r/EPA
             United States
             Environmental Protection
             Agency
               Office of Solid Waste .
               and Emergency Response
               Washington, DC 20460
EPA/530-SW-88-OO2
February 1988
            Solid Waste
Report  to
Congress

Wastes  from the Combustion
of  Coal  by Electric Utility
Power Plants

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    UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

                   WASHINGTON. D.C. 20460
                        MAR   8
                                          THE ADMINISTRATOR
Honorable George Bush
President of the Senate
Washington, D.C.  20510

Dear Mr. President:

    I am pleased to transmit  the  Report  to  Congress  on
Wastes from the Combustion  of Coal  by  Electric Utility
Power Plants.  The report presents  the results of
studies carried out pursuant  to Section  8002 (n)  of
the Resource Conservation and Recovery Act  of  1976 as
amended (42 U.S.C. Section  6982 (n)).

    The report provides a comprehensive  assessment of the
management of solid wastes  generated by  the combustion of
coal from electric utility  power  plants.  These wastes
account for approximately 90  percent of  all wastes
generated from the combustion of  fossil  fuels.  The
principal waste categories  covered  include  fly ash,
bottom ash, boiler slag and flue  gas emission  control
waste.

    The report and appendices are transmitted  in two
separate volumes.
                         Sincerely,.
                         Lee M. Thomas

Enclosure

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f 22?
\
3   UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
     x                   WASHINGTON. D.C.  20460
  •

                            MAR   8 1988
                                                THE ADMINISTRATOR
      Honorable James C. Wright
      Speaker of the House
        of Representatives
      Washington, D.C.  20515

      Dear Mr.  Speaker:

         I am pleased to transmit the Report to Congress on
      Wastes  from the Combustion of Coal by Electric Utility
      Power Plants.   The report presents the results of
      studies carried out pursuant to Section 8002(n) of
      the Resource Conservation and Recovery Act of 1976 as
      amended (42 U.S.C. Section 6982(n)}.

          The report provides a comprehensive assessment of the
      management of  solid wastes generated by the combustion of
      coal from electric utility power plants.  These wastes
      account for approximately 90 percent of all wastes
      generated from the combustion of fossil fuels.  The
      principal waste categories covered include fly ash,
      bottom  ash, boiler slag and flue gas emission control
      waste.

          The report and appendices are transmitted in two
      separate  volumes.
                               Lee M. Thomas

      Enclosure

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                         TABLE  OF  CONTENTS



                                                                           Page

EXECUTIVE SUMMARY 	      ES-1

I.    INTRODUCTION	       1-1

      1.1  Legislative History	       1-1
      1.2  Scope and Sources	       1-7
      1.3  Organization	       1-9

II.   OVERVIEW OF THE ELECTRIC UTILITY INDUSTRY 	       2-1

      2.1  The Demand for Electricity	       2-1
           2.1.1  Structure of the U.S.  Electric
                    Utility Industry  	       2-7
           2.1.2  Economic and Environmental Regulation
                    of the Electric Utility Industry  	      2-11
      2.2  Importance of Coal to Electric Utilities	      2-14
      2.3  Overview of Coal-Fired Power Plants  	      2-18
           2.3.1  Regional Characteristics of Coal-Fired
                    Electric Generating Plants  	      2-18
           2.3.2  Electricity Generating Technologies 	      2-21
      2.4  Coal Constituents and By-Products	      2-29

III.  WASTES GENERATED FROM COAL-FIRED ELECTRIC UTILITY
      POWER PLANTS	       3-1

      3.1  Overview of Electric Utility Wastes  	       3-1
      3.2  High-Volume Wastes 	       3-3
           3.2.1  Ash	       3-3
           3.2.2  FGD Sludge	      3-21
      3.3  Low-Volume Wastes  	      3-41
           3.3.1  Boiler Slowdown	      3-43
           3.3.2  Coal Pile Runoff	      3-45
           3.3.3  Cooling Tower Slowdown	      3-47
           3.3.4  Demineralizer Regenerant and Rinses 	      3-50
           3.3.5  Metal and Boiler Cleaning Wastes  	      3-52
           3.3.6  Pyrites	      3-57
           3.3.7  Sump Effluents	      3-60
      3.4  Summary	      3-62

IV.   COAL COMBUSTION WASTE MANAGEMENT PRACTICES  	       4-1

      4.1  State Regulation of Coal Combustion
             Waste Disposal	       4-1
           4.1.1  State Classification of Coal Combustion
                    Wastes	       4-2

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                                       -2-
                    TABLE  OF  CONTENTS  (cont'd)
                                                                           Page

4.1.2  Requirements for Coal Combustion Waste
          Disposal	                 4-6
4.1.3  Summary	                  4-9

      4.2  Available Waste Management Methods and
             Current Practices  	      4-10
           4.2.1  Land Management of Coal Combustion Wastes	      4-10
           4.2.2  Alternative Waste Management Technologies  	     4-24
           4.2.3  Ocean Disposal	      4-44
           4.2.4  Waste Utilization and Recovery of
                    Various Waste By-Products 	      4-45
      4.3  Summary	      4-53

V.    POTENTIAL DANGERS TO HUMAN HEALTH AND THE ENVIRONMENT 	       5-1

      5.1  RCRA Subtitle C Hazardous Waste Characteristics
             and Listing Criteria 	       5-2
           5.1.1  Corrosivity of Coal Combustion Wastes 	       5-4
           5.1.2  Extraction Procedure Toxicity of Coal
                    Combustion Wastes 	       5-5
      5.2  Effectiveness of Waste Containment at Utility
             Disposal Sites 	      5-28
           5.2.1  ADL Study of Waste Disposal at
                    Coal-Fired Power Plants 	      5-29
           5.2.2  Franklin Associates Survey of State
                    Ground-Water Data	      5-44
           5.2.3  Envirosphere Ground-Water Survey  	      5-48
           5.2.4  Summary	      5-52
      5.3  Evidence of Damage	      5-53
           5.3.1  Envirosphere Case Study Analysis  	      5-54
           5.3.2  Dames & Moore Study of Environmental
                    Impacts	      5-56
           5.3.3  Case Studies of the Environmental
                    Impact of Coal Combustion By-Product
                    Waste Disposal	'     5-63
           5.3.4  Summary	      5-67
      5.4  Factors Affecting Exposure and Risk at
             Coal Combustion Waste Sites  	      5-68
           5.4.1  Environmental Characteristics of
                    Coal Combustion Waste Sites 	      5-69
           5.4.2  Population Characteristics of Coal
                    Combustion Waste Disposal Sites 	      5-83
           5.4.3  Ecologic Characteristics of Coal
                    Combustion Waste Disposal Sites 	      5-89
           5.4.4  Multivariate Analysis 	      5-93
      5.5  Summary	      5-95

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                                       -3-
                    TABLE  OF  CONTENTS  (cont'd)


                                                                           Page

VI.   ECONOMIC COSTS AND IMPACTS	        6-1

      6.1  Waste Disposal Costs Associated With
             Current Disposal Methods 	        6-2
           6.1.1  Costs of Waste Placement and
                    Disposal  	 .....        6-5
           6.1.2  Costs Associated with Lined
                    Disposal Facilities 	       6-11
      6.2  Costs of Alternative Disposal Options  	       6-12
           6.2.1  Regulatory Alternatives Under
                    Subtitle C	       6-13
           6.2.2  Cost Estimates for Individual RCRA
                    Subtitle C Disposal Standards 	       6-17
           6.2.3  Potential Costs to the Industry of RCRA
                    Subtitle C Waste Management 	       6-30
      6.3  Impact of Regulatory Alternatives on
             Utilization of Coal Combustion Wastes  	       6-33
      6.4  Economic Impacts of Alternative Waste
             Disposal Options 	       6-37
      6.5  Summary	       6-43

VII.  CONCLUSIONS AND RECOMMENDATIONS 	        7-1

      7.1  Scope of Report	        7-1
      7.2  Summary of Report	        7-2
           7.2.1  Location and Characteristics of Coal-
                    Fired Power Plants	        7-2
           7.2.2  Waste Quantities and Characteristics  	        7-3
           7.2.3  Waste Management Practices  	        7-5
           7.2.4  Potential Hazardous Characteristics 	        7-6
           7.2.5  Evidence of Environmental Transport
                    of Potentially Hazardous Constituents 	        7-7
           7.2.6  Evidence of Damage	        7-9
           7.2.7  Potential Costs of Regulation 	        7-9
      7.3  Recommendations	       7-11

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                                       -4-
                    TABLE  OF  CONTENTS  (cont'd)
                                                                           Page
Bibliography

Glossary

Appendix A:




Appendix B:


Appendix C:


Appendix D:
Letter from Gary N. Dietrich, EPA, to Paul Emler, Jr.,
USWAG, January 13, 1981 and Memorandum from EPA
Headquarters to EPA Regional Directors, February
18, 1981

Methodology For Estimating Volume of Ash and FGD
Sludge Generation

Regulation of Coal Combustion Waste Disposal In
Seventeen High Coal-Burning States

Waste Fluid Studies
A-l


B-l


C-l

D-l
Appendix E:     Arthur D. Little Study of Waste Disposal At Coal-Fired
                Power Plants                                                E-l

Appendix F:     Data On Sample of Coal-Fired Combustion Waste Disposal
                Sites                                                       F-l

Appendix G:     Methodology For Calculating The Cost of Alternative
                Waste Management Practices                                  G-l
2923C

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                               INDEX OF EXHIBITS

                                                                          Page
CHAPTER TWO
2-1  Growth in Electricity Demand - 1975-2000 	     2-2
2-2  Electricity Sales By Year and Class of Service 	     2-4
2-3  Electricity Demand by EPA Region:  1985 	     2-5
2-4  EPA Federal Regions 	     2-6
2-5  Generating Capacity in the United States 	     2-8
2-6  Electricity Generation by Primary Energy
        Source:  1975-2000 	    2-15
2-7  Electric Utility Dependence on Coal by EPA Region:   1985 	    2-17
2-8  U.S. Coal Consumption by Sector:  1975-2000 	    2-19
2-9  Total Number and Average Size of Coal-Fired
         Plants and Units 	    2-20
2-10 Range of Coal-Fired Power Plant Sizes 	    2-22
2-11 Process For Generating Electricity at Coal-Fired
        Power Plants 	    2-23
2-12 Diagram of a Pulverized Coal Boiler 	    2-25
2-13 Diagram of a Cyclone Boiler 	    2-27
2-14 Characteristics of Various Types of Stokers 	    2-30
2-15 Diagram of a Spreader Stoker 	    2-31
2-16 Total Coal Boiler Capacity by EPA Region 	    2-32
2-17 Average Coal Boiler Size By Type of Boiler
        and By EPA Region 	    2-33
2-18 Electric Utility Production of FGD Wastes:   1985 	    2-36
CHAPTER THREE                                                               '

3-1  Representative Ash Contents By Producing
        Region and Coal Rank:  1985 	     3-9
3-2  Volume of Ash Generated by Coal-Fired Electric
        Utility Power Plants -- 1975-2000 	    3-10
3-3  Average Ash Content of Coal Burned by Electric
        Utility Power Plants in the U.S. -- 1975-2000 	    3-12
3-4  Representative Ranges of Values For the Physical
        Characteristics of Fly Ash, Bottom Ash,
        and Boiler Slag 	    3-14
3-5  Low and High Concentrations of Major Chemical
        Constituents Found in Ash Generated by
        Coal-Fired Power Plants 	    3-16
3-6  Element Concentrations In Ash From Three
        Geographic Sources 	    3-18
3-7  Effect Of Geographic Coal Source On Ash
        Element Concentration 	    3-19
3-8  Element Concentrations In Three Types Of Ash 	    3-20
3-9  Major Types of Flue Gas Desulfurization Systems 	    3-23
3-10 Flow Diagram of Wet Flue Gas Desulfurization System 	    3-25

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                               INDEX OF EXHIBITS

                                                                         Page

CHAPTER THREE (Continued)

3-11 Flow Diagram of Spray-Drying Flue Gas Desulfurization
        System 	     3-27
3-12 Flow Diagram of Dry Injection Flue Gas Desulfurization
        System 	     3-28
3-13 Flow Diagrams of Recovery Flue Gas Desulfurization Systems 	     3-30
3-14 FGD Capacity and FGD Sludge Generation -- 1970-2000 		     3-32
3-15 Representative Ranges of Values for the Physical
        Characteristics of FGD Sludge 	     3-36
3-16 Concentration of Major Chemical Constituents of Wet FGD
        Sludge Solids by Scrubber System and Source of Coal 	     3-39
3-17 Concentration of Major Chemical Constituents of Wet FGD
        Sludge Liquors by Scrubber System and Source of Coal 	     3-40
3-18 Concentration of Trace Elements Found in Wet-FGD Sludges	     3-42
3-19 Annual Low-Volume Waste Generation At a Representative
        Coal-Fired Power Plant 	     3-44
3-20 Characteristics of Boiler Slowdown 	     3-46
3-21 Characteristics of Coal Pile Runoff 	     3-48
3-22 Characteristics of Cooling Tower Slowdown 	 	     3-51
3-23 Characteristics of Spent Demineralizer
        Regenerants 	     3-53
3-24 Reported Characteristics of Gas-Side Cleaning Wastes 	     3-55
3-25 Characteristics of Spent Water-Side Alkaline
        Cleaning Wastes 	     3-56
3-26 Characteristics of Spent Water-Side Hydrochloric Acid
        Cleaning Wastes 	     3-58
3-27 Characteristics of Spent Water-Side Alkaline Passivating
        Wastes 	     3-59
3-28 Characteristics of Pyrites and Pyrite Transport Water 	     3-61
CHAPTER FOUR

4-1  State Regulations Governing Coal Combustion Waste Disposal 	      4-3
4-2  Typical Surface Impoundment (Pond)  Stages 	     4-12
4-3  Diagrams of Active and Closed Landfills 	     4-15
4-4  Utility Waste Management Facilities By EPA Region 	     4-19
4-5  Location of Utility Waste Management Facilities:
        On-site versus Off-site 	     4-21
4-6  Installation of Liners For Leachate Control at Utility
        Waste Management Facilities 	     4-31
4-7  Summary of Current Handling,  Treatment and Disposal
        of Low-Volume Wastes 	     4-39

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                               INDEX OF EXHIBITS

                                                                         Page
CHAPTER FIVE
5-1  Maximum Concentration of Contaminants For Characteristic
        of EP Toxicity	      5-6
5-2  Effect of Geographic Coal Source On Element
        Concentration In Ash 	     5-10
5-3  Results of Tetra Tech Extraction Tests On Coal Combustion Ash ..     5-12
5-4  Results of Arthur D. Little Testing Showing
        The Range of Concentration of Metals In
        EP Extracts	     5-17
5-5  EP Toxicity Analysis For Untreated and Treated Boiler
        Chemical Cleaning Wastes 	     5-21
5-6  EP Toxicity Test Results For Liquid Low-Volume Wastes 	     5-23
5-7  Comparison of EP and TCLP Extractions For Low-Volume Sludge
        Dredged From Wastewater Ponds 	     5-24
5-8  EP Toxicity Test Results of Low-Volume Wastes Before
        and After Co-Disposal 	     5-26
5-9  Primary And Secondary Drinking Water Standards 	     5-30
5-10 Summary of Arthur D. Little's Ground-Water Quality
        Data On Primary Drinking Water Exceedances 	     5-35
5-11 Summary of Arthur D. Little's Ground-Water
        Quality Data on Secondary Drinking Water
        Exceedances 	     5-37
5-12 Summary of Arthur D. Little's Surface-Water
        Quality Data On Primary Drinking Water Exceedances 	     5-40
5-13 Summary of PDWS Exceedances in the Franklin
        Associates Survey	     5-46
5-14 Summary of SOWS Exceedances in the Franklin
        Associates Survey 	     5-47
5-15 Summary of PDWS Exceedances in Envirosphere's
        Ground-water Data 	     5-50
5-16 Summary of SOWS Exceedances in Envirosphere's
        Ground-water Data 	     5-51
5-17 Distance Of Coal Combustion Waste Sites To Surface Water 	     5-72
5-18 Flow Of Nearest Surface-Water Body 	     5-74
5-19 Depth To Ground Water at Coal Combustion Waste Sites 	     5-77
5-20 Hydraulic Conductivity at Coal Combustion Waste Sites 	     5-78
5-21 Net Recharge at Coal Combustion Waste Sites 	     5-81
5-22 Ground-Water Hardness at Coal Combustion Waste Sites 	     5-82
5-23 Populations Within One Kilometer of Waste Sites 	     5-85
5-24 Populations Within Three Kilometers of Waste Sites 	     5-86
5-25 Populations Within Five Kilometers of Waste Sites 	     5-87
5-26 Populations Served By Public Water Systems Near Waste Sites ....     5-89
5-27 Ecological Status of Waste Sites 	     5-92
CHAPTER SIX

6-1  Overview of Waste Handling and Disposal Options
        for Coal Ash	      6-3

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                               INDEX OF EXHIBITS

                                                                         Page

CHAPTER SIX (Continued)

6-2  Overview of Waste Handling and Disposal Options
        for FGD Waste 	      6-4
6-3  Ranges of Average Capital Costs Associated With
        Coal-Fired Electric Utility Waste Disposal 	      6-6
6-4  Ranges of Average Total Costs For Coal-Fired
        Electric Utility Waste Disposal 	      6-7
6-5  Summary of Costs to Close Existing Waste Disposal
        Facilities 	     6-23
6-6  Summary of Costs For Different Types of Lined
        Waste Management Facilities 	     6-28
6-7  Costs to the Electric Utility Industry For Hypothetical
        RCRA Compliance Strategies 	 	     6-29
6-8  Summary of Economic Impacts on By-Product Utilization
        Under Different RCRA Regulatory Scenarios 	     6-36
6-9  Impact of Current Waste Disposal Costs on Total
        Electricity Generation Costs 	     6-39
6-10 Impact of Alternative Disposal Options on Electricity
        Generation Costs 	     6-40

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                               EXECUTIVE SUMMARY



    The Environmental Protection Agency (EPA) has prepared this report on

fossil fuel combustion wastes pursuant to the requirements of Section 8002(n)

of the Resource Conservation and Recovery Act (RCRA),  as amended in 1980.

These amendments to the Act added Section 8002(n),  which directed the

Administrator of EPA to


         conduct a detailed and comprehensive study and submit a
         report on the adverse effects on human health and the
         environment, if any, of the disposal and utilization of fly
         ash waste, bottom ash waste, slag waste, flue gas emission
         control waste, and other by-product materials generated
         primarily from the combustion of coal or other fossil fuels.


    Pending the completion of this study,  fossil fuel combustion wastes were

exempted from the hazardous waste requirements established under RCRA.  Under

Section 3001(b)(3)(A),  EPA is prohibited from regulating these wastes until at

least six months after this report is submitted to Congress.



    If EPA determines that fossil fuel combustion wastes are hazardous under

RCRA, and therefore subject to regulation under Subtitle C, EPA has some

flexibility to promulgate regulations that take into account the unique

characteristics of these wastes.   Section 3004(x) states ...
         If ... fly ash waste, bottom ash waste, slag waste and flue
         gas emission control waste generated primarily from the
         combustion of coal or other fossil fuels ... is subject to
         regulation under this subtitle, the Administrator is
         authorized to modify the requirements of subsections (c),
         (d),  (e), (f), (g), (o) and (u) and section 3005(j) ... to
         take  into account the special characteristics of such wastes,
         the practical difficulties associated with implementation of
         such requirements, and site-specific characteristics ... so
         long as such modified requirements assure protection of human
         health and the environment.

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                                     ES-2
    This report examines only those wastes generated from the combustion of coal




by the electric utility industry.  These wastes account for approximately 90




percent of all wastes generated from the combustion of fossil fuels.  EPA has




deferred study of the disposal of wastes generated by the combustion of other




fossil fuels and from coal combustion in industries other than the electric




utility industry until a later date.









    Coal-fired power plants produce substantial quantities of wastes.  In 1984




about 69 million tons of ash and 16 million tons of flue gas desulfurization




wastes were generated.  Because of increasing reliance on coal for producing




electricity, by the year 2000 the amount of ash waste is expected to increase by




about 75 percent to about 120 million tons annually; production of FGD wastes is




expected to triple to about 50 million tons annually.   In addition to the




high-volume ash and flue gas desulfurization wastes, coal-fired power plants




also generate several lower-volume waste streams as a result of equipment




maintenance and cleaning activities.









    About one-fifth of all waste generated at coal-fired electric utility power




plants is currently reused; the remaining four-fifths are typically disposed in




surface impoundments or landfills.  The recycled wastes,  usually fly ash, bottom




ash, or boiler slag, have been used primarily as cement additives, high-volume




road construction material, and blasting grit.  There is some potential for




increased use of these wastes in such applications.  However, barring the
     •*• It is possible that advances in coal combustion technology will alter




the amount and types of coal-combustion wastes produced in the future.  An




analysis of these technological advances is beyond the scope of this report.

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                                     ES-3
development of new utilization techniques, or major changes in combustion and




environmental control technologies, the proportion of coal combustion wastes




that are reused is unlikely to change significantly.









    While utility waste management sites are currently exempt from RCRA




hazardous waste requirements, they are subject to state and local level solid




waste laws and regulations.  There is substantial variation in the




state-mandated disposal requirements.









    Most utility waste management facilities were not designed to provide a high




level of protection against leaching.  Only about 25 percent of all facilities




have liners to reduce off-site migration of leachate, although 40 percent of the




generating units built since 1975 have liners.  Additionally, only about 15




percent have leachate collection systems; about one-third of all facilities have




ground-water monitoring systems to detect potential leachate problems.   Both1




leachate collection and ground-water monitoring systems are more common at newer




facilities.









    The primary concern regarding the disposal of wastes from coal-fired power




plants is the potential for waste leachate to cause ground-water contamination.




Although most of the materials found in these wastes do not cause much concern




(for example, over 95 percent of ash is composed of oxides of silicon,  aluminum,




iron, and calcium), small quantities of other constituents that could




potentially damage human health and the environment may also be present.  These




constituents include arsenic, barium, cadmium, chromium, lead,  mercury,  and




selenium.  At certain concentrations, these elements have toxic effects.

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                                     ES-4
    To assess the potential threat to health and the environment posed by these




wastes and to document any specific damage cases, EPA, other agencies, and




various private organizations sponsored several studies.  The main research




efforts cited in this Report to Congress are a 1985 study by Arthur D. Little,




Inc. for EPA, which characterized the environmental effects of waste disposal at




several utility disposal sites, and a series of reports submitted to the Agency




in 1982 by the Utility Solid Waste Activities Group, the Edison Electric




Institute, and the National Rural Electric Cooperative Association.









    The findings of these various research efforts indicate that most coal




combustion wastes do not exhibit any of the four hazardous characteristics




defined in RCRA Subpart C.  The results of a substantial number of extraction




procedure tests were examined;  these tests indicated that metals do not




generally leach out of coal combustion wastes at levels classified as hazardous




under RCRA.  The only metals which were found in any ash or sludge samples at




"hazardous" levels were cadmium and arsenic.   For boiler cleaning wastes,




chromium and lead were sometimes found at levels classified as hazardous under




RCRA.  This waste stream was also found to be corrosive in a number of samples.




Results of EP Tests performed on co-disposed high and low volume wastes




indicate, however, that boiler cleaning wastes do not exhibit hazardous




characteristics when co-disposed with ash.









    While most of the laboratory results indicated that coal combustion wastes




do not possess RCRA hazardous characteristics, in some instances,  data on actual




field observations indicate that migration of potentially hazardous constituents




from utility waste disposal sites has occurred.   For example,  observed

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                                     ES-5
concentrations of contaminants found in ground water downgradient from the sites




exceed the Primary Drinking Water Standards about 5 percent of the time.




Although the magnitude of the PDWS exceedances are typically not many times




greater than the standard, a large number of disposal facilities report at least




one PDWS exceedance at some time.









    While a causal connection cannot always be made between the utility waste




disposal site and the presence of contaminants at concentrations in excess of




these standards, the available information indicates that some ground-water




contamination from utility disposal sites is indeed occurring.  The actual




potential for exposure of human and ecological populations is likely to be




limited, however, since ground water in the vicinity of utility waste disposal




sites is not typically used for drinking water; the concentrations of




contaminants in the ground water also tend to be diluted in nearby surface water




bodies.  These surface water bodies are typically used by electric utilities in




the power plants for cooling and other purposes.









    The electric utility industry currently spends about $800 million annually




to dispose of its coal-fired combustion wastes.  Under current practices,  costs




for waste management at most basic facilities range from as little as $2 per ton




to as much as $31 per ton.  Mitigative measures to control potential




leaching include installation of liners, leachate collection systems, and




ground-water monitoring systems and corrective action to clean up ground-water




contamination.  These mitigative measures, which are currently used at some




utility waste disposal sites,  may reduce the likelihood of ground-water




contamination, but may also substantially increase disposal costs.  For example,

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                                     ES-6
the incremental cost of new waste disposal practices, excluding corrective




action costs or higher recycling costs, could range up to $70 per ton, or $3.7




billion annually if all wastes were listed as hazardous.  While substantial on a




total cost basis, these increases would be unlikely to significantly affect the




rate at which existing power plants consume coal.  Due to the competitiveness of




alternative fuels for electricity generation at future power plants, however,




any increase in disposal costs could potentially slow the growth in electric




utility coal consumption in future years.  Moreover, if new disposal standards




require corrective action measures as set forth in 40 CFR 264.100,  the costs to




utilities could be extremely high and could have a substantial effect on the




utility industry.









    Based on the findings from this Report to Congress,  the Agency presents




three preliminary recommendations for those wastes included in the scope of this




study.   The recommendations are subject to change based on continuing




consultations with other government agencies and new information submitted




through the public hearings and comments on this report.  Pursuant to the




process outlined in RCRA 3001(b)(3)(C), EPA will announce its regulatory




determination within six months after submitting this report to Congress.









    First. EPA has concluded that coal combustion waste streams generally do not




exhibit hazardous characteristics under current RCRA regulations.   EPA does not




intend to regulate under Subtitle C fly ash, bottom ash, boiler slag, and flue




gas desulfurization wastes.  EPA's tentative conclusion is that current waste




management practices appear to be adequate for protecting human health and the




environment.  The Agency prefers that these wastes remain under Subtitle D

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                                     ES-7
authority.  EPA will use section 7003 of RCRA and sections 104 and 106 of CERCLA




to seek relief in any cases where wastes from coal combustion waste disposal




sites pose substantial threats or imminent hazards to human health and the




environment.  Coal combustion waste problems can also be addressed under RCRA




Section 7002, which authorizes citizen lawsuits for violations of Subtitle D




requirements in 40 CFR Part 257.









    Second. EPA is concerned that several other wastes from coal-fired utilities




may exhibit the hazardous characteristics of corrosivitv or EP toxicity and




merit regulation under Subtitle C.   EPA intends to consider whether these waste




streams should be regulated under Subtitle C of RCRA based on further study and




information obtained during the public comment period.  The waste streams of




most concern appear to be those produced during equipment maintenance and water




purification, such as metal and boiler cleaning wastes.   The information




available to the Agency at this time does not allow EPA to determine the exact




quantity of coal combustion wastes that may exhibit RCRA Subtitle C




characteristics.  However, sufficient information does exist to indicate that




some equipment maintenance and water purification wastes do occasionally exhibit




RCRA hazardous characteristics, and therefore,  may pose  a danger to human health




and the environment.  These wastes are similar to wastes produced by other




industries that are subject to Subtitle C regulation,  and waste management




practices for coal combustion wastes are often similar to waste management




practices employed by other industries.  EPA is considering removing the




exemption for all coal-fired utility wastes other than those identified in the




first recommendation.  The effect would be to apply Subtitle C regulation to any




of those wastes that are hazardous by the RCRA characteristic tests.  EPA

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                                     ES-8
believes there are various treatment options available for these wastes that




would render them nonhazardous without major costs or disruptions to the




utilities.









    Third. EPA encourages the utilization of coal combustion wastes as one




method for reducing the amount of these wastes that need to be disposed to the




extent such utilization can be done in an environmentally safe manner.  From the




information available to the Agency at this time, current waste utilization




practices appear to be done in an environmentally safe manner.  The Agency




supports voluntary efforts by industry to investigate additional possibilities




for utilizing coal combustion wastes.









    Through its own analysis, evaluation of public comments,  and consultation




with other agencies, the Agency will reach a regulatory determination within six




months of submission of this Report to Congress.  In so doing, it will consider




and evaluate a broad range of management control options consistent with




protecting human health and the environment.  Moreover, if the Agency determines




that Subtitle C regulation is warranted, in accordance with Section 3004(x) EPA




will take into account the "special characteristics of such waste, the practical




difficulties associated with implementation of such requirements, and




site-specific characteristics . .  .," and will comply with the requirements of




Executive Orders 12291 and 12498 and the Regulatory Flexibility Act.

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                                  CHAPTER ONE




                                  INTRODUCTION









    This is the Environmental Protection Agency's Report to Congress on wastes




from fossil fuel combustion, as required by section 8002(n) of the Resource




Conservation and Recovery Act.  It describes sources and quantities of utility




waste, current utilization and disposal practices and alternatives to these




practices, potential dangers to human health and the environment, and the costs




of current and alternative waste management practices.  This report is based on




numerous literature reviews and contractor studies; EPA's RCRA Docket contains




copies of the source materials that the Agency used in preparing this report.









1.1  Legislative History









    Because Congress has amended the Resource Conservation and Recovery Act  >




several times and EPA's regulatory program continues to evolve in response to




these Congressional mandates and other additional information, a brief




legislative and regulatory history is provided below.









    The Resource Conservation and Recovery Act (RCRA, or the Act) of 1976




(Public Law 94-580) substantially amended the Solid Waste Disposal Act of 1965




and authorized the U.S. Environmental Protection Agency (EPA) to establish and




enforce regulations concerning the identification, generation, transportation,




and management of hazardous waste.   These regulations would accomplish the




Act's objectives of "...promote[ing] the protection of health and the




environment ... and conserve[ing] valuable material and energy resources...."^-




RCRA comprises several subtitles, including Subtitle C-- Hazardous Waste

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                                      1-2


Management, and Subtitle D-- State or Regional Solid Waste Plans.  The intent

of the regulations promulgated under Subtitle C of the Act is that wastes

identified as hazardous be properly managed from "cradle to grave," that is,

from the time they are generated, during transport, throughout their use in

various applications, and during disposal.  As provided under RCRA Subtitle D,

other wastes not considered hazardous as defined under Subtitle C are subject

to State regulations.



    On December 18, 1978, EPA proposed the first regulations to implement

Subtitle C.  In the course of preparing these regulations, EPA recognized that

certain very large-volume wastes (e.g., wastes generated by utility power

plants) could require special treatment:
          ...  The Agency has very little information on the
          composition, characteristics, and the degree of hazard
          posed by these wastes, nor does the Agency yet have data on
          the effectiveness of current or potential waste management
          technologies or the technical or economic practicability of
          imposing the Subpart D standards [current RCRA section
          3004--Standards applicable to owners and operators of
          hazardous waste treatment, storage, and disposal
          facilities] on facilities managing such waste.

          The limited information the Agency does have indicates that
          such waste occurs in very large volumes, that the potential
          hazards posed by the waste are relatively low, and that the
          waste generally is not amenable to the control techniques
          developed in Subpart D.^


    Thus, the Agency proposed a limited set of regulations for managing

large-volume wastes, pending an additional rulemaking.  Until that rulemaking

was completed, EPA proposed exempting utility wastes from storage and disposal

regulations.

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                                      1-3


    On May 19, 1980, EPA promulgated the first regulations implementing

Subtitle C of RCRA.  By then, Congress was debating RCRA reauthorization,  and

both Houses had passed bills restricting EPA's ability to regulate utility

wastes.  Anticipating the enactment of legislation amending RCRA Section 3001,

EPA excluded utility wastes from the promulgated regulations,  writing in the

preamble:



          The United States Senate and House of Representatives have
          each recently passed a bill to reauthorize and amend RCRA
          (S.1156 and H.R.3994).  Both bills contain amendments to
          Section 3001 which, if enacted, would repeal or temporarily
          suspend EPA's authority to regulate certain utility and
          energy development wastes as hazardous wastes under
          Subtitle C.  These bills are now awaiting action by a
          conference committee.  Because it appears likely that
          Congress will act before November 19, 1980 [the end of the
          six month comment period on the promulgated interim final
          regulations and the date on which they would take effect]
          to exempt these wastes, EPA has temporarily excluded them
          from this regulation (see section 261.4(b)).   This
          exclusion will be revised, if necessary, to conform to the
          legislation which is ultimately enacted.-^


    In fact, Congress did act before November 19, 1980; the Solid Waste

Disposal Act Amendments (Public Law 96-482) were passed in October 1980.



    As anticipated, the amendments temporarily exempted from regulation fly ash

waste, bottom ash waste, boiler slag waste, and flue gas emission control waste

generated primarily from the combustion of coal or other fossil fuels.   In

section 8002(n), Congress directed EPA to produce a report on the kinds of

waste generated by the combustion of coal and other fossil fuels, which would

include an analysis of eight topics:


    1.    the source and volumes of such material generated
          per year;

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                                      1-4
    2.    present disposal and utilization practices;
    3.    potential danger, if any, to human health and the
          environment from the disposal and reuse of such material;
    4.    documented cases in which danger to human health or the
          environment from surface runoff or leachate has been
          proved;
    5.     alternatives to current disposal methods;


    6.     the costs of such alternatives;
    7.     the impact of those alternatives on the use of coal and
          other natural resources;  and
    8.     the current and potential utilization of such
          materials. ^
    Finally, in section 3001(b)(3)(C),  Congress directed that within six months

after submitting this report, EPA must conduct public hearings and decide

whether regulating the management of coal combustion wastes under Subtitle C is

warranted.  Once the decision is made,  the Administrator must publish the

Agency's regulatory determination in the Federal Register.



    In a January 1981 letter,-' Gary Dietrich, then Associate Deputy Assistant

Administrator for Solid Waste, provided an interpretation of RCRA regulations

concerning the exemption from regulation of fossil fuel combustion waste.

(This letter, as well as a February 18, 1981 memorandum that enclosed it as

part of a mailing to EPA Regional Directors, is included as Appendix A.)  The

letter noted that the beneficial use of hazardous waste as a fuel was not

subject to regulation, though it might well be subject to regulation in the

future.  This meant that utilities could burn as fuel a combination of

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                                      1-5


hazardous waste and coal, as long as more than 50 percent of the mixture was

comprised of coal.  The letter also addressed disposal, noting that wastes

produced in conjunction with the burning of fossil fuels (e.g., cleaning and

other maintenance-related wastes) may be exempt from Subtitle C regulations

provided they are mixed and co-disposed or co-treated with fossil fuel wastes

and provided "there is no evidence of any substantial environmental danger from

these mixtures."'  The letter concluded:
          ...Pending the completion of [further study on the hazards
          posed by waste from coal-fired utility plants and the
          collection of relevant data from the utility industry],  EPA
          will interpret 40 CFR 261.4(b)(4) to mean that the
          following solid wastes are not hazardous wastes:

                (a)  Fly ash, bottom ash, boiler slag, and
                     flue gas emission control wastes
                     resulting from (1) the combustion
                     solely of coal, oil, or natural gas,
                     (2) the combustion of any mixture of
                     these fossil fuels,  or (3) the
                     combustion of any mixture of coal and
                     other fuels, where coal makes up more
                     than 50 percent of the mixture.

                (b)  Wastes produced in conjunction with
                     the combustion of fossil fuels, which
                     are necessarily associated with the
                     production of energy, and which
                     traditionally have been, and which
                     actually are,  mixed with and
                     co-disposed or co-treated with fly
                     ash, bottom ash,  boiler slag, or flue
                     gas emission control wastes from coal
                     combustion.
This provision includes,  but is not limited to,  boiler cleaning solutions,

boiler blowdown, demineralizer reagent,  pyrites, and cooling tower blowdown.



    In November 1984,  Congress reauthorized RCRA by passing the Hazardous  and

Solid Waste Amendments (HSWA).   These amendments restricted the land disposal

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                                      1-6


of certain hazardous wastes without treatment, established minimum technology

requirements for landfills and surface impoundments,  issued corrective action

requirements for continuing releases at permitted facilities,  and established

interim status requirements for surface impoundments.   Under this new

legislation, EPA was granted some flexibility to promulgate regulations that

take into consideration the unique characteristics of several types of

large-volume wastes, including wastes generated by utility power plants.

Specifically, if EPA determined that some or all of the wastes from fossil fuel

combustion were subject to regulation under Subtitle  C, EPA was empowered to

modify the standards imposed by HSWA "...to take into account the special

characteristics of such wastes, the practical difficulties associated with

implementation of such requirements, and site-specific characteristics ... so

long as such modified requirements assure protection  of human health and the
             o
environment."0



    The HSWA Conference Report accompanying H.R. 2867 (which in its final

amended form was passed by both Houses of Congress as Public Law 98-616)

provides clarification:
          This Amendment recognizes that even if some of the special
          study wastes [which include utility wastes as specified in
          Section 8002(n)]  are determined to be hazardous it may not
          be necessary or appropriate because of their special
          characteristics and other factors, to subject such waste to
          the same requirements that are applicable to other
          hazardous wastes,  and that protection of human health and
          the environment does not necessarily imply the uniform
          application of requirements developed for disposal of other
          hazardous wastes.   The authority delegated to the
          Administrator under this section is both waste-specific and
          requirement-specific.  The Administrator could also
          exercise the authority to modify requirements for different
          classes of wastes.   Should these wastes become subject to
          the requirements  of Section 3005(j),  relating to the
          retrofit of surface impoundments, the Administrator could

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                                      1-7
          modify such requirements so that they are not identical to
          the requirements that are applied to new surface
          impoundments containing such wastes.  It is expected that
          before any of these wastes become subject to regulation
          under Subtitle C, the Administrator will determine whether
          the requirements of Section 3004(c), (d),  (e),  (f), (g) ,
          (o),  and (u),  and Section 3005(j) should be modified."
1.2. Scope and Sources
    This report addresses only the wastes generated by coal-fired electric

utility power plants.  Because this industry generates the vast majority of all

fossil fuel combustion waste (nearly 90 percent),    EPA decided to focus its

study in this area.  This study does not address oil- and gas-fired electric

utility power plants or coal, oil and gas-fired industrial boilers.
    A number of research projects were undertaken to provide data for this

report.  EPA sponsored a major study of current coal ash and flue gas

desulfurization waste management practices at coal-fired electric utility power

plants.    In this study comprehensive environmental monitoring was conducted1,

which included characterizing the wastes, soils, ground water, and surface

water at six disposal sites.  The contractor (Arthur D. Little, Inc.) evaluated

the environmental effects of the disposal practices used at these six sites

and, by inference, what effects may be present at other utility waste disposal

sites.  They also performed extensive engineering and cost evaluations of

disposal practices at the six sites.



    EPA also sponsored a separate study effort to develop information on the

incidences of ground water contamination resulting from utility waste

                     12
management practices.    In this study, contamination was defined as the

presence of hazardous constituents at levels above primary drinking water

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                                      1-8





standards.  The main source of information for this phase of the research was a



review of case files at the state offices having responsibility for such



matters.







    In addition, the Agency also reviewed reports submitted by the Utility



Solid Waste Activities Group (USWAG),  the Edison Electric Institute (EEI), and


                                                            13
the National Rural Electric Cooperative Association (NRECA).     The reports



present information on the sources, volumes, and physical and chemical



characteristics of waste streams; ground-water monitoring results assembled



from various utility plants; damage case information from various sources;



costs of complying with hazardous waste regulations; and resource recovery



opportunities using utility wastes.







    EPA also has incorporated findings from several documents prepared by the


                                                                            14
Department of Energy (DOE) and the Electric Power Research Institute (EPRI).



These reports examined the chemical composition of utility wastes, technologies



for disposal and the costs associated with disposal, as well as results of



leaching tests performed on utility wastes.







    Finally, EPA gathered information from the Utility Data Institute's Power



Statistics Database.    This database contains information concerning the size



of utility power plants,  location of power plants,  the types of disposal



technologies employed by each power plant, and the amount of waste produced by



site and by region.  The information on location of power plants was combined



with hydrogeologic, population, and ecological profiles of these locations to



analyze the potential for exposure to coal combustion wastes.

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                                      1-9






1.3  Organization









    The following chapters of this report address the eight issues (enumerated




earlier in this chapter) as required by Section 8002(n) as they apply to




coal-fired combustion wastes generated by electric utilities.  Chapter Two of




this report provides an overview of the U.S. electric utility industry.




Chapter Three examines the amount and types of wastes that are generated.




Chapter Four discusses current waste management and disposal practices used by




the electric utility industry, as well as alternatives to these practices; a




review of applicable State regulations is included in this chapter.   Chapter




Five reviews the potential and documented impact of these wastes on human




health and the environment, and Chapter Six evaluates costs associated with




current waste disposal practices' and additional costs that could be incurred




under a variety of alternative waste management practices.  Finally, Chapter




Seven summarizes the conclusions contained in the previous chapters and




presents recommendations.

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                                      1-10


                                  CHAPTER ONE

                                     NOTES


    1  Resource Conservation and Recovery Act of 1976 (RCRA),  Section 1003(a).

    2  Federal Register. Volume 43, No. 243, December 18, 1978, pp.
58991-58992.

    3  Federal Register. Volume 45, No. 98, May 19, 1980, p. 33089.

    4  RCRA, Section 8002(n).

    5  Letter of January 13, 1981, from Gary N. Dietrich, Associate Deputy
Assistant Administrator for Solid Waste, to Paul Elmer,  Jr., Chairman of the
Utility Solid Waste Activities Group.

    6  See 40 CFR 261.4.

    7  Gary N. Dietrich, January 13, 1981, op. cit.:  for further information,
see Congressional Record, February 20, 1980, p. H 1102,  remarks of Congressman
Bevill; also see remarks of Congressional Record, February 20, 1980, p.  H 1104,
remarks of Congressman Rahall.

    8  RCRA, Section 3004(x)

    9  H.R. Report 98-1133, pp. 93-94, October 3, 1984.

        Most fossil fuel combustion wastes are generated from coal.  For
example,  as indicated in Physical-Chemical Characteristics of Utility Solid
Wastes (by Tetratech, Inc. for EPRI, September 1983), only about one percent of
utility wastes are generated from oil; the remaining 99 percent is largely
attributable to coal-fired electricity production.  Of the coal consumed in the
U.S., electric utilities burn nearly 90 percent (excluding metallurgical coal,
which is not burned but is instead converted into coke primarily for making
steel).

        Arthur D. Little, Inc.,  Full-Scale Field Evaluation of Waste Disposal
From Coal-Fired Electric Generating Plants.  Prepared for EPA's Office of
Research and Development, EPA Contract #68-02-3167; June 1985.

    12
        Franklin Associates, Ltd.,  Survey of Groundwater Contamination Cases
at Coal Combustion Waste Disposal Sites, prepared for U.S. Environmental
Protection Agency, March 1984.

    13
        USWAG is an informal consortium of approximately 65 electric utility
operating companies, EEI, and NRECA.  The primary source used in the
preparation of this report was Report and Technical Studies On The Disposal and
Utilization of Fossil-Fuel Combustion Bv-Products. USWAG, EEI, and NRECA,
October 26, 1982.

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                                      1-11


    14
        For example,  see Impacts of Proposed RCRA Regulations and Other Related
Federal Environmental Regulations on Utility Fossil Fuel-Fired Facilities:
Prepared by Engineering-Science for DOE, DOE Contract Number
DE-AC-01-79ET-13543,  May 1983; Physical-Chemical Characteristics of Utility
Solid Wastes. EPRI, September 1983; Analytical Aspects of the Fossil Energy
Waste Sampling and Characterization Project. Prepared by Western Research
Institute, DOE Order Number DE-AP20-84LC00022, March 1984; and Environmental
Settings and Solid Residues Disposal in the Electric Utility Industry.  EPRI,
July 1984.  More sources are included in the Bibliography.

        Utility Data Institute's Power Statistics Database was developed under
the auspices of the Edison Electric Institute to assist in their analysis of
issues affecting the electric utility industry.

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                                 CHAPTER TWO


                  OVERVIEW OF THE ELECTRIC UTILITY INDUSTRY





    This chapter provides a general overview of the U.S. electric utility


industry.  Section 2.1 summarizes electricity demand and discusses the overall


structure of the electric utility industry.  Section 2.2 focuses the


discussion on the role that coal plays in generating electricity.  Section 2.3


provides details of coal-fired electric generating technologies and the


regional characteristics of coal-fired plants.  The chapter concludes with a


discussion in Section 2.4 of the waste streams that are produced during coal


combustion.





2.1  THE DEMAND FOR ELECTRICITY





    The generation, transmission, and distribution of electricity is one of
                                                                            l

our nation's largest industries.  With annual revenues in excess of $140


billion and assets of about $500 billion, the electric utility industry


provides vital services to nearly every person in the U.S.





    Total demand for electricity in the U.S. has increased substantially in


recent decades and will likely continue to grow in coming years (see Exhibit


2-1).  From the 1940's through the early 1970's, electricity demand grew at


about 7 percent per year, doubling approximately every ten years.  This growth


slowed beginning with the 1973 OPEC oil embargo and subsequent changes in the


energy markets such as fuel price increases, shifts in the economy to markets


that require less electricity to meet their power needs, and energy


conservation measures.  Since 1973, growth in electricity demand has averaged

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                                         2-2
                                    EXHIBIT 2-1

                     GROWTH  IN  ELECTRICITY DEMAND  -  1975-2000
               4000-
               3600-

               3200-

               2800-


  Electricity    240°-
    Sales
  (billions of   200°-
kilowatthours)
               1600-

               1200-

               800-

               400-
                  1975
1980
1985
1990
1995
2000
                                                           Forecast
                                               Year
    Sources:     1975-1985:   Energy Information Administration,  Electric Power
                Monthly.  DOE/EIA-0226 (85/12), December 1985, p.  39.

                1985-2000:   ICF Incorporated,  Analysis  of 6 and 8 Million ton and
                30 Year/NSPS and 30 Year/1.2 Ib.  Sulfur Dioxide Emission Reduction
                Cases,  Prepared for Environmental Protection Agency,  February 1986.

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                                     2-3




about three percent per year.  Expectations are that electricity demand will


continue to grow at an average rate of about 2 to 3 percent per year over the

                   f\
next several years. *•





    Every major segment of the U.S. economy relies on electricity to meet a


portion of its energy needs.  As shown in Exhibit 2-2, the demand for


electricity is divided almost evenly between the industrial, commercial, and


residential sectors.  This demand for electricity has continued to increase


over the last decade with total sales increasing from 1.7 million gigawatt-


hours (Gwh) in 1975  to 2.3 million Gwh in 1985.3  As demand has increased,


electricity sales patterns have remained relatively consistent.  Industry


continues to be the  largest consuming sector, although industry's fraction of


total sales has decreased by about 2.7 percent from 1975 to 1985, primarily


due to an increased market share for the commercial sector (i.e., stores,


office buildings, restaurants, etc.).  Residential customers consume about


one-third of all electricity for basic necessities such as lighting, heating,


and electrical appliances.





    Virtually every geographic area in the U.S. relies on electricity supplied


by the electric utility industry.  As shown in Exhibit 2-3, electricity demand


is highest in the eastern half of the U.S., particularly in EPA Regions 3-6


(see Exhibit 2-4 for a map of these EPA Regions).  This level of demand is not


surprising considering that these areas are the most heavily industrialized


and densely populated areas of the country.

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                                        2-4
                                   EXHIBIT 2-2

                  ELECTRICITY SALES BY YEAR AND CLASS OF  SERVICE
                                 (gigawatt-hours)
  '   1975 SALES
Total Sales = 1.733,024 kWh
     1980 SALES
Total Sales = 2,126,094 kWh
                                                                 1984 SALES
                                                                                 Other
                                                            Total Sales = 2.285,532 kWh
    Source:  Edison  Electric  Institute, Statistical Yearbook of the Electric
            Utility Industry/1985, December  1986.
         ^Includes  street  lighting, other public authorities, railroads and
    interdepartmental  transfers within utilities (i.e., use of electricity by the
    utility itself).

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                                    2-5
                               EXHIBIT 2-3

                    ELECTRICITY DEMAND  by EPA REGION
                                  1985
                             Millions of         Percent
            EPA Region       Kilowatt Hours       of Total

                 1               86,397             3.8
                 2              164,780             7.2
                 3              230,055            10.1
                 4              483,248            21.2  .
                 5              428,873            18.8
                 6              340,198            14.8
                 7              112,076             4.9
                 8               72,458             3.2
                 9              227,006            10.0
               10              135,716             6.0
         Total  U.S.           2,280,585           100.0
Source:   Edison  Electric Institute, Statistical Yearbook of the Electric
         Utility Industry/1985, December 1986.

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    EXHIBIT  2-4


EPA FEDERAL REGIONS
                                                         Philadelphia
                                                        Washintlon D.C.

                                                      a.
                                                                     to
                                                                      I
                                                                     ON

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                                     2-7






    2.1.1  Structure of the U.S. Electric Utility Industry








    The U.S. electric power industry is a combination of private, Federal, and




public nonprofit organizations.  The distribution•of capacity, generation,




revenue, and sales differs widely among these ownership groups since each




group has different obj ectives, organizational characteristics,  and financing




methods.  Private investor-owned utilities dominate the U.S. electric utility




industry as shown in Exhibit 2-5.  Investor-owned utilities have historically




served large consolidated markets to take advantage of economies of scale.




Federal, municipal, cooperative, and other publicly-owned utilities have




generally served smaller markets where local governments or nonprofit




organizations have had access to limited supplies of less expensive Federal




power or to government-supplied capital for power plant construction.  These




circumstances have allowed municipal, cooperative,  or other publicly-owned




utilities to predominate in areas not traditionally served by investor-owned




utilities.   A brief discussion of each type of organization is  provided




below.








    2.1.1.1  Investor-Owned Utilities








    Investor-owned utilities account for about three-quarters of all U.S.




electric utility generating capacity, generation, sales, and revenue.




Investor-owned utilities are privately owned, profit-oriented businesses




granted service monopolies in certain geographic areas.  As franchised




monopolies, they are obligated to provide service to all customers within




their geographic area.  In providing this service,  investor-owned utilities




are required to charge reasonable prices, to charge similar prices to similar

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                                      2-8
                                 EXHIBIT 2-5

                 GENERATING  CAPACITY IN THE UNITED STATES
    Kilowatts ^Millions)
                                                          Government and
                                                           Cooperatives
                                                                                100
                                                                                50
    65   66  67  68   69  70  71  72   73  74  75   76  77  78   79   80  81  82  83  84  85
Source: Edison Electric Institute, Statistical Yearbook  for  the Electric
        Utility Industry/1985, December 1986.

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                                     2-9





customers, and to give customers access to services under similar conditions.^



Investor-owned utilities operate in all states except Nebraska (which depends



primarily on public power districts and rural electric cooperatives for



electricity).  In 1984, consumers paid an average of 6.5 cents per



kilowatt-hour (kwh) for privately-produced power compared to the industry



average from all ownership groups of 6.3 cents per kilowatt-hour (an average



customer consumed 23,150 kwh in 1984).6







    2.1.1.2  Federal Power







    The U.S. Government is the second largest producer of electricity in the



United States with roughly 10 percent of total U.S. generation and generating



capacity.  Consumers of Federal- power paid the lowest rate among the different



ownership groups -- only 3.5 cents per kwh on average in 1984, (compared to an



industry average of 6.3 cents per kwh).^  Federal power production is designed



to provide power at the lowest possible rate, with preference in the sale of



electricity given to public entities and cooperatives."  In this role the



Federal Government is primarily a generator and wholesaler of electricity to



other organizations, rather than a direct distributor to electricity


          o
consumers.?







    2.1.1.3  Municipal Utilities







    Municipal utilities are nonprofit local government agencies designed to



serve their customers at the lowest possible cost.  Most municipal utilities



simply distribute power obtained from one of the other ownership groups (e.g.,



Federal facilities), although some larger ones also generate and transmit

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                                     2-10
power.  Municipally-owned electric utilities rank third in the amount of



installed capacity (5.5 percent of total generating capacity), but comprise



the single most numerous ownership group (1,811 utilities in 1984).    Average



revenue per kwh sold in 1984 was 5.69 cents compared to an industry average of



6.3 cents per kwh.  Municipal utilities are exempt from local, state, and



Federal taxes and have access to less expensive capital via public financing



and less expensive Federal power.  As a result, municipal utilities can



generally afford to charge less than investor-owned utilities for the power



they produce.
    2.1.1.4  Cooperatives








    Rural electric cooperatives are owned by and provide electricity to their



members and currently operate in 46 states.   They have the lowest amount of



installed capacity among all ownership categories (24.7 gigawatts in 1984 or


                                     12
less than 4 percent of all capacity).








    In 1984, average revenue for cooperatives from sales to consumers was 6.7



cents per kwh, the highest of all ownership types (the industry average was



6.3 cents per kwh).  Large construction programs in the 1970's usually account


                   13
for the high rates.








    2.1.1.5  Other Public Entities








    There are a variety of other public organizations that provide electric



power, including public power districts, state authorities, irrigation



districts, and various other State organizations.  These other public entities

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                                     2-11
operated a combined total of 32.8 gigawatts in 1984, or about 5 percent of all


                               14
generating capacity in the U.S.    The public power districts are concentrated



in five states -- Nebraska, Washington, Oregon, Arizona, and California.  The



average price paid for electricity from all of these entities was 4.37 cents



per kwh in 1984, compared to an industry average of 6.3 cents per kwh.
     2.1.2  Economic and Environmental Regulation of the Electric Utility

              Industry





    The electric utility industry is regulated by several different regulatory



bodies at both the Federal and State levels.  According to the U.S. Department



of Energy:  "The basic purpose of public utility regulation is to assure



adequate service to all public utility patrons, without discrimination and at



the lowest reasonable rates consistent with the interests both of the public



and the electric utilities."    This regulation involves both economic and



environmental objectives.   As natural monopolies, electric utilities are



regulated to ensure that adequate,  reliable supplies of electric power are



available to the public at a reasonable cost.  Additionally, since the



operations of electric utilities can affect environmental quality, they are



regulated to ensure the protection of the nation's air and water resources.



This section briefly reviews the main regulatory bodies that affect the



electric utility industry.







    2.1.2.1  Federal Regulation







    There are five major organizations at the Federal level that regulate some



aspect of the electric utility industry -- the Federal Energy Regulatory



Commission (FERC),  the Economic Regulatory Administration (ERA),  the

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                                     2-12


Securities and Exchange Commission (SEC), the Nuclear Regulatory Commission

(NRC), and the Environmental Protection Agency (EPA).
    •    The Federal Energy Regulatory Commission (FERC) oversees
         various aspects of the electric utility, natural gas,
         hydroelectric, and oil pipeline industries. FERC approves
         the rates and standards for wholesale interstate electricity
         sales between investor-owned utilities and other
         investor-owned utilities, municipals, or cooperatives (these
         sales are about 15 percent of total U.S. electricity
         sales).    It determines whether these rates are reasonable
         and non-discriminatory.  FERC also oversees utility mergers
         and the issuance of certain stock and debt securities,
         approves the rates of Federal Power Marketing
         Administrations, and administers agreements between
         utilities concerning electricity transmission.

    •    The Economic Regulatory Administration (ERA) has several
         responsibilities, including administering a program to
         ensure that all future power plants have the potential to
         burn coal, regulating international electricity transmission
         connections, and licensing exports of power.

    •    The Securities and Exchange Commission (SEC) is an
         independent regulatory agency established to regulate
         interstate transactions in corporate securities and stock
         exchanges.  With respect to the electric utility industry,
         the SEC regulates the purchase and sale of securities,
         utility properties, and other assets.

    •    The Nuclear Regulatory Commission (NRC) is involved only in
         the regulation of nuclear facilities owned and operated by
         the utility industry.  Its main responsibilities include
         licensing the construction and operation of nuclear
         facilities, licensing the possession, use,  transportation,
         handling, and disposal of nuclear materials, licensing the
         export of nuclear reactors and the import and export of
         uranium and plutonium, and regulating activities affecting
         the protection of nuclear facilities and materials.


    In addition to these regulatory bodies, the Environmental Protection

Agency (EPA) is the main Federal regulatory authority for protecting the

nation's air and water quality.  As part of its overall authority, EPA sets

limits on the level of air pollutants emitted from electric power plants and

develops regulations to control discharges of specific water pollutants.

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                                     2-13





Throughout this Report to Congress key regulations that affect the electric



utility industry are discussed.  While EPA often takes the Federal lead when



these regulations are developed, the Agency also works closely with the States



since they often retain primary authority for implementing and enforcing



standards (for example, see Section 4.1 on state regulation of coal combustion



wastes).







    2.1.2.2  State Regulation







    States are also involved in the environmental and economic regulation of



the electric utility industry.  As mentioned above, the States often share



regulatory authority with the various Federal organizations.  For



environmental regulation the States often have their own environmental



protection agencies to implement and enforce State and Federal environmental



regulations.  For example, they are responsible for drafting State



Implementation Plans (SIP) that must be approved by the U.S. EPA to attain



National Ambient Air Quality Standards (NAAQS).   Similarly, as will be



discussed in greater detail in Chapter Four, the States have authority for



implementing and enforcing regulations concerning the disposal of solid wastes



under Subtitle D of RCRA.  Environmental regulations for which the States



exercise regulatory authority are discussed throughout this Report to



Congress.







    States are also very involved in the economic regulation of the electric



utility industry.  The primary goals of state economic regulation is usually



to provide adequate nondiscriminatory service to electricity consumers at


                  19
reasonable prices.     This is usually accomplished by state regulatory

-------
                                     2-14





agencies such as public utility commissions.  The amount of authority these



state regulatory agencies have can differ widely from state to state.



However, these agencies usually have the authority to approve electricity



price levels and the rates of return allowed for utility stockholders.  State



regulators also approve the franchise under which the utility operates.



Licensing for construction and operation and approval of the sites at which



power plants will be built are also important functions of some state



regulatory commissions. Other areas into which some commissions have entered



to ensure that utility activities protect the public interest include setting



rules about when competitive bids are required, promulgating company



performance standards, deriving methods for allocating power during shortages,


                                                                  20
establishing billing and safety rules, and promoting conservation.








2.2  IMPORTANCE OF COAL TO ELECTRIC UTILITIES








    Electric utilities use many different technologies and energy sources to



generate electricity.  At present, as shown in Exhibit 2-6, over 70 percent of



electricity in the U.S. is generated by the combustion of fossil fuels (coal,



oil and natural gas); most of the remaining 30 percent is generated by



hydroelectric plants and nuclear power plants.  A small portion of electricity



demand is satisfied by alternative sources such as geothermal energy,



renewable resource technologies (e.g., wood, solar energy, wind), purchased



power from industrial and commercial cogeneration (cogeneration is the



simultaneous production of electricity and process steam; the electricity is



typically used by the cogenerator or sold to another industry while the  steam



is used for various production processes), and power imports (primarily  from



Canada).

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                                            2-15
                                      EXHIBIT 2-6

                 ELECTRICITY GENERATION BY PRIMARY ENERGY SOURCE
                                       1975-2000
              4000
  Generation
  (billions of
kilowatthours)
                 1975
                                           Year
                                                     Forecast
                                                                             Hydro &
                                                                             Other
                                                        Nuclear

                                                        Oil & Gas


                                                        Coal
       Source:
1975-1985:  Energy Information Administration, Electric Power
Monthly DOE/EIA-0226  (85/12), December 1985, p. 10.

1985-2000:  ICF Incorporated, Analysis of 6 and 8 million Ton
and 30 Year/NSPS and  30 Year/1.2 Ib. Sulfur Dioxide Emission
Reduction Cases. Prepared for Environmental Protection Agency,
February 1986.

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                                     2-16





    In 1984, coal accounted for more than half of all the electricity


                     21
generated in the U.S.    The portion of electricity generated from coal is



expected to remain at about this level throughout the rest of the century



since coal-fired generation is expected to remain economically attractive.



The relative contribution to total generation made by other fossil fuels and



by hydroelectric power will likely continue to decline, while the contribution



made by nuclear power plants will likely increase for the next few years as



several new units come on-line.  However,  the addition of nuclear plants



beyond those now under construction will be minimal, leading to an eventual



decline in nuclear's relative contribution.  Cogeneration, power imports, and



emerging technologies are expected to continue to grow, but their share of



total generation will remain small.  As a result, coal will continue to be the



major fuel source for electricity generation.







    The extent of the electric utility industry's dependence on coal varies



geographically.  Exhibit 2-7 shows that coal accounts for over three-quarters



of electricity generation in some regions, but less than half in others.  For



example, in the far West and southern Plains states, the local availability of



oil, gas, and hydroelectric power has limited regional dependence on coal.  In



many of the eastern regions, where coal is relatively more accessible and less



costly than oil or gas, coal is significantly more dominant.  Despite these



regional variations, however, coal-fired electricity generation is an



important source of electricity in most regions of the United States.







    The use of coal by electric utilities has also made the coal and electric



utility industries highly interdependent;  not only does coal-fired electricity



generation account for over half of the electricity produced in the U.S., but

-------
       Coal
Percentages represent the proportion
of the total electricity generated in
the region by each type of fuel.
                                                        EXHIBIT 2-7


                                            ELECTRIC UTILITY DEPENDENCE ON COAL
                                                   BY EPA REGION:   1985
                                                                                                                                33.4%
                                                                                                                       21.5%
                                                                                                                       4.8%
Source:  Energy Information Administration,  Electric Power
         Annual 1985.  DOE/EIA-0348(85),  pp.17-30.

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                                     2-18





the electric utility industry is the largest customer of the coal industry,



purchasing approximately three-quarters of all coal mined, as shown in Exhibit



2-8.  This interdependence has increased as electric utility coal consumption


                                                                         22
has grown from 406 million tons in 1975 to over 600 million tons in 1985.



Moreover, electric utility coal consumption is expected to continue to



increase to about 1 billion tons by the year 2000.







2.3  OVERVIEW OF COAL-FIRED POWER PLANTS







    Coal-fired power plants can vary greatly in terms of their generating



capacity and the type of boiler technology they employ which, in turn, can



affect the amount and type of combustion wastes produced.  This section



discusses the geographic differences in the size of plants and generating



units and describes the three main boiler types along with the regional



importance of each.







    2.3.1  Regional Characteristics of Coal-Fired Electric Generating Plants







    Coal-fired power plants can range in size from less than 50 MW to larger



than 3000 MW.  In many cases, particularly at the larger power plants, one



power plant site may be the location for more than one generating unit (a



generating unit is usually one combination of a boiler, turbine, and generator



for producing electricity).  Exhibit 2-9 shows the number of coal-fired power



plants and number of units in each EPA region and their average size in



megawatts.  On average, each power plant site is comprised of about three



generating units.  The average generating capacity of coal-fired power plants



in the U.S. is approximately 584 MW, with an average unit size of 257 MW.

-------
                                     2-19
                                 EXHIBIT  2-8


                       U.S COAL CONSUMPTION  BY  SECTOR
                                   1975-2000
Consumption
  T   ,  ,.     1200-
  Including
  Exports        _,
  (miUions   100°-

  of tons)     800-
              1975
                            1980
1985
1990
                                                                          Industrial &
                                                                          Other

                                                                          Exports
                                                                          Metallurgical

                                                                          Electric
                                                                          Utilities
1995
2000
                                        Year
                                                 Forecast
Sources: 1975-1985:  Energy Information Administration, Annual Energy Review
         1985. DOE/EIA-0384 (85), April 1985, pp. 167, 169.


         1985-2000:  ICF Incorporated, Analysis of 6 and 8 Million Ton  and  30
         Year/NSPS and 30 Year/1.2 Ib. Sulfur Dioxide Emission Reduction
         Cases,  Prepared for Environmental Protection Agency, February  1986.

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                                     2-20


                              EXHIBIT 2-9

    TOTAL NUMBER AND AVERAGE SIZE OF COAL-FIRED  PLANTS AND UNITS
                Number      Average Size     Number    Average Size a/
EPA Region     of Plants        (MW>       of Units a/      (MW)

     1            6             374           18            158
     2           17             297           39            138
     3           57             753          144            308
     4           93             799          295            301
     5          171             492          492            185
     6           39             852           87            580
     7           66             400          149            186
     8           48             454          109            250
     9           13             603           34            383
    10            4             479           11            382

U.S. Total      514             584         1378            257
Source:  Utility Data Institute Power Statistics Database.

a/  The total amount of generating capacity indicated by multiplying the
    number of units by their average size (e.g., 1378 units X 257 Mw - 354,146
    Mw) is greater than the amount indicated by multiplying the number of
    power plants by their average (e.g., 514 plants X 584 Mw - 300,176 Mw)
    because the information in the UDI Power Statistics Database by generating
    units includes units planned, currently under construction, etc.  while  the
    information by power plants refers only to power plants currently
    operating.

-------
                                     2-21






Regional averages for power plant size range from 297 MW in Region 2 to 852 MW




in Region 6.  Unit sizes range from an average of 138 Mw in Region 2 to 580 Mw




in Region 6.  Individual power plants and units can be larger or smaller than




these averages indicate.








    The majority of coal-fired plants (60%) are smaller than 500 MW, while




only about 4 percent of U.S. coal-fired power plants have a generating




capacity exceeding 2000 MW.  Exhibit 2-10 shows the distribution of coal-fired




plant sizes across EPA regions.








    2.3.2  Electricity Generating Technologies








    The basic process by which 'electricity is produced with coal is shown in




Exhibit 2-11.  When coal is burned to produce electricity, there are three key




components that are critical to the operation of the power plant:  the boiler,




turbine, and generator.  As coal is fed into the boiler, it is burned in the




boiler's furnace.  In the boiler there are a series of water-filled pipes.  As




heat is released during combustion, the water is converted to steam until it




reaches temperatures that can exceed 1000°F and pressures that approach 4000




pounds per square inch.  This high pressure, high temperature steam is then




injected into a turbine, causing the turbine blades to rotate.  The turbine,




in turn, is connected to a generator, so the mechanical energy available from




the rotating turbine blades is transformed into electrical energy.   The




electricity produced by this process is distributed via transmission lines to




residential, commercial, and industrial end-users who rely on the power to




meet their electrical requirements.  Although each step of this process is




critical to the production of electricity, this study focuses on boilers only

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                                     2-22
                             EXHIBIT 2-10

               RANGE OF COAL-FIRED POWER PLANT SIZES
                           (number of plants)
                                  Power Plant Size
EPA Region

   1
   2
   3
   4
   5
   6
   7
   8
   9
  10

U.S. Total
<100
MW
1
6
6
15
63
10
25
18
5
2
101-500
MW
4
6
23
31
51
4
24
14
2
0
501-1000
MW
0
5
11
17
23
10
8
10
4
1
1001-2000
MW
1
0
14
23
29
12
7
4
1
1
>2000
MW
0
0
3
7
5
3
2
2
1
0
151
159
89
92
23
Total

  6
 17
 57
 93
171
 39
 66
 48
 13
	4

514
Source: Utility Data Institute Power Statistics Database.

-------
                                               EXHIE  2-11


                                    PROCESS FOR GENERATING ELECTRICITY
                                      AT COAL-FIRED POWER  PLANTS
                                           Flue Gases
                                       Fly Ash


                                       Steam
                                                   FGD Sludge
I .I*' >• .0- .? ..y .f -jV .-.V 0> AV rf'
>^vy7/^v^
•/',/././././././.// /
XX Turbine  ^X/",

^•mM
                                       •*  Bottom Ash/Boiler Slag
                                                                            I Generator!
  Electricity
to Power Grid
                                                                                                                 to
Source: ICF Incorporated

-------
                                     2-24




since it is in the boiler where the combustion wastes are produced as the coal


is burned.






    There are three main types of boilers:  (1) pulverizers, (2) cyclones, and


(3) stokers.  As discussed below in greater detail, the key differences


between these boiler types are operating size and the procedures used for


handling and burning the coal.  Pulverized coal boilers are so-named because


the coal is finely pulverized prior to combustion; most utility boilers are


this type.  Cyclones have been used in past utility applications, but have not


been built recently.  They are called cyclones because of the cyclone-like


vortex created by the coal particles in the furnace during combustion.  Stoker


boilers are usually used when smaller capacities are required (e.g., 20-30 MW)


and burn coal in a variety of'sizes.
    A brief description of each of these coal combustion technologies

        23
follows.
    2.3.2.1  Pulverized-Coal Boiler






    Exhibit 2-12 shows a typical pulverized-coal boiler setup.  In a


pulverized coal boiler, coal is ground to a fine size (about 200 mesh, which


is powder-like) in a pulverizer or mill.  The pulverized fuel is then carried


to the burners by forced air injection and blown into the furnace, where it is


burned in suspension.  Much of the ash remaining after combustion remains


airborne and is carried from the furnace by the flue gas stream (i.e., it


becomes fly ash; see Chapter Three for a more detailed discussion of types of


waste and how they are produced).  Some ash is deposited on the furnace walls,

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                                      2-25


                               EXHIBIT 2-12

                   DIAGRAM OF A PULVERIZED COAL BOILER
                                 iiTi'iii'lVfii'iijiisiliJill'ii'lfici'Li -.."-i--?
                                 ^rtH^ff>
                                 '?£>is^^&$$ x-1 n
Coal in
                                    ^             Pulverizer

                    Two-drum boiler direct-fired with pulverized coal.
Source:  Babcock and Wilcox  Co., Steam:  Its Generation and Use, New York, NY
        1978.

-------
                                      2-26






where it agglomerates and may sinter or fuse.  Ash that falls to the bottom of




the furnace is removed via an ash hopper.  Ash deposits and slagging are more




of a problem in pulverized coal boilers than in stoker boilers.








    Most modern pulverized-coal boilers have dry-bottom furnaces; that is, the




ash is intended to be removed as a dry solid before complete melting occurs.




As a result, for dry-bottom boilers, the ash-fusion temperature




(the melting point) of the coal must be high enough to prevent the ash from




becoming a running slag (i.e., a liquid form).  Wet-bottom, or slag-tap,




pulverized-coal boilers are designed to remove the ash as a flowing slag.




These boilers depend on lower ash-fusion temperature coals so that the ash will




melt to form slag for easier removal.








    2.3.2.2  Cyclones








    The cyclone furnace consists of a water-cooled horizontal furnace in which




crushed coal is fired and heat is released at high rates, as shown in Exhibit




2-13.  The temperature inside the furnace may reach 3000°F, which is sufficient




to melt the ash into a liquid slag that forms on the walls of the furnace.  Air




circulation within the furnace typically creates a cyclone-like vortex that not




only helps the coal to burn in suspension but also causes many coal particles




to impinge upon the slag-covered walls of the furnace.  This tendency for coal




particles to adhere to the walls of the cyclone boiler aids the combustion




process because the coal particles will burn more thoroughly before reaching




the bottom of the boiler.   Most of the ash is retained in the slag layer, thus




minimizing the amount of fly ash that is carried out of the boiler.  The slag,

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                                         2-27



                                 EXHIBIT 2-13


                        DIAGRAM OF A CYCLONE BOILER
                                                      Attimpcrator
                                                         Rtti«at
                                                       SuptrftMttr
                                                                      »Gil Outlet
                                                                        Air Inlit
Source:    Babcock and Wilcox Co.,  Steam:   Its  Generation and Use. New York, NY,
           1978.

-------
                                      2-28






or melted ash particles, is typically removed at the bottom of the furnace.








    The cyclone offers the advantage of being able to burn low ash-fusion coals




that create problems when burned in most conventional pulverized-coal




burners.  The cyclone design also helps to minimize erosion and fouling




problems in the boiler.  The smaller amounts of fly ash created compared to




other boiler types reduces the costs associated with particulate collection.








    2.3.2.3  Stokers








    Stokers are designed to mechanically feed coal uniformly onto a grate




within a furnace.  Because most of the combustion takes place in the fuel bed,




not in suspension within the furnace, the heat release rate of this type of




boiler is lower than it is for pulverizers or cyclones.  As a result, stokers




are generally designed for smaller-sized applications.  In fact, this boiler




type is used by many manufacturing industries, but has seen only limited use by




electric utilities.








    Stokers are classified by the method of feeding fuel to the furnace and by




the type of grate.  The three most important stoker types include:








    1)   the spreader stoker, the most popular type of overfeed stoker,








    2)   other overfeed stokers, such as the chain-grate, travelling-grate




         stoker, or the vibrating-grate stoker, and








    3)   the underfeed stoker.

-------
               ,                       2-29







The major features of each are summarized in Exhibit 2-14.  An illustration of




a spreader stoker is provided in Exhibit 2-15.









    Use of the different boiler types varies by geographic region.  As shown in




Exhibit 2-16, about three-fourths of all boiler capacity in the U.S. uses




pulverizers,  with most of these dry-bottom pulverizers.   Cyclones are the next




most prevalent boiler type, representing only about 8 percent of all boilers.




Stokers represent less than one-half of one percent of the total; due to their




size limitations stokers are used primarily in other industrial applications




for the production of steam.









    Exhibit 2-17 shows the distribution of average capacity for each boiler




type by EPA region.  The range in average sizes is most pronounced in dry




bottom boilers (127.8-610.0 MW),  which reflects their substantial flexibility




in terms of size and dominance in electric utility applications.  Stokers tend




to have the smallest capacities (an average of 14 MW nationwide), limiting




their usefulness in utility applications compared to all of the other boiler




types.









2.4  COAL CONSTITUENTS AND BY-PRODUCTS









     Despite its attractiveness as a power plant fuel, coal has its drawbacks.




As a solid fuel, coal is often more difficult and more costly to transport,




store,  and burn than oil or gas.   Also, coal's many impurities require




environmental control at various  stages of the fuel cycle.

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                                                 2-30

                                        EXHIBIT 2-14

                    CHARACTERISTICS  OF VARIOUS TYPES OF STOKERS
Stoker Type & Subclass

1.  Spreader
    - Stationary and
      dumping grata
    - Travailing grate
    - Vibrating grate
2.  Overfeed
    - Chain grate and
      travelling grate
    - Vibrating grata
3.  Underfeed
    - Single or double
      retort
    - Multiple retort
Typical Maximum
Capacity Range
(pph atean) a/
 30,000-150,000
 20,000-30,000
Burning Hate
(Btu/hr/ft2) b/   Characteristics
  20,000-80,000    420,000

100,000-400,000    750,000
 20,000-100,000    400,000
 20,000-100,000    600,000
 400,000
 400,000
Capable of burning a wide
range of coals, beat
ability to follow
fluctuating loads, high
fly ash carry over, low load
smoke.

Characteristics similar
to vibrating-grate stokers
except these stokers experience
difficulty in burning strongly
caking coals

Low maintenance, low fly ash
carry over, capable of
burning wide variety of weakly caking
coals, smokeless operation over
entire range.

Capable of burning caking
coals and a wide range of
coals (including anthracite),
high maintenance, low fly ash  carry
over, suitable for continuous-load
operation.
a/ pph - pounds  steam/hr;  1 pph • 1000 Btu/hr.

b/ Maximum amount  of  Btus  consumed per hour for each square foot of grate in
   the stoker.

Source:  Meyers, Robert A.  (Ed.), Coal Handbook. Marcel Dekker,  Inc.,  New York,
         NY,  1981.

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                                       2-31


                                EXHIBIT 2-15

                       DIAGRAM OF A SPREADER STOKER
           COAL HOPPER
          FEEDER
       OVERTHROW
        ROTOR
Source:   Meyers, Robert A. (Ed.)» Coal Handbook.  Marcel Dekker, Inc.,  New
          York, NY,  1981.

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                                     2-32


                               EXHIBIT 2-16

                TOTAL COAL BOILER CAPACITY BY EPA REGION
                     Pulverizers
EPA










U.S
Region
1
2
3
4
5
6
7
8
9
10
. Total
Dry Bottom
69.2
60.6
87.6
71.6
70. A
48.6
58.3
60.3
77.5
100.0
69.3
Wet Bottom
11.3
19.4
0.3
5.3
4.9
12.5
3.5
5.4
0.0
0.0
5.3
                                         Cyclone    Stoker    Other a/    Total
                                          16.7
                                           5.0
                                           2.8
                                           5.2
                                          14.0
                                           0.0
                                          19.2
                                          10.6
                                           0.0
                                           0.0

                                           8.3
0.0
2.7
0.0
0,
0.
0.0
1.0
1.1
0.0
0.0

0.4
 0.0
16.7
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0

100.0
a/  Includes unknown,  or other boiler types.
Source:   ICF Coal and Utilities Information System Database.

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                                      2-33
                                  EXHIBIT  2-17

                 AVERAGE COAL BOILER SIZE BY TYPE OF BOILER
                               AND BY EPA REGION
                                      (MW)
                           Pulverizers
EPA Region
1
2
3
4
5
6
7
8
9
10
U.S. Total
Drv Bottom
210.2
127.8
297.6
249.3
185.0
522.7
162.5
234.2
388.3
610.0
231.8
Wet Bottom
102.7
137.7
136.0
147.4
117.0
489.0
148.3
141.7
N/A
N/A
162.9
                                                       Cyclone

                                                        228.0
                                                        143.5
                                                        195.3
                                                        342.6
                                                        222.6
                                                        N/A
                                                        243.2
                                                        322.8
                                                        N/A
                                                        N/A

                                                        243.2
N/A - Not applicable.

Source:  ICF Coal and Utilities Information System Database.
Stoker

 N/A
 39.0
 N/A
 14.6
 11.2
 N/A
 12.3
 17.9
 N/A
 N/A

 14.0

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                                      2-34





     These impurities are typically referred to as "ash", whether the reference



is to some of the constituents that compose the coal itself prior to combustion



or the waste products that result from its combustion.  Some coal ash is



inherent to the coal seam, while other ash comes from non-coal strata near the



coal seam which are intermixed during mining.  The coal consumed by electric


                                           24
utilities is generally over 10 percent ash.    At current rates of coal



consumption, about 70 million tons of ash pass through coal-fired power plants



each year.







     The ash generated at utility power plants is produced inside the boiler



furnace from the inorganic components as the organic components of the coal



combust.  The types of ash produced can vary -- some ash is swept through the



furnace with the hot flue gases to form fly ash, while some settles to the



bottom of the boiler as bottom ash or slag.  The amount of each type of ash



produced depends upon the boiler configuration as described in Section 2.3 and



the characteristics of the coal (see Chapter Three for further discussion of ash



types).







     Air quality regulations have long restricted the amount of fly ash that may



be released through a power plant's stacks.  Primarily through the use of



electrostatic precipitators or bag houses, power plants collect fly ash



particles, leaving the flue gases nearly particulate-free as they are emitted



from the stack.   As a result, the fly ash, bottom ash, and slag that is



collected during and after combustion is approximately equal to the amount of



ash in the coal prior to combustion.

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                                      2-35


     For many power plants constructed since the 1970's, additional

environmental controls also require that a portion of the sulfur oxides be

removed from the flue gases.   The dominant technology for removing sulfur

oxides is known as flue gas desulfurization (FGD),  in which alkaline agents,

usually in liquid slurry form, are mixed with the flue gases to convert the

sulfur into non-gaseous compounds.  The resulting waste product is generally

referred to as FGD sludge and can amount to 25 percent or more of the volume of
                               f\ f
coal consumed at a given plant.    In total, U.S. coal-fired power plants

produce about 85 million tons of ash and FGD sludge per year.  By the end of the

century, this volume is expected to approximately double.




     Exhibit 2-18 shows the number of coal-fired utility power plants and units

that produce FGD wastes in each EPA region as of 1985.  Regions 6, 8, and 9 have

the highest proportion of both plants and units producing FGD wastes.  For

example, more than half of the coal-fired units in region 9 produce FGD wastes.

The high proportion of FGD-producing plants in these regions is in part

attributable to the fact that many of the coal-fired plants in these regions are

relatively new and were required to incorporate scrubbers to meet air emission

regulations.




     Plants and units producing FGD waste represent a smaller percentage in

other regions, primarily because these regions relied on coal-fired capacity for

a major portion of their generation before units with FGD technology were

installed.  For example, the absolute number of both plants and units producing

FGD waste is greatest in Region 4, reflecting this area's reliance on coal for

generating electricity.

-------
                                      2-36


                                  EXHIBIT 2-18

               ELECTRIC UTILITY PRODUCTION  OF FGD WASTES:   1985
EPA Region

    1
    2
    3
    4
    5
    6
    7
    8
    9
   10

Total U.S.
# of Plants
 Producing
 FGD waste

     0
     3
     5
    11
    10
     8
     6
     9
     3
    _0

    55
   Percent of
Plants Producing
   FGD Wastes

      0.0
     17.6
      8.8
     12.0
      5.8
     20.5
      9.1
     18.8
     23.1
      0.0

     12.0
# of Units
Producing
FGD Wastes

    0
    3
   13
   26
   16
   23
   11
   25
   12
   _0

  129
  Percent of
Units Producing
  FGD Wastes
      0.0
     14.4
Source:  Utility Data Institute Power Statistics Database.

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                                      2-37






     Regions 1 and 10, at the other extreme, have no plants or units producing




FGD wastes.  These regions (New England and the Pacific Northwest) are not




highly dependent upon coal and consequently, have relatively few coal-fired




plants.








     Numerous other types of wastes are produced during normal operation and




maintenance at coal-fired power plants.  These include, among others, boiler




blowdown, coal pile runoff, cooling tower blowdown, demineralizer regenerants




and rinses, metal and boiler cleaning wastes, pyrites, and sump effluents.




These wastes are usually small in volume relative to ash and FGD sludge, but




because they may have higher concentrations of certain constituents that may




cause environmental concern,  they also require care in handling and disposal.




All of these wastes are discussed in greater detail in Chapter Three.

-------

-------
                                     2-39


                               CHAPTER TWO

                                  NOTES
      1  Edison Electric Institute,  1985 Statistical Yearbook.

      2  Energy Information Administration,  Annual Energy Outlook 1985.
DOE/EIA-0383(85), p.  50.

      ^  A gigwatt-hour (Gwh) is one million kilowatt -hours; a kilowatt-hour is
the amount of electricity generated by 1 kilowatt of electric generating
capacity operating for one hour.

      ^  Energy Information Administration,  Annual Outlook for U.S. Electric
Power .  DOE/EIA-0474(86) , 1986.

      5  Ibid.

      6  Ibid.

      7  Ibid.

      8  Ibid.

      9  Ibid.

     10  Ibid.

     11  Ibid.

     12  Ibid.

     13  Ibid.

     14
     15  Ibid.

         The major portion of this discussion is taken from Annual Outlook for
U.S. Electric Power. DOE/EIA, 1986.  See this document for further information.

     17  Ibid., page 5.

     18  Ibid.

     19  Ibid.

     20  Ibid.
     21
         Energy Information Administration, Electric Power Annual 1984.
DOE/EIA-0348(84), p. 24.

-------
                                      2-39


     22
         Energy Information Administration, Electric Power Monthly.
DOE/EIA-0226(85/12), December 1985, p. 21.

     23
         For more detail, see Meyers, Robert A. (Ed.), Coal Handbook.  Marcel
Dekker, Inc., New York, New York, 1981, pp. 378-431.

         Energy Information Administration, Cost and Quality of Fuels  for
Electric Utility Plants 1984. DOE/EIA-0191(84), July 1985, p. 6.

     25
         American Coal Ash Association.

     26
         For example, a coal with 2 percent sulfur would produce approximately
80 pounds sulfur dioxide per ton of coal consumed.  A limestone scrubber
capturing 90 percent of the sulfur dioxide, assuming a stoichiometric  ratio of
1.4 and a sludge moisture content of 50 percent, would product almost  500
pounds of FGD sludge per ton of coal consumed.  See Appendix B for a detailed
discussion of the methodologies used to determine this calculation.

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                             CHAPTER THRKR

                    WASTES GENERATED FROM COAL-FIRED
                     ELECTRIC UTILITY POWER PLANTS
   As part of EPA's responsibility under Section 8002(n) of RCRA, Congress

directed that the study of wastes from the combustion of fossil fuels should

include an analysis of "the source and volumes of such material generated per

year."  In response to this directive, this chapter examines the physical and

chemical characteristics of the types and quantities of wastes that are

generated currently and likely to be generated in the future.



3.1  OVERVIEW OF ELECTRIC UTILITY WASTES



   As discussed initially in Chapter Two, the noncombustible material that

remains after coal is burned is called ash.  The proportion of noncombustible

material in coal is referred to as the ash content.  There are four basic

types of wastes that can be produced directly from coal combustion:  fly ash.

bottom ash, boiler slag, and flue gas desulfurization (FGD) sludge.  The

smaller ash particles entrained by the flue (exhaust) gas are referred to as

fly ash and are produced in varying degrees by all plants.   Larger ash

particles that settle on the bottom of the boiler will form either bottom ash

(if the particles have never completely melted) or boiler slag (if the ash

particles have melted),  depending on the furnace design.  Another waste

product, called FGD sludge, is generated when some of the sulfur dioxide

(formed when the sulfur present in the coal combines with oxygen during

combustion) is removed from other flue gases.  This removal process is

required by the Clean Air Act Amendments of 1979, which revised the New Source

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                                     3-2






Performance Standards for any electric utility boiler constructed after




September 1978.  These plants are required to remove 90 percent of the sulfur




dioxide, which is usually accomplished with a flue gas desulfurization (FGD,




or scrubber) system.  Because they are generated in very large quantities,




these four waste materials -- fly ash, bottom ash, boiler slag, and FGD sludge




-- are referred to by the industry as high-volume wastes.  This term will be




used throughout this study to be consistent with the terminology that is




commonly used for these wastes.








   Electric utility power plants also generate waste streams that the industry




typically calls low-volume wastes. which are formed during equipment




maintenance and water purification processes.   Types of low-volume wastes




generated by coal-fired power plants include boiler blowdown, coal pile




runoff, cooling tower blowdown, demineralizer regenerants and rinses, metal




and boiler cleaning wastes, pyrites, and sump effluents.  Because it is common




industry terminology, the term "low-volume wastes" will be used throughout




this report; however, some of these wastes (such as cooling tower blowdown)




can be generated in substantial quantities, although generally in smaller




quantities than high-volume wastes.








   The remainder of this chapter describes each type of high-volume and




low-volume waste stream, the various methods of collection used for each, the




volumes produced, and the physical and chemical characteristics that determine




the waste's behavior during disposal and its potential to leach.

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                                     3-3






3.2  HIGH-VOLUME WASTES








    High-volume coal combustion utility wastes are those waste streams




generated in the boiler furnace -- fly ash, bottom ash, and boiler slag -- and




in the cleaning of coal combustion flue gas.  The following sections describe




the volumes and the physical and chemical characteristics of these high-volume




waste streams.








        3.2.1  Ash








    The noncombustible waste material that remains after coal is burned is




referred to as ash.  Some noncombustible materials are characteristic of the




coal itself, originating from the chemical elements in the plants from which




the coal was formed.  These materials generally account for no more than two




percent of the ash content of the coal.  Other noncombustible materials




extraneous to the coal, such as minerals lodged in the coal seam during or




after its geologic formation and rocks near the coal seam that are carried




away with the coal during mining, are burned during the fuel combustion




process along with the coal itself.  These materials account for most of the




ash content.








        3.2.1.1  How Ash is Generated








    The type of ash produced from a boiler is determined by the type of coal




that is burned and the design of the boiler furnace.  As discussed in Chapter




Two, the major types of boilers used by electric utilities are wet-bottom




pulverizers, dry-bottom pulverizers, cyclone-fired boilers, and stokers.

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                                     3-4
    Pulverizers are the most widely used boilers in the electric utility




industry because they can burn many different types of coal.  Due to the very




fine consistency of the coal after it is pulverized, the ash particles are




easily carried out of the boiler along with the flue gases, resulting in a




relatively large proportion of fly ash.








    The amount of fly ash that accumulates in a pulverizer depends on whether




it is dry-bottom or wet-bottom.   In dry-bottom pulverizers, which constitute




the majority of electric utility boilers, ash particles in the coal generally




do not melt during the combustion process because the ash fusion temperature




(i.e., the melting point) is higher than the operating temperature in the




boiler.  In dry-bottom pulverizers, therefore, about 80 percent of the fine




ash remains in the flue gas as fly ash.  The remaining ash settles to the




bottom of the boiler (hence the term bottom ash) where it is collected at a




later time.  In wet-bottom pulverizers, about 50 percent of the ash exits the




boiler as fly ash, while the other 50 percent remains in the furnace.




However, ash particles that remain in wet-bottom pulverizers become molten;




this boiler slag remains in a molten state until it is drained from the boiler




bottom.








    Cyclone-fired boilers burn larger-sized coal particles than do




pulverizers, since partial crushing is the only preparation required prior to




injection into the furnace.  The amount of fly ash that is generated in a




cyclone boiler is. less than that generated in a pulverizer because of the




larger-sized coal particles and the design of the cyclone boiler.  Because the




air circulation within the boiler furnace is designed to create a cyclone-like

-------
                                     3-5






vortex, the coal particles have a tendency to contact the boiler walls.  The




operating temperature is high enough to melt the ash so that it adheres to the




furnace walls as liquid slag.  Excess slag continually drains to the bottom of




the furnace, where it is removed for disposal.  Only 20 to 30 percent of the




ash formed in a cyclone boiler leaves the boiler as fly ash.








    A few older and smaller power plants have stoker-type boilers, in which




coal is burned on or immediately over a grate in the furnace.  Stokers are




designed to burn coals that do not contain too many small particles (fines),




which can tend to smother the fire.  Because there are fewer small particles,




the amount of fly ash is reduced.  For example, in a spreader stoker, the most




common type of stoker boiler, the coal is uniformly fed over the fire in a




manner that enables suspension burning of the finer pieces, while heavier




pieces of coal fall onto the grate for further combustion.  The large amount




of coal that is burned on the grate reduces the amount of fly ash; the ash




produced in a spreader stoker is generally about 50 percent fly ash and 50  '




percent bottom ash.








        3.2.1.2  Methods of Ash Collection








    As the flue gas leaves the boiler, it is passed through a mechanical ash




collector to remove some of the fly ash particles.  A mechanical ash collector




operates by exerting centrifugal force on the fly ash particles, throwing them




to the outside wall of the collector where they can be removed.  These




collectors are effective mainly for capturing the larger fly ash particles.




To remove the smaller particles,  the flue gas must then pass through some

-------
                                     3-6






other type of particulate control device, such as an electrostatic




precipitator, a baghouse, or a wet scrubber.









    The electrostatic precipitator (ESP) is the most common device for fine




ash collection.  ESPs operate by applying an electrical charge to the fly ash




particles.  In the presence of an intense electrical field, the charged




particles are attracted to a grounded collection electrode.  The collected




dust is then discharged to a storage hopper by a process called rapping that




dislodges the collected particles.  ESPs are most efficient when coal with




high sulfur content is used because the sulfur dioxide in the flue gas helps




retain the electrical charge.  When properly designed and maintained, an ESP




is capable of collecting over 99 percent of the ash present in the flue gas.








    When coal with lower sulfur content is burned, baghouses (also called




fabric filters) are often more appropriate to use as fly ash collection




devices.  If operated efficiently, they also can remove over 99 percent of the




ash from the flue gas.   In this system, the flue gas passes through a filter




that traps the ash particles.  The ash builds up on the filter, forming a




filter cake.  As this process continues, the ash collection efficiency tends




to increase as it becomes more difficult for particles to pass through the




filter material.  Periodically, the cake is dislodged from the filters, which




reduces efficiency until buildup occurs again.








    Some power plants remove fly ash by the wet scrubbing method, in which




liquids are used to collect the ash.  In one method, the ash particles are




removed from the flue gas stream by contacting them with a scrubbing liquid in




a spray tower.  This process forms an ash slurry, which is then discharged.

-------
                                     3-7






Alternatively, fly ash particles may be dislodged from the walls of the




scrubber by a liquid flushing of the scrubber.  Because the operation of a




scrubber is very plant-specific, the collection efficiency of wet scrubbers




varies, though wet scrubbers are generally not as efficient as ESPs and




baghouses.  The advantage of wet scrubbers, however, is that they can also be




used simultaneously to collect sulfur oxides from the flue gas system.








    Ash particles that do not escape as fly ash become bottom ash or boiler




slag.  In dry-bottom pulverizers and stokers, the temperatures are low enough




to allow the molten ash to cool and reform into dry, solid ash particles, or




bottom ash.  In smaller boilers of this type, the ash falls onto a grate,




which then is opened, allowing the ash to drop into a flat-bottom hopper.  The




large quantities of bottom ash produced in larger boilers often require




hoppers with sloped sides for self-feeding.  Some hoppers may contain water to




quench the ash and to facilitate disposal.








    In cyclone-fired boilers and wet-bottom pulverizers, the liquified ash




particles that fall to the bottom of the boiler during combustion remain in a




molten state and coalesce into large masses (called slag),  which then drop




onto the boiler floor.  The slag is tapped into a water-filled hopper, or slag




tank, which is periodically emptied and the slag disposed.   Slag tanks for




cyclone-fired boilers are similar to those used for pulverizers but have a




higher relative capacity because a greater percentage of the ash in cyclones




becomes boiler slag.

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                                     3-8






        3.2.1.3  Quantities of Ash Generated








    Nearly all of the noncombustible material in coal ends up as fly ash,




bottom ash, or boiler slag.  As mentioned earlier, the coal industry and the




electric utility industry refer to this material as a coal's ash content.  As




a result, the volume of ash generated is directly related to the amount of




coal consumed and the ash content of the coal.  The ash content of coal will




vary according to several factors, including coal-producing region, coal rank




(i.e., bituminous, subbituminous, anthracite, or lignite), mine, seam, and




production method.  Although the proportion of ash in coal may range from 3 to




30 percent, the industry-wide average for electric utility power plants is




10.1 percent.^  Exhibit 3-1 shows the average ash content of coal that was




delivered to coal-fired power plants in 1985 for some of the major




coal-producing regions.








    In 1984, electric utilities generated about 69 million tons of coal ash.




Ash generation is expected to increase considerably, to about 120 million tons




in the year 2000, an increase of about 72 percent over 1984 levels.  This




increase can primarily be attributed to the increase in the demand for coal by




electric utilities.   While there is some uncertainty over the amount of coal




that will be consumed by electric utility power plants, coal-fired electricity




generation is likely to increase significantly.  For example, one estimate




indicates that by the year 2000 electric utility power plants will burn over




one billion tons of coal to meet 61 percent of total electricity demand,-* an




increase of 70 percent over the 664 million tons consumed in 1984.   Exhibit




3-2 shows historical and forecasted future ash generation by coal-fired




electric power plants.

-------
                                 3-9
                          EXHIBIT 3-1

          REPRESENTATIVE ASH CONTENTS BY PRODUCING
                  REGION AND COAL RANK:   1985
    Coal Rank and Region                        Percent Ash

Anthracite

      Northeastern Pennsylvania                    29.4

Bituminous

      Western Pennsylvania                         10.9
      Northern West Virginia                       10.4
      Ohio                                         11.3
      Eastern Kentucky                              9.9
      Alabama                                      12.2
      Illinois                                      9.7
      Colorado                                      6.2
      Utah                                          9.4
      Arizona                                       8.9

Subbituminous

      Wyoming                                       5.9
      New Mexico                                   18.8
Lignite
      Texas
      North Dakota

      U.S. Average                                 10.1
Source:  Energy Information Administration, Cost and Quality of Fuels for
         Electric Utility Plants 1985.  DOE/EIA-0191(85),  July 1986.

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                                            3-10
                                         EXHIBIT 3-2

                            VOLUME OF ASH GENERATED BY COAL-FIRED
                                ELECTRIC  UTILITY  POWER  PLANTS
                                         1975 - 2000
             120
Ash Volume
                                                                                  Boiler Slag


                                                                                  Bottom Ash



                                                                                  Fly Ash
               1975
1980
1985
1990
1995
2000
                                                       Estimated
                                    Year
        Sources:   1975-1984:  American Coal Ash Association.
                  1985-2000:  ICF Incorporated.  See Appendix B for in-depth
                  discussion of the methodologies used to  develop these estimates,

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                                     3-11
   The average ash content of coal burned by electric utilities has declined
from about 14 percent to slightly more than 10 percent over the past decade
(see Exhibit 3-3).  To meet particulate emission standards and to lower
certain operating and maintenance costs, more electric utilities are now
choosing to burn coal with lower ash contents.  Although some coals are
naturally low in ash, producers and/or utilities can also reduce ash content
by cleaning the coal.^  In some cases, cleaning can reduce ash content by as
much as 50 to 70 percent.  At present, utilities clean about 35 percent of all
the coal they consume;  most of the coal that is cleaned comes from eastern and
midwestern underground bituminous coal-mining operations.  Another reason for
the increased use of coal with lower average ash content is the growth in
Western coal production, particularly in the Powder River Basin area of
Montana and Wyoming.  These coals are naturally low in ash content, and little
ash is extracted during the mining process.

                                                                            i
   The quantity of fly ash and bottom ash produced is likely to increase
faster over time than the quantity of boiler slag because most new coal-fired
plants will employ dry-bottom pulverizer boilers, which generate fly ash and
bottom ash rather than boiler slag.  Because dry-bottom pulverizers are
capable of burning coal with a wide range of ash fusion temperatures,  they
are able to burn a greater variety of coals  compared with cyclone boilers and
wet-bottom pulverizers.  Another advantage of dry-bottom pulverizers is that
they produce less nitrogen oxide emissions than do other boiler types,  which
enables electric utilities to meet requirements for nitrogen oxide emissions
control more easily.

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                                             3-12
                                       EXHIBIT 3-3

                           AVERAGE ASH CONTENT OF COAL BURNED
                      BY ELECTRIC UTILITY POWER PLANTS IN THE U.S.
                                       1975  -  2000
Ash Content

  (Percent)
                1975
     1980
1985
1990
1995
2000
                                                          Estimated
                                      Year
   Source:  1975-1984:

          1985-2000:
Energy Information Administration, Cost and Quality of Fuels for
Electric Utility Plants.
ICF Incorporated.   See Appendix B for in-depth discussion of the
methodologies used to develop these estimates.

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                                     3-13






        3.2.1.4  Physical Characteristics of Ash









    The physical characteristics of coal combustion ash of interest are




particle size and distribution, compaction behavior, permeability, and shear




strength.  Exhibit 3-4 provides representative ranges of values for these




characteristics of fly ash, bottom ash, and boiler slag.








    The greater the assortment of particle sizes in the material, the more it




can be compacted to achieve greater density and shear strength and lower




permeability.  Generally, fly ash is similar in size to silt.  Most fly ash




particles are between 5 and 100 microns in diameter; within a single sample,




the largest particles may be 200 times larger than the smallest particles."




The size of bottom ash and boiler slag particles can range from that of fine




sand to fine gravel, or about 0.1 to 10 millimeters.








    Compaction behavior refers to the amount of settling that takes place




after disposal and the rate at which such settling occurs.  Compressibility,




density, and moisture content are factors affecting compaction behavior.




When compacted and dry, most fly ash and bottom ash behave very similarly to




cohesive soil.








    Permeability reflects the rate at which water will seep through the waste




material in a given period of time and provides a good first estimate of the




rate and quantity of leachate migration.  A number of factors can influence




the degree of permeability, such as the size and shape of the waste particles,




the degree of compaction, and the viscosity of the water.  Properly compacted




fly ash often has low permeability, similar to that of clay, while the

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                                    3-14
                              EXHIBIT 3-4

                    REPRESENTATIVE RANGES OF VAUDES
                  FOR THE PHYSICAL CHARACTERISTICS OF
                 FLY ASH, BOTTOM ASH, AND BOILER SLAG
                                                         Bottom Ash/
                                          Fly Ash        Boiler Slag

   Particle Size (mm)                    0.001-0.1         0.1-10

   Compaction Behavior:

       Compressibility (%)               1.8               1.4

       Dry Density (lbs/ft3)             80-90             80-90

   Permeability (cm/sec)                  10~6-10*4         lO^-lO"1

   Shear Strength

       Cohesion (psi)                    0-170             0

       Angle of Internal  Friction (°)    25-45             25-45
Sources:     For compressibility values,  Arthur D. Little,  Full-Scale Field
             Evaluation of Waste Disposal from Coal-Fired Electric Generating
             Plants.  Volume I,  Prepared for U.S. Environmental Protection
             Agency,  June 1985, p.  3-29.   For other values, Tetra Tech Inc.,
             Physical-Chemical Characteristics of Utility Solid Wastes.
             Prepared for Electric  Power Research Institute, EPRI EA-3236,
             September 1983,  p. 3-3 -  3-8.

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                                     3-15






permeability of bottom ash is usually slightly higher.  Boiler slag is higher




still, having a permeability comparable to that of fine gravel.






   Shear strength is an important determinant of the shape and structural




stability of wastes disposed in landfills; a strong material (i.e., one with




high shear strength) can form steep slopes and support heavy loads from above.




Two indicators of shear strength are cohesion, a measure of the attraction




between particles due to electrostatic forces, and the angle of internal




friction, an indicator of the friction between particles.  Dry, nonalkaline




ash has no cohesion.  Dry ash that is alkaline demonstrates some cohesion and,




when compacted, increases in strength over time.  The angle of internal




friction associated with ash varies with the degree of compaction, although it




is similar to that for clean, graded sand.








   3.2.1.5  Chemical Characteristics of Ash








   The chemical composition of ash is a function of the type of coal that is




burned, the extent to which the coal is prepared before it is burned, and the




operating conditions of the boiler.  These factors are very plant- and




coal-specific.








   In general, over 95 percent of ash is made up of silicon, aluminum, iron,




and calcium in their oxide forms.  Magnesium, potassium, sodium, and titanium




are also present to a lesser degree.  Exhibit 3-5 shows the concentration of




these major elements typically found in fly ash, bottom ash, and boiler slag.








   Ash also contains many other elements in much smaller quantities.  The




types and proportions of these trace elements are highly variable and not

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                         3-16
                  EXHIBIT 3-5
LOW AND HIGH CONCENTRATIONS OF MAJOR CHEMICAL
CONSTITUENTS FOUND IN ASH GENERATED
BY COAL-FIRED POWER PLANTS
(parts per ni.lli.on)
Flv Ash Bottom
Aluminum
Calcium
Iron
Magnesium
Potassium
Silicon
Sodium
Titanium
Source :
Low
11,500
5,400
7,800
4,900
1,534
196,000
1,180
400
Utility Solid Waste
on the Disposal and
High
144,000
177,100
289,000
60,800
34,700
271,000
20,300
15,900
Activities Group,
Utilization of FOJ
Bv- Products. Appendix A, Submitted to
Low
88,000
8,400
27,000
4,500
7,300
180,000
1,800
3,300
Report
Ash/Boiler Slag
High
135,000
50,600
203,000
32,500
15,800
273,000
13,100
7,210
and Technical Studies
ssil-Fuel Combustion
the U.S
. Environmental
Protection Agency,  October 26,  1982,  p.  31.

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                                     3-17






readily categorized.  Concentrations for various trace elements in coal ash




are shown in Exhibit 3-6, which indicates the potential range of values and




median concentration for such trace elements for coals from different regions




of the U.S.  A summary of how the concentration of elements in ash varies




according to coal source is shown in Exhibit 3-7.  For example, Eastern and




Midwestern coal ashes usually contain greater amounts of arsenic, selenium,




chromium, and vanadium than do Western coal ashes, while Western coals have




larger proportions of barium and strontium.  Coal mining and cleaning




techniques can reduce the amount of trace elements that are ultimately found




in the ash after combustion.  For example, in some cases, coal cleaning can




remove more than half of the sulfur, arsenic, lead, manganese, mercury, and




selenium that is contained in the coal prior to combustion.








   The proportions of elements contained in fly ash, bottom ash, and boiler




slag can vary.  Exhibit 3-8 provides ranges and median values for element




concentrations in different types of ash -- bottom ash and/or boiler slag, and




fly ash.  The concentrations of elements formed in fly ash are shown for two




types -- the larger particles removed from the flue gas by mechanical




collection and the smaller particles removed with an electrostatic




precipitator or a baghouse (see Section 3.2.1.2 for more detail on methods of




ash collection).  For example, much higher quantities of arsenic, copper, and




selenium are found in fly ash than are found in bottom ash or boiler slag.




The distribution of elements among the different types of ash is largely




determined by the firing temperature of the boiler relative to the coal's ash




fusion temperature, which in turn affects the proportions of volatile elements




that end up in fly ash and bottom ash.  Some elements, such as sulfur,




mercury, and chlorine, are almost completely volatilized and leave the boiler

-------
                                                            EXHIBIT 3-6

                                    ELEMEHT CUNUJI1KATICHS IH ASH FBCM TUKKK GEOGBAFHIC SOUHCES
                                                    (•Ullgraaa per kilosran)*
                               Eastern Coal
                                                            Midwestern Coal
                                                                                             Western Coal
Element
Arsenic
Barium
Boron
Cadmium
Chromium
Cobalt
Copper
Fluorine
Lead
Manganese
Mercury
Molybdenum
Nickel

Selenium
Silver
Strontium
Thallium
Vanadium
Zinc
Range
2.0-279
52-2200
10.0-580
0.10-8.24
34-437
6.22-79
3.7-349
0.40-89
1.3-222
79-430
0.02-4.2
0.84-51
6.6-258

0.36-19.0
0.25-8.0
59-2901
7.0-28.0
110-551
16-1420
Median
75
892
121
1.59
165
40.6
136
8.8
18.0
190
0.192
15.0
78

8.05
0.695
801
25.0
269
163
Range
0.50-179
300-4300
10-1300
0.50-18
70-395
19-70
20-330
3.2-300
3.0-252
194-700
0.005-0.30
7.0-70
26-253

0.08-19
0.10-1.20
30-2240
2.0-42
100-570
20-2300
Median
54
905
870
2.6
172
35.7
125
75
149
410
0.044
43
121

7.0
0.39
423
16.0
270
600
Range
1.3-129
300-5789
41.9-1040
0.10-14.3
3.4-265
4.9-69
29-340
0.40-320
0.40-250
56.7-769
0.005-2.5
1.4-100
1.8-229

0.13-19.0
0.040-6.0
931-3855
0.10-3.50
11.9-340
4.0-854
Median
18
2700
311
1.01
45
13.0
74.8
50.1
26.1
194
0.067
12.0
38.0
LO
*•* M
0.26 °°
2300
1.06
94
71
*  Values shown are for all types of ash combined.

Source:   Tetra Tech Inc.,  Physical-Chemical Charaeteristica of Utility Solid Hastea.  EPRI EA-3236, September  1983.

-------
                                    3-19


                                  EXHIBIT 3-7

    EFFECT OF GEOGRAPHIC COAL SOURCE ON ASH ELEMENT CONCENTRATION
   Element

   Arsenic


   Barium

   Cadmium

   Chromium


   Mercury


   Lead

   Selenium


   Strontium


   Vanadium


   Zinc
    Concentration Pattern

low in western coal ash; eastern and midwestern coal
ashes indistinguishable

highest in western coal ash

most concentrated in midwestern coal ash

low in western coal ash; eastern and midwestern coal
ashes indistinguishable

highest in eastern coal ash; all distributions highly
skewed toward high concentrations

highest in midwestern coal ash

similar in eastern and midwestern coal ash; lower in
western coal ash

greater in eastern than in midwestern coal ash;
greater still in western coal ash

similar in eastern and midwestern coal ash; lower in
western coal ash

greater in eastern than in western coal ash; greater
still in midwestern coal ash
Source:   Tetra Tech,  Inc.,  Physical-Chemical Characteristics of Utility Solid
         Wastes.  EPRI EA-3236,  September 1983,  p.  3-30.

-------
                                                           EXHIBIT 3-8



                                           ELEMENT LUTCEHIKATIOBS n THKEE TTPES OF ASH

                                                    (milligrams per kilogram)
                                                                               Ply Aah
Bottom Ash/Boiler Slag
Element
Silver
Arsenic
Boron
Barium
Cadmium
Cobalt
Chromium
Copper
Fluorine
Mercury
Manganese
Lead
Selenium
Strontium
Vanadium
Zinc
Range
0.1-.51
.50-168
Al. 9-513
300-5789
0.1-4.7
7.1-60.4
3.4-350
3.7-250
2.5-104
0.005-4.2
56.7-769
0.4-90.6
.08-14
170-1800
12.0-377
4.0-798
Median
0.20
4.45
161
1600
0.86
24
120
68.1
50.0
0.023
297
7.1
0.601
800
141
99.6
Mechanical Hopper Ash
Range
0.08-4.0
3.3-160
205-714
52-1152
0.40-14.3
6.22-76.9
83.3-305
42.0-326
2.50-83.3
0.008-3.00
123-430
5.2-101
0.13-11.8
396-2430
100-377
56.7-215
Median
0.70
25.2
258
872
4.27
48.3
172
130
41.8
0.073
191
13.0
5.52
931
251
155
Fine Fly Ash
Range
0.04-8.0
2.3-279
10.0-1300
110-5400
0.10-18.0
4.90-79.0
3.6-437
33.0-349
0.40-320
0.005-2.50
24.5-750
3.10-252
0.60-19.0
30.0-3855
11.9-570
14.0-2300
Median
0.501
56.7
371
991
1.60
35.9
136
116
29.0
0.10
250
66.5
9.97
775
248
210
                                                                                                                                               ro
                                                                                                                                               o
Source:   Tetra Tech.  Inc..  Physical-Chemical Characteristics of Utility Solid Hastes.  EHII  EA-3236, September 1983. p. 3-24.

-------
                                      3-21





in the flue gas rather than remaining in the bottom ash or boiler slag.   Some



of these more volatile elements may condense on the surface of the fly ash



particles as the flue gas cools.







    3.2.2  PGD Sludge







    Another waste stream often generated in large volumes by coal-fired utility



power plants is FGD sludge, which is created when utilities remove sulfur



oxides from the flue gases.  Emissions of sulfur oxides in the flue gases are



due to the oxidation of sulfur during coal combustion.  State and Federal



regulations require power plants to control the amount of sulfur oxides



released through the stack.  To meet the applicable requirements most power



plants use coals whose inherent sulfur content is low.  If the sulfur content



is so low that additional sulfur dioxide removal is not needed, then FGD sludge



is not produced.







    Present requirements for all new coal-fired plants, however, not only limit



the amount of sulfur oxides that can be emitted, but also mandate a percentage


                                                    12
reduction in the amount of sulfur dioxide emissions.    This requirement will



substantially increase the number of sulfur dioxide control systems in use.



The primary method of sulfur dioxide control currently available is a flue gas



desulfurization (FGD) system through which the flue gases pass before being



emitted from the stack.  The wastes produced by this system are called FGD



(scrubber) sludge.  Other methods of control include newer technologies such as



fluidized bed combustion (FBC) and limestone injection multistage burners



(LIMB).     The technical and economic feasibility of the latter two



technologies are currently under evaluation by private industry and the U.S.

-------
                                      3-22





Department of Energy.  If these technologies do become more widely available,



they also will produce substantial volumes of wastes.








         3.2.2.1  Methods of PGD Sludge Collection








    There are two major types of FGD (scrubber) systems.  Non-recovery systems



produce a waste material for disposal.  Recovery systems produce recyclable



by-products.  Exhibit 3-9 illustrates the different types of FGD systems



currently in use.  Non-recovery systems, which account for 95 percent of the



scrubber systems now in use by electric utilities, are further classified as



wet or dry systems.  In wet non-recovery scrubber systems, the flue gas



contacts an aqueous solution of absorbents, thereby producing waste in a slurry



form.  The wastes generated by dry non-recovery systems contain no liquids.








    Direct lime and limestone FGD systems are the most common wet non-recovery



processes.  With these systems, flue gases pass through a fly ash collection



device and into a contact chamber where they react with a solution of lime or



crushed limestone in the form of a slurry.   The slurry circulates between the



contact chamber and a separate reaction tank, where the reagents are added.



From the reaction tank, the slurry is fed to a thickening and dewatering device



to be prepared for disposal.  After dewatering, the resulting liquid is



recycled back to the reaction tank and the sludge solids are removed for



disposal.  Under certain conditions, direct lime and limestone scrubbers have


                                                                          14
been able to remove over 95 percent of the sulfur dioxide in the flue gas.

-------
                                      3-23


                                  EXHIBIT 3-9

               MAJOR TYPES OF FLOE GAS DESTJLFURIZATION SYSTEMS
             Non-Recovery
      Wet
Direct Lime
      Drv
Spray Drying
Direct Limestone     Dry Sorbent
                       Injection*

Alkaline Fly Ash

Dual-Alkali
                                  Recovery
      Wet
Wellman-Lord
                     Magnesium Oxide
      Drv
Alumina/Copper*
  Sorbent

Activated Carbon*
  Sorbent
*Systems are currently in development and testing phases,  and are not as yet being
used commercially.

Source:  Tetra Tech Inc.,  Physical-Chemical Characteristics of Utility Solid Wastes.
         Prepared for Electric Power Research Institute, EPRI EA-3236, September
         1983, pp. 4-1 - 4-4.

-------
                                      3-24






    A variation on the direct lime and limestone systems is the alkaline fly




ash scrubber.  Several western power plants that burn coal containing




high-alkaline ash use these systems, which can improve sulfur dioxide




removal.  Rather than being collected by a separate upstream device (such as an




ESP or baghouse),  fly ash particles remain in the gas stream as it passes




through the scrubber.  In the scrubber, the alkaline fly ash, augmented with an




alkaline lime/limestone slurry, acts to remove sulfur oxides.  Alkaline fly ash




scrubbers are not as efficient as direct lime and limestone systems, removing




on average only about 40 percent of the sulfur dioxide.








    Another wet non-recovery system is the dual-alkali process.  These




scrubbers operate in much the same manner as the direct lime and limestone




scrubbers.  However, dual-alkali systems use a solution of sodium salts as the '




primary reagent to which lime is added for additional absorption.  The soluble




sodium salts are then recycled to the scrubber system and the insoluble portion




of the slurry is left to settle so that it can be collected and disposed.  Like




direct lime and limestone systems, dual-alkali scrubbers remove up to 95




percent of the sulfur dioxide.








    Exhibit 3-10 presents a diagram of the operations of a wet FGD system.  The




flows shown for the flue gas, absorbent, slurry, and sludge are essentially the




same for direct lime, direct limestone, alkaline fly ash, and dual-alkali




systems.








    At present, the two most popular methods of dry scrubbing under




investigation are spray-drying and dry sorbent injection, although only the




spray-drying process is now in commercial use at electric utility power plants.

-------
                                              EXHIBIT 3-10

                         FLOW DIAGRAM OF WET  FLUE GAS  DESULFURIZATION SYSTEM
                   \Separale
                      ly Ash
Absorber
System
                                       Spent
                                       Slurry
                       Slurried
                       Primary
                       Absorbent
    ^ \flue Gas
     r\Reheatef.
           Cleaned Gas
           to Stack
        Recycled
        Slurry
Reaction
Tank
Slurry
Bleed
                                                           Liquid
Thickening/
Dewatering
Sludge
_• -«»• __• ^
Disposal
                                                           Recycle
                                                                                  Key
                                                                                  o
                                                                                  RVV1
                                                                                  L
                                          J
                                             Inputs
                                             Flue Gas Pathway
                                             Liquid Pathway
                                             Sludge Pathway
                                             Optional Processes

                                             Major Processes
                                                                                                                      10
                                                                                                                      Ln
Source:   Tetra Tech Inc.,  Physical-Chemical Characteristics of Utility Solid
          Wastes.  Prepared  for Electric Power Research Institute, September
          1983, p.  4-3.

-------
                                      3-26





A flow diagram of a spray-drying system is presented in Exhibit 3-11.  With



this system, a fine spray of an alkaline solution is injected into the flue gas



as it passes through a contact chamber, where the reaction with the sulfur



oxides occurs.  The heat of the flue gas evaporates the water from the



absorbent solution, leaving a dry powder.  This powder is then collected



downstream of the contact chamber by a particulate collector, usually a



baghouse.  Spray-drying typically removes about 70 percent of the sulfur



dioxide from the flue gas.    Because of the relatively low percentage



reduction in sulfur dioxide achieved by spray-drying scrubbers compared with



other scrubber technologies, this dry-scrubbing method is most commonly used



for furnaces that burn lower sulfur coals.







    Dry sorbent injection, illustrated schematically in Exhibit 3-12, is not



yet used commercially by electric utilities, although one utility is designing



a generating unit that will use this type of scrubber and which is due to begin


                  18
operation by 1990.    This system involves the injection of a powdered sorbent,



either nacholite or trona, into the flue gas upstream of a baghouse.  Sulfur



dioxide reacts with the reagent in the flue gas and on the surface of the



filter in the baghouse.  The dry wastes, which form a filter cake, are then



removed during normal filter cleaning.







    Dry injection offers several advantages over traditional wet scrubbing and



spray-drying techniques:  the required equipment is smaller and less expensive,



no water is needed, flue gas reheating is not necessary, and sulfur dioxide and



fly ash are removed simultaneously.  Potential drawbacks of this process are



the limited geographic availability of the sorbents and problems associated



with waste disposal.  For example, the waste tends to be very water soluble,

-------
                                          EXHIBIT 3-11

               FLOW DIAGRAM OF SPRAY-DRYING  FLUE GAS DESULFURIZATION  SYSTEM
                                  Spray
                                  Absorber
                Slurried
                Absorbent
                (Soda ash.
                trona.lime)
                              Mixed
                              Slurry
	+
                            Dust
                            Collector
Slurry
Tank
                   Partial
                   Solids Recycle
                                                 Cleaned Gas
                                                                                             to Slack
                                  Dry Waste Removal
                                  lor Processing or
                                  Disposal
                                                                               Key
                                                                                     ro
                                                                               o
                                                       Inputs
                                                       Gas Pathway
                                                       Slurry or Wet
                                                       Solids Pathway
                                                       Dry Waste Output
                                                       Optional Processes
                                                       Major Processes
Source:   Tetra Tech Inc., Physical-Chemical Characteristics of Utility Solid
          Wastes.  Prepared for  Electric  Power Research Institute,  September
          1983, p.  4-5.

-------
                                          EXHIBIT 3-12

            FLOW  DIAGRAM  OF  DRY INJECTION  FLUE GAS  DESULFURIZATION SYSTEM

      Dry Absorbent
      (limestone, lime,
      soda ash. nahoolile,
      trona) added by
      process AorB
                                  Dry Sorbent
                                  Injection
                                                Dust
                                                Collector
B
                                                  Filter
                                                  Precoat on
                                                  Baghouse
                                               Cleaned Gas

                                               to Stack
                                   Dry Waste Removal
                                   for Processing or
                                   Disposal
                                                                             (-0
                                                                             I
                                                                             ro
                                                                             CO
                                                                               Key
                                                                               o
                                                                                      I
                                                Inputs
                                                Gas Pathway
                                                Solids Pathway
                                                Dry Waste Output
                                                Optional Processes
                                                Major Processes
Source:   Tetra Tech Inc., Physical-Chemical Characteristics of Utility Solid
          Wastes. Prepared for  Electric Power Research Institute,  September
          1983, p.  4-6.

-------
                                      3-29

and could potentially affect ground-water quality.  Also, dry injection is most
effective when used for low-sulfur coals, achieving only 70 to 80 percent
sulfur dioxide removal in most cases,  compared with up to 95 percent removal by
                      19
wet scrubbing systems.


    Recovery systems are designed to produce a salable by-product such as
sulfur, sulfuric acid, or liquid sulfur dioxide; however, small amounts of
waste are still produced.  A prescrubber is usually required upstream of the
main scrubber to filter out such contaminants as fly ash and chlorides.
Secondary waste streams formed by the oxidation of the absorbent are sometimes
present and, along with the prescrubber by-products, are the materials that
need to be disposed.  Two recovery FGD systems presently used commercially, the
Wellman-Lord and Magnesium Oxide processes, are both based on wet scrubbing.
Diagrams of these systems are shown in Exhibit 3-13.  Other recovery systems,
both wet and dry, have been developed, but are still in the testing phase.
                                                                             i

         3.2.2.2  Quantities of PGD Sludge Generated


    There has been a large increase in the quantity of FGD sludge generated
over the past decade, as shown in Exhibit 3-14.  This increase is due to the
                      i
more widespread use of scrubbers brought about by tightened state limits on
sulfur dioxide emissions, the Federal New Source Performance Standards (NSPS)
of the Clean Air Act of 1971, and the revisions to the NSPS in 1979.  This
trend will continue as new power plants are equipped with scrubbers as required
under the NSPS.  By the year 2000, scrubber capacity is likely to be several
times greater than at present.

-------
                                   EXHIBIT 3-13

             FLOW DIAGRAMS OF  RECOVERY FLUE GAS DESULFURIZATION SYSTEMS

                                 WELLMAN-LORD PROCESS









GAS —
FIOM BOILEI
P








WET
SCRUMER
1
ARTKULATI
DE








mrn^m
ES
SULFUR
nut t










IZED
Kit
S

\
»
AISO
it.
^r

V
"1
SI

N
J&
/
HER


A
y
C
JLUII
IN N


-«—




J~


ONEN
•NSO]
SOLUTION OF



RECYCLE ^^-X
COLO / >
SLURRY/ CH|UH
1 . CRYSTALLIZE
<9f ( ,
jcp vx
itFRICERANTT 1

H»2S04 SLURRY
RICKED
•
N.HSO



;
i


H
J joi
SCPAR
1_
i
PUI
jANDN.^,

S0|.r—
WATER 1
S^^
j| EVAPORAT
RECYCLE
HOT)
"T ^J^-
l/?
-------
               EXHIBIT 3-13 (Continued)


FLOW DIAGRAMS OF RECOVERY FLUE GAS DESULFURIZATION SYSTEMS

                 MAGNESIUM OXIDE PROCESS

FLUE CAS CO
ELECTROSTAIC
PRECIPITATOR
CAS 	 —
FROM ROM FR
VW
DRY ASH | 1 _J
-
I
MAKE UP^
WATER ^
WETASH 1 A« 1 11
SEPARATOR ~~



M«0 SLURRY
FROM ACID PLANT
LNUOR




Source: Federal Power Commission,
Applications in the Unitec

MTAWWC SO | AND SOME FLY ASH

I
S H
SCRUIIER-
AISOR1ER
STACE 1
' FLY ASH
•ocu ^ ,ilwyu )
\/ \ 	 /
jf FLUICASCONTAIHIMCSO,
WATER. ASH
SCRUIIER-
^^^^^^^^^^, STACE II * riuf crifff
RECYCLE 1 10 , REMOVAL J
SLURRY >L /
s\ /

RLEEO STREAM Mrf0< MfSO, M,0
• * im int

/ TO ACID PLANT

The Status of Flue Gas Desulfurization
i States: A Technological Assessment,
                                                                               CO
                                                                               I
 July 1977, pp. VII-27, VII-30.

-------
     Gigawatts
   (10 3 Megawatts)
                                       3-32
                                 EXHIBIT 3-14

                    FGD CAPACITY AND FGD SLUDGE  GENERATION
                                   1970-2000
                  200
                                     FGD Capacity
                           1975   1980    1985   1990   1995   2000
                                                 Estimated
                                FGD Sludge Generation
        Millions
        of Tons
                    1970   1975    1980    1985   1990   1995   2000
                                                 Estimated

Source:     1970-1984:   Energy Information  Administration, Cost and Quality
           of Fuels  for Electric  Utility Plants,  and Arthur D. Little, Inc.,
           Full Scale  Field Evaluation  of  Waste Disposal  from Coal-Fired
           Electric  Generating Plants.  Vol.  1, June 1985.

           1985-2000:   ICF Incorporated.   See Appendix B  for in-depth
           discussion  of the methodologies used to develop
           these estimates.

-------
                                      3-33





    The dramatic increase in scrubber capacity has a direct effect on the



amount of scrubber sludge produced.  In 1984, about 16 million tons of scrubber



sludge were generated.  By 2000, the annual amount of sludge produced is



estimated to be about 50 million tons, over three times the sludge generated at


      «. 20
present.








    All FGD sludge is comprised of spent reagent, which is made up of the



chemicals that result from the reaction of the absorbent with the sulfur oxides



in the flue gas, plus any unreacted portion of the absorbent.  The sludge may



also contain water and fly ash.  Several factors determine how much spent



reagent, water, and ash are present in the FGD sludge.  These factors include



the type of scrubber system used, the characteristics of the coal, and the



sulfur dioxide emission limit that the power plant is required to meet by state



or Federal law.








    The type of FGD system is an important determinant of the amount of spent



reagent, amount of water, and amount of ash present in the sludge.  Reagents



used in different systems vary as to their absorbent utilization, or



"stoichiometry," which is the percentage of the reagent that reacts with the



sulfur oxides.   A lower percentage implies more reagent is needed to remove a



given percentage of sulfur dioxide.  Direct limestone systems have an average



absorbent utilization of 80 percent, while the direct lime and dual-alkali



processes both achieve higher utilization of 90 and 95 percent, respectively.



This results in the generation of about six percent more sludge by direct


                                                                      21
limestone scrubbers compared to direct lime and dual-alkali processes.

-------
                                      3-34






    Wet systems, both non-recovery and recovery, employ aqueous solutions to




remove the sulfur oxides from the flue gas.  Dry FGD systems use no water for




sulfur oxide removal, although dry FGD wastes may be mixed with water prior to




disposal, which increases the volume of sludge.  Because of their dependency on




water, wet FGD systems generally produce larger volumes of wastes than do dry




systems.








    Wet FGD systems can also be used as fly ash removal devices.  The amount of




ash in the sludge depends on how much fly ash is generated by the boiler and




whether any other particulate control device is upstream of the scrubber.  In




particular, alkaline fly ash scrubbers rely on the entrapment of ash to act as




their primary absorbent, and therefore their sludge contains large amounts of




ash.  The collection of fly ash and wastes in a spray-drying system occurs




simultaneously by a baghouse; therefore, the wastes from these systems also




contain large proportions of ash.  Recovery FGD systems often require




prescrubbers to remove fly ash.  Although recovery systems produce only about




half the wastes of non-recovery systems, these wastes are predominantly made up




of ash.








    Specific characteristics of the coal can have a large effect on the




quantity of sludge generated.  For example, the higher the sulfur content, the




more reagent that must be used to achieve a certain level of sulfur dioxide




removal and, consequently, the more spent reagent in the sludge.  The ash




content of the coal affects the amount of ash caught up in the sludge.  Just as




using low-sulfur coal will reduce the amount of spent reagent, reducing the ash




content prior to combustion will greatly reduce the amount of fly ash that is




absorbed by wet scrubbers and thus the amount of sludge that must be disposed.

-------
                                      3-35
    The amount by which a power plant must reduce sulfur dioxide emissions also



affects the volume of sludge produced.  To achieve a higher reduction,



the amount of reagent used in the scrubber needs to be increased, which will,



in turn, produce greater quantities of sludge.








         3.2.2.3  Physical Characteristics of FGD Sludge








    In general, the same physical properties important in determining the



disposal behavior of ash are also important determinants of the disposal



characteristics of FGD sludge.   These physical characteristics -- particle



size, compaction behavior, permeability, and shear strength -- vary



considerably depending on the type of scrubber system and what (if any)



preparation is done prior to disposal.  Exhibit 3-15 presents representative



ranges of values for these characteristics of FGD sludge.



                                                                             j




    Depending on the type of FGD system used, the particle size distribution of



FGD sludge can vary substantially.  For example, sludge from wet scrubbers



tends to have a narrow range of particle sizes.  The particles produced by



dual-alkali systems are finer than those produced by direct lime or limestone



scrubbers, while dry scrubbers  generally produce sludge containing larger



particles.








    The density of FGD sludge depends directly on the method of handling.  Wet



sludge mixed with ash will have a higher density than untreated sludge, while


                                                  22
chemical fixation increases the density even more.    The density of the



particles in dry sludge varies  widely.

-------
                                  3-36
                           EXHIBIT 3-15

             REPRESENTATIVE RANGES OF VALUES FOR THE
              PHYSICAL CHARACTERISTICS OF FGD SLUDGE
                                         Wet             Dry

Particle Size (mm)                    .001-.05       .002-.074

Density (g/cm3)                        0.9-1.7        Variable

Optimum Moisture Content (%)           16-43          0

Permeability (cm/sec)                  10"6-10"4      10~7-10"6

Unconfined Compressive Strength        0-1600         41-2250
(psi)
Source: Tetra Tech Inc., Physical-Chemical Characteristics of Utility
        Solid Wastes, prepared for Electric Power Research Institute,
        EPRI EA-3236, September 1983, pp. 4-8 - 4-15.

-------
                                      3-37





    The solids content of scrubber sludge is a function of many things,



including whether the sludge is treated prior to disposal, the size of the



particles in the sludge, the sulfur content of the coal, the amount of ash



present in the sludge, and the desulfurization process used.  The percentage of



solids in untreated sludges usually ranges from 20 to 40 percent, although it


                             23
can be as high as 60 percent.    Depending on the method of treatment used



before disposal (if any), the percentage of solids could be much higher.  In



fact, some chemical fixation processes are designed to transform the sludge



into a cement-like product.







    The permeabilities of untreated FGD sludges from wet scrubber systems



generally are very similar.  Mixing the sludge with fly ash does not



necessarily change the degree of permeability, although if fly ash acts as a



fixative when added to the sludge, the mixed waste product will have a reduced



permeability.  Chemical fixation also can decrease permeability.  Sludge from



dry scrubber systems has low permeability relative to sludge from wet systems.







    The shear strength of FGD sludge is referred to as "unconfined compressive



strength," which reflects the load-bearing capacity of the sludge.  The



unconfined compressive strength of sludge is sensitive to the moisture content



and age of the sludge.  Untreated wet sludge has no compressive strength and is



similar to toothpaste in this respect.  Mixing with ash or lime increases



compressive strength, as does chemical fixation.  Also, as the treated sludge



ages, its compressive strength becomes greater.

-------
                                      3-38




        3.2.2.4  Chemical Characteristics of FGD Sludge





    The major constituents found in wet FGD sludge are determined by the


absorbent reagent used, the quantity of fly ash present, the sulfur content of


the coal, and whether or not forced oxidation is used.





    Most wet FGD systems operate by causing the sulfur dioxide in the flue gas


to react with an absorbent reagent, such as lime or limestone, to form a


calcium compound, such as calcium sulfite (CaS03),  calcium sulfate or gypsum


(CaS04),  or calcium sulfite-sulfate (CaS03'CaS04),  which can then be removed


from the system in the sludge.   The ratio of calcium sulfate to calcium sulfite


is generally greater in sludge  generated by direct limestone scrubber systems


than in that produced by direct lime systems.





    Dual-alkali scrubber systems differ slightly in that they use absorbent


solutions containing sodium hydroxide (NaOH) or sodium sulfite (Na2S03) as well


as lime;  sludges from these processes tend to have high levels of calcium


sulfite and sodium salts.  Because these compounds are highly soluble and apt

                                                                            24
to leach, they may pose problems as major components in a landfilled sludge.





    Spray-drying scrubber systems produce particulates containing either sodium


sulfate (Na2S04) and sodium sulfite (Na2S03) or calcium sulfate (CaS04) and


calcium sulfite (CaS03),  depending on whether the reagents are sodium-  or


calcium-based.





    Exhibits 3-16 and 3-17 show the major chemical constituents found in sludge


solids and sludge liquors.  Oxides of calcium, silicon, magnesium, aluminum,


iron,  sodium,  and potassium can be found in most FGD sludge.   The presence of

-------
                                      3-39
                               EXHIBIT 3-16

              CONCENTRATION OF MAJOR CHEMICAL CONSTITUENTS
               OF WET FGD SLDDGE SOLIDS BY SCRUBBER SYSTEM
                            AND SOURCE OF COAL *
                            (percent of total)
Direct
East
15-19
13-69
Lime
West
17-95
2-11
Direct Limestone
East West
5-23 85
17-50 8
Dual-Alkali
East West
15-68 82
13-68 1
Alkaline
Flv Ash
West
20
15
Calcium Sulfate
(CaS04)

CaS03-l/2 H20

Calcium Sulfite
(CaS03)          1-22      0-3      15-74       6       8-10   11

Sodium Sulfate
(Na2S04-7H20)     --       --        --        --       4-7     4

Fly Ash          16-60     3-59      1-45       3       0-7     8        65
*   Source of coal is categorized by Eastern producing regions (Northern
    Appalachia, Central Appalachia, Southern Appalachia, Midwest, Central West,
    and Gulf; i.e., Bureau of Mine (BOM) Districts #1-15, 24) and Western
    producing regions (Eastern Northern Great Plains, Western Northern Great
    Plains, Rockies, Southwest, and Northwest; i.e., BOM Districts #16-23).

Source:   Tetra Tech Inc.,  Physical-Chemical Characteristics of Utility Solid
         Wastes, prepared for Electric Power Research Institute,  EPRI EA-3236,
         September 1983,  p. 4-18.

-------
                                      3-40
                                EXHIBIT 3-17

                CONCENTRATION OF MAJOR CHEMICAL CONSTITUENTS
                 OF VET FGD SLUDGE LIQUORS BY SCRUBBER SYSTEM
                           AND SOURCE OF COAL a/
Constituent b/
pH (units)
Total Dissolved
Solids
Chloride
Potassium
Sodium
Calcium
Magnesium
Sulfate
Sulfite
Direct Lime
East
8-9.4
2,800 -
10,260
1050-4900
11-28
36-137
660-2520
24-420
800-4500
0.9-2.7
Direct
East
5.5-8.4
5400
1000
24
12
1600
53
2500
160
Limestone
West
6.6-6.8
3300-
14,000
620-4200
8-28
370-2250
390-770
3-9
1360-4000
1-3900
Dual -Alkali
East
12.1
155,700
4900-5600
320-380
53,600-55,300
7-12
0.1
80,000-84,000
_ _
a/  Source of coal is categorized by Eastern producing regions (Northern
    Appalachia, Central Appalachia,  Southern Appalachia,  Midwest,  Central West,
    and Gulf; i.e., BOM Districts #1-15,  24) and Western producing regions
    (Eastern Northern Great Plains,  Western Northern Great Plains, Rockies,
    Southwest, and Northwest; i.e.,  BOM Districts #16-23).

b/  All constituent concentrations,  unless noted, in milligrams per liter.

Source:  Tetra Tech Inc.,  Physical-Chemical Characteristics of Utility Solid
         Wastes, prepared for Electric Power Research Institute,  EPRI EA-3226,
         September 1983,  p. 4-20.

-------
                                      3-41





these compounds results from the presence of fly ash In the sludge, and they are



unreactive in FGD systems.  In wet scrubbers that also serve as fly ash



collection devices, more than 50 percent of the sludge solids may be ash.



However, when an ESP or baghouse precedes the scrubber, ash may make up less


                                     25
than 10 percent of the sludge solids.







    The calcium sulfate/calcium sulfite ratio of the sludge solids is important



because sludge containing a greater proportion of sulfates has better disposal



properties due to its lower solubility.  This ratio is usually higher in systems



scrubbing lower sulfur coals and in direct limestone systems.  Many scrubber



systems add a forced oxidation step .to lower the calcium sulfite content of the



sludge, thereby lowering its solubility.







    The concentration of trace elements in FGD sludge reflects the levels of



trace elements in the ash, the efficiency of the scrubber in capturing trace

                                                                             i

elements in the flue gas,  and the trace elements present in the reagent and in



the process makeup waters.  Fly ash is the primary source of most of the trace



elements found in scrubber sludge.  Some elements, such as mercury and selenium,



may be scrubbed directly from the flue gases and then captured in the scrubber



sludge.  Exhibit 3-18 illustrates the concentrations at which major trace



elements are found in sludge from wet scrubber systems.







3.3  LOW-VOLUME WASTES







    Low-volume utility wastes are those waste streams generated in the routine



cleaning of plant equipment and in purifying of water used in the combustion



process.  The types and volumes of low-volume wastes vary among different power

-------
                                3-42
                        EXHIBIT 3-18

CONCENTRATION OF TRACE ELEMENTS FOUND IN WET-FGD SLUDGES
                     (Solids and Liquors)
Sludge Solids
Ranee
Low









&/
Arsenic
Boron
Cadmium
Chromium
Copper
Fluoride
Mercury
Lead
Selenium
Sludge
0
42
0
1
6
266
0
0
2
.8
.0
.1
.6
.0
.0
.01
.2
.0
High
52.0
530.0
25.0
180.0
340.0
1017.0
6.0
290.0
60.0
solid concentrations
a/

Median
12
14
10
15
17
625
0
2
.0
.6
.0
.5
.0
.4
.4
5.0
in milligrams

-LS
0.
2.
0.
0.
0.
0.
0.
0.
Sludge
Liauors b/
Range
iW
0004
1
002
0002
0045
2
00006
005
0.003
per kilogram
b/ Sludge liquor concentrations in milligrams per liter.
Source: Tetra Tech Inc.. Physical -Chemical Characteristics

Hi eh Median
0
76
0
0
0
63
0
0
1
.1
.0
.1
.3
.5
.0
.1
.5
.9
of Utility
0.03
14.9
0.02
0.02
0.03
2.3
0.005
0.03
0.18
Solid
  Wastes,  prepared for Electric Power Research Institute,  EPRI EA-3226,
  September 1983,  p.  4-24.

-------
                                      3-43






plants, depending on plant-specific factors such as the size of the plant,  the




type of equipment, and the age of the equipment.  Some low-volume wastes




commonly produced are:








        •   boiler blowdown.




        •   coal pile runoff.




        •   cooling tower blowdown.




        •   demineralizer regenerants and rinses.




        •   metal and boiler cleaning wastes.




        •   pyrites.  and




        •   sump effluents.








    Estimates of the  total amount of low-volume wastes generated each year  by




coal-fired power plants are not available.   The frequency of generation and the




quantities generated  vary widely from power plant to power plant, depending on




the maintenance requirements  of the plant and  operating conditions.   Variations




also occur within the same power plant,  according to its maintenance schedule




and operations.  Exhibit 3-19  gives representative annual production figures




for low-volume wastes generated by a typical power plant.








    This section presents for  each type  of low-volume waste a brief description




of how the waste is generated,  typical quantities  produced, and the physical




and chemical composition of the waste.








    3.3.1  Boiler Blowdown








    Boiler systems can be either a once-through (supercritical) type or a

-------
                                      3-44
                                  EXHIBIT 3-19

                     ANNUAL LOW-VOLUME HASTE GENERATION
                AT A REPRESENTATIVE COAL-FIRED POWER PLANT *
              Type of Waste

        Boiler Slowdown

        Coal Pile Runoff

        Cooling Tower Slowdown

        Demineralizer Regenerant

        Gas-side Boiler Cleaning

        Water-Side Boiler Cleaning

        Pyrites
 Average Annual Production

11 million gallons/year

20 inches/year

2.6 billion gallons/year

5 million gallons/year

700,000 gallons/year

180,000 gallons/year

65,000 tons/year
*   Assuming a 500 megawatt power plant, operating at 70 percent capacity.

Sources: Envirosphere Company, Information Responding to EPA's Request
         Regarding Burning and Co-Treatment/Co-Disposal of Low Volume Wastes
         Generated at Fossil Fuel Fired Electric Generating Stations, prepared
         for Utility Solid Waste Activities Group and Edison Electric
         Institute, August 1981.

         U.S. Environmental Protection Agency,  Waste and Water Management for
         Conventional Coal Combustion Assessment Report - 1979: Volume II:
         Water Management. EPA-600/7-80-012b, March 1980.

-------
                                      3-45



drum-type.  In drum-type boiler systems, after steam passes through the

turbines, it is converted back to water in the condenser and is recirculated

through the boiler to produce steam again.   In this process, impurities that

become concentrated in the feedwater periodically must be purged from the

system.  This waste stream is known as boiler blowdown.  A once-through system,

however, maintains pressurized "steam throughout the cycle, and thus does not

require the recirculation of water.  These boiler types, therefore, do not

generate boiler blowdown.




    Boiler blowdown is produced either in a continuous stream or intermittently

during the day.  The flow is adjusted in order to maintain the desired water

quality in the boiler and is dependent on the quality of the feedwater and the

size and condition of the boiler.  The average blowdown rate for a 500 megawatt

unit can range from 20 to 60 gallons per minute, or about 2 to 7 gallons per
              O £
megawatt-hour.




    Boiler blowdown is generally fairly alkaline with a low level of total

dissolved solids.  The waste stream usually contains certain chemical additives

used to control scale and corrosion.  Trace elements commonly found in boiler

blowdown are copper, iron, and nickel.  The components and characteristics of

boiler blowdown are presented in Exhibit 3-20.




    3.3.2  Coal Pile Runoff




    Power plants typically maintain two types of coal storage piles in their

coal yards:  an active pile to supply their immediate needs and an inactive or

long-term pile, which generally stores a 60- to 90-day supply of coal.  Coal

-------
                                      3-46


                                  EXHIBIT 3-20

                       CHARACTERISTICS OF BOILER SLOWDOWN
                                                            a/
                                                       Range
	Parameter	                             Low           High

pH (units)                                        8.3          12.0
Total Solids                                    125.0       1,407.0
Total Suspended Solids                            2.7          31.0
Total Dissolved Solids                           11.0       1,405.0
BODS                                             10.8          11.7
COD                                               2.0         157.0
Hydroxide Alkalinity                             10.0         100.0
Oil and Grease                                    1.0          14.8
Phosphate (total)                                 1.5          50.0
Ammonia                                           0.0           2.0
Cyanide (total)                                   0.005         0.014
Chromium (total)                                  0.02           b/
Chromium (Hexavalent)                             0.005         0.009
Copper                                            0.02          0.2
Iron                                              0.03          1.4
Nickel                                            0.03           b/
Zinc                                              0.01          0.05
a/  All concentrations, unless noted, in milligrams per liter.

b/  Data on these elements were limited.

Source: Envirosphere Company, Information Responding to EPA's Request
        Regarding Burning and Co-Treatment/Co-Disposal of Low Volume
        Wastes Generated at Fossil Fuel Fired Electric Generating
        Stations, prepared for Utility Solid Waste Activities Group and
        Edison Electric Institute, August 1981.

-------
                                      3-47
piles are usually 25-40 feet high and can cover an area of up to 75 acres,

                                                     27
depending on the size and demands of the power plant.    Inactive coal piles


are generally sealed with a tar spray to protect the coal against the weather;


active piles are usually open and exposed.  Coal pile runoff is formed when


water comes into contact with the piles, whether from rainfall or snowfall,


during spraying for dust control, or from underground streams that surface


under the piles.





    The quantity of coal pile runoff depends primarily on rainfall and, to a


lesser extent, the permeability of the soil.  It has been estimated that,  on


average, 73 percent of the total rainfall on coal piles becomes coal pile

    -_ 28
runoff.
    The composition of coal pile runoff is influenced by the composition of the


coal, the drainage patterns of the coal pile, and the amount of water that has

                                                                             l
seeped through.  Bituminous coals generate runoff that is usually acidic,  with


the level of acidity depending on the availability of neutralizing materials in


the coal, while subbituminous coals tend to produce neutral to alkaline runoff.


Elements commonly found in high concentrations in coal pile runoff are copper,


zinc, magnesium, aluminum, chloride, iron, sodium, and sulfate.  Exhibit 3-21


displays ranges of concentrations for these and other characteristics.





    3.3.3  Cooling Tower Slowdown





    Power plants need cooling systems to dissipate the heat energy that remains

                                    29
after the production of electricity.    The two major types of cooling systems


are once-through and recirculating.  Cooling tower blowdown generally refers to

-------
                                      3-48
                                  EXHIBIT 3-21

                     CHARACTERISTICS OF COAL PILE RUNOFF
                                                        Ranee
     Parameter
pH (units)
Acidity (as CAC03)
Total Dissolved Solids
Total Suspended Solids
Aluminum
Ammonia
Arsenic
Beryllium
Cadmium
Chloride
Chromium
Cobalt
Copper
Iron
Magnesium
Manganese
Mercury
Nickel
Nitrate
Phosphorus
Selenium
Sodium
Sulfate
Zinc
Low
2.1
300.0
270.0
8.0
20.0
0.0
0.005
0.01
0.001
3.6
0.005
0.025
0.01
0.1
0.0
0.9
0.0002
0.1
0.3
0.2
0.001
160.0
130.0
0.006
Hi eh
9.3 by
7,100.0
28,970.0
2,500.0
1,200.0
1.8
0.6
0.07
0.003
481.0
16.0
--
6.1
5,250.0
174.0
180.0
0.007
4.5
1.9
1.2
0.03
1,260.0
20,000.0
26.0
a/ All concentrations, unless noted, in milligrams per liter.

b/  Electric Power Research Institute,  Manual For Management of Low-Volume
    Wastes From Fossil-Fuel-Fired Power Plants, prepared by Radian Corporation,
    Austin, Texas, July 1987.

Source: All information, unless noted otherwise, is from Envirosphere Company,
        Information Responding to EPA's Request Regarding Burning and
        Co-Treatment/Co-Disposal of Low Volume Wastes Generated at Fossil Fuel
        Fired Electric Generating Stations, prepared for Utility Solid Waste
        Activities Group and Edison Electric Institute, August 1981.

-------
                                      3-49

the water withdrawn from a recirculating cooling system to control the
concentration of impurities in the cooling water; although once-through systems
also discharge water from the cooling system, this discharge is not typically
referred to as cooling tower blowdown.  At present, about two-thirds of
electric utility power plants use a once-through cooling system.  This
percentage may decrease, however, due to concern over water availability and
potential environmental concern over thermal discharges; consequently, future
plants may be built with recirculating systems that use cooling towers or
   . .       ,30
cooling ponds.


    Once-through cooling systems are primarily used by power plants located
next to large bodies of water.  After passing through the condenser, the
cooling water is discharged, usually into a river, lake, or pond.  The quantity
discharged ranges from 26,000 to 93,000 gallons per megawatt-hour.  For a 500
                                                                    31
megawatt plant, this roughly equals 70-300 billion gallons per year.    In most
instances, the chemical composition of the water remains the same after passing
through the condenser, but some changes may occur as the result of the
formation of corrosion products or the addition of biocides.


    Recirculating cooling systems can use either cooling ponds or cooling
towers.  In a cooling pond system, water is drawn from a large body of water,
such as a pond or canal.  After it passes through the condenser to absorb waste
heat, the water is recycled back into the pond or canal.  Cooling tower systems
operate by spraying the water through a cooling tower.  About 80 percent of the
waste heat contained in the water is then released through evaporation.  The
remainder of the water is recycled back through the cooling tower system.
Cooling tower blowdown is a waste stream bled off to control the concentrations

-------
                                      3-50
of impurities and contaminants in the cooling system that could lead to scale


                           32
formation in the condenser.
    The cooling tower blowdown rate is adjusted to maintain water quality in



the recirculating cooling system in order to prevent scale formation in the



condenser.  The quantity of blowdown generated is a function of the quality of



the makeup water (the water added to the system to replace that which is lost



by evaporation and blowdown), the condition of the cooling system, and the



amount of water evaporated by the cooling tower.  For a representative 500



megawatt unit, the blowdown rate varies between 2 and 30 cubic feet (15 to 225



gallons) per second.








    The composition and quantity of cooling tower blowdown varies greatly from



plant to plant.  It generally reflects the characteristics of the makeup waters



(e.g., fresh water versus brackish or saline water) and the chemicals added to



prevent the growth of fungi, algae, and bacteria in the cooling towers and to



prevent corrosion in the condensers.  Some of these chemical additives are



chlorine, chromate, zinc, phosphate, and silicate.  Ranges of concentration for



some of the characteristics and components of cooling tower blowdown are shown



in Exhibit 3-22.








    3.3.4  Denineralizer Regenerant and Rinses








    A power plant must treat water prior to its use as makeup water.  The use



of demineralizers is the most common method of purification.  During the



demineralization process, which may entail several rinses, high-purity process



water is provided for the boiler through an ion exchange process.  The wastes

-------
                                      3-51
                                  EXHIBIT 3-22

                  CHARACTERISTICS OF COOLING TOWER SLOWDOWN
                                                             a/
                                                        Range
     Parameter	                              Low          High
Alkalinity (as CaC03)                               8.0         556.0
BOD                                                --            94.0
COD                                                --           436.0
Total Solids                                      750.0      32,678.0
Total Dissolved Solids                              4.1      32,676.0
Total Suspended Solids                              0.2         220.0
Ammonia (as N)                                      0.01         11.6
Nitrate (as N)                                      0.1         711.0
Phosphorus (as P)                                   0.1          17.7
Total Hardness (as CaC03)                          84.0       2,580.0
Sulfate                                             7.2      20,658.0
Chloride                                            5.0      16,300.0
Fluoride b/                                         0.3          33.0
Aluminum b/                                     1,100.0       1,700.0
Boron b/                                            0.5           1.0
Chromium (ug/1)                                     0.02        120.0
Copper (ug/1)                                       0.01      1,740.0
Iron (ug/1))                                        0.1       1,160.0
Lead (ug/1) b/                                      4.0
Magnesium (ug/1)                                    0.1       1,580.0
Manganese (ug/1) b/                                24.0         220.0
Mercury (ug/1) b/                                   1.5
Nickel (ug/1)                                       0.03        150.0
Zinc (ug/1)                                         0.02      3,000.0
Oil & Grease                                        1.0           7.4
Phenols (ug/1)                                     --            72.0
Surfactants                                         0.2
Sodium                                              3.4      11,578.0
a/  All concentrations, unless noted, in milligrams per liter.

b/  Data on these elements were limited.

Source: Envirosphere Company, Information Responding to EPA's Request Regarding
        Burning and Co-Treatment/Co-Disposal of Low Volume Wastes Generated at
        Fossil Fuel Fired Electric Generating Stations, prepared for Utility
        Solid Waste Activities Group and Edison Electric Institute, August
        1981.

-------
                                      3-52





produced in this process can be either acidic or alkaline.  When sulfuric acid



is employed as the regenerant, calcium sulfate is precipitated in the waste



stream.  Exhibit 3-23 presents ranges for the components of demineralizer



regenerants and rinses.







    Regeneration of boiler makeup water by demineralizers is done on a batch



basis.  The frequency with which the process occurs depends on the quality of



the incoming water, although for a 500 megawatt unit, regeneration usually



occurs every one to four days.  A single regeneration requires approximately



30,000 gallons of water, which amounts to about 3-10 million gallons per


     34
year.







    3.3.5  Metal and Boiler Cleaning Wastes







    This category of low-volume waste streams can be divided into two basic



types:  gas-side cleaning wastes and water-side cleaning wastes.  Gas-side



wastes are produced during maintenance of the gas-side of the boiler, which



includes the air preheater, economizer, superheater, stack, and ancillary



equipment.  Residues from coal combustion (such as soot and fly ash), which



build up on these surfaces, must be removed periodically -- usually with plain



water containing no chemical additives.







    Water-side wastes are produced during cleaning of the boiler tubes, the



superheater, and the condenser, which are located on the water-side or



steam-side of the boiler.  The scale and corrosion products that build up on



these boiler parts must be removed with cleaning solutions containing chemical



additives.

-------
                                      3-53
                                  EXHIBIT 3-23

                               CHARACTERISTICS OF
                        SPENT DEMINERALIZER REGENERANTS
     Parameter
 Low
                                                        Range
   High
Alkalinity (as CaC03)
BOD
COD
Total Solids
Total Dissolved Solids
Total Suspended Solids
Ammonia (as N)
Phosphorus (as P)
Turbidity (JTU)
Total Hardness (as CaC03)
Sulfate
Chloride
Boron
Chromium
Copper (ug/1)
Iron (ug/1)
Lead (ug/1) b/
Magnesium (ug/1)
Manganese (ug/1)
Mercury (ug/1)
Nickel (ug/1)
Zinc (ug/1)
Oil & Grease b/
Phenols (ug/1)
Surfactants b/
Nitrate as N
Algicides b/
Sodium
  0.0
  0.0
  0.0
284.0
283.0
  0.0
  0.0
  0.0
  2.5
  0.0
  4.5
  0.0
  0.0
  0.0
  0.0
  0.0
160.0
  0.0
  0.0
  0.05
  0.0
  0.0
  0.0
  0.0
  1.7
  0.0
  0.003
  4.9
  3,831.0
    344.0
    440.0
 36,237.0
 25,235.0
    300.0 c/
    435.0
     87.2
    100.0
  8,000.0
  9,947.0
 20,500.0
      0.1
  2,168.0
  3,091.0
  2,250.0
 37,500.0
    753.0
  3,100.0

    560.0
  4,500.0
     24.5
303,000.0

    118.0

 30,000.0
a/  All concentrations, unless noted, in milligrams per liter.

b/  Data on these components were limited.

c/ Electric Power Research Institute, Manual For Management of Low-Volume
Wastes From Fossil-Fuel-Fired Power Plants, prepared by Radian Corporation,
Austin, Texas, July 1987.

Source: All data, unless noted otherwise, are from Envirosphere Company,
        Information Responding to EPA's Request Regarding Burning and
        Co-Treatment/Co-Disposal of Low Volume Wastes Generated at Fossil Fuel
        Fired Electric Generating Stations, prepared for Utility Solid Waste
        Activities Group and Edison Electric Institute, August 1981.

-------
                                      3-54





    The boiler and auxiliary equipment are cleaned intermittently,  creating



large quantities of wastes in a short time.  Gas-side boiler cleaning is done



approximately twice a year.  The volume of the waste stream produced depends on



the size of the boiler and the number of rinses.  For a typical plant,  gas-side



cleanings can produce between 24,000 and 700,000 gallons of wastes.  Water-side



equipment is cleaned less frequently, approximately once every three years.  As



is true of gas-side cleaning, the volume of waste produced varies with the



number of rinses.  A representative 500 megawatt unit generates about


                                                    35
120,000-240,000 gallons of wastewater per treatment.







    Because no chemicals are used, the composition of the waste streams



associated with gas-side cleaning directly reflects the composition of the soot



and fly ash residues and, therefore, of the coal that is burned.  Exhibit 3-24



shows two reported values for components and characteristics of gas-side



cleaning waste streams.







    The particular solution used for the cleaning of the water-side of the



boiler varies depending on the equipment being cleaned and the type of scale



that needs to be removed.  When the scale contains high levels of metallic



copper, an alkaline solution that contains ammonium salts, an oxidizing agent



such as potassium or sodium bromate or chlorate, and nitrates or nitrites is



used.  Exhibit 3-25 presents some of the major characteristics associated with



these types of solutions and representative ranges of concentrations in which



they are found.







    For the removal of scale caused by water hardness, iron oxides, and copper



oxide, an acid cleaning solution is needed.  Usually hydrochloric acid acts as

-------
                                      3-55


                               EXHIBIT 3-24

           REPORTED CHARACTERISTICS OF GAS-SIDE CLEANING WASTES
       Parameter
Cleaning Frequency (cycles/yr)
Batch Volume (1000 gallons)
Alkalinity
COD
Total Solids
Total Dissolved Solids
Total Suspended Solids
Turbidity (JTU)
Hardness
Ammonia
Chloride
Chromium (total)
Copper
Iron
Lead
Magnesium
Nickel
Nitrate
Phosphorus
Sodium
Sulfate
Vanadium
Zinc
Quantities Produced per Cleaning
   fin Ibs. except as noted) a/
Source A           Source B
     2.0
   720.0
     0.0
 1,134.0
40,861.0
35,127.0
 3,823.0
   476.0
35,409.0
     1.5
     0.0
     0.03

   900.0

11,949.0
    30.0
    14.7
    11.1
     0.0
11,949.0

    28.7
   8.0
  24.0
   6.0
  19.0
,002.0
,002.0
 119.1
  98.0
 791.4
   0.4
  18.0
   1.0
   0.3
  30.0

 190.3

   0.7
   0.3
   9.0
 299.4

   2.0
a/ Quantities produced are shown for two different reported values.

Source: Envirosphere Company, Information Responding to EPA's Request
        Regarding Burning and Co-Treatment/Co-Disposal of Low Volume
        Wastes Generated at Fossil Fuel Fired Electric Generating
        Stations, prepared for Utility Solid Waste Activities Group and
        Edison Electric Institute, August 1981.

-------
                                      3-56
                                  EXHIBIT 3-25

                      CHARACTERISTICS OF SPENT HATER-SIDE
                           ALKALINE CLEANING WASTES
                                                              fi/
                                                        Range
      Parameter	                              Low          High
Alkalinity (as CaC03)                           20,200.0     25,700.0
NH3-N                                            4,280.0      6,360.0
Kjeldahl-N                                       5,190.0      7,850.0
Nitrate-N                                            1.0        193.0
Oil & Grease                                         7.9         10.3
BODS                                             5,820.0      8,060.0
COD                                             14,600.0     20,900.0
Total Suspended Solids                           5,580.0      6,720.0
Total Dissolved Solids                              10.0        400.0
TDS                                             22,100.0     32,300.0
Total Iron                                   .      180.0     10,800.0
Silica                                               1.0         40.0
Chromium                                             0.2          7.7 b/
Copper                                               8.0      1,912.0
Lead                                                 0.004 b/    23.0 b/
Manganese                                            0.1         14.3
Nickel                                               2.5        130.0
Tin                                                  2.0         20.7
Zinc                                                 3.1        390.0
pH (units)                                           8.4 b/      10.3 b/
a/  All concentrations, unless noted, in milligrams per liter.

b/  Electric Power Research Institute,  Manual For Management of Low-Volume
    Wastes From Fossil-Fuel-Fired Power Plants, prepared by Radian Corporation,
    Austin, Texas, July 1987.

Source: All data, unless noted otherwise, are from Envirosphere Company,
        Information Responding to EPA's Request Regarding Burning and
        Co-Treatment/Co-Disposal of Low Volume Wastes Generated at Fossil Fuel
        Fired Electric Generating Stations,  prepared for Utility Solid Waste
        Activities Group and Edison Electric Institute, August 1981.

-------
                                      3-57






the solvent in these solutions, although sulfuric, phosphoric, and nitric acids




can also be used.  Organic acids have been used increasingly as substitutes for




hydrochloric acid because of their lower toxicity.  .For the removal of silica




deposits, hydrofluoric acid or fluoride salts are added to the cleaning




solution.  Exhibit 3-26 presents the various characteristics of acid boiler




cleaning solutions.








    Alkaline chelating rinses and alkaline passivating rinses are often used to




remove iron and copper compounds and silica and to neutralize any residual




acidity left over from acid cleaning.  These solutions may contain phosphates,




chromates, nitrates, nitrites, ammonia, EDTA, citrates, gluconates, caustic




soda, or soda ash.  Exhibit 3-27 gives representative ranges for these




components and others present in these rinses.








    3.3.6  Pyrites








    Pyrites are the solid mineral compounds, such as iron sulfides or other




rock-like substances, present in raw coal.   Most pyrites are generally




separated out before coal is burned, usually at a preparation plant prior to




shipment to the power plant.  Smaller quantities of pyrites are often removed




at the power plant just before the coal is pulverized.  The size of the




deposits depends on the method by which they are separated from the coal.








    The volume of pyrites collected at a power plant depends on the amount and




quality of the coal that is burned, which is determined by the source of the




coal and the preparation process, as well as by the coal pulverization process.

-------
                                      3-58
                                  EXHIBIT 3-26

                      CHARACTERISTICS OF SPENT WATER-SIDE
                      HYDROCHLORIC ACID CLEANING WASTES
      Parameter
  Low
                                                        Ranee
 High
pH (units)
Total Suspended Solids
Silica
NH3-N
Nitrogen
Phosphorus
Sulfate
Aluminum
Arsenic
Barium
Beryllium
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Nickel
Potassium
Selenium
Silver
Sodium
Tin
Zinc
   0.5
   8.0
  19.0
  80.0
   1.0
   1.0
   1.0
   6.5
   0.01
   0.1
   0.0
   0.001
  16.0
   0.005
   2.2
1125.0
   0.01
   5.7
   6.9
   0.0
   3.0
   1.4
   0.002
   0.02
   9.2
   1.0
   0.9
   3.3
2375.0
 280.0
 325.0
 870.0
 300.0
  10.0
   8.2
   0.1
   0.4
   0.1
   0.13 b/
 980.0
  16.8
 960.0
6470.0
   5.2
   8.8
  29.0
   0.002
 500.0
   2.3
   0.004
   0.2 b/
  74.0
   7.3
 840.0
a/  All concentrations, unless noted, in milligrams per liter.

b/  Electric Power Research Institute, Manual For Management of Low-Volume
    Wastes From Fossil-Fuel-Fired Power Plants, prepared by Radian Corporation,
    Austin, Texas, July 1987.

Source:  All data, unless noted otherwise, are from Envirosphere Company,
         Information Responding to EPA's Request Regarding Burning and
         Co-Treatment/Co-Disposal of Low Volume Wastes Generated at Fossil Fuel
         Fired Electric Generating Stations, prepared for Utility Solid Waste
         Activities Group and Edison Electric Institute, August 1981.

-------
                            3-59
                        EXHIBIT 3-27

             CHARACTERISTICS OF SPENT HATER-SIDE
                 ALKALINE FASSIVATING WASTES
                                               Range*
Parameter
pH (units)
Total Suspended Solids
NH3-N
Kjeldahl-N
Nitrite -N
BODS
COD
TOG
Iron
Chromium
Copper
* All concentrations ,
Source: Envirosphere
Regarding Bur
Generated at
Low
9.2
13.0
15.0
97.0
7.0
40.0
98.0
16.0
7.5
0.0
0.1
unless noted, in milligrams per liter.
Company. Information Responding to EPA's
ning and Co-Treatment/Co-Disposal of Low
High
10.0
45.0
232.0
351.0
12.9
127.0
543.0
23.0
28.0
0.4
1.2
Request
Volume Wastes
Fossil Fuel Fired Electric Generating Stations, prepar
for Utility Solid Waste Activities Group and Edison Electric
Institute, August 1981.

-------
                                      3-60
The amount of pyrites to be disposed at a power plant can vary considerably,


                                                         36
although coal typically contains up to 5 percent pyrites.    A 500 megawatt



plant, depending on how often it operates and the quality of its coal,  will



generate, on average, between 30,000 and 100,000 tons of pyrites per year.   The



characteristics of pyrites and pyrite slurry transport water are shown in



Exhibit 3-28.
    3.3.7  Sump Effluents







    Floor and yard drains collect waste streams from a variety of sources at



power plants, such as rainfall, seepage from ground-water sources,  leakage,



small equipment cleaning operations, and process spills and leaks.   As a



result, the composition of drain effluents is highly variable.  Depending on



the particular circumstances at the power plant, these waste streams may



contain coal dust, fly ash, oil, and detergents.







    The frequency of sump effluent generation and quantities generated are very



plant-specific.  The more efficient a plant's operating procedures,  the smaller



this waste stream will be.  Also, power plants located in dry areas  of the



country will have relatively small amounts of wastes collected in yard drains.







3.4  SUMMARY







    In the process of generating electricity, coal-fired utility power plants



produce a number of waste products.  These wastes are produced in large



quantities and have widely varying physical and chemical characteristics.

-------
                                      3-61
                                  EXHIBIT 3-28

                         CHARACTERISTICS  OF PYRITES AND
                             FYRITE TRANSPORT WATER
     Parameter
Total Suspended Solids
Total Aluminum
Total Calcium
Total Iron
Total Magnesium
Sulfate
pH (units)
Arsenic
Chromium
Copper
Lead
Zinc
Manganese
Selenium
Silica
Silver
Cobalt
Nickel
Vanadium
Pvrite Slurry Water

     1,700.0
        93.3
       134.0
       220.0
        13.6
       177.0
         7.7

         0.1
         0.1
         0.1
         0.3
       212.0
  Pyrites  b/
  Solid Form
  500-5000

 10-10,000
  200-1000
500-10,000
   10-5000
    10-100

     10-50
  100-5000
   10-1000
   100-200
a/  All concentrations, unless noted, in milligrams per liter.

b/  All concentrations in parts per million.

Source:  Envirosphere Company, Information Responding to EPA's Request
         Regarding Burning and Co-Treatment/Co-Disposal of Low Volume Wastes
         Generated at Fossil Fuel Fired Electric Generating Stations, prepared
         for Utility Solid Waste Activities Group and Edison Electric
         Institute, August 1981.

-------
                        3-62
Coal-fired electric utility power plants produce three
major forms of wastes:

1)   Ash, formed from the noncombustible material
     present in coal.  There are three types of
     ash -- fly ash, bottom ash, and boiler slag;

2)   FGD sludge, produced by flue gas desulfurization
     systems designed to remove sulfur oxides from
     flue gas; and

3)   Low-volume wastes, generated primarily from equipment
     maintenance and cleaning operations.

In 1984, about 69 million tons of ash and about 16
million tons of FGD sludge were produced by coal-fired
electric utilities.  By the year 2000, these wastes
are expected to increase to about 120 million and
50 million tons, respectively.
Several physical characteristics of utility waste
determine the waste's behavior during disposal and
the potential for leachate problems.  These
characteristics vary a great deal among the different
types of ash and FGD sludge.
The chemical constituents of ash and FGD sludge
largely depend on the chemical components in the coal.
Other chemical compounds present in FGD sludge,  primarily
calcium and sodium salts, are the result of the reactions
between the absorbent reagent used and the sulfur oxides
in the flue gas.
Compared with ash and FGD sludge, low-volume wastes are
generally produced in much smaller quantities.   Many
of these wastes contain various chemicals from the
cleaning solutions used for power plant operations
and maintenance; potentially-hazardous elements in
these chemicals may be found at high concentrations
in the low-volume waste.

-------
                               CHAPTER THREE

                                     NOTES
    1  See Appendix B for a more in-depth discussion of boiler types and how
the type of boiler affects the types of waste that are generated.

    2  Babcock & Wilcox, Steam:  Its Generation and Use. New York:  The Babcock
& Wilcox Company, 1978, p. 18-3.

    3  Ibid.

       Energy Information Administration, Cost and Quality of Fuels for
Electric Utility Plants-1985. DOE/EIA-0191(85),  July 1986.

    5 ICF Incorporated, Analysis of 6 and 8 Million Ton and 30 Year/NSPS and 30
Year/I.2 Pound Sulfur Dioxide Emission Reduction Cases, prepared for EPA,
February 1986.  There are many factors that can affect the amount of coal
consumed, including electricity growth rates, oil and gas prices, types of
technology available, etc.  Nevertheless, utilities will continue to burn
substantial amounts of coal in the foreseeable future.

    ^ Energy Information Administration, Electric Power Annual 1984.
DOE/EIA-0348(84), p. 45.

    ' There are presently over 500 coal cleaning plants in the U.S., the
majority of which are operated by coal companies and located at the mouth of
the mine.  The type of cleaning method employed depends upon the size of the
coal pieces to be cleaned, a factor that can be controlled at the cleaning
plant.

    The most widely used methods of coal cleaning are those that use specific
gravity, relying on the principle that heavier particles (i.e., impurities)
separate from lighter ones (i.e., coal) when settling in fluid.  A common
method of cleaning coarse coal pieces is to pulse currents of water through a
bed of coal in a jig; impurities, such as shale and pyrite, sink, while the
coal floats on top.  The heavy, or dense, media process is used for cleaning
coarse and intermediate-sized pieces.  A mixture of water and ground magnetite,
having a specific gravity between that of coal and its impurities, acts as a
separating fluid.  An inclined vibrating platform with diagonal grooves, known
as a concentrating table, also is used to clean intermediate-sized coal pieces.
Raw coal slurry is fed onto the high end of the table.  As the slurry flows
down, the vibrations separate the coal from the refuse, allowing the lighter
coal to be carried along in the water, while the heavier impurities are trapped
in the grooves.

    Because of their small size, fine coal particles are very difficult to
clean.  Their recovery is important, however, because these particles can
provide up to 25 percent of the energy derived from raw coal.   A popular method
of fine coal cleaning is froth flotation.  The coal pieces are coated with oil
and then agitated in a controlled mixture of water, air, and reagents
until froth is formed on the surface.  Bubbles tend to attach to the coal
pieces, keeping them buoyant, while heavier particles such as pyrite, shale,
and slate remain dispersed in the water.  The coal can then be removed from the

-------
                                      3-2
surface.  For more information, see Coal Preparation. 4th edition, Joseph
Leonard, editor, American Institute of Mining, Metallurgical, and Petroleum
Engineers, Inc., 1979.

    8 Ash melts when heated to a sufficiently high temperature.  The
temperatures at which the ash changes forms -- e.g., melting from a cone shape
to a spherical shape to a hemispherical shape to a flat layer -- are referred
to as ash fusion temperatures.

    ^   Tetra Tech, Inc., Physical-Chemical Characteristics of Utility Solid
Wastes. EPRI EA-3236, prepared for Electric Power Research Institute, September
1983, p. 3-4.  A micron is 0.001 millimeters.

    10  Ibid.

        The compressibility of a material is measured as the ratio of its
height at 50 psi to its original height at atmospheric pressure.  The dry
density, the ratio of weight to unit volume of the material containing no
water, affects permeability and strength, which in turn determine the
structural stability of a landfill and the extent of leachate mobility.  The
optimum moisture content is the moisture content, in percentage terms, at which
the material attains its maximum density.
    12
       In 1979 the New Source Performance Standards, part of the Clean Air Act
of 1971, were revised.  The new regulations required that all coal-fired
electric utility units with capacity greater than 73 megawatts, whose
construction commenced after September 18, 1978, would not only have to meet a
1.2 pound sulfur dioxide per million Btu emission limit, but would have to do
so by a continuous system of emissions reduction.  New power plants must reduce
sulfur dioxide emissions between 70 and 90 percent, depending on the type of
coal burned.

       During fluidized bed combustion the sulfur oxides react with limestone
or dolomite to form calcium sulfate.  In LIMB technology, limestone is injected
into the boiler, also forming calcium compounds.

    14
       Federal Power Commission, The Status of Flue Gas Desulfurization
Applications in the United States:  A Technological Assessment. July 1977,
p. VII-15.
        Ibid..  p. VII-18.
       Tetra Tech,  Inc.,  Physical-Chemical Characteristics of Utility Solid
Wastes. EPRI EA-3236, prepared for Electric Power Research Institute, September
1983, p. 4-4.

    18 "Dry Capture of S02," EPRI Journal. March 1984, p. 21.

    19 Ibid.. p. 15.

-------
                                      3-3


    20
       ICF, op. clt.  See Appendix B for a detailed explanation of how future
FGD sludge estimates were derived.

    21
       U.S. Environmental Protection Agency, Controlling S02 Emissions from
Coal-Fired Steam-Electric Generators:  Solid Waste Impact. Volume I,
EPA-600/7-78-044a, March 1978, p. 23.
    22
       See Chapter Four for a detailed discussion of the methods of sludge
fixation.
    03
       Michael Baker, Jr., Inc., State-of-the-Art of FGD Sludge Fixation.
prepared for Electric Power Research Institute, January 1978, p. 2-25.

    24
       Tetra Tech, Inc., op. cit.. p. 4-17.

    25 Ibid.
    26
       Envirosphere Company, Information Responding to EPA's Request Regarding
Burning and Co-Treatment/Co-Disposal of Low Volume Wastes Generated at Fossil
Fuel Fired Electric Generating Stations, prepared for Utility Solid Waste
Activities Group and Edison Electric Institute, August 1981, p. 26.

    27
       U.S. Environmental Protection Agency, Waste and Water Management for
Conventional Coal Combustion Assessment Report - 1979: Volume II;  Water
Management. EPA-600/7-80-012b, March 1980, p. 3-146.
    OQ
       Ibid.,  p. 3-147.
    29
       Ibid..  p. 3-16.  About 35 to 40 percent of the total heat input of  a
power plant is converted to electricity, about 5 percent is lost in the stack,
gases, and the remaining 55 to 60 percent is rejected in the condenser.

    30 Ibid..  p. 3-17.

    31 Ibid.

    32
       The term "cooling tower blowdown" refers to the waste waters produced by
all recirculating cooling systems, whether they use a cooling pond or a cooling
tower.

    33
       U.S. EPA, Waste and Water Management, p. 3-19.

    34
       Envirosphere Company, Information Responding to EPA's Request Regarding
Burning and Co-Treatment/Co-Disposal of Low Volume Wastes Generated at Fossil
Fuel Fired Electric Generating Stations, prepared for Utility Solid Waste
Activities Group and Edison Electric Institute, August 1981, p. 27.

    35 Ibid..  p. 27.

       Ibid..  p. 28.  The term "pyrites" is used to refer to a variety of
rock-like substances that may be found in raw coal; it does not just refer to
pyritic sulfur that is found in all raw coal, although pyritic sulfur is
typically part of the pyrites generated at a power plant.

-------
                                  CHAPTER FOUR




                   COAL COMBUSTION WASTE MANAGEMENT PRACTICES






    Under Section 8002(n) of RCRA, EPA is to analyze "present disposal and




utilization practices" and "alternatives to current disposal methods."  This




chapter addresses these issues by first examining the various state regulations




that affect coal combustion disposal since these regulations set the context




for current practices.  The following section describes coal combustion waste




management practices.  First, three commonly employed types of land management




practices are described in detail.  Next, this chapter describes additional




measures currently employed by some utilities; more widespread use of these




technologies could be employed as an alternative to current practices.  Ocean




disposal, an alternative that is in the research and development stage, is also




addressed in this chapter.  Finally, the extent of coal combustion waste




recycling as an alternative to disposal is described.








4.1  STATE REGULATION OF COAL COMBUSTION WASTE DISPOSAL








    Since coal combustion wastes are currently exempt from Federal hazardous




waste regulation under RCRA., their regulation is primarily carried out under




the authority of state hazardous and solid waste laws.   State solid waste laws




establish programs to provide for the safe management of non-hazardous solid




wastes.  If solid wastes are considered hazardous, state hazardous waste laws




establish programs to provide for their safe management.  To implement these




laws, state health or environmental protection agencies promulgate solid and




hazardous waste regulations.  A 1983 report for the Utility Solid Waste




Activities Group (USWAG) surveyed these regulations; the USWAG report provided

-------
                                      4-2
summaries of state regulations based on applicable state laws, regulations, and




interviews with state environmental officials.^-  EPA updated the information




provided in the USWAG summaries for the purposes of this report.








    Exhibit 4-1 lists the disposal requirements promulgated under each state's




solid waste (non-hazardous) regulations.  (As will be discussed below, it is




very rare for coal combustion wastes to be regulated as hazardous under state




regulations.)  The list of states is arranged in descending order according to




each state's share of national coal-fired generating capacity (Column 1 of




Exhibit 4-1).  The information shown in the Exhibit is discussed in detail in




Sections 4.1.1 and 4.1.2.








    4.1.1  State Classification of Coal Combustion Wastes








    Forty-three states have exempted coal combustion wastes from hazardous




waste regulation.   As a result,  in these states the state solid waste laws,




which apply to non-hazardous wastes, regulate the disposal of these coal




combustion wastes.  Column 2 of Exhibit 4-1 shows that: (1) in seven states,




coal combustion wastes are not exempt from hazardous waste regulation




(indicated by an entry of CH),  which means that they are tested to determine




whether they will be regulated as solid or hazardous wastes; (2) in all but one




of the remaining states wastes are regulated by solid waste regulations




(indicated by an entry of SW);  and (3) in the one remaining state, wastes are




exempt from both the hazardous waste and solid waste regulations (indicated by




an entry of EX).

-------
                                                              4-3
                                                          EXHIBIT 4-1
STATE
   (1)           (2)
X NATIONAL
COAL-FIRED  CLASSIFICATION
CAPACITY
                                                                                           (7)         (8)          (9)
                                                                                       GROUND-HATER  CLOSURE     FINANCIAL
                                                                                       MONITORING  CONDITIONS    ASSURANCE
Texas
Indiana
Kentucky
Ohio
Pennsylvania
Illinois
West Virginia
North Carolina
Michigan
Georgia
Florida
Missouri
Alabama
Tennessee
Nevada
South Carolina
Wisconsin
Louisiana
Colorado
Iowa
Wyoming
Kansas
Arizona
New Mexico
Utah
Minnesota
Arkansas
Maryland
North Dakota
Oklahoma
New York
Virginia
Washington
Nebraska
Montana
Mississippi
New Jersey
Massachusetts
Oregon
Delaware
Maine
South Dakota
8.401
6.44Z
6.431
6.02Z
5. 711
5.461
3.87X
3.41Z
3.37Z
3.351
3.26Z
3.16Z
3.08Z
2.54Z
2.49Z
2.24Z
2.19Z
1.98Z
1.97Z
1.83Z
1.82Z
1.69Z
1.67Z
1.58Z
1.57Z
1.54Z
1.48Z
1.48Z
1.39Z
1.34Z
1.24Z
0.94Z
0.931
0.85Z
0.74Z
0.621
0.51Z
0.41Z
0.31Z
0.27Z
0.15Z
0.13X
sw
sw
CE
EX
SW
SW
SW
sw
sw
sw
sw
sw
sw
CH
sw
sw
sw
sw
sw
sw
sw
sw
sw
sw
sw
sw
sw
sw
sw
CH
sw
sw
CH
sw
sw
sw
CH
sw
sw
sw
CH
sw
OFF SITE
ON & OFF SITE
ON & OFF SITE

ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
OFF SITE
OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
OFF SITE
ON & OFF SITE
OFF SITE
OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
NO
NO
YES

YES
NO
NO
YES
YES
NO
YES
YES
YES
YES
YES
YES
YES
YES
YES
NO
YES
YES
NO
NO
NO
YES
YES
NO
NO
YES
YES
NO
YES
NO
YES
NO
YES
YES
YES
YES
YES
NO
NO
NO
MAY

NO
NO
NO
NO
NO
NO
YES
NO
MAY
MAY
NO
NO
MAY
YES
YES
NO
NO
NO
NO
NO
NO
NO
NO
HO
NO
NO
MAY
NO
YES
NO
NO
MAY
NO
NO
NO
NO
YES
NO
NO
NO
YES

NO
NO
NO
NO
NO
NO
YES
MAY
NO
NO
NO
YES
MAY
YES
YES
MAY
NO
NO
NO
NO
NO
MAY
NO
YES
MAY
NO
MAY
NO
YES
MAY
NO
NO
NO
NO
NO
YES
YES
NO
MAY
MAY
MAY

MAY
NO
NO
YES
YES
NO
YES
NO
YES
MAY
NO
NO
MAY
YES
YES
NO
NO
MAY
NO
NO
NO
YES
NO
YES
YES
YES
YES
NO
YES
NO
NO
NO
YES
NO
MAY
YES
MAY
NO
YES
NO
YES

YES
YES
NO
YES
NO
NO
YES
YES
YES
YES
NO
YES
YES
YES
NO
NO
NO
YES
NO
NO
NO
YES
YES
NO
YES
YES
YES
NO
YES
NO
NO
YES
YES
NO
NO
YES
YES
YES
YES
NO
NO

YES
YES
NO
NO
HO
NO
YES
NO
NO
NO
NO
RO
YES
YES
NO
NO
NO
YES
NO
NO
NO
NO
YES
NO
YES
YES
NO
NO
NO
NO
NO
NO
YES
NO
YES
NO
NO
NO

-------
                                                                 4-4
                                                     lUHIHIT 4-1 (continued)
                                   STATE UHJlLATdmS GOVEKNIBG COAL OOMBDSTIOB HASTE DISPOSAL


STATE

Haw Hampshire
Alaska
California
Connecticut
Vermont
Rhode Island
Hawaii
Idaho
(1)
Z NATIONAL
COAL-FIRED
CAPACITY
0.121
0.01Z
O.OOX
O.OOX
O.OOZ
O.OOZ
O.OOZ
O.OOZ
(2)

CLASSIFICATION

SW
sw
CH
SW
SW
SW
SW
SW
(3)

(4)
SITE
PERMITS RESTRICTIONS

ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE
ON & OFF SITE

HO
YES
YES
YES
NO
YES
NO
NO
(5)

LINER

NO
NO
HO
NO
NO
NO
NO
NO
(6)
LEACHATE
CONTROL

NO
NO
YES
YES
NO
YES
NO
MAY
(7)
GROUND -HATER
MONITORING

YES
MAY
MAY
YES
NO
YES
NO
NO
(8)
CLOSURE
CONDITIONS

NO
HO
YES
YES
NO
NO
NO
NO
(9)
FINANCIAL
ASSURANCE

HO
no
YES
NO
NO
NO
NO
NO
NOTES

Column (1) Percent national coal-fired capacity:  i.e.,  each state's  share  of total U.S.  coal-fired generating capacity.

Column (2) Classification:  SW - coal combustion  waste  is exempted from hazardous waste  regulation and regulated as a solid
                                 waste.

                            CH - coal combustion  waste  is not exempted  from hazardous waste  regulation and is tested for
                                 hazardous characteristics (In practice, coal combustion wastes are rarely considered hazardous,
                                 therefore columns  3-8  reflect solid, not  hazardous, waste regulations).

                            EX - coal combustion  waste  is exempted from both solid and hazardous waste regulation.

Column (3) Permits: Permits are required for off-site facilities  only,  or  for both on-site and off-site facilities.

Columns (4), (5), (6),  (7), (8), (9):   YES - the  disposal standard is imposed by state regulations.

                                       NO - the disposal standard is not imposed by state regulations.

                                       MAY - the  regulation states that a  case-by-case investigation will determine whether the
                                             disposal standard will  be  imposed.
Source:  Wald, Harkrader & Ross,  Survey of State  Laws  and Regulations Governing Disposal of Utility Coal-Combustion Byproducts.
         prepared for the Utility Solid Waste Activities  Group, September,  1983.

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                                      4-5
    Of the seven states that do not exempt coal combustion wastes from




hazardous waste regulation (indicated by a CH classification in Exhibit 4-1),




California burns little coal to produce electricity.  The hazardous waste.




regulations of the six remaining states -- Kentucky, Tennessee, New Jersey,




Oklahoma, Maine, and Washington -- regard coal combustion wastes as




"characteristic" waste; that is, the wastes are tested for Extraction Procedure




(EP) toxicity (see Chapter Five for further discussion),  and if the waste




proves to be toxic, some or all sections of state hazardous waste regulations




apply.  In Kentucky, for example, hazardous waste standards concerning lining




and leachate control are enforced for coal combustion wastes that are found to




be toxic, but utilities are not required to participate in the hazardous waste




management fund established to ensure the long-term viability of disposal




facilities.  Similarly, according to the hazardous waste regulations of




Tennessee and Oklahoma, if a waste is determined to be toxic, strict analysis




and monitoring requirements must be followed, but compliance with state




hazardous waste design and operating standards is not required.  Officials from




these five states have indicated that it is very rare for a coal-burning




utility's waste to be classified as hazardous.   Therefore, state solid waste




regulations, with only isolated exceptions, establish the standards applicable




to most coal combustion waste disposal activities.








    Although solid waste regulations in most states do not differentiate




between coal combustion wastes and other solid wastes, solid waste regulations




in three states make specific reference to coal combustion waste disposal:

-------
                                      4-6
         •    Ohio's solid waste regulations list "non-toxic fly
              ash ...   and slag ...  that are not harmful or
              inimical to public health" as wastes that are
              exempt from solid waste regulation.  Ash is
              typically determined to be non-toxic, according to
              the USWAG report.

         •    Maine's solid waste regulations provide a separate,
              more stringent set of design and operating
              requirements for the disposal of coal combustion
              wastes.   The requirements call for lining, leachate
              control, and ground-water monitoring at coal
              combustion waste sites.  These standards do not
              apply to other solid waste disposal facilities.^

         •    Pennsylvania has established industry-specific
              waste disposal standards.  Pennsylvania's
              regulations for coal combustion waste disposal
              exclude the leachate control systems and liner
              requirements that apply to general solid waste
              disposal facilities.


    4.1.2  Requirements for Coal Combustion Waste Disposal



    The solid waste regulations of every state require that off-site solid

waste disposal facilities be permitted or have some form of official approval.

In order to obtain a permit, the operator of a facility must meet  the

requirements that are outlined in the regulations.  These regulations are

listed in Exhibit 4-1 and described below:
              The regulations in 41 states require permits for
              both on-site and off-site facilities.  Eight
              states' regulations explicitly exempt on-site
              disposal from the permit requirement (Ohio, which
              exempts coal combustion wastes from solid waste
              regulation, is not included among the eight
              states).  Column 3 of Exhibit 4-1 shows whether a
              permit is required for the operation of on-site and
              off-site solid waste disposal facilities.

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                        4-7
Site restrictions are included in the solid waste
regulations of 30 states.  Examples of site
restrictions are prohibiting solid waste disposal
facilities from violating local zoning laws,
banning placement of a new facility in a 100-year
floodplain, and prohibiting waste placement unless
there is a minimum depth to ground water.  Column
4, "site restrictions," shows whether a state's
regulations include restrictions on a disposal
facility's location.

Five states' regulations (Florida, Louisiana,
Colorado, Washington, and Maine) call for all solid
waste facilities to have a clay or synthetic liner.
In addition, six states' regulations (Kentucky,
Alabama, Tennessee, Wisconsin, New York, and
Mississippi) call for the state permitting
authority to determine, on a case-by-case basis,
whether a liner is required.  Column 5, "liners,"
shows whether the state's regulations include a
requirement for liners at solid waste disposal
facilities.

Leachate control systems are collection devices
placed under wastes in landfills or impoundments to
collect waste leachate.  Regulations in 12 states
call for leachate control systems in all solid
waste disposal facilities; the regulations of an
additional 8 states allow leachate control systems
to be required on a case-by-case basis.  Column 6,
"leachate control systems," shows whether a state's
regulations include a requirement for leachate
control systems at solid waste disposal facilities.

The solid waste regulations of 17 states call for
ground-water monitoring systems at all solid waste
disposal facilities.  The regulations of an
additional 11 states specify that ground-water
monitoring may be required on a case-by-case basis.
Column 7, "ground-water monitoring," shows whether
a state's regulations include requirements for
ground-water monitoring wells at solid waste
disposal facilities.

Twenty-six states have solid waste regulations that
call for closure and post-closure care.  Column 8,
"closure conditions," shows whether a state's
regulations include requirements for closure and
post-closure care for disposal facilities that have
ceased operating.

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                                      4-8
         •    Thirteen states have solid waste regulations that
              include a financial assurance requirement.  Column
              9, "financial assurance," shows whether a state's
              regulations include a requirement that a solid
              waste facility operator post a bond or participate
              in a waste management fund to ensure the long-term
              viability of safe disposal facilities.


    The management of waste in surface impoundments, a common practice for

coal-burning utility plants, is often only indirectly addressed by state solid

waste regulations.  Only six states -- Louisiana, Colorado, New York,

Washington, Oregon, and New Hampshire -- have solid waste regulations that

include requirements exclusively for surface impoundments.  The solid waste

regulations of Indiana, Tennessee, Kentucky, North Carolina, Georgia, and

Missouri exclude surface impoundments and defer to state water laws for

regulatory authority.  The water regulations in these states do not include any

design and operating requirements for surface impoundments.  However, according

to the USWAG report, the water agencies in Missouri do regulate the design and

operation of impoundments -- requiring lining and ground-water monitoring.

According to the same report, state water agencies in Pennsylvania also

regulate the design and operation of surface impoundments.



    The regulatory requirements discussed above refer to regulations explicitly

promulgated by the states for waste disposal facilities.  However, state solid

and hazardous waste regulations generally allow state authorities a large

degree of discretion in designing site-by-site disposal standards that are more

strict than those specified in the solid waste regulations.  Many states'

regulations allow local governments to design their own waste disposal

regulations, provided that the standards set forth in the state solid waste

regulations are enforced.  Interviews with several state environmental

-------
                                      4-9
officials and the summaries in the USWAG report indicate that in some states




coal combustion utility wastes are regulated more stringently than what is




required by the solid waste regulations.  For example, the solid waste




regulations in Texas have few design and operating requirements and exempt




on-site disposal from the permit requirement.  It is, however, the policy of




the state environmental agency to provide guidelines for on-site facilities as




well as off-site facilities, and to require ground-water monitoring.  (For more




information on individual state regulations, see Appendix C.)








    4.1.3  Summary








    The regulation of coal combustion waste is generally carried out under




state solid, not hazardous, waste regulations.  These solid waste regulations




vary from state to state.  Based on the requirements included under each




state's solid waste regulations (as shown in Exhibit 4-1), it is difficult to




generalize about the extent of state regulation of coal combustion wastes; some




states have very stringent regulations and/or policies, such as those that




impose design and operating standards and on-site and off-site permit




requirements, whereas other states have few requirements or exempt on-site




disposal from regulation.  For a number of states, requirements are determined




on a case-by-case basis.  This allows the states to take climatic, geologic,




and other site-specific characteristics into account for each waste management




facility.

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                                      4-10
4.2  AVAILABLE WASTE MANAGEMENT METHODS AND CURRENT PRACTICES








    There are a variety of methods available for managing coal combustion




wastes.  Wastes may be land managed in impoundments,  landfills,  mines,  and




quarries or may be reused for various purposes.  This section describes types




of land management of coal combustion wastes and their prevalence within the




ten EPA-designated regions of the United States.  The second part of the




section reviews available waste management technology alternatives (such as




lining, leachate collection, and pre-disposal treatment), and explores  how




these different technologies are currently used in different parts of the U.S.




and how these technologies have changed over time.  The third part of this




section describes the potential for ocean disposal to be used to manage coal




combustion wastes.   The final section describes coal combustion waste




recycling.  The waste management methods discussed in this section apply to




high-volume and low-volume utility waste streams since these wastes are often




co-disposed in the same facility.^








    4.2.1  Land Management of Coal Combustion Wastes








    80 percent of coal combustion waste is treated, stored,  and/or disposed by




means of land management, with the remaining 20 percent recycled (see Section




4.2.4).  This section describes three common methods  of land management




currently used for coal combustion wastes.  It also presents data on use of




these management methods geographically and how land management practices have




changed over time.

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                                      4-11
    4.2.1.1  Types of Coal Combustion Waste Land Managenent



    Three types of utility waste land management facilities are commonly used

today:7


         •    Surface Inpoundnents -- often called wet ponds, in
              which coal combustion wastes are disposed as a
              slurry or sludge, allowing solids to settle and
              accumulate at the bottom of the pond.

         •    Landfills -- facilities used for disposing of dry
              or dewatered coal combustion wastes; landfills are
              typically managed like an earth-moving operation in
              which the wastes are disposed in the excavated
              area.

         •    Mines and Quarries -- abandoned pits in which wet
              or dry wastes are disposed.
Surface Impoundnents


                                                                             J

    Surface impoundments are used to treat, store, and dispose of coal

combustion wastes.  Slurried coal ash and other wastes are introduced into the

impoundment; the solids settle out and gradually accumulate at the bottom of

the pond, leaving relatively clear water at the surface, which is often

discharged to surface water.  By using this method, certain types of waste

treatment, such as neutralization of acids, can be accomplished concurrently

with disposal.  Exhibit 4-2 illustrates the different stages in the life of a

typical impoundment.



    Historically, wet ponding has been one of the most widely used disposal

methods for coal ash and FGD wastes because it is simple and easily

implemented.  In 1983, about 80 percent of the waste management facilities used

-------
                            4-12
                          EXHIBIT 4-2


               TYPICAL SURFACE IMPOUNDMENT (POND) STAGES
SLURRIED =
COAt WASTE
                        ACTIVE POND
                                                     EFFLUENT
                     CLOSED STORAGE POND
                      (with wastes removed)
  X"
(*r
                     CLOSED DISPOSAL F3OND
                     (with wastes remaining)

-------
                                      4-13
by utilities employed some type of sedimentation treatment pond; most of these




treatment ponds were used directly as final disposal impoundments (about 45




percent of all facilities; see section 4.2.1.2).  The remainder of the




impoundments were used only for treatment and temporary storage of waste, in




part to comply with the National Pollutant Discharge Elimination System




established in Section 402 of the Clean Water Act.**  In recent years, some




state and local regulations concerning wet ponds have become more restrictive,




requiring liners and ground-water monitoring at these facilities.  These types




of restrictions will tend to increase wet ponding costs,  making it less




attractive as a disposal option.








    Utilities may use a single pond or a series of ponds  to facilitate the




settling of solids.   Chemicals or different wastes can be added at different




points in the ponding system to produce desired chemical  reactions, such as




metals precipitation or neutralization.  Fly ash, bottom  ash, and FGD wastes




are usually sluiced with water to the impoundments.  The  ash solids may be




allowed to accumulate in a pond until it is full, or the  pond may be drained




and the solids dredged periodically and taken to an alternative disposal site,




such as a landfill.








    Pond designs vary widely depending upon local site conditions, the




regulations that govern design of the impoundment, and whether bottom ash,




fly ash, FGD wastes, or a combination of wastes are to be disposed and/or




treated in the ponds.  Because utility wastes are generated in large volumes,  a




pond's total surface area may cover up to several hundred acres, and the




initial depth of a pond may be anywhere between 10 and 100 feet.    The total

-------
                                      4-14
volume of an impoundment system depends on several factors, including the total




quantity of ash to be disposed (both dry and slurried volumes), the liquid and




solid retention times, the type and degree of treatment performed, and the




desired quality of the discharge or effluent.  The number of ponds in a system




and the specific uses to which each is put can also influence the total volume




required for wet ponding.








Landfills








    Landfills are used to dispose of coal combustion wastes such as fly ash,




bottom ash, and FGD sludges when they are produced or after they are dredged




from surface impoundments that are used as interim treatment facilities.  The




typical design of a landfill during its active stage and after closure is




depicted in Exhibit 4-3.








    Landfills are constructed in a somewhat similar fashion to surface




impoundments.  Excavation is required in both cases, but may be ongoing




throughout a landfill's active life because most large landfills are divided




into sections,  or cells, of which only one or two may be active at any given




time.   A landfill cell is defined as the area (up to several hundred square




feet)  over which waste is placed to a depth ranging from one to ten feet




(industry practice refers to each layer of cells as a lift).  Several lifts may




be stacked atop one another in the landfill.  A cell may be open for periods




ranging from a day to a few weeks,  after which it is usually covered with six




inches to several feet of soil.  The waste and soils are often sprinkled with




water throughout the fill operation to mitigate potential dust problems.

-------
                  4-15








              EXHIBIT 4-3



   DIAGRAMS OF ACTIVE AND CLOSED LANDFILLS
          ACTIVE LANDFILL
Cells
           'LA WASTE
SOILS
          CLOSED LANDFILL


-------
                                      4-16
    Excavation may be initiated in phases; for example, as one cell is filled,



another is prepared for waste placement, while yet another is being excavated.



Roads are built in to provide access for waste-hauling equipment as well as for



the earth-moving and earth-compacting equipment that prepares the waste after



it has been placed in the landfill cell.  After a cell is filled, the access



road frequently becomes part of the containment system as a wall separating one



cell from the next.








    Landfilling of coal ash and FGD sludges has increased over the past few



years as the costs of wet ponding have increased (see section 4.2.1.2).  Most



electric utilities that use landfills currently dispose their high-volume



wastes in Subtitle D (non-hazardous waste) landfills.  Landfills in compliance



with RCRA Subtitle C standards may be used occasionally for disposal of small



quantities of hazardous waste.








Mine and Quarry Disposal








    Some utilities use abandoned mines or quarries as ash and FGD sludge



disposal sites.  Abandoned mine disposal includes the use of mine shafts as



well as strip-mined areas.  Wastes disposed to abandoned mine shafts can be



dumped into the shaft or carefully placed within the mine to fill the areas



remaining after the coal or other material has been removed.  Strip-mined areas



may be filled like a landfill.  Regulatory agencies may consider wastes



disposed in this manner to pose less of a threat than the runoff and potential


                                             12
contamination from the abandoned mine itself.    In some cases,  a chemical



reaction between the waste and the mine runoff and leachate might actually

-------
                                      4-17
reduce the toxicity of the runoff (for example, an alkaline sludge could
neutralize acid mine drainage).  However, the likelihood of such a mitigative
effect is very site-specific and would not necessarily occur uniformly
throughout any given mine disposal site.


    In a few cases, utility wastes,  particularly acidic wastes, have been
disposed in quarries.   Limestone quarries are considered the best setting for
this type of disposal because they provide a natural acid buffering capacity
and the capacity for the metals present in the waste to be attenuated by
chemically combining with materials.in the quarry.    Quarry disposal of wastes
works well for lime or limestone slurry wastes, which harden to form a
concrete-type floor at the bottom of the quarry, thereby plugging any potential
leakage paths.   The probability of achieving success with this method must be
evaluated on a case-by-case basis prior to its use.
                                                                             i

    4.2.1.2  Prevalence of Various Land Management Methods


    Use of the waste management methods described above can vary from plant to
plant and, in some cases, among individual generating units at a single power
plant.  This section presents information on how these utility waste management
methods are employed nationwide and within EPA regions.  It also discusses how
these utility waste management methods have changed over time.  The emphasis is
on surface impoundments and landfills because these two waste management
methods are the most commonly-used utility waste management practices in the
United States.

-------
                                      4-18
    The information presented in this section was derived from the Edison




Electric Institute Power Statistics Database, currently maintained by the




Utility Data Institute.  This database contains information on power plant




characteristics for all electric utility generating plants in the U.S.  These




data include number of power plants, number of generating units at each power




plant site, type of fuel, plant capacity, as well as other information.  It




also contains information on the type of waste management methods currently




used by power plants throughout the country, including type of disposal




facility and whether the wastes were disposed at the power plant or in off-site




facilities.  Because each generating unit at a power plant may have its own




waste management practice, the database gives waste disposal information for




all generating units.








    Data were not available for all generating units in the database.  When




information is not available, the extent of data coverage is indicated.  In




some instances the number of generating units on which no information was




available was quite high.  Although EPA recognizes the possibility of some




statistical bias due to lack of data on some generating units, this database is




the most comprehensive source available on utility waste management practices.




EPA has no reason to believe that such bias is serious enough to call into




question conclusions drawn in this analysis.








    Exhibit 4-4 displays, for each of the ten EPA regions of the U.S. (see




Exhibit 2-4 for a map of these regions), the number of generating units whose




waste is managed in surface impoundments, in landfills,  or mines.   The most

-------
                                     4-19
                                EXHIBIT 4-4

               UTILITY HASTE MANAGEMENT FACILITIES BY EPA REGION
                       (number of generating units) a/
EPA Region
  Surface
Impoundments
                      Other/
Landfills  Minefills  Unknown
                       Total
    1
    2
    3
    4
    5
    6
    7
    8
    9
   10
     1
     0
    33
   195
   160
    19
    55
     9
    11
     0
 10
 22
103
 55
198
 48
 61
 56
 16
  9
 0
 0
 1
 0
 4
 2
 1
23
 0
 2
   U.S. Total   483
               578
            33
  7
 17
  7
 45
130
 18
 32
 21
  7
  0

284
  18
  39
 144
 295
 492
  87
 149
 109
  34
  11

13~78
   Source:   Utility Data Institute Power Statistics Database

   a/ The data are provided by generating unit because each generating unit at
      a power plant may have its own management facility.   A generating unit
      typically refers to a single boiler,  turbine, and generator set at a
      power plant.  A power plant may have more than one generating unit at
      the site.   For the database used here,  data were available for 1,378
      generating units located at 514 power plants.

-------
                                     4-20
common types of facilities used by the electric utility industry are

surface impoundments and landfills:

    •    Landfills are the most common type of disposal facility
         used.  Of the 1,094 generating units for which data were
         available (for 284 units,type of waste disposal method
         was unknown), 578 units (about 53 percent) used
         landfills for waste disposal.  Landfills are used
         throughout the United States, with the largest number
         (over one-half of all landfills) located in the high
         coal-consuming, industrialized areas of the East and
         Midwest (Regions 3 and 5).

    •    Surface impoundments are also commonly used;
         approximately 44 percent of the generating units (483
         out of 1,094) used this type of management facility.  Of
         the 483 generating units that place wastes in surface
         impoundments, nearly 75 percent are located in Regions 4
         and 5. (In the past, access to abundant, inexpensive
         supplies of water in these  Regions often made it
         economical to use this management option.)

    •    Mine disposal is used for about three percent of all
         generating units (33 units  out of 1,094).  This disposal
         technique is used most frequently in the western U.S.,
         particularly Region 8.  Power plants in this area are
         often located at or near the coal mine that is supplying
         the plant.   Since the coal  mine is located nearby,
         disposal of waste in the mine is often economic.
    When managing coal combustion wastes, electric utilities may treat,

store, or dispose of the wastes at the power plant or at facilities

located off-site.  EPA could not determine from the data available how far

the wastes are transported when managed off-site, although the cost of

transporting the wastes would tend to encourage disposal near the power

plant.  A summary of industry practices is provided in Exhibit 4-5, which

shows for each EPA region, by type of facility, whether the wastes are

managed on-site or off-site.

-------
                                    4-21
                               EXHIBIT 4-5

            LOCATION OF UTILITY WASTE MANAGEMENT FACILITIES:
                         ON-SITE VERSUS OFF-SITE
                      (number of generating units)*
EPA Region
On-Site
Off-Site
Unknown
Total
    Surface Impoundments
    Landfills
    Other/Unknown
       Total
    1
    0
    0
    0
    8
    0
    0
    2
    Surface Impoundments
    Landfills
    0 the r/Unknown
      Total
    0
    3
    0
    0
   18
    0
   18
    0
    1
  J2
   18
    Surface Impoundments
    Landfills
    0 the r/Unknown
      Total
                             5
                             4
                           _7
                            16
                          144
    Surface Impoundments
    Landfills
    0 the r/Unknown
      Total
                4
                8
                0
               12
    Surface Impoundments
    Landfills
    0 the r/Unknown
      Total
141
41
0
182
5
140
6
151
14
17
128
159
160
198
J.34
492
    Surface Impoundments     18
    Landfills                36
    Other/Unknown         	0
      Total                  54
                0
                3
                           19
                           48
                         _20
                           87

-------
                                     4-22
                         EXHIBIT 4-5 (continued)

             LOCATION OF UTILITY WASTE MANAGEMENT FACILITIES:
                         ON-SITE VERSUS OFF-SITE
                      (number of generating units)*
EPA Region
On-Site
Off-Site
Unknown
Total
    Surface Impoundments     42
    Landfills                20
    Other/Unknown         	7
      Total                  69
                            13
                            15
                         	25
                            53
    Surface Impoundments      6
    Landfills                28
    Other/Unknown         	2
      Total                  36
    Surface Impoundments      9
    Landfills                16
    Other/Unknown         	0
      Total                  25
                2
                0
                 0
                 0
                _7
                 7
10
    Surface Impoundments
    Landfills
    Other/Unknown
      Total
    0
    5
    0
    0
    4
   _2
    6
    0
    0
   _0
    0
Total U.S.
    Surface Impoundments
    Landfills
    Other/Unknown
      Total
428
237
__9
674
16
255
	 39
310
39
86 .
269
394
483
578
_317
1378
    The data are provided by generating unit because each generating unit
    at a power plant may have its own management facility.  A generating
    unit typically refers to a single boiler, turbine, and generator set
    at a power plant.  A power plant may have more than one generating
    unit at the site.  For the database used here, data were available for
    1,378 generating units located at 514 power plants.

-------
                                     4-23
          Nearly 70 percent of all generating units in the U.S.
          manage their coal combustion wastes on-site (based on
          information for 984 units, 674 units dispose on-site).
          About two-thirds of the on-site facilities are surface
          impoundments; most of the other on-site facilities are
          landfills.

          Landfills are used for about 95 percent of all
          off-site disposal in the U.S.  This is not surprising
          considering that surface impoundments are typically
          used when wastes are transported as a wet slurry; the
          cost of disposal could become prohibitive if a utility
          transported the slurry off-site.

          Coal combustion waste management practices also differ
          by region:

               In the Northeast (Regions 1 and 2), where
               few coal-fired generating units are located,
               management tends to occur off-site in
               landfills.

               The highest percentage of on-site management
               is found in the South (Region 4), where
               about 95 percent of all units manage their
               waste on-site (212 units, based on
               information from 224 units).  On-site
               management is common because utilities in
               this region often use surface impoundments,
               which are typically located at the power
               plant.

               In the Rockies and northern Great Plains
               area (Region 8), most of the off-site
               disposal (23 of 36 units) occurs in mines
               that are generally adjacent to the power
               plant.
     These trends in utility waste management methods have been changing

in recent years, with a shift towards greater use of disposal in landfills

located on-site.  For example, for generating units built since 1975,

nearly 65 percent currently dispose of coal combustion wastes in

landfills, compared with just over 50 percent for units constructed before

1975.  Similarly, over 80 percent of all units built since 1975 use

-------
                                     4-24
on-site management facilities, compared with just under 65 percent of all




units built before 1975 that manage wastes on-site.








     4.2.2  Alternative Waste Management Technologies








     Section 4.2.1 described the types of land management facilities used




by utilities and patterns of use.  This section describes the additional




technologies that utilities may employ at the facilities described above




in order to reduce potential environmental risk associated with waste




management.  For example, some utilities use liner systems for




impoundments and landfills, leachate collection systems,  and ground-water




monitoring systems to control and monitor waste constituent migration.




Pre-treatment technologies, by altering physical and chemical properties,




can also render wastes more amenable for certain disposal methods.   This




section also presents data on the prevalence of these various




technologies.  The alternative technologies discussed in this section,




although not necessarily the same as technologies required for RCRA




Subtitle C facilities,  may be required by current state regulations




(described in Section 4.1) and could be more widely used in the future to




further mitigate potential environmental impacts at utility waste disposal




sites not currently employing these technologies.









          4.2.2.1  Installation of Liners








     Until recently,  most surface impoundments and landfills used for




utility waste management have been simple, unlined systems.  Lining is

-------
                                     4-25
becoming a more common practice, however, as concern over potential



ground-water contamination from "leaky ponds" and, to a lesser extent,



from landfills has increased.  Some waste management facilities use one or



more impermeable synthetic liners; some are lined with one or more layers


                     14
of low-permeable clay  ;  and some use a combination of clay and synthetic



liners.
     Synthetic Liners







     Several dozen manufacturers and distributors supply impermeable



synthetic liners.  The most common materials of construction for these



liners include polyvinyl chloride (PVC) and high-density polyethylene



(HDPE),  although several other impermeable synthetics have also been used.



Liners may be reinforced with fibers to increase strength and decrease the



likelihood of punctures.  The liners can be purchased in standard



thicknesses that range from 10 mils to 100 mils,   or can be made to



order.  Most liner installations will include protective geotextile fabric



above and/or below the impermeable synthetic liner to minimize further the



potential for puncture.







     Preparation of the site prior to installation of a synthetic liner is



similar to that which occurs before clay liner construction.  However,



more care must be taken to smooth out the surfaces to eliminate any peaks



and cavities on the disposal facility floor that could cause a puncture of



the liner material.  Consequently, surface preparation costs are greater



than those for clay liners.  Excavation costs are usually less, however,

-------
                                     4-26
because the thinner synthetic liners allow shallower excavation (i.e.,  the




additional excavation required to install a clay liner that is several




feet thick can be avoided if a much thinner synthetic liner is installed).








     The liner itself, which comes rolled or folded in large pieces, is




laid in the field and sealed along the seams by heat or solvent fusion




techniques; the seams may be field tested at spot checkpoints.  The liner




is usually covered with a foot or more of soil to protect it from puncture




and to keep it in place during construction of the disposal facility.  The




edges of the liner at the tops of the dikes or landfill cell walls must be




well secured to prevent the liner from pulling out and shifting due to the




mass of the wastes placed in the impoundment or landfill.  Some facilities




are double lined and often contain a leachate collection system located in




a soil or sand layer between the two liners.








     Among the limitations to the use of synthetic liners is their




susceptibility to tear and puncture.  This is of particular concern in a




single-lined impoundment because of the opportunity for liquids to seep




through a single tear.  Synthetic liners are also susceptible to




degradation by certain waste materials.  Acidic wastes, for example, can




degrade some synthetic liner materials.  As with clay liners, waste/liner




compatibility testing should be performed to ensure that the disposed




wastes will not weaken or permeate the liner.  Additionally, because the




seams of a synthetic liner are frequently weaker than the liner itself,




they may pull apart under stress (e.g., large mass loadings or wave

-------
                                     4-27
action).  Finally, dredging of synthetically-lined impoundments must be




done cautiously, sometimes at very significant expense.








     Synthetic liners,  unlike clay liners (described below),  are




impermeable.  Another advantage is the ease of repairing an exposed,




damaged impoundment liner.  A tear or puncture can be patched and seamed,




and an impoundment put back into service, relatively quickly.  (To repair




subsurface damage, however, the impoundment must be wholly or partially




drained.)  Another advantage to using synthetic liners is that because of




manufacturer quality control, a facility owner can be fairly certain that




each liner sheet is as impermeable as the next.  Clay is expensive to




transport and in areas of the country where clay soils are scarce, a




synthetic liner system may prove to be the less expensive option.








     Clay Liners








     The installation of a clay liner in a surface impoundment or landfill




entails several steps.   First, the site must be excavated or graded to a




level below the design elevation of the facility floor.  Many facilities




take advantage of natural low areas or abandoned ponds to minimize




excavation costs.  The excavated earth can be used to build up the dike




walls for the impoundment or to build containing berms within the




landfill.  Occasionally,  soil must be brought to the construction site to




raise the dikes to the design height.

-------
                                    4-28
     Once the floor and dikes or berms have been prepared, the clay liner




is laid in 6- to 9-inch lifts; its final thickness will be between 1 foot




and 8 feet.  Each lift is individually compacted before the next one is




laid, thereby providing effective compaction and minimizing leakage




potential.  Field testing of the clay for permeability and other pertinent




characteristics is sometimes performed during construction to provide




quality assurance.  Before the impoundment or landfill can be used, the




liner is visually inspected for flaws; non-contaminated water may also be




piped to the pond to assure that the liner is sufficiently impermeable.








     One of the primary concerns about the use of clay liners is whether




the entire clay liner meets thickness and permeability requirements.  If




weather conditions during liner construction are arid and hot, the liner




may dry out and crack, causing localized areas of leakage.  If conditions




are wet or the clay is too moist, clay compaction may never be sufficient




to achieve the necessary low permeability.  The clays used as liner




materials vary in the degree to which they are compatible with the wastes




placed in the facility.  Laboratory tests, in which the proposed liner




material is exposed to the wastes intended for management, should be




conducted for each facility to ensure that components of the waste




material will not unduly alter the permeability of the clay used as liner




material.  If the chemical characteristics of the generated waste were to




change over time, then the tests would need to be repeated to determine




what effect the altered waste stream would have on the clay liner.

-------
                                     4-29
     An advantage of clay liners is their potential for chemical,




particularly cation, attenuation.  The chemical structure of clay allows




its use as an exchange site for metallic cations and other ions that might




gradually seep out of the facility.  Such exchange further reduces the




opportunities for migration of waste constituents to the ground water.




For facilities with fairly ready access to clays, the capital and




construction costs associated with the use of a clay liner, even one that




is several feet thick, may he substantially lower than those associated




with the use of a synthetic liner.








     Composite Liners








     Many waste management facilities in industries currently subject to




RCRA Subtitle C requirements are installing liner systems that combine




both clay liner and synthetic liner technologies.  Most commonly, an




impoundment or landfill will be lined with 2-4 feet of impermeable clay,




which is then prepared for placement of a synthetic liner.  The synthetic




liner may be covered with 1-2 feet of sand to serve as drainage for a leak




detection system.  Some facilities may then add another 1- to 2-foot layer




of clay, which is again prepared for placement of the upper synthetic




liner.  In landfills, another leachate collection system is usually placed




above this upper liner.








     The composite synthetic/clay liner system offers a combination of




advantages over single-material liners.  A composite liner has some of the




advantages provided by synthetic liners, such as factory quality control

-------
                                     4-30
and ease of repair (for the upper liner), as well as the advantage of

clay's propensity for attenuating escaped ions.  Furthermore, use of

multiple-liner materials reduces the likelihood that waste material will

leak into the ground water because of chemical incompatibility between a

waste and a single liner material.  In general, the more layers of

impermeable liner material that are used, the more efficient containment

of liquids will be,  thus reducing the likelihood of a release of waste

material.



     The biggest drawback of the composite synthetic/clay liner system is

the cost of installation.  Utility waste landfills are very large (up to

100 acres  or more),  and a liner large enough to cover such a area could be

very expensive.  In areas where labor costs are high and clay is

unavailable locally and must be transported long distances, these costs

would be magnified.



Frequency of Liner Use



     Some  electric utilities have installed liners to retard the flow of

leachate from the waste disposal facility to the surrounding area.

Exhibit 4-6 shows the extent to which electric utilities are currently

using this technology.
          About 25 percent of all generating units in the U.S.
          for which data were available (139 of 580 units) have
          installed some type of liner.  There are no available
          data on the material used to construct these liners or
          if more than one liner has been installed at the
          disposal facility.

-------
                                     4-31
                               EXHIBIT 4-6

               INSTALLATION OF LINERS FOR LEACHATE CONTROL
                 AT UTILITY WASTE MANAGEMENT FACILITIES
                      (number of generating units)*


EPA Region                 Unlined       Lined         Unknown

1
   Surface Impoundments        001
   Landfills                   0             0            10
   Other/Unknown           	0         	0         	~]_
      Total                    0             0            18
2
   Surface Impoundments        0000
   Landfills                   1-14             7           22
   Other/Unknown           	0         	0         	17           17
      Total                    1            14            24           39
3
   Surface Impoundments       17             2
   Landfills                  17             7
   Other/Unknown           	0         	0
      Total                   34             9
4
   Surface Impoundments      153             3
   Landfills                  14             7
   Other/Unknown           	0         	0
      Total                  167            10
5
   Surface Impoundments       90            20            50          160
   Landfills                  64            31           103          198
   Other/Unknown           	0         	4           130          134
      Total                  154            55           283          492
6
   Surface Impoundments        7             7             5           19
   Landfills                  11            17            20           48
   Other/Unknown           	0         	0         	20         	20
      Total                   18            24            45           87

-------
                                     4-32
                         EXHIBIT 4-6 (continued)

               INSTALLATION OF LINERS FOR LEACHATE CONTROL
                  AT UTILITY WASTE MANAGEMENT FACILITIES
                      (number of generating units)*
EPA Region
Unlined
Lined
Unknown
Total
   Surface Impoundments
   Landfills
   Other/Unknown
      Total
                  4
                  4
                 _0
                  8
                 21
                 50
                _2Z
                 98
   Surface Impoundments
   Landfills
   Other/Unknown
      Total
                  0
                  6
                 _Q
                  6
                  5
                 38
                 44
                 87
   Surface Impoundments
   Landfills
   Other/Unknown
      Total
    2
    2
10
   Surface Impoundments
   Landfills
   0 the r/Unknown
      Total
    0
    4
    0
    0
    0
   _0
    0
    0
    5
   0
   9
 _2
  11
Total U.S.
   Surface Impoundments      303
   Landfills                 132
   Other/Unknown           	6
      Total                  441
                 45
                 90
               _A
                139
                135
                356
                307
                798
               483
               578
              _312
              1378
     The data are provided by generating unit because each generating unit
     at a power plant may have its own waste management facility.  A
     generating unit typically refers to a single boiler,  turbine,  and
     generator set at a power plant.   A power plant may have more than one
     generating unit at the site.   For the database used here, data were
     available for 1378 generating units located at 514 power plants.

-------
                                    4-33
          Based on the information available, landfills are more
          likely to be lined than surface impoundments.  Of the
          222 generating units that use landfills and that
          indicated whether the disposal facility was lined or
          not, about 40 percent (90 units) have lined disposal
          facilities.  Only 13 percent of surface impoundments
          have liners installed (based on information from 348
          of the 483 units).
     The information in Exhibit 4-6 should be interpreted cautiously since

data were available for only 42 percent of the population (580 units of

1,378 units).  One of the reasons this information is unavailable is due

to the number of electric utilities that dispose of coal combustion wastes

off-site.  In many of these cases,  the utility does not know whether the

off-site disposal facility is lined or not since the utility does not run

the disposal operation.



    Liner use has been increasing in recent years.  Before 1975, less than

20 percent of all generating units  managed their coal combustion wastes in

lined facilities.  For units constructed since 1975, however, this

percentage has increased to over 40 percent.  The proportion of lined

management facilities is particularly high at generating units that

produce FGD sludge; since 1975 about 60 percent of management facilities

containing these wastes have been lined.



    4.2.2.2  Leachate Collection and Ground-Water Monitoring



    Any lined management facility may have a leachate collection system

and any facility (lined or unlined) may be equipped with a ground-water

monitoring system.  Leachate collection systems are used to prevent the

-------
                                     4-34
migration of contamination from a landfill or impoundment.  Both systems




can be used to monitor the rate and extent of contaminant migration.  The




design and placement of ground-water monitoring and leachate collection




systems should take into account the manner in which a landfill or




impoundment might potentially interfere with natural ground-water flow and




usage patterns.








    In surface impoundments, the leachate collection system(s) can be




placed below the entire liner system or it can be placed between any two




liners.  Leachate collection systems typically consist of a drainage media




(coarse sand and/or gravel) and perforated pipes (called riser pipes) that




slope toward a collection sump.  The collected leachate is pumped out via




these riser pipes to the surface for treatment and/or disposal.  If the




riser pipes through which the leachate is pumped perforate the synthetic




or clay liner, tight seals are necessary to ensure that the leachate does




not escape through the perforation.








    In landfills, leachate control systems can be installed below all




liners (this is usually called a pressure relief system), between liners




(the inter-liner leachate control system), and/or above the upper liner.




The floors of a landfill cell are designed to slope to the leachate




collection sumps and are usually covered with a drainage media such as




sand or gravel.  Each leachate control system has its own collection sump,




which is emptied through riser pipes so that the leachate can be treated




or disposed appropriately.  As with impoundment liner systems, riser




pipes, if they pierce the liners, must be sealed to prevent leakage.

-------
                                     4-35
    Ground-water monitoring wells are placed at strategic locations to




facilitate early detection of any contaminants that escape the facility




and migrate to the ground water.  The design and placement of the




monitoring wells is based on site-specific hydrogeological assessments,




soil chemistry, specific regulatory directives, and other physical and




chemical factors.  Downgradient wells typically are used to monitor the




extent of contamination arising from a facility, and upgradient




"background" wells are installed to serve as controls.








    Most newer utility waste management facilities have ground-water




monitoring systems, and many also have leachate collection systems.  In




other industries, permitted facilities subject to Subtitle C regulations




are required by law to have both ground-water monitoring and leachate




collection systems.    For utility waste disposal sites, it is estimated




that about 15 percent of all facilities have leachate collection systems




and about 35 percent have ground-water monitoring systems.








    4.2.2.3  Pre-disposal Treatment








    Facilities employ a variety of waste treatment processes to alter the




physical or chemical characteristics of wastes so that they will be




compatible with the disposal method used.  Treatment methods may also be




employed to comply with the effluent limitations established under the




Clean Water Act.

-------
                                     4-36
    Sludge Devatering







    The most commonly used pre-disposal treatment process is sludge



dewatering.  This process is often necessary so that the sludge can be



more easily handled and of a consistency suitable for landfill disposal.



This procedure can also be used for any wet coal ash or combined coal



ash/FGD sludge wastes.  Most frequently, sludge dewatering is accomplished



by sedimentation of the suspended solids in surface impoundments or, in



some cases, in clarification tanks.   This type of dewatering is carried


                                   18
out at 80 percent of the utilities.







    After the waste solids have had sufficient time to settle, the water



layer is drawn off the tank or impoundment and is either discharged



subject to National Pollutant Discharge Elimination System (NPDES) permits



or recycled back to the plant as sluice or cooling water.  The sludge



layer containing the solid ash and other particles is allowed to



accumulate for several months (or longer),  and is finally dredged after



the pond is drained.  With this process, the solids content (initially



between 5 and 15 percent by weight)  can be increased to between 30 and 60



percent.  The final solids content in the sludge is affected by the



sedimentation impoundment or tank design, the initial solids content, the



liquid and solids retention times, and the physical and chemical



characteristics of the solid particles.







    Even after dewatering, the settled sludges often have a mud-like



consistency and still contain so much free liquid that they are

-------
                                     4-37
inappropriate for landfill disposal.  In this case, the sludge may be



further dewatered by natural or mechanical processes.  In arid and



semi-arid areas, the sludges may be retained in the impoundments until



natural evaporation removes still more water.   Sludges may also be placed



on drying beds made of screens, sand, or other drainage media designed to



allow water to percolate out by gravity, while the solids are retained.



In mechanical sludge dewatering, belt or vacuum filters, filter presses,



thermal dryers, or other processes are used.  Ten percent of the utilities


                                               19
use some sort of filtration to dewater sludges.    For high-volume



sludges, however, mechanical dewatering equipment may be expensive and



inconvenient to operate.







    Reagent Addition








    Most FGD sludges and some other wet sludges can be rendered less



chemically reactive and/or more structurally stable by adding



solidification, stabilization, or fixation reagents.  This practice is not



widespread; less than 10 percent of the utilities report using these


          20
processes.    Solidification agents, such as sawdust or soil, absorb the



liquid in a sludge but do not chemically react with the sludge.



Stabilization and fixation reagents chemically react with some portion of



the sludge -- either the water, the dissolved solids, the particulate



solids, or some combination of the three-- and, in some cases, may render



potentially hazardous material non-hazardous as a result.  All of these



processes result in an increased volume of waste that contains less free



water and is easier to handle than the original waste stream.  An

-------
                                     4-38
additional benefit is an increase in the structural integrity (shear




stress and load-bearing potential; see Chapter Three for discussion of




these characteristics) of the waste material so that it may be placed in




deeper disposal facilities and covered with more material.








    Low-volune Waste Treatment








    The major methods available for low-volume waste management and




treatment include:








    •    co-disposal;




    •    contract disposal;




    •    evaporation;




    •    incineration;




    •    neutralization;




    •    physical/chemical treatment; and




    •    recycle/reuse.








    The type of waste management method used most often depends on the




type of low-volume waste stream.  Exhibit 4-7 shows the treatment process




commonly used for each low volume waste stream.  Each of these treatment




processes is discussed briefly below.

-------
                                      4-39
                                EXHIBIT 4-7

                 SUMMARY OF CURRENT HANDLING, TREATMENT AND
                       DISPOSAL OF LOW VOLUME BASTES
 Low Volume
   Waste
              Treatment
  Predominant Disposal
         Method
Waterside       If organic chelating agents are used,
Cleaning        this stream can be incinerated.  If
Waste           acids are used, the stream is often
                neutralized and precipitated with
                lime and flocculants.
                                           Co-disposal with high
                                           volume wastes in pond
                                           or landfill following
                                           treatment.
                                           Disposal by paid
                                           contractor.
Fireside
Cleaning
Waste
Air Preheater
Cleaning
Waste
Coal Pile
Runoff
Sometimes neutralized and precipi-
tated.  For coal-fired plants most
often diverted to ash ponds with-
out treatment.  If metals content
is high, chemical coagulation and
settling is used.

Settling in ash pond; neutralized
and coagulated if combined with
other streams before treatment.
   Co-disposal with high
   volume wastes in pond
   without treatment.
   Ponding following
   treatment.
1. Co-disposal in pond
   without treatment.
2. Ponding with treat-
   ment .
Neutralized by diverting to             1. Co-disposal of
alkaline ash pond.  Fine coal material     sludge in landfill
caught in perimeter ditch is often         after treatment.
diverted back to coal pile.             2. Co-disposal in ash
                                           pond.
Wastewater
Treatment
Make-up Water
Treatment

Cooling Tower
Basin Sludge
Usually ponded with ash or as a
separate waste.  Sometimes solids
co-disposed with bottom ash.

usually co-disposed in ash pond.
Very little survey or literature
information; infrequent stream.
Sludge comingled with wastewater
treatment sludge.
1.  Ponding
2.  Landfilling
1. Co-disposal in pond.
1. Landfilling

-------
                                     4-40
                             EXHIBIT 4-7 (Continued)

                    SUMMARY OF CURRENT HANDLING, TREATMENT AND
                          DISPOSAL OF LOW VOLUME BASTES
 Low Volume
   Waste
              Treatment
  Predominant Disposal
         Method
Demineralizer
Regenerants

Pyrite Wastes
Equalized in tanks,  then comingled
into ash ponds.

Disposed in landfills with bottom
ash or diverted to ash pond
1.  Ponding
1.  Ponding
2.  Landfilling
Source:  EPRI, Characterization of Utility Low-Volume Wastes,  prepared by
         Radian Corporation,  Austin, Texas, May 1985.

-------
                                      4-41
           Co-Disposal








     Co-disposal of low-volume wastes with high-volume wastes into landfills and



surface impoundments is commonly used in the utility industry.  A January 1981



EPA letter (the Dietrich memorandum) currently allows co-disposal of low-volume


                                                                     21
wastes with high-volume wastes in landfills and surface impoundments.    In a



1985 EPRI study on low-volume waste management, about three-fourths of the power



plants interviewed co-disposed some low-volume wastes in a surface impoundment or


         22
landfill.    The amount of treatment necessary before co-disposal varies with the



waste stream.  Solid wastes are typically disposed directly into the waste



management facility.  Liquid wastes are often routed to an interim treatment



surface impoundment.  Once in the surface impoundment, evaporation occurs and the



remaining sludge is landfilled.  If the liquid waste is chemically treated before



ponding, heavy metals are often removed in a treatment facility; the treated



liquid may then be reused or diverted to a surface impoundment while the residue



from the treatment process is disposed in a landfill.








           Contract Disposal








     Many utilities hire outside contractors to treat and dispose of low-volume



wastes.  Contract disposal is most common for low-volume waste streams produced



intermittently that are difficult to treat on-site.  For example, hydrochloric



acid boiler cleaning waste typically requires neutralization with high dosages of



a caustic material.  Construction of an on-site treatment system for this waste



stream requires a large capital investment, although boiler cleaning wastes are



produced only over a few hours once every two to five years.  As a result, some

-------
                                      4-42
utilities (7 of 22 power plants surveyed in EPRI's 1985 study) employ outside


                                             23
contractors when boiler cleaning is required.    The treated boiler cleaning



waste is then co-disposed on-site or disposed of off-site.
     Contract disposal is also a common waste management practice for



 spent ion exchange resin.  In EPRI's 1985 study, of five power plants



 responding, four plants hauled these wastes off-site while one power plant


                               24
 co-disposed the waste on-site.







          Evaporation







     Evaporation ponds are used to dispose of high concentration, low-volume



 liquid wastes.  Prior to final disposal, liquid wastes are diverted to an



 evaporation pond, generally shallow ponds with a large surface area.  The



 sludge remaining after most of the water evaporates is then dredged and    '



 disposed of in a landfill.







          Incineration







     Incineration of low-volume wastes includes injection into the boiler or



 mechanical evaporation.  This method of disposal is most common with organic



 cleaning wastes (Ethylenediamide tetracedic acid (EDTA) or citrate waste).


                  25
 A 1987 EPRI study   examined the effect of incinerating EDTA and citrate



 wastes in a utility boiler.  The findings showed that the additional metals



 contributed were minimal compared to the amount contributed by the coal.

-------
                                     4-43
Two of the twenty-two power plants interviewed in EPRI's 1985 study use this


                         r\f

method of waste disposal.
         Neutralization








    Acidic or alkaline wastes can be treated with either strong bases or



acids, respectively, to produce a near neutral stream.  For example,



wastewaters, demineralizer regenerant, and coal pile runoff must typically



be within a pH range of 6.0 to 9.0 to meet Clean Water Act (CWA) and



National Pollutant Discharge Elimination System (NPDES) limits.



Neutralization can be used to achieve these levels.  Similarly, hydrochloric



acid boiler cleaning waste, which may have a ph below 2.0, can undergo



neutralization to raise the ph above RCRA corrosivity guidelines (ph values


                                                              27
between 2.0 and 12.5 are not considered corrosive under RCRA).








         Other Physical/Chemical Treatment








    Physical and/or chemical treatment systems can be used for reducing and



removing dissolved and suspended contaminants from aqueous streams.   The



most prevalent treatments incorporate pH adjustment (i.e., addition of basic



or acidic materials), precipitation (i.e., separating solids from solution



or suspension), flocculation (i.e., aggregation of fine suspended



particles), clarification (i.e., separating liquid and suspended solids) and



filtration (i.e., trapping suspended solids).  The continuous waste streams



are treated to allowable levels.  Boiler chemical cleaning and fireside



cleaning wastes require higher reagent doses and occasionally additional

-------
                                     4-44
processing to meet Clean Water Act (CWA) and National Pollutant Discharge



Elimination System (NPDES) discharge limits for metals.  Ten of the 15 power



plants questioned in EPRI's 1985 study route boiler cleaning wastes through


                                                              28
physical and/or chemical treatment systems prior to discharge.
         Reuse
    Reuse is a common practice for many water-based low volume wastes,



especially in water-limited regions of the country.  For example,  less



contaminated streams (boiler blowdown, yard drains) can be used without



treatment in cooling towers,  ash handling systems,  and flue gas



desulfurization systems.  Other wastes, such as boiler cleaning wastes and



coal pile runoff, cannot easily be reused because they require extensive



treatment prior to reuse.  If a power plant does decide to treat these waste



streams, the liquid portion of treated waste may be reused while the sludges



produced during treatment are typically landfilled.







    4.2.3  Ocean Disposal







    Many different types of wastes, including industrial and municipal



wastes, have been disposed at sea in the past, although the use of this



method for disposing coal combustion wastes is only in the research and



development phase.  Typically, industrial and municipal wastes are shipped



out to sea and disposed at any of several regulated dump sites, which are



located anywhere from 20 miles to over 100 miles off the shore line.



Another method of ocean disposal (seldom used, however) involves pumping or

-------
                                     4-45
gravity feeding wastes through a pipeline that feeds directly from the



land-based waste generating site or dump site into the ocean.  When the



wastes reach the final oceanic disposal site, they either dissolve and



disperse or form a manmade reef.








    The 1972 Marine Protection Research and Sanctuaries Act (MPRSA), EPA


                                     29
regulations regarding ocean disposal,   and the London Dumping Convention



currently regulate ocean dumping with respect to the solids content, metals



content, and toxicity of wastes considered for this method of disposal.







4.2.4  Waste Utilization and Recovery of Various Waste By-Products








    Although the majority of the waste generated by coal-fired electric



utilities is land disposed, a substantial percentage is recovered and



reused.  From 1970 to 1980, an average of 18 percent of all coal ash



generated annually was utilized;   from 1980 to 1985, the average coal ash



utilization rate exceeded 22 percent, with utilization in 1985 over 27



percent of all coal ash produced.    The amount of FGD sludge waste utilized



is less than one percent of the total volume of FGD waste generated,



although more efficient FGD sludge recovery and utilization processes



currently being developed by the utility industry may increase this use.



The combined utilization rate for all high-volume coal combustion wastes,



i.e., fly ash, bottom ash, boiler slag, and FGD sludge, was about 21 percent



in 1985.

-------
                                     4-46
    The recovery processes are usually performed at the power plant.  Use of

the recycled waste may occur on-site or the recycled product may be sold for

off-site use.  Like any industrial product, the wastes to be recycled may be

accumulated on-site prior to sale and delivery.



    The recovery processes and the uses for waste by-products are numerous

and quite varied:
         Bottom ash currently has the highest rate of utilization
         at 33 percent.  It is used as blasting grit, road and
         construction fill material, for roofing granules,  and has
         other miscellaneous uses.

         Fly ash utilization is substantial.  About 17 percent of
         fly ash production is used for concrete admixture, cement
         additives, grouting, road and construction fill material,
         and for miscellaneous other uses.

         FGD wastes are not heavily utilized in the industry (less
         than 1 percent),  but some utilities have the capacity to
         recover sulfur,_sulfuric acid, or other sulfur products
         from the waste.

         Some low-volume wastes (particularly solvents) that are
         segregated from the high-volume waste streams are
         potentially recoverable or available for other uses.

         Numerous other recovery processes and utilization
         techniques are currently in the research and development
         phase.  At this time, however, the Agency is unaware of
         any advances in recovery processes that will significantly
         change the proportion of coal combustion wastes that are
         disposed.
    Coal Ash



    There are a variety of different options currently available for the

utilization of fly ash, bottom ash,  and boiler slag from coal-fired electric

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                                     4-47
utilities.  All types of coal ash are appropriate for use as construction




materials, as cement additives, and for several other uses.  Coal ash




utilization is primarily centered in the southeast and north central United




States.35








    Most fly ash and some bottom ash exhibit pozzolanic (bonding) properties




-- that is, the dried materials are cohesive and exhibit high shear strength




and compressive load-bearing characteristics.  These properties make ash an




appropriate substitute for portland cement for many applications, including




concrete production, standard cement production, and for special uses such




as for the production of road base cement or even grouting.








    Cement made with fly ash may be preferable to regular portland cement




for some applications.  One of the key benefits is the absence of heat




release while the concrete or cement mixture cures; this absence of heat




generation means that the design structural strength is more likely to be




achieved.  However, the use of fly ash and bottom ash as cement substitutes




is limited because of the wide variability in ash composition, even in ash




originating from the same coal supply or utility.  The presence of metals in




the ash can reduce the structural integrity of the final concrete by




preventing the necessary chemical bonding.  The presence of large quantities




of sulfates or nitrates will also interfere with the pozzolanic properties.




Because of this bonding interference,  fly ash and bottom ash are thought to




be able to replace no more than 20 percent of the cement used (or about 15




million tons of ash annually).     Improvements in utilization techniques may




reduce the bonding interference and increase the reutilization potential of

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                                     4-48
fly ash; however, the Agency is unaware of technical advances at this time




that will allow substantially greater utilization in cement applications.








    Fly ash and bottom ash are also commonly used as high-volume fill for




various construction materials.  The pozzolanic properties of these




materials facilitate soil stabilization, making them desirable as fill




additives.  Coal ash has been used as fill in asphalt, road bases, parking




lots, housing developments, embankments, and to line on-site disposal




facilities at the utilities.   In the future,  numerous other construction




applications may use coal ash as fill, particularly if the ash is available




at lower cost than standard fill materials.  However, the use of ash as fill




is limited somewhat because of the variability of the ash composition.








    Bottom ash and boiler slag have been used as substitutes for sand in




sand-blasting operations and road de-icing.  Ash and slag particles are     J




similar in size and density to sand particles.  In areas where sand is




costly to transport, these wastes can be economical substitutes.  Ash is




less corrosive than salt and could therefore be a preferable de-icing




material, although in some municipalities the use of ash for de-icing has




been prohibited due to public concern over aesthetics (e.g., ash residue on




cars).








    A variety of minor uses for fly ash and bottom ash have been considered,




some of which have already been implemented at a small number of utilities.




For example, bottom ash has been used for granular roofing material.  Fly




ash has been used by some facilities as a stabilization reagent for acidic

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                                     4-49
aqueous or semi-solid hazardous wastes:  the high-pH fly ash reacts with




other, low-pH waste to generate a neutral solution and to simultaneously




precipitate dissolved metals as oxides and hydroxides.  Because the fly ash




exhibits pozzolanic properties, the ultimate waste product, when dried,




often resembles concrete.  The metals from the original waste stream are




usually so strongly bound within the chemical structure of the final waste




product that they will not leach out, even under acidic conditions.








    Because fly ash has some of the same physical characteristics as a silty




clay, fly ash may be used as an additive to clay liners for waste management




facilities, particularly for impoundments.  Fly ash is cohesive and fairly




impermeable when properly compacted, and mixes well with some of the clays




used in impoundment liners.  However, because chemical composition of fly




ash is variable, its utilization as liner material may be limited.  If




methods are improved to be sure that minimum permeability and shear strength




requirements could be maintained over time, then the use of fly ash as an




impoundment liner material may increase.








    Fly ash has been used occasionally as a soil conditioner to increase the




pH of acidic soils, thereby enhancing crop growth.  Fly ash can also




contribute minerals to the soil.  However, soil conditioners in common use




today, mostly agricultural limestones, are so inexpensive and easy to obtain




that it would be difficult to penetrate this market with a fly ash product.








    There are few processes currently available for recovery of materials




from coal ash.   One facility has had some commercial success at producing

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                                     4-50
                       37
magnetite from fly ash.    Magnetite recovered from fly ash actually



contains a higher percentage of magnetics than does natural magnetite,



making it a more efficient coal cleaning agent.  This particular technology



shows some promise of expanding; other processes, mostly for metals



recovery, are in the development stage.  Recovery processes for alumina and



titanium are at an advanced stage of development.  However, while both these



technologies have been proven feasible, neither is currently economically



competitive with ore-processing technologies.  Another potential metal



recovery process, dubbed the DAL process and still in the research stage,



involves a series of relatively simple operations that can be performed with



commercially available process equipment to recover various metals from fly



ash.  Theoretically, this process could show a substantial return on


                                                            38
investment soon after the recovery facility began operating.







    There is little information available to the Agency on the environmental



effects of utilization of coal combustion wastes.  For many applications,



such as the use of coal ash in cement and concrete products, it would appear



that any adverse environmental impacts would be minimal.  To the extent that



coal combustion wastes can be recycled in an environmentally acceptable



manner, utilization would help to reduce the amount of waste disposed.  The



Agency is very interested in reducing the amount of waste that needs to be



disposed by the utility industry; however, barring major breakthroughs in



recycling techniques, it appears the potential for significantly increasing


                                               39
the amount of waste utilization may be limited.   Given current utilization



techniques, the Agency expects that the major portion of coal combustion



wastes will continue to be land disposed.

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                                     4-51
    FGD Wastes







    The prospects for utilization of FGD sludge are less promising than



those for ash utilization.  FGD sludge is not structurally stable or strong



enough to serve as a construction material, nor does it show the pozzolanic



properties required for a cement substitute.  Current research in the field



of FGD sludge utilization is focusing on a dry scrubber method in which



reagents will be used to precipitate the FGD waste streams as dry gypsum



powder.  Gypsum is sold for use in wallboard; however, there is currently a



glut on the market, and in any case, other sources of gypsum may be



preferred because the gypsum produced from FGD is often of lesser quality.



Some researchers are making an effort to find a reagent that will



precipitate a dry powder which, when mixed with water, will exhibit



pozzolanic properties and will harden to a concrete-like material.  No



testing has been done, however, as the research is still in the conceptual



stage.







    Although by-product utilization of FGD sludges comprises less than one



percent of total sludge production, a much greater percentage of FGD



by-products may be recoverable in the very near future since two full-scale



recovery processes and one test-scale recovery process for FGD by-products



are currently under development.  Of the two full-scale processes, the



Wellman-Lord process recovers both sulfuric acid and elemental sulfur from



the waste stream, while the magnesium oxide scrubber process recovers only


              40
sulfuric acid.    The citrate scrubbing process, currently in the testing



phase, recovers elemental sulfur.   FGD recovery processes currently in the

-------
                                     4-52
research stage will be used to recover elemental sulfur, sulfuric acid, and
gypsum from the FGD process, and should be available for full-scale use


                       41
within the next decade.    All recovery processes for FGD wastes general



both a by-product stream and a waste stream that must be disposed.
    Lov-Volune Utility Wastes








    EPA currently assumes that most low-volume utility wastes are



co-disposed with the high-volume wastes or, in some instances, burned in the



boiler at the power plant, although little data exist that accurately


                                                              42
describe industry-wide practices on low-volume waste disposal.    Since



co-disposal is a common industry practice, low-volume wastes do not have



specific processes associated with their recovery or utilization.  Although



this practice of co-disposal (or burning) may continue into the future,



certain waste streams, such as spent cleaning solvents,  might be recovered



by distilling and collecting the solvents at high temperature, which would



leave a low-volume residue to be disposed.  The recovered solvent could then



be reused on-site as a cleaning solvent or sold to another facility.  If an



organic solvent were contaminated in such a way that contaminant removal



were difficult or impossible, the contaminated solvent could be burned.  For



low-volume waste streams burned in the boiler, these wastes could be



transported to an off-site facility that would burn them as fuel.  If



low-volume wastes were considered hazardous, regulations might restrict the


                                                                   43
burning of these wastes, potentially making this option infeasible.

-------
                                     4-53
    Other recovery schemes for individual low-volume waste streams may be




developed if these streams are segregated from the high-volume wastes.  At




this time, however, few recovery processes and utilization techniques have



been considered separately for low-volume utility wastes.








    Recycled Effluent








    Approximately 25 percent of the utilities that utilize surface


                                                                   44
impoundments recycle some of their pond effluent back to the plant.    If



the recycled effluent is used as sluice water, the system pH may increase to



values well above 10.  The recycled effluent may also be used as cooling



water prior to ultimate discharge.   Although effluent recycling is not a



waste recovery or utilization technique, it can affect the chemical



characteristics of the solid wastes that may come into contact with the




recycled water.








4.3  SUMMARY








    Coal combustion waste management practices by electric utilities vary



widely across the industry.  State regulation, regional factors such as land



availability and water availability, and age of the power plant all have an



effect on the type of waste management practices that are employed.



Alternative practices, such as ground-water monitoring and leachate




collection, are used by some utilities, and in some states are mandated by



regulation.  A significant portion of coal combustion by-products are



recovered and utilized for various  purposes.

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                            4-54
All but one state regulates the disposal of coal
combustion wastes under their hazardous or solid waste
disposal regulations.  One state exempts these wastes from
regulation.

State solid waste regulations applicable to coal
combustion wastes vary widely across the country.
Generally, solid waste regulations require that disposal
facilities have permits; location restrictions and
standards related to liners, leachate control, and
ground-water monitoring are applied on a case-by-case
basis.

Currently, about 80 percent of all coal-fired power plant
wastes are land managed; the remaining 20 percent are
recycled or recovered.  The most common types of disposal
facilities used by utilities generating coal-fired wastes
are surface impoundments,  landfills,  and abandoned mines.

Currently, about 25 percent of utility treatment, storage,
and disposal facilities that receive combustion waste are
lined.  About 15 percent of all facilities have leachate
collection systems, and 35 percent have ground-water
monitoring.

Newer facilities are more likely to be lined, have
leachate collection systems, and ground-water monitoring
systems.  More than 40 percent of all generating units
constructed since 1975 use lined disposal facilities.

About 20 percent of all high-volume combustion wastes,
particularly fly ash and bottom ash,  are recycled,
primarily as cement additives,  high-volume road
construction material, or blasting grit.

About 99 percent of FGD wastes are currently disposed;
however, recovery of sulfur and sulfur products from FGD
wastes is a developing and promising technology.

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                                CHAPTER 4

                                 NOTES
     * Wald, Harkrader & Ross, Survey of State Laws and Regulations
Governing Disposal of Utility Coal-Combustion Byproducts, for the Utility
Solid Waste Activities Group (USWAG) , 1983.

     2 States have probably followed U.S. EPA's lead in exempting coal
combusting wastes.  Many states' regulations explicitly refer to 40 CFR 261.4,
or use the clause's exact wording.

     ^ The following State officials were interviewed: Brett Bettes, Solid
Waste Division, Washington Department of Ecology, January 6, 1987; Ken Raymond,
Industrial and Solid Waste Division, Oklahoma Department of Health, December
31, 1986; Dwight Hinch, Division of Waste Management, Tennessee Department of
Health, December 31, 1986; Shelby Jett, Division of Waste Management, Kentucky
Department of Environmental Protection, January 6, 1987; Vincent Nikle,
Assistant Liaison's Office, New Jersey Department of Environmental Protection,
December 17, 1986.

     ^ According to Maine's Solid Waste Management Regulations:  "More
Stringent Criteria for Large-Scale Disposal of Oil, Coal and Incinerator Ash:
Because of the concentration of heavy metals in residues from the combustion of
municipal solid waste or the combustion of oil or coal, including bottom ash
and fly ash, disposal of such ashes when they occur in amounts that exceed a
total accumulation of 20 cubic yards of coal ash . . .  per week over any
one -month period shall be confined to a secure landfill.  For the purposes of
these rules, a secure landfill shall mean a landfill with a liner and a
leachate management system."  (Maine's Solid Waste Management Regulations,
Chapter 401.2.3.).

     ^ The exhibit assumes that both on-site and off-site permits are required
unless the regulations explicitly state otherwise.

     ° See Chapter One for discussion of the regulation of low-volume utility
waste streams.

     ' Waste piling, a method occasionally employed by utilities, is not
discussed in this report.  Waste piles are mounds of ash placed on the ground
and covered with soil.

     ° U.S. Department of Energy, Impacts of Proposed RCRA Regulations and
Other Related Federal Environmental Regulations on Utility Fossil Fuel -Fired
Facilities. Volume II. 1983.

     * See Chapter 6 for a discussion of disposal costs.

     10 Haller, W.A. , J.E. Harwood, S.T. Mayne, and A. Gnilka, "Ash Basin
Equivalency Demonstration (for treatment of boiler cleaning wastes containing
heavy metals)," Duke Power Company, 1976.

-------
                                      -2-                                      ;


        Envirosphere Company,  Environmental Settings and Solid Residues
Disposal in the Electric Utility Industry. EPRI Report EA-3681, 1982.

     12 Ibid.

     13 Ibid.

     14
        A low-permeable clay is one that has been determined in laboratory
testing to have a permeability coefficient, K, of 10   cm/sec or less.

        There are one thousand mils per inch.

     16 See 40 CFR 264.

        Engineering-Science, Background Data on Utility Fossil Fuel-fired
Facilities, prepared for USDOE, Office of Fossil Energy, 1983.

     18 Ibid.

     19 Ibid.
     20
        EPRI Journal, 1985, cja. cit.

     21
        EPRI, Manual for Low-Volume Wastes From Fossil-Fuel-Fired Power Plants.
prepared by Radian Corporation, Austin,  Texas, July 1987.
     22
        EPRI, Characterization of Utility Low-Volume Wastes, prepared by Radian
Corporation, Austin, Texas, May 1985.

     23 Ibid.

     24 Ibid.

     25 EPRI, 1987.

     26 EPRI, 1985.

     27 EPRI, 1987.
     9fi
        EPRI, 1985.
     29
        40 CFR 228, Criteria for the Management of Ocean Disposal Sites for
Ocean Dumping.

-------
                                      -3-




     30
        Envirosphere Company, "Economic Analysis of Impact of RCRA on Coal

Combustion By-Products Utilization" in Report and Technical Studies on the

Disposal and Utilization of Fossil-Fuel Combustion Bv-Products. Appendix G,

prepared for Utility Solid Waste Activities Group (USWAG),  October 1982.


     31
        Information compiled by the American Coal Ash Association on 1985 ash

utilization, August 1, 1986.



     32 EPRI Journal.  1985.  O£. cit.


     33
     " Ibid.


     34
        Ibid.



     35 USWAG, 1982.



     36 EPRI Journal.  1985.  o^. cit.



     37 USWAG. 1982.  OE. cit.


     38
        Ibid.


     39
        For example, see comments by Garry Jablonski, section manager of ash

utilization for the American Electric Power Company, "Coal Ash Market Report,"

Vol. 1, No. 9, July 15, 1987.


     A.O
        EPRI, State-of-the-Art of FGD Sludge Fixation. 1978.



     41 Ibid.


     42
        Envirosphere Company, Information Responding to EPA's Request Regarding

Burning and Co-Treatment/Co-Disposal of Low Volume Wastes Generated At Fossil

Fuel Electric Generating Stations, prepared for USWAG and Edison Electric

Institute, August 1981.


     43
        The economics of burning these wastes would depend on the applicable

regulations.   Regulations concerning the burning of hazardous wastes are

currently being developed and are scheduled for final promulgation in mid-1987.


     44
        U.S.  Department of Energy.  1983.  Op. cit.

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                                 CHAPTER FIVE




            POTENTIAL DANGERS TO HUMAN HKAT.TH AND THE ENVIRONMENT
    Under Section 8002(n) of RCRA, EPA is to analyze the "potential danger, if




any, to human health and the environment from the disposal and reuse" of coal




combustion wastes and "documented cases in which danger to human health or the




environment from surface runoff or leachate has been proved."  This chapter




examines potential and documented dangers to human health and the environment




caused by wastes generated from the combustion of coal at electric utility




power plants.








    As described in Chapter One,  special large volume wastes, including coal




combustion wastes, are to be treated differently under RCRA than other




industrial wastes.  Due to the extremely large volume of coal combustion waste




and the expectation of relatively low risk from its disposal, Congress directed




EPA to evaluate all the factors in 8002(n) of RCRA in determining whether




Subtitle C regulation is warranted.  The danger from coal combustion waste




management is  only one of the factors EPA must consider.  In order to provide a




starting point for evaluating the potential danger from coal combustion waste




management, this chapter begins by providing the reader with background




information on the characteristics that an industrial solid waste must exhibit




to be considered hazardous under  RCRA,  and then looks at which of these




characteristics apply to coal combustion wastes.  The next section analyzes




several studies that monitored ground-water and surface-water concentrations in




and around coal combustion waste  disposal sites and documented the number of




times that drinking water standards were exceeded.  The third section of this

-------
                                      5-2


chapter reviews studies that compiled and evaluated reported incidences of

contamination to ground water and surface water due to the disposal of coal

combustion wastes.  Finally, the fourth section analyzes the factors affecting

the exposure of humans, animals, and plants to contaminants from coal

combustion waste by examining environmental setting and population data for a

random sample of 100 coal-fired utility power plants.
    5.1  RCEA SUBTITLE C HAZARDOUS WASTE CHARACTERISTICS
         AND LISTING CRITERIA
    Under RCRA, solid wastes are classified as hazardous if they exhibit

characteristics of ignitibility, corrosivity,  reactivity,  and/or EP toxicity as

defined by RCRA or if they are listed as hazardous by the Administrator.
         Ignitibility refers to the tendency of a substance to
         catch fire.  A liquid waste is ignitable if it has a
         flash point less than 60°C, as determined by
         EPA-specified test protocols.   A non-liquid waste is
         ignitable if, under standard temperature and pressure,  it
         is capable of causing a persistent, hazardous fire _._
         through friction, absorption of moisture, or spontaneous
         chemical change.^

         Corrosivity of waste is determined by measuring the
         waste's pH, the value used to express relative acidity or
         alkalinity.  A pH value of 7.0 is neutral; substances
         with a pH less than 7.0 are acidic, while those with a pH
         greater than 7.0 are alkaline.  A waste is corrosive, and
         therefore hazardous, if it is aqueous and has a pH less
         than or equal to 2.0 or greater than or equal to 12.5.   A
         waste is also corrosive if it is liquid and corrodes
         steel at a rate greater than 6.35 mm per year.  The pH
         measurements and the corrosion rate must be determined
         using EPA-approved methods.-*

         Reactivity refers to the stability of a substance.
         Wastes that are highly reactive and extremely unstable
         tend to react violently or explode.  A waste is reactive
         if it undergoes violent physical change without
         detonating, if it reacts violently with water, if it
         forms a potentially explosive or toxic mixture with

-------
                                      5-3


         water, or if it is capable of detonating or exploding at
         standard temperature and pressure.

         Extraction Procedure (EP) Toxicity is determined from a
         laboratory procedure designed to simulate leaching from a
         disposal site under actual disposal conditions.^
         Concentrations in the effluent from this test are
         compared with the Primary Drinking Water Standards (PDWS)
         of eight constituent metals to determine whether a waste
         is hazardous.  A waste is EP toxic if it produces a
         leachate using an EPA-approved procedure that has
         concentrations of contaminants that are 100 times the
         PDWS.6
    Wastes are also regulated as hazardous wastes under Subtitle C if the

Administrator lists them in 40 CFR 261.31-261.33.  The Administrator may list

wastes using several criteria:
         if they are ignitable, corrosive, reactive, or EP toxic
         as described above.

         if they have been found to be fatal to humans in low
         doses, or, in the absence of data on human toxicity,
         fatal to animals in laboratory tests (these wastes are
         designated Acute Hazardous Wastes).'

         if they contain any of the toxic constituents listed in
         Appendix VIII of 40 CFR 261, unless the Administrator,
         after considering the factors contained in 40 CFR
         261.11(a)(3), concludes that "the waste is not capable of
         posing a substantial present or potential hazard to human
         health or the environment when improperly treated,
         stored, transported or disposed of, or otherwise
         managed."  The factors that the Administrator may
         consider include the toxicity of the constituent, the
         concentration of the constituent in the waste, the
         potential for degradation, the degree of bioaccumulation
         to be expected from the constituent, and the quantities
         of the waste generated.  These wastes are designated
         Toxic Wastes.
    Determining whether coal combustion wastes show any of the hazardous

characteristics is important in analyzing potential danger to human health and

the environment.  In general, most coal combustion wastes, such as ash and FGD

sludge, are not ignitable.  Reactivity is also generally not a characteristic

-------
                                      5-4






of concern for coal combustion wastes.  The chemical and physical




characteristics of most coal combustion wastes identified in Chapter Three




indicate that these wastes are very stable and will likely not react with other




substances in their disposal area.  The remainder of this section will analyze




data on coal combustion wastes to see if these wastes exhibit the




characteristics of corrosivity and/or EP toxicity.








    5.1.1  Corrosivity of Coal Conbustion Wastes








    Under current RCRA regulations, only liquid wastes can be considered




corrosive.  Coal combustion ash, therefore, could not by itself be considered




corrosive, even if it generates a corrosive leachate.








    For wastes that are aqueous, a waste is corrosive if its pH is less than or




equal to 2.0 or greater than or equal to 12.5.  Available data indicate that the




pH values of most waste streams of coal-fired power plants do not fall within




these ranges; in fact, the only wastes that may be classified as corrosive




according to the above definition are water-side, hydrochloric acid-based




cleaning wastes, which have had measured pH as low as 0.5 (see Exhibit 3-26).




In an EPRI report on low volume wastes (see section 5.1.2) three samples of




hydrochloric acid-based boiler cleaning waste all had pH levels less than 2.




However, these wastes are often neutralized before disposal.  Several other




waste streams have pH levels which fall very near the corrosive ranges.  Most of




these are also low volume wastes.  Boiler blowdown has measured pH as high as




12, with a range of 8.3-12 (see Exhibit 3-20), and coal pile runoff has measured




pH as low as 2.1,  with a range of 2.1-6.6 (see Exhibit 3-21).  Sludge from




dual-alkali FGD processes using eastern coal is a high volume waste with

-------
                                      5-5






measured pH of approximately 12.1 (see Exhibit 3-17).  Chapter Three contains a




complete description of these wastes.









    Several studies of coal combustion waste streams surveyed in this chapter




indicate that the alkalinity or acidity of coal combustion wastes, while not




necessarily falling in the RCRA corrosive ranges, may occasionally reach levels




of potential concern.  For example, pH readings of waste fluids taken during a




study by Arthur D. Little were as high as 11.4 (see Section 5.2.1).  Three case




studies described in Appendix D (a study of 12 Tennessee Valley Authority power




plants, an individual study at the Bull Run Power Plant, and a study of the




Savannah River Project) showed pH readings of waste fluids at 2.0, 3.5, and 2.9,




respectively.  Section 5.3.1 describes a documented case in which highly




alkaline coal combustion waste (pH 12.0) caused substantial harm to aquatic life




after it accidentally spilled into Virginia's Clinch River in 1967.








    5.1.2  Extraction Procedure (EP) Toxicity of Coal Combustion Wastes




                                              • ^ '' '




    Current RCRA regulations (40 CFR 261.24) specify that if a leachate';.,




extracted using an EPA-.approved extraction procedure contains any of the metals




shown in Exhibit 5-1 at concentrations equal to or greater than the given limit,




the waste is classified as EP toxic and, unless otherwise exempted, will be




subject to Subtitle C regulation.'  The concentrations shown in Exhibit 5-1 are




100 times the current Primary Drinking Water Standards (PDWS) established by the




Safe Drinking Water Act for those constituents.








    Waste extraction tests are used to predict the type and concentration of




constituents that may leach from a waste disposal site under field conditions.

-------
                                      5-6
                               EXHIBIT 5-1

                MAXIMUM CONCENTRATION OF CONTAMINANTS FOR
                      CHARACTERISTIC OF EP TOXICITY
                         Contaminant         Level
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
5.0
100.0
1.0
5.0
5.0
0.2
1.0
5.0
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
Source:   40 CFR 261.24,  January 16,  1987.

-------
                                      5-7


Host extraction tests are conducted by mixing or washing a waste sample with a

water-based solution of a specified composition for a specified length of time.

The resulting leachate solution is then separated from the solids and tested for

constituent concentrations.



    5.1.2.1  Types of Extraction Procedures



    Several different types of waste extraction procedures are described in

detail below.  Although under current regulations only the Extraction Procedure

(EP) toxicity test is used to determine whether a waste is EP toxic, EPA has

recently proposed a new procedure, the Toxic Characteristic Leaching Procedure

(TCLP),  to replace the EP test (see Federal Register, Volume 51. No. 114, June

13, 1986, p. 21648).  Furthermore, in the period since EPA has promulgated the

Extraction Procedure (EP) toxicity test, many people have alleged that the EP

provides an inappropriate measure of leaching under field conditions.  For these

reasons, EPA has reviewed the results of other extraction procedure tests as

well as the EP.  To the extent that the results of these other procedures on

coal combustion wastes are generally consistent with the EP results, the debate

over whether the EP test is appropriate or not is moot.  Three of the extraction

tests described below (EP, TCLP,  and ASTM) are batch leaching tests.  Batch

tests are conducted by placing a waste sample in a water-based solution for a

specified period of time.  The fourth procedure, the column test, passes a

solution through the waste.


    •    The procedure for the standard EPA extraction test, the
         Extraction Procedure (EP) toxicity test.   requires
         obtaining a waste sample of at least 100 grams and then
         separating the liquids from the solids.  The solid
         portion is placed in a container along with 16 times its
         weight in deionized water, and continually agitated at
         20-40°C.   Throughout the test, the pH of the batch

-------
                                      5-8
         mixture is monitored.  If the solution remains above pH
         5.0, acetic acid is added to maintain a pH of 5.0.  If
         the solution is less than pH 5.0, no acetic acid is
         added.  If the pH of the batch solution is not below 5.2
         after the initial 24-hour agitation period, the pH is
         adjusted to 5.0 + 0.2 at the beginning of each hour
         during an additional 4 hour agitation period.  After
         agitation, the leachate solution is then separated from
         the solid portion,  and the liquid extracted from the
         original waste sample is added to the leachate solution.
         These combined liquids are then tested for constituent
         concentrations.

         Toxic Characteristic Leaching Procedure (TCLP),  which EPA
         has proposed as a replacement for the EP,   uses a
         different leaching solution depending on the nature of
         the waste being tested.  For wastes of low alkalinity, a
         pH 5.0 acetic acid/sodium acetate buffer is used for
         extraction.  If the waste is more alkaline, a normal
         acetic acid solution is used.  Unlike the EP toxicity
         test, the TCLP can be used for volatile waste
         constituents.

         The American Society for Testing and Materials (ASTM)
         developed the ASTM A procedure, which requires 48-hour
         agitation of a 1:4 mixture of waste to distilled
         deionized water.   Another test, ASTM B, involves the
         extraction of waste constituents in a buffered acetic
         acid solution of pH 4.5.    ASTM D, similar to ASTM A,
         involves the 48-hour agitation of a 350-gram sample with
         1400 milliliters of deionized distilled water, and the
         filtering of the aqueous phase, after agitation, with a
         0.45 micron filter.
         Unlike the batch testing methods described above,  the
         column test is conducted by passing a solution through
         the waste.  This test process simulates the migration of
         leachate and ground water through waste,  but still cannot
         duplicate field conditions perfectly.  Because there is
         no standard column test procedure, column tests are
         described individually in the studies reviewed in the
         next section of this chapter.
    The results of various studies (conducted with the above-mentioned

extraction tests) on the leaching of constituents from coal combustion wastes

are discussed below.

-------
                                      5-9
    5.1.2.2  Results of Extraction Tests
    Tetra Tech Study
    In 1983 Tetra Tech conducted a literature review for the Electric Power




Research Institute (EFRI) and reported results from a number of leachate




extraction studies.    An examination of the results of various leaching tests




(EF toxicity test, ASTM A, and ASTM B) on coal ash and flue gas desulfurization




(FGD) sludge revealed that results differed by waste type and were ultimately




dependent upon the source of the fuel (see Exhibit 5-2) and the mechanics of




combustion.  The study results were presented separately for ash and FGD sludge.
    Results of the batch leaching tests (EP, ASTM A, and ASTM B) reported in the




studies reviewed by Tetra Tech were presented as averages of the element




concentrations found in numerous runs of one type of extraction test.  Ranges of




the concentrations were sometimes presented as well.  Depending on the




laboratory that ran the test,  EP, ASTM A,  and ASTM B batch leaching tests were




run on as few as 3 and as many as 62 samples.








    Tetra Tech reviewed 457 EP tests on various types of ash.  Results from




these EP tests show a geometric mean concentration for selenium equal to its




PDWS.  Geometric mean concentrations for the other 7 metals were below their




respective PDWS.  The maximum concentrations were 4 times the PDWS for silver,




29 times for arsenic, 8 times  for barium,  140 times for cadmium, 14 times for




chromium, 4 times for mercury, 5 times for lead, and 17 times for selenium.








    Tetra Tech also reported results from 202 ASTM A tests on ash.  Selenium was

-------
                                      5-10
                                EXHIBIT 5-2

                    EFFECT OF GEOGRAPHIC COAL SOURCE
                    ON ELEMENT CONCENTRATION IN ASH
              Element

              Arsenic



              Barium

              Cadmium

              Chromium



              Mercury



              Lead

              Selenium


              Strontium


              Vanadium


              Zinc
     Geographic Variation

low in western coal ash; difference in
concentration between eastern coal and
midwestern coal ashes indistinguishable

highest in western coal ash

most concentrated in midwestem coal ash

low in western coal ash; difference in
concentration between eastern and
midwestern coal ashes indistinguishable

highest in eastern coal ash; all
distributions highly skewed toward high
concentrations

highest in midwestern coal ash

similar in eastern and midwestern coal
ash; lower in western coal ash

highest in western ash; lowest in
midwestern ash

similar in eastern and midwestern coal
ash; lower in western coal ash

highest in midwestern ash; lowest in
western ash
Source: Tetra Tech, Inc., Physical-Chemical Characteristics of Utility Solid
        Wastes, prepared for Electric Power Research Institute, EA-3236,
        September 1983.

-------
                                      5-11






the only constituent with a geometric mean concentration greater than the PDWS,




at a level approximately 2 times the PDWS.  The maximum concentrations were less




than the PDWS for silver and mercury.  For the other elements, the maximum




concentrations from the ASTM-A procedure were 7 times PDWS for arsenic, 4 times




for barium, 1.3 times for cadmium, 10 times for chromium, 5 times for lead, and




48 times for selenium.








    Cadmium was the only constituent in fly ash leachate extracted using the EP




for which there was a maximum concentration over 100 times the PDWS (and




therefore above the EP toxicity level).  The EP produced a leachate that had a




maximum cadmium concentration 140 times the PDWS.  However, the average cadmium




concentration for the 62 EP samples was only half the PDWS.  Tetra Tech did not




report the percentage of samples whose cadmium concentration exceeded 100 times




the PDWS.  In general, the more acidic or alkaline the leaching solution, the




higher the concentrations of leached constituents.  Tetra Tech concluded that




the geometric mean concentrations from the EP and ASTM-A tests were similar.




The results of the EP and ASTM-A tests are presented in Exhibit 5-3.








    Tetra Tech also reviewed data from a number of column tests on coal ash.




The test results did not show any concentrations greater than 100 times the PDWS




for any element tested.  One test was conducted during a two-year period using a




continuous-flow method to produce leachate from fly ash.  In another test, fly




ash and bottom ash were packed separately in glass columns, each of which was




leached for 27 days with 200 milliliters per day of either distilled water,




dilute base, or dilute acid.  For a third test, fly ash and bottom ash were




packed in water-saturated glass columns.  At one-week intervals, the columns




were flushed from below at a moderate rate for two hours.  This test was

-------
                                                              EXHIBIT 5-3




                                     RESULTS GF TETHA TECH EXTRACTION TESTS OH COAL OOMBUSTICB ASH
                                                 EP Test Results
                                                                                                ASTH A Test Results
Primary
Drinking Hater

Constituent
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
Standard
(nw/1)
.05
1.0
.01
.05
.05
.002
.01
.05

Range
<.004- 1.46 mg/1
.003- 7.6 mg/1
.0001- 1.4 mg/1
.001- 0.68 mg/1
<. 0001-0. 25 mg/1
<.0001- .007 mg/1
<. 0001-0. 17 mg/1
<. 0001-0. 20 mg/1

Geometric Mean
.012 mg/1
0.222 mg/1
.0047 mg/1
.036 mg/1
.005 mg/1
.00042 mg/1
.01 mg/1
.00064 mg/1
Maximum
Exeeedance
29 X PDWS
8 X PDWS
140 X PDWS
14 X PDWS
5 X FDWS
4 X PDWS
17 X PDWS
4 X PDWS

Range
<. 0005-0. 37 mg/1
.0004-3.8 mg/1
.0001-. 013 mg/1
.0005-0.5 mg/1
<. 0001-0. 25 mg/1
<.0001-.0012 mg/1
.0005-0.48 mg/1
<.0001-.03 mg/1

Geometric Mean
.0072 mg/1
0.208 mg/1
.00039 mg/1
.047 mg/1
.0025 mg/1
.00027 mg/1
.019 mg/1
.0007 mg/1 •
Maximum
Exceedanee
7 X PDWS
4 X PDWS
1.3 X PDWS
10 X PDWS
5 X PDWS
0.6 X PDWS
48 X FDWS
0.6 X FDWS
Source: Tetra Tech, Inc., Physical-Chemical Characteristics of Utility Solid Wastes,  prepared for Electric Power Research Institute,

        EA-3236, September 19S3.
Ui

I-1
ro

-------
                                      5-13
intended to simulate the intermittent wetting to which some ash disposal sites




are subject.








    Partly because flue gas desulfurization (FGD) technologies have only




achieved widespread commercial usage in recent years, FGD sludge has not been as




thoroughly characterized as coal ash.  However, the Tetra Tech study reported




the results of tests performed on sludges from a number of scrubber processes,




including the lime/limestone/alkaline fly ash process, the dual alkali/sodium




carbonate process (both these processes produce "lime sludge" and are the main




technologies currently in use), and the spray drying process (this process




produces calcium-based dry scrubber sludge and may be used more extensively in




the future).








    Results from EP tests on calcium-based dry scrubber sludge showed a maximum




concentration of cadmium that was 150 times the PDWS, above the EP toxic level.




Arsenic and selenium were also analyzed using the EP test; the maximum arsenic




concentration was 32 times the PDWS and the maximum for selenium was 1.8 times




the PDWS.  No other constituents were tested for this waste stream.  (Results




from the EP studies on calcium-based dry scrubber sludge were not averaged but




reported as ranges - the number of tests performed was not given).








    Tetra Tech also presented results of EP tests on lime sludge.  These tests




measured concentrations of all EP toxicity constituents,  and none were found to




be at EP toxic levels.








    Tetra Tech also reported on column tests performed on FGD sludge.  In one




column test, calcium-based dry scrubber sludge was leached with deionized water

-------
                                      5-14





for 11 months.  In another, various proportions of fly ash, wet calcium sulfate



(i.e., gypsum), calcium sulfite precipitate, and calcium oxide (lime) were



mixed, cured for 500 days, and leached with deionized water that was forced



through the waste columns.  The leaching test results (reported in a manner



similar to that for reporting results of coal ash leaching studies) indicated,



on the basis of an unreported number of tests, that PDWS constituents in lime



sludge and calcium-based dry scrubber sludge leached at concentrations that



exceeded their PDWS by multiples of less than 5 for silver, 32 for arsenic, 2



for barium, 30 for chromium, 10 for lead, and 15 for selenium; the concentration



of mercury found in sludge leachate matched its PDWS.   No constituents were at



concentrations above 100 times the PDWS.







    In summary, none of the coal ash or FGD sludge leaching studies reviewed by



Tetra Tech showed constituent concentrations greater than 100 times the PDWS,



with the exception of cadmium from calcium-based dry scrubber FGD sludge and



from coal ash.  Both results were from EP toxicity procedure tests.  The



behavior of these wastes primarily depended on the source of the fuel and the



mechanics of combustion.  Tetra Tech concluded that there were gaps in the



characterization of these wastes that made definitive conclusions difficult to



reach.







    Departnent of Energy Study







    The Department of Energy (DOE) conducted a compilation study of leaching



test results,  Analytical Aspects of the Fossil Energy Waste Sampling and


                         14
Characterization Project.   for the purpose of generating a data base on the

-------
                                      5-15






leaching characteristics of coals and their combustion wastes.  The EP test was




compared to a water leach test developed by ASTM (this test later became ASTM D)




and evaluated to determine the precision of the EP toxicity method when applied




to coal wastes.  In their summary of the collected data, DOE reported that for




six of the analyzed constituents there were no significant differences between




the testing results derived from the two methods.  The results of 2492 separate




extraction tests for the eight PDWS constituent metals (arsenic, barium,




cadmium, chromium, lead, mercury, selenium and silver) indicated that none of




the metals leached at concentrations that exceeded the PDWS by 50 times, and




most leached at concentrations less than 10 times the PDWS.  This was true for




both the EP test and the ASTM test.








    Arthur D. little Study








    EPA sponsored a study by Arthur D. Little, Inc. (see Section 5.2.1) which




included EP Toxicity tests on 20 fly ash samples from 16 power plants and 3 FGD




waste samples from 3 power plants.     The names of the plants from which the




samples were taken were not revealed because Arthur D. Little did not consider




the single "grab" samples obtained for testing to be representative.  The EP




test results showed no EP toxic levels in the extracted leachates of any




samples.  Silver and mercury concentrations were below the reported detection




limits of .001 mg/1 and .002 mg/1,  respectively, for all samples.  Lead was




detected in only three out of seventeen samples.  Other PDWS constituents




(arsenic, cadmium, chromium, selenium, and barium) were detected, but all were




found at concentrations less than 100 times the PDWS.  In contrast to the Tetra




Tech study reported above, leachates extracted from FGD samples had




concentrations of PDWS constituents that tended to be lower than the

-------
                                      5-16






concentrations in leachates extracted from fly ash samples, whereas the Tetra




Tech report indicated that, in general, higher concentrations of PDWS




constituents were leached from FGD sludges than from coal ash.  This discrepancy




may be due to variations in the wastes themselves, which, in turn, are due to




differences among coals derived from different sources.  Results of the Arthur




D. Little study are presented in Exhibit 5-4.








    Battelle Pacific Northwest Study








    In another study for the Electric Power Research Institute (EPRI), Battelle




Pacific Northwest reviewed data developed during a round-robin study that




compared results from three laboratories performing both the EP and TCLP




tests.    Battelle Northwest compared the two extraction procedures by looking




at the ratio of the mean TCLP concentrations to the mean EP concentrations for




each element.  These ratios fell within the range of 0.8 to 1.2 about 60 percent




of the time.  Only 15 percent of the ratios exceeded 2.0.  In 83 percent of the




comparisons, the TCLP test leachate contained greater concentrations of the PDWS




constituents than the EP test leachate.








    Battelle compared the maximum mean concentration of each compound (taken




from the pool of averaged results for each constituent from both EP and TCLP




testing of all the waste samples) with the corresponding PDWS.  This comparison




indicated that for both the EP and the TCLP procedures, concentrations of




silver, barium, and mercury were less than the established PDWS for those




metals, whereas the concentration of arsenic was 21 times the PDWS; cadmium, 25




times; chromium, 13 times; lead, 4 times; and selenium, 14 times.

-------
                                                              5-4
                                    RESULTS OF AKIUUK D. LITTLE itsiiBL. SBDHIH3 THE
                                  BARGE OF OOHCENTRATICH OF METALS IR EP EXTRACTS a/
Metal

Arsenic
Barium
Cadmium
Chromium (CrVI) b/
Lead
Mercury
Selenium
Silver
(A)
Overall
Average Values
Fly Ash
.08
.34
.03
.16
.01
<.002
.05
<.001
FGD Haste
0.20
.18
.01
.02
.01
<.002
.020
<.001
Range Observed (mg/1)
Fly Ash
0.002-.410
0.1-0.7
0.002-0.193
0.008-0.930
0.003-0.036
<0.002
.002-0.340
<0.001
FGD Haste
0.002-0. 065
0.15-0.23
0.002-0.020
.011-0.026
0.005
<0.002
0.008-0.049
<0.001
(B)
Primary Drinking
Hater Standards
.05 mg/1
1.0 mg/1
0.01 mg/1
0.05 mg/1
0.05 mg/1
0.002 mg/1
0.01 mg/1
0.05 mg/1
Ratio of Observed
Range to
Fly Ash
0.04-8.2
0.1-0.7
0.2-19.3
0.16-18.6 c/
0.06 to 0.72
<1
0.2 to 34
<0.02
PDHS (A/B)
FGD Haste
0.04-1.30
0.15-0.23
0.2-2
0.22-0.52
0.1
<1
0.8-4.9
<0.02
a/ Ranges are shown for fly ash and FGD samples; comparisons are made to the Primary Drinking Hater Standards.
b/ The Arthur D. Little study tested the concentration of Cr(VI), an ion of chromium.
c_/ Since total chromium values are measured by the graphite furnace atomic absorption analysis method,  these are upper limits
   for the Cr(VI) values.
 I
l->
*J
Source:  Arthur D. Little, Inc., Full-Scale Evaluation of Haste Disposal from Coal-fired Electric Generation Plants,  prepared for
         the Air and Energy Research Laboratory of the U.S. Environmental Protection Agency, for the Office of Solid  Haste,
         EPA-600-7-85-028, June 1985.

-------
                                      5-18
    University of Alberta Study
    The University of Alberta conducted a study for EPRI that involved passing a


water-based solution through a series of columns with increasing ash

               1 R
concentrations.    The study results indicate that while some constituent metals


were initially released or mobilized from the wastes using this method, these


same constituents were attenuated in columns further along in the series.


Boron, selenium, and arsenic were initially mobilized, but only boron remained


mobilized to a significant extent.  Arsenic and selenium interacted in


successive columns such that the movement of arsenic and selenium through the


system was retarded.
    In addition to studying the test leachates, the University of Alberta


researchers studied the fly ash itself to determine the processes that affect


the migration of metal constituents.  The study results indicated that some


constituents are not uniformly distributed within the fly ash particles.   The


fly ash particles typically consist of an interior "glass" matrix covered by a


relatively reactive and soluble exterior coating.  The study found that arsenic


and selenium were concentrated almost exclusively in the coating of the fly ash


particles and thus were readily leached; the barium concentration was split


evenly between the interior and exterior of the particles; about 75 percent of


the cadmium and chromium were concentrated in the interior glass matrix;  and


almost all the lead was concentrated in the interior glass matrix and was,


therefore, not readily mobilized.





    The study attributed the uneven concentration of constituents in the fly ash


particles to the vaporization of relatively volatile constituents during

-------
                                      5-19






combustion, followed by the condensation of these constituents on the exterior



of fly ash particles entrained in the flue gas.  However, this study reported




that lead was contained within the interior glass matrix of the fly ash



particles, while the Tetra Tech study discussed earlier reported that lead was



volatile and thus likely to be found on the surface of fly ash particles.  Both




studies reported that arsenic and selenium were found on the surface of the fly



ash particles.  The University of Alberta concluded that the physical and



chemical characteristics of the fly ash were determined by both the chemical



composition of the coal from which it came and the mechanics of fly ash



formation during combustion.








    The difference between the University of Alberta study and the standard



leaching test studies is that the mobility of constituents was observed under a



variety of conditions.  A number of waste concentrations could be tested in the



columns to imitate specific field conditions.  (Single column extractions also



possess such flexibility,  but to a lesser degree.)  The University of Alberta




study simulated landfill conditions by allowing the laboratory leachate solution



to continually change as it migrated through multiple waste columns, whereas in



batch extraction tests the laboratory leachate solution is allowed to come into



contact with only one ash sample.








    Battelle Chemical Characterization Study








    Battelle Pacific Northwest Laboratories recently completed a study for EPRI


                                                                   19
on chemical characteristics of fly ash,  bottom ash, and FGD sludge.     As part



of this study, Battelle performed a comparison of the EP Toxicity Test and the



TCLP test.  While most of the results of the two procedures were consistent,

-------
                                      5-20






differences were observed with acidic samples.  One acidic fly ash EP sample had



both arsenic and chromium above RCRA limits.  Another acidic fly ash sample also



exhibited elevated levels of arsenic and chromium, but not at levels exceeding



RCRA limits.  The study found, however, that the two samples showed considerably



less leachability for arsenic and chromium with the TCLP, while other elements



tested showed similar results from the two testing procedures.  The study



concluded that the difference between the two types of tests resulted from the



acidic character of the samples.








    Radian Corporation Study








    The Radian Corporation conducted two studies for EPRI that involved testing



various low-volume waste streams.   In the first of these studies (published in


          20
May 1985),    Radian Corporation collected thirty-two samples on eight types of



low volume wastes.  These samples  were tested using the EP toxicity test as well



as some other testing procedures.   The results of the EP toxicity test showed



that the only waste stream Radian tested that exceeded the EP toxicity limits in



the 1985 Radian study was untreated boiler chemical cleaning waste.  Exhibit 5-5



presents the results for three samples of untreated boiler cleaning wastes.  All



three samples had elevated levels  of chromium and cadmium, including exceedances



of EP toxicity limits, and two samples of boiler cleaning wastes had elevated



concentrations of lead, including an exceedance of EP limits.  This study also



performed EP tests on boiler cleaning wastes after neutralization in a plant



treatment system.  As shown in Exhibit 5-5, the two samples of treated boiler



cleaning waste did not exceed EP toxicity limits for any metals.

-------
                                      5-21
                                   EXHIBIT 5-5

                        EP TOXICITY ANALYSIS FOR UNTREATED
                  AND TREATED BOILER CHEMICAL CLEANING HASTES a/
                            (concentrations in ng/1)

                                 Untreated Boiler Cleaning Waste Type
Metals

Silver
Barium
Cadmium
Chromium
Arsenic
Mercury
Lead
Selenium
 Maximum
Allowable
EP Toxicity
  Limits

   5.0
 100.0
   1.
   5.
 .0
 .0
5.0
0.2
5.0
1.0
Ammoniated
EDTA with
Inhibitor

   0.002 b/
   0.76
   1x0
   4.7
   0.006
   0.0002 b_/
   3.6
   0.002 b/
                              Oxidizer

                                 0.002 b/
                                 0.67
4.7
0.002 b/
0.0002 b/
                                    0.002 b/
Hydrochloric
   Acid

    0.007
    0.91
    0.64
   20.0
    0.051
    0.0042
    0.002 b/
    0.003 b/
                                 Treated Boiler Cleaning Waste Type
Metals

Silver
Barium
Cadmium
Chromium
Arsenic
Mercury
Lead
Selenium
     Maximum
    Allowable
   EP Toxicity
     Limits

       5.0
     100.0
       0.2
       5.0
       1.0
                       HC1+
                    Inhibitor,
                     Chelant

                       0.042
                       0.40
                       0.002 b/
                       0.001 b/
                       0.002 b/
                       0.0002 b/
                       0.002 b/
                       0.002 b/
                     Hydrochloric
                        Acid

                         0.033
                         0.25
                         0.012
                         0.099
                         0.002 b/
                         0.0002 b/
                         0.002 b/
                         0.002 b/
a/  All underlined values exceed maximum allowable limits under current RCRA
regulations for hazardous wastes.

b/  Values shown are detection limits.  Actual values could be less than,  but no
greater than, the indicated value.

Source:   Electric Power Research Institute, Characterization of Utility
          Low-Volume Wastes.  Radian Corporation, May 1985.

-------
                                      5-22
    In Radian Corporation's second study of low-volume wastes (published in July


      21
1987),   they collected additional data on certain low-volume waste streams that



the first study indicated might have high concentrations of metals.  As shown in



Exhibit 5-6, eight of twenty-one samples of low-volume liquid wastes from



coal-fired plants were found to exceed EP toxicity limits.  For boiler chemical



cleaning wastes, 7 of 10 samples exceeded EP toxicity limits for at least one



constituent.  Six of the boiler chemical cleaning waste exceedances were for



chromium and the remaining exceedance was for lead.  One wastewater brine sample



out of five tested samples exceeded the EP limits for selenium.  There were no



reported EP exceedances for waterside rinses or coal pile runoff.







    Radian Corporation also conducted EP Toxicity tests on low-volume waste



sludges.  None of the three samples from coal-fired power plants were considered



EP Toxic, including a boiler chemical cleaning waste sludge.  For the two



wastewater pond sludges,  the study compared the EP and TCLP testing procedures.



Results of the EP and TCLP tests are shown in Exhibit 5-7.  The two extraction



procedures produced nearly identical concentrations of metals in their extracts.







    As in their first study, the Radian Corporation also sampled low-volume



wastes that had been treated.  This study found significant reductions in



concentrations of chromium, copper, iron, nickel and zinc after hydrochloric



acid boiler cleaning waste was neutralized.







    The study also examined the treatment effectiveness of co-disposal of



low-volume wastes with high-volume wastes.   Results of EP toxicity tests on



co-disposal mixtures found that co-disposal significantly reduced concentrations



of contaminants in the co-disposed mixture.   Results of the EP tests are

-------
                                                                    EXHIBIT 5-6


ELEMENT
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
ph (units)
EP
Toxicity
Limit
5.0
100.0
1.0
5.0
5.0
0.2
1.0
5.0
2
-------
                            5-24
                       EXHIBIT 5-7

        COMPARISON OF EP AND TCLP EXTRACTIONS  FOR
     LOW-VOLUME SLUDGE DREDGED FROM WASTEWATER PONDS
                           (ag/D
EP Test
ELEMENT
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
Source:
RCRA
Limit
5.0
100.0
1.0
5.0
5.0
0.2
1.0
5.0
Manual for
Fuel -Fired
# of
Tests
2 0
2 0
2 0
2 0
2 0
2
2
2 0
Management of
Power Plants.
Range
.002-0.015
.045-0.12
.002-0.002
.01-0.011
.002-0.006
0002-0.0002
003-0.0003
.002-0.004
Low -Volume
Mean
0.0085
0.0825
0.002
0.0105
0.004
0.0002
0.003
0.003
Wastes
TCLP Test
Range
0.004-0.016
0.07-0.089
0.002-0.002
0.018-0.023
0.002-0.16
0.0002-0.0002
0.003-0.03
0.009-0.012
From Fossil-
Electric Power Research Institute
Mean
0.010
0.080
0.002
0.021
0.081
0.0002
0.017
0.011
1
prepared by Radian Corporation, Austin, Texas,  July 1987.

-------
                                      5-25






presented in Exhibit 5-8 for co-disposal with fly ash from three geographic




areas.









    5.1.2.3  Summary of Extraction Test Results








    In conclusion, the results of these studies indicate that coal combustion




utility wastes may leach several elements,  including PDWS constituents.  While a




variety of extraction procedures were used in these studies, and questions have




been raised about the applicability of certain testing methods to coal




combustion wastes (which are generally disposed on-site in monofills), all of




the extraction procedures used in the studies (EP, TCLP, ASTM, and column)




produced average concentrations of constituents that were below the EP toxic




level for all waste streams except untreated boiler cleaning waste.  In the 1987




Radian Corporation study, untreated boiler cleaning wastes had a mean




concentration 169 times the PDWS for chromium using the EP Toxicity test.








    For the high-volume waste streams, cadmium, arsenic, and chromium were the




only elements for which a maximum concentration was found that was over 100




times the PDWS.   Arsenic and chromium were above EP toxicity limits based on EP




tests for one acidic fly ash sample in the Battelle chemical characterization




study.  These were the only exceedances based on 23 samples.  Cadmium was found




at a concentration 150 times the PDWS in calcium-based dry scrubber sludge




leachate and at a concentration 140 times the PDWS in some coal ash leachate as




reported in the Tetra Tech study; these leachates were extracted using the EP




test method.  For both types of waste, however, the exceedances represented the




maximum concentrations; all averages of cadmium concentration levels were below




100 times the PDWS.   In fact, the geometric mean of cadmium in coal ash

-------
             EXHIBIT 5-8

EP TLOClClTX TEST RESULTS OP LOW VDUMK
 HASTES BEFORE AND AFTER CO-DISEOSAL*
                (BR/L)

  Midwestern Bituminous Coal Fly Ash

ELEMENT
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
RCRA
Limit
5.0
100.0
1.0
5.0
5.0
0.2
1.0
5.0

Fly Ash Haste
0.006
0.006
0.02
0.01
0.002
0.0002
0.028
0.02
EDTA
Waste
0.006
0.76
3
A. 7
3.6
0.0002
0.002
0.002
EDTA Waste
Co-disposed
With Ash
0.026
0.23
0.02
0.01
0.008
0.0002
0.006
0.02
Citrate
Waste
0.21
1.6
0.64
3.9
0.002
0.0002
0.003
0.006
Citrate' Waste
Co-disposed
With Ash
0.037
0.006
0.02
0.01
0.002
0.0002
0.002
0.02
General
Wastewater
0.003
1.2
0.008
0.11
0.002
0.0002
0.003
0.009
Wastewater
Co-disposed
With Ash
0.031
0.17
0.02
0.01
0.002
0.0002
0.002
0.02
 Southeastern Bittrainoua Coal Fly Ash
                                                                                                     0*


ELEMENT
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver

RCRA
Limit
5.0
100.0
1.0
5.0
5.0
0.2
1.0
5.0


Fly Ash Waste
0.037
N/A
0.02
0.036
0.002
0.0002
0.003
0.02

EDTA
Waste
0.006
0.76
3
4.7
3.6
0.0002
0.002
0.002
EDTA Waste
Co-disposed
With Ash
0.036
0.33
0.02
0.01
0.002
0.0003
0.015
0.02

Citrate
Waste
0.21
1.6
0.64
3.9
0.002
0.0002
0.003
0.006
Citrate Haste
Co-disposed
With Ash
N/A
0.006
0.02
0.15
0.004
0.0002
0.082
0.02

General
Hastewater
0.003
1.2
0.008
0.11
0.002
0.0002
0.003
0.009
Wastewater
Co-disposed
With Ash
0.042
0.47
0.085
0.01
0.023
0.0002
0.003
0.02

-------
                                                      EXHIBIT 5-8 (Continued)

ELEMENT
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
RCRA
Limit
5.0
100.0
1.0
5.0
5.0
0.2
1.0
5.0
                     Fly Ash Waste

                         0.006
                         0.94
                         0.02
                         0.01
                         0.002
                         0.0002
                         0.034
                         0.02
 EDTA
Waste

 0.006
 0.76
 3
 4.7
 3.6
 0.0002
 0.002
 0.002
> TUKICITY TEST KESULTS OF LOW VOLUME
HASTES BKVUtK AID AFTER CODISPOSAL
(•C/L)
Western SubbituBinooa
EDTA Haste
Co-disposed
With Ash
0.08
0.7
0.02
0.01
0.041
0.0002
0.026
0.02

Coal Fly Ash

Citrate
Waste
0.21
1.6
0.64
3.9
0.002
0.0002
0.003
0.006


Citrate Waste
Co-disposed
With Ash
0.45
0.43
0.02
0.01
0.002
0.0002
0.031
0.02



General
Wastewater
0.003
1.2
0.008
0.11
0.002
0.0002
0.003
0.009
 Wastewater
Co-disposed
 With Ash

    0.005
    0.8
    0.02
    0.01
    0.002
    0.0002
    0.003
    0.02
                                                                                                                                                     N>
*A11 underlined values indicate an exceedance of the current RCRA limit for hazardous wastes.
Source:   Manual for Management of Low-Volume Wastes From Fossil-Fuel-Fired Power Plants.  Electric  Power Research Institute,
          prepared by Radian Corporation,  Austin,  Texas,  July 1987.

-------
                                      5-28






leachates in the Tetra Tech study was just under 0.5 of the PDWS.









    For the low-volume waste streams, the only exceedance of EP toxicity limits




for wastes other than boiler cleaning waste was one wastewater brine sample that




had selenium at 150 times the PDWS.  The mean concentration of selenium in the




wastewater brine samples was below EP toxicity limits.  While untreated boiler




cleaning wastes had exceedances of EP toxicity limits for chromium and lead, as




noted above, EP toxicity tests on neutralized boiler cleaning wastes and on




boiler cleaning wastes co-disposed with fly ash showed no exceedances of EP




limits.








5.2  EFFECTIVENESS OF WASTE CONTAINMENT AT UTILITY DISPOSAL SITES








    Coal combustion wastes contain trace elements that at certain levels could




pose a potential danger to human health and the environment if they migrate from




the disposal area.   The extraction procedure tests described in Section 5.1.2




indicate that these trace elements may leach out of disposed wastes, although




rarely at concentrations greater than 100 times the PDWS.  This section of the




report analyzes studies of ground-water and surface-water quality at and around




utility disposal sites to ascertain whether potentially hazardous constituents




that leach out of the waste migrate into surrounding ground water or surface




water.  The studies discussed in this section use as a measure of water quality




the concentration of Primary Drinking Water Standards (PDWS) and Secondary




Drinking Water Standards (SOWS) constituents in the water around utility waste




disposal sites.  Primary and Secondary Drinking Water Standards were established




in the Safe Drinking Water Act.  Primary Drinking Water Standards establish




concentration limits for toxic constituents.  Secondary Drinking Water Standards

-------
                                      5-29





are based on aesthetic characteristics such as taste, color, and odor.  Exhibit



5-9 shows the current PDWS and SDWS.  If ground water and surface water



downgradient from waste disposal sites have concentrations of constituents in



excess of PDWS or SDWS, and upgradient concentrations are below the standards or



are lower than the downgradient concentrations, the coal combustion waste could



be one of the sources contributing to ground water or surface water



contamination.






    EPA has conducted a number of studies on the quality of ground water in the



immediate vicinity of utility disposal sites.  Arthur D. Little performed



extensive ground-water monitoring at six utility disposal sites.  In a second



study, Franklin Associates compiled data from state records on ground-water



quality in the vicinity of 66 utility disposal sites.  This section also reviews



and evaluates a study conducted by Envirosphere for USWAG on available data on



ground-water quality at 23 electric utility sites to evaluate whether and to



what extent occurrences of ground-water contamination have resulted from the



disposal of coal combustion wastes.






    5.2.1  ADL Study of Waste Disposal at Coal-Fired Power Plants






    Arthur D. Little, Inc. (ADL), conducted a three-year study for EPA's Office



of Research and Development to assess the environmental effects and engineering



costs associated with coal ash and flue gas desulfurization waste disposal


                                         22
practices at six coal-fired power plants.    Appendix E contains a detailed



discussion of the study, including how the six sampled sites were selected, the



study approach,  and results for each site.   A summary of the six sites is



presented below:

-------
                                      5-30


                                    EXHIBIT  5-9

                       PRIMARY DRINKING WATER STANDARDS
                                            Concentration
                       Contaminant

                       Arsenic •
                       Barium
                       Cadmium
                       Chromium
                       Fluoride
                       Lead
                       Mercury
                       Nitrate (as N)
                       Selenium
                       Silver
     0.
     1.
  .05
  .0
 0.01
 0.05
 4.0
 0.05
 0.002
10.0
 0.01
 0.05
                      SECONDARY DRINKING WATER STANDARDS
                       Contaminant

                       Chloride
                       Color
                       Copper
                       Corrosivity
                       Foaming Agents
                       Iron
                       Manganese
                       Odor
                       PH
                       Sulfate
                       Total Dissolved Solids
                       Zinc
  Level
250 mg/1
15 color units
1.0 mg/1
Noncorrosive
0.5 mg/1
0.3 mg/1
0.05 mg/1
3 Threshold odor number
6.5 - 8.5
250 mg/1
500 mg/1
5.0 mg/1
Source:  40 CFR 141 and 143,  September 1,  1986.

-------
                             5-31
The Allen Plant in North Carolina disposed of a mixture
of fly ash and bottom ash in two unlined disposal ponds,
one closed and one in active use.  Intermittent waste
streams, such as boiler wastes and coal pile runoff, were
also disposed in the ponds.  While concentrations of
trace elements in downgradient ground water were higher
than upgradient concentrations, exceedances of the
Primary Drinking Water Standards were not found.
Elevated concentrations of arsenic (up to 31 times the
PDWS) were found in fluids within the active ash pond.
Attenuation tests indicated that the arsenic
concentrations would be chemically attenuated by iron and
manganese in the soils beneath and surrounding the site.
Ground-water contamination, particularly from arsenic,
could have resulted if these attenuative soils had not
been present.  Secondary Drinking Water Standards were
exceeded in both the upgradient and downgradient ground
water for manganese and in the downgradient ground water
for iron.  This was attributed to high concentrations of
these elements present in the soils of the site.
Steady-state conditions have probably not been achieved
at the Allen site; increases in downgradient ground-water
concentrations of non-attenuated contaminants may be
expected in the future.
The Elrama Plant in western Pennsylvania disposed a
fixated FGD sludge-fly ash mixture, along with small
volumes of bottom ash and sludge from coal pile runoff
treatment ponds, in an abandoned coal-mining area 12
miles from the plant.  Part of the landfill is underlain
by acid-producing spoils from the strip mining of coal.
Cadmium was found in concentrations exceeding the Primary
Drinking Water Standard by as much as 20 times in
downgradient ground water; the highest concentration was
found in the well closest to the landfill.  There were no
upgradient exceedances for cadmium.  Steady-state
conditions did not appear to have been achieved at the
site, so that effects of leachate from the landfill may
be expected to increase with time.  Secondary Drinking
Water Standards (for pH, manganese, sulfate, and iron)
were exceeded at the site in both upgradient and
downgradient ground water.  These exceedances probably
occurred because of characteristics of the disposal area
and because ground water was already contaminated from
acid mine drainage.  Test results indicated that any
constituent migration from the landfill did not
measurably affect the water quality of the nearby
Youghiogheny River.

Arsenic was repeatedly detected at levels three to five
times the Primary Drinking Water Standard in pond
liquors, but appeared to be attenuated by soils at the
site.  This suggests the possibility that similar wastes

-------
                             5-32
at other sites could leach arsenic at higher levels if
arsenic were not attenuated by surrounding soils or
diluted before reaching drinking water.

The results discussed above indicate that the fixated
FGD/fly ash wastes have been, and will continue to be, a
source of contamination at the site.   Because
exceedances for many contaminants were probably due to
concurrent contamination from acid mine drainage,
leachate from coal combustion waste may have only a small
incremental impact on water quality.

The Dave Johnston plant in Wyoming is located in an arid
region with little ground-water recharge.  The plant is
the oldest of the six sites, and burns low-sulfur western
coal.  There are a number of disposal areas at the site;
the ADL study investigated two unlined fly ash landfills,
one active and one closed.  Exceedances of the Primary
Drinking Water Standards for cadmium (up to 3 times the
PDWS) were found in ground water upgradient and
downgradient of the site. .Cadmium was found at elevated
concentrations in pond liquors and ground water beneath
the wastes.  Exceedances of Secondary Drinking Water
Standards for manganese and sulfate were also observed in
downgradient and upgradient ground water.  These two
contaminants and boron were found in elevated
concentrations in ground water beneath the waste and in
pond liquors.   No samples were analyzed for the presence
of arsenic in the pond liquors.  Chemical attenuation by
soils at the site was found to be low for trace metals
such as arsenic.Interpretations of the sampling results
were difficult to make because other potential
contamination sources exist, such as other waste disposal
areas at the site (the location and ages of which are
uncertain) and contaminants naturally occurring in the
soil, which is highly mineralized around the Johnston
site; and uncertainties with regard to what degree
leachate from the two landfills had reached the
downgradient wells.  Contamination from the site could
possibly increase until steady-state concentrations are
reached.

The Sherburne County Plant in central Minnesota disposed
of fly ash and FGD waste in one clay-lined pond and
bottom ash in an adjacent clay-lined pond.  Exceedances
of the Primary Drinking Water Standards were observed in
both upgradient and downgradient ground water for cadmium
(up to 2 times the PDWS for both) and for nitrate,  and in
downgradient ground water for chromium (up to 1.2 times
the PDWS).  Pond liquors were found to exhibit high
concentrations of several constituents, including cadmium
(up to 30 times the PDWS), chromium (up to 16 times the
PDWS), fluoride, nitrate, lead (up to 28 times the PDWS),
and selenium (up to 25 times the PDWS).  While the pond

-------
                             5-33
liquors exhibited high concentrations of contaminants,
leachate from these wastes did not appear to have
migrated into and mixed with ground water to a great
extent.  Ground-water samples collected at the site
seemed to indicate that a few constituents (sulfate and
boron) had migrated from the wastes, but not at levels
exceeding SOWS.  The clay liner appeared to have
significantly reduced the rate of release of leachate
from the disposal ponds, precluding the development of
elevated trace metal concentrations at downgradient
wells.  Over time, downgradient wells will likely show
increased levels of contamination, since steady-state
conditions had not been achieved between leachate from
the landfill and the ground water.  Without the clay
liner, the leachate seepage rate would probably have been
much greater.  Since the surrounding soils may not
chemically attenuate selenium, this contaminant might
cause PDWS exceedances once steady-state concentrations
in ground water are reached.

The Powerton Plant disposed fly ash, bottom ash, and slag
in an older landfill approximately one mile south of the
site.  In a newer portion of the landfill, disposal
operations consisted of disposing intermixed fly ash and
slag.  The newer landfill and part of the older one are
underlain by a liner consisting of ash and lime.  The
downgradient ground-water wells exhibited levels of
cadmium up to three times the Primary Drinking Water
Standard and, in one sample, lead at four times the PDWS.
An upgradient well, located on the border of the landfill
wastes, exhibited a concentration of cadmium at the level
of the Primary Drinking Water Standard.  Secondary
Drinking Water Standards for iron, manganese, and sulfate
were exceeded in downgradient wells, and for manganese in
an upgradient well (but at a level of exceedance lower
than the downgradient measurements).  These results
indicate that leaching and migration of ash wastes had
occurred at the site, but it was difficult to determine
the effect the leachate had, or will have, on
ground-water quality.  Dilution and chemical attenuation
may have prevented the buildup at downgradient locations
of significant concentrations of trace metals such as
arsenic and selenium.  The degree to which Lost Creek, a
nearby downgradient stream, was diluting waste
constituents that reach it may be significant.

The Lansing Smith plant in southern Florida disposed a
mixture of fly ash and bottom ash in an unlined disposal
pond located in a coastal area.  Concentrations greater
than the Primary Drinking Water Standards were observed
for cadmium (up to five times the PDWS),  chromium (up to
four times the PDWS), and fluoride in the downgradient
ground water at the site and, with the possible exception

-------
                                      5-34
         of fluoride, appeared to be due largely to the leaching
         of the ponded ash wastes.  Exceedances of Secondary
         Drinking Water Standards for sulfate, chloride,
         manganese, and iron were also observed in downgradient
         ground water.  However, most of these contaminants are
         seawater-related and their reported concentrations
         appeared to be influenced by the use of seawater in plant
         operations and infiltration of estuarine (saline) water
         at the site.  The leachate generated migrates to a
         shallow, unused, tidal aquifer. These results indicate
         that ash disposal at this site appears to have had a
         measurable impact on ground-water quality.  Health risks
         at this particular site, however, were probably minimal
         since the ground water and surface water were not used as
         a source of drinking water.


    5.2.1.1  Ground-water Sanpling



    Exhibits 5-10 and 5-11 summarize the results of the ADL ground-water quality

data at the six disposal sites for constituents with established Primary and

Secondary Drinking Water Standards, respectively.  As can be seen from Exhibit

5-10:
         One site had no exceedances of PDWS constituents, either
         upgradient or downgradient.

         One site had PDWS exceedances for cadmium only, with the
         same maximum PDWS exceedance upgradient and downgradient.

         One site had downgradient PDWS exceedances for cadmium,
         chromium, and nitrate, but for cadmium and nitrate the
         upgradient exceedances were at least as large as the
         downgradient exceedances.  There were no upgradient
         exceedances of chromium; the one downgradient exceedance
         was 1.2 times PDWS.

         The three remaining sites had downgradient PDWS
         exceedances for cadmium that were more frequent and
         larger than upgradient exceedances.  The largest
         downgradient exceedance for cadmium at any of the six
         sites was 20 times the PDWS.

         There were no upgradient chromium exceedances and only
         three exceedances out of 94 downgradient observations.
         Two of the downgradient exceedances were 1.2 times the
         PDWS and one was 4 times the PDWS.  These three
         exceedances were at three different sites.

-------
                                                         5-35
                                               EXHIBIT 5-10

                           SUMMARY OF ARTHUR D.  LITTLE'S  GROUND-WATER
                      QUALITY DATA ON PRIMARY DRINKING WATER EXCEEDANCES
Units = pprn

PDWS



••
2/ Drinking
Contain. Water
Standard
	
Arsenic 0.05
(liq.)
Barium 1
Cadmium 0.01
Chromium 0.05
(Cr VI)
Fluoride 4.0
Lead 0.05
Mercury 0.002
Nitrate 5/ 45
Selenium 0.1
(liq.)
Silver 0.05
Allen Site

V
Downgrade ent
(11 wells)


3/ 4/
Exceed./ Max.
Total Exceed.
	 	 —
0/12

0/31
0/31
0/31

0/34
0/31
0/0
0/34
0/5

0/31


V
Upgradient
(1 well)

...............
	
3/ 4/
Exceed./ Max.
Total Exceed.
	
0/2

0/3
0/3
0/3

0/4
0/3
0/0
0/4
0/2

0/3
New Elrama Site

V
Downgradient
(5 wells)

	
3/ 4/
Exceed./ Max.
Total Exceed.
0/1

0/19
3/19 20
1/19 1.2

0/21
0/19
0/0
0/20
0/1

0/19


V
Upgradient
(1 well)

...............
	
3/ 4/
Exceed./ Max.
Total Exceed.
	
0/2

0/4
0/4
0/4

0/4
0/4
0/0
0/4
0/2

0/4
Dave Johnston S

V
Downgradient
(3 wells)

1...............
	
3/ 4/
Exceed./ Max.
Total Exceed.
	
0/2

0/9
6/9 3
0/9

0/12
0/9
0/0
0/12
0/2

0/9
'te

V
Upgradient
(2 wells)

I...............
	
3/ 4/
Exceed./ Max.
Total Exceed.
0/3

0/6
3/6 3
0/6

0/8
0/6
0/0
0/8
0/3

0/9
V For specific site descriptions,  including lists and maps of wells used for data,
    see Appendix E.

2/ Where the reported detection limit for a contaminant was greater than the drinking
    water standard and the sample contained less contaminant than the reported detection
    limit, the sample is tabulated  as being below the drinking water standard.  For a more
    detailed explanation, see Appendix E.

3/ The number of samples with reported concentrations above the drinking water standard (slash)
    the total number of samples.

4/ Max. Exceed, is the concentration of the greatest reported exceedance divided
    by the drinking water standard  for that particular contaminant.
5/ The PDWS for nitrate measured as N is 10 ppm.

-------
                                                      5-36
                                    EXHIBIT  5-10 (Continued)

                        SUMMARY OF ARTHUR D.  LITTLE'S GROUND-WATER
                   QUALITY DATA ON PRIMARY DRINKING WATER EXCEEDANCES
Units z ppm

PDUS


2/ Drinking
Contain. Water
Standard
	
Arsenic 0.05
(liq.)
Bar inn 1
Cadmiun 0.01
Chromium 0.05
(Cr VI)
Fluoride 4.0
Lead 0.05
Mercury 0.002
Nitrate 5/ 45
Selenium 0.1
(liq.)
Silver 0.05
Sherburne Count'

I/
Downgradient
(3 wells)
3/ 4/
Exceed./ Max.
Total Exceed.
	
0/3

0/12
2/12 2
1/12 1.2

0/12
0/12
0/0
2/12 1.1
0/3

0/12
f Site

I v
Upgradient .
(2 wells)
	
3/ 4/
Exceed./ Max.
Total Exceed.
	
0/3

0/8
2/8 2
0/8

0/8
0/8
0/0
2/8 27
0/3

0/8
Powerton Statioi
I
V
Downgradient
(3 wells)
	
3/ 4/
Exceed./ Max.
Total Exceed.
0/8

0/9
8/9 3
0/9

0/9
1/9 4
0/0
0/9
0/8

0/9
i Site

1 v
Upgradient
(1 well)
1 	
3/ 4/
Exceed./ Max.
Total Exceed.
	
0/2

0/4
2/4 1
0/4

0/4
0/4
0/0
2/4 1.1
0/2

0/4
Lansing Smith S
I
V
Downgradient
(5 wells)
	
3/ 4/
Exceed./ Max.
Total Exceed.
	
0/5

0/14
10/14 5
1/14 4

5/14 13.5
0/14
0/0
0/0
0/5

0/14
team Plant

I v
Upgradient
(3 wells)
3/ 4/
Exceed./ Max.
Total Exceed.
0/4

0/6
2/6 2
0/6

0/6
0/6
0/0
0/0
0/4

0/6
1/ For specific site descriptions, including  lists and maps of wells used for data,
    see Appendix E.

2/ Where the reported detection limit for a contaminant was greater than the drinking
    water standard and the sample contained less contaminant than the reported detection
    limit, the sample is tabulated as being below the drinking water standard.  For a more
    detailed explanation, see Appendix E.

3/ The number of samples with reported concentrations above the drinking water standard (slash)
    the total number of samples.

4/ Max. Exceed, is the concentration of the greatest reported exceedance divided
    by the drinking water standard for that particular contaminant.
5/ The PDWS for nitrate measured as N is 10 ppm.

-------
                                                      5-37
                                            EXHIBIT 5-11

                  SUMMARY  OF ARTHUR D.  LITTLE'S GROUND-WATER  QUALITY
                      DATA  ON SECONDARY  DRINKING WATER EXCEEDANCES
Units = ppm

SOWS


	
2/ Drinking
Contain. Water
Standard
	
Chloride 250
Copper 1
Iron 0.3
Manganese 0.05
Sulfate 250
Zinc 5
pH Lab 5/ <=6.5

>=8.5

pH Field 5/ <=6.5

>=8.5
Allen Site

V
Downgradient
(11 wells)
3/ 4/
Exceed./ Max.
Total Exceed.
	
0/34
0/31
7/31 82
19/31 102
0/34
0/31
10/10 4.7

0/10

21/28 4.4

0/28


V
Upgradient
(1 well)
	
3/ 4/
Exceed./ Max.
Total Exceed.
	
0/4
0/3
0/3
1/3 1.4
0/3
0/3
1/1 5.9

0/1

2/3 6.2

0/3
New Elrama Site

V
Downgradient
(5 wells)
	
3/ 4/
Exceed./ Max.
Total Exceed.
0/21
0/19
0/19
19/19 456
9/19 4.7
0/19
0/0

0/0

9/14 5.2

0/14


v
Upgradient
(1 well)
3/ 4/
Exceed./ Max.
Total Exceed.
	
0/4
0/4
1/4 1.8
4/4 197
3/4 1.5
0/4
0/0

0/0

2/2 4.5

0/2
Dave Johnston S

V
Downgradient
(3 wells)
. .............
	
3/ 4/
Exceed./ Max.
Total Exceed.
	
0/12
0/9
0/9
1/9 3.2
12/12 5.8
0/9
0/0

0/0

0/9

0/9
te

v
Upgradient
(2 wells)
...............
3/ 4/
Exceed./ Max.
Total Exceed.
0/8
0/6
0/6
1/6 4.6
4/8 5.1
0/6
0/0

0/0

0/6

0/6
V For  specific site descriptions, including  lists and maps of the wells used for data,
    see Appendix E.

2/ Where the reported detection limit for  a contaminant was greater than the drinking
    water standard and the sample contained less contaminant than the reported detection
    limit, the sample is  tabulated as being below the drinking water standard.  For a more
    detailed explanation, see Appendix E.

3/ The  number of samples  with reported concentrations above the drinking water standard  (slash)
    the total number of samples.

4/ Max. Exceed, is the concentration of the greatest reported exceedance divided
    by  the drinking water standard for that particular contaminant.  The only
    exception is for pH,  where Max. Exceed, is the actual measurement.

5/ As indicated in footnote 15, the Max. Exceed column for the reported pH measurements
    is  a tabulation of the actual measurements, not the maximum exceedance divided by
    the drinking water standard.

-------
                                                     5-38
                                   EXHIBIT  5-11 (Continued)

                  SUMMARY OF ARTHUR D.  LITTLE'S  GROUND-WATER QUALITY
                     DATA ON SECONDARY DRINKING  WATER EXCEEDANCES
Units = ppm
SOWS
2/ Drinking
Contain. Water
Standard
Chloride 250
Copper 1
Iron 0.3
Manganese 0.05
Sulfate 250
Zinc 5
pH Lab 5/ <=6.5
>=8.5
pH Field 5/ <=6.5
>=8.5
Sherburne Count)
V
Downgradient
(3 wells)
...............
	
3/ 4/
Exceed./ Max.
Total Exceed.
	
0/12
0/12
0/12
2/12 22
0/12
0/12
0/0
0/0
0/8
0/8
f Site
v
Upgradient
(2 wells)
	
3/ 4/
Exceed./ Max.
Total Exceed.
0/8
0/8
1/8 1.9
1/8 1.4
0/8
0/8
0/0
.
0/0
0/6
0/6
Powerton Statior
V
Downgradient
(3 wells)
...............
	
3/ 4/
Exceed./ Max.
Total Exceed.
...............
	
0/9
0/9
4/9 42
9/9 194
6/9 2.7
0/9
0/0
0/0
1/9 6
0/9
i Site
v
Upgradient
(1 well)
...............
	
3/ 4/
Exceed./ Max.
Total Exceed.
0/4
0/4
0/4
2/4 11
0/4
0/4
0/0
0/0
0/3
0/3
Lansing Smith S
V
Downgradient
(5 wells)
...............
	
3/ 4/
Exceed./ Max.
Total Exceed.
14/14 22.4
0/14
14/14 118
13/14 17.2
8/14 8.4
0/14
4/6 4.4
0/6
10/13 2.9
0/13
team Plant
V
Upgradient
(3 wells)
...............
3/ 4/
Exceed./ Max.
Total Exceed.
0/6
0/6
6/6 37
2/6 1.4
0/6
0/6
1/2 6.5
J
0/2
4/6 6
0/6
I/ For specific site descriptions,  including lists and maps of the wells used for data,
    see Appendix E.

21 Where the reported detection limit  for a contaminant was greater than the drinking
    water standard and the sample contained less contaminant than the reported detection
    limit, the sample is tabulated as  being below the drinking water standard.  For a more
    detailed explanation, see Appendix E.

3/ The number of samples with reported concentrations above the drinking water standard (slash)
    the total number of samples.

4/ Max. Exceed, is the concentration of the greatest  reported exceedance divided
    by the drinking  water standard for that particular contaminant.  The only
    exception is for pH, where Max.  Exceed, is the actual measurement.

5/ As  indicated in footnote 15, the  Max. Exceed column for the reported pH measurements
    is a tabulation  of the actual  measurements, not the maxinun exceedance divided by
    the drinking water standard.

-------
                                      5-39
    •    One site had downgradient PDWS exceedances for fluoride
         in 5 of 14 samples.   The maximum exceedance was 13.5
         times the PDWS.  There were no upgradient PDWS
         exceedances for fluoride at any of the six sites.

    •    There were no lead exceedances upgradient and only one
         PDWS exceedance out of 94 downgradient observations at 4
         times the PDWS.

    •    The contaminants of most concern at the six sites appear
         to be cadmium and, to a lesser extent, chromium.  For
         both of these contaminants,  three sites had exceedances
         of the PDWS in downgradient ground water at levels higher
         than were found in upgradient ground water.


    For constituents for which there are Secondary Drinking Water Standards,

exceedances in downgradient ground water generally were higher than levels

observed in upgradient wells.  Results are shown in Exhibit 5-11.
    5.2.1.2  Surface Water Sampling



    Exhibit 5-12 summarizes the results of surface-water quality data obtained

by ADL at background, peripheral, and downstream locations at three of the study

sites -- Elrama, Powerton, and Lansing Smith -- for constituents with

established Primary and Secondary Drinking Water Standards.  Examination of

these results for PDWS constituents indicates that:
         At the Lansing Smith site, downgradient and peripheral
         surface water samples showed cadmium concentrations up to
         5 times the PDWS, chromium concentrations up to 1.2 times
         the PDWS,  and fluoride concentrations up to 20 times the
         PDWS.   No upgradient samples were collected at the
         Lansing Smith site.

         Exceedances were found for cadmium (up to 2 times the
         PDWS)  and nitrate (up to 1.2 times the PDWS) in both
         upgradient and downgradient surface water at the Powerton
         site.   The exceedances were similar in upgradient and
         downgradient samples both in terms of the proportion of
         samples in which exceedances were found and the magnitude
         of the exceedances.

-------
                                                         5-40
                                              EXHIBIT  5-12

             SUMMARY  OF ARTHUR D.  LITTLE'S  SURFACE-WATER QUALITY DATA
                 ON PRIMARY  AND  SECONDARY DRINKING HATER EXCEEDANCES
   Units - ppn    |New Elrama Site
(Powerton Station Sit*
(Lansing Smith Steam Plant
POWS
2/ Drinking
Contan. Water
Standard
	 	
Arsenic 0.05
(liq.)
Barium 1
Cadmium 0.01
Chromium 0.05
(Cr V!)
Fluoride 4.0
Lead 0.05
Mercury 0.002
Nitrate 5/ 45
Selenium 0.1
(liq.)
Silver 0.05
V
Downgradient
(4 stations)
3/ 4/
Exceed./ Max.
Total Exceed.
	 ..........
0/1
0/7
0/7
0/7
0/7
0/7
0/0
0/7
0/1
0/7
V
Upgradient
(1 station)
3/ 4/
Exceed./ Max.
Total Exceed.
...............
0/1
0/3
0/3
0/3
0/3
0/3
0/0
0/3
0/1
0/3
»/
Downgradient
(1 station)
3/ 4/
Exceed./ Max.
Total Exceed.
	 ...
0/1
0/3
2/3 2
0/3
0/3
0/3
0/0
1/3 1.1
0/1
-
0/3
V
Upgradient
(3 stations)
3/ 4/
Exceed./ Max.
Total Exceed.
	 	
0/2
0/8
5/8 2
0/8
0/8
0/8
0/0
3/7 1.2
0/2
0/8
V
Downgradient
(6 stations)
3/ 4/
Exceed./ Max.
Total Exceed.
	 	
0/2
0/13
10/13 5
0/13
5/13 6.5
0/13
0/0
0/0
0/2
0/13
V
Peripheral
(3 stations)
"" 	 	
3/ 4/
Exceed./ Max.
Total Exceed.
0/1
0/8
4/8 4
0/8
2/8 2
0/8
0/0
0/0
0/1
0/8
V
Downgradient
Saline
(2 stations)
3/ 4/
Exceed./ Max.
Total Exceed.
0/3
0/5
5/5 4
1/5 1.2
2/5 20
0/5
0/0
0/0
0/3
0/5
I/ For specific site descriptions, including lists and maps of the stations used for data,
    see Appendix E.  Peripheral  stations are neither upgradient nor downgradient of the site.
    These stations are located across the gradient from the site, and may become contaminated
    by lateral dispersion of waste constituents.

2/ Where the reported detection  limit for a contaminant was greater than the drinking
    water standard and the sample contained less contaminant than the reported detection
    Unit, the sample is tabulated as being below the drinking water standard.  For a more
    detailed explanation, see Appendix E.

3/ The number of samples with reported concentrations above the drinking water standard (slash)
    the total nurter of samples.

4/ Max. Exceed, is the concentration of the greatest reported exceedance divided
    by the drinking water standard for that particular contaminant.
5/ The PDUS for nitrate measured as N is 10 ppn.

-------
                                                          5-41
                                      EXHIBIT  5-12  (Continued)

              SUMMARY OF  ARTHUR D.  LITTLE'S  SURFACE-WATER QUALITY DATA
                 ON  PRIMARY AND SECONDARY DRINKING HATER EXCEEDANCES
   Units « ppm    (New Elrama Site
|Pow*rton Station Site
|Lansing Smith Steam Plant
SOUS
if Drinking
Contain. Water
Standard
Chloride 250
Copper 1
Iron 0.3
Manganese 0.05
Sulfate 250
Zinc 5
pH Lab 5/ «6.5
>-8.5
pti Field 5/ «6.5
>«8.5
V
Downgradient
(4 stations)
3/ 4/
Exceed./ Max.
Total Exceed.
0/7
0/7
0/7
7/7 7.4
0/7
0/7
0/0
0/0
4/7 6.1
0/7
I V
Upgradient
(1 station)
3/ 4/
Exceed./ Max.
Total Exceed.
0/3
0/3
0/3
3/3 4.2
0/3
0/3
0/0
0/0
2/3 6
0/3
1
V
Downgradient
(1 station)
3/ 4/
Exceed./ Max.
Total Exceed.
0/3
0/3
0/3
2/3 2.2
0/3
0/3
0/0
0/0
0/3
1/3 8.5
V
Upgradient
(3 stations)
...............
3/ 4/
Exceed./ Max.
Total Exceed.
0/8
0/8
0/8
2/8 1
0/8
0/8
0/0
0/0
0/8
2/8 8.5
V
Downgradient
(6 stations)
...............
3/ 4/
Exceed./ Max.
Total Exceed.
13/13 11.9
0/13
11/13 370
11/13 64
12/13 7.5
0/13
5/6 3.3
0/6
5/10 4.1
0/10
V
Peripheral
(3 stations)
3/ 4/
Exceed./ Max.
Total Exceed.
5/8 10
0/8
6/8 34
6/8 4.8
4/8 3.4
0/8
2/3 3.8
0/3
4/7 3.4
0/7
VI
Doungradfent
Saline
(2 stations)
3/ 4/
Exceed./ Max.
Total Exceed.
...... — ......
5/5 58
0/5
0/5
0/5
5/5 9.9
0/5
0/1
0/1
0/5
0/5
I/ For specific site descriptions,  including lists and maps of the stations used for data,
    see Appendix E.  Peripheral stations are neither Upgradient nor downgradient of the site.
    These stations are located across the gradient from the site,  and may becom contaminated by
    lateral dispersion of waste constituents.

21 Where the reported detection limit for a contaminant was greater than the drinking
    water standard and the sample contained less contaminant than  the reported detection
    limit, the sample is tabulated as being below the drinking water standard.  For a more
    detailed explanation, see Appendix I.

3/ The number of samples with reported concentrations above the drinking water standard (slash)
    the total number of samples.

4/ Max. Exceed, is the concentration of the greatest reported exceedance divided
    by the drinking water standard for that particular contaminant. The only
    exception is for pN, where Max. Exceed, is  the actual measurement.

5/ As indicated in footnote 10, the Max. Exceed, column for reported pM measurements
    is a tabulation of the actual measurements, not the maximum exceedance divided by
    the drinking water standard.

-------
                                      5-42
         No exceedances of PDWS were found upgradient or
         downgradient at the Elrama site, although there had been
         downgradient exceedances at Elrama in ground water for
         cadmium and chromium.
    5.2.1.3  Waste Fluid Sampling



    In addition to ground-water monitoring, waste fluid samples were

collected from the waste ponds at the Allen, Sherburne County, and Lansing

Smith sites, and from dry fly ash landfills at the Dave Johnston site.

Water from within and beneath FGD sludge and fly ash waste mixtures were

collected from the Elrama landfill.  No waste fluid samples were obtained

at the Powerton site.  Key observations are presented below.
         Arsenic was present in the waste fluids at elevated
         concentrations (up to 31 times the Primary Drinking Water
         Standard) at two of the five sites sampled.  At these
         sites (Allen and Elrama),  arsenic may be attenuated by
         soils at the site; attenuation tests indicate the soils
         had a moderate to high attenuation capacity, and no
         exceedances for arsenic were observed in ground water at
         the sites.  The Dave Johnston site was the only disposal
         area where soils were found to have low attenuation
         capacities for arsenic; however, there are no data
         pertaining to waste fluids at this site, and exceedances
         for arsenic in the ground water were not observed.  These
         results indicate that, depending on the coal source,
         arsenic may occur at elevated concentrations in waste
         fluids, but can be attenuated by soils within and
         surrounding a coal combustion waste disposal site.  If
         the soils at a disposal site have low attenuation
         capacities for arsenic, this element may be of concern
         with regard to ground water and surface water
         contamination.

         Cadmium is present at elevated concentrations (up to 30
         times the Primary Drinking Water Standard) in the waste
         fluids at all five sites.   At Powerton, although no waste
         fluid samples were taken,  ground-water samples obtained
         from directly beneath the  wastes also exhibited elevated
         concentrations of cadmium.  These results support the
         conclusion that elevated concentrations of cadmium
         observed in downgradient ground water may be attributable
         to coal combustion wastes.

-------
                             5-43
Chromium is present at elevated concentrations (up to 21
times the Primary Drinking Water Standard) in the waste
fluids at two of the five sites.  At these sites, higher
chromium concentrations were found in downgradient ground
water than were found in upgradient ground water.  These
observations suggest that ground-water contamination by
chromium at these two study sites may be attributable to
the coal combustion wastes.  At a third site at which
downgradient exceedances of chromium in ground water were
observed, waste fluid samples were mixed with ground
water occurring beneath the wastes during collection,
which may account for lower waste fluid concentrations at
this site.

Other constituents that were found at elevated
concentrations within the waste fluids include fluoride
at all five sites (up to 10 times the PDWS); lead at one
of five sites (up to 28 times the PDWS); nitrate at one
of five sites (up to 7 times the PDWS); and selenium at
one of four sites (up to 25 times the PDWS).

Constituents for which Secondary Drinking Water Standards
are established were found at the following elevated
concentrations:   chloride at three of five sites (up to
61 times the SOWS);  iron at two of five sites (up to 221
times the SDWS);  manganese at four of five sites (up to
466 times the SDWS); and sulfate at four of five sites
(up to 42 times the SDWS).  Exceedances of pH standards
were found in the waste fluids at two of three sites
tested.  At these two sites, both acidic (as low as pH
5.9) and alkaline (as high as pH 11) conditions were
found to exist.   Average pH values measured in these
waste fluids indicated that they were generally alkaline.

Results of waste fluid sampling at the Sherburne County
site showed exceedances of Primary Drinking Water
Standards for cadmium (up to 30 times PDWS); chromium (up
to 16 times the PDWS); fluoride (up to 13 times the
PDWS); lead (up to 28 times the PDWS); nitrates (up to
6.9 times the PDWS); and selenium (up to 25 times the
PDWS).  Measurements also showed maximum exceedances of
Secondary Drinking Water Standards for chloride (up to
1.9 times the SDWS); iron (up to 6.1 times the SDWS);
manganese (up to 316 times the SDWS);  and sulfate (up to
42 times the SDWS).   This was the only site where
disposal areas or ponds were completely lined.  The clay
liner appeared to have reduced the release of leachate,
thereby concentrating waste constituents.

-------
                                      5-44






    Results from waste fluid studies conducted by other organizations are



described in Appendix D.








    5.2.1.4  Sumary







    Results from the Arthur D. Little study suggest that under the waste



management procedures used by the facilities studied, some coal combustion waste



leachate was migrating into ground water beneath and downgradient from disposal



sites.  Five sites had concentrations of cadmium in downgradient ground water



that exceeded the PDWS.  Two of these five had maximum upgradient exceedances at



the same level as the maximum downgradient exceedance, and two of the sites had



upgradient concentrations that were equal to or above the PDWS, although the



maximum concentration was less than the downgradient concentrations.   One of the



five sites had upgradient measurements of cadmium that were below the PDWS.



Exceedances of chromium were detected in a few ground-water samples downgradient



of three sites; there were no chromium concentrations above the PDWS in the



upgradient ground water of any site.  There were no detected exceedances of



arsenic, barium, mercury, selenium, or silver in the ground water or surface



water at any of the six sites.  In total, approximately 5 percent of the



downgradient observations exceeded the PDWS.







    5.2.2  Franklin Associates Survey of State Ground-Water Data








    EPA commissioned Franklin Associates to gather data from state regulatory



agencies on the quality of ground water at or near coal-fired electric utility


                       23
fly ash disposal sites.     The objective of this survey was to determine the



level of ground-water contamination in the vicinity of disposal sites.  However,

-------
                                      5-45






according to the Franklin Associates report:  "No attempt was made to determine




what monitoring wells might be up gradient, or what wells might be down




gradient, or even as to whether specific ash disposal sites were in fact




contributing specific pollutants."








    Franklin Associates contacted 44 states in which coal-fired facilities were




located; of these 44 states, 13 provided data.  The data base that was developed




included data from more than 4700 well samples taken from 66 sites.








    Analysis of these samples revealed 1129 exceedances of the PDWS out of more




than 15,000 observations, as shown in Exhibit 5-13.  Ninety-two percent of the




exceedances were less than ten times the PDWS; eight of the exceedances were 100




times greater than the PDWS.








    There were 5952 exceedances of the SOWS out of nearly 20,000 observations as




shown in Exhibit 5-14.  These secondary standards were exceeded more frequently




than the primary standards, and exceedances were usually greater.  For example,




about 77 percent of the SOWS exceedances were less than 10 times the standard




(compared with 92 percent for PDWS exceedances), whereas 4 percent of the




exceedances were greater than 100 times the SOWS (compared with less than one




percent for PDWS exceedances).








    Since this study did not compare upgradient and downgradient concentrations,




it is not possible to determine whether occurrences of contamination at




particular sites are the result of utility waste disposal practices or




background levels of contaminants.

-------
                             5-46


                      EXHIBIT 5-13

SUMMARY OF FDWS EXCEEDANCES IN THE FRANKLIN ASSOCIATES SURVEY
          Total
Number of Observations
   Exceeding PDWS Bv
Highest Exceedance
Constituent
Arsenic
Barium
Cadmium
Chromium
Fluoride
Lead
Mercury
Nitrate
Selenium
Silver
TOTAL
Observations
1995
1353
1733
1863
995
1722
1282
1432
2453
530
15,358
Source: Franklin Associates,
at Coal Combustion W;
1 X
94
108
126
92
28
243
30
204
196
8
1129
Ltd. . Summarv
aste Disposal
10 X
0
9
16
5
3
20
8
0
30
0
100 X
0
0
1
0
0
1
5
0
1
0
CX. PDWS1)
9.8
44.0
531.0
50.2
19.3
182.0
500.0
7.3
100.0
8.0
81 8
of Ground-water Contamination Cases
Sites.
prepared for
the U.S.
Environmental Protection Agency,  March 1984.

-------
                                 5-47
                           EXHIBIT 5-14

SUMMARY OF SDWS EXCEEDANCES IN THE FRANKLIN ASSOCIATES SURVEY
              Total
Number of Observations
 Exceeding SDWS Bv
Highest Exceedance
Constituent
Chloride
Copper
Iron
Manganese
pH
Sulfate
IDS
Zinc
TOTAL
Observations
2921
650
3140
1673
4107
4378
1925
1175
19,969
Source: Franklin Associates ,
at Coal Combustion W<
1 X
109
1
1942
1050
843
1059
920
5952
Ltd. . Summary
iste Disposal
10 X
14
0
862
467
-
13
24
100 X
0
0
149
80
-
0
0
rx sows}
42.0
1.2
4,000.0
2,400.0
-
23.2
28.7
	 4 	 Q 46.0
1384 229
of Ground-water Contamination Cases
Sites, prepared for
the U.S.
    Environmental Protection Agency, March 1984.

-------
                                      5-48
    5.2.3  Envirosphere Ground-Water Survey








    In response to the temporary exemption of utility wastes from regulation



under Subtitle C of RCRA, the Utility Solid Waste Activities Group (USWAG)



commissioned Envirosphere, Inc., to review information available from electric


                                                                         24
utilities on the quality of ground water at utility waste disposal sites.



Envirosphere solicited information from 98 utilities on the number and type of



constituents they monitored, the frequency with which measurements were taken,



and the period of time for which they had collected ground-water monitoring



data.  Ninety-six of the contacted utilities responded to the request for



information.  From these 96 utilities, Envirosphere selected for further study



those that appeared to have adequate data on ground-water quality.  These



utilities were contacted and asked to provide their available data for use in



Envirosphere's study.  The participating utilities (the exact number of



utilities was not provided) forwarded the requested information to Envirosphere



on the 28 disposal facilities they operated.  The utilities chose to withdraw



three of the 28 disposal sites from the study subsequent to the analysis of the



data, leaving 25 disposal sites in the data pool.








    In order to analyze the data, Envirosphere paired the measurements taken at



upgradient and downgradient wells at approximately the same time and in the same


        25
aquifer.    These data were then compared to the applicable drinking water



standards to determine whether the standards had been exceeded.  Two disposal



sites were then eliminated from further consideration because no upgradient



wells could be identified.  The remaining 23 disposal sites produced a total of



9,528 paired measurements of upgradient and downgradient ground-water



concentrations.

-------
                                      5-49



    Exhibit 5-15 summarizes the information from the Envirosphere data base for

those cases where the Primary Drinking Water Standards (PDWS) were exceeded by

the downgradient measurement.  The most obvious indication that a waste facility

is contributing to a PDWS exceedance is a measurement indicating downgradient

values higher than the PDWS and upgradient values lower than the PDWS.

According to Envirosphere's report, about 1.7 percent of the data fell into this
         t\f
category.    For those cases in which both the upgradient and downgradient

values were exceeded, Envirosphere argued that it was difficult to attribute the

exceedances to the disposal facility without further site-specific analysis.

About 5 percent of the measurements fell into this category, with 60 percent of

these indicating upgradient values equal to or greater than the downgradient

values.




    Maximum concentrations of several substances significantly exceeded the PDWS

in downgradient wells:  arsenic, 560 times the PDWS; lead, 480 times the PDWS;

mercury, 235 times the PDWS, and selenium, 100 times the PDWS.  These values

must be compared to the maximum upgradient reading since some of the

contamination may be unrelated to the disposal facility.  As shown in Exhibit

5-15, the downgradient concentration was sometimes higher than the upgradient

value even when the upgradient value exceeded the PDWS.  However, exceedances of

the magnitudes shown in Exhibit 5-15 comprised a small fraction of the total

measurements in the Envirosphere data base.




    The Envirosphere data also included information regarding exceedances of the

Secondary Drinking Water Standards (SOWS).  A summary of these data is shown in

Exhibit 5-16.   The data indicate that in 8.2 percent of the cases the

-------
                                      5-50


                               EXHIBIT 5-15

        SUMMARY OF PDWS EXCEEDANCES IN ENVIROSPHERE'S GROUND-HATER DATA
                                   Downgradient Observations a/
Constituent
Arsenic
Barium
Cadmium
Total
Observations
588
298
571
Exceeding PDWS When:
Upgradient Does
Not Exceed Uogradient
Number % Number
710
000
59 10 9

Exceeds
_a_
0
0
2
Maximum
Downgradient
Observation
CX. PDWS} b/
560 (192)
1 (3)
6 (1)
Chromium
 658
 20
        10
        20
(76)
Lead
Mercury
Selenium
639
575
489
29
8
5
5
1
1
67
2
34
10
£/
7
480
235
100
(220)
(9)
(100)
Silver
TOTAL
 261
4079
                                                (0.2)
128
3 d/   122
3 d/
a/  Envirosphere classified measurements by comparing downgradient values with
    upgradient values.  When the downgradient value exceeded the PDWS, classi-
    fication depended on whether the upgradient value also exceeded the PDWS.
    Both categories of measurements are shown here, although Envirosphere
    focused primarily on pairs of measurements in which the downgradient value
    exceeded the PDWS but the upgradient value did not.

b/  Maximum downgradient value observed in the Envirosphere data base.  The
    corresponding paired upgradient concentrations are not available.   The
    maximum upgradient value of all measurements at the same facility is shown
    in parentheses.

c/  Less than 0.5 percent.

d/  These percentages apply to the total number of observations.  Envirosphere
    "normalized" the data to correct for sites that had a high proportion of
    data points so that one site would not be overly represented; these
    normalized values are noted in the text of the report.

Source:  Envirosphere Company, "Report on the Ground-water Data Base
         Assembled by the Utility Solid Waste Activities Group," in USWAG,
         Report and Technical Studies on the Disposal and Utilization of
         Fossil-Fuel Combustion Bv-Products. October 26, 1982, Appendix C.

-------
                                      5-51


                               EXHIBIT 5-16

        SUMMARY OF SDWS EXCEEDANCES IN ENVIROSPHERE'S GROUND-HATER DATA
                Total
                                Downgradient Observations a/
                           	Exceeding SDWS When:	
                           Upgradient Does
                             Not Exceed
Constituent  Observations  Number
Chloride

Copper

Iron

Manganese

Sulfate

Total Dissolved
 Solids

Zinc

TOTAL
 502

 452

 964

 487

1028
  4

  9

 60

157

289


159
                            Upgradient Exceeds
                            Number          %
                            681
 1

 2

 6

32

28


18

JL

14 c/
  7

  0

376

143

 57


292

	3

875
 1

 0

39

29

 6
  Maximum
Downgradient
Observation
  (X SDWS^   by

   22     (5)

    2  (0.02)

 3458     (2)

  474     (5)
                                                                     32
          (8)
32
JL
19 c/
31 (2)
1 (0.1)
a/  Envirosphere classified measurements by comparing downgradient values with
    Upgradient values.  When the downgradient value exceeded the SOWS,
    classification depended on whether the Upgradient value also exceeded the
    SOWS.   Both categories of measurements are shown here,  although Envirosphere
    focused primarily on pairs of measurements in which the downgradient value
    exceeded the SOWS but the upgradient value did not.

b/  Maximum downgradient value observed in the Envirosphere data base.  The
    corresponding (paired) upgradient concentrations are not available.  The
    maximum upgradient value of all measurements at the same facility is shown
    in parentheses.

c/  These percentages apply to the total number of observations.   Envirosphere
    "normalized" the data to correct for sites that had a high proportion of
    data points so that one site would not be overly represented; these
    normalized values are noted in the text of the report.

Source:  Envirosphere Company, "Report on the Ground-water Data Base Assembled
         by the Utility Solid Waste Activities Group," in USWAG,  Report and
         Technical Studies on the Disposal and Utilization of Fossil-Fuel
         Combustion By-Products. October 26, 1982, Appendix C.

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                                      5-52






downgradient value exceeded the SDWS while the upgradient value did not.  In




some cases the exceedances were substantially greater than the SDWS; e.g., the




maximum observation for iron was 3458 times greater than the SDWS and manganese




was 474 times greater.








    In summary, the Envirosphere ground-water data show that Primary and




Secondary Drinking Water Standards were exceeded in ground water downgradient




from utility waste disposal facilities.  However, the percentage of cases in




which constituent concentrations in downgradient wells exceeded the standards




when those in upgradient wells did not was small.  There are limitations in the




data, due in part to the way in which they were collected (e.g., only data from




those utilities that voluntarily submitted data are included in the report).




There is also a limited amount of information regarding the extent to which




site-specific factors, such as environmental setting characteristics or other




possible sources of contamination, could have had an effect on ground-water




contamination.








    5.2.4  Sunrmary








    The studies described in this section demonstrate that downgradient




ground-water and surface-water concentrations exceeded the PDWS and SDWS for a




few constituents.  In some of these downgradient exceedances, corresponding




upgradient exceedances also occurred, suggesting that the contamination was not




necessarily caused by the waste disposal sites.  For cases in which the




downgradient ground water had constituent concentrations higher than the




corresponding upgradient concentrations, the PDWS exceeded most often were those




for cadmium,  chromium, lead, and to a lesser extent, arsenic.

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                                      5-53







    Some PDWS exceedances were quite high, e.g., up to 560 times for arsenic and




480 times for lead (see Exhibit 5-15).  However, the frequency of PDWS




exceedances for downgradient ground water and surface water is rather low.  For




example,  3.7 percent of the Envirosphere data had downgradient ground-water




concentrations of PDWS higher than those measured in upgradient wells.  Three of




the six Arthur D. Little sites had downgradient ground water with concentrations




of constituents that were both above the PDWS and above corresponding upgradient




concentrations.  Although the Arthur D. Little pond liquor data show high




concentrations of PDWS and SOWS constituents, in most cases the constituents




appeared to be contained within the disposal area or attenuated in the




surrounding soils.  This is particularly true for the case of arsenic, which was




detected in the waste fluids at a level 31 times the PDWS, but was not found at




elevated levels in ground water or surface water.  There were no exceedances of




arsenic,  barium, mercury, selenium, or silver in downgradient ground water at




any of the six Arthur D. Little sites.  The Envirosphere study detected no




exceedances of barium or silver.









5.3  EVIDENCE OF DAMAGE









    This section examines documented cases in which danger to human health or




the environment from surface runoff or leachate from the disposal of coal




combustion wastes has been proved.  The first part of this section reviews two




major studies conducted for the Utility Solid Waste Activities Group (USWAG):  a




1979 Envirosphere, Inc., study and a 1982 Dames and Moore study.  To supplement




these two major studies, in 1987 EPA conducted a literature review of all




readily-available sources, which revealed only two additional case studies on




proven damages occurring in 1980 and 1981.  The Agency has not identified any

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                                      5-54






proven damage cases in the last seven years; however, no attempt was made to



compile a complete census of current damage cases by conducting extensive field



studies.








    As with all damage cases, it is not always clear whether damages could occur



under current management practices or whether they are attributable to practices



no longer used.  As described in Chapter Four, there has been an increased



tendency in recent years for utilities to utilize mitigative technologies,



including a shift to greater use of landfills rather than surface impoundments



and an increased use of liners.








    5.3.1  Envirosphere Case Study Analysis








    The Utility Solid Waste Activities Group (USWAG) and the Edison Electric



Institute (EEI) commissioned the Envirosphere Company in 1979 to investigate and



document available information on the nature and extent of the impact of utility


                                                                    27
solid waste disposal on public health, welfare,  and the environment.    To



conduct this analysis, Envirosphere reviewed various reports, including EPA's



damage incident files, environmental monitoring studies at utility disposal



sites, and other research and studies as available; they contacted state



regulatory agencies to determine what information was available in state files.








    From its review of the available data,  Envirosphere found few documented



cases where utility solid waste disposal had potentially adverse environmental



effects.  They identified nine cases from EPA's  damage incident files that



appeared to show damage to the environment.  Envirosphere reviewed data from



environmental monitoring studies at the utility disposal sites and other

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                                      5-55


available research, and noted that the information available on the potential

impacts of utility waste disposal was inconclusive.  Some data indicated "... -

that elevated levels of some chemical parameters have occurred at locations

downgradient of some utility solid waste disposal sites."  Envirosphere

concluded, however, that it was not clear to what extent these impacts could be

attributed to utility solid waste disposal practices.



    Some of the specific cases from Envirosphere's sources are summarized below:


    •    Texas. 1977.  A clay liner was improperly installed in a
         14.3 acre disposal pond for metal cleaning solutions.
         The liner dried and cracked before wastes were introduced
         into the facility.  After the pond was put in service,
         ground-water monitoring wells detected contaminant
         migration.  Levels of selenium and chromium occasionally
         exceeded the PDWS for these elements,  and several SDWS
         were exceeded.  The pond was taken out of service, the
         liner was saturated with water, and the pond was put back
         into operation.

    •    Indiana. 1977.  Envirosphere found that leaching from two
         large, unlined ash disposal ponds was  contributing to
         ground-water contamination.  Arsenic and lead were found
         in downgradient ground water at concentrations about two
         times the PDWS, while concentrations of selenium were
         about four times the PDWS.

    •    Pennsylvania. 1975.  A private waste handler illegally
         disposed fly ash in a marsh located in a tidal wetland
         area.  Visual inspections by the state indicated marsh
         contamination due to fly ash leachate.  When ordered to
         stop the dumping and clean up the site, the handler
         declared bankruptcy, and the ash remained in the marsh.
         Detailed analysis of any potential impacts has not -been
         conducted.

    •    Connecticut. 1971.  A municipal landfill, which was
         located in a marsh, accepted many substances,  including
         large quantities of fly ash.  Surveys  revealed numerous
         SDWS contaminants, some of which appeared to be related
         to the ash.  The site,  considered unsuitable for disposal
         of solid waste, was closed and turned  into a state park.

    •    Virginia. 1967.  A dike surrounding a  fly ash settling
         lagoon collapsed, and 130 million gallons of caustic
         solution (pH 12.0) were released into  the Clinch River.

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                                      5-56
         Large numbers of fish were killed over a distance
         extending 90 miles from the spill site.  Surveys
         conducted 10 days after the spill showed dramatic
         reductions in bottom dwelling fish food organisms for 77
         miles below the release site.  Virtually all such
         organisms were eliminated for a distance of 3 to 4 miles.
         The waste was eventually diluted, dispersed, and
         neutralized by natural physical/chemical processes.  Two
         years after the spill, however, the river had not fully
         recovered.
    5.3.2  Dames & Moore Study of Environmental Impacts



    Dames & Moore, in a study for USWAG, conducted a survey of existing data and

literature to document instances in which danger to human health and the

environment was found to have occurred because of the disposal of coal

                  28
combustion wastes.    Dames & Moore established criteria by which to evaluate

whether a given record of a contamination incident could be considered

"documented" evidence proving danger to health or the environment:  1) the

report must exist in the public record; 2) the case must involve high-volume

(utility) wastes; 3) information must exist to permit determination of possible

health or environmental risks; and 4) the possible risks may have been caused by

leachate migration or runoff from utility disposal sites.



    The danger to health and the environment was examined by accounting for the

types, concentrations, and locations of constituents shown to be present that

could have harmful effects.  In addition, Dames & Moore considered both the

potential for public access to utility waste constituents and any observed

effects on the population or environment.  The three major data sources

providing information reviewed in this study were computer data bases used to

search for publicly available references; Federal Government agencies such as

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                                      5-57


EPA, U.S. Geological Survey, and the Tennessee Valley Authority; and 12 state

environmental, natural resource, health or geological agencies.



    Using information from these sources, Dames & Moore identified seven cases

that presented a potential danger to human health and the environment.  Six of

the seven cases involved potential impacts from ground water and one case

involved surface water.  Dames & Moore concluded that none of these cases

represented a "documented" case of such danger.  However, Dames & Moore

eliminated several sites from the documented category because they believed

sufficient data from the sites were unavailable or did not meet the selection

criteria described above.  Dames & Moore evaluated in detail the seven sites at

which there existed a potential for adverse environmental and health effects.

Their findings are summarized below.
         Chisman Creek Disposal Site. York County. Virginia.  The
         Chisman Creek disposal area was an inactive site with
         four separate fly ash disposal pits on both sides of
         Chisman Creek.  An electric utility hired a private
         contractor to transport and dispose of fly ash and bottom
         ash from petroleum coke (a residual product of the oil
         distillation process) and coal combustion.  The site was
         active from the late 1950's to 1974.  In 1980, nearby
         residential drinking water wells became green from
         contamination of vanadium and selenium and could no
         longer be used.  The site is currently on the CERCLA
         (Superfund) National Priorities List.  A minimum of 38
         domestic wells and 7 monitoring wells near the four
         disposal sites were sampled over time.  Two off-site
         domestic wells located 200 feet from the disposal area
         had elevated concentrations of vanadium, selenium, and
         sulfate.  One of these two wells was sampled four times.
         Three of the four measurements exceeded the PDWS for
         selenium up to 2 times.  Another domestic well contained
         0.11 mg/1 of vanadium.  (EPA has not established
         concentration limits for vanadium.)  At both wells,
         sulfate concentrations exceeded the SOWS.  In addition,
         samples from six of the seven monitoring wells exhibited
         increased concentrations of sulfates.  The highest
         concentrations of selenium and vanadium that were
         observed in monitoring well samples were 0.03 (3 times

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                             5-58
the PDWS) and 30 mg/1, respectively.  The high
concentrations of selenium and vanadium were noticed in
monitoring wells that were drilled directly through the
disposal pits.

The Virginia State Water Control Board (SWCB) conducted
the initial study at this site.  The SWCB concluded that
the quality of ground water immediately beneath and down-
gradient from the site had been affected.  Moreover, the
SWCB stated that the water in the two domestic wells had
elevated concentrations of selenium and vanadium because
of the disposal of the fly ash.  Dames & Moore was
critical of the conclusions reached by the SWCB because
of what they termed "significant data gaps."  Dames &
Moore cited a lack of background water quality
information and a general lack of information on the well
installation, sample collection procedures, and other
possible sources of contamination, such as the York
County landfill which is adjacent to one of the ash
disposal areas.  The two contaminated off-site domestic
wells identified by the SWCB, however, were over 2,000
feet from the county landfill but within a couple of
hundred feet from the ash disposal areas.  Additionally,
monitoring wells located between the landfill and the
affected domestic wells did not register the same
elevated concentrations of selenium.  Residents in the
area no longer rely on ground water for their drinking
water.

Pierce Site. Wallingford. Connecticut.  Coal fly ash had
been deposited at the Pierce Site since 1953.  In 1978,
the United States Geological Survey (U.S.G.S.) collected
ground-water quality data from three on-site wells - one
upgradient and two downgradient.   The U.S.G.S. took
samples from the wells on three days over a period of two
months.  One sample from one downgradient well showed a
concentration of chromium that exceeded the PDWS by a
multiple of 1.6.  Concentrations of cadmium, manganese,
zinc, and sulfate were higher in the downgradient wells
than in the upgradient well.

According to Dames & Moore, there were not enough data at
this site to state conclusively whether or not the ground
water had been adversely affected by the fly ash pit.  To
determine potential damage to ground water quality, Dames
ft Moore stated that EPA recommends a minimum of three
downgradient wells and one upgradient well.  In this
case, there were only two downgradient wells.  Three
samples over a period of two months were not considered
sufficient because naturally occurring temporal changes
in the area were believed to render comparisons invalid.

The Pierce disposal site is situated on a deposit of
thick, stratified sediments composed of particles that

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                             5-59
range in size from clay to coarse sand.  The disposal
site is located within a few hundred feet of the
Quinnipiac River, and the ground water flows from the
site to the river, which diluted contaminants in the
ground water.  Although there are residences within a few
blocks of the power plant, they do not use local ground
water for drinking supplies.
Michigan City Site. Michigan City. Indiana.  The Michigan
City site, situated on the shore of Lake Michigan,
contained two fly ash disposal ponds.   Ground-water flow
at the site was towards Lake Michigan, facilitated by the
porous sand that underlies the site.  Twenty-one
monitoring wells were installed at this site.  Two of
these were placed upgradient from the  site outside the
site boundaries; the remaining 19 wells were established
within the boundaries of the facility  and downgradient
from the disposal areas.

Monitoring of the wells (which took place periodically
over a one-year period) indicated that trace metals
migrated from the disposal sites and that certain
constituents had elevated ground-water concentrations.
Arsenic and lead were observed in concentrations that
exceeded their PDWS.  Seven samples collected from three
downgradient monitoring wells had arsenic concentrations
that exceeded the standard - - up to 100 times the PDWS.
All of the samples taken from the upgradient off-site
monitoring wells contained arsenic at  concentrations
below the PDWS.  Five of the downgradient monitoring
wells contained lead concentrations which exceeded the
PDWS, with the highest exceedance 7 times the PDWS.
Three samples from the two upgradient  monitoring wells
also had lead concentrations in excess of the standard,
with the highest exceedance 3 times the PDWS.

Dames & Moore concluded that effects on ground water
appeared to be limited to areas within the facility
boundaries because of attenuation mechanisms operative at
the site -- absorption, dilution, precipitation, and a
steel slurry wall installed between the disposal site and
Lake Michigan.  However,  no downgradient monitoring wells
were situated off-site.  Based on the  locations of the
waste disposal sites and the monitoring wells, it appears
that the ash ponds are responsible for arsenic concen-
tration above the PDWS in the ground water within the
site boundaries.  Because high lead concentrations were
observed in some of the upgradient background wells, it
is impossible to state with certainty  that the high lead
concentrations in the ground water are attributable to
the disposal sites.  Dames and Moore noted that nearby
residents do not use the ground water  for their water
supply.

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                             5-60
Baillv Site. Dune Acres. Indiana.  The Bailly site is
located near the Indiana National Lakeshore on Lake
Michigan in a highly industrialized area.  Fly ash at
this site has been slurried to interim settling ponds,
which are periodically drained.  The drained ash is then
disposed in an on-site pit.  Two aquifer units,
designated Unit 1 and Unit 3, underlie the site.  Unit 1
contains fine-to-medium sand and some gravel, while Unit
3 is composed of sand with overlying layers of varying
amounts of sand, clay and gravel.

Ground-water samples from Unit 1 were collected from an
upgradient well and from several wells downgradient from the
ash settling ponds.   Samples from Unit 3 were collected
upgradient and from one well downgradient from the ash ponds.
These wells were sampled at five-week intervals between
September 1976 and May 1978.

In samples from Unit 1, arsenic, cadmium, fluoride, and
lead occasionally exceeded the PDWS.   Upgradient
concentrations of arsenic never exceeded the PDWS,
whereas the maximum downgradient concentration for
arsenic was 4.6 times the PDWS.  Downgradient on-site
concentrations of cadmium exceeded the PDWS at one well
by 25 times, while the maximum upgradient concentration
of cadmium exceeded the PDWS by 22 times.  One
downgradient well measurement indicated lead
concentrations that exceeded PDWS by 1.26 times.

All of the above-mentioned exceedances were observed in
Unit 1.  None of the samples from Unit 3 contained
constituents at concentrations that exceeded the PDWS.

Aluminum, boron, iron, manganese, molybdenum, nickel,
strontium, and zinc all increased in concentration
downgradient from the disposal areas,  though not in
levels exceeding the SOWS.

Leachate from the ash disposal ponds is the most probable
contributor to the increased concentrations of arsenic
and lead observed in the aquifer samples taken from the
on-site wells.  Cadmium was the only constituent whose
downgradient off-site concentration was observed to
exceed the PDWS.  However,  because elevated cadmium
concentrations were also found in samples taken from the
background well, the elevated concentrations of cadmium
may not have been caused by the leachate from the coal
ash.  Dames and Moore noted that ground water at this
site flows away from the nearest residential area.

Zullineer Quarry Flv Ash Disposal Site. Franklin County.
Pennsylvania.  The Zullinger quarry was situated in a
limestone formation in south-central Pennsylvania.  The

-------
                             5-61
quarry was excavated to 40 feet below the water table.
Fly ash was deposited in the quarry from 1973 to 1980
with no attempt to dewater the quarry prior to placement
of the fly ash.

The site operator, consultants, and the Pennsylvania
Department of Environmental Resources (DER) have been
independently involved in water quality investigations at
the site.  Initially, six monitoring wells were
established onsite.  Later, several existing off-site
domestic wells were added to the sampling program.  Two
of the monitoring wells were installed upgradient to
provide background constituent concentrations.   The other
monitoring wells, and the domestic wells in the sampling
program, were downgradient from the fly ash deposited in
the quarry.

Lead was found to exceed its PDWS by up to eight times in
eight out of over 100 samples.  Six of these eight
exceedances occurred in two on-site monitoring wells,
while the seventh (2.6 times PDWS) was found in an
off-site domestic well.  Another exceedance (1.5 times
PDWS) was found in the background well.

Several constituents for which there are secondary
drinking water standards were found in elevated
concentrations downgradient from the ash disposal site.
Sulfate concentrations increased dramatically during the
first few years of quarry filling, then began to sharply
decline in 1976 when the fly ash had filled the quarry.
From 1976 until deactivation of the disposal site in
1980, the fly ash was deposited above the water table.
Zinc and iron were also found in elevated concentrations.
Elevated levels of sulfate, zinc, and iron are probably
attributable to leachate from the fly ash, as are the
lead levels in excess of the PDWS.  Most of the trace
metals appear to be attenuated onsite by the limestone
formation.

Conesville Site. Conesville. Ohio.  Various types of coal
combustion waste had been deposited at the Conesville
site in central Ohio.  The monitoring program at the
Conesville site was established to determine the ability
of an FGD sludge fixation process (Poz-0-Tec, a solid
material produced by mixing FGD sludge with fly ash and
lime) to stabilize and thus immobilize potential
contaminants.  The stabilized FGD sludge has been
deposited next to a fly ash pond.  Permeable sand and
gravel underlie the Muskingum River flood plain on which
the Conesville site is located.

A total of 34 monitoring wells were installed at the
Conesville site.  Two of the wells were situated
upgradient from the disposal area to provide the

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                             5-62
necessary background water quality data.  Two sets of
water quality data were taken, the first between February
27 and April 12, 1979, and the second between December 4,
1979, and July 10, 1980.

Some samples from the first set of data contained
constituents at concentrations that exceeded the PDWS.
Lead concentrations exceeded the PDWS in two on-site
wells by up to 3 times and three off-site wells by up to
2 times.   The concentration of mercury found in one
sample from an on-site well exceeded the PDWS by 1.4
times; however, this exceedance could not be attributed
to the fly ash.  One of the fourteen background
measurements had the highest observed concentration of
selenium, 6 times the PDWS.  Thus, selenium appears to be
leaching from indigenous sediments rather than from the
FGD waste and fly ash deposited at the site.  The first
set of data also showed the SOWS constituents of calcium,
magnesium, total dissolved solids, sulfate, and iron, had
increased in those wells located on the site property and
just across the property boundaries.

Measurements taken between December 1979 and July 1980
showed increases in calcium, magnesium, total dissolved
solids, and sulfate relative to those measurements taken
in the first data collection period.  Concentrations'in
excess of the PDWS were found for selenium (several
wells), arsenic (one sample), cadmium (four samples), and
chromium (five samples).  Two of the chromium exceedances
were found in on-site wells, while three occurred in
off-site wells, with concentrations ranging up to 16
times the PDWS on-site and 2 times the PDWS off-site.
Background wells also had elevated levels of selenium.
The single arsenic exceedance (2.4 times the PDWS) and
all of the cadmium exceedances (up to 12 times the PDWS)
were detected in on-site wells.  In contrast to the first
round of sampling, lead was not detected in concentra-
tions greater than the PDWS.  The only constituents that
appear to be migrating offsite are lead and chromium.
Based on the data collected, it appears there may be a
temporal variation in the water quality at this site.
Dames and Moore noted that the town of Conesville is
downgradient from the site but on the other side of the
river, which would tend to mitigate potential adverse
impacts.

Hunts Brook Watershed. Montville-Waterford. Connecticut
The electric utility hired a private contractor to
transport and dispose of fly ash in three separate sites
(Chesterfield-Oakdale, Moxley Hill, and Linda Sites)
along three different tributaries to Hunts Brook.
Disposal of fly ash in this area began in the mid 1960's
and ended in 1969.  The surface-water quality studies
that took place in this area focused on pH, iron,

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                                      5-63
         sulfate, and total dissolved solids (IDS).  No analyses
         were performed for any of the PDWS constituents.
         Upstream surface water samples were compared to
         downstream samples to determine if the surface water
         quality had been degraded at any of the sites.

         At the Chesterfield-Oakdale site, concentrations of iron
         in the surface water increased from less than the SDWS to
         more than 100 times the SDWS between the upstream and
         downstream sampling points.  Sulfate concentrations
         increased by over an order of magnitude, from 20 to 299
         mg/1, (at 299 mg/1, still only 1.2 times the SDWS)
         between the upstream and downstream sampling positions,
         while IDS increased from less than the SDWS to 44 times
         the SDWS.  At another sampling point approximately 1.2
         miles downstream from the site, the measured parameters
         had all returned to levels close to the upstream values.

         At the Moxley Hill Site, the pH and iron concentrations
         remained relatively constant between the upstream and
         downstream sampling points;, median sulfate values
         increased, although not to levels exceeding the SDWS.
         The elevated concentrations of sulfate and TDS had been
         significantly attenuated at another point three-quarters
         of a mile downstream.

         At the Linda Site, no upstream data were collected.  It
         is therefore impossible to quantify the potential effects
         of fly ash deposition on the water quality.
                                                                             1

    5.3.3     Other Case Studies of the Environnental Inpact of Coal
              Combustion By-Product Waste Disposal


    This section presents a review of two independent case studies of

ground-water contamination at utility disposal sites.



    Cedarsauk Site, Southeastern Wisconsin



    The Cedarsauk site is a fly ash landfill in southeastern Wisconsin.   At the
                   29
time of this study,   fly ash had been deposited at the site into an abandoned

sand and gravel pit over a period of eight years.  Part of the pit is in direct

contact with an aquifer composed mainly of sand and gravel with some clay.   This

upper aquifer is approximately 15 to 20 meters thick with a permeability of 10

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                                      5-64



     _2
to 10   cm/sec.  Soluble carbon aqueous material comprises about 35 percent of


the aquifer.  The upper sandy aquifer overlies another aquifer consisting of


fractured dolomite-bedrock.
    A water quality study of the area was undertaken in 1975.  This study


eventually included 35 monitoring wells and seven surface-water sampling sites.


Twenty of the wells were placed upgradient of the site to provide background


water quality information, while the remaining wells were positioned


downgradient.   Sampling was performed on a monthly basis.  Most of the


ground-water flow beneath the site surfaced in a marsh directly east of the asb


disposal area.





    The monitoring results showed that downgradient ground water had SDWS


exceedances.  Background levels of total dissolved solids (TDS) were below 500


mg/1,  while the levels in the ground water downgradient from the disposal site


exceeded 800 mg/1, or 1.6 times the SDWS.  After eight years of disposal, .tie


contaminant plume appeared to stabilize approximately 200 meters downgradient


from the ash disposal site.  The stabilization of the constituent plume appeared


to be due to dilution and the ability of the materials in the aquifer to


attenuate contaminants.  Only iron, manganese, and zinc were found in detectable


quantities in the downgradient off-site wells.





    The maximum detected iron concentration was more than 33 times the SDWS,


while the maximum manganese concentration reached 30 times the SDWS.  Neither


iron nor zinc could be detected 200 meters downgradient from the disposal site.


Another contributor to ground-water contamination at this site was sulfate.


Background concentrations of sulfate varied between 20 and 30 mg/1 (well below

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                                      5-65






The SDHS) , while the  concentrations of sulfate in the contaminant plume achieved




levels approximately  3. -4 times the BBSS.   Other trace metals for which analyses




•were performed, such  as  copper, molybdenum,  nickel,  lead,  and titanium, were not




detected.
   -As the I'gg^h^fff ronracf pd -t-h* cfri-i-mgni-c -in i-fw> aipii-fjor^  jt- uac neutralized




from an initial pH -ralue of 4.5 TD ^rumid ueul.iHl pfl levels  (i.e. , about 7.0) .




^»T« change in pH  pTTAaAly fan-mod -Hw* pra»r* jpf •t-at-i tm nf tnony  r\f the trace Dietal




and other constituents in the leacliate.   In addition, adsorption- reactions




t>etween tiie clay in the  sediments and tne i-mn.Hn«»rYt^ probably .attenuated the




leachate concentrations  of many of the potential contaminants observed in the




leachate .









    Center Mine. Center, Harib Dakota
    Fly agh at f-his site had been deposited on a ™JTM» pit .and between mine ash




piles.  A study was conducted  to determine the potential effects of FGD and fly




ash disposal on ground vater quality at the surface mining site.    This




investigation used field monitoxing and laboratory column leaching experiments




dn conjunction with geochemical  computations.   By collecting both field and




laboratory data,  the  investigators hoped  to test the applicability of laboratory




column experiments to field situations.   Roughly 150 veils were placed both in




the vicinity of the waste disposal sites  and in unaffected areas.
    Ground-water  concentrations were generally within drinking water standards




in the background wells.  However, selected constituents were higher than the




drinking water standards.  For instance, sulfate concentrations tended to exceed

-------
                                      5-66






the SDWS by a factor of 2 to 4.  The maximum iron concentration was 4.3 times




the SDWS.  Manganese concentrations were all above the SDWS, varying from 0.06




to 2.75 mg/1, or 1.2 to 55 times the SDWS.








    Samples collected from wells located adjacent to the FGD waste site




indicated that none of the PDWS constituents exceeded the standards.  For the




SDWS constituents, molybdenum concentrations fluctuated between 0.070 and 4.850




mg/1, and sulfate concentrations reached a high of 9,521 mg/1, or 38 times the




SDWS.  (EPA has not established maximum concentration levels for molybdenum.)








    Ground water in areas that appear to be affected by leachate from the fly




ash disposal sites had sulfate concentrations ranging from 21.7 to 211 times the




SDWS.  Higher values were obtained immediately below recent deposits of fly ash,




while lower values were observed at older sites or at greater distances from the




disposal area.  Arsenic and selenium concentrations in the ground water were as




high as 0.613 mg/1 (12 times the PDWS) and 0.8 mg/1 (80 times the PDWS),




respectively.  The highest arsenic and selenium concentrations were associated




with higher pH values.  Ground-water pH values for samples in the area of the




fly ash ranged from 6.95 to 12.1.  (The Secondary Drinking Water Standard for pH




is 6.5 to 8.5).  Iron and manganese concentrations were also high in samples




taken from around the fly ash disposal site.  The maximum concentration of iron




was 8.6 times the SDWS; the maximum concentration of manganese was 130 times the




SDWS.








    Leachates from the fly ash of western coals are often characterized by a




high pH that tends to cause many potentially harmful constituents to be




released.  The pH-dependent solubility of many trace elements, as apparently

-------
                                      5-67






observed at this site, demonstrates the importance of neutral pH values that are




conducive to contaminant attenuation.








    5.3.4  Sumaxy








    The studies reviewed in this section indicate that constituents from




coal-combustion waste disposal sites have been detected in both on-site and




off-site ground and surface water.   However,  those constituents that did exceed




the drinking water standards seldom exceeded these standards by more than ten




times.  Moreover, the total number of exceedances is quite small compared to the




total number of monitoring wells and samples gathered.  The contaminant




exceedances that do occur appear to be correlated to some extent with acidic or




alkaline pH levels.  At fly ash disposal sites,  pH values between 2 and 12 have




been measured.  High and low pH values can contribute to metal solubility in




ground water.








    There are two documented cases of coal combustion waste disposal sites




causing significant harm to the environment.   Drinking water wells around the




Chisman Creek fly ash disposal site in Virginia (which was closed in 1974) were




contaminated with high concentrations of vanadium and selenium.  Concentrations




of these elements at this site were also due to petroleum coke waste (a product




of oil combustion, not coal combustion).  The site has been placed on the CERCLA




National Priority List.  In 1967, a dike failed at a utility waste disposal site




on the banks of the Clinch River in Virginia, causing waste to spill into the




river.  This accident caused substantial damage to the biotic life in the river.

-------
                                      5-68
5.4. FACTORS AFFECTING EXPOSURE AND RISK AT COAL
     COMBUSTION WASTE SITES
    The previous sections analyzed the constituents of coal combustion waste

leachates and the quality of the ground water and surface water surrounding

disposal sites.  However, this is only part of determining the potential dangers

that the wastes pose to human health and the environment.  Exposure potential,

the degree to which populations could be expected to be exposed to potentially

harmful constituents, must also be analyzed.  Exposure potential is determined

by a variety of factors.  Hydrogeologic characteristics of a site will affect

the migration potential of waste constituents.  Proximity of sites to drinking

water sources and to surface-water bodies will determine potential for exposure

to populations using the water sources.



    In order to address this issue of exposure, EPA collected a wide variety of

data on a random sample of 100 coal-fired utility plants around the country.

The sample was taken from the Utility Data Institute Power Statistics Database,

which contains information on every coal-fired electric utility plant in the

country.  Most plants dispose of their waste on-site, and in these cases

information was collected on the plant location given by the data base.  If the

plant disposed off-site, data were collected on that off-site location.  EPA

assumed that off-site disposal took place at the nearest municipal landfill,

unless additional information indicated otherwise.  Characteristics such as

depth to ground water, hydraulic conductivity, distance to surface water,

location of private and public drinking water systems, type of surrounding

natural ecosystems, and location of human population were obtained from a wide

variety of sources.  This simple aggregation of the individual factors affecting

exposure at coal combustion waste sites provides a qualitative perspective on

-------
                                      5-69


the potential risk that coal combustion waste sites pose, and is presented in

Sections 5.4.1-5.4.3.  Appendix F displays the data for each coal combustion

waste site in the random sample.



    5.4.1 Environmental Characteristics of Coal Combustion Waste Sites



    Environmental characteristics of coal combustion utility waste sites will

have a significant effect on the potential for the waste constituents to travel

and reach receptor populations.  Key environmental characteristics are:


    •    Distance to surface water - The distance between a coal
         combustion waste disposal site and the nearest surface
         water body.  Proximity to surface water would decrease
         the possible health effects of ground-water contamination
         due to the fact that there would be fewer opportunities
         for drinking water intakes before the ground water
         reached the surface water body; once the plume reached
         the surface water, contamination would be diluted.
         However, proximity to surface water would possibly
         increase danger to aquatic life because less dilution of
         the contaminant plume would occur before the plume
         reached the surface water body.

    •    Flow of surface water -  A high surface water flow will
         increase the dilution rate of coal combustion
         constituents that may enter the surface water, thereby
         reducing concentrations in the surface water.

    •    Depth to ground water -  The distance from ground level to
         the water table.   A larger depth to ground water will
         increase the time it takes for waste leachates to reach
         the aquifer; it also allows more dispersion of the
         leachate before it reaches the aquifer so that once the
         leachate reached the aquifer, concentrations of metals
         would be decreased.

    •    Hydraulic conductivity - This factor is an indication of
         the rate at which water travels through the aquifer.  A
         high hydraulic conductivity indicates that constituents
         will travel quickly through the ground water and possibly
         more readily reach drinking water wells,  although high
         conductivity also indicates a more rapid dilution of
         constituent concentration.

-------
                                      5-70
         Net recharge - This factor is a measure of net
         precipitation of a site after evapotranspiration and
         estimated runoff is subtracted.  Recharge is calculated
         in order to determine the amount of rainfall annually
         absorbed by the soil.  A high net recharge indicates a
         short period of time for contaminants to travel through
         the ground to the aquifer, but will also indicate a
         higher potential for dilution.

         Ground-water hardness - This factor is a measure of the
         parts per million (ppm) of calcium carbonate (CaC03) in
         the aquifer.  Ground water with over 240 ppm of CaCOS is
         typically treated when used as a public drinking water
         supply.  This treatment of the hard ground water has an
         indirect mitigative effect on exposure because treatment
         of the ground water will tend to remove contamination
         from other sources.
    To conduct this exposure analysis, environmental data on the 100 randomly

selected coal combustion waste sites were gathered using a number of sources.

These data were then aggregated in order to present an overview of the

environmental characteristics that contribute to exposure.  The data collected

on the sample of coal combustion waste sites were compared to information

presented in a study by Envirosphere for the Electric Power Research

          31
Institute.    The Envirosphere report gave detailed information on the

hydrogeologic settings of 450 operating utility plants.  The information

provided by the exposure analysis on the sample of 100 plants corresponded

fairly closely with the settings described in the Envirosphere report.



    The following sections summarize the data that were collected and the

relationship of the various characteristics to potential exposure.



    5.4.1.1 Distance to Surface Water and Surface-Water Flow



    The proximity of a waste site to surface water affects exposure potential in

several ways.  If the site is very near a surface-water body, there is less

-------
                                      5-71







opportunity for humans to use contaminated ground water as a source of drinking




water.  However, sites that are close to surface water can more easily




contaminate the surface-water body, although waste constituents will be more




quickly diluted if the flow of the surface water is high.









    Distance to the nearest surface-water body, e.g., creek, river, lake, or




swamp, was determined from measurements obtained using United States Geologic




Survey (U.S.G.S.) maps.  The sample of coal combustion waste sites was located




on 7-1/2 or 15 minute maps, and the distance between the site and nearest




surface water body was calculated.









    When the boundaries of the plant or waste site were marked on the maps,  the




reference point was the downgradient boundary of the site.  If the boundaries




were not marked, the latitude and longitude points for the sites provided by the




Utility Data Institute Power Statistics Database were used.









    The average distance from the sample of coal-burning waste sites to




surface-water body is 1279 meters.  Distances range from 10 to 18,000 meters.




Over 50 percent of the disposal sites are within 500 meters of surface water;




more than 70 percent are within 1,000 meters of surface water.  Exhibit 5-17




provides the number and percentage of sites within specified distances of




surface water.









    Since most sites are located somewhat near surface-water bodies, the




potential for human exposure to contaminated ground water seems to be low.  The




proximity of the sites to surface water could, however, pose a threat to




aquatic life and to humans using the surface water if contaminants are entering

-------
                                             5-72





                                          EXHIBIT 5-17



          DISTANCE OF COAL COMBUSTION  WASTE SITES TO SURFACE WATER
 CO
 111


 V)

 LL
 O

 111
 a
'
 UJ
 u
 oc
 u
 a
       80%
       70% -
       60% -
50%
40%
30%
       20%
       10%
               0-500
                            500-1000
                                           1000-3000
                                                          3000-5000
                                                                         5000-9000
                                 DISTANCE (METERS)

           SOURCE: ICF Inc. based on USGS data

-------
                                      5-73







the surface water.  The concentration in surface water will be less, however,




if the surface-water body close to the site has a high flow.









    Flow data on surface-water bodies near the sample of 100 sites were




obtained from U.S.G.S. data.  Flow is expressed in terms of cubic feet per




second (cfs), and given for minimum and maximum average flow for one-month




periods.  In order to obtain a conservative estimate of exposure (i.e., one




that does not understate exposure) this report used estimates for the month




with the minimum monthly flow.  The results are presented in Exhibit 5-18.









    Exhibit 5-18 shows that 19 percent of the sites have a flow of zero.  A •




zero flow generally indicates that the body of water is a lake, swamp, or marsh




that does not have any continual flow of water, although this category could




include a seasonal stream.  For surface-water bodies with zero flow, dilution




of potential contamination would occur because of the volume of water in the




surface-water body, but there would not be any additional dilution as water




flowed away from the source of contamination.  Forty-one percent of the




surface-water bodies have a flow of 1-1000 cubic feet per second, 21 percent




have a flow of 1,000-10,000 cfs, and 18 percent have a flow of over 10,000 cfs.









    5.4.1.2  Hydrogeologic Measurements









    The hydrogeologic measurements of depth to ground water, hydraulic




conductivity, and net recharge were determined through the use of information




provided by the DRASTIC system.  The DRASTIC system, developed by the National




Well Water Association, categorizes aquifers on the basis of geographic region




and subregion.  Each site was located on a 7 1/2 or 15 minute U.S.G.S. map that

-------
                                           5-74




                                    EXHIBIT 5-18


                      FLOW OF NEAREST SURFACE-WATER BODY
      eox
to
111

CO
u.
O
Ul
O
LU
O
cc
UJ
Q.
                                  1-1000
                                                  1000-10,000
10,000.
                            FLOW (CUBIC FEET/SECOND)

          SOURCE: ICF Inc. based on USQS data

-------
                                      5-75





was then compared with a map on which the 11 major DRASTIC regions had been



outlined.  The topography and geology of the sites, which were determined from



looking at the U.S.G.S. maps, were assessed in order to further classify



thesites into DRASTIC subregions.  Subregions are defined by hydrogeologic



characteristics and vary in size from a few acres to hundreds of square miles.



Measurements for depth to ground water, hydraulic conductivity, and net



recharge of the sites were taken largely from A Standardized System for



Evaluating Ground-water Pollution Potential Using Hvdrogeologic Settings.  by



the National Well Water Association, which presents a range of values for each


                                                     32
of these hydrogeologic properties for each subregion.    The ranges were



compared with characteristics that could be observed by studying U.S.G.S.  maps,



and, when necessary, they were modified accordingly.







    Depth to Ground Water







    A small depth to ground water indicates a higher potential for waste



constituents to reach the ground water at harmful concentrations than if the



distance to ground water were greater, thereby increasing the chance of



ground-water contamination.  Depth to ground water was generally based on



DRASTIC region and subregion, but was modified when the topography or site



characteristics indicated a depth different from that provided by the DRASTIC



system.  For example, if the DRASTIC subregion indicated that there was a high



depth to ground water range, but a particular site was located very near a



surface-water body, the Agency used a smaller depth to ground water than the



DRASTIC range indicated.

-------
                                      5-76







    Exhibit 5-19 provides the number and percentage of sites within each range




of depth to ground water.  Depth to ground water is calculated in feet and




based on 10 ranges.  In over 80 percent of the sites depth to ground water is




less than 30 feet, indicating a reasonably high potential that leachate from




the disposal site would reach the ground water.




                             *



    Hydraulic Conductivity









    Hydraulic conductivity is an indication of the ease with which a




constituent may be transported through the ground water.  Conductivity is also




based on the site's DRASTIC region and subregion, and is measured in gallons




per day per square foot and grouped into six ranges.









    Hydraulic conductivity is one of the factors used to calculate ground-




water velocity, or volumetric flow of the water table.  Velocity has a direct




bearing on the degree to which leachate constituents are diluted once they




reach the ground water and travel to a point of exposure (i.e., human drinking




water source).  High ground-water conductivity signifies high velocity and




therefore a high dilution potential.









    Exhibit 5-20 provides the number and percentage of sites falling into each




hydraulic conductivity range.  Thirty-three percent of the sites show a




hydraulic conductivity of 700-1,000 gallons per day per square foot; 27 percent




have a conductivity of 1,000-2,000 gallons per day per square foot.   There is




a wide spread of conductivity values -- indicating hydrogeologic diversity




among sites.

-------
                                           5-77
                                    EXHIBIT  5-19



                             DEPTH TO GROUND WATER

                        AT COAL COMBUSTION HASTE SITES
      60%
      50% -
OT
UJ
E    40% -
V)
u.
o
Ul
o
u
u
ec
ui
Q.
30% -
20% -
      10%
            0-5     0-10    5-15    10-20   15-30   30-50   50-75   50-100  75-100



                              EXPECTED DEPTH (FEET)

           SOURCE: ICF Ine, based on DRASTIC

-------
                                           5-78
                                    EXHIBIT 5-20



                               HYDRAULIC CONDUCTIVITY

                          AT COAL COMBUSTION HASTE SITES
      100%
OT
111
H
w
u.
o
u
o
UJ
O
oc
111
D.
90% -




eo% -




70% -




60% -




60% -




40% -
30% -
                                               33%
                                                             27%
        0%
            1-100         100-300         300-700        700-1000       1000-2000


                       HYDRAULIC CONDUCTIVITY (GAL/DAY/SQ.FT)


            SOURCE: ICF Inc, based on DRASTIC d»tt
                                                                                 2000»

-------
                                      5-79







    While ground-water velocity gives an indication of how fast contamination




may travel in the ground water, contaminants do not move at the same velocity




as the ground water.  This is because of basic interactions between




contaminants and soil that retard the movement of the contaminants.  There are




three different mechanisms that affect the retardation of contaminant movement




-- exchange on soil particle sites (ion exchange), adsorption onto soil




particle surfaces, and precipitation.  The exchange and adsorption mechanisms




will retard the movement of contaminants but will not eliminate the movement of




all contaminants due to limited soil attenuation capacity.









    As with the diversity among sites in terms of hydraulic conductivity and




ground-water velocity, the various attenuation mechanisms differ among sites.




To determine the attenuation potential at a site requires detailed data inputs




on water chemistry on a site-specific basis.









Net Recharge









    Net recharge indicates how much water is annually absorbed into the ground.




It is measured by subtracting evapotranspiration (the amount of rainfall that




evaporates and transpires from plant surfaces) and estimated runoff from total




precipitation at a site.  It affects exposure potential in a number of ways.




Low recharge will result in smaller volumes of more concentrated leachate, but




if the aquifer is deep and/or has a high velocity, it will quickly dilute the




leachate.   High recharge produces more leachate,  but may also indicate that the




area has higher ground-water flow.

-------
                                      5-80






    Exhibit 5-21 shows the number and percentage of sites that fall into each



range.  Recharge is measured in inches and is grouped into five ranges.



Although a wide variety of net recharge ranges is represented by the sample,



the recharge of sites generally falls into the higher ranges of 4-7 inches,



7-10 inches, and over 10 inches.  For example, more than 80 percent of the



sites have a net recharge of over 4 inches and over 50 percent have a recharge



of over 7 inches.  This implies that leachate constituents will be more quickly



carried to the water table but the higher recharge rate will also result in



greater dilution of the leachate.








    Ground-water Hardness








    The hardness of the ground water near coal combustion waste sites will have



an effect on potential exposure through drinking water since excessive hardness



is typically treated in a public drinking water system.  Treatment would lessen



the exposure potential to humans.from contaminants in the ground water from



other sources (such as coal combustion wastes).  Measurements for ground-water



hardness were obtained by locating the sites on maps provided in Ground-water


                                                               33
Contamination in the United States (Pye, Patrick, and Quarles).








    As shown in Exhibit 5-22, ground-water hardness is measured in parts per



million (ppm) of calcium carbonate (CaC03) and grouped into five ranges.



Ground water with a hardness of over 240 ppm of calcium carbonate is typically



treated if used in a public drinking water system.  In this sample, 45 percent



of the sites show ground-water hardness in this range.  Ground water with a



hardness of 180-240 ppm of calcium carbonate may also be treated, although

-------
                                          5-81
                                    EXHIBIT 5-21


                                   NET RECHARGE

                          AT COAL COMBUSTION HASTE SITES
      80%
      50% -
W
111
£Z    40% -
w
IL
O
111
O

g

Ul
O
a
ui
tt.
30% -
20% -
      10%
               0-2            2-4             4-7            7-10


                                 NET RECHARGE (INCHES)


          SOURCE: ICF Inc. bistd on DRASTIC

-------
                                             5-82
                                       EXHIBIT  5-22


                                 GROUND-WATER  HARDNESS

                            AT COAL COMBUSTION BASTE SITES
Ill
t
in
u.
O
Ul
O
in
O
ec
111
D.
      BOX
      SOX -
      40X -
      30X -
      20* -
      10X
               .80            80-120          120-180          180-240


                               HARDNESS (PPM CaCO3)
                                                                            •240
           SOURCE: ICF Inc. b«»«d on Py», *t »l, Groundw»t«r Contamlnitlon In U.S.

-------
                                      5-83






treatment is much less likely.  An additional 22 percent fall in the 180-240




ppm range.








    The high levels of calcium carbonate found in the ground water near coal




combustion waste disposal sites suggest that if a drinking water supply is in




the vicinity, the water would often require treatment before being used.




Therefore, contamination that might exist in the drinking water from other




sources would be mitigated due to the treatment process since trace




constituents tend to be removed during the treatment process.








    5.4.2 Population Characteristics of Coal Combustion Waste Sites








    Environmental characteristic's, such as distance and flow of surface water




and hydrogeologic measurements, are only one part of the analysis of exposure




potential.  Opportunities for human exposure to coal combustion waste




constituents depend in part on the proximity of coal combustion waste disposal




sites to human populations and to human drinking water supplies.  Census data




(1980) provide information about the number of people living within specified




distances from the coal combustion waste sites.  This information is obtained




through the CENBAT program, part of the Graphic Exposure Modeling System




developed by EPA's Office of Solid Waste.   The Federal Reporting Data System




(FRDS) data base, developed by EPA's Office-of Drinking Water,  provides




estimates of the number of public water supply systems and the size of the




populations using them.

-------
                                      5-84






    5.4.2.1  Proxinity of Sites to Human Populations









    CENBAT provides information on the number of people living within specified




distances around designated locations.  The sites were defined by latitude and




longitude coordinates.  Populations were analyzed for areas within 1-, 2-, 3-,




4-, and 5-kilometer radii of the waste disposal sites.








    Exhibit 5-23 shows the distribution of population within one kilometer of




the waste disposal sites.  The CENBAT results show that most sites, 71 per-




cent, do not have any population within a one-kilometer radius.  Overall, the




population range within a one-kilometer radius is 0 - 3708 people, with an




average of 359 people.








    Exhibit 5-24 shows the population characteristics for the sample of coal




combustion waste sites at a three-kilometer radius.  When the search distance




is increased to three kilometers, the percentage of sites that have no people




within a three-kilometer radius decreases to 32 percent.  Average population




within three kilometers is 3,737, and the range is 0 - 35,633 people.  There is




a large degree of diversity of populations at this distance.  For example,




while 32 percent of the sites have zero population, the same percentage has




populations over 2,000.








    Exhibit 5-25 shows the distribution of populations within a five-kilometer




radius.  Only 10 percent of the sites do not have any population living within




this distance.  The average population is 12,128 people, with a range from 0 to




123,160.  The diversity among coal combustion waste disposal sites is even more




apparent at this distance.  While 20 percent of the sites have populations

-------
                                            5-85
                                     EXHIBIT 5-23


                  POPULATIONS WITHIN ONE KILOMETER OF WASTE SITES
      100%
M
Ul

55
u.
o
Ul
c
<


Ul
o
cc
Ul
Q.
      90% -
      80% -
70%
60%
50%
40%
              71%
30%
      20%
       10%
                                                                 0%
                                                                             0%
              r»ro          1-900        501-2000     2001-10,000   10,001-25,000


                                 POPULATION RANGES


           SOURCE: ICF Inc, based on CENBAT data
                                                                            25000-

-------
                                            5-86





                                     EXHIBIT 5-24



                POFDIATIONS WITHIN THREE KILOMETERS OF WASTE SITES
      100%
V)
la

55
u.
o
in
o
ui
u
cc
111
0.
      90% -
      80% -
70% -
60% -
50% -
      40% -
30%
      20%
        32%
      10%
                                                    20%
              zero         1-500       501-2000     2001-10,000   10,001-25,000



                                 POPULATION RANGES


           SOURCE: ICF Inc., based on CENBAT data
                                                                            25000*

-------
                                             5-87





                                      EXHIBIT 5-25



              POPULATIONS WITHIN FIVE KILOMETERS OF WASTE SITES
      100%
w
111
H
33
u.
o
ui
o
<

z
111
o
ft
111
a.
      90% H
      80% H
70% H
60% H
50% H
40% H
30% H
       20% -
       10%
                                             31%
                                                                             14%
              Ztro          1-500        501-2000     2001-10,000   10,001-25,000



                                 POPULATION RANGES


          SOURCE: ICF Inc., based on CENBAT
                                                                            25000*

-------
                                      5-88






within a five-kilometer radius of fewer than 500 persons, 29 percent have




populations over 10,000.








    The CENBAT results indicate that density increases on average with distance




from the disposal site.  Many waste sites appear to be located on the outskirts




of populated areas, with fairly low population immediately adjacent to the




site, but with significant populations within a five-kilometer radius.








    5.4.2.2  Proximity of Sites to Public Drinking Water Systems








    If coal combustion waste sites are close to public drinking water systems,




there may be potential for human exposure through drinking water supplies.   The




location of public water supplies was determined through the use of the Federal




Reporting Data System (FRDS),  developed by EPA's Office of Drinking Water.








    The FRDS data base provides the number of public water supply systems




located within specified distances from a site and the populations using the




systems.  It should be noted that the FRDS data base locates water systems




based on the centroid of the zip code of the mailing address of each utility




and that the actual location of the intake or well may be different.  This can




cause some inaccuracy in the calculation of the distance and location of public




drinking water supplies in relation to the waste site.  In order to remedy




potential inaccuracies and omissions, the locations of public water systems




that appeared on topographical maps but were not reported by FRDS are also




recorded.

-------
                                      5-89






    Exhibit 5-26 shows the population served by public water systems located in




the downgradient plume from the sites and within a five-kilometer radius.  The




exhibit also shows how many sites have no public water systems within a




five-kilometer radius.  Sixty-six percent of the sites have no public water




systems within a five-kilometer radius.  Fifteen percent of coal combustion




sites have public water systems located within a five-kilometer distance and




had systems which served over 5,000 people, and 19 percent have public water




systems that serve fewer than 5,000 people.








    The population data indicate that while there are often quite large




populations in the vicinity of coal combustion waste sites, only 34 percent of




the sites have public drinking water systems downgradient from the site.








    5.4.3  Ecologic Characteristics of Coal Conbustion Waste Sites








    Ecological data on endangered, threatened, or unique plants and animals is




available through state Heritage Programs.   The Nature Conservancy established




the Heritage Programs, which now usually function as offices of state




governments.  The Heritage Programs develop and maintain data bases that




describe jeopardized species and rare ecosystems within each state.  It should




be noted that there can be substantial variation in the completeness of data




available from different states; some state Heritage Programs are fairly new,




and basic data collection is still in its preliminary stages.








    While it may not currently be possible to quantitatively model risk to




ecosystems from coal combustion waste, the information provided by the Heritage




Programs can indicate whether there are any jeopardized species near a specific

-------
                                        5-90
V)
111
I-

55
u.
o
111
o

f

Ul
u
ec
u
D.
                                  EXHIBIT 5-26



      POPULATIONS SERVED BY PUBLIC HATER SYSTEMS NEAR HASTE SITES
       90%
       80% -
       70% -
60% -
50% -
40% -
30% -
      20% -
       10%
                1-1000
                                  1000-5000             >5000



                                      POPULATION
                                                              NO PUBLIC WATER SYSTEM


                                                            WITHIN FIVE KILOMETER RADIUS
           SOURCE: ICF, bated on FRDS data

-------
                                      5-91







waste site.  If potentially hazardous constituents of coal combustion waste do




migrate and produce environmental contamination, it could affect species and




natural communities that are particularly vulnerable, thereby lessening




ecosystem diversity.









    EPA provided Heritage Program staff with latitudes and longitudes for the




sampled sites in states that had such programs.  Using these coordinates, the




Heritage Program staff performed a search of their data bases for rare or




endangered species within a five-kilometer radius from the site.









    The sample sites were grouped into four categories based on the results




obtained from the Heritage Program.   Category 1 includes sites having Federally




designated threatened or endangered species within the five-kilometer radius.




Category 2 includes sites that have no Federally designated threatened or




endangered species within the five-kilometer distance, but which do contain




species or natural communities designated by state Heritage Offices as




critically endangered in that state.  Category 3 contains sites for which there




are species or natural communities of concern in the area.  For sites in




Category 4, there is no record of the existence of species of concern in the




five-kilometer area.









    Information was available on 85  of the 100 coal combustion waste sites in




the sample.  Exhibit 5-27 presents the breakdown of sites according to the




categories described above.   Twelve  percent of the sites fall into Category 1,




29 percent in Category 2; 32 percent in Category 3; and 12 percent in Category




4 (no information was available for  15 percent).

-------
                                                       5-92




                                               EXHIBIT 5-27



                                ECOLOGICAL STATUS OF WASTE SITES
       32X
                                                                 32%
V)
111
t
to
U.
o
U
o
<

z
111
o
oc
111
Q.
                                           2   CATEGORY      '


       Category 1: Federally designated plants or anlmalt within a five Km. radius

       Category 2: Species of priority state concern within five km. radius

       Category 3: species of concern to state environmental offices
       Category 4: no data on ecosystem surrounding the site
SOURCE: ICF inc., based on State Heritage Data

-------
                                      5-93




    Given the high percentage of sites that have rare plant and animal


communities within a five-kilometer radius supplies, and the proximity        ;.


discussed earlier of waste disposal sites to surface-water bodies (which


provide animals with drinking water),  there could be a high potential for


species exposure to coal combustion constituents.





    5.4.4  Multivariate Analysis





    The previous sections of this exposure analysis presented independent


analyses of the population, environmental,  and ecological characteristics of


coal combustion waste sites.  This section examines a number of these factors


simultaneously in order to determine interactions that affect the overall


potential for exposure from coal combustion waste sites.





    As mentioned previously, only 34 percent of coal combustion waste sites

                                                                             j
(based on a random sample of 100 sites) have public drinking water systems in


the downgradient plume within 5 kilometers of the waste site.  Some of these


public drinking water systems may use ground water that is currently treated


before it is used as drinking water, indicating that human populations are


unlikely to be directly exposed to any water that may be  contaminated from coal


combustion waste constituents.  As discussed earlier, one reason for treating


the water is ground-water hardness.   Ground water that has a hardness greater


than 240 ppm CaC03 is likely to be treated if it is used  as a drinking water


source.  Of the 34 percent of the sites in the sample that have public water


systems in the downgradient plume within 5 kilometers of  the waste site,  just


under one-half of these sites have ground water with a hardness over 240  ppm


CaC03.  These results show that the potential for human exposure through

-------
                                      5-94






drinking water is likely to be less than the proximity to public drinking water



systems (FRDS data) indicates.  Of all the sites sampled, only 18 percent have



public drinking water systems within 5 kilometers and ground water under 240


          34
ppm CaC03.








    The potential for human exposure through drinking water can be further



evaluated by comparing the FRDS and ground-water quality characteristics with



the hydrogeologic factors of net recharge and depth to ground water.  Sites



with a net recharge greater than 7 inches and a depth to ground water of



fifteen feet or less are more likely to develop ground-water contamination due



to waste leaching since water has a greater likelihood of contacting the coal



combustion wastes.  Of the 18 percent of the sites that have public water



supplies and ground-water hardness below 240 ppm CaCOS, two-thirds have a net



recharge greater than 7 inches as well as a depth to ground water of 15 feet or



less.  Therefore, only 12 percent of the sites in the sample (18 percent x 2/3)



have ground water that is likely to be used without treatment and hydrogeologic



characteristics that indicate high potential for leachate migration.








    This multivariate analysis of the factors affecting exposure at coal



combustion waste sites illustrates the limited potential for human health risk



through drinking water.  Only 34 percent of the sites have public water systems



within five kilometers and many of these public water systems are likely to



treat the ground water due to hardness.

-------
                                     5-95
5.5  SUMMARY



    This chapter has reviewed available information on the potential for

coal-fired combustion wastes from electric utility power plants to affect human

health and the environment.  First,  data on the potential corrosivity and EP

toxicity of utility wastes was reviewed.  After determining that coal

combustion leachate sometimes contains hazardous constituents at levels above

drinking water standards,  the potential for this leachate to migrate from waste

disposal sites was examined.  Results of ground-water monitoring in several

studies were interpreted and a number of compilations of "documented" damage

cases were evaluated.  After describing instances in which trace elements in

coal combustion leachate have migrated from waste disposal sites, the potential

effect of these migrations was examined.  A sample of 100 utility waste

disposal sites was selected, and these sites were evaluated in terms of

population, environmental, and ecological characteristics to assess the

potential for leachate migration and exposure of human and ecological

populations.



    Based on these data and analyses, several observations relating to

potential dangers to human health and the environment can be made:
    •    If the current exemption from Subtitle C regulation
         were lifted for coal combustion wastes and these
         wastes were required to be tested for corrosivity or
         EP toxicity, most current waste volumes and waste
         streams would not be subject to hazardous waste
         regulation.  The only waste stream which has had
         corrosive results is boiler cleaning waste.  (Since
         coal ash is not aqueous, it cannot be corrosive.)
         For the other waste streams,  available data indicate
         that while some of these waste streams could have
         high or low pH levels, they are not likely to fall
         under the RCRA definition of corrosive waste.

-------
                             5-96
Similarly, while a few high-volume waste samples did
exceed the EP toxicity limits for cadmium, chromium,
and arsenic, this was limited to a few waste streams
and represented only a small fraction of the samples
for these waste streams (the chromium and arsenic
exceedances were from only one fly ash sample).
Available data on low-volume wastes showed that the
only waste stream with significant RCRA exceedances
was boiler cleaning waste, which had exceedances for
chromium and lead.  Wastewater brines were shown to
exceed the RCRA standard for selenium in one sample.
Results of EP tests on co-disposed wastes indicate
that boiler cleaning wastes may not possess
hazardous characteristics when co-disposed with ash.
Results for all other waste streams and all other
constituents were below EP toxicity limits.

Results available from ground-water monitoring
studies and documented cases of ground-water or
surface-water contamination show some migration of
PDWS constituents from utility waste disposal sites.
In the most comprehensive and systematic of these
studies, the Arthur D. Little survey of six utility
sites, evidence of constituent migration downstream
from the waste sites was conclusive only for
cadmium.  The Envirosphere ground-water study showed
that only 3.7 percent of the samples showed
downgradient concentrations of PDWS constituents
that were higher than the concentrations of
upgradient constituents (indicating that some
contaminants are migrating from the site).  This
tends to support the results of the waste extraction
tests.  For the one utility disposal site on the
National Priorities List, a site currently inactive
since it was closed in 1974, the major ground-water
contaminants were vanadium and selenium.  However,
this site differs from some other sites for which
ground-water quality data are available in that
wastes are from both coal and petroleum coke
combustion.

Although coal combustion waste leachate has the
potential to migrate from the disposal area, the
actual potential for exposure of human and
ecological populations is likely to be limited.
Because utility plants need a source of water to
operate, most of the disposal sites are located
quite close to surface water.  Fifty eight percent
of the 100 sample sites were within 500 meters of
surface water.  It is not common for drinking water
wells to be located between the disposal site and
the nearest downgradient surface water body.  The
effect of this proximity to surface water is that
only 34 percent of the sampled sites had drinking

-------
                             5-97
water intakes within five kilometers.  Furthermore,
the flow of the surface water will tend to dilute
the concentrations of trace metals to levels that
satisfy drinking water standards.

Simultaneously examining the environmental and
population characteristics of coal combustion waste
sites shows even less potential for exposure to
human populations.  12 percent of the sites in the
sample have public water systems within five
kilometers of the site' where the ground water may
not be treated (i.e., ground-water hardness below
240 ppm CaCOS) and hydrogeologic characteristics
that indicate high potential for leachate migration.

-------
                                   CHAPTER 5

                                     NOTES
*-   See 40 CFR 261.21.

2   See 40 CFR 261.22.   In using pH to determine corrosivity, EPA explained
    that "wastes exhibiting low or high pH can cause harm to human tissue,
    promote the migration of toxic contaminants from other wastes,  and harm
    aquatic life."

3   These methods are set forth in 40 CFR 260.21 and 260.22.

4   See 40 CFR 261.23.

5   See 40 CFR 261.24.

6   See 40 CFR Part 261,  Appendix II..  These procedures for testing and the
    limits allowed for determining whether a waste is hazardous or not are
    currently under review.

'   A waste would be considered hazardous if it has been shown to have an oral
    ID 50 toxicity to rats of less than 50 mg/kg, an inhalation LC toxicity to
    rats of less than 2 mg/1, or a dermal ID 50 toxicity to rabbits of less
    than 2000 mg/kg.
8
    See 40 CFR 261.11.
9   See CFR 40 Section 261.24.   RCRA also establishes EP toxicity limits for
    six pesticides.

    See CFR 40 Section 261,  Appendix II.

11  Federal Register,  Volume 51, No. 114, Friday,  June 13,  1986, p.  21648.

12
    Since the completion of the ASTM B tests discussed in this section,  ASTM
    has dropped this extraction test (EPRI 1983).

13
    Tetra Tech, Inc.,  Physical-Chemical Characteristics of Utility Solid
    Wastes. prepared for Electric Power Research Institute, EA-3236, September
    1983.

14
    Jackson, L. and Moore,  F.,  Analytical Aspects  of the Fossil Energy Waste
    Sampling and Characterization Project, prepared for the U.S. Department of
    Energy, Office of Fossil Energy, DOE/LC/00022-1599 (DE84009266), March
    1984.

-------
                                      -2-
    Arthur D. Little, Inc., Full-Scale Field Evaluation of Waste Disposal from
    Coal-fired Electric Generation Plants, prepared for the Air and Energy
    Engineering Research Laboratory of the U.S. Environmental Protection Agency
    for the Office of Solid Waste, EPA-600-7-85-028, June 1985.

    Mason, B.J., and Carlile, D.W.,  draft report of Round Robin Evaluation for
    Selected Elements and Anionic Species from TCLP and EP Extractions.
    prepared by Battelle Pacific Northwest Laboratories, for the Electric Power
    Research Institute, EPRI EA-4740, April 25, 1986.

    Battelle's test varied from standard TCLP procedure by allowing 14 days,
    rather than the normal 7, for the completion of the test.
18
    Electric Power Research Institute, "Mobilization and Attenuation of Trace
    Elements in an Artificially Weathered Fly Ash," prepared by the University
    of Alberta, Edmonton, Canada, EPRI EA-4747, August 1986.

19
    Battelle Pacific Northwest Laboratories, Chemical Characterization of
    Fossil Fuel Combustion Wastes, prepared for the Electric Power Research
    Institute, September 1987.
on
    Radian Corporation, Characterization of Utility Low-Volume Wastes, prepared
    for the Electric Power Research Institute,  May 1985.

21
    Radian Corporation, Manual For Management of Low-Volume Wastes From
    Fossil-Fuel-Fired Power Plants,  prepared for the Electric Power Research
    Institute, July 1987.
22
    Arthur D. Little, Inc., Full-Scale Field Evaluation of Waste Disposal from
    Coal-fired Electric Generation Plants, prepared by the Air and Energy
    Engineering Research Laboratory of the U.S. Environmental Protection
    Agency, for the Office of Solid Waste, EPA-600-7-85-028, June 1985.
23
    Franklin Associates, Ltd., Survey of Ground-water Contamination Cases at
    Coal Combustion Waste Disposal Sites, prepared for U.S. Environmental
    Protection Agency, March 1984.

24
    Envirosphere Company, "Report on the Ground Water Data Base Assembled by
    the Utility Solid Waste Activities Group,"  in Utility Solid Waste
    Activities Group (USWAG), Report and Technical Studies on the Disposal and
    Utilization of Fossil-Fuel Bv-Products. October 26, 1982, Appendix C.

25
    It is not necessarily true that measurements taken from upgradient and
    downgradient wells at approximately the same time yield comparable
    measurements.  In fact, due to migration time, there will be a lag
    between the time of comparable upgradient and downgradient
    measurements.

-------
                                      -3-
26
    Envirosphere Company,  Op. cit..  p.  38.  These percentage numbers do not
    correspond precisely to the data in Exhibit 5-11 because Envirosphere
    normalized the data it received from the utilities so that each facility
    would be weighted evenly (i.e.,, a facility with many more measurements   '
    would not be weighted excessively).  Envirosphere reports that 1.7 percent
    of the normalized data had upgradient measurements lower than the PDWS and
    the downgradient higher than the FDVS; 5 percent of the data indicated that
    both values exceeded the standard.

27
    Envirosphere Company,  Environmental Effects of Utility Solid Waste
    Disposal, prepared for Utility Solid Waste Activities Group and Edison
    Electric Institute, July 1979.
O Q
    Dames ft Moore, "Review of Existing Literature & Published Data to Determine
    if Proven Documented Cases of Danger to Human Health and the Environment
    Exist as a Result of Disposal of Fossil Fuel Combustion Wastes", in Utility
    Solid Waste Activities Group (USWAG),  Report and Technical Studies on the
    Disposal and Utilization of Fossil-Fuel Combustion By-Products. October 26,
    1982, Appendix B.
09
    Cherkauer, D. S.  "The Effect of Fly Ash Disposal on a Shallow Ground-Water
    System."  Ground Water. Vol. 18, No. 6, pp. 544-550, 1980.

    Groenewold, G. H.,  and B. W. Rehm.   "Applicability of Column Leaching Data
    to the Design of Fly Ash and- FGD Waste Disposal Sites in Surface- Mined
    Areas."  In Proceedings of the Low-Rank Coal Technology Development
    Workshop. comp. Energy Resources Company, Inc., DOE/ET/17086-1932,
    CONF-8106235; Washington, D.C.,  U.S. Department of Energy, Technical
    Information Center, pp. 3-79 - 3-95, 1981.

    Envirosphere Company,  Environmental Settings and Solid-Residues Disposal in
    the Electric Utility Industry: prepared for the Electric Power Research
    Institute, August 1984.
32
    Linda Aller, Truman Bennet, Jay H.  Laher, Rebecca J. Betty, A Standardized
    System for Evaluating Ground Water Pollution Potential Using Hydrologic
    Settings, prepared by the National Well Water Association for U.S. EPA
    Office of Research and Development, Ada, OK, May 1985.  EPA 600-285-018.

    Veronica T. Pye, Ruth Patrick, John Quarles, Ground Water Contamination in
    the United States.  Philadelphia: University of Pennsylvania Press, 1983.

34
    Ground water over 180 ppm CaC03 may also be treated.  Of the 34 percent of
    the sites in the sample that have public water systems in the plume
    downgradient from the site within 5 kilometers, 73 percent have ground
    water with a hardness over 180 ppm CaC03.  Therefore, only 9 percent of the
    sites in the sample have both public water systems within 5 kilometers and
    ground water under 180 ppm CaC03.  Since many public water systems may not
    treat water in the range of 180-240 ppm CaC03,  the discussion in the report
    focuses only on ground water in excess of 240 ppm CaC03.  This is a
    conservative assumption since the water may be treated, either by the
    public authority or the private homeowner.  In all cases, the extent of
    exposure through private wells would have to be evaluated on a site-by-site
    basis.

-------
                                  CHAPTER SIX




                           ECONOMIC COSTS AND IMPACTS
    Section 8002(n) of RCRA requires that EPA's study of coal combustion wastes




examine "alternatives to current disposal methods," "the costs of such




alternatives," "the impact of those alternatives on the use of coal and other




natural resources" and "the current and potential utilization of such




materials."  In response to these directives this chapter examines the




potential costs to electric utilities if coal-fired combustion waste disposal




practices are regulated differently than they are currently.








    The first section of this chapter (Section 6.1) examines the costs incurred




by electric utilities using current disposal methods for coal combustion




wastes.1  Section 6.2 follows with a discussion of the costs that could be




incurred if coal combustion wastes were regulated differently than they are




today.  These costs include the costs of implementing alternative waste




management practices and the costs of additional administrative




responsibilities that would be incurred.  Section 6.3 examines how new




regulations might affect the cost of utilizing coal combustion wastes in




various by-product applications.  The last section of this chapter (Section




6.4) considers how energy use patterns in the electric utility industry might




change if alternative waste management practices that significantly affect the




cost of generating electricity with coal were imposed.

-------
                                      6-2
6.1  HASTE DISPOSAL COSTS ASSOCIATED WITH CDRREHT DISPOSAL METHODS



    The management of utility wastes comprises a series of activities -- from

initial waste collection to disposal.  These current waste management

activities can be classified into five basic components.
    1.   Waste Han AT jTig and Processing.  This is the initial phase of
         the disposal process,  involving collection of the various
         waste products after they have been generated and initial
         treatment of the wastes to prepare them for final disposal.

    2.   Interim Waste Storage at the Plant.  Some waste products that
         are dry when produced, such as fly ash or flue gas
         desulfurization (FGD)  wastes from dry scrubbers, often
         require interim storage prior to final disposal.

    3.   Raw Materials Handling and Storage.  Some disposal processes
         involve stabilization or chemical fixation of the waste to
         prepare it for disposal.  The raw materials used for this
         phase, including additives such as lime, Calcilox, and basic
         fly ash, often require special handling and storage
         facilities.

    4.   Waste Transport to a Disposal Facility.  Environmentally
         sound disposal requires careful transportation of the waste
         to the disposal site.   Many modes of transportation can be
         used, including trucks, railroads, barges, pipelines, and
         conveyor systems.

    5.   Waste Placenent and Disposal.  This is the final stage of the
         waste disposal chain.   It involves placing the waste in a
         suitable waste management facility (usually a surface
         impoundment or landfill) and all activities required after
         the facility is closed.  Alternatively, the final disposition
         of a waste product may entail utilization of the waste in
         various applications (such as cement production or
         sandblasting operations).


    Exhibit 6-1 presents a schematic illustration of the current waste

management and disposal options for coal ash;  Exhibit 6-2 illustrates the

options available for FGD wastes.  The waste management costs discussed in this

-------
                                Exhibit  6-1
Overview of Waste Handling and Disposal Options for  Coal Ash
   COAL ASH HANDLING
    AND PROCESSING
   COAL ASH
|   STORAGE
               RAW
COAL ASH     MATERIALS      COAL ASH PLACEMENT
TRANSPORT  |  HANDLING   |       AND DISPOSAL

1
1
•
1
1
•
L
I*
FLY ASH 1
COLLECTED BYJ
ESPs AND 1
MECHANICAL 1








•
FLY ASH 1
COLLECTED BYI
UJ C T 1

SCRUBBERS 1
1
1
•


BOTTOM ASH/ j
SLAG 1
•

••»





-»



•»•














-»•




Vacuum
Pneumatic
Conveying

Pressure
Conveying


Vacuum/
Pressure
Conveying


Wel
Handling



Wel
Handling








Wel




»•





»•



•»












































— »•












»•









L»




*













Interim




.





Dewalering



No
Dewalering




Bins

1
•
1
1
1.
1

•
I

+*
•

1




•
1
1
•
I»
*

•


i
fc




Storage
Silo



No
Storage











No
Q.






Storage
                                                                                  Landfill
                                                                                  Disposal
                                                                                 Utilization!
          Source:  Arthur D. Little, Inc.,  Full-Scale Field Evaluation of Waste Disposal From Coal-Fired
                  Electric Generating Plants, June 1985.

-------
                                                  Exhibit  6-2
           Overview  of  Waste Handling and Disposal  Options  for  FGD  Waste
FQD WASTE
FROM WET
SCRUBBERS
                FQO WASTE
                WITHIN THE
              SCRUBBER LOOPI    FGD WASTE HANDLING AND PROCESSING
                                                          FGD WASTE
                                                          TRANSPORT   |     FGD WASTE DISPOSAL
                  Forced
                 Oxidation
   No
 Forced
Oxidation
                                                            Blending
                                                              with
                                                              Soil
                                                           Stabilization
                                                               with
                                                             Fly Ash
                                          Ichem
                                           Flxa
Chemical
    lion
                                                              No
                                                            Treatment
                  No
               Dewalering
                                                           Conveyor
                                                             Truck
Rail
                                                             Barge
                                                                          Ulllliallon
                                 Landfill
                                 Disposal
  Mine
DUpotal
                                 Ocean
                                 DUpotal
                                                                             Pipeline
                                                                                       H
                                  Pond
                                 Dlapoaal
                                                                                             Interim
                                                                                             Ponding
                                                                                                        o\
                                                                                                        i
                                                                                                          Utilization
                                                                                                       i
                                                                                         Landllll
                                                                                         Dlapoaal
                              Source:   Arthur D. Little, Inc.,  Full-Scale Field Evaluation of Waste Disposal From Coal-Fired
                                       Electric Generating Plants, June 1985.

-------
                                      6-5
chapter are those associated with the last component of waste management (i.e.,




waste placement and disposal).  These are the costs associated with actual




construction of the waste management facility and placement of the wastes into




the facility.  If current practices for managing coal-fired wastes from




electric utilities are altered, it is this final stage in waste management that




would probably be most affected.  However, as will be explored later in this




chapter, some regulatory alternatives may affect other aspects of waste




management.








    6.1.1  Costs of Waste Placement and Disposal








    The wastes from coal-fired combustion at electric utility power plants are




often mixed together in the same waste management facility, typically a surface




impoundment or landfill.  Although surface impoundments were once the preferred




method, and are still widely used, landfilling has become the more common




practice because less land is required, and it is usually more environmentally




sound (because of the lower water requirements, reduced leaching problems,




etc.).








    The costs of waste disposal can vary substantially.  Exhibit 6-3 shows




representative capital costs associated with constructing surface impoundments




and landfills for coal-fired electric utility wastes.  Exhibit 6-4 shows total




costs (i.e., annualized capital costs plus operation and maintenance




expenses).   Costs are shown for power plants that range in size from 100 to




3000 megawatts (Mw);  power plants that fall outside of this range may incur

-------
                                      6-6
                                  EXHIBIT 6-3

                RANGES OF AVERAGE CAPITAL COSTS ASSOCIATED WITH
                  COAL-FIRED ELECTRIC UTILITY WASTE DISPOSAL
                      (4th quarter 1986 dollars per kilowatt)


                                            Size of Power Plant
Type of Waste
Landfills
Fly Ash
Bottom Ash
FGD Waste
Surface Impoundments
Fly Ash
Bottom Ash
FGD Waste
100 MW

9-14
2- 5
6-13

27-50
10-20
14-30
500 MW

4-7
2-3
4-7

15-27
6-11
10-19
1000 MW

3-5
1-2
3-6

13-23
5- 9
9-17
3000 MW

2-3
1-1.3
2-4

10-18
3- 6
7-14
Source:  Arthur D.  Little,  Inc.,  Full-Scale Field Evaluation of Waste Disposal
        From Coal-Fired Electric Generating Plants.  EPA 600/7-85-028,  June
        1985.

-------
                                      6-7
                               EXHIBIT 6-4

        RANGES OF AVERAGE TOTAL COSTS FOR COAL-FIRED ELECTRIC
                          UTILITY HASTE DISPOSAL
                      (4th quarter 1986 dollars per ton)*
                                            Size of Power Plant
    Tvoe of Waste	100 MW	500 MW	1000 MW	3000 MW

Landfills

    Fly Ash                    9-18         6-11         5-9           2-6

    Bottom Ash                10-16         5-9          4-8           2-6

    FGD Waste                  4-10         4-7          3-6           2-4


Surface Impoundments

    Fly Ash                   17-31         9-17         8-14          5-8

    Bottom Ash                11-26         8-15         7-13          5-8

    FGD Waste                  8-17         7-13         6-10          5-7
     *   Dollar per ton estimates are based on the amount of waste produced
         each year.  For purposes of this illustration,  a power plant is
         assumed to generate annually 308 tons of fly ash per megawatt (MW),  77
         tons of bottom ash per MW,  and 264 tons of FGD waste per MW.  Amounts
         will vary depending on coal quality,  FGD technology, and boiler type,
         among other factors.

Source:  Arthur D. Little,  Inc., Full-Scale Field Evaluation of Waste Disposal
         From Coal-Fired Electric Generating Plants.  EPA 600/7-85-028, June
         1985.

-------
                                      6-8
different waste management costs.  Both capital costs and total costs are shown




for unlined facilities without ground-water monitoring or leachate control




systems. The major factors affecting the cost of waste management are discussed




below.








    The amount of capital costs for a waste management facility can be




attributed primarily to three factors:  site preparation, excavation, and




construction of containment structures.^  Capital costs can be substantially




reduced if the amount of earthwork can be minimized.  Capital costs for surface




impoundments, for example, increase significantly if dike construction or




excavation is required.  However, if existing site features can be used, such




as valleys or abandoned pits, capital costs will be lower.  Similarly, capital




costs for landfills that require little excavation are lower than for those




sites requiring extensive earthwork.








    As Exhibit 6-3 illustrates, landfills are far less capital intensive than




surface impoundments.  For example, capital costs for fly ash placement in a




surface impoundment at a 500 MW power plant would range from approximately $15




to $27 per kilowatt.   In contrast, capital costs for landfills range from




about $4 to $7 per kilowatt.  Landfills tend to cost less than impoundments




primarily because the area required for a given amount of waste is less, and




neither dikes nor piping and pumping systems are necessary.








    Annual costs for landfills (see Exhibit 6-4) also tend to be less than




those for surface impoundments primarily because landfills tend to be far less




capital intensive.  For example, costs for fly ash management at a 500 MW power




plant range from about $9 to $17 per ton when the wastes are placed in surface

-------
                                      6-9
impoundments, while the comparable range at a landfill is about $6 to $11 per

ton.  Similarly, the cost for bottom ash disposal at an impoundment for a 500

MW power plant ranges from $8 to $15 per ton, while the costs to dispose in a

landfill range from about $5 to $9 per ton.



    Other factors that affect the cost of utility waste disposal include
    •   Size of the Power Plant.  Because larger power plants
        consume more coal than smaller facilities, they generate
        more waste material.  However, more efficient operating
        procedures allow a larger disposal site to realize
        economies of scale not available at smaller sites; thus,
        the cost per ton of waste disposed is typically less.

    •   Rate of Operation.  The number of hours that a coal-fired
        power plant operates varies from plant to plant, ranging
        from fewer than 3,500 hours per year to more than 6,500
        hours.  As operating levels increase, the amount of waste
        generated will increase as more coal is burned to meet the
        higher generation load.

    •   Type of Coal.  The quantity of ash produced is proportional
        to the ash content of the coal, which ranges from 5 to 20
        percent on average.  Also, the grade of coal and boiler
        design will affect the relative proportions of fly ash and
        bottom ash (see Chapter Three for a discussion of the
        impact of boiler design on types and amount of wastes
        generated).

    •   FGD Equipment.  Because of the additional materials used in
        flue gas desulfurization, a power plant that uses this
        process to remove sulfur dioxide generates substantially
        more waste than does a power plant with no sulfur dioxide
        controls.  The amount of waste generated also varies from
        one FGD operation to the next, primarily because of
        differences in sulfur content among the various coals and,
        to a lesser extent, because of the type of FGD process
        employed.


    For the few power plants currently disposing their waste in mines or

quarries, this disposal method has been economic because of convenient access  to

the disposal site.  Since much of the excavation normally required at a disposal

-------
                                      6-10
site has already been performed as a result of the mining or quarrying




operation, waste disposal costs can be quite competitive with costs associated




with more traditional methods of disp9sal.  The cost of disposing in mines or




quarries for power plants that do not have easy access to the mine or quarry




could quickly become prohibitive due to the costs of arranging for disposal at a




remote site and of transporting the waste.  Costs are also affected by whether




or not the mine or quarry is still operating, whether the mining was surface or




underground, and the amount of additional preparation required to dispose of the




wastes, among other factors.








    The costs of ocean disposal are not well known because there has been




limited experience with this disposal method.  Ocean disposal has been




considered for unconsolidated waste (i.e., waste material that has not been




physically or chemically altered prior to disposal)^ and for more stabilized




forms of waste, such as blocks for artificial reef construction,  however, this




method has been attempted only for projects such as artificial reef




construction, and then only on a trial basis.  The most critical factors that




would affect the magnitude of costs for ocean disposal are the availability of




ash-handling facilities to load ocean-going vessels, the ability to gain easy




access to the necessary waterways, and the physical characteristics of the




wastes intended for disposal.








    Because neither ocean disposal nor mine or quarry disposal is likely to be




used on a widespread basis,  they have been discussed here only briefly; see




Chapter Four for a more detailed discussion of these two disposal options.

-------
                                      6-11
    6.1.2  Costs Associated with lined Disposal Facilities





    The waste management costs presented above for surface impoundments and


landfills do not include the cost of natural or synthetic liners to control the


flow of leachate from the disposal area.  Traditionally, most waste management


sites, both surface impoundments and landfills, have not been lined to retard


leaching, although this practice has become more widespread in recent years (see


Chapter Four for a detailed discussion of liners).  Currently, about 25 percent


of all coal combustion waste management sites employ some type of liner system.


Host liners are made of clay, synthetic materials, or stabilized utility waste.





    Clay is used as a liner material because it is not very permeable, although


its permeability will vary depending on the nature of the clay and the degree of


compaction.  Because clay is expensive to transport, the costs of the various


clays used for liner material are directly related to the local availability of


the clay.  The installed cost of clay liners can range from $4.45 to $15.75 per

           P
cubic yard.   For a liner 36-inches thick, (liner thicknesses do vary), this


results in a cost range of $21,000 to $75,000 per acre, or about $0.70 to $2.55


per ton of waste disposed in a landfill and $2.25 to $8.20 per ton for waste


placed in an impoundment for a 500 MW power plant.*





    Synthetic liner materials come in two basic varieties--exposable and


unexposable.  The membranes of exposable liners are resistant to degradation


from exposure to the elements even if the liner is left uncovered.  The


membranes of unexposable liners will not function properly if the liner is


exposed.  Costs for installing exposable liners range from $43,000 to $113,000


per acre, or $1.45 to $3.85 per ton of waste disposed in landfills and from

-------
                                      6-12
$4.70 to $12.35 per ton of waste placed in surface impoundments.    Costs to



install unexposable liners range from $59,000 to $123,000 per acre, or $2.00 to



$4.15 per ton of waste disposed in landfills and $6.45 to $13.45 per ton placed



in impoundments.    The ranges of costs are due primarily to differences in the



cost of the material, differences in liner thickness, and allowances for various



site-specific costs.
    Stabilized utility waste, made from combinations of various ash wastes (such



as fly ash or bottom ash), FGD waste, and lime, may be used as liner material



when the required materials are available at the plant site.  At an installed



cost of about $13.70 per cubic yard, liners ranging from 3 feet to 5 feet in


                                                              12
thickness can be constructed for $66,000 to $110,000 per acre,   which



corresponds to total capital costs of $3.0-$5.0 million at a landfill, or about



$2.25 to $3.75 per ton of disposed waste from a 500 Mw power plant.  Total



capital costs at impoundments would be $9.6-$16.0 million, or $7.20-$12.00 per


                     13
ton of waste managed.








6.2  COSTS OF ALTERNATIVE DISPOSAL OPTIONS








    As described above, coal-fired utility wastes are currently exempt from RCRA



Subtitle C waste management requirements.  In the interim, coal combustion



wastes are regulated under state statutes and regulations (see Chapter Four).



If these wastes are subject to Subtitle C regulation, the incremental costs will



depend on the regulatory option(s) ultimately selected.  Section 6.2.1 outlines



the major regulatory alternatives and discusses the flexibility allowed EPA



under RCRA to promulgate regulations that account for the special nature of coal



combustion wastes.  Section 6.2.2 presents cost estimates for individual

-------
                                      6-13
Subtitle C disposal requirements, and Section 6.2.3 presents cost estimates for

three regulatory scenarios if coal combustion wastes are regulated under

Subtitle C.



    6.2.1  Regulatory Alternatives under Subtitle C



    As described in Chapter Five, there are two ways in which coal combustion

wastes could be identified as hazardous and thus subject to requirements

outlined in Part 264 of RCRA:  the characteristic procedure and the listing

procedure.


    •   Regulation As Characteristic Waste.  Unless otherwise
        exempted,  solid wastes are hazardous under RCRA if
        they display any of four characteristics:
        ignitibility, corrosivity, reactivity, or EP toxicity.
        Coal combustion wastes are unlikely to be ignitable or
        reactive,  but could be corrosive (for aqueous wastes)
        or EP toxic.  Subtitle C regulations would apply only
        to those waste streams that exhibited any of the
        hazardous characteristics.  As discussed in Chapter
        Five, it is likely that only a small percentage of all
        waste generated would be hazardous.  However, since
        some low volume wastes may be corrosive, this could
        have an impact on utilities that currently co-dispose
        high- and low-volume wastes.  In these cases, the
        utility could either stop co-disposing or the landfill
        would have to conform to Subtitle C standards.  In the
        case of surface impoundments,  it might still be
        possible to co-dispose high- and low-volume wastes if
        the disposal impoundment met the requirements for a
        neutralization surface impoundment as set forth in 47
        FR 1254, January 11, 1982.

    •   Regulation as Listed Waste.  In addition to regulation
        under Subtitle C as characteristic waste, the
        Administrator may list a waste as hazardous under RCRA
        if it meets any of the three criteria contained in 40
        CFR 261.11:  (1) the waste exhibits any of the four
        characteristics described above; (2) it has been found
        to be fatal to humans in low doses or is otherwise
        measured as acutely hazardous; or (3) it contains any
        of the toxic constituents listed in Appendix VIII of
        Part 261.   The Administrator does not have to list a

-------
                                      6-14
        waste that contains any of the toxic constituents
        listed in Appendix VIII if the Agency concludes that
        "the waste is not capable of posing a substantial
        present or potential hazard to human health or the
        environment when improperly treated, stored,
        transported or disposed of, or otherwise managed".
        The Administrator could decide to list as hazardous
        all coal combustion waste streams or only selected
        ones.
    If Subtitle C regulation is warranted for coal combustion wastes,  all the

requirements for hazardous waste treatment, storage, disposal, and recycling

facilities in 40 CFR 264 could be applied to the wastes from coal-fired power

plants.  Since coal combustion waste is mainly managed in surface impoundments

and landfills, the requirements of Subparts A-H, K, and N would apply.  In

general, the required activities include the following:
        General Facility Standards.  Facilities must apply for
        an identification number,  prepare required notices
        when necessary,  perform general waste analysis,  secure
        the disposal facility to prevent unauthorized entry,
        comply with general inspection requirements,  provide
        personnel training, and observe location standards
        (these include a provision that facilities located in
        a 100-year flood plain must be designed, constructed,
        operated, and maintained to prevent washout of any
        hazardous waste by a 100-year flood).   (40 CFR 264
        Subpart B)

        Preparedness and Prevention.  Hazardous waste facility
        operators must design and operate facilities  to
        minimize the possibility of fire or explosion, equip
        the facility with emergency equipment,  test and
        maintain the equipment, and provide EPA and other
        government officials access to communications or alarm
        systems.  (40 CFR 264 Subpart C)

        Contingency Plan and Emergency Procedures. The
        facility operators must have a contingency plan to
        minimize hazards to human health or the environment in
        the event of fire or explosion.  (40 CFR 264 Subpart D)

-------
                                      6-15
    •   Manifest System, Recordkeeping, and Reporting.
        Hazardous waste facility operators must maintain a
        manifest system, keep a written operating record, and
        prepare a biennial report.  (40 CFR 264 Subpart E)

    •   Ground-water Protection.  Unless a,waste management
        facility meets certain standards,   a Subtitle C
        facility is required to comply with requirements to
        detect, characterize, and respond to releases from
        solid waste management units at the facility.  These
        requirements include ground-water monitoring and
        corrective action as necessary to protect human health
        and the environment.  (40 CFR 264 Subpart F)

    •   Closure and Post-closure.  Subtitle C facilities must
        comply with closure and post-closure performance
        standards to minimize the risk of hazardous
        constituents escaping into the environment.  (40 CFR
        264 Subpart G)

    •   Financial Requirements.  Subtitle C facilities must
        establish a financial assurance plan for closure of
        the facility and for post-closure care.  Possible
        methods of financial assurance include a closure trust
        fund, surety bonds, closure letter of credit, closure
        insurance,-or financial test and corporate
        guarantee.     (40 CFR 264 Subpart H)

    •   Design and Operating Requirements.  Unless granted an
        exemption,  new surface impoundments or landfills or
        new units at existing impoundments or landfills must
        install two or more liners and a leachate collection
        system between the liners. (40 CFR 264 Subparts K
        and H)

    In recognition of the special nature of coal combustion wastes,  Congress

afforded EPA some flexibility in designing regulations for coal combustion

wastes if they are subject to regulation under Subtitle C.  This flexibility

allows EPA to exempt electric utilities from some regulations imposed on owners

and operators of hazardous waste treatment, storage, and disposal facilities by

the Hazardous and Solid Waste Amendments of 1984.  Specifically, section 3004(x)

of RCRA allows the Administrator to modify the following requirements when

promulgating regulations for utility waste.

-------
                                      6-16
    •   Section 3004 (c) prohibits the placement of uncontained
        liquids in landfills;

    •   Section-3004 (d) prohibits the land disposal of specified
        wastes;

    •   Section 3004 (e) prohibits the land disposal of solvents
        and dioxins;

    •   Section 3004 (f) mandates a determination regarding
        disposal of specified wastes into deep injection wells;

    •   Section 3004 (g) mandates determinations on continued land
        disposal of all listed hazardous wastes;

    •   Section 3004 (o) lists minimum technical requirements for
        design and operation of landfills and surface impoundments,
        which specify the installation of two or more liners, a
        leachate collection system, and ground-water monitoring;

    •   Section 3004 (u) requires the Administrator to promulgate
        standards for facilities that burn hazardous waste as fuel;
        and

    •   Section 3005 (j) provides that interim-status surface
        impoundments must also meet minimum technical requirements
        specified in section 3004 (o).


    In addition to the flexibility afforded by 3004 (x),  it is possible for EPA

to modify any of the standards applicable to waste treatment and disposal

facilities if lesser standards are protective of human health and the

environment.  Section 3004 (a) states "... The Administrator shall promulgate

regulations establishing such performance standards, applicable to owners and

operators of facilities for the treatment, storage, or disposal of hazardous

waste identified or listed under this subtitle, as may be necessary to protect

human health and the environment."
    There remains substantial uncertainty, however, about the extent to which,

in practice, the statutory language of Subtitle C would provide sufficient

flexibility to design a waste management program appropriate for high-volume,

-------
                                      6-17
low-toxicity coal combustion wastes.  EPA may also consider waste management

requirements, as needed, under the current Subtitle D provisions for solid

wastes, or may seek appropriate additional authorities.



    6.2.2  Cost: Estimates for Individual RCRA Subtitle C Disposal Standards



    If EPA determines that Subtitle C regulation is warranted for coal

combustion wastes, there is a wide range of regulatory options that could be

undertaken.  Required activities could consist of some, all, or variations of

the requirements listed in 40 CFR Subparts B-H (and described briefly in Section

6.2.1).  This section presents estimates for the costs that would be associated

with compliance with individual Subtitle C requirements.



        6.2.2.1  General Facility Standards; Preparedness and Prevention;
                 Contingency Plan and Emergency Procedures; and Manifest
                 Systen


    Subparts B through E in Part 264 of the RCRA regulations list general

requirements for such activities as preparing written notices and plans for

submission to EPA; conducting waste analyses; providing security at the disposal

site; and recordkeeping and reporting.  Many of these activities would be

undertaken during the permitting process,  which is set forth in Part 270 of

RCRA.



    The Part B application must contain the technical information listed in Part

264 B through E.  The cost to the electric utility industry to prepare a Part B

permit application was estimated in a study done for the Utility Solid Waste

Activities Group (USWAG),  which calculated that the total cost of submitting

-------
                                      6-18
Part B permit analyses would be $721,000 per plant, or about $0.55 per ton of



waste disposed.    The industry cost, if all power plants filed Part B



applications, would be about $370 million, or about $54 million in annualized



costs.
    Location standards are also specified under Subpart B of Part 264 of RCRA.



One such standard is for facilities located in a 100-year flood plain.  Part



246.16(b) requires protective measures to prevent washout from flooding.







    USWAG estimated the costs for protecting waste disposal facilities located



within a 100-year flood plain to be about $740 per acre for surface impoundments


                                                               18
and about $1,100 per acre for landfills on an annualized basis.    This



corresponds to waste management costs of approximately $0.55 per ton of waste at


                                                    19
surface impoundments and $0.25 per ton at landfills.    Industry-wide costs for



flood protection at all impoundments are estimated to be about $92 million for



capital expenditures (about $13 million in annualized costs); costs for flood



protection at all landfills would be about $146 million for capital expenditures


                                        20
(about $20 million in annualized costs).







        6.2.2.2  Ground-water Protection







    Subpart F of 40 CFR Part 264 lists requirements for ground-water monitoring



systems.  The costs of installing and maintaining an acceptable ground-water



monitoring program are dependent on the number of monitoring wells required and



the frequency of testing.  The study conducted by Arthur D.  Little for EPA



estimated that capital costs for installing six monitoring wells at a facility


                                    21
would range from $18,000 to $25,000.    At a sampling frequency of four times

-------
                                      6-19
per year, annual operating and maintenance costs would be $10,000 to $14,500.



Total ground-water monitoring costs would range from $0.06 to $0.10 per ton of



managed waste.  In another study conducted for USWAG by Envirosphere,  which used



different well configurations and cost parameters, somewhat higher costs


                                                      22
($0.10-$0.12 per ton of waste managed) were estimated.








    It is not known how many coal-fired power plants currently have adequate



ground-water monitoring systems in place.  To estimate industry-wide costs, EPA



has conservatively assumed that all power plants would be required to install



new ground-water monitoring systems.  Using the costs developed in the Arthur D.



Little study, EPA calculated that total capital costs would be about $9.3 to



$12.8 million.  Total annualized costs would range from $6.5 to $9.3 million.








    6.2.2.3  Corrective Action








    Subpart F of 40 CFR Part 264 also lists requirements for corrective action.



A variety of actions may be undertaken to correct ground-water contamination



problems caused by a hazardous waste disposal facility.  The facility owner or



operator would need to conduct a site-specific investigation to ascertain the



potential degree of contamination and the appropriate response that would be



most effective in remedying the situation.  Types of remedial responses that



might be required would be placing a cap (made of either a clay or synthetic



material) on the disposal unit, counter-pumping the ground water to retard



contaminant migration, excavating the disposal area and removing the wastes to a



Subtitle C landfill, or installing an impermeable curtain around the disposal



area to prevent ground-water flow into or out of the disposal area.  As one



example of the potential magnitude of corrective action costs, this section

-------
                                      6-20
evaluates the cost to excavate the existing disposal areas and transfer the



wastes to RCRA Subtitle C-approved facilities.







    EPA developed the following formula to calculate total excavation costs for



Subtitle C units, (including closure of the existing site and removal of the



wastes to a Subtitle C facility):







          Cost - [(Surface Area x $45) + (Volume x $187)] x 2.16
where the surface area is measured in square meters, and volume is measured in



cubic meters.
    For a power plant of average size (500 MW),  it has been assumed that a



45-acre landfill would be required, or about 182,000 square meters, with a



capacity of approximately 5 million cubic meters.   Based on the cost equation



listed above, costs for excavation and waste transfer for a landfill site would


                      24
be about $2.0 billion.    For surface impoundments, the appropriate parameters



are 145 acres, or about 587,000 square meters, and a volume of about 5 million



cubic meters, which works out to about $2.1 billion for the same type of



corrective action.  If this type of corrective action were required at all power



plants, compliance costs for the industry would be enormous.  At a cost of about



$2 billion per plant, industry-wide costs would exceed one trillion dollars.







        6.2.2.4  Closure and Post-closure







    Subpart G of 40 CFR 264 specifies general closure and post-closure



requirements for Subtitle C facilities and 40 CFR 264(K) and (N) list specific

-------
                                      6-21
requirements for closure and post-closure care of surface impoundments and



landfills, respectively.  These requirements, as applied to coal combustion



wastes, would require the dewatering of ash ponds, installation of a suitable



cover liner made of synthetic materials, application of topsoil to support



vegetation, seeding and fertilizing, installation of security fencing, and



long-term ground-water monitoring.  USWAG estimates that capital costs for



closing a waste management facility range from $39,000 to $128,000 per acre for


                                                                         25
surface impoundments and from $55,000 to $137,000 per acre for landfills.



Once the facility is closed, additional costs would be incurred for post-closure



care -- about $1,050 per acre annually.    Total annual costs for closure of a



surface impoundment would range from about $1.0 to $2.8 million for a typical



500 Mw power plant, or $5.00 to $14.75 per ton of waste managed.  For a



landfill, total annual costs would range from $0.4 to $0.9 million, or $2.10 to


              07
$4.90 per ton.




                                                                             i


    An owner or operator that chooses to close a facility in the event that coal



combustion wastes are brought under Subtitle C regulation would not necessarily



have to follow the closure and post-closure requirements for hazardous waste



facilities listed in 40 CFR Part 264.  If regulations are proposed, there would


                                                            28
be some period of time before final regulations take effect.    If the disposal



facility is closed during this interim period, the closure standards that would



apply would be those required under state regulations,  not Subtitle C



regulations.







    A facility that closes after the new regulations take effect, however, is



subject to Subtitle C closure and post-closure requirements.  The USWAG study



provides an estimate of the total costs of closing all existing coal combustion

-------
                                      6-22
waste disposal facilities and of the costs of closing only unlined facilities


(See Exhibit 6-5).  Total capital costs required to close all unlined landfills


and impoundments would range from $3.5 billion for clay-capped facilities to


$9.7 billion for synthetic-capped facilities.  If all facilities closed under


Subtitle C regulation, total capital costs would be about $4.3 billion for

                                                                   09
clay-capped closure and $12.0 billion for synthetic-capped closure.    Total


annualized costs to close only unlined facilities would range from about $575


million for closure with clay caps to about $1.5 billion for synthetic caps.  If


all current waste management facilities were closed, annualized costs would be


about $700 million for clay caps to $1.8 billion for synthetic caps.





        6.2.2.5  Financial Responsibility





    Subpart H of 40 CFR 264 sets forth requirements for financial responsibility


for closure and post-closure care of hazardous waste facilities.  A facility


owner may use several different financial mechanisms to demonstrate financial


responsibility, including purchasing a letter of credit, posting a surety bond,


establishing a trust fund, purchasing an insurance policy, providing a corporate


guarantee, or passing a financial test.  Financial responsibility could be


required for closure/post-closure costs or corrective action costs.  The


magnitude of the costs can vary considerably depending on the financial


mechanism that is used and the type of activity for which financial assurance is


required.  For example, costs to provide a corporate guarantee or pass a


financial test may be on the order of a few hundred dollars per facility; on the


other hand, annual costs to obtain a letter of credit or to establish a trust


fund are often based on some percentage (e.g., one to two percent) of the total

-------
                                                     6-23
                    14
               12-


               10-


                8-

Capital Costs

(10'Dollars)     6'


                4-


                2-
                                                EXHIBIT  6-5


                                        SUMMARY  OF COSTS TO CLOSE
                                   EXISTING WASTE DISPOSAL FACILITIES
                          Clay Synthetic
                          Cap    Cap

                        Impoundments
                             Only
                                          Clay Synthetic
                                          Cap    Cap

                                           Landfills
                                             Only
  Clay Synthetic
  Cap   Cap

Impoundments
 And  Landfills
                                                                                      Close
                                                                                      all Facilities
                                                                                      Close Only
                                                                                      Unlined Facilities
                          Clay Synthetic
                          Cap   Cap

                        Impoundments
                             Only
                                         Clay Synthetic
                                         Cap   Cap

                                          Landfills
                                            Only
/uuu-
1800-

1600-
1400-
Annualized 1200-
Costs
Including innn
f\ p Ttif AVv/V"
M 0 T")n11sirO ft/\/\
^ i \j j_/uuai sj 800-

600-


400-

o f\f\
200-
0-



























''''* *'**! ''
\v<
\,SN





















\X\

^SN
v\\
•,\\
0\\
•;\\
<^

























>\\"
\v
\ \ •
^N



















'«'%/%.
\ \ "'

\\\
r'/\\
\'\\
''i '\ '\
'» \ \

^J






















*% \ ''
>NX''
> *\ '% J
\ \ ''
'\''V'
\"v\
^SN

















^
>^
^
''/, \ '''/
''* \ \
», '\ X
\N>
^,\\
'•., \

v ^ '




























  Clay Synthetic
  Cap    Cap

Impoundments
And Landfills
                                                                                      Close
                                                                                      all Facilities
                                                                                     Close Only
                                                                                     Unlined Facilities
     Source:   Envirosphere Company, "Report on the Costs of Utility Ash and FGD Waste Disposal,'
               in USWAG, Report on the Costs of Utility Ash and FGD Waste Disposal, Appendix F
               Part 2,  October 19, 1982.
4/87

-------
                                      6-24
costs of the closure/post-closure or corrective action activity to be



       i    30
undertaken.
        6.2.2.6  Design and Operating Requirements for Landfills and Surface

                 Inpoundnents
    The level of effort required to come into compliance with Subtitle C design




and operating requirements will depend on many site-specific considerations.   In




some cases, it may be possible to seal off the portion of the existing disposal




site that has been in use and upgrade the remaining portion by installing a




liner.  In other situations the required changes may be sufficiently different




from existing disposal practices that the most cost-effective action may be to




open an entirely new disposal facility.








    Given the variety of site-specific situations that may arise,  and given the




regulatory flexibility EPA has in designing coal combustion waste  management




standards, it is not feasible to estimate how many utility waste management




facilities may be affected or what type of waste management measures may be




required without conducting site-specific investigations.  Nevertheless, to




indicate the approximate magnitude of costs that may be involved for different




waste management practices, the costs for three management options --




single-lined landfills, single-lined surface impoundments, and double-lined




surface impoundments -- are presented below.








    Landfills








    As noted earlier, single clay liners can be installed in a landfill for

-------
                                      6-25
about $0.70 to $2.55 per ton of disposed waste and single synthetic liners for



about $1.45 to $4.15 per ton of disposed waste.  The costs presented in Exhibit



6-4 indicate that waste disposal costs at a representative 500 Hw power plant



with no flue gas desulfurization equipment would average about $5 to $11 per ton



of disposed waste for a landfill operation.  Adding a single clay liner to the



landfill would increase total costs to $5.70 to $13.55 per ton of disposed



waste; adding a single synthetic liner would increase costs to $6.45 to $15.15



per ton of disposed waste.







    These estimates appear to be similar in magnitude, although somewhat lower



than costs estimated in another study of utility waste disposal costs conducted



for the Utility Solid Waste Activities Group (USWAG) by Econometric Research,



Inc.  That study estimated that total costs for complying with requirements



related to the construction, operation, and maintenance of a single-lined



landfill would range from about $15 to $24 per ton of waste, depending on the


              31
type of liner.







    The study for USWAG also analyzed the total costs to the electric utility



industry if all power plants currently using landfills were required to



construct new landfills with single liners.  For this scenario, USWAG assumed



that existing facilities, even if lined, would have to be replaced to comply



with new requirements.   Total capital costs for this alternative would range



from $2.6 billion for landfills with one synthetic liner to $4.0 billion for


                                   32
landfills with a single clay liner.    Estimated annualized costs were about



$400 million for installing a single synthetic liner at all landfills and about


                                                33
$600 million for installing a single clay liner.

-------
                                      6-26
    Surface Inpoundaents







    The costs presented in Exhibit 6-4 for onlined surface impoundments



indicated that waste managed at a representative 500 Mw power plant with no FGD



waste production would cost about $8 to $17 per ton of waste.  Using the cost



estimates for liners noted earlier (see Section 6.1.2), adding a single clay



liner would increase total management costs to about $10.25-$25.20 per ton of



waste, and adding a synthetic liner would increase costs to $12.70-$30.45 per



ton of waste.







    These cost estimates for single-lined impoundments appear to be reasonably



consistent with other estimates.  Studies for USWAG indicated that management



costs for impoundments with a single synthetic liner were about $19 per ton of


                                                                         34
waste and $30 per ton of waste for impoundments with a single clay liner.







    The USWAG report also estimated the total costs to the electric utility



industry to construct new impoundments with single liners (i.e., all power



plants currently using surface impoundments would be required to construct new



facilities to meet disposal requirements even if the current impoundment is



already lined).  For this alternative total capital costs would range from $5.8



billion for impoundments with single synthetic liners to $9.5 billion for


                                     35
impoundments with single clay liners.    Annualized costs would range from $850



million for single synthetic liners at all impoundments to $1.4 billion for



single clay liners.







    The study for USWAG also estimated management costs for surface impoundments



with two different types of double liners --a double synthetic liner (each with

-------
                                      6-27
a 30 mil thickness) and a double liner system consisting of one synthetic liner


(30 mil) and a clay liner (36 inches).   Total management costs for double-lined


surface impoundments would range from about $29 per ton of waste for a site with


two synthetic liners to $36 per ton of waste for a site with one synthetic liner


and one clay liner.






    Industry-wide costs were also estimated for the installation of new


double-lined surface impoundments at all power plants currently using surface


impoundments.  Total capital costs for installing a double-lined impoundment


ranged from $9.3 billion for a double synthetic liner to $11.6 billion for one

                             38                       .
clay and one synthetic liner.    Total annualized costs were estimated at $1.4


billion for all impoundments with a double synthetic liner and $1.7 billion for


all impoundments with one clay liner and one synthetic liner.  A summary of the


costs for the various types of lined disposal facilities discussed herein is


presented in Exhibit 6-6.






        6.2.2.7  Summary of Costs for Various Waste Management Alternatives






    Exhibit 6-7 summarizes the costs to the electric utility industry of each of


the waste management options previously discussed.  The exhibit presents cost


estimates for the total amount of capital required for each waste management


standard and for the total amount of annualized costs (i.e., annual capital,


operation, and maintenance costs) that would be incurred in order to comply with


each requirement if coal-fired combustion wastes were regulated as hazardous


wastes.

-------
                                   6-28
                               EXHIBIT 6-6

                   SUMMARY OF COSTS FOR DIFFERENT TYPES
                   OF LINED WASTE MANAGEMENT FACILITIES
Landfills

  Basic Practice--Unlined

  Single Clay Liner
  Single Synthetic Liner

Surface Impoundments

  Basic Practice--Unlined

  Single Clay Liner
  Single Synthetic Liner

  Double Synthetic Liners
  Double Liners:
    1 Synthetic and 1 Clay
                                 Cost per ton
$ 5.00-$11.00

$ 5.70-$13.55
$ 6.45-$15.15
$ 8.00-$17.00

$10.25-$25.20
$12.70-$30.45

$29.00

$36.00
                      Total Annual Costs
                       for the industry a/
                     (millions of dollars)
N.A.

600
400
N.A.

1,380
865

1,360

1,680
a/  Total annual costs refer to annualized costs that capture capital,
operation, and maintenance expenses.  Since these costs were calculated by
assuming that the utility industry would have to construct new facilities to
comply with hypothetical alternative regulations, these costs are in-addition
to the current management costs incurred by the industry.

  Source:  Envirosphere Company, "Report on the Costs of Utility Ash and FGD
Waste Disposal."  In USWAG, Report and Technical Studies on the Disposal and
Utilization of Fossil-Fuel Combustion By-Products. October 19, 1982.

-------
Preparation of Part B Permit
Construction of New Disposal
Facilities
    Landfills
     - Single clay liner
     - Single synthetic liner
    Surface Impoundments
     - Single clay liner
     - Single synthetic liner
     - Double liner
         - clay/synthetic
         - two synthetic

Closure of Existing Disposal
Facilities
    Only Unlined Facilities Close
     - Clay cap
     - Synthetic cap
    All Facilities Close
     - Clay cap
     - Synthetic cap

Installation of Leachate
Collection Systems

Provisions for Flood Protection
    Landfills
    Impoundments

Ground-water Monitoring Systems

Excavate Existing Facilities,
Removing Waste to Subtitle C Facilities
 2.6

 9.5
 5.8

11.6
 9.3
 3.5
 9.7

 4.3
12.0
 1.2
 0.15
 0.09

 0.009-0.013
1028.0 a/
14Uu
 850

1700
1400
 575
1500

 700
1800
 460
  20
  13

 6-9
  NA
    a/ Costs shown are for capital, operation, and maintenance costs for the
entire industry since the amount of capital required was not readily available.

-------
                                      6-30
    A combination of compliance alternatives could occur (e.g., closing




existing disposal facilities and constructing new facilities with leachate




collection and ground-water monitoring systems).   The actual cost to the




electric utility industry for complying with RCRA Subtitle C requirements would




depend on the regulatory actions taken by the Agency if the temporary exemption




under Section 3001 of RCRA is removed.  Three possible regulatory scenarios are




discussed in the following section.








6.2.3  Potential Costs to the Industry of RCRA Subtitle C Waste Management








    Section 6.2.2 presented cost estimates for individual regulatory




requirements that could be imposed on utilities if EPA determines that Subtitle




C regulation is warranted for coal combustion wastes.  In this section, three




possible regulatory scenarios are examined to quantify the range of incremental




costs that could result from various regulatory options.  In the first scenario,




the incremental costs of regulating a portion of low volume wastes under




Subtitle C are presented.  The second scenario assumes that all coal combustion




waste would be subject to Subtitle C requirements.  The third scenario assumes




that high volume coal combustion wastes would be  tested for RCRA hazardous




characteristics and that a small portion of the waste would be classified as




Subtitle C characteristic waste.  For all three regulatory scenarios,  costs are




shown only for bringing all existing power plants into compliance with the




assumed RCRA Subtitle C management regulations.

-------
                                      6-31
    Low Volune Waste Scenario







    This scenario evaluates the costs to the utility industry if some low volume



waste streams are classified as hazardous wastes under Subtitle C.  As discussed



in Chapter Three, some of these wastes can exhibit hazardous characteristics



such as corrosivity.  The information available to EPA at this time does not



permit the Agency to quantify the amount of low volume wastes that may exhibit



hazardous characteristics.  In this scenario, EPA has assumed that all



water-side boiler cleaning wastes are regulated as hazardous wastes since these



waste streams may exhibit corrosive characteristics.  These waste



streams are assumed to be hazardous to provide an approximate estimate of the



costs to the industry if some low volume wastes display RCRA hazardous



characteristics.  That is, both high-volume and low-volume wastes could be



tested for RCRA hazardous characteristics,  but only a small portion of the



low-volume wastes (as represented by all water-side boiler cleaning wastes)



would need to be treated as hazardous.







    As shown in Exhibit 3-19, a representative power plant generates about



180,000 gallons per year of water-side boiler cleaning wastes.  The cost to



dispose of these wastes as hazardous liquids can vary depending on waste stream



variability, regional differences in disposal costs, and quantity to be


                              39
disposed, among other factors.    For purposes of this analysis, an incremental



cost of $2 per gallon (including transportation) has been assumed based on a


                                                 40
1985 survey of hazardous waste management prices.    With 180,000 gallons



generated per year at a representative power plant, annual disposal costs would



be about $360,000 per power plant.  Since there are 514 power plants in the



U.S., annual disposal costs to the utility industry would be about $185 million.

-------
                                      6-32
    Full Subtitle G Regulation Scenario









    If EPA lists high volume coal combustion waste streams in 40 CFR




261.31-261.33, all utilities will be affected.  Utilities would be required to




manage all coal combustion wastes in Subtitle C permitted facilities.  To




estimate the incremental costs to the industry of this regulatory scenario, the




Agency assumed that all utilities would close existing facilities and open new




waste management facilities that complied with Subtitle C standards.  This




scenario assumes that the costs of managing wastes off-site will equal the costs




of managing wastes on-site and that existing facilities would be closed in the




six months before Subtitle C regulation took effect, thereby avoiding Subtitle C




closure and post-closure requirements.








    Under existing state regulations, a clay cap is assumed to be adequate to




close existing waste management facilities.  The total annual costs of closing




all existing facilities with a clay cap would be $700 million.  For the new




facilities, EPA assumed utilities would prepare a Part B permit application,




construct new landfills and surface impoundments with clay/synthetic double




liners, install leachate collection systems, make provisions for flood




protection, and install ground-water monitoring systems.  To determine




incremental costs for the industry, EPA assumed that the current proportions of




waste management facilities that were landfills and surface impoundments would




remain unchanged under Subtitle C regulation.   As summarized in Exhibit 6-7,




total annual costs of the new Subtitle C facilities would be $54 million for




Part B permit applications, $725 million for new double lined landfills,   $1700




million for new double lined surface impoundments, $460 million for leachate

-------
                                      6-33
collection systems, $33 million for flood protection, and $9 million for



ground-water monitoring.  Total incremental costs for this regulatory scenario


                               42
would be $3.7 billion annually.
    High Volune Characteristic Waste Scenario







    If coal combustion wastes were not exempt from RCRA Subtitle C regulation,



utilities would have to test high-volume and low-volume coal combustion wastes



for RCRA hazardous characteristics.  Based on the RCRA characteristic results



in Chapter Five,  it appears that only a small portion of coal combustion wastes



possess the hazardous characteristics of EP Toxicity or corrosivity.   For



purposes of this scenario,  the Agency assumed that five percent of the wastes



generated by utilities would need to be disposed in Subtitle C permitted



facilities.  The Agency does not have sufficient information to know exactly the



amount of coal combustion waste that would exhibit RCRA hazardous
                                                                             i


characteristics.   EPA believes that coal combustion wastes generally would not



fail the RCRA hazardous characteristic tests.  Based on limited information



presented in Chapter Five that indicate about five percent of all ground-water



observations at utility sites exceed the Primary Drinking Water Standards, the



Agency assumed that five percent of all wastes would require Subtitle C



treatment.  The total annual cost to the industry if utilities close existing



facilities and construct new double lined facilities for five percent of all



coal combustion wastes would be $185 million.
6.3  IMPACT OF REGDIATORY ALTERNATIVES ON UTILIZATION OF COAL

     COMBUSTION WASTES
    As discussed in Chapter Four,  coal-fired utility wastes have been used in a

-------
                                      6-34
variety of applications by electric utilities and other industries to replace



other types of material.  The use of utility wastes as a replacement for other



materials has reduced the amount of wastes utilities have had to dispose, while



correspondingly reducing the resource requirements of other industries that have



managed to find a productive use for the waste material.







    In the event that some or all of these wastes were declared hazardous, it is



possible that the amount of by-product utilization of coal-fired utility wastes



would decline as a result of increased costs for their use and the potential for



outright prohibition of their use in some applications.  On the other hand, it



is possible that certain forms of utilization (e.g., the use of fly ash in



cement) may be deemed environmentally acceptable practices if the wastes would



be unlikely to pose an environmental threat when used for such purposes.  Since



costs for other forms of disposal may increase, utilization may also increase.



However, for discussion purposes, this section assumes that designation as a



hazardous waste would tend to discourage by-product utilization.







    The costs that would be incurred as a result of environmental concerns over



the utilization of coal-fired utility wastes would depend on the regulatory



requirements that would have to be followed to use the wastes.   The more



stringent the additional regulatory burden imposed, the greater the impact on



by-product utilization due to the higher costs of using the wastes.







    In the USWAG study referenced above, the potential range of costs associated



with reduced use of coal combustion by-products was also evaluated.  Three


                                             43
different regulatory scenarios were analyzed.

-------
                                      6-35
    •   The transportation of coal-fired utility wastes is
        regulated as hazardous waste transportation under Subtitle
        C of RCRA; use or disposal of the wastes would not be
        regulated.

    •   All activities associated with reuse of coal combustion
        by-products is regulated, and the regulations affect both
        the transporter and owner/operator of a Subtitle C
        hazardous waste management facility.

    •   Reuse of coal combustion by-products is prohibited.
    There would be three types of costs incurred under these regulatory

scenarios:  (1) replacement costs to the end-users who would no longer find

it economic to utilize the coal combustion by-products, (2) costs to

utilities to dispose of wastes no longer reused by other industries, and

(3) additional costs to the utility industry for replacement and disposal

of wastes that could no longer be used on-site.  A summary of the costs

                                                         44
associated with each scenario is provided in Exhibit 6-8.



    If the transportation of coal combustion by-products were subject to

increased regulation under Subtitle C, the USWAG report estimated that the

use of these by-products would decline by nearly 40 percent, increasing

                                            45
overall disposal volumes by about 8 percent.    The industries that would

be affected the most would be the roofing granules industry (conventional

roofing granules would replace bottom ash and boiler slag at a cost of

about $115 million in annual costs) and the concrete industry (portland

cement would replace fly ash at a cost of about $40 million in annual

   «- N 46
costs).



    If all activities pertaining to reuse of coal combustion wastes were

subject to Subtitle C regulations, utilization of coal combustion

-------
                                         6-36
                                   EXHIBIT 6-8
             Summary of Economic Impacts on By-Product
       Utilization under Different RCRA Regulatory Scenarios*
         Cost
      (106 dollars)
                  2700
                  2400
                  2100
                  1800
                  1500
                  1200
                  900
                  600
                  300
                           Utility Costs—Changes in
                                     On-Site Practices
Utility Costs—Disposal of Wastes
          no Longer Reused
Replacement Costs to End-Users
                            Reuse
                        Transportation
                          Regulated
               All Reuse
               Activities
               Regulated
  Reuse
Prohibited
                    *A11 costs are annualized based on impacts estimated from 1984-2000.
         Source: USWAG, Report and Technical Studies on the Disposal and Utilization of Fossil-Fuel
               Combustion Bv-Products. Appendix G, October 26, 1982
6/87

-------
                                      6-37
by-products was estimated to decline by about 75 percent, increasing


                                             47
overall disposal volumes by about 14 percent.    The greatest impact would



be on the concrete industry, which would spend about $270 million annually



to replace fly ash with portland cement.
    If all reuse of coal combustion by-products were prohibited,  industries



using these by-products would have to find suitable replacements;  total


                                                     49
disposal volumes would increase by nearly 20 percent.    The largest



impacts would be on the asphalt industry, which would be forced to replace



ash with asphalt at a cost of approximately $250 million annually, and the



concrete industry, which would replace fly ash with portland cement at a



cost of about $270 million annually.
6.4  ECONOMIC IMPACTS OF ALTERNATIVE HASTE DISPOSAL OPTIONS








    Since many alternative disposal practices discussed in this chapter



could impose additional costs on the electric utility industry, this



section evaluates the effect that these increased costs might have on



electricity generation costs and U.S. coal consumption.  This study employs



three measures to determine the potential economic impact of alternative



disposal practices:
    1.   Average increase in electricity generation costs at existing

        coal-fired power plants,
    2.   Average increase in electricity generation costs at coal-fired

        power plants yet to be constructed,  and
    3.   Impact on the electric utility industry's consumption of coal.

-------
                                      6-38
    Exhibit 6-9 summarizes the cost of generating electricity at both existing



and yet-to-be-constructed power plants (see Appendix G for a detailed discussion



of the assumptions used to determine these generation costs).     Disposal costs



average about 3-5 percent of total generation costs at existing coal-fired power



plants, but only about 1-3 percent at future power plants.  Although the actual



costs of disposal at existing and future power plants are similar, the



percentages are different because total generation costs at future power plants



are higher than generation costs at existing power plants (resulting in a lower



overall percentage for disposal costs at future power plants).  Total generation



costs are higher at future power plants because they include capital, operation



and maintenance, and fuel costs, while the generation costs for existing power


                                                             52
plants include operation and maintenance and fuel costs only.



Based on the cost assumptions used to develop Exhibit 6-9, coal-fired


                                                      53
electricity generation at both new and future baseload   power plants is less


                                           54
expensive than generation with natural gas.
    The economic impacts likely to result from the use of alternative coal-fired



utility waste disposal practices will depend upon several factors, including



which disposal options are required, how much the cost of coal-fired electricity



generation changes,  and whether these changes affect the relative



competitiveness between coal and other fuels.  To indicate the potential



magnitude of these impacts, Exhibit 6-10 summarizes the potential cost impacts



on electricity generation rates due to the alternative waste disposal options



discussed earlier in this chapter.







    As indicated in Exhibit 6-10, some alternative disposal options could

-------
                                                6-39
                                           EXHIBIT 6-9


                            IMPACT OF CURRENT WASTE  DISPOSAL COSTS
                            ON TOTAL ELECTRICITY GENERATION COSTS*
               60
               50
               40-
 Generation    30
    Costs
(Mills Per
Kilowatt-Hour)
20-
               10-

                       Coal
                 Gas
 Low
Sulfur
 Coal
 High
Sulfur
 Coal
Gas
                    Existing Power Plant
                                      Future Power Plant
                 !HHi  Disposal Cost
                       Fuel


                       Operation and Maintenance


                       Capital
                                       * Generation costs are based on typical 500 Mw
                                         power plant in the midwest operating at 70
                                         percent utilization rate.  Regional costs will vary
                                         depending on fuel price and availability, among
                                         other factors.
Source:   Generation cost estimates are from ICF Incorporated. Waste disposal costs are taken from
          Arthur D. Little, Inc., Full-Scale Field Evaluation of Waste Disposal From Coal-Fired
          Electric Generating Plants.  June 1985.

-------
                                              6-40
                                           Btninn £-10
IMPACT OF ALTEBUIIVE DISPOSAL (UTIUCi OH KLH.THIUTX
Impact On


Option
Fart B Permit
Existing Landfills b/
Single Clay Liner
Single Synthetic Liner
Incremental Cost
($/ton of
disposed waste)
$0.55

$0.70-$2.55
$1.45-$4.15

a/
mills/lcilowatt-hour
0.03

0.04-0.16
0.09-0.26
GEnuATIjOiI (XJfriTK
Generation Costs

X of Total Generation Costa
Existing Plant Future Plant
0.2 0.1

0.2-0.9 0.1-0.3
0.5-1.4 0.2-0.6
Existing Surface Impoundments
Single Clay Liner
Single Synthetic Liner
Hew Landfills
Single Clay Liner
Single Synthetic Liner
New Surface Impoundments
Single Clay Liner
Single Synthetic Liner
Double Synthetic Liner
Double Synthetic/
Clay Liner
Site Closure
Leachate Control
Flood Protection
Ground-water Monitoring
Utilization
Transportation
Regulated
All Activities
Regulated
Reuse Prohibited
$2.2S-$8.20
$4.70-$13.45

$ 5.70-S12.55
$ 6.45-S15.15

$10.25-$25.20
$12.70-$30.45
$29.00

$36.00
$2.10-$14.75
$4.70
$0.25-$0.55
$0.06-$0.10


$3.00

$13.20
$18.75
0.14-0.51
0.30-0.84

0.36-0.79
0.40-0.95

0.64-1.58
0.80-1.91
1.82

2.26
0.13-0.93
0.30
0.02-0.03
0.004-0.006


0.19

0.83
1.18
0.8-2.8 0.3-1.1
1.7-4.7 0.6-1.8

2.0-4.4 0.8-1.7
2.2-5.3 0.9-2.0

3.6-8.8 1.4-3.4
4.4-10.6 1.7-4.1
10.1 3.9

12.6 4.8
0.7-5.2 0.3-2.0
1.7 0.6
0.1-0.2 c/
£/ £/


1.1 0.4

4.6 • 1.8
6.6 2.5
a/  Based on a representative 500 Mw plant  operating  at  a  70 percent utilization rate.  Costs are
    incremental costs only;  that is,  cost impact of new  disposal facilities is only that portion of
    costs in excess of current disposal costs  (see Exhibit 6-4 for these costs).  A mill is
    one-tenth of a cent ($0.001).

b/  Costs for existing waste disposal facilities refer only to the cost of liner installation.
    Costs for new waste disposal facilities refer to  all the costs for site construction and liner
    installation.

£/  Less than 0.1 percent.

-------
                                      6-41
increase electricity generation costs at existing power plants by several




percent.  In some cases the cost impact could be substantial if several options




were combined as part of an integrated waste management strategy.  For example,




if new waste management regulations led to closure of the current disposal site




and the construction of a new lined facility with a leachate control system,




flood protection, and ground-water monitoring system, coal-fired generation




costs at existing coal-fired power plants could increase by nearly 20 percent




(roughly 3.5 mills/kilowatt-hour).








    Generation cost increases of this magnitude have the potential to reduce




coal consumption at existing coal-fired power plants if these cost increases




make it more expensive to generate electricity with coal than with other fuels.




A utility decides how much electricity to generate at any existing power plant




primarily by comparing the operation and maintenance costs (including fuel)




associated with generating electricity at all of its power plants.  Power plants




with the lowest generation costs will be operated first.  Generally, it is less




expensive to generate electricity with coal than with other fuels such as oil or




gas, but oil-fired electricity generation can be competitive with coal when the




price of oil is approximately $10-$15 per barrel.    However, whether and to




what degree electric utilities would shift away from the use of coal would




depend on several factors,  including the relative price of coal compared with




the price of other fuels, the magnitude of the increase in generation costs if




disposal practices were altered, and the overall efficiency of competing power




plants.








    For power plants yet to be constructed, the impact of higher disposal costs




on coal consumption could be more substantial, with possible generation cost

-------
                                      6-42
increases approaching 8-10 percent if several options are combined.  Generation




cost increases of this magnitude could have a substantial effect on the amount




of coal consumed at future power plants since many utilities may decide not to




build coal-fired power plants.  Although currently coal-fired electricity




generation may be a more economic option than oil-fired or gas-fired generation




at plants yet to be constructed, this situation could change if more expensive




disposal practices were required for coal combustion wastes.  This is because




the higher capital costs of coal-fired electricity generation, compared with




oil- or gas-fired generation, reduces the overall cost differential between the




use of coal and the use of oil or gas at future power plants (compared to the




cost differential between coal and oil or gas at existing power plants).  As a




result, coal is more likely to be replaced by alternative fuels at future power




plants than it is at existing power plants.








    In fact, since oil prices dropped below $20 per barrel in early 1986, many




utilities have been seriously evaluating the feasibility of building oil- or




gas-fired generating capacity in lieu of coal-fired units.  As a result, in some




instances even an increase of a few percent in coal-fired generation costs could




be sufficient to tip the balance in favor of using natural gas or oil to fuel




power plants that have not yet been constructed.  If increased disposal costs do




promote such competition, growth in future U.S. consumption of coal would




probably decline.  The exact magnitude of this decrease in future coal




consumption would depend on many factors,  including the type of new waste




disposal practices adopted and the price of alternative fuels in different




regions of the country.   An in-depth analysis of the potential impact of




alternative waste management scenarios on electric utility generation practices




and investment decisions and, as a result, the level of coal consumption, is

-------
                                      6-43
beyond the scope of this Report to Congress.  However, EPA intends to seek more

information and analysis on the issue of economic impacts through the public

hearing process and through its own additional investigations.  As required by

law EPA will conduct the appropriate regulatory impact analyses, including the

economic impact analysis, during the six month public review period following

submission of this report to Congress if it is determined that current utility

waste management practices for coal-fired combustion wastes are inadequate and

additional regulations are warranted.



6.5  SUMMARY



    The cost to manage coal combustion waste in basic waste management

facilities currently ranges from as little as $2 to as much as $31 per ton.  The

wide range in management costs is primarily due to differences in (1) the type

of facility, (2) the size of the facility and (3) the characteristics of the

waste.
    •   Some facilities currently incur additional costs because
        they have undertaken additional safeguards against
        leaching, including liner installation, leachate collection
        and treatment, and ground-water monitoring.

    •   Management costs at surface impoundments tend to be greater
        than those at landfills because of the higher costs of site
        preparation at impoundments.

    •   The size of larger waste disposal facilities allows them to
        operate more efficiently, which tends to reduce the cost
        per ton of waste management.

    •   Fly ash is typically more expensive to manage than bottom
        ash or FGD waste because of additional requirements for
        collection, handling, and treatment prior to disposal.

-------
                              6-44
If additional regulations are promulgated requiring
electric utilities to alter the current methods by which
they manage coal-fired wastes, additional costs may be
incurred by the industry as it complies with the new
requirements.

The most common practice for controlling leaching at a
waste management site is installation of a liner prior to
placement of the waste.  Liners are usually made of low
permeable clay or a synthetic material and can be installed
in one or more layers.  The cost of installing a liner
ranges from $0.70 to $8.20 per ton of waste for clay liners
and $1.45 to $13.45 per ton for synthetic liners.  Total
disposal costs for single-lined landfills range from about
$6 to $15 per ton of waste, while costs for single-lined
surface impoundments range from $10 to $30 per ton.
Industry-wide costs to construct and install lined
management facilities could range from $0.4 to $1.7 billion
on an annualized basis, depending on type of facility, type
of liner material, and number of liners installed.

Installation of leachate collection systems to control
potential environmental problems that might result from
substances leaching from a waste management site could cost
about $4 to $5 per ton of waste.  Total costs to the
utility industry to install leachate collection systems
could be $1.2 billion in capital costs, or about $460
million in annualized costs.

The cost of installing a ground-water monitoring system to
detect the presence and concentration of various waste
constituents in the ground water surrounding a waste
management facility is generally less than $0.25 per ton of
waste.  Total capital requirements to the industry would
likely range from $9 to $13 million, with annual costs of
$6 to $9 million.

If-coal combustion wastes were regulated under Subtitle C
of RCRA, costs to the utility industry could approach $3.7
billion annually if all wastes were listed as hazardous.
Costs would be substantially lower than $3.7 billion
annually if coal combustion wastes were tested for
hazardous characteristics since only a small portion of
coal combustion wastes would be likely to fail the RCRA
hazardous characteristic tests.  These costs to comply with
Subtitle C do not include corrective action costs or the
higher costs that may be associated with recycling coal
combustion wastes; these costs to the utility industry
could be very high.

-------
                              6-45
New waste management practices could increase the cost of
generating electricity at existing coal-fired power plants
by nearly 20 percent in some cases.  Although coal is
generally the preferred boiler fuel at existing power
plants, an increase of this magnitude could cause a decline
in the amount of coal consumed at these power plants if
alternative fuel prices were reasonably competitive.

If new management practices are required at future power
plants, the increase in generation costs is unlikely to
exceed 10 percent.  Although on a percentage basis this
increase would be less than the percentage increase
possible at existing power plants, the choice of fuels at
future power plants is much more competitive (due to the
capital costs that must be included in the costs of a
future power plant).  In some instances this could lead to
a decrease in coal consumption if the use of alternative
fuels is found to be more cost effective since many
utilities may decide not to build coal-fired power plants.

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                                       -2-
    ^  In one study, the cost of building and operating an artificial reef
construction system was estimated to be about $50 per ton, roughly double the
amount estimated by the study authors for more conventional waste disposal.  In
those situations where space constraints or other factors would substantially
increase the costs for conventional disposal, ocean disposal through reef
construction was seen as an economically viable option.  See J.H. Parker,
P.M.J. Woodhead, and I.W. Dued all, "A Constructive Disposal Option for Coal
Wastes - - Artificial Reefs," in Proceedings of the Second Conference on
Management of Municipal. Hazardous, and Coal Wastes. S. Sengupta (Ed.),
September 1984, p. 134.

    8  Arthur D. Little, p.  6-132.  "Installed cost" of a liner (expressed in
terms of cost per ton of disposed waste) refers to the increase in the cost of
disposing of one ton of waste as a result of adding a liner to an unlined
landfill or surface impoundment.

    ^  Ibid.  The costs in the Arthur D. Little report were presented for an
18-inch clay liner.  Costs were doubled to approximate the costs for installing
a 36-inch clay liner, which is currently a more common practice.  The dollar
per ton estimate was derived by multiplying total capital costs by a 14.5
percent capital recovery factor to determine annual capital charges.  Assuming
that a 500 Mw power plant has a 45 acre landfill disposal site, total capital
charges would range from $945,000 to $3.4 million, or about $140,000 to
$490,000 in annualized charges.  Assuming that a 500 Mw power plant would need
a 145-acre wet surface impoundment, total costs would range from $3.0 to $10.9
million, or $440,000 to $1.6 million in annualized costs.  These annualized
charges were then divided by the amount of waste produced annually by a 500 Mw
power plant with no FGD process, (i.e., 192,500 tons) to determine the dollar
per ton cost.  This approach is used throughout the report to calculate dollar
per ton estimates.  See Appendix G for more detail on this methodology.

        Ibid.  For landfills, total installed costs would range from $1.9 to
$5.1 million per plant, assuming a 45-acre disposal site.  Annual costs would
range from about $280,000 to $740,000.  Based on 192,500 tons of waste, the
cost is $1.45-$3.85 per ton.  For ponds (i.e., impoundments), total installed
costs would be $6.2-$16.4 million, or $900,000-$2.4 million annualized.  On a
dollar per ton basis, this range is $4.70-$12.35.

        Ibid.  For landfills total installed costs would range from $2.7-$5.5
million, or about $385,000-$800,000 in annual costs per ton.  This corresponds
to $2.00-$4.15 per ton.  Total installed costs for ponding operations are
$8.6-$17.8 million, or $1.2-$2.6 million annualized.  This corresponds to
$6.45-$13.45 per ton.

    12  Ibid.

        Total capital costs for landfills of $3.0 to $5.0 million correspond
to annual charges of about $430,000 to $720,000.  Assuming 192,500 tons of
waste, the per ton cost is $2.25 to $3.75.  Using the same approach to derive
disposal costs at a 145-acre lined impoundment yields $7.20 to $12.00 per ton.

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                                       -3-
    14
        A waste management unit is not subject to regulation under Section
264.1 if the Regional Administrator finds that the unit (1) is an engineered
structure, (2) does not receive or contain liquid waste or waste containing
free liquids, (3) was designed and is operated in such a way to exclude
liquids, precipitation, and other run-on and run-off (4) has both inner and
outer layers of containment enclosing the waste, (5) has a leak detection
system built into each containment layer, (6) will have continuing operation
and maintenance of these leak detection systems during its active life and
throughout the closure and post-closure care periods, and (7) is constructed in
such a way that, to a reasonable degree of certainty, hazardous constituents
will not migrate beyond the outer containment layer prior to the end of the
post-closure care period.  (40 CFR 264.90(b)(vii).

    15  See 40 CFR 246.143.

        These specified wastes are liquid hazardous wastes that have a pH less
than or equal to 2.0 and/or (1) free cyanides at concentrations greater than or
equal to 1,000 mg/1, (2) arsenic and/or arsenical compounds at concentrations
greater than or equal to 500 mg/1, (3) cadmium and/or cadmium compounds at
concentrations greater than or equal to 100 mg/1, (4) chromium and/or chromium
compounds at concentrations greater than or equal to 500 mg/1 (5) lead and/or
lead compounds at concentrations greater than or equal to 500 mg/1, (6) nickel
and/or nickel compounds at concentrations greater than or equal to 134 mg/1,
(7) mercury and/or mercury compounds at concentrations greater than or equal to
20 mg/1, (8) selenium and/or selenium compounds at concentrations greater than
or equal to 100 mg/1, (9) thallium and/or thallium compounds at concentrations
greater than or equal to 130 mg/1, (10) polychlorinated biphenyls at
concentrations greater than or equal to 50 mg/1, (11) halogenated organic
compounds at concentrations greater than or equal to 1,000 mg/kg.

        Envirosphere Company,  "Report on the Costs of Utility Ash and FGD Waste
Disposal", in USWAG,  Report and Technical Studies on the Disposal and
Utilization of Fossil-Fuel Combustion Bv-Products.  October 19, 1982, p. 21,
Appendix F, part 2.  Dollar per ton estimates were determined by calculating
annual costs ($721,000 x 14.5 percent capital recovery factor - $104,500).  The
capital recovery factor was applied to all costs since a breakdown of different
types of costs required for a Part B permit was not available.

    18  Ibid, p. 18.

    19
        Assuming a 145-acre impoundment site, costs would be about $107,000.
On a per ton basis, this corresponds to about $0.55.  For a 45-acre landfill
with costs of $1100 per acre,  total costs would be about $50,000, for a per ton
cost of $0.25.
    20
        Envirosphere, in USWAG, Appendix F,  Part 2,  p.  27, 32.

    21
        Arthur D. Little, p.  6-133.  On an annualized basis, capital costs
would range from about $2,650 to $3,550.

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                                      -4-
    22
        Envirosphere Company, in USWAG, Appendix F, Part 2, p. 37.
Envirosphere estimated that about four wells, one upgradient from the site and
three downgradient, would be required for each 100 acre disposal site (or about
six wells for a site of 145 acres) at a capital cost of approximately $6,000
per well.  Total capital costs for six wells would be $36,000, which is about
$5,200 on an annualized basis.  It was assumed that the wells would be sampled
quarterly the first year, then semi-annually thereafter.  The operation
and maintenance costs would average about $2,500 to $3,000 per well, for
facility costs (assuming six wells) of $15,000 to $18,000 per year.  Total
annualized costs, therefore, would range from $20,200 to $23,200, or $0.10 to
$0.12 per ton of waste disposed.
    23
        For a more complete discussion, see ICF Incorporated, Liner Location
Risk and Cost Analysis Model. Draft Phase II Report, Appendix F-2, Office of
Solid Waste, U.S. Environmental Protection Agency, March 1987.

        The cost equation on which this cost estimate is based was developed
for typical RCRA Subtitle C landfills.  Since these facilities tend to be much
smaller than the size of utility disposal areas, extrapolating the cost
equation for larger sizes may introduce some errors.  Nevertheless, these cost
estimates do indicate the approximate magnitude of corrective action costs that
would likely be incurred.

    25
        Econometric Research, "The Economic Costs of Potential RCRA Regulations
Applied to Existing Coal-Fired Electric Utility Boilers," in USWAG, Report and
Technical Studies on the Disposal and Utilization of Fossil-Fuel Combustion
Bv-Products. October 26, 1982, p. 15, Appendix F, part 1.

    26  Ibid, p.  15.
    27
        Ibid, p.  18.  On a per acre basis, total annual costs range from $6,700
to $19,600 for surface impoundments and $9,000 to $21,000 for landfills.  For a
145-acre impoundment, this corresponds to $1.0 to $2.8 million in total annual
costs, or $5.00 to $14.75 per ton of waste.  For landfills the per ton cost
would be $2.10 to $4.90 based on total annual costs of $0.4 to $0.9 million.

    28
        See Administrative Procedure Act, U.S. Code 5 Sec. part 551.

    29
        Ibid, see pages 26 and 31 of the Econometric report for all closure
costs.
    30
        For further discussion of the potential magnitude of these costs, see
ICF Incorporated, Flexible Regulatory and Enforcement Policies for Corrective
Action, prepared for U.S. Environmental Protection Agency, September 12, 1985.

        Econometric Research, in USWAG, Appendix F, Part 1, p. 15.  Econometric
Research used capital costs for disposal of about $5.20 per ton of waste
produced over a 20-year life of the facility for synthetic liners and about
$8.10 per ton for clay liners, plus about $0.06 per ton per year for operation
and maintenance costs.  Total initial capital outlays would then be $104 per
ton ($5.20 per ton times 20 years) for synthetic liners, or about $15.08 per
ton on an annualized basis, and $162 per ton ($8.10 per ton times 20 years) for
clay liners, or $23.49 per ton on an annualized basis.  With the addition of

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                                      -5-
the $0.06 per ton for operation and maintenance costs,  total costs would range
from $15.14 per ton for synthetic liners and $23.55 per ton for clay liners for
each ton of waste produced annually.

    32
        Ibid..  p. 27.  Total capital costs for existing power plants were
assumed to be $2.1 billion for single synthetic liners and $3.2 billion for
single clay liners.  Since these cost estimates were based on a universe of 412
power plants, costs were adjusted upward by 514/412 to approximate total
industry costs for the number of power plants estimated at the time of this
study -- 514 power plants.  This adjustment was made for all industry-wide
costs cited from the USWAG report.

    33  Ibid..  p. 32.

    34
        Ibid..  p. 18.  Econometric Research, Inc., calculated that disposal
costs for an impoundment with a single synthetic liner were about $0.95 per ton
of waste over the life of the facility and about $1.50 per ton of waste for
clay-lined impoundments.  For a plant generating 192,500 tons each year for 20
years (or 3.85 million tons), that corresponds to 3.85 million tons x $0.95 per
ton - $3.7 million for an impoundment with a single synthetic liner (or about
$19 per ton based on $3.7 million divided by 192,500 tons of waste annually)
and 3.85 million tons x $1.50 per ton - $5.8 million for an impoundment with a
single clay liner (or about $30 for each ton of waste disposed in a year).

        Ibid, p. 26.  The costs in the USWAG report were adjusted by 514/412 to
account for the 514 power plants estimated at the time of this study compared
to the 412 power plants assumed in the USWAG report.
    37
        Ibid, p. 18.  The double synthetic liner disposal system averages about
$1.45 per ton over the life of the facility and a system with one synthetic
liner and one clay liner costs about $1.80 per ton.  At 3.85 million tons of
waste over a 20 year facility life, that is $5.6 million for a double synthetic
liner (or about $29 for each ton disposed in a year).   For a combination
synthetic/clay liner system, 3.85 million tons x $1.80 per ton - $6.9 million
(or about $36 per ton).
    39
        ICF Incorporated, 1985 Survey of Selected Firms In The Commercial
Hazardous Waste Management Industry.  Prepared for U.S. Environmental Protection
Agency, November 6, 1986.

    40  TWH
        Ibid.

    41
        To develop a cost estimate for landfills constructed with clay/
synthetic double liners, the ratio of the cost of single clay and synthetic
liners at landfills in Exhibit 6-7 to the cost of single clay and synthetic
liners at surface impoundments was multiplied by the cost of clay/synthetic
liners at surface impoundments.

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                                      -6-
    42
        The costs to close and cap existing facilities have been included in
this estimate, while corrective action costs have not been included.  Although
closure costs will be incurred eventually by the industry, in most cases they
would not be incurred for many years to come.  To be conservative, EPA has
included closure costs as part of potential RCRA Subtitle C compliance costs.

    43
        Envirosphere Company, "Economic Analysis of Impact of RCRA On Coal
Combustion By-Products Utilization."  In USWAG, Report and Technical Studies On
the Disposal and Utilization of Fossil-Fuel Combustion By-Products. October 26,
1982, Appendix G.
    44
        Envirosphere Company, in USWAG, Appendix G.  The costs in Exhibit 6-8
are based on estimated impacts between 1984 and 2000 and adjusted by a capital
recovery factor of 14.5 percent to annualize the costs (total capital
requirements were not identified).  It was estimated that about 203 million
tons of coal combustion by-products would be used over this period, with a
similar amount used on-site by the utilities.  That is, the costs assume that
the amount of by-products utilized would have increased over time.

    45
        Ibid.. p. 89.  Total ash generation in 2000 was assumed to be 169.5
million tons, with about 27.3 million tons utilized and therefore, 142.2
million tons destined for disposal areas.  Utilization was estimated to decline
about 11.5 million tons, so the total amount of waste to be disposed would
increase to 153.7 million tons.

    46  Ibid.

    47
        Ibid.. p. 91.  Total utilization was assumed to decline by about 20.3
million tons in 2000.  Therefore, the total amount of waste disposed would
increase from 142.2 million tons to 162.5 million tons.

    48  Ibid.

    49
        Total utilization was assumed to be 27.3 million tons in 2000, thereby
increasing total disposal volume from 142.2 million tons to 169.5 million tons.


        Envirosphere Company, in USWAG, Appendix G, p. 93.

        To estimate the potential impact of alternative disposal practices on
electricity generation costs, the first step was to calculate the approximate
portion of generation costs due to current basic disposal practices.  Current
basic disposal practices for coal-fired utility wastes were assumed to be
disposal in either an unlined pond or landfill, although other practices are
sometimes followed.  Generation costs for a typical coal- and gas-fired power
plant are shown to indicate the relative competitiveness of these two fuels
when current disposal practices for coal-fired utility wastes are followed.
See Appendix G for a detailed discussion of the assumptions used to determine
these generation costs.

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                                      -7-
    52
        Capital costs are not included in the cost estimates for existing power
plants because these are "sunk" costs, i.e., they have already been spent.  As
a result, the percentage impact on total generation costs at existing power
plants is larger because the cost base is smaller compared to future power
plants.

          Baseload refers to power plants that are operated as much as possible
to maximize the amount of electricity these plants can generate.  For this
analysis a.baseload power plant is assumed to operate 70 percent of the time.

    54
          The generation costs in Exhibit 6-9 are intended to be representative
of typical power plants.  However, the actual cost of generation and the
relative competitiveness between coal and gas depends on many factors,
including plant size, utilization rate, and delivered fuel cost.

        This price range is only intended to illustrate the approximate range
at which oil becomes competitive with coal at existing power plants.  The
actual level at which coal might begin to lose market share depends on many
factors, including relative price differentials, fuel availability, gas prices
vis-a-vis oil prices, types of power plants (i.e., overall plant efficiency),
etc.

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                                CHAPTER SEVEN




                       CONCLUSIONS AND RECOMMENDATIONS
    This chapter concludes the Environmental Protection Agency's Report to




Congress on fossil fuel combustion wastes.  Pursuant to the requirements of




Section 8002(n) of the Resource Conservation and Recovery Act (RCRA),  the




Report addresses the nature and volumes of coal combustion wastes, the




environmental and human health effects of the disposal of coal combustion




wastes, present disposal and utilization practices,  and the costs and economic




impacts of employing alternative disposal and utilization techniques.   A




statement of the scope of the report and a summary of the report's findings




are presented below, followed by the Agency's recommendations.








7.1  SCOPE OF REPORT








    As discussed in Chapter One, this Report to Congress covers the generation




of coal-fired combustion wastes by the electric utility industry.  Other




fossil fuel combustion wastes not discussed in this report include coal, oil




and gas combustion wastes from other industries and oil and gas combustion




wastes from electric utilities.  Overall, coal combustion by electric




utilities accounts for approximately 90 percent of all fossil fuel combustion




wastes that are produced.  Moreover, this percentage is likely to increase in




the future since coal consumption by the electric utility industry is  expected




to increase substantially while coal use by other sectors remains relatively




constant.  Electric utility coal consumption will grow as new coal-fired power

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                                     7-2






plants are constructed to meet increasing electricity requirements in the




United States.








7.2 SUMMARY OF REPORT








    The Agency's conclusions from the information presented in this report are




summarized under seven major groupings paralleling the organization of the




report: 1) Location and Characteristics of Coal-Fired Power Plants, 2) Waste




Quantities and Characteristics, 3) Waste Management Practices, 4) Potential




Hazardous Characteristics, 5) Evidence of Environmental Transport of




Potentially Hazardous Constituents, 6) Evidence of Damage, and 7) Potential




Costs of Regulation.








    7.2.1  Location and Characteristics of Coal-Fired Power Plants








    1.   There are about 500 power plant sites in the United States that




         consume coal to generate electricity.  Each power plant may be the




         location for more than one generating unit; at these 500 power plants




         there are nearly 1400 generating units.








    2.   The size of coal-fired power plants can vary greatly.  The size of a




         power plant is typically measured by the number of megawatts '(Mw) of




         generating capacity.  Coal-fired power plants can range in size from




         less than 50 Mw to larger than 3000 Mw.

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                                 7-3






3.   Coal-fired power plants are located throughout the United States.




     Coal is used to generate electricity in every EPA region; almost




     every state has some coal-fired generating capacity.








4.   More coal-fired power plants will be built as the demand for




     electricity increases.  Coal is a fuel often used by the electric




     utility industry to generate power.  This reliance on coal is




     unlikely to change for many years to come in the absence of greatly




     increased costs for coal-fired electricity.








5.   Coal-fired power plants are located in areas of widely-varying




     population density.  Some power plants are located in remote rural




     areas, whereas others are located in urban environments.  They are




     usually, although not always, located at least a couple of kilometers




     from major population concentrations.  In general they are located




     near a major body of surface water such as a lake, river, or stream.








7.2.2.  Waste Quantities and Characteristics








1.   The amount of wastes generated annually by coal-fired power plants is




     large by any standard.  About 84 million tons of high-volume wastes




     -- fly ash, bottom ash, boiler slag, and FGD sludge -- are generated




     annually.  The total amount of low-volume wastes generated from




     equipment maintenance and cleaning operations is not known precisely,




     but is also substantial.

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                                 7-4






2.   Quantities of waste produced will increase significantly as more




     electricity is generated by coal.  The amount of high-volume wastes




     produced annually could double by the year 2000.  In particular, the




     amount of FGD sludge produced will triple (to about 50 million tons)




     as newly-constructed power plants install FGD equipment to remove




     sulfur dioxide from the flue gases.








3.   Coal combustion wastes are a common by-product from the generation of




     electricity.   The noncombustible materials are present in the coal as




     a result of geologic processes and mining techniques.   Given current




     technologies  for generating electricity, wastes from coal combustion




     will continue to be produced in significant quantities.








4.   High-volume coal combustion wastes do contain elements that in




     sufficient concentrations can pose a potential danger to human health




     and the environment.  Most elements in coal are not hazardous.




     However, trace elements typically found in coal become concentrated




     as a result of the combustion process.   Certain elements known to




     pose health risks can be found in the wastes at hazardous levels.








5.   Although most low-volume wastes do not appear to be hazardous. there




     are some waste streams from cleaning that could potentially be




     hazardous.   The waste streams of most concern are water-side boiler




     cleaning solutions, which may be corrosive or toxic.  Because the




     amount and type of low-volume wastes produced can vary substantially




     from one power plant to the next, not as much is known about




     low-volume wastes compared to high-volume wastes.

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                                 7-5
7.2.3  Waste Managenent Practices









1.   Most coal combustion wastes are typically disposed in landfills or




     surface impoundments.  with recent trends toward increased reliance on




     landfills.   Although some disposal does occur off-site,  most wastes




     are disposed on-site;  it is likely that most power plants built in




     the future will dispose on-site in a landfill.








2.   Typical industry practice is to co-dispose low-volume wastes with




     high-volume wastes or. in some instances, to burn the low-volume




     wastes in the utility boiler.   There are many other types of waste




     management practices that are also used to alter the physical and




     chemical characteristics of low-volume wastes prior to disposal.




     These practices vary widely from plant to plant.  There are no




     reliable data sources that accurately describe the types of




     low-volume disposal practices used at each power plant.








3.   The potential for increased waste utilization as a solution to waste




     management in the utility industry appears to be limited.  About 21




     percent of all high-volume wastes are currently recycled; some




     opportunities appear to exist to increase utilization, but not in a




     major way.








4.   Coal combustion wastes are typically regulated under state solid




     waste laws, which treat these wastes as non-hazardous materials.  The

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                                 7-6






     extent of state regulation can vary significantly from one state to




     another.








5.   Many waste management practices applied to hazardous waste in other




     industries, such as liners, have only seen limited use for coal




     combustion waste management.  In recent years,  some of these




     practices, including liners and leachate collection systems, have




     become more common.  There is an increasing tendency to manage coal




     combustion wastes by disposing on-site (at the  power plant) in




     landfills.








6.   There are few major innovations under development that would lead to




     major changes in waste management practices.








7.2.4  Potential Hazardous Characteristics








1.   The RCRA hazardous characteristics of most concern are corrosivity




     and EP toxicitv.  Coal combustion wastes are generally not ignitable




     or reactive.








2.   Most waste streams would not be considered corrosive under RCRA




     definitions.  Only aqueous wastes, which most coal combustion wastes




     are not, are considered corrosive under RCRA.  There are some aqueous




     coal combustion waste streams that are very near corrosive levels,




     particularly low volume wastes such as boiler blowdown or coal pile




     runoff.  In some instances, boiler cleaning wastes may be corrosive,




     particularly those that are hydrochloric acid-based.

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                                 7-7
3.   Coal combustion wastes generally are not EP toxic, although there are




     some exceptions.  It is rare for coal combustion wastes to fail the




     EP test (or the TCLP test developed more recently) .   Extract




     concentrations in excess of 100 times the Primary Drinking Water




     Standards have been found only for the elements cadmium, chromium,




     and arsenic from some FGD sludges and coal ash samples, although




     these levels are quite rare -- average levels are substantially below




     100 times the PDWS.








4.   There are insufficient data to determine a priori which waste streams




     at a power plant will exhibit RCRA hazardous characteristics.




     Accurate determinations could only be made if site-specific analyses




     were conducted.
7.2.5  Evidence of Environnental Transport of Potentially




       Constituents .
1.   Migration of potentially hazardous constituents has occurred from




     coal combustion waste sites.  From the limited data available,




     exceedances of the Primary Drinking Water Standards have been




     observed in the ground water for several elements, including cadmium,




     chromium, lead, selenium, and arsenic.








2.   Ground-water contamination does not appear to be widespread.  Only a




     few percent of all ground-water quality observations indicate that a




     PDWS exceedance has occurred, although many utility waste management

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                                 7-8






     sites at which ground-water monitoring has been done have had at




     least one exceedance.  However, the observed contamination may not




     necessarily be chronic since sites at which exceedances have been




     noted do not consistently register in excess of the PDWS.








3.   When ground-water contamination does occur, the magnitude of the




     exceedance is generally not large.   Most PDWS exceedances tend to be




     no more than 10 or 20 times the PDWS, although a few observations




     greater than 100 times the PDWS have been noted.








4.   Human populations are generally not directly exposed to the




     groundwater in the vicinity of utility coal combustion waste




     management sites.  Public drinking water intakes are usually at least




     a few kilometers away.  Also,  most power plants are located near




     surface water bodies that dilute the concentration of any elements




     found in the ground water.








5.   Because high-volume and low-volume waste streams are often




     co-disposed, it cannot be determined if one specific waste stream was




     the source of contamination.








6.   The ground-water quality information on which this evidence is based




     is limited.  Data were only available from a small number of utility




     waste management sites; no comprehensive database on ground-water




     contamination potentially attributable to coal combustion wastes




     exists.

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                                 7-9






7.2.6  Evidence of Danage








1.   There are few cases considered to be documented evidence of




     from coal combustion wastes.  Among these cases there is some dispute




     whether any observed damage can be attributed to the utility waste




     management facility.








2.   Damage cases are dominated by chronic incidents (seepage, periodic




     runoff) as opposed to catastrophic incidents (sudden releases.




     spills).  although one documented damage case was due to structural




     failure of a surface impoundment.








3.   Documented damage typically involves physical or chemical degradation




     of ground water or surface water, including fish kills or reduction




     in biota, but seldom involves direct effects on human health because




     the water is not consumed for drinking water purposes.  Much of the1




     damage has occurred in the immediate vicinity of the waste management




     site; drinking water intakes are generally far enough away such that




     any contaminated water is not being directly used for human




     consumption.








7.2.7  Potential Costs of Regulation








1.   If additional regulations are promulgated for utility waste




     management, the total costs incurred by the industry could vary




     considerably depending on the extent of the additional regulations.

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                                    7-10




         For example,  total annual costs to install and operate ground-water


         monitoring systems would be unlikely to exceed $10 million.   On the
                                                                             >

         other hand,  total annual costs for the industry could approach $5


         billion if all existing facilities were capped and closed and new


         facilities were constructed with liners,  leachate collection systems,


         flood protection, and ground-water monitoring.  (Corrective  action


         costs, such as excavating all existing facilities for removal of the


         wastes to RCRA Subtitle C facilities,  are not included in this


         estimate; such costs would be extremely high.)






2.       Regulation of utility coal combustion wastes under full RCRA Subtitle


         C requirements could halt all recycling of coal combustion wastes if


         recycling was also subject to Subtitle C requirements.  Total costs


         to the industry could approach $2.4 billion annually.  If recycled


         wastes were not subject to Subtitle C disposal requirements, it is


         possible the amount of recycling could increase as the utility


         industry increased waste utilization to avoid full Subtitle  C


         disposal costs.






    3.   The costs to the utility industry for full RCRA Subtitle C compliance


         could decrease the amount of coal consumed in coal-fired power


         plants.   The costs of generating electricity with coal could increase


         by several percent (depending on the extent of additional


         regulations), making it economic to generate electricity with other


         fuels.  These impacts could be felt in two ways:   1)  lower coal


         consumption at existing power plants and 2) construction of  fewer


         coal-fired power plants in the future.

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                                     7-11






7.3  RECOMMENDATIONS








    Based on the findings from this Report to Congress, this section presents




the Agency's preliminary recommendations for those wastes included in the




scope of this study.  The recommendations are subject to change based on




continuing consultations with other government agencies and new information




submitted through the public hearings and comments on this report.  Pursuant




to the process outlined in RCRA 3001(b)(3)(C), EPA will announce its




regulatory determination within six months after submitting this report to




Congress.








    First. EPA has concluded that coal combustion waste streams generally do




not exhibit hazardous characteristics under current RCRA regulations.   EPA




does not intend to regulate under Subtitle C flv ash, bottom ash, boiler slag.




and flue gas desulfurization wastes.  EPA's tentative conclusion is that




current waste management practices appear to be adequate for protecting human




health and the environment.  The Agency prefers that these wastes remain under




Subtitle D authority.  EPA will use section 7003 of RCRA and sections 104 and




106 of CERCLA to seek relief in any cases where wastes from coal combustion




waste disposal sites pose substantial threats or imminent hazards to human




health and the environment.  Coal combustion waste problems can also be




addressed under RCRA Section 7002, which authorizes citizen lawsuits for




violations of Subtitle D requirements in 40 CFR Part 257.








    Second. EPA is concerned that several other wastes from coal-fired




utilities may exhibit the hazardous characteristics of corrosivitv or EP




toxicitv and merit reeulation under Subtitle C.  EPA intends to consider

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                                     7-12






whether these waste streams should be regulated under Subtitle C of RCRA based




on further study and information obtained during the public comment period.




The waste streams of most concern appear to be those produced during equipment




maintenance and water purification, such as metal and boiler cleaning wastes.




The information available to the Agency at this time does not allow EPA to




determine the exact quantity of coal combustion wastes that may exhibit RCRA




Subtitle C characteristics.  However, sufficient information does exist to




indicate that some equipment maintenance and water purification wastes do




occasionally exhibit RCRA hazardous characteristics, and therefore, may pose a




danger to human health and the environment.  These wastes are similar to




wastes produced by other industries that are subject to Subtitle C regulation,




and waste management practices for coal combustion wastes are often similar to




waste management practices employed by other industries.  EPA is considering




removing the exemption for all coal-fired utility wastes other than those




identified in the first recommendation.  The effect would be to apply Subtitle




C regulation to any of those wastes that are hazardous by the RCRA




characteristic tests.  EPA believes there are various treatment options




available for these wastes that would render them nonhazardous without major




costs or disruptions to the utilities.








    Third. EPA encourages the utilization of coal combustion wastes as one




method for reducing the amount of these wastes that need to be disposed to the




extent such utilization can be done in an environmentally safe manner.  From




the information available to the Agency at this time, current waste




utilization practices appear to be done in an environmentally safe manner.




The Agency supports voluntary efforts by industry to investigate additional




possibilities for utilizing coal combustion wastes.

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                                     7-13
    Through its own analysis, evaluation of public comments, and consultation




with other agencies, the Agency will reach a regulatory determination within




six months of submission of this Report to Congress.  In so doing, it will




consider and evaluate a broad range of management control options consistent




with protecting human health and the environment.  Moreover, if the Agency




determines that Subtitle C regulation is warranted, in accordance with Section




3004(x) EPA will take into account the "special characteristics of such waste,




the practical difficulties associated with implementation of such




requirements, and site-specific characteristics . . .," and will comply with




the requirements of Executive Orders 12291 and 12498 and the Regulatory




Flexibility Act.

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GLOSSARY

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acidity -   the amount of free carbon dioxide, mineral acids and salts
(especially sulfates or iron and aluminum) which hydrolyze to give hydrogen
ions in water and is reported as milli-equivalents per liter of acid, or ppm
acidity as calcium carbonate, or pH the measure of hydrogen ions
concentration.  Indicated by a pH of less than 7.

adninistrator -   the Administrator of the United States Environmental
Protection Agency, or his/her designee.

alkaline cleaning solution wastes -   water-side cleaning waste resulting from
the removal of high copper content scale from the utility boiler.

alkaline passivating waste - water-side cleaning waste resulting from the
removal of iron and copper compounds and silica to neutralize acidity after
acid cleaning.

alkalinity -   the amount of carbonates, bicarbonates, hydroxides and
silicates or phosphates in the water and is reported as grains per gallon, pH,
or ppm of carbonate.  Indicated by a pH of greater than 7.

alkaline fly ash scrubber -   a flue gas desulfurization system in which flue
gas reacts with alkaline fly ash that is augmented with a lime/limestone
slurry.

anthracite -   a high ASTM ranked coal with dry fixed carbon 92% or more and
less than 98%; and dry volatile, matter 8% or less and more than 2% on a
mineral-matter-free basis.

aquifer - a water-bearing bed or structure of permeable rock, sand, or gravel
capable of yielding quantities of water to wells or springs.

ash - the incombustible solid matter in fuel.

ash fusion -   the temperatures at which a cone of coal or coke ash exhibits
certain melting characteristics.

attenuation - a process that slows the migration of constituents through the
ground.

baghouse - an air pollution abatement device used to trap particulates by
filtering gas streams through large fabric bags usually made of glass fibers.

base load - base load is the term applied to that portion of a station or
boiler load that is practically constant for long periods.

batch test - a laboratory leachate test in which the waste sample is placed
in, rather than washed with, leachate solution.
                                    -2-

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 bituminous coal -   ASTM coal classification by rank on a mineral/matter-free
 basis and with bed moisture only.

     low volatile; dry fixed carbon 78% or more and less than 86%; and
     dry volatile matter 22% or more and less than 14%.
     medium volatile: dry fixed carbon 69% or more and less than
     78%; and dry volatile matter 22% or more and less than 31%.
     high volatile (A):  dry fixed carbon less than 69% and dry
     volatile matter more than 31% - Btu value equal to or greater
     than 14,000 moist,  mineral-matter-free basis.
     high volatile (B):  Btu value 13,000 or more and less than 14,000
     moist, mineral-matter-free basis.
     high volatile (C):  Btu value 11,000 or more and less than 13,000
     moist, mineral-matter-free basis commonly agglomerating, or 8,300

to 11,500 Btu agglomerating.

blower - the fan used to force air through a pulverizer or to force primary air
through an oil or gas burner register.

boiler - a closed vessel in which water is heated, steam is generated, steam is
superheated, or any combination thereof, under pressure or vacuum by the
application of heat.

boiler blovdown -   removal of a portion of boiler water for the purpose of
reducing solid concentration or discharging sludge.

boiler cleaning waste -  waste resulting from the cleaning of coal combustion
utility boilers.  Boiler cleaning wastes are either water/side or gas-side
cleaning wastes.

boiler slag - melted and fused particles of ash that collect on the bottom of
the boiler.

boiler water - a term used to define a representative sample of the boiler
circulating water. The sample is obtained after the generated steam has been
separated and before the incoming feedwater or added  chemical becomes mixed
with it so that its composition is affected.

bottom ash - large ash particles that settle on the bottom of the boiler.

British Thermal Unit (Btu) -   the mean British Thermal Unit is 1/180  of the
heat required to raise the temperature of 1 pound of water from 32°F to 212°F
at a constant atmospheric pressure. It is about equal to the quantity of heat
required to raise 1 pound of water 1 degree F.

capacity factor - the total output over a period of time divided by the product
of the boiler capacity and the time period.

CERC1A -   The Comprehensive Environmental Response, Compensation, and
Liability Act, commonly referred to as Superfund.


                                     -3-

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cell -   a section of a landfill, or the size of that section.  Usually only a
few cells of a landfill are open to accept waste at a time.

chain grate stoker -   a stoker which has a moving endless chain as a grate
surface, onto which coal is fed directly from a hopper.

coal pile runoff -   surface runoff from a plant's coal pile.

cogeneration -   the production of steam (or hot water) and electricity for use
by multiple users generated from a single source.

colunn test - a leachate extraction procedure that involves passing a solution
through the waste material to remove soluble constituents.

contingency plan -   a document setting out an organized, planned, and
coordinated course of action to be followed in case of a fire or explosion or a
release of hazardous waste constituents into the environment.

cooling tower blowdovn -   water withdrawn from the cooling system in order to
control the concentration of impurities in the cooling water.

cyclone furnace -   specialty furnace for high intensity heat release. So named
because of its swirling gas and fuel flows.

demineralizer regeneration and rinses waste -   a low volume wastewater
generated from the treatment of water to be used at the plant.

direct lime flue gas desulfurization - see lime/limestone FGD process.

direct linestone flue gas desulfurization - see lime/limestone FGD process.

disposal -   the discharge, deposit, injection, dumping, spilling, leaking, or
placing of any solid waste or hazardous waste into or on any land or water such
that any constituent thereof may enter the environment or be emitted into the
air or discharged into any waters,  including ground waters.

dry-botton furnace -   a pulverized-fuel furnace in which ash particles are
deposited on the furnace bottom in a dry, non-adherent condition.

dry scrubber -   an FGD system for which sulfur dioxide is collected by a solid
medium; the final product is totally dry, typically a fine powder.

dry sorbent injection -   an FGD system in the research and development stage
for which a powdered sorbent is injected into the flue gas before it enters the
baghouse.  Sulfur dioxide reacts with the reagent in the flue gas and on the
surface of the filter in the baghouse.

dual alkali fly ash scrubber -   a flue gas desulfurization system similar to
the lime/limestone process, except that the primary reagent is a solution of
sodium salts and lime.
                                     -A-

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effluent -   a waste liquid in its natural state or partially or completely
treated that discharges in to the environment from a manufacturing or treatment
process.

electrostatic precipitator -     an air pollution control device that imparts
an electrical charge to particles in a gas stream causing them to collect on an
electrode.

evapotranspiration -   the combined process of evaporation and transpiration.

fabric filter -   a cloth device that catches dust and particles from
industrial or utility emissions.

flash point -   the lowest temperature at which vapors above a volatile
combustible substance ignite in air when exposed to flame.

flue gas -   the gaseous products of combustion in the flue to the stack.

flue gas desulfurization (FGD) sludge -   waste that is generated by the
removal of some of the sulfur compounds from the flue gas after combustion.

fly ash -   suspended ash particles carried in the flue gas.

furnace -   the combustion chamber of a boiler.

gas-side cleaning waste -   waste produced during the removal of residues
(usually fly ash and soot) from the gas-side of the boiler (air preheater,
economizer, superheater, stack, and ancillary equipment).

ground water -   water found underground in porous rock strata and soils.

ground water monitoring well -   a well used to obtain ground-water samples for
water-quality analysis.

hazardous waste -   a solid waste, or combination of solid wastes, which,
because of its quantity, concentration, or physical, chemical, or infectious
characteristics, may (1) cause, or significantly contribute to, an increase in
serious irreversible, or incapacitating reversible illness; or (2) pose a
substantial present or potential hazard to human health or the environment when
improperly treated, stored, transported, disposed of, or otherwise managed.

hard water - Water that contains sufficient dissolved calcium and magnesium to
cause a carbonate scale to form when the water is boiled or to prevent the
sudsing of soap in the water.

high volume waste -   fly ash, bottom ash, boiler slag, and flue gas
desulfurization sludge.

hydraulic conductivity -   the quantity of water that will flow through a unit
cross-sectional area of a porous material per unit of time.
                                     -5-

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hydrochloric acid cleaning waste -   wastes from the cleaning of scale caused
by water hardness, iron oxides, and copper.

land disposal -  the placement of wastes in a landfill, surface impoundment,
waste pile, injection well, land treatment facility, salt dome formation, salt
bed formation, or underground mine or cave.

landfill -   a  disposal facility or part of a facility where hazardous  waste
is placed in or on land and which is not a land treatment facility, a surface
impoundment or injection well.

leachate -   the liquid resulting from water percolating through, and
dissolving materials in, waste.

leachate extraction test: -   a laboratory procedure used to predict the type
and concentration of constituents that will leach out of waste material.

leachate collection, removal, and treatment systems -   mitigative measures
used to prevent the leachate from building up above the liner.

lift -   the depth of a cell in a landfill.

lignite -   a coal of lowest ASTM ranking with calorific value limits on a
moist, mineral-matter-free basis less than 8,300 Btu.

line -   calcium oxide (CaC03), a chemical used in some FGD systems.

limestone -   calcium carbonate (CaOH2),  a chemical used in some FGD systems.

lime/limestone FGD process -   form of wet non-recovery flue gas
desulfurization system in which flue gases pass through a fly ash collection
device and into a contact chamber where they react with a solution of lime or
crushed limestone to form a slurry which is dewatered and disposed.

liner -   a mitigative measure used to prevent ground-water contamination in
which synthetic, natural clay, or bentonite materials that are compatible with
the wastes are used to seal the bottom or surface impoundments and landfills.

low volume waste -   wastes generated during equipment maintenance and water
purification processes.  Low volume wastes include boiler cleaning solutions,
boiler blowdown, demineralizer regenerant, pyrites, cooling tower blowdown.

mechanical stoker - a device consisting of mechanically operated fuel  feeding
mechanism and a grate, and is used for the propose of feeding solid fuel into a
furnace,  and to distribute it over a grate, admitting air to the fuel for the
purpose of combustion, and providing a means for removal or discharge of
refuse.

net recharge -   the amount of precipitation absorbed annually into the soil.

off-site -   geographically noncontiguous property, or contiguous property that
is not owned by the same person.  The opposite of on-site.

                                     -6-

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em-site -   the same or geographically contiguous property which may be divided
by public or private right(s)-of-ways, provided the entrance and exit between
the properties is at across-roads,  intersection, and access is by crossing as
opposed to going along the right(s)-of-way. Noncontiguous properties owned by
the same person but connected by a right-of-way which the person controls and
to which the public does not have access, is also considered on-site property.

Part A - the first part of the two part application that must be submitted by a
TSD facility to receive a permit.  It contains general facility information.

Fart B - the second part of the two part application that includes detailed and
highly technical information concerning the TSD in question.  There is no
standard form for the Part B, instead the facility must submit information
based on the regulatory requirements.

particulates -   fine liquid or solid particles such as dust, smoke, mist,
fumes, or smog, found in the air or emissions.

permeability (1) - the ability of a geologic formation to transmit ground water
or other fluids through pores and cracks.

pemeability (2) - the rate at which water will seep through waste  material.

petroleum coke - solid carbaceous residue remaining in oil refining stills
after distillation process.

pH -   a measure of the acidity or alkalinity of a material, liquid or solid.
pH is represented on a scales of 0 to 14 with 7 being neutral state, 0 most
acidic and 14 most alkaline.

plume -   a body of ground water originating from a specific source and
influenced by such factors as the local ground-water flow pattern and character
of the aquifer.

pond liquors -   waste fluid extracted from a surface impoundment or landfill.

pozzolanic -   forming strong,  slow-hardening cement-like substance when mixed
with lime or other hardening material.

PDVS -   Primary Drinking Water Standards established by the Safe Drinking
Water Act.

pulverizer -   a machine which reduces a solid fuel to a fineness suitable for
burning in suspension.

pyrites -   solid mineral deposits  of raw coal that are separated from the coal
before burning.

reagent -  a substance that takes part in one or more chemical reactions or
biological processes and is used to detect other substances.


                                     -7-

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recharge - the  replenishment of ground water by infiltration of precipitation
through the soil.

RCRA -   Resource Conservation and Recovery Act, as amended (Pub. L. 94-580).
The legislation under which EPA regulates solid and hazardous waste.

RCRA Subtitle C Characteristics -   criteria used to determine if an unlisted
waste is a hazardous waste under Subtitle C of RCRA.

          - corrosivity - a solid waste is considered corrosive if it is
          aqueous and has a pH less than or equal to 2 or greater than or
          equal to 12.5 or if it is a liquid and corrodes steel at a rate
          greater than 6.35 mm per year at a test temperature of 55°C.

          - EP toxicitv - a solid waste exhibits the characteristic of EP
          (extraction procedure) toxicity if, after extraction by a prescribed
          EPA method, it yields a metal concen- tration 100  times the
          acceptable concentration limits set forth in EPA's primary drinking
          water standards.

          - ignitability - a solid waste exhibits the characteristic of
          ignitability if it is a liquid with a flashpoint below 60°C or a
          non-liquid capable or causing fires at standard temperature and
          pressure.

          - reactivity - a waste is considered reactive if it reacts violently,
          forms potentially explosive mixtures, or generates toxic fumes when
          mixed with water, or if it is normally unstable and undergoes violent
          change without deteriorating.

SDVS -   Secondary Drinking Water Standards established by the Safe Drinking
Water Act.

settling lagoon -   surface impoundment.

shear strength -   the resistance offered by a material subjected to a
compressive stress created when two contiguous parts of the material are forced
in opposite parallel directions.

slag -   molten or fused solid matter.

sludge -   a soft water-formed sedimentary deposit that is mud-like in its
consistency.

slurry -   a mixture of insoluble mater in a fluid.

solid waste -   As defined by RCRA, the term "solid waste"  means any garbage,
refuse,  sludge from a waste treatment plant, water supply  treatment plant,  or
air pollution control facility and other discarded material, including solid,
liquid,  semisolid, or contained gaseous  material resulting from industrial,
commercial,  mining,  and agricultural operations, and from community activities,

                                     -8-

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but does not include solid or dissolved material in domestic sewage, or solid
or dissolved  materials in irrigation return flows or industrial  discharges
which are point sources subject to permits under the Clean Water Act, or
special nuclear or byproduct material as defined by the Atomic Energy Act of
1954.

spray drying process - a flue gas desulfurization system in which a fine spray
of alkaline solution is injected into the flue gas as it passes through a
contact chamber, where the reaction with the sulfur oxides occurs. The heat of
the flue gas evaporates the water in the solution, leaving a dry powder, which
is collected by a particulate collector.

stabilization -  making resistant to physical or chemical changes by treatment.

steady state - an adjective that implies that a system is in a stable dynamic
state in which inputs balance outputs.

stoker -   see mechanical stoker.

storage - the holding of waste for a temporary period, at the end of which the
hazardous waste is treated, disposed of, or stored elsewhere.

subbituninous coal -   An intermediate rank coal between lignite and bituminous
with more carbon and less moisture than lignite.

sunp effluent -   waste from sumps that collect floor and equipment drains.

surface inpoundment -   a  facility which is a natural topographic depression,
artificial excavation, or diked area formed primarily of  earthen materials
(although it may be lined with artificial materials), which is designed to hold
an accumulation of liquid wastes  or wastes containing free liquids.

surface water -    water that rests on the surface of the rocky crust of the
earth.

traveling grate stoker -   a stoker similar to a chain grate stoker except that
the grate is separate from but is supported on and driven by chains.

trace element -   An element that appears in a naturally-occurring
concentration of less than 1 percent.

treatment -   any method, technique, or process, including neutralization,
designed to change the physical, chemical, or biological character or
composition of a waste so as to neutralize it, recover it, make it safer to
transport, store or dispose of, or amenable for recovery, storage, or volume
reduction.

TSD facility - waste treatment, storage, or disposal facility.

utility boiler -   a boiler which produces steam primarily for the production
of electricity in the utility industry.


                                     -9-

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volatile -   A volatile substance is one which tends to vaporize at a
relatively low temperature.

water-side cleaning waste -   waste produced during the removal of scale and
corrosion products from the water side of the boiler (i.e., the piping systems
containing the steam or hot water).

wet botton furnace -   a pulverized fuel fired furnace in which the ash
particles are deposited and retained on the floor thereof and molten ash is
removed by tapping either continuously or intermittently, (also called a slag
tap furnace)

wet scrubber -   a device utilizing a liquid, designed to separate  particulate
matter or gaseous contaminants from a gas stream by one or more mechanisms such
as absorption, condensation, diffusion, inertial impaction.
                                     -10-

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Tennessee Valley Authority, Potential Groundwater Quality Impacts at Tennessee
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University of California at Los Angeles, Ecological Effects of Precipitater
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U.S. Department of Energy, Evaluation of Impacts of Proposed Resource
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U.S. Environmental Protection Agency, Abundance of Trace and Minor Elements in
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U.S. Environmental Protection Agency, Assessment of Techniques for Control of
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U.S. Environmental Protection Agency, Disposal of By-Products from
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U.S. Environmental Protection Agency, Disposal of Flue Gas Cleaning Wastes.
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U.S. Environmental Protection Agency, Effects of Ash and Flue Gas Cleaning
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U.S. Environmental Protection Agency, Groundwater Protection Strategy. August
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U.S. Environmental Protection Agency, Handling of Combustion and Emission -
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U.S. Environmental Protection Agency, Study of Non-Hazardous Wastes from
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U.2. Environmental Protection Agency, Waste and Water Management for
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U.S. Geological Survey, Effects of Selected Sources of Contamination on Ground
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Utility Solid Waste Activities Group, Report and Technical Studies on the
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Versar, Fossil Energy Waste General Sampling Guideline, prepared for U.S.
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Versar, Selection of Representative Coal Ash and Coal Ash/Flue Gas Desulfuri-
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Virginia Institute of Marine Sciences, Nature and Extent of Trace Element
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Wald, Harkrader & Ross, Survey of State Laws and Regulations Governing
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Webster and Associates, Analysis of Selected Trace Metals in Leachate from
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