
specific Subtitle C regulation, the cost of generating electricity by burning coal could
substantially increase.
3.8.3 Recommendations
Following are the Agency's recommendations for the wastes covered in this chapter. The
recommendations are based on EPA's analysis of the eight Congressionally mandated study factors
(Section 1.2). These conclusions are subject to change based on continuing information collection,
continuing consultations with other government agencies and the Congress, and comments and new
information submitted to EPA during the comment period and any public hearings on this report. The
final Agency decision on the appropriate regulatory status for these wastes will be issued after receipt
and consideration of comments as part of the Regulatory Determination, which will be issued within 6
months.
1. The Agency has tentatively concluded that disposal of these wastes should remain exempt from
RCRA Subtitle C.
The Agency has tentatively concluded that the comanaged wastes generated at coal-fired utilities,
including petroleum coke combustion wastes as well as wastes from other fuels co-fired with coal,
generally present a low inherent toxicity, are seldom characteristically hazardous, and generally do not
present a risk to human health and the environment. Current management practices and trends and
existing state and federal authorities appear adequate for protection of human health and the
environment. State programs increasingly require more sophisticated environmental controls, and tend to
focus on utility waste management due to the high waste volumes. For example, the frequency of
environmental inspections at utilities is among the highest of all the major industry sectors in the United
States. Most of the landfills and 40 percent of the impoundments implement ground-water monitoring,
reflecting the states' focus on this industry sector. In addition, the Agency has identified relatively few
damages cases. Although one damage case identified arsenic as a constituent of concern, none of the
damage cases affected human receptors. These types of facilities are typically located in areas of low
population and thus present infrequent opportunity for human exposure. The industry trend, as detailed
in this chapter, is to line waste disposal units and to use dry ash handling techniques at new facilities; dry
ash handling eliminates the use of impoundments for waste management. Currently, more than one-half
of the active landfills are lined. Although one-quarter of all existing active impoundments are lined,
about 45 percent of the impoundments constructed since 1975 have been lined.
If these wastes were listed as hazardous, and therefore regulated under Subtitle C, coal
combustion units would be required to obtain a Subtitle C permit, which would unnecessarily duplicate
existing State requirements, and would establish a series of waste unit design and operating requirements
for these wastes that would most often be in excess of requirements to protect human health and the
environment. The estimated total annual cost to mitigate the potential arsenic risk identified in this study
exceeds $800 million. This cost does not represent implementation of full Subtitle C controls, but rather
Subtitle C requirements modified by RCRA 3004(x) factors to target the identified risks. The Agency
estimates that the total cost of full Subtitle C controls would be several times this amount. Full Subtitle
C controls include location restrictions, manifesting, liners, leachate collection, ground-water monitoring,
covers, dust control, closure controls, financial assurance, and corrective action.
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For these reasons, EPA tentatively concludes that Subtitle C is inappropriate to address any
problems associated with disposal of these wastes and that the continued use of site and region specific
approaches by the states is more appropriate for addressing the limited human health and environmental
risks that may be associated with disposal of these wastes. For the issues discussed below involving
agricultural use and management of these wastes in mines (minefill), the Agency is still considering
whether some regulation under RCRA Subtitle C may be warranted.
The Agency identified several situations where pyrite materials (sulfur-bearing components of
mill rejects) comanaged with coal combustion wastes might have been of concern. The pyritic waste
materials had turned acidic and may have caused localized environmental damage. One such situation is
considered to be a damage case. While mismanagement of these pyritic wastes can theoretically cause
problems because of their inherent chemical properties, such evidence is rare, and the Agency has no
means of systematically evaluating the extent to which they would cause or contribute to risks. To
address the problem management situations, the Agency has engaged the utility industry in a program to
ensure that these particular wastes are appropriately managed, as reflected in the industry's development
of technical guidance and an industry education program concerning proper management of pyritic
materials. The Agency is encouraged by the industry program, and has tentatively concluded that
additional regulation of pyrite disposal is not necessary. EPA, however, will follow-up with oversight on
the industry's progress with management of these wastes, and will revisit this issue if necessary.
The Agency identified potential ecological risks from selenium (mammals), although potential
risks were also found from arsenic (birds), aluminum (amphibians), and boron (amphibians) for coal
combustion wastes that are comanaged in surface impoundments. While the waters in surface
impoundments can theoretically pose risks to birds, mammals, and amphibians exposed to them, the
Agency has no actual information about the scale and frequency at which receptors are actually exposed,
and therefore cannot quantify the magnitude of the actual ecological impacts at these facilities. No
documented or anecdotal ecological impact information was available with which to compare with the
risk modeling results. Moreover, the Agency was unable to identify any feasible risk mitigation practices
for these very large impoundments other than to continue to rely on the Clean Water Act new source
standards to move the industry toward dry handling of the coal combustion wastes. (Dry handling
methods do not involve surface impoundments and therefore do not present the ecological risks identified
for impoundments.) Outright elimination of the large impoundments would impose extremely high costs
on the operators. The benefits to be derived from elimination of impoundments are uncertain due to
unavailability of information on actual receptor exposure rates and impacts as described above. The
Agency solicits information on the practices and techniques that may be effective in mitigating the
potential ecological risks, considering the large surface areas involved at these facilities.
2. The Agency has tentatively concluded that most beneficial uses of these wastes should remain
exempt from RCRA Subtitle C.
No significant risks to human health and the environment were identified or believed to exist for
any beneficial uses of these wastes, with the possible exception of minefill and agricultural use as
discussed below. This is based on one or more of the following reasons for each use or resulting product:
absence of identifiable damage cases, fixation of the waste in finished products which immobilizes the
material, and/or low probability of human exposure to the material.
3. The Agency is tentatively considering the option of subjecting practices involving the use of these
wastes for agricultural purposes (i.e., as a soil nutrient supplement or other amendment) to some
form of regulation under Subtitle C.
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As mentioned above, the Agency identified potential risk from exposure to arsenic in these
wastes when they are used for agricultural purposes. The risks identified with this practice are of
sufficient concern to consider whether some form of control under Subtitle C is appropriate, given the
increasing trend for use of these materials as agricultural amendments. An example of such controls
could include regulation of the content of these materials such that arsenic concentrations could be no
higher than that found in agricultural lime. On the other hand, imposition of controls under Subtitle C
may not be warranted if sufficient protection may be afforded by the Agency engaging the industry to
establish voluntary controls on this practice. An example of such voluntary controls could consist of an
agreement to limit the level of arsenic in these materials. The Agency solicits comment on its tentative
conclusion and specific approaches that could be pursued to address the concern. While the part 1
regulatory determination exempted all beneficial uses for the large-volume coal combustion wastes, the
tentative conclusion for the comanaged wastes would also affect the status of the part 1 wastes for
agricultural use. This is because the source of the identified risk is the metal content of the coal
combustion wastes. The Agency has no information indicating that any of the comanaged low-volume
wastes significantly affect the identified potential risks and, therefore, the risks should be comparable for
the wastes subject to the part 1 regulatory determination. Additionally, the Agency considers its current
risk analysis for this practice to be more thorough than that conducted for the part 1 wastes, and
accordingly believes it proper to reconsider the part 1 wastes in this respect.
As indicated in the summary above, although the practice of minefilling these wastes is within
the scope of this study, the Agency currently lacks sufficient information with which to adequately assess
risk associated with this practice. Several factors make the practice of minefilling difficult to assess.
First, minefill is occurring in areas where there are often pre-existing environmental concerns, such as
acid mine drainage. With its existing data the Agency is unable to determine if elevated contaminants in
ground water are due to minefill practices, or rather are associated with pre-existing problems or
conditions. Second, although minefill in a surface pit has similarities to landfill situations we have
modeled, both surface and subsurface minefill raises complexities beyond the landfill model. Third,
these operations, with their pre-existing concerns, may require very site-specific determinations that do
not lend themselves to national standards.
The Agency solicits comment on whether there are some minefill practices that are universally
poor and warrant specific attention. For example, the Agency has found several situations where cement
kiln dust placed in direct contact with the ground-water table has created problems. EPA specifically
seeks comment on whether coal or other fossil fuel combustion wastes used as minefill and placed in
direct contact with the water table would create other environmental concerns, and if that specific
practice should be regulated. Last, with a few exceptions, use of these wastes as minefill is generally a
recent practice and therefore long-term practices and environmental data cannot be assessed. The
potential for risks associated with this practice may be of sufficient concern to consider whether some
form of control under Subtitle C is appropriate, given the increasing trend for use of these materials as
minefill. The Agency's focus is on potential risks that may be posed via the ground-water and surface
pathways from use of these wastes as minefill. The Agency solicits additional information in the form of
additional case studies of actual minefill situations, with the following types of information: minefill
project design including areal extent, volumes, depth, environmental controls, mine spoils mixing ratio;
characterization of combustion wastes that are involved; the background, pre-existing conditions in
ground water at the mine location; and the depth to ground water at the mine location. The Agency is
also interested in obtaining information on analytical modeling tools that can simulate fractured flow
conditions and facilitate prediction of alkalinity consumption by acid mine drainage intrusion into the
combustion wastes. The Agency will consider such comments and information in the formulation of the
Regulatory Determination.
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4.0 NON-UTILITY COAL COMBUSTION WASTES
Non-utility fossil fuel combustors do not produce and sell electricity as their primary industrial
activity. Non-utility combustors are commercial, industrial, and institutional facilities that use fossil
fuels in boilers to generate steam. Steam thus produced is used to generate electricity for captive use, to
provide heat, or as a production process input. This chapter focuses on coal-fired non-utilities because of
their much larger waste generation relative to other non-utilities. Coal combustion accounts for only 22
percent of non-utility fossil fuel generating capacity, but is responsible for the majority (greater than 99
percent) of non-utility fossil fuel combustion waste, as shown in Figure 4-1. Oil-fired boilers (covered in
Chapter 6) and natural gas-fired boilers (covered in Chapter 7) account for larger shares of capacity, but
generate very little waste. In addition to non-utility coal combustion waste (CCW), this chapter covers
wastes from non-utilities combusting petroleum coke and coburning coal and other fuels.
Note that non-utilities, for purposes of this study, do not include independent power producers
(sometimes called non-utilities in the electric power industry). Large-volume CCWs from independent
power producers, when managed alone, were covered by the 1993 Regulatory Determination.
Comanaged CCWs from independent power producers are covered in Chapter 3.
Figure 4-1. Non-Utility Fossil Fuel Combustion Sector by Fuel Type
Equivalent Electrical Capacity
Other 9.5%
Waste Generation
Coal 99.7%
Coal 22.2%
Natural Gas 31.5%
Oil 36.7%
Oil, Natural Gas, and Other 0.3%
Sources: Equivalent electrical generation capacity from EPA, 1990; waste generation based on EPA estimates.
Sector Overview
The coal-fired non-utility sector is small relative to the coal-fired utility sector. In 1997, non-
utilities consumed approximately 76 million tons of coal, compared to the 921 million tons consumed by
utilities and independent power producers. Industrial facilities (as opposed to commercial or institutional
combustors) account for the majority (92 percent) of non-utility coal usage (EIA, 1997e). The major
industries accounting for a significant portion of coal-fired non-utility generating capacity include paper
and allied products, chemicals and allied products, food and kindred products, primary metals, and
transportation equipment (EPA, 1990). The 1990 U.S. EPA National Interim Emissions Inventory
identifies 958 non-utility coal combustors in the United States operating nearly 2,300 individual boilers.
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As discussed below, this figure is from a source that may underestimate the total number of non-utilities,
but likely captures the majority of non-utility CCW generated. Note that cement kilns that burn fossil
fuels are not included in the non-utility population covered by this study because these facilities are
covered by the Report to Congress on Cement Kiln Dust.
As discussed in Chapter 2, non-utility coal combustion is expected to increase slowly through the
year 2020. As shown in Figure 4-2, non-utility coal combustors are spread throughout the United States,
with the largest numbers in the Northeast and Midwest. Most non-utility coal-fired electrical generation
capacity is located in the same regions. Within states, facility settings vary from urban to rural. As
discussed in Section 4.3, non-utilities practice both onsite and offsite waste management. Offsite waste
management units are expected to be located near the generating facility in most cases. Therefore, the
geographic distribution of combustion facilities presented in Figure 4-2 also approximates the universe of
waste management locations.
Figure 4-2. Number of Non-Utility Coal Combustors by State
(NJ)
3(DE)
(MD)
4 (DC)
Percent of national coal-fired non-utility capacity:
a >4%
B 2-4%
a <2%
Source: EPA, 1990
The 1990 U.S. EPA National Interim Emissions Inventory is a major source used in this study to
characterize the non-utility coal combustion universe. This database includes information on major
stationary point sources of air emissions. As such, it captures only the largest non-utility facilities; many
small non-utility fossil fuel combustors are not included in the database. These small facilities, however,
are expected to represent only a small percentage of the total capacity of the non-utility universe and are
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unlikely to generate significant quantities of waste.1 Therefore, this source is representative of facilities
that generate the majority of non-utility CCW. The database contains incomplete information from EPA
Regions 9 and 10, thus underrepresenting facilities in some Western states.
4.1 WASTE GENERATION
Coal-fired non-utilities have the potential to generate the same four large-volume CCWs as
utilities:
Fly ash. Uncombusted material carried out of the boiler along with flue gases.
Bottom ash. Uncombusted material that settles to the bottom of the boiler. Bottom ash
does not melt and therefore remains in the form of unconsolidated ash.
Boiler slag. Uncombusted material that settles to the bottom of the boiler. Slag forms when
operating temperatures exceed ash fusion temperature, and remains in a molten state until it
is drained from the boiler bottom.
Flue gas desulfurization (FGD) waste. Waste produced during the process of removing
sulfur oxide gases from flue gases (less likely to be generated at non-utilities than utilities,
as discussed below).
As for utilities, the generation of these CCWs depends upon boiler technology (Section 4.1.1),
air pollution control technology (Section 4.1.2), and fuel usage (Section 4.1.3). There are no
comprehensive data on industry-wide generation of these non-utility CCWs. An annual ash generation
rate, however, can be derived for coal-fired non-utilities using the data in the 1990 U.S. EPA National
Interim Emission Inventory database (EPA, 1990). For these facilities, the estimated annual rate of
CCW generation is approximately 5.8 million tons per year (EPA, 1997d). This estimate is significantly
less than the quantity of CCWs generated by utilities due to the smaller total capacity of the non-utility
sector and the factors discussed below (Sections 4.1.1 through 4.1.3). Because slow growth in non-utility
consumption of coal is expected (see Chapter 2), dramatic increases in non-utility CCW generation are
not expected.
Like utilities, non-utilities can generate low-volume combustion wastes as a result of supporting
processes (see Section 4.1.4) that are ancillary to, but a necessary part of, the combustion and power
generation processes. These low-volume wastes include the following:
Coal pile runoff. Produced by precipitation falling on coal storage areas (less likely to be
generated at non-utilities than utilities, as discussed below).
Coal mill rejects/pyrites. Produced by onsite processing of coal prior to use (less likely to
be generated at non-utilities than utilities, as discussed below).
Boiler blowdown. Waste that is continuously or intermittently removed from boilers that
recirculate water.
1 Small facilities are disproportionately populated by natural gas- and oil-fired units, which generate small
or negligible quantities of solid waste. Small facilities burn less fuel, resulting in lower waste generation. Finally,
small units are less likely to be fitted with air pollution control devices, decreasing the quantity of fly ash collected.
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Cooling tower blowdown and sludge. Wastes removed periodically from closed-loop
cooling systems.
Water treatment sludge. Wastes resulting from treatment of makeup water for the steam
cycle or for non-contact cooling.
Regeneration waste streams. Wastes resulting from periodic cleaning of ion exchange
beds used to remove mineral salts from boiler makeup water.
Air heater and precipitator washwater. Wastes resulting from the periodic cleaning of
the fireside (i.e., the side exposed to hot combustion products) of heat exchanging surfaces.
Boiler chemical cleaning waste. Wastes resulting from the periodic cleaning of the inside
(waterside) of boiler tubes with chemical solutions.
Floor and yard drains and sumps. Wastewaters collected by drains and sumps, including
precipitation runoff, piping and equipment leakage, and washwater (may include wastes not
associated with combustion processes).
Laboratory wastes. Wastes generated in small quantities during laboratory analyses at the
facility (may include wastes not associated with combustion processes).
Wastewater treatment sludge. Sludge generated from the treatment in settling basins or
other treatment facilities of liquid waste streams, including those above and others not
associated with combustion processes.
Non-utilities would be expected to generate smaller quantities of these wastes, consistent with
their smaller unit size (see Section 4.1.1). In some cases, non-utilities may generate insignificant
quantities of some low-volume wastes (see Section 4.1.4).
In addition to large-volume CCWs and low-volume wastes, non-utility combustors have the
potential to generate a wide range of process wastes unrelated to the combustion of fossil fuels,
consistent with the variety of industries represented by these facilities. These process wastes may be
disposed along with combustion wastes. No comprehensive data exist on the quantity of low-volume
wastes or non-combustion process wastes generated at non-utilities. For purposes of this study, however,
the total quantity generated is less significant than the quantity comanaged with large-volume wastes.
Section 4.3 presents the available data on the quantities of waste comanaged and the frequency of
comanagement.
4.1.1 Boiler Technology
Coal-fired non-utilities use the same conventional combustion technologies as coal-fired utilities:
pulverized coal (PC) boilers, stokers, and cyclones. All three conventional technologies involve
combustion of coal in a boiler to heat water and produce steam. The steam may then be used to provide
process heat or generate electricity. Note that when non-utilities generate electricity, they generally do
so for onsite use rather than retail sale like the utilities and independent power producers covered in
Chapter 3. The three conventional technologies differ in design, particularly in the type and the size of
the coal particle to be burned, fuel delivery mechanisms, and the combustion conditions inside the boiler
furnace. Chapter 3 provides a description of these technologies and their waste generation implications.
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Figure 4-3 compares the technologies used in the non-utility sector to those in the utility sector.
The figure shows that, while PC boilers predominate for utilities, both PC boilers and stokers are
significant for non-utilities. Based on average capacity, non-utility units (14 megawatts average
capacity) are smaller than utility units (256 megawatts average capacity). Examining the size distribution
of individual boilers in Figure 4-4 confirms this observation. The majority of boilers in the non-utility
industry are in the 0 to 50 megawatt equivalent range, while those in the utility industry range from 10 to
1,000 megawatts. This size difference is most obvious for PC boilers, however. Non-utility PC boilers
are much smaller than those in the utility sector. Stokers in both populations are similar in size.
Figure 4-3. Comparison of Utility and Non-Utility
Conventional Coal Combustion Technologies
Number of Units
Non-Utilitv
Stokers 76%
PC Boilers 23%
Cyclones 1%
Total Capacity
Non-Utility
PC Boilers 46%
Cyclones 2%
Utility
Stokers 52%
Utility
PC Boilers 85%
PC Boilers 92%
Cyclones 7%
Stokers 8%
Cyclones 8%
Stokers 0%
Sources: EEI, 1994; EPA, 1990
These differences in boiler technology have implications with respect to non-utility CCW
generation. The generally smaller boiler size for non-utilities means lower fuel usage, and, in turn, less
waste generation on a per-boiler basis. The greater proportion of stokers means greater waste generation
per unit of energy generated, due to the lower efficiency of these units. The greater proportion of stokers
also suggests a lesser percentage of the CCW generated will be in the form of fly ash.
4.1.2 Air Pollution Control Technologies
Air pollution control (APC) technologies used to meet the needs of coal combustion facilities
may be categorized broadly as particulate controls and flue gas controls. The technologies of most
relevance in the latter category are those for control of sulfur oxide emissions. As at utilities, the capture
of non-utility fly ash is governed by the particulate control technology used. Fly ash leaving the boiler
must be removed from the gas stream in which it is entrained or it will be released to the atmosphere.
Generation of FGD waste results from the use of FGD technology. Chapter 3 describes both particulate
control and desulfurization technologies.
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Figure 4-4. Distribution of Coal-Fired Boilers by Capacity
1000
0) 800
0
'o
CD
0-10 >10-50 >50-100 >1 00-250 >250-500 >500-1000 >1000
Boiler Size (megawatt equivalents)
G Utility Q Non-Utility
Note: Boilers not reporting size are not included.
Smirks: FFL 1994: FPA. 1990
Figure 4-5 shows data on particulate control devices employed at non-utilities. Due to their
smaller size, non-utilities are less likely to be subject to particulate control regulations than utilities (see
Section 4.5). As a result, a significant proportion of non-utilities does not use particulate controls or
apply only low efficiency controls, such as gravity collection. This latter technique involves collecting
fly ash that falls out of flue gas due to gravity at points where flow changes. Gravity collection has a low
efficiency (less than 10 percent) compared to more complex particulate control devices. Units with
gravity collection as their only control thus collect smaller quantities of fly ash. The proportion of units
without particulate controls (or with low efficiency controls) leads to lower collection of fly ash in the
non-utility sector.
Still, a large number of coal-fired non-utilities do employ high efficiency particulate control
devices. These devices are most commonly mechanical collectors. This is because of the large
proportion of stokers in the non-utility population. Stokers generate larger fly ash particles for which
mechanical collection is efficient.
Of non-utility generating units that provided sulfur dioxide emissions information in the 1990
National Interim Emissions Inventory, only 4 percent reported using FGD technologies with the potential
to generate FGD waste. A few units reported controlling sulfur dioxide emissions through combustion
modifications or using particulate control technologies. The infrequent use of desulfurization technology
for non-utilities may result from differences in regulatory requirements between large utility boilers and
smaller non-utilities (see Section 4.5). Because of this, non-utilities as a group generate much less FGD
waste than do utilities.
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Figure 4-5. Participate Control Technologies Used at Coal-Fired Non-Utilities
None 13%
Gravity Collection 5%
Electrostatic Precipitator (ESP) 16%
Fabric Filter 10%
'Mechanical collector followed by fabric filter or ESP
Source: EPA, 1990
Scrubber or Miscellaneous 5%
Combination* 16%
Mechanical 35%
4.1.3 Fuel Usage
The quantity of ash and slag generated is affected by the ash content of the fuel. Ash content is,
in part, determined by the rank of the coal: anthracite, bituminous, subbituminous, or lignite. These
ranks reflect the degree of metamorphism of the coal and typically correspond to the geologic age of the
coal deposit and to the heating value of the coal. Anthracite coal is the oldest rank and has the highest
heating value, while lignite is the youngest and has the lowest heating value (Stultz and Kitto, 1992).
Table 4-1 shows the usage of each rank by non-utilities in 1990, along with typical ash content. Non-
utilities use the same four classes of coal as do utilities; however, a large percentage of non-utility use is
bituminous coal.
Table 4-1. Fuel Usage by Coal-Fired Non-Utilities
Coal Class
Anthracite
Bituminous
Subbituminous
Lignite
Ash Content
4-19%
3-32%
3-16%
4-19%
Total
Non-Utility Usage in 1990
(1,000 tons)
609
56,762
2,576
3,998
63,945
Percent of Total Usage
1%
89%
4%
6%
100%
Sources: CIBO, 1997c; EPA, 1990
In addition to coal rank, ash content depends on the specific coal producing region, mine, seam,
and production method. The ash content of coal burned by non-utilities varies from state to state. On
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average, however, ash content of non-utility coal is less than that of utility coal, 7.58 percent compared to
9.22 percent in 1996 (EIA, 1998c).
The type of coal burned also affects the distribution of the ash and slag waste streams generated
by combustion. For example, because softer lignite coals tend to have a lower ash fusion temperature,
they tend to generate boiler slag rather than bottom ash.
Like utilities, coal-fired non-utilities may burn other non-coal fossil fuels, such as petroleum
coke (see Section 5.1.3), or coburn coal with other fuels (see Section 3.1.3). No data are available on the
extent of these practices at non-utilities. Their impacts on waste generation and characteristics, however,
are expected to be similar to those discussed in Chapters 3 (for coburning) and 5 (for petroleum coke).
4.1.4 Supporting Processes
The generation of low-volume wastes primarily is associated with processes that support the
combustion process or make use of the products of combustion. Some of the same supporting and
enabling processes can accompany combustion at coal-fired non-utilities as at utilities, including the
following:
Coal storage
Coal processing
Steam generation
Cooling
Water treatment
Cleaning and maintenance.
Chapter 3 describes these processes in detail. The paragraphs below describe potential
differences in these processes at non-utilities with respect to waste generation. Little quantitative
information is available on the quantities of low-volume wastes generated at non-utilities.
Coal Storage and Processing
Because of their small capacity, coal-fired non-utilities generally do not store large quantities of
fuel onsite; therefore, they are less likely to generate significant coal pile runoff. Also, because of their
small capacity, non-utilities are less likely to conduct onsite coal cleaning. The large proportion of
stokers, which require less extensive feed processing than PC boilers, in the population means less need
for coal processing at non-utilities. Therefore, many non-utilities may not generate coal mill rejects
(including pyrites).
Steam Generation, Cooling, and Water Treatment
These processes generate low-volume wastes, including boiler blowdown, cooling tower
blowdown, water treatment wastes, and regenerant wastes. The quantities of these wastes generated are
related to the quantity of water used in the steam and cooling cycles, which in turn is related to
combustion capacity. Because of their smaller capacity, non-utilities generally use less water in
combustion-related processes, and, therefore, may generate smaller quantities of these wastes. In
addition, some non-utilities use steam directly for heat in industrial processes rather than to generate
electricity. In some cases, this practice may reduce the need for cooling, and in turn reduce the
generation of wastes associated with the cooling cycle.
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Cleaning and Maintenance
Cleaning processes intermittently generate low-volume wastes, including air heater and
precipitator washwater and boiler chemical cleaning waste. Because of their small size, some non-utility
combustors may require less frequent cleaning, using lower volumes of cleaning solution, than utilities.
This can result in a lesser generation of cleaning wastes. For example, boiler fireside cleaning may take
place so infrequently at a small non-utility combustor that the amount of cleaning waste generated over
the life of the facility may be small. Eighteen coal-fired non-utilities reported the quantity of boiler
fireside wash water and boiler waterside chemical cleaning rinse generated in response to a voluntary
survey by the Council of Industrial Boiler Owners (CIBO). The plants reported a combined average
annual volume of 35,941 gallons for both wastes (CIBO, 1997a).
4.2 WASTE CHARACTERISTICS
Analytical data to broadly characterize non-utility combustion wastes are not available. EPA,
however, believes that non-utility CCW characteristics are similar to those of utility CCWs. The greater
use of stoker technology in the non-utility sector does raise the possibility of differences in waste
characteristics. Such differences might stem from differences in combustion conditions and fuel feed
characteristics between stokers and the PC boilers used extensively by utilities. The available data,
however, do not indicate that these differences are significant for the purpose of evaluating risk to human
health and the environment.
CIBO provided a summary of leaching test results for fly ash and grate ash from stoker boilers
(CIBO, 1998). CIBO obtained these data by voluntary survey of 33 facilities (non-utility and utility) with
stoker boilers. Figure 4-6 compares these data with the leachate data for utility CCWs (from PC boilers)
collected for the 1993 Regulatory Determination. For most of the constituents examined, mean
concentrations in stoker ash are similar to or less than those in PC boiler ash. Also for most constituents,
the range of concentrations observed for stoker ash are similar to or within the corresponding ranges for
PC boiler ash. For selenium, the concentrations observed in stoker ash appear to be in the upper end of
the range of concentrations observed in PC boiler ash. However, the maximum reported concentration
for selenium in stoker ash appears to be an artifact of a high detection limit (0.5 milligrams per liter) in
the analysis used for at least two samples. This detection limit drives the maximum concentration and
inflates the mean concentration shown in Figure 4-6.
No data are available for organic constituents, dioxins, or radiation in non-utility CCWs. Based
on the observed similarity of non-utility and utility CCWs with respect to metals, however, these other
characteristics are not expected to be significantly different for non-utility CCWs. Data also are not
available characterizing the smaller amounts of FGD waste expected to be generated by non-utilities.
There is no reason, however, to expect non-utility FGD wastes to have significantly different
characteristics than utility FGD wastes. Finally, the effects on waste characteristics of burning non-coal
fossil fuels, such as petroleum coke, or coburning coal and other fuels, are expected to be similar to those
discussed in Sections 3.2.3 and 5.2.
Based on the observed similarity of non-utility and utility CCWs with respect to constituents of
concern, the risk assessment for non-utility CCWs relies on data for comanaged utility CCWs.
Comanaged utility waste data were chosen, rather than data representing large-volume non-utility CCWs
alone, because of the high rate of comanagement in the non-utility sector (see Section 4.3) and because
the comanaged waste data are more extensive than the CIBO stoker ash data.
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Figure 4-6. Comparison of Leachate Characteristics of Utility and Non-Utility Wastes
100^
10-
I 1
1 °-1 "
1 °-01 ~
0 0.001 -
0.0001
n nnnm
i
i
i
i
i
- -
*-
i
i
Arsenic Bt
^^m
Sources: CIBO, 1998; supporting doc
i i
irium Cadmium Chrom
Stoker Ash
jmentation to the 1993 Regu
1
urn Copper L
atory Determination
i
i -
ii
ead Mercury Selenium Silver
C Boiler Ash
4.3 CURRENT MANAGEMENT PRACTICES
This section covers the management of wastes from the combustion of coal at non-utilities that
use conventional (non-fluidized bed combustion) combustion technologies. The Agency evaluated two
sources of data on this topic. The first is the CIBO non-utility survey (CIBO, 1997a). This was a
voluntary survey of CIBO member companies and a select list of other companies known to operate
non-utility boilers, conducted in support of this EPA effort. CIBO obtained responses from more than
50 coal-fired non-utilities. EPA believes this sample of facilities is representative of the non-utility
population in terms of industries covered and boiler and air pollution control technologies used.
The second source is regulatory permit file information EPA collected on the generation and
management of fossil fuel combustion (FFC) wastes from selected non-utilities in six states (Illinois,
North Carolina, Virginia, New York, Pennsylvania, and Wisconsin). These six states were selected
based on their large populations of non-utility boilers, both coal-fired and oil-fired.2 The information
available from this effort varies from state to state, depending on the information requirements of state
regulations. For example, identification of waste management unit types was possible in five of the
states, while extensive information on environmental controls was available in only three. Information
from the search of state permit file information is used in this report to supplement the CIBO non-utility
survey results.
2 The selection criterion considered both coal-fired and oil-fired boilers in an effort to collect information
for this section and Chapter 6 of this report; however, the state files contained little information regarding oil-fired
boilers. Therefore, the state file information ultimately obtained covered coal-fired non-utilities only.
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4.3.1 Unit Types and Location
Twenty-six coal-fired non-utility facilities provided information on waste management unit type
in the CIBO non-utility survey. These 26 facilities appear to operate a total of 27 waste management
units. This count assumes one management unit for each facility that reported a given management
practice. For example, it assumes one surface impoundment for each facility that reported using a
surface impoundment, when, in fact, the facility might have several impoundments. Thus, this analysis is
based on a lower bound on the number of waste management units.
The available data indicate landfilling is the primary practice for non-utility CCWs, with few
facilities operating surface impoundments. The 27 units identified in the CIBO non-utility survey
include 25 landfills and only two surface impoundments. Of the 49 units identified in five of the states
from which EPA obtained information,3 42 (or 86 percent) are landfills. The other seven units include
four surface impoundments, a land application facility, and two units of unknown type. Non-utility waste
management units also appear to include a large proportion of offsite units. The 25 landfills in the CIBO
non-utility survey include eight commercial units (32 percent), which would be located offsite. The
survey did not distinguish between onsite and offsite management for landfills owned by the respondent.
Because the review of state permit file information was directed at facilities operating captive disposal
units, the units identified in that effort all are onsite; however, other information collected during the
review of permit files suggests that the majority of non-utility CCWs are managed offsite in at least three
of the six states (Illinois, New York, and Pennsylvania). This is based on information from
Pennsylvania's Residual Wastes Database and observations reported by officials in the other states.
A possible explanation for the predominance of landfills and the larger proportion of offsite units
in the non-utility population is the power generating capacity of these facilities. As discussed in Chapter
3, the smaller coal-fired utilities tend to dispose offsite in landfills, most likely because of economies of
scale and available space. If similar trends hold for non-utilities, one would expect a larger proportion of
landfills and offsite units for these small facilities as well.
4.3.2 Types of Waste Managed
As at utilities, large-volume CCWs at non-utilities frequently are combined for management.
Sixty-one percent (31 of 51) of coal-fired non-utilities providing information in the CIBO non-utility
survey manage bottom ash and fly ash in the same unit. Just under half (4 of 9) of the facilities
generating FGD waste manage this waste in the same unit as fly ash.
As discussed in Section 4.1, non-utilities have the potential to manage large-volume CCWs with
a great variety of other wastes because they may generate both low-volume combustion wastes and
wastes from other processes. Figure 4-7 describes the combined management of other wastes with non-
utility CCW, based on the CIBO non-utility survey. As shown in Figure 4-7, commingling of large-
volume CCWs and other wastes at non-utilities appears to be as common as at utilities (see Section 3.3).
The state permit file information generally supports this observation. For onsite landfills in two of the
three states for which information on combined management is available, 90 percent or more of the units
combine FFC wastes and other wastes (9 of 10 landfills in North Carolina and 17 of 18 landfills in
Wisconsin). On the other hand, in Pennsylvania, most non-utility CCW that is managed onsite is
managed separately in monofills. For offsite landfills, quantitative data are not available from the state
3 Information on management unit types was not available for the sixth state from which EPA collected
information.
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Figure 4-7. Combined Management of CCWs with Other Wastes at Non-Utilities
CCWs Comanaged with Low-Volume Combustion Wastes 28%
/f /Y CCWs Mana9ed Separately 14%
CCWs Commingled with Other Wastes 24%A ^fl W
CCWs Managed with Both 34%
Note: Data shown are the 29 facilities that provided information about waste combinations managed.
Source: CIBO, 1997a
files concerning the prevalence of comanagement; however, offsite landfills are likely to include
commercial units that accept a variety of wastes in addition to CCWs.
Table 4-2 details the specific types of wastes reported in the CIBO non-utility survey. Low-
volume combustion wastes comanaged include the same types reported for utilities, although coal mill
rejects (pyrites) in particular are comanaged less frequently at non-utilities. This is likely because, as
discussed in Section 4.1, coal mill rejects are less likely to be generated at non-utilities. The table also
shows a number of types of non-combustion wastes. Wastes identified in the state permit file
information include an even greater variety of non-combustion wastes: construction debris, paper and
wood mill waste, bark, lime, wood ash, spent alum mud, pulp fiber, incinerator ash, dimethyl-
terephthalate, terephthalate acid, wastewater treatment sludge, aluminum sludge, filter cake, reactor
bottoms, spodumene ore residue, decrepitation kiln solids, asbestos, metallurgical process residues, filter
pads, plastics, pipe insulation, scrap metal, fibrets, crushed coal, masonry waste, paper products, sand,
oily soil, and sulfite liquor.
4.3.3 Environmental Controls
Information was available on environmental controls including liners, leachate collection,
ground-water monitoring, and runoff controls from the state permit files in three of the six states studied
(North Carolina, Virginia, and Wisconsin). In addition, the CIBO non-utility survey collected
information on the use of liners and issuance of regulatory permits. Table 4-3 summarizes this
information.
The state permit file data suggest that environmental controls are common at non-utility landfills;
however, the state permit file sample may be biased in this regard. Because they were identified through
state permit files, these units are subject to some form of regulatory oversight (e.g., permit review,
inspections, monitoring). This regulatory oversight may have resulted in the imposition of environmental
controls at these units. The liner data from the CIBO non-utility survey, which show a much lower
percentage of landfills with controls, support the hypothesis that the state permit file data reflect a sample
bias toward environmental controls. Based on this, the prevalence of environmental controls at non-
utility landfills may be less than that at utilities.
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Table 4-2. Types of Wastes Comanaged with Non-Utility CCWs
Waste Type
Number of
Non-Utilities
Percent of Plants
Reporting (25 facilities)
Low-Volume Combustion Wastes
Boiler Slowdown
Demineralizer Regenerant/Rinses
Coal Mill Rejects/Pyrites
Water Treatment Wastes
Boiler Cleaning Chemical Waste
Air Preheater/Precipitator Wash Waste
Cooling Tower Blowdown
Coal Storage Pile Runoff
8
6
6
6
5
4
3
2
32%
24%
24%
24%
20%
16%
12%
8%
Other Wastes*
Wastewater Treatment Sludges/Residuals
General Site Runoff
Floor Drains/Sumps
Laboratory Wastes
Miscellaneous Plant Wastes
Domestic/Municipal Wastes
Contaminated/Dredged Soils
Other Unspecified Wastes
8
7
6
5
5
3
2
5
32%
28%
24%
20%
20%
12%
8%
20%
* Wastes not clearly related to combustion processes were categorized as other wastes.
Source: CIBO, 1997a
Table 4-3. Environmental Controls at Non-Utility CCW Landfills
Environmental Control
Liner
Leachate Collection
Runoff Control
Ground-Water Monitoring
Regulatory Permit
Number of Units Reporting
Data on Each Control"
19
27
30
6
34
23b
Percent with Control"
16%
52%
67%
100%
94%
65%b
Data Source
CIBO non-utility survey
State perm it files
State permit files
State perm it files
State perm it files
CIBO non-utility survey
a The number of facilities reporting data on the presence or absence of each control type was different for each control type. For example, it
was possible to determine the presence or absence of leachate collection systems at 30 facilities. Twenty of these 30 (67 percent) had
leachate collection systems. The other 10 (33 percent) did not. Information on leachate collection systems was not available for units
other than these 30.
b Data presented is number of non-utility plants, not number of management units. Unit-specific information was not available. Three of the
facilities counted as unpermitted indicated that permits are required, but have not yet been issued. Once these permits have been issued,
the percentage of permitted non-utility facilities would increase to 78 percent.
March 1999
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Liners
As discussed above, the CIBO data suggest a much lower percentage of landfills are lined than
the state permit file information may indicate. It is unclear which sample is more representative,
although the state permit file units are not geographically representative and are probably biased toward
having liners. Figure 4-8 shows the types of liners reported in the state permit file information. Only
limited data exist for non-utility surface impoundments. The two impoundments in the CIBO non-utility
survey are unlined.
Figure 4-8. Types of Liners at Non-Utility CCW Landfills
None 48%
Unspecified 11 %
Clay 26% \. Wv **,
' ^ ' ^ Composite* 4%
Silt 4%
Synthetic 7%
Composite liners consist of clay and synthetic layers.
Source: State permit files
4.3.4 Beneficial Uses
Current statistics are not available on the quantities of non-utility CCWs that are utilized;
however, available data indicate that beneficial use of these wastes does indeed occur. The small sample
of facilities responding to the CIBO non-utility survey (CIBO, 1997a) provided information on whether
they utilize some of their CCW. Table 4-4 summarizes these responses. Overall, 56 percent of
respondents described one or more beneficial uses. The uses reported are the same as those described for
utility CCWs, with cement and concrete and construction fill uses being reported most commonly. These
results are consistent with the statistics showing these uses to be the most common for utility CCW.
Based on these results and because of the similarities between utility and non-utility CCWs, EPA
believes that nearly all of the beneficial uses described for utilities also are applicable to non-utility
wastes. In some cases, economic barriers to the commercialization of these uses for non-utility CCWs
may exist because of the smaller volumes of waste generated. Individual non-utility generators may not
be able to competitively market their byproducts for uses (such as construction fill) that require large
volumes of CCW. The extent of such barriers, as well as techniques for overcoming them, require
further investigation.
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Table 4-4. Non-Utility FFC Waste Beneficial Uses
Beneficial Use
Do Not Utilize
One or More Beneficial Use*
Cement/Concrete
Flow/able Fill
Structural Fill
Road Base/Subbase
Miinefill
Agricultural Use
Waste Stabilization
Snow and Ice Control
Blasting Grit/Roofing Granules
Mineral Filler
Total
Number of Facilities
Reporting
22
28
18
6
14
13
8
7
5
3
1
1
50
Percent
44%
56%
36%
12%
28%
26%
16%
14%
10%
6%
2%
2%
100%
* Total shown is less than the sum of individual uses because a facility may employ more than one beneficial use.
Note: Data shown are for the 50 (of 51) facilities that provided beneficial use information.
Source: Cl BO, 1997a
4.4 POTENTIAL AND DOCUMENTED DANGERS TO HUMAN HEALTH AND THE
ENVIRONMENT
4.4.1 Potential Ground-Water Risks to Human Health
Section 3.4 provides a discussion of the methodology employed by EPA in assessing risks from
coal-fired utility comanaged wastes. EPA followed a similar approach for wastes from the non-utility
sector, with several important differences. First, EPA initially obtained very few data on the
characteristics of wastes generated in non-utility boilers. To overcome this data gap, EPA used the waste
characterization data developed for the utility comanaged waste sector to represent wastes from non-
utilities. As non-utility data were developed and provided by industry (CIBO, 1998), EPA compared
utility and non-utility waste characteristics as a function of fuel, boiler type, and boiler size to
corroborate the initial assumption that the wastes from the sectors are similar (see Section 4.3). Second,
EPA found the primary differences between the sectors, from a risk assessment standpoint, to be in waste
management practices and waste unit sizes. Non-utility boiler operators were found to generate smaller
quantities of wastes overall, and to manage these wastes either in small onsite landfills or large onsite or
offsite units containing primarily other non-FFC wastes. EPA found the proportion of FFC wastes in
most mixed waste disposal units to be small, and, therefore, judged the risks from such units attributable
to FFC wastes to be similarly small. EPA, therefore, focused its examination of ground-water pathway
risks on small onsite landfills. Finally, EPA found that non-utility boilers reflect a geographic
distribution distinct from the larger utilities, and so modified its modeling scenarios accordingly.
Note that EPA did not model risks from minefilling of non-utility FFC wastes. EPA believes
minefill practices to be the same for utility and non-utility operators. See Section 3.4.5 for an overview
of EPA concerns and data limitations for minefills.
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Non-Utility Ground-Water Risk Findings
Table 4-5 summarizes selected results from the deterministic and probabilistic analyses of risk
from non-utility coal combustion wastes for the adult receptor. Overall, EPA found that the risks
associated with all modeled constituents of concern, except for arsenic, fell below a hazard quotient (HQ)
of 1 or lifetime cancer risk of 1 * 10~6. Potential risks associated with arsenic in the high-end deterministic
scenario exceeded IxlO"4.
Table 4-5. Comparison of Deterministic and Monte Carlo Risk Model Results for Non-
Utility Coal Combustion Waste Ground-Water Pathway Scenario
Scenario
NMa
Constituent"
Arsenic
Barium
Deterministic
Risk, Central
Tendency
1.4x10*
HQ<1
Deterministic
Risk, High-End
1.8x10"
HQ = 0.2
Corresponding
Monte Carlo
Percentile
99
99
Monte Carlo 95th
Percentile
6.5x1 06
HQ = 0.002
aNM = non-utility onsite monofill (i.e., managing CCWs and low-volume combustion wastes, but not other non-combustion industrial wastes).
"Constituents are limited to those for which estimated risks exceeded target values in the April 1 998 Draft Final Report. Revised nickel
screening results were HQ <1 so modeling results are not reproduced here. All other metals modeled yielded an HQ <1
Note: Results shown are those from the October 10, 1998, Sensitivity Analysis.
Comparison of the deterministic and Monte Carlo results reveals that the deterministic results
exceed the 95th percentile Monte Carlo results. Specifically, 99 percent of the 2,000 Monte Carlo
simulation combinations of parameter values exceed the deterministic high-end results for arsenic and for
barium. Even at the 95th percentile level, the risks predicted by the Monte Carlo simulations were almost
two orders of magnitude below the corresponding risks estimated for the high-end scenario.
In essence, using coal-fired utility comanaged waste characteristics data for the non-utility
analysis, EPA found cancer risk from arsenic from onsite landfills to be similar to those found for
comanaged wastes, at the 1 * 10"4 level. EPA also considered the time at which risks were predicted to
result from the release of constituents of concern. EPA found that the concentration of arsenic in ground
water at the receptor well would not reach the health-based levels (HBL) for arsenic (i.e., achieve a risk
level of 1 x 10"6) for more than 1,400 years.
Table 4-6 summarizes the estimated risks to adult and child receptors for the high-end
deterministic scenario for non-utility CCWs. Overall, the results show that risks to the two child types
and adult were similar.
Table 4-6. Comparison of Adult and Child Risk Model Results
for Non-Utility Coal Combustion Waste - Ground-Water Pathway Scenario
Scenario
NMa
Constituent"
Arsenic
Barium
High-End Deterministic Risk
Adult
1.8x10"
HQ = 0.2
Young Child
2.3x10"
HQ = 0.3
Child
1.6x10"
HQ = 0.2
aNM = Non-utility on-site monofill (i.e., managing CCWs and low-volume combustion wastes, but not other non-combustion industrial wastes).
"All other metals modeled yielded HQ <1
Note: Results shown are from the October 10, 1998, Sensitivity Analysis
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4.4.2 Potential Above-Ground Multi-Pathway Risk to Human Health and the
Environment
Human Health Risk
Similar to the results discussed in Section 3.4.2, no plausible non-ground-water risks were found
for the non-utility wastes except in the event of possible use in agricultural applications, where risks
would be similar to those noted for the utility wastes (in excess of 10~5).
Ecological Risk
No ecological risks were found for this category of ash in that no disposal in large surface
impoundments was noted.
4.4.3 Documented Damages to Human Health and the Environment
Summary of Findings
EPA collected information on the generation and management of combustion residues at non-
utilities from six states (Illinois, New York, North Carolina, Pennsylvania, Virginia, and Wisconsin).
Detailed, facility-specific information for about 50 sites was collected from conversations with State
personnel and the review of facility-specific files at state offices. Based on this review, EPA concluded
that none of these sites meet the "test of proof' for damage cases. Although releases of waste have been
documented and ground-water monitoring results show exceedences of standards in some cases,
documentation was not available which would satisfy the EPA tests of proof for damage cases.
EPA also reviewed four Superfund Records of Decision (ROD) involving non-utility CCWs
(codisposed with other wastes). In one of these decisions (Wheeler Pit, Wisconsin, ROD/R05-90/130),
no principal threat warranting treatment has been identified. In a second decision (U.S. DOE Feed
Materials Production Center), FFC wastes were found not to contribute to contamination.
In the remaining two cases, non-combustion wastes are codisposed with CCWs and the source of
the ash (utility or non-utility) is unspecified. In one case, the Lemberger landfill (Wisconsin, ROD/R05-
91/186), the source material does not implicate, or rule out, contributing influences from CCWs. In the
second case, Salem Acres (Massachusetts, ROD/ROI-93/078), an area used as a fly ash waste pile is
identified as a potential source of risk.
Based on information available and in consideration of EPA's "tests of proof," EPA identified
the cases in Table 4-7 as potential damage cases.
Cases Meeting Test of Proof
The Salem Acres (Massachusetts) National Priority List site comprises unlined sludge lagoons
containing tannery wastes (typical components include chromium and greases), contaminated soil areas,
a landfill, a debris pile, and a fly ash pile. Wastes were disposed at the site from the mid 1940s to 1969;
the source of the ash (utility or non-utility) was not described in the source documents. The volume of
fly ash is estimated to be 9,600 cubic yards; the volume of lagoon sludge is estimated to be 21,000 cubic
yards. Therefore, the ash represents a significant percentage of the overall waste volume present.
Ground-water monitoring showed arsenic to be present below its maximum contaminant limit. The ROD
concluded that several areas of the site, including the fly ash pile, pose health risks exceeding risk
management criteria. Ground-water risks from antimony and manganese also were identified.
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Table 4-7. Potential Damage Cases
Damage Case
Salem Acres (MA)
Lemberger Landfill, Inc.
(Wl)
Wastes Present
Large volume; many
other wastes present
including MSW and
ISW
Comanaged wastes;
many other materials
including MSW, with
adjacent site receiving
ISW
Event
PAHs, VOCs, PCBs,
and metals, including
As and Cr, in soils,
surface waters, and
ground water
Elevated concentra-
tions of As, Cr, and Pb
onsite, plus VOCs,
PCBs
VOCs in private wells
initiated action
Test of Proof
Administrative
(on NPL)
Administrative
(on NPL)
Comment
Contribution of FFC wastes to
damage not separable from
other wastes. Remedial
measures include excavation,
treatment, and removal of
sludges and soils; proposed
fixation with fly ash; Subtitle C
capping if performance criteria
are not met
>$20 million cleanup
Contribution of FFC wastes to
damage not separable from
other wastes
An old gravel pit, the Lemberger Landfill (Wisconsin) was used for waste disposal from 1940 to
about 1980. Wastes disposed included general refuse, power plant fly ash (1969 to 1977) and bottom ash
(1969 to 1976), and municipal solid waste. Other industrial wastes also were disposed at a nearby site.
Environmental effects and damages included the seepage of landfill leachate into adjacent property,
presence of volatile organic compounds in drinking water wells, the presence of organic compounds in
surface water, and potential effects from direct soil or waste contact. Inorganic constituents detected in
the ground water include barium, cadmium, and chromium. The source of contamination was identified
as the landfilled waste, although specific wastes were not identified in the ROD as contributing or not
contributing to the ground-water contamination.
Evaluation of the sites is complicated by three factors: disposal ceased at least 10 years ago, non-
combustion wastes are mixed with CCWs at each of the sites, and the information does not specify if
CCWs result from utility or non-utility operations. These two cases, however, meet EPA's tests of proof
as damage cases for purposes of this study.
4.5 EXISTING REGULATORY CONTROLS
EPA's objective in this analysis was to identify and evaluate the existing regulatory controls that
pertain to the management of non-utility CCWs. The regulatory analysis is directed toward addressing
the question of whether existing regulations adequately protect human health and the environment. The
analysis also is helpful in understanding waste generation and current management practices.
The sections below discuss regulations addressing air pollution, water pollution, and solid and
hazardous waste, respectively. Air regulations are relevant primarily because of their effect on waste
generation. Water regulations have an influence both on waste generation and management and, in
particular, address the impact of CCWs on surface waters. Solid and hazardous waste regulations are of
the greatest interest because they directly govern waste management practices.
The sections below describe federal regulations in each of these areas. In many cases, the
implementation of these federal programs is carried out by the states. Therefore, where appropriate,
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aspects of state implementation also are discussed. Because the nuances of state implementation are of
particular importance with respect to solid waste regulation, state solid waste programs are discussed in
detail. Where appropriate, state controls on two of the CCW beneficial uses of concern to EPA
minefilling and soil amendmentare described.
4.5.1 Regulations Addressing Air Pollution
The federal Clean Air Act (CAA) is intended to protect and enhance the quality of the nation's
air resources. The CAA requirements most relevant to non-utilities include the following:
National Ambient Air Quality Standards (NAAQS) for particulate matter (PM)
NAAQS for sulfur dioxide
NAAQS for ozone
National Emissions Standards for Hazardous Air Pollutants (NESHAP).
Title IV acid rain provisions, the fifth set of requirements that affect fossil fuel combustors as a group,
currently apply only to the largest coal-fired utility generating units, and, therefore, are not relevant for
non-utility units. Historically, CAA requirements have been a significant factor affecting the generation
and collection of certain non-utility CCWs (specifically fly ash and FGD waste). Recent and
forthcoming changes in these requirements also may impact waste generation or characteristics, as
discussed below.
NAAQS for Particulate Matter
The NAAQS for PM establish maximum concentrations of PM with diameter less than or equal
to 10 micrometers (PM10) in the ambient air. These standards are among the factors motivating the use
of particulate control technologies at FFC facilities. EPA recently proposed to lower the size criterion to
2.5 micrometers, which may affect the volume of fly ash collected and selection of control technology;
however, final standards will not be issued for at least 5 years, so the impacts of the new standard are
difficult to predict at this time.
The NAAQS for PM are implemented through New Source Performance Standards and State
Implementation Plans.
New Source Performance Standards (NSPS). The NSPS subject newly constructed or
modified units to specific PM emissions limits. These limits may be met by changing fuel types,
modifying combustion conditions, or installing control devices. The applicability of the NSPS and the
specific limits imposed vary with the age and size of the combustion unit, with older and smaller units
less likely to be subject to the NSPS. Specifically, the regulation of non-utilities can be considered in the
following three categories (one of the four categories discussed for coal-fired utilities in Chapter
3facilities subject to Subpart Daapplies specifically to utilities; therefore, it is not relevant to non-
utilities):
40 CFR 60 Subpart D governs the standards of performance for new fossil fuel-fired steam
generators that were constructed or underwent major modification after August 17, 1971.
Subpart D affects only units that are capable of burning fossil fuels at greater than 73
megawatts (MW) of heat input rate.
Subpart Db affects coal-fired units with the capacity to fire fuel at greater than 29 MW of
heat input rate that commenced construction or modification after June 19, 1984.
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Subpart DC governs coal-fired units constructed or modified after June 9, 1989, with
capacity to fire fuel at less than 29 MW but greater than 8.7 MW of heat input rate.
The NSPS requirements discussed above apply to all fossil fuel steam generating units, utility or
non-utility. Non-utilities, however, tend to have smaller capacities than utilities, and, therefore, are more
likely captured by those NSPS requirements that apply to smaller capacity units (i.e., Subparts Db and
DC). Under the NSPS regulations, facilities that were in operation before the dates stated in each of the
subparts are considered "grandfathered" and would not be subject to the newer standards unless they
underwent a major modification.
State Implementation Plans (SIPs). The performance standards above can be enforced by a
Federal, State, or local regulatory agency. There are additional CAA regulations that could require a
coal-fired unit to install a particulate removal device notwithstanding the grandfather clause in Subparts
D, Db and DC. SIPs may impose, on a state-by-state basis, PM controls of varying stringency on specific
sources or categories of sources, including coal-fired non-utilities. Such controls are required under Title
I of the CAA if a particular area is in nonattainment for the NAAQS for a criteria pollutant such as PM.
For this reason, SIP controls will generally be more stringent in such nonattainment areas. In attainment
areas, the prevention of significant deterioration (PSD) program requires new sources to apply Best
Available Control Technology (BACT), which must be at least as stringent as NSPS.
NAAQS for Sulfur Dioxide
Like the NAAQS for PM, the NAAQS for sulfur dioxide establish a maximum concentration of
sulfur dioxide in the ambient air. The NAAQS for sulfur dioxide are implemented through NSPS and
SIPs. The functioning and applicability of the sulfur dioxide NSPS requirements are similar to those for
PM, although there is less variation based on age and size.
Each of the three categories of coal-fired non-utilities regulated under Subparts D, Db, and DC is
subject to the same requirement: sulfur dioxide emissions must be less than 520 nanograms per joule
(ng/J) of heat input. Facilities with greater than 22 MW of heat input capacity generally also must
achieve a 10-percent reduction in their sulfur dioxide emissions, based on the potential concentration in
fuel. An additional category of coal-fired facilities, those constructed or modified after June 9, 1989, and
between 2.9 and 8.7 MW of heat input capacity, also must meet the 520 ng/J standard, but may do so
based on certification from the fuel supplier that the sulfur content of the fuel is low enough to meet the
standards.
In addition to NSPS, states may impose controls through their SIPs to meet the sulfur dioxide
NAAQS. These controls may vary in stringency depending on attainment status and may be placed on
specific sources or categories of sources, including coal-fired non-utilities.
In spite of the similarities in NAAQS programs for sulfur dioxide for utilities and non-utilities,
the prevalence of FGD technologies among non-utilities is less than that among utilities (see Section 4.1).
This may be because Title IV requirements currently do not apply to non-utilities, because of the lack of
percent reduction requirements on these smaller facilities, because of differences in fuel characteristics,
and/or because of differences in SIP requirements for non-utilities.
NAAQS for Ozone
The NAAQS for ozone establish a maximum concentration of ozone in the ambient air. EPA
recently lowered this concentration from 0.12 parts per million (ppm) to 0.08 ppm. The new standard
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allows four exceedences of the maximum in a region over a 3-year period. EPA expects states will meet
the new standard by amending their SIPs to limit nitrogen oxide emissions at utilities. Therefore, the
recent changes are not expected to affect non-utilities (and, in turn, non-utility waste generation)
significantly.
NESHAP
Under the NESHAP, EPA is required to establish technology-based standards for 189 hazardous
air pollutants (HAPs). These standards are to be set on an industrial category basis and will apply to
facilities that emit greater than 10 tons/year of any one HAP or greater than 25 tons/year of any
combination of HAPs.
EPA has not specifically studied HAP emissions from non-utility coal combustors. Because
NESHAP will be set on an industrial category basis, when promulgated, the impact of these regulations
on waste generation and characteristics may vary depending on the industrial sector of the non-utility
combustor.
4.5.2 Regulations Addressing Water Pollution
Under the federal Clean Water Act, the National Pollutant Discharge Elimination System
(NPDES) controls discharges to waters of the United States. As discussed below, the controls required
under NPDES affect the collection and management of CCWs. In states authorized by EPA, these
controls are implemented through state programs (often termed State Pollutant Discharge Elimination
Systems, or SPDES). Because state programs must be at least as stringent as the federal program, the
discussion here focuses on federal requirements as a lowest common denominator. NPDES requirements
apply differently to two categories of discharges: process wastewaters and stormwater runoff.
NPDES Requirements for Process Wastewaters
Non-utility coal combustors face NPDES requirements for process wastewaters that are specific
to their industrial sectors. In most cases, under these requirements each discharge requires an individual
NPDES permit with numeric limitations based on Best Practicable Control Technology Currently
Available (BPT), Best Available Technology Economically Achievable (BAT), or New Source
Performance Standards (NSPS). Facilities that discharge to publicly owned treatment works (POTWs)
rather than directly to surface waters face Pretreatment Standards for Existing Sources (PSES) similar to
BAT or BPT or Pretreatment Standards for New Sources (PSNS) similar to NSPS.
As discussed in Section 4.3, non-utility CCWs are rarely managed wet (although they may be
conditioned with liquids during management for dust control). Therefore, the NPDES process
wastewater requirements generally are not relevant to management of these wastes. In those cases in
which these wastes are managed wet, the most relevant requirements are total suspended solids (TSS)
limits. The specific NPDES effluent standards applicable to a non-utility depend on the facility's
industrial category. Effluent standards expected to apply to large numbers of non-utility fossil fuel
combustors include those for the following industry categories:
Pulp, paper, and paperboard (40 CFR Part 430)
Organic chemicals, plastics, and synthetic fibers (40 CFR Part 414)
Inorganic chemicals manufacturing (40 CFR Part 415)
Textile mills (40 CFR Part 410)
Timber products processing (40 CFR Part 429)
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Iron and steel manufacturing (40 CFR Part 420)
Sugar processing (40 CFR Part 409)
Grain mills (40 CFR Part 406).
The standards for these categories include TSS limits, and these limits are applicable to nearly all
of the industrial subcategories covered under each category. Some subcategories are subject to zero
discharge requirements. Based on the SIC codes reported by non-utilities in the 1990 U.S. EPA National
Emissions Inventory database, these industrial category requirements are expected to cover roughly 20
percent of non-utility fossil fuel combustors. A number of other facilities are scattered through other
industrial categories, many of which are also subject to TSS limits. Some facilities (such as institutional
fossil fuel combustors) may not be subject to the specific standards of any industrial category. In these
cases, the specific effluent limitations would be determined on a case-by-case basis as part of the non-
utility's individual NPDES permit.
In addition, the steam electric category NPDES requirements applicable to utilities also may be
incorporated in individual permits at non-utilities to supplement their industrial category requirements.
Application of steam electric requirements to relevant waste streams at non-utility fossil fuel combustors
is left to the best professional judgement of the individual permit writer (EPA, 1996). The steam electric
category NPDES requirements place TSS limits directly on fly ash handling and bottom ash handling
waters. In addition, the NSPS for the steam electric category include a zero discharge requirement for fly
ash handling water.
In those cases in which non-utility CCWs are managed wet, the TSS and zero discharge
requirements discussed above are relevant as follows. Facilities may have to settle or otherwise remove a
certain amount of waste solids from the handling water to meet the TSS limits prior to discharge. Zero
discharge requirements effectively eliminate the release of waste solids to surface water; thus, the
requirements control the direct release of fly ash, bottom ash, and any treatment solids to surface waters.
NPDES Requirements for Stormwater
NPDES Stormwater requirements apply to Stormwater runoff from FFC facilities. Stormwater
runoff may include runoff from operating areas, ash handling areas, and waste management units. Like
the process wastewater requirements, Stormwater requirements have been established on an industrial
sector basis. The NPDES Stormwater requirements, however, are additive across industrial sectors.
Therefore, steam electric Stormwater requirements apply to non-utilities just as they apply to utilities.
A chemical manufacturer, for example, operating a fossil fuel-fired boiler must meet both chemical
manufacturing and steam electric requirements.
Facilities can meet the Stormwater requirements by including Stormwater in their individual
NPDES permit or seeking coverage under a general permit by submitting a Notice of Intent (NOI).
Individual permit control and monitoring requirements will be facility-specific, subject to the judgment
of the permit writer.
When covered by a general Stormwater permit, requirements include implementation of a
Stormwater pollution prevention plan, "reasonable and appropriate" control measures, and 1 or 2 years of
monitoring and reporting. No site visit by regulators is required under the general permit. Under the
general permit approach, non-utilities have a great deal of flexibility in selecting appropriate control
measures for runoff that may have contacted CCWs. The general permit requirements include
recommended best management practices for Stormwater at steam electric facilities, landfills, treatment
works, and construction areas greater than 5 acres. Because these requirements are additive across
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industrial sectors, if the hypothetical chemical manufacturer described above also operated an onsite ash
landfill, that facility would have to meet landfill requirements in addition to chemical manufacturing and
steam electric requirements.
Because the stormwater program is relatively new and managed only by authorized states, the
number of facilities with general versus individual permits is not known. EPA handles NOIs for 10
nonauthorized states. In these states, 700 steam electric facilities (both utility and non-utility) have filed
for general permits.
4.5.3 Regulations Addressing Solid and Hazardous Waste
EPA regulates the management of solid and hazardous waste through Subtitles C and D of the
federal Resource Conservation and Recovery Act (RCRA). Subtitle C of RCRA establishes a "cradle-to-
grave" management system for wastes that are considered hazardous because they fail tests based on their
physical and chemical characteristics (i.e., toxicity, corrosivity, ignitability, and reactivity) or because
they are listed as hazardous by EPA. Federal regulations establish stringent environmental and
administrative controls that must be applied to the management of these wastes. Non-utility coal
combustion wastes are currently exempt from federal regulation as hazardous waste under Subtitle C
pending this Report to Congress and the subsequent regulatory determination. Therefore, these wastes
currently are subject to the requirements of Subtitle D of RCRA as nonhazardous solid waste.
Implementation of Subtitle D is the responsibility of individual states, but nothing prevents states
from imposing more stringent requirements (including hazardous waste requirements) on FFC wastes.
Currently, 44 states (representing 87 percent of non-utility coal-fired electrical generation capacity)
duplicate the federal policy exempting CCWs from hazardous waste regulations. The six remaining
states (Kentucky, Tennessee, Washington, New Jersey, Maine, and California) do not exempt CCWs
from hazardous waste regulation. In these states, non-utility CCWs that fail the hazardous waste
characteristic tests are subject to hazardous waste requirements. These wastes, therefore, must be
managed in units that meet permitting, design, operating, corrective action, and closure standards.
Based on available characterization data, however, non-utility CCWs seldom are expected to fail
the hazardous waste characteristic tests. The majority of non-utility CCWs would be subject to state
requirements under Subtitle D because they do not fail the hazardous waste tests and/or are generated in
the 44 states that duplicate the federal exemption. States generally regulate onsite waste management
units that handle only non-utility CCWs using the same regulatory approaches used for utility CCW
management units. They often regulate units, both onsite and offsite, that manage non-utility CCWs
along with other nonhazardous industrial wastes in accordance with industrial Subtitle D programs.
These programs are expected to be essentially the same as those applicable to CCW-only management
units. Detailed review of regulations in several states supports the view that states regulate non-utility
CCWs in the same manner as utility CCWs.
Table 4-8 shows data on state regulatory authority with respect to non-utility CCW landfills.
These data show that the majority of states have the authority to require permits and to impose physical
controls and monitoring requirements on non-utility landfills, at least on a case-by-case basis. The types
of regulatory controls include siting controls, liners, leachate collection systems, ground-water
monitoring, closure controls, daily (or other operational) cover, and fugitive dust controls. EPA believes
that the use of such controls has the potential to mitigate risks, particularly ground-water pathway risks,
from comanaged waste disposal. The sufficiency of this mitigation depends on the extent to which states
are exercising their authority in situations in which climate, geology, site-specific conditions, and waste
characteristics affect the magnitude of the risk.
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Table 4-8. State Regulatory Controls on Non-Utility Coal Combustion Waste Landfills
Hazardous Waste Exemption3
Permit Onsite
Permit Offsite
Siting Controls
Liners
Leachate Collection Systems
Ground-Water Monitoring
Closure Controls
Cover and/or Dust Controls
Number of States"
44
41
48
46
43
42
46
45
49
Percent of States0
88%
82%
96%
96%
86%
84%
92%
90%
98%
Percent of Capacity
87%
82%
96%
89%
88%
81%
90%
94%
96%
a Exemption from state hazardous waste regulations for coal combustion wastes
" Number of states with authority to impose the indicated requirement, either by regulation or on a case-by-case basis
c Percent of surveyed states with authority
d Percent of surveyed generating capacity represented by states with authority
Sources: CIBO, 1997c; ASTSWMO, 1995; EPA, 1995b; and ACAA, 1996a
Section 4.3 summarizes the use of regulatory permits and environmental controls at non-utility
waste management units. The available data suggest that states have exercised their authority to impose
controls, although perhaps to a lesser extent at non-utilities than at utilities. To further examine state
implementation of solid waste requirements on non-utility CCWs, EPA examined in greater detail the
regulations applicable in five states: Indiana, Pennsylvania, Wisconsin, North Carolina, and Virginia.
These five states account for more than 20 percent of coal-fired non-utility electrical generation capacity.
Table 4-9 summarizes the requirements in each of these five states. Because surface impoundments are
uncommon for non-utilities, this analysis focuses on landfill regulations.
Based on this detailed analysis, it appears that state requirements have become increasingly
stringent over time. States vary in their approaches to regulating non-utility CCW landfills. For
example, programs in Indiana and Pennsylvania impose requirements tailored to the characteristics of the
waste. North Carolina may impose requirements based on site-specific modeling. In Virginia,
requirements apply generically to all industrial wastes. Wisconsin may modify its requirements
specifically for landfills designed to receive coal combustion ash. In several of the states studied, CCWs
may be disposed of in older landfills that are "grandfathered" out of requirements imposing design
requirements such as liners.
Table 4-9. State Waste Management Requirements Applicable to Non-Utility CCWs
in Selected States
Indiana
Landfill
Requirements
Grandfather Clause
Landfills are classified according to TCLP results for the wastes to be disposed. Specific design
requirements depend on the class of the landfill. Based on available characterization data, most non-
utility CCWs would be amenable to Type III landfills. Requirements for these include clay liner
(thickness of 3 feet), siting restrictions, fugitive dust control, weekly cover, soil erosion control, 2-foot
clay cap at closure, and revegetation at closure. Leachate collection systems are not required but may
be used in some cases to relax the liner thickness requirements.
Facilities that existed prior to September 1989 may continue to operate, but any expansions at these
facilities must comply with the requirements above.
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Pennsylvania
Landfill
Requirements
Grandfather Clause
Minefill
Requirements
Soil Amendment
Requirements
Landfills are classified according to TCLP results for the wastes to be disposed. Specific design
requirements depend on the class of the landfill. Based on available characterization data, most non-
utility CCWs would be amenable to Class III landfills. Requirements for these include siting restrictions,
a 4-foot attenuating soil base (or 1 -foot-per-4-feet of waste), fugitive dust control, daily cover, soil
erosion control, ground-water monitoring, 2-foot clay cap at closure, and revegetation at closure.
Units permitted prior to July 4, 1992 were required to modify their operations to comply with the above
requirements by July 4, 1 997. Liner and leachate collection requirements may be modified if the
operator can demonstrate that the unit has not caused unacceptable ground-water degradation.
CCWs must meet TCLP limits for disposal at a Class III landfill. Ground-water monitoring is required.
CCWs must meet pH limits. State agency notification and runoff and erosion controls are required.
There are siting limitations.
North Carolina
Landfill
Requirements
Grandfather Clause
Industrial waste landfills must demonstrate that their design will ensure that the state ground-water
standards are not exceeded at the compliance boundary. The design criteria for demonstrating this
include a composite liner, leachate collection system, and cap at closure. Alternatively, the operator
may submit ground-water modeling results that demonstrate, based on hydrologic and climatic
conditions and waste characteristics, that the standards will be met.
To continue operating after January 1 , 1 998, landfills operating prior to October 1 , 1 995 must
demonstrate that their original design or proposed design changes will meet the ground-water
standards. The state has the authority to require design modifications if ground-water modeling
methods or results are inadequate.
Wisconsin
Landfill
Requirements
Grandfather Clause
Requirements include clay or composite liners, leachate collection systems, fugitive dust controls, 2-foot
clay cap at closure, revegetation at closure, and ground-water monitoring. The state may modify the
requirements for landfills designed to receive "high-volume" industrial waste, specifically coal ash waste,
on a case-by-case basis.
Landfills with plan of operations approved prior to July 1, 1996, are exempt from liner and leachate
collection requirements. For landfills constructed prior to February 1, 1988, the state may require
ground-water monitoring on a case-by-case basis.
Virginia
Landfill
Requirements
There are separate programs for industrial landfills and sanitary landfills. While sanitary landfills
primarily manage household waste, they are allowed to receive nonhazardous industrial solid wastes,
such as CCWs. Offsite landfills may be either industrial or sanitary landfills; onsite landfills are expected
to be industrial landfills.
For industrial landfills, design requirements include leachate collection systems, run-on controls, liner (1
foot of compacted clay or equivalent), cap at closure, fugitive dust controls, and ground-water
monitoring. A double liner system in which the primary liner is synthetic may be used in lieu of ground-
water monitoring. For fly ash and bottom ash from the combustion of fossil fuels, periodic cover or dust
control measures such as surface wetting or crusting agents are required.
For sanitary landfills, design requirements include leachate collection systems, run-on and run-off
controls, composite liner, cap at closure, revegetation at closure, daily cover, fugitive dust control, and
ground-water monitoring. Air pollution control residues (such as fly ash) should be incorporated into the
working face of the landfill and periodically covered to prevent them from becoming airborne.
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Grandfather Clause
Minefill
Requirements
Soil Amendment
Requirements
Landfills permitted prior to 1988 must submit a monitoring plan, but may continue operating without
retrofits as long as they do not expand.
Use in structural fills, mine reclamation, or mine refuse disposal requires notification and development of
design, operation, and closure plans. CCWs thus used must not exceed the toxicity characteristic levels
for metals. Fugitive dust and run-on and runoff controls and 18 inches of cover at closure are required.
Agricultural uses of CCW are exempt from the solid waste regulations provided they meet the
requirements of the Virginia Department of Agriculture and Consumer Services.
4.6 WASTE MANAGEMENT ALTERNATIVES
The risk assessment identified potential ground-water pathway risks to human health from non-
utility CCWs managed in unlined landfills. Mitigation of these potential risks might be accomplished
through the use of technologies that prevent or contain and collect leachate from non-utility CCW
landfills. Specifically, EPA identified the combination of technologies in Table 4-10 as an alternative
that would be practical and effective to target and mitigate the potential ground-water risk. The
technologies shown in Table 4-10 are considered further in the cost and economic impact analysis
(Section 4.7). Section 4.7 includes the option of sending waste to an offsite commercial landfill
employing these technologies as well as the option of constructing such a unit on site. Note that these
technologies are consistent with those required under Subtitle D of RCRA.
Table 4-10. Management Alternatives for Non-Utility Coal Combustion Waste
Landfill
Design includes filter fabric, T sand layer, 2' clay liner, synthetic high-density polyethelene (HOPE) liner, leachate collection
system, and ground-water wells.
Operation includes environmental monitoring, leachate collection and treatment.
Closure requirements include 6" topsoil and vegetation, filter fabric, 1.5' sand layer, 2' clay layer, synthetic (HOPE) liner, and
a cover drainage system.
Post-closure includes environmental monitoring, landscape maintenance, slope maintenance, inspection, and administration.
In addition to landfill disposal, agricultural use may be of environmental concern, based on the
above-ground risk assessment that found potential arsenic risks to human health from this practice. An
approach for mitigating this potential risk might include a standard limiting the arsenic concentration in
wastes intended for this use. Because of the small quantity of waste potentially affected, EPA has not
estimated cost for such an alternative. Minefilling also may be of concern, particularly when wastes are
placed below the water table. EPA is seeking further information on this practice.
4.7 COMPLIANCE COSTS AND ECONOMIC IMPACTS
This section discusses the costs and economic impacts of risk mitigation alternatives for non-
utility CCWs. Details of this analysis, together with a background describing the variety of industries
represented, are documented as part of the EPA docket.
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4.7.1 Overview and Methodology
In estimating costs and economic impacts for non-utilities, EPA used a similar approach to that
described in Section 3.7.1 for coal-fired utilities. Salient distinctions between the utility analysis and this
non-utility analysis are reviewed below.
EPA's analysis for non-utilities began with 958 facilities identified in the 1990 U.S. EPA
National Interim Emissions Inventory database (EPA, 1990). EPA estimated the incremental compliance
cost of the risk mitigation alternative described in Section 4.6. As described in that section, this requires
generators to construct onsite composite-lined landfills or transport waste to an offsite commercial
Subtitle D landfill. The more economical method was assigned to each plant depending upon its estimate
annual CCW generation rate.
The cost estimate summed costs in five categories: initial capital costs, recurring capital costs,
annual operating and maintenance costs, closure costs, and annual post-closure costs. The specific
components included in each cost category were the same as those in the utility analysis (see Section
3.7.1). As in the utility analysis, the cost estimate employed three different landfill sizes. Table 4-11
identifies the design features for non-utility landfills.
As in the utility analysis, a single cost equation was developed, annualized costs were estimated
as a function of facility-specific waste generation, and total industry costs were derived by summing the
facility-specific estimates. Costs and economic impacts are set forth in the following three sections:
incremental compliance cost, compliance cost impact on facilities as a function of size, and industry
impact. Incremental compliance costs are the costs of risk mitigation practices over and above the cost
of current management practices. Using incremental compliance costs as an indicator of potential cost
burden, the analysis examined impacts on individual facilities as a function of size. Unlike for the utility
analysis, this was performed using industry average sales for only the average and large facilities.
Detailed financial profiles of representative "model" facilities were not developed for the non-utility
sector because of the data collection requirements and multiplicity of facilities involved.
For the industry impact evaluation, the use of econometric models was considered and rejected
because of the diversity of industrial and institutional sectors potentially affected. The industry-level
analysis, therefore, focuses on the same two measurements used in the utility analysis: the number of
affected facilities and the magnitude of incremental compliance costs relative to the value of electricity
sales.
4.7.2 Incremental Compliance Cost
EPA's estimate of incremental compliance cost for non-utility coal combustors is approximately
$103 million per year. This compliance cost would be distributed across the range of industries
represented by non-utility combustors. Table 4-12 summarizes the details of this cost estimate by non-
utility industry SIC code. As with the utility sector, delayed compliance, were this to be considered,
would result in far lower costs.
Note that the costs shown are incremental (above current costs). Annual costs were discounted
at 7 percent to 1998 dollars, with no inflation built into out-year estimates. Also, it was presumed that
compliance would be required immediately, and that amortization would take place over 40 years.
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Table 4-11. Design Parameters Assumed for Small, Medium, and Large Landfills
Parameter
Sizes
(tons/year)
Depth
(feet)
Height
(feet)
Area
(acres)
Note: Landfill designs considered include a
constructed both above and below grade.
small
medium
large
small
medium
large
small
medium
large
small
medium
large
small
medium
large
small
medium
large
small
medium
large
Non-Utility Ash Landfill
150
5,000
15,000
Pile design
1.0
1.0
1.0
Combination fill design
3.3
17.4
43.6
Pile design
15.0
25.0
25.0
Combination fill design
4.3
22.2
28.1
Pile design
0.4
5.6
15.7
Combination fill design
0.5
3.5
6.5
'pile design" constructed primarily above grade and a "combination fill design"
4.7.3 Compliance Cost Impact on Facilities as a Function of Size
EPA believes that the ability of industry to pass through cost increases will be limited because
only a small share of plants within the affected industries operate coal-fired boilers. Competition from
unaffected facilities would restrict the ability of facilities facing incremental compliance costs to increase
prices. Therefore, this analysis includes no analytical consideration of price effects.
As discussed previously in this chapter, non-utility CCWs are generated by a wide variety of
industrial and institutional facilities that generate electricity or energy for primarily internal use. In
general, the affected facilities represent a small share of an industry or economic sector, and fossil fuel
use and costs are a relatively small part of production inputs and costs. The most common types of
facilities affected include pulp and paper mills, food processing facilities, chemical manufacturers,
cement manufacturers, and educational institutions/universities.
The order of magnitude of expected facility-level impacts can be demonstrated by examining one
industry sector as an example. In 1992, the Bureau of the Census reported there were about 15,000
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Table 4-12. Cost Estimates for Non-Utility CCW
(1998 million $/yr, annualized)
SIC Code
20
21
22
25
26
28
29
30
32
33
34
35
36
37
49
80
82
92
97
Industry
Food and Kindred Products
Tobacco Manufactures
Textile Mill Products
Furniture and Fixtures
Paper and Allied Products
Chemicals and Allied Products
Petroleum and Coal Products
Rubber and Miscellaneous Plastics Products
Stone, Clay, and Glass Products
Primary Metal Industries
Fabricated Metal Products
Industrial Machinery and Equipment
Electric and Electronic Equipment
Transportation Equipment
Electric, Gas, and Sanitary Services
Health Services
Educational Services
Justice, Public Order, and Safety
National Security and International Affairs
Other SICs
Unknown SICs
Totals
Number of Facilities
98
11
59
35
140
114
12
21
17
44
21
26
15
61
44
58
77
26
17
53
9
958
Incremental Costs
$9.7
$0.9
$3.2
$0.1
$24.4
$23.8
$0.7
$1.5
$1.3
$4.1
$1.2
$1.6
$0.9
$3.4
$12.3
$2.5
$5.3
$0.9
$0.7
$4.5
$0.3
$103.3
establishments engaged in food processing (SIC 20) with an annual value of shipments of $281 billion.
Based on these numbers, the average food processing facility had approximately $19 million per year in
sales. In comparison, only 98 food processing facilitiesthose burning coalwould be expected to
incur incremental compliance costs. Annualized, these costs are estimated to be $9.7 million, or about
$100,000 per facility per year. Thus, for this industry, less than 1 percent of the facilities would incur
any impacts. The cost would equal about 0.5 percent of annual sales for each facility4 Most affected
facilities, however, are expected to be relatively large as only large facilities can usually justify captive
coal-fired boiler operations. In 1992, the food processing industry contained 2,788 facilities that
employed 100 or more employees. These larger facilities had a combined value of shipments of
4 In these estimates, sales are in 1992 dollars and compliance costs in 1998 dollars. Therefore, the figures
shown may overestimate impacts.
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$225 billion or $81 million per facility. Thus, if the 98 affected facilities were all large, still only 1 in 30
would be affected and the incremental compliance costs would be 0.1 percent of annual sales.
Table 4-13 shows similar comparisons for other major non-utility industry sectors. The sectors
presented include food processing facilities, pulp and paper mills, chemical manufacturers, primary
metals manufacturers, and transportation equipment manufacturers. Together, these five industries
account for approximately 80 percent of non-utility CCW generation, based on data from the 1990
U.S. EPA National Interim Emissions Inventory. In general, facilities in these sectors should not incur
significant overall cost burdens; however, the incremental cost could significantly affect their energy use
practices by causing some facilities to switch from internal generation to external purchase, similar to the
practices of most facilities in the affected industries, to avoid the regulatory burden and to obtain cheaper
energy.
Table 4-13. Facility-Level Economic Impacts, Non-Utility CCW
Sector
Food Processing
Pulp and Paper
Chemical
Manufacturing
Primary Metals
Transportation
Equipment
Number of
Affected
Facilities
98
140
141
44
61
Facility Size
Average
Large
Average
Large
Average
Large
Average
Large
Average
Large
Average
Facility Sales
(1992 $ million/yr)
$19
$81
$118
$151
$26
$157
$21
$85
$35
$217
Average Facility
Incremental
Compliance Cost
(1998 $ million/yr)
$0.10
$0.10
$0.17
$0.17
$0.21
$0.21
$0.09
$0.09
$0.06
$0.06
Compliance Cost as
a Percentage
of Sales
0.5%
0.1%
0.2%
0.1%
0.8%
0.1%
0.4%
0.1%
0.2%
0.03%
Note: Large facilities are establishments with more than 100 employees.
4.7.4 Industry Impacts
This analysis addresses the major non-utility industries shown in Table 4-14. For example, the
food processing sector would incur incremental costs of $9.7 million per year; however, the food
processing sector was a $448-billion-per-year industry in 1995. Thus, incremental compliance costs
would represent less than 0.002 percent of overall market value. Moreover, only about 1 out of every
150 facilities would be affected directly. Similar results are evident for other major non-utility industry
sectors, as shown in Table 4-14.
4.8 FINDINGS AND RECOMMENDATIONS
4.8.1 Introduction
Based on the information collected for this Report to Congress, this section presents a summary
of the Agency's main findings presented under headings that parallel the organization of this chapter. It
then presents the Agency's tentative conclusions concerning the disposal and beneficial uses of wastes
generated at non-utilities, including wastes from the burning of coal and petroleum coke and the
coburning of other fuels with coal as identified in this chapter.
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Table 4-14. Industry-Level Economic Impacts, Non-Utility CCW
Sector
Food Processing
Pulp and Paper
Chemical Manufacturing
Primary Metals
Transportation Equipment
Other Industrial/Institutional
Industry Sales
(Sbillion/yr)
$448
$52
$362
$180
$463
Not estimated
Incremental Compliance
Cost ($billion/yr)
$0.010
$0.024
$0.024
$0.004
$0.003
$0.026
Compliance Cost as a
Percentage of Sales
0.002%
0.050%
0.010%
0.002%
0.001%
Note: Sales are in 1995 dollars and compliance costs in 1998 dollars. Therefore, the percentages shown may overestimate
impacts.
4.8.2 Findings
Sector Profile
There are no comprehensive data on industry-wide generation of non-utility coal
combustion wastes. The Agency was able to characterize the sector profile based on major
stationary point sources of air emissions but not the smaller combustors. On this basis, the
Agency identified 958 major non-utility burners of coal, petroleum coke, and other fuels
that are coburned with coal. The eastern United States has a larger concentration of these
facilities than the western United States.
There are approximately 2,300 boilers in operation at the major non-utility facilities.
Non-utilities burn these fuels for a variety of purposes, including manufacturing process
steam production, hot water, space heating, and captive electric power generation. They
include industrial, commercial, and institutional facilities. They are located in diverse
environments, including areas that vary widely in population density, geography,
precipitation, and general climate.
Waste Generation and Characteristics
Non-utility burners of coal and petroleum coke generate the same types of large-volume and
low-volume wastes as utilities. They employ the same types of combustion technologies
and combustion support processes as the utilities. The major non-utility facilities generate
nearly 6-million tons per year of the high-volume wastes.
Wastes from non-utility burners appear to be similar to their counterpart utility wastes.
Similarly, the constituents of concern are trace metal elements, particularly the eight RCRA
metals.
The total quantities of low-volume wastes generated at these facilities is not well
established; however, the aggregate quantities are much lower than utility low-volume
wastes.
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Waste Management Practices
Landfills appear to be the predominant type of waste management unit for the disposal of
wastes. Limited information suggests that the majority of combustion wastes are disposed
in offsite landfills. Surface impoundments appear to be the only other type of waste
management unit employed, and they are infrequently used.
Combustion wastes are more frequently comanaged with low-volume wastes or a diverse
range of other (unrelated) industrial wastes as opposed to separate management.
Comprehensive statistics are not available on the amounts of these wastes that serve
beneficial uses. Available information suggests that use of these materials as a component
in cement and concrete and as construction fill are the most common beneficial uses.
Potential Risks and Damage Cases
EPA conducted a risk assessment that found a lack of potential human health risk for
virtually all waste constituents. Arsenic was the one constituent for which the Agency
identified potential human health risks via the ground-water pathway where the combustion
wastes are managed alone or comanaged with low-volume wastes in landfills. The
identified risk is based on high-end risk scenarios in EPA's risk modeling analysis for
human ingestion of well water influenced by releases from the waste management unit. The
time to reach the health-based level for arsenic in ground water at the receptor well is
estimated to be in excess of 1,400 years.
EPA conducted a risk assessment that found a lack of potential human health risk for
virtually all waste constituents. Arsenic was the one constituent for which the Agency
identified potential human health risks via non-ground-water pathways where these wastes
are used as soil amendments for agricultural purposes. The identified risk is based on high-
end risk scenarios in EPA's risk modeling analysis for human ingestion exposure routes.
No ecological risks were identified for management of wastes in this sector.
No damage cases were identified for this sector that exclusively involve these wastes,
although this finding is based on rather limited information. Two superfund National
Priority List sites were identified that involve coal combustion wastes. These sites are
considered to be damage cases, but other wastes unrelated to the generation of CCWs were
comanaged at these sites, and there is uncertainty about the contributing influences of the
CCWs. Arsenic was identified as a constituent of concern in these two damage cases, but
because of the mixed wastes, it could not be conclusively attributed to the CCW component.
Some natural arsenic levels in U.S. soils have the potential to pose higher risks than the risk
identified with the level of arsenic contributed by these wastes for non-ground-water
pathways.
Existing Regulatory Controls, State and Federal Requirements
The major facilities in the non-utility sector have a significant level of installed
environmental controls for these wastes that mitigate the potential human health risks
identified in this study.
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States have increasingly begun to impose controls on these wastes. The states vary
somewhat in their approaches to regulating these wastes; however, in aggregate, there is
existing state authority to impose substantial regulatory controls on these wastes. For
example, there exists authority at the state level to impose siting controls, liners
requirements, leachate collection systems, and permit procedures for more than 80 percent
of the generated wastes. There exists additional authority at the state level to impose
ground-water monitoring requirements, closure controls, and dust/cover controls for more
than 90 percent of the generated wastes.
Potential Costs and Impacts of Regulation
The Agency estimates that the total annual incremental compliance costs for mitigation of
the potential arsenic risks identified in this study would be approximately $100 million
(1998$). These costs represent replacement of existing unlined management units with
lined management units, and implementing ground-water monitoring and leachate collection
and treatment. These measures do not represent implementation of full Subtitle C
requirements, but rather modifications of such requirements that could potentially be
adopted under Section 3004(x) of RCRA.
If these wastes were to be regulated under full Subtitle C, virtually all existing facilities
would be required to invest substantial funds and resources to modify existing management
practices. The total annual cost of full Subtitle C requirements would considerably exceed
the $100 million (1998 $) estimate above.
If beneficial uses of theses wastes were subject to Subtitle C requirement, possibly all
beneficial use practices and markets would cease.
4.8.3 Recommendations
Following are the Agency's recommendations for the wastes covered in this chapter. The
recommendations are based on EPA's analysis of the eight Congressionally mandated study factors
(Section 1.2). These conclusions are subject to change based on continuing information collection,
continuing consultations with other government agencies and the Congress, and comments and new
information submitted to EPA during the comment period and any public hearings on this report. The
final Agency decision on the appropriate regulatory status for these wastes will be issued after receipt
and consideration of comments as part of the Regulatory Determination, which will be issued within 6
months.
1. The Agency has tentatively concluded that disposal of these wastes should remain exempt from
RCRA Subtitle C.
As with the utility coal combustion wastes addressed in Chapter 3, the Agency has tentatively
concluded that the non-utility CCWs, including wastes from petroleum coke combustion and from other
fuels that are co-fired with coal, and also low-volume wastes where they are managed with the
combustion wastes, generally present a low inherent toxicity, are seldom characteristically hazardous,
and generally do not present a risk to human health and the environment. State programs increasingly
require more sophisticated environmental controls at these types of facilities. There are few damage
cases and none of the identified damage cases exclusively involved these wastes or affected human
receptors. These types of facilities are typically located in areas of low population and thus present
infrequent opportunity for human exposure. The Agency believes that no significant ecological risks are
posed by disposal of these wastes. The predominant practice is to manage these wastes in landfills, with
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a much lower frequency of using impoundments. Environmental controls are common at the landfills.
For example, nearly all implement ground-water monitoring and runoff controls, and two-thirds have
leachate collection. Overall, the Agency believes that when these wastes are disposed, regulation under
Subtitle C authority is not warranted. For the issues discussed below involving agricultural use and
management of these wastes in mines (minefill), the Agency is still considering whether some regulation
under RCRA Subtitle C may be warranted.
There is a very small segment of non-utility coal burners that generates mill rejects, a low-
volume waste, that may be comanaged with the CCWs. The Agency has the same concerns about the
potential for problem management situations involving pyritic materials as described for utilities in
Chapter 3. Although the Agency did not identify any of these situations at non-utility facilities during
this study, it is engaging the non-utility sector in a program to ensure that these particular wastes are
appropriately managed. This effort parallels the pyrites management program described for utilities in
Chapter 3. EPA will follow-up with oversight on the industry's management of these wastes, and will
revisit this issue if necessary.
2. The Agency has tentatively concluded that most beneficial uses of these wastes should remain
exempt from Subtitle C.
No significant risks to human health and the environment were identified or believed to exist for
any beneficial uses of these wastes, with the possible exception of minefill and agricultural use as
discussed below. This is based on one or more of the following reasons for each use or resulting product:
absence of identifiable damage cases, fixation of the waste in finished products which immobilizes the
material, and/or low probability of human exposure to the material.
3. The Agency is tentatively considering the option of subjecting practices involving the use of these
wastes for agricultural purposes (i.e., as a soil nutrient supplement or other amendment) to some
form of regulation under Subtitle C.
As mentioned above, the Agency identified potential risk from exposure to arsenic in these
wastes when they are used for agricultural purposes. The risks identified with this practice may be of
sufficient concern to consider whether some form of control under Subtitle C is appropriate, given the
increasing trend for use of these materials as agricultural amendments. An example of such controls
could include regulation of the content of these materials such that arsenic concentrations could be no
higher than that found in agricultural lime. On the other hand, imposition of controls under Subtitle C
may not be warranted if sufficient protection may be afforded by the Agency engaging the industry to
establish voluntary controls on this practice. An example of such voluntary controls could consist of an
agreement to limit the level of arsenic in these materials. The Agency solicits comment on its tentative
conclusion and specific approaches that could be pursued to address the concern.
Non-utility burners of coal, particularly those that generate significant quantities of combustion
wastes, may have opportunities for their wastes to be minefilled, that is, permanently placed in mine
voids similar to the practice with some utility combustion wastes. As discussed in Chapter 3, the Agency
currently lacks sufficient information with which to adequately assess risk associated with this practice
and, therefore, to decide whether this practice should remain exempt from Subtitle C. For the same
reasons discussed in Chapter 3's recommendations, the Agency solicits comment on whether there are
some minefill practices that are universally poor and warrant specific attention. EPA also seeks comment
on whether coal or other fossil fuel combustion wastes used as minefill and placed in direct contact with
the water table would create environmental concerns, and if that specific practice should be regulated.
The Agency's focus is on potential risks that may be posed via the ground-water and surface pathways
from use of these wastes as minefill.
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5.0 FLUIDIZED BED COMBUSTION WASTES
Fluidized bed combustion (FBC) is an emerging technology for the combustion of fossil and
other fuels. Coal is the most common fossil fuel burned by FBC facilities, although some facilities burn
waste coal, petroleum coke, or other fuels. This chapter covers FBC wastes from facilities combusting
all types of fossil fuels (e.g., including petroleum coke). FBC makes up only a portion of the fossil fuel
combustion (FFC) universeapproximately 1 percent of fossil fuel-fired capacity. The potential for
increased use of the technology and the potential differences in waste characteristics, however, led EPA
to consider FBC wastes separately from coal combustion wastes from conventional technologies in its
1993 Regulatory Determination (58 FR 42466, 8/9/93). For the same reasons, FBC is presented
separately for analysis in this report.
SECTOR OVERVIEW
FBC technology is used in both the utility and non-utility sectors. Approximately half of the
facilities using FBC technologies are utilities or independent power producers. Facilities in the food
products and pulp and paper industries, along with educational institutions, make up most of the non-
utility FBC facilities. Other industries represented include chemicals and allied products, petroleum
refining, transportation equipment, wholesale trade, and research services. Also included are municipal
government buildings and one correctional facility.
Although FBC technology accounts for a small proportion of capacity relative to the other
sectors considered in this report, use of the technology has increased dramatically over the last 20 years.
In 1978, there were four plants with four FBC boilers in the United States. As of December 1996, there
were 84 facilities with 123 FBC boilers representing 4,951 megawatts of equivalent electrical generating
capacity (CIBO, 1997c). Furthermore, the fuel flexibility, efficiency, and emissions characteristics of
FBC boilers are such that use of the technology has the potential to increase in the future.
Figure 5-1 shows the geographic distribution of FBC facilities. While these facilities are
distributed throughout the United States, Pennsylvania and California account for the largest numbers of
plants. Pennsylvania accounts for more than 20 percent of capacity and California more than 10 percent.
As discussed in Section 5.3, FBC facilities practice both onsite and offsite waste management. Offsite
waste management units are located near the generating facility in most cases. Therefore, the geographic
distribution of combustion facilities presented in Figure 5-1 also is generally representative of the
universe of waste management unit locations.
5.1 WASTE GENERATION
The two main waste streams generated in FBC processes are listed below:
Bed ash (or bottom ash). Spent bed material and fuel ash removed from the boiler bottom.
Fly ash. Ash removed from the entrained air stream.
As for the wastes from conventional combustion technologies discussed in Chapters 3 and 4, the
generation of FBC wastes is governed by combustion technology (Section 5.1.1), air pollution control
technology (Section 5.1.2), and fuel usage (Section 5.1.3). Unlike the wastes from conventional
technologies, FBC wastes comprise not only uncombusted material from the fuel, but also spent
incombustible bed material, as discussed below.
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Figure 5-1. Number of Fluidized Bed Combustion Facilities by State
Percent of national FBC electrical generating capacity:
Source: CIBO, 1997c
No comprehensive industry-wide data exist on the generation of FBC wastes. In 1996, however,
in support of this study, the Council of Industrial Boiler Owners (CIBO) sent a voluntary questionnaire to
every fossil fuel-fired FBC plant, both utility and non-utility, in the United States (CIBO, 1997b). This
survey collected general facility information, characterized process inputs and outputs, gathered data on
waste generation and characteristics, and captured details of FBC waste management practices. Thirty-
nine FBC facilities provided waste generation information in response to the survey. By extrapolating
from the generation rates reported by these 39 respondents, CIBO estimates total FBC waste generation
in 1995 to be between 9,091,600 and 13,150,560 short tons, with the most likely estimate being
9,417,500 short tons (CIBO, 1997c). This estimate is only about 10 percent of the total quantity of utility
CCWs generated, because there are far fewer FBC facilities, most of which have lower capacity than a
typical utility. On a per-megawatt basis, however, FBC units generate a larger quantity of waste than
comparable conventional combustion units. The reasons for this increased waste generation are
discussed in the sections below.
Like conventional combustors, FBC units generate low-volume combustion wastes as a result of
supporting processes (see Section 5.1.4) that are ancillary to, but a necessary part of, the combustion and
power generation processes. These low-volume wastes include the following:
Coal pile runoff. Runoff and drainage produced by precipitation falling on coal storage
areas (not generated at petroleum coke-fired FBC facilities).
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Coal mill rejects. Produced by onsite processing of coal prior to use (not generated at
petroleum coke-fired FBC facilities).
Boiler blowdown. Waste that is continuously or intermittently removed from boilers that
recirculate water.
Cooling tower blowdown and sludge. Wastes removed periodically from closed-loop
cooling systems.
Water treatment sludge. Wastes resulting from treatment of make-up water for the steam
cycle or for non-contact cooling.
Regeneration waste streams. Wastes resulting from periodic cleaning of ion exchange
beds used to remove mineral salts from boiler make-up water.
Air heater and precipitator washwater. Wastes resulting from the periodic cleaning of
the fireside (i.e., the side exposed to hot combustion products) of heat exchanging surfaces.
Boiler chemical cleaning waste. Wastes resulting from the periodic cleaning of the inside
(waterside) of boiler tubes with chemical solutions.
Floor and yard drains and sumps. Wastewaters collected by drains and sumps, including
precipitation runoff, piping and equipment leakage, and wash water.
Laboratory wastes. Wastes generated in small quantities during routine analysis of coal,
intake water, wastes, and other samples at a plant site.
Wastewater treatment sludge. Sludge generated from the treatment in settling basins or
other treatment facilities of any or all of the liquid waste streams described above.
FBC facilities would be expected to generate smaller quantities of these wastes, consistent with their
smaller unit size (see Section 5.1.1). In some cases, other characteristics of FBC technology may reduce
the generation of some of these wastes (see Section 5.1.4).
In addition to FBC wastes and low-volume combustion wastes, non-utility FBC facilities have
the potential to generate a wide range of non-combustion process wastes, consistent with the variety of
industries represented by these facilities. These process wastes may be managed together with
combustion wastes. No comprehensive data exist on the quantity of these non-combustion process
wastes generated at non-utility FBC facilities.
5.1.1 Fluidized Bed Combustion Technology
Box 5-1 provides a general overview of FBC technology. Such technology presents several
advantages over conventional processes in terms of fuel flexibility, combustion efficiency, and reduction
of emissions:
Fuel Flexibility. The temperatures in FBC systems are below the ash softening temperature
for most fuels. In addition, the mixing of fuel with incombustible bed material creates a
high thermal inertia. These conditions allow for stable ignition and combustion of even low
grade fuels and make the FBC process insensitive to fuel characteristics such as moisture
and ash content (Stultz and Kitto, 1992).
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Combustion Efficiency. FBC processes allow for efficient combustion even at the low
temperatures used because of the relatively long residence time of fuel in the bed, the heat
transfer between incombustible bed material and fuel, and the gas/solids contact created by
the fluidizing conditions (CIBO, 1997c).
Emissions Control. The low temperatures also limit the generation and emission of
nitrogen oxides. Furthermore, a sorbent material, typically limestone, often makes up a
portion of the bed material. This sorbent, along with the low temperature, allows the
efficient capture of sulfur oxides (CIBO, 1997c).
The FBC technologies discussed in Box 5-1 operate at atmospheric pressure. An advanced form
of FBC, called Pressurized Fluidized Bed Combustion (PFBC), currently is under development. PFBC
systems are similar to other FBC systems, but operate under pressure. Because of the pressurized
operation, the combustion air in PFBC systems contains more oxygen per unit volume, allowing more
intense combustion in smaller combustion units. Also, because the combustion off-gases are pressurized,
they can be passed through both a turbine and a steam boiler in sequence, allowing greater combustion
efficiency. Only one PFBC system currently is in operation at the commercial scale (EERC, 1997) and
this facility is a research facility. Because this emerging technology has not yet received commercial
application, limited data are available on PFBC wastes and waste management practices. Therefore, this
chapter applies to wastes from the more developed atmospheric FBC systems.
Box 5-1. Fluidized Bed Combustion (FBC) Technology
In FBC processes, fuel is burned on a bed of incombustible material (e.g., sand and limestone) while combustion
air is forced upward at high velocities, making the particles flow as a fluid. The fuel typically is a solid
(frequently coal), although FBC can burn gas and liquid fuels as well. When coal is fed to an FBC boiler, it
usually is crushed to 0.25 inches, a size between that used by stokers and pulverizers. FBC temperatures are
below those for conventional processesbed temperatures are maintained between 1,500 °F and 1,600°F. The
bed material often includes a sorbent, such as limestone, that allows the capture of sulfur oxides without the end-
of-stack scrubbers often required for conventional coal combustion processes. There are two primary types of
FBC systems: bubbling fluidized beds and circulating fluidized beds. The differences between the two depend
mainly on the bed particle diameter and gas flow velocity.
Bubbling fluidized bed systems have air velocities of 5 to 12 feet per second and larger bed particle size. These
conditions result in a dense bed (45 pounds per cubic foot) with a well-defined surface. Excess air passes
through the bed in the form of bubbles. A small amount of bed material entrained in the gas stream (a maximum
of 25 percent of the combustion gas weight) may be recycled back to the furnace to maximize combustion
efficiency and sulfur capture.
Circulating fluidized bed systems have greater air velocities (as high as 30 feet per second) and finer particle
sizes. As a result, the fluid bed is less dense (35 pounds per cubic foot) and has no well-defined top surface.
Bed and fuel material are distributed uniformly throughout the furnace, although density declines as particles
move upward. Particle entrainment increases in these systems such that large quantities of bed material must be
recaptured from the gas stream and recirculated back to the furnace to maintain bed inventory.
Sources: CIBO, 1997c; Stultz and Kitto, 1992; Elliott, 1989
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The partitioning of FBC waste between fly ash and bed ash depends on combustion technology.
In bubbling fluidized beds, waste generated is mostly bed material: fuel ash, lime (if used as sulfur
sorbent), calcium sulfate (formed by the reaction of sulfur with the sorbent), and sand or other inert bed
material. On the other hand, fly ash represents most of the waste generated by circulating fluidized beds
(Stultz and Kitto, 1992).
In general, FBC facilities are small in capacity. Figure 5-2 compares the capacity distribution of
FBC units to that of conventional coal-fired boilers in both the utility and non-utility sectors. Figure 5-3
shows the distribution of utility and non-utility FBC units in each capacity category. Utility FBC units,
although larger on average than non-utility FBC units, are smaller than typical conventional coal-fired
utility boilers. Non-utility FBC units are similar in capacity to the small conventional boilers used by
non-utilities. As a result of their small capacity, FBC units would be expected to generate less waste on a
per-boiler basis, all other factors being equal. Also, the high combustion efficiency of FBC units would
tend to result in lower waste generation on a per-unit basis. The presence of spent bed and sorbent
materials and the potentially greater ash content of the fuel, however, more than counteract this
reduction, as discussed in Section 5.1.3.
Figure 5-2. Capacities of Conventional and FBC Boilers
1200
120
>0-10 >10-50 >50-100 >100-250
Boiler Size (megawatt equivalents)
n Conventional Utility (Y1) | Conventional Non-Utility (Y1) g
Sources: EEI, 1994; EPA, 1990; CIBO, 1997b; CIBO, 1997c
>250
FBC (Y2)
5.1.2 Air Pollution Control Technologies
Just like conventional combustion facilities, the capture of FBC fly ash is governed by the
particulate control technology used. Fly ash leaving the boiler must be removed from the gas stream in
which it is entrained or it will be released to the atmosphere. Because FBC technologies capture sulfur
oxides using a sorbent within the combustion bed, they do not require the application of separate flue gas
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Figure 5-3. Capacities of Utility and Non-Utility FBC Units
70
1
_g
4-1
c
o
«._ ^n
«g 30
i_
X\N
V^fc^h%fc%fc^
iXXXVs, K\\\\N
>0-10 >10-50 >50-100 >1 00-250 >250
Boiler Size (megawatt equivalents)
H FBC Utility G FBC Non-Utility
Sources: EEI, 1994; EPA, 1990; CIBO, 1997b; CIBO, 1997c
desulfurization (FGD) technologies; however, FBC units can use the same basic particulate control
technologies as those used at conventional coal-fired utilities. Chapter 3 describes these technologies.
Figure 5-4 shows data on particulate control devices used at FBC facilities. FBC units are as
likely as conventional coal-fired utilities to apply particulate controls. This is due to two factors. First,
all circulating fluidized bed processes use some form of particulate control to accomplish the
recirculation of bed material. Second, all FBC facilities are relatively new. Thus, they are subject to
regulatory controls on air emissions despite their smaller size, as discussed in Section 5.5. FBC facilities
tend to use fabric filters for particulate control rather than the electrostatic precipitators (ESPs) that are
common for coal-fired utilities. Like ESPs, however, fabric filters provide for efficient collection of fly
ash.
5.1.3 Fuel and Sorbent Use
The quantity of FBC waste generated is affected by the ash content of the fuel. Ash content is, in
part, determined by the rank of the coal: anthracite, bituminous, subbituminous, or lignite. In addition to
coal rank, ash content depends on the specific coal-producing region, mine, seam, and production
method. Because of their fuel flexibility, FBC boilers burn a wider range of fuels than do conventional
coal-fired boilers. Table 5-1 shows the primary fuels used by facilities responding to the CIBO FBC
Survey.
FBC facilities that burn coal show a breakdown by coal rank similar to that observed for
conventional coal facilities: primarily bituminous, followed by subbituminous and lignite. Some FBC
facilities, however, may burn coal with higher ash content than conventional boilers. Furthermore, in
addition to coal, FBC facilities burn waste coal and other fuels. Waste coal includes culm (anthracite
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Figure 5-4. Particulate Control Technologies Used at FBC Facilities
None 3%
Combination* 38%
Fabric Filter 59%
'Mechanical collector followed by fabric filter or ESP.
Note: Percentages shown are of 39 facilities providing participate information.
Source: CIBO, 1997b
Table 5-1. Primary Fuels Used by FBC Facilities
Type of Fuel
Coal
Waste Coal
Other
Fuel
Anthracite Coal
Bituminous Coal
Subbituminous Coal
Lignite Coal
Anthracite Culm
Bituminous Gob
Petroleum Coke
Natural Gas
Total
Number of
Facilities
0
20
4
2
6
5
5
1
43
Mass of Fuel (tons)
0
7,384,624
2,306,910
2,086,227
2,604,863
2,089,268
895,658
191,601
17,559,151
Percent of Total Mass
0%
42%
13%
12%
15%
12%
5%
1%
100%
Source: CIBO, 1997b
coal refuse) and gob (bituminous coal refuse) and results from the coal-cleaning processes used to
separate standard coal from its impurities. Waste coals are higher in ash and lower in carbon content
(and therefore lower in fuel value) than standard coals. Several FBC facilities reported burning
petroleum coke as a primary fuel. Petroleum coke is the heavy residual from petroleum cracking
processes. Its characteristics vary widely depending on the process used. One facility reported burning
natural gas (CIBO, 1997c).
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While smaller capacities and greater efficiency may reduce waste generation at FBC facilities
relative to that at conventional coal-combustion facilities, the use of higher ash content fuels at some
facilities tends to counteract this reduction. The presence of spent bed and sorbent materials further
counteract this reduction. Spent bed and sorbent material can compose a significant proportion of the
waste generated from FBC technology. Table 5-2 presents data on the types and quantities of sorbent
and bed material used by FBC facilities in 1995. Limestone is the most commonly used material and
serves as a sorbent for sulfur dioxides. Sand is the most common incombustible bed base. Other
materials include clay and gravel as bed material and ammonia and urea to control nitrogen oxide
emissions.
Table 5-2. Sorbent and Bed Materials Used at FBC Facilities
Non-Combustible Commodities
Limestone
Sand
Other
Total
Number of Plants
36
20
7
63
Total Annual Usage (tons)
2,420,820
16,154
3,002
2,439,976
Source: CIBO, 1997b
5.1.4 Supporting Processes
The generation of low-volume combustion wastes primarily is associated with processes that
support the combustion process or make use of the products of combustion. Some of the same
supporting and enabling processes can accompany combustion at FBC facilities as at conventional
facilities, including the following:
Coal storage
Coal processing
Steam generation
Cooling
Water treatment
Cleaning and maintenance.
Chapter 3 describes these processes in detail. The paragraphs below describe potential
differences in these processes at FBC facilities with respect to waste generation. Little quantitative
information is available on the quantities of low-volume combustion wastes generated at FBC plants.
Coal Storage and Processing
The FBC population includes a large percentage of small capacity units. These small capacity
units are less likely to store large quantities of fuel onsite than conventional coal-fired utilities.
Therefore, these facilities are less likely to generate coal pile runoff than conventional coal-fired utilities.
Also, because of their fuel feed tolerance, FBC plants are less likely to conduct onsite coal cleaning than
conventional coal-fired utilities. Therefore, FBC plants generally do not generate coal mill rejects
(pyrites). No information is available on wastes from the storage and processing of fuels other than coal
(e.g., petroleum coke).
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Steam Generation, Cooling, and Water Treatment
These processes generate wastes including boiler blowdown, cooling tower blowdown, water
treatment wastes, and regenerant wastes. The quantities of these wastes generated are related to the
quantity of water used in the steam and cooling cycles, which in turn is related to combustion capacity.
Because of their smaller capacity, FBC units generally use less water in the combustion process than
conventional utilities and, therefore, may generate smaller quantities of these wastes. In addition, some
non-utility FBC plants may use steam directly for heat in industrial processes rather than to generate
electricity. In some cases, this practice may reduce the need for cooling, and in turn reduce the
generation of wastes associated with the cooling cycle.
Cleaning and Maintenance
Cleaning processes intermittently generate low-volume wastes including air heater and
precipitator washwater and boiler chemical cleaning waste. Because of the lower operating temperatures
compared to conventional coal combustion technologies, FBC units may require less frequent cleaning
than conventional boilers. The small capacities of some units also may require smaller quantities of
cleaning solutions than required at conventional coal-fired utilities. These factors can result in lesser
generation of cleaning wastes at FBC units than at conventional coal combustors.
5.2 WASTE CHARACTERISTICS
5.2.1 Physical Characteristics
FBC fly ash is a solid composed of fine particles, similar in size to that generated by pulverized
coal combustors. Sixty to 90 percent of FBC fly ash particles are finer than 100 microns. FBC fly ash
particles are less rounded than those from conventional combustion processes because of the lower
combustion temperatures. FBC bed ash also is a solid particulate, with a size that varies depending on
fuel and sorbent characteristics. FBC bed ash particle size varies from 0.1 to 2 millimeters (CIBO,
1997c).
5.2.2 Chemical Characteristics
Both FBC fly ash and bed ash contain non-combustible mineral matter, sorbent material, and
unburned carbon. The major constituents of FBC waste are calcium, sulfur, silicon, iron, aluminum,
magnesium, and potassium. As with conventional coal combustion waste (CCW), most of these
constituents are present in the form of oxides. Due to the presence of sorbent material, however, FBC
wastes have a higher content of calcium and sulfate and a lower content of silica and alumina than
conventional CCWs (CIBO, 1997c). In addition, the amount of unburned carbon in FBC ash is quite
small because of the low concentration of fuel in the bed. The carbon content in a fluidized bed burning
bituminous coal typically is less than 1 percent (Stultz and Kitto, 1992). Like conventional CCWs, FBC
waste constituents include trace metals. Table 5-3 presents typical concentrations for these constituents.
Leachate and Hazardous Waste Characteristics
Using data available on the composition of FBC wastes, EPA evaluated whether the waste
exhibited any of the four characteristics of hazardous waste: corrosivity, reactivity, ignitability, and
toxicity. Based on available information and engineering judgment, EPA does not believe that FBC
wastes are reactive, ignitable, or corrosive. FBC waste cannot be considered corrosive under EPA's
definitions because the characteristic does not apply to solid materials.
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Table 5-3. Facility Average Concentrations of Trace Constituents in FBC Wastes
(parts per million)
Constituent
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Chromium
Cobalt
Copper
Lead
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Thallium
Vanadium
Zinc
Fly Ash
Mean
33.4
38.1
542
3.31
366
1.79
46
22.3
40.5
30.3
223
7.86
13.9
179
19.5
2.35
9.46
771
53
Range
0.125-259
2.8-176
31.3-2,690
1.08-11.5
0.025-2,470
0.013-6.68
5.17-97.1
2.5-79.8
2-99
1.03-105
0.05-548
0.00005-129
2.35-48.6
6.25-923
0.47-166
0.05-11.6
1.25-39
36.4-3,830
24-143
Bed Ash
Mean
40.1
25.1
190
3
79.1
1.79
36.4
16.9
17.5
18.9
311
1.43
20.8
190
5.45
8.75
7.63
987
64.7
Range
0.125-361
2.5-80
7.3-453
0.5-8
0.025-304
0.0125-7.16
4.1-86
1.4-75.8
1.65-37.1
0.848-58
52.2-751
0.00005-16.2
6-63.4
1-945
0.152-45
0.05-87.6
0.5-25
12-5,240
17.4-399
Combined Ash
Mean
14.3
25.1
258
2.97
149
1.53
43.7
5.6
40.1
23.2
88.7
0.431
9.65
142
5.86
2.75
5.56
144
3150
Range
0.065-62
1.4-77.2
39.2-690
0.148-9.5
1.25-1,670
0.009-5.9
12-181
0.6-18.7
1.9-192
0.45-67
20-211
0.0113-1.68
0.125-41
0.77-985
0.404-18
0.479-21.8
0.09-12.5
26.3-5,000
11-45,300
Notes: Encompasses wastes generated by facilities burning all types of fuel reported in the CIBO survey (i.e., coal, waste coal, and
petroleum coke). All measurements identified as below detection limit were assigned a value equal to one-half the detection limit for use in
the calculations. All concentrations are facility-averaged; i.e., multiple measurements from a single site were averaged, and the resulting
population of facility averages was used to generate the statistics in this table.
Source: CIBO, 1997b
EPA evaluates the characteristic of toxicity using Toxicity Characteristic Leaching Procedure
(TCLP) results. Table 5-4 presents typical TCLP results for FBC wastes for a number of constituents.
These include the eight metals regulated under the Resource Conservation and Recovery Act (RCRA)
and several other constituents. Data also are available from Extraction Procedure (EP) tests (a test
previously used by EPA to evaluate toxicity) for many of these same constituents. The EP results are
generally similar to or lower than the TCLP results shown in Table 5-4. The exceptions are antimony,
arsenic, chromium, mercury, and zinc in fly ash and aluminum, beryllium, and zinc in bed ash, which
appear in EP results at somewhat higher levels. The discussion below addresses the leachate data first
for RCRA-regulated constituents, then for non-RCRA-regulated constituents.
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Table 5-4. Facility Average TCLP Results for FBC Wastes (mg/l)
Constituent
RCRA
Standard
Fly Ash
Mean
Range
Bed Ash
Mean
Range
Combined Ash
Mean
Range
RCRA Toxicity Constituents
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
5.0
100.0
1.0
5.0
5.0
0.2
1.0
5.0
0.0498
3.40
0.0193
0.0577
0.113
0.000661
0.0739
0.0258
0.0125-0.17
0.0175-42
0.0005-0.09
0.01-0.141
0.0025-0.505
0.00005-0.00192
0.002-0.2
0.005-0.053
0.0369
0.613
0.0175
0.0526
0.0715
0.00116
0.0415
0.0533
0.0025-0.125
0.025-2.5
0.0005-0.051
0.0025-0.14
0.0025-0.235
0.00025-0.005
0.002-0.158
0.005-0.25
0.102
1.22
0.0181
0.0667
0.13
0.00198
0.0584
0.0253
0.0023-0.365
0.0223-10.5
0.00125-0.096
0.0033-0.25
0.001-1
0.00005-0.0169
0.00413-0.175
0.0038-0.145
Non-RCRA Constituents
Antimony
Beryllium
Boron
Cobalt
Copper
Manganese
Molybdenum
Nickel
Thallium
Vanadium
Zinc
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
0.224
0.00947
0.447
0.0725
0.042
0.190
0.168
0.0926
0.0229
0.105
0.111
0.0095-0.66
0.00005-0.025
0.06-0.76
0.0025-0.19
0.0025-0.077
0.00125-0.6
0.11-0.32
0.0025-0.3
0.0208-0.025
0.025-0.185
0.0025-0.35
0.218
0.01085
1.328
0.125
0.0403
0.403
0.16
0.119
0.0356
0.941
0.141
0.025-0.52
0.00005-0.025
0.13-2.6
0.025-0.225
0.0275-0.0633
0.05-1.27
0.119-0.2
0.0167-0.28
0.025-0.0463
0.025-1.858
0.015-0.51
0.121
n/a
3.2
0.106
0.0574
0.208
0.108
0.121
n/a
n/a
0.114
0.00065-0.27
n/a
0.0367-26.7
0.0065-0.4
0.00188-0.203
0.00208-0.507
0.0125-0.21
0.0025-0.46
n/a
n/a
0.0025-0.38
n/a = data not available
Notes: Encompasses wastes generated by facilities burning all types of fuel reported in the CIBO survey (i.e., coal, waste coal, and
petroleum coke). All measurements identified as below detection limit were assigned a value equal to one-half the detection limit for use in
the calculations. All concentrations are facility-averaged; i.e., multiple measurements from a single site were averaged, and the resulting
population of facility averages was used to generate the statistics in this table. Statistics presented here are based on a varying number of
samples, depending on the constituent. For details, refer to the Technical Background Document for the Report to Congress on Remaining
Wastes from Fossil Fuel Combustion: Waste Characterization.
Source: CIBO, 1997b
Based on the TCLP and EP data for the eight RCRA metals, FBC wastes rarely exhibit the
RCRA characteristic of toxicity. Only one FBC site of 24 (4 percent) for which data are available had
any samples of waste for which TCLP or EP analyses exceeded the regulatory threshold. At this site, a
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facility that burns waste coal, the only sample of fly ash analyzed for mercury exceeded the threshold for
that metal.1
In addition, as shown in Table 5-4, TCLP data (and, in some cases, EP data) are available for a
number of other non-RCRA-regulated constituents, including antimony, beryllium, boron, cobalt, copper,
manganese, molybdenum, nickel, thallium, vanadium, and zinc. These constituents of potential concern
are considered further in Section 5.4 along with the eight RCRA-regulated metals for their potential risk
to human health and the environment.
A few respondents to the CIBO survey also provided data on organic constituents in FBC waste
leachate. Of 102 analyses for various organics from seven facilities, 97 (or 95 percent) were below
detection limits. The five analyses above detection limits were from a single facility. This facility
reported concentrations of 0.1 milligrams per liter (mg/1) each for benzene, chlorobenzene, 1,4-
dichlorobenzene, trichloroethylene, and tetrachloroethylene. These concentrations are well below the
RCRA regulatory threshold for these constituents (0.1 mg/1 compared to 0.5 mg/1, 100 mg/1, 7.5 mg/1,
0.5 mg/1, and 0.7 mg/1 for each constituent, respectively). Analyses for 24 other organics at the same
facility were below detection limits. The leachate data presented in this section include facilities burning
all types of fuel. There is a possibility that facilities burning petroleum coke may leach higher
concentrations of certain metals, due to higher concentrations of these metals in the fuel. To investigate
this possibility, EPA compared TCLP and EP results for FBC facilities burning petroleum coke to those
for facilities burning other fuels (mainly coal). The available data on petroleum coke-fired FBC wastes
are sparse. On a constituent-by-constituent basis, data are available for a maximum of three of the five
petroleum coke-fired facilities. In addition, the majority of samples are below detection limits for all
constituents other than barium, vanadium, and zinc. Although the data are somewhat limited, trace
constituent concentrations for petroleum coke-fired FBC wastes are similar to or less than levels in coal-
fired FBC wastes, except for vanadium.2 Thus, coal-fired FBC wastes are considered the bounding case
in terms of waste characteristics, and EPA relied on the coal-fired FBC data in its risk assessment
analysis for FBC wastes.
5.3 CURRENT MANAGEMENT PRACTICES
Unlike the other wastes covered by this study, the majority of FBC waste is not disposed in
traditional waste management units. Instead, most FBC waste is beneficially used, primarily in
minefilling. Sections 5.3.1 through 5.3.4 characterize the management units used for that portion of FBC
waste that is disposed. Section 5.3.5 covers beneficial uses and minefilling.
Two sources of data are available to characterize management practices for FBC wastes. The
first is the CIBO FBC survey (CIBO, 1997b) conducted in 1996. In addition, four of the landfills
covered in the Electric Power Research Institute (EPRI) utility comanagement survey (EPRI, 1997a), also
conducted in 1996, reported managing FBC waste. One of these facilities responded to the CIBO FBC
1 At another facility, one sample for selenium was reported as a non-detect with a detection limit more than
twice the regulatory level. If assigned a value of one-half the detection limit according to the approach used in this
report, the sample would be counted as an exceedence; however, given that no other samples exceeded the
regulatory threshold for selenium, this apparent exceedence was assumed to be an artifact of the high detection limit
and not counted here.
2 The facility average TCLP concentration of vanadium at the single petroleum coke-fired facility for which
data are available was 1.86 mg/1 for bed ash and 0.185 mg/1 for fly ash. By comparison, all vanadium analyses were
below detection limits at the single coal-fired facility where vanadium was sampled.
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survey, but the other three did not. The EPRI responses from these three additional units are analyzed
here along with the CIBO responses. This analysis treats the CIBO respondents plus the three EPRI
respondents as a single sample. The 23 facilities in this sample cover 27 percent of all U.S. facilities
using FBC. The estimated quantity of FBC waste managed by the surveyed waste management units is
about 2.1-million tons per year, or 22 percent of the total estimated FBC waste generated. The sample
facilities include utilities and non-utilities and are geographically representative of the full population,
with the exception that Pennsylvania and Illinois appear to be underrepresented in the sample.
5.3.1 Unit Types and Locations
The 23 facilities in the combined sample reported a total of 25 waste management units: 12
onsite landfills, 5 offsite landfills, 4 onsite surface impoundments, and 4 units of unknown type. These
data show landfilling as the most common FBC waste management practice, accounting for 81 percent of
the units whose type (i.e., landfill or surface impoundment) is known. The proportion of landfills for
FBC wastes is greater for FBC wastes than for utility CCWs. In addition, of the four impoundments
identified, three are operated by the same company. The fourth impoundment is a conventional utility
CCW management unit in which FBC wastes also are disposed. Therefore, EPA believes the identified
impoundments represent unusual cases.
The FBC waste management units in the sample are relatively new. One of the surface
impoundments was constructed in 1974, but the remaining units all were constructed after 1981. This
may be due to the relatively recent adoption of FBC technology. New facility construction may include
new waste management units to serve the facility. Where this new facility construction includes FBC
technology (as opposed to cases in which FBC is a retrofit at an older facility), the FBC waste would
consequently be managed in these new waste management units. The age distribution of FBC waste
management units also may help explain the predominance of landfills, if the FBC sector follows the
general trend found for utility CCW management (see Section 3.3).
5.3.2 Types and Volumes of Wastes Managed
The two types of FBC waste, fly ash and bed ash, are frequently combined and managed
together. Combined management with other, non-FBC wastes, however, is less common for FBC wastes
than for other types of FFC waste. Only 10 (or 40 percent) of the 25 FBC waste management units for
which data are available reported managing FBC wastes with other wastes. In addition, two of the offsite
landfills did not report comanagement, but are described as municipal solid waste landfills. Presumably,
in these landfills, FBC wastes are managed along with municipal solid waste, bringing the total to 12
units (48 percent) that practice combined management. This compares to comanagement by 84 percent
of conventional utility CCW management units.
In management units that combine FBC wastes with other wastes, the types of waste managed
are as variable for FBC waste management units as those for CCW management units. The types of
waste comanaged include conventional CCWs, low-volume combustion wastes (e.g., metal cleaning
wastes, cooling tower blowdown, boiler blowdown, regenerant wastes, and coal pile runoff), and non-
combustion wastes (e.g., municipal waste, wastewater treatment sludge, dredged soils, wastepaper
deinking sludge, and construction debris). One facility, a utility with a conventional coal boiler in
addition to an FBC boiler, comanages coal mill rejects. The quantities of non-FBC waste managed range
from several times to a fraction of the quantity of FBC waste.
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5.3.3 Unit Size
Table 5-5 shows summary statistics on the dimensions of FBC waste management units. These
data show that FBC waste management units are smaller than typical conventional utility CCW
management units (see Section 3.3). While most FBC landfills are clustered around the median size, two
units in the population are much larger, with capacities of 5-million and 6.1-million cubic yards.
Table 5-5. FBC Waste Management Unit Sizes
Number of Units
Minimum
Maximum
Median
Mean
Landfills
Capacity
(cubic yards)
13
350,000
6,100,000
1,500,000
2,063,461
Area
(acres)
11
17
96
38
38
Height
(feet)
10
17
75
52
51
Surface Impoundments
Capacity
(cubic yards)
3
2,240,000
5,600,000
4,000,000
3,946,667
Area
(acres)
2
28
55
41
41
Depth
(feet)
2
70
125
98
98
Note: Not all units in the sample reported all three measurements (area, height or depth, and capacity). Where a unit reported two of the
three dimensions, the third was derived from the other two. For example, if a landfill reported only capacity and area, the design height was
calculated by dividing the reported capacity by the area.
Sources: CIBO, 1997b; EPRI, 1997a
5.3.4 Environmental Controls
The CIBO FBC survey collected information on liners, covers, leachate collection systems,
ground-water monitoring systems, and regulatory permits. These environmental controls are defined in
Chapter 3. The CIBO FBC survey also collected information on several other types of environmental
controls, described in Box 5-2.
Table 5-6 summarizes the use of environmental controls in FBC waste management units. Based
on these data, the frequencies of environmental controls for FBC waste management units are similar to
corresponding frequencies for utility comanagement units. The following discussion provides additional
details on each type of environmental control.
Liners
As shown in Table 5-6, the frequencies of liner use for FBC waste landfills are similar to those
for utility CCW units (see Section 3.3). Figure 5-5 displays the types of materials used for FBC landfill
liners. One surface impoundment reported a synthetic liner. Two other impoundments reported being
constructed on bedrock, while the fourth reported an in situ clay liner.
Covers, Compaction, and Dust Suppression
Based on the data in Table 5-6, FBC waste landfills appear less likely than utility CCW
comanagement units to use covers (see Section 3.3). It is unclear, however, whether respondents
interpreted the question about cover as relating to current daily or interim cover or final cover at closure.
If responses relate to final cover, then the lower percentage for FBC waste landfills is not surprising. All
of the respondents are currently active, and, therefore, would not have final cover and, as relatively new
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Box 5-2. Environmental Control Technologies
Dust Suppression/Control. Dust suppression, typically used at landfills, usually involves conditioning the
waste with water or other liquid before and during transport and placement. The purpose of this activity is to
prevent airborne transport of waste and to reduce inhalation exposure to site workers.
Run-On and Runoff Controls and Collection Systems. Examples of run-on and runoff controls include
curbs, dikes, and diversion ditches. Run-on controls prevent precipitation runoff from other parts of a site from
reaching waste management areas, preventing this runoff from becoming contaminated by contact with waste
and/or creating leachate by percolation through waste. Runoff controls and collection systems prevent
precipitation runoff from the waste management unit, which may be contaminated by contact with waste or carry
waste particles, from being transported offsite.
Compaction. Compacting waste after placement can reduce or prevent wind and water erosion of the waste and
subsequent release to the environment. Under the right circumstances, where voids are minimized, compaction
also can reduce the permeability of the waste, slowing the creation and release of leachate.
Surface Water and Air Monitoring Systems. Similar to ground-water monitoring systems, surface water and
air monitoring systems comprise periodic collection and analysis of surface water or air samples near a waste
management unit. These systems serve as a warning that a release is occurring through the air or that a surface
water body is being contaminated.
Table 5-6. Environmental Controls at FBC Waste Management Units
Environmental Control
Liner*
Cover
Leachate Collection
Run-on and Runoff Control and/or Collection
Dust Suppression
Compaction
Ground-Water Monitoring
Surface Water Monitoring
Air Monitoring
Regulatory Permits
Landfills
Number
Reporting Data
12
13
17
14
11
11
16
14
13
17
Percent
with Control
42%
62%
59%
93%
91%
55%
77%
29%
8%
89%
Surface Impoundments
Number
Reporting Data
4
3
4
4
3
3
3
4
3
4
Percent
with Control
25%
67%
50%
100%
67%
33%
100%
50%
0%
100%
*Does not count bedrock or other in situ materials as a liner.
Source: CIBO, 1997b; EPRI, 1997a
units, may not yet have plans for cover at closure. If responses relate to daily cover, the low number may
be partially explained by the use of dust suppression and compaction (as controls with a similar purpose
to daily cover). Nearly all FBC waste landfills use dust suppression and/or compaction.
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Figure 5-5. FBC Landfill Liner Types
In-Situ Soil, Clay, Shale, or Bedrock 58%
Composite* 17%
^^^ ^^mt//
Compacted Ash 8%
Compacted Clay or Shale 8% Synthetic 8%
'Composite liners include synthetic and compacted clay layers.
Note: Percentages shown are of 12 landfills providing linea data. Percentages may not sum to 100 due to rounding.
Sources: CIBO, 1997b; EPRI, 1997a
Just like CCW comanagement units, the results for surface impoundments are difficult to
interpret. The two impoundments reporting covers may have placed caps on closed or full portions.
Alternatively, these units may have reported covers to reflect standing liquid maintained above the waste
layer in the impoundment. For impoundments reporting compaction or dust suppression, the responses
could be interpreted by three scenarios: (1) that compaction or dust suppression are used on dry,
inactive, or closed areas of the impoundment; (2) that dust suppression or compaction are practiced
during dry transport of waste, prior to placement in the impoundment; or (3) that waste is transported wet
or wastes are managed under water in the impoundment, therefore preventing dust generation.
Regulatory Permits
As shown in Table 5-6, the proportions of FBC waste management units subject to permit
requirements are similar to those for CCW comanagement units (see Section 3.3). Some of the
respondents provided information about the permitting agency, as well as indicated whether the unit had
one or more permits. Six of the surveyed units (four landfills and two impoundments) had multiple
permits. In each case, the permitting agency was a state government, although one unit had both a state
and a county permit.
5.3.5 Beneficial Uses
Like conventional CCWs, FBC wastes may be applied to useful purposes as an alternative to
traditional waste management. In fact, according to CIBO survey statistics, the majority of FBC wastes
currently are beneficially used. Table 5-7 shows data on the current developed uses of FBC wastes. The
most dominant use of these wastes is in minefills, followed by waste stabilization, construction fills, and
agricultural uses. Box 5-3 provides a brief discussion of these uses.
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Table 5-7. Beneficial Uses of FBC Wastes
Use Category
Mining Applications
Waste Stabilization
Construction Fills
Agricultural Use
Cement and Concrete Products
Other
Total
Quantity (thousand tons)
3,629
351
302
66
5
79
4,432
Percent of Generation"
61.0%
5.9%
5.1%
1.1%
0.9%
1.3%
74.5%
* Percent of total waste generation reported by survey respondents.
Note: Percentages might not sum due to rounding.
Source: CIBO, 1997c
5.4 POTENTIAL AND DOCUMENTED DANGERS TO HUMAN HEALTH AND THE
ENVIRONMENT
5.4.1 Potential Ground-Water Risks to Human Health
Section 3.4 provides a discussion of the methodology employed by EPA in assessing risks from
coal-fired utility comanaged wastes. EPA followed a similar approach for wastes from fluidized bed
combustion, with several important differences. First, waste characterization data for FBC wastes
provided to EPA reflect wastes generated at a large portion of generators nationwide. All data were
generated using TCLP or EP Toxicity methods, and these data were combined to provide as large a
sample set as possible. Second, EPA found that very few FBC unit operators managed their wastes in
impoundments. Moreover, the majority of these few impoundments are lined or constructed on bedrock.
Therefore, EPA limited its modeling efforts to landfill scenarios. Finally, EPA found that FBC boilers
reflect a geographic distribution distinct from utilities, and so modified its modeling scenarios
accordingly.
Information provided by CIBO indicates that minefilling is common for FBC wastes. As
discussed in Section 3.4.5, minefill risks were not evaluated using EPACMTP due to data and model
limitations.
Findings-FBC Wastes Ground Water Human Health Risk Assessment
Table 5-8 summarizes selected results from the deterministic and probabilistic analyses of risk
from FBC wastes for the adult receptor. Overall, EPA found that the risks associated with all modeled
constituents of concern, except for antimony, arsenic, beryllium, and chromium, fell below a hazard
quotient (HQ) of 1 or a lifetime cancer risk of 1 x 10~6. Potential risks associated with arsenic in the high-
end deterministic scenario exceeded 1*10~4.
Comparison of the deterministic and Monte Carlo results reveals that the deterministic results
generally exceed the 95th percentile Monte Carlo results. None of the 2,000 Monte Carlo simulation
combinations of parameter values performed for any constituent yielded a risk estimate as high as the
corresponding high-end deterministic result. Even at the 95th percentile level, the risks predicted by the
Monte Carlo simulations were two orders of magnitude or more below the corresponding risks estimated
for the high-end scenario.
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Box 5-3. Beneficial Uses of FBC Wastes
Mining Applications. According to CIBO survey statistics, FBC wastes are most often utilized in mining
applications. FBC wastes can be beneficially used in coal mine remediation activities, including the control of
acid mining drainage, backfilling, blending mine soils and spoils, and revegetation. The alkaline characteristics
of FBC wastes make them useful as a neutralizing buffer to dampen or eliminate the self-sustaining acid mining
drainage generation. FBC waste has a significant quantity of unreacted sorbent (i.e., lime or limestone) that
contributes to this buffer capability. FBC wastes mixed with conventional coal combustion fly ash and other
mine spoils also have been used successfully. Another use of FBC waste is as backfill material to neutralize
acidity at mine pits, and to prevent mine subsidence from abandoned underground mines. In order to neutralize
the acidity of mine soils and spoils, significant quantities of mine wastes are mixed with FBC wastes. This also
is performed in an effort to create a topsoil amenable to revegetation at mine sites.
Waste Treatment. FBC wastes also are applied in the treatment and management of hazardous waste. The
primary objective of solidification and stabilization processes is to chemically fix potentially hazardous wastes in
a solid matrix. Mixtures using FBC wastes have been found to stabilize the acidic components and trace
constituents found in hazardous waste in a cost-effective manner.
Construction Fills. The granular and cementitious properties of FBC wastes and their free lime content are
useful in various civil engineering applications. These wastes are applied as stabilizing agents in subgrade or
subbase soils (e.g., road and road base construction, low-strength backfilling). Like lime, FBC wastes improve
the compaction and load bearing capabilities and lower the plasticity of clays or silty soils. Moreover, FBC
wastes introduce some degree of cementitious bonding not obtained with the addition of lime alone.
Agricultural Use. Besides increasing the pH of the soils, FBC waste also provides increased solubility. The
gypsum contained in FBC waste has a significant impact on soil chemical and physical properties. Specifically,
it has the potential to improve filtration, reclaim high sodium soils, increase rooting in acid subsoils due to the
reduction of aluminum toxicity, and supply calcium and sulfur to plants. Increasing rates of FBC waste
application have also been found to decrease soil extractable zinc, manganese, phosphorous, and potassium.
Lastly, the ash content acts as a supplier of macro- and micro-nutrients essential to plant growth. The major
problems associated with FBC residue use for agricultural purposes are high alkalinity and salinity, which may
reduce plant growth at high application rates.
Cement and Concrete Products. The volume of FBC wastes used in concrete products has been minimal.
Several factors including slow setting and expansion of the concrete product with time have been experienced,
even when FBC wastes are mixed with fly ash. Still, studies are being conducted to understand the cementing
action, strength development, and stability of concretes that use only FBC wastes and fly ash as binders (i.e.,
concretes that do not contain Portland cement).
Sources: CIBO, 1997c; EPA, 1998h
EPA also considered the time at which risks were predicted to result from the release of
constituents of concern. EPA found that the concentration of arsenic in ground water at the receptor well
would not reach the health-based level (HBL) for arsenic (i.e., achieve a risk level of 1 * 10~6) for more
than 3,000 years.3 The times to reach the antimony HBL and the beryllium MCL in ground water were
predicted to be nearly 6,000 years and greater than 6,500 years, respectively.4
3 EPA, 1998d,p. 5-33.
4 Ibid. Note that the time to risk calculated for beryllium in the draft report was the time to reach the CSF-
based HBL. The MCL is greater than the HBL and so the time to reach the MCL must be at least as great as the
time to reach the HBL.
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Table 5-8. Comparison of Deterministic and Monte Carlo Risk Model Results for FBC
Waste Ground-Water Pathway Scenario
Scenario
FLb
Constituent"
Antimony
Arsenic
Beryllium
Chromium
Deterministic
Risk, Central
Tendency
HQ<1
1x108
HQ<1
HQ<1
Deterministic
Risk, High-End
HQ = 12
4.3x10"
HQ = 1.4
HQ = 1.1
Corresponding
Monte Carlo
Percentile
>100
>100
>100
>100
Monte Carlo
95th Percentile
HQ = 0.007
2x1 06
HQ <0.001
HQ = 0.002
a All other metals modeled resulted in HQ <1
" FL = FBC waste landfill
Note: Results shown are those from the October 10, 1998, Sensitivity Analysis.
Considering the low hazard quotients, the very low probabilistic risk, and the long time to reach a
level of risk for beryllium, antimony, and chromium, EPA eliminated these metals from further
consideration for this pathway.
Table 5-9 summarizes the estimated risks to adult and child receptors for the high-end
deterministic scenario for FBC wastes. Overall, the results show that for non-carcinogens the risks for
young children increased roughly twofold compared with the adult receptors. For arsenic, risks changed
very little between the receptors.
Table 5-9. Comparison of Adult and Child Risk Model Results
for FBC Waste Ground-Water Pathway Scenario
Scenario
FLb
Constituent"
Antimony
Arsenic
Beryllium
Chromium
High-End Deterministic Risk
Deterministic Risk,
Central Tendency
HQ = 12
4.3x10"
HQ = 1.4
HQ = 1.1
Deterministic Risk,
High-End
HQ = 20.8
5.4x10"
HQ = 2.4
HQ = 1.9
Monte Carlo
95th Percentile
HQ =13.4
3.8x10"
HQ = 1.6
HQ = 1.2
a All other metals modeled resulted in HQ <1
" FL = FBC waste landfill
Note: Results shown are those from the October 10, 1998, Sensitivity Analysis.
5.4.2 Potential Above-Ground Multi-Pathway Risks to Human Health and the
Environment
Human Health Risk Findings
No cancer risk in excess of 10~6 or non-cancer HQ in excess of 1 were found, except for agricultural
application. Risks to farmer and child were approximately 10~5 for the pathway.
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Ecological Risk Findings
No ecological risk was found, but EPA had no characterization data with which to assess FBC
impoundments. Given that landfill risks for human health risk approximate those for utilities, it is likely,
based on total constituent analysis, that ecological risks similar to those for utility impoundments would
exist for the few reported FBC impoundments.
5.4.3 Documented Damages to Human Health and the Environment
EPA relied on a report prepared by CIBO to assess releases and damage cases to human health or
the environment involving FBC wastes (CIBO, 1997c). In addition, while not specifically directed at
FBC non-utilities, EPA's examination of state file information for non-utilities in six states did not
identify any additional incidents related to FBC waste management sites. This indicates that the state
officials contacted were unaware of any damage cases related to FBC non-utilities. EPA has not
specifically pursued other references to further identify other FBC waste management sites with
documented releases or damages.
The CIBO report identified eight sites managing FBC wastes where ground- or surface-water
contamination was observed. In seven of the cases, the contamination appears to be related to pre-
existing conditions (based, for example, on evidence of upgradient ground-water contamination). At the
eighth site, insufficient historical information was available and the contaminant found in the ground
water (lead) was found to be inconsistent with those typically present in FBC wastes. EPA concluded
from the review of these eight cases that contamination likely resulted from other sources; therefore, the
observed damages do not result from FBC waste management. More detailed discussion of these eight
sites are presented in the Technical Background Document for the Report to Congress on Remaining
Wastes from Fossil Fuel Combustion: Potential Damage Cases, as well as in the CIBO report.
5.5 EXISTING REGULATIONS
EPA's objective in this analysis was to identify and evaluate the existing regulatory controls that
pertain to the management of FBC wastes. The regulatory analysis is directed toward addressing the
question of whether existing regulations adequately protect human health and the environment. The
analysis also is helpful in understanding waste generation and current management practices.
The sections below discuss regulations addressing air pollution, water pollution, and solid and
hazardous waste, respectively. Air regulations are relevant primarily because of their effect on waste
generation. Water regulations have an influence both on waste generation and management, and, in
particular, address the impact of FBC wastes on surface waters. Solid and hazardous waste regulations
are of the greatest interest because they directly govern waste management practices.
The sections below describe federal regulations in each of these areas. In many cases, the
implementation of these federal programs is carried out by the states. Therefore, where appropriate,
aspects of state implementation also are discussed. Because the nuances of state implementation are of
particular importance with respect to solid waste regulation, that section discusses state programs in
detail. Where appropriate, that section also describes state control on two of the beneficial uses of
concern to EPA: minefilling and soil amendment.
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5.5.1 Regulations Addressing Air Pollution
The federal Clean Air Act (CAA) is intended to protect and enhance the quality of the nation's
air resources. The CAA requirements most relevant to FBC wastes include the following:
National Ambient Air Quality Standards (NAAQS) for particulate matter (PM)
NAAQS for sulfur dioxide
Title IV acid rain provisions
NAAQS for ozone
National Emissions Standards for Hazardous Air Pollutants (NESHAP).
Historically, CAA requirements have been a significant factor affecting the generation and collection of
FBC wastes. Recent and forthcoming changes in these requirements also may impact waste generation or
characteristics.
NAAQS for Particulate Matter
The NAAQS for PM establish maximum concentrations of PM with diameter less than or equal
to 10 micrometers (PM10) in the ambient air. These standards are among the factors motivating the use
of particulate control technologies at FFC facilities. EPA recently proposed to lower the size criterion to
2.5 micrometers, which may affect the volume of fly ash collected and selection of control technology;
however, final standards will not be issued for at least 5 years, so the impacts of the new standard are
difficult to predict at this time.
The NAAQS for PM are implemented through the following regulatory mechanisms: New
Source Performance Standards and State Implementation Plans, described below.
New Source Performance Standards (NSPS). The NSPS subjects newly constructed or
modified units to specific PM emissions limits. These limits may be met by changing fuel types,
modifying combustion conditions, or installing control devices. The applicability of the NSPS and the
specific limits imposed vary with the age and size of the combustion unit, with older and/or smaller units
less likely to be subject to the NSPS. Specifically the regulation of facilities can be considered in four
categories.
40 CFR 60 Subpart D governs the standards of performance for new fossil fuel-fired steam
generators that were constructed or underwent major modification after August 17, 1971.
Subpart D affects only units that are capable of burning fossil fuels at greater than 73
megawatts (MW) of heat input rate.
Subpart Da affects utility units with the capacity to fire fuel at greater than 73 MW heat
input rate that commenced production or major modification after September 18, 1978.
Subpart Db affects coal-fired units with the capacity to fire fuel at greater than 29 MW of
heat input rate that commenced construction or modification after June 19, 1984.
Subpart DC governs coal-fired units constructed or modified after June 9, 1989, with
capacity to fire fuel at less than 29 MW but greater than 8.7 MW heat input rate.
With the exception of Subpart Da, which applies specifically to utilities, the NSPS requirements
apply to all FBC units, utility or non-utility. Non-utilities, however, tend to have smaller capacities than
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utilities. Also, FBC units, in general, tend to be smaller and newer than conventional units. Therefore,
FBC units, and particularly non-utility FBC units, are more likely captured by those NSPS requirements
that apply to smaller capacity, newer units (i.e., Subparts Db and DC). Note that under the NSPS
regulations, facilities that were in operation before the dates stated in each of the four subparts are
considered "grandfathered" and would not be subject to the newer standards unless they underwent a
major modification.
State Implementation Plans (SIPs). The performance standards above can be enforced by a
federal, state, or local regulatory agency. There are additional CAA regulations that could require an
FBC unit to install a particulate removal device notwithstanding the grandfather clause in Subparts D,
Da, Db, and DC. SIPs may impose, on a state-by-state basis, PM controls of varying stringency on
specific sources or categories of sources, including FBC facilities. Such controls are required under Title
I of the CAA if a particular area is in nonattainment for the NAAQS for a criteria pollutant such as PM.
For this reason, SIP controls will generally be more stringent in such nonattainment areas. In attainment
areas, the prevention of significant deterioration (PSD) program requires new sources to apply Best
Available Control Technology (BACT), which must be at least as stringent as NSPS.
NAAQS for Sulfur Dioxide and Title IV Acid Rain Requirements
Like the NAAQS for PM, the NAAQS for sulfur dioxide establish a maximum concentration of
sulfur dioxide in the ambient air. The NAAQS for sulfur dioxide are implemented through NSPS and
SIPs. The functioning and applicability of the sulfur dioxide NSPS requirements are similar to those for
PM, although there is less variation based on age and size.
Each of the four categories of FBC facilities regulated under Subparts D, Da, Db, and DC is
subject to the same requirement: sulfur dioxide emissions must be less than 520 nanograms per joule
(ng/J) of heat input. Facilities with greater than 22 MW of heat input capacity generally also must
achieve a 10-percent reduction in their sulfur dioxide emissions, based on the potential concentration in
fuel. An additional category of FBC units, those constructed or modified after June 9, 1989, and between
2.9 and 8.7 MW of heat input capacity, also must meet the 520 ng/J standard, but may do so based on
certification from the fuel supplier that the sulfur content of the fuel is low enough to meet the standards.
Finally, FBC units firing only waste coal are subject to a more stringent percent reduction requirement: a
20-percent reduction in their sulfur dioxide emissions, based on the potential concentration in fuel.
In addition to NSPS, states may impose controls through their SIPs to meet the sulfur dioxide
NAAQS. These controls may vary in stringency depending on attainment status and may be placed on
specific sources or categories of sources, including FBC units.
The Title IV acid rain provisions provide additional impetus for the application of FGD
technology at utilities. These provisions require specific reductions of sulfur dioxide emissions via the
following:
Installing FGD equipment
Switching to low sulfur fuel
Purchasing emissions allowances from other sources that have exceeded their reduction
requirements.
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Affected sources are allowed complete flexibility in choosing among these options. The current
phase of the Title IV program affects several hundred of the largest generating units at utilities. These
requirements, therefore, do not currently apply to non-utility FBC units. EPA is currently evaluating
further requirements for lower sulfur dioxide standards and emissions.
Because they capture sulfur oxides using a sorbent within the combustion bed, FBC units
generally do not require the application of separate FGD technologies to comply with the Title IV acid
rain provision or the NAAQS for sulfur dioxide. In fact, these regulations may have been a contributing
factor in the development and commercialization of FBC technology.
NAAQS for Ozone
The NAAQS for ozone establish a maximum concentration of ozone in the ambient air. EPA
recently lowered this concentration from 0.12 parts per million (ppm) to 0.08 ppm. The new standard
allows four exceedences of the maximum in a region over a 3-year period. EPA expects states will meet
the new standard by amending their SIPs to limit nitrogen oxide emissions at utilities. In proposing the
new rule, EPA published a Regulatory Impact Analysis (RIA) forecasting changes in the operating
practices of utilities that could result from these SIP modifications (EPA, 1997b). The RIA, however, did
not specifically estimate the impact of these regulations on the subset of utilities utilizing FBC
technology. Therefore, the impact on this segment is uncertain. The recent changes are not expected to
affect non-utilities (and, in turn, non-utility FBC waste generation) significantly.
NESHAP
Under the NESHAP, EPA is required to establish technology-based standards for 189 hazardous
air pollutants (HAPs). These standards are to be set on an industrial category basis and will apply to
facilities (major sources) that emit greater than 10 tons/year of any one HAP or greater than 25 tons/year
of any combination of HAPs.
EPA has studied HAP emissions from utility coal-fired steam generating units (including FBC
units) and found that mercury from coal-fired utilities is the HAP of greatest concern. Dioxins and
arsenic (primarily from coal-fired plants) also are of potential concern. EPA has deferred any
determination as to whether regulations to control HAP emissions from utilities are appropriate and
necessary (EPA, 1998c). If such regulations were promulgated, they could affect the characteristics or
quantities of FFC solid wastes.
EPA has not studied HAP emissions specifically for non-utility FBC facilities. Because
NESHAP will be set on an industrial category basis, when promulgated, the impact of these regulations
on FFC waste generation and characteristics may vary depending on the industrial sector of the non-
utility FBC facility.
5.5.2 Regulations Addressing Water Pollution
Under the federal Clean Water Act, the National Pollutant Discharge Elimination System
(NPDES) controls discharges to waters of the United States. The controls required under NPDES affect
the collection and management of FBC wastes. In states authorized by EPA, these controls are
implemented through state programs (often termed State Pollutant Discharge Elimination Systems, or
SPDES). Because state programs must be at least as stringent as the federal program, the discussion here
focuses on federal requirements as a lowest common denominator. NPDES requirements apply
differently to two categories of discharges: process wastewaters and stormwater runoff. Neither the
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NPDES process wastewater or NPDES stormwater requirements make a distinction between
conventional and FBC units. Distinctions may apply, however, between utilities and non-utilities.
NPDES Requirements for Process Wastewaters
The NPDES requirements that apply to process wastewaters from utility FBC facilities are those
for the steam electric point source category under 40 CFR Part 423. These requirements apply to
facilities "primarily engaged in the generation of electricity for distribution and sale" (i.e., utilities).
Non-utility FBC facilities face NPDES requirements for process wastewaters that are specific to their
industrial sector. In most cases, under these requirements each discharge requires an individual NPDES
permit with numeric limitations based on Best Practicable Control Technology Currently Available
(BPT), Best Available Technology Economically Achievable (BAT), or New Source Performance
Standards (NSPS). Facilities that discharge to publicly owned treatment works (POTWs) rather than
directly to surface waters face Pretreatment Standards for Existing Sources (PSES) similar to BAT, or
Pretreatment Standards for New Sources (PSNS) similar to NSPS.
As discussed in Section 5.3, FBC wastes are rarely managed wet. Therefore, the NPDES process
wastewater requirements generally are not relevant to management of these wastes. In those unusual
cases where FBC wastes are managed wet, the most relevant requirements are total suspended solids
(TSS) limits.
At non-utilities, the specific NPDES effluent standards applied depend on industrial category.
Effluent standards with potential applicability to non-utility FBC facilities include those for the following
industry categories:
Pulp, paper, and paperboard (40 CFR Part 430)
Organic chemicals, plastics, and synthetic fibers (40 CFR Part 414)
Inorganic chemicals manufacturing (40 CFR Part 415)
Grain mills (40 CFR Part 406).
The standards for all of these categories include TSS limits, and these limits are applicable to nearly all
of the industrial subcategories covered under each category. Some subcategories are subject to zero
discharge requirements. Some FBC facilities are found in other industrial categories, many of which are
also subject to TSS limits. Some facilities (such as education institutions) may not be subject to the
specific standards of any industrial category. In these cases, the specific effluent limitations would be
determined on a case-by-case basis as part of the individual NPDES permit for the facility.
At utilities, the steam electric category NPDES requirements place TSS limits directly on fly ash
handling and bottom ash handling waters. In addition, the NSPS for the steam electric category include a
zero discharge requirement for fly ash handling water. These steam electric requirements also may be
incorporated in individual permits at non-utilities to supplement their industrial category requirements.
Application of steam electric requirements to relevant waste streams at non-utility fossil fuel combustors
is left to the best professional judgment of the individual permit writer (EPA, 1996).
In the few cases in which FBC wastes are managed wet, the TSS and zero discharge
requirements discussed above are relevant as follows. Facilities may have to settle or otherwise remove a
certain amount of waste solids from the handling water to meet the TSS limits prior to discharge. Zero
discharge requirements effectively eliminate the release of waste solids to surface water. The
requirements control the direct release of fly ash, bed ash, and any treatment solids to surface waters.
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NPDES Requirements for Stormwater
NPDES Stormwater requirements apply to Stormwater runoff from FFC facilities, which may
include runoff from operating areas, ash handling areas, and waste management units. Like the process
wastewater requirements, Stormwater requirements have been established on an industrial sector basis.
The NPDES Stormwater requirements, however, are additive across industrial sectors. Therefore, the
steam electric requirements apply to both utility and non-utility FBC facilities. A chemical manufacturer,
for example, operating an FBC unit must meet both chemical manufacturing and steam electric
Stormwater requirements.
Facilities can meet the Stormwater requirements by including Stormwater in their individual
NPDES permit or seeking coverage under a general permit by submitting a Notice of Intent (NOI).
Individual permit control and monitoring requirements will be facility-specific, subject to the judgment
of the permit writer.
When covered by a general Stormwater permit, requirements include implementation of a
Stormwater pollution prevention plan, "reasonable and appropriate" control measures, and 1 or 2 years of
monitoring and reporting. No site visit by regulators is required under the general permit. Under the
general permit approach, facilities have a great deal of flexibility in selecting appropriate control
measures for runoff that may have contacted FBC wastes. The general permit requirements include
recommended best management practices for Stormwater at steam electric facilities, landfills, treatment
works, and construction areas greater than 5 acres. Because these requirements are additive across
industrial sectors, if the hypothetical chemical manufacturer described above also operated an onsite ash
landfill, that facility would have to meet landfill requirements in addition to chemical manufacturing and
steam electric requirements.
Because the Stormwater program is relatively new and managed by authorized states, the number
of facilities with general versus individual permits is not known. EPA handles NOIs for 10
nonauthorized states. In these states, 700 steam electric facilities (utilities and non-utilities) have filed
for general permits.
5.5.3 Regulations Addressing Solid and Hazardous Waste
Subtitle C of RCRA establishes a "cradle-to-grave" management system for wastes that are
considered hazardous because they fail tests based on physical and chemical characteristics (i.e., toxicity,
corrosivity, ignitability, and reactivity) or because they are listed as hazardous by EPA. Federal
regulations establish stringent environmental and administrative controls that must be applied to
management of these wastes. FBC wastes are currently exempt from federal regulation as hazardous
waste under Subtitle C pending this Report to Congress and the subsequent regulatory determination.
Therefore, these wastes are subject to the requirements of Subtitle D of RCRA as nonhazardous solid
waste.
Implementation of Subtitle D is the responsibility of individual states, but nothing prevents states
from imposing more stringent requirements (including hazardous waste requirements) on FBC wastes.
FBC units are located in 30 of the 50 states. EPA characterized the waste management requirements in
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27 of these 30 states using survey and other data sources.5 All of these states regulate FBC wastes under
the same programs as CCWs from conventional combustion processes.
Currently, 24 of the 27 states for which data are available (representing 86 percent of the
surveyed FBC generating capacity and 78 percent of FBC capacity overall) duplicate the federal policy
exempting CCWs (including those from coal-fired FBC) from hazardous waste regulations. The three
remaining states (Washington, Maine, and California) do not exempt FBC wastes from state hazardous
waste regulation. In these states, any FBC wastes that fail the hazardous waste characteristic tests would
be subject to state hazardous waste requirements and managed in units that meet permitting, design,
operating, corrective action, and closure standards.
As discussed in Section 5.2, FBC wastes seldom fail the hazardous waste characteristic tests.
Therefore, the majority of FBC wastes would be subject to state requirements under Subtitle D because
they do not fail the hazardous waste characteristic tests and/or are generated in the states that duplicate
the federal exemption. Table 5-10 describes state regulatory authority with respect to FBC landfills in
the 27 states for which data are available. These data show that the majority of states have the authority
to require permits and to impose physical controls and monitoring requirements on FBC landfills, at least
on a case-by-case basis. The types of regulatory controls include siting controls, liners, leachate
collection systems, ground-water monitoring, closure controls, daily (or other operational) cover, and
fugitive dust controls. EPA believes that the use of such controls has the potential to mitigate risks,
particularly ground-water pathway risks, from FBC waste disposal. The adequacy of this mitigation
depends on the extent to which states are exercising their authority in situations in which climate,
geology, site-specific conditions, and waste characteristics affect the magnitude of the risk.
Section 5.3 of this report found that most of the FBC waste landfills surveyed are subject to
regulatory permits and ground-water monitoring requirements and nearly all incorporate dust suppression
and run-on or runoff controls. Just over half of those surveyed have covers and leachate collection
systems and just under half are lined. These statistics suggest that states have exercised their authority to
impose control at FBC waste management units. To further examine state implementation of solid waste
requirements on FBC wastes, EPA examined in greater detail the regulations applicable in two states:
Pennsylvania and California. These two states are ranked first and second in FBC generating capacity.
Together, they account for more than 30 percent of total U.S. FBC electrical generation capacity. Table
5-11 summarizes the requirements in these states. Because surface impoundments are seldom used for
FBC wastes, this analysis focuses on landfill regulations.
Examination of these two states reveals some variation in approaches to implementing Subtitle D
requirements for FBC landfills. Both Pennsylvania and California subject FBC wastes to regulations that
impose requirements tailored to the characteristics of the waste. The program in California, however,
contains special provisions that apply to nonhazardous FBC wastes. The state allows generators of FBC
wastes that do not test hazardous to utilize facilities in the "standardized" regulatory tier. Nonhazardous
FBC wastes disposed in these facilities are subject to less stringent requirements, regardless of their
characteristics.
5 Four states (Colorado, Florida, Georgia, and Pennsylvania) indicated in the CIBO survey that they impose
different requirements based on the combustion technology used. EPA supplemented the survey data with specific
information from its review of regulations in Pennsylvania. EPA did not collect specific data on FBC waste
requirements in the other three states. These three states account for less than 10 percent of FBC equivalent
electrical generating capacity.
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Table 5-10. Current State Regulatory Controls on FBC Landfills
Permit Onsite
Permit Offsite
Siting Controls
Liner
Leachate Collection Systems
Ground-Water Monitoring
Closure Controls
Cover and/or Dust Controls
Corrective Action
Number of States"
23
27
25
23
23
25
25
27
22
Percent of States"
85%
100%
93%
85%
85%
93%
93%
100%
81%
Percent of Capacity"
94%
100%
96%
91%
95%
97%
94%
100%
96%
a Number of states with authority to impose the indicated requirement, either by regulation or on a case-by-case basis.
b Percent of the 27 surveyed states with authority. For testing requirements, percent of 1 7 states providing information on these
requirements.
c Percent of FBC generating capacity in the 27 surveyed states represented by states with authority.
Sources: CIBO, 1997c; EPA, 1995b; ASTSWMO, 1995; ACAA, 1996a
Table 5-11. State Waste Management Requirements Applicable to FBC Wastes
in Selected States
Pennsylvania
Landfill
Requirements
Grandfather
Clause
Minefill
Requirements
Soil Amendment
Requirements
Landfills are classified according to TCLP results for the wastes to be disposed. Specific design
requirements depend on the class of the landfill. Based on available characterization data, most FBC
wastes would be amenable to Class III landfills. Requirements for these include siting restrictions, a 4-foot
attenuating soil base (or 1 -foot-per-4 feet of waste), fugitive dust control, daily cover, soil erosion control,
ground-water monitoring, 2-foot clay cap at closure, and revegetation at closure.
Units permitted prior to July 4, 1992, were required to modify their operations to comply with the above
requirements by July 4, 1997. Liner and leachate collection requirements may be modified if the operator
could demonstrate that the unit had not caused unacceptable ground-water degradation.
FBC wastes must meet TCLP limits for disposal at a Class III landfill. Ground-water monitoring is required.
FBC wastes must meet pH limits. State agency notification and runoff and erosion controls are required.
There are siting limitations.
California
Landfill
Requirements
Any FBC wastes failing hazardous waste characteristic tests are subject to state hazardous waste
management requirements. However, based on available characterization data, most FBC wastes would
be managed under the non-hazardous solid waste program. Under this program, FBC wastes may be
managed in special "nonhazardous ash disposal/monofill facilities" which fall into the state's "standardized"
regulatory tier. FBC wastes also may be managed in solid waste landfills in the more stringently regulated
"full permit" tier.
"Nonhazardous ash disposal/monofill facilities" tier are required to obtain a standardized permit and are
subject to minimum operating standards including siting restrictions, control of windblown material, and
drainage control.
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Grandfather
Clause
Minefill
Requirements
Soil Amendment
Requirements
Information not available.
Information not available.
Information not available.
5.6 WASTE MANAGEMENT ALTERNATIVES
The risk assessment identified potential ground-water pathway risks to human health from FBC
wastes managed in unlined landfills. Mitigation of these potential risks might be accomplished through
the use of technologies that prevent or contain and collect leachate from FBC landfills. Specifically,
EPA identified the technologies in Table 5-12 as an alternative that would be practical and effective to
target and mitigate the potential ground-water risk. The technologies shown in Table 5-12 are considered
further in the cost and economic impact analysis (Section 5.7). Section 5.7 includes the option of
sending waste to an offsite commercial landfill employing these technologies, as well as the option of
constructing such a unit on site. Note that these technologies are consistent with those required under
Subtitle D of RCRA.
Table 5-12. Management Alternatives for Non-Utility CCW
Landfill
Design includes filter fabric, T sand layer, 2' clay liner, synthetic high-density polyethelene (HOPE) liner, leachate collection
system, and ground-water wells.
Operation includes environmental monitoring and leachate collection and treatment.
Closure requirements include 6" topsoil and vegetation, filter fabric, 1.5' sand layer, 2' clay layer, synthetic (HOPE) liner, and a
cover drainage system.
Post-closure includes environmental monitoring, landscape maintenance, slope maintenance, inspection, and administration.
Of the beneficial uses discussed in Section 5.3.5, agricultural use may be of environmental
concern, based on the non-ground-water risk assessment that found potential arsenic risks to human
health from this practice. An approach for mitigating this potential risk might include a standard limiting
the arsenic concentration in wastes intended for this use. The cost estimate for FBC waste includes
consideration of a more stringent approach: a ban on agricultural use. Minefilling also may be of
concern, particularly when wastes are placed below the water table. EPA is seeking further information
on this practice.
5.7 COMPLIANCE COSTS AND ECONOMIC IMPACTS
This section discusses the costs and economic impacts of risk mitigation alternatives for FBC
wastes. Details of this analysis are documented as part of the EPA docket.
5.7.1 Overview and Methodology
In estimating costs and economic impacts for FBC facilities, EPA used a similar approach to that
described in Section 3.7.1. Salient distinctions between the analysis in Section 3.7 and this analysis are
reviewed below.
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EPA's analysis for FBC facilities began with 84 FBC facilities identified in the CIBO FBC
Report (CIBO, 1997c). Half of these are in the electric service sector. EPA estimated the incremental
compliance cost of the risk mitigation alternative described in Section 5.6. As described in that section,
this requires generators to construct onsite composite-lined landfills or transport waste to an offsite
commercial Subtitle D landfill. The more economical method was assigned to each plant depending
upon its estimated annual FBC waste generation rate.
The cost estimate summed costs in five categories: initial capital costs, recurring capital costs,
annual operating and maintenance costs, closure costs, and annual post-closure costs. The specific
components included in each cost category were the same as those in the analysis for coal-fired utility
comanaged waste (see Section 3.7.1). As in that analysis, the cost estimate for FBC facilities employed
three different landfill sizes. Table 5-13 identifies the design features for FBC landfills.
Table 5-13. Design Parameters Assumed for Small, Medium, and Large FBC Landfills
Parameter
Landfill
Sizes
(tons/year)
small
medium
large
5,000
50,000
500,000
Depth
(feet)
small
medium
large
small
medium
large
Pile design
1.0
1.0
3.0
Combination fill design
17.1
51.8
75.1
Height
(feet)
small
medium
large
small
medium
large
Pile design
25.0
25.0
84.9
Combination fill design
21.4
20.3
74.6
Area
(acres)
small
medium
large
small
medium
large
Pile design
7.3
106.6
207.2
Combination fill design
4.6
24.5
111.8
Note: Landfill designs considered include a "pile design" constructed primarily above grade and a "combination fill design" constructed both
above and below grade.
For FBC wastes, the cost estimate was based on alternative management for the quantity of FBC
wastes currently disposed in landfills that do not meet the requirements described in Section 5.6. EPA
also estimated the additional, incremental cost if the large quantity of FBC waste currently minefilled and
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used in agriculture also were subject to the alternative management practices. This latter cost would
reflect a ban on minefilling and agricultural use. This is discussed below.
As in the analysis for coal-fired utility comanaged waste, a single cost equation was developed,
annualized costs were estimated as a function of facility-specific waste generation, and total industry
costs were derived by summing the facility-specific estimates. Costs and economic impacts are set forth
in the following three sections: incremental compliance cost, compliance cost impact on facilities as a
function of size, and industry impact.
Incremental compliance costs are the costs of risk mitigation practices over and above the cost of
current management practices. Using incremental compliance costs as an indicator of potential cost
burden, the analysis examined impacts on individual facilities as a function of size. As in Section 3.7,
this was performed using pro forma financial statements for three representative plant sizes. As for the
conventional coal-fired utility sector, the use of econometric models for the industry impact evaluation
was considered and rejected because of the uncertainty surrounding ongoing deregulation of the electric
power industry and the diversity of industrial and institutional sectors potentially affected. The industry-
level analysis, therefore, focuses on the number of affected facilities and the magnitude of incremental
compliance costs relative to the value of electricity sales.
5.7.2 Incremental Compliance Cost
EPA's estimate of the incremental compliance cost for FBC facilities is approximately $32
million per year. If the quantities of FBC waste currently used in minefill and agricultural applications
were subject instead to the risk mitigation alternative of Section 5.6, the additional incremental
compliance cost would be an estimated $52 million per year (for a total of some $84 million per year).
As discussed above, this latter cost would reflect a ban on minefilling and agricultural use. Variations on
this approach, as noted, could substantially reduce the total incremental compliance cost with
approximately $32 million being the floor. A limit on the arsenic concentration in FBC wastes destined
for agricultural use, for example, would affect a smaller quantity of waste than a ban on agricultural use.
Although the quantity of waste in agricultural use is small relative to quantities used in minefilling, this
variation would still result in a decrease in compliance costs.
Costs, again, are incremental (above current costs). Annual costs were discounted at 7 percent to
1998 dollars, with no inflation built into out-year estimates. Also, it was presumed that compliance
would be required immediately, and that amortization would take place over 40 years. As with the utility
and non-utility sectors, delayed compliance, were this to be considered, would result in much reduced
costs.
5.7.3 Compliance Cost Impact on Facilities as a Function of Size
EPA believes that the ability of industry to pass through cost increases will be limited because
only a small share of plants within the affected industries operate FBC units. Competition from
unaffected facilities would restrict the ability of facilities facing incremental compliance costs to increase
prices. Therefore, this analysis includes no analytical consideration of price effects.
Also, the analysis below excludes costs for quantities currently used in mining and agriculture.
The minefilling issue is discussed in detail in Section 3. If minefilling were to be banned, the impacts
shown below would increase roughly in proportion to the compliance costs given in Section 5.7.2.
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As discussed previously in this chapter, about half of the 84 FBC facilities are operated/owned
by entities in the electric service industry (i.e., independent power producers and utilities). The
remaining FBC waste generating facilities include about 7 operated by universities or colleges, about 15
operated by large businesses such as Archer Daniels Midland, General Motors, Iowa Beef Processors,
Exxon, and Fort Howard Paper, and the balanceabout 20operated by various small businesses or
unknown operators. Thus, EPA addressed the electric power segment of FBC facilities separately from
the more broad-based industrial/institutional FBC facilities.
Electric Power Sector
Based on the incremental compliance cost estimate, 42 FBC waste generators in the electric
power industry would incur incremental compliance costs of about $15.2 million per year, or about
$361,000 per facility. Economic impacts at the plant level will depend on several major factors,
including quantity of fuel used, quality of fuel, profitability, and production technology. To assess these
impacts across the range of plants, EPA estimated financial data for model plants representing three size
ranges: large (generating capacity of 100 MW), medium (generating capacity of 50 MW), and small
(generating capacity of 30 MW). These model facilities are representative of independent power
producers. Table 5-14 compares incremental compliance costs to revenues and net income for these
three model plants.
Table 5-14. Plant-Level Impact of Incremental Compliance Costs
Revenues from Electricity
Baseline Before Tax Net Income
Expected Incremental Compliance
Costs (replace unlined management
unit with composite-lined unit)
Expected Post-Compliance Net Income
Large FBC Independent
Power Producer
$1,000's
37,840
3,780
520
3,260
Percent of
Revenues
100%
10.0%
1.4%
8.6%
Medium FBC
Independent Power
Producer
$1,000's
18,900
1,510
280
1,230
Percent of
Revenues
100%
8.0%
1.5%
6.5%
Small FBC Independent
Power Producer
$1,000's
11,400
790
190
600
Percent of
Revenues
100%
7.0%
1.7%
5.3%
The incremental compliance cost for FBC waste should not impact the financial viability of FBC
facilities in the electric service sector. This appears true even for plants transitioning from the worst case
unlined landfill to a composite-lined landfill. For example, a large FBC independent power plant with
100 MW of generating capacity is estimated to comply for about $520,000 per year (or about $13 per ton
of waste). Based on typical annual revenues and cost, compliance costs would increase overall costs by
1.4 percent of revenues. Without any price adjustments, net income before taxes for a typical FBC
facility would be reduced from about 10 percent to 8.6 percent and remain at nearly $3.3 million per
year. EPA recognizes that such profit margin reductions may be considered significant by the individual
firm.
Financial impacts on a medium-sized FBC independent power plant suggest it should also remain
financially viable. Costs would increase by about 1.5 percent of revenues, with profitability (before tax)
at 6.5 percent of revenue and net income levels after compliance of more than $1.2 million per year.
(Annual incremental compliance costs are estimated at $14 per ton of FBC waste, or about $280,000 per
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year.) Small FBC independent power plants would incur slightly higher impacts at about 1.7 percent of
revenues.
Industrial/Institutional Sectors
As for conventional non-utility combustors, industrial and institutional FBC facilities include a
wide variety of facilities that generate electricity or energy for primarily internal use. The vast majority
of firms in these sectors, however, do not operate FBC units or burn coal at all. Because of the smaller
number of affected FBC facilities, FBC facilities represent an even smaller share of the corresponding
industry sectors than do conventional non-utility combustors. As for conventional non-utilities, fossil
fuel use and costs are a relatively small part of production inputs and costs. Therefore, the conclusions
presented in the paragraph above generally also are applicable to industrial and institutional FBC
facilities.
5.7.4 Industry Impacts
This analysis addresses the overall industry and the general implications for market supply of
selected industries.
Approximately half of all FBC facilities, as noted, are in the electric generating sector.
Department of Energy data show that independent power producers as a group generated 61.4 billion
kWh from coal fired generating capacity. Assuming this output is valued at $0.07 per kWh, the
equivalent market value of this output would be $4.3 billion. Assuming all FBC electric power facilities
fall in this special power generating segment, incremental compliance costs would equal about 0.3
percent of the segment's general market value, as shown in Table 5-15.
Table 5-15. Industry-Level Economic Impacts (FBC Wastes)
Sector
FBC Independent Power
FBC Industrial/Institutional
Industry Sales
($ billion/yr)
$4.3
Not estimated *
Incremental Compliance
Cost ($ billion/yr)
$0.015
$0.017
Compliance Cost as a
Percentage of Sales
0.3%
*
* Given the similar variety of sectors and smaller number of facilities, impacts are expected to be similar to or less significant
than those for conventional non-utilities (see Section 4.7.4).
Institutional/industrial FBC facilities include a broad variety of industry sectors similar to that
reflected in the conventional non-utility combustion population. Because of their small numbers, FBC
facilities account for an even smaller share of these industry sectors. Thus, the industry-wide economic
impacts from industrial and institutional FBC facilities are expected to be similar to or less significant
than those presented in Section 4.7.4.
5.8 FINDINGS AND RECOMMENDATIONS
5.8.1 Introduction
Based on the information collected for this Report to Congress, this section presents a summary
of the Agency's main findings presented under headings that parallel the organization of this chapter. It
then presents the Agency's tentative conclusions concerning the disposal and beneficial uses of FBC
wastes as discussed in this chapter.
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5.8.2 Findings
Sector Profile
There are about 84 facilities with a total of 123 FBC boilers in the United States. The
facilities are distributed throughout the United States, but Pennsylvania and California
together have 29 facilities.
Commercial-scale FBC technology is relatively new in the United States. Its use has
increased during the past 20 years, and the trend appears to be continuing.
The advantages of FBC over conventional processes include flexibility in fuel grades,
combustion efficiency, and emissions control.
Waste Generation and Characteristics
Nearly 10-million tons of combustion wastes are generated annually by FBC units. The
wastes comprise mostly fly ash and bottom ash (called bed ash).
These wastes contain relatively high residual levels of lime (which is introduced with fuel to
control sulfur emissions) and often exhibit self-cementing properties.
The types of low-volume wastes generated by FBC operations are similar to those generated
at facilities that use conventional boiler technologies, such as pulverized coal boilers
commonly used at utility facilities. Based on limited available data, the characteristics of
FBC low-volume wastes are also similar to the counterpart utility low volume wastes at
facilities that employ conventional boiler technologies.
The constituents of concern in the combustion wastes are trace metal elements, in particular
the eight RCRA metals. No organic constituents and no radionuclides were identified at
potential levels of concern in these wastes.
FBC wastes seldom test characteristically hazardous. Only one constituent, mercury, in one
sample at one facility (out of 24 facilities for which data are available) exceeded the
regulatory level.
Based on limited data, none of the combustion wastes appears to be characteristically
corrosive, reactive, or ignitable.
Waste Management Practices
The predominant FBC waste disposal practice is placement in landfills. The typical landfill
is about 40 acres in size. Surface impoundments are rarely used to manage these wastes.
These wastes are monofilled and to a lesser extent are comanaged with low-volume wastes
and/or other industrial wastes.
The current trend for environmental controls at FBC waste management units is toward use
of liners, cover, leachate collection, dust suppression, and surface and ground-water
monitoring.
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A significant portion of FBC wastes is reused. About 75 percent of the wastes are currently
managed through beneficial uses. The largest single beneficial use is in minefill, including
mine reclamation, which accounts for about 60 percent of the generated wastes. Other
beneficial uses include waste stabilization (6 percent), construction fill (5 percent), and
agricultural use (1 percent).
Potential Risks and Damage Cases
EPA conducted a risk assessment that found a lack of potential human health risk for
virtually all waste constituents. Arsenic was the one constituent for which the Agency
identified potential human health risks via the ground-water pathway for FBC wastes that
are managed in unlined landfills. The identified risk is based on high-end risk scenarios in
EPA's risk modeling analysis for human ingestion of well water influenced by releases from
the waste management unit. The time to reach significant risk in ground water is estimated
to be in excess of 3,000 years.
EPA conducted a risk assessment that found a lack of potential human health risk for
virtually all waste constituents. Arsenic was the one constituent for which the Agency
identified potential human health risks via non-ground-water pathways where these wastes
are used as soil amendments for agricultural purposes. The identified risk is based on high-
end risk scenarios in EPA's risk modeling analysis, for human ingestion exposure routes.
The Agency did not perform a risk analysis for management in impoundments because they
are rarely used and the known impoundments are lined; however, the Agency believes that
there should be no significant ground-water risks posed by lined waste management units.
The Agency identified no ecological risks associated with management of FBC wastes.
The Agency identified no documented damage cases associated with the management of
FBC wastes.
Some natural arsenic levels in U.S. soils have the potential to pose higher risks than the risk
identified with the level of arsenic contributed by these wastes for non-ground-water
pathways.
Existing Regulatory Controls, State, and Federal Requirements
The FBC sector has a significant level of installed environmental controls for these wastes.
Most of the active FBC waste landfills are subject to regulatory permits and ground-water
monitoring requirements; nearly all incorporate dust suppression and surface runon/runoff
controls. Nearly half are lined and have leachate collection systems and covers.
States increasingly have begun to impose controls on FBC waste management units. In
addition to regulatory permit programs, the majority of states now have the authority to
require siting controls, liners, leachate collection systems, ground-water monitoring, closure
controls, daily or other operational cover, and fugitive dust controls for management of
these wastes.
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Potential Costs and Impacts of Regulation
The Agency estimates that the total annual incremental compliance costs for mitigation of
the potential arsenic risks identified in this study would be approximately $32 million
(1998$). These costs represent replacement of existing unlined management units with
lined management units, and implementing ground-water monitoring and leachate collection
and treatment. These measures do not represent implementation of full Subtitle C
requirements, but rather modifications of such requirements that could potentially be
adopted under Section 3004(x) of RCRA.
If these wastes were to be regulated under full Subtitle C, virtually all existing facilities
would be required to invest substantial funds and resources to modify existing management
practices. The total annual cost of full Subtitle C requirements would considerably exceed
the $32 million (1998 $) estimate above.
If beneficial uses of theses wastes were subject to Subtitle C requirements, possibly all
beneficial use practices and markets would cease. If so, the impact on waste management
practices would be substantial, considering that about 75 percent of FBC wastes are reused.
5.8.3 Recommendations
Following are the Agency's recommendations for the wastes covered in this chapter. The
recommendations are based on EPA's analysis of the eight Congressionally mandated study factors
(Section 1.2). These conclusions are subject to change based on continuing information collection,
continuing consultations with other government agencies and the Congress, and comments and new
information submitted to EPA during the comment period and any public hearings on this report. The
final Agency decision on the appropriate regulatory status for these wastes will be issued after receipt
and consideration of comments as part of the Regulatory Determination, which will be issued within
6 months.
1. The Agency has tentatively concluded that disposal of these wastes should remain exempt from
RCRA Subtitle C.
As with the utility and non-utility coal combustion wastes addressed in Chapters 3 and 4, the
Agency has tentatively concluded that FBC wastes, including wastes from petroleum coke combustion
and from other fuels that are co-fired with coal, and also low-volume wastes where they are managed
with the combustion wastes, generally present a low inherent toxicity, are seldom characteristically
hazardous, and generally do not present a risk to human health and the environment. State programs
increasingly require more sophisticated environmental controls at these types of facilities. For example,
most all of the FBC landfills are subject to regulatory permits and ground-water monitoring
requirements; nearly all implement dust suppression and runon/runoff controls. No documented damage
cases were identified and no significant ecological risks were identified. These types of facilities are
typically located in areas of low population and thus present infrequent opportunity for human exposure.
Although arsenic was identified from EPA modeling to pose a potential risk at unlined landfills, there
were no documented problem or damage cases identified with arsenic as a constituent of concern. The
predominant practice is to manage these wastes in landfills, with a much lower frequency of using
impoundments. Nearly half of the landfills are lined and more than half have leachate collection systems
and covers. Overall, the Agency believes that regulation under Subtitle C authority is not warranted
when these wastes are disposed. For the issues discussed below involving agricultural use and
management of these wastes in mines (minefill), the Agency is still considering whether some regulation
under RCRA Subtitle C may be warranted.
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2. The Agency has tentatively concluded that most beneficial uses of these wastes should remain
exempt from Subtitle C.
No significant risks to human health and the environment were identified or believed to exist for
any beneficial uses of these wastes, with the possible exception of minefill and agricultural use as
discussed below. This is based on one or more of the following reasons for each use or resulting product:
absence of identifiable damage cases, fixation of the waste in finished products which immobilizes the
material, and/or low probability of human exposure to the material.
3. The Agency is tentatively considering the option of subjecting practices involving the use of these
wastes for agricultural purposes (i.e., as a soil nutrient supplement or other amendment) to some
form of regulation under Subtitle C.
As mentioned above, the Agency identified potential risk from exposure to arsenic in these
wastes when they are used for agricultural purposes. The risks identified with this practice may be of
sufficient concern to consider whether some form of control under Subtitle C is appropriate, given the
increasing trend for use of these materials as agricultural amendments. An example of such controls
could include regulation of the content of these materials such that arsenic concentrations could be no
higher than that found in agricultural lime. On the other hand, imposition of controls under Subtitle C
may not be warranted if sufficient protection may be afforded by the Agency engaging the industry to
establish voluntary controls on this practice. An example of such voluntary controls could consist of an
agreement to limit the level of arsenic in these materials. The Agency solicits comment on its tentative
conclusion and specific approaches that could be pursued to address the concern..
A significant amount of FBC waste, about 60 percent, is used for minefill. Of this amount, large
quantities are used specifically for reclamation of old surface coal mine working. EPA recognizes that
mine reclamation practices with the highly alkaline FBC wastes can have some significant, positive
environmental benefits. For example, the FBC wastes contribute to neutralizing acid mine drainage at
the old mine workings, and when mine reclamation activities are completed, new productive uses may
be made of the land. The Agency also realizes that there are a number of well-managed state mine
reclamation programs that oversee the application of FBC wastes. RCRA, however, does require the
Agency to review the management of these wastes. As discussed in Chapter 3's recommendations, the
potential for risks associated with this practice may be of sufficient concern to consider whether some
form of control under Subtitle C is appropriate, given the increasing trend for use of these materials as
minefill. The Agency, however, currently lacks sufficient information with which to adequately assess
risk associated with this practice and therefore to decide whether this practice should remain exempt
from Subtitle C. The Agency solicits comment on whether there are some minefill practices that are
universally poor and warrant specific attention. For example, the Agency has found several situations in
which cement kiln dust placed in direct contact with the ground-water table has created problems. EPA
also seeks comment on whether coal or other fossil fuel combustion wastes used as minefill and placed in
direct contact with the water table would create environmental concerns, and if that specific practice
should be regulated. The Agency's focus is on potential risks that may be posed via the ground-water
and surface pathways from use of these wastes as minefill.
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6.0 OIL COMBUSTION WASTES
Oil combustion is used by utilities to generate electricity and by non-utilities to generate
electricity, heat, or steam for a variety of operations. The analysis of oil-fired combustion processes and
wastes in this report is based primarily on electric utility data. EPA has included available
characterization information and analysis of non-utility operations in this study. Only a portion of the
oil combustion facility population generates significant amounts of combustion waste. This portion
comprises steam electric plants that burn residual fuel oil and is described further in Section 6.1.
SECTOR OVERVIEW
Petroleum products account for a substantial portion of the energy consumed in the United
Statesnearly 40 percent in 1997 according to the Energy Information Administration (EIA, 1998a).
Most of this, however, is in the form of motor gasoline and other fuels used in the transportation sector.
Only a fraction of U.S. petroleum consumption is by utilities and non-utility combustors, and only part of
this is residual fuel oil, which is the only form likely to generate significant quantities of combustion
waste (EIA, 1998a).
In the utility sector, the total amount of electricity generated by oil is small relative to the total
generation of electricity. Electricity from oil combustion is less than 3 percent of a total that includes
hydroelectric and nuclear as well as fossil fuel combustion (FFC) (EIA, 1998a). As discussed in Chapter
2, oil combustors represent a much smaller portion of utility FFC capacity than coal combustors. Oil
combustion is, however, the dominant utility power source for certain regions of the United States
(e.g., Florida, Hawaii, the Northeast) and the territories (Puerto Rico, the Virgin Islands, and Guam).
Additionally, oil has a history of use in support of utilities that burn coal for their baseload but
use oil units to meet peak needs. These peakload units are used to supply electricity during periods of
high electricity demand. The predominant characteristic of the peaking unit is the ability to startup and
shutdown relatively rapidly, a characteristic that coal-fired units are unable to provide, but to which oil
and gas are well-suited. Oil also may be used in coal-fired boilers for startup and flame stabilization.
This practice, however, was covered by the 1993 Regulatory Detemrination.
As of December 1994, there were 177 utility facilities in the United States and its territories that
combusted oil (EEI, 1994). Some of these facilities burned only oil, some operated both oil-fired boilers
and boilers fired by other fossil fuels, and other facilities used oil as alternate fuel in units that primarily
burned other fossil fuels. Figure 6-1 shows the geographic distribution of these facilities. Only 40 of
these facilities are baseload oil-fired generators. Because of this, the location of facilities shown in the
figure does not closely mirror the concentration of oil-fired utility capacity in the United States.
In fact, the concentration of oil-fired utility capacity corresponds more closely to the presence of
large, oil-fired baseload units in certain regions of the country. Table 6-1 shows the location of these
baseload units. It is these baseload units that are likely to generate significant quantities of oil
combustion waste on a regular basis. Thus, while utility oil combustion waste has the potential to be
generated in a number of locations, generation and management of significant quantities of this waste
takes place primarily in the Northeast, mid-Atlantic, and Florida.
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Figure 6-1. Number of Utility Power Plants Burning Oil (in whole or in part) by State
Percent of national oil-fired utility capacity:
IZ3
1-5%
6(CT)
11 (NJ)
2(DE)
6(MD)
1(DC)
Source: EEI, 1994
Table 6-1. Locations of Utilities with Oil-Fired Baseload Units
Location
Florida
Islands (GU, HI, PR, VI)
New England (MA, ME, CT)
Mid-Atlantic (NY, NJ, MD, DE)
Total
Number of Facilities
11
13
6
10
40
Source: EEI, 1994
Oil-fired non-utilities represent a much larger number of facilities than do utilities. The 1990
U.S. EPA National Interim Emissions Inventory (EPA, 1990) includes more than 2,000 facilities with oil-
fired units.1 These facilities, however, account for only about 25 percent more generating capacity than
1 As discussed in Chapter 4, because the 1990 National Interim Emissions Inventory captures only the
largest non-utilities, it likely underestimates the total number of non-utility fossil fuel combustors. The small
facilities that are not included in the database, however, are unlikely to generate significant quantities of waste.
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oil-fired utilities. Equivalent electrical generating capacity is approximately 54,000 megawatts (MW) for
oil-fired non-utilities (EPA, 1990) compared to 43,000 MW for oil-fired utilities (EEI, 1994). Unlike
utilities, oil-fired non-utilities are distributed throughout the United States and in a variety of settings
(urban to rural). As discussed in Section 6.1, the fuel and air pollution control technology characteristics
of non-utilities indicate they are a less significant source of oil combustion waste than are utilities.
Despite its significance within certain niches (i.e., regional power generation, peakload units,
non-utility use), the quantity of oil used to generate power is decreasing. The last 20 years have seen a
significant drop in the use of fuel oil by utilities, from over 600-million barrels (25.2-billion gallons) in
1978 to only 86-million barrels (3.6-billion gallons) in 1995 with the steepest decline between 1978 to
1985 (EPRI, 1998a). This trend corresponds to a decline in construction of new oil-fired utility plants.
While over 100 units were constructed during the 1960s and 1970s, the Electric Power Research Institute
(EPRI) reports that only three new units have been brought on line since 1980. EPRI additionally reports
that many oil units have been, or are being, converted to burn both natural gas and oil to provide
additional flexibility in economical fuel choice (EPRI, 1998a).
As discussed in Chapter 2, the declining trend for oil combustion is expected to continue during
the next two decades. Oil-fired utility steam plants are expected to be replaced by combustion turbine
technologies. As a result, while industrial combustion of residual oil is expected to grow modestly, this
growth will be more than counter balanced by a dramatic reduction for oil-fired utilities (EIA, 1998a).
6.1 WASTE GENERATION
The generation of large-volume wastes from oil combustion depends on combustion technologies
(Section 6.1.1), air pollution control technologies (Section 6.1.2), and fuel type (Section 6.1.3). Oil
combustion wastes (OCWs) consist primarily of the following:
Fly ash. The fine particles entrained in the flue gas leaving the boiler. If present, a
particulate control system will capture some part of these particles. Additionally, particles
may adhere to equipment through which the flue gas is routed (e.g., the air preheater) or be
knocked down in other units (e.g., the economizer). These particles are removed during
equipment cleanout and are often described as washwater solids. Washwater solids usually
are similar to, and managed along with, fly ash captured in the air pollution control system.
Bottom ash. The heavier fraction of the waste stream that collects in the bottom of the
boiler and is removed either manually or by gravity. Bottom ash includes a small amount of
boiler slag that adheres to the boiler surfaces. The slag fraction must be removed by
chiseling, jackhammering, sootblowing, or sandblasting.
In addition to the large-volume combustion wastes, oil combustors generate certain low-volume
wastes similar to those generated by coal combustors. These low-volume wastes are the result of
supporting processes (see Section 6.1.4) that are ancillary to, but a necessary part of, the combustion and
power generation processes. These wastes may include the following:
Boiler blowdown. Waste that is continuously or intermittently removed from boilers that
recirculate water.
These facilities burn less fuel because of their capacity and are less likely to operate air pollution control devices.
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Cooling tower blowdown and sludge. Wastes removed periodically from closed-loop
cooling systems.
Water treatment sludge. Wastes resulting from treatment of makeup water for the steam
cycle or for noncontact cooling.
Regeneration waste streams. Wastes resulting from periodic cleaning of ion exchange
beds used to remove mineral salts from boiler makeup water.
Air heater and precipitator washwater. Wastes resulting from the periodic cleaning of
the outside (fireside) of heat exchanging surfaces.
Boiler chemical cleaning waste. Wastes resulting from the periodic cleaning of the inside
(waterside) of boiler tubes with chemical solutions.
Floor and yard drains and sumps. Wastewaters collected by drains and sumps and
include miscellaneous drainage from the plant site, including precipitation runoff, piping
and equipment leakage, and washwater.
Laboratory wastes. Wastes generated in small quantities during routine analysis of fuel,
intake water, wastes, and other samples at a plant site.
Finally, at most oil-fired utilities, fly ash (and sometimes bottom ash) is transported wet to solids
settling basins (SSBs) (see Section 6.3), often using equipment washwater. Often, low-volume wastes
also are managed in these basins. The periodic dredging of solids from these basins results in the
generation of a waste stream known as SSB solids. SSB solids are composed of fly ash and solids settled
from washwater and other low-volume wastes.
Comprehensive industry-wide data on the generation of OCWs are not available. Estimates by
EPRI are available for the utility sector. Extrapolation has been made based on these estimates and
relative fuel usage in order to also characterize waste generation in the non-utility sector.
For the utility sector, EPRI has estimated that between 15,000 and 90,000 tons of oil ash are
"generated" annually. As discussed in Section 6.1.2, only a portion of the fly ash generated is collected.
An estimated total of 23,000 tons of OCW were collected by utility oil combustors in 1995 (EPRI,
1998a).2 This quantitative estimate is less than one one-thousandth of the quantity of large-volume utility
coal combustion wastes generated in 1997 (105-million tons).
For oil-fired non-utilities, less total ash is expected to be generated because of air pollution
control technologies and fuel characteristics (see Sections 6.1.2 and 6.1.3). EPA estimates that 5,500
tons of ash should be generated annually by non-utility oil combustion operations. While non-utilities
and utilities burn comparable amounts of residual oil, the limited application of air pollution control
devices at non-utilities results in significantly lower aggregate ash generation. Using EPA's estimate in
the 1990 U.S. EPA National Interim Emission Inventory (EPA, 1990) (5,245 oil-fired boiler units in the
non-utility sector), the average non-utility OCW generation rate would be just over 1 ton per unit per
year.
2 According to EPRI, a conservative "high" estimate would be about 70,000 tons, assuming most waste is
handled wet and then dewatered to 60 percent water content.
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The portion of OCW generated that represents bottom ash versus fly ash varies greatly depending
on fuel type and combustion technology. In some cases, the quantity of bottom ash generated is so low
that it is collected infrequently. EPRI, in a study of 17 utility oil combustors, found the amount of
bottom ash collected to be between 6 percent and 25 percent of the amount of fly ash (EPRI, 1998a). A
general rule of thumb in the industry is that 70 percent of the ash generated (emitted and collected)
should be fly ash versus 30 percent bottom ash (Stultz and Kitto, 1992).
Little information is available on the rates at which low-volume wastes are generated at oil-fired
utilities; however, EPRI reports that oil-fired units typically generate boiler fireside washwater at a rate
of 7 gallons per day per MW. EPRI estimates air preheater washwater generation to be at a rate of 17.6
gallons per day per MW, or 2.5-million gallons per year for a 400-MW baseload unit (EPRI, 1998a).
6.1.1 Combustion Technology
Two technologies are currently used for oil combustion: steam electric boilers and combustion
turbines (CT). Combustion turbine operations use exhaust from oil combustion directly to drive turbines
that produce electricity. Because the exhaust must be free of particulates (e.g., ash) that would damage
the turbine, natural gas or high-grade fuel oil (i.e., distillate oil) is typically burned. Thus, ash generation
from this technology is reportedly low. For example, one CT facility discussed in the EPRI 1998 Oil
Combustion By-Products Report generated about one-half ton of bottom ash per year (EPRI, 1998a).
Because CTs produce little ash, the focus of this discussion will be on steam electric boilers.3
Oil-fired steam electric units are conceptually similar to coal combustion units: they combust oil
in a boiler to produce steam, which is in turn used to provide heat or steam or drive turbines that generate
electricity. Box 6-1 provides a general overview of this technology. Oil-fired steam electric boilers,
especially in the utility sector, burn a relatively low grade and, therefore, less expensive oil (i.e., residual
oil, typically Number 6 fuel oil). As discussed in Section 6.1.3, the combustion of this type of fuel
results in the generation of significant amounts of OCW.
Box 6-1. Oil-Fired Steam Electric Boiler Technology
In steam electric generation, atomized oil and preheated air are combined in a boiler and combusted. Oil for
combustion is atomized to very small droplets, producing high surface to volume ratios. Atomization may be
accomplished mechanically, with the pressure of the fuel itself providing the energy for atomization, or with the
assistance of pressurized steam or compressed air. The residual oils typically used for steam generation require
heating to reduce their viscosity prior to atomization. The atomized fuel is injected into the furnace in a fine
mist through specially designed burners.
The burners disperse the fuel stream into a stream of preheated combustion air. In a typical oil combustion unit,
air entering the boiler is preheated in a heat exchange unit (i.e., an air preheater). These are typically rotating,
basket-shaped devices that pass alternately through the flue gas (i.e., hot gas leaving the boiler) and combustion
air streams (i.e., unheated air entering the boiler). Heat recovered from the flue gas is transferred to the
incoming air to increase boiler efficiency. Air preheaters collect ash from the flue gas and must periodically be
cleaned to maintain maximum efficiency.
Sources: Stultz and Kitto, 1992; EPRI, 1998a
3Oil-fired CT ash, however, is covered by this study.
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Oil-fired utility boilers are smaller on average than coal-fired boilers. This is because the oil-
fired utility population contains a higher proportion of small units, as shown in Figure 6-2. Nearly all of
the small units shown in Figure 6-2, however, are peaking, cycling, or standby units. Baseload oil-fired
boilers (average 269 MW) are similar in size to coal-fired utility boilers (average 256 MW). Based on
the average size reported in the 1990 U.S. EPA National Interim Emissions Inventory (just over 10 MW
equivalent), oil-fired non-utility boilers are much smaller than utility boilers. Because of their smaller
size, oil-fired non-utility boilers generate less ash on a per-boiler basis and likely are subject to less
frequent cleanout.
Figure 6-2. Capacity of Utility Oil-Fired and Coal-Fired Boilers
e.
:i
m 200
5
i_
0-10
Source: EEI, 1994
1B6
152
90
>10-50
"63"
249
180
89
56
48
1 12
1 1 1
>50-100 >100-250 >250-500 >500-1000 >1000
Boiler Size (megawatt equivalents)
D Coal-fired Q Oil-fired
6.1.2 Air Pollution Control Technologies
Because of the low sulfur content of the fuel, oil combustion units typically do not require flue
gas desulfurization (FGD) technology; therefore, oil combustion does not generate FGD waste.
Although oil-fired utilities are subject to particulate matter restrictions similar to those for coal-
fired utilities, particulate controls are utilized much less frequently at oil-fired facilities than at coal-fired
plants. As shown in Figure 6-3, the majority (nearly two-thirds) of utility generating units that combust
oil either as primary or as alternate fuel do not utilize particulate control equipment. This is due to three
factors:
1. Because of the relatively low ash content of the fuel (see Section 6.1.3), the rate of emission
may be low enough to not require control.
2. The physical size of a large fraction of oil fly ash (see Section 6.2) is below that currently
regulated under the Clean Air Act (CAA).
3. The size (i.e., MW capacity) of many of the facilities (see Section 6.1.1) is such that they
fall below thresholds for regulation under the CAA (see Section 6.5).
6-6
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Figure 6-3. Participate Control Technologies at Oil-Fired Utilities
Mechanical 18%
None 66%
Electrostatic Precipitator (ESP) 15%
Fabric Filter 1%
Combination* 1%
'Mechanical collector followed by ESP.
Note: Percentages shown are of 354 units identified that burned oil In 1994. Total may notsum to 100 due to rounding.
Source: EEI, 1994
While participate control use for oil-fired units overall is low, the larger utility oil combustion
facilities are more likely to incorporate controls (see Table 6-2). As size decreases, oil-fired utilities are
less likely to apply controls. Because of their smaller size distribution, oil-fired non-utilities are expected
to be even less likely than utilities to apply controls. This, in turn, would mean less fly ash is collected
for management in the non-utility sector.
Table 6-2. Participate Control by Size of Utility Oil Combustion Unit
Utility Units" with Capacity
Over 500 MW
Between 101 and 500 MW
Under 1 00 MW
Percent of Total Units
within Size Category
14%
42%
44%
Percent of Total in Size Category
with Participate Control
39%
39%
29%
* 354 units at 177 facilities burned oil in whole or in part in 1994
Source: EEI, 1994
The same technologies are used to control particulates at oil-fired utilities as at coal-fired
utilities. Chapter 3 provides general descriptions of these technologies. When applied at oil-fired units,
the collection efficiencies of these technologies varies due to fly ash characteristics and combustion
conditions, as shown in Table 6-3. Even at its most effective, oil ash capture is less efficient than coal
ash capture. The lower collection efficiency means less fly ash to be managed by oil combustors.
6.1.3 Fuel Usage
Like ash from coal combustion, oil ash results from uncombusted materials in the fuel; therefore,
OCW generation is affected by the ash content of the fuel. The ash content of fuel oils varies depending
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Table 6-3. Relative Removal Efficiencies of Particulate Control Technologies
Fuel
Oil
Coal
Control
Mechanical
Electrostatic
Precipitators
(ESP)
Mechanical
Electrostatic
Precipitators
Conditions
Normal operations
Unusual operating conditions
(upsets, dirty oil, cleanouts)
Older combustion units
Newer combustion units
Normal operations
Normal operations
Removal
Efficiencies
30%
up to 85%
40-60%
70-90%
up to 90%
99%
Comments
Due to the small particle size of oil fired systems;
particularly in units with reburn systems
Capturing larger particles associated with unusual
conditions
Less efficient; carbon factor*
Smaller particle size and higher carbon content*
than coal ash
Most efficient for largest particles
Large particles, lower carbon content
*A higher carbon content results in a lower resistivity of fly ash and, therefore, less effective collection by the electric field in an ESP.
Sources: EPRI, 1998a; Stultz and Kitto, 1992; EPA, 1998c; Elliott, 1989; DOE, 1993
on type. Fuel oils are classified according to the point of production in the distillation process, which
separates crude oil into various oil fractions according to vapor pressure. For purposes of this discussion,
the significant fractions resulting from distillation are distillate oils (including No. 1, No. 2, and No. 4
fuel oils) and residual oils (including No. 5 and No. 6 fuel oil and Bunker C oil). Because oil-fired
boilers provide a wide range of fuel flexibility, the same burner technology can be used to combust a
variety of fuel oil grades.
As shown in Table 6-4, all types of fuel oil have a much lower ash content than coal. This is a
significant factor contributing to the much lower generation of waste by oil combustors. Furthermore, of
the types of fuel oil, only residual oil has a significant ash content. Distillate oil generates little or no
ash.
Table 6-4. Relative Ash Content by Weight
Type of Fossil Fuel
Coal:
Oil:
Sources:
Anthracite and Lignite
Bituminous
Average: 1975
1996
Residual Oil (No. 6 fuel oil)
Distillate Oil (No. 2 fuel oil)
Percent of Ash by Weight
4 to 19%
3 to 32%
13.5%
9.22%
less than 1% (0.009 to 0.1 6)
negligible
CIBO, 1997c; DOE, 1993; EIA, 1996f; EPRI, 1998a
As presented in Figure 6-4, most of the oil burned by electric utilities is residual fuel oil. At
utilities, distillate oil, which is more costly than residual oil, is used mainly for boiler startup prior to
combusting residual oil and coal.4 The less expensive residual oils, particularly No. 6, are the primary
4EPA's 1993 Regulatory Determination covered coal combustion wastes where oil is used as a start-up fuel
and for flame conditioning.
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March 1999
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Figure 6-4. Oil Consumption by Utilities and Non-Utilities
mnnn
IUUUU
c onnn
o OUUU
I
c
o
= cnnn
p DUUU
s^
c /.nnn
. fUUU
S
a
3 onnn
in £\J\J\J
o
O
Utilities Non-utilities
O Distillate Oil Q Residual Oil
Source: EIA, 1997f
fuels for oil-fired utilities (EPRI, 1998a). Non-utility fuel usage, in contrast, favors the distillate oils. As
a result, despite the greater total oil-fired capacity of non-utilities, utilities burn more residual oil and,
thus, generate more waste. The total annual amount of residual oil used by utilities is about 800-million
gallons more (about 26 percent) than that used by non-utilities.
Fuel characteristics affect waste generation in other, less direct ways as well. For example,
corresponding to its low ash content, fuel oil contains a large carbon content. Because of this, significant
amounts of carbon may remain unburned, contributing to the waste volume. Certain plants reinject fly
ash back into the boiler to increase the burn efficiency, lower the waste carbon, and reduce the net
quantity of waste generated.
In addition to the inherent amount of non-carbon material in the original fuel, additives to the
fuel account for some of the waste residual. EPRI reports that fuel additives are assumed to add a factor
of two to the inorganic ash fraction. The most common additives are magnesium-based compounds
added to control slagging and corrosion caused primarily by vanadium in the oil; the amount added
typically varies in proportion to the amount of vanadium present.
In addition to residual and distillate fuel oils, some oil-fired utilities in the United States have
considered burning a new type of fuel, called Orimulsion. Orimulsion is the trademark name of a fuel
produced in Venezuela that is a mixture of water (30 percent) and bitumen (70 percent), a heavy
hydrocarbon. Orimulsion performs similarly to No. 6 fuel oil and can be burned using existing oil-fired
boilers. Worldwide, only a few facilities, primarily in Japan and Canada, have begun firing Orimulsion
on a commercial basis. No facilities in the United States currently burn Orimulsion. Therefore, this
chapter focuses on wastes from standard fuel oils.
March 1999
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Report to Congress on Wastes from the Combustion of Fossil Fuels
6.1.4 Supporting Processes
The generation of low-volume combustion wastes is associated primarily with processes that
support the combustion process or make use of the products of combustion. Some of the same
supporting and enabling processes can accompany combustion at oil-fired facilities as at coal-fired
facilities, with the obvious exceptions of coal storage and coal processing. Little if any fuel oil
processing occurs at oil combustion sites. Thus, the types of supporting processes at oil combustors
include the following:
Steam generation
Cooling
Water treatment
Cleaning and maintenance.
Chapter 3 describes these processes in detail. The discussion below describes some aspects of
these processes that are relevant to waste generation at oil combustors; however, quantitative information
on the amounts of low-volume combustion wastes generated at oil combustors is scarce.
The supporting process of primary concern at oil-fired utilities is equipment cleaning operations.
Boiler chemical cleaning wastes and equipment washwater frequently are comanaged with OCWs in the
settling basins that generate SSB solids (see Section 6.3). At oil-fired utilities, cleanout operations
addressing fireside equipment (boilers, flues, hoppers, and stacks) are performed periodically (e.g.,
yearly or less frequently) while units are not operating. Deposits in fireside equipment are typically
removed using high pressure water, although alkaline (caustic) or acidic solutions may be used. Heat
exchange units such as the air preheaters and economizers are typically cleaned more often (e.g.,
quarterly, monthly) to maintain boiler efficiency. Slag on the walls of boilers may in some circumstances
require physical cleaning (i.e., jackhammering or chiseling); in other cases compressed air (i.e.,
sootblowing) may be used (EPRI, 1998a).
6.2 WASTE CHARACTERISTICS
The available data to characterize OCWs are from utilities. The Agency believes that OCWs at
non-utilities have the same characteristics as those at utilities due to the use of the same fuel types and
combustion technologies.
6.2.1 Physical Characteristics
Oil fly ash is a solid composed of fine particles. The particles are characterized by a smaller size
distribution than coal fly ash. The typical median diameter is a few microns compared to median
diameter of 10 to 20 microns for bituminous coal ash. Eighty percent of oil fly ash particles are smaller
than 15 microns in diameter (EPRI, 1998a).
Oil bottom ash also is a solid, but is made up of heavier particles that are not entrained in flue
gas. Some bottom ash may form a fused solid in the boiler that must be broken up to be removed.
OCWs (particularly fly ash and sometimes bottom ash) often are sluiced to SSBs, where they are
managed along with equipment washwaters and other plant wastewaters. Solids settled from these basins
are known as SSB solids and are composed primarily of fly ash captured either in particulate control
units or in operational equipment (economizers, air preheaters) (EPRI, 1998a). Because they result from
wet management, SSB solids have a much higher moisture content than other OCWs.
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Report to Congress on Wastes from the Combustion of Fossil Fuels
6.2.2 Chemical Characteristics
Major constituents of oil fly ash include silicon, iron, sulfur, magnesium, vanadium, aluminum,
sodium, calcium, nickel, and potassium. These constituents are present primarily in the form of oxides.
In most cases, their presence can be traced to the inorganics contained in fuel oil. Magnesium content
may be high when it is used as a fuel additive to control slagging. Most of the unburned carbon from oil
combustion is partitioned into the fly ash stream; oil fly ash may contain 30 to 80 percent unburned
carbon. For the calculation of ash generation discussed in Section 6.1, EPRI used the value of 67 percent
unburned carbon.
Bottom ash, in contrast, contains little unburned carbon. It is generally higher in silicon than fly
ash, with other major constituents present in similar concentrations to fly ash. Because they are
composed primarily of fly ash from the particulate control operations and the air preheater and
economizers, SSB solids are chemically similar to fly ash in their major constituents. A notable
difference is in the iron content in the SSB solids, presumably resulting from precipitation during
treatment (EPRI, 1998a).
Based on available data on organics (see Section 6.2.3), dioxins, and nonmetallic inorganics,
EPA believes metals are the class of constituents of concern in OCW. Oil ash can contain high levels of
vanadium and nickel, and varying levels of other trace elements. Table 6-5 presents observed
concentrations for these constituents.
6.2.3 Leaching and Hazardous Waste Characteristics
Using data available on the composition of OCWs, EPA evaluated whether the waste exhibited
any of the four characteristics of hazardous waste: corrosivity, reactivity, ignitability, and toxicity. Based
on available information and professional judgment, EPA believes that OCWs are not reactive or
ignitable. Fly ash and bottom ash cannot be considered corrosive under EPA's definitions because the
characteristic does not apply to solid materials. Furthermore, pH data are available for 29 samples of
OCW from six sites (presumably from ash sluice water or liquids entrained in SSB solids). None of
these samples exceeded the limits for corrosivity (pH less than or equal to 2 or greater than or equal to
12.5). The range of pH exhibited by these samples was 2.97 to 10.8.
EPA evaluates the characteristic of toxicity using Toxicity Characteristic Leaching Procedure
(TCLP) results. Table 6-6 presents observed TCLP results for OCWs for a number of constituents.
These include the eight metals regulated under the Resource Conservation and Recovery Act (RCRA)
and several other metal constituents. Data also are available from Extraction Procedure (EP) tests (a test
previously used by EPA to evaluate toxicity) for most of these same constituents (plus several others).
The EP results are generally similar to or lower than the TCLP results shown in Table 6-6, with the
exception of arsenic in bottom ash and arsenic and mercury in SSB solids, which appear in EP results at
somewhat higher levels. The discussion below addresses the leachate data first for RCRA-regulated
constituents, then for non-RCRA-regulated constituents.
Based on the TCLP and EP data for the eight RCRA metals, OCWs exhibit the RCRA
characteristic of toxicity only infrequently. Table 6-7 summarizes data on the frequency of exceedences
of the toxicity characteristic. Out of 176 samples analyzed by TCLP or EP, only 11 (6 percent) exceeded
the regulatory threshold for one or more of the characteristic metals; however, these exceedences were
spread across a relatively large number of sites. Seven sites out of the 40 for which data are available (18
percent) had at least one sample that exceeded a regulatory threshold. Details of these exceedences are
as follows:
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Chromium was the metal with the most exceedences (five); most of these were in samples of
solids from equipment washwater. Chromium exceeded the threshold in four samples of
wash solids collected at three sites and in one of three samples of bottom ash at a fourth site.
The site that had an exceedence for chromium in bottom ash also exceeded the threshold for
lead in two of three bottom ash samples.
Arsenic exceeded the threshold in one of two samples of bottom ash at one site and one of
four samples of composite ash at another site.
The site that had an exceedence for arsenic in composite ash also exceeded the threshold for
cadmium in two of four samples of composite ash (one of these samples was the same one
displaying the characteristic for arsenic).
One of nine samples of fly ash from one site exceeded the threshold for selenium. The eight
other samples of fly ash from the same site did not exceed the threshold; seven of these were
below detection limits.
Table 6-5. Facility Average Concentration of Selected Constituents in OCWs
(parts per million)
Constituent
Arsenic
Barium
Boron
Cadmium
Chromium
Cobalt
Copper
Lead
Manganese
Mercury
Nickel
Selenium
Silver
Vanadium
Zinc
Fly Ash
Mean
82.0
907
35.9
6.98
1,016
233
587
515
331
5.96
9,997
11.1
3.16
48,816
1,735
Range
34.0-198
330-2,500
21.3-50.4
2.92-9.93
138-4,000
233-233
270-920
288-1,334
120-698
0.06-23.5
4,300-24,562
0.4-17.7
1.06-5.98
22,528-110,647
880-2,009
Bottom Ash
Mean
23.5
594
33.5
3.12
205
n/a
789
108
327
0.993
13,654
6.07
n/a
55,541
458
Range
3.6-52
248-820
12-55
0.50-4.77
33-675
n/a
154-2,860
57-176
200-520
0.081-2.80
1,950-44,136
2.16-10
n/a
8,749-200,000
183-744
SSB Solids
Mean
210
317
160
5.5
456
51
2,250
622
868
0.22
9,410
13.4
3.9
31,580
830
Range
6.28-1,650
7.18-980
160-160
0.2-21.7
13-1,250
51-51
69-16,460
46-1,773
72-2,600
0.108-0.38
2,410-32,350
0.79-35.0
0.05-9.7
880-69,670
74-4,010
Note: All measurements identified as below detection limit were assigned a value equal to one-half the detection limit for use in the
calculations. All concentrations are facility-averaged; i.e., multiple measurements from a single site are averaged, and the resulting
population of facility averages used to generate the statistics in this table. Statistics presented here are based on a varying number of
samples, depending on the constituent. For details, refer to the Technical Background Document for the Report to Congress on Remaining
Wastes from Fossil Fuel Combustion: Waste Characterization.
n/a = data not available
Source: EPRI, 1997a
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Table 6-6. Facility Average TCLP Results for OCWs (mg/l)
Analyte
RCRA
Standard
Fly Ash
Mean
Range
Bottom Ash
Mean
Range
SSB Solids
Mean
Range
RCRA Toxicity Constituents
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
5.0
100.0
1.0
5.0
5.0
0.2
1.0
5.0
0.319
0.370
0.160
0.447
0.164
0.00108
0.0622
0.0248
0.01-1.5
0.105-1
0.005-0.520
0.005-1.17
0.03-0.325
0.0001-0.0025
0.0025-0.183
0.00052-0.05
0.391
1.88
0.130
0.387
1.23
0.00133
0.0887
0.0542
0.025-3
0.025-12.9
0.00075-0.62
0.02-3.44
0.012-13.4
0.0001-0.00563
0.0025-0.250
0.0002-0.175
0.0666
0.647
0.0187
0.0621
0.0824
0.00269
0.0605
0.0353
0.0015-0.321
0.09-1.7
0.005-0.04
0.005-0.279
0.01-0.0625
0.0001-0.0005
0.0025-0.302
0.005-0.145
Non-RCRA-Regulated Constituents
Cyanide
Nickel
Vanadium
n/a
n/a
n/a
n/a
n/a
397
n/a
n/a
36.4-882
0.264
30.7
211
0.264-0.264
3.3-58
33.2-513
n/a
28.8
114
n/a
13-44.5
0.01-448
Note: All measurements identified as below detection limit were assigned a value equal to one-half the detection limit for use in the
calculations. All concentrations are facility-averaged; i.e., multiple measurements from a single site are averaged, and the resulting
population of facility averages used to generate the statistics in this table. Statistics presented here are based on a varying number of
samples, depending on the constituent. For details, refer to the Technical Background Document for the Report to Congress on Remaining
Wastes from Fossil Fuel Combustion: Waste Characterization.
n/a = data not available
Source: EPRI, 1997a
Thus, while OCWs overall rarely display the toxicity characteristic, a fraction of sites have a single OCW
stream that exceeds the threshold for one or more metals in a large percentage of samples.
TCLP and EP leachate data also are available from 25 sites for toxic organics in OCWs. Of 57
samples, only 6 resulted in analyses above detection limits for one or more organics (one sample for
benzene, one for chloroform, one for methyl ethyl ketone, two for chloroform and methyl ethyl ketone,
and one for chloroform and 1,2-dichloroethane). None exceeded the regulatory thresholds for toxicity.
Because of the low frequency of detection and EPA's experience with these specific organics as often
being the result of laboratory contamination at reported levels, the Agency concludes that organics are
not of further concern for OCWs.
Table 6-6 also shows TCLP data for three non-RCRA-regulated constituents: cyanide, nickel,
and vanadium. Nickel and vanadium show high leachate concentrations, consistent with their high total
concentrations in OCWs. Both these metals are considered further in Section 6.4, along with the RCRA
toxicity constituents, in terms of their risk to human health and the environment. Cyanide was detected
in only one of three samples at one siteinsufficient data with which to evaluate its risk to human health
and the environment. In addition, EP data are available for a number of other non-RCRA constituents,
including calcium, chloride, copper, fluoride, iron, magnesium, manganese, nitrate, nitrite, sodium,
sulfate, and zinc. Of these, copper, manganese, and zinc are considered further in Section 6.4.
March 1999
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Table 6-7. Frequency of Toxicity Characteristic Exceedences for OCWs£
TC Metal
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury15
Selenium
Silver
All TC Metals
Total Numbers
Sites
40
40
40
40
40
40
40
40
40
Samples
169
169
168
176
176
169
175
168
176
Toxicity Characteristic Exceedences
Number of Samples
2
0
2
5
2
0
1
0
11
Percent of Samples
1%
0%
1%
3%
1%
0%
1%
0%
6%
Number of Sites
2
0
1
4
1
0
1
0
7
Percent of Sites
5%
0%
3%
10%
3%
0%
3%
0%
18%
a Table compares individual sample concentration data for fly ash, bed ash, composite ash, SSB solids, wash solids, and "other as h" analyzed
by TCLP or EP, to the RCRA regulatory levels.
b One sample for mercury was reported as a non-detect with a detection limit more than twice the regulatory level. If assigned a value of one-
half the detection limit according to the standard approach used in this report, the sample would be counted as an exceedence. However,
given that no other samples approached the regulatory threshold for mercury, this apparent exceedence was assumed to be an artifact of
the high detection limit and not counted here.
Source: EPRI, 1997a
6.3 CURRENT MANAGEMENT PRACTICES
The primary source used to evaluate the current waste management practices for oil combustion
wastes was a recent study by EPRI of oil combustion byproducts (EPRI, 1998a) that contains detailed
summaries of waste management practices at 17 large utility facilities that operate oil-fired units.
Combined, these facilities reportedly account for 32 percent of oil-fired utility generating capacity and 46
percent of utility No. 6 fuel oil consumption. Of the 17 facilities, EPA used 15 for its characterization of
the current management of oil combustion waste. One facility was not included because it was a
combustion turbine unit; the second facility was disregarded because, although an oil facility, it was in
backup status and was reportedly seldom used. This facility, furthermore, had no particulate controls and
did not wash equipment. It reportedly was used so infrequently that routine cleaning was not necessary.
The management of OCWs varies depending on the type of waste (bottom ash, fly ash, low-
volume wastes) and the type of facility (oil-fired facilities versus plants with both coal-fired and oil-fired
units); therefore, the 15 facilities studied were divided into two groups: those that generated both CCWs
and OCWs onsite (2 facilities) and those that generated only OCWs (13 facilities). Of this later group,
eight also burned gas, while the remaining five were strictly oil operations. The common management
practices observed at oil-fired utilities include onsite settling basins and offsite landfills, with a few
onsite landfills (monofills handling only OCWs) represented.
Information regarding presence or characterization of management units at non-utility facilities
combusting oil is not available. As discussed in Section 6.1, volumes of OCW are expected to be signif-
icantly smaller at non-utilities. Accordingly, onsite management units dedicated solely to OCWs (as
observed at oil-fired utilities) are unlikely except at the largest non-utilities. Those few non-utilities that
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Report to Congress on Wastes from the Combustion of Fossil Fuels
generate significant amounts of OCW likely manage the waste similarly to utilities. The smaller non-
utilities likely manage OCW dry in offsite units or onsite in combination with non-combustion waste.
6.3.1 Facilities Generating OCWs Only
Ash Management
At facilities that generate only oil combustion wastes, oil fly ash and bottom ash are typically
managed separately (see Table 6-8). Most commonly, fly ash is sluiced wet to a settling basin after
collection by particulate control technology. This occurred at 10 of the 12 facilities that captured fly
ash.5 The remaining two facilities operate oil-fired baseload generation units and manage their oil fly ash
in the following ways. One of these two facilities chemically thickens the ash slurry (and, on an "as-
needed" basis, solids dredged from an onsite surface impoundment). The thickened material is drum
filtered to dewater the material to about 50 percent solids. The filter cake drops into a rolloff box for
immediate transportation to an offsite destination (landfill or vanadium recovery depending on the
market). The supernatant from the filter operation is managed in surface impoundments with
washwaters. This facility also collects bottom ash dry for offsite transport. The second of these facilities
pneumatically transports its fly ash directly to an unlined onsite ash basin (landfill) where it is disposed
with bottom ash. The facility operates a separate surface impoundment for washwaters.
Table 6-8. Combinations of OCW Managed
Description of Management
Bottom ash and fly ash managed separately
Bottom ash mixed with dredged solids from fly ash impoundments
Bottom ash and fly ash comanaged dry in onsite landfill (ash basin)
No particulate controls to collect fly ash; bottom ash collected
Total
Number of Sites
9
2
1
1
13
Percent
69%
15%
8%
8%
100%
Source: EPRI, 1998a
The most common practice for the oil bottom ash is to collect it dry and transport it to an offsite
destination (11 of the 13 facilities). Reportedly, the offsite destination is usually a landfill, unless the
market is favorable for utilizing vanadium content in the ash. The remaining two facilities manage their
oil bottom ash as follows. One of these facilities sluices its oil bottom ash to a surface impoundment
(this is the facility that collects and manages no oil fly ash). The second facility transports its oil bottom
ash dry directly to an onsite ash basin (landfill), where it is disposed with oil fly ash.
Low-Volume Waste Management
The practice of comanaging low-volume wastes is as prevalent for OCWs as it is for CCWs.
Table 6-9 shows the frequency of comanaging OCWs and low-volume wastes for the 13 facilities
studied. Because these "low-volume" wastes are liquid, they are typically managed in large quantities.
For a typical site, the EPRI oil combustion report estimates a volume of 2.1-million gallons per year of
the low-volume wastes, compared with 5-million gallons per year of fly ash sluice water.
5 One of the 13 facilities had no particulate controls and did not collect fly ash.
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Table 6-9. Comanagement of OCWs and Low-Volume Wastes
Description of Management
Comanagement of OCW and Low-Volume Wastes
Low-volume waste comanaged with fly ash
Low-volume waste comanaged with bottom ash
No Comanagement
Total
Number of Facilities
11
(10)
0)
2
13
Percent
85%
(77%)
(8%)
15%
100%
Source: EPRI, 1998a
The most common practice (11 of the 13 facilities) is for low-volume wastes to be comanaged in
the same impoundments with fly ash. The two remaining facilities include one that disposes all ash dry
in a landfill and a second that sends all ash off site; these two facilities both operate impoundments for
low-volume waste management. The types of low-volume waste most commonly comanaged are fireside
washwaters, boiler chemical cleaning wastes, and equipment washwater and floor drains.
Settling Basin Solids Management
Solids from the surface impoundments (commonly called SSB solids) typically are dredged on an
"as-needed" basis. The solids may be composed of several materials. At three of the EPRI oil
combustion report sites, wastewater in the fly ash impoundments is specifically noted as being treated
with coagulants (ferrous chloride and/or polymers) to precipitate metals and promote settling. This
practice effectively results in commingling of fly ash with wastewater treatment sludge; other facilities
also are likely to be using some chemicals in treatment. Ten of the 13 facilities sluice fly ash to these
settling basins and their solids, therefore, contain fly ash as well as any treatment sludges. At one facility
the solids include all the bottom ash generated. Solids from all facilities will include fly ash components
that were captured in fireside equipment (air preheaters, economizers, stacks, fireside boiler surfaces)
and subsequently washed down. Facilities that commingle boiler chemical cleaning waste for treatment
also will have solids precipitated from this waste stream.
The most common practice for the SSB solids is to dredge them, dewater them, and transport
them to an offsite destination.6 Reportedly, the typical destination is an offsite landfill, unless the market
is favorable for either utilizing vanadium content in the solids or using the solids in concrete applications.
Management Unit Description - Surface Impoundments
The surface impoundments used to manage sluiced ash and comanaged low-volume wastes at the
13 facilities in the study ranged from a tenth of an acre to nearly 13 acres (see Table 6-10). OCW waste
management unit sizes range from small deep sump-like basins (the smallest acreage SSB unit is also the
relatively deepest unit) to very large, relatively shallow surface impoundments. The system with the
smallest capacity (just under 3,000 cubic yards) is only a half acre in surface area and between 3- and
6 Only one of the 13 facilities reported leaving the solids in its basin. No fly ash is collected at this facility,
it operates no baseload units, and the two basins were designed for other purposes, are cement-lined, and have very
large capacities.
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Table 6-10. OCW Management Surface Impoundment System Sizes'
Size Description
Area
Capacity
Relative Depth c
Adjusted Average b
1 .0 acres
9,038 cubic yards
6.5 feet
Range (min-max)
0.1 -12.8 acres
2,968-1 23,655 cubic yards
1.8-21. 5 feet
a Size data are for combined settling basin system; SSB systems range in number of actual units from 1 to 4 with 2 being the most common.
" Two facilities were removed from this average as the units were originally designed for other uses and the sizes were significantly
disproportionate to amount of wastewater managed (if included area would be 2.8 acres and capacity 26671 yd3).
0 Calculated using capacity and surface area, does not account for side slopes configuration.
Note: Depth data are derived from the reported capacity and area for each site.
Source: EPRI, 1998a
4-feet deep. The adjusted average7 size unit was a 1-acre system; the median after adjustment was 1.1
acres. The typical settling basin system has two ponds. Concrete sump-type basins tend to be smaller
and deeper; ponds used for percolation/evaporation range larger but shallower (average depth for pond
units was 4.4 feet).
Figure 6-3 describes the types of liners employed in the OCW surface impoundments for the 13
facilities studied. Based on EPRI data, about two-thirds of the OCW surface impoundments are lined.
The unlined impoundments are all located in the southeast Atlantic or southeast Gulf coasts and are
percolation basins designed to discharge to ground water. This practice of discharging to ground water is
allowed under Florida's state wastewater permits. State ground-water standards are applied to these units
outside a specified zone of discharge. According to the EPRI oil combustion report, two of these unlined
percolation basins at one site were cleaned and rebuilt in 1995 to alleviate trace metal movement. The
rebuilding included the addition of a sand filter layer to retain fine particles and a crushed limestone
base. Two unlined percolation basins at another site also have crushed limestone bases. Although these
designs do not prevent leachate as a liner would, they may serve as a form of environmental control
because the limestone can provide pH control and the filter layer may slow the migration of certain other
constituents in leachate. Ground-water monitoring is practiced at 50 percent or more of the onsite SSBs.
Limited data for these units suggest a trend toward the increasing use of liners. Three of the
OCW surface impoundments were lined only recentlytwo in 1993 and one in 1996. In addition, one
site that currently operates two lined impoundments historically used a single unlined basin.
Furthermore, the major producer of power in Florida has verbally declared its intent to eventually line all
units.
Management Unit Description - Landfills and Wastepiles
As noted above, the final disposition for most of the ash and SSB solids is in land-based disposal
units, except when markets for vanadium recovery or other alternative use are favorable. With two
exceptions, the waste is shipped offsite. No data are available on liners or other environmental controls
employed at the offsite landfills.
7 EPA calculated the adjusted average using 11 of the 13 facilities because two of the facilities operated
units that were designed for other uses. The sizes of these units were significantly disproportionate to the amount of
OCW wastewater managed.
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Figure 6-3. Liners Used in OCW Surface Impoundments
None 38%
Plastic 31%-
\ mv////^
Plastic & Concrete 15%
Concrete 15%
Note: Percentages shown are of the 13 facilities studied.
Source: EPRI, 1998a
In the two instances of onsite management, some limited information was available in the EPRI
report. Ground-water monitoring is performed at both sites. One facility utilizes an ash basin to which
oil combustion fly ash and bottom ash are conveyed by dry collection and transport. Although it does not
receive equipment washwaters or other plant wastewaters, the basin is described in the EPRI oil
combustion report as part of a larger wastewater treatment complex, and appears from the accompanying
map to be a cell built on the edge of a larger unit. It is unclear if standing water is maintained in the
basin. The basin reportedly is unlined. The owners have indicated to EPRI that they intend to close the
unit and ship ash offsite in the future. The second unit is described as a stabilized ash pad. The pad
receives solids that are dredged from oil combustion fly ash surface impoundments and stabilized with a
cement-based mixture. The pad has an asphalt cover and vegetated sides.
6.3.2 Facilities Generating Both OCWs and Coal Combustion Wastes
At facilities that generated both coal and oil combustion wastes, OCWs typically are comanaged
with certain coal combustion wastes. Two facilities in the EPRI study were coal plants that each
operated three coal-fired units along with a single oil-fired unit; these facilities are discussed below.
Ash Management
At both facilities, particulate controls in the form of electrostatic precipitators are used to capture
oil fly ash. Neither facility reinjects oil fly ash into their oil units. One facility, however, does route
about 70 percent of its oil fly ash to coal-fired units, where the high carbon content is reburned; any
residue from this reburning is captured with the coal ash. The remaining oil fly ash at this facility, as
well as all oil fly ash at the second facility, is sluiced to a surface impoundment system for treatment.
The oil fly ash at both operations was at one point sent offsite for vanadium recovery. Both operations
indicated that recent changes to low nitrogen oxide (NOX) burners resulted in increased carbon content in
the ash, making the relative proportion of the vanadium less and the recovery economics unfavorable.
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Oil bottom ash from both operations is managed separate from oil fly ash; in one case it is comanaged
with coal bottom ash. One facility collects it dry and trucks it to an offsite landfill. The second facility
sluices the bottom ash to an impoundment that also manages bottom ash from the coal units. The
combined coal and oil bottom ash is used for structural fill or construction applications; the majority of
this waste would be expected to be coal ash.
Low-Volume Waste Management
All the low-volume wastes typical of oil-fired units are managed together with oil fly ash at these
two facilities. These are routed at both facilities to pond-based wastewater treatment systems. All
wastewaters at these two coal plants (e.g., bottom ash pondwater, coal pile runoff, floor drains) are
routed to the same system; therefore, all oil fly ash and low-volume wastes from oil combustion are
comanaged with low-volume wastes from the coal operations. Solids from these wastewater treatment
impoundments are dredged at both facilities and sent to landfills, one onsite and the other offsite. Lime
is added to both systems for pH control. Thus, wastewater treatment sludge is a component of the solids
that settle from the wastewater.
Management Unit Description
The two facilities manage their OCWs in units similar to the SSBs used for oil-fired utilities.
The facility that reburns most of its fly ash and ships its bottom ash to an offsite landfill (i.e., manages
little ash in the SSB) uses a 1-acre SSB system. The three-basin system is unlined. Solids dredged from
this basin are shipped offsite to a landfill; no data about this unit's environmental controls are available.
The facility that slurries all its fly ash, coal pile runoff, and bottom ash pond water operates a larger 2.8-
acre SSB system. This two-basin system is high density polyethelene (HDPE)-lined. Dredged solids
from this system are landfilled in a very large (i.e., over 60 acres as shown on map) landfill. The landfill,
operated under a Massachusetts state permit, has 11 cells, 2 of which are currently active. The two active
cells have double HDPE liners, leak detection, and leachate collection systems. At least 1 foot of
standing water is maintained in the active cells to control fugitive dust. The nine inactive cells have
single synthetic liners and are capped with a polyvinyl chloride cover, a drainage layer, and a soil top
cover that has been seeded with grass.
6.3.3 Beneficial Uses
While comprehensive statistics do not exist on the quantities of OCW serving beneficial uses,
there exist a few applications with the potential to serve as alternatives to traditional waste management
for these wastes. In particular, the high metal content present in OCWs can make them a valuable
resource for metals recovery. Vanadium, either in the form of oxides or carbides, may be recovered from
oil fly ash and bottom ash through high-temperature or leaching processes. In turn, oil ash vanadium
compounds are incorporated primarily as alloying agents or hardeners in steel manufacturing. While the
vanadium in fly ash needs to be extracted prior to its addition into the smelting furnace, oil bottom ash
can be added to the furnace directly due to its low carbon content. In addition to the steel industry,
recovered vanadium compounds also serve as oxidation catalysts or as plasma-sprayed coatings in other
industrial applications. The amounts of vanadium currently recovered from oil ash or utilized in any of
the applications mentioned above are unknown. Reportedly, vanadium recovery from oil ash has been
conducted, when economically viable, with OCW from 10 of the 17 oil-fired facilities studied by EPRI.
Two of these facilities discontinued this practice in the early 1990s, following the installation of low
nitrogen oxide (NOX) burners, which increased the carbon content in the oil ash and affected the cost-
effectiveness of the vanadium recovery process. One of the facilities reported sending all of its oil ash
for vanadium recovery (EPRI, 1998a).
March 1999 6-19
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Some use of OCWs in construction applications also has been reported. Approximately half of
the oil-fired facilities studied by EPRI reported sending some portion of their OCWs offsite for use in
concrete products, as structural fills and roadbed fills, when the opportunity was available (EPRI, 1998a).
OCWs have not been used extensively for other beneficial use applications like those described
in Chapters 3 and 5 for CCWs and FBC wastes. Since the quantities of OCW are much lower than those
of CCWs and FBC wastes, the use of oil wastes may not be economically feasible in applications
requiring large volumes of material. In addition, the high content of vanadium, nickel, aluminum, and
molybdenum presents a barrier to OCW utilization, particularly as soil amendment.
6.4 POTENTIAL AND DOCUMENTED DANGERS TO HUMAN HEALTH AND THE
ENVIRONMENT
Section 3.4 provides a discussion of the methodology employed by EPA in assessing risks from
coal-fired utility comanaged wastes. EPA followed a similar approach for wastes from oil-fired boilers,
with several important differences. First, as with FBC wastes, EPA received waste characterization data
for sites representing roughly 30 percent of the generator population and an even greater percentage of
wastes generated industry-wide. TCLP and EP Toxicity data were grouped to provide as large a sample
population as possible. Second, EPA found that oil-fired utility waste generation and management
practices differ significantly from those of their coal-fired counterparts (see Section 6.3). Oil-fired
utilities commonly manage oil ash in very small onsite solids settling basins, from which ash is
periodically removed for final disposal in an onsite or offsite landfill or for offsite processing for
vanadium recovery. Offsite commercial landfills receiving oil ash typically are expected to be lined
facilities (as discussed in Section 6.3 and 6.5). Accordingly, EPA developed scenarios for small unlined
landfills and impoundments only. Finally, EPA found that oil-fired utilities reflect a geographic
distribution distinct from coal-fired utilities, and so modified its modeling scenarios accordingly.
6.4.1 Potential Ground-Water Risks to Human Health
Table 6-11 summarizes selected results from the deterministic and probabilistic analyses of risk
from OCWs for the adult receptor. EPA found that the risks associated with all modeled constituents of
concern, except for arsenic, nickel, and vanadium, fell below a hazard quotient (HQ) of 1 or a lifetime
cancer risk of 1 x 10~6. Potential high-end risks associated with arsenic in the landfill and surface
impoundment (solid settling basin) high-end deterministic scenarios exceeded 1 x 10~5. Further, the
predicted high-end HQs for nickel and vanadium exceeded 1 in both management unit scenarios; this was
especially so for vanadium.
Comparison of the deterministic and Monte Carlo results reveals that the deterministic results
generally exceeded the 95th percentile Monte Carlo results. For example, none of the 2,000 Monte Carlo
simulation combinations of parameter values performed for nickel yielded a risk estimate as high as the
corresponding high-end deterministic results. The deterministic result exceeded the 95th percentile
Monte Carlo result for all constituents for the surface impoundment. This was not the case, however, for
the landfill scenario. The 95th percentile Monte Carlo results for the landfill exceeded the deterministic
results for arsenic and vanadium. These differences reflect the small number of data points in the sample
population for several key variables, including waste concentration and management unit size, and are
considered of little significance.
EPA also considered the time at which risks were predicted to result from the release of
constituents of concern. As shown in Table 6-12, EPA found that the concentration of arsenic in ground
water at the receptor well downgradient of the surface impoundment and the landfill would not reach the
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Report to Congress on Wastes from the Combustion of Fossil Fuels
Table 6-11. Comparison of Deterministic and Monte Carlo Risk Model Results
for Oil Combustion Waste
Ground-Water Pathway Scenarios
Scenario
osb
OMb
Constituent"
Arsenic
Nickel
Vanadium
Arsenic
Nickel
Vanadium
Deterministic
Risk, Central
Tendency
1x1012
HQ<1
HQ<1
1x1015
HQ<1
HQ<1
Deterministic
Risk, High-End
7x1 05
HQ = 28
HQ = 680
2x1 05
HQ = 1.8
HQ = 6.7
Corresponding
Monte Carlo
Percentile
97.75
>100
>99.9
93.45
>100
85.9
Monte Carlo
95th Percentile
2.6x1 05
HQ = 0.005
150
3x1 05
HQ = 0.05
HQ = 21
aAII other metals modeled resulted in HQ <1
bOS = oil ash impoundment; OM = oil ash landfill
Note: Results shown are those from the October 10, 1998, Sensitivity Analysis.
Table 6-12. Predicted Time to Reach Risk for Oil Combustion Waste -
Deterministic Scenarios
Scenario
osb
OMb
Constituent"
Arsenic
Nickel
Vanadium
Arsenic
Nickel
Vanadium
Time to Risk (years)
400
50
10
2,800
900
80
aAII other modeled metals yielded HQ <1
"OS = oil ash impoundment; OM = oil ash landfill
Note: Results are from the April 1998 Draft Final Report.
health-based level (HBL) for arsenic (i.e., achieve a risk level of 1 * 10~6) for roughly 400 and 2,800 years,
respectively. The times to reach the nickel and vanadium HBLs in ground water below the surface
impoundment were considerably smaller at 50 and 10 years, respectively. The predicted near-term
observations of nickel and vanadium in ground water also were corroborated by observations of these
metals in ground water below actual waste management units (see Section 6.4.3).
Table 6-13 summarizes the estimated risks to adult and child receptors for the high-end
deterministic scenario for OCWs. Overall, the results show that for non-carcinogens the risks for young
children increased roughly twofold compared with the adult receptors. For arsenic, risks stayed at the
10"5 level for both adult and child.
March 1999
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Table 6-13. Comparison of Adult and Child Risk Model Results for Oil
Combustion Waste - Ground-Water Pathway Scenarios
Scenario
osb
OMb
Constituent"
Arsenic
Nickel
Vanadium
Arsenic
Nickel
Vanadium
High-End Deterministic Risk
Adult
7x1 05
HQ = 28
HQ = 680
2x1 05
HQ = 1.8
HQ = 6.7
Young Child
8.8x1 05
HQ = 48.4
HQ = 1,176.4
2.5x105
HQ = 3.1
HQ = 11.6
Child
6.2x105
HQ = 31.4
HQ = 761.6
1.8x105
HQ = 2.0
HQ = 7.5
aAII other modeled metals yielded HQ<1
bOS = oil ash impoundment; OM = oil ash landfill
Note: Results shown are those from the October 10, 1998 Sensitivity Analysis.
6.4.2 Potential Above-Ground Multi-Pathway Risks to Human Health and the
Environment
Human Health Risk Findings
No significant non-ground water human health risks were identified for landfill or impoundment
scenarios.
Ecological Risk Findings
EPA found no significant ecological risks associated with releases from onsite landfills. EPA did
not evaluate risks associated with standing waters in solids settling basins. However, because these
basins are very small and because they are located within industrial facilities, the Agency believes that
ecological impacts from direct exposure to these basin waters would be very small.
6.4.3 Documented Damages to Human Health and the Environment
EPA identified a total of nine sites managing oil combustion wastes that have ground-water
contamination. Seven of the nine sites were documented in EPRI's oil combustion report (EPRI, 1998a).
The two other sites were identified in supporting documentation for the 1993 Regulatory Determination
and from RCRA Corrective Action records. EPA determined that ground water has been affected at all
of these sites, though not always above maximum contaminant levels (MCLs) or other state standards.
EPA, however, found that only one of these sites, the Possum Point, Virginia, facility previously
described in the 1993 Supplemental Analysis and Section 3.4.3 of this Report, met the "test of proof for
a damage case.
Many of the sites evaluated are located next to the ocean or other large bodies of water where
releases to ground water are discharged to surface water and no drinking water wells would be located
between the management unit and the surface water. EPA did not find any cases of drinking water
contamination or other environmental damages resulting from these releases. Additionally, most or all
unlined units are operated under state permit allowing exceedences of ground-water standards close to
the management unit but which must be met outside the zone of discharge. EPA found insufficient
evidence of state action at these sites to meet the test of proof.
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At two sites studied by EPA (Ft. Meyers, Florida; Possum Point, Virginia), the state required
removal of oil ash waste from the management units. At the Possum Point facility, exceedences of
constituents above primary MCLs were observed, while at the Fort Meyers facility no exceedences of
MCLs were determined. Therefore, only the Possum Point facility (previously described in Section
3.4.3, damage cases related to comanaged coal combustion wastes) meets EPA's test of proof for
identifying cases of damage.
Based on information available and consideration of EPA's "tests of proof," EPA identified the
cases in Table 6-14 as potential damage cases.
Table 6-14. Potential Damage Cases
Damage Case
Wastes Present
Event
Test of Proof
Comment
Oil Combustion Wastes
VEPCO - Possum
Point (VA)
Coal ash, pyrites, oil
ash, water treatment
wastes, and boiler
cleaning wastes
Ground water
contaminated with Cd
and Ni, attributed to
pyrites and oil ash
Administrative
Response included
sequestration of oil
ash, pyrites, and metal
cleaning wastes to
separate lined units
6.5 EXISTING REGULATORY CONTROLS
EPA's objective in this analysis was to identify and evaluate the existing regulatory controls that
pertain to the management of oil combustion wastes. The regulatory analysis is directed toward
addressing the question of whether existing regulations are adequately protecting human health and the
environment. The analysis also is helpful in understanding waste generation and current management
practices.
The sections below discuss regulations addressing air pollution, water pollution, and solid and
hazardous waste, respectively. Air regulations are relevant primarily because of their effect on waste
generation. Water regulations have an influence both on waste generation and management and, in
particular, address the impact of OCWs on surface waters. Solid and hazardous waste regulations are of
the greatest interest because they directly govern waste management practices.
The sections below describe federal regulations in each of these areas. In many cases, the
implementation of these federal programs is carried out by the states; therefore, where appropriate,
aspects of state implementation also are discussed. Because the nuances of state implementation are of
particular importance with respect to solid waste regulation, that section discusses state programs in
detail.
6.5.1 Regulations Addressing Air Pollution
The CAA is intended to protect and enhance the quality of the nation's air resources. CAA
requirements have been a significant factor affecting the generation and collection of certain OCWs
(specifically, fly ash). The CAA requirements most relevant to OCWs include the following:
National Ambient Air Quality Standards (NAAQS) for particulate matter (PM)
NAAQS for sulfur dioxide
NAAQS for ozone
National Emissions Standards for Hazardous Air Pollutants (NESFfAP).
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Title IV acid rain provisions, the fifth set of requirements that affect fossil fuel combustors as a
group, currently apply only to the largest coal-fired utility generating units and, therefore, are not
relevant for oil-fired units. Historically, CAA requirements have been a significant factor affecting the
generation and collection of certain OCWs. Recent and forthcoming changes in these requirements also
may impact waste generation or characteristics, as discussed below.
NAAQS for Particulate Matter
The NAAQS for PM establish maximum concentrations of PM with diameter less than or equal
to 10 micrometers (PM10) in the ambient air. These standards are among the factors motivating the use
of particulate control technologies at FFC facilities. EPA recently proposed to lower the size criterion to
2.5 micrometers, which may affect the volume of fly ash collected and selection of control technology.
Final standards, however, will not be issued for at least 5 years, so the impact of the new size criterion is
difficult to predict at this time.
The NAAQS for PM are implemented through New Source Performance Standards and State
Implementation Plans.
New Source Performance Standards (NSPS). The NSPS subjects newly constructed or,
importantly in the case of oil-fired utilities, modified units to specific PM emissions limits. These limits
may be met by changing fuel types, modifying combustion conditions, or installing control devices. The
applicability of the NSPS and the specific limits imposed vary with the age and size of the combustion
unit, with older and/or smaller units less likely to be subject to the NSPS. Specifically, the regulation of
facilities can be considered in four categories.
40 CFR 60 Subpart D governs the standards of performance for new fossil fuel-fired steam
generators that were constructed or underwent major modification after August 17, 1971.
Subpart D affects only units that are capable of burning fossil fuels at greater than 73
megawatts (MW) of heat input rate.
Subpart Da affects utility units with the capacity to fire fuel at greater than 73 MW heat
input rate that commenced production or major modification after September 18, 1978.
Subpart Db affects units with the capacity to fire fuel at greater than 29 MW of heat input
rate that commenced construction or modification after June 19, 1984.
Subpart DC governs units constructed or modified after June 9, 1989, with capacity to fire
fuel at less than 29 MW but greater than 8.7 MW of heat input rate.
With the exception of Subpart Da, which applies specifically to utilities, the NSPS requirements apply to
all oil-fired steam generating units, utility or non-utility. Non-utilities, however, tend to have smaller
capacities than utilities and, therefore, are more likely captured by those NSPS requirements that apply to
smaller capacity units (i.e., Subparts Db and DC). Note that under the NSPS regulations, facilities that
were in operation before the dates stated in each of the four subparts are considered "grandfathered" and
would not be subject to the new performance standards unless they underwent a major modification.
State Implementation Plans (SIPs). The performance standards above can be enforced by a
federal, state, or local regulatory agency. There are additional CAA regulations that could require an oil-
fired unit to install a particulate removal device notwithstanding the grandfather clause in Subparts D,
Da, Db, and DC. SIPs may impose, on a state-by-state basis, PM controls of varying stringency on
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specific sources or categories of sources, including oil combustion facilities. Such controls are required
under Title I of the CAA if a particular area is in nonattainment for the NAAQS for a criteria pollutant
such as PM. For this reason, SIP controls will generally be more stringent in such nonattainment areas.
In attainment areas, the prevention of significant deterioration (PSD) program requires new sources to
apply Best Available Control Technology (BACT), which must be at least as stringent as NSPS.
NAAQS for Sulfur Dioxide
Similar to the NAAQS for PM, the NAAQS for sulfur dioxide establish a maximum
concentration of sulfur dioxide in the ambient air. The NAAQS for sulfur dioxide are implemented
through NSPS and SIPs. The functioning and applicability of the sulfur dioxide NSPS requirements are
similar to those for PM.
Each of the first three categories of oil-fired facilities regulated under Subparts D, Da, and Db is
subject to the same requirement: sulfur dioxide emissions must be less than 340 nanograms per joule
(ng/J) of heat input. Under Subpart DC, facilities constructed or modified after June 9, 1989, with heat
input capacity between 2.9 MW and 29 MW must limit emissions to less than 215 ng/J heat input.
Facilities with greater than 22 MW heat input capacity generally also must achieve a 10-percent
reduction in their sulfur dioxide emissions, based on the potential concentration in fuel. Facilities
constructed or modified after June 9, 1989, and between 2.9 and 8.7 MW heat input capacity may meet
the standard based on certification from the fuel supplier that the sulfur content of the fuel is low enough
to meet the standard.
In addition to NSPS, states may impose controls through their SIPs to meet the sulfur dioxide
NAAQS. These controls may vary in stringency depending on attainment status and may be placed on
specific sources or categories of sources, including oil-fired units.
Because of the low sulfur content of fuel oil and the ability to switch fuel easily, the NAAQS for
sulfur dioxide have not led to extensive use of FGD technology at oil-fired facilities.
NAAQS for Ozone
The NAAQS for ozone establish a maximum concentration of ozone in the ambient air. EPA
recently lowered this concentration from 0.12 to 0.08 parts per million (ppm). The new standard allows
four exceedences of the maximum in a region over a 3-year period. EPA expects states will meet the new
standard by amending their SIPs to limit nitrogen oxide emissions at utilities. In proposing the new rule,
EPA published a Regulatory Impact Analysis (RIA) forecasting changes in the operating practices of
utilities that could result from these SIP modifications.8 The RIA estimates that total utility capacity will
increase by the year 2010. As a result of the new regulations, however, utilities are expected to invest in
new combined cycle gas-fired units and oil- or gas-fired CTs to provide this new capacity. Oil-fired
steam generating capacity is not expected to increase (EPA, 1997b; EIA, 1998a); therefore, utility
generation of ash is not expected to increase dramatically, even with future expansion of the utility
industry.
8 The RIA was based on a slightly more stringent ozone standard that allowed only three exceedences over
a 3-year period and also incorporated the impacts of proposed changes to the PM standard that have not yet been
finalized. Still, the general trends forecast by the RIA are expected to be valid for purposes of this analysis.
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NESHAP
Under the NESHAP, EPA is required to establish technology-based standards for 189 hazardous
air pollutants (HAPs). These standards are to be set on an industrial category basis and will apply to
facilities that emit greater than 10 tons/year of any one HAP or greater than 25 tons/year of any
combination of HAPs.
EPA has studied HAP emissions from utility oil-fired steam generating units and found that
nickel from oil-fired utilities is a HAP of potential concern. EPA has deferred any determination as to
whether regulations to control HAP emissions from utilities are appropriate and necessary (EPA, 1998c).
If such regulations were promulgated, they could affect the characteristics or volumes of FFC solid
wastes.
For non-utility oil combustors, EPA has not specifically studied HAP emissions. Because
NESHAP will be set on an industrial category basis, when promulgated, the impact of these regulations
on OCW generation and characteristics may vary depending on the industrial sector of the non-utility oil
combustor.
6.5.2 Regulations Addressing Water Pollution
Under the federal Clean Water Act, the National Pollutant Discharge Elimination System
(NPDES) controls discharges to waters of the United States. As discussed below, the controls required
under NPDES affect the collection and management of CCWs. In states authorized by EPA, these
controls are implemented through state programs (often termed State Pollutant Discharge Elimination
Systems, or SPDES). Because state programs must be at least as stringent as the federal program, the
discussion here focuses on federal requirements as a lowest common denominator. NPDES requirements
apply differently to two categories of discharges: process wastewaters and stormwater runoff. Neither
the NPDES process wastewater or NPDES stormwater requirements make a distinction between oil-fired
and coal-fired units. Distinctions may apply, however, between utilities and non-utilities.
NPDES Requirements for Process Wastewaters
The NPDES requirements that apply to process wastewaters from oil-fired utilities are those for
the steam electric point source category under 40 CFR Part 423. These requirements apply to facilities
"primarily engaged in the generation of electricity for distribution and sale" (i.e., utilities). Oil-fired non-
utilities face NPDES requirements for process wastewaters that are specific to their industrial sector. In
most cases, under these requirements each discharge requires an individual NPDES permit with numeric
limitations based on Best Practicable Control Technology Currently Available (BPT), Best Available
Technology Economically Achievable (BAT), or New Source Performance Standards (NSPS). Facilities
that discharge to publicly owned treatment works (POTWs) rather than directly to surface waters face
Pretreatment Standards for Existing Sources (PSES) similar to BAT, or Pretreatment Standards for New
Sources (PSNS) similar to NSPS.
The majority of OCWs (and particularly fly ash) are managed wet. For these wastes, the most
relevant requirements are total suspended solids (TSS) limits.
At non-utilities, the specific NPDES effluent standards applied depend on industrial category.
Effluent standards expected to apply to large numbers of non-utility fossil fuel combustors include those
for the following industry categories:
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Pulp, paper, and paperboard (40 CFR Part 430)
Organic chemicals, plastics, and synthetic fibers (40 CFR Part 414)
Inorganic chemicals manufacturing (40 CFR Part 415)
Textile mills (40 CFR Part 410)
Timber products processing (40 CFR Part 429)
Iron and steel manufacturing (40 CFR Part 420)
Sugar processing (40 CFR Part 409)
Grain mills (40 CFR Part 406).
The standards for all of these categories include TSS limits, and these limits are applicable to nearly all
of the industrial subcategories covered under each category. Some subcategories are subject to zero
discharge requirements. Based on the Standard Industrial Classification (SIC) codes reported by non-
utilities in the 1990 U.S. EPA National Interim Emissions Inventory (EPA, 1990) database, these
industrial category requirements are expected to cover roughly 20 percent of non-utility fossil fuel
combustors. A number of other facilities are scattered through other industrial categories, many of which
are also subject to TSS limits. Some facilities (such as institutional fossil fuel combustors) may not be
subject to the specific standards of any industrial category. In these cases, the specific effluent
limitations would be determined on a case-by-case basis as part of the non-utility's individual NPDES
permit.
At utilities, the steam electric category NPDES requirements place TSS limits directly on fly ash
handling and bottom ash handling waters. In addition, the NSPS for the steam electric category include a
zero discharge requirement for fly ash handling water. These steam electric requirements may also be
incorporated in individual permits at non-utilities to supplement their industrial category requirements.
Application of steam electric requirements to relevant waste streams at non-utility fossil fuel combustors
is left to the best professional judgment of the individual permit writer (EPA, 1996).
Because of these requirements, when OCWs are managed in surface impoundments or settling
basins, facilities may have to settle or otherwise remove a certain amount of waste solids from the
handling water to meet the TSS limits prior to discharge. Zero discharge requirements effectively
eliminate the release of waste solids to surface water. Thus, the requirements control the direct release of
fly ash, bed ash, and any treatment solids to surface waters.
NPDES Requirements for Stormwater
NPDES Stormwater requirements apply to Stormwater runoff from FFC facilities, which may
include runoff from operating areas, ash handling areas, and waste management units. Like the process
wastewater requirements, Stormwater requirements have been established on an industrial sector basis;
therefore, the steam electric requirements apply to non-utilities just as they apply to utilities. A chemical
manufacturer, for example, operating a fossil fuel-fired boiler must meet both chemical manufacturing
and steam electric Stormwater requirements.
Facilities can meet the Stormwater requirements by including Stormwater in their individual
NPDES permit or seeking coverage under a general permit by submitting a Notice of Intent (NOI).
Individual permit control and monitoring requirements will be facility-specific, subject to the judgment
of the permit writer.
When covered by a general Stormwater permit, requirements include implementation of a
Stormwater pollution prevention plan, "reasonable and appropriate" control measures, and 1 or 2 years of
monitoring and reporting. No site visit by regulators is required under the general permit. Under the
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general permit approach, oil-fired facilities have a great deal of flexibility in selecting appropriate control
measures for runoff that may have contacted OCWs. The general permit requirements include
recommended best management practices for stormwater at steam electric facilities, landfills, treatment
works, and construction areas greater than 5 acres. Because these requirements are additive across
industrial sectors, an oil-fired utility with an onsite ash landfill, for example, must meet both steam
electric and landfill requirements.
Because the stormwater program is relatively new and managed by authorized states, the number
of facilities with general versus individual permits is not known. EPA handles NOIs for 10
nonauthorized states. In these states, 700 steam electric facilities (utility and non-utility) have filed for
general permits.
6.5.3 Regulations Addressing Solid and Hazardous Waste
EPA regulates the management of solid and hazardous waste through Subtitles C and D of the
RCRA. Subtitle C of the RCRA establishes a "cradle-to-grave" management system for wastes that are
considered hazardous because they fail tests based on their physical and chemical characteristics (i.e.,
toxicity, corrosivity, ignitability, and reactivity) or because they are listed as hazardous by EPA. Federal
regulations establish stringent environmental and administrative controls that must be applied to
management of these wastes. OCWs, whether generated at a utility or non-utility, are currently exempt
from federal regulation as hazardous waste under Subtitle C pending this Report to Congress and the
subsequent regulatory determination. Therefore, these wastes are currently subject to the requirements of
Subtitle D of the RCRA as nonhazardous solid waste.
Implementation of Subtitle D is the responsibility of individual states, but nothing prevents states
from imposing more stringent requirements (including hazardous waste requirements) on FFC wastes.
Although federal policy currently exempts OCW, like CCW, from Subtitle C regulation, state adoption of
this exemption is not as extensive for OCW as for CCW. Only 26 states extend the federal exemption to
OCW. These 26 states, however, represent more than 80 percent of oil-fired utility capacity. In the other
states, any OCWs that fail the hazardous waste characteristic tests would be subject to state hazardous
waste requirements and managed in units that meet permitting, design, operating, corrective action, and
closure standards.
OCWs fail the hazardous waste characteristic tests only infrequently; therefore, the majority of
OCWs that do not fail the hazardous waste characteristic tests and/or are generated in the states that
duplicate the federal exemption generally would be subject to less stringent state requirements under
Subtitle D. In the CIBO survey, 20 states (accounting for 60 percent of oil-fired utility capacity)
indicated that their waste management requirements for oil combustion wastes differed from those for
coal combustion wastes. To characterize these differing requirements, EPA examined solid waste
regulations pertaining to OCWs in four states: Florida, New York, Massachusetts, and Pennsylvania.
These states account for more than half of the oil-fired utility electric generating capacity. Table 6-15
summarizes the requirements in each of these five states.
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Table 6-15. State Waste Management Requirements Applicable to OCWs
in Selected States
Florida
Landfill
Requirements
Impoundment
Requirements
Utility Siting
Requirements
Grandfather
Clause
Landfills must not cause ground water or surface water quality to exceed minimum standards outside a
specified zone of discharge. Requirements include composite or double liners, leachate collection
systems, run-on/runoff controls, ground-water monitoring, a cap including a geomembrane layer at
closure, and revegetation at closure. State imposes a more stringent requirements as necessary due to
site-specific conditions and types of waste disposed.
Regulations do not dictate any specific design requirements. Impoundments may be permitted to
discharge to ground water as long as they do not cause ground-water quality to exceed minimum
standards outside a specified zone of discharge.
Utilities with generating capacity of 75 MW or greater must receive a certification to construct and operate
under the Power Plant Siting Act. The certification process explicitly includes consideration of ash
generation and the impacts of onsite solid waste management. This includes consideration of natural or
manmade liners and leachate and runoff controls. The granting of certification can be subject to
restrictions and requirements on any aspect of operation, including solid waste management.
Landfills constructed before July 6, 1993, are exempt from the liner, leachate collection, and run-on/runoff
control requirements.
New York
Landfill
Requirements
Impoundment
Requirements
Grandfather
Clause
State has separate programs for landfills that accept mixed solid waste (including municipal solid waste
landfills) and industrial or commercial waste monofills. Either may receive OCWs.
Mixed solid waste landfill requirements include two composite liners, leachate collection systems, ground-
water monitoring, daily cover requirements, cover at closure, and revegetation at closure.
Industrial and commercial waste monofills are subject to similar requirements as those for mixed solid
waste landfills; however, the state may impose additional or less stringent requirements based on the
volume and characteristics of the waste. In practice, single composite liners typically have been required
for these monofills.
Regulations do not impose any specific design requirements on surface impoundments managing OCW.
Landfills permitted prior to October 9, 1993, are not required to retrofit liners or leachate collection
systems, except for expansions of the facility.
Massachusetts
Landfill
Requirements
Impoundment
Requirements
Grandfather
Clause
Specifically because of concerns about vanadium in oil ash, the state has developed an interim policy
placing conditions on the disposal of OCWs from utilities. Coal and oil ash mixtures from utilities and
OCWs from non-utilities are subject to the policy on a case-by-case basis.
Under the interim policy, disposal of oil ash is subject to written approval. The waste may be disposed
only at landfills with lined active disposal areas and leachate collection systems. It must be delivered
damp to control fugitive dust and must be covered daily to prevent fugitive vanadium emissions. When
landfilled according to the policy, OCWs may be handled similarly to residential refuse. They are not
considered "special wastes," which, under Massachusetts regulations, are nonhazardous wastes that
require particular management controls to prevent adverse impact.
Regulations do not impose any specific design requirements on surface impoundments that manage
OCWs. Units may be permitted to discharge to ground water.
No specific grandfather clause; interim policy has been in place since 1983.
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Pennsylvania
Landfill
Requirements
Landfills are classified according to TCLP results for the wastes to be disposed. Specific design
requirements depend on the class of the landfill. Based on available characterization data, OCWs would
sometimes require management in Class I or Class II units, with Class III management allowed for about
60 percent of waste. Liners are required for all classes, with liner type determined by class. Leachate
collection and detection are required for Class I and II units. All classes are subject to the following: siting
restrictions, fugitive dust control, daily cover, soil erosion control, ground-water monitoring, 2-foot clay cap
at closure, and revegetation at closure.
Impoundment
Requirements
Surface impoundments (including those that store waste for less than one year) are classified according
to TCLP results for the wastes to be disposed. Specific design requirements depend on the class of the
impoundment. Based on available characterization data, some OCWs would require management in
Class I units, with Class II management allowed for about 80 percent of waste. Liners are required for all
classes, with liner type determined by class. All classes also are subject to the following: siting
restrictions, leachate detection system, leachate collection system, minimum freeboard requirements,
structural integrity requirements, ground-water monitoring, 2-foot clay cap at closure, and revegetation at
closure.
Grandfather
Clause
Units permitted prior to July 4,1992, were required to modify their operations to comply with the above
requirements by July 4,1997. Liner and leachate collection requirements may be modified if the operator
could demonstrate that the unit had not caused unacceptable ground-water degradation.
Based on this detailed analysis, it appears states have varied in their application of solid waste
management requirements to OCW landfills. For example, Pennsylvania's program imposes
requirements tailored to the characteristics of the waste. Massachusetts' interim policy specifically
addresses concerns over vanadium in OCWs. According to discussion with Florida waste management
officials, the combination of solid waste and power plant siting regulations have not, in practice, resulted
in any permit requirements specifically tailored to the onsite management of oil ash. Thus, Florida's and
New York's programs apply generically to industrial wastes. In these states, OCWs may be disposed of
in landfills that are "grandfathered" out of requirements imposing design requirements such as liners.
Regulations in three of the four states studied do not impose specific design requirements on
surface impoundments that are commonly used to store OCWs. Two of these states permit discharges to
ground water from these units.
6.6 WASTE MANAGEMENT ALTERNATIVES
The risk assessment identified potential ground-water pathway risks to human health from OCW
in unlined landfills and impoundments. Mitigation of these potential risks might be accomplished
through the use of technologies that prevent or contain and collect leachate from OCW landfills and
surface impoundments. Specially, EPA identified the combination of technologies in Table 6-16 as an
alternative that would be practical and effective to mitigate the potential ground-water risk. The
technologies identified in the table are considered further in the cost and economic impact analysis.
These technologies also are consistent with those required under Subtitle D of RCRA.
6.7 COMPLIANCE COSTS AND ECONOMIC IMPACTS
This section discusses the costs and economic impacts of risk mitigation alternatives for OCWs.
Because of the quantity of waste generated and availability of data, the analysis focuses on wastes
generated by oil-fired utilities only. Details of this analysis are documented as part of the EPA docket.
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Table 6-16. Management Alternatives for OCW
Landfill
Impoundment
Design includes filter fabric, 1' sand layer, 2' clay liner,
synthetic (HOPE) liner, leachate collection system, ground-
water wells.
Operation includes environmental monitoring and leachate
collection and treatment.
Closure requirements include 6" topsoil and vegetation, filter
fabric, 1.5' sand layer, 2' clay layer, synthetic (HOPE) liner,
cover drainage system.
Post-closure includes environmental monitoring, landscape
maintenance, slope maintenance, inspection, administration.
Design includes filter fabric, 1' sand layer, 2' clay liner,
synthetic (HOPE) liner, leachate collection system, synthetic
liner for sludge drying basin, ground-water wells.
Operation includes environmental monitoring, leachate
collection and treatment, solids settling and dewatering
followed by disposal in landfill meeting standards at left.
Closure requirements include final solids dredging and
dewatering followed by disposal in landfill meeting standards
at left, pressure washing sludge drying basin, 6" topsoil and
vegetation, 1.5' soil layer, leachate sampling.
6.7.1 Overview and Methodology
In estimating costs and economic impacts for oil-fired utilities, EPA used a similar approach to
that described in Section 3.7.1 for coal-fired utilities. Salient distinctions between the analysis in
Section 3.7 and this analysis are reviewed below.
EPA's analysis began with the 89 oil-fired plants identified in the 1993 U.S. Department of
Energy (DOE) Energy Information Administration (EIA) 767 database that have electrical generating
capacities of at least 10 MW. EPA estimated the incremental compliance cost of the risk mitigation
alternative described in Section 6.6. The cost estimate required oil-fired utilities to construct composite
lined solids settling basins (SSBs). Because the few onsite landfills identified currently are lined and
assuming that offsite landfills are compliant with Subtitle D, no incremental costs were estimated for
OCW landfills.
The cost estimate summed costs in the following categories: initial capital costs, annual
operating and maintenance costs, and closure costs. Recurring capital costs and post-closure costs were
minimal for management units as small as the oil SSBs. Table 6-17 identifies the specific cost
components included in each cost category for oil-fired utilities.
Similar to the analysis for coal-fired utilities, the cost estimate for OCWs employed three
different SSB sizes. Table 6-18 identifies the design features for these basins. A single cost equation
was developed, annualized costs were estimated as a function of facility-specific waste generation, and
total industry costs were derived by summing the facility-specific estimates. Costs and economic impacts
are set forth in the following three sections: incremental compliance cost, compliance cost impact on
facilities as a function of size, and industry impact.
Incremental compliance costs are the costs of risk mitigation practices over and above the cost of
current management practices. Using incremental compliance costs as an indicator of potential cost
burden, the analysis examined impacts on individual facilities as a function of size. As in Section 3.7,
this was performed using pro forma financial statements for three representative plant sizes. For the
industry impact evaluation, the use of econometric models was considered and rejected for the same
reasons discussed in Section 3.7. The industry-level analysis, therefore, focuses on the number of
affected facilities and the magnitude of incremental compliance costs relative to the value of electricity
sales.
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Table 6-17. Cost Components Included in OCW Solid Settling Basin Designs
Category
Cost Components
Initial Capital Costs
Site development (access road, drainage ditch)
Excavation
Discharge structure
Filter fabric
1'sand
2' clay liner
Synthetic (HOPE) liner
Leachate collection
Synthetic liner for sludge drying basin
Ground-water wells
Indirect capital costs
Annual O&M Costs
Dredging
Ash dewatering
Operating and maintenance labor
Electricity
Offsite Subtitle D landfill ash disposal
Environmental monitoring
Leachate collection and treatment
Closure Costs
Pressure wash sludge drying basin
Final ash dredging, dewatering and Subtitle D disposal
6" topsoil and vegetation
1.5'soil
Leachate sampling
Indirect closure costs
Table 6-18. Design Parameters Assumed for Small, Medium, and Large OCW SSBs
Parameter
Sizes
(dry tons/year)
Depth
(feet)
Area
(acres)
small
medium
large
small
medium
large
small
medium
large
SSB
36
172
923
8.0
11.0
12.0
0.3
1.0
2.5
6.7.2 Incremental Compliance Cost
Key variables in estimating incremental compliance cost were the same as those discussed in
Section 3.7.2. EPA's estimate of incremental compliance cost is some $1.7 million per year, using the
most likely values for all the input variables. The potential range of annual incremental compliance costs
is from $1.0 million to $3.5 million, allowing for uncertainty in the input variables.
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Note that the costs above are incremental (above current costs). Annual costs were discounted at
7 percent to 1998 dollars, with no inflation built into out-year estimates. Also, it was presumed that
compliance would be required immediately, and that amortization would take place over 40 years.
6.7.3 Compliance Cost Impact on Plants as a Function of Plant Size
As discussed in Section 3.7.3, this analysis does not include the potential impact of the ongoing
restructuring of the utility industry and includes no analytical consideration of price effects.
Economic impacts at the plant level will depend on several major factors, including quantity of
fuel used, quality of fuel, profitability, and production technology. To assess these impacts across the
range of plants, EPA estimated financial data for model plants representing three size ranges: large
(burning greater than 750,000 barrels of oil per year), medium (burning between 250,000 and 750,000
barrels of oil per year), and small (burning less than 250,000 barrels of oil per year). These model
facilities are representative of publicly owned utilities. Table 6-19 compares incremental compliance
costs to revenues and net income for these three model plants. The incremental compliance costs used in
this analysis reflect EPA's best estimate based on most likely values of the relevant input variables.
Table 6-19. Plant-Level Impact of Incremental Compliance Costs
Revenues from Electricity
Baseline Before Tax Net Income
Expected Incremental Compliance Costs
(replace unlined management unit with
composite-lined unit)
Expected Post-Compliance Net Income
Large Oil Plant
Publicly Owned Utility
$1,000's
72,000
6,480
43
6,437
Percent of
Revenues
100%
9.0%
0.1%
8.9%
Medium Oil Plant
Publicly Owned Utility
$1,000's
18,000
1,620
29
1,591
Percent of
Revenues
100%
9.0%
0.2%
8.8%
Small Oil Plant
Publicly Owned Utility
$1,000's
3,000
210
12
198
Percent of
Revenues
100%
7.0%
0.4%
6.6%
Thus, the incremental compliance cost for OCWs should not impact the financial viability of oil-
fired plants. For a large publicly owned oil-fired plant generating about 1.2-billion kWh per year, costs
would be expected to increase only $43,000 annually. This would increase costs by about 0.1 percent of
annual revenue and thus reduce net income from 9.0 percent of revenue to 8.9 percent of revenue. Net
income would thus be reduced from $6.48 million to $6.43 million per year.
Small and medium-sized oil-fired plants (generating from 50- to 300-million kWh per year)
would be more significantly affected but still remain financially viable. Waste management costs would
be in the range of $200 to $500 per dry ton; however, total compliance costs, as a percent of revenue,
would climb about 0.2 to 0.4 percent only. Annual net income for these plants would decline about
$12,000 to $29,000 per year, depending on the size of the plant. If such plants could increase prices to
offset oil waste management costs, they would need only to increase from the representative baseline
price of 6 cents per kWh to 6.02 cents per kWh to regain the pre-compliance position.
Table 6-20 shows how the estimated population of affected facilities breaks down by the three
size categories represented by the model plants. It also compares the incremental compliance costs
estimated for the model plants to average sales for individual plants in each size category. Based on this
criterion, incremental compliance costs range from 0.1 to 0.4 percent of sales.
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Table 6-20. Incremental Compliance Cost by Plant Size
Size Category
Large (>750,000 barrels/year of oil)
Medium (250,000 to 750,000 barrels/year of oil)
Small (<250,00 barrels/year of oil)
Number of
Plants
43
15
31
Percent of
Plants
35%
17%
48%
Plant Sales
($ million/year)
$72
$18
$3
Compliance Cost
($ million/year)
$0.04
$0.03
$0.01
Percent
of Sales
0.1%
0.2%
0.4%
6.7.4 Industry Impacts
The electric power generating industry, including fossil fuel, hydroelectric, nuclear, and other
fuel sources, was a $212 billion per year industry in 1996. Other economic characteristics of the electric
utility industry are discussed in Section 3.7.4, along with information on the current restructuring of the
U.S. electric power industry.
Based on the estimate of costs presented above, if OCWs were subject to risk mitigation
alternatives, the electric utility industry would incur about $1.7 million in incremental annualized
compliance costs. As shown in Table 6-21, this would represent less than one-tenth of 1 percent of the
value of sales even if the oil-fired segment of the industry only is considered. Thus, the cost of
compliance would be a very small percentage of revenues.
Table 6-21. Industry Economic Impacts, Oil Combustion Wastes
Industry Sales ($ billion/year)
$4.3
Compliance Cost ($ billion/year)
$0.002*
Percent of Sales
0.05%
* Rounded up from $1.7 million
Because impacts as a percent of sales would be an order of magnitude less, oil-fired plants would
have less need to pass through costs in the form of higher prices than would coal-fired plants if both were
subject to risk mitigation alternatives. But again, the ability to pass through costs, even if quite modest,
would be restricted by competition from unaffected plants.
6.8 FINDINGS AND RECOMMENDATIONS
6.8.1 Introduction
Based on the information collected for this Report to Congress, this section presents a summary
of the Agency's main findings presented under headings that parallel the organization of this chapter. It
then presents the Agency's tentative conclusions concerning the disposal and beneficial uses of
comanaged wastes generated at facilities that burn oil.
6.8.2 Findings
Sector Profile
There are about 177 utility and more than 2,000 non-utility facilities that burn oil. Oil-
burning facilities are located throughout the United States, but utility facilities in particular
are concentrated in the eastern United States and in California.
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Non-utilities burn oil for a variety of purposes, including production of manufacturing
process steam, space heating, and captive power generation. They include industrial,
commercial, and institutional facilities. They are located in diverse environments, including
areas that vary widely in population density, geography, precipitation, and general climate.
There is a declining trend of oil combustion, and the trend is expected to continue for the
next two decades. While industrial combustion of oil is expected to grow modestly, it will
be more than counterbalanced by gas turbine technologies replacing oil-fired utility steam-
cycle processes.
Waste Generation and Characteristics
Large-volume OCWs comprise primarily fly ash and bottom ash. Low-volume wastes
associated with the burning of oil are similar in type and characteristics to those described
previously for coal combustion, although comprehensive information on the amounts is not
available. Examples of similar low-volume wastes at coal and oil combustors include boiler
blowdown, ion exchange regeneration wastes, and boiler chemical cleaning waste.
The utility sector generates an estimated 23,000 tons of OCWs annually. This is less than
0.1 percent of the quantity of coal combustion wastes generated by the utility sector.
Comprehensive waste quantity information for the non-utility oil burning sector is not
available. The Agency estimates that a maximum of 18,000 tons of OCWs are generated
annually by the non-utility sector. Of this amount, the Agency estimates about 5,500 tons
are collected; the remainder are released with stack gases. On average, this collected
amount would equate to about 1 ton per year per boiler unit.
The constituents of concern in OCWs are trace metal elements. No organic constituents,
including dioxins, were identified at potential levels of concern in these wastes.
OCWs only infrequently exhibit the RCRA toxicity characteristic. Six percent of the
samples in the Agency's database exceeded the RCRA regulatory level for one or more of
the eight RCRA metals. These sample were represented by 7 of the 40 sites in the database.
The exceedences involved chromium, arsenic, cadmium, and selenium.
Although not RCRA metals, both nickel and vanadium in whole waste and leachate are
present at relatively high levels. Nickel and vanadium can range up to 4 percent and 20
percent, respectively, in the whole waste. These metals are naturally present in the source
crude oil. Vanadium levels can be high enough in OCWs to make it economically feasible
to process the wastes for recovery of vanadium.
Based on the available data and engineering judgment, OCWs are not reactive, ignitable, or
corrosive.
Waste Management Practices
OCWs are managed alone by some facilities and are comanaged with low-volume wastes at
other facilities. Utilities most often comanage oil fly ash with low-volume wastes in onsite
impoundments (settling basins), and eventually transfer and manage the solids in landfills.
Bottom ash is typically managed dry and placed in landfills.
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Settling basins used for onsite management are typically small, about 1 acre in size. Both
concrete-lined basins and unlined percolation/evaporation basins are in use by the utility
industry. The unlined basins are designed to discharge to ground water.
Waste management survey information and anecdotal information suggests a recent trend
toward the increased use of liners for impoundments.
There are several beneficial uses of OCWs. These include vanadium recovery, use in
concrete products, and use in structural fill materials. Comprehensive statistics do not exist
on the total amounts of waste that are managed through beneficial uses.
Potential Risks and Damage Cases
EPA conducted a risk assessment that found a lack of potential human health risk for most
waste constituents. The Agency did identify potential human health risks via the ground-
water pathway where these wastes are managed in unlined landfills and surface
impoundments for arsenic (cancer), nickel (non-cancer), and vanadium (non-cancer). The
identified risks are based on high-end risk scenarios in EPA's risk modeling analysis for
human ingestion of well water influenced by release from the waste management unit. The
time to reach the health-based level for arsenic in ground water at the receptor well ranges
from 400 to 2,800 years. For nickel and vanadium, the times to reach the health-based
levels are 50 years and 10 years, respectively.
The Agency identified no potential human health risks via non-ground-water pathways.
The Agency believes there is no significant ecological risk posed by the relatively small
onsite surface impoundments and landfills used to manage these wastes.
The Agency identified one damage case associated with management of these wastes, which
involved elevated levels of cadmium. The release was basically confined to the vicinity of
the facility and did not affect human receptors.
Existing Regulatory Controls, State, and Federal Requirements
The utility industry, the sector that collects the majority of these wastes, has a significant
level of installed environmental controls for managing these wastes. All of the identified
landfills and about 60 percent of the impoundments used to manage these wastes are
currently lined. The recent trend for utility facilities is toward liners and ground-water
monitoring controls for these wastes.
States have increasingly begun to impose controls on OCW management units. The
majority of states have regulatory permit programs, as well as general authority to require
siting controls, liners, leachate collection systems, ground-water monitoring, closure
controls, daily or other operational cover, and fugitive dust controls for waste management.
In a few states with significant generation of OCWs, newer landfills must have liners and
other controls, but older landfills do not have to be retrofit with these controls.
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In a few states with significant generation of OCWs, there are no specific design
requirements for surface impoundments used to store or manage these wastes. At least two
of these states permit discharges to ground water from the impoundment units.
Potential Costs and Impact of Regulation
The Agency estimates that the total annual incremental compliance costs for mitigation of
the potential risks identified in this study (arsenic, nickel, vanadium by ground-water
pathway) would be nearly $2 million (1998$). These costs represent replacement of
existing unlined management units with lined management units, and implementing ground
water monitoring and leachate collection and treatment. These measures do not represent
implementation of full Subtitle C requirements, but rather modifications of such
requirements that could potentially be adopted under Section 3004(x) of RCRA.
If these wastes were to be regulated under full Subtitle C, virtually all existing facilities
would be required to invest substantial funds and resources to modify existing management
practices. The total annual cost of full Subtitle C requirements would considerably exceed
the $2 million (1998$) estimate above.
If beneficial uses of these wastes were subject to Subtitle C requirements, possibly all
beneficial use practices and markets would cease.
6.8.3 Recommendations
Following are the Agency's recommendations for the wastes covered in this chapter. The
recommendations are based on EPA's analysis of the eight Congressionally mandated study factors
(Section 1.2). These conclusions are subject to change based on continuing information collection,
continuing consultations with other government agencies and the Congress, and comments and new
information submitted to EPA during the comment period and any public hearings on this report. The
final Agency decision on the appropriate regulatory status for these wastes will be issued after receipt
and consideration of comments as part of the Regulatory Determination, which will be issued within 6
months.
1. The Agency is considering two approaches to address the potential risks that may be posed by
disposal of these wastes. One approach would be regulatory using Subtitle C authority and the
other would be to encourage voluntary changes in industry practices.
The Agency found in many cases that OCWs, whether managed alone or comanaged with low-
volume wastes, are seldom characteristically hazardous and may not present a significant risk to human
health and the environment. These cases include situations in which the wastes are managed in lined
units with adequate cover. The Agency believes that no significant ecological risks are posed by disposal
of these wastes. Only one damage case was identified and it did not affect human receptors.
In light of the results of EPA's risk assessment, however, the Agency is concerned about
situations in which the wastes are managed in unlined units, particularly comanagement in settling basins
and impoundments that are designed and operated to discharge to ground water. As discussed in this
chapter, the Agency's risk analysis suggests that three metals may pose potential ground-water pathway
risks at such facilities: arsenic, nickel, and vanadium. While there is a trend in recent years to line new
units and the Agency has anecdotal information that some facilities are preparing to either line or close
their unlined units, the Agency has particular concerns with the high levels of nickel and vanadium in the
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wastes and in the leachate that is being discharged to ground water. The Agency's risk analysis
identified high hazard quotients and short time periods to exceedence of health-based risk criteria at
potential ground-water receptor locations for nickel and vanadium. The risks identified with these
practices may be of sufficient concern to consider whether tailored regulations are necessary to target the
potential risks. On the other hand, since the recent industry and state regulatory trends have been toward
liners and ground-water monitoring for these waste disposal units, sufficient protection may be obtained
by facilitating this trend and engaging the industry to voluntarily establish the appropriate controls. An
example would be to line the existing unlined units and, where appropriate, to implement ground-water
monitoring. The Agency solicits comment on its tentative conclusion, specific approaches that could be
pursued to address these concerns, and the identification of only one damage case.
2. The Agency has tentatively concluded that the existing beneficial uses of these wastes should
remain exempt from Subtitle C.
There are few existing beneficial uses of these wastes, which include components of cement,
concrete, and construction fill as discussed in this chapter. No significant risks to human health exist for
the identified beneficial uses of these wastes. This is based on one or more of the following reasons for
each use: absence of identifiable damage cases, fixation of the waste in finished products which
immobilized the material, and/or low probability of human exposure to the material. In the case of
vanadium recovery operations, a valuable product is being produced; however, if the wastes resulting
from the metal recovery processes are hazardous, they will be subject to the existing hazardous waste
requirements.
Unlike coal combustion wastes, these wastes are not known to be used in minefill or agricultural
applications. These wastes are not generated at rates high enough to justify their transport and use for
filling mine voids. There are no known benefits to using these wastes for agricultural purposes.
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7.0 NATURAL GAS COMBUSTION WASTES
Natural gas is the second most significant fossil fuel used by utilities in the United States. In
1996, gas-fired units accounted for approximately 20 percent of utility generating capacity, but only
9 percent of utility electricity generated. This generation rate represents a decline of 15 percent from
the level reported in 1995 due in part to a substantial increase in the cost of gas in 1996. (Use of
hydroelectric, oil-fired, and geothermal sources increased in 1996 to make up for the decrease in use of
gas) (EIA, 1998a). Many gas-fired units are used to generate power during periods of peak demand.
Figure 7-1 shows the locations of gas-fired power plants. Gas-fired units generate virtually no solid
waste. Thus, although a significant portion of capacity is represented by gas combustors, this study does
not include extensive analysis of natural gas combustors. The Agency intends to continue the exemption
from Resource Conservation and Recovery Act (RCRA) Subtitle C for gas combustors.
Figure 7-1. Number of Gas-Fired Power Plants by State
7.1 TECHNOLOGY
As shown in Table 7-1, natural gas combustion accounts for a substantial fraction of both utility
and non-utility generating capacity. Natural gas combustion technologies are similar to those used for oil
combustion. In gas-fired steam electric boilers, gas is injected into the furnace in the presence of excess
air. The same burner designs used for oil also are used to inject and combust natural gas. In fact, many
combustion units can utilize either oil or gas. Unlike oil, natural gas does not require preparation
(atomization) for mixing with combustion air (Stultz and Kitto, 1992). Because of its negligible ash
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Table 7-1. Natural Gas-Fired Generating Capacity
Sector
Utility
Non-Utility
Total
Number of
Gas-Fired Boilers
788
6,907
7,695
Gas-Fired Capacity
(megawatts equivalent)
104,961
46,663
151,624
Total Sector Capacity
(megawatts equivalent)
469,272
148,021
621,884
Percent
Gas- Fired
22%
32%
24%
Because these capacity data are from different sources and different points in time, the percentages should be treated only as estimates.
Sources: EEI, 1994; EPA, 1990
content, combustion of natural gas generates virtually no solid waste; therefore, this study focuses
primarily on coal-fired and oil-fired combustors.
7.2 FINDINGS AND RECOMMENDATIONS
As discussed above, combustion of natural gas generates virtually no solid waste; therefore,
further analysis of the RCRA 8002(n) study factors is not warranted for gas fuels. EPA intends to
continue the exemption from RCRA Subtitle C for gas combustors.
7.2.1 Introduction
Based on the information collected for this Report to Congress, this section presents a summary
of the Agency's main findings presented under headings that parallel the organization of this chapter. It
then presents the Agency's tentative conclusions concerning the wastes from burning natural gas.
7.2.2 Findings
Sector Profile
There are nearly 800 gas-fired boilers in the utility sector that represent about 22 percent of
utility power generating capacity.
There are about 6,900 gas-fired boilers in the non-utility sector that represent about one-
third of the non-utility power generating capacity.
Waste Generation and Characteristics
There is virtually no solid waste that results from the combustion of natural (fossil fuel) gas.
7.2.3 Recommendations
Following are the Agency's recommendations for the wastes covered in this chapter. The
recommendations are based on EPA's analysis of the eight Congressionally mandated study factors
(Section 1.2). These conclusions are subject to change based on continuing information collection,
continuing consultations with other government agencies and the Congress, and comments and new
information submitted to EPA during the comment period and any public hearings on this report. The
final Agency decision on the appropriate regulatory status for these wastes will be issued after receipt
and consideration of comments as part of the Regulatory Determination, which will be issued within
6 months.
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1. The Agency has tentatively concluded that it will retain the Subtitle C exemption for natural gas
combustors.
The Agency has tentatively concluded that it will retain the Subtitle C exemption for natural gas
combustors. The Agency solicits comment on whether it is appropriate to retain or remove the Subtitle C
exemption for natural gas combustion since there are no solid wastes generated by the process.
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papers, June 14-15, Albany, New York.
Radian Corporation. 1988. Assessment of NORM Concentrations in Coal Ash and Exposure to Workers
and Members of the Public. Prepared for the Utility Solid Waste Activities Group (USWAG).
June.
R.S. Means. 1997. Site Work and Landscape Cost Data. 16th annual edition. R.S. Means Company,
Inc., Kingston, Massachusetts.
R.S. Means. 1998a. Environmental Remediation Cost Data-Assembles. 4th annual edition. R.S.
Means Company, Inc., Kingston, Massachusetts, and Delta Technologies Group, Inc.,
Englewood, Colorado.
R.S. Means. 1998b. Environmental Remediation Cost Data-Unit Price. 4th annual edition. R.S.
Means Company, Inc., Kingston, Massachusetts, and Delta Technologies Group, Inc.,
Englewood, Colorado.
Stultz, S.C. and J.B. Kitto, eds. 1992. Steam: Its Generation and Use. Barberton, Ohio: Babcock &
Wilcox.
USDA (U.S. Department of Agriculture). 1998. Agricultural Uses of Municipal, Animal and Industrial
Byproducts. Conservation Research Report Number 4. January.
VDEQ (Virginia Department of Environmental Quality). 1994. Cogeneration of Steam and Electric
Power: Pollution Prevention Opportunities and Options. Office of Pollution Prevention.
September.
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GLOSSARY*
ACAA - American Coal Ash Association.
air heater or air preheater - device that uses flue gases to preheat combustion input air.
air heater and precipitator washwater - wastes resulting from the periodic cleaning of the fireside
(i.e., the side exposed to hot combustion products) of heat exchanging surfaces.
air monitoring system - periodic collection and analysis of air samples near a waste management unit.
alkalinity - the amount of carbonates, bicarbonates, hydroxides, and silicates or phosphates in a liquid.
Reported as grains per gallon, pH, or parts per million of carbonate. Indicated by a pH of greater than 7.
anthracite - a hard black lustrous rank of coal (see coal rank).
APC - air pollution control.
ash - incombustible material in fuel that can become waste after combustion.
ash fusion temperature - the temperature at which a cone of coal or coke ash exhibits certain melting
characteristics.
ASTM - American Society for Testing and Materials.
ASTSWMO - Association of State and Territorial Solid Waste Management Officials.
backfill - a project in which an excavation area is refilled with earth or other materials.
BACT - Best Available Control Technology under the Clean Air Act.
baghouse - an air pollution abatement device used to trap particulates by filtering gas streams through
large fabric bags usually made of glass fibers.
baseload - that portion of electricity demand from a station or boiler that is practically constant for long
periods.
baseload unit - an electrical generating unit that is used to supply baseload, and thus is operated
continuously at an essentially constant rate.
BAT - Best Available Technology Economically Achievable under the Clean Water Act.
bed ash - spent bed material and fuel ash (bottom ash) that settle on the bottom of an FBC boiler.
bituminous coal - A common dense black rank of coal (see coal rank).
* References for this glossary include EIA, 1997d; EPA, 1988; CIBO, 1997c, and Stultz andKitto, 1992.
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BMP - best management practice under the Clean Water Act.
boiler - a closed vessel in which heat from an external combustion source (such as a fossil fuel) is
transferred to produce hot water or generate steam.
boiler blowdown - waste generated by removal of a portion of boiler water for the purpose of reducing
solid concentration or discharging sludge.
boiler chemical cleaning waste - waste resulting from the cleaning of boiler surfaces using chemical
solutions.
boiler slag - melted and fused particles of ash that collect on the bottom of the boiler. Slag forms when
operating temperatures exceed ash fusion temperature.
bottom ash - large ash particles that settle on the bottom of a boiler. Bottom ash does not melt and
therefore remains in the form of unconsolidated ash.
BPT - Best Practicable Control Technology Currently Available under the Clean Water Act.
Btu - British Thermal Unit, a unit of heat energy.
bubbling fluidized bed system - a fluidized bed combustion system in which excess air passes through
the bed in the form of bubbles. These systems have air velocities of 5 to 12 feet per second and larger
bed particle size than circulating fluidized bed systems. These conditions result in a dense bed (45
pounds per cubic foot) with a well-defined surface.
Bunker C fuel oil - a residual fuel oil, also characterized as No. 6 fuel oil, which is used for commercial
and industrial heating, electricity generation, and to power ships.
CAA - Clean Air Act.
CCW - coal combustion waste.
CERCLA - the Comprehensive Environmental Response, Compensation, and Liability Act, commonly
referred to as Superfund.
CIBO - Council of Industrial Boiler Owners.
circulating fluidized bed system - a fluidized bed system that has high air velocities (as high as 30 feet
per second) and fine particle sizes. As a result, the fluid bed is less dense (35 pounds per cubic foot) and
has no well-defined top surface. Large quantities of bed material are recaptured from the gas stream and
recirculated back to the furnace to maintain bed inventory.
CMTP - Composite Model for Leachate Migration with Transformation Products.
coal cleaning - the act of processing coal prior to combustion to change its characteristics (e.g., size, ash
content, and/or sulfur content).
coal pile runoff- surface water runoff produced by precipitation falling on coal storage areas.
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coal mill rejects - solid waste produced by onsite processing of coal in a mill prior to use.
coal rank - a system of classifying coal corresponding to its degree of metamorphism, geologic age, and
heating value. Ranks include anthracite, bituminous, subbituminous, and lignite, with anthracite being
the oldest and lignite being the youngest.
cogeneration - the production of electricity and another form of useful thermal energy (steam or hot
water) from a single source.
combustion turbine (CT) - a system that uses exhaust from combustion (typically of oil or natural gas)
directly to drive turbines.
compaction - the act of compacting waste after placement to reduce or prevent wind and water erosion
of the waste and subsequent release to the environment.
condenser - a device that converts low-pressure steam back to water by transferring heat to a cooling
water system.
cooling tower/cooling pond - recirculating cooling water system used to transfer heat picked up in the
condenser to the atmosphere by evaporative cooling.
cooling tower basin sludge - solids that collect in the bottom of cooling towers and must be removed
periodically and disposed.
cooling tower blowdown - water withdrawn from the cooling system in order to control the
concentration of impurities in the cooling water.
corrosivity - see RCRA Subtitle C characteristics.
cover - a barrier placed on top of a waste management unit.
culm - refuse from the cleaning of anthracite coal.
CWA-Clean Water Act.
cyclone furnace - A combustion technology that creates a cyclone-like air circulation pattern causing
smaller particles to burn in suspension, while larger particles adhere to a molten layer of slag that forms
on the barrel walls.
demineralizer regenerant and rinses - see regeneration waste streams.
dioxin - general term for polychlorinated dibenzo-p-dioxins (PCDDs), a class of toxic chemicals.
distillate fuel oil - one of the petroleum fractions produced in conventional distillation operations.
Included are products known as No. 1, No. 2, and No. 4 fuel oils.
dry scrubber - a flue gas desulfurization system in which the resulting byproduct is a dry, typically fine,
powder.
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dust suppression/control - conditioning waste with water or other liquid before and during transport
and placement to prevent airborne transport of the waste and to reduce inhalation exposure to site
workers.
economizer - a device for transferring heat from combustion exhaust to boiler input water.
EEI - Edison Electric Institute.
EEI database - 1994 EEI Power Statistics Database.
EIA - The U.S. Department of Energy's Energy Information Association.
electrostatic precipitator (ESP) - an air pollution control device that imparts an electrical charge to
particulates in a gas stream, causing them to collect on an electrode.
EP - Extraction Procedure.
EPACMTP - EPA's Composite Model for Leachate Migration with Transformation Products.
EPRI - Electric Power Research Institute.
fabric filter - see baghouse.
FGD - flue gas desulfurization.
flue gas - the gaseous products of combustion that exit a boiler through a flue or stack.
flue gas desulfurization (FGD) technology - device that is used to remove sulfur oxides from flue gas
after combustion.
flue gas desulfurization (FGD) waste - waste that is generated during the process of removing sulfur
oxide gas from the flue gas after combustion.
fluidized bed combustion (FBC) - a combustion process in which fuel is burned on a bed of
incombustible material (e.g., sand and limestone) while combustion air is forced upward at high
velocities, making the particles flow as a fluid.
fly ash - suspended, uncombusted ash particles carried out of the boiler along with flue gases.
fossil fuel - a naturally occuring organic fuel, including coal, oil, and natural gas.
Fur an - general term for polychlorinated dibenzofurans (PCDFs), a class of toxic chemicals.
generating unit - a combination of one or more boilers operated together to produce electricity or other
useable thermal energy. May include one or more turbines, fuel processing systems, and/or air pollution
control devices.
gigawatt (GW) - one billion watts.
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gob - refuse from the cleaning of bituminous coal.
ground water monitoring system - one or several wells from which samples of ground water are
periodically collected and analyzed.
HAP - Hazardous Air Pollutant under the Clean Air Act.
HOPE - high density polyethylene.
ignitability - see RCRA Subtitle C characteristics.
kilowatt (kW) - one thousand watts.
landfill - a facility or part of a facility in which wastes are placed for disposal in or on land.
leachate - the liquid resulting from water percolating through waste.
leachate collection system - a series of drains and tubing placed beneath a waste management unit,
typically a landfill, that collect leachate for treatment or disposal.
lift - the depth of a cell in a landfill.
lignite - a brownish-black rank of coal (see coal rank).
lime - calcium oxide (CaO).
limestone - calcium carbonate (CaCO3).
liner - a barrier placed underneath a landfill or on the bottom and/or sides of a surface impoundment.
MCL - maximum contaminant level.
mechanical collector - an air pollution control device that forces a cyclonic flow of the exit gas. This
flow causes ash particles to be thrown against the walls of the collector and drop out of the gas.
megawatt (MW) - one million watts.
minefill - a project involving placement of fossil fuel combustion wastes in mine voids, whether for
purposes of disposal or for beneficial uses such as mine reclamation.
monofill - a landfill that contains only one type of waste.
NAAQS - National Ambient Air Quality Standards under the Clean Air Act.
natural gas - a fossil fuel consisting of a mixture of hydrocarbon and nonhydrocarbon gases found
beneath the Earth's surface.
NESHAP - National Emissions Standards for Hazardous Air Pollutants under the Clean Air Act.
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No. 1 fuel oil - A light distillate fuel oil intended for use in vaporizing pot-type burners.
No. 2 fuel oil - A distillate fuel oil for use in atomizing-type burners for domestic heating or for
moderate capacity commercial-industrial burner units.
No. 4 fuel oil - a fuel oil for commercial burner installations not equipped with preheating facilities. It is
used extensively in industrial plants. This grade is a blend of distillate fuel oil and residual fuel oil
stocks.
No. 5 fuel oil - a residual fuel oil of medium viscosity.
No. 6 fuel oil - a residual fuel oil used for commercial and industrial heating, electricity generation, and
to power ships. Includes Bunker C fuel oil.
non-utility - for purposes of this study, an entity that combusts fossil fuel and whose primary
commercial activity is not the production of electricity (see utility).
NPDES - National Pollution Discharge Elimination System under the Clean Water Act.
NSPS - New Source Performance Standards under either the Clean Water Act or Clean Air Act.
OCW - oil combustion waste.
particulates - fine liquid or solid particles such as dust, smoke, mist, fumes, or smog, found in the air or
emissions.
PCB - polychlorinated biphenyls, a class of toxic chemicals.
PCDD - polychlorinated dibenzo-p-dioxin.
PCDF - polychlorinated dibenzofuran.
PDWS - Primary Drinking Water Standards established by the Safe Drinking Water Act.
peakload - the maximum electricity demand from a facility or boiler that occurs during a specified
period of time.
peakload unit or peaking unit - an electrical generating unit that is used to supply peakload, and thus is
used intermittently during periods of high demand.
percolation basin - a surface impoundment in which liquids are allowed to discharge (percolate) into
the ground.
petroleum coke - solid carbaceous residue remaining in oil refining stills after the distillation process.
PM - particulate matter.
pore water - interstitial water from borings of waste managed in surface impoundments.
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POTW - Publicly Owned Treatment Works.
pozzolanic - forming a strong, slow-hardening cement-like substance when mixed with lime or other
hardening material.
PSD - prevention of significant deterioration under the Clean Air Act.
PSES - Pretreatment Standards for Existing Sources under the Clean Water Act.
pulverized coal (PC) boiler or pulverizer - a combustion technology that burns finely ground coal in
suspension.
PVC - polyvinyl chloride.
pyrites - iron sulfide (FeS2) minerals that may oxidize during the combustion process to generate sulfur
oxide gases. Pyrites may be a component of coal mill rejects.
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.
corrosivitv - 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 millimeters per year at a test temperature of 55 °C.
toxicitv - a solid waste exhibits the characteristic of toxicity if, after extraction by a prescribed
EPA method, it yields a metal concentration 100 times the acceptable concentration limits set
forth in EPA's primary drinking water standards.
ignitabilitv - a solid waste exhibits the characteristic of ignitability if it is a liquid with a
flashpoint below 60°C or a non-liquid capable of 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.
reactivity - see RCRA Subtitle C characteristics.
regeneration waste streams - wastes resulting from periodic cleaning of ion exchange beds used to
remove mineral salts from boiler makeup water.
reinjection - the act of returning fly ash to a boiler to use any residual carbon content as fuel.
residual fuel oil - the heavier oils that remain after the distillate fuel oils and lighter hydrocarbons are
distilled away in refinery operations. Included are No. 5 fuel oil, Navy Special, and No. 6 fuel oil (which
includes Bunker C fuel oil).
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RIA - Regulatory Impact Analysis.
run-on and runoff control and collection system - Run-on controls prevent precipitation runoff from
other parts of a site from reaching waste management areas. Runoff controls and collection systems
prevent precipitation runoff from the waste management unit from being transported offsite.
scrubber - an air pollution control device used to remove particulates or contaminant gases from flue
gas (see wet scrubber and dry scrubber).
SOWS - Secondary Drinking Water Standards established by the Safe Drinking Water Act.
SIC - Standard Industrial Classification.
SIP - State Implementation Plan under the Clean Air Act.
slag - molten or fused solid matter.
sluice water - liquid used to transport combustion waste or other material.
sluiced ash - combustion waste that has been transported using liquid.
slurry - a mixture of insoluble matter in a fluid.
SPLP - Synthetic Precipitation Leaching Procedure.
spray canal - recirculating cooling water system used to transfer heat picked up in the condenser to the
atmosphere by evaporative cooling.
SSB - solids settling basin.
Standard Industrial Classification (SIC) code - a code developed by the U.S. government that
categorizes businesses into groups with similar economic activities.
steam electric boiler - a system that combusts fuel in a boiler to produce steam, which in turn is used to
provide heat or steam or drive turbines.
stoker - a combustion technology using a mechanically operated fuel feeding mechanism to distribute
solid fuel over a grate for combustion.
subbituminous coal - an intermediate ranked coal between lignite and bituminous with more carbon and
less moisture than lignite (see coal rank).
superheater - a device that follows a boiler and uses exhaust gases from combustion to raise the
temperature of steam generated in the boiler.
surface impoundment - a facility that 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 containing free liquids.
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surface water monitoring system - periodic collection and analysis of surface water samples near a
waste management unit.
TCLP - Toxicity Characteristic Leaching Procedure.
toxicity - see RCRA Subtitle C characteristics.
TSS - total suspended solids.
UCCW - utility coal combustion waste.
unit - see generating unit or waste management unit.
USWAG - Utility Solid Waste Activities Group.
utility - a private or public organization that generates, transmits, distributes, or sells electricity. For
purposes of this study, includes independent power producers regulated under the Public Utility
Regulatory Policies Act (PURPA).
waste management unit - a structure, typically a landfill or surface impoundment, in which waste is
placed for disposal or storage.
wastewater treatment sludge - waste generated from the treatment in settling basins or other treatment
facilities of liquid waste streams.
water treatment sludge - waste resulting from treatment of makeup water for the steam cycle or for
non-contact cooling.
watt - a unit of electrical power.
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,
or inertial impaction.
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