United States
Environmental Protection
Agency
EPA 821-R-09-008
Steam Electric Power Generating
Point Source Category:
Final Detailed Study Report
October 2009
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Final Detailed Study Report Contents
CONTENTS
Page
EXECUTIVE SUMMARY xii
1. INTRODUCTION AND BACKGROUND OF THE STUDY 1-1
2. DATA COLLECTION ACTIVITIES 2-1
2.1 Site Visits 2-2
2.2 Wastewater Sampling 2-10
2.3 Questionnaire ("Data Request") 2-12
2.4 EPA and State Sources 2-15
2.4.1 NPDES Permits and Fact Sheets 2-16
2.4.2 State Groups and Permitting Authorities 2-16
2.4.3 1974 and 1982 Technical Development Documents for the Steam
Electric Power Generating Point Source Category 2-16
2.4.4 CWA Section 316(b) - Cooling Water Intake Structures Supporting
Documentation and Data 2-17
2.4.5 Office of Air and Radiation 2-17
2.4.6 Office of Research and Development 2-18
2.4.7 Office of Solid Waste and Emergency Response 2-18
2.5 Interactions with the Utility Water Act Group 2-18
2.5.1 Database of Power Plant Information 2-19
2.5.2 Wastewater Sampling 2-19
2.5.3 Data Request 2-20
2.5.4 NPDES Form 2C 2-20
2.6 Interactions with the Electric Power Research Institute (EPRI) 2-20
2.7 Department of Energy (DOE) 2-21
2.8 Other Sources 2-22
2.8.1 Wastewater Treatment Equipment Vendors 2-22
2.8.2 U.S. Geological Survey (USGS) COALQUAL Database 2-22
2.8.3 Literature and Internet Searches 2-22
2.8.4 Environmental Groups and Other Stakeholders 2-22
3. STEAM ELECTRIC INDUSTRY PROFILE 3-1
3.1 Overview of the Electric Generating Industry 3-1
3.1.1 Demographics of the Electric Generating Industry 3-3
3.1.2 Steam Electric Power Generating Industry 3-4
3.2 Steam Electric Process and Wastewater Sources 3-12
3.2.1 Fly Ash and Bottom Ash 3-15
3.2.2 Flue Gas Desulfurization 3-16
3.2.3 Selective Catalytic Reduction 3-17
3.2.4 Condenser Cooling 3-18
3.2.5 Low Volume Wastes 3-20
3.2.6 Metal Cleaning 3-21
3.2.7 Coal Piles 3-21
3.2.8 Landfill Leachate and Runoff 3-23
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Final Detailed Study Report Contents
CONTENTS (Continued)
Page
3.2.9 Combined Cycle Generating Units 3-25
3.2.10 Integrated Gasification Combined Cycle (IGCC) 3-26
3.2.11 Carbon Capture and Storage 3-29
3.3 Effluent Guidelines for the Steam Electric Power Generating Point Source
Category 3-32
4. FLUE GAS DESULFURIZATION SYSTEMS 4-1
4.1 Coal-Fired FGD System Statistics 4-1
4.1.1 Current Coal-Fired FGD System Profile 4-1
4.1.2 Projected Use of FGD Systems at Coal-Fired Plants 4-4
4.2 Process Description and Wastewater Generation 4-7
4.2.1 Forced Oxidation FGD Systems 4-7
4.2.2 Inhibited Oxidation FGD System 4-10
4.2.3 Other Types of FGD Systems 4-13
4.3 FGD Wastewater Characteristics 4-15
4.4 FGD Wastewater Treatment Technologies 4-26
4.4.1 Settling Ponds 4-26
4.4.2 Chemical Precipitation 4-27
4.4.3 Biological Treatment 4-30
4.4.4 Constructed Wetlands 4-33
4.4.5 Vapor-Compression Evaporation System 4-33
4.4.6 Design/Operating Practices Achieving Zero Discharge 4-36
4.4.7 Other Technologies under Investigation 4-40
4.4.8 Wastewater Treatment System Use in the Coal-Fired Steam
Electric Industry 4-43
4.5 Comparison of FGD Wastewater Control Technologies 4-50
4.6 FGD Pollutant Loads Estimates 4-68
4.6.1 FGD Wastewater Treatment Industry Profile 4-68
4.6.2 Calculation of Loads 4-69
4.6.3 Industry Baseline and Treatment Technology Loads 4-70
5. COAL ASH HANDLING SYSTEMS 5-1
5.1 Fly Ash Handling Operations 5-1
5.2 Bottom Ash Handling Operations 5-3
5.3 Ash Transport Water Characteristics 5-5
5.4 Ash Transport Water Treatment Systems 5-11
6. ENVIRONMENTAL ASSESSMENT OF COAL COMBUSTION WASTEWATER 6-1
6.1 Coal Combustion Wastewater Pollutants 6-2
6.2 Coal Combustion Wastewater Interactions with the Environment 6-7
6.2.1 Discharges to Surface Waters 6-8
6.2.2 Leaching to Groundwater 6-11
6.2.3 Surface Impoundments and Constructed Treatment Wetlands as
Attractive Nuisances 6-13
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Final Detailed Study Report Contents
CONTENTS (Continued)
Page
6.3 Types of Environmental Effects 6-13
6.3.1 Lethal Effects 6-14
6.3.2 Sublethal Effects 6-15
6.3.3 Population and Community Effects 6-16
6.3.4 Human Health Impacts 6-17
7. PRELIMINARY INVESTIGATION OF OTHER INDUSTRY SEGMENTS 7-1
7.1 Alternative-Fueled Steam Electric Plants 7-2
7.1.1 Demographic Data for Alternative-fueled Steam Electric Plants 7-3
7.1.2 Alternative-Fueled Steam Electric Fuel Types and Processes 7-3
7.1.3 Summary ofNPDES PermitReview 7-9
7.2 Industrial Non-Utilities 7-10
7.2.1 Overview of Industrial Non-Utilities 7-11
7.2.2 Demographic Data for Fossil-Fueled Industrial Non-Utilities 7-12
7.2.3 Review of Industrial Non-Utility Discharge Permits 7-18
7.2.4 Contacts with Industrial Non-Utilities 7-20
7.3 Steam and Air Conditioning Supply Plants 7-21
7.3.1 Wastewater Discharge Characterization Data 7-23
7.3.2 NPDES Permit Review 7-23
7.3.3 Contacts with Steam Supply Companies 7-26
7.4 Combination Utility Plants 7-27
7.4.1 Wastewater Discharge Characterization Data 7-28
7.4.2 NPDES Permit Review 7-31
8. REFERENCES 8-1
IV
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Final Detailed Study Report List of Tables
LIST OF TABLES
Page
2-1 Summary of the Detailed Study Site Visits 2-5
2-2 Summary of the Detailed Study Sampling Program 2-10
2-3 Analytes Included in the Detailed Study Sampling Program 2-11
2-4 Profile of Coal-Fired Power Plants Operated by Data Request Respondents 2-13
3-1 Distribution of U.S. Electric Generating Plants by NAICS Code in 2002 3-4
3-2 Distribution of Prime Mover Types for Plants Regulated by the Steam Electric
Power Generating Effluent Guidelines 3-7
3-3 Distribution of Fuel Types Used by Steam Electric Generating Units 3-8
3-4 Types of Fuel Used by Stand-Alone and Combined Cycle Steam Turbines 3-10
3-5 Distribution of Fuel Types for Combined Cycle Units Regulated by the Steam
Electric Power Generating Effluent Guidelines 3-11
3-6 Distribution by Size of Steam Electric Capacity, Plants, and Electric Generating
Units Regulated by the Steam Electric Effluent Guidelines 3-12
3-7 Coal Pile Runoff Generation Reported for the EPA Data Request 3 -22
3-8 Current Effluent Guidelines and Standards for the Steam Electric Power
Generating Point Source Category 3-33
4-1 Scrubbed Coal-Fired Steam Electric Power Generation as of June 2008 4-2
4-2 Characteristics of Coal-Fired Power Plants with Wet FGD Systems 4-3
4-3 Proj ected Future Use of FGD Systems at Coal-Fired Power Plants 4-5
4-4 FGD Scrubber Purge Flow Rates 4-16
4-5 Influent to FGD Wastewater Treatment System Concentrations 4-19
4-6 FGD Scrubber Purge Self-Monitoring Data 4-25
4-7 FGD Wastewater Treatment Systems Identified During EPA's Detailed Study 4-44
4-8 Pollutant Concentrations in Sampled Effluent from FGD Wastewater Treatment
Systems 4-57
4-9 Monitoring Data: Pollutant Concentrations in Effluent from Settling Ponds 4-64
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Final Detailed Study Report List of Tables
LIST OF TABLES (Continued)
Page
4-10 Monitoring Data: Pollutant Concentrations in Effluent from Chemical
Precipitation Systems 4-65
4-11 Monitoring Data: Pollutant Concentrations in Effluent from Biological Treatment
Systems 4-67
4-12 Treatment Technology Loads by Model Plant Size 4-70
5-1 Fly Ash Handling Practices at Plants Included in EPA's Combined Data Set 5-3
5-2 Bottom Ash Handling Practices at Plants Included in EPA's Combined Data Set 5-5
5-3 Fly Ash Transport Water Flow Rates 5-6
5-4 Bottom Ash Transport Water Flow Rates from EPA Data Request Responses 5-7
5-5 Ash Pond Influent Concentrations 5-7
5-6 Fly Ash Transport Wastewater Treatment Systems at Plants Included in EPA's
Combined Data Set 5-12
5-7 Bottom Ash Transport Wastewater Treatment Systems at Plants Included in
EPA's Combined Data Set 5-13
5-8 Ponds Containing Coal Combustion Residues 5-14
5-9 Ash Pond Effluent Concentrations 5-17
6-1 Selected Coal Combustion Wastewater Pollutants 6-3
6-2 Number of Documented Cases of Environmental Impacts from Coal Combustion
Wastewater 6-7
7-1 Summary of Alternative-Fueled Steam Electric Plants, by Fuel/Energy Source
Type 7-4
7-2 Comparison of Available Coal Ash, Municipal Solid Waste Ash, and Wood Ash
Composition Data 7-5
7-3 Summary of Fossil-Fueled, Steam Electric Industrial Non-Utilities,
by NAICS Code in 2005 7-14
7-4 Distribution of Prime Mover Types Among Fossil-Fueled,
Steam Electric Industrial Non-Utilities 7-16
7-5 Distribution of Fuel Types Among Fossil-Fueled, Steam Electric Industrial Non-
Utilities 7-17
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Final Detailed Study Report List of Tables
LIST OF TABLES (Continued)
Page
7-6 Steam and Air-Conditioning Supply Plants Identified in DMRLoads2007
Database 7-24
7-7 Combination Utilities Identified in DMRLoads2007 Database 7-29
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Final Detailed Study Report List of Figures
LIST OF FIGURES
Page
2-1 Locations of Coal-Fired Power Plants Included in EPA Data Collection Activities
for the Detailed Study 2-2
2-2 Locations of Coal-Fired Power Plants Included in EPA's Site Visit and Sampling
Program 2-4
2-3 Locations of Coal-Fired Power Plants for which Data Request Respondents
Provided Technical Information 2-14
3-1 Types of U.S. Electric Generating Plants 3-1
3-2 Steam Electric Process Flow Diagram 3-13
3-3 Typical Wet FGD System 3-16
3-4 Diagram of a Recirculating Cooling System 3-18
3-5 Diagram of Landfill Leachate and Landfill Runoff Generation and Collection 3-24
3-6 Combined Cycle Process Flow Diagram 3-26
3-7 Wabash River ConocoPhillips E-Gas™ Gasification Process 3-28
3-8 AEP's Chilled Ammonia Process at Mountaineer Power Station 3-31
4-1 Wet FGD Systems at Coal-Fired Power Plants (Current and Proj ected 2020) 4-6
4-2 Typical Process Flow Diagram for a Limestone Forced Oxidation FGD System 4-8
4-3 Process Flow Diagram for a Lime or Limestone Inhibited Oxidation FGD System 4-12
4-4 Distribution of FGD Scrubber Purge Daily Flow Rates 4-17
4-5 Distribution of FGD Scrubber Purge Normalized Daily Flow Rates 4-17
4-6 Process Flow Diagram for a Hydroxide and Sulfide Chemical Precipitation
System 4-29
4-7 Process Flow Diagram for an Anoxic/Anaerobic Biological Treatment System 4-31
4-8 Process Flow Diagram for a Vapor-Compression Evaporation System 4-34
4-9 Distribution of FGD Wastewater Treatment Systems Among Plants Operating
Wet FGD Systems 4-47
4-10 Comparison of Distribution of FGD Wastewater Treatment Systems by Type of
Oxidation System 4-48
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Final Detailed Study Report List of Figures
LIST OF FIGURES (Continued)
Page
4-11 Distribution of FGD Wastewater Treatment Systems Among Plants that
Discharge FGD Wastewater 4-49
4-12A Concentration of Arsenic in FGD Scrubber Purge and Effluent from Chemical
Precipitation and Biological Treatment Systems atBelews Creek 4-52
4-13 A Concentration of Arsenic in FGD Scrubber Purge and Effluent from Settling Pond
and Biological Treatment Systems at Roxboro 4-52
4-12B Concentration of Arsenic in Effluent from Chemical Precipitation and Biological
Treatment Systems atBelews Creek 4-52
4-13B Concentration of Arsenic in Effluent from Settling Pond and Biological Treatment
Systems at Roxboro 4-52
4-12C Concentration of Mercury in FGD Scrubber Purge and Effluent from Chemical
Precipitation and Biological Treatment Systems atBelews Creek 4-53
4-13C Concentration of Mercury in FGD Scrubber Purge and Effluent from Settling
Pond and Biological Treatment Systems at Roxboro 4-53
4-12D Concentration of Mercury in Effluent from Chemical Precipitation and Biological
Treatment Systems atBelews Creek 4-53
4-13D Concentration of Mercury in Effluent from Settling Pond and Biological
Treatment Systems at Roxboro 4-53
4-12E Concentration of Selenium in FGD Scrubber Purge and Effluent from Chemical
Precipitation and Biological Treatment Systems atBelews Creek 4-54
4-13E Concentration of Selenium in FGD Scrubber Purge and Effluent from Settling
Pond and Biological Treatment Systems at Roxboro 4-54
4-12F Concentration of Selenium in Effluent from Chemical Precipitation and
Biological Treatment Systems atBelews Creek 4-54
4-13F Concentration of Selenium in Effluent from Settling Pond and Biological
Treatment Systems at Roxboro 4-54
4-12G Concentration of TDS in FGD Scrubber Purge and Effluent from Chemical
Precipitation and Biological Treatment Systems atBelews Creek 4-55
4-13G Concentration of TDS in FGD Scrubber Purge and Effluent from Settling Pond
and Biological Treatment Systems at Roxboro 4-55
4-14 Estimated Industry-Level FGD Effluent Discharge Loadings By Treatment
Scenario 4-71
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Final Detailed Study Report
Acronyms
AEP
API
ASTM
BAT
BOD5
BPJ
BPT
CaCO3
Ca(OH)2
CaSO3
CaSO4
CaSO4 • 2H2O
CCR
CFR
CO
CCh
COD
COS
CPO
CWA
CWTS
DBA
DCN
DMR
DOE
DRC
EIA
EPA
EPRI
ESP
FGD
gpd
gpm
gpy
H2
H2S
HEM
HERO™
HG-AFS
HRSG
ICIS
IGCC
IPM
MCL
MDEA
mgd
ACRONYMS
American Electric Power
American Petroleum Institute
American Society for Testing and Materials
Best available technology economically achievable
Biochemical oxygen demand (5-day)
Best Professional Judgment
Best practicable control technology currently available
Limestone
Lime
Calcium sulfite
Calcium sulfate
Gypsum
Coal combustion residues
Code of Federal Regulations
Carbon monoxide
Carbon dioxide
Chemical oxygen demand
Carbonyl sulfide
Chlorine-produced oxidants
Clean Water Act
Constructed wetland treatment system
Dibasic acid (a mixture of glutaric, succinic, and adipic acid)
Document control number
Discharge Monitoring Report
Department of Energy
Dynamic reaction cell
Energy Information Administration
Environmental Protection Agency
Electric Power Research Institute
Electrostatic precipitator
Flue gas desulfurization
Gallons per day
Gallons per minute
Gallons per year
Hydrogen
Hydrogen sulfide
Hexane Extractable Material
High-efficiency reverse osmosis
Hydride generation and atomic fluorescence spectrometry
Heat recovery steam generator
Integrated Compliance Information System
Integrated gasification combined cycle
Integrated Planning Model
Maximum contaminant level
Methyl di ethanol amine
Million gallons per day
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Final Detailed Study Report
Acronyms
MSW Municipal solid waste
MW Megawatt
N2 Nitrogen
Na2CO3 Sodium carbonate
NAICS Northern American Industry Classification System
NEEDS National Electric Energy Data System
NETL National Energy Technology Laboratory
NH3 Ammonia
(NH4)2SO4 Ammonium sulfate
NH4HSO4 Ammonium bisulfate
NPDES National Pollutant Discharge Elimination System
NO Nitrogen monoxide
NO2 Nitrogen dioxide
NOX Nitrogen oxides
NSPS New source performance standards
OAP Office of Atmospheric Programs
OAQPS Office of Air Quality Planning and Standards
OAR Office of Air and Radiation
OECA Office of Enforcement and Compliance Assistance
ORCR Office of Resource Conservation and Recovery
ORD Office of Research and Development
ORSANCO Ohio River Valley Water Sanitation Commission
OSWER Office of Solid Waste and Emergency Response
OW Office of Water
PCS Permit Compliance System
PPM Parts per million
PSES Pretreatment standards for existing sources
PSNS Pretreatment standards for new sources
SBR Sequencing batch reactor
SCR Selective catalytic reduction
SIC Standard Industrial Classification
SGT-HEM Silica Gel Treated Hexane Extractable Material
SNCR Selective non-catalytic reduction
SO2 Sulfur dioxide
SO3 Sulfur trioxide
TDS Total dissolved solids
TKN Total Kjeldahl nitrogen
TMT Trimercapto-s-triazine
TRI Toxics Release Inventory
TRO Total residual oxidants
TSS Total suspended solids
TVA Tennessee Valley Authority
TWF Toxic weighting factor
TWPE Toxic-weighted pound equivalent
USGS U.S. Geological Survey
UWAG Utility Water Act Group
XI
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Final Detailed Study Report Executive Summary
EXECUTIVE SUMMARY
This report summarizes the information collected and analyzed by the United States
Environmental Protection Agency (EPA) to review discharges from the steam electric power
generating industry and to determine whether the current effluent guidelines for this industry
should be revised. EPA's detailed study of wastewater discharges and treatment technologies
associated with this industry evaluated a range of waste streams and processes. However, the
study ultimately focused largely on discharges associated with coal ash handling operations and
wastewater from flue gas desulfurization (FGD) air pollution control systems because these
sources comprise a significant fraction of the pollutants discharged by steam electric power
plants. In this report, EPA provides an overview of the steam electric power generating industry
and its wastewater discharges, and the data collection activities and analyses conducted over the
course of EPA's detailed study.
The scope of the study included plants covered by the Steam Electric Power Generating
effluent guidelines (40 CFR Part 423), which is a subset of the entire electric generating industry.
The Steam Electric Power Generating effluent guidelines apply to wastewater discharges from
plants primarily engaged in the generation of electricity for distribution and sale which results
primarily from the use of nuclear or fossil fuels in conjunction with a steam-water
thermodynamic cycle. During the study, EPA collected data about the industry by performing the
following activities: conducting site visits and wastewater sampling episodes at steam electric
power plants, distributing a questionnaire to collect data from nine companies (30 coal-fired
power plants), reviewing publicly available sources of data, and coordinating with EPA program
offices, other government organizations (e.g., state groups and permitting authorities), and
industry and other stakeholders.
EPA evaluated several waste streams generated at power plants, including wastewaters
from wet FGD systems, fly ash and bottom ash handling, coal pile runoff, condenser cooling,
equipment cleaning, and leachate from landfills and impoundments. Additionally, EPA reviewed
information on integrated gasification combined cycle (IGCC) and carbon capture technologies.
Wastewaters from flue gas mercury control systems (i.e., when the dry mercury capture residues
are transported by a wet fly ash handling system to ash ponds) and regeneration of the catalysts
used for Selective Catalytic Reduction (SCR) NOx controls were identified as potential new
waste streams that warrant attention; however, EPA was not able to obtain characterization data
for these wastes.
The use of wet FGD systems to control 862 emissions has increased significantly since
the effluent guidelines were last revised in 1982 and is projected to increase substantially in the
next decade as power plants take steps to address federal and state air pollution control
requirements. FGD wastewaters generally contain significant levels of metals, including
biaccumulative pollutants such as arsenic, mercury, and selenium. The FGD wastewaters also
contain significant levels of chloride, total dissolved solids (TDS), total suspended solids (TSS),
and nutrients. EPA identified and investigated technologies for treating FGD wastewaters,
including settling ponds, chemical precipitation systems, biological treatment systems (anaerobic
and aerobic), constructed wetlands, vapor-compression evaporation systems, and other
technologies under investigation. From information collected during the study, EPA determined
that settling ponds are the most commonly used treatment system for managing FGD wastewater.
These ponds can be effective at removing suspended solids and those metals present in the
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Final Detailed Study Report Executive Summary
particulate phase from FGD wastewater; however, they are not effective at removing dissolved
metals. Other treatment systems, such as chemical precipitation and certain biological treatment
systems, are demonstrated to be effective at removing certain dissolved metals from FGD
wastewater. EPA also identified operating/management practices and treatment technologies that
are used to reduce the discharge of FGD wastewater, and in some cases, eliminate the discharge
completely.
Coal-fired power plants may manage bottom ash and fly ash using either wet or dry
handling techniques. For wet handling systems, the plants typically sluice the fly ash and/or
bottom ash to a surface impoundment or settling pond where most of the solids settle out of the
water. Some plants recycle a portion or all of the settled ash pond effluent, but most plants
discharge the pond overflow. Untreated ash transport waters contain significant concentrations of
TSS and metals. The treated effluent from ash ponds generally contains low concentrations of
TSS; however, metals are still present in the wastewater, predominantly in dissolved form.
Most of the newer electric generating units operate dry fly ash handling systems because
of new source performance standards that require "... no discharge of wastewater pollutants
from fly ash transport water." [40 CFR Part 423.15] These dry fly ash handling systems use a
vacuum or blower to transport the fly ash to a storage silo where it is typically sold for beneficial
use or landfilled. The dry bottom ash handling process typically consists of collecting the bottom
ash in a quench water bath and conveying it out of the boiler to a dewatering pile.
FGD and ash transport wastewaters, as well as other coal combustion wastewaters,
contain pollutants that can have detrimental impacts to the environment. EPA reviewed publicly
available data to identify documented cases where environmental impacts were attributable to
releases from surface impoundments or landfills containing coal combustion residues. EPA
determined that there are a number of pollutants present in wastewaters generated at coal-fired
power plants that can impact the environment, including metals (e.g., arsenic, selenium,
mercury), TDS, and nutrients. The primary routes by which coal combustion wastewater impacts
the environment are through discharges to surface waters, leaching to ground water, and by
surface impoundments and constructed wetlands acting as attractive nuisances that increase
wildlife exposure to the pollutants contained in the systems. EPA found the interaction of coal
combustion wastewaters with the environment has caused a wide range of environmental effects
to aquatic life.
As part of the study, EPA also investigated other electric power and steam generating
activities that are similar to the processes regulated for the Steam Electric Power Generating
Point Source Category, but which are not subject to the effluent guidelines. Such activities
include electric generating units fueled by non-fossil or non-nuclear fuels (e.g., municipal solid
waste, biomass), electric generating units at industrial facilities (e.g., chemical plants, petroleum
refineries), plants that produce steam for distribution and/or sale but do not generate electric
power, and facilities that provide a combination of electric power and other utility services. EPA
compared the volume and characteristics of wastewaters generated by these activities to the
plants regulated by the Steam Electric effluent guidelines and determined that these processes
may generate similar types of wastewaters in terms of pollutants present; however, the volume of
the wastewaters generated are much smaller than those generated at plants regulated by the
effluent guidelines.
Xlll
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Final Detailed Study Report Chapter 1 - Introduction and Background of the Study
1. INTRODUCTION AND BACKGROUND OF THE STUDY
This report summarizes the information collected and analyzed by the United States
Environmental Protection Agency (EPA) to review discharges from steam electric power
generating facilities and to determine whether the current wastewater discharge regulations for
these operations should be revised. EPA's review of wastewater discharges and treatment
technologies evaluated a range of waste streams and processes, but has focused primarily on coal
ash ponds and wastewater from flue gas desulfurization (FGD) air pollution control systems
because these sources comprise a significant fraction of the pollutants discharged by steam
electric power plants. In this report, EPA provides an overview of the steam electric power
generating industry and its wastewater discharges, and the data collection activities and analyses
conducted over the course of the study. Much of the information in this report is associated with
the processes, wastewaters, and pollution controls for fly ash, bottom ash, and FGD wastes.
The Steam Electric Power Generating effluent limitations guidelines and standards
(referred to in this report as "effluent guidelines") apply to a subset of the electric power
industry, namely those plants "primarily engaged in the generation of electricity for distribution
and sale which results primarily from a process utilizing fossil-type fuel (coal, oil, or gas) or
nuclear fuel in conjunction with a thermal cycle employing the steam water system as the
thermodynamic medium." The effluent guidelines are codified in the Code of Federal
Regulations (CFR) at Title 40, Part 423 (40 CFR Part 423). EPA's most recent revisions to the
effluent guidelines for this industry sector were promulgated in 1982 (see 47 Fed. Reg. 52290;
November 19, 1982).
EPA is required by section 304 of the Clean Water Act (CWA) to periodically review all
effluent guidelines to determine whether revisions are warranted. In addition, section 304(m) of
the CWA requires EPA to develop and publish a biennial plan that establishes a schedule for the
annual review and revision of national effluent guidelines required by section 304(b) of the
CWA. EPA last published an Effluent Guidelines Program Plan in 2008 [73 Fed. Reg. 53218;
September 15, 2008], in which EPA discussed the status of the detailed study of the steam
electric power generating industry.
EPA first identified this industry for study during the 2005 annual review of effluent
guidelines. At that time, publicly available data reported through the National Pollutant
Discharge Elimination System (NPDES) permit program and the Toxics Release Inventory (TRI)
indicated that this industry ranked high in discharges of toxic and nonconventional pollutants
[U.S. EPA, 2005b]. Because of these findings, EPA initiated a more detailed study of this
category to determine if the effluent guidelines should be revised.
During the detailed study, EPA investigated whether pollutant discharges reported under
these programs accurately reflected current discharges for the Steam Electric Power Generating
Point Source Category, including those associated with recent process and technology changes
being implemented by the industry. Additionally, EPA evaluated certain electric power and
steam generating activities that are similar to the processes regulated for the Steam Electric
Power Generating Point Source Category, but that are not currently subject to effluent
guidelines. EPA found that the existing publicly available data were insufficient to fully evaluate
the industry's discharges. To fill these data gaps, EPA collected information on wastewater
characteristics and treatment technologies through site visits, wastewater sampling, a data
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Final Detailed Study Report Chapter 1 - Introduction and Background of the Study
request that was sent to a limited number of companies, and various secondary data sources (see
Chapter 2 for more detail about data collection activities).
EPA focused efforts for these data collection activities on certain discharges from coal-
fired steam electric power plants (referred to in this report as "coal-fired power plants").
Specifically, these activities focused on: (1) characterizing the mass and concentrations of
pollutants in wastewater discharges from coal-fired power plants; (2) identifying the pollutants
that comprise a significant portion of the category's toxic-weighted pound equivalent (TWPE)
discharge estimate and the corresponding industrial processes responsible for the release of these
pollutants; and (3) evaluating process changes and treatment technologies available for reducing
these pollutant discharges. EPA's review determined that most of the toxic loadings for this
category are associated with metals and certain other constituents, such as selenium, present in
wastewater discharges, and that the waste streams contributing the majority of these pollutants
are associated with ash handling and wet FGD systems. Other potential sources of these
pollutants include coal pile runoff, metal cleaning wastes, coal washing, leachate from landfills
and wastewater impoundments, and certain low-volume wastes.
EPA evaluated pollution prevention practices and reviewed examples of water
recycle/reuse to identify opportunities to address water quality and water quantity issues.
Information was compiled for wastewaters generated by emerging technologies such as carbon
capture/sequestration and coal gasification.
EPA also assessed available information on plants that are not currently regulated by the
Steam Electric Power Generating effluent guidelines but that use a steam cycle to generate
electricity, such as steam electric generating units at industrial facilities and plants that use non-
fossil and non-nuclear fuel. Examples of such fuels include wood wastes, landfill methane, and
municipal solid wastes.
Throughout the study, EPA's Office of Water (OW) coordinated efforts with ongoing
research and activities being undertaken by other EPA offices, including the Office of Research
and Development (ORD), the Office of Solid Waste and Emergency Response (OSWER), and
the Office of Air and Radiation (OAR), specifically the Office of Air Quality Planning and
Standards (OAQPS) and the Office of Atmospheric Programs (OAP). EPA also exchanged
information with state NPDES permitting authorities about the characteristics of power plant
wastewater, the availability and implementation of treatment technologies, and water quality
concerns.
This report, Steam Electric Power Generating Point Source Category: Final Detailed
Study Report (EPA-821-R-09-008; DCN 06390), documents the data and information that EPA
has collected over the course of the detailed study. For additional information about the
progression of the detailed study since its inception, see the interim reports supporting the 2006
and 2008 Effluent Guidelines Program Plans: the Interim Detailed Study Report for the Steam
Electric Power Generating Point Source Category (EPA-821-R-06-015; November 2006) [U.S.
EPA, 2006e] and the Steam Electric Power Generating Point Source Category: 2007/2008
Detailed Study Report (EPA-821-R-08-011; DCN 05516) [U.S. EPA, 2008e], respectively.
1-2
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Final Detailed Study Report Chapter 1 - Introduction and Background of the Study
This report is organized into the following chapters:
• Chapter 2 discusses the data sources used in the detailed study;
• Chapter 3 presents a profile of the steam electric power generating industry,
including demographic data, a discussion of the steam electric process and
wastewaters generated, and a discussion of the Steam Electric Power Generating
effluent guidelines;
• Chapter 4 discusses FGD operations at coal-fired power plants, specifically their
current use in the industry, their operating characteristics and wastewater
generation, potential control technologies for FGD wastewater, and EPA's
pollutant load estimates associated with the discharge of FGD wastewaters;
• Chapter 5 discusses ash handling operations at coal-fired power plants, the
wastewater generated, and ash wastewater treatment;
• Chapter 6 discusses the environmental effects of coal combustion wastewaters;
• Chapter 7 discusses plants and processes that are not regulated by the Steam
Electric Power Generating effluent guidelines, but that use a steam cycle to
generate electricity; and
• Chapter 8 presents the references cited in this report.
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Final Detailed Study Report Chapter 2 - Data Collection Activities
2. DATA COLLECTION ACTIVITIES
EPA collected and evaluated information from various sources in the course of
conducting the detailed study of the steam electric power generating industry. EPA used these
data to develop an industry profile, determine wastewater characteristics and potential pollution
control technologies, review the potential pollutant load reductions and costs associated with
certain treatment technologies, and review environmental impacts associated with discharges
from this industry. This section discusses the following data collection activities:
• Site visits, including the site selection process, characteristics of the sites visited,
and their locations;
• Wastewater sampling, including information about and the locations of plants
sampled, types of samples collected, analytes included in the sampling program,
and analytical methods used;
• Industry questionnaire, including the characteristics and location of plants
responding to the questionnaire, and a description of the data request instrument;
• Coordination and informal consultations with EPA program offices, EPA regional
offices, and state permitting agencies, including information collected from
Agency databases;
• Interactions with UWAG, including input from and coordination with UWAG on
sampling, site visits, and other data;
• Interactions with EPRI, including input from EPRI on EPA's wastewater
sampling and questionnaire activities;
• Use of Department of Energy (DOE) data, including the use of data collected by
the Energy Information Administration; and
• Other data sources.
As described in Chapter 1, EPA focused most efforts for the detailed study on certain
discharges from coal-fired power plants, including FGD system wastes and ash handling wastes.
Figure 2-1 shows the locations of coal-fired power plants at which EPA conducted site visits,
collected samples of wastewater, or obtained technical information via the questionnaire.
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Final Detailed Study Report Chapter 2 - Data Collection Activities
Figure 2-1. Locations of Coal-Fired Power Plants Included in EPA Data Collection
Activities for the Detailed Study
2.1 Site Visits
EPA conducted a site visit program to gather information on the types of wastewaters
generated by coal-fired power plants, and the methods of managing these wastewaters to allow
for recycle, reuse, or discharge. EPA focused data gathering activities primarily on FGD
wastewater treatment and management of ash transport water because the FGD and ash transport
water stream are the primary sources of metal discharges from the industry. EPA conducted 34
site visits at steam electric power generating plants in 14 states between December 2006 and
April 2009.
The purpose of the site visits was to collect information about each site's electric
generating processes, wastewater management practices and treatment technologies, and to
evaluate each plant for potential inclusion in the sampling program. To identify potential
candidate plants for visits, EPA began by compiling a list of U.S. coal-fired power plants
believed to operate wet FGD systems, based on information from EPA's Office of Air and
Radiation and data provided by the Utility Water Act Group. EPA used the Utility Water Act
Group data in conjunction with information from other sources, including publicly available
plant-specific information and state and regional permitting authorities.
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Final Detailed Study Report Chapter 2 - Data Collection Activities
From its data collection activities, EPA identified 108 plants that as of June 2008 were
operating one or more wet FGD systems. *
EPA considered the following characteristics to select plants for site visits (not listed in
any priority order):
• Coal-fired boilers;
• Type of coal;
• Wet FGD system, including:
— Type of scrubber,
— Sorbent used,
— Year operation began,
— Chemical additives used,
— Forced oxidation process,
— Water cycling, and
— Solids removal process.
• FGD wastewater treatment system;
• Selective catalytic reduction (SCR) and/or selective non-catalytic reduction
(SNCR) NOX controls;
• Ash handling systems;
• Ash treatment system; and
• Advanced flue gas mercury controls.
Using these characteristics, EPA identified plants to contact in order to obtain more
detailed information about their operations. From the information obtained during these contacts,
EPA selected plants for site visits. Plant conditions, such as type of FGD system and whether
target waste streams are segregated or commingled with other wastes, influenced the plant
selection process.
The specific objectives of these site visits were to:
• Gather general information about each plant's operations;
• Gather information on pollution prevention and wastewater treatment/operations;
• Gather plant-specific information to develop sampling plans; and
• Select and evaluate potential sampling points.
1 See the memorandum in the docket entitled "Development of the Current and Future Industry Profile for the Steam
Electric Detailed Study," dated 10/9/2009 [ERG, 2009r] for details on the development of this list. The total number
of plants operating wet FGD systems is dynamic; additional plants have started operating FGD systems since EPA
compiled this profile or are currently in the process of installing FGD systems.
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Chapter 2 - Data Collection Activities
Based on information obtained during these site visits, EPA selected six plants for
wastewater sampling episodes, which are discussed further in Section 2.2.
Table 2-1 presents information on the characteristics of each plant visited during the site
visit program. The geographic distribution of these plants is illustrated by the map in Figure 2-2.
\
Legend
A Plants that were visited by EPA and were not sampled
A Plants that were sampled during the EPA's detailed study (EPA conducted pre-sampling visits at each of these plants)
Figure 2-2. Locations of Coal-Fired Power Plants Included in EPA's Site Visit and
Sampling Program
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Final Detailed Study Report
Chapter 2 - Data Collection Activities
Table 2-1. Summary of the Detailed Study Site Visits
Plant Name
Location
(Reference)
Yates
Georgia
[ERG, 2007f]
Wansley
Georgia
[ERG, 2007e]
Widows Creek
Alabama
[ERG, 2007h; ERG,
2007k]
Conemaugh
Pennsylvania
[ERG, 20071]
Homer City
Pennsylvania
[ERG, 2007i; ERG,
2007J]
Pleasant Prairie
Wisconsin
[ERG, 2007d]
Bailly
Indiana
[Hall, 2007]
Seminole
Florida
[Jordan, 2007]
Big Bend
Florida
[ERG, 2007b; ERG,
2007g]
Month/Year of
Site Visit
December 2006
December 2006
December 2006
February 2007
February 2007
April 2007
April 2007
April 2007
April 2007
Coal Type
Eastern Bituminous
Eastern Bituminous
Eastern Bituminous
Eastern Bituminous
Eastern Bituminous
Subbituminous
(Powder River
Basin)
Bituminous (75%),
Eastern Bituminous
(25%)
Eastern Bituminous,
also burns
petroleum coke as a
small percentage
(up to 30%)
Eastern Bituminous,
also burns
petroleum coke as a
small percentage
(typically 1-2%; 5%
maximum)
FGD System a
Jet-bubbling reactor, limestone
forced oxidation, no additives (1
unit)
Installation in progress during
site visit
Spray tower, limestone forced
oxidation b, no additives (2
units)
Spray tower, limestone forced
oxidation, dibasic acid additive
(2 units)
Spray tower, limestone forced
oxidation, formic acid additive
(1 unit)
Spray tower, limestone forced
oxidation, no additives (2 units)
Spray tower, limestone forced
oxidation, no additives (2 units)
Spray tower, limestone forced
oxidation, dibasic acid additive
(2 units)
Two scrubbers for 4 units (2
units per scrubber): (1) spray
tower, limestone forced
oxidation, and (2) double loop
spray tower, limestone forced
oxidation, dibasic acid additive
Year FGD
Began
Operation
1992
NA
1977 and
1981
1994 and
1995
2001
2006 and
2007
1992
1984
1985
(double
loop) and
2000
(spray
tower)
SCR/SNCR
NOX Control
No SCR or
SNCR
SCRs on 2
units
SCRs on both
units with
FGD
No SCR or
SNCR
SCRs on 3
units
SCRs on both
units with
FGD
SCR on one
of the units
with FGD
No SCR or
SNCR
SCR on one
unit; will
install SCRs
on the other
units over the
next 3 years
Type of FGD Wastewater
Treatment System
Settling pond
Visited prior to installation of
settling pond
Settling pond
Chemical precipitation (lime
addition, ferric chloride,
sodium sulfide, polymer),
followed by aerobic sequencing
batch reactors
Chemical precipitation (lime
addition, ferric chloride,
polymer), followed by aerobic
biological reactor
Chemical precipitation (lime
addition, organosulfide, ferric
chloride, polymer)
Polymer addition only; no pH
adjustment
Chemical precipitation (lime
addition, ferrous chloride,
polymer)
Chemical precipitation (lime
addition, ferric chloride,
polymer)
Fly Ash
Handling
(wet/dry)
Wet
Wet
Wet
Dry
Dry
Dry
Dry
Dry
Dry
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Table 2-1. Summary of the Detailed Study Site Visits
Plant Name
Location
(Reference)
Cayuga
New York
[Jordan, 2008b]
Mitchell
West Virginia
[ERG, 2007o]
Cardinal
Ohio
[ERG, 2007n]
Bruce Mansfield
Pennsylvania
[U.S. EPA, 2008d]
Roxboro
North Carolina
[Jordan, 2008a]
Belews Creek
North Carolina
[ERG, 2008h]
Marshall
North Carolina
[ERG, 2008i]
Mount Storm
West Virginia
[ERG, 2008p]
Month/Year of
Site Visit
May 2007
May 2007
May 2007
October 2007
March 2008
March 2008
March 2008
September 2008
Coal Type
Eastern Bituminous
Eastern Bituminous
Subbituminous
Bituminous
Eastern Bituminous
Eastern Bituminous
Eastern Bituminous,
additionally bums a
small percentage of
South American
coal (2%)
Bituminous
FGD System a
Spray tower, limestone forced
oxidation, formic acid additive
(2 units)
Spray tower, limestone forced
oxidation, no additives (2 units)
Installation in progress during
site visit
Venturi scrubber, magnesium-
enhanced lime, inhibited
oxidation (2 units); horizontal
spray scrubber, magnesium-
enhanced lime, inhibited
oxidation (1 unit); additional
forced oxidation as separate
process for all 3 units
Tray tower, limestone forced
oxidation, no additive (2 units
operating, 2 more units planned
for 2008)
Spray tower, limestone forced
oxidation (1 unit operating, 1
more unit planned for 2008)
Spray tower, limestone forced
oxidation. (3 scrubbers for 4
units)
Spray tower, limestone forced
oxidation, no additives (3 units)
Year FGD
Began
Operation
1995
NA
NA
1976,
1977, and
1980
2007 and
2008)
2008
2006 and
2007
1995 and
2002
SCR/SNCR
NOX Control
SCR on 1 unit
SCRs on both
units with
FGD
SCRs on 3
units
SCRs on 3
units
SCRs on 4
units
SCRs on 2
units
SNCRs on 4
units
SCRs on 3
units
Type of FGD Wastewater
Treatment System
Chemical precipitation (lime
addition, ferric chloride,
polymer)
Chemical precipitation (lime
addition, ferric chloride,
polymer)
Currently being installed
Surface impoundment (settling)
Settling pond followed by a
anaerobic/anoxic biological
treatment system for removal of
metals and nutrients
Chemical precipitation
followed by anaerobic/anoxic
biological treatment for
removal of metals and nutrients
followed by a constructed
wetland treatment system
Clarifier followed by a
constructed wetland treatment
system
No FGD wastewater
discharged; FGD solids
landfilled (leachate from FGD
landfill treated by settling
ponds and discharged)
Fly Ash
Handling
(wet/dry)
Dry
Wet
Wet
Wet
Dry (but wet
capability)
Dry (but wet
capability)
Dry (but wet
capability)
Dry
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Chapter 2 - Data Collection Activities
Table 2-1. Summary of the Detailed Study Site Visits
Plant Name
Location
(Reference)
Harrison
West Virginia
[ERG, 2009c]
Mountaineer
West Virginia
[ERG, 2009u]
Gavin
Ohio
[ERG, 2009b]
Deely
Texas
[ERG, 2009o]
Clover
Virginia
[ERG, 2009d]
JK Spruce
Texas
[ERG, 2009o]
Fayette Power
Project/Sam Seymour
Texas
[ERG, 2009p]
Month/Year of
Site Visit
September 2008
September 2008
September 2008
October 2008
October 2008
October 2008
October 2008
Coal Type
Eastern Bituminous
Eastern Bituminous
Eastern Bituminous
NA
Eastern Bituminous
Subbituminous
(Powder River
Basin)
Subbituminous
(Powder River
Basin)
FGD System a
Spray tower, magnesium-
enhanced lime inhibited
oxidation (2 units); emulsified
sulfur added
Spray tower, limestone forced
oxidation, no additives (1 unit)
Spray tower, magnesium-
enhanced lime inhibited
oxidation (2 units); emulsified
sulfur added
Considering dry and limestone-
forced oxidation wet scrubbers
(2 units)
Spray tower, limestone forced
oxidation (2 units)
Spray tower, limestone natural
oxidation, no additives (1 unit -
but plans to convert to limestone
forced oxidation in future);
spray tower, limestone forced
oxidation, no additives (1 unit
planned)
Spray tower, limestone forced
oxidation, no additives (1 unit
operating, 2 units planned)
Year FGD
Began
Operation
1994
2007
1994 and
1995
Planned
for 20 12
and 20 13
1995 and
1996
1992,2010
1988 (and
2 units
planned for
2010)
SCR/SNCR
NOX Control
SCRs on 3
units
SCR on 1 unit
SCRs on 2
units
SCRs planned
on 2 units by
2015
SNCRs on
both units
SCR on 1
unit; SCR
expected by
20 15 on other
unit
No SCR
Type of FGD Wastewater
Treatment System
No FGD wastewater
discharged; FGD solids
landfilled (leachate from lined
portion of FGD landfill flows
into settling ponds and leachate
from unlined portion of FGD
landfill is transferred to a
constructed wetlands treatment
system and then discharged)
Chemical precipitation (lime
addition, polymer, ferric
chloride)
No FGD wastewater
discharged; FGD solids
landfilled (leachate from FGD
landfill collected in settling
ponds and discharged)
To be determined
No FGD wastewater
discharged; FGD solids
landfilled
Settling pond followed by a
clarifier with polymer addition.
No FGD wastewater discharged
Fly Ash
Handling
(wet/dry)
Dry
Dry
Dry
Dry
Dry
Dry
Dry
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Chapter 2 - Data Collection Activities
Table 2-1. Summary of the Detailed Study Site Visits
Plant Name
Location
(Reference)
Ghent
Kentucky
[ERG, 2009g]
Trimble County
Kentucky
[ERG, 2009J]
Cane Run
Kentucky
[ERG, 2009h]
Mill Creek
Kentucky
[ERG, 2009i]
Brandon Shores
Maryland
[ERG, 2009k]
Kenneth C Coleman
Kentucky
[ERG, 2009m]
Month/Year of
Site Visit
December 2008
December 2008
December 2008
December 2008
January 2009
February 2009
Coal Type
Eastern Bituminous,
previously would
occasionally burn
50/50 mixture of
Eastern
Bituminous/Powder
River Basin in 2
units
Eastern Bituminous
in one unit; 70/30
mixture of Eastern
Bituminous/Powder
River Basin for
planned unit
Eastern Bituminous
Eastern Bituminous
Eastern Bituminous
Bituminous
FGD System a
Tray tower, limestone forced
oxidation, no additives currently
used (DBA capability) (3 units
operating, 1 unit planned)
Spray tower, limestone forced
oxidation, no additives currently
used (DBA capability for
operating unit) (1 unit operating,
1 unit planned)
Spray tower, lime inhibited
oxidation (2 units); spray tower,
lime inhibited oxidation and
sodium carbonate dual-alkali (1
unit); emulsified sulfur added to
all three units
Tray tower, limestone forced
oxidation (4 units)
Tray tower, limestone forced
oxidation (planned for 2 units)
Tray tower, limestone forced
oxidation (1 scrubber for 3
units)
Year FGD
Began
Operation
1994,
2007,
2008, (and
1 unit
planned for
2009)
1990(1
unit
planned for
2010)
1976,
1977, and
1978
1978,
1980,
1981, and
1982
1 unit
planned for
2009 and
one
planned for
2010
2006
SCR/SNCR
NOX Control
SCRs on 2
units
SCRs on 2
units
No SCRs
SCRs on 2
units
SCRs on 2
units
No SCRs
Type of FGD Wastewater
Treatment System
Settling pond
No FGD wastewater
discharged; FGD solids are
stored in a settling pond (plant
completely reuses the
wastewater in the settling pond)
[Note: configuration of
treatment system will change in
2010 to settling pond when new
unit begins operation]
Settling pond
Settling pond
Chemical precipitation (lime
addition, organosulfide, ferric
chloride); aerobic/anoxic
biological sequencing batch
reactors
Clarifier and filter
Fly Ash
Handling
(wet/dry)
Wet
Wet and dry
capability
Dry
Dry (but wet
capability)
Dry
Wet
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Chapter 2 - Data Collection Activities
Table 2-1. Summary of the Detailed Study Site Visits
Plant Name
Location
(Reference)
Gibson
Indiana
[ERG, 2009e]
Paradise
Kentucky
[ERG, 20091]
Wabash River
Indiana
[ERG, 2009f; ERG,
2009v]
Miami Fort
Ohio
[ERG, 2009r]
Month/Year of
Site Visit
February 2009
February 2009
February 2009
April 2009
Coal Type
Bituminous
Bituminous
Petroleum coke
(IGCC unit);
Bituminous (5
pulverized coal
units)
Eastern Bituminous
FGD System a
Spray tower, limestone forced
oxidation for 3 units (Units 1,2,
and 3); horizontal flow,
limestone forced oxidation for 1
unit (Unit 5); spray tower,
limestone inhibited oxidation for
1 unit (emulsified sulfur added)
(Unit 4)
Spray tower, limestone forced
oxidation (3 units)
No FGD systems
Spray tower, limestone forced
oxidation (2 units); no additives
Year FGD
Began
Operation
1982,
1995,
2006, and
2007
1982(2
units) and
2006 (1
unit)
NA
2007
SCR/SNCR
NOX Control
No
information
SCRs on 2
units
No SCR or
SNCR
SCRs on 2
units
Type of FGD Wastewater
Treatment System
No FGD wastewater discharged
from the Unit 4 and 5 FGD
systems. Chemical precipitation
(ferric chloride and polymer)
treatment for the FGD
wastewater from Units 1 , 2, and
3. The treated FGD wastewater
is sent to the cooling lake and
recycled for plant use. The
plant is constructing a system to
inject the treated FGD
wastewater into underground
geological formations.
Settling pond
NA
Chemical precipitation (lime
addition, organosulfide, ferric
chloride, polymer)
Fly Ash
Handling
(wet/dry)
Wet (3 units)
and dry (2
units)
Wet
Wet (but
converting
one unit to
dry)
Wet (1 unit)
and dry (2
units)
a - The number of generating units in parentheses is also the number of FGD systems unless otherwise specified.
b - The FGD system is a once-through system in which the gypsum slurry in the scrubber reaction tank is not recycled back through the scrubber, but rather, is
continuously discharged.
NA - Not available.
Note: The table reflects the data collected at the time of each individual site visit and does not reflect changes that have occurred since the site visits were
conducted.
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Chapter 2 - Data Collection Activities
2.2 Wastewater Sampling
EPA conducted a sampling program to characterize untreated wastewaters generated by
coal-fired power plants, as well as to evaluate treatment technologies and best management
practices for reducing pollutant discharges. EPA developed a "generic" sampling plan [ERG,
2007c] to provide general sampling procedures and methods that were followed when
conducting sampling activities. The generic sampling plan, in combination with plant-specific
sampling plans, served as a guide to the field sampling crew and provided procedural
information for plant personnel.
Between July 2007 and October 2008, EPA collected and analyzed samples to
characterize wastewater streams at six coal-fired power plants. Specifically, EPA characterized
wastewater streams associated with wet FGD systems and ash handling operations and evaluated
the capability of various types of treatment systems to remove metals and other pollutants of
concern prior to discharge. Table 2-2 presents information on the plants selected for the sampling
program. The plant locations are shown in Figure 2-2.
Table 2-2. Summary of the Detailed Study Sampling Program
Plant Name
Big Bend
Homer City
Widows
Creek
Mitchell
Cardinal
Belews Creek
Sampling
Episode
No.
6547
6548
6549
6550
6551
6557
Date of
Sampling
Episode
July 2007
August 2007
September
2007
October
2007
October
2007
October
2008
Type of Samples Collected
FGD Treatment System
Influent
•/
•/
•/
•/
•/
In-Process
•/
•/
•/
Effluent
•/
•/
•/
•/
•/
Ash Pond
Influent
^
(fly + bottom)
^
(fly ash)
Effluent
•/
(bottom ash)
•/
(fly + bottom)
•/
(fly ash + other)
^
(fly ash)
The sampling program consisted of one-day or two-day sampling episodes at the six
selected plants. EPA prepared sampling episode reports for each plant, describing the specific
sample points, the sample collection methods used, the field quality control samples collected,
and the laboratory analytical results. The reports for these six episodes are in the docket for the
Preliminary 2010 Effluent Guidelines Program Plan [ERG, 20081; ERG, 2008m; ERG, 2008k;
ERG, 2008n; ERG, 2008o; ERG, 2009q].
Table 2-3 lists the analytes for which EPA collected sampling data. The analytes listed
generally reflect the expected characteristics of coal-fired power plant wastewaters, including
contributions from coal, scrubber sorbents, treatment chemicals, and other sources. Several
analytes, such as yttrium, were included in the analyte list because of pre-established laboratory
contracts and perhaps would not have been individually selected for inclusion.
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Table 2-3. Analytes Included in the Detailed Study Sampling Program
Parameter
Method Number
(Sampling Episodes 6547,
6548, 6549, 6550, 6551)
Method Number
(Sampling Episode
6557)
Classical*
Biochemical Oxygen Demand (5-day) (BOD5)
Chemical Oxygen Demand (COD)
Total Suspended Solids (TSS)
Total Dissolved Solids (TDS)
Sulfate
Chloride
Ammonia as Nitrogen
Nitrate/Nitrite as Nitrogen
Total Kjeldahl Nitrogen (TKN)
Total Phosphorus
Hexane Extractable Material (HEM)
Silica Gel Treated Hexane Extractable Material (SGT-HEM)
SM5210B
a
SM 2540 D
SM 2540 C
ASTMD5 16-90
SM 4500-C1-C
SM 4500— NH3 F (18th
ed.)
SM 4500-NO3 H b
SM 4500— N, C
EPA 365.3 (Rev 1978)
EPA 1664A
EPA 1664A
SM5210B
SM 5220 C
SM 2540 D
SM 2540 C
EPA 300.0
EPA 300.0
EPA 350.1
EPA 353. 2
EPA 35 1.2
EPA 365.2
EPA 1664A
EPA 1664A
Metals
Total and Dissolved Metals (27 Metals: Aluminum,
Antimony, Arsenic, Barium, Beryllium, Boron, Cadmium,
Calcium, Chromium, Cobalt, Copper, Iron, Lead,
Magnesium, Manganese, Mercury, Molybdenum, Nickel,
Selenium, Silver, Sodium, Thallium, Tin, Titanium,
Vanadium, Yttrium, Zinc)
Low-Level Total and Dissolved Metals (11 Metals:
Antimony, Arsenic, Cadmium, Chromium, Copper, Lead,
Nickel, Selenium, Silver, Thallium, Zinc)
Low-Level Total and Dissolved Mercury
Hexavalent Chromium
Low-Level Hexavalent Chromium
EPA 200.7
EPA 245.1
EPA 245.5
EPA 1638
EPA 163 IE
ASTMD 1687-92
EPA 1636
EPA 200.7 c
EPA 200.8 c
EPA 200.8 with DRC d
EPA 1638
EPA 163 8 with DRC e
HG-AFS f
EPA 163 IE
EPA 218.6
EPA 1636
a - COD was analyzed only for Sampling Episode 6557.
b - EPA Method 353.2 was used for the nitrate/nitrite analysis for Sampling Episode 6548. Standard Method 4500-NO3-
H was used for Sampling Episodes 6549, 6550, and 6551. Nitrate/nitrite was not analyzed in Sampling Episode 6547
because a laboratory instrument failure delayed analysis until the sample holding time was exceeded.
c - Molybdenum, tin, titanium, and yttrium were not analyzed by EPA Methods 200.7 or 200.8 for Sampling Episode
6557. Additionally, mercury was not analyzed by EPA Method 245.1 for Sampling Episode 6557.
d - Samples were analyzed for arsenic, chromium, iron, manganese, nickel, selenium, vanadium, and zinc using EPA
Method 200.8 with a dynamic reaction cell (DRC) instrumentation for Sampling Episode 6557.
e - Samples were analyzed for arsenic, chromium, nickel, selenium, and zinc using EPA Method 1638 with a DRC for
Sampling Episode 6557.
f - Samples were analyzed for arsenic and selenium using hydride generation and atomic fluorescence spectrometry
(HG-AFS) using Frontier Geosciences Method 055 (modified SM 3114) for Sampling Episode 6557.
During the sampling program, EPA also collected data on the design, operation, and
performance of treatment systems at steam electric plants, specifically regarding system design
and day-to-day operation. The sampling activities were focused on influent, effluent, and in-
process streams for FGD and ash handling wastewater treatment systems. During each sampling
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Final Detailed Study Report Chapter 2 - Data Collection Activities
episode, EPA collected engineering information regarding the design and operation of the plant
being sampled, such as coal usage, plant capacity, wastewater flow rates, sludge generation rates,
and retention times in wastewater treatment process stages. Engineering data collection sheets
were completed for each plant.
EPA used data from the sampling program to help identify the pollutants present in
wastewater streams generated by or associated with wet ash handling systems and SO2/NOX air
pollution controls (e.g., wet FGD systems, SCR/SNCR). The data were also used to characterize
the performance of wastewater treatment systems.
2.3 Questionnaire ("Data Request")
EPA collected information from a limited number of coal-fired power plants using a
questionnaire issued under authority of Section 308 of the Clean Water Act (Data Request for
the Steam Electric Power Generating Industry)., referred to in this report as the "data request"
[U.S. EPA, 2007a]. The data request complemented EPA's site visit and sampling program by
obtaining information about wastewater generation rates and management practices for the FGD
and ash transport water waste streams, other waste streams not sampled by EPA's sampling
program (e.g., coal pile runoff), and other power plant information as described below.
EPA selected nine power companies to receive the data request based on specific
characteristics of plants they operate. These companies all operate coal-fired plants that have wet
FGD systems and/or wet fly ash handling systems. Table 2-4 presents a profile of the coal-fired
power plants operated by the nine selected companies (referred to in this report as "data request
respondents"). As shown in Table 2-4, the data request respondents operated a total of 67 coal-
fired power plants and provided technical information for 30 of these coal-fired power plants as
instructed by Part B of the data request. These 30 coal-fired power plants (i.e., the "data request
plants") either operated wet FGD systems as of October 2007, and/or were planning to begin
constructing wet FGD systems by December 31, 2010. The plants that are most likely to operate
FGD systems are those that burn eastern bituminous coal, which has relatively high sulfur
content, so the vast majority of the data request plants are located in the eastern United States.
Figure 2-3 shows the location of the data request plants.
EPA distributed the data request to the nine selected power companies in May 2007 and
received data request responses in August and October 2007 . The data requests were divided
into two parts: Part A, General Power Company Information; and Part B, Power Plant Technical
Information. EPA requested that each power company complete Part A of the data request and to
complete Part B of the data request for each coal-fired power plant they operate that meets the
following criteria: was in operation in calendar year 2006; and operates at least one wet FGD
system and/or is currently constructing/installing (or plans to begin constructing prior to
December 31, 2010) at least one wet FGD system.
2 EPA received data request responses from each of the nine data request respondents in August 2007. One
respondent also provided a Part B response for one data request plant in October 2007.
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Chapter 2 - Data Collection Activities
Table 2-4. Profile of Coal-Fired Power Plants Operated by Data Request Respondents
Company
Number
1
2
3
4
5
6
7
8
9
Total
Coal-Fired Power Plants Operated by Data
Request Respondents
Total
No. of
Plants
10
6
16
8
10
3
8
4
2
67
Number
Currently
Operating
Wet FGD
Systems b
3
1
2
1
1
3
1
2
2
16
Number Not Currently
Operating Wet FGD
Systems, But Planning
to Begin Constructing
by 12/31/2010 b
2
1
1
o
6
4
0
2
0
0
13 c
Plants for which Data Request Respondents
Provided Technical Information a
Total
No. of
Plants
5
2
3
4
6
3
o
5
2
2
30 c
Number with
Segregated FGD
Wastewater
Treatment System
(Operating) b
0
1
0
1
1
0
1
0
0
4
Number with
Wet Fly Ash
Systems
0
1
1
2
6
3
2
0
2
17
Source: [U.S. EPA, 2008a].
a - Plants within the scope of Part B of the data request.
b - Based on information provided in the data request responses, as of October 2007.
c - EPA received data request technical information for 30 coal-fired power plants. One company initially reported
plans to install wet FGD systems atone plant by December 31, 2010; however, during follow-up communications,
the company informed EPA that they subsequently decided not to install wet FGD systems as part of the company's
long-term air pollution control strategies.
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Chapter 2 - Data Collection Activities
I
Legend
O Currently operating one or more wet FGD systems
• Not currently operating wet FGD systems, but planning to begin constructing by 12/31/2010
Source: [U.S. EPA, 2008a].
Note: Based on information provided in the data request responses, as of October 2007.
Figure 2-3. Locations of Coal-Fired Power Plants for which Data Request Respondents
Provided Technical Information
Part A requested the following: company contact information; corporate structure
information; and profile information for the coal-fired power plants that the companies currently
operate and that were in operation during 2006. Part B requested the following information:
•
General plant information, including address and contact information.
Steam electric power production information and fuels used for each steam
electric unit that the plant operated in 2006.
Wastewater generation information, including flow rate data, for the following
wastewaters: coal pile runoff; coal pulverizer waste streams; wastewaters from
ash handling and air pollution control systems (FGD, SCR/SNCR, and enhanced
mercury air controls); and cooling water.
Operation of each wastewater treatment system at each plant and the associated
wastewater flow rates; flow rates for untreated wastewaters; and a diagram for
each plant including all coal-fired steam electric process operations, wastewater
treatment systems, and treated and untreated flows.
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Final Detailed Study Report Chapter 2 - Data Collection Activities
• Operation and maintenance cost data for each wastewater treatment system
operated in 2006 and capital cost data for each FGD wastewater treatment system
constructed between January 01, 1997, and December 31, 2006.
• Monitoring data that the plant collected for any reason during 2006 for coal-fired
steam electric wastewater streams that meet certain sample location and analyte
criteria.
In developing the data request, EPA worked with industry trade associations and other
EPA program offices to develop questions that addressed the needs of the detailed study while
minimizing respondent burden. After distributing the data request to the nine data request
respondents, EPA provided assistance and clarification regarding the data request questions
directly via a help line and indirectly via UWAG.
EPA conducted a technical review of the data request responses to ensure the quality and
consistency of the data. Following the technical review of each data request response, EPA
communicated with the data request respondents to resolve questions and/or discrepancies found.
Once resolved, EPA key-entered the revised data request responses into a database and
conducted a quality assurance check of the key-entered data [ERG, 2008J]. A database
containing the responses to the data request is included in the docket for the Final 2008 Effluent
Guidelines Program Plan. A portion of the information provided by data request respondents was
claimed as confidential business information. In these cases, EPA has provided sanitized
versions of the data request responses.
2.4 EPA and State Sources
Throughout the detailed study, EPA collected information from the Agency's databases
and publications and state groups and permitting authorities, including the following, which are
discussed further in the subsections below:
• Information on current permitting practices for the steam electric industry from a
review of selected National Pollutant Discharge Elimination System (NPDES)
permits and accompanying fact sheets;
• Input from EPA and state permitting authorities regarding implementation of the
Steam Electric Power Generating effluent guidelines;
• Background information on the steam electric industry from documents prepared
during the development of the Steam Electric Power Generating effluent
guidelines;
• Information from a survey of the industry conducted in support of the Clean
Water Act Section 316(b) Cooling Water Intake Structures rulemaking;
• Information from EPA's OAR used to predict impacts from environmental
policies;
• Information from EPA's ORD characterizing coal combustion residues (CCRs)
and the potential leaching of these CCRs from landfills and surface
impoundments;
• Information collected by EPA's OSWER regarding surface impoundments or
other similar management units that contain CCRs at power plants.
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Final Detailed Study Report Chapter 2 - Data Collection Activities
Other data sources include the Permit Compliance System (PCS) and Toxics Release
Inventory (TRI) databases, from which EPA obtained initial information on reported pollutant
releases from the electric generating industry, and the Office of Enforcement and Compliance
Assistance (OECA) Sector Notebook, Profile of the Fossil Fuel Electric Power Generation
Industry [U.S. EPA, 1997].
EPA's Office of Water has coordinated its efforts with ongoing research and activities
being undertaken by other EPA offices, including the Office of Air and Radiation (OAR), the
Office of Research and Development (ORD), the Office of Solid Waste and Emergency
Response (OSWER), the Office of Enforcement and Compliance Assurance, and EPA regional
offices.
2.4.1 NPDES Permits and Fact Sheets
The CWA requires direct dischargers (i.e., industrial facilities that discharge process
wastewaters from any point source into receiving waters) to control their discharges according to
effluent guidelines and water quality-based effluent limitations included in NPDES permits.
EPA reviewed selected NPDES permits and, where available, accompanying fact sheets
to identify the sources of wastewater at steam electric plants and to determine how the
wastewaters are currently regulated (i.e., effluent limitations for specific parameters and the basis
for selecting the parameters). As part of the NPDES permit review, EPA contacted state permit
writers to obtain additional information or clarify permit information.
2.4.2 State Groups and Permitting A uthorities
Throughout the detailed study, EPA interacted with states and EPA regional permitting
authorities. When contacting and visiting power plants, EPA coordinated with state and regional
permit writers. EPA solicited input and suggestions from states and permitting authorities on
specific power plant characteristics and implementation of the Steam Electric Power Generating
effluent guidelines. EPA hosted a webcast seminar in December 2008 to review information on
wastewater discharges from coal-fired power plants for NPDES permitting and pretreatment
authorities. The webcast provided an update on EPA's review of the current effluent guidelines
(40 CFR Part 423) and presented information on pollutant characteristics and treatment
technologies for wastewater from FGD scrubbers. During the webcast, state and interstate
approaches for managing steam electric power plant wastewaters were shared by representatives
from Wisconsin, North Carolina, and the Ohio River Valley Water Sanitation Commission
(ORSANCO).
2.4.3 1974 and 1982 Technical Development Documents for the Steam Electric Power
Generating Point Source Category
The 1974 Development Document for Effluent Limitations Guidelines and New Source
Performance Standards for the Steam Electric Power Generating Point Source Category
(referred to in this report as "the 1974 Development Document") [U.S. EPA, 1974] and the 1982
Development Document for Effluent Limitations Guidelines and Standards and Pretreatment
Standards for the Steam Electric Point Source Category (referred to in this report as "the 1982
Development Document") [U.S. EPA, 1982] present the results of studies of the steam electric
industry that EPA conducted in developing the Steam Electric Power Generating effluent
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Final Detailed Study Report Chapter 2 - Data Collection Activities
guidelines. These development documents contain findings, conclusions, and recommendations
on control and treatment technology relating to discharges from steam electric power plants. In
this detailed study, EPA used the information presented in the 1974 and 1982 Development
Documents for historical background on the Steam Electric Power Generating effluent guidelines
and for information on sources of pollutants.
2.4.4 CWA Section 316(b) - Cooling Water Intake Structures Supporting Documentation
and Data
For the CWA section 316(b) Cooling Water Intake Structures rulemaking, EPA
conducted a survey of steam electric utilities and steam electric non-utilities that use cooling
water, as well as facilities in four other manufacturing sectors: Paper and Allied Products (SIC
code 26), Chemical and Allied Products (SIC code 28), Petroleum and Coal Products (SIC code
29), and Primary Metals (SIC code 33). The survey requested the following types of information:
• General plant information, such as plant name, location, and SIC codes;
• Cooling water source and use;
• Design and operational data on cooling water intake structures and cooling water
systems;
• Studies of the potential impacts from cooling water intake structures conducted by
the facility; and
• Financial and economic information about the facility.
Although the Section 316(b) survey was used to create guidelines for cooling water
intake structures, the cooling water system information collected in the survey was useful for the
detailed study of the steam electric industry. EPA used the information provided by the Section
316(b) survey in the following analyses:
• Linking Energy Information Administration (EIA) facility information to the TRI
and PCS discharges;
• Identifying the type of cooling systems used by facilities; and
• Identifying industrial non-utilities.
2.4.5 Office of A ir and Radiation
EPA's Office of Air and Radiation (OAR) develops national programs, technical policies,
and regulations for controlling air pollution and radiation exposure. EPA used the 2006
Integrated Planning Model (IPM) database used by OAR to estimate the projected scrubbed
capacity for the future industry profile [U.S. EPA, 2006]. The IPM was developed by ICF
Consulting, Inc. and is used to estimate the projected impacts from environmental policies on the
electric power sector. IPM Version 3.0 projects the electric generating capacity for various "plant
types" at different run years in the future (i.e., 2010, 2015, 2020, and 2025). EPA used the data
from run year 2020 as a basis for future industry profile for this study, which EPA used to assess
future growth of FGD usage in the industry. Additionally, EPA used OAR's Acid Rain Database
[ERG, 2007a] and NEEDS 2006 database [U.S. EPA, 2006h] to supplement information
collected on characteristics of plants within the steam electric industry.
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Final Detailed Study Report Chapter 2 - Data Collection Activities
2.4.6 Office of Research and Development
EPA's Office of Research and Development is currently evaluating the impact of air
pollution controls on the characteristics of coal combustion residues (CCRs). Specifically, the
Office of Research and Development is studying the potential cross-media transfer of mercury
and other metals from flue gas, fly ash, and other residues collected from coal-fired boiler air
pollution controls and disposed of in landfills or surface impoundments. The key routes of
release being studied are leaching into groundwater or subsequent release into surface waters, re-
emission of mercury, and bioaccumulation. The Office of Research and Development is also
examining the use of CCRs in asphalt, cement, and wallboard production.
This research seeks to better understand potential impacts from disposal practices and
beneficial use of CCRs by taking a holistic approach, evaluating life-cycle environmental
tradeoffs that compare beneficial use applications with and without using CCRs. The outcome of
this research will help to identify potential management practices of concern where
environmental releases may occur, such as the development and application of a leach testing
framework that evaluates a range of materials and the different factors affecting leaching for the
varying field conditions in the environment.
EPA's Office of Water consulted with the Office of Research and Development on the
status and findings of current research assessing the potential for CCRs to impact water quality.
2.4.7 Office of Solid Waste and Emergency Response
EPA's Office of Solid Waste and Emergency Response (OSWER) recently issued
Information Request Letters to electric utilities that have surface impoundments or similar
management units that contain CCRs. EPA's OSWER is using the data collected from the
Information Request Letters to evaluate the threat of releases of pollutants from these
management units. EPA's Office of Water used the OSWER data as another source of
information about the use of ash ponds and FGD ponds at coal-fired power plants.
The OSWER database contains information collected from plants identified as potentially
operating ash ponds or FGD ponds, based on data compiled by the Department of Energy's
Energy Information Administration (EIA). The EIA data does not include information about
waste disposal practices for those plants with nameplate electric generating capacity of less than
100 MW. In addition, due to the nature of EIA's data collection form, the EIA data may also
exclude information about the presence of ponds at plants that use the pond as an interim step
(e.g., to dewater ash or other CCR solids), but final disposition of the CCRs is an on-site landfill
or off-site disposal/use. In requesting information on CCR surface impoundments and similar
waste management units, OSWER directed the requests to those plants identified by the EIA data
as disposing of CCRs in an on-site pond. As such, the OSWER database potentially
underestimates the total number of ash ponds and FGD ponds nationwide.
2.5 Interactions with the Utility Water Act Group
UWAG is an association of over 200 individual electric utilities and four national trade
associations of electric utilities: the Edison Electric Institute, the National Rural Electric
Cooperative Association, the American Public Power Association, and the Nuclear Energy
Institute. The individual utility companies operate power plants and other facilities that generate,
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Final Detailed Study Report Chapter 2 - Data Collection Activities
transmit, and distribute electricity to residential, commercial, industrial, and institutional
customers. The Edison Electric Institute is an association of U.S. shareholder-owned electric
companies, international affiliates, and industry associates. The National Rural Electric
Cooperative Association is an association of nonprofit electric cooperatives supplying central
station service through generation, transmission, and distribution of electricity to rural areas of
the United States. The American Public Power Association is a national trade association
representing publicly owned (municipal and state) electric utilities in 49 states. The Nuclear
Energy Institute establishes industry policy on legislative, regulatory, operational, and technical
issues affecting the nuclear energy industry on behalf of its member companies. These members
include the companies that own and operate commercial nuclear power plants in the United
States, as well as nuclear plant designers and other organizations involved in the nuclear energy
industry. UWAG's purpose is to participate on behalf of its members in EPA's rulemakings
under the CWA.
UWAG commented on EPA's selection of the steam electric power generating industry
for a detailed study as part of the 2006 Effluent Guidelines Program Plan and submitted
comments to EPA regarding the detailed study as part of the Preliminary 2008 Effluent
Guidelines Program Plan. UWAG also provided data during a review of PCS and TRI data to
assess national discharge loadings associated with this industry, as summarized in the Interim
Detailed Study Report for the Steam Electric Power Generating Point Source Category
(EPA/821-R-06-015, November 2006) [U.S. EPA, 2006e]. As EPA continued with the detailed
study and began formulating approaches to data collection, the Agency held a series of
discussions with UWAG to streamline and facilitate the data collection process. Specifically,
EPA coordinated with UWAG on collecting information on power plant characteristics to
support site visit selection, discussing wastewater sampling approaches and recommendations,
reviewing the data request for clarity, and collecting existing permit data. At the invitation of
individual plants, UWAG also collected split samples during EPA's sampling program and
participated in most site visits.
2.5.1 Database of Power Plant Information
UWAG provided EPA with additional power plant information to augment data compiled
from other data sources described in this chapter. EPA provided UWAG with a list of 96 coal-
fired power plants believed to be operating wet FGD systems and UWAG provided information
regarding plant operations at 76 of the plants. UWAG provided information on the operation of
the wet FGD systems, including the installation year, sorbent usage, additive usage, oxidation
type, solids handling practices, and wastewater treatment system. UWAG also provided the type
of bottom and fly ash handling and wastewater treatment systems.
2.5.2 Wastewater Sampling
As discussed in Section 2.2, EPA conducted a sampling program to characterize
wastewaters generated by coal-fired power plants and to evaluate treatment technologies and best
management practices available to reduce pollutant discharges. EPA held several meetings with
UWAG to discuss various approaches to the sampling program, including identifying
representative sample points, providing comment on the generic sampling plan, and providing
recommendations on laboratory analyses and potential interferences (particularly with handling
influent samples with high concentrations of solids). UWAG participated in the plant pre-
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Final Detailed Study Report Chapter 2 - Data Collection Activities
sampling site visits and provided review and comment on site-specific sampling plans. At the
invitation of the plants being sampled, UWAG also collected split samples during EPA's
sampling episodes. EPA met with UWAG to discuss the FGD effluent sampling results and
during these meetings, compared analytical results and discussed the challenges associated with
laboratory analyses of FGD wastewaters [ERG, 2008d; ERG, 2009n]. UWAG also provided
written suggestions to EPA for improving the analytical procedures for the sampling program
[Hill, 2008].
2.5.3 Data Request
As discussed in Section 2.3, EPA developed a questionnaire (i.e., data request) to collect
information on coal-fired power plants. EPA provided UWAG an opportunity to review the data
request and to recommend changes to improve the clarity of the questions involved. For
example, UWAG provided input on the industry's definitions of scrubber terminology to ensure
that the respondents would understand the questions that EPA included in the request. After EPA
distributed the data request to the data request respondents, UWAG requested clarification
regarding certain data request questions on behalf of its members. Copies of UWAG's comments
and questions on the data request are included in the docket for the Preliminary 2010 Effluent
Guidelines Program Plan [UWAG, 2007].
2.5.4 NPDESForm2C
UWAG and EPA coordinated efforts to create a database of selected NPDES Form 2C
data from UWAG's member companies. The NPDES Form 2C (or an equivalent form used by a
state permitting authority) is an application for a permit to discharge wastewater that must be
completed by existing industrial facilities (including manufacturing, commercial, mining, and
silvicultural operations). This form includes facility information, data on facility outfalls, process
flow diagrams, treatment information, and intake and effluent characteristics.
The NPDES Form 2C database contains information about the outfalls of coal-fired
power plants that receive FGD, ash handling, or coal pile runoff waste streams. EPA received
Form 2C data from UWAG for 86 plants in late June 2008. [UWAG, 2008] UWAG did not
include data on other outfalls, such as separate outfalls for sanitary wastes, cooling water, landfill
runoff, and other waste streams, in the database. The database does not include Form 2C
information for plants that have neither a wet FGD system nor wet fly ash handling. For
example, if a plant has no wet FGD system and the plant's only wet ash handling is for bottom
ash sluicing, UWAG did not include its information in the database. EPA reviewed the Form 2C
data for use in developing the industry profile, in particular for ash wastewater treatment
operations.
2.6 Interactions with the Electric Power Research Institute (EPRI)
EPRI is a research-oriented trade association for the steam electric industry. EPRI
conducts research funded by the steam electric industry and has extensively studied wastewater
discharges from FGD systems. The trade association provided EPA with the following reports
that summarize the data collected during several EPRI studies:
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Final Detailed Study Report Chapter 2 - Data Collection Activities
• Flue Gas Desulfurization (FGD) Wastewater Characterization: Screening Study
[EPRI, 2006a];
• EPRI Technical Manual: Guidance for Assessing Wastewater Impacts of FGD
Scrubbers [EPRI, 2006b];
• The Fate of Mercury Absorbed in Flue Gas Desulfurization (FGD) Systems
[EPRI, 2005];
• Update on Enhanced Mercury Capture by Wet FGD: Technical Update [EPRI,
2007b]; and
PISCES Water Characterization Field Study, Sites A-G [EPRI, 1997b-2001 ].
The EPRI reports provided EPA with background information regarding the
characteristics of FGD wastewaters and the sampling techniques used to collect the samples.
In addition, EPRI participated in meetings with EPA and provided comments on EPA's
planned data collection activities, including the data request and the sampling program. EPRI
specifically commented on the sample collection techniques and considerations for laboratory
analysis of FGD and ash handling wastewaters. EPRI also provided comments on EPA's Generic
Sampling and Analysis Plan for Coal-fired Steam Electric Power Plants. A copy of EPRI's
comments on the sampling plan is included in the docket for the Preliminary 2010 Effluent
Guidelines Program Plan [EPRI, 2007c].
2.7 Department of Energy (DOE)
DOE is the department of the United States government responsible for energy policy. In
the detailed study, EPA used information on electric generating facilities from DOE's Energy
Information Administration (EIA) data collection forms.
EIA is a statistical agency of the DOE that collects information on existing U.S. electric
generating facilities and associated equipment to evaluate the current status and potential trends
in the industry. EPA used information from two of EIA's data collection forms: Form EIA-860,
Annual Electric Generator Report, and Form EIA-767, Steam Electric Plant Operation and
Design Report. Form EIA-860 collects information annually for all electric generating facilities
that have or will have a nameplate capacity3 of one megawatt (MW) or more and are operating
or plan to be operating within five years of the filing of the Annual Electric Generator Report.
The data collected in Form EIA-860 are associated only with the design and operation of the
generators at facilities [U.S. DOE, 2005a]. Form EIA-767 collects information annually from all
electric generating facilities with a total existing or planned organic-fueled or renewable steam
electric generating unit that has a nameplate rating of 10 MW or larger. The data collected in
Form EIA-767 are associated with the operation and design of the entire facility. EPA used Form
EIA-767 primarily for information on the facilities operating (or planning to operate) FGD
systems [U.S. DOE, 2005b].
3 DOE defines the generator nameplate capacity as the maximum rated output of a generator under specific
conditions designated by the manufacturer. Generator nameplate capacity is usually indicated in units of kilovolt-
amperes (kVA) and in kilowatts (kW) on a nameplate physically attached to the generator. More generally,
generator capacity is the maximum output, commonly expressed in megawatts (MW), that generating equipment can
supply to system load, adjusted for ambient conditions.
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Final Detailed Study Report Chapter 2 - Data Collection Activities
2.8 Other Sources
EPA obtained additional information on steam electric processes, technologies,
wastewaters, pollutants, and regulations from sources including wastewater treatment equipment
vendors, the U.S. Geological Survey (USGS), and literature and Internet searches. In addition,
EPA considered information provided in public comments during the effluent guidelines
planning process, as well as other contacts with interested stakeholders.
2.8.1 Wastewater Treatment Equipment Vendors
EPA contacted companies that manufacture, distribute, or install various components of
pollutant removal systems. EPA obtained information about the operation and performance of
these systems and the type of equipment used for treating FGD wastewaters.
2.8.2 U.S. Geological Survey (USGS) COALQUAL Database
Since the middle 1970s, the USGS has maintained a national coal quality database,
containing data compiled on more than 13,000 coal samples collected by USGS and cooperative
state geological surveys. The database contains 136 parameters for each sample, including data
on location and sample description, analytical data from American Society for Testing and
Materials (ASTM) tests, and USGS tests for major, minor, and trace elements. The COALQUAL
database [USGS, 1998] contains data for 7,430 coal samples that represent complete-bed
thicknesses at various locations. EPA generally reviewed data from the COALQUAL database
when initially studying the industry to determine potential constituents that may be present in
coal combustion wastes.
2.8.3 Literature and Internet Searches
EPA conducted literature and Internet searches to obtain information on various aspects
of the steam electric process, both for plants regulated by the effluent guidelines and certain
operations outside the scope of the regulations. The information collection objectives of these
searches included characterizing wastewaters and pollutants originating from these steam electric
processes, the environmental impacts of these wastewaters, and applicable regulations. EPA used
industry journals, reference texts about the industry, and company press releases obtained from
Internet searches. EPA participated in the 2007 and 2008 International Water Conference and
reviewed papers presented at these conferences.
2.8.4 Environmental Groups and Other Stakeholders
EPA received information from several environmental groups and other stakeholders as
part of public comments submitted for the 2006 and 2008 Effluent Guidelines Plans, and in other
discussions over the course of the detailed study. The public comments and other information
were reviewed to determine whether they identified new waste streams or pollutant issues that
warranted investigation beyond that being conducted as part of the study. In general, the
information highlighted environmental concerns associated with the pollutants present in power
plant wastewaters, and technological controls for reducing or eliminating pollutant discharges
from FGD and ash handling systems.
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Final Detailed Study Report Chapter 3 - Steam Electric Industry Profile
3. STEAM ELECTRIC INDUSTRY PROFILE
Electric generating plants use various types of prime movers (e.g., combustion turbines,
steam turbines, diesel engines) to convert mechanical, chemical, and/or fission energy into
electric energy. Within this population of electric generating plants, there are different types of
processes employed to produce electricity (e.g., coal-fired power plants, wind turbines) and there
are different types of companies that operate these electric generating plants (e.g., utilities,
industrial plants). The Steam Electric Power Generating effluent guidelines apply to only certain
types of electric generating plants. Figure 3-1 broadly depicts the various types of electric
generating plants operating in the United States and identifies which are regulated by the Steam
Electric Power Generating effluent guidelines.
This chapter provides an overview of the various types of electric generating processes
operating in the United States and then focuses on the categories of processes regulated by the
Steam Electric Power Generating effluent guidelines. The chapter also describes the wastewaters
generated by these processes.
Electric Generating Plants
Electric Generating Industry |ndustrja| Non.utiNties
(Utilities and Non-Utilities)
Non-Steam Electric Steam Electric
Power Generation Power Generation
Fossil or Nuclear Steam Electric Non-Fossil and Non-Nuclear
Generating Plants Steam Electric Generating Plants
(Steam Electric Power Generating
Point Source Category)
Figure 3-1. Types of U.S. Electric Generating Plants
3.1 Overview of the Electric Generating Industry
This section describes the types of plants that compose the overall electric generating
industry. As shown in Figure 3-1, the plants regulated by the Steam Electric Power Generating
effluent guidelines are only a portion of the electric generating industry.
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Final Detailed Study Report Chapter 3 - Steam Electric Industry Profile
In general, the companies generating electrical power are categorized as one of the
following types:
1. Utility: Any entity that generates, transmits, and/or distributes electricity and
recovers the cost of its generation, transmission and/or distribution assets and
operations, either directly or indirectly, through cost-based rates set by a separate
regulatory authority (e.g., state Public Service Commission), or is owned by a
governmental unit or the consumers that the entity serves. According to the
Energy Information Administration (EIA), plants that qualify as cogenerators or
small power producers under the Public Utility Regulatory Policies Act are not
considered electric utilities [U.S. DOE, 2006b].
2. Non-industrial non-utility: Any entity that generates, transmits, and/or sells
electricity, or sells or trades electricity services and products, where costs are not
established and recovered by regulatory authority. Non-utility power producers
include, but are not limited to, independent power producers, power marketers
and aggregators, merchant transmission service providers, self-generation entities,
and cogeneration firms with Qualifying Facility Status. [U.S. DOE, 2006b]. Like
utilities, the primary purpose of non-industrial non-utilities is producing electric
power for distribution and/or sale.
3. Industrial non-utility: Industrial non-utilities are similar to non-industrial non-
utilities except their primary purpose is not the distribution and/or sale of
electricity. This category includes electric generators that are located at facilities
such as chemical manufacturing plants or paper mills. Industrial non-utilities
typically provide most of the electrical power they generate to the industrial
operation with which they are located, although they may also provide some
electric power to the grid for distribution and/or sale.
Industrial non-utilities are generally not included within the scope of the existing Steam
Electric Power Generating effluent guidelines because they are not primarily engaged in
producing electricity for distribution and/or sale4. As described above, these industrial non-
utilities typically are industrial plants that are producing, processing, or assembling goods and
the electricity generated at these plants is an ancillary operation used to dispose of a by-product
or for cost savings. Industrial non-utilities are discussed in greater detail in Chapter 7 of this
report.
Because industrial non-utilities are not included in the applicability of the Steam Electric
Power Generating effluent guidelines, EPA has excluded them from the discussion of the U.S.
electric generating industry for the purposes of this report. Therefore, information presented on
plants comprising the electric generating industry include only the utilities and the non-industrial
4 The applicability of the Steam Electric Power Generating Point Source Category (40 CFR Part 423.10) states the
following: "The provisions of this part are applicable to discharges resulting from the operation of a generating unit
by an establishment primarily engaged in the generation of electricity for distribution and sale which results
primarily from a process utilizing fossil-type fuel (coal, oil, or gas) or nuclear fuel in conjunction with a thermal
cycle employing the steam water system as the thermodynamic medium."
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Final Detailed Study Report Chapter 3 - Steam Electric Industry Profile
non-utilities, which are generally categorized by the following four North American Industry
Classification System (NAICS) codes5:
• 221111 - Hydroelectric Power Generation;
• 221112 - Fossil Fuel Electric Power Generation;
• 221113 - Nuclear Electric Power Generation; and
• 221119 - Other Electric Power Generation.
Although the transmission and distribution entities are included in the definition of
utilities and non-industrial non-utilities, they are not included in the Steam Electric Power
Generating effluent guidelines; therefore, this report only presents information on the plants and
NAICS codes associated with the generation of electricity.
As shown in Figure 3-1, the electric generating industry can be further broken down
based on the type of prime mover used to generate electricity. DOE's Energy Information
Administration (EIA) defines a prime mover as the engine, turbine, water wheel, or similar
machine that drives an electric generator, or a device that converts energy to electricity directly
(e.g., photovoltaic solar and fuel cell(s)) [U.S. DOE 2006a]. Because the Steam Electric Power
Generating effluent guideline is applicable only to plants generating electricity using a "...
thermal cycle employing the steam water system as a thermodynamic medium," EPA
categorized the prime movers into "steam electric" and "non-steam electric" categories. The
steam electric generating units include steam turbines and combined cycle systems (see Section
3.2 for more details on these types of units). The non-steam electric generating units include, but
are not limited to, combustion turbines, internal combustion engines, fuel cells, and wind
turbines.
The final criteria for a plant to meet the Steam Electric Power Generating effluent
guideline applicability is that they must primarily utilize a fossil-type or nuclear fuel to generate
the steam used in the turbine. The fossil-type fuels include coal, oil, or gas, and fuels derived
from coal, oil, or gas such as petroleum coke, residual fuel oil, and distillate fuel oil. Fossil-type
fuels also include blast furnace gas and the product of gasification processes using fossil-based
feedstocks such as coal, petroleum coke, and oil. Examples of non-fossil/non-nuclear fuels used
by some steam electric generating power plants include pulp mill black liquor, municipal solid
waste, and wood solid waste.
3.1.1 Demographics of the Electric Generating Industry
This section presents available demographic data and other information for the electric
generating industry (i.e., excluding industrial non-utilities). EPA analyzed the available
demographic information using EIA data for the year 2005 (Form EIA-860 and Form EIA-767)
[U.S. DOE, 2005a; U.S. DOE, 2005b], and U.S. Census Bureau data collected in the 2002
Economic Census [USCB, 2002]. EPA used the 2005 EIA data because it is the most recent year
for which both EIA-860 and EIA-767 data are available, and the 2002 Census data because it is
the most recent year for which data at the six-digit NAICS code are available. Together, these
5 Prior to the introduction of NAICS codes, Standard Industrial Classification (SIC) codes were used to classify
operations. The SIC codes applicable to the Steam Electric Power Generating effluent guidelines are discussed in
Chapter 7.
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Final Detailed Study Report Chapter 3 - Steam Electric Industry Profile
sources provide the most recent and comprehensive dataset of power plant data available. EPA
identified electric generating plants in the EIA database as those reporting NAICS code 22 -
Utilities6. The 2002 Economic Census data include more specific industry sector information at
the six-digit NAICS code level.
According to the Economic Census, there were 2,138 electric generating plants in the
United States in 2002, 61 percent (1,311 plants) of which are characterized primarily as using
fossil or nuclear fuel [USCB, 2002]. These data include both steam and non-steam electric
generation processes. Table 3-1 presents the distribution of plants among each of the electric
generating NAICS codes. The Economic Census includes all facilities reporting under NAICS
code 22. As a result, it includes entities categorized by U.S. DOE as utilities and non-industrial
non-utilities, but does not include industrial non-utilities.
Table 3-1. Distribution of U.S. Electric Generating Plants by NAICS Code in 2002
NAICS Code - Description
22 1 1 1 1 - Hydroelectric Power Generation
22 1 1 12 - Fossil Fuel Electric Power Generation
22 1 1 1 3 - Nuclear Electric Power Generation
221119 - Other Electric Power Generation (includes conversion of other forms of energy,
such as solar, wind, or tidal power, into electrical energy)
22111 - Electric Power Generation (Total)
Plants
416
1,233
78
411
2,138
Source: [USCB, 2002].
EPA also examined the data on electricity generating plant operations that were reported
to the EIA in 2005. Form EIA-860 contains records for 16,807 steam and non-steam electric
generating units having at least one MW of capacity operated at 5,267 plants for calendar year
2005 [U.S. DOE, 2005a]. These plants include both the electric generating industry and
industrial non-utilities.
3.1.2 Steam Electric Power Generating Industry
EPA used EIA's Form EIA-860 information on plant type, energy source, and capacity to
develop a demographic profile of the portion of the electric generating industry regulated by the
Steam Electric Power Generating effluent guidelines. As mentioned in Section 3.1.1, these
records include data from all plants that produce electricity, including steam electric plants. EPA
defined the subset of EIA data for the Steam Electric Power Generating effluent guidelines by
the reported NAICS code, as well as the type of turbine and the fuel reported to be used to
generate electricity.
All electric generating plants (i.e., utilities, non-industrial non-utilities, and industrial
non-utilities) report information about each of their electric generating units to the EIA in Form
EIA-860, and each plant identifies a "primary purpose" code for its operations that is analogous
to their NAICS code. Utilities and non-industrial non-utilities report under the general NAICS
6 NAICS code 22 - Utilities is defined as establishments providing the following utility services: electric power,
natural gas, steam supply, water supply, and sewage removal. Excluded from this sector are establishments primarily
engaged in waste management services [USCB, 2002].
-------
Final Detailed Study Report Chapter 3 - Steam Electric Industry Profile
code 22, while industrial non-utilities report under the particular NAICS code for their primary
manufacturing or service operation. Because utilities and non-industrial non-utilities are
regulated by the Steam Electric Power Generating effluent guidelines, their EIA data are
combined in this report.
3.1.2.1 Definition of the Steam Electric Power Generating Industry
The Steam Electric Power Generating effluent guidelines apply to ".. .discharges
resulting from the operation of a generating unit by an establishment primarily engaged in the
generation of electricity for distribution and sale which results primarily from a process utilizing
fossil-type fuel (coal, oil, or gas) or nuclear fuel in conjunction with a thermal cycle employing
the steam water system as the thermodynamic medium." (40 CFR 423.10) EPA identified the
subset of electric generating plants in the EIA database that use steam electric processes as those
operating at least one prime mover that utilizes steam. The following electric generating unit or
prime mover types are included in the demographic data for the steam electric industry presented
in this report:
• Steam turbine;
• Combined cycle system - steam turbine portion;
• Combined cycle system - combustion turbine portion; and
• Combined cycle system - single shaft (i.e., the steam turbine and combustion
turbine are used together to drive a single generator).
The subset of steam electric plants that are regulated by the steam electric effluent
guidelines use a fossil or nuclear fuel as the primary energy source for the steam electric
generating unit. In analyzing the EIA data, EPA included plants using the following EIA-defined
nuclear and fossil (or fossil-derived) fuel types:
• Anthracite coal, bituminous coal;
• Lignite coal;
• Subbituminous coal;
• Coal synfuel;
• Waste/other coal;
• Petroleum coke;
• Distillate fuel oil;
• Residual fuel oil;
• Jet fuel;
• Kerosene;
• Oil-other and waste oil (e.g., crude oil, liquid by-products, oil waste, propane
(liquid), re-refined motor oil, sludge oil, tar oil);
• Natural gas;
• Blast furnace gas;
• Gaseous propane;
• Other gas; and
• Nuclear (e.g., uranium, plutonium, thorium).
Using the criteria for the prime mover type and energy source described above for all
plants (utilities and non-industrial non-utilities) reporting a primary purpose/NAICS code of 22,
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Final Detailed Study Report Chapter 3 - Steam Electric Industry Profile
EPA identified 1,187 steam electric plants regulated under the Steam Electric Power Generating
effluent guidelines that reported to the EIA in 2005. In analyzing the EIA energy source data for
the purpose of this report, EPA only identified plants/units that reported one of the above energy
sources as a "primary" energy source in the 2005 EIA data. These plants operate an estimated
2,557 stand-alone steam electric generating units or combined cycle systems, which have a total
generating capacity of 762,386 MW [U.S. DOE, 2005a].
3.1.2.2 Demographics of the Steam Electric Power Generating Industry
Table 3-2 presents the distribution of the types of steam electric prime movers used by
plants subject to the Steam Electric Power Generating effluent guidelines. The table presents the
numbers of plants, electric generating units, and capacity for each type of steam electric prime
mover. The number of electric generating units represents the number of generators/turbines that
are used to generate electricity and does not necessarily relate to the number of boilers.
Based on the 2005 EIA data, the majority (74 percent) of the steam electric power
produced by the plants subject to the effluent guideline is generated using stand-alone steam
turbines, which are also the most prevalent type of steam electric prime mover used.
In the 2005 EIA database, an estimated 411 plants regulated by the Steam Electric Power
Generating effluent guidelines reported operating at least one fossil-fueled combined cycle
system. Due to the nature of the EIA data, EPA was able to identify the number of combined
cycle turbines (i.e., prime movers), but could not discern the number of actual combined cycle
systems. A combined cycle system is comprised of one or more combustion turbines linked to
one or more steam turbines; these systems often do not have a one-to-one relationship between
the number of combustion turbines and steam turbines. The total combined cycle system
generating capacity of 198,660 MW represents 26 percent of the total capacity regulated by the
steam electric effluent guidelines [U.S. DOE, 2005a].
Table 3-3 presents the distribution of fossil and nuclear fuels used to power each type of
steam electric prime mover. The number of electric generating units represents the number of
generators/turbines that are used to generate electricity and is not equal to the number of boilers.
The vast majority (90 percent) of these generating units are fueled by either coal or gas. Coal is
the primary fuel type for stand-alone steam turbines, while gas is the primary fuel for nearly all
combined cycle systems.
3-6
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Final Detailed Study Report
Chapter 3 - Steam Electric Industry Profile
Table 3-2. Distribution of Prime Mover Types for Plants Regulated by the Steam Electric
Power Generating Effluent Guidelines
Steam Electric Prime Mover
Stand-Alone Steam Turbine
Combined Cycle Systems b:
Combined Cycle Steam Turbine c' d
Combined Cycle Single Shaft (steam and
combustion turbines share a single shaft)
Combined Cycle Combustion Turbine °' d
Total
Number of
Plants a
818
(69%)
411
(35%)
392
22
390
1,187
(100%)
Number of
Electric
Generating Units
1,995
(78%)
562
(22%)
512
50
889
2,557 e
(100%)
Total Steam or
Combined Cycle
Turbine Capacity
(MW)
563,726
(74%)
198,660
(26%)
70,020
9,503
119,137
762,386
(100%)
Source: [U.S. DOE, 2005a].
a - Because a single plant may operate multiple electric generating units of various types, the number of plants by
prime mover type is not additive. There are 1,187 plants in the industry that operate at least one steam electric
generating unit powered by either fossil or nuclear fuel.
b - Due to the nature of the EIA data, EPA was able to identify the number of combined cycle turbines (i.e., prime
movers), but could not discern the number of actual combined cycle systems. EPA estimated the number of
combined cycle systems by adding the number of combined cycle steam turbines and the number of combined cycle
single shaft turbines. Typically there are multiple combustion turbines to a single steam turbine in a combined cycle
system; therefore, EPA believes this methodology is a better representation of the number of combined cycle
systems than simply adding the number of combined cycle combustion and steam turbines.
c - The 2005 EIA database contains a total of 506 combined cycle steam turbines, with an additional six plants
reporting at least one combined cycle combustion turbine, but not a combined cycle steam turbine. EPA believes
that these six plants likely operate a combined cycle steam turbine; therefore, EPA assumed that each of the six
plants operates one combined cycle steam turbine and counted six additional turbines and six additional plants to the
numbers identified in the 2005 EIA database for the number of combined cycle steam turbines and combined cycle
steam turbine plants.
d - One plant in the 2005 EIA database reported having a combined cycle steam turbine electric generating unit and
two internal combustion electric generating units. Another plant in the database reported a fossil fuel for its
combined cycle steam turbine and a non-fossil/non-nuclear fuel for its three combined cycle combustion turbines.
EPA included the combined cycle steam turbines for these plants in the table, but did not include the internal
combustion or the combined cycle combustion turbines using fuels not covered by the effluent guidelines.
e - EPA estimated the total number of electric generating units as the sum of the stand-alone steam turbines and the
estimated number of combined cycle systems. EPA did not sum the total number of turbines.
3-7
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Final Detailed Study Report
Chapter 3 - Steam Electric Industry Profile
Table 3-3. Distribution of Fuel Types Used by Steam Electric Generating Units
Fossil or Nuclear Fuel a
Coal:
Anthracite Coal, Bituminous Coal
Subbituminous Coal
Lignite Coal
Coal Synfuel
Waste/Other Coal
Petroleum Coke
Oil:
Residual Fuel Oil
Distillate Fuel Oil
Waste Oil
Gas:
Natural Gas
Blast Furnace Gas
Other Gas
Nuclear
Total
Number of Electric Generating Units
Stand-Alone
Steam Turbines
1,179
695
411
29
22
22
12
136
125
11
0
564
559
5
0
104
1,995
Combined Cycle Steam
Turbines b'c
2
2
0
0
0
0
0
11
2
8
1
499
495
0
4
0
512
Combined Cycle
Single Shaft
0
0
0
0
0
0
0
0
0
0
0
50
50
0
0
0
50
Combined Cycle
Combustion Turbine b' c
2
2
0
0
0
0
0
20
2
16
2
867
866
0
1
0
889
Total
1,183
699
411
29
22
22
12
166
129
34
3
1,975
1,966
5
4
104
2,557 d
Source: [U.S. DOE, 2005a].
a - No steam electric generating units were reported to use jet fuel, kerosene, or gaseous propane in the 2005 EIA database.
b - The 2005 EIA database contains a total of 506 combined cycle steam turbines, with an additional six plants reporting at least one combined cycle combustion
turbine, but not a combined cycle steam turbine. EPA believes that these six plants likely operate a combined cycle steam turbine; therefore, EPA assumed that
each of the six plants operates one combined cycle steam turbine and counted six additional turbines and six additional plants to the numbers identified in the
2005 EIA database for the number of combined cycle steam turbines and combined cycle steam turbine plants.
c - One plant in the 2005 EIA database reported having a combined cycle steam turbine electric generating unit and two internal combustion electric generating
units. Another plant in the database reported a fossil fuel for its combined cycle steam turbine and a non-fossil/non-nuclear fuel for its three combined cycle
combustion turbines. EPA included the combined cycle steam turbines for these plants in the table, but did not include the internal combustion or the combined
cycle combustion turbines using fuels not covered by the effluent guidelines.
d - EPA estimated the total number of electric generating units as the sum of the stand-alone steam turbines and the estimated number of combined cycle
systems. EPA did not sum the total number of turbines.
3-8
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Final Detailed Study Report Chapter 3 - Steam Electric Industry Profile
Table 3-4 presents the distribution of fossil and nuclear fuels used by plants applicable to
the Steam Electric Power Generating effluent guideline. The 2005 EIA data demonstrate that
more than half of the electricity produced by steam turbines is fueled by coal. Natural gas
accounts for 27 percent of the electricity produced by steam turbines, nuclear for 16 percent, and
oil for 5 percent of the electricity from steam turbines. Table 3-4 includes only the prime movers
that are specifically steam-driven turbines (i.e., stand-alone steam turbines, combined cycle
steam turbines, and combined cycle single shaft). Therefore, the total numbers of plants, electric
generating units, and capacity presented in Table 3-4 do not match the total numbers presented in
Table 3-2. EPA included only the steam turbines in Table 3-4 to focus on identifying the fuels
used to produce electricity using steam.
Table 3-5 presents the distribution of combined cycle units powered by fossil and nuclear
fuels. Table 3-5 includes only the prime movers associated with combined cycle units (i.e.,
combined cycle steam turbine, combined cycle single shaft, and combined cycle combustion
turbine). The stand-alone steam turbines are not included in the table. The 2005 EIA data show
that natural gas is the predominant fuel source for combined cycle units, accounting for 99
percent of the total combined cycle capacity. There are a small number of plants that reported
operating combined cycle units fueled by oil. The two plants that reported coal as the fuel source
are Integrated Gasification Combined Cycle (IGCC) units. These "coal-fired" combined cycle
systems are actually powered by syngas generated by a coal gasification process [U.S. DOE,
2005a]. Section 3.2.10 contains additional information about IGCC systems.
Table 3-6 presents the steam electric capacity, as well as the number of steam electric
plants and electric generating units in the industry, distributed by overall plant capacity1. Table
3-6 includes the stand-alone steam turbines and all the combined cycle system turbines (i.e.,
combined cycle steam turbine, combined cycle single shaft, and combined cycle combustion
turbine) in the determination of the number of steam electric plants and steam electric capacity.
For the number of electric generating units, EPA only included the stand-alone steam turbines,
the combined cycle steam turbines, and the combined cycle single shaft to estimate the number
of stand-alone electric generating units and the number of combined cycle systems. According to
the 2005 EIA data, the largest capacity plants (>500 MW) comprise nearly half of all steam
electric plants, approximately 60 percent of the electric generating units, and 87 percent of the
steam electric generating capacity for all plants regulated by the effluent guidelines. Based on the
2005 EIA data, most steam electric plants are either gas or coal-fired and have a generating
capacity greater than 500 MWs.
7 The overall plant capacity includes all electric power generated by the plant, including electricity produced by non-
steam generators and through the use of non-fossil/non-nuclear energy sources.
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Final Detailed Study Report
Chapter 3 - Steam Electric Industry Profile
Table 3-4. Types of Fuel Used by Stand-Alone and Combined Cycle Steam Turbines
Fossil or Nuclear Fuel a
Coal:
Anthracite Coal, Bituminous Coal
Subbituminous Coal
Lignite Coal
Coal Synfuel
Waste/Other Coal
Petroleum Coke
Oil:
Residual Fuel Oil
Distillate Fuel Oil
Waste Oil
Gas:
Natural Gas
Blast Furnace Gas
Other Gas
Nuclear
Total
Number of Plants b
488
(41%)
280
173
17
10
20
;;
(0.9%)
75
(6.3%)
60
14
1
619
(52%)
613
2
4
66
(5.6%)
1,187
(100%)
Number of Electric
Generating Units
1,181
(46%)
697
411
29
22
22
12
(0.5%)
147
(5. 7%)
127
19
1
1,113
(44%)
1,104
5
4
104
(4.1%)
2,557
(100%)
Total Steam Turbine
Capacity
(MW)C
329,211
(51%)
175,271
130,300
14,643
6,960
2,037
778
(0.1%)
32,219
(5.0%)
30,983
1,216
20
175,455
(27%)
175,186
152
117
105,585
(16%)
643,249
(100%)
Source: [U.S. DOE, 2005a].
Note: The table includes only the stand-alone steam turbines, combined cycle steam turbines, and combined cycle
single shaft. The combined cycle combustion turbines are not included in the table.
a - No steam electric generating units were reported to use jet fuel, kerosene, or gaseous propane in the 2005 EIA
database.
b - Because a single plant may operate multiple electric generating units utilizing differing fuel types, the number of
plants by fuel type is not additive. There are 1,187 plants in the industry that operate at least one stand-alone steam
turbine, combined cycle steam turbine, or combined cycle single shaft electric generating unit powered by either
fossil or nuclear fuel.
c - The total steam electric capacity shown does not equal the sum of the steam electric capacities for each fuel type
due to rounding errors.
3-10
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Final Detailed Study Report
Chapter 3 - Steam Electric Industry Profile
Table 3-5. Distribution of Fuel Types for Combined Cycle Units Regulated by the Steam Electric Power Generating Effluent
Guidelines
Fossil or Nuclear Fuel a
Coal:
Anthracite Coal, Bituminous Coal
Petroleum Coke
Oil:
Residual Fuel Oil
Distillate Fuel Oil
Waste Oil
Gas:
Natural Gas
Other Gas
Nuclear
Total
Combined Cycle Steam Turbine
Number of
Plants b
2
2
0
10
2
7
1
379
376
4
0
392
Number of
Electric
Generating
Units c
2
2
0
11
2
8
1
499
495
4
0
512
Total
Turbine
Capacity
(MW)d
246
246
0
399
97
280
20
69,375
69,258
117
0
70,020
Combined Cycle Single Shaft (steam
and combustion turbines share a
single shaft)
Number of
Plants b
0
0
0
0
0
0
0
22
22
0
0
22
Number of
Electric
Generating
Units
0
0
0
0
0
0
0
50
50
0
0
50
Total
Turbine
Capacity
(MW)C
0
0
0
0
0
0
0
9,503
9,503
0
0
9,503
Combined Cycle Combustion
Turbine
Number of
Plants b
2
2
0
8
1
6
1
380
379
1
0
390
Number of
Electric
Generating
Units e
2
2
0
20
2
16
2
867
866
1
0
889
Total
Turbine
Capacity
(MW)d
385
385
0
821
238
536
46
117,932
117,926
5
0
119,137
Source: [U.S. DOE, 2005a].
Note: The table includes only the combined cycle steam turbines, combined cycle single shaft, and combined cycle combustion turbines. The stand-alone steam
turbines are not included in this table, but can be found in Table 3-4.
a - No combined cycle electric generating units were reported to use lignite coal, coal synfuel, subbituminous coal, waste/other coal, jet fuel, kerosene, gaseous
propane, or blast furnace gas in the 2005 EIA database.
b - Because a single plant may operate multiple electric generating units utilizing differing fuel types, the number of plants by fuel type is not additive.
c - The 2005 EIA database contains a total of 506 combined cycle steam turbines, with an additional six plants reporting at least one combined cycle combustion
turbine, but not a combined cycle steam turbine. EPA believes that these six plants likely operate a combined cycle steam turbine; therefore, EPA assumed that
each of the six plants operates one combined cycle steam turbine and counted six additional turbines and six additional plants to the numbers identified in the
2005 EIA database for the number of combined cycle steam turbines and combined cycle steam turbine plants.
d - The total capacity shown does not equal the sum of the steam electric capacities for each fuel type due to rounding errors.
e - One plant in the 2005 EIA database reported having a combined cycle steam turbine electric generating unit and two internal combustion electric generating
units. Another plant in the database reported a fossil fuel for its combined cycle steam turbine and a non-fossil/non-nuclear fuel for its three combined cycle
combustion turbines. EPA included the combined cycle steam turbines for these plants in the table, but did not include the internal combustion or the combined
cycle combustion turbines using fuels not covered by the effluent guidelines.
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Final Detailed Study Report
Chapter 3 - Steam Electric Industry Profile
Table 3-6. Distribution by Size of Steam Electric Capacity, Plants, and Electric
Generating Units Regulated by the Steam Electric Effluent Guidelines
Overall Plant
Capacity a
Total Steam
Electric Capacity
(MW)
Percentage of
Capacity °
Number of Plants
Percentage of
Plants c
Number of Steam
Electric Generating
Units d
Percentage of
Steam Electric
Generating Units °
0-50
MW
3,033
0.4%
112
9.4%
183
7.2%
50-100
MW
8,225
1.1%
120
10%
210
8.2%
100-200
MW
20,544
2.7%
152
13%
257
10%
200-300
MW
21,075
2.8%
91
7.7%
155
6.1%
300-400
MW
20,604
2.7%
64
5.4%
131
5.1%
400-500
MW
27,730
3.6%
67
5.6%
148
5.8%
>500MW
661,476
87%
581
49%
1,473
58%
Total
762,386 b
100%
1,187
100%
2,557
100%
Source: [U.S. DOE, 2005a].
Note: The number of plants, number of steam electric generating units, and total steam electric capacity includes the
stand-alone steam turbines, combined cycle steam turbines, combined cycle single shaft, and combined cycle
combustion turbines.
a - Overall plant capacity includes electricity produced by both steam and non-steam electric generating units, as
well as through the use of non-fossil/non-nuclear energy sources.
b - The total steam electric capacity shown does not equal the sum of the steam electric capacities for each size
category due to rounding errors.
c - The sum of the percentages for each size category may not equal 100 percent due to rounding errors.
d - EPA estimated the total number of electric generating units as the sum of the stand-alone steam turbines and the
estimated number of combined cycle systems. EPA did not sum the total number of turbines. EPA estimated the
number of combined cycle systems by adding the number of combined cycle steam turbines and the number of
combined cycle single shaft turbines.
3.2 Steam Electric Process and Wastewater Sources
Steam electric plants generate electricity using a process that includes: a steam generator
(i.e., boiler); a steam turbine/electrical generator; and a condenser. Figure 3-2 illustrates the
stand-alone steam electric process, in which a combustible fuel is used as the energy source to
generate steam. The Steam Electric Power Generating effluent guidelines regulate wastewaters
discharged by those steam electric plants that use fossil-type fuel (e.g., coal, oil, or gas) or
nuclear fuel to generate the steam. However, other fuel sources such as municipal solid wastes or
wood wastes may also be used to produce the steam for generating electricity. Section 7.1 of this
report discusses steam electric processes that use alternative fuel sources.
3-12
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Final Detailed Study Report
Chapter 3 - Steam Electric Industry Profile
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Final Detailed Study Report Chapter 3 - Steam Electric Industry Profile
As shown in Figure 3-2, fuels are fed to a boiler where they are combusted to generate
steam. Boilers and their associated subsystems often include components to improve
thermodynamic efficiency by boosting steam temperature and preheating intake air using
superheaters, reheaters, economizers, and air heaters. The hot gases from combustion (i.e., the
flue gas) leaves the steam generator subsystem and passes through particulate collection and the
sulfur dioxide scrubbing system (if present), then is emitted through the stack. The high-
temperature, high-pressure steam leaves the boiler and enters the turbine generator where it
drives the turbine blades as it moves from the high-pressure to the low-pressure stages of the
turbine. The spinning of the turbine blades drives the linked generator, producing electricity. The
lower-pressure steam leaving the turbine enters the condenser, where it is cooled and condensed
by the cooling water flowing through heat exchanger (condenser) tubes. The water collected in
the condenser (condensate) is sent back to the boiler where it is again converted to steam
[Babcock & Wilcox, 2005].
The steam electric process may be used in conjunction with other processes that use a
portion of the thermal energy produced in the boiler. Cogeneration facilities, also known as
combined heat and power generators, are facilities that use thermal energy to produce electricity
and also to produce steam or hot water, typically for use in manufacturing processes or for
central heating. Cogeneration technologies are classified as either bottoming-cycle or topping-
cycle systems. In a typical bottoming-cycle system, high temperature steam is first used in a
manufacturing process and then the waste heat is used to generate steam to drive a turbine for
generating electricity. In one of two top-cycling configurations, high-temperature high-pressure
steam from a boiler is used to drive a turbine to generate electricity, and the waste heat or steam
exhausted from the turbine is then used as a source of heat for an industrial or commercial
process, such as space heating or food preparation. In another topping-cycle configuration, a
combustion turbine or diesel engine burns fuel to spin a shaft connected to a generator to produce
electricity, and the waste heat from the burning fuel is recaptured in a waste-heat recovery boiler
for use in direct heating or producing steam for thermal applications [U.S. DOE, 2000b]. Some
of the industrial non-utilities discussed in Section 7.2 are Cogeneration plants, and some of the
alternative-fueled8 steam electric plants discussed in Section 7.1 may be Cogeneration plants.
The nuclear-fueled steam electric process is similar to the same steam/water system
described above. Key differences between the nuclear and non-nuclear systems include fuel
handling, nuclear fission within the reactor core replaces the boiler as the heat source for
producing steam, and the air pollution control equipment is not needed for the flue gases. No fuel
is combusted and no ash is generated in a nuclear-fueled steam electric process. Instead, heat is
transferred from the reactor core by creating steam in boiling water reactors or creating
superheated water in pressurized-water reactors. The steam turbine/electric generator and
condenser portions of the nuclear-fueled steam electric process are the same as those described
for the stand-alone steam electric process [U.S. DOE, 2006c].
The remainder of this section discusses the waste streams generated at steam electric
plants. This section also discusses the combined cycle system process and emerging technologies
such as IGCC and carbon capture processes. Chapters 4 and 5 discuss FGD and ash handling
8 An alternative-fueled plant is defined for the purpose of this report as a plant that is not fueled by fossil or nuclear
fuel.
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Final Detailed Study Report Chapter 3 - Steam Electric Industry Profile
systems and wastewaters in greater detail, as these wastewaters were the focus of the detailed
study.
3.2.1 Fly Ash and Bottom Ash
Combusting coal and oil in steam electric boilers produces a residue of noncombustible
fuel constituents, referred to as ash. Depending on the boiler design, as much as 70 to 80 percent
of the ash from a pulverized coal furnace will consist of very fine particles that are light enough
to be entrained in the flue gas and carried out of the furnace. This portion of the ash is commonly
known as fly ash. The remaining 20 to 30 percent of the heavier ash that settles in the furnace or
dislodged from furnace walls is collected at the bottom of the boiler and is referred to as bottom
ash. Certain boiler designs, such a cyclone boilers, will produce relatively small amounts of fly
ash, on the order of 20 to 30 percent, and upwards of 70 to 80 percent bottom ash.
Some of the fly ash will be collected in hoppers located under the economizer and air
heaters as the coarser particles drop out of suspension as the flue gas flow changes direction. The
fly ash particles that remain entrained in the flue gases are carried to the particulate control
equipment, such as baghouses and electrostatic precipitators, for removal. The captured fly ash is
collected in hoppers and then either pneumatically transferred as dry ash to silos for temporary
storage or sluiced with water to a surface impoundment (i.e., ash pond). Dry fly ash stored in the
silos is periodically transferred, usually by truck, to either a landfill or for use offsite.
Bottom ash is usually hydraulically conveyed (i.e., sluiced with water) to either an ash
pond or dewatering bin. In such a system, the hot bottom ash drops to the bottom of the furnace
where it is quenched in a water-filled hopper. Ash from the hopper is fed into a conveying line
where it is diluted into slurry and pumped to the ash pond or dewatering storage bin. The ash
sent to a dewatering bin is separated from the transport water, then sent to a landfill or
transported offsite.
An alternative to the hydraulic bottom ash handling system is the mechanical drag
system. As is the case with the hydraulic systems, the bottom ash first drops to the bottom of the
furnace where it is quenched in a water bath. The ash is then removed from the furnace using a
submerged mechanical drag conveyor, which is essentially a parallel pair of chains with
crossbars attached at regular intervals. Ash conveyed out of the bottom of the furnace is typically
dumped into a nearby bunker and periodically trucked to landfill or sent offsite.
At any given facility, either the fly ash or bottom ash, or both, may be handled in a wet or
dry fashion. If handled wet, the fly ash and bottom ash may be stored in a common ash pond or
in separate impoundments. Coal-fired power plants typically generate large quantities of both fly
ash and bottom ash. Oil-fired plants produce less ash than coal-fired plants, and most of the ash
produced is fly ash. Natural gas-fired plants do not produce ash. The characteristics of ash
depend to some degree on the type of fuel combusted, how it is prepared prior to combustion,
and the operating conditions of the boiler. Fly ash and bottom ash transport waters typically
contain heavy metals, including priority pollutants [U.S. EPA, 1982]. Chapter 5 further discusses
ash handling operations and wastewater generation at coal-fired power plants.
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Chapter 3 - Steam Electric Industry Profile
3.2.2 Flue Gas Desulfurization
Power plants use FGD scrubber systems to remove SC>2 from stack emissions. Typically,
FGD scrubber systems can remove over 90 percent of the SC>2 in the flue gas, and in many cases
can remove up to or greater than 99 percent. Wet FGD scrubbers are the most common;
however, dry FGD scrubbers also exist [U.S. EPA, 2003]. Although dry FGD scrubbers use
water in their operation, they do not generate any wastewaters.
In wet FGD scrubbers, the flue gas stream comes in contact with a liquid stream
containing a sorbent, which is used to effect the mass transfer of pollutants from the flue gas to
the liquid stream. Figure 3-3 presents a simplified diagram of a typical wet FGD system. The
sorbents typically used for SC>2 absorption are lime (Ca(OH)2) or limestone (CaCOs), which react
with the sulfur in the flue gas to form calcium sulfite (CaSOs). Scrubber systems can be operated
with varying levels of oxidation. In forced oxidation systems, the CaSO3 is fully oxidized to
produce gypsum (CaSCV 2H2O). Section 4.2 discusses these processes in further detail.
Gas to
Stack
Sorbent Slurry Makeup
FGD
Scrubber
Flue Gas
FGD Scrubber
Blowdown/Sludge
Figure 3-3. Typical Wet FGD System
Limestone forced oxidation systems are the most common scrubbers operated in the
steam electric industry today. Plants that generate gypsum using limestone forced oxidation
systems can market the gypsum for use in building materials (e.g., wallboard), while plants that
do not generate gypsum or only partially oxidize the CaSOs must dispose of their scrubber
solids, typically in landfills or surface impoundments [U.S. EPA, 2006a]. Plants that are
producing a saleable product, such as gypsum, may rinse the product cake to reduce the level of
chlorides in the final product. This wash water may be reused or potentially treated and
discharged. Both sludge by-products, gypsum and CaSOs, typically require dewatering prior to
sale, disposal, or processing for reuse. This dewatering process generates a wastewater stream
that likely needs to be treated before it is discharged or reused. FGD scrubber system
wastewaters, including the wastewater stream from dewatering and scrubber blowdown, may
contain significant concentrations of metals, such as arsenic, mercury, and selenium. During the
scrubbing process, metals and other constituents that were not removed from the flue gas stream
by the electrostatic precipitators (ESPs) may be transferred to the scrubber blowdown and other
downstream wastewaters and/or solid products.
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Final Detailed Study Report Chapter 3 - Steam Electric Industry Profile
FGD wastewaters are currently regulated by the effluent guidelines as low volume wastes
generated at steam electric plants [40 CFR 423.1 l(b)]. EPA first identified FGD wastewater as a
potential wastewater for regulation during the 1982 rulemaking. At that time, EPA concluded
that the available data were not sufficient for characterizing the pollutant loadings from FGD
systems and that additional studies would be needed. [U.S. EPA, 1982]. Chapter 4 contains more
information on FGD systems, FGD wastewater characteristics, and the treatment of FGD
wastewater.
3.2.3 Selective Catalytic Reduction
Selective catalytic reduction (SCR) is a technology used to control nitrogen oxide (NOX)
emissions in the flue gas from the boiler. Ammonia (NH3) is injected into the flue gas upstream
of a catalyst, such as vanadium or titanium. The NOX in the flue gas (comprising mainly nitrogen
monoxide (NO) with lesser amounts of nitrogen dioxide (NO2)) reacts with the NH3 in the
presence of oxygen and the catalyst to form nitrogen and water:
4NO + 4NH3 + O2 -> 4N2 + 6H2O (3-1)
2NO2 + 4NH3 + O2 -> 3N2 + 6H2O (3-2)
In addition to these primary reactions, a fraction of the SO2 in the flue gas may be
oxidized to sulfur trioxide (SO3), and other side reactions may produce ammonium sulfate
((NH4)2SO4) and ammonium bisulfate (NH4HSO4) as by-products:
SO2 + '/2 O2 -> SO3 (3-3)
2NH3 + SO3 + H2O -> (NH4)2SO4 (3-4)
NH3 + SO3 + H2O -> NH4HSO4 (3 -5)
These by-products can foul and corrode downstream equipment. The extent to which they
are formed depends upon various factors within the process, including the sulfur content of the
coal used in the boiler and the amount of excess NH3 in the system. Unreacted NH3 present in
the flue gas from the SCR is commonly termed ammonia slip [CCT, 1997].
Plants may use different SCR configurations based on the particular operations of the
system, including placing the SCR upstream of the air heater9 and other emission control devices
such as a FGD scrubber and/or paniculate controls (e.g., ESP). Although the SCR does not
produce a waste stream, it can affect the characteristics of fly ash transport water, air heater wash
water, and FGD wastewater. As previously explained, unreacted NH3 and SO3 by-product can
create (NH4)2SO4 and NH/tHSO4, which can deposit in the air heater and must be removed
through periodic washes. Ammonia that passes unreacted through the SCR may attach to the
particulates in the flue gas and be removed from the flue gas in the air pollution control
equipment (e.g., ESP, baghouse, FGD scrubber). Because ammonia is soluble, if the ash
collected from the paniculate removal device is handled with a wet system (e.g., wet sluicing),
9 The air preheater utilizes the heat contained in the flue gas to increase the temperature (via heat exchange) of the
air injected into the boiler for combustion.
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Chapter 3 - Steam Electric Industry Profile
then the ammonia will likely partition into the wastewater and be discharged from the plant
[Wright, 2003].
In addition to reducing the ammonia slip, installing an SOs removal system before the air
heater may further reduce the amount of (NH^SC^ and NH4HSO4 formed and deposited in the
air heater and, consequently, the amount of NFL? in the air heater wash water [Wright, 2003].
3.2.4 Condenser Cooling
In the steam electric process, a constant flow of cooling water is required to maintain
steam condensation and a low pressure in the condenser. Steam electric plants typically use
either once-through cooling water systems or recirculating cooling water systems to condense the
steam from the process. In once-through cooling water systems, the cooling water is withdrawn
from a body of water, flows through the condenser, and is discharged back to the body of water.
A recirculating cooling system recirculates the cooling water required to maintain steam
condensation and a low pressure in the condenser. After it passes through the condenser, the
heated water is sent to a cooling tower to lower its temperature. The heated water enters the
cooling tower at the top and falls down the packing material in the tower. Air flows upward
through the tower, and as the air contacts the droplets of water, some of the water evaporates.
The high surface area of the packing material enhances evaporation. As water evaporates, the
latent heat required to evaporate the water is transferred from the water to the air, cooling the
water. Fresh water is periodically added to the cooling water system to make up for evaporative
losses. Additionally, as cooling water evaporates in the cooling tower dissolved minerals present
in the water remain behind in the system. Over time, these minerals will increase in
concentration. To prevent these minerals from building up to unacceptable levels, a volume of
water must be discharged periodically to purge the minerals from the system, which is referred to
as "cooling tower blowdown." Figure 3-4 presents a diagram of a recirculating cooling system.
7
Cooling
Tower
Make-up Water
Recirculated Cooling
Water
Cooling Tower
Blowdown
Figure 3-4. Diagram of a Recirculating Cooling System
As the cooling water passes through the condenser, microbiological species (e.g.,
bacterial slimes and algae) stick to and begin growing on the condenser tubes. This growth,
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Final Detailed Study Report Chapter 3 - Steam Electric Industry Profile
referred to in the industry as biofouling, reduces heat transfer, decreases flow, and accelerates
corrosion of the condenser. Various macro-organisms, such as mussels, mollusks, and clams, can
also inhibit condenser performance. Steam electric plants use biocides, such as sodium
hypochlorite, sodium bromide, or chlorine gas, to control biofouling on the condenser tubes and
cooling tower packing material. Plants may also use chlorine or other antimicrobials, or other
methods (e.g., mechanical, thermal) to control macro-organisms.
Once-through cooling water and cooling tower blowdown may contain the following
pollutants, often in low concentrations, as a result of chlorination and corrosion and erosion of
the piping, condenser, and cooling tower materials: chlorine, iron, copper, nickel, aluminum,
boron, chlorinated organic compounds, suspended solids, brominated compounds, and
nonoxidizing biocides. Although the pollutants present in cooling water-related wastewaters are
often at low concentrations, the overall pollutant mass discharge may be significant due to the
large flow rates of cooling water discharges at steam electric power plants.
Once-through cooling water is the largest volume wastewater discharge at coal-fired
power plants. EPA's data request obtained information on once-through cooling water flows
from 15 plants. The once-through cooling water flow rates at these plants ranged from 178 to
1,860 million gallons per day (mgd), with an average discharge rate of 720 mgd. Recirculating
cooling water systems minimize the amount of water used by steam electric plants. On average,
recirculating cooling water systems reduce the cooling water flow rate between 92 and 95
percent compared to once-through cooling systems, depending on the water source [U.S. EPA,
2001]. According to information obtained through the data request, the average cooling tower
blowdown flow rate (for 16 coal-fired power plants and 39 recirculating cooling water systems)
is 37.7 mgd. The recirculating cooling water flow rates for these plants ranged from 0.89 to 512
mgd. These data generally compare to the cooling water flow rate data presented in the 1996
Preliminary Data Study and the 1982 Development Document [U.S. EPA, 1996; U.S. EPA,
1982]10.
Although recirculating cooling systems reduce the amount of water used by the cooling
system, they consume more water than once-through cooling systems. Recirculating cooling
systems use evaporation to remove heat from the cooling water, and the water evaporated is lost
from the system. In a once-through cooling system, all the water used for cooling is discharged
from the cooling water system.
Some plants have implemented dry cooling technology to minimize cooling water usage,
due in part to water shortages that exist in arid parts of the world. Dry cooling systems transfer
heat to the atmosphere without water evaporation. There are two types of dry cooling systems for
power plant applications: direct dry cooling and indirect dry cooling. Direct dry cooling systems
use air to directly condense steam, whereas indirect dry cooling systems use a closed-cycle water
cooling system to condense steam, and the heated water is then cooled by air.
10 The 1982 Development Document states that the average flow rate through a once-through cooling system was
305 mgd and the average blowdown flow rate from a recirculating cooling system was 0.94 mgd, based on industry
survey data [U.S. EPA, 1982]. The 1996 Preliminary Data Study states that for a 1,150-MW coal-fired power plant,
the once-through cooling water flow rate is approximately 1,440 mgd and the cooling tower blowdown flow rate
ranges from 13.6 mgd to 36.6 mgd, depending on the cycle of concentration [U.S. EPA, 1996].
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Final Detailed Study Report Chapter 3 - Steam Electric Industry Profile
After the cooling water has been used to condense the steam in the condenser, the once-
through or recirculating cooling water is discharged (treated or untreated) to surface waters or a
POTW, or reused in other processes such as FGD make-up or transporting fly ash or bottom ash
to the ash pond.
Some plants use the large flow rates of the cooling water discharges to help meet their
effluent limits for other process wastewaters by diluting these other process wastes. This dilution
allows plants to meet low concentration limits for certain metals or other pollutants, but it does
not reduce the overall mass of pollutants discharged from the plant. This could result in nutrient
loads or bioaccumulative metals, such as arsenic, mercury, or selenium, accumulating in the
receiving water body.
Some plants treat the cooling tower blowdown generated at the plant, including a number
of plants that use vapor-compression evaporation systems in combination with a final drying
process for treatment system residuals, to treat cooling tower blowdown. Section 4.3 describes
the operation of vapor-compression evaporation/distillation systems used to treat FGD
wastewaters. The systems used to treat cooling tower blowdown are similar to the system used to
treat FGD scrubber purge; however, it is generally easier and more economical for plants to treat
cooling tower blowdown because cooling tower blowdown does not contain the types of salts
present in FGD scrubber purge. The distillate generated from the vapor-compression evaporation
system is reused for processes such as boiler or cooling water make up.
Several best management practices and treatment technologies are available to reduce the
discharge of chlorine and other biocides from steam electric plants. The 1982 Development
Document describes the following four biocide management practices in use at steam electric
plants for once-through and/or recirculating cooling systems [U.S. EPA, 1982; UWAG, 2006]:
• Low-level biocide application. Perform optimization study to determine
minimum amount of biocide needed to control biofouling;
• Natural decay of total residual oxidants (TRO)/free available oxidants. Isolate
(i.e., shut off) blowdown from cooling system after biocide application until the
biocide has naturally decayed to an acceptable level;
• Dechlorination (Dehalogenation). Add reducing agent, typically sulfur dioxide,
to the cooling water stream prior to discharge to consume the oxidizing biocide
present; and
• Mechanical cleaning. Clean the condenser tubes using a mechanical operation
(e.g., circulate oversized sponge rubber balls through the condenser tubes) instead
of using biocides, or to allow for reduced use of biocides.
3.2.5 Low Volume Wastes
Low volume wastes, as defined by the effluent guidelines, include a variety of waste
streams, such as wastewater associated with wet scrubber air pollution control systems, ion
exchange water treatment systems, water treatment evaporator blowdown, laboratory and
sampling streams, boiler blowdown, floor drains, cooling tower basin cleaning wastes, and
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Final Detailed Study Report Chapter 3 - Steam Electric Industry Profile
recirculating house service water systems. See 40 CFR 423.11. The wastewater associated with
wet scrubber air pollution control systems are described in section 3.2.2 and chapter 4 of this
report. The 1982 Development Document presents information on the generation and
characteristics of boiler blowdown, boiler feed water treatment wastewaters, and drains and
spills. For example, the 1982 Development Document describes that boiler blowdown can be
discharged continuously or intermittently to control the build-up of suspended and dissolved
solids in the boiler water and that the average blowdown flow rate is 33,000 gpd/plant (for 231
coal-fired power plants) [U.S. EPA, 1982].
Low volume wastes are typically combined with other plant wastewaters for treatment,
often in settling ponds. In some cases, low volume wastewaters can be recycled within the plant.
One data request plant reported using untreated low volume wastewater as a source for bottom
ash sluicing and another reported using it as a source for FGD make-up water. Some plants also
report reusing settling pond effluent from systems that receive a variety of wastewaters including
ash transport water and low volume wastes.
3.2.6 Metal Cleaning
The Steam Electric Power Generating effluent guidelines define metal cleaning waste as
"any wastewater resulting from cleaning [with or without chemical cleaning compounds] any
metal process equipment, including, but not limited to, boiler tube cleaning, boiler fireside
cleaning, and air preheater cleaning." (See 40 CFR 423.11). Chemicals are used to remove scale
and corrosion products that accumulate on the boiler tubes and retard heat transfer. The major
constituents of boiler cleaning wastes are the metals of which the boiler is constructed, typically
iron, copper, nickel, and zinc. Boiler firesides are commonly washed with a high-pressure water
spray against the boiler tubes while they are still hot. Fossil fuels with significant sulfur content
will produce sulfur oxides that adsorb on air preheaters. Water with alkaline reagents is often
used in air preheater cleaning to neutralize the acidity due to the sulfur oxides, maintain an
alkaline pH, and prevent corrosion. The types of alkaline reagents used include soda ash, caustic
soda, phosphates, and detergent.
Metal cleaning wastes are generated infrequently at many plants, with some operations
taking place perhaps once every 10 years. The metal cleaning wastewater is often sent to an ash
pond, but it may first receive initial treatment in a separate impoundment/basin as necessary to
meetNPDES permit limitations such as limitations on pH and selected metals. Some plants
handle metal cleaning wastes differently than other wastewaters because the metal cleaning
wastes are generated so infrequently and often have high pollutant concentrations. For example,
one plant EPA visited transfers its metal cleaning wastes to a concrete basin and allows the water
to evaporate over time (e.g., several years). Another plant EPA visited has its metal cleaning
wastes hauled off site by a contractor. Some plants have reported that they do not discharge
metal cleaning wastewater, accomplishing this by feeding the wastes to the boiler. The 1982
Development Document discusses the use of incineration, ash basin treatment, and physical
chemical treatment as options for handling metal cleaning wastes [U.S. EPA, 1982].
3.2.7 Coal Piles
Coal-fired power plants typically receive the coal via train or barge; however, depending
on the location of the mine, trucks may also be used to transport the coal to the plant. The coal is
unloaded in a designated area and conveyed to an outdoor storage area, referred to as the coal
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Chapter 3 - Steam Electric Industry Profile
pile. Power plants generally store between 25 and 40 days worth of coal in the coal pile, but this
varies by plant. Some coal-fired plants may operate more than one coal pile depending on the
location of the boilers and whether different types of coal are used or blended.
Rainwater and melting snow contacting the coal pile generates a waste stream that
contains pollutants associated with the coal, referred to as coal pile runoff. The quantity of runoff
depends upon the amount of precipitation, the physical location and layout of the pile, and the
extent to which water infiltrates the ground underneath the pile. Coal pile runoff is usually
collected in a runoff pond during or immediately after times of rainfall. Table 3-7 presents the
estimated coal pile runoff flow rates reported in the data request responses. Most of the flow
rates in Table 3-7 were estimated by the plants based on the amount of rainfall at the plant, the
size of the coal pile, and a runoff coefficient (based on plant experiences). The flow rates that are
normalized on a MW basis are based on the plants' total coal-fired capacity. The average coal-
fired capacity for the 30 plants included in the dataset is 1,490 MW per plant, and the median
coal-fired capacity per plant is 1,300 MW.
Table 3-7. Coal Pile Runoff Generation Reported for the EPA Data Request
Number of days runoff was
generated in 2006 b
Number of Plants
30
Average a
133
Median a
124
Range a
40 - 365
Flow Rate per Plant
gpy/plant
30
31,100,000
17,600,000
2,070,000 - 364,000,000
Flow Rate Normalized by Coal-Fired Capacity
gpy/MWc
30
19,300
12,600
2,650 - 109,000
Flow Rate Normalized by Tons of Coal Burned
gpy/Ton of Coal
30
6.61
5.20
1.25-26.2
Source: [U.S. EPA, 2008a].
Note: The coal pile runoff flow rate depends upon the geographic location of the plant (determines the amount of
rainfall), the capacity of the plant, and the amount of coal reserve at the plant (determines the size of the pile).
a - The flow rates presented have been rounded to three significant figures.
b - Estimated number of days coal pile runoff wastewater was generated in 2006.
c - For this summary, EPA assumed that the total capacity for each coal-fired steam electric unit is associated with
coal use. Non-coal-fired units are not included in the capacity calculations.
EPA also obtained coal pile runoff data from the NPDES Form 2C data provided by
UWAG. Within this dataset, there were 13 plants which reported a discharge for coal pile runoff.
Of these 13 plants, 7 reported flow rates associated with the outfall. The average flow rate for
these 7 plants was 213 gpm, but the flow rates ranged from 25 to 953 gpm [UWAG, 2008]. EPA
did not calculate the flow rates in gallons per year because EPA does not have data for the
duration or the frequency of the discharge from the outfalls in the Form 2C data set.
The type and amount of contaminants generated in coal pile runoff depends upon the coal
characteristics and the residence time of water within the coal pile. The rainfall generating the
coal pile runoff can dissolve inorganic salts or cause chemical reactions in the coal piles, which
will be carried away in the runoff. Coal pile runoff is typically acidic due to the oxidation of iron
sulfide, which produces sulfuric acid, and ferric hydroxide or ferric sulfate. Coal pile runoff may
contain high concentrations of copper, iron, aluminum, nickel, and other constituents present in
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Final Detailed Study Report Chapter 3 - Steam Electric Industry Profile
coal [U.S. EPA, 1982]. Plants typically direct coal pile runoff wastewaters to a holding pond
along with stormwater runoff from other areas near the coal pile.
During the site visit program, EPA requested that plants report the pH of their coal pile
runoff ponds. In some cases, EPA collected the pH measurement directly while on site, while in
other cases the plants collected the measurements before, during, or after EPA's site visit. These
coal pile runoff ponds were generally acidic with observed pH values often near 3 S.U. The
lowest pH observed in a coal pile runoff pond during a site visit was 2.57 S.U. The highest
observed pH was 8 S.U.; however, in this case, the plant's coal pile runoff pond also received
limestone pile runoff.
Because the transfers to the coal pile runoff are intermittent depending on rainfall, and
the transfers from the coal pile runoff pond are based on the level in the pond, the residence time
for treating the coal pile runoff is highly variable. For example, if the plant receives a heavy
rainfall for several hours causing the pond to overflow and transfer the runoff to surface waters,
then some of the runoff may only have been managed in the pond for an hour or two before
being discharged. However, if the plant receives a light rainfall that doesn't cause the pond to
overflow and the plant receives no rain for several weeks, then the rainfall that was collected will
have been in the pond that entire time. Most of the coal pile runoff ponds that EPA visited during
the site visit program are designed to manage the volume of coal pile runoff associated with a
10-year, 24-hour storm event.
3.2.8 Landfill Leachate and Runoff
Coal combustion residues (CCR) comprise a variety of wastes from the coal combustion
process, including fly ash, bottom ash, boiler slag, and FGD solids (e.g., gypsum and calcium
sulfite). CCR may be stored at the plant in on-site landfills or surface impoundments. Leachate is
the liquid that drains or leaches from a landfill or an impoundment. The two sources of landfill
leachate are precipitation that percolates through the waste deposited in the landfill and the
liquids contained within the CCR when it was placed in the landfill. Surface runoff is
precipitation that contacts the landfill wastes and flows over the landfill. Landfills typically have
some sort of storm water drainage to minimize the amount of rainwater entering the landfill.
Figure 3-5 presents a diagram depicting the generation and collection systems for landfill
leachate and landfill runoff.
As discussed in Section 4.2, some plants operating FGD systems can completely reuse
the FGD wastewater. To do this, most of these plants dispose of the FGD solids (i.e., gypsum or
calcium sulfite) in an on-site landfill. Additionally, many plants transfer fly ash or bottom ash to
an on-site landfill. These FGD solids and ash contained in the landfill can contaminate the water
that contacts it and this wastewater may eventually be discharged as contaminated runoff or
leachate.
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Chapter 3 - Steam Electric Industry Profile
66 66
6 6 & 6 6
6 6
"66
* o ,
6«"
6 66
66 66
6 6 & 6 6
> 6 6 6 & 6
6 Clay Liner/Vegitation
6 (if necessary) " 6
6 6 1 ^ 6
6 6 & 1 6 ? A.
^ 6 6
6
6
A ^
& 6
Runoff Drainage
Ditch
Bottom Liner
Leachate to
Collection Pond
Figure 3-5. Diagram of Landfill Leachate and Landfill Runoff Generation and Collection
Landfill leachate and surface runoff will contain heavy metals and other contaminants
through the contact with the CCRs. Because the various CCRs have different characteristics
(e.g., pollutant levels, moisture content, leaching ability), the characteristics of the leachate and
runoff depend upon the types of CCRs that are contained in the landfill. EPA's ORD is currently
conducting research evaluating the potential for pollutants to leach during the disposal or use of
CCRs. This research is being conducted to identify any potential cross-media transfers of
mercury and other metals and to meet EPA's commitment in the Mercury Roadmap
(www.epa.gov/hg/roadmap.htm) to report on the fate of mercury and other metals from
implementation of multi-pollutant control at coal-fired power plants. A series of reports are being
developed to document the results from the ORD research. Two reports have been published to
date:
• Characterization of Mercury-Enriched Coal Combustion Residuals from Electric
Utilities Using Enhanced Sorbents for Mercury Control [U.S. EPA, 2006a]; and
• Characterization of Coal Combustion Residues from Electric Utilities Using Wet
Scrubbers for Multi-Pollutant Control [U.S. EPA, 2008c].
These reports document changes in fly ash resulting from the addition of sorbents for
enhanced mercury capture, and evaluate residues from the expanded use of wet scrubbers. A
third report currently being prepared will provide data for additional CCR samples to cover coal
types and air pollution control configurations that were not addressed in the first two reports.
Adding to the previous research on the leaching potential for fly ash and FGD gypsum, the third
report will include data for other types of CCRs including non-gypsum scrubber residues
(primarily scrubber sludge containing calcium sulfite), blended CCRs (non-gypsum scrubber
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residues, fly ash, and lime), and wastewater treatment filter cake. The data compiled in these
reports can be used to evaluate the composition and leaching behavior of CCRs.
Some of the plants that EPA visited during the site visit program have a runoff and/or
leachate collection system for the landfills they operate. Typically, the leachate collected from
the landfill flows through a collection system consisting of ditches and/or underground pipes.
From the collection system, the leachate is transported to a collection pond. The runoff collection
systems typically consist of one or more small collection ponds surrounding the landfill area.
The leachate and runoff waters may be treated in separate ponds or combined together. Some
plants discharge the effluent from these collection ponds, while other plants send the collection
pond effluent to the ash pond.
When a landfill has reached its capacity, it will typically be closed (i.e., covered) to
protect against environmental release of the pollutants contained in the waste. The covering for
these landfills typically comprises several layers of material, which may include a clay liner to
keep as much moisture from entering the landfill as possible and a top layer of top soil on which
vegetation is planted. After the covering is applied to the landfill, the runoff should not become
contaminated from the solids in the landfill, but because the covering may still be permeable,
these landfills may continue to generate leachate.
CCRs can also be stored in surface impoundments (i.e., ash ponds and FGD ponds) as
well as landfills. Some of these surface impoundments may have liners and collection systems
similar to the landfills discussed previously. EPA lacks data quantifying the extent to which the
effluent from the surface impoundment collection systems is recycled back to the surface
impoundment, rather than discharged directly to surface water.
3.2.9 Combined Cycle Generating Units
Approximately 411 power plants operate one or more combined cycle systems fueled by
fossil or fossil-type fuels to produce electricity. A combined cycle system is a combination of
one or more combustion turbine electric generating units operating in conjunction with one or
more steam turbine electric generating units. Combustion turbines, which typically are similar to
jet engines, are usually fueled with natural gas, but may also be fueled with oil.
Exhaust gases from combustion are sent directly through the combustion turbine which is
connected to a generator to produce electricity. The exhaust gases exiting the combustion turbine
still contain useful waste heat, so they are directed to heat recovery steam generators (FIRSGs) to
generate steam to drive an additional turbine. The steam turbine is also connected to a generator
(which may be a different generator or the same generator that is connected to a combustion
turbine) that produces additional electricity. Thus, combined cycle systems use steam turbine
technology to increase the efficiency of the combustion turbines. Figure 3-6 illustrates the
combined cycle system process.
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Gas
Turbine
Cycle
Fuel (e.g., gas, oil, or
gasified coal)
Air-
Electric
Generator
Steam
Turbine
Cycle
-Exhaust Gase
Heat Recovery
Steam Generator
(HRSG)
Figure 3-6. Combined Cycle Process Flow Diagram
The operation of steam electric units within combined cycle systems is virtually identical
to stand-alone steam electric units, with the exception of the boiler. In a combined cycle system,
the combustion turbines and HRSGs functionally take the place of the boiler of a stand-alone
steam electric unit. The other two major components of steam electric generating units within
combined cycle systems, the steam turbine/electric generator and steam condenser, are virtually
identical to those of stand-alone steam electric units. Thus, the wastewaters and pollutants
generated from the combined cycle system are the same as those from the stand-alone steam
electric process. These wastewaters include cooling water and steam condensate water treatment
wastes.
Combustion turbines may generate wastewaters from emissions control, equipment
cooling, and equipment cleaning [U.S. EPA, 1996]. Because combustion turbines require clean-
burning fuels, combined cycle combustion turbines do not discharge ash wastewaters. Although
the amount generated from the combustion turbines is relatively low, these wastewaters may
contain similar pollutants and concentrations as the regulated steam electric wastewaters.
3.2.10 Integrated Gasification Combined Cycle (IGCC)
IGCC is an electric power generation process that combines gasification technology with
both gas turbine and steam turbine power generation (i.e., combined cycle power generation). In
an IGCC system, a gasifier is used to convert carbon-based feedstock (e.g., coal or petroleum
coke) into a syngas. The syngas is cleaned of particulates, sulfur, and other contaminants and is
then combusted in a high-efficiency combustion gas turbine/generator. Heat from the combustion
turbine exhaust is then extracted in a heat recovery steam generator to produce steam and drive a
steam turbine/generator. IGCC plants can achieve higher thermodynamic efficiencies, emit lower
levels of criteria air pollutants, and consume less water than traditional coal combustion power
plants [Ratafia-Brown, 2002].
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Final Detailed Study Report Chapter 3 - Steam Electric Industry Profile
According to DOE's NETL Gasification World Database, 144 plants around the world
operated gasification systems that generate electricity as of 2007 and approximately 10
additional gasification plants were planned to be built between 2008 and 2010. The total 2007
installed global capacity amounts to approximately 29,000 MW of electricity [U.S. DOE,
2007a]. NETL reports that there are currently 15 operating IGCC projects around the world as of
March 2009, four of which are commercial-scale [Stiegel, 2009]. Two of these commercial-scale
IGCC systems are located in the United States — the 262-MW Wabash River IGCC Repowering
Project (Wabash River) in Indiana and the 250-MW Tampa Electric Polk Power Station IGCC
Project (Polk) in Florida. Other U.S. power companies are investigating or planning IGCC
systems at new or existing plants, such as the proposed Duke Energy Edwardsport Station in
Knox County, Indiana, which is planning to start up an IGCC plant by 2011 or 2012 [Duke
Energy, 2009].
This section discusses the IGCC operations at the currently operating U.S. systems and
the wastewaters generated from these systems. The majority of information is specific to the
Wabash River IGCC gasification process, which EPA visited in February 2009. Supplemental
information from the Polk process is also included here. The following stages of the Wabash
River IGCC gasification process are discussed below and shown in Figure 3-7:
• Gasification and slag handling. A gasifier converts hydrocarbon feedstock into
gaseous components by applying heat under pressure in the presence of steam.
The feedstock is broken down into a syngas consisting of primarily hydrogen,
carbon monoxide, water, and carbon dioxide gases. Sulfur in the fuel is converted
to primarily hydrogen sulfide (H2S) with a small portion converted to carbonyl
sulfide (COS). In the gasifier, mineral matter in the fuel forms a molten slag that
drops down to the bottom of the gasifier into a water quench bath. The slag/water
slurry is dewatered in a dewatering bin and settler, and the overflow water is
recycled as slag quench water.
• Syngas cooling and particulate removal. Syngas contains impurities from the
coal such as sulfides, chlorides, mercury, particulate matter, and other impurities
from the feedstock that must be removed prior to combusting the syngas.
Particulate matter is removed from the syngas using filter elements.
• Low-temperature heat recovery, chloride scrubbing, and syngas
moisturization. The particulate-free sour syngas (i.e., syngas containing a
significant amount of sulfur compounds) is sent to a water scrubber that removes
chlorides and trace metals from the syngas. The syngas then enters the COS
hydrolysis unit where COS in the gas is converted to H2S. The syngas is then
cooled, which condenses water from the syngas and transfers ammonia (NFb),
carbon dioxide (CO2), and H^S from the syngas into the condensed "sour" water,
which is transferred to the sour water treatment system. The cooled sour syngas is
transferred to the acid gas removal system, in which the sulfur compounds are
removed, producing sweet syngas (i.e. syngas with very few sulfur compounds
present). The sweet syngas is then moisturized and superheated prior to use in the
combustion turbine.
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Acid gas removal. The remaining hydrogen sulfide and carbon dioxide in the
sour syngas stream are removed in the absorber of the acid gas removal system,
which uses methyldiethanolamine (MDEA) as a solvent.
Sulfur recovery. In the sulfur recovery unit, H2S from the acid gas removal
stripper and the sour water treatment system is converted into pure, molten
elemental sulfur (or sulfuric acid, such as in the Polk process).
Sour water treatment. Sour water treatment involves removing the ammonia,
CC>2, and H2S dissolved gases in a two-step stripping process in which steam is
used to drive off the dissolved gases. First, the CC>2 and H^S are stripped,
generating a gas stream and a water stream, a large portion of which is recycled
for feedstock slurry preparation. A small portion of the water is treated in an
ammonia stripping column, which generates a "sweet" water stream, which
contains 500 to 1,000 ppm chlorides.
Recycle Slurry Water
Slag Product
Sulfur Product
Figure 3-7. Wabash River ConocoPhillips E-Gas™ Gasification Process
Although it has been treated by steam stripping, the sweet water stream contains elements
from the gasifier such as selenium, chromium, and arsenic. Additionally, at the high operating
temperatures and pressures of a gasification unit, various metal compounds are formed, such as
selenocyanate, which are not known to be generated in a traditional coal-fired unit. At Wabash
River, prior to 2002, the sweet water was sent to a settling pond but the plant often was unable to
meet its permit limits. To resolve this situation, in 2002 a vapor-compression evaporator system
was installed at Wabash River to treat the sweet water. The concentrated brine from the
evaporator is sent to a rotary drum dryer that concentrates the pollutants through evaporation and
deposits solid waste on the drum as a cake. The salt cake, which is treated as a hazardous waste
due to selenium and arsenic levels, is hauled away one to two times per week and it is made into
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Final Detailed Study Report Chapter 3 - Steam Electric Industry Profile
a cement product that is used for stabilization only (i.e., for disposal). The distillate from the
rotary drum dryer is sent to the gasification wastewater settling pond. The effluent from the
gasification wastewater settling pond is transferred to Wabash River's ash pond and then
discharged. Since operation of the evaporator unit, Wabash River has had more success in
meeting its permit requirements [ERG, 2009f; EPRI, 2007d].
The following is a list of the key wastewaters that are associated with the operation of the
Wabash River IGCC unit:
• Rotary drum dryer distillate;
• Slag handling wastewater;
• Slowdown from the heat recovery steam generator;
• CO2 stripper wastewater
• Petroleum coke pile runoff pond effluent;
• Air separation unit blowdown;
• Raw water filtration backwash;
• Demineralizer system reject;
• Sump water (miscellaneous liquid waste from the process area); and
• Cooling tower blowdown.
The rotary drum dryer distillate, cooling tower blowdown, and sump water is treated in
the gasification wastewater settling pond. Other wastewaters generated in the Wabash River
IGCC gasification process are able to be reused in the gasifier or in the feedstock slurry
preparation [ERG, 2009f; Wabash River Energy, 2000].
The processes and wastewaters generated at the Polk plant are generally similar to those
described above for Wabash River, with a few differences. The major difference is that Polk uses
a brine concentrator/evaporator system to treat the gasification process wastewater. The only
solid product from the brine evaporator is ammonium chloride, which is transferred to a landfill.
The distillate from the brine concentrate displaces boiler make-up boiler feed water for
instrument tap purges and pump seal flushes. Because the distillate is reused, there are no
wastewaters discharged from Folk's gasification process [EPRI, 2007d; Tampa Electric
Company, 2008].
Because IGCC syngas contains high concentrations of carbon compared to post-
combustion flue gas, CC>2 capture is expected to be less expensive for pre-combustion capture
from IGCC systems than for post-combustion capture. Although no current IGCC plants use
carbon capture, several technologies have been proposed. One is to convert the carbon monoxide
in the syngas to carbon dioxide and hydrogen gas using a water gas shift reactor [EPRI, 2009].
The following section discusses carbon capture and storage processes in more detail.
3.2.11 Carbon Capture and Storage
Carbon capture and storage is an approach being investigated to reduce or mitigate the
contribution of fossil fuel emissions to global warming. Due to potential future regulations on
carbon dioxide (CO2) emissions, many steam electric power plants are considering alternatives
available for reducing carbon emissions.
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Final Detailed Study Report Chapter 3 - Steam Electric Industry Profile
There are three main approaches for capturing the CO2 associated with generating
electricity: post-combustion, pre-combustion, and oxyfuel combustion.
• In post-combustion capture, the CO2 is removed after combustion of the fossil
fuel.
• In pre-combustion capture, the fossil fuel is partially oxidized, for instance in a
gasifier. The resulting syngas (CO and H2) is shifted into CO2 and more H2 and
the resulting CO2 can be captured from a relatively pure exhaust stream before
combustion takes place.
• In oxy-fuel combustion., also known as oxy-combustion, the fuel is burned in
oxygen instead of air. The flue gas consists of mainly carbon dioxide and water
vapor, the latter of which is condensed through cooling. The result is an almost
pure carbon dioxide stream that can be transported to the sequestration site and
stored. Processes based on oxyfuel combustion are sometimes referred to as "zero
emission" cycles, because the CO2 stored is not a fraction removed from the flue
gas stream (as in the cases of pre- and post-combustion capture) but the flue gas
stream itself. However, a certain fraction of the CO2 generated during combustion
will inevitably end up in the condensed water.
After capture, the CO2 would be transported to a suitable storage, or sequestration, site.
Approaches under consideration include geologic sequestration (injection of the CO2 into an
underground geologic formation), ocean sequestration (typically injecting the CO2 into the water
column at depths to allow dissolution or at deeper depths where the CO2 is denser than water and
would form CO2 "lakes"), and mineral storage where CO2 is exothermically reacted with metal
oxides to produce stable carbonates.
DOE's National Energy Technology Laboratory (NETL) is currently leading a research
effort to develop retrofit technologies for coal-fired power plants, including the oxy-combustion
process, and pre-combustion carbon capture technologies specifically for IGCC plants (see
Section 3.2.10 for discussion of the IGCC process) [U.S. DOE, 2009]. Based on preliminary
information regarding these technologies, EPA believes they may result in new air pollution
control wastewaters that will need to be addressed at steam electric power plants. However, as
these technologies are currently in the early stages of research and development and/or pilot
testing, the industry has little information on the potential wastewaters generated from carbon
capture processes or the characteristics of these wastewaters.
American Electric Power's (AEP's) Mountaineer Power Plant and We Energies' Pleasant
Prairie Power Plant are participating in EPRI-led pilot tests demonstrating one of Alstom
Corporation's post-combustion carbon capture technologies, the chilled ammonia process
[Alstom, 2009]. Alstom has several demonstration projects11 either operating or being built for
three carbon capture technologies: chilled ammonia, advanced amines, and oxy-combustion. The
Pleasant Prairie Power Plant CO2 capture project started operating in 2008 and the Mountaineer
Power Plant CO2 capture and storage pilot project is expected to start operating this year. The
latter project will be the first phase of the Alstom/AEP two-phase process to bring the chilled
ammonia process to full scale by 2011. For the second phase, Alstom plans to design, build, and
11 Alstom has four carbon capture projects operating or under construction, and six additional projects scheduled.
These projects are taking place in seven different countries using coal, oil, or natural gas as fuels [Alstom, 2008]
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add the first commercial-scale CO2 capture system at one of the AEP plants [Power Magazine,
2008].
The chilled ammonia process planned at Mountaineer absorbs and strips CO2 from flue
gas following the FGD process (see Figure 3-8). First, the water-saturated flue gas is cooled and
cleaned by refrigerated water injected directly into the gas stream. As the flue gas is cooled,
water condenses from the gas, carrying the residual contaminants with it. The water is then
evaporated in cooling towers, which reduces the total flue gas volume prior to entry into the CC>2
absorber unit. In the absorber, a dissolved and suspended mix of ammonium carbonate and
ammonium bicarbonate reacts with the flue gas, potentially removing 90 percent or more of the
CC>2 in the flue gas. The cleaned flue gas exits the absorber and then exits the stack. Residual
ammonia is captured by a cold-water wash and recycled to the absorber. The CO2-rich slurry is
pumped through a heat exchanger, in which the slurry is dissolved. The slurry is then transferred
to a high-pressure regenerator, in which additional heat is added by a reboiler and the CC>2 gas is
stripped from the solution. The removed CC>2 can be washed, compressed, and sequestered by
injection into geologic formations, such as deep saline aquifers or depleted oil and gas reservoirs.
[AWMA, 2008; Power Magazine, 2008].
Low Sulfur
Flue Gas
Concentrated CO2
to Compression/
Storage
Rich (CO2)
Agent
Lean
Reagent
Source: [Power Magazine, 2008].
Figure 3-8. AEP's Chilled Ammonia Process at Mountaineer Power Station
As discussed previously in this section, there are other post-combustion carbon capture
technologies currently being developed for the industry. One such technology is planned to be
pilot tested at the Alabama Power Company's Plant Barry beginning in 2011. The pilot test is a
partnership between DOE, Mitsubishi Heavy Industries, EPRI, and Southern Company. The
carbon capture technology is an amine solvent based technology developed by Mitsubishi Heavy
Industries [POWERnews, 2009].
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Final Detailed Study Report Chapter 3 - Steam Electric Industry Profile
3.3 Effluent Guidelines for the Steam Electric Power Generating Point Source Category
The Clean Water Act establishes a structure for regulating discharges of pollutants to
surface waters of the United States. As part of the implementation of the Act, EPA issues
effluent guidelines for industrial dischargers. EPA first issued effluent guidelines for the Steam
Electric Power Generating Point Source Category (i.e., the Steam Electric effluent guidelines) in
1974 with subsequent revisions in 1977 and 1982. The Steam Electric effluent guidelines are
codified at 40 CFR Part 423 and include limitations for the following waste streams:
• Once-through cooling water;
• Cooling tower blowdown;
• Fly ash transport water;
• Bottom ash transport water;
• Metal cleaning wastes;
• Coal pile runoff; and
• Low-volume waste sources, including but not limited to wastewaters from wet
scrubber air pollution control systems, ion exchange water treatment systems,
water treatment evaporator blowdown, laboratory and sampling streams, boiler
blowdown, floor drains, cooling tower basin cleaning wastes, and recirculating
house service water systems (sanitary and air conditioning wastes are not
included) [40 CFR423.11(b)].
The current effluent guidelines are summarized in Table 3-8 and are applicable to:
".. .discharges resulting from the operation of a generating unit by an establishment
primarily engaged in the generation of electricity for distribution and sale which results
primarily from a process utilizing fossil-type fuel (coal, oil, or gas) or nuclear fuel in
conjunction with a thermal cycle employing the steam water system as the
thermodynamic medium." [40 CFR 423.10]
The effluent guidelines do not apply to plants that primarily use a non-fossil or non-
nuclear fuel source (e.g., wood waste, municipal solid waste) to power the steam electric
generators, nor do they apply to generating units operated by establishments that are not
primarily engaged in generating electricity for distribution and sale.
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Table 3-8. Current Effluent Guidelines and Standards for the Steam Electric Power Generating Point Source Category
Waste Stream
All Waste Streams
Low-Volume
Wastes
Fly Ash Transport
Bottom Ash
Transport
Once-Through
Cooling
Cooling Tower
Blowdown
Coal Pile Runoff
BPTa
pH: 6-9 S.U. b
PCBs: Zero discharge
TSS: 100 mg/L; 30 mg/L
Oil & Grease: 20 mg/L; 15 mg/L
TSS: 100 mg/L; 30 mg/L
Oil & Grease: 20 mg/L; 15 mg/L
TSS: 100 mg/L; 30 mg/L
Oil & Grease: 20 mg/L; 15 mg/L
Free Available Chlorine: 0.5
mg/L; 0.2 mg/L
Free Available Chlorine: 0.5
mg/L; 0.2 mg/L
TSS*: 50 mg/L instantaneous
maximum
BATa
PCBs: Zero discharge
Total Residual Chlorine:
If > 25 MW: 0.20 mg/L
instantaneous maximum;
If<25MW, equal to BPT
Free Available Chlorine: 0.5
mg/L; 0.2 mg/L
126 Priority Pollutants: Zero
discharge, except:
Chromium: 0.2 mg/L; 0.2 mg/L
Zinc: 1.0 mg/L; 1.0 mg/L
NSPSa
pH: 6-9 S.U. b
PCBs: Zero discharge
TSS: 100 mg/L; 30 mg/L
Oil & Grease: 20 mg/L; 15 mg/L
Zero discharge
TSS: 100 mg/L; 30 mg/L
Oil & Grease: 20 mg/L; 15 mg/L
Total Residual Chlorine:
If > 25 MW: 0.20 mg/L
instantaneous maximum;
If < 25 MW, equal to BPT
Free Available Chlorine: 0.5
mg/L; /0.2 mg/L
126 Priority Pollutants: Zero
discharge, except:
Chromium: 0.2 mg/L; 0.2 mg/L
Zinc: 1.0 mg/L; 1.0 mg/L
TSS*: 50 mg/L instantaneous
maximum
PSES and PSNS a
PCBs: Zero discharge
Zero discharge
(PSNS only)
No limitation for PSES
126 Priority Pollutants: Zero
discharge, except:
Chromium: 0.2 mg/L; 0.2 mg/L
Zinc: 1.0 mg/L; 1.0 mg/L
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Table 3-8. Current Effluent Guidelines and Standards for the Steam Electric Power Generating Point Source Category
Waste Stream
BPTa
BATa
NSPSa
PSES and PSNS a
Metal Cleaning
Wastes
Chemical
TSS: 100 mg/L; 30 mg/L
Oil & Grease: 20 mg/L; 15 mg/L
Copper: 1.0 mg/L; 1.0 mg/L
Iron: 1.0 mg/L; 1.0 mg/L
See Metal Cleaning Wastes above
See Chemical Metal Cleaning
Wastes below
Copper: 1.0 mg/L; 1.0 mg/L
Iron: 1.0 mg/L; 1.0 mg/L
Non-chemical See Metal Cleaning Wastes above Reserved
See Chemical Metal Cleaning
Wastes below
TSS: 100 mg/L; 30 mg/L
Oil & Grease: 20 mg/L; 15 mg/L
Copper: 1.0 mg/L; 1.0 mg/L
Iron: 1.0 mg/L; 1.0 mg/L
Reserved
See Chemical Metal Cleaning
Wastes below
Copper: 1.0 mg/L (daily
maximum)
Reserved
Source: [40 CFR Part 423].
a - The limitations for TSS, oil & grease, copper, iron, chromium, and zinc are presented as daily maximum (mg/L); 30-day average (mg/L). For all effluent
guidelines, where two or more waste streams are combined, the total pollutant discharge quantity may not exceed the sum of allowable pollutant quantities for
each individual waste stream. BPT, BAT, and NSPS allow either mass- or concentration-based limitations.
b - The pH limitation is not applicable to once-through cooling water.
Free Available Chlorine: 0.5 mg/L; 0.2 mg/L - 0.5 mg/L instantaneous maximum, 0.2 mg/L average during chlorine release period. Discharge is limited to 2
hrs/day/unit. Simultaneous discharge of chlorine from multiple units is prohibited. Limitations are applicable at the discharge from an individual unit prior to
combination with the discharge from another unit.
Total Residual Chlorine: 0.20 mg/L instantaneous maximum. Total residual chlorine (TRC) = free available chlorine (FAC) + combined residual chlorine (CRC).
TRC discharge is limited to 2 hrs/day/unit. TRC is applicable to plants >25 MW, and FAC is applicable to plants <25 MW. The TRC limitation is applicable at
the discharge point to surface waters of the United States and may be subsequent to combination with the discharge from another unit.
126 Priority Pollutants: zero discharge -126 priority pollutants from added maintenance chemicals (refer to App. A to 40 CFR 423). At the permitting authority's
discretion, compliance with the zero-discharge limitations for the 126 priority pollutants may be determined by engineering calculations, which demonstrate that
the regulated pollutants are not detectable in the final discharge by the analytical methods in 40 CFR part 136.
TSS*: 50 mg/L instantaneous maximum on coal pile runoff streams. No limitation on TSS for coal pile runoff flows >10-year, 24-hour rainfall event.
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4. FLUE GAS DESULFURIZATION SYSTEMS
This chapter presents an overview of flue gas desulfurization (FGD) systems at coal-fired
power plants within the steam electric industry, with particular emphasis on FGD wastewater
characteristics and treatment. This chapter also presents a profile of the current and projected
future use of FGD systems within the industry.
Power plants use FGD systems to control SC>2 emissions from the flue gas generated in
the plants' boilers. Wet FGD scrubbers are the most common type of FGD system; however,
approximately 20 percent of electric generating units serviced by SO2 scrubbers are serviced by
dry FGD systems [U.S. DOE, 2005b]. There are several variations of wet FGD systems, but this
section focuses on the limestone forced oxidation system and the lime or limestone inhibited
oxidation system, which are the designs predominantly used in the industry today. This section
also presents some information about other types of FGD systems used at coal-fired power
plants, including dry scrubbers, which do not generate wastewaters.
EPA has compiled information on the current and projected use of FGD systems at coal-
fired power plants using information collected from the 2005 Form EIA-767 [U.S. DOE, 2005b],
the 2005 Form EIA-860 [U.S. DOE, 2005a], EPA's site visit and sampling data, EPA's data
request information [U.S. EPA, 2008a], EPA's National Electric Energy Data System (NEEDS)
2006 database [U.S. EPA, 2006h], the Integrated Planning Model [U.S. EPA, 2006b] developed
by ICF Consulting, Inc., and other publicly available information (e.g., company websites,
vendor news releases). The collective data from these data sources are referred to in this report as
the "combined data set12." See Chapter 2 for additional information about EPA's data collection
activities.
4.1 Coal-Fired FGD System Statistics
This section presents statistics on the number and characteristics of coal-fired power
plants that currently operate wet or dry FGD systems, or are expected to install an FGD system
in the next decade. Also included in this section are estimates of the coal-fired steam electric
industry's current and projected total generating capacity and scrubbed capacity.
4.1.1 Current Coal-Fired FGD System Profile
The current coal-fired FGD system profile presents a picture of the coal-fired steam
electric industry as of June 2008, including the number of coal-fired power plants with FGD
systems, the associated scrubbed capacity, and plant characteristics. EPA used information from
the combined data set to generate the profile.
Wet FGD systems are in operation at 108 plants, treating the flue gases from 223
generating units. These 223 electric generating units represent the number of electric generating
units scrubbed and is not exactly equal to the number of FGD systems. The two numbers are
similar; however, EPA is aware of several plants that use a single FGD scrubber to service more
than one electric generating unit. The combined generating capacity of the wet-scrubbed
generating units represents approximately 33 percent of the total nationwide coal-fired steam
12 Due to the limited time available upon receiving the surface impoundment data collected by EPA's ORCR, the
ORCR data are not included in the combined data set.
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electric power generating capacity. EPA expects that percentage to increase significantly over
the next decade, as discussed in Section 4.1.2. Table 4-1 presents statistics on the current coal-
fired steam electric power generation associated with FGD systems, relative to total industry
coal-fired and fossil-fueled steam electric power generation.
Table 4-1. Scrubbed Coal-Fired Steam Electric Power Generation as of June 2008
Industry Category
Fossil-Fueled Steam Electric Power Generation d' e> f
Coal-Fired Steam Electric Power Generation ^ f
Coal-Fired Steam Electric Power Generation with
Any FGD System (Wet or Dry) 8
Coal-Fired Steam Electric Power Generation with a
Wet FGD System8'11
Coal-Fired Steam Electric Power Generation with a
Diy FGD System8'11
Number of
Plants a
1,120
488
146
108
41
Number of Electric
Generating Units a'b
2,450
1,180
280
223
57
Capacity
(MW) a'c
657,000
330,000
123,000 '
108,000 '
14,900 '
a - The numbers presented have been rounded to three significant figures.
b - The number of electric generating units represents the number of electric generating units scrubbed and does not
represent the number of FGD systems. The two numbers are similar, but several plants use a single FGD scrubber
for more than one electric generating unit.
c - The capacities presented represent the nameplate capacity for the electric generating unit.
d- Source: 2005 EIA-860 [U.S. DOE, 2005a].
e - Fossil-fueled generation includes coal, oil, and natural gas. It does not include nuclear generation.
f - The table includes the stand-alone steam electric and all combined cycle turbines (i.e., combined cycle steam
turbine, combined cycle single shaft, and combined cycle combustion turbine).
g - Source: Combined data set (2005 EIA-767 [U.S. DOE, 2005b], UWAG-provided data [ERG, 2008g], data
request information [U.S. EPA, 2008a], and site visit and sampling information).
h - The wet and dry FGD system information is a subset of the information for "Any FGD System." Note that
several plants operate both wet and dry FGD systems. Thus, there is overlap between the number of plants with wet
FGD systems and the number of plants with dry FGD systems.
i - Includes only the capacity for the scrubbed electric generating units.
The majority of the plants in the combined data set with wet FGD systems (46 percent)
use eastern bituminous coal as the primary fuel source. This is to be expected because eastern
bituminous coal typically contains a higher sulfur content than other coal types, thus producing
higher 862 emissions than other types of coal. Other coals reported to be used in wet-scrubbed
units include subbituminous (24 percent of plants), lignite (9 percent of plants), and other
bituminous coal (20 percent of plants). Table 4-2 summarizes plant characteristics for the
currently operating wet scrubbed electric generating units included in the combined data set.
4-2
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Chapter 4 - Flue Gas Desulfurization Systems
Table 4-2. Characteristics of Coal-Fired Power Plants with Wet FGD Systems
Total
Combined Data Set a
Number of Plants with
Wet FGD Systems
108
Number of Wet Scrubbed
Electric Generating Units
223
Wet Scrubbed Capacity1"
(MW)
108,000
Primary Coal Type c
Bituminous
Subbituminous
Lignite
72
26
10
161
48
14
76,300
22,700
9,060
Type of Oxidation System
Forced Oxidation
Inhibited or Natural Oxidation
No Information
50
36
26
111
62
50
61,600
30,000
16,700
Sorbent
Limestone
Limestone & Fly Ash
Lime
Lime & Fly Ash
Magnesium-Enhanced Lime
Magnesium Oxide
Fly Ash
Soda Ash
Soda Liquor
Sodium Carbonate
No Information
74
1
17
2
3
2
3
1
1
2
3
151
1
33
5
8
3
6
2
4
5
4
78,200
50
11,800
2,750
7,390
896
2,360
530
2,320
938
800
NOx Controls
SCRd
SNCR
None/Other (no SCR/SNCR)
No Information
40
7
44
25
79
15
80
49
47,000
4,700
35,600
20,900
Note: All 108 plants are included in the each of the categories presented in this table. Because a plant may operate multiple
electric generating units that may represent more than one type of operation in each specific category, the sum of the plants for
each category may be greater than 108 plants.
a - Source: Combined Data Set (2005 Form EIA-767 [U.S. DOE, 2005b], the 2005 Form EIA-860 [U.S. DOE, 2005a], EPA's
site visit and sampling data, EPA's data request information [U.S. EPA, 2008a], EPA's NEEDS 2006 database [U.S. EPA,
2006h], and other publicly available information (e.g., company web sites, vendor news releases)).
b - The capacities represent the reported nameplate capacity. The capacities presented have been rounded to three significant
figures. Due to rounding, the total capacity may not equal the sum of the individual capacities.
c - Some plants/electric generating units use a blend of more than one coal in the electric generating units. This table presents
information for only the primary type of coal burned in the electric generating unit.
d - Some of the SCRs included in the table are planned/under construction.
Of these wet scrubbed electric generating units, 111 (50 percent) are serviced by forced
oxidation systems and 62 (28 percent) are serviced by natural or inhibited oxidation systems.
EPA does not have information regarding the type of oxidation system for the FGD systems
servicing the remaining 50 electric generating units (22 percent).
Wet FGD systems use a sorbent to transfer pollutants from the flue gas to the liquid
stream. Limestone is by far the predominant sorbent used in wet FGD systems (68 percent of the
4-3
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
currently operating electric generating units), followed by lime (17 percent of electric generating
units), and magnesium-enhanced lime (4 percent of electric generating units). Magnesium oxide,
fly ash, soda ash, soda liquor, or sodium carbonate sorbents collectively are used in FGD systems
servicing 9 percent of electric generating units. EPA does not have sufficient information to
determine the type of sorbent used for the remaining 2 percent of electric generating units.
Nearly one-third of the plants reported using additives in their FGD systems. Some plants
add organic acids, such as dibasic acid (DBA) or formic acid, to improve the sulfur dioxide
removal efficiency. Inhibited oxidation plants typically will add emulsified sulfur or a similar
compound to prevent oxidation of the calcium sulfite by-product so that calcium sulfate
(gypsum) will not be formed.
Over 40 percent of the wet-scrubbed electric generating units in the combined data set
operate either a SCR or SNCR system to reduce NOX emissions (35 percent SCR; 7 percent
SNCR). See Section 3.2 for details regarding the operation of NOX control systems at power
plants.
No plants in the combined data set were identified as currently operating advanced flue
gas mercury controls; however, according to the DOE, more than 130 full-scale activated carbon
injection systems have been ordered by coal-fired plants [Feeley, 2009]. One outcome of
litigation surrounding the Clean Air Mercury Rule has been that in the absence of a specific
regulatory requirement, plants are refraining from operating the mercury control systems that
have been installed.
4.1.2 Projected Use of FGD Systems at Coal-Fired Plants
EPA used information from EPA's NEEDS 2006 database [U.S. EPA, 2006h], and the
IPM [U.S. EPA, 2006b] to evaluate the expected trends in the number and capacity of units that
will be scrubbed in the future.
The use of FGD systems has increased substantially since the effluent guidelines were
last revised in 1982. Power plants are expected to continue installing new FGD systems in
substantial numbers until at least 2025.13 Table 4-3 presents the projected use of wet and dry
FGD systems, from 2009 through 2025, and compares the projected scrubbed capacity to the
projected total coal-fired capacity.14 EPA models have predicted that over 60 percent of coal-
fired capacity will be wet scrubbed by 2020. EPA predicts that the industry's dry scrubbed
capacity will increase only slightly into the future and that most new FGD systems will be wet
scrubbers [ERG, 2008f].
13 EPA projected future generating capacity with FGD systems using IPM Base Case 2006 (v.3.0), which reflects the
CAMR mercury reduction requirements and the CAIR NOx and SO2 emission reduction requirements for power
plants.
14 The data presented in Table 4-3 is based on the NEEDS 2006 database and IPM Base Case 2006 (v. 3.0). The
2020 capacity presented is the basis for the future FGD wastewater treatment industry profile presented in Section
4.6.1; however, the two data sets are not identical because the future FGD wastewater treatment industry profile
does not include the "NEW" plants from the IPM data set and EPA's Office of Water made additional corrections to
the IPM data set in some instances for the purpose of the detailed study. The data set corrections were necessary to
address conflicting information. For more information about the future FGD wastewater treatment industry profile,
see Section 4.6.1 or the memorandum entitled "Development of the Current and Future Industry Profile for the
Steam Electric Detailed Study," dated October 9, 2009 [ERG, 2009r].
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
Table 4-3. Projected Future Use of FGD Systems at Coal-Fired Power Plants
Wet Scrubbed a
Dry Scrubbed a
Total Scrubbed a
Total Coal-Fired Generating
Capacity a
Percent Wet Scrubbed
Percent Scrubbed (Wet & Dry
Combined)
2009
Capacity
(MW)
136,000
21,000
157,000
316,000
43%
50%
2010
Capacity
(MW)
162,000
21,500
184,000
318,000
51%
58%
2015
Capacity
(MW)
189,000
30,100
219,000
333,000
57%
66%
2020
Capacity
(MW)
231,000
36,700
268,000
371,000
62%
72%
2025
Capacity
(MW)
282,000
38,600
321,000
409,000
69%
78%
Source: [ERG,2008f].
a - The capacities presented have been rounded to three significant figures. Due to rounding, the total capacity may
not equal the sum of the individual capacities. The 2009 capacities are from the NEEDS 2006 database which
preferentially uses summer and winter capacity before nameplate capacity. Capacities presented in this table for the
period 2010 through 2025 are from estimates based on the IPM model [U.S. EPA, 2006b], which uses the NEEDS
2006 database [U.S. EPA, 2006h] as a starting point. Because the nameplate capacities are not used in these
projections, caution should be used when comparing the capacities in this table to Table 4-1 and the industry profile
tables presented in Chapter 3.
Figure 4-1 shows the locations and relative scrubbed capacity of coal-fired plants
currently operating wet FGD systems and those plants projected to operate wet FGD systems in
2020. The figure illustrates the expected growth in wet FGD systems, especially in the eastern
United States due to the use of higher sulfur coal. Note that the projections for 2020 only include
FGD installations for power plants and generating units that are currently in operation. New
generating units or power plants that will be built in the future are not depicted, although many if
not all new coal-fired generating units are likely to operate wet or dry FGD systems.
Based on communications with industry and corroborated by responses to the data
request, EPA expects that new wet FGD systems will be limestone forced oxidation systems that
produce a commercial-grade gypsum by-product, even for those plants located in an area where
there may be no market available for the sale of such a byproduct. Additionally, EPA expects
that the majority of wet scrubbed steam electric generating units will also include SCR systems
to meet state and federal requirements to reduce stack emissions of NOX.
4-5
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
.
V
' ;•
i
•
*
O O
Wet Scrubbers
(June 2008}
* *
,
-.
" *
•
* * *{--&' *•
A,
1 '.¥
i%
.°V* '
• * • •
•
;
. .
.
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f (Projected 2020)
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
4.2 Process Description and Wastewater Generation
4.2.1 Forced Oxidation FGD Systems
The EPA site visit and sampling program focused primarily on forced oxidation systems
because these types of FGD systems are the most common systems operating segregated
wastewater treatment systems prior to discharging FGD wastewater. In addition, based on
discussions with industry representatives, EPA expects that the majority of future wet FGD
systems will be forced oxidation.
Most forced oxidation systems use limestone as the sorbent in the process, but lime can
also be used in a forced oxidation system. The limestone forced oxidation FGD system works by
contacting the flue gas stream with a liquid slurry stream containing a limestone (CaCO3)
sorbent, which effects the mass transfer of pollutants from the flue gas to the liquid stream.
Equation 4-1 shows the reaction that occurs between limestone and sulfur dioxide, producing
hydrated calcium sulfite (CaSO3) [EPRI, 2006a].
CaCO3 (s) + SO2 (g) + 1/2 H2O -> CaSO3 '1/2 H2O (s) + CO2 (g) (4-1)
The calcium sulfite is then oxidized to calcium sulfate (gypsum) by injecting air into the
calcium sulfite slurry. Equation 4-2 shows the reaction producing gypsum (CaSO4*2H2O) from
calcium sulfite [EPRI, 2006a].
CaSO3 '1/2 H2O (s) + '/2 O2 (g) + 3/2 H2O 0) -> CaSO4 «2H2O (s) (4-2)
During the site visits to power plants, EPA determined that the operation of these
limestone forced oxidation systems varies somewhat by plant; however, most of the systems
follow the same general operating procedure. Figure 4-2 presents a typical process flow diagram
for a limestone forced oxidation FGD system.
Most of the plants EPA visited operate a spray or tray tower FGD scrubber, in which the
flue gas and the limestone slurry are configured with countercurrent flow. The fresh limestone
slurry is typically fed to the reaction tank at the bottom of the FGD scrubber to maintain the pH
levels in the system. This fresh limestone slurry mixes with the already reacted scrubber slurry
and is pumped to the top of the FGD scrubber where it is sprayed downward from several
different spray levels. The flue gas enters near the bottom of the FGD scrubber, just above the
water level of the reaction tank. As the flue gas rises through the absorber vessel, the spray
droplets of the limestone/water slurry contact the flue gas and absorb the sulfur dioxide. The
limestone and water react with the sulfur dioxide to produce calcium sulfite (see Equation 4-1).
To increase the sulfur dioxide removal efficiency, some plants use additives such as organic
acids (e.g., DBA or formic acid) in the FGD system. These additives buffer the scrubber slurry,
which controls the sulfur dioxide vapor pressure in the scrubbers, thereby maximizing the sulfur
dioxide absorption rate [Babcock & Wilcox, 2005]. The scrubbed flue gas exits the top of the
FGD scrubber through a mist eliminator and then is emitted through the stack.
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Chapter 4 - Flue Gas Desulfurization Systems
Scrubber
Slurry Recyle
FGD Scrubber
Reaction Tank
Limestone
Slurry Feed
Flue Gas
Solids-Lean
Stream
DQ
i_
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
The spray droplets, some containing the calcium sulfite product and others with
unreacted limestone, fall to the bottom of the FGD scrubber into a reaction tank. The plant
injects air into the reaction tank and vigorously mixes the slurry to oxidize the calcium sulfite to
gypsum (see Equation 4-2). The scrubber recycle pumps pump the slurry from the reaction tank
to the various spray levels within the FGD scrubber. The plant continuously recirculates the
slurry in the FGD scrubber. When the percent solids or the chlorides concentration in the slurry
reach a certain high set point in the reaction tank, the plant uses the scrubber blowdown pumps to
remove some of the slurry from the FGD scrubber. As the blowdown stream is removed from the
scrubber, the levels of solids and chlorides in the scrubber slurry decreases until a low set point is
reached within the FGD scrubber. The plant then shuts off the blowdown pumps until the solids
and chlorides build up again to the point of triggering a blowdown. Therefore, the scrubber
blowdown is typically an intermittent transfer from the scrubber. Some plants, however, operate
an FGD scrubber with a continuous blowdown, which can either be a once-through FGD system
with no recycle or an FGD system that recycles some of the slurry but is constantly blowing
down slurry at a rate that maintains the solids and chlorides levels within a defined operating
range.
The parameter used to control the FGD system (e.g., percent solids or chlorides
concentration) and the level at which it is controlled varies by plant. Plants maintain a chlorides
concentration below the maximum level which the FGD scrubber materials of construction can
withstand to prevent corrosion, normally around 12,000 - 20,000 ppm; however, some systems
operate with chloride concentrations as low as 2,000 to 3,000 ppm and other plants may operate
near 40,000 ppm. Plants also monitor and control the FGD system based on the percent solids
because the solids can affect the operation of the FGD system and because the plant must limit
the amount of fines (small inert particles) in the gypsum by-product [EPRI, 2006a].
The scrubber blowdown, which for a forced oxidation system is a gypsum slurry, is
transferred to a solids separation process. Often, this process uses one or two sets of
hydrocyclones, referred to in the industry as hydroclones.15 The hydroclones separate the
gypsum solids from the water using centrifugal force. The gypsum solids are forced outward to
the walls of the hydroclones and fall downward, while the water exits the top of the hydroclones.
The underflow, or solids-rich stream, from the solids separation process contains the gypsum
solids and is transferred to a dewatering process. The overflow, or solids-lean stream (which is
mostly water and fines), from the solids separation process is typically transferred to the purge
tank.
The solids-rich stream from the solids separation process is transferred to a dewatering
process, which is usually a vacuum belt filter or a vacuum drum filter. The dewatering process
removes the water from the gypsum, drying the gypsum to its desired moisture content. If the
plant intends to market the gypsum for wallboard production, then a vacuum belt filter is
typically used because it can dry the gypsum to a lower moisture content than a drum filter.
Additionally, the gypsum is usually rinsed with service water at the beginning of the belt filter to
reduce the chlorides concentration to meet the wallboard manufacturer's specifications. If the
plant does not intend to market the gypsum, then the gypsum does not need to be rinsed and
either a vacuum belt or vacuum drum filter can be used for the dewatering because the gypsum
15 Another approach for solids separation practiced by some plants entails using settling ponds instead of
hydroclones or other mechanical devices.
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
most likely will not need to meet any chloride or moisture content specifications. However, EPA
has visited several plants that are currently unable to market the gypsum, but the plant still rinses
the gypsum prior to on-site disposal in case a future gypsum market develops for the gypsum.
The dried gypsum product is removed from the dewatering process and transferred to a storage
area until it is transported off site (for beneficial use or disposal at an off-site landfill) or to a
disposal area on site. The filtrate from the dewatering process is recovered in a reclaim tank and
either returned to the FGD scrubber or used in the limestone slurry preparation process.
The solids-lean stream from the solids separation process is typically transferred to a
purge tank and then sent to a wastewater treatment system and discharged. Alternatively, the
solids-lean stream can be transferred to a second solids separation process (e.g., a second set of
hydroclones) to remove additional solids prior to wastewater treatment. Many plants that are
operating clarifiers in the FGD wastewater treatment system have two stages of solids separation
to minimize the size requirements and/or prevent overloading of the clarifier. In this case, the
solids-lean stream from the second solids separation process is transferred to the purge tank and
the solids-rich stream is typically transferred to the reclaim tank and recycled back to the FGD
system or limestone preparation process.
From the purge tank, the scrubber purge16 is typically transferred to some type of FGD
wastewater treatment system, such as a settling pond or a more advanced system (see Section
4.4). It may also be commingled with other wastewater streams (e.g., cooling water or ash pond
wastewater) and discharged. Because most FGD treatment systems currently being used do not
significantly affect the level of chlorides in the wastewater, the treated FGD wastewater is not
recycled back to the FGD scrubber.
Some plants are able to operate their solids removal process in a manner that purges
sufficient chlorides along with the solids to allow reuse of the FGD wastewater. For example,
plants that dispose of their gypsum solids in a landfill do not typically have to meet
specifications for the chlorides or fines content in the gypsum; therefore, these plants can operate
the FGD system (including the solids separation and dewatering process) to allow the gypsum to
retain more water and, therefore, more chlorides and fines. Operating the system in this manner
allows the plant to purge scrubber water (and by extension chlorides and fines) through the solids
disposal process. If they are able to purge enough chlorides with the FGD solids, these plants
may then be able to recycle the solids-lean stream from the solids separation process. Most of the
plants that sell the gypsum for beneficial use have to meet chloride and fines specifications, and
therefore, must operate with a scrubber purge stream [Sargent & Lundy, 2007].
4.2.2 Inhibited Oxidation FGD System
Both the forced oxidation and inhibited oxidation FGD systems remove sulfur dioxide
from the flue gas; however, in the inhibited oxidation FGD system, a chemical such as
emulsified sulfur is added to the system to prevent gypsum from forming during the process.
16 For the purpose of this document, the scrubber blowdown refers to the slurry stream exiting the FGD scrubber,
which is typically transferred to a solids separation process. The scrubber purge refers to the waste stream from the
FGD scrubber system (typically from a solids separation process) that is transferred to a wastewater treatment
system or discharged. Both the scrubber blowdown and scrubber purge waste streams are depicted in Figure 4-2. In
some instances, the scrubber blowdown and scrubber purge may be the same waste stream if the plant does not
operate a solids separation process prior to wastewater treatment or discharge.
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
Many of the plants operating inhibited oxidation systems do not have wastewater treatment
systems, other than settling ponds, to treat the scrubber purge. In addition, some plants are able
to recycle their FGD wastewater back to the FGD system and, therefore, do not produce a
scrubber purge waste stream.
The lime or limestone inhibited oxidation FGD systems work by contacting the flue gas
stream with a liquid slurry stream containing a lime (Ca(OH)2) or limestone sorbent, which
effects mass transfer. Equation 4-1 shows the reaction between limestone and sulfur dioxide and
Equation 4-3 shows the reaction that occurs between lime and sulfur dioxide, producing hydrated
calcium sulfite.
Ca(OH)2 (s) + SO2 (g) -> CaSO3 -Vi H2O (s) + V2 H2O 0) (4-3)
The operation and absorption of the SO2 in an inhibited oxidation FGD system is similar
to the forced oxidation FGD system. A FGD process operation description for a forced oxidation
system is presented in Section 4.2.1. The most significant differences between the two systems
are that in an inhibited oxidation FGD system, elemental or emulsified sulfur is added to the
FGD system, and oxidation air is not introduced to the absorber. The sulfur forms thiosulfate
within the FGD system, which is an oxygen scavenger. Because thiosulfate reacts so readily with
the dissolved oxygen, it inhibits the calcium sulfite from oxidizing to calcium sulfate, thereby
generating a calcium sulfite by-product instead of a gypsum by-product.
Although the operation of the FGD scrubber is similar for the two FGD systems, there are
some differences in the solids separation and solids dewatering processes. Figure 4-3 presents a
typical process flow diagram for a lime or limestone inhibited oxidation FGD system. One of the
major differences between the forced oxidation and inhibited oxidation systems is that inhibited
oxidation systems are more likely than forced oxidation systems to be operated in a manner that
recycles the solids-lean stream from the solids separation process back to the scrubber, and thus
are less likely to discharge a scrubber purge stream.
As is done for the limestone forced oxidation system, the scrubber blowdown is
transferred to a solids separation process. The calcium sulfite by-product generated from the
inhibited oxidation process is more difficult to dewater than the gypsum by-product generated by
the limestone forced oxidation process; therefore, plants operating inhibited oxidation FGD
systems typically use a thickener for the solids separation process; however, hydroclones can
also be used for inhibited oxidation systems. Thickeners operate with long residence times that
allow the solids to settle out of the solution. The underflow, or solids-rich stream, from the solids
separation process contains the calcium sulfite and is transferred to a dewatering process which
is typically a centrifuge or vacuum drum filter.
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Chapter 4 - Flue Gas Desulfurization Systems
Scrubber
Slurry Recyle
Emulsified or
Elemental Sulfur
FGD Scrubber
Reaction Tank
Lime/Limestone
Flue Gas
Reclaim To Scrubber
Slurry Feed
To Storage/Disposal
Wastewater Treatment
Figure 4-3. Process Flow Diagram for a Lime or Limestone Inhibited Oxidation FGD System
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
The dewatering process removes water from the calcium sulfite, drying it to its desired
moisture content. The filtrate from the dewatering process is transferred to a reclaim tank. The
solid cake from the final dewatering process is usually sent to a landfill, either on or off site.
Although the calcium sulfite FGD solids can be landfilled after the final dewatering process,
some plants operating inhibited oxidation systems further process the calcium sulfite by mixing
it with dry fly ash and lime in a pug mill to generate a cementitious material similar to concrete.
The resultant cementitious material is transported to a landfill.
The overflow, or solids-lean stream, from the solids separation process and the filtrate
from the dewatering process are typically transferred to a reclaim tank. Some of the wastewater
collected in the reclaim tank is recycled back to the FGD scrubber process and some may be
discharged or transferred to an additional treatment system. Because the inhibited oxidation
system typically does not generate a saleable solid product, the solids are typically disposed of in
a landfill. Like the limestone forced oxidation systems that are not beneficially using the
gypsum, the plant may be able to recycle the FGD wastewater without a purge stream because
the chlorides can be removed from the FGD system by retaining the chlorides with the solids that
are sent to the landfill [Sargent & Lundy, 2007]. However, not all plants operating inhibited
oxidation FGD systems completely recycle the FGD wastewater. For example, Louisville Gas &
Electric Company's Cane Run plant stated that they do not achieve complete recycle because of
instances where they have accumulated rainfall in their ponds which treat the recycle water.
When this happens, they manage the additional water volume by discharging from the FGD
ponds.
4.2.3 Other Types of FGD Systems
Natural Oxidation FGD Systems
Sections 4.2.1 and 4.2.2 describe the operation of the forced oxidation and inhibited
oxidation systems. A natural oxidation system operates similarly to both the forced oxidation and
inhibited oxidation systems, except that air is not fed to the reaction tank to force the oxidation of
calcium sulfite to calcium sulfate as in the forced oxidation system; likewise, emulsified sulfur is
not added to inhibit the calcium sulfite from oxidizing as in the inhibited oxidation system. In a
natural oxidation system, some of the calcium sulfite (typically the majority) is oxidized to
calcium sulfate using the dissolved oxygen present in the system; however, because the plant is
not forcing the oxidation, some of the calcium sulfite may not oxidize and the FGD process may
produce a mixture of calcium sulfite and calcium sulfate. The solids handling associated with the
operation of a natural oxidation FGD system is also similar to the solids handling of the forced
oxidation and/or the inhibited oxidation systems (see Figure 4-2 and Figure 4-3).
During the detailed study, EPA visited one plant that operates a natural oxidation FGD
system. The plant operates a thickener for the solids separation process and a vacuum drum filter
for the dewatering process. The FGD solids produced, which consist predominantly of calcium
sulfate, are transferred to a third party distributor for sale (primarily to a cement manufacturer).
The overflow from the thickeners is transferred to a reclaim tank and is typically reused within
the FGD process. The plant occasionally transfers the thickener overflow to a settling pond,
which is ultimately discharged [ERG, 2009o].
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
Dual-Alkali FGD Systems
The dual-alkali FGD process is different from the other FGD processes previously
discussed because two alkaline sorbents are used in the process. For this type of FGD system, a
soda ash (sodium carbonate, Na2CO3) liquor/solution is fed into the FGD scrubber to absorb the
sulfur dioxide from the flue gas. The sodium is dissolved in this liquor, and therefore the liquor
contains almost no suspended solids. The sodium reacts with the sulfur dioxide and the product
is transferred to the reaction tank where the second alkaline sorbent, lime, is added. The lime
reacts with this product to generate hydrated calcium sulfite. Additionally, the sodium solution is
regenerated in this reaction and can be reused in the scrubbing process. The slurry from the
reaction tank is then sent to a solids separation process, such as a thickener. The underflow, or
solids-rich stream, from the solids separation process contains mostly calcium sulfite, and is
transferred to a dewatering process similar to the description for the lime inhibited oxidation
system (see Section 4.2.2). The overflow, or solids-lean stream, that contains the sodium solution
is recycled back to the FGD system as the sorbent for the scrubbing process. Because some of
the sodium will leave the system with the solids-rich stream from the solids separation process, a
make-up soda ash solution is added to the sodium solution that is recycled back to the FGD
scrubber.
Dry FGD Systems
A dry FGD system is a spray dryer absorption process in which a lime slurry removes
sulfur dioxide from the flue gas. These dry FGD systems are also sometimes referred to as semi-
dry FGD systems because a wet slurry is injected into the flue gas; a dry sorbent is not used in
the process. In the dry FGD process, the wet lime slurry, which ranges from approximately 18 to
25 percent solids, is atomized and sprayed into the spray dryer. The percent solids in the lime
slurry is calculated to control the sulfur dioxide removal from the flue gas but also allows for
essentially all the water to evaporate within the spray dryer. The flue gas can enter the spray
dryer from one or more different locations and typically enters through a disperser to allow for
effective contact with the atomized spray droplets. The sulfur dioxide in the flue gas is absorbed
by the spray droplets and reacts with the lime to generate calcium sulfite. These reactions take
place in the aqueous phase of the spray droplets at the same time that the heat from the flue gas is
evaporating the water from the spray droplets. The evaporation of the water cools the flue gas
and produces a calcium sulfite product with low moisture content [Babcock & Wilcox, 2005].
The flue gas exiting the spray dryer is then transferred to a particulate removal system
(e.g., electrostatic precipitator (ESP) or baghouse), which collects the solids generated in the
spray dryer and some unreacted lime, as well as fly ash if there is no particulate removal system
upstream of the spray dryer. A plant may operate a pre-collection particulate removal system if it
intends to market the fly ash generated. The particulates removed from the process are usually
transferred to a silo for storage until the plant disposes of the material or transfers it off site.
Additionally, the solids removed from the particulate removal process can be reused in the
process as slurry feed to reduce lime usage. This recycle also has the benefit of using the inherent
alkalinity in the fly ash for the sulfur dioxide absorption. In these recycle systems, some of the
solids removed from the particulate removal process are mixed with water to approximately 35
to 45 percent solids and returned to the process. Not all of the solids can be recycled for the
process; therefore, the remaining solids are stored on site, sold for beneficial use, or disposed of
in a landfill [Babcock & Wilcox, 2005].
-------
Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
4.3 FGD Wastewater Characteristics
This section discusses the pollutant characteristics and flow rates for FGD wastewaters
based on information EPA collected during the detailed study. Pollutant concentration data are
presented for samples collected during the EPA wastewater sampling program and monitoring
data provided by the individual plants/companies. These pollutant concentration data represent
information from limestone forced oxidation systems. This section also presents flow rate data
from EPA's site visit and sampling program and responses to EPA's data request. These flow
rate data include information from limestone forced oxidation systems, as well as non-forced
oxidation systems. Chapter 2 describes EPA's data collection activities.
The FGD system works by contacting the flue gas stream with a slurry stream containing
a sorbent. The contact between the streams allows for a mass transfer of sulfur dioxide as it is
absorbed into the slurry stream. Other pollutants in the flue gas (e.g., metals, nitrogen
compounds, chloride) are also transferred to the scrubber slurry and leave the FGD system via
the scrubber blowdown (i.e., the slurry stream exiting the FGD scrubber that is not immediately
recycled back to the spray/tray levels). Depending upon the pollutant, the type of solids
separation process and the solids dewatering process used, the pollutants may partition to either
the solid phase (i.e., FGD solids) or the aqueous phase (i.e., scrubber purge waste stream).
As described in Section 4.2 and shown in Figure 4-2 and Figure 4-3, the FGD scrubber
blowdown is typically intermittently transferred from the FGD scrubber to the solids separation
process. As a result, the FGD scrubber purge (i.e., the waste stream from the FGD scrubber
system that is transferred to a wastewater treatment system or discharged) is also usually
intermittent. Factors that can affect the characteristics and flow rate of the FGD scrubber purge
wastewater include the type of coal, scrubber design and operating practices, solids separation
process, and solids dewatering process used at the plant.
The type of coal burned at the plant can affect the FGD scrubber purge flow rate
associated with the system. Generally, burning a higher sulfur coal will lead to a higher flow rate
for the scrubber blowdown and scrubber purge. Higher sulfur coals produce more sulfur dioxide
in the combustion process, which in turn increases the amount of sulfur dioxide removed in the
FGD scrubber. As a result, more solids are generated in the reaction in the scrubber, which
increases blowdown volumes.
Likewise, a high chlorine coal can increase the volume and frequency of the scrubber
blowdown and scrubber purge. Many FGD systems are designed with materials resistant to
corrosion for specific chloride concentrations. An electric generating unit burning coal with
higher chlorine content will more quickly reach the maximum allowable chloride concentration
in the scrubber, which may trigger more frequent blowdowns. In addition, the plant will need to
purge more FGD wastewater from the system to prevent chlorides from building up to an
unacceptable concentration.
Table 4-4 summarizes the FGD scrubber purge flow rates reported in the data request
responses and collected during EPA's site visit and sampling program. In Table 4-4, there are 26
plants that operate a total of 57 wet FGD systems, which scrub the flue gas from 65 coal-fired
electric generating units. The size of the plants varies from scrubbed capacities of 300 to 2,700
MW. The average scrubbed capacity per plant is 1,310 MW, with a median scrubbed capacity of
-------
Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
1,330 MW/plant. Most of the plants operate limestone forced oxidation systems; however,
several plants operate lime inhibited oxidation systems.
Table 4-4. FGD Scrubber Purge Flow Rates
Number of Plants
Average Flow Rate
Median Flow Rate
Range of Flow Rate
Flow Rate per Plant
gpm/plant
gpd/plant
gpy /plant
26
26
26
448
598,000
211,000,000
340
410,000
142,000,000
30.0-2,300
24,300-3,310,000
4,980,000 -
1,210,000,000
Normalized Flow Based on Wet-Scrubbed Capacity
gpm/scrubbed MW
gpd/scrubbed MW
gpy /scrubbed MW
26
26
26
0.423
578
202,000
0.250
301
106,000
0.0365-2.04
19.7-2,940
2,500 - 1,070,000
Source: Data request information [U.S. EPA, 2008a] and site visit and sampling information.
a - The flow rates presented have been rounded to three significant figures.
b - The instantaneous (gpm) flow rate represents the rate during the actual purge, unless it is a design scrubber purge
flow rate for a planned FGD wastewater treatment system installation.
c - Because some FGD scrubber purge flows are intermittent, instantaneous rates cannot be directly used to
calculate daily and annual average flows.
Table 4-4 presents the actual purge flow rates for the 26 plants, as well as calculated
normalized purge flow rates that are based on the plants' wet scrubbed capacity. The scrubber
purge flow rates reported, including the normalized flow rates, vary significantly from plant to
plant. Figure 4-4 and Figure 4-5 present the distribution of the scrubber purge flow rates for the
26 plants included in Table 4-4. The majority of plants report scrubber purge flow rates less than
1.5 mgd. However, one plant operates a once-through FGD system (i.e., no recirculation of the
scrubber slurry) and has a scrubber purge flow rate exceeding 3 mgd (see Figure 4-4). There are
three plants that have normalized scrubber purge flow rates greater than 2,000 gpd/MW
scrubbed. One of the three plants operates a once-through FGD system, as described above. The
other two plants operate lime inhibited oxidation systems that transfer the FGD wastewater to a
settling pond for treatment. Because these plants are generating a calcium sulfite byproduct,
which is not marketable, and the scrubber purge is being transferred to a settling pond for
treatment, the plants are transferring the entire scrubber blowdown to the settling pond (i.e., there
is no solids separation process). For this reason, the normalized scrubber purge flow rate for
these plants is larger than the other plants because the solids, as well as the water retained in the
solids, are included in the scrubber purge flow rate.
4-16
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
3.5
3
0.5
0
Jllll
3 500
-o
0 3 000
.0
3
0 2 500 -
^
^ 2 000 -
"O '
Q.
O»
fe 1 500
o
LJ_
•o 1 000 -
E 500-
o
•z.
Q
...ill
Illllllll
Figure 4-4. Distribution of FGD Scrubber
Purge Daily Flow Rates
Figure 4-5. Distribution of FGD Scrubber
Purge Normalized Daily Flow Rates
Source: Data request information [U.S. EPA, 2008a] and site visit and sampling information.
The average gpd/plant and gpd/scrubbed MW purge flow rates calculated for these 26
plants are similar to the FGD blowdown stream flow rates EPA observed when developing the
effluent guidelines promulgated in 1982 (671,000 gpd/plant and 811 gpd/MW) [U.S. EPA,
1982].
The pollutant concentrations in FGD scrubber purge vary from plant to plant depending
on the coal type, the sorbent used, the materials of construction in the FGD system, the FGD
system operation, and the air pollution control systems operated upstream of the FGD system.
The coal is the source of the majority of the pollutants that are present in the FGD wastewater
(i.e., the pollutants present in the coal are likely to be present in the FGD wastewater). The
sorbent used in the FGD system also introduces pollutants into the FGD wastewater and
therefore, the type and source of the sorbent used affects the pollutant concentrations in the FGD
wastewater.
The air pollution controls operated upstream of FGD system can also affect the pollutant
concentrations in the FGD wastewater. For example, if a plant does not operate a particulate
collection system (e.g., ESP) upstream of the FGD system, then the FGD system will act as the
particulate control system and the FGD blowdown exiting the scrubber will contain fly ash and
other particulates. As a result, the FGD scrubber purge will likely contain increased amounts of
pollutants associated with the fly ash.
Research conducted by EPA's ORD has observed that the use of post-combustion NOx
controls (e.g., SCR and SNCR) is correlated to an increased fraction of chromium in CCR
(including FGD wastes) being oxidized to hexavalent chromium (Cr+6), a more toxic form of
chromium than trivalent chromium (Cr+3). Hexavalent chromium is more a soluble form of
chromium than the Cr+3 usually measured in CCRs, which could explain why ORD has observed
increased teachability of chromium when post-combustion NOx controls are operating [U.S.
EPA, 2008c].
The materials of construction in the FGD system and the FGD system operation affect the
pollutants present in the wastewater, as well as the levels of the pollutants. The use of organic
4-17
-------
Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
acid additives contributes to higher levels of BODS in the FGD scrubber purge. Additionally, the
type of oxidation (i.e., forced oxidation, inhibited oxidation, natural oxidation) in the FGD
system has the potential to affect the form of the pollutants present in the FGD wastewater. The
materials of construction and the other FGD system operations can also affect the levels of
pollutants present in the FGD wastewater because as discussed previously, they affect the rate at
which scrubber purge is generated. For example, the larger the maximum allowable chlorides
concentration in the scrubber, the lower the scrubber purge flow rate; however, this leads to
additional cycling in the scrubber, which increases the pollutant concentrations present in the
FGD wastewater.
Table 4-5 presents the pollutant concentrations representing the influent to the FGD
wastewater treatment systems for the FGD wastewaters that EPA sampled.17 FGD wastewater
contains significant concentrations of chloride, TDS, nutrients, and metals, including
bioaccumulative pollutants such as arsenic, mercury, and selenium. Table 4-5 also shows that
some of the pollutants are more likely to be present in the particulate phase (e.g., aluminum,
chromium, mercury), whereas other pollutants are almost exclusively present in the dissolved
phase (e.g., boron, magnesium, manganese).
For the Big Bend sampling episode, EPA collected a grab sample of the influent to the
wastewater treatment system downstream of the equalization tank feeding the treatment system.
The equalization tank receives FGD scrubber purge from secondary hydroclones, treatment
system recirculation flows, and other related treatment process waste streams. During sampling,
the plant was recirculating 154 gpm off-specification filter press filtrate to the equalization tank,
which caused the plant to divert some of the FGD scrubber purge away from the equalization
tank. As a result, the scrubber purge comprised only one-third (96 gpm of 250 gpm) of the total
influent-to-treatment flow sampled by EPA. The sampling episode report for Big Bend contains
more detailed information regarding the sampling event [ERG, 2008n].
For the Homer City sampling episode, EPA collected a grab sample of the influent to the
wastewater treatment system downstream of the equalization tank feeding the treatment system.
The equalization tank receives FGD scrubber purge from the secondary hydroclones and
backwash from sand filters. During sampling, the flow rate from the equalization tank to the
wastewater treatment system was 109 gpm. The sampling episode report for Homer City
contains more detailed information regarding the sampling event [ERG, 20081].
17 Note that the influent-to-treatment sample obtained for a given plant does not necessarily represent the unaltered
scrubber purge, since the sample collected may include both scrubber purge and treatment system recirculation flow
streams.
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
Table 4-5. Influent to FGD Wastewater Treatment System Concentrations
Analyte
Method
Unit
Big Bend -
Influent to FGD
Wastewater
Treatment a
Homer City -
Influent to FGD
Wastewater
Treatment a
Widows Creek -
FGD Scrubber
Slowdown a
Mitchell -
FGD Scrubber
Purge a
Belews Creek -
FGD Scrubber
Purge a
Routine Total Metals - 200.7
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Sodium
Thallium
Titanium
Vanadium
Yttrium
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
245.1
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
31,200
62.5
75.5
1,590
12.9
626,000
224
6,690,000
757
172
120
23,500
69.1
4,830,000
21,900
ND (10.0)
618
2,090
4,150
ND (20.0)
2,530,000
ND (10.0)
420
724
245
289,000
86.4
1,590
11,900 R
28.8
224,000
150
3,220,000
1,400
369
811
824,000
340
2,760,000
225,000
243
375
2,560 R
4,000 R
ND (40.0)
1,430,000
Exclude
1,300 R
766
586
234,000
ND (86.9)
523
7,200
44.3
28,900
89.2
5,990,000
1,360
ND (217)
653
299,000
436
321,000
2,780
26.5
1,340
489
652
ND (86.9)
104,000
ND (43.4)
8,180
1,580
217
17,900
28.7
72.5
588
8.04
229,000
19.7
3,030,000
70.7
68.0
164
60,600
103
1,470,000
28,800
67.5
65.0
554
2,130
ND (20.0)
314,000
ND (10.0)
377
203
64.9
33,100 R
18.1 R
236
651
3.60 R
307,000 R
ND (0.250)
6,070,000
84.8 R
14.7 R
37.6
59,100 R
31.2 R
990,000
9,020 R
NA
NA
1.59 R
2,930 R
10.0
61,000
41.2 R
NA
77.6
NA
4-19
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
Table 4-5. Influent to FGD Wastewater Treatment System Concentrations
Analyte
Zinc
Method
200.7
Unit
ug/L
Big Bend -
Influent to FGD
Wastewater
Treatment a
1,540
Homer City -
Influent to FGD
Wastewater
Treatment a
1,900
Widows Creek -
FGD Scrubber
Slowdown a
3,140
Mitchell -
FGD Scrubber
Purge a
885
Belews Creek -
FGD Scrubber
Purge a
ND (25.0)
Routine Dissolved Metals - 200.7
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Hexavalent Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Sodium
Thallium
Titanium
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
D 1687-92
200.7
200.7
200.7
200.7
200.7
200.7
245.1
200.7
200.7
200.7
200.7
200.7
200.7
200.7
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ND (50.0)
33.9
18.6
1,820
ND (5.00)
618,000
179
4,470,000
ND (10.0)
24.0
ND (50.0)
27.2
ND (100)
ND (50.0)
4,110,000
9,610
ND (10.0)
581
851
3,610
ND (20.0)
1,970,000
14.3
12.5
ND (50.0)
ND (20.0)
ND (10.0)
149 R
10.5
254,000
26.2
1,990,000
ND (10.0)
ND (2.00)
201
14.5
ND (100)
ND (50.0)
3,100,000
173,000
ND (10.0)
30.6
1,350
656 R
ND (20.0)
1,440,000
61.2
ND (10.0)
86.6
ND (20.0)
13.9
257
ND (5.00)
24,100
ND (5.00)
849,000
18.7
ND (2.00)
ND (50.0)
ND (10.0)
ND (100)
ND (50.0)
176,000
583
ND (2.00)
876
ND (50.0)
366
ND (20.0)
76,700
14.3
ND (10.0)
ND (50.0)
ND (20.0)
ND (10.0)
488
6.02
232,000
ND (5.00)
2,350,000
ND (10.0)
5.00
ND (50.0)
ND (10.0)
ND (100)
ND (50.0)
1,370,000
27,900
ND (10.0)
22.2
355
46.9
ND (20.0)
324,000
ND (10.0)
ND (10.0)
ND (50.0)
ND (4.00)
24.7 R
489 R
ND (1.00)
301,000 R
ND (0.250)
5,370,000
19.2 R
4.20
8.40 L,R
ND (2.50)
ND (25.0)
ND (1.50)
955,000 R
8,540
NA
NA
105 R
105 R
7.80
58,700
106 R
NA
4-20
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
Table 4-5. Influent to FGD Wastewater Treatment System Concentrations
Analyte
Vanadium
Yttrium
Zinc
Method
200.7
200.7
200.7
Unit
ug/L
ug/L
ug/L
Big Bend -
Influent to FGD
Wastewater
Treatment a
108
ND (5.00)
16.8
Homer City -
Influent to FGD
Wastewater
Treatment a
ND (20.0)
6.28
ND (10.0)
Widows Creek -
FGD Scrubber
Slowdown a
ND (20.0)
ND (5.00)
ND (10.0)
Mitchell -
FGD Scrubber
Purge a
ND (20.0)
ND (5.00)
87.8
Belews Creek -
FGD Scrubber
Purge a
2.00 R
NA
ND (25.0)
Low-Level Total Metals - 1631E, 1638, HG-AFS
Antimony
Arsenic
Arsenic
Arsenic
Cadmium
Chromium
Chromium
Copper
Lead
Mercury
Nickel
Nickel
Selenium
Selenium
Selenium
Thallium
Zinc
Zinc
1638
1638
1638 -DRC
HG-AFS
1638
1638
1638 -DRC
1638
1638
163 IE
1638
1638 -DRC
1638
1638 -DRC
HG-AFS
1638
1638
1638 -DRC
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
24.9
165
NA
NA
238
651 L
NA
103
69.9
16.4
2,570
NA
3,470
NA
NA
39.8
1,870
NA
31.1
1,220
NA
NA
52.8 R
1,270
NA
747
351
533
2,840
NA
3,530
NA
NA
37.3
2,130
NA
51.8
617
NA
NA
86.0
1,380
NA
826
545
24.7
634
NA
651
NA
NA
93.8
2,720
NA
9.23
59.9
NA
NA
5.28
176 L
NA
139
68.1
138
650
NA
1,990
NA
NA
6.33
730
NA
17.6 R
1,270
1,010 R
929
4.84 R
256
262 R
188 R
193 R
85.6
1,240
396 R
8,660
8,250 R
9,100
9.51 R
438
526 R
Low-Level Dissolved Metals - 1631E, 1636, 1638, HG-AFS
Antimony
Arsenic
Arsenic
1638
1638
1638-DRC
ug/L
ug/L
ug/L
21.9
137
NA
ND (0.400)
24.2 R
NA
8.90
18.0
NA
1.97
20.2
NA
3.83
133
17.4 R
4-21
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
Table 4-5. Influent to FGD Wastewater Treatment System Concentrations
Analyte
Arsenic
Cadmium
Chromium
Chromium
Copper
Lead
Mercury
Nickel
Nickel
Selenium
Selenium
Selenium
Thallium
Zinc
Zinc
Method
HG-AFS
1638
1638
1638-DRC
1638
1638
163 IE
1638
1638-DRC
1638
1638-DRC
HG-AFS
1638
1638
1638-DRC
Unit
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
Big Bend -
Influent to FGD
Wastewater
Treatment a
NA
190
ND (160)
NA
ND (40.0)
ND (10.0)
0.206
1,030
NA
3,280
NA
NA
39.4
ND (100)
NA
Homer City -
Influent to FGD
Wastewater
Treatment a
NA
24.5
ND (16.0)
NA
11.3
ND (1.00)
0.0809
1,450
NA
584
NA
NA
23.2
34.7
NA
Widows Creek -
FGD Scrubber
Slowdown a
NA
3.16
ND (16.0)
NA
ND (4.00)
ND (1.00)
0.0761
29.6
NA
325
NA
NA
22.5
ND (10.0)
NA
Mitchell -
FGD Scrubber
Purge a
NA
ND (1.00)
ND (80.0)
NA
ND (20.0)
ND (0.500)
0.0111
433
NA
443
NA
NA
4.47
160
NA
Belews Creek -
FGD Scrubber
Purge a
11.4
4.47
19.1
ND (5.00)
ND (5.00)
ND (2.00)
0.0844
382
316 R
468
412 R
206
11.1 R
78.6
69.7 R
Classical*
Ammonia As Nitrogen (NH3-N)
Nitrate/Nitrite (NO3-N + NO2-N)
Total Kjeldahl Nitrogen (TKN)
Biochemical Oxygen Demand
(BOD)
Chemical Oxygen Demand
(COD)
Chloride
Hexane Extractable Material
(HEM)
4500-NH3Fb
353.2
4500-N,Cb
5210B
5220 C
4500-CL-Cb
1664A
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
31.5
NA
51.6
1,370
NA
24,200
ND (6.00)
4.12
54.5
14.2
ND (120)
NA
11,800
ND (5.00)
2.26
1.00
22.3
172
NA
832
22.0
1.89
20.6
13.3
21.0
NA
7,200
11.0
1.50
14.7
6.20
ND (4.00)
304
9,680
ND (5.00)
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
Table 4-5. Influent to FGD Wastewater Treatment System Concentrations
Analyte
Silica Gel Treated HEM (SGT-
HEM)
Sulfate
Total Dissolved Solids (TDS)
Total Phosphorus
Total Suspended Solids (TSS)
Method
1664A
D516-90b
2540 C
365.3b
2540 D
Unit
mg/L
mg/L
mg/L
mg/L
mg/L
Big Bend -
Influent to FGD
Wastewater
Treatment a
NA
3,590
44,600
0.990
4,970
Homer City -
Influent to FGD
Wastewater
Treatment a
NA
6,920
23,200
2.64
13,300
Widows Creek -
FGD Scrubber
Slowdown a
6.00 E
11,900
4,740
10.5
25,300 E
Mitchell -
FGD Scrubber
Purge a
ND (5.00)
1,640
18,100
3.57
7,320
Belews Creek -
FGD Scrubber
Purge a
ND (5.00)
1,290
34,600
9.90
5,200
Source: [ERG, 20081; ERG, 2008m; ERG, 2008n; ERG, 2008o; ERG, 2009q].
Note: EPA used several analytical methods to analyze for metals during the sampling program. For the purposes of sampling program, EPA designated some of
the analytical methods as "routine" and some of them as "low-level." EPA designated all of the methods that require the use of clean hands/dirty hands sample
collection techniques (i.e., EPA Method 1669 sample collection techniques) as "low-level" methods. Note that although not required by the analytical method,
EPA used clean hands/dirty hands collection techniques for all low-level and routine metals samples.
a - The concentrations presented have been rounded to three significant figures.
b - The method used for the Belews Creek sampling analysis is different than the method presented in the table. See Table 2-3 for details.
DRC - Dynamic reaction cell. For the Belews Creek analysis, a DRC was used in combination with EPA Method 1638 for certain analytes.
E - Sample analyzed outside holding time.
HG-AFS - Hydride generation and atomic fluorescence spectrometry.
L - Sample result between 5x and lOx the blank result.
R - MS/MSD % recovery outside method acceptance criteria.
Exclude - Results were excluded because the MS/MSD samples had a zero percent recovery.
NA - Not analyzed.
ND - Not detected (number in parentheses is the report limit). The sampling episode reports for each of the individual plants contains additional sampling
information, including analytical results for analytes measured above the detection limit, but below the reporting limit (i.e., J-values).
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
Widows Creek operates once-though FGD scrubbers (i.e., no recirculation of slurry
within the absorber), with the scrubber blowdown continuously sent to settling ponds. For the
Widows Creek sampling episode, EPA collected a four-hour composite sample of the influent to
the FGD settling pond from a diked channel containing FGD scrubber blowdown from the two
FGD scrubbers. EPA collected the samples from the diked channel at a point downstream of the
influent to the channel to allow for some initial solids settling, but upstream of the inlet to the
FGD settling pond. At the time of the sampling, although one of the electric generating units
operating a FGD system was shut down and therefore not sending flue gases through the
scrubber, the plant continued to transfer water from the scrubber to the FGD settling pond. The
flow rate entering the open water area of the FGD settling pond at the time of sampling was
approximately 1,170 gpm, and plant personnel estimated that approximately 390 gpm of the flow
rate (one-third of the entire flow) was from the FGD system of the electric generating unit that
was shut down. The sampling episode report for Widows Creek contains more detailed
information regarding the sample collection procedures [ERG, 2008o].
For the Mitchell sampling episode, EPA collected a grab sample of the FGD scrubber
purge transfer to the FGD wastewater treatment system. The sample collected contained only
FGD scrubber purge, which was transferred to the system at a flow rate of approximately 500
gpm. The sampling episode report for Mitchell contains more detailed information regarding the
sampling event [ERG, 2008m].
For the Belews Creek sampling episode, EPA collected a grab sample of the FGD
scrubber purge transfer to the FGD wastewater treatment system. The sample collected contained
only FGD scrubber purge, which was transferred from the purge tank to the system at a flow rate
of 489 gpm during the sample collection. The sampling episode report for Belews Creek contains
more detailed information regarding the sampling event [ERG, 2009q].
EPA also collected self-monitoring data for the FGD scrubber purge from four plants.
Table 4-6 presents the number of facilities that reported concentration data for specific analytes,
the total number of samples from all the plants for each analyte, and the average, minimum, and
maximum concentrations for all the monitoring data. These monitoring data were used along
with EPA's sampling data to calculate the pollutant mass loads in scrubber purge, as discussed in
Section 4.6.
The monitoring data collected from industry confirm EPA's sampling data and
demonstrate that FGD scrubber purge wastewater contains significant concentrations of chloride,
TSS, TDS, and metals. The type of treatment system operated at an individual plant is typically
dependent on the permit limits that the plant must meet. Section 4.4 describes the wastewater
treatment systems planned or currently operated by coal-fired power plants to treat FGD
wastewater s.
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Chapter 4 - Flue Gas Desulfurization Systems
Table 4-6. FGD Scrubber Purge Self-Monitoring Data
Analyte
Number of
Plants
Number of
Samples
Minimum
Concentration
Maximum
Concentration a
Units
Total Metals
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Thallium
Vanadium
Zinc
1
1
4
1
1
3
2
2
1
2
3
1
1
1
4
1
3
4
3
2
1
4
38
38
99
38
38
95
51
51
38
43
79
38
13
38
132
38
67
158
44
46
38
72
8,200
4.1
58
110
ND (0.7)
7,410
ND (0.5)
1.7
6.4
12.8
1,100
14.7
1,200,000
339
ND(O.l)
ND(2)
23.4
400
ND (0.2)
ND(4)
14.2
33.1
333,000
23
5,070
2,050
113
250,000
302
350
148
456
300,000
252
1,800,000
5,460
872
250
710
21,700
65
746
14,800
1,060
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
Dissolved Metals
Mercury
Selenium
1
2
17
33
60
130
440
3,000
ug/L
ug/L
Classicals
BOD5
COD
Total suspended solids
Total dissolved solids
Sulfate
Chloride
Bromide
Fluoride
Nitrate/nitrite
Total Kjeldahl nitrogen
Total phosphorus
1
2
2
3
4
4
1
1
2
2
1
8
49
111
106
85
104
28
37
76
37
1
3.40
140
24.0
6,500
780
1,100
43.0
6.80
ND (10.0)
2.80
4.00
21.0
1,100
14,000
26,000
4,100
13,000
96.0
57.0
270
24.0
4.00
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
Source: [ERG, 2009x].
a - The maximum concentration presented is the maximum detected value in the data set, unless all the results in the
data set were not detected for the analyte.
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
4.4 FGD Wastewater Treatment Technologies
During this detailed study, EPA identified and investigated wastewater treatment systems
operated by steam electric plants for the treatment of FGD scrubber purge, as well as
operating/management practices that were used to reduce the discharge of FGD wastewater. This
section describes the following technologies:
• Settling ponds;
• Chemical precipitation (using hydroxide and/or sulfide precipitation);
• Biological treatment;
• Constructed wetlands;
• Vapor-compression evaporation system;
• Design/operating practices achieving zero discharge; and
• Other technologies under investigation.
Most plants currently discharging FGD wastewater use settling ponds; however, the use
of more advanced wastewater treatment systems is increasing to a limited extent due to more
stringent requirements imposed by some states on a site-specific basis. Section 4.4.8 presents
information EPA has compiled on the types of FGD wastewater treatment systems currently
operating or expected to be installed.
4.4.1 Settling Ponds
Settling ponds are designed to remove particulates from wastewater by means of gravity.
For this to occur, the wastewater must stay in the pond long enough to allow sufficient time for
particles to fall out of suspension before being discharged from the pond. The size and
configuration of settling ponds varies by plant; some settling ponds operate as a system of
several ponds, while others consist of one large pond. The ponds are initially sized to provide a
certain residence time to reduce the TSS levels in the wastewater and to allow for a certain life-
span of the pond based on the expected rate of solids buildup within the pond. Coal-fired power
plants do not typically add treatment chemicals to settling ponds, other than to adjust the pH of
the wastewater before it exits the pond to bring it into compliance with NPDES permit limits.
Settling ponds can reduce the amount of TSS in wastewater, as well as specific pollutants
that are in particulate form, provided that the settling pond has a sufficiently long residence time;
however, settling ponds are not designed to reduce the amount of dissolved metals in the
wastewater. The FGD wastewater entering a treatment system contains significant concentrations
of several pollutants in the dissolved phase, including boron, manganese, and selenium. These
dissolved metals are likely discharged largely unremoved from FGD wastewater settling ponds.
Additionally, EPRI has reported that adding FGD wastewater to ash ponds may reduce the
settling efficiency in the ash ponds, due to gypsum particle dissolution, thus increasing the
effluent TSS concentration [EPRI, 2006b]. EPRI has also reported that the FGD wastewater
includes high loadings of volatile metals which can impact the solubility of metals in the ash
pond, thereby potentially leading to increases in the effluent metal concentrations [EPRI, 2006b].
Section 5.4.1 contains a more detailed discussion of this topic.
EPA compiled data for plants operating wet FGD systems and wastewater treatment
systems used to treat the FGD wastewaters generated. Based on these data, settling ponds are the
most commonly used systems for managing FGD wastewater. Most plants using ponds transfer
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
FGD scrubber purge directly to a settling pond that also treats other waste streams, specifically
fly ash transport water and/or bottom ash transport water. Approximately one-third of the plants
using FGD ponds transfer the FGD scrubber purge to a settling pond specifically designated to
treat FGD wastewater. In these cases, the FGD wastewater pond effluent is either discharged
directly to surface waters (with or without first mixing with cooling water or other large volume
wastes streams) or transferred to an ash pond for further settling and dilution.
EPA has also identified two plants (one currently operating an FGD system and one
planned) that transfer the FGD scrubber purge to a settling pond for initial solids removal and
then transfer the wastewater to a biological treatment system for further treatment.
EPA reviewed information to determine whether the use of settling ponds to treat FGD
wastewater was limited to relatively older scrubbers. Approximately 20 percent of the plants
using settling ponds began operating an additional wet FGD system after 2000. Each of these
plants was already operating another FGD system prior to 2000. This suggests plants do not
replace the settling pond treatment system with a more advanced system when a new FGD
system is installed; instead, the plants begin transferring the additional FGD wastewater to the
existing treatment system. In addition, some plants currently without scrubbers have announced
that they intend to rely on settling ponds to treat their FGD wastewater. The information
compiled by EPA for this study indicates that the use of pond systems will continue to be
significant in the future, with about half of plants discharging FGD wastewater in 2020 using
settling ponds.
4.4.2 Chemical Precipitation
In a chemical precipitation wastewater treatment system, chemicals are added to the
wastewater to alter the physical state of dissolved and suspended solids to facilitate settling and
removal of the solids. The specific chemical(s) used depends upon the type of pollutant requiring
removal. Steam electric plants commonly use the following three types of precipitation systems
to precipitate metals out of FGD wastewater:
• Hydroxide precipitation;
• Iron coprecipitation; and
• Sulfide precipitation.
In a hydroxide precipitation system, lime (calcium hydroxide) is often added to elevate
the pH of the wastewater and help precipitate metals into insoluble metal hydroxides that can be
removed by settling or filtration. Sodium hydroxide can also be used in a hydroxide chemical
precipitation system, but it is more expensive than lime and therefore, not used as commonly.
Many plants use iron coprecipitation as a way to increase the removal of metals in a
hydroxide precipitation system. Ferric or ferrous chloride can also be added to the precipitation
system to coprecipitate additional metals and organic matter. The ferric chloride also acts as a
coagulant, forming a dense floe that enhances settling of the metals precipitate in downstream
clarification stages.
In a sulfide precipitation system, sulfide chemicals (e.g., trimercapto-s-triazine (TMT),
Nalmet®, sodium sulfide) are used to precipitate and remove heavy metals, such as mercury.
While hydroxide precipitation can remove some heavy metals, sulfide precipitation can be more
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
effective because metal sulfides have lower solubilities than metal hydroxides. FGD wastewater
chemical precipitation systems may include various configurations of lime, ferric chloride, and
sulfide addition stages, as well as clarification stages.
A process flow diagram for a typical chemical precipitation system using both hydroxide
and sulfide addition to treat FGD wastewater is illustrated by Figure 4-6. A chemical
precipitation system that omits the sulfide precipitation stage would be similar, but would
exclude the reaction tank where sulfide is added.
For the system illustrated by Figure 4-6, the FGD scrubber purge from the plant's solid
separation/dewatering process is transferred to an equalization tank, where the intermittent flows
are equalized, allowing the plant to pump a constant flow of wastewater through the treatment
system. The equalization tank also receives wastewater from a filtrate sump, which includes
water from the gravity filter backwash and filter press filtrate.
The FGD scrubber purge is transferred at a continuous flow from the equalization tank to
reaction tank 1, where the plant adds hydrated lime to raise the pH of the wastewater from
between 5.5 - 6.0 to between 8.0 - 10.5 to precipitate the soluble metals as insoluble hydroxides
and oxyhydroxides. The reaction tank also desaturates the remaining gypsum in the wastewater,
which prevents gypsum scale formation in the downstream wastewater treatment equipment.
From reaction tank 1, the wastewater flows to reaction tank 2, where organosulfide (most
commonly TMT) or inorganic sulfide is added. The treatment system can also be configured so
that the organosulfide addition occurs before the hydroxide precipitation step, or with a
clarification step between the two chemical addition steps.
From reaction tank 2, the wastewater flows to reaction tank 3, where ferric chloride is
added to the wastewater for coagulation and coprecipitation. The effluent from reaction tank 3
flows to the flash mix tank, where polymer is added to the wastewater, prior to be being
transferred to the clarifier. Alternatively, the polymer can be added directly to the waste stream
as it enters the clarifier or added to reaction tank 3. The polymer is used to flocculate fine
suspended particles in the wastewater.
The clarifier settles the solids that were initially present in the FGD scrubber purge as
well as the additional solids (precipitate) that were formed during the chemical precipitation
steps. A sand filter may also be included in the process to further reduce solids, as well as metals
attached to the particulates. The backwash from the sand filters is transferred to a filtrate sump
and recycled back to the equalization tank at the beginning of the treatment system.
The treated FGD wastewater is collected in a wastewater holding tank and either
discharged directly to surface waters or, in most cases, commingled with other waste streams
prior to discharge to dilute the concentration of pollutants in the wastewater. As described in
Section 4.2, plants do not typically reuse this treated FGD wastewater because the chlorides are
at levels that have the potential to corrode downstream equipment.
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Chapter 4 - Flue Gas Desulfurization Systems
FGD Scrubber Purge
Wastewater
Lime
1 I
Organosulfide
o
Reactior
O
i Tank 1
^
Oko
Reaction
Tank 2
Ferric
Chloride
Reaction
TankS
Treated
Effluent to
Discharge
Figure 4-6. Process Flow Diagram for a Hydroxide and Sulfide Chemical Precipitation System
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
The solids settling in the clarifier (clarifier sludge) are transferred by pumps to the sludge
holding tanks, after which the sludge is dewatered using a filter press. The dewatered sludge, or
filter cake, is typically sent to an on-site landfill for disposal. The filtrate from the filter press is
transferred to a sump and recycled back to the equalization tank at the beginning of the treatment
system.
4.4.3 Biological Treatment
Biological wastewater treatment systems use microorganisms to consume biodegradable
soluble organic contaminants and bind much of the less soluble fractions into floe. Pollutants
may be reduced aerobically, anaerobically, and/or by using anoxic zones. Based on the
information EPA collected during the detailed study, two main types of biological treatment
systems are currently used (or planned) to treat FGD wastewater: aerobic systems to remove
BOD5 and anoxic/anaerobic systems to remove metals and nutrients. These systems can use
fixed film or suspended growth bioreactors, and operate as conventional flow-through or as
sequencing batch reactors (SBRs). The wastewater treatment processes for each of these
biological treatment systems is discussed below.
Aerobic Biological Treatment
An aerobic biological treatment system can effectively reduce BOD5 from wastewaters.
In a conventional flow-through design, the wastewater is continuously fed to the aerated
bioreactor. The microorganisms in the reactor use the dissolved oxygen from the aeration to
digest the organic matter in the wastewater, thus reducing the BOD5. The digestion of the
organic matter produces sludge, which may be dewatered with a vacuum filter to better manage
its ultimate disposal. The treated wastewater from the system overflows out of the reactor.
An SBR is a type of activated sludge treatment system that can reduce BODs and, when
operated to create anoxic zones under certain conditions, can also reduce nitrogen compounds
through nitrification and denitrification. Plants often operate at least two identical reactors
sequentially in batch mode. The treatment in each SBR consists of a four-stage process: fill,
aeration and reaction, settling, and decant. While one of the SBRs is settling and decanting, the
other SBR is filling, aerating, and reacting.
When operated as an aerobic system, the SBR operates as follows. The filling stage of the
SBR consists of transferring the FGD wastewater into a reactor that contains some activated
sludge from the previous reaction batch. During the aeration and reaction stage, the reactor is
aerated and the BOD5 is reduced as the microorganisms digest the organic matter in the
wastewater. During the settling phase, the air is turned off and the solids in the SBR are allowed
to settle to the bottom. The wastewater is then decanted off the top of the SBR and either
transferred to surface water for discharge or transferred for additional treatment. Additionally,
some of the solids from the bottom of the SBR are removed and dewatered, but some of the
solids are retained in the SBR to retain microorganisms in the system.
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Chapter 4 - Flue Gas Desulfurization Systems
Anoxic/Anaerobic Biological Treatment
Some coal-fired power plants are moving towards using anoxic/anaerobic biological
systems to achieve better reductions of certain pollutants (e.g., selenium, mercury, nitrates) than
has been possible with other treatment processes used at power plants. Figure 4-7 presents a
process flow diagram for an anoxic/anaerobic biological treatment system. These biological
systems include either a settling pond or chemical precipitation system as a pretreatment step to
reduce TSS entering the bioreactors. Additionally, the microorganisms are susceptible to high
temperatures, which may require the FGD wastewater to be cooled prior to entering the
biological system.
The fixed-film bioreactor consists of an activated carbon bed that is inoculated with
microorganisms which reduce selenium and other metals. Growth of the microorganisms within
the activated carbon bed creates a fixed-film that retains the microorganisms and precipitated
solids within the bioreactor. A molasses-based feed source for the microorganisms is added to
the wastewater before it enters the bioreactor [Pickett, 2006].
FGD Scrubber
Purge
k
0
<3 *-
LJ- C
M- 0
M
Recycle to Beginni
Wastewater Tre
I
I
I
1
Solids Pretreatment Exc
Step (e.g., Settling ^f
Pond, unemicai H
Precipitation)
i
First-Stage First-Stage
Bioreactors Eff|uent
I
I Bio Reactor Backflush
r
i
+
Sump
1
Effluent Treated FGD \
Storage for Disci-
ICCU
nanger
._. Nutrient
AN>
V \)
4 —
+
Second-Stage
Bioreactors
I
______ j
A/astewater
large k
Leaend
• Wastewater Flow
Intermittent Wastewater Flow
Figure 4-7. Process Flow Diagram for an Anoxic/Anaerobic Biological Treatment System
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
The bioreactor is designed for plug flow, containing different zones within the reactor
that have differing oxidation potential. The top part of the bioreactor is aerobic and allows for
nitrification and organic carbon oxidation. As the wastewater moves down through the
bioreactor, it enters an anoxic zone where denitrification occurs as well as chemical reduction of
both selenate and selenite, which are forms of selenium [Pickett, 2006].
As selenate and selenite are reduced within the bioreactor, elemental selenium forms
nanospheres that adhere to the cell walls of the microorganisms. Because the microorganisms are
retained within the bioreactor by the activated carbon bed, the elemental selenium is essentially
fixed to the activated carbon until it is removed from the system. The bioreactor can also reduce
other metals, including arsenic, cadmium, and mercury, by forming metal sulfides within the
system [Pickett, 2006].
The bioreactor system typically contains multiple bioreactors; however, they can either
be set up in series, as shown in Figure 4-7, or they can be set up in parallel, where the FGD
wastewater is split and treated in separate bioreactors. Multiple bioreactors are typically required
to allow for additional residence time to achieve the specified removals.
Periodically, the bioreactor must be flushed to remove the solids and inorganic materials
that have accumulated within it. The flushing process involves fluidizing the carbon bed by
flowing water upward through the system, which dislodges the particles fixed within the
activated carbon. The water and solids overflow from the top of the bioreactor and are removed
from the system. This flush water must be treated prior to being discharged because of the
elevated levels of solids and selenium [Pickett, 2006]. One plant currently operating an
anoxic/anaerobic bioreactor system recycles the flush water to the beginning of the chemical
precipitation wastewater treatment system so that the solids can be removed by the clarifier. The
other plant transfers the flush water to a segregated portion of the settling pond upstream of the
bioreactor [ERG, 2008h; Jordan, 2008a].
Another system developed by a treatment system vendor is similarly based on
anoxic/anaerobic biological treatment, but relies on using suspended growth flow-through
bioreactors instead of fixed-film bioreactors. Both designs share the fundamental processes that
lead to denitrification and reduction of metals in anoxic and anaerobic environments. This
suspended growth bioreactor system recently completed long-term pilot testing.
SBRs can also be operated to achieve the anoxic/anaerobic conditions described for the
flow-through systems. The SBR operation would be similar to that described above for the
aerobic biological treatment system; however, to create anoxic conditions, the aeration stage
would be followed by periods of air on, air off, which create aerobic zones for nitrification and
anoxic zones for denitrification to remove the nitrogen in the wastewater. EPA has collected
information on four coal-fired power plants that are planning to operate anoxic/anaerobic
biological SBRs, with startup scheduled to occur by 2010. The SBR systems at these plants are
expected to be operated in combination with chemical precipitation systems, with the overall
systems designed to optimize removal of metals and nitrogen compounds. According to the
treatment system vendor, these SBR systems will denitrify the wastewaters, but the oxidation
reduction potential in the system will not be conducive for reducing metals.
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4.4.4 Constructed Wetlands
A constructed wetland treatment system is an engineered system that uses natural
biological processes involving wetland vegetation, soils, and microbial activity to reduce the
concentrations of metals, nutrients, and TSS in wastewater. A constructed wetland typically
consists of several cells that contain bacteria and vegetation (e.g., bulrush, cattails), which are
selected based on the specific pollutants targeted for removal. The vegetation completely fills
each cell and produces organic matter (i.e., carbon) used by the bacteria. The bacteria reduce
metals that are present in the aqueous phase of the wastewater, such as mercury and selenium, to
their elemental state. The targeted metals partition into the sediment where they either
accumulate or are taken up by the vegetation in the wetland cells [EPRI, 2006b; Rodgers, 2005].
High temperature, COD, nitrates, sulfates, boron, and chlorides in wastewater can
adversely affect constructed wetlands performance. To overcome this FGD wastewater is
typically diluted with service water before it enters a constructed wetland to reduce the
temperature and concentration of chlorides and other pollutants, which can harm the vegetation
in the treatment cells. Chlorides in a constructed wetlands treatment system typically must be
maintained below 4,000 mg/L. Most plants operate their FGD scrubber system to maintain
chloride levels within a range of 12,000-20,000 ppm, so plants must dilute the FGD wastewater
prior to transferring it to the wetlands. EPA has observed that power plants operating a
constructed wetland tend to operate the FGD scrubber at the lower end of the chloride range. To
do this, the plants purge FGD wastewater from the system at a higher flow rate than they
otherwise would do if operating the FGD scrubber at a higher chloride level.
4.4.5 Vapor-Compression Evaporation System
Evaporators in combination with a final drying process can significantly reduce the
quantity of wastewater discharged from certain process operations at various types of industrial
plants, including power plants, oil refineries, and chemical plants. One type of evaporation
system uses a falling-film evaporator (also referred to as a brine concentrator) to produce a
concentrated wastewater stream and a reusable distillate stream. The concentrated wastewater
stream may be further processed in a crystallizer or spray dryer, in which the remaining water is
evaporated, eliminating the wastewater stream. When used in conjunction with a crystallizer or
spray dryer, this process reportedly generates a clean distillate and a solid by-product that can
then be disposed of in a landfill. Figure 4-8 presents a process flow diagram for a vapor-
compression evaporation system.
Power plants most often use vapor-compression evaporator systems to treat waste
streams such as cooling tower blowdown and demineralizer waste, but they have recently begun
to operate vapor-compression evaporator systems to treat FGD wastewater as well. One U.S.
coal-fired plant and six coal-fired power plants in Italy are treating FGD wastewater with vapor-
compression evaporator systems [Rao, 2008; Veolia, 2007; ERG, 2009a].
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Chapter 4 - Flue Gas Desulfurization Systems
Deaerator
Vent to
Atmosphere
b
FGD
Scrubber
Purge
Acid
Vent to
Atmosphere
FGD Waste
Feed/Distillate
Heat Exchanger
Brine Concentrator/
Vapor Separator
Distillate
>
Distillate for
Reuse/Discharge
Brine
Recycle
Brine
Solution
Multistage
Compressor/
Blower
Distillate
Tank
Concentrated Brine
Slurry to: k
Crystallizer; T
Spray Dryer; or
Fly Ash Conditioning
Legend
Liquid Stream
Gas Stream
2-Phase Stream
Figure 4-8. Process Flow Diagram for a Vapor-Compression Evaporation System
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
When a vapor-compression evaporator system is used to treat FGD wastewater, the first
step is to adjust the pH of the FGD scrubber purge to approximately 6.5. Following pH
adjustment, the scrubber purge is sent through a heat exchanger to bring the waste stream to its
boiling point. The waste stream continues to a deaerator where the noncondensable materials
such as carbon dioxide and oxygen are vented to the atmosphere [Aquatech, 2006].
From the deaerator, the waste stream enters the sump of the brine concentrator. Brine
from the sump is pumped to the top of the brine concentrator and enters the heat transfer tubes.
While falling down the heat transfer tubes, part of the solution is vaporized and then compressed
and introduced to the shell side of the brine concentrator (i.e., the outside of the tubes). The
temperature difference between the compressed vapor and the brine solution causes the
compressed vapor to transfer heat to the brine solution, which flashes to a vapor. As heat is
transferred to the brine, the compressed vapor cools and condenses as distilled water [Aquatech,
2006].
The condensed vapor (distillate water) can be recycled back to the FGD process, used in
other plant operations (e.g., boiler make-up water), or discharged. If the distillate is used for
other plant operations that generate a discharge stream (e.g., used as boiler make-up and
ultimately discharged as boiler blowdown), then the FGD process/wastewater treatment system
is not achieving true zero liquid discharge. Therefore, the operation of the vapor-compression
evaporation system itself does not guarantee that the FGD process/wastewater treatment system
achieves zero discharge.
To prevent scaling within the brine concentrator as a result of the gypsum present in the
FGD scrubber purge, the brine concentrator is seeded with calcium sulfate. The calcium salts
preferentially precipitate onto the seed crystals instead of the tube surfaces of the brine
concentrator [Shaw, 2008].
The concentrated brine slurry from the brine concentrator tubes falls into the sump and is
recycled with the feed (FGD scrubber purge) back to the top of the brine concentrator, while a
small amount is continuously withdrawn from the sump and typically transferred to a final
drying process. The brine concentrator can typically concentrate the FGD scrubber purge five to
ten times, which reduces the inlet FGD scrubber purge water volume by 80 to 90 percent [Shaw,
2008].
Three options are typically considered to be available for eliminating the brine
concentrate: (1) final evaporation in a brine crystallizer; (2) evaporation in a spray dryer; or (3)
using the brine to condition (add moisture to) dry fly ash or other solids, and disposal of the
mixture in a landfill.
Power plants may use brine concentrators to treat a waste stream other than FGD
scrubber purge (e.g., cooling tower blowdown). For these non-FGD systems, the concentrated
brine withdrawn from the sump is typically sent to a forced-circulation crystallizer to evaporate
the remaining water from the concentrate and generate a solid product for disposal. However, the
calcium and magnesium salts present in the scrubber purge can pose difficulties for the forced-
circulation crystallizer. To prevent this, the FGD scrubber purge can be pretreated using a lime-
softening process (i.e., chemical precipitation) upstream of the brine concentrator. With water
softening, the magnesium and calcium ions precipitate out of the purge water and are replaced
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with sodium ions, producing an aqueous solution of sodium chloride that can be more effectively
treated with a forced-circulation crystallizer [Shaw, 2008].
Coal-fired power plants can avoid having to operate the chemical precipitation
pretreatment process by using a spray dryer to evaporate the residual waste stream from the brine
concentrator. Because the material is hygroscopic (i.e., readily taking up and retaining moisture),
the solid residual from the brine concentrator is typically bagged immediately and disposed of in
a landfill. Alternatively, the concentrated brine waste stream can be combined with dry fly ash or
other solids and disposed of in a landfill.
4.4.6 Design/Operating Practices Achieving Zero Discharge
During its site visit program, EPA observed that many of the plants operating wet FGD
systems were able to design and/or manage the FGD system in a manner that prevented the need
for a discharge of FGD wastewater. Based on information EPA collected during the detailed
study, EPA identified four design/operating practices available to prevent the discharge of FGD
wastewater: evaporation ponds, conditioning dry fly ash, underground injection, and several
variations of complete recycle. The wastewater treatment processes for each of these practices
are discussed below.
Complete Recycle
As discussed in Section 4.2, most plants do not recycle the treated FGD wastewater
within the FGD system because of the elevated chloride levels in the treated effluent. Some
plants, however, can completely recycle the FGD wastewater within the system without using a
wastewater purge stream to remove chlorides. Such plants generally do not produce a saleable
solid product from the FGD system (e.g., wallboard-grade gypsum). Because the FGD solid by-
product is not being sold and is most likely disposed of in a landfill, there are no specific
chloride specifications for the material. Therefore, the plant can operate the FGD system and
solids separation/dewatering process such that the moisture retained with the landfilled solids
entrains sufficient chlorides that a separate wastewater purge stream is not needed. By operating
in this manner, the transfer of the FGD solids to the landfill essentially serves as the chloride
purge from the system.
EPA visited four plants that operate limestone forced oxidation FGD systems that do not
discharge any FGD wastewaters directly to surface waters. Case Study I describes how one of
these plants, Dominion Resources' Mount Storm Plant, is able to completely reuse the FGD
wastewaters within the system.
EPA also visited three plants that operate lime or limestone inhibited oxidation FGD
systems and do not discharge any FGD wastewaters directly to surface waters. Case Study II
describes how one of these plants was able to completely reuse the FGD wastewaters within the
system.
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Case Study I: Coal-Fired Power Plant Water Reuse
Limestone Forced Oxidation FGD System
Dominion Resources' Mount Storm Plant
The Facility
FGD type: Limestone forced oxidation spray tower
Scrubber chlorides cone.: 40,000 ppm
Materials of construction chlorides limit: 120,000 ppm
FGD WWT system: None: complete recycle
Gypsum destination: Landfill, concrete manufacturing, land application
The FGD Wastewater Handling System
The gypsum slurry blowdown from the FGD system is transferred to hydroclones for initial
dewatering. The underflow from the hydroclones contains the gypsum solids and is transferred
to vacuum rotary drum filters. The hydroclone overflow, which is mostly water and fines, is
recycled back to the FGD scrubber.
The hydroclone underflow sent to the vacuum rotary drum filters is not rinsed with service
water, as some plants do. The underflow is fed to a tray that holds the underflow as the vacuum
drum filter rotates and the bottom of the drum filter is dipped in the underflow water. The
vacuum on the rotary drum filter pulls the solids and water to the drum and then pulls the water
out of the solids to dry the gypsum. The dry gypsum (20-25% moisture content) is then scraped
off the drum as it rotates. The gypsum collected from the vacuum rotary drum filters is
conveyed to the storage area until it is either sent to the on-site landfill, transferred off site to a
concrete manufacturer, or transferred off site for land application. The filtrate from the vacuum
rotary drum filters is either recycled back to the FGD scrubber or to the limestone preparation
process.
Why the Plant is Able to Completely Reuse FGD Wastewater
Gypsum is not sold to a wallboard manufacturer; therefore, the gypsum dried on the vacuum
rotary drum filters does not need to meet any particular specifications. Since higher levels of
chlorides are acceptable, the gypsum does not require washing. Chlorides are purged from the
system entrained in the gypsum (20-25% moisture), and the mass removal rate is sufficient to
maintain the chlorides in the FGD system at a constant level.
Source: [ERG, 2008p].
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Case Study II: Coal-Fired Power Plant Water Reuse
Lime or Limestone Inhibited Oxidation FGD System
Ohio Power Company's General James M Gavin Plant
The Facility
FGD type: Magnesium-enhanced lime inhibited oxidation spray/tray towers
Scrubber chlorides cone.: 2,500 to 3,000 ppm
FGD WWT system: None: complete recycle
Calcium sulfite destination: Landfilled as cementitious material
The FGD Wastewater Handling System
The calcium sulfite slurry from the FGD system is transferred to a pair of thickeners to separate
the solids from the water. The underflow from the thickener contains the calcium sulfite solids
and is transferred to centrifuges for final dewatering. The thickener overflow is sent to a reclaim
tank and recycled back to the FGD scrubber.
The thickener underflow sent to the centrifuges is not rinsed with service water. The underflow
is fed to a centrifuge to dewater the solids. The water leaving the centrifuge, referred to as
centrate, is recycled back to the FGD scrubber. The solids stream from the centrifuge contains
40-50 percent moisture. This stream is combined with dry fly ash and lime in a pug mill to
generate a cementitious material that can be landfilled.
How FGD Wastewater is Completely Reused
The calcium sulfite does not need to meet any particular specifications; therefore, it is not
washed to remove chlorides prior to dewatering. The dewatered calcium sulfite has a moisture
content of 40 to 50 percent water (before mixing with fly ash and lime) and chlorides are
retained in the cementitious material sent to the landfill. The FGD system has reached a steady
state operation in which the chlorides entering the system from the coal are equal to the
chlorides that are leaving the system in the cementitious material.
Source: [ERG, 2009b].
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Evaporation Ponds
EPA identified three coal-fired power plants located in the southwestern United States
using evaporation ponds to avoid discharging FGD wastewater. Because of the warm, dry
climate in this region, the plants can send the FGD wastewater to one or more ponds where the
water is allowed to evaporate. At these plants, the evaporation rate from the pond is greater than
or equal to the flow rate of the FGD wastewater to the pond and no water is discharged from the
evaporation pond.
Conditioning Dry Fly Ash
Many plants that operate dry fly ash handling systems need to add water to the fly ash for
dust suppression or to improve handling and/or compaction characteristics. EPA has identified
one plant that uses FGD wastewater to condition its dry fly ash. In addition, another plant is
using a vapor-compression evaporation system in combination with conditioning dry fly ash to
prevent the discharge of FGD wastewater [ERG, 2009a]. The plant uses the vapor-compression
evaporation system to reduce the volume of the FGD scrubber purge and then mixes the effluent
from the brine concentrator with dry fly ash and disposes of it in a landfill.
Underground Injection
Underground injection is a technique used to dispose of wastes by injecting them into an
underground well. This technique is an alternative to discharging wastewater to surface waters.
One plant began using underground injection to dispose of the FGD wastewater in 2007, but due
to unexpected pressure issues and problems with building the wells due to geological formations
encountered, which may not be related to the characteristics of the FGD wastewater, the plant
has not been able to continuously inject the wastewater. The plant operates a chemical
precipitation system as pretreatment for the injection system. When the plant is not injecting the
FGD wastewater, the effluent from the chemical precipitation system is transferred to the plant's
pond system. Since the pond water is used as make-up for the plant's service water, the chlorides
from the FGD wastewater are not purged from the system. The plant needs to sustain continuous
injection of the wastewater to avoid chlorides increasing to a level that would promote corrosion
of equipment [ERG, 2009e]. Another plant is also scheduled to begin injecting the FGD
wastewater underground later this year [Gulf Power, 2009]. Underground injection has its own
permitting and regulations, which are not covered under the NPDES program.
Combination of Wet and Dry FGD Systems
The combination of a wet and a dry FGD system operated on the same unit or at the same
plant can result in elimination of the scrubber purge associated with the wet FGD process. As
described in Section 4.2.3, the dry FGD process involves atomizing and injecting wet lime
slurry, which ranges from approximately 18 to 25 percent solids, into a spray dryer. The water
contained in the slurry is evaporated from the heat of the flue gas within the system, leaving
behind a dry residue which is removed from the flue gas by a fabric filter (i.e., baghouse). By
operating a combination of a wet and dry FGD system, the scrubber purge associated with the
wet FGD system can be used as make-up water for the lime slurry feed to the dry FGD process,
thereby eliminating the FGD wastewater.
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From its data collection activities, EPA has identified one plant that is expected to
operate a dry FGD system in combination with a wet FGD system to eliminate the need to
discharge the FGD wastewater associated with the wet FGD system. Case Study III describes
how this plant is expected to operate when the new electric generating unit begins operation in
2012.
4.4.7 Other Technologies under Investigation
Industry-funded studies are being conducted by EPRI to evaluate and demonstrate
technologies that have the potential to remove trace metals from FGD wastewater. EPRI is
conducting pilot- and full-scale optimization field studies on some technologies already in use by
coal-fired power plants to treat FGD wastewater, such as chemical precipitation (organosulfide
and iron coprecipitation), constructed wetlands, and an anoxic/anaerobic biological treatment
system. EPRI is also conducting lab- and pilot-scale studies for other technologies that may be
capable of removing metals from FGD wastewaters. EPA obtained limited information regarding
these other technologies, which include iron cementation, reverse osmosis, absorption media, ion
exchange, and electro-coagulation. Each of these technologies are discussed below.
Iron Cementation
EPRI conducted laboratory feasibility studies of the metallic iron cementation treatment
technology as a method for removing all species of selenium from FGD wastewater. EPRI
believes this process may also be effective at removing mercury. The iron cementation process
consists of contacting the FGD wastewater with an iron powder, which reduces the metal to its
elemental form (cementation). The pH of the wastewater is raised to form metal hydroxides, and
the wastewater is filtered to remove the precipitated solids. The iron powder used in the process
is separated from the wastewater and recycled back to the cementation step. From the initial
studies, EPRI concluded that the metallic iron cementation approach is promising for treating
FGD wastewater for multiple species of selenium, including selenite, selenate, and other
unknown selenium compounds. EPRI is planning to continue conducting laboratory- and pilot-
scale feasibility studies of the technology to evaluate selenium and mercury removal
performance [EPRI, 2008b].
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Case Study III: Coal-Fired Power Plant Water Reuse
Integrated Dry and Wet FGD Systems
Duke Energy Carolinas' Cliffside Steam Station
The Facility
FGD type: Unit 6: Lime spray dryer and wet limestone forced oxidation
spray tower; Unit 5: wet limestone forced oxidation spray tower
FGD WWT system: Unit 6: None; Unit 5: chemical precipitation system
FGD solids destination: Sold for wallboard production or landfilled
The FGD Operation and Wastewater Handling System
When Unit 6 begins operation (expected in 2012), its flue gas will first be treated with a dry
lime FGD system (spray dryer). The flue gas exiting the spray dryer will pass through a fabric
filter baghouse to remove the FGD solids, fly ash, and other particulates from the flue gas. The
flue gas will then be directed to the wet limestone forced oxidation system. The wet FGD
system will operate similarly to Figure 4-2; however, instead of the scrubber purge being
transferred to wastewater treatment and discharged, the scrubber purge will be reused in the
lime slurry feed to the dry FGD system.
Unit 5 is currently operating at the plant, but its wet FGD system is not yet operating. Once the
FGD system is operating, the Unit 5 flue gas will be treated by a cold-side ESP followed by a
wet limestone forced oxidation system. When Unit 6 is not operating, the scrubber purge from
Unit 5 will be transferred to a chemical precipitation wastewater treatment system. When Unit 6
is operating, most, if not all, of the scrubber purge from Unit 5 can be used in the lime slurry
feed for the Unit 6 dry FGD system; the remainder will be transferred to the wastewater
treatment system. Units 5 and 6 operate independently from each other and, therefore, the
wastewater treatment system will allow the plant to operate Unit 5 and discharge its scrubber
purge stream when Unit 6 is not operating.
How the FGD Wastewater Discharge will be Eliminated
The scrubber purge streams from Units 5 & 6 will be reused in the feed stream to Unit 6's dry
FGD system, which will evaporate the water during the process and generate only solid
residues that are removed in the fabric filter baghouse.
Source: [McGinnis, 2009].
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Reverse Osmosis
Reverse osmosis systems are currently in use at power plants, usually to treat boiler
make-up water or cooling tower blowdown wastewaters. EPRI has identified a high-efficiency
reverse osmosis (HERO™) process which operates at a high pH, allowing the system to treat
high silica wastewaters without scaling or membrane fouling because silica is more soluble at
higher pHs. The wastewater undergoes a water-softening process to raise the pH of the
wastewater prior to entering the HERO™ system.
Although the HERO™ system has been demonstrated for use with power plant cooling
tower blowdown wastewater, its use for FGD wastewater is potentially limited due to the
osmotic pressure of the FGD wastewater resulting from the high concentrations of chloride and
IDS [EPRI, 2007a].
Although many power plants may not be able to use the HERO™ system to treat FGD
wastewater, some plants with lower IDS and chloride concentrations may be able to do so. The
HERO™ system is of particular interest for treating boron from FGD wastewaters because boron
becomes ionized at an elevated pH and, therefore, could be removed using a reverse osmosis
system [EPRI, 2007a].
Sorption Media
Sorption media has been used by the drinking water industry to remove arsenic from the
drinking water. These sorption processes are designed to adsorb pollutants onto the media's
surface area using physical and chemical reactions. The designs most commonly used in the
drinking water industry use metal-based adsorbents, typically granular ferric oxide, granular
ferric hydroxide, or titanium-based oxides. The sorption media is usually a single use application
that can typically be disposed of in a nonhazardous landfill after its use. In addition, the single-
use design prevents the plant from needing to further treat the residuals. According to EPRI,
these sorption media have been shown to remove the common forms of arsenic and selenium
from drinking water [EPRI, 2007a].
Ion Exchange
Ion exchange systems are currently in use at power plants to pretreat boiler make-up
water. Ion exchange systems are designed to remove specific constituents from wastewater;
therefore, specific metals can be targeted by the system. The typical metals targeted by ion
exchange systems include boron, cadmium, cobalt, copper, lead, mercury, nickel, uranium,
vanadium, and zinc. Although the ion exchange process does not generate any residual sludge, it
does generate a regenerant stream that contains the metals stripped from the wastewater. EPA
has compiled information on a plant that is pilot testing two ion exchange resins for treatment of
FGD wastewater. The plant and the ion exchange resins tested in the pilot study are focused
specifically on the removal of mercury. [EPRI, 2007a].
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Electro-Coagulation
Electro-coagulation uses an electrode to introduce an electric charge to the wastewater,
which neutralizes the electrically charged colloidal particles. These systems typically use
aluminum or iron electrodes, which are dissolved into the waste stream during the process. The
dissolved metallic ions precipitate with the other pollutants present in the wastewater and form
insoluble metal hydroxides. According to EPRI, additional polymer or supplemental coagulants
may need to be added to the wastewater depending on the specific characteristics. These systems
are typically used to treat small waste streams, ranging from 10 to 25 gpm, but may also be able
to treat waste streams of up to 50 or 100 gpm [EPRI, 2007a].
Other Technologies
Other technologies under laboratory-scale study include polymeric chelates, taconite
tailings, and nano-scale iron reagents. In addition, EPRI is investigating various physical
treatment technologies, primarily for mercury removal, including filtration [EPRI, 2008a].
4.4.8 Wastewater Treatment System Use in the Coal-Fired Steam Electric Industry
Table 4-7, presents information on the FGD wastewater treatment systems currently
operating (as of June 2008) at plants included in EPA's combined data set. Table 4-7 also
includes information on FGD wastewater treatment systems projected to be operating in 2020.
EPA's combined data set includes wastewater treatment system information for 84 of the 108
plants (78 percent) operating wet FGD scrubber systems as of June 2008, representing 175 of the
223 wet-scrubbed coal-fired electric generating units (78 percent). Of these 84 plants, 32 plants
(38 percent) do not discharge FGD wastewater.18 These plants are able to achieve "zero
discharge" by either recycling all FGD wastewater back to the scrubber (28 plants), using
evaporation ponds (3 plants), mixing the FGD wastewater with dry fly ash (1 plant), or deep well
injecting the FGD wastewater (1 plant19). Figure 4-9 shows the distribution of FGD wastewater
management/treatment within the group of 84 plants.
18 There is a plant that operates several wet FGD systems and for some of the wet FGD systems there is a
wastewater discharge; however, the other wet FGD systems operate without discharging. In Table 4-7, this plant is
included in the count of plants for both the "zero discharge" wastewater treatment systems and the other type of
wastewater treatment system operated by the plant.
19 As discussed in Section 4.4.6, the plant began using underground injection to dispose of the FGD wastewater in
2007, but due to issues encountered with the system, has not been able to continuously inject the wastewater.
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Table 4-7. FGD Wastewater Treatment Systems Identified During EPA's Detailed Study
Settling Ponds
Combined FGD and Ash Ponds (FGD
solids removal prior) d> e
Combined FGD and Ash Ponds (No FGD
solids removal prior) d> f
FGD Ponds (FGD solids removal prior) e' g
FGD Ponds (No FGD solids removal prior)
f,g
Chemical Precipitation ("Chem Precip")
Chem Precip (type unknown)
Hydroxide Chem Precip
Hydroxide and Sulfide Chem Precip
Combination Settling Pond and Chem
Precip
Chem Precip and Constructed Wetland
Tank-Based Biological
Combination Settling Pond and
Anoxic/Anaerobic Biological (designed for
metals & nitrogen removal)
Wet FGD Systems in the Combined Data Set
Operating as of June 2008 a
Number of Plants
with FGD
Wastewater
Treatment
Systems
29
17
2
4
6
15
—
10
2
2
1
1
1
Number of Electric
Generating Units
Serviced by FGD
Wastewater
Treatment Systems
63
41
4
8
10
27
—
18
4
3
2
3
3
Wet
Scrubbed
Capacity0
(MW)
27,700
14,400
1,440
4,450
7,350
14,200
—
10,500
2,350
896
414
2,150
2,150
Wet FGD Systems in the Combined Data Set
Projected to be Operating in 2020 b
Number of Plants
With or Expected
to Operate FGD
Wastewater
Treatment Systems
35
18
2
7
8
24
5
11
5
2
1
2
2
Projected Number
of Electric
Generating Units
Serviced by the
Treatment
Systems
95
48
4
18
25
52
11
25
11
3
2
6
6
Projected
Wet
Scrubbed
Capacity c
(MW)
44,000
16,600
1,440
12,500
13,400
28,300
5,800
14,800
6,460
896
414
3,294
3,294
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Table 4-7. FGD Wastewater Treatment Systems Identified During EPA's Detailed Study
Combination Chem Precip and Tank-Based
Biological
Chem Precip and Aerobic Biological
(designed for metals and BOD5 removal)
Chem Precip and Aerobic/Anaerobic
Biological (designed for removing nitrogen
and selected metals)
Chem Precip and Anoxic/ Anaerobic
Biological (designed for metals & nitrogen
removal)
Chem Precip, Anoxic/ Anaerobic Biological
(designed for metals & nitrogen removal),
and CWTS
Zero Discharge
Zero Discharge: Recycle All FGD Water
Zero Discharge: Evaporation Pond
Zero Discharge: Conditioning Dry Fly Ash
Zero Discharge: Deep Well Injection
Zero Discharge: Evaporator &
Conditioning Dry Fly Ash
Zero Discharge: Recycled to Dry FGD
Wet FGD Systems in the Combined Data Set
Operating as of June 2008 a
Number of Plants
with FGD
Wastewater
Treatment
Systems
3
2
1
33
28
o
6
i
i
—
—
Number of Electric
Generating Units
Serviced by FGD
Wastewater
Treatment Systems
5
3
2
65
56
4
2
o
J
—
—
Wet
Scrubbed
Capacity0
(MW)
4,720
2,560
2,160
38,700
33,800
1,800
1,140
2,000
—
—
Wet FGD Systems in the Combined Data Set
Projected to be Operating in 2020 b
Number of Plants
With or Expected
to Operate FGD
Wastewater
Treatment Systems
8
1
4
o
J
35
27
o
3
1
2
1
1
Projected Number
of Electric
Generating Units
Serviced by the
Treatment
Systems
23
2
11
10
75
58
4
2
7
2
2
Projected
Wet
Scrubbed
Capacity c
(MW)
12,500
1,870
5,260
5,330
43,000
34,700
1,800
1,140
3,140
1,580
571
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Table 4-7. FGD Wastewater Treatment Systems Identified During EPA's Detailed Study
Other Handling
Clarifier
Clarifier and Constructed Wetland
Commingled with other Wastewater
No Information
Subtotal: Wastewater treatment systems for
which EPA has information available h
Subtotal: Systems treating FGD wastewater
discharged to surface waters h
Total h
Wet FGD Systems in the Combined Data Set
Operating as of June 2008 a
Number of Plants
with FGD
Wastewater
Treatment
Systems
5
1
1
o
J
24
84
53
108
Number of Electric
Generating Units
Serviced by FGD
Wastewater
Treatment Systems
12
3
4
5
48
175
110
223
Wet
Scrubbed
Capacity0
(MW)
5,010
521
2,000
2,490
15,600
92,500
53,800
108,000
Wet FGD Systems in the Combined Data Set
Projected to be Operating in 2020 b
Number of Plants
With or Expected
to Operate FGD
Wastewater
Treatment Systems
5
1
1
o
J
85
107
74
192
Projected Number
of Electric
Generating Units
Serviced by the
Treatment
Systems
12
3
4
5
164
237
162
401
Projected
Wet
Scrubbed
Capacity c
(MW)
5,010
521
2,000
2,490
65,900
123,000
79,900
189,000
a - Source: Combined data set (UWAG-provided data [ERG, 2008g], data request information [U.S. EPA, 2008a], and site visit and sampling information).
Includes treatment systems servicing electric generating units identified in the "combined data set" with wet FGD systems operating as of June 2008. Excludes
OSWER data for surface impoundments containing CCRs.
b - Source: Combined data set (UWAG-provided data [ERG, 2008g], data request information [U.S. EPA, 2008a], and site visit and sampling information).
Includes treatment systems servicing electric generating units identified in the "combined data set" with wet FGD systems operating by 2020.
c - The capacities presented have been rounded to three significant figures. Due to rounding, the total capacity may not equal the sum of the individual
capacities. The capacities presented represent the reported nameplate capacity for the unit.
d - The combined FGD and ash pond system refers to a settling pond that handles untreated FGD scrubber purge and ash wastewaters (either bottom ash or fly
ash transport water). Some plants transfer treated FGD wastewaters to an ash pond for dilution prior to discharge, but these systems are not reflected in this table.
e - "FGD Solids removal prior" means that gypsum or calcium sulfite sludge was removed prior to treatment.
f - "No FGD Solids removal prior" means that gypsum or calcium sulfite sludge was sent to the settling pond.
g - The FGD pond system refers to settling ponds that handle untreated FGD scrubber purge, but do not handle ash wastewaters. The FGD pond may handle
other wastewaters along with the FGD scrubber purge, such as low-volume wastes, but the pond cannot receive ash wastewaters to be considered an FGD pond.
h - There are two plants with multiple types of wastewater treatment systems; therefore, there is overlap in these totals.
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Zero Discharge
38%
Other Handling
6%
Anoxic/Anaerobic
Biological
2%
Settling Ponds
34%
Chemical Precipitation
20%
Figure 4-9. Distribution of FGD Wastewater Treatment Systems Among Plants Operating
Wet FGD Systems
Figure 4-10 compares the distribution of FGD wastewater treatment systems within the
group of plants that operate limestone forced oxidation FGD systems, to the group of plants
operating inhibited/natural oxidation FGD systems. EPA has information about FGD wastewater
management/treatment for 50 plants operating forced oxidation FGD systems servicing 111
electric generating units, and 36 plants operating inhibited or natural oxidation FGD systems
servicing 65 electric generating units20. A larger percentage of the plants operating forced
oxidation FGD systems discharge the FGD wastewater, relative to plants that operate inhibited
and natural oxidation FGD systems. This is largely due to the fact that inhibited oxidation FGD
systems produce calcium sulfite by-product which, since it has little or no value in the
marketplace, typically is disposed of in a landfill. This provides plants the opportunity to operate
the FGD system in a manner that purges chlorides from the FGD system along with the
landfilled solids and eliminates the need for the FGD wastewater discharge. See section 4.2 for
additional discussion of this operational practice.
20 EPA has information regarding FGD wastewater treatment systems for 84 plants; however, two of these plants
operated both forced oxidation and natural/inhibited oxidation FGD systems.
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
70
I Forced Oxidation n Inhibited/Natural Oxidation
(Number of plants shown in parantheses)
Settling Ponds
Chemical
Precipitation
Anoxic/
Anaerobic
Biological
FGD Wastewater Treatment Technology
Other Handling Zero Discharge
Figure 4-10. Comparison of Distribution of FGD Wastewater Treatment Systems by Type
of Oxidation System
Of the 84 plants for which EPA has information about FGD wastewater, 53 discharge the
FGD wastewater. The technologies used by these 53 plants to treat FGD wastewater is
summarized below, and illustrated by Figure 4-11. It should be noted that most of these plants
subsequently commingle the treated FGD wastewater with other waste streams (e.g., ash
wastewater or cooling water) to enable dilution to reduce the pollutant concentrations in the
discharged wastewater.
• Twenty-nine plants treat the wastewater using a settling pond.21
• Eighteen plants operate chemical precipitation systems. Fifteen of these 18 plants
operate a hydroxide chemical precipitation system, and three use both hydroxide
and sulfide precipitation in the treatment system. Additionally, two of the 15
hydroxide plants currently have equipment installed to also perform a sulfide
precipitation step, but are no longer adding sulfide to the system.
• Two of the 18 plants with chemical precipitation systems also operate aerobic
biological reactors following the precipitation system. Both of these plants use
For comparison, note that the OSWER data on surface impoundments identifies 78 plants operating a total of 170
ponds that contain FGD wastes. There is insufficient data to determine whether the FGD wastestream undergoes
solids separation to remove gypsum or calcium sulfite prior to the ponds, nor is there information to determine
which of these ponds may discharge to surface water. Some of the ponds also contain ash wastes and may be more
accurately described as ash ponds that also receive FGD wastes (with or without first removing FGD solids)
[Schroeder, 2009].
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
organic acid additives in their FGD scrubbers to improve the SO2 removal
efficiency, increasing the BODS concentration in the scrubber purge.
Two plants operate fixed-film anoxic/anaerobic bioreactors. One of these plants
also operates a chemical precipitation system (one of the 18 plants described
previously) and the other operates a settling pond as pretreatment to the
bioreactor. Two additional plants are in the process of installing similar fixed-film
bioreactors. One will operate the biological system in conjunction with chemical
precipitation; the other will use a settling pond for pretreatment.
One plant uses a clarifier and one plant uses a constructed wetlands treatment
system as the primary treatment mechanism. Two other plants also operate
constructed wetland systems; however, the constructed wetland acts as a polishing
step following chemical precipitation and/or biological treatment.
Three plants commingle the FGD wastewater with other waste streams (other than
ash transport water).
Other Handling
9%
Anoxic/Anaerobic
Biological
4%
^^ Settling Ponds
Chemical Precipitation\ ^ / 550/0
32%
Figure 4-11. Distribution of FGD Wastewater Treatment Systems Among Plants that
Discharge FGD Wastewater
Table 4-7 also presents information for the type of treatment systems that, based on the
combined data set, EPA anticipates will be used to treat wastewater from the FGD scrubbers that
will be operating in 2020. Despite recent interest in the use of more advanced wastewater
treatment systems, the data compiled by EPA indicate that widespread use of settling ponds to
treat FGD wastewater will continue.
EPA expects that more than 192 plants will be operating wet FGD scrubbers by 2020 and
that 158 of these plants will discharge FGD wastewater22. Of these 158 plants, there are 74 for
which EPA has information on their expected system use. Below is a description of the type of
22 As discussed in section 4.1.2, EPA's projections for new FGD systems do not include the systems that will be
installed at new generating units or new plants. Thus, the projections for 2020 are considered to under-estimate the
actual number of FGD systems that will be installed.
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
wastewater treatment systems either currently operating or expected to be operating at these 74
plants:
• Thirty-five plants are expected to treat the wastewater using a settling pond;
• Thirty-four plants are expected to rely on more advanced treatment such as
chemical precipitation or biological treatment;
• One plant is expected to use a clarifier and one plant is expected to use a
constructed wetlands treatment system as the primary treatment mechanism; and
• Three plants are expected to commingle the FGD wastewater with other waste
streams (other than ash transport water).
4.5 Comparison of FGD Wastewater Control Technologies
As part of the detailed study, EPA evaluated several treatment technologies or
combinations of treatment technologies that plants are using to remove heavy metals and other
pollutants from FGD wastewater. Using the data available for these systems, EPA evaluated
these systems as potential controls for the treatment of FGD wastewater, as follows:
• Chemical Precipitation. Physical/chemical precipitation for heavy metals
removal using hydroxide or a combination of hydroxide and sulfide precipitation;
• Chemical Precipitation + Biological Metals Removal. Chemical precipitation
followed by anoxic/anaerobic biological treatment for removing additional metals
and to reduce nitrogen compounds; and
• Chemical Precipitation/Softening + Evaporation + Crystallization. Chemical
precipitation or softening followed by evaporation in a brine concentrator and
crystallization for potential elimination of the FGD wastewater stream.
EPA used information collected throughout the detailed study in evaluating these
technologies, including operational and performance information from plants, vendors, and
EPA's site visit and sampling programs. Data collected during EPA's sampling program and
self-monitoring data obtained from individual plants were used to evaluate the performance of
the chemical precipitation and biological treatment technologies. These data show that chemical
precipitation is an effective means for removing many metals from the FGD wastewater.
Biological treatment, specifically fixed-film anoxic/anaerobic bioreactors when paired with a
chemical precipitation pretreatment stage, is very effective at removing additional pollutants
such as selenium and nitrogen compounds (e.g., nitrates, nitrites). If operated with a nitrification
step, the technology would also be expected to remove ammonia that may be present in the waste
stream. Coal-fired power plants have only recently begun to use evaporation/crystallization
systems to treat FGD scrubber purge, so EPA was able to collect only limited data for these
systems.
Figure 4-12 (A-G) and Figure 4-13 (A-G) present a series of graphs of monitoring data
collected in 2008 from the FGD wastewater treatment systems at Duke Energy Carolinas'
Belews Creek Steam Station and Progress Energy Carolinas' Roxboro Power Plant, respectively.
For each plant, the graphs present the concentrations of arsenic, mercury, selenium, and TDS at
the following points in the FGD wastewater treatment systems:
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
• FGD scrubber purge;
• Intermediate point preceding the biological treatment stage (i.e., settling pond
effluent for Roxboro and chemical precipitation effluent for Belews Creek); and
• Effluent from the anoxic/anaerobic biological treatment system.
The Belews Creek FGD wastewater treatment system consists of an equalization tank
followed by a chemical precipitation system to reduce dissolved metals using lime for hydroxide
precipitation, ferric chloride for iron co-precipitation, and a clarifier and sand filter for solids
removal. After the sand filter, the wastewater is transferred to a fixed-film, anoxic/anaerobic
biological treatment system designed to remove metals and nitrogen compounds. Belews Creek
operates two stages of the biological reactors in series. After the biological system, the
wastewater is transferred to a constructed wetland and then to the ash pond and discharged.
The Roxboro FGD wastewater treatment system consists of a settling pond followed by a
fixed-film, anoxic/anaerobic biological treatment system designed to remove metals and nitrogen
compounds. The settling pond was designed specifically for FGD wastewater, to reduce the
wastewater temperature and TSS prior to the bioreactor. The bioreactor operates with four
parallel trains that each has two biological cells in series. Wastewater flows from the bioreactor
to the ash pond discharge canal and is discharged.
The Belews Creek and Roxboro graphs show that the chemical precipitation system, the
settling pond, and the biological treatment systems are all able to remove arsenic, mercury, and
selenium to some extent from the FGD scrubber purge. Figure 4-12 and Figure 4-13 show that
the chemical precipitation system at Belews Creek is achieving lower pollutant concentrations of
metals than the settling pond at Roxboro. Despite the two plants having relatively comparable
levels of mercury, selenium, and arsenic in their scrubber purge stream, the chemical
precipitation stage at Belews Creek achieved pollutant concentrations approximately an order of
magnitude lower than was observed for the settling pond at Roxboro. In addition, the
anoxic/anaerobic biological treatment stage at both plants further reduced the metals in the FGD
wastewater. The effectiveness of the biological treatment stage is particularly notable for
selenium which, depending on the form of selenium present in the wastewater, usually is not
effectively nor consistently removed by settling ponds or chemical precipitation. The bioreactor
effluent selenium concentrations at Belews Creek are substantially lower than those observed for
Roxboro's bioreactor effluent, presumably due to the chemical precipitation stage providing
more effective pretreatment than achieved by the settling pond. Finally, the figures show that
TDS is not significantly removed by the settling pond, the chemical precipitation system, or the
biological treatment system.
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Chapter 4 - Flue Gas Desulfurization Systems
Belews Creek Monitoring Data (2008)
• Purge -*- Chem Precip -*- Bio
_l
"3)
3
(/)
o nnn
1 nnn
n
l
A
l/\ A
V \/ V _ ,
1-Jun 21-Jun 11-Jul 31-Jul 20-Aug 9-Sep 29-Sep 19-Oct
Figure 4-12A. Concentration of Arsenic in FGD Scrubber Purge
and Effluent from Chemical Precipitation and Biological
Treatment Systems at Belews Creek
-•- Chem Precip -*- Bio
21-Jun 11-Jul 31-Jul 20-Aug 9-Sep 29-Sep 19-Oct
Figure 4-12B. Concentration of Arsenic in Effluent from
Chemical Precipitation and Biological Treatment Systems at
Belews Creek
6,000
5,000
Roxboro Monitoring Data (2008)
- Purge -•- Settling Pond -*- Bio
22-Feb 12-Apr 1-Jun 21-Jul 9-Sep 29-Oct 18-Dec 6-Feb
Figure 4-13A. Concentration of Arsenic in FGD Scrubber Purge
and Effluent from Settling Pond and Biological Treatment
Systems at Roxboro
-•- Settling Pond -*- Bio
250
22-Feb 12-Apr 1-Jun
21-Jul
9-Sep 29-Oct 18-Dec 6-Feb
Figure 4-13B. Concentration of Arsenic in Effluent from Settling
Pond and Biological Treatment Systems at Roxboro
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
400
350
Belews Creek Monitoring Data (2008)
- Purge -*- Chem Precip -*- Bio
1-Jun
21-Jun 11-Jul 31-Jul 20-Aug 9-Sep 29-Sep 19-Oct
Figure 4-12C. Concentration of Mercury in FGD Scrubber
Purge and Effluent from Chemical Precipitation and Biological
Treatment Systems at Belews Creek
0.60
- Chem Precip
21-Jun 11-Jul 31-Jul 20-Aug 9-Sep 29-Sep 19-Oct
Figure 4-12D. Concentration of Mercury in Effluent from
Chemical Precipitation and Biological Treatment Systems at
Belews Creek
Roxboro Monitoring Data (2008)
• Purge -*- Settling Pond -*- Bio
Feb 12-Apr 1-Jun 21-Jul 9-Sep 29-Oct 18-Dec 6-Feb
Figure 4-13C. Concentration of Mercury in FGD Scrubber
Purge and Effluent from Settling Pond and Biological
Treatment Systems at Roxboro
-•-Settling Pond -*- Bio
6
L
0
22-Feb 12-Apr 1-Jun
21-Jul
9-Sep 29-Oct 18-Dec 6-Feb
Figure 4-13D. Concentration of Mercury in Effluent from
Settling Pond and Biological Treatment Systems at Roxboro
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
16,000
Belews Creek Monitoring Data (2008)
• Purge -•- Chem Precip
1-Jun 21-Jun 11-Jul 31-Jul 20-Aug 9-Sep 29-Sep 19-Oct
Figure 4-12E. Concentration of Selenium in FGD Scrubber
Purge and Effluent from Chemical Precipitation and Biological
Treatment Systems at Belews Creek
350
- Chem Precip -*- Bio
300 -
250 -
200 -
100 -
50
1-Jun
21-Jun 11-Jul 31-Jul 20-Aug 9-Sep 29-Sep 19-Oct
Figure 4-12F. Concentration of Selenium in Effluent from
Chemical Precipitation and Biological Treatment Systems at
Belews Creek
25,000
Roxboro Monitoring Data (2008)
- Purge -*- Settling Pond -*- Bio
22-Feb 12-Apr 1-Jun 21-Jul 9-Sep 29-Oct 18-Dec 6-Feb
Figure 4-13E. Concentration of Selenium in FGD Scrubber
Purge and Effluent from Settling Pond and Biological
Treatment Systems at Roxboro
3,000
-•- Settling Pond -*- Bio
12-Apr 1-Jun 21-Jul 9-Sep 29-Oct 18-Dec 6-Feb
Figure 4-13F. Concentration of Selenium in Effluent from
Settling Pond and Biological Treatment Systems at Roxboro
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Chapter 4 - Flue Gas Desulfurization Systems
Belews Creek Monitoring Data (2008)
- Purge -*- Chem Precip -*- Bio
30,000,000
25,000,000 -
_ 20,000,000 -
"S
3. 15,000,000 -
10,000,000 -
5,000,000 -
1-Jun 21-Jun 11-Jul 31-Jul 20-Aug 9-Sep 29-Sep 19-Oct
Figure 4-12G. Concentration of TDS in FGD Scrubber Purge
and Effluent from Chemical Precipitation and Biological
Treatment Systems at Belews Creek
Roxboro Monitoring Data (2008)
-•- Purge -•- Settling Pond
18,000,000
16,000,000
14,000,000
12,000,000
? 10,000,000
~ 8,000,000
H 6,000,000
4,000,000
2,000,000 -
0
22-Feb 12-Apr 1-Jun 21-Jul 9-Sep 29-Oct 18-Dec 6-Feb
Figure 4-13G. Concentration of TDS in FGD Scrubber Purge
and Effluent from Settling Pond and Biological Treatment
Systems at Roxboro
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
Table 4-8 presents the pollutant concentrations associated with the effluent from the FGD
wastewater treatment systems for the plants that EPA sampled. For comparison, refer to Table
4-5 in Section 4.3 for the pollutant concentrations representing the influent to the FGD
wastewater treatment systems for these plants. Three of these plants operate chemical
precipitation systems (Big Bend, Homer City, and Mitchell), and one of these plants operates
both chemical precipitation and biological treatment stages (Belews Creek). The Widows Creek
plant operates only a settling pond system.
The Widows Creek FGD wastewater treatment system is a pond system that consisted of
three settling ponds at the time of sampling; however, during the two site visits prior to the
sampling episode, the plant was operating four settling ponds. The FGD scrubber blowdown is
pumped to the inlet channels of the pond system, which direct the wastewater to the first FGD
settling pond. The overflow from the first FGD settling pond is transferred to a second FGD
settling pond and then to a final FGD settling pond. The overflow from the final settling pond is
then discharged from the plant. EPA collected a grab sample of the effluent from the third
settling pond. [ERG, 2008o].
The Big Bend FGD wastewater treatment system consists of an equalization tank
followed by a chemical precipitation system to reduce dissolved metals using lime for hydroxide
precipitation and ferric chloride for coagulation and iron co-precipitation. The plant then adds a
flocculating polymer to the wastewater and transfers it to a clarifier to remove the solids. The
overflow from the clarifiers is filtered using sand gravity filters, transferred to a final holding
tank, and then discharged. EPA collected a grab sample of the effluent downstream of the final
hoi ding tank. [ERG, 2008n].
The Homer City FGD wastewater treatment system consists of an equalization tank
followed by a chemical precipitation system to reduce dissolved metals using lime for hydroxide
precipitation, ferric chloride for coagulation and iron co-precipitation, and a clarifier for solids
removal. The FGD wastewater is sent through a first stage of lime and ferric chloride
precipitation followed by a clarifier, and the wastewater is then treated in a second stage of lime
and ferric chloride precipitation followed by a clarifier. After the second clarifier, the wastewater
is transferred to an aerobic biological treatment system designed to remove BOD. After the
aerobic biological system, the wastewater is filtered, transferred to a final holding tank, and
discharged. EPA collected a grab sample of the effluent directly from the final holding tank.
[ERG, 20081].
The Mitchell FGD wastewater treatment system consists of a chemical precipitation
system to reduce dissolved metals using lime for hydroxide precipitation followed by a clarifier
for solids removal. The overflow from the clarifier is transferred to an equalization tank, where
treated effluent is recycled by the plant when the system is not discharging. After the
equalization tank, the plant uses ferric chloride for iron co-precipitation and then adds an anionic
polymer and transfers the wastewater to a second clarifier. The overflow from the second
clarifier is transferred to a final holding tank and either transferred to the bottom ash pond and
eventually discharged or recycled back to the equalization tank. EPA collected a grab sample of
the effluent from the discharge line of the final holding tank. [ERG, 2008m].
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Table 4-8. Pollutant Concentrations in Sampled Effluent from FGD Wastewater Treatment Systems
Analyte
Method
Unit
Settling Pond
Widows Creek —
Effluent from FGD
Pond System "•"
Chemical Precipitation
Big Bend ab
Homer1"'
Mitchell "•"
Belews Creek bc
Anoxic/Anaerobic
Biological
Belews Creek1"1
Routine Total Metals - 200.7
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Sodium
Thallium
Titanium
Vanadium
Yttrium
Zinc
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
245.1
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
ug/L
ug/L
ug/L
ug/L
Ug/L
ug/L
ug/L
ug/L
Ug/L
Ug/L
Ug/L
ug/L
ug/L
ug/L
Ug/L
Ug/L
Ug/L
Ug/L
ug/L
ug/L
ug/L
Ug/L
Ug/L
Ug/L
ug/L
ug/L
111
ND (20.0)
49.5
179
ND (5.00)
31,500
ND (5.00)
987,000
ND(IO.O)
ND (50.0)
ND(IO.O)
ND(IOO)
ND (50.0)
189,000
623
ND (2.00)
1,500
ND (50.0)
236
ND (20.0)
69,500
ND(IO.O)
ND(IO.O)
42.1
ND (5.00)
ND(IO.O)
ND (50.0)
22.1 R
ND(IO.O)
1,490
ND (5.00)
369,000
24.9
4,420,000
ND(IO.O)
ND (50.0)
<10.3
ND(IOO)
ND (50.0)
2,510,000
60.1
ND(IO.O)
450 R
221
2,910 R
ND (20.0)
1,590,000
16.8
13.5
ND (20.0)
ND (5.00)
ND(IO.O)
ND (50.0)
<20.8
ND (10.0)
71.3 R
7.68
191,000
ND (5.00)
2,000,000
ND(IO.O)
ND (50.0)
12.5
<117
ND (50.0)
2,610,000
30,100
ND (10.0)
37.6
ND (50.0)
771
ND (20.0)
1,280,000
ND (10.0)
ND (10.0)
ND (20.0)
ND (5.00)
ND (10.0)
ND (50.0)
ND (20.0)
<10.3
433
ND (5.00)
208,000
ND (5.00)
2,380,000
ND(IO.O)
ND (50.0)
16.2
318
ND (50.0)
1,280,000
4,440
ND(IO.O)
22.9
ND (50.0)
83.6 R
ND (20.0)
305,000
ND(IO.O)
<10.1
ND (20.0)
ND (5.00)
25.4
ND (50.0)
ND (4.00)
ND (2.00)
326
ND (1.00)
291,000
ND (0.250)
5,670,000
25.3
ND(2.50)
ND(2.50)
ND (25.0)
ND(1.50)
983,000
3,280
NA
NA
21.1
82.5
7.90
60,300
62.5
NA
2.10
NA
ND (25.0)
ND (50.0)
ND (4.00)
ND (2.00)
296 R
ND (1.00)
283,000 R
ND (0.250)
5,570,000
24.2 R
ND(2.50)
ND(2.50)
ND (25.0)
ND(1.50)
950,000
2,340 R
NA
NA
ND (1.00)
ND (5.00)
7.75
58,900
52.7 R
NA
ND (0.500)
NA
ND (25.0)
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Table 4-8. Pollutant Concentrations in Sampled Effluent from FGD Wastewater Treatment Systems
Analyte
Method
Unit
Settling Pond
Widows Creek —
Effluent from FGD
Pond System "•"
Chemical Precipitation
Big Bend ab
Homer1"'
Mitchell "•"
Belews Creek bc
Anoxic/Anaerobic
Biological
Belews Creek1"1
Routine Dissolved Metals - 200.7
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Hexavalent Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Sodium
Thallium
Titanium
Vanadium
Yttrium
Zinc
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
D1687-92
200.7
200.7
200.7
200.7
200.7
200.7
245.1
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
ug/L
ug/L
ug/L
ug/L
Ug/L
ug/L
ug/L
ug/L
Ug/L
Ug/L
Ug/L
ug/L
ug/L
ug/L
Ug/L
Ug/L
Ug/L
Ug/L
ug/L
ug/L
ug/L
Ug/L
Ug/L
Ug/L
ug/L
ug/L
ug/L
ND (50.0)
ND (20.0)
46.7
191
ND (5.00)
29,200
ND (5.00)
932,000
ND(IO.O)
ND (2.00)
ND (50.0)
ND(IO.O)
ND(IOO)
ND (50.0)
184,000
543 R
ND (2.00)
1,470
ND (50.0)
226
ND (20.0)
66,200
ND(IO.O)
ND(IO.O)
40.0
ND (5.00)
ND(IO.O)
ND (50.0)
20.8 T
10.8 R,T
1,410
ND (5.00)
397,000
19.3
5,210,000
ND(IO.O)
ND (2.00)
ND (50.0)
ND(IO.O)
ND(IOO)
ND (50.0)
2,930,000
55.6
ND(IO.O)
430 T
210
2,860 R
ND (20.0)
1,880,000
12.5
13.7
ND (20.0)
ND (5.00)
ND(IO.O)
ND (50.0)
ND (20.0)
ND (10.0)
70.6 R,T
7.71
184,000
ND (5.00)
1,930,000
ND (10.0)
ND (2.00)
ND (50.0)
11.8
166 R
ND (50.0)
2,510,000
29,100
ND (10.0)
35.8
ND (50.0)
741 R
ND (20.0)
1,230,000
ND (10.0)
ND(IO.O)
ND (20.0)
ND (5.00)
ND (10.0)
ND (50.0)
ND (20.0)
ND (10.0)
389
ND (5.00)
199,000
ND (5.00)
2,270,000
ND (10.0)
11.0
ND (50.0)
14.1
ND (100)
ND (50.0)
1,220,000
4,120
ND(IO.O)
21.4
ND (50.0)
71.7
ND (20.0)
300,000
ND(IO.O)
ND(IO.O)
ND (20.0)
ND (5.00)
ND (10.0)
97.0 L
4.50
6.40 L
270
ND (1.00)
306,000
2.30
5,790,000
ND (0.500)
1.57
ND(2.50)
ND(2.50)
ND (25.0)
ND(1.50)
970,000
3,240
NA
NA
28.2
58.7
7.70
59,300
105
NA
2.50
NA
ND (25.0)
<78.5 L
ND (4.00)
8.70 L,R
271 R
ND (1.00)
284,000 R
<0.875
5,760,000
<10.7 R
ND (0.500)
ND(2.50)
ND(2.50)
<27.9
ND(1.50)
938,000
2,310
NA
NA
<2.15
ND (5.00)
8.10
58,500
120 R
NA
0.665 R
NA
ND (25.0)
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
Table 4-8. Pollutant Concentrations in Sampled Effluent from FGD Wastewater Treatment Systems
Analyte
Method
Unit
Settling Pond
Widows Creek —
Effluent from FGD
Pond System "•"
Chemical Precipitation
Big Bend ab
Homer1"'
Mitchell ab
Belews Creek bc
Anoxic/Anaerobic
Biological
Belews Creek1"1
Routine Total Metals - 200.8
Aluminum
Antimony
Arsenic
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Chromium
Cobalt
Copper
Iron
Iron
Lead
Magnesium
Manganese
Manganese
Nickel
Nickel
Selenium
Selenium
Sodium
Thallium
Vanadium
Vanadium
200.8
200.8
200.8
200.8 -DRC
200.8
200.8
200.8
200.8
200.8
200.8
200.8 -DRC
200.8
200.8
200.8
200.8 -DRC
200.8
200.8
200.8
200.8 -DRC
200.8
200.8 -DRC
200.8
200.8 -DRC
200.8
200.8
200.8
200.8 -DRC
ug/L
ug/L
ug/L
ug/L
Ug/L
ug/L
ug/L
ug/L
Ug/L
Ug/L
Ug/L
ug/L
ug/L
ug/L
Ug/L
Ug/L
Ug/L
Ug/L
ug/L
ug/L
ug/L
Ug/L
Ug/L
Ug/L
ug/L
ug/L
ug/L
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
61.6
3.60
200
6.94
465
ND (0.300)
260,000
1.77
4,920,000
13.7
0.855
17.4
2.13
173
ND (50.0)
ND (0.200)
973,000
3,110
3,330
159
72.9
1,120
313
48,200
7.03
113
3.67
67.2 R
0.465
194
5.47
466 R
ND (0.300)
250,000 R
0.360 R
5,030,000
9.25
ND (0.500)
12.1
1.08
165
66.9
ND (0.200)
998,000
2,240
2,350 R
102
11.5 R
803
159 R
50,000 R
ND (0.0250)
154
<1.93
4-59
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
Table 4-8. Pollutant Concentrations in Sampled Effluent from FGD Wastewater Treatment Systems
Analyte
Zinc
Zinc
Method
200.8
200.8 -DRC
Unit
ug/L
ug/L
Settling Pond
Widows Creek —
Effluent from FGD
Pond System "•"
NA
NA
Chemical Precipitation
Big Bend ab
NA
NA
Homer1"'
NA
NA
Mitchell ab
NA
NA
Belews Creek bc
5.87
ND (2.00)
Anoxic/Anaerobic
Biological
Belews Creek1"1
5.89
ND (2.00)
Routine Dissolved Metals - 200.8
Aluminum
Antimony
Arsenic
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Chromium
Cobalt
Copper
Iron
Iron
Lead
Magnesium
Manganese
Manganese
Nickel
Nickel
Selenium
Selenium
Sodium
Thallium
200.8
200.8
200.8
200.8 -DRC
200.8
200.8
200.8
200.8
200.8
200.8
200.8 -DRC
200.8
200.8
200.8
200.8 -DRC
200.8
200.8
200.8
200.8 -DRC
200.8
200.8 -DRC
200.8
200.8 -DRC
200.8
200.8
Ug/L
Ug/L
Ug/L
ug/L
ug/L
ug/L
Ug/L
Ug/L
Ug/L
ug/L
ug/L
ug/L
Ug/L
Ug/L
Ug/L
Ug/L
ug/L
ug/L
ug/L
Ug/L
Ug/L
Ug/L
ug/L
ug/L
ug/L
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
51.8
3.69
194
8.15
457
ND (0.300)
261,000
1.66
5,050,000
13.4
0.775
17.9
2.20
151
ND (50.0)
ND (0.200)
1,010,000
3,080
3,140
158
74.2
1,110
281
48,700
7.04
58.7
0.430
205
4.15
459
ND (0.300)
238,000 R
0.250 R
4,730,000
6.93
ND (0.500)
12.2
ND(l.OO)
138
59.7
ND (0.200)
960,000
2,250
2,300 R
104
10.9
711
151
47,100 R
ND (0.0250)
4-60
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
Table 4-8. Pollutant Concentrations in Sampled Effluent from FGD Wastewater Treatment Systems
Analyte
Vanadium
Vanadium
Zinc
Zinc
Method
200.8
200.8 -DRC
200.8
200.8 -DRC
Unit
ug/L
ug/L
ug/L
Ug/L
Settling Pond
Widows Creek —
Effluent from FGD
Pond System "•"
NA
NA
NA
NA
Chemical Precipitation
Big Bend ab
NA
NA
NA
NA
Homer1"'
NA
NA
NA
NA
Mitchell "•"
NA
NA
NA
NA
Belews Creek bc
131
4.66
6.23
ND (2.00)
Anoxic/Anaerobic
Biological
Belews Creek1"1
148
ND(l.OO)
5.81
ND (2.00)
Low-Level Total Metals - 1631E, 1638, HG-AFS
Antimony
Arsenic
Arsenic
Arsenic
Cadmium
Chromium
Chromium
Copper
Lead
Mercury
Nickel
Nickel
Selenium
Selenium
Selenium
Thallium
Zinc
Zinc
1638
1638
1638 -DRC
HG-AFS
1638
1638
1638 -DRC
1638
1638
1631E
1638
1638 -DRC
1638
1638 -DRC
HG-AFS
1638
1638
1638 -DRC
Ug/L
Ug/L
ug/L
ug/L
Ug/L
Ug/L
Ug/L
Ug/L
Ug/L
ug/L
Ug/L
Ug/L
Ug/L
Ug/L
Ug/L
ug/L
ug/L
Ug/L
11.8
47.6
NA
NA
3.73
ND(16.0)
NA
ND (4.00)
ND(l.OO)
0.0438
36.2
NA
208
NA
NA
11.1
ND(IO.O)
NA
14.2
68.0
NA
NA
25.8
ND (80.0)
NA
ND (20.0)
ND (5.00)
0.156
381
NA
2,500
NA
NA
31.1
ND (50.0)
NA
ND (0.400)
23.0
NA
NA
ND (2.00)
ND(16.0)
NA
9.67
ND (1.00)
0.117
92.1
NA
613
NA
NA
16.0
15.2
NA
<1.37
<25.2
NA
NA
ND (3.00)
ND(120)
NA
ND (30.0)
ND(1.50)
0.788
<155
NA
431 T
NA
NA
3.96
<83.5
NA
3.75
197
4.86
2.27
1.51
6.06
0.610
2.13
ND (0.200)
0.0765
113
54.3
616
300
139
8.43
6.24
ND (2.00)
0.545
202
2.51
0.247
0.230
5.37
ND (0.500)
ND (1.00)
ND (0.200)
0.0133
97.1
9.00
581
191
4.93
ND (0.0250)
4.87
ND (2.00)
Low-Level Dissolved Metals - 1631E, 1636, 1638, HG-AFS
Antimony
Arsenic
Arsenic
Arsenic
1638
1638
1638 -DRC
HG-AFS
Ug/L
Ug/L
ug/L
ug/L
11.9
46.5
NA
NA
13.7
72.4
NA
NA
ND (0.400)
22.5
NA
NA
1.64
20.9 T
NA
NA
3.73
196
5.79
2.12
0.545
199
2.63
0.227
4-61
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
Table 4-8. Pollutant Concentrations in Sampled Effluent from FGD Wastewater Treatment Systems
Analyte
Cadmium
Chromium
Chromium
Hexavalent Chromium
Copper
Lead
Mercury
Nickel
Nickel
Selenium
Selenium
Selenium
Thallium
Zinc
Zinc
Method
1638
1638
1638 -DRC
1636
1638
1638
1631E
1638
1638 -DRC
1638
1638 -DRC
HG-AFS
1638
1638
1638 -DRC
Unit
ug/L
ug/L
ug/L
Ug/L
Ug/L
Ug/L
ug/L
ug/L
ug/L
Ug/L
Ug/L
Ug/L
ug/L
ug/L
ug/L
Settling Pond
Widows Creek —
Effluent from FGD
Pond System "•"
3.74
ND(16.0)
NA
3.20
ND (4.00)
ND(l.OO)
0.0107
33.3 L
NA
293
NA
NA
11.0
ND(IO.O)
NA
Chemical Precipitation
Big Bend ab
22.2
ND (80.0)
NA
ND (5.00)
ND (20.0)
ND (5.00)
0.0688
396
NA
2,560
NA
NA
31.5
ND (50.0)
NA
Homer1"'
ND (2.00)
ND(16.0)
NA
ND(2.50)
9.39
ND (1.00)
0.0542
93.5
NA
620
NA
NA
15.8
15.7
NA
Mitchell "•"
ND(l.OO)
ND (80.0)
NA
ND(2.50)
ND (20.0)
ND (0.500)
0.159
102
NA
407
NA
NA
3.99
ND (50.0)
NA
Belews Creek bc
1.53
6.23
0.700
ND (0.500)
1.57
ND (0.200)
0.00804
84.4
43.8
651
305
137
8.55
4.40
ND (2.00)
Anoxic/Anaerobic
Biological
Belews Creek1"1
0.210
5.16
ND (0.500)
ND (0.500)
ND (1.00)
ND (0.200)
<0.00168
96.2
10.1
564
194
2.67
ND (0.0250)
4.93
ND (2.00)
Classicals
Ammonia As Nitrogen (NH3-N)
Nitrate/Nitrite (NO3-N + NO2-N)
Total Kjeldahl Nitrogen (TKN)
Biochemical Oxygen Demand (BOD)
Chemical Oxygen Demand (COD)
Chloride
Hexane Extractable Material (HEM)
Silica Gel Treated HEM (SGT-HEM)
Sulfate
4500-NH3F
353.2
4500-N,C
5210B
4500-CL-C
1664A
1664A
D5 16-90
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
0.220
0.0945
2.51
<10.0
NA
1,120
ND (5.00)
NA
2,060
24.1
NA
98.7
> 1,720
NA
22,500
6.00
ND (6.00)
1,920
0.295
36.5 R
3.04
ND (120)
NA
11,800
ND (5.00)
NA
2,790
3.49
25.4
9.74
<7.50
NA
6,700
5.00
ND (4.00)
1,770
1.80
14.0
4.05
ND (4.00)
501
9,720
ND (5.00)
ND (5.00)
1,210
2.73
ND (0.100)
5.77
9
451
9,960
ND (5.00)
ND (5.00)
1,240
4-62
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
Table 4-8. Pollutant Concentrations in Sampled Effluent from FGD Wastewater Treatment Systems
Analyte
Total Dissolved Solids (IDS)
Total Phosphorus
Total Suspended Solids (TSS)
Method
2540 C
365.3
2540 D
Unit
mg/L
mg/L
mg/L
Settling Pond
Widows Creek —
Effluent from FGD
Pond System "•"
5,830
0.0115 E
8.00 E
Chemical Precipitation
Big Bend ab
40,600
0.355
31.5
Homer1"'
22,600
0.520
<5.50
Mitchell ab
17,700
0.0745
17.5
Belews Creek bc
34,000
ND (0.100)
30.0
Anoxic/Anaerobic
Biological
Belews Creek1"1
33,800
ND (0.100)
21.3
Source: [ERG, 20081; ERG, 2008m; ERG, 2008n; ERG, 2008o; ERG, 2009q].
Note: EPA used several analytical methods to analyze for metals during the sampling program. For the purposes of sampling program, EPA designated some of the analytical methods as "routine" and
some of them as "low-level." EPA designated all of the methods that require the use of clean hands/dirty hands sample collection techniques (i.e., EPA Method 1669 sample collection techniques) as
"low-level" methods. Note that although not required by the analytical method, EPA used clean hands/dirty hands collection techniques for all low-level and routine metals samples.
a - The FGD effluent results represent the average of the FGD effluent and the duplicate of the FGD effluent analytical measurements.
b - The concentrations presented have been rounded to three significant figures.
c - The FGD chemical precipitation effluent results represent the average of the FGD chemical precipitation effluent day 1 and FGD chemical precipitation effluent day 2 measurements, if the analyte
was collected on both days of sample collection.
d - The FGD effluent results represent the average of the FGD effluent day 1, the FGD effluent day 2, and the duplicate of the FGD effluent analytical measurements, if all three measurements were
collected for the analyte. Otherwise, it represents the average of the FGD effluent day 1 and the duplicate of the FGD effluent analytical measurements.
< - Average result includes at least one nondetect value (calculation uses the report limit for nondetected results).
> - Result above measurement range.
E - Sample analyzed outside holding time.
L - Sample result between 5x and lOx blank result.
R - MS/MSD % Recovery outside method acceptance criteria.
T - MS/MSD RPD outside method acceptance criteria.
NA - Not analyzed.
ND - Not detected (number in parenthesis is the report limit). The sampling episode reports for each of the individual plants contains additional sampling information, including analytical results for
analytes measured above the detection limit, but below the reporting limit (i.e., J-values).
4-63
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
The Belews Creek FGD wastewater treatment system consists of an equalization tank,
chemical precipitation system, clarifier, anoxic/anaerobic biological treatment system, and
constructed wetland23. EPA collected grab samples of the effluents from the chemical
precipitation and biological treatment stages. [ERG, 2009q].
Table 4-9 through Table 4-11 summarize the monitoring data EPA collected from
individual plants/companies representing the effluent from settling ponds, effluent from chemical
precipitation systems, and the effluent from anoxic/anaerobic biological treatment systems,
respectively. The tables present the number of plants that reported concentration data for the
analyte at the given effluent point, the total number of samples at the point for all the plants, and
the minimum and maximum concentrations. Because the data included in these tables were
provided by individual plants and the plants may monitor different analytes, the data presented in
each table do not necessarily contain the same list of analytes [ERG, 2009x].
Table 4-9. Monitoring Data: Pollutant Concentrations in Effluent from Settling Ponds
Analyte
Number of
Plants
Number of
Samples
Minimum
Concentration
Maximum
Concentration a
Units
Total Metals
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Chromium
Cobalt
Copper
Iron
Lead
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Thallium
Vanadium
Zinc
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
37
37
37
37
37
37
37
37
37
37
37
37
37
36
37
37
37
37
37
37
37
ND (50)
ND(2)
6.4
37.5
ND (0.7)
7,950
ND (0.5)
ND (0.61)
ND(l.l)
ND (1.6)
ND(20)
ND(1.9)
ND(ll)
ND(O.ll)
ND(O.ll)
11.5
1,180
ND (0.2)
ND (0.2)
ND (0.36)
ND (3.8)
632
36
201
528
1.02
108,000
6.11
2,110
36
44.4
13,000
ND (220)
3,210
7.32
47
2,190
2,740
30
102
285
136
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
23 At the time sampling was conducted, Belews Creek was transferring the effluent from the biological treatment
system to the constructed wetland treatment system (CWTS); however, Belews Creek plans to reroute the biological
treatment effluent to bypass the CWTS and be transferred directly to the ash pond.
4-64
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
Table 4-9. Monitoring Data: Pollutant Concentrations in Effluent from Settling Ponds
Analyte
Number of
Plants
Number of
Samples
Minimum
Concentration
Maximum
Concentration a
Units
Classical*
COD
TSS
TDS
Sulfate
Chloride
Fluoride
Nitrate/nitrite
Total Kjeldahl nitrogen
Total Phosphorus
1
1
1
1
1
1
1
1
1
33
36
36
34
36
36
1
1
1
120
2.60
9,600
1,100
3,600
6.30
12.0
1.20
ND (0.050)
370
53.0
12,000
1,300
5,300
10.0
12.0
1.20
ND (0.050)
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
Source: [ERG, 2009x].
a - The maximum concentration presented is the maximum detected value in the data set, unless all the results in the
data set were not detected for the analyte.
Table 4-10. Monitoring Data: Pollutant Concentrations in Effluent from Chemical
Precipitation Systems
Analyte
Number of
Plants
Number of
Samples
Minimum
Concentration
Maximum
Concentration a
Units
Total Metals
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Sodium
1
2
5
1
o
5
2
3
1
4
1
4
o
6
4
2
2
5
1
5
6
3
2
1
8
101
1
52
7
18
7
48
1
50
16
47
8
7
275
1
66
398
17
7
183
3.7
1.6
1,520
ND (0.03)
17,000
0.07
670,000
0.12
ND(10)
1.3
19
ND (0.07)
ND (3,000)
ND(10)
0.0019
63
4.7
16
0.02
1,000,000
183
28
310
1,520
0.94
474,000
21.9
790,000
69
ND(10)
71
6,000
11
9,200,000
63,000
61
63
810
18,000
1.64
1,700,000
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
4-65
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
Table 4-10. Monitoring Data: Pollutant Concentrations in Effluent from Chemical
Precipitation Systems
Analyte
Thallium
Tin
Titanium
Vanadium
Zinc
Number of
Plants
1
1
1
1
4
Number of
Samples
1
1
1
1
35
Minimum
Concentration
ND(10)
ND(50)
ND(50)
ND(10)
1.7
Maximum
Concentration a
ND(10)
ND(50)
ND(50)
ND(10)
15
Units
ug/L
ug/L
ug/L
ug/L
ug/L
Dissolved Metals
Antimony
Arsenic
Beryllium
Boron
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Nickel
Selenium
Silver
Sodium
Zinc
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
6
23
19
4
3
5
6
6
5
4
6
6
195
6
25
4
5
5
4
ND (2.4)
ND(0.19)
17,000
0.74
660,000
12
11
ND (32)
ND (0.6)
6,200,000
42,000
0.032
170
62
0.61
1,100,000
7.7
6
240
0.94
22,000
0.74
710,000
27
36
ND (8,800)
5.2
7,400,000
62,000
54
810
4,300
1.9
1,300,000
17
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
Classicals
TSS
TDS
Sulfate
Chloride
Bromide
Fluoride
NH3-N
Total Nitrogen, as N
HEM
n-Hexane
1
1
2
2
1
1
2
1
1
1
10
16
9
21
4
8
27
30
6
29
3.93
12,000
930
4,700
180
0.91
2.30
2.05
ND (5.00)
ND (1.40)
33
23,000
24,000
20,500
260
8.60
65.6
165
ND (5.00)
2.70
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
Source: [ERG, 2009x].
a - The maximum concentration presented is the maximum detected value in the data set, unless all the results in the
data set were not detected for the analyte.
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Chapter 4 - Flue Gas Desulfurization Systems
Table 4-11. Monitoring Data: Pollutant Concentrations in Effluent from Biological
Treatment Systems
Analyte
Number of
Plants
Number of
Samples
Minimum
Concentration
Maximum
Concentration a
Units
Total Metals
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Chromium
Cobalt
Copper
Iron
Lead
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Thallium
Vanadium
Zinc
1
1
2
1
1
2
1
1
1
1
1
1
1
2
1
2
2
1
1
1
2
37
37
53
37
37
38
37
37
37
37
37
37
37
51
37
53
53
37
37
37
53
ND(32)
ND(2)
ND(10)
26.2
ND (0.7)
7,820
ND (0.5)
ND(1)
ND(l.l)
ND (1.6)
ND (22)
ND(1.9)
52
ND (0.001)
ND(2)
ND (1.8)
ND(10)
ND (0.2)
ND (0.36)
ND(1)
ND(1)
602
92
93
2,440
1.89
666,000
3.57
4,020
241
628
23,000
291
3,170
0.3
192
3,770
510
36
97
293
432
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
Dissolved Metals
Selenium
1
16
ND(10)
18
ug/L
Classicals
COD
TSS
TDS
Sulfate
Chloride
Fluoride
NO3-N + NO2-N
TKN
Total Phosphorus
1
1
2
2
1
1
1
1
1
33
36
52
39
36
36
1
1
1
120
1.10
2,500
970
3,800
5.30
0.056
2.70
0.160
380
12.0
23,000
1,300
5,100
11.0
0.056
2.70
0.160
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
Source: [ERG, 2009x].
a - The maximum concentration presented is the maximum detected value in the data set, unless all the results in the
data set were not detected for the analyte.
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
4.6 FGD Pollutant Loads Estimates
As discussed in Section 4.2, wet FGD systems need to prevent the buildup of certain
constituents (e.g., chlorides), which is often accomplished by purging a wastewater stream.
Because of the corrosivity of chlorides, plants do not typically reuse the FGD wastewater for
other process operations and will typically discharge the FGD purge stream.
EPA used data collected during EPA's sampling program, as well as self-monitoring data
obtained from individual plants, to estimate the mass of pollutants (pollutant loads) associated
with the FGD scrubber purge (prior to treatment) and the effluent associated with four treatment
alternatives: settling ponds; chemical precipitation; biological treatment; and
evaporation/crystallization. EPA estimated these loads for two model plant sizes, which are
discussed further below. EPA then used these model plant loads to estimate industry-wide total
pollutant loads for FGD wastewaters being discharged from the coal-fired steam electric
industry. EPA also estimated the pollutant removals that would be achieved by the industry
through installing or upgrading existing FGD wastewater controls.
4.6.1 FGD Wastewater Treatment Industry Profile
To estimate FGD wastewater loads for the entire steam electric industry, EPA developed
an industry profile and determined the number of coal-fired power plants that currently operate
wet or dry scrubbers (as of June 2008), and the number of plants that are planning or projected to
install wet or dry scrubbers by 2020.
To generate this industry profile, EPA used EIA data to identify power plants that operate
at least one coal-fired electric generating unit. From the available information, EPA identified
488 coal-fired power plants that are currently operating a coal-fired generating unit as well as
three additional plants that are either planning or constructing a coal-fired generating unit. For
each of these 491 plants, EPA then determined whether the plant currently operates a wet or dry
scrubber (as of June 2008) and whether the plant has announced plans or is projected to install a
scrubber by 2020. EPA additionally used information from the site visit and sampling program,
the data request, and other publicly available information to identify the wastewater treatment
systems that the plants operate to treat the FGD wastewater stream. If EPA did not have
information to identify the type of FGD wastewater treatment system for the plant, EPA assumed
that the plant operates a settling pond, which is the most commonly used FGD wastewater
treatment system.
As part of this industry profile and for estimating the pollutant loads, EPA also classified
the plants into one of two model plant sizes, "small" or "large," based on the FGD purge flow
rate and the necessary treatment system capacity. For those plants for which purge flow rate is
unknown, EPA classified the plants based on the total wet scrubbed capacity of the plant (i.e., the
total capacity of the electric generating units that are wet scrubbed).
EPA used these model plants to better estimate the loads associated with the industry, by
grouping the plants into two different sizes instead of assuming that all plants in the industry are
the same size. The data and methodologies used to generate the FGD wastewater treatment
industry profile are discussed in detail in the memorandum entitled "Development of the Current
and Future Industry Profile for the Steam Electric Detailed Study," dated October 9, 2009 [ERG,
2009s].
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Final Detailed Study Report Chapter 4 - Flue Gas Desulfurization Systems
For each model plant size, EPA calculated a flow rate to use in the loads calculation for
each of the model plants. The memorandum entitled "Technology Option Loads Calculation
Analysis for Steam Electric Detailed Study," dated October 9, 2009 [ERG, 2009t], describes in
detail the calculation of the model plant flow rates.
4.6.2 Calculation of Loads
EPA used data collected during EPA's sampling program and monitoring data obtained
from individual plants to calculate loads associated with the FGD wastewater discharges from
coal-fired power plants. EPA calculated these loads to evaluate the effectiveness of the FGD
wastewater treatment systems
To calculate pollutant loads associated with the FGD scrubber purge, EPA calculated
plant-specific loads to account for differences in the FGD system configurations and operating
characteristics at the plants. EPA first calculated the scrubber purge loads on a plant basis using
data from the four plants for which EPA had both scrubber purge concentrations and scrubber
purge flow rate data available. After calculating the plant-specific loads for each of these plants,
EPA calculated an average load for each pollutant and an average flow rate associated with the
load for each pollutant. EPA then divided the average pollutant load by the average flow rate to
calculate a weighted-average concentration for each pollutant.
To calculate pollutant loads associated with FGD settling pond effluent, EPA used data
representing the effluent from a settling pond treating FGD scrubber purge from all the plants for
which EPA had available data. For some plants, EPA estimated the settling pond effluent
concentrations based on scrubber purge concentrations obtained during EPA's sampling
program. The assumptions used to estimate the settling pond effluent concentrations are
described in the memorandum entitled "Technology Option Loads Calculation Analysis for
Steam Electric Detailed Study," dated October 9, 2009 [ERG, 2009t]. EPA used the settling pond
effluent concentration data from all the plants for which data were available to determine an
average concentration for each pollutant.
To calculate the effluent pollutant loads for the chemical precipitation and biological
treatment technologies, EPA used effluent concentration data from plants that represent these
treatment technologies. The effluent data from these plants were used to determine an average
concentration for each pollutant. For the evaporation/crystallization treatment technology, EPA
assumed the effluent pollutant loads were equal to zero.
After calculating these average pollutant concentrations, EPA multiplied the
concentrations by the "small" and "large" model plant flow rates to determine the individual
pollutant loads for the FGD scrubber purge, settling pond effluent, and effluent from each of the
treatment technologies for both a "small" and a "large" model plant. EPA then multiplied the
loads by each pollutant's individual toxic weighting factor (TWF) to calculate the toxic-weighted
pound equivalent (TWPE) for each pollutant. Because the TWPE accounts for each pollutant's
toxicity, it allows for a relative comparison of the pollutant discharges. Finally, EPA summed the
individual pollutant TWPE to calculate the total TWPE for the FGD scrubber purge, settling
pond effluent, and effluent from each of the treatment technologies for each model plant size.
Table 4-12 presents EPA's model plant loads, in TWPE per year, for the FGD scrubber
purge, settling pond effluent, and effluent from each of the treatment technologies. The
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Final Detailed Study Report
Chapter 4 - Flue Gas Desulfurization Systems
memorandum entitled "Technology Option Loads Calculation Analysis for Steam Electric
Detailed Study," dated October 9, 2009 [ERG, 2009t], describes the data and methodology used
to calculate pollutant loads.
Table 4-12. Treatment Technology Loads by Model Plant Size
Waste Stream/Treatment System
FGD Scrubber Purge (prior to treatment)
Settling Pond
Chemical Precipitation
Chemical Precipitation + Biological Treatment
Chemical Precipitation + Evaporation
Small Model Plant Loads
(TWPE/Year)
28,400
10,900
6,410
2,650
0
Large Model Plant Loads
(TWPE/Year)
97,300
37,300
22,000
9,080
0
Source: [ERG, 2009t].
4.6.3 Industry Baseline and Treatment Technology Loads
EPA used the FGD wastewater treatment industry profile information (see Section 4.6.1)
and the model plant treatment technology loads (see Section 4.6.2) to estimate the FGD
discharge loads associated with the steam electric industry. EPA calculated the loads for the
"current" industry, based on the status of FGD operations as of June 2008, and the "future"
industry, based on projections of FGD operations in 2020. EPA estimated the baseline loads for
the industry by multiplying the model plant loads for each treatment scenario by the number of
small and large plants operating that treatment system. If EPA lacked treatment information for a
plant, EPA assumed the plant currently operates or will operate a settling pond treatment system.
Based on information in EPA's combined data set, 108 plants are currently operating wet
FGD systems and EPA estimates that 77 of these plants discharge FGD wastewater. EPA also
estimates that more than 192 plants will be operating wet FGD scrubbers by 2020 and that 158 of
these plants will discharge FGD wastewater.
24
EPA estimated the industry loads for the FGD scrubber purge, settling pond effluent, and
the three control technologies by multiplying the model plant loads by the number of plants
operating that treatment system. EPA then summed the resulting "small" and "large" model plant
TWPE to determine the total TWPE for each scenario. EPA calculated the baseline loads by
summing the total TWPE for the settling pond and three treatment technologies.
EPA also calculated industry-level loads that would result from plants installing or
upgrading to a particular level of treatment technology (i.e., the industry-level chemical
precipitation loads assume that all plants operating a settling pond will install a chemical
precipitation system and all other plants will continue operating with their current system).
Figure 4-14 presents a comparison of the total baseline industry effluent loads to the effluent
loads estimated for each of the different scenarios.
24 As discussed in section 4.1.2, EPA's projections for new FGD systems do not include the systems that will be
installed at new generating units or new plants. Thus, the projections for 2020 are considered to under-estimate the
actual number of FGD systems that will be installed.
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Chapter 4 - Flue Gas Desulfurization Systems
D Current • 2020 (Projected)
— 2,500,000
0
2,000,000
o
ra
1,500,000
« 1,000,000
5
500,000
UJ
Q
O
Baseline Chemical Chemical Chemical
Precipitation Precipitation and Precipitation and
Biological Evaporation
Treatment Scenario
Figure 4-14. Estimated Industry-Level FGD Effluent Discharge Loadings By Treatment
Scenario
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Final Detailed Study Report Chapter 5 - Coal Ash Handling Systems
5. COAL ASH HANDLING SYSTEMS
Combusting coal in steam electric boilers generates solid, noncombustible constituents of
the coal, referred to as ash. The heavier ash particles that collect on the bottom of the boiler are
referred to as bottom ash and may also be called slag. The finer ash particles that are light
enough to be transferred out of the boiler with the flue gas exhaust are referred to as fly ash.
Some of the particles that are initially carried with the flue gases collect in the economizer or air
preheater sections of the boiler. Depending on operations at the plant, this ash may be handled
along with either the fly ash or bottom ash.
This chapter presents an overview of fly ash and bottom ash handling systems at coal-
fired power plants within the steam electric industry, with particular emphasis on the
wastewaters generated from the process and the treatment of those wastewaters.
5.1 Fly Ash Handling Operations
To remove the fly ash particles from the flue gas at coal-fired power plants, many plants
operate electrostatic precipitators (ESPs). ESPs use high voltage to generate an electrical charge
on the particles contained in the flue gas. The charged particles then collect on a metal plate with
an opposite electric charge. Additionally, some plants may use agglomerating agents, such as
ammonia, which help small charged ash particles form larger agglomerates that are more readily
attracted to the charged plates, improving the removal efficiency of the ESPs. As the particles
begin to layer on the metal plates, the plates are tapped/rapped to loosen the particles, which fall
into collection hoppers. ESPs are the most common type of fly ash collection system used by the
steam electric industry, and the system can achieve removals of greater than 99.9 percent
[Babcock & Wilcox, 2005].
Plants may also use other particulate control technologies, such as baghouse filters. A
baghouse system contains several compartments, each containing fabric filter bags that are
suspended vertically in the compartment. The bags can be quite long (e.g., 40 feet) and small in
diameter [Babcock & Wilcox, 2005].
The reverse air system is the baghouse configuration most commonly used by steam
electric plants. In this system, the flue gas enters into the various compartments and is forced to
flow into the bottom of the fabric filter bags. The flue gas passes through the fabric filter
material, but the fly ash particulates cannot pass and are captured on the inside walls of the
baghouses. As the baghouses collect more parti culates, the layer of parti culates becomes thicker
and also helps to remove parti culates from the flue gas. After a specified period of time or once
the pressure drop in the baghouses reaches a high set point level, the plants reverse the flow in a
compartment and send clean flue gas from the outside of the fabric filter bags to the inside,
which dislodges the parti culates. The parti culates are captured in hoppers at the bottom of the
compartment [Babcock & Wilcox, 2005].
Additionally, some plants use venturi-type wet scrubbers to remove fly ash and 862
emissions. Venturi scrubbers contain a tube with flared ends and a constricted middle section.
The flue gas enters from one of the flared ends and approaches the constricted section. The liquid
slurry stream is added to the scrubber just prior to or at the constricted section. As the flue gas
enters the constricted section, its pressure increases and the velocity of the gas increases, which
causes the gas and liquid slurry to mix. The greater the pressure drop in the scrubber, the better
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Final Detailed Study Report Chapter 5 - Coal Ash Handling Systems
the mixing and the better the reaction rate, which increases the sulfur dioxide and particulate
removal efficiency. However, venturi scrubbers must be operated at high pressure drops to
remove the same level of particulates as ESPs, which results in higher operating expenses for
venturi scrubbers compared to ESPs. The scrubber blowdown from a venturi scrubber is handled
similarly to the FGD scrubber blowdown from other FGD operations, which are described in
Section 4.2 [Babcock & Wilcox, 2005; U.S. EPA, 2007b].
After the ESP or baghouse deposits the fly ash into the hoppers, the plant can either
handle the fly ash in a dry or wet fashion. In either system, dry fly ash is initially drawn away
from the hoppers using a vacuum to pneumatically transport the ash. Plants that operate a dry fly
ash handling system pneumatically transfer the fly ash from the hoppers to fly ash storage silos.
From the silos, the fly ash is loaded into trucks or rail cars and either hauled to a landfill for
disposal or hauled off site for beneficial use.
Plants operating a wet fly ash handling system also use vacuum to draw the fly ash away
from the hoppers, but this vacuum will typically be created by water flowing through an eductor.
These water jet eductors, also known as venture eductors, use the kinetic energy of the water to
create the vacuum for the dry portion of the ash handling system. The ash is pulled to a
separator/transfer tank, where it combines with the water flowing through the sluice pipes and is
transported to the ash pond. Plants usually have a sluice stream for each individual ESP or set of
hoppers, with the sluice water flowing continuously to maintain the necessary vacuum and
prevent solids from settling in the piping.
EPA compiled information regarding management techniques for fly ash and wastewater
treatment systems for fly ash transport water. Table 5-1 presents fly ash handling practices at
plants included in EPA's combined data set, which includes UWAG-provided data, site visits
and sampling data, and data request information. Approximately one-third of these plants handle
the majority of their fly ash wet. In addition to the combined data set, EPA identified 46
additional plants that operate wet fly ash handling systems through application data reported to
the NPDES permit program (also known as Form 2C data) [UWAG, 2008]. However, EPA was
unable to determine the number of generating units and capacity associated with these wet fly
ash handling operations; therefore, these plants are not included in Table 5-1. Nevertheless, these
data suggest that at least 80 plants are operating wet fly ash handling systems (34 plants in
combined data set plus 46 additional plants in the Form 2C database).
EPA also reviewed data recently collected by EPA's Office of Solid Waste and
Emergency Response (OSWER), which sent letters to power plants requiring that they report
certain information about waste management units used for the storage or disposal of coal
combustion residues. The OSWER database identifies 188 plants that are operating 398 surface
impoundments containing fly ash. Sixty-four of these ponds contain only fly ash; the remainder
also contain bottom ash (212 ponds), FGD wastes (14 ponds), or both (108 ponds) [Schroeder,
2009].
More plants in the combined data set operate wet bottom ash handling systems than wet
fly ash handling systems. Fewer wet fly ash systems are expected because the NSPS
promulgated in 1982 prohibit the discharge of wastewater pollutants from fly ash transport water.
Not surprisingly, EPA has found that the steam electric units generating wet fly ash transport
water tend to be older units, while dry ash handling systems tend to be operated on newer units.
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Final Detailed Study Report
Chapter 5 - Coal Ash Handling Systems
EPA identified several plants that have installed dry fly ash handling systems, either to
replace the pre-existing wet handling system or to operate as a parallel system. The reasons for
installing the dry handling systems include environmental remediation (i.e., discharges from the
fly ash ponds caused environmental impacts), economic opportunity (e.g., revenues from sale of
fly ash), and the need to replace ash ponds approaching full storage capacity. Because dry fly ash
handling practices do not generate wastewater streams, converting to a dry system eliminates the
discharge of fly ash transport water and the pollutants typically present in the wastewater (e.g.,
arsenic, mercury, and selenium). In addition, it reduces the amount of water used by the plant
and eliminates the need for the fly ash pond.
Table 5-1. Fly Ash Handling Practices at Plants Included in EPA's Combined Data Set
Fly Ash Handling
Wet-Sluiced
Handled Dry or Removed in Scrubber
Other - Most Ash Handled Dry or Unknown
Total
Number of Plants a
34 (35%)
63 (65%)
7 (7%)
97
Number of Electric
Generating Units b
95 (40%)
128 (54%)
14 (6%)
237
Capacity c
(MW)
38,300 (33%)
73,600 (63%)
4,950 (4%)
117,000
Source: Combined Data Set (defined in Chapter 4).
a - Number of plants is not additive because some plants operate units with different types of fly ash handling
practices.
b - The number of electric generating units in the table represents the number of boilers, not the number of
turbines/generating units associated with fly ash handling systems. The number of boilers does not necessarily
correspond to the same number of turbines.
c - Due to rounding, the total capacity may not equal the sum of the individual capacities. The capacities for the
UWAG-provided data, data request information, and site visit and sampling information are based on information
provided to EPA and may represent various capacities (e.g., nameplate capacity, net summer capacity, gross winter
capacity, etc.).
5.2 Bottom Ash Handling Operations
As discussed previously, the combustion of coal produces heavy bottom ash particulates
that are collected in the bottom of the boiler. In a typical boiler, the lower portion of the boiler
slopes inward from the front and rear walls of the boiler, leaving a three- to four-foot opening
that runs the width of the bottom of the boiler. These sloped walls and opening allow the bottom
ash to feed by gravity to the bottom ash hoppers that are positioned below the boiler. The bottom
ash hoppers are connected directly to the boiler bottom to prevent any boiler gases from leaving
the boiler. The hoppers have sloped side walls as well, except the hoppers' left and right walls
slope downward, which allows the hoppers to have a single exit point. Depending on the size of
the boiler, there may be more than one bottom ash hopper running along the opening of the
bottom of the boiler. Most bottom ash hoppers are filled with water to quench the hot bottom ash
as it enters the hopper [Babcock & Wilcox, 2005].
Once the bottom ash hoppers have filled with bottom ash, a gate at the bottom of the
hopper opens and the ash is directed to grinders to reduce the bottom ash into smaller pieces.
After the bottom ash hoppers below the boiler have been emptied, the gate at the bottom of the
hoppers closes and the hoppers again fill with water. The bottom ash hoppers are typically sized
to accommodate approximately eight hours of bottom ash generation; therefore, the bottom ash is
sluiced about two to four times a day. The frequency of bottom ash sluicing depends upon the
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Final Detailed Study Report Chapter 5 - Coal Ash Handling Systems
hopper size and the operation of the boiler. The duration of the bottom ash sluicing depends upon
the number and size of hoppers and the bottom ash transport water flow rate. From EPA's site
visit experiences, the bottom ash sluicing duration is generally between 30 minutes to one hour
for each unit [Babcock & Wilcox, 2005].
After the bottom ash has been ground, the ash is sluiced with water and pumped either to
a pond or a dewatering bin. Some plants operate large settling ponds for bottom ash, while others
use a system of relatively small ponds operating in series and/or parallel.
Because the bottom ash particles are heavier than the fly ash particles, they are more
easily separated from the sluice water than the fly ash particles. A dewatering bin system is a
tank-based settling operation that is used to separate the bottom ash solids from the transport
water. A dewatering bin system generally consists of at least two bins because while one bin is
receiving bottom ash, the other bin is decanting the water from the collected bottom ash material.
The dewatering bins are cylindrical in shape and have a gate at the bottom of the bin for
removing the bottom ash [Babcock & Wilcox, 2005].
The bottom ash transport water is fed to the center of the bin and contacts a bar screen
classifier that allows the finer particulates to fall down to the center of the bin while the coarser
particulates are forced to the outside walls of the bin. As the dewatering bins are receiving
bottom ash, they fill with the bottom ash transport water. The particulates are contained at the
bottom of the bin, while the water rises to the top of the bin. At the top of the bin, an underflow
baffle prevents finer particulates from floating out of the bin with the overflow. Excess water in
the bin flows over a serrated overflow weir and leaves the dewatering bin. This overflow water
can either be reused directly as bottom ash transport water, sent to an ash pond for additional
settling, or discharged directly to surface water [Babcock & Wilcox, 2005].
As the dewatering bin continues to receive bottom ash transport water, the bin eventually
reaches its solids loading capacity, at which time the operator will direct the bottom ash transport
water to another dewatering bin and will begin the decanting process in the first bin. As the water
is being decanted, the coarser particulates at the outside of the bin act as a filter to prevent the
finer particulates at the center of the bin from leaving the bin. After the water has been drained
from the system, the gate at the bottom of the bin is opened and the bottom ash is removed,
usually by loading trucks that drive under the bin structure [Babcock & Wilcox, 2005].
Most plants operate with a wet bottom ash handling system, as described above;
however, some plants operate a dry bottom ash handling system. As seen in Table 5-2, 13
percent of the plants in EPA's combined data set handle at least a portion of their bottom ash dry.
The dry bottom ash handling systems that EPA observed during the site visit program operated a
drag chain system. In the drag chain system, the bottom ash is collected in a water bath trough at
the bottom of the boiler to cool the ash. The plant operates a drag chain that moves along the
bottom of the trough and drags the bottom ash out of the boiler. At the end of the trough, the drag
chain reaches an incline, which dewaters the bottom ash by gravity, draining the water back to
the trough as the ash moves upward. The bottom ash is often conveyed to a nearby collection
area, such as a small bunker outside the boiler building, from which it is loaded onto trucks and
either sold for beneficial use or stored on-site in a landfill.
Most of the plants in EPA's combined data set (88 percent; 85 plants) operate wet
handling systems for bottom ash. EPA also reviewed the OSWER data recently collected for
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Final Detailed Study Report
Chapter 5 - Coal Ash Handling Systems
waste management units at coal-fired power plants. The OSWER data identifies 211 plants
operating a total of 417 surface impoundments containing bottom ash. Ninety-one of these ponds
contain only bottom ash; the remainder also contain fly ash (212 ponds), FGD wastes (6 ponds),
or both (108 ponds). The OSWER database likely does not identify plants using wet handling
systems that employ dewatering bins, unless the decant from the bins is sent to a pond
[Schroeder, 2009].
Table 5-2. Bottom Ash Handling Practices at Plants Included in EPA's Combined Data
Set
Bottom Ash Handling
Wet-Sluiced
Handled Dry
Unknown
Total
Number of Plants a
85 (88%)
13 (13%)
1 (1%)
97
Number of Electric
Generating Units b
214 (90%)
22 (9%)
2 (1%)
238
Capacity c
(MW)
106,000 (91%)
10,200 (9%)
600 (<1%)
117,000
Source: Combined Data Set (defined in Chapter 4).
a - Number of plants is not additive because some plants operate units with different types of bottom ash handling
practices.
b - The number of electric generating units in the table represents the number of boilers, not the number of
turbines/generating units associated with fly ash handling systems. The number of boilers does not necessarily
correspond to the same number of turbines.
c - Due to rounding, the total capacity may not equal the sum of the individual capacities. The capacities for the
UWAG-provided data, data request information, and site visit and sampling information are based on information
provided to EPA and may represent various capacities (e.g., nameplate capacity, net summer capacity, gross winter
capacity, etc.).
5.3 Ash Transport Water Characteristics
Fly ash transport water is one of the larger volume flows for coal-fired power plants.
Table 5-3 presents the fly ash transport water flow rates reported in the data request responses.
The flow rates that are normalized on a MW basis are based on the plant's total coal-fired
capacity. The average coal-fired capacity for the plants in the data set is 1,210 MW and the
median coal-fired capacity per plant is 1,140 MW.
Sluice flow rates are not the same as pond overflow rates. Ash ponds typically receive
other waste streams in addition to bottom ash and fly ash. Factors acting to reduce the pond
overflow rate include pond losses from infiltration through the bottom of the pond or retaining
dikes, evaporation, and whether the water held in the ash pond is recycled back to the plant for
reuse. The average fly ash pond overflow flow rates collected during the development of the
1982 effluent guidelines are 2,610,000 gpd/plant and 3,810 gpd/MW [U.S. EPA, 1982].
5-5
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Final Detailed Study Report
Chapter 5 - Coal Ash Handling Systems
Table 5-3. Fly Ash Transport Water Flow Rates
Number of
Plants
Average Flow Rate a
Median Flow Rate a
Range of Flow Rate a
Flow Rate per Plant
gpm/plant b
gpd/plant d
gpy /plant d
17
17
17
5,890
7,640,000
2,710,000,000
3,000
4,030,000
1,470,000,000
188 - 27,500
270,000 - 39,600,000
6,480,000 -
14,500,000,000
Normalized Flow Rate based on Total Coal-Fired Capacity
gpm/Coal-FiredMWb'c
gpd/Coal-FiredMWc'd
gpy/Coal-FiredMWc'd
17
17
17
4.59
5,830
2,090,000
4.08
5,140
1,870,000
0.291-9.38
419-11,900
2,050 - 4,350,000
Source: [U.S. EPA, 2008a].
a - The flow rates presented have been rounded to three significant figures.
b - The gpm flow rate represents the flow rate during the actual sluice.
c - For this analysis, EPA assumed that the total capacity for each coal-fired steam electric unit is associated with
coal use. Non-coal-fired units are not included in the capacity calculations.
d - Because the fly ash transport water flow rate is not always continuous, the gpd cannot be directly calculated
from the gpm. Similarly, some of the fly ash transport water flows are not generated 365 days per year, so gpy
cannot be directly calculated from gpd.
As described in Section 5.2, bottom ash transport water is an intermittent stream from
each of the coal-fired units. The bottom ash transport water flow rates are typically not as large
as the fly ash transport water flow rates. However, bottom ash transport water is still one of the
larger volume flows for steam electric plants.
Table 5-4 presents the bottom ash transport water flow rates reported in the data request
responses. The flow rates that are normalized on a MW basis are based on the plants' total coal-
fired capacity. The average coal-fired capacity per plant is 1,570 MW and the median coal-fired
capacity per plant is 1,560 MW.
As was noted above, sluice flow rates are not the same as pond overflow rates. The
average bottom ash pond overflow flow rates collected during the development of the 1982
effluent guidelines are 2,600,000 gpd/plant and 3,880 gpd/MW [U.S. EPA, 1982]. The bottom
ash transport water flow rates presented in Table 5-4 may be lower than the bottom ash pond
overflow flow rates collected during the 1982 effluent guideline development because the bottom
ash pond overflow likely includes other plant wastewaters, in addition to bottom ash transport
water.
5-6
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Final Detailed Study Report
Chapter 5 - Coal Ash Handling Systems
Table 5-4. Bottom Ash Transport Water Flow Rates from EPA Data Request Responses
Number of Plants a
Average Flow
Rateb
Median Flow
Rateb
Range of Flow
Rateb
Flow Rate per Plant
gpm/plant °
gpd/plant d
gpy /plant d
27
27
27
3,370
3,290,000
1,190,000,000
1,740
2,380,000
810,000,000
358 - 12,600
253,000 -
18,100,000
92,400,000 -
6,600,000,000
Normalized Flow Rate Based on Total Coal-Fired Capacity
gpm/Coal-Fired MW c' e
gpd/Coal-FiredMWd'e
gpy/Coal-FiredMWd'e
27
27
27
2.21
1,940
701,000
1.18
1,600
585,000
0.479-9.38
222 - 7,070
81,100-2,580,000
Source: [U.S. EPA, 2008a].
a - Twenty-nine of the 30 data request plants reported generating bottom ash transport water; however, two plants
are excluded from this summary because they were unable to estimate the bottom ash transport water flow rates.
b - The flow rates presented have been rounded to three significant figures.
c - The gpm flow rate represents the flow rate during the actual sluice.
d - Because the bottom ash transport water flow rate is not always continuous, the gpd cannot be directly calculated
using only the gpm. Similarly, some of the bottom ash transport water flows are not generated 365 days per year, so
gpy cannot be directly calculated from gpd.
e - For this summary, EPA assumed that the total capacity for each coal-fired steam electric unit is associated with
coal use. Non-coal-fired units are not included in the capacity calculations.
The pollutant concentrations in ash transport water vary from plant to plant depending on
the coal used, the type of boiler, and the particulate control system used by the plant. In addition,
the waste stream characteristics also vary in a cyclical fashion during the discharges. For
example, the fly ash transport water characteristics vary depending on which of the ash hoppers
is being sluiced. The bottom ash transport water characteristics at the beginning of the
intermittent sluicing period are likely to be different than the characteristics at the end of the
sluice period. Table 5-5 presents the pollutant concentrations representing the influent to the ash
pond systems sampled during EPA's sampling program.
Table 5-5. Ash Pond Influent Concentrations
Analyte
Method
Unit
Widows Creek - Diked
Channel Influent to
Combined Ash Pond a'b
Cardinal - Influent to
Fly Ash Pond a
Routine Metals - Total
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
ug/L
ug/L
ug/L
Ug/L
ug/L
ug/L
ug/L
ug/L
94,800
ND (38.0)
131
6,080
11.3
4,330
ND (9.50)
103,000
320,000
ND (81.2)
1,520
5,060
71.5
2,790
39.6
204,000
5-7
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Final Detailed Study Report
Chapter 5 - Coal Ash Handling Systems
Table 5-5. Ash Pond Influent Concentrations
Analyte
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Sodium
Thallium
Titanium
Vanadium
Yttrium
Zinc
Method
200.7
200.7
200.7
200.7
200.7
200.7
200.7
245.1
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
Unit
ug/L
ug/L
Ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
Widows Creek - Diked
Channel Influent to
Combined Ash Pond a'b
107
ND (95.0)
188
80,700
208
25,700
337
2.66
65.5
ND (95.0)
27.5
31,200
ND (19.0)
7,150
346
133
785
Cardinal - Influent to
Fly Ash Pond a
1,300
381
964
298,000
786
35,100
1,120
2.31
333
739
ND (20.3)
69,900
ND (40.6)
24,900
2,340
521
1,220
Routine Metals - Dissolved
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Hexavalent Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Sodium
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
D 1687-92
200.7
200.7
200.7
200.7
200.7
200.7
245.1
200.7
200.7
200.7
200.7
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
663
ND (20.0)
46.0
178
ND (5.00)
2,150
ND (5.00)
40,300
ND (10.0)
ND (2.00)
ND (50.0)
ND (10.0)
ND (100)
ND (50.0)
7,110
ND (15.0)
ND (0.200)
50.1
ND (50.0)
26.8
13,400
283
ND (20.0)
86.8
164
ND (5.00)
1,380
ND (5.00)
94,800
ND (10.0)
5.00
ND (50.0)
ND (10.0)
ND (100)
ND (50.0)
15,200
40.3
ND (0.200)
243
ND (50.0)
16.6
64,400
5-8
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Final Detailed Study Report
Chapter 5 - Coal Ash Handling Systems
Table 5-5. Ash Pond Influent Concentrations
Analyte
Thallium
Titanium
Vanadium
Yttrium
Zinc
Method
200.7
200.7
200.7
200.7
200.7
Unit
ug/L
ug/L
Ug/L
ug/L
ug/L
Widows Creek - Diked
Channel Influent to
Combined Ash Pond a'b
ND (10.0)
ND (10.0)
66.8
ND (5.00)
ND (10.0)
Cardinal - Influent to
Fly Ash Pond a
ND (10.0)
ND (10.0)
70.7
ND (5.00)
ND (10.0)
Low-Level Metals - Total
Antimony
Arsenic
Cadmium
Chromium
Copper
Lead
Mercury
Nickel
Selenium
Thallium
Zinc
1638
1638
1638
1638
1638
1638
163 IE
1638
1638
1638
1638
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
13.1 L
88.9
ND (20.0)
ND (160)
114
104
1.02
ND (200)
ND (200)
ND (4.00)
198
33.1
519
9.51
569
719
260
1.16
291
ND (200)
43.6
720
Low-Level Metals - Dissolved
Antimony
Arsenic
Cadmium
Chromium
Hexavalent Chromium
Copper
Lead
Mercury
Nickel
Selenium
Thallium
Zinc
1638
1638
1638
1638
1636
1638
1638
163 IE
1638
1638
1638
1638
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
8.54
49.5
ND (2.00)
ND (16.0)
NA
ND (4.00)
ND (1.00)
ND (0.000500)
ND (20.0)
ND (100)
ND (0.400)
ND (10.0)
17.4
80.7
ND (1.00)
ND (80.0)
NA
ND (20.0)
ND (0.500)
0.000550
ND (100)
21.2
3.10
ND (50.0)
Classicals
Ammonia As Nitrogen (NH3-
N)
Nitrate/Nitrite (NO3-N + NO2-
N)
Total Kjeldahl Nitrogen (TKN)
Biochemical Oxygen Demand
(BOD)
Chloride
4500-
NH3F
353.2
4500-N,C
5210B
4500-CL-C
mg/L
mg/L
mg/L
mg/L
mg/L
0.400
0.360
7.41
53.0
21.4
0.170
2.65
1.01
ND (2.00)
56.8
5-9
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Final Detailed Study Report
Chapter 5 - Coal Ash Handling Systems
Table 5-5. Ash Pond Influent Concentrations
Analyte
Hexane Extractable Material
(HEM)
Silica Gel Treated HEM (SGT-
HEM)
Sulfate
Total Dissolved Solids (TDS)
Total Phosphorus
Total Suspended Solids (TSS)
Method
1664A
1664A
D5 16-90
2540 C
365.3
2540 D
Unit
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
Widows Creek - Diked
Channel Influent to
Combined Ash Pond a'b
ND (5.00)
NA
58.1
224
16.6
9,190 E
Cardinal - Influent to
Fly Ash Pond a
7.00
6.00
1,110
662
4.03
23,400
Source: [ERG, 2008k; ERG, 2008o].
Note: EPA used several analytical methods to analyze for metals during the sampling program. For the purposes of
sampling program, EPA designated some of the analytical methods as "routine" and some of them as "low-level."
EPA designated all of the methods that require the use of clean hands/dirty hands sample collection techniques (i.e.,
EPA Method 1669 sample collection techniques) as "low-level" methods. Although not required by the analytical
methods, EPA used clean hands/dirty hands collection techniques for all low-level and routine metals samples.
a - The concentrations presented have been rounded to three significant figures.
b - The sample collected from the diked channel influent to the combined ash pond represents only the wastewaters
associated with six of the eight generating units. The wastewaters for the other two units enter the combined ash
pond at a different point.
E - Sample analyzed outside holding time.
L - Sample result between 5x and lOx blank result.
NA - Not analyzed.
ND - Not detected (number in parenthesis is the report limit). The sampling episode reports for each of the
individual plants contains additional sampling information, including analytical results for analytes measured above
the detection limit, but below the reporting limit (i.e., J-values).
For the Widows Creek sampling episode, EPA collected a 12-hour composite sample of
the influent to the ash pond from a diked channel containing fly ash transport water, bottom ash
transport water, and several low-volume wastewaters, including coal pile runoff overflow, boiler
blowdown, nonchemical metal cleaning wastewater, roof and switchyard drainage, flow wash
water, and miscellaneous cooling water. Due to the very high flow rates and solids loading of the
influent stream and the challenge of safely collecting a representative sample, EPA collected the
samples from the diked channel at a point downstream of the influent to the channel to allow for
some initial solids settling, but upstream of the open water area of the ash pond. The wastewater
contained within the diked channel represents the wastewater generated from six of the eight
units at the plant, which represents approximately 42 percent of the plant's generating capacity.
The other two units also generate wastewaters that enter the ash pond; however, the wastewaters
enter the pond at a different location. Plant personnel estimated that the flow rate entering the ash
pond at the time of sampling for the six units was approximately 12.1 mgd. The sampling
episode report for Widows Creek contains more detailed information regarding the sample
collection procedures [ERG, 2008o].
For the Cardinal sampling episode, EPA collected a three-hour composite sample of the
influent to the fly ash pond. The influent to the fly ash pond consisted of fly ash transport water
and some dilution water (approximately one-third of the total influent flow). Due to the very high
flow rates and solids loading of the influent stream and the challenge of safely collecting a
5-10
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Final Detailed Study Report Chapter 5 - Coal Ash Handling Systems
representative sample, EPA collected the sample near the influent point but was not able to
sample the influent stream directly from the ash sluice pipes. The fly ash is collected by ESPs at
the plant and sluiced to the fly ash pond. During the sampling episode, the plant personnel
estimated the influent flow rate to the fly ash pond was 9.1 mgd. The sampling episode report for
Cardinal contains more detailed information regarding the sample collection procedures [ERG,
2008k].
Table 5-5 shows that the ash transport water streams contain significant concentrations of
TSS and metals. The ash transport water metals concentrations are typically lower than those of
the FGD wastewater (see Table 4-5 and Table 4-6), but the TSS concentration is higher. Many of
the metals in the ash transport water stream are primarily present in the particulate phase. The
TSS and metals concentrations present in the ash transport water are large enough that the waste
stream typically requires some form of treatment prior to being discharged, at a minimum to
lower the TSS concentrations to meet the 30 mg/L (30-day average) effluent guidelines limit for
fly ash and bottom ash transport water (see Section 3.2.3 for more details).
5.4 Ash Transport Water Treatment Systems
Fly ash transport water and bottom ash transport water are typically treated in large
settling pond systems. For plants operating both wet fly ash and wet bottom ash handling
systems, the two sluice streams are often commingled within the same settling pond system
along with other waste streams. For plants operating only one wet ash handling system (e.g., fly
or bottom ash, but typically wet bottom ash), the ash transport water may be treated in an ash
pond, which would likely receive other plant wastewaters. The design and operation of ash
settling ponds is comparable to that of FGD settling ponds, which is described in Section 4.4.1.
Ash ponds are designed to remove particulates from wastewater by means of gravity. For
this to occur, the wastewater must reside in the pond long enough for removal of the desired
particle size. The ponds provide residence time for the fly ash, bottom ash, and other solids (e.g.,
FGD solids) to settle out of the wastewater to the bottom of the pond. Ash ponds can be an
effective way to reduce TSS in ash transport water, particularly from bottom ash transport water,
which contains relatively dense ash particles. Because ash ponds remove solid particulates, they
may also be an effective means of removing some metals from fly ash transport water when
these metals are present in particulate form.
Surface impoundments (i.e., ash ponds and FGD ponds) can vary substantially in size,
capacity, and age. According to a survey conducted by EPRI, pond surface areas ranged from 5
acres to 1,500 acres, with a median of 91 acres. Disposal capacities ranged from 100,000 cubic
yards to 63 million cubic yards, with a median of 3.4 million cubic yards. The ponds in the
survey had been in operation for less than two years to nearly 50 years, with a median of 22
years of operation. Some ponds were projected to continue operating beyond 2045 [EPRI,
1997a].
During the summer, some ash ponds become thermally stratified. When this occurs, the
top layer of the pond is warmer and contains higher levels of dissolved oxygen, whereas the
bottom layer of the pond is colder and has significantly lower levels of oxygen, often being
anoxic. Typically during fall, as the air temperature decreases, the upper layer of the pond
becomes cooler and more dense, then sinks and causes the entire volume of the ash pond to
circulate. Solids that have settled at the bottom of the pond could potentially become
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Final Detailed Study Report
Chapter 5 - Coal Ash Handling Systems
resuspended due to the mixing, increasing the concentrations of pollutants being discharged
during the turnover period. In addition, anaerobic conditions at the bottom of the pond may be
conducive to the formation of methylmercury, which could then be present in the discharge.
Seasonal turnover effects largely depend upon the size and configuration of the ash pond.
Smaller, and especially shallow, ponds likely do not experience turnover because they do not
have physical characteristics that promote thermal stratification. However, some power plant
settling ponds are large (e.g., greater than 300 acres) and deep (e.g., greater than 10 meters deep)
and likely experience some degree of turnover [MDC, 2004; Heidorn, 2005].
Table 5-6 shows that 95 percent of the plants in the combined data set that handle any
amount of fly ash wet send the fly ash transport water to settling ponds. Sixty-five percent of the
fly ash ponds from the combined data set receive both fly ash and bottom ash. Only one of the
fly ash ponds included in the combined data set is completely segregated (i.e., it receives only fly
ash wastewater).
Table 5-6. Fly Ash Transport Wastewater Treatment Systems at Plants Included in EPA's
Combined Data Set
Type of Fly Ash Wastewater Treatment
System
Settling pond, fly ash commingled with bottom
ash
Settling pond, fly ash NOT commingled with
bottom ash
Settling pond, not known if fly ash is commingled
with bottom ash
Other (tracked away, no wastewater discharge)
Total
Number of
Plants
22 (58%)
4(11%)
10 (26%)
2 (5%)
38
Number of
Electric
Generating
Units a
74 (68%)
9 (8%)
24 (22%)
2 (2%)
109
Capacity
(MW)b
25,300 (59%)
7,240 (17%)
9,690 (23%)
747 (2%)
43,000
Number of
Treatment
Systems That
Also Receive
FGD Wastewater
4
1
2
0
7
Source: Combined Data Set (defined in Chapter 4).
a - The number of electric generating units in the table represents the number of boilers, not the number of
turbines/generating units associated with fly ash handling systems. The number of boilers does not necessarily
correspond to the same number of turbines.
b - Due to rounding, the total capacity may not equal the sum of the individual capacities. The capacities for the
UWAG-provided data, data request information, and site visit and sampling information are based on information
provided to EPA and may represent various capacities (e.g., nameplate capacity, net summer capacity, gross winter
capacity).
The plants within EPA's combined data set that operate wet bottom ash handling systems
send their bottom ash transport water to dewatering bins, settling ponds, or both. EPA has
observed that most bottom ash settling ponds also receive other plant wastewaters. In response to
the data request, no plants reported operating segregated bottom ash ponds. Table 5-7 shows that
90 percent of the plants in the combined data set that handle the bottom ash with a wet system
transfer the bottom ash transport water to a settling pond for treatment. Only 18 percent of the
plants are operating dewatering bins prior to the settling pond. As shown in Table 5-7, there are
more plants that keep their bottom ash transport and fly ash transport waters segregated than not.
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Final Detailed Study Report
Chapter 5 - Coal Ash Handling Systems
Table 5-7. Bottom Ash Transport Wastewater Treatment Systems at Plants Included in
EPA's Combined Data Set
Type of Bottom Ash Wastewater
Treatment System
Dewatering bins, NOT sent to settling pond
(not known if commingled with fly ash)
Dewatering bins, overflow to settling pond
(comingled with fly ash)
Dewatering bins, overflow to settling pond
(not comingled with fly ash)
Dewatering bins, overflow to settling pond
(not known if commingled with fly ash)
Settling pond (comingled with fly ash)
Settling pond (not commingled with fly ash)
Settling pond (not known if commingled
with fly ash)
Unknown
Total
Number of
Plants
8
2
14
1
23
37
7
1
93
Number of
Electric
Generating
Units
18
6
28
1
73
78
14
2
220
Capacity
(MW)
11,100
3,300
17,200
176
25,200
44,700
5,270
596
108,000
Number of
Treatment Systems
That Also Receive
FGD Wastewater
0
1
o
3
i
11
10
2
0
28
Source: Combined Data Set (defined in Chapter 4).
a - The number of electric generating units in the table represents the number of boilers, not the number of
turbines/generating units associated with fly ash handling systems. The number of boilers does not necessarily
correspond to the same number of turbines.
b - Due to rounding, the total capacity may not equal the sum of the individual capacities. The capacities for the
UWAG-provided data, data request information, and site visit and sampling information are based on information
provided to EPA and may represent various capacities (e.g., nameplate capacity, net summer capacity, gross winter
capacity).
For all of the fly and bottom ash ponds reported in response to the data request, waste
streams other than ash transport water ranged from 3 to 93 percent of the total pond influent flow
(in 2006). The major types of influent, other than ash transport water, were cooling tower
blowdown, FGD wastewater, and various types of low-volume wastes [U.S. EPA, 2008a]. Other
types of wastewater that may be transferred to ash ponds include coal pile runoff, transport water
containing mill rejects (which may be pyritic), or coal washing operations (if washed on site).
Because these wastewaters are in direct contact with the coal, they often have low pH (i.e., they
are acidic wastewaters). According to information that EPRI collected during its PISCES
program, coal pile runoff can have a pH as low as 1.5 S.U. EPRI determined when that metals
entering an ash pond from the fly ash and/or bottom ash transport water come in contact with an
acidic waste stream, such as coal pile runoff, more of the metals will become dissolved.
Therefore, because ash ponds are not designed to treat for dissolved metals, the introduction of
acidic waste streams to an ash pond can result in an increase in the metals concentration at the
effluent of the ash pond [EPRI, 1997b].
From the 2005 EIA data, EPA identified 130 steam electric plants that dispose of their fly
ash in a surface impoundment (i.e., ash pond). EPA also identified that 156 steam electric plants
dispose of their bottom ash in an ash pond. EPA determined that a total of 186 plants dispose of
either their fly ash or bottom ash in a pond. Additionally, EPA determined that all of the 186
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Final Detailed Study Report Chapter 5 - Coal Ash Handling Systems
plants burn coal in at least one of the electric generating units at the plant. Within the EIA data
set, 100 of the 488 coal-fired steam electric plants did not report any information regarding the
disposal of the fly ash and bottom ash; therefore, from the EIA data, EPA identified that at least
186 of the 488 coal-fired plants dispose of fly or bottom ash in a pond.
Table 5-8 presents a summary of data recently collected by EPA's OSWER, which sent
letters to power plants requiring that they report certain information about waste management
units used for the storage or disposal of coal combustion residues. The OSWER data includes
information for 214 plants in 35 states operating a total of 537 ponds containing coal combustion
residues (i.e., fly ash, bottom ash, boiler slag, or FGD solids)25. All but one of these plants
operates at least one ash pond, with a total nationwide population of 213 plants operating 495 ash
ponds. Table 5-8 presents summary statistics that identify the type of coal combustion residues
contained in ash ponds, most of which also receive other power plant wastewaters. For
completeness, the table also includes information OSWER collected for ponds that receive FGD
wastes [Schroeder, 2009].
Table 5-8. Ponds Containing Coal Combustion Residues
Type of CCR Contained in Pond
Fly ash and bottom ash
Fly ash, bottom ash, and FGD
Fly ash only
Bottom ash only
FGD only
Fly ash and FGD
Bottom ash and FGD
Total
Number of CCR Ponds
212
108
64
91
42
14
6
537
Source: [Schroeder, 2009].
As shown in Table 5-6 and Table 5-7, some plants combine the FGD wastewater in ash
ponds. EPRI conducted settling tests to determine whether transferring FGD wastewater to an
ash pond presents any issues with the settling pond treatment. EPRI determined that when the
FGD wastewater was mixed with the more dilute ash pond water, the gypsum particles in the
water dissolved and became smaller, which caused the solids to settle slower. EPRI determined
that this mixing reduces the settling efficiency in the ash pond and therefore, may result in an
increase in the effluent TSS concentration from the ash pond [EPRI, 2006b]. Additionally, EPRI
reported that the FGD wastewater includes high loadings of volatile metals which can impact the
solubility of metals in the ash pond, thereby potentially leading to increases in the effluent metal
concentrations from the ash pond [EPRI, 2006b]. According to the OSWER data, 61 power
plants operate a total of 128 ponds that combine FGD wastes with fly ash and/or bottom ash
wastes.
25 The OSWER database also includes information for another 47 ponds which reportedly contain no coal
combustion residues. However, a review of the wastes contained in these additional ponds or the names given these
ponds suggests that some of these ponds may also contain CCRs. Some of the non-CCR ponds are located at five
plants included in the OSWER database, which reportedly do not operate any ponds containing CCR.
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Final Detailed Study Report Chapter 5 - Coal Ash Handling Systems
The design, operation, and maintenance of ash ponds in the steam electric industry vary
by plant/company. As described above, the ash ponds are designed for TSS removal; therefore,
the size of the pond is dependent on the flow rate of the influent waste streams, as well as the
settling properties of the solids in the waste stream. The amount of land available to the plant is
another factor that may determine the size of the ash pond. Ash ponds may be lined with clay or
geosynethic liners, but many ash ponds are unlined. From EPA's site visit program, EPA
determined that relatively new ash ponds may have some type of liner, but older ponds are more
likely to be unlined. EPA was unable to identify a comprehensive source of data quantifying the
number of lined and unlined ash ponds.
Some plants may add chemicals to the ash ponds to control the pH of the ash pond
effluent discharge. The current effluent guidelines pH limit for discharges from steam electric
plants is the range of 6.0 to 9.0 S.U. Common chemicals used to control the pH in ash ponds are
sodium hydroxide and hydrochloric acid. Other plants, such as Widows Creek, inject CC>2 into
the pond, which becomes carbonic acid in the aqueous phase and therefore reduces the alkalinity
of the pond [ERG, 2007h]. Some plants may operate additional treatment systems to control the
ash pond discharges. For example, Kentucky Utilities' Ghent Generating Station operates a
filtration system that treats approximately 50 percent of the ash pond overflow prior to
commingling it with the other 50 percent of the ash pond overflow and discharging it [ERG,
2009g]. Polymers may also be added to the ash pond to promote coagulation/flocculation to
enhance settling of the solids [ERG, 2009r].
During the site visit program, EPA observed varying ways of maintaining the ash ponds.
Some plants constantly remove settled ash solids from the ash pond delta and stack them on the
sides of the pond to dewater and build up the height of the pond. Alternatively, some plants
periodically dredge the pond to remove the ash from the bottom of the pond and transfer the
solids off site for disposal or to an on-site landfill, or use the solids to build up the height of the
ash pond. Finally, some plants may not dredge the ash pond at all. These plants leave the ash in
the pond permanently and, when the ash pond reaches its capacity, a new ash pond is built and
the old pond is decommissioned.
Table 5-9 presents the pollutant concentrations representing the effluent from ash ponds
collected during EPA's sampling program. Each of these pond systems treats different types of
wastewater; therefore, the various effluents cannot be directly compared with each other. In
addition, the influent concentrations presented in Table 5-5 for Widows Creek should not be
directly compared with the effluent concentrations in Table 5-9 because the influent represents
only a portion of the waste streams entering the pond system. Table 5-9 shows that the treated
ash pond effluent wastewaters contain low concentrations of TSS and most nutrients; however,
metals are still present in the pond effluent. Table 5-9 also shows that most of the metals present
in the treated ash pond wastewater are predominantly in the dissolved phase.
Homer City operates a dry fly ash handling system and a wet bottom ash handling
system. The bottom ash transport water from Homer City is first transferred to dewatering bins,
which remove approximately 90 to 95 percent of the solids from the wastewater. The overflow
from the dewatering bins is transferred to the two bottom ash ponds operating in parallel. The
overflow from the bottom ash ponds is transferred to a clearwell and then discharged or reused to
sluice more bottom ash. EPA collected a grab sample of the effluent from the bottom ash
treatment system at Homer City directly from the clearwell. The average flow rate discharged
-------
Final Detailed Study Report Chapter 5 - Coal Ash Handling Systems
from the clearwell during the sampling episode was 0.453 mgd. The sampling episode report for
Homer City contains more detailed information regarding the sample collection procedures
[ERG, 20081].
Widows Creek operates a combined fly ash and bottom ash pond system. The fly ash
from seven of the eight units (one unit uses the FGD system for particulate control, which sends
the wastewater to a separate FGD settling pond system) and bottom ash from all eight units, as
well as several other low-volume wastewaters enter the combined ash pond. The wastewater
enters the ash pond at two different areas, then flows by gravity through diked channels made of
ash until it reaches the open water portion of the main pond. The overflow from the main ash
pond flows to a second pond where the plant injects carbon dioxide, if needed, to decrease the
pH of the wastewater to within the range of 6.0 to 9.0 S.U. The overflow from the second pond
enters the pumping basin, where the treated wastewater is pumped to a stub canal off the river
where the plant draws intake water from the river. Alternatively, if the pumping basin begins to
overflow, then the plant has an emergency overflow discharge directly to surface water. EPA
collected a grab sample of the effluent from the combined ash pond directly from the pumping
basin. EPA estimated that the average flow rate discharged from the pumping basin during the
sampling episode was 29.9 mgd. The sampling episode report for Widows Creek contains more
detailed information regarding the sample collection procedures [ERG, 2008o].
Mitchell operates a fly ash pond treatment system. The fly ash pond receives the fly ash
transport water from Mitchell, fly ash transport water from a neighboring power plant,
wastewater from a coal washing preparation plant, treated acid mine drainage wastewater, and
stormwater runoff. The waste streams enter the fly ash pond at various locations within the pond
and flow to the dam located at the end of the pond. The dam controls the flow from the pond into
a channel that discharges to surface water. EPA collected a grab sample of the fly ash pond
effluent from the channel discharging to the surface water. The average flow rate discharged
from the fly ash pond during the sampling episode was 7.8 mgd. The sampling episode report for
Mitchell contains more detailed information regarding the sample collection procedures [ERG,
2008m].
5-16
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Final Detailed Study Report
Chapter 5 - Coal Ash Handling Systems
Table 5-9. Ash Pond Effluent Concentrations
Analyte
Method
Unit
Homer City -
Effluent from Bottom
Ash Pond a
Widows Creek -
Effluent from
Combined Ash Pond a
Mitchell - Effluent
from Fly Ash Pond a
Cardinal - Effluent
from Fly Ash Pond a'b
Routine Metals - Total
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Sodium
Thallium
Titanium
Vanadium
Yttrium
Zinc
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
245.1
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
323
ND (20.0)
ND (10.0)
101
ND (5.00)
396
ND (5.00)
186,000
ND (10.0)
ND (50.0)
ND (10.0)
355
ND (50.0)
31,800
128
ND (0.200)
19.7
ND (50.0)
6.02
106,000
ND (10.0)
ND (10.0)
ND (20.0)
ND (5.00)
21.6
1,070
ND (20.0)
38.2
227
ND (5.00)
2,210
ND (5.00)
58,500
13.5
ND (50.0)
ND (10.0)
144
ND (50.0)
6,680
ND (15.0)
ND (0.200)
143
ND (50.0)
16.2
21,300
ND (10.0)
14.5
68.5
ND (5.00)
ND (10.0)
404
24.6
150
133
ND (5.00)
2,350
ND (5.00)
115,000
15.9
ND (50.0)
ND (10.0)
ND (100)
ND (50.0)
21,000
ND (15.0)
ND (0.200)
359
ND (50.0)
177
526,000
ND (10.0)
ND (10.0)
110
ND (5.00)
ND (10.0)
344
21.2
77.6
165
ND (5.00)
1,100
ND (5.00)
88,400
ND (10.0)
ND (50.0)
ND (10.0)
ND (100)
ND (50.0)
17,900
64.7
ND (0.200)
361
ND (50.0)
44.5
70,800
ND (10.0)
12.6
104
ND (5.00)
ND (10.0)
5-17
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Final Detailed Study Report
Chapter 5 - Coal Ash Handling Systems
Table 5-9. Ash Pond Effluent Concentrations
Analyte
Method
Unit
Homer City -
Effluent from Bottom
Ash Pond a
Widows Creek -
Effluent from
Combined Ash Pond a
Mitchell - Effluent
from Fly Ash Pond a
Cardinal - Effluent
from Fly Ash Pond a'b
Routine Metals - Dissolved
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Hexavalent Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Sodium
Thallium
Titanium
Vanadium
Yttrium
Zinc
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
D 1687-92
200.7
200.7
200.7
200.7
200.7
200.7
245.1
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
200.7
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
231
ND (20.0)
ND (10.0)
106
ND (5.00)
397
ND (5.00)
192,000
ND (10.0)
ND (2.00)
ND (50.0)
ND (10.0)
106
ND (50.0)
32,600
129
ND (0.200)
20.2
ND (50.0)
6.10 L
106,000
ND (10.0)
ND (10.0)
ND (20.0)
ND (5.00)
35.2
357
ND (20.0)
30.1
206
ND (5.00)
2,200
ND (5.00)
55,400
11.9
12.0
ND (50.0)
ND (10.0)
ND (100)
ND (50.0)
6,430
ND (15.0)
ND (0.200)
136
ND (50.0)
15.3
20,000
ND (10.0)
ND (10.0)
64.7
ND (5.00)
ND (10.0)
241
23.9
138
128
ND (5.00)
2,290
ND (5.00)
113,000
14.1
7.00
ND (50.0)
ND (10.0)
ND (100)
ND (50.0)
20,300
ND (15.0)
ND (0.200)
330
ND (50.0)
162
514,000
ND (10.0)
ND (10.0)
108
ND (5.00)
ND (10.0)
130 L
20.9
74.6
157
ND (5.00)
1,090
ND (5.00)
87,200
ND (10.0)
<3.50
ND (50.0)
ND (10.0)
ND (100)
ND (50.0)
17,700
42.9
ND (0.200)
352
ND (50.0)
43.8
70,300
ND (10.0)
ND (10.0)
99.9
ND (5.00)
ND (10.0)
5-18
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Final Detailed Study Report
Chapter 5 - Coal Ash Handling Systems
Table 5-9. Ash Pond Effluent Concentrations
Analyte
Method
Unit
Homer City -
Effluent from Bottom
Ash Pond a
Widows Creek -
Effluent from
Combined Ash Pond a
Mitchell - Effluent
from Fly Ash Pond a
Cardinal - Effluent
from Fly Ash Pond a'b
Low-Level Metals - Total
Antimony
Arsenic
Cadmium
Chromium
Copper
Lead
Mercury
Nickel
Selenium
Thallium
Zinc
1638
1638
1638
1638
1638
1638
163 IE
1638
1638
1638
1638
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
1.09
6.52
ND (0.500)
ND (4.00)
2.37
ND (0.250)
0.00511
10.7
5.74
1.32
24.2
4.39
34.9
ND (0.500)
13.5 L
1.49
0.490
0.00157
ND (5.00)
17.1
1.46
ND (2.50)
25.8
142
1.32
20.4
5.47
0.580
0.00212
11.0
191
1.72
10.1
21.9
69.8
1.14
4.64 L
2.98
0.420
0.00125
10.7
45.8
2.84
5.98
Low-Level Metals - Dissolved
Antimony
Arsenic
Cadmium
Chromium
Hexavalent Chromium
Copper
Lead
Mercury
Nickel
Selenium
Thallium
Zinc
1638
1638
1638
1638
1636
1638
1638
163 IE
1638
1638
1638
1638
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
0.990
5.00
ND (0.500)
ND (4.00)
3.01
2.08
ND (0.250)
0.00141
10.4
5.16
1.31
15.0
4.45
29.0
ND (0.500)
12.6 L
14.7
ND (1.00)
ND (0.250)
ND (0.000500)
ND (5.00)
15.6
1.49
ND (2.50)
22.5
131
1.17
16.0
17.4
4.54
ND (0.250)
ND (0.000500)
9.57
161
1.42
9.51
22.4
68.9
1.11
4.49 L
3.96
2.27
ND (0.250)
ND (0.000500)
10.6
45.0
2.87
4.15
5-19
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Final Detailed Study Report
Chapter 5 - Coal Ash Handling Systems
Table 5-9. Ash Pond Effluent Concentrations
Analyte
Method
Unit
Homer City -
Effluent from Bottom
Ash Pond a
Widows Creek -
Effluent from
Combined Ash Pond a
Mitchell - Effluent
from Fly Ash Pond a
Cardinal - Effluent
from Fly Ash Pond a'b
Classical*
Ammonia As Nitrogen (NH3-N)
Nitrate/Nitrite (NO3-N + NO2-N)
Total Kjeldahl Nitrogen (TKN)
Biochemical Oxygen Demand (BOD)
Chloride
Hexane Extractable Material (HEM)
Silica Gel Treated HEM (SGT-HEM)
Sulfate
Total Dissolved Solids (TDS)
Total Phosphorus
Total Suspended Solids (TSS)
4500-NH3F
353.2
4500-N,C
5210B
4500-CL-C
1664A
1664A
D516-90
2540 C
365.3
2540 D
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
0.340
37.0
1.36
ND (2.00)
90.0
ND (5.00)
NA
1,290
1,250
1.09
5.00
0.160
0.230
3.39
4.00
20.0
6.00
ND (5.00)
80.7
281
0.250 E
12.0 E
0.150
0.730
ND (0.100)
2.00
240
ND (5.00)
NA
1,110
2,050
0.200
15.0
0.205
4.73 E
0.785 L
ND (2.00)
60.0
10.0
ND (4.00)
494
673
0.0870
6.00
Source: [ERG, 20081; ERG, 2008m; ERG, 2008k; ERG, 2008o].
Note: EPA used several analytical methods to analyze for metals during the sampling program. For the purposes of sampling program, EPA designated some of
the analytical methods as "routine" and some of them as "low-level." EPA designated all of the methods that require the use of clean hands/dirty hands sample
collection techniques (i.e., EPA Method 1669 sample collection techniques) as "low-level" methods. Note that although not required by the analytical method,
EPA used clean hands/dirty hands collection techniques for all low-level and routine metals samples.
a - The concentrations presented have been rounded to three significant figures.
b - The ash pond effluent results represent the average of the ash pond effluent and the duplicate of the ash pond effluent analytical measurements.
< - Average result includes at least one non-detect value. (Calculation uses the report limit for non-detected results).
E - Sample analyzed outside holding time.
L - Sample result between 5x and lOx blank result.
NA - Not analyzed.
ND - Not detected (number in parenthesis is the report limit). The sampling episode reports for each of the individual plants contains additional sampling
information, including analytical results for analytes measured above the detection limit, but below the reporting limit (i.e., J-values).
5-20
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Final Detailed Study Report Chapter 5 - Coal Ash Handling Systems
Cardinal operates a fly ash pond treatment system. The fly ash pond receives fly ash
transport water and occasionally some dilution water. The ash transport water and dilution water
enter at the same point in the pond and flow to the dam located at the opposite end of the pond.
The dam controls the flow from the pond into a channel that discharges to surface water. EPA
collected a grab sample of the fly ash pond effluent from the channel discharging to the surface
water. The average flow rate discharged from the fly ash pond during the sampling episode was
7.8 mgd. The sampling episode report for Cardinal contains more detailed information regarding
the sample collection procedures [ERG, 2008k].
If the fly ash and/or bottom ash transport water is treated in an ash pond, then the
overflow from these systems can be reused as sluice water or recycled elsewhere within the
plant. During the site visit program, EPA visited two plants that operate combined ash ponds
receiving both fly ash and bottom ash transport water that are completely reusing the overflow
from the ash pond as the bottom ash and fly ash transport waters with no discharge. One of these
plants is highlighted in Case Study IV.
Additionally, EPA visited two plants with segregated bottom ash handling systems and
these plants reused the bottom ash pond overflow as the bottom ash transport waters; however,
these plants do discharge some of the overflow from the bottom ash pond. These plants only
discharged the bottom ash overflow if the water began accumulating in the system and needed to
be discharged to manage the volume of water in the system. One of these plants is highlighted in
Case Study V.
Some plants achieve partial recycle from ash ponds. For example, from information
obtained through the data request, EPA estimates that Georgia Power's Bowen plant is recycling
approximately 85 percent of the water from its ash pond. This ash pond receives and recycles
several types of wastewaters including bottom ash and fly ash transport water.
5-21
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Final Detailed Study Report Chapter 5 - Coal Ash Handling Systems
Case Study IV: Coal-Fired Power Plant Water Reuse
Fly Ash and Bottom Ash Transport Water Reuse
Western Kentucky Energy's Kenneth C. Coleman Station
The Facility
Number of coal-fired units: 3 (485 total MW capacity for all three units)
Coal used: Eastern bituminous
Bottom ash handling: Wet
Fly ash handling: Wet
Ash treatment system: Ash ponds (no discharge)
The Ash Handling and Treatment System
Bottom ash transport water and fly ash transport water are pumped to Ash Pond A, which was
built in 1980 and has a discharge point (Outfall 002), but the plant does not typically discharge
from the pond. Ash pond A also receives the effluent from the coal pile runoff pond and
stormwater collected in Ash Pond C (the old pond, which is now closed). Coleman also has a
new ash pond (Ash Pond D), which receives the dredged ash solids from Ash Pond A and the
gypsum solids from the FGD process. All of the ponds at the plant have clay liners.
The ash transport water collected in Ash Pond A is treated by the pond and then reused as fly
ash and bottom ash transport water by the plant. The plant operates the system with a complete
recirculation and does not discharge from the ash pond system, even though the plant has a
permitted outfall that allows it to discharge.
Water is removed from the ash system through evaporation from the ponds and evaporation of
bottom ash quench water in the boiler. There may also be some loss to infiltration if water is
able to pass through the clay liner of the pond. The plant monitors the levels of the ponds
closely and adjusts the make-up water to the sluicing system to control the level of the ponds.
During the rainy season, the plant keeps the levels lower to allow to additional rainfall to
accumulate in the ponds.
Highlights of Ash Transport Water Reuse
Recycle achieved: Complete recycle from combined ash pond
Type of water reused: Bottom and fly ash transport water, coal pile runoff, rainfall,
stormwater
Recycle destination: Bottom ash transport water and fly ash transport water
Source: [ERG, 2009m].
5-22
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Final Detailed Study Report Chapter 5 - Coal Ash Handling Systems
Case Study V: Coal-Fired Power Plant Water Reuse
Bottom Ash Transport Water Reuse
EME Homer City Generation L.P.'s Homer City Power Plant
The Facility
Number of coal-fired units: 3 (650 MW; 650 MW; 700 MW)
Coal used: Eastern bituminous
Bottom ash handling: Wet
Fly ash handling: Dry
Ash treatment system: Dewatering bins and bottom ash pond
The Ash Handling and Treatment System
Bottom ash transport water is piped from the boilers to dewatering bins, which remove 90 to 95
percent of the solids. The dewatered bottom ash from the dewatering bins is either used locally
for antiskid and road construction or placed in the on-site, unlined ash landfill. The decant
overflow from the dewatering bins drains to ash settling ponds.
Homer City operates four ash settling ponds. The plant typically operates two ash settling ponds
at one time, which are operated in series. Each ash pond has an approximate volume of 1.76
million gallons. The ash settling ponds receive overflow from the bottom ash dewatering bins,
as well as storm water runoff and rainfall. Runoff from the ash handling and precipitator areas
(covering approximately six acres) drains into the ponds. Water from the first pond in a series
pair overflows to the second pond, which in turn overflows to a clearwell. From the clearwell,
water is recycled for use as bottom ash transport water. There is a periodic discharge from the
clearwell through the NPDES outfall as needed to maintain the water balance in the system, the
frequency of which depends on the amount of rainfall that has been received. As one pair of ash
settling ponds fills with solids, the transport water is shifted to the other pair of ponds so that
the settled ash can be removed. The ash settling ponds are dredged every six to eight months.
The recovered solids are transported to the on-site, unlined ash landfill.
Highlights of Ash Transport Water Reuse
Recycle achieved: Significant percentage of recycle from bottom ash pond
Type of water reused: Bottom ash transport water and contaminated stormwater
Recycle destination: Bottom ash transport water
Source: [ERG, 2007J].
5-23
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Final Detailed Study Report Chapter 6 - Environmental Assessment of Coal Combustion Wastewater
6. ENVIRONMENTAL ASSESSMENT OF COAL COMBUSTION WASTEWATER
Numerous studies have shown that the pollutants found in wastewater associated with
coal combustion wastes can impact aquatic organisms and wildlife, and can result in lasting
environmental impacts on local habitats and ecosystems. Many of these impacts may not be
realized for years due to the persistent and bioaccumulative nature of the pollutants released. The
total amount of toxic pollutants currently being released in wastewater discharges from coal-fired
power plants is estimated to be significant and raises concerns regarding the long-term impacts to
aquatic organisms, wildlife, and human health that are exposed to these pollutants. This chapter
presents case study examples to illustrate the impacts that pollutants present in coal-fired power
plant wastewater can have on the environment.
As described in Chapters 4 and 5, coal combustion wastes comprise a variety of residuals
from the coal combustion process, including fly ash, bottom ash, and FGD solids (i.e., gypsum
and calcium sulfite). Coal-fired plants remove these solid wastes through both wet and dry
disposal methods. Dry disposal practices typically involve transferring the combustion wastes to
a storage silo or outdoor storage pile to either be hauled to a landfill or, depending on the
particular residual, sent offsite where it may be used to create beneficial by-products such as
drywall or cement. In wet handling systems, bottom ash and fly ash is transported from the boiler
and particulate removal units and is typically disposed of in surface impoundment settling ponds.
Wet FGD systems use lime or limestone slurry to remove sulfur dioxide from flue gas. The water
remaining from the slurry at the end of the FGD process, commonly called scrubber purge, is
either discharged to a surface impoundment or sent to an advanced wastewater treatment system
prior to discharge to a receiving stream.
Although there are several wastewater streams associated with coal-fired power plants,
for the purposes of this chapter, coal combustion wastewater includes the following waste
streams:
• FGD wastewater (i.e., scrubber purge) - the wastewater remaining following the
use of a sorbent slurry (e.g., lime, limestone) to remove sulfur dioxide from flue
gas;
• Fly ash transport water - the wastewater stream used to transport the fly ash away
from the electrostatic precipitators (ESPs) or fabric filter baghouses;
• Bottom ash transport water - the wastewater stream used to transport the bottom
ash away from the boiler; and
• Leachate or seepage from surface impoundments or landfills containing coal
combustion residues.
The most common treatment and disposal practice for coal combustion wastewater
involves pumping the slurried wastes into surface impoundments that serve as a physical
treatment to remove particulate material through gravitational settling. The coal combustion
wastewater present in surface impoundments can include one specific wastewater stream (e.g.,
fly ash transport water) or a combination of combustion wastewaters (e.g., fly ash transport water
and FGD wastewater). The wastewaters sent to surface impoundments can also include coal pile
runoff. Although coal pile runoff is not the result of a combustion process, it can contain many of
the pollutants present in coal combustion wastewater. Some coal-fired power plants have
implemented more advanced wastewater treatment systems such as chemical precipitation,
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Final Detailed Study Report Chapter 6 - Environmental Assessment of Coal Combustion Wastewater
biological treatment, and evaporation/distillation to treat the FGD wastewater. Chapter 4
describes these advanced treatment practices in more detail. Regardless of whether a plant uses a
settling pond or advanced treatment system, coal combustion wastewater is typically discharged
into the natural environment where numerous studies have raised concern regarding the toxicity
of these waste streams [Rowe et al., 2002; U.S. EPA, 2007c; NRC, 2006].
A number of variables can affect the composition of coal combustion wastewater,
including parent coal composition, type of combustion process, flue gas cleaning technologies
implemented, and management techniques used to dispose of coal combustion wastewater
[Carlson and Adriano, 1993]. In particular, the practice of commingling coal combustion
wastewater with other waste streams from the plant in surface impoundments can result in a
chemically complex effluent that is ultimately released to the environment [Rowe et al., 2002].
Exposure to coal combustion wastewater has been associated with fish kills, reductions in the
growth and survival of aquatic organisms, behavioral and physiological effects in wildlife and
aquatic organisms, potential impacts to human health (i.e., drinking water contamination), and
changes to the local habitat [Rowe et al., 2002; Carlson and Adriano, 1993]. The
bioaccumulative properties of several coal combustion wastewater pollutants and long recovery
times associated with many of the ecological impacts emphasize the potential threat these wastes
present to the local environment. Research published in the scientific literature demonstrates that
coal combustion wastewater is not a benign waste and further study is needed to fully understand
how these chemically complex waste streams interact with the environment [Rowe et al., 2002;
NRC, 2006].
This chapter examines the potential impacts of coal combustion wastewater on the
environment by addressing the following three questions:
• What are the characteristics of coal combustion wastewater?
• How does coal combustion wastewater interact with the environment?
• What are the environmental effects of coal combustion wastewater?
Section 6.1 discusses the characteristics of coal combustion wastewater and why they are
a threat to the environment. Section 6.2 explores the various ways that pollutants in coal
combustion wastewater can come into contact with the environment through different waste
management practices (e.g., surface impoundments and landfills). In addition this section
describes how different surface water environments (e.g., lentic and lotic systems) can influence
the environmental effect of coal combustion wastewater. Section 6.3 provides an overview of the
different environmental effects reported in the literature resulting from exposure to coal
combustion wastewater.
6.1 Coal Combustion Wastewater Pollutants
An increasing amount of evidence indicates that the characteristics of coal combustion
wastewater have the potential to impact human health and the environment. Many of the
common pollutants found in coal combustion wastewater (e.g., selenium, mercury, and arsenic)
are known to cause environmental harm and can potentially represent a human health risk.
Pollutants in coal combustion wastewater are of particular concern because they can occur in
large quantities (i.e., total pounds) and at high concentrations (i.e., exceeding Maximum
Contaminant Levels (MCLs)) in discharges and leachate to groundwater and surface waters. In
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Chapter 6 - Environmental Assessment of Coal Combustion Wastewater
addition, some pollutants in coal combustion wastewater present an increased ecological threat
due to their tendency to persist in the environment and bioaccumulate in organisms, which often
results in slow ecological recovery times following exposure.
Constituents present in coal combustion wastewater are primarily derived from the parent
coal. A number of these constituents have the potential to cause environmental harm depending
on the mass pollutant load, wastewater concentration, and how organisms are exposured to them
in the environment. Table 6-1 lists some of the common pollutants found in coal combustion
wastewater that have been associated with documented environmental impacts or could have the
potential to cause environmental impacts based on the loads and concentrations present in the
wastewater. Table 6-1 is intended to highlight the most frequently cited pollutants in coal
combustion wastewater associated with environmental impacts and does not include all
pollutants that may cause adverse impacts. The remainder of this section provides an overview of
the metals and pollutants most frequently cited as causing ecological impacts following exposure
to coal combustion wastewater, some of which have been the focus of some state NPDES permit
programs.
Table 6-1. Selected Coal Combustion Wastewater Pollutants
Compound
Potential Environmental Concern a'b'c'd
Arsenic
Frequently observed in high concentrations in coal combustion wastewater; causes poisoning of
the liver in fish and developmental abnormalities; is associated with an increased risk of cancer
in humans in the liver and bladder.
BOD
Can cause fish kills because of a lack of available oxygen; increases the toxicity of other
pollutants, such as mercury. Has been associated with FGD wastewaters that use organic acids
for enhanced SO2 removal in the scrubber.
Boron
Frequently observed in high concentrations in coal combustion wastewater; leachate into
groundwater has exceeded state drinking water standards; human exposure to high
concentrations can cause nausea, vomiting, and diarrhea. Can be toxic to vegetation.
Cadmium
Elevated levels are characteristic of coal combustion wastewater-impacted systems; organisms
with elevated levels have exhibited tissue damage and organ abnormalities.
Chlorides
Sometimes observed at high concentrations in coal combustion wastewater (dependent on FGD
system practices); elevated levels observed in fish with liver and blood abnormalities.
Chromium
Elevated levels have been observed in groundwater receiving coal combustion wastewater
leachate; invertebrates with elevated levels require more energy to support their metabolism and
therefore exhibit diminished growth.
Copper
Coal combustion wastewater can contain high levels; invertebrates with elevated levels require
more energy to support their metabolism and therefore exhibit diminished growth.
Iron
Leachate from impoundments has caused elevated concentrations in nearby surface water; biota
with elevated levels have exhibited sublethal effects including metabolic changes and
abnormalities of the liver and kidneys.
Lead
Concentrations in coal combustion wastewater are elevated initially, but lead settles out quickly;
leachate has caused groundwater to exceed state drinking water standards. Human exposure to
high concentrations of lead in drinking water can cause serious damage to the brain, kidneys,
nervous system, and red blood cells.
Manganese
Coal combustion wastewater leachate has caused elevated concentrations in nearby groundwater
and surface water; biota with elevated levels have exhibited sublethal effects including metabolic
changes and abnormalities of the liver and kidneys.
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Chapter 6 - Environmental Assessment of Coal Combustion Wastewater
Table 6-1. Selected Coal Combustion Wastewater Pollutants
Compound
Mercury
Nitrogen
pH
Phosphorus
Selenium
Total dissolved
solids
Zinc
Potential Environmental Concern a'b'c'd
Biota with elevated levels have exhibited sublethal effects including metabolic changes and
abnormalities of the liver and kidneys; can convert into methylmercury, increasing the potential
for bioaccumulation; human exposure at levels above the MCL for relatively short periods of
time can result in kidney damage.
Frequently observed at elevated levels in coal combustion wastewater; may cause eutrophication
of aquatic environments.
Acidic conditions are often observed in coal combustion wastewater; acidic conditions may
cause other coal combustion wastewater constituents to dissolve, increasing the fate and transport
potential of pollutants and increasing the potential for bioaccumulation in aquatic organisms.
Frequently observed at elevated levels in coal combustion wastewater; may cause eutrophication
of aquatic environments.
Frequently observed at high concentrations in coal combustion wastewater; readily
bioaccumulates; elevated concentrations have caused fish kills and numerous sublethal effects
(e.g., increased metabolic rates, decreased growth rates, reproductive failure) to aquatic and
terrestrial organisms. Short term exposure at levels above the MCL can cause hair and fingernail
changes; damage to the peripheral nervous system; fatigue and irritability in humans. Long term
exposure can result in damage to the kidney, liver, and nervous and circulatory systems.
High levels are frequently observed in coal combustion wastewater; elevated levels can be a
stress on aquatic organisms with potential toxic effects; elevated levels can have impacts on
agriculture & wetlands.
Frequently observed at elevated concentrations in coal combustion wastewater; biota with
elevated levels have exhibited sublethal effects such as requiring more energy to support their
metabolism and therefore exhibiting diminished growth, and abnormalities of the liver and
kidneys.
a - Source: [Rowe et al., 2002].
b - Source: [NRC, 2006].
c - Source: EPA Drinking Water Contaminants (http://www.epa.gov/safewater/contaminants/index.htmMmcls)
d- Source: [U.S. EPA, 2007c].
Selenium
Selenium is the most frequently cited pollutant associated with documented
environmental impacts following exposure to coal combustion wastewater [NRC, 2006].
Selenium concentrations present in coal combustion wastewater originate from the parent coal
used in the combustion process. The toxic potential of selenium is related to its chemical form
(i.e., selenite, selenate, elemental selenium) and solubility. The predominate forms of selenium in
aquatic systems that receive coal combustion wastewater discharges are selenite and selenate
[Besser et al., 1996]. Availability of selenium is controlled by dissolved oxygen levels, hardness,
pH, salinity, temperature, and the other chemical constituents present [NFS, 1997].
Selenium has been tied to fish kills, and to developmental and reproductive failure in fish,
reptiles, and birds. In a 1991 study, Sorensen found that selenium levels as low as 3-8 ug/L in
aquatic environments can be life-threatening to fish [NFS, 1997]. Selenium has the potential to
bioaccumulate and can be transferred maternally. As a result, selenium-related environmental
impacts can linger for years even after exposure to coal combustion wastewater has ceased
[Rowe et al., 2002]. Aquatic organisms exposed to coal combustion wastewater have exhibited
elevated selenium concentration in organs such as their kidneys, liver, and gonads, resulting in
abnormalities that hinder growth and survival [Rowe et al., 2002]. In addition to ecological
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Final Detailed Study Report Chapter 6 - Environmental Assessment of Coal Combustion Wastewater
impacts, EPA has documented numerous damage cases where selenium in coal combustion
wastewater discharges resulted in the issuance offish consumption advisories in surface waters
and the exceedance of selenium MCLs in groundwater, suggesting that selenium concentrations
in coal combustion wastewater has the potential to represent a human health risk [U.S. EPA,
2007c; NRC, 2006].
Arsenic
Arsenic, like selenium, is soluble in near-neutral pH and in alkaline conditions, which are
commonly associated with coal combustion wastewater. Because of these solubility
characteristics, arsenic is highly mobile and is frequently observed at elevated concentrations at
sites located downstream from coal combustion wastewater impoundments [NRC, 2006]. In
addition, EPA has documented several damage cases where arsenic levels exceeded drinking
water standards in groundwater near coal combustion waste management facilities [U.S. EPA,
2007c]. Groundwater contamination of arsenic at these concentrations represents a potential
human health risk if the aquifer is used as a drinking water source or has the potential to impact a
drinking water source.
Arsenic is also of concern due to its tendency to bioaccumulate in aquatic communities
and potentially impact higher trophic level organisms in the area. For example, studies have
documented water snakes, which feed on fish and amphibians, with arsenic tissue concentrations
higher than their prey [Rowe et al., 2002]. Elevated arsenic tissue concentrations are associated
with several biological impacts such as liver tissue death, developmental abnormalities, and
reduced growth [NRC, 2006; Rowe et al., 2002].
Mercury
Although mercury concentrations in coal combustion wastewater are relatively low,
mercury is a highly toxic compound that represents an environmental and human health risk even
in small concentrations. One of the primary environmental concerns regarding mercury
concentrations in coal combustion wastewater is the potential for methylmercury to form in
surface impoundments and constructed wetlands prior to discharge. Methylmercury is an organic
form of mercury that readily bioaccumulates in fish and other organisms and is associated with
high rates of reproductive failure. Bacteria found in anaerobic conditions, such as those that may
be present in sediments found on the bottom of coal combustion surface impoundments or in
river sediments, convert mercury to methylmercury through a process called methylation.
Microbial methylation rates increase in acidic and anoxic environments with high concentrations
of organic matter. Studies have documented fish and invertebrates exposed to mercury from coal
combustion wastewater exhibiting elevated levels of mercury in their tissues and developing
sublethal effects such as reduced growth and reproductive success [Rowe et al., 2002].
Biochemical Oxygen Demand (BOD)
Biochemical oxygen demand (BOD) is a measure of the quantity of oxygen used by
microorganisms (e.g., aerobic bacteria) in the oxidation of organic matter. The primary source of
BOD in coal combustion wastewater is the addition of organic acid buffers to the FGD
scrubbers. High BOD concentrations in surface waters have the potential to decrease dissolved
oxygen levels and contribute to fish kills in waters that receive coal combustion wastewater.
BOD levels can also influence the availability and toxicity of other coal combustion wastewater
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Final Detailed Study Report Chapter 6 - Environmental Assessment of Coal Combustion Wastewater
constituents such as metals. For example, the rate of methylation, or the conversion from
elemental mercury to methylmercury, increases at high concentrations of BOD, thus increasing
the potential toxic effects of mercury present in coal combustion wastewater.
pH
The pH of coal combustion wastewater varies depending on the type of coal and the
amount of metal oxides present [NRC, 2006]. Although some coal combustion wastewaters are
alkaline, wastewater that is generated from power plants burning bituminous coal from
southeastern or mid-Atlantic states is acidic [NRC, 2006]. Many pollutants in coal combustion
wastewater, including cadmium, copper, chromium, lead, nickel, and zinc, are highly soluble in
acidic, or non-neutral, conditions [NRC, 2006]. As a result, coal combustion wastewater often
has high dissolved metal concentrations.
Chlorides and Total Dissolved Solids
Chloride levels in coal combustion wastewater are dependent upon chlorine
concentrations present in the parent coal as well as the amount of recirculation in the FGD
system. FGD systems with many iterations of circulation between blowdown cycles exhibit high
concentrations of chlorides. Studies have found that coal combustion wastewater leachate
reaching groundwater has caused chloride levels to exceed secondary MCLs [NRC, 2006].
Chlorides also contribute to the high total dissolved solids (TDS) levels typical of coal
combustion wastewater. TDS, a reflection of water's salinity level, is a measure of the amount of
dissolved matter in water. Calcium and magnesium also factor heavily into TDS levels of coal
combustion wastewater. The remaining composition of TDS consists of other common dissolved
metals and constituents, particularly at acidic pH levels when they exhibit high solubilities. Both
chloride levels and TDS play a role in determining the availability and toxicity of other coal
combustion wastewater constituents, including metals. As TDS and chloride levels fluctuate, so
do the amounts of other metals that dissolve due to solubility characteristics.
Nutrients
Nutrient concentrations present in coal combustion wastewater are primarily attributed to
the parent coal composition and air pollution controls in the coal combustion process.
Phosphorus concentrations in coal combustion wastewater tend to vary based on the parent coal
composition with high sulfur coals commonly associated with higher levels of phosphorus.
The primary concern with nutrients in coal combustion wastewater is the potential for the
total nitrogen load from coal-fired power plants to significantly increase in the future as air
pollution limits become stricter and the use of air pollution controls increases. While the current
concentration of nitrogen present in coal combustion wastewater from any individual power
plant is probably relatively low, the total nitrogen load from a single plant can be significant due
to large wastewater flow rates. There are concerns that nutrient impacts could occur on
waterbodies receiving discharges from multiple power plants. This is especially a concern on
waterbodies that are nutrient impaired or in watersheds that contribute to downstream nutrient
problems. Higher nutrient loads from coal-fired power plants could result in the eutrophication of
waters receiving coal combustion wastewater. Eutrophication is the process where excess
nutrients stimulate excessive plant and algal growth which can lead to declining dissolved
oxygen levels.
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Chapter 6 - Environmental Assessment of Coal Combustion Wastewater
6.2 Coal Combustion Wastewater Interactions with the Environment
The interaction of a pollutant source with the environment can be described as either a
release from the source that alters the physical, chemical, or biological characteristics of an
ecosystem or the attraction of wildlife and humans to the pollutant source (i.e., an attractive
nuisance) prior to discharge. In 2007, EPA's Office of Resource Conservation and Recovery
(ORCR, formerly named the Office of Solid Waste) evaluated 85 cases of environmental damage
to determine if the observed impacts were due to pollutants from coal combustion wastes [U.S.
EPA, 2007c]. EPA's Office of Water reviewed this information, along with several other
instances where environmental impacts are attributable to coal combustion wastewater. Table 6-2
summarizes the number of environmental impact cases by type of waste management system and
type of impacted water body resource.
Table 6-2. Number of Documented Cases of Environmental Impacts from Coal
Combustion Wastewater
Source of Pollutant Release
(Waste Management System)
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Total Number of Cases = 70
Source: [Jordan, 2009].
The three primary routes through which coal combustion wastewater interacts with the
environment are:
Discharges to surface waters;
Leaching to groundwater; and
Surface impoundments and constructed wetlands acting as attractive nuisances.
The method of exposure plays an important role in determining the potential effects of
coal combustion wastewater on the environment. For example, the physical and chemical
characteristics of receiving waters and groundwater aquifers can affect the fate and transport of
pollutants from coal combustion wastewater to the environment and how the pollutants interact
with the biological community. This section describes the three primary methods through which
coal combustion wastewater interacts with the environment and explores how each route can
affect the potential for environmental impact from coal combustion wastewater.
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Final Detailed Study Report Chapter 6 - Environmental Assessment of Coal Combustion Wastewater
6.2.1 Discharges to Surface Waters
Coal combustion wastewater is commonly discharged directly to surface waters
following treatment in settling ponds. More recently, FGD wastewater at some power plants may
be treated using advanced wastewater treatment systems employing tanks and similar structures
(e.g., chemical precipitation or biological treatment systems) prior to discharge to an ash pond or
directly to surface water.
One of the primary factors controlling the environmental impact of coal combustion
wastewater on surface waters is the residence time of the pollutants once they enter an aquatic
system. Residence times are often determined by the flow rate of the receiving water and type of
ecosystem it supports. For example, the potential for pollutant retention in lentic (i.e., still or
slow-moving water) aquatic systems and the creation of hot spots in lotic (i.e., actively-moving
water) aquatics systems are of particular concern especially when bioaccumulative pollutants are
present in coal combustion wastewater. Several coal combustion wastewater constituents (e.g.,
arsenic, mercury, selenium) can readily bioaccumulate in exposed biota. Bioaccumulation is the
process wherein an organism absorbs a toxic substance through food and exposure to the
environment at a faster rate than the substance is removed from the body. The bioaccumulation
of coal combustion wastewater pollutants is of particular concern due to the potential for
impacting higher tropic levels, local terrestrial environments, and transient species in addition to
the aquatic organisms directly exposed to coal combustion wastewater. Aquatic systems with
long residences times and potentially exposed to bioaccumulative pollutants often experience a
persistence of environmental effects and suffer from long recovery times following the
introduction of coal combustion wastewater to the system. The following sections describe how
the differences in stream flow between lentic and lotic systems can impact the environmental
effect of coal combustion wastewater on aquatic organisms and wildlife and the role that
sediments in surface waters play in the persistence of these effects in aquatic systems.
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Chapter 6 - Environmental Assessment of Coal Combustion Wastewater
Lentic System Case Study:
Belews Lake, North Carolina
In 1970, Duke Power Company constructed
Belews Lake, a 1,500 hectare cooling reservoir to support
the Belews Creek Steam Station in Stokes County, North
Carolina. Following completion of the reservoir, Duke
Power began monitoring the fish populations in Belews
Lake prior to any discharges of coal combustion
wastewater. From 1974 to 1985, ash pond effluent was
discharged into Belews Lake. Almost immediately
following the introduction of the ash pond effluent to lake
employees observed rapid and dramatic changes in the fish
populations [Rowe et al., 2002]. By 1975, one year after
discharges began, morphological abnormalities were
reported for all 19 fish species monitored in the lake.
Within two years following the release of coal combustion
wastewater into the lake, several species experienced
complete reproductive failure with only four species
remaining by 1978 (i.e., four years after discharges
began). Water samples collected in the lake reported
elevated levels of arsenic, selenium, and zinc. The
observed fish abnormalities were eventually correlated
with high selenium whole-body concentrations with the
planktonic community identified as the key source of
selenium to the impacted fish.
In 1985 the Belews Creek Steam Station
switched to a dry landfilling disposal method for the coal
ash and ash pond discharges to the lake ended. In a 1997
study, Lemly determined that there was evidence that the
lake was recovering; however, even 11 years after the
discharges ceased selenium levels in the sediments still
posed a risk to wildlife that feed on benthic organisms
[Rowe et al., 2002]. Lemly also observed that despite the
reduction in the selenium concentration present in fish
ovaries, reproductive abnormalities remained persistent
highlighting the long ecological recovery times commonly
experienced in lentic systems with high pollutant retention
rates and low sedimentation rates such as Belews Lake
[Rowe etal., 2002].
Lentic Systems
Many aquatic environments that
contain coal combustion wastewater
(e.g., surface impoundments) or receive
coal combustion wastewater discharges
are lentic systems such as lakes, ponds,
reservoirs, and swamps. The majority of
ecological studies on the impact of coal
combustion wastewater in aquatic
environments have focused on lentic
systems [Rowe et al., 2002]. In lentic
aquatic systems, the hydraulic residence
time, or the amount of time it takes for
the water in the aquatic system to be
replaced by influent (i.e., streams,
precipitation), is relatively long,
allowing pollutants to build up over time
and making lentic systems more
vulnerable to impacts from coal
combustion wastewater. In addition,
aquatic organisms are limited in their
ability to avoid areas of high pollutant
concentrations and are restricted to the
food supply available within the water
body. Some coal combustion wastewater
pollutants (e.g., selenium) are known to
bioaccumulate and have been known to
concentrate in the upper tiers of the
aquatic food web in lentic systems. For
example, samples of sediments, plants,
and aquatic organisms collected from
the swamp near the D-Area Power
Facility on the U.S. Department of
Energy's Savannah River Site near
Aiken, SC, reported elevated concentrations of arsenic, cadmium, chromium, copper, and
selenium. In addition to the accumulation of these pollutants in organisms directly exposed to
discharges of the coal combustion wastewater, studies of turtles, alligators, and birds living near
the drainage swamp have shown these animals transfer trace metals such as selenium to their
offspring. Chronic exposure to coal combustion wastewater pollutants in the swamp has been
linked to detrimental changes in morphology, behavior, energetics, and endocrinology in local
wildlife [Rowe et al. 2002]. In a 1999 study, Hopkins et al. observed that water snakes, which
fed on fish and amphibians in the areas contaminated with coal combustion wastes, had
accumulated higher arsenic tissue concentrations than their prey [Rowe et al., 2002].
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Final Detailed Study Report Chapter 6 - Environmental Assessment of Coal Combustion Wastewater
Lotic Systems
Lotic systems are water bodies with flowing water such as streams, rivers, and springs
that may provide more rapid dilution of coal combustion wastewater discharges than lentic
systems. The moving water in lotic systems provides a transport mechanism to disperse coal
combustion constituents greater distances from the power plant, and enables aquatic organisms
to move away from the areas of coal combustion wastewater contamination [Rowe et al., 2002].
Although the discharge of coal combustion wastewater into a lotic system has the potential to
increase the distribution of pollutants across a greater spatial area, changes in flow velocity may
result in the concentration of pollutants at a single location further downstream [Rowe et al.
2002]. For example, coal combustion wastewater discharged to a river may encounter areas of
slower moving water downstream where pollutants would fall out of suspension and concentrate
in a limited area. These pockets of higher pollutant concentrations, or hot spots, could be
vulnerable to continued resuspension as stream velocities are affected by rainfall events,
resulting in the pollutants being available to aquatic organisms over much longer periods of time
[Rowe et al., 2002; Lemly, 1996].
Few studies have demonstrated lethal and sublethal effects to aquatic organisms from the
discharge of coal combustion wastewater into lotic systems; however, several studies have
demonstrated the bioaccumulation of trace elements in fish and invertebrates in creeks
downstream of coal combustion wastewater impoundments [Rowe et al., 2002]. In a 2001 study
by Lemly et al., fish and water quality samples were collected downstream from the American
Electric Power (AEP) John E. Amos Plant in Winfield, WV along Little Scary Creek and at a
reference location along the Ohio River. Water quality samples reported elevated levels of
arsenic, copper, and selenium in Little Scary Creek relative to the reference location. Bluegill
fish liver concentrations were higher than the reference location for arsenic, cadmium, copper,
chromium, selenium, and zinc demonstrating that pollutants from the ash pond discharge are
accumulating in fish living downstream from the Amos Plant. Although currently there is a
limited amount of information available on the environmental impacts of coal combustion
wastewater on lotic systems, Lemly's results show that discharges from coal-fired power plants
can affect organisms living downstream in lotic environments [Rowe et al., 2002].
Sediments in Surface Waters
Sediments present in both lentic and lotic aquatic environments play a major role in the
residence time of coal combustion wastewater pollutants. Sediments act as long-term storage
sites for contaminants, serving as an exposure source for organisms and downstream waters even
after coal combustion wastewater discharges have ceased [Rowe et al., 2002]. This characteristic
causes recovery of aquatic systems following coal combustion wastewater release to be
extremely slow [Rowe et al., 2002]. A 1985 study by Lemly found that detrital pathways (i.e.,
processes associated with decomposition) in Belews Lake provided toxic doses of sediment-
stored selenium to local biota many years after water concentrations of selenium were below
levels of concern [Rowe et al., 2002]. The recovery of aquatic systems is particularly slow when
sediment release acts in combination with a lentic system to continuously expose and reintroduce
bioaccumulative pollutants to aquatic organisms. These factors cause pollutant levels in aquatic
organisms to steadily rise because the pollutants remain stationary due to the slow-moving water,
the organisms are exposed to additional pollutants that are released from sediments over time,
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Final Detailed Study Report Chapter 6 - Environmental Assessment of Coal Combustion Wastewater
and the tissue concentrations of aquatic organisms increase beyond levels available in the water
due to bioaccumulative properties.
6.2.2 Leaching to Groundwater
Pollutants in coal combustion wastewater and coal combustion wastes (e.g., ash, gypsum,
calcium sulfite) can impact local groundwater systems through leaching from surface
impoundments, landfills, and minefills. Coal combustion wastewater held in unlined surface
impoundments can infiltrate through the subsurface and enter the groundwater system. Unlined
landfills and minefills, used to dispose of coal combustion residues, are also subject to leaching
as rainfall penetrates the residue pile dissolving pollutants into the pore water, which eventually
migrates to aquifers. Pollutants from coal combustion wastewater can also enter the groundwater
system when liners fail or when a disposal site is inappropriately situated such that natural
groundwater fluctuations come into contact with the disposed-of waste. As Table 6-2 indicates,
EPA has identified 51 instances where coal combustion wastes and wastewater have caused
impacts to ground water.
Older disposal sites are of particular concern because most of these surface
impoundments and landfills were not built with liners. Although the use of liners for surface
impoundments and landfills is increasing at new facilities, many states do not require basic
environmental protection standards such as leachate collection systems and impermeable liners
[Roweetal., 2002].
Once in the groundwater system, coal combustion wastewater pollutants have the
potential to migrate from the site at concentrations that could contaminate drinking water wells
and surface waters [NRC, 2006]. The fate of coal combustion wastewater pollutants in
groundwater systems is controlled by an array of geochemical (e.g., adsorption, desorption, and
precipitation reactions with aquifer materials) and biological processes that can vary over large
spatial and temporal scales [NRC, 2006]. For example, pollutants leaching from unweathered
coal combustion residues disposed of in landfills and minefills may experience an initial set of
rapid dissolution and desorption reactions followed by slower reactions as alkalinity is leached
from the residue pile over time [NRC, 2006].
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Chapter 6 - Environmental Assessment of Coal Combustion Wastewater
The degree of degradation caused
by coal combustion wastewater leaching
into groundwater systems depends on the
type and concentration level of the
pollutants, volume of contaminated water
entering the subsurface, and the ability of
the aquifer to dilute or attenuate the
contamination [NRC, 2006]. Some coal
combustion wastewater pollutants may
be unaffected by subsurface geochemical
processes and move freely with the
groundwater flow, readily contaminating
local drinking water wells and surface
waters [NRC, 2006]. However, other
pollutants may be subject to adsorption
or precipitation reactions or transformed
by microbiotic mediated biological
reactions altering the extent of the
contamination [NRC, 2006].
The rate of pollutant transport in
groundwater systems depends on several
factors such as the biogeochemical
characteristics of the subsurface (e.g.,
soil pH and oxidation-reduction
potentials), local rates of groundwater
recharge, and unsaturated and saturated
groundwater flow velocities. Predicting
the transport of coal combustion
pollutants in groundwater can be
challenging due to the wide range of
biogeochemical characteristics that can
exist between sites and within a given site. Groundwater models that require information on the
groundwater chemistry, the mass and form of mineral phases present at the site, and the
dominant microbially mediated geochemical reactions can be used to predict the potential for
transport. However, the conditions (e.g., pH, oxidation-reduction conditions, and hydraulic
conductivity) influencing the field behavior of coal combustion wastes over the extended time
frames typically encountered at coal combustion wastewater disposal sites is poorly understood
[NRC, 2006]. Pollutant transport times can vary significantly and it might take relatively little
time or many years before pollutants from coal combustion wastewater degrade local drinking
water wells and surface waters. For example, in the damage case at the Wisconsin Electric Power
Company facility in Port Washington, Wisconsin, fly ash had been disposed of in a quarry for
over 20 years (1943-1971) prior to the selenium and boron contamination being reported in a
down-gradient private drinking water well [U.S. EPA, 2007c]. This suggests that a longer period
of groundwater monitoring may be required at some sites to adequately assess the full release of
contaminants, which can occur over several decades [NRC, 2006]. In addition to potentially long
temporal scales, groundwater contamination can occur on large spatial scales based on the
Groundwater Case Study: Constellation Ash Disposal
at Waugh Chapel and Turner Pits
Anne Arundel County, Maryland
For over a decade, Constellation Energy Group
(Constellation) supplied fly ash for structural fill at the
B.B.S.S. Inc. (BBSS) sand and gravel mines in Anne
Arundel County, Maryland. Fly ash from Constellation's
Brandon Shores and Wagner plants were used to reclaim
portions of BBSS' Turner Pit starting in 1995 and the
Waugh Chapel Pit starting in 2000. In the fall of 2006,
Anne Arundel County Health Department officials
documented concentrations of sulfate and metals (i.e.,
antimony, beryllium, cadmium, manganese, and nickel)
exceeding the state's screening criteria for potable aquifers
in residential wells located downgradient from Waugh
Chapel and Turner Pits [Erbe et al., 2007].
An independent study of the contamination
confirmed that the elevated concentrations of sulfate and
metals observed in the wells were the direct result of
precipitation infiltrating the fly ash deposited in the BBSS
sand and gravel mines [Erbe et al., 2007]. In October
2007, MDE fined Constellation and BBSS $1 million for
the ground water contamination and included requirements
for the companies to restore the local aquifer water quality
[MDE, 2008]. In addition, a group of Anne Arundel
homeowners impacted by the contamination filed a class
action lawsuit against Constellation and were awarded a
$45 million settlement that required Constellation to pay
the costs for converting 84 homes from well water to
public water; cease future deliveries of new coal ash to the
quarry; and to establish trust funds to compensate
impacted property owners, enhance the neighborhood, and
remediate and restore a former quarry site [Schultz, 2008].
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hydraulic properties of the subsurface traveling long distances before it encounters a drinking
water well or discharges as a spring or as seepage into a stream, lake, or ocean [NRC, 2006].
6.2.3 Surface Impoundments and
Constructed Treatment Wetlands
as Attractive Nuisances
The environmental characteristics
of settling ponds or surface
impoundments and constructed wetlands
that are used to treat coal combustion
wastewater often support an ecosystem
unto themselves that attracts wildlife to
these waste and wastewater storage
areas. Surface impoundments can be
classified as a lentic system supporting
aquatic vegetation and organisms, and
serving as an attractive nuisance that
draws wildlife from other terrestrial
habitats. An attractive nuisance is
typically defined as an area or habitat
that is attractive to wildlife and that is
contaminated with pollutants at
concentrations high enough to potentially
cause harm to exposed organisms.
As an attractive nuisance, surface
impoundments holding coal combustion
wastewater may impact local wildlife as
well as transient species that may rely on
them during critical reproduction periods
such as seasonal breeding events [Rowe
et al., 2002]. Exposure to coal
combustion wastewater during sensitive
life cycle events is potentially of concern
given that exposure to coal combustion
wastewater has been associated with
complete reproductive failure in various
vertebrate species [Rowe et al., 2002].
6.3 Types of Environmental Effects
Surface Impoundment Case Study:
Gibson Lake and Cane Ridge Wildlife Management
Area (WMA) Gibson County, Indiana
Gibson Lake is a large (3,000-acre) man-made
shallow impoundment that provides cooling water for
Duke Energy's Gibson Generating Station located near the
Wabash River in Gibson County, Indiana. In addition to
cooling water discharges, the lake also receives ash pond
effluent. Starting in 1986, least terns, an endangered
species of migratory birds, began using the dike in Gibson
Lake as a nesting ground for breeding [Pruitt, 2000]. By
1993, nearby ash ponds at the Gibson Generating Station
were also attracting nesting least terns, placing these
sensitive species in direct contact with coal combustion
wastewater. To address the attractive nuisance problem
presented by the ash ponds and Gibson Lake, the Gibson
Generating Station began a cooperative program with the
Indiana Department of Natural Resources to protect the
nesting birds by creating a nearby alternative habitat
known as the Cane Ridge WMA [Pruitt, 2000]. To create
the new habitat, water from Gibson Lake was pumped into
ponds at the Cane Ridge WMA.
In April of 2007, Duke Energy closed access to
Gibson Lake for recreational fishing due to elevated
selenium levels [Duke Energy, 2007]. Selenium levels in
the lake fish presented a human health risk based on
EPA's recommended concentration for subsistence fishers.
A year later, the U.S. Fish and Wildlife Service (USFWS)
became concerned about selenium levels in the water and
fish present in the Cane Ridge WMA. A result, the
USFWS decided to immediately stop the flow of water
from Gibson Lake into Cane Ridge, discourage least terns
from using the refuge, draw down the water in the ponds,
and remove the contaminated fish [USFWS, 2008]. In
addition, the pond bottom was plowed to redistribute and
bury the selenium in the soil and water was piped in from
the Wabash River, instead of from Gibson Lake. Duke
Energy paid to stock the Cane Ridge ponds with fathead
minnows to lure back migratory birds. As of June 2009
avocets, dunlins, black terns, Forster's terns, Caspian terns
and 50 endangered least terns have returned to Cane Ridge
[USFWS 2009].
The discharge of coal combustion wastewater from coal-fired power plants has caused a
wide range of environmental effects to local aquatic life. Studies have documented numerous
ecological impacts from the intentional and accidental release of coal combustion wastewaters,
as well as through detailed laboratory and field studies examining the toxicity of the
characteristics of coal combustion wastewater. Environmental effects documented in the
literature can be broken into the following three categories:
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• Lethal effects - fish kills and mortality to other organisms;
• Sublethal effects - histopathological changes, or accumulation of trace elements
in tissue, and damage to reproductive and developmental success; and
• Population and community effects - changes in species abundance and
composition.
In addition to a direct impact on aquatic ecology and local wildlife, coal combustion
wastewater has also resulted in other environmental impacts such as altering local habitats,
contaminating drinking water, and resulting in fish advisories.
6.3.1 Lethal Effects
Fish kills are one of the most
common lethal effects documented in the
literature from exposure to coal
combustion wastewater. In many cases,
fish kills are the result of the accidental
release of coal combustion wastewater;
however, fish kills have been associated
with the intentional discharge of coal
combustion wastewater. In a number of
these documented fish kills, coal
combustion wastewater was discharged
to what appeared to be a healthy aquatic
habitat until lethal effects such as fish
kills were observed in the system. For
example, in 1978 the Texas Utilities
Generating Company located in Martin
Creek, Texas, began discharging coal
combustion wastewater from two fly ash
settling ponds into a 2,000-hectare
cooling water reservoir located on the
facility's property. Within eight months
after the discharges began, a major fish
kill occurred in the reservoir prompting
Texas Utilities to cease discharging coal combustion wastewater into the reservoir. The sudden
appearance offish kills and other ecological effects, such as developmental abnormalities and
reproductive failure, in aquatic systems receiving coal combustion wastewater prompted
numerous research studies to identify the extent of damage and the specific cause. In a 1981
study conducted by Carolina Power and Light Company, Environmental Services Station at
Hyco Reservoir, scientists concluded that elevated selenium concentrations were likely the
primary factor contributing to fish kills and to lethal effects towards amphibians and crustaceans
[Rowe et al., 2002]. Long-term studies of aquatic environments exposed to coal combustion
wastewater found that, after experiencing fish kills, the affected environments can experience
population and community effects for many years before biomass returns to normal levels [Rowe
etal., 2002].
Lethal Effects Case Study:
Hyco Reservoir, North Carolina
Hyco Reservoir is a large cooling reservoir
located in Roxboro, North Carolina. In addition to
receiving cooling tower blowdown, the reservoir also
received effluent from fly ash basins prior to 1981. In the
fall of 1981, a large-scale fish kill occurred in the reservoir
prompting numerous scientific studies to examine the
extent and cause of the environmental damage.
In a 1981 study conducted by Carolina Power &
Light, fish and water chemistry samples were collected in
the reservoir to evaluate the cause of the fish kill. Water
samples indicated that dissolved selenium concentrations
were quite high (up to 5.5 ppb), whereas concentrations of
other coal combustion wastewater-derived trace elements
were not elevated. Similarly, fish tissue samples exhibited
high concentrations of selenium, while other trace
elements were within normal concentration ranges.
Bluegill fish livers were found to have selenium
concentrations approximately 50 times greater than liver
concentrations found in fish not exposed to water from
Hyco Reservoir. While other coal combustion wastewater-
derived trace elements may also contribute to lethal
effects, this case study indicates that elevated selenium
concentrations from coal combustion wastewater can
result in lethal effects, such as fish kills.
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Laboratory and outdoor mesocosm studies have confirmed that both acute and chronic
exposure to coal combustion wastewater can be lethal to a wide range of aquatic organisms. For
example, in a 1976 study by Guthrie and Cherry, shrimp darters and salamanders were found to
be highly sensitive to acute exposures of coal combustion wastewater. In the study, shrimp
darters and salamanders caged for five days in a drainage basin outflow located on the D-Area
Power Facility grounds experienced nearly 100 percent mortality [Rowe et al., 2002].
Invertebrates and fish in the study were also affected by the exposure to coal combustion
wastewater; however, they reported lower rates of mortality [Rowe et al., 2002]. In a 2001 study
by Hopkins, juvenile chubsuckers (a benthic fish) demonstrated a high sensitivity to chronic
exposure to coal combustion wastewater [Rowe et al., 2002]. In this outdoor mesocosm study,
organisms were exposed to sediments, water, and food from the D-Area Power Facility grounds,
and experienced a 75 percent mortality rate after 45 days. These studies and others indicate that
the lethal effects of coal combustion wastewater exposure can be quite potent, even though
extreme differences in species sensitivity have been observed [Rowe et al., 2002].
6.3.2 Sublethal Effects
Sublethal effects from exposure to coal combustion wastewater can vary widely and
include changes that impact growth, reproduction, and survival of susceptible organisms.
Numerous vertebrate and invertebrate species have demonstrated a sensitivity to coal combustion
wastewater and developed sublethal conditions such as increased metabolic rates, decreased
growth rates, abnormal teeth and fin morphology, accumulation of trace elements in tissue, and
reproductive failure [Rowe et al., 2002]. Sublethal effects documented in the literature are
primarily linked to exposure to selenium concentrations present in coal combustion wastewater;
however, sublethal effects have also been attributed to a number of other coal combustion
wastewater pollutants such as arsenic, cadmium, chromium, copper, and lead [Rowe et al.,
2002].
Histopathological effects (i.e., accumulation of trace elements in tissue), increased
metabolic rate, and decreased growth rates are typical growth effects caused by coal combustion
wastewater contamination. Water and fish samples collected before and after the discharge of
coal combustion wastewater to the Texas Utilities Martin Creek Reservoir found that selenium
concentrations were significantly elevated in the reservoir and in fish livers, kidneys, and gonads
[Rowe et al., 2002]. In 1984, Garrett and Inman reported that elevated selenium concentrations
persisted in the livers and kidneys of several species offish for up to three years after the coal
combustion wastewater discharges ceased [Rowe et al., 2002]. Additionally, a 1988 study by
Sorensen found that red ear sunfish native to the reservoir exhibited ovary abnormalities related
to elevated selenium concentrations up to eight years following the brief exposure to coal
combustion wastewater [Rowe et al., 2002]. Although the ash pond discharge was short-lived
(i.e., eight months), many of the histopathological effects persisted for years after the discharge
had ceased [Rowe et al., 2002].
Fish are not the only organisms with documented sublethal impacts from exposure to coal
combustion wastewater. Several studies have demonstrated increased metabolic rates and
decreased growth rates in crustaceans exposed to coal combustion wastewater. In Rowe's 1998
study, grass shrimp caged in situ in the D-Area Power Facility's secondary settling basin
experienced a 51 percent increase in standard metabolic rate after eight months [Rowe et al.,
2002]. Similarly, crayfish captured in the vicinity of the secondary basin as well as crayfish
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collected from unpolluted sites and exposed to sediments and food collected from the secondary
basin both experienced increased metabolic rates and decreased growth rates. These changes in
metabolism reflect that the organism wastes energy during normal metabolic processes in
response to contaminant exposure and accumulation [Rowe et al., 2002].
Exposure to coal combustion wastewater has caused a number of organisms to experience
reproductive failure and other forms of diminished reproductive success. A 1986 study by
Gillespie and Baumann at Hyco Reservoir found that bluegill sunfish exposed to coal
combustion wastewater accumulated selenium in ovarian tissue. Affected sunfish produced
edematous, or fluid-swelled, larvae that died before maturing [Rowe et al., 2002]. Maternal
transfer of coal combustion wastewater pollutants to offspring has been observed for several
species. A 2001 study conducted by Nagle et al. at the D-Area Power Facility found that turtles,
alligators, and birds inhabiting the vicinity of the settling basins and drainage swamp transfer
coal combustion wastewater contaminants to developing offspring [Rowe et al., 2002]. Nagle et
al., however, concluded that this transfer of contaminants did not cause any noticeable biological
ramifications [Rowe et al., 2002].
Morphological changes that affect survival have also been observed for organisms
exposed to coal combustion wastewater. A 2003 laboratory study by Hopkins et al. found that
the sustained swimming speed and burst swimming speeds of the lake chubsucker (fish) were
greatly reduced when exposed to coal combustion wastewaters [Rowe et al., 2002]. This
reduction in speed was caused by fin abnormality, a morphological change that can be attributed
to exposure to coal combustion wastewater [Rowe et al., 2002]. A study of larval bullfrogs living
in the D-Area Power Facility's secondary settling basin found that more than 95 percent of
individuals had abnormal oral structures, such as the absence of grazing teeth or entire rows of
teeth. Rowe et al.'s 1996 study found that these oral malformations changed the feeding ecology
of the affected individuals, limiting their feeding niche and subsequently reducing their growth
rate [Rowe et al., 2002]. A 1998 study by Raimondo et al. found that larval bullfrogs also
displayed abnormal swimming behavior, which was caused by malformations of their tails
[Rowe et al., 2002]. These abnormal larval bullfrogs, living in the secondary basin of the D-
Area, were more frequently preyed upon than were bullfrogs from an unpolluted site [Rowe et
al., 2002].
6.3.3 Population and Community Effects
In addition to environmental effects on individual organisms, coal combustion
wastewater has the potential to modify higher-order ecological processes (i.e., population and
community dynamics) in the surrounding ecosystems. Changes to the number of aquatic
organisms and wildlife present in a system, interspecies interactions, and the structure of aquatic
communities have all been linked to contamination of aquatic habitats by coal combustion
wastewater [Rowe et al., 2002].
Numerous studies have documented the decline in invertebrates, fish, and local wildlife
populations following exposure to coal combustion wastewater [Rowe et al., 2002]. Population
effects (i.e., decline in number of organisms present) have been attributed to lethal effects of
pollutants present in coal combustion wastewater, declines in organism survival rates from
abnormalities attributed to coal combustion wastewater exposure, and declines in the abundance
or quality of prey. For example, many species of benthic fish rely on small invertebrates as a
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Final Detailed Study Report Chapter 6 - Environmental Assessment of Coal Combustion Wastewater
source of food and, when the food source is diminished (i.e., lower invertebrate abundance and
density), benthic fish exhibit higher mortality rates and smaller growth than fish exposed to coal
combustion wastewater with high quality food sources [Rowe et al., 2002]. In a 1980 study of
Rocky Run Creek by Forbes and Magnuson, fungal decomposition of detritus was extremely
limited due to the effects of coal combustion wastewater. Benthic invertebrates, which graze on
detrital material, displayed a lower population density as a result. Similarly, benthic fish that
prey upon small invertebrates exhibited increased mortality due to a reduction in available
resources, and therefore a decreased population density [Rowe et al., 2002].
In addition to density effects, communities have experienced alterations in species
diversity due to exposure to coal combustion wastewater. In the Martin Creek Reservoir, during
a short eight-month period of coal combustion wastewater input, both planktivorous (i.e., diet
primarily consists of plankton) and carnivorous (i.e., diet primarily consists of meat) fish
experienced severe reductions in total biomass, while omnivorous (i.e., diet consists of meat and
plants) fish increased in biomass [Rowe et al., 2002]. A study by Garrett and Inman in 1984
found that in the three years after the effluent release was halted, planktivorous fish populations
remained extremely low, while carnivorous fish populations nearly recovered. This recovery
occurred because carnivorous fish have a more diverse diet than planktivorous fish, so food
availability increased relatively quickly as the aquatic system recovered [Rowe et al., 2002].
These changes in population diversity indicate a significant change in community structure as a
result of exposure to coal combustion wastewater.
In contrast to the Martin Creek Reservoir studies, coal combustion wastewater can also
affect species diversity in the top predators of the food chain. In 1993, a study conducted by
Lemly at Belews Lake found that large predatory fish were some of the first fish species to die
out completely, due to the lethal and sublethal effects of coal combustion wastewater exposure
[Rowe et al., 2002]. Because a top predator was no longer present, some fish that exhibited
developmental abnormalities were able to survive, despite their otherwise high susceptibility to
predation [Rowe et al., 2002].
Density and diversity effects caused by coal combustion wastewater contamination have
the potential to be wide-ranging geographically. A 1972 study by Cairns et al. examined the
effects of an ash effluent spill from the AEP Clinch River Power Plant into the Clinch River in
Virginia. A dike surrounding an ash settling pond collapsed, releasing effluent with a pH greater
than 12.0 and killing more than 200,000 fish. The study observed drastic reductions in both
diversity and densities of aquatic organisms [Carlson and Adriano, 1993]. A follow-up survey
taken two years after the spill indicated that some recovery was occurring, but the diversity and
density of benthic fauna was still greatly reduced downstream from the spill [Carlson and
Adriano, 1993].
6.3.4 Human Health Impacts
In addition to the individual and community ecological impacts discussed above, coal
combustion wastewater has been linked to human health concerns as a result of elevated
pollutant concentrations in surface water and groundwater, which have resulted in fish advisories
and groundwater that has exceeded SDWA MCLs.
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Metals and other pollutants present in coal combustion wastewater may contaminate
actual or potential drinking water sources by leaching from surface impoundments or landfills
into groundwater or surface waters. For example, at the Chisman Creek Disposal Site, a fly ash
landfill in Virginia, water in nearby residential wells turned green and testing revealed the wells
were contaminated with selenium and sulfate from groundwater contaminated with leachate from
coal combustion wastewater [NRC, 2006]. EPA closed the residential wells to reduce the risk of
human exposure to coal combustion pollutants [NRC, 2006]. EPA's ORCR has documented
instances where coal combustion wastewater contaminated groundwater at concentrations
exceeding EPA's MCL for drinking water [U.S. EPA, 2007c]. Although the contaminated
groundwater sources may not directly be used as a drinking water source in all cases, the
contamination represents a possible human health risk due to the potential for groundwater to
impact other nearby aquifers and surface waters designated as drinking water sources.
EPA has also identified cases of human health concerns related to coal combustion
wastewater causing elevated pollutant concentrations in biota. Fish consumption advisories are
the most common human health concern and are issued in response to elevated pollutant
concentrations in fish that are considered unsafe for human consumption. In 1992, the Texas
Parks and Wildlife Department's monitoring program documented elevated levels of selenium in
fish at the Southwestern Electric Power Company Welsh Reservoir in Mount Pleasant, Texas.
The reservoir received influent from ash settling ponds, which was the likely source of high
selenium levels. In response to these elevated levels, the Texas Commissioner of Health issued a
fish advisory that lasted for 12 years before it was lifted. A similar case identified by EPA
occurred in the Brandy Branch Reservoir in Marshall, Texas. The cooling reservoir received ash
pond effluent from Southwestern Electric Power Company's Pirkey Power Plant [U.S. EPA,
2007c]. Studies by the Texas Parks and Wildlife Department reported that average selenium
concentrations in fish nearly tripled between 1986 and 1989, once coal combustion wastewater
discharges began [U.S. EPA, 2007c]. The Texas Department of Health issued a fish consumption
advisory that lasted from 1992 to 2004 [U.S. EPA, 2007c].
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7. PRELIMINARY INVESTIGATION OF OTHER INDUSTRY SEGMENTS
As described in Chapter 3, the electric generating industry is generally categorized by
NAICS Code 2211. However, prior to the introduction of NAICS codes, the electric generating
industry had been categorized by three Standard Industrial Classification (SIC) codes:
• 4911 - Electric services. Establishments engaged in the generation, transmission,
and/or distribution of energy for sale.
• 4931 - Electric and other services combined. Establishments primarily engaged
in providing electric services in combination with other services when the electric
services are the major part of the services, but are less than 95 percent of the total
services.
• 4939 - Combination utilities, not elsewhere classified. Establishments primarily
engaged in providing combinations of electric, gas, and other services, not
elsewhere classified.
It should be noted that these SIC codes include all electric generating plants, not just
steam electric plants. For example, some of the plants included in SIC code 4911 generate
electricity solely by way of combustion turbines or hydroelectric turbines (i.e., steam is not used
to move the turbine). EPA did not investigate the operations at power plants that do not use a
water/steam thermodynamic medium to generate electricity (e.g., combustion turbines,
hydroelectric plants). However, during the detailed study, EPA evaluated certain electric power
and steam generating activities that are similar to the processes regulated for the Steam Electric
Power Generating Point Source Category, but are not currently subject to the effluent guidelines.
EPA assessed information regarding the following types of plants and operations:
• Plants that generate electric power using steam to drive a turbine, but whose
energy/heat source used to produce the steam is not a fossil or nuclear fuel
(referred to in this report as "alternative-fueled" plants). These energy sources
may include combustible fuels (e.g., municipal solid wastes, wood and wood
wastes, landfill gas) or other energy sources, such as solar power and geothermal
energy.
• Industrial plants that generate electric power using steam to drive a turbine, but
that are not primarily engaged in distributing and/or selling that electric power
(referred to in this report as "industrial non-utilities"). These industrial steam
electric non-utilities provide electric power to an industrial process (e.g., chemical
manufacturing, petroleum refining) and in some cases may sell excess electrical
power to the grid. EPA's focus for these plants is on the waste streams generated
by the electric generating units, and not the other waste streams generated by the
primary industrial processes at the plant.
• Plants that generate steam for distribution and/or sale, but that do not primarily
use that steam to drive a turbine and produce electric power (referred to in this
report as "steam and air conditioning supply" plants).
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Final Detailed Study Report Chapter 7 - Preliminary Investigation of Other Industry Segments
• Plants that provide a combination of electric power and other utility services (i.e.,
SIC Code 4939 - referred to in this report as "combination utilities"). EPA
specifically focused on those combination utilities that generate electric power by
using steam to drive a turbine.
This chapter describes the information EPA obtained during the detailed study regarding
these types of operations and resulting wastewaters. Section 3.1 provides additional definitions
and demographics for the electric generating industry.
7.1 Alternative-Fueled Steam Electric Plants
This section describes EPA's study of alternative-fueled steam electric plants, which
produce electricity for distribution and/or sale using steam that is created by means other than
fossil-fueled or nuclear-fueled processes. In this report, alternative-fueled steam electric plants
refer to those plants that produce steam by combusting a solid or gaseous alternative fuel, those
that use steam from geothermal reservoirs (geothermal steam electric plants), and those that
produce steam using the sun's energy (solar steam electric plants).
EPA reviewed NPDES permits for a prioritized subset of alternative-fueled steam electric
plants to identify sources of wastewater and determine how wastewater discharges from these
plants are currently regulated (e.g., whether the Steam Electric Power Generating effluent
guidelines are applied using best professional judgment (BPJ)). Additionally, EPA contacted
several companies operating alternative-fueled steam electric plants to discuss the operations and
wastewaters generated at the plants related to steam or electricity production.
Wastewater generated by alternative-fueled steam electric processes is not currently
regulated by the Steam Electric Power Generating effluent guidelines, because the electricity
does not result"... primarily from a process utilizing fossil-type fuel (coal, oil, or gas) or nuclear
fuel...", as defined at 40 CFR Part 423.10. Information that EPA obtained during the detailed
study indicate that these alternative-fueled plants use similar processes to plants that are
regulated under the Steam Electric Power Generating effluent guidelines. In fact, many of these
alternative-fueled plants also combust fossil fuels as a secondary energy source to generate the
steam (40 percent of plants), typically within the same generating unit and typically natural gas
or oil instead of coal. Because many of the waste streams generated from the operation of
combustion processes are associated with the handling of fuel wastes (e.g., ash transport water),
the characteristics of the wastewaters may vary depending on the type of fuel used by the plant.
During the detailed study, EPA collected little information about the pollutants and
associated concentrations in the wastewater discharged from steam electric processes using
alternative fuels. However, EPA determined that these plants generally produce a much smaller
amount of electricity and discharge a smaller amount of wastewater to the environment than
steam electric plants regulated by the Steam Electric Power Generating effluent guidelines. EPA
also determined that permits regulating the discharges from alternative-fueled plants vary from
plant to plant and are dependent on both the type of fuel used and the handling of the
wastewaters generated. EPA found that some of the permits reviewed contained few limits based
on the Steam Electric Power Generating effluent guidelines, while others wholly incorporate the
Steam Electric Power Generating effluent guidelines limits.
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7.1.1 Demographic Data for A Iternative-fueled Steam Electric Plants
The 2005 EIA database includes 198 plants that reported a NAICS code of 22 (Utilities)
and the use of an alternative fuel as a primary energy source to drive a steam turbine. Some of
these plants use alternative fuels in combination with a fossil-type (i.e., 423-type) fuel. Three of
the 198 plants reported operating an electric generating unit burning a fossil fuel as a primary
energy source, in addition to the electric generating unit(s) burning alternative fuels. Seventy-six
of the 198 plants reported using both an alternative fuel and a fossil fuel to power the same
generator (the fossil fuel is reported as the secondary or tertiary energy source); however, these
secondary fossil fuel energy sources may be serving as a starter or supplemental fuel in the
boiler.
The average electric generating capacity for alternative-fueled plants in the 2005 EIA
database is less than 50 MW. Excluding geothermal steam electric plants, the 156 alternative-
fueled plants produce less than one percent of the electricity produced by the fossil- and nuclear-
fueled steam electric plants currently regulated by the Steam Electric Power Generating effluent
guidelines. EPA did not include geothermal steam electric plants in this calculation because they
are assumed not to directly discharge wastewater [CEP A, 2006d; CEP A, 2006c; U.S. DOE,
2006a]. Table 7-1 presents a breakdown of plant energy capacity by fuel type. Section 3.1.2.2 of
this report provides additional detail on the demographics of the Steam Electric Power
Generating Point Source Category.
EPA is not aware of any analyses demonstrating that pollutant loadings are correlated to
electric power generated; however, EPA believes it is reasonable to assume that alternative-
fueled plants will produce smaller pollutant loadings than those produced by steam electric
plants with energy capacities that are one or two orders of magnitude larger.
7.1.2 Alternative-Fueled Steam Electric Fuel Types and Processes
The steam electric generating process used at alternative-fueled steam electric plants is
similar to that used by all steam electric plants, as described in Section 3.2, in that these plants
use a steam/water system as the thermodynamic medium to produce electricity. Alternative-
fueled steam electric plants use steam (which may or may not be produced in a boiler) to drive a
steam turbine/electric generator and condense the steam by noncontact cooling.
Because the alternative-fueled process operations are similar to those of the steam electric
plants regulated under the Steam Electric Power Generating effluent guidelines, they may
generate many of the same types of wastewaters (e.g., ash transport water, boiler blowdown,
cooling water). Because there are similar operations between the different types of plants, the
wastewaters that do not directly contact the fuel (i.e., boiler blowdown, cooling water) may have
similar pollutant characteristics. Because these wastewaters are not associated with the fuels used
at the plant, they are likely to be similar in characteristics to the wastewaters generated by the
steam electric plants regulated under the Steam Electric Power Generating effluent guidelines.
The wastewaters that do contact the fuel (e.g., fuel storage runoff) or the fuel wastes (ash
transport water) may not have similar characteristics as the wastewaters generated by steam
electric plants regulated under the Steam Electric Power Generating effluent guidelines because
the different fuels have different constituents.
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Table 7-1. Summary of Alternative-Fueled Steam Electric Plants, by Fuel/Energy Source
Type
Fuel/Energy Source
Number of Plants
Total Capacity a
(MW)
Steam Electric Plants Regulated Under the Steam Electric Power Generating effluent guidelines
Fossil and Nuclear Fuel
1,187
762,000
Alternative-Fueled Steam Electric Plants
Municipal Solid Waste
Wood Solid Waste
Solar
Landfill Gas
Agricultural By-products
Other Biomass Solids
Tires
Other Biomass Gas
Total for Alternative-Fueled Facilities (excluding Geothermal)
Geothermal °
59
66
9
12
5
2
2
1
156 b
42
2,270
1,830
400
261
184
58
57
23
5,080
2,950
Source: [U.S. DOE, 2005a].
Note: The table includes only the capacity associated with stand-alone steam turbines, combined cycle steam
turbines, combined cycle single shaft turbines, and combined cycle combustion turbines.
a - The capacities represent the reported nameplate capacity. The capacities presented have been rounded to three
significant figures. Due to rounding, the total capacity may not equal the sum of the individual capacities.
b - It is possible that some of these 156 alternative-fueled plants may be cogeneration plants, as discussed in Section
3.2.1.
c - Steam electric processes using geothermal energy sources are assumed not to generate wastewater [CEPA,
2006d; CEPA, 2006c; U.S. DOE, 2006a].
The steam electric process, sources of wastewater, potential wastewater pollutants,
current operating practices, and current permitting practices for various types of alternative-
fueled steam electric plants are discussed below by type of fuel.
7.1.2.1 Solid Fuels
Steam electric plants fueled by solid alternative fuels (e.g., municipal solid waste (MSW),
wood solid waste, agricultural by-products, tires) use a similar process as those plants that are
currently regulated under the Steam Electric Power Generating effluent guidelines. These
alternative-fueled steam electric plants combust a solid fuel, typically in a boiler, to produce
steam, which powers a steam turbine/electric generator. This combustion process generates ash.
The steam exiting the turbine is condensed with cooling water and the condensate is typically fed
back to the boiler. Thus, steam electric plants fueled by solid alternative fuels generate some of
the same types of wastewaters as those currently regulated under the Steam Electric Power
Generating effluent guidelines. As described in Section 3.2.1, these wastewaters include fly ash
and/or bottom ash transport water, metal cleaning wastes, once-through cooling water and/or
recirculating cooling tower blowdown, fuel storage runoff, boiler feedwater treatment wastes,
boiler blowdown, and other low-volume wastes [CEPA 2006a; CEPA, 2006b; U.S. DOE, 2000a;
IDNR, 2006a; Fairfax, 2006; U.S. EPA, 2006i; FDEP, 2006].
7-4
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Chapter 7 - Preliminary Investigation of Other Industry Segments
The types of solid alternative fuels included in EPA's study of alternative-fueled steam
electric plants are discussed below.
Municipal Solid Waste
Typical constituents of MSW include paper, paperboard, yard waste, plastics, metals,
glass, food waste, wood, rubber, leather, and textiles. Refuse-derived fuel is produced from
MSW through processing steps such as, at a minimum, coarse shredding of the MSW and
magnetic separation of ferrous metals [Kirk-Othmer, 2000].
At the time of the initial 1974 Steam Electric Power Generating effluent guidelines, EPA
identified one steam electric plant in the United States as using refuse-derived fuel for 10 percent
of its fuel [U.S. EPA, 1974]. As shown in Table 7-1, there were 59 plants operating electric
generating units powered by municipal solid waste in 2005 [U.S. DOE, 2005a]. The 1974
Development Document stated that incinerating "garbage" produces moderate amounts of
hydrogen chloride, and that EPA should continue to study the disposal of the effluents from
steam electric plants using these alternative fuels.
During the detailed study, EPA obtained data on the pollutant concentrations found in
MSW ash, wood ash, and coal ash. Although the compositions of these ashes vary significantly
depending on the type of material that is combusted and the location that the ash is sampled (e.g.,
fly ash, bottom ash), EPA noted general differences between MSW ash and coal ash. Table 7-2
presents the range of concentrations associated with both the bottom and fly ash generated from
coal ash, MSW ash, and wood ash (which is discussed below). As shown in Table 7-2, MSW ash
can contain significantly higher amounts of barium, cadmium, mercury, molybdenum, nickel,
selenium, and zinc than coal ash.
Table 7-2. Comparison of Available Coal Ash, Municipal Solid Waste Ash, and Wood Ash
Composition Data
Component
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chloride
Chromium (III)
Chromium (VI)
Chromium - Total
Cobalt
Copper
Cyanide
Coal Ash
(ppm)
60,000 - 157,000
NIA
10.4-169.6
210-310
NIA
14-618
7- 10
3,100 - 125,600
NIA
NIA
NIA
NIA
NIA
NIA
NIA
Municipal Solid Waste Ash
(ppm)
NIA
NIA
2.9-50
79 - 2,700
ND - 2.4
24 - 174
0.18-100
NIA
NIA
NIA
NIA
12 - 1,500
1.7-91
40 - 5,900
NIA
Wood Ash
(ppm)
NIA
9-11.58
1-28.5
130 - 527
ND-2
1 - 16.9
1-16
NIA
382.35-3,200
43
0.7-4
16.8-33.55
4.6 - 20
31.3-176.5
0.08-6
7-5
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Final Detailed Study Report
Chapter 7 - Preliminary Investigation of Other Industry Segments
Table 7-2. Comparison of Available Coal Ash, Municipal Solid Waste Ash, and Wood Ash
Composition Data
Component
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Potassium
Selenium
Silicon
Silver
Sodium
Strontium
Thallium
Titanium
Vanadium
Zinc
Coal Ash
(ppm)
3,000 - 163,000
NIA
900 - 60,200
NIA
ND-0.08
5.6-39.3
123 - 242
300 - 2,800
6,500-31,900
7.6-36.1
302,000-331,000
NIA
560 - 1,200
NIA
NIA
7,700-11,600
NIA
13-378
Municipal Solid Waste Ash
(ppm)
NIA
31 -36,600
700 - 16,000
14-3,130
0.05 - 17.5
2.4 - 290
13 - 12,910
NIA
NIA
0.1-50
NIA
NIA
NIA
12 - 640
NIA
NIA
NIA
92 - 46,000
Wood Ash
(ppm)
NIA
7.7 - 142.5
NIA
NIA
ND-0.6
3.0-14
11-50
NIA
23,220-59,918
ND-20
NIA
ND-4
934.25-3,110
NIA
ND - 70.5
NIA
22-27
130 - 886
Source: [Evangelou, 1996; Otero-Rey, 2003; Narukawa, 2003; Kirk-Othmer, 2000; CEP A, 2006b; WAI, 2003].
ND - Not detected.
NIA - No information available.
To obtain additional information about the process operations and wastewaters generated
from MSW plants, EPA reviewed EIA information and contacted two companies that operate
MSW plants. According to information EPA obtained from EIA and these two companies, most
of these plants operate dry FGD systems and baghouses or ESPs to remove the fly ash, sulfur
dioxide, hydrogen chloride, and hydrogen fluoride from the flue gas. At these plants, the
particulates collected in the baghouse or ESP are handled dry and transported to a landfill. The
bottom ash aggregate generated in the boiler is quenched in a water bath, which is drained, and
the quenched aggregate then goes through the metal recovery process and is transported to a
landfill. The water that drains off of the bottom ash is reused in the water bath. Therefore, most
of these plants do not generate and/or discharge FGD or ash transport water waste streams.
Additionally, some of the other wastewaters generated during the process (e.g., boiler blowdown,
cooling tower blowdown, low-volume wastewaters) are often reused as make-up water for the
bottom ash quench process or discharged indirectly to municipal wastewater treatment plants.
Therefore, it appears these MSW plants may discharge fewer, if any, wastewater streams directly
to surface waters than plants regulated by the Steam Electric Power Generating effluent
guidelines [Covanta, 2009; Xcel Energy, 2009c; Xcel Energy, 2009d].
7-6
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Final Detailed Study Report Chapter 7 - Preliminary Investigation of Other Industry Segments
Wood Solid Waste
Wood wastes combusted in steam electric processes typically consist of chipped lumber
and residuals from sawmills or other forest industry operations, including bark, trim ends,
sawdust, and planer shavings [Kirk-Othmer, 2000].
EPA obtained data on the pollutant concentrations found in wood ash, which is presented
in Table 7-2. As with MSW ash, EPA noted general differences between wood ash and coal ash.
Wood ash generally has a lower metal content (e.g., arsenic, boron, molybdenum, nickel, and
selenium) than coal ash; however, as shown in Table 7-2, wood ash often contains higher
amounts of potassium and zinc, and may contain slightly higher amounts of barium, cadmium,
and mercury, than coal ash.
To obtain additional information about the process operations and wastewaters generated
from wood solid waste plants, EPA contacted two companies that operate these types of plants.
According to information EPA obtained from the two companies, some of these plants operate
dry FGD systems and baghouses. However, not all of the plants operate a dry FGD system; some
just operate the baghouse. These systems remove the fly ash, sulfur dioxide, and hydrogen
chloride from the flue gas. The particulates that collect in the baghouse are handled dry and
transported to a landfill or beneficially reused. The bottom ash is typically handled dry, but if it
is handled wet, the water is drained from the solids and reused in the process. Therefore, these
types of plants do not generate and/or discharge any FGD or ash transport water waste streams.
The wastewaters that are typically discharged from these plants, indirectly to municipal
wastewater treatment plants in some cases, consist of cooling tower blowdown, boiler
blowdown, wash waters associated with operation areas, and other low-volume wastewaters
[Xcel Energy, 2009a; Xcel Energy, 2009b; U.S. Renewables Group, 2009].
Agricultural By-Products
Typical types of agricultural by-products combusted in steam electric processes include
bagasse (plant residue) from sugar-refining operations, rice hulls, orchard and vineyard prunings,
cotton gin trash, and the by-products of many other food and fiber-producing operations.
Agricultural wastes are relatively low in metals content, and the ash often contains a lower
metals content than coal and wood ash [Kirk-Othmer, 2000].
Tires
Scrap tires can be combusted in steam electric processes either in shredded form, which
is known as tire-derived fuel, or as whole tires. Scrap tires, which have a high heating value, are
often used as a supplement to other fuels, such as coal or wood. Tires produce roughly the same
amount of energy as oil and roughly 25 percent more energy than coal, by weight. The ash
residues from tire-derived fuel may contain lower heavy metals content than some coals [U.S.
EPA, 20061].
7.1.2.2 Gaseous Fuels
Steam electric plants fueled by gaseous alternative fuels (e.g., landfill gas) use a similar
process as those plants that are fueled by natural gas or other gases and are currently regulated
under the Steam Electric Power Generating effluent guidelines. These alternative-fueled steam
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Final Detailed Study Report Chapter 7 - Preliminary Investigation of Other Industry Segments
electric plants combust a gaseous fuel in a boiler to produce steam, which powers a steam
turbine/electric generator; however, like the natural gas combustion process, the gaseous
alternative fuel combustion process does not generate ash. The steam exiting the turbine is
condensed with cooling water and the condensate is typically fed back to the boiler. Thus, steam
electric plants fueled by gaseous alternative fuels generate some of the same types of
wastewaters as those currently regulated under the Steam Electric Power Generating effluent
guidelines and described in Section 3.2.1 (e.g., boiler blowdown, cooling tower blowdown, low-
volume wastewaters).
Landfill gas, by volume, consists of approximately 50 percent methane and 50 percent
carbon dioxide. It also contains small amounts of nitrogen, oxygen, and hydrogen, less than 1
percent nonmethane organic compounds, and trace amounts of inorganic compounds. The gas is
generated in landfills as bacteria degrade organic matter. This gas mixture can be captured and
processed for use as fuel in steam electric plants. During processing, a portion of the nonmethane
components is typically removed from landfill gas, which results in a fuel with a higher heating
value [U.S. EPA, 2006g; CEC, 2006]. A steam electric plant fueled with landfill gas is similar to
a steam electric plant fueled with natural gas in terms of fuel composition (natural gas and
landfill gas are both composed primarily of methane) and overall process [PDEP, 2006]. Because
these gaseous fuel operations do not generate wastewaters that contact the fuel or fuel wastes like
the solid-fueled plants, these plants typically only generate wastewaters such as boiler
blowdown, cooling water, and other low-volume wastewaters. These wastewaters generally are
expected to have similar characteristics as the wastewaters generated from the plants regulated
under the Steam Electric Power Generating effluent guidelines.
7.1.2.3 Geothermal
In the geothermal steam electric process, geothermal fluids (typically steam) are extracted
from geothermal reservoirs and are used to power steam turbine/electric generators. No fuels are
combusted to produce steam. Steam exiting the turbines is condensed with cooling water and the
condensate is injected into the geothermal reservoir. Geothermal steam electric plants generate
steam condensate wastewater and condenser cooling wastes (typically cooling tower blowdown)
[CEPA, 2006d].
EPA addressed geothermal electric generation in developing both the 1974 and 1982
Steam Electric Power Generating effluent guidelines. The 1982 Development Document states
that geothermal fluids are disposed of by reinjection to the subsurface geothermal reservoir after
use [U.S. EPA, 1982]. Permit writers confirmed this statement, indicating that geothermal steam
electric plants do not typically have NPDES permits because they do not discharge their
wastewater to surface waters [CEP A, 2006d; CEP A, 2006c]. These plants inject wastewater
underground into the geothermal steamfield reservoirs for two major reasons [CEPA, 2006d;
CEP A, 2006c; U.S. DOE, 2006a]. First, injecting water into the steamfield reservoirs is required
to maintain steam production [CEPA, 2006d; U.S. DOE, 2006a]. Second, the geothermal steam
condensate from the steam electric generating process contains high levels of salts and metals,
specifically arsenic and boron, which would be costly to remove to meet limits for discharges to
surface waters [CEP A, 2006d; CEP A, 2006c].
7-8
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Final Detailed Study Report Chapter 7 - Preliminary Investigation of Other Industry Segments
7.1.2.4 Solar
Solar electric generating plants concentrate sunlight onto receivers using various
reflecting devices. Heat transfer fluid is heated as it flows through the receivers and is used to
create steam, which, in turn, is used to create electricity in steam turbines/generators. Most solar
electric plants that use parabolic trough reflectors to concentrate sunlight (such as the Solar
Electric Generating Stations plants in the Mojave Desert, CA) generate cooling water, boiler
blowdown, and demineralizer wastewater. These wastewaters are typically transferred to an
evaporation pond and are not discharged to surface waters [IEEE, 1989]. Many solar electric
plants burn natural gas when necessary to meet electrical demands [IEEE, 1989; Kirk-Othmer,
2000].
According to the 1982 Development Document, all solar electric generating plants at that
time were developmental; however, EPA acknowledged that more systems would be developed
in the future as traditional fossil fuels were depleted [U.S. EPA, 1982]. Since 1982, the solar
power technologies have advanced and the 2005 EIA database includes nine solar-powered
plants (see Table 7-1) [U.S. DOE, 2005a].
7.1.3 Summary ofNPDES Permit Review
During the detailed study, EPA obtained NPDES permits for 13 alternative-fueled plants.
EPA obtained at least one permit for each of the fuels discussed in Section 7.1.2, except solar.
EPA reviewed the permits to determine the types of wastewaters generated by the plants and
how the wastewaters were being permitted.
Based on the limited number of permits reviewed and communications with permitting
authorities, EPA was not able to determine any trends in the regulation of wastewaters based on
alternative fuel type; however, EPA was able to make some general observations about the types
of wastewaters generated at these operations and determine some general trends in the way the
wastewaters are regulated.
EPA found that some of the permits reviewed contained relatively few limits based on the
Steam Electric Power Generating effluent guidelines. In each of these cases, the process
wastewaters are not discharged directly to surface waters, whereas direct discharge of these
wastewaters is the typical practice for plants regulated under the Steam Electric Power
Generating effluent guidelines. Specific examples include geothermal electric wastewaters that
are reinjected into underground geothermal reservoirs, agricultural-by-product-fueled steam
electric wastewaters that are discharged to percolation ponds (these are permitted via state
groundwater monitoring program), and other process wastewaters from indirect dischargers
(these are usually permitted under a separate state program, not the NPDES program).
In most cases for direct dischargers, permit writers established limitations using BPJ. The
bases used for these BPJ limits vary and may include the Steam Electric Power Generating
effluent guidelines, more stringent state water quality standards, or general permitting
requirements. Most parameters limited appear to have been selected based on state water quality
standards.
A small portion of the permits wholly incorporate the requirements of the Steam Electric
Power Generating effluent guidelines. These permits are unique in that the plants use a fossil fuel
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Final Detailed Study Report Chapter 7 - Preliminary Investigation of Other Industry Segments
in addition to the alternative fuel to generate electricity, or the permit only specifies the use of a
fossil fuel. In at least one of these cases, the fossil-fueled steam electric wastewaters have
separate limits than the alternative-fueled steam electric wastewaters.
7.2 Industrial Non-Utilities
This section describes EPA's review of plants within various industrial sectors operating
steam electric generators that produce electricity and/or thermal output primarily to support the
activities performed at the plant. These industrial non-utilities include cogenerators26, small
power plants, and other non-utility generators, and generally do not produce electric power for
distribution and/or sale.
EPA reviewed NPDES permits for a prioritized subset of industrial non-utilities to
identify sources of wastewater generated from steam electric processes and determine how the
wastewater discharges from these operations are currently regulated (e.g., whether the Steam
Electric Power Generating effluent guidelines are applied as BPJ). Additionally, EPA contacted
several companies operating electric generating units at their industrial plants to discuss the
operations and wastewaters generated from the plant related to steam or electricity production.
The steam electric generating process used at industrial non-utilities is similar to that
used by all steam electric plants, as described in Section 3.2. A boiler or Heat Recovery Steam
Generator (HRSG) is used to generate steam that is in turn used (at least in part) to drive an
electric generator or turbine. Finally, the steam is condensed through noncontact cooling before
it is returned to the boiler. Additionally, some of the steam generated may be used by the plant
for other process operations. Since the processes are similar, EPA expects that industrial non-
utilities generate wastewater from the same sources as do steam electric plants regulated under
the Steam Electric Power Generating effluent guidelines.
Wastewater generated by the steam electric processes at industrial non-utilities is not
currently regulated by the Steam Electric Power Generating effluent guidelines, because the
plants are not"... primarily engaged in the generation of electricity for distribution and sale..."
With the exception of certain instances (e.g., certain subcategories of the Pulp, Paper and
Paperboard effluent guidelines; see 40 CFR Part 430.01(m)), steam electric wastewaters from
industrial non-utilities are not directly regulated by effluent guidelines. Information that EPA
obtained during the detailed study indicate that industrial plants operating steam electric
generating units use a similar process as those plants currently regulated under the Steam Electric
Power Generating effluent guidelines. These industrial plants use both fossil and non-fossil fuels
to generate the steam to drive the turbines.
The electric generating units at industrial facilities are typically smaller than those at
plants regulated under the Steam Electric Power Generating effluent guidelines. Additionally, the
industrial non-utilities burning coal as the primary fuel source typically burn significantly less
coal than the coal-fired steam electric plants regulated under the Steam Electric Power
Generating effluent guidelines. Because industrial non-utilities tend to be smaller in terms of
electric power production and coal usage, the relative volume of wastewater discharged by these
26 A cogenerator is defined as "a generating plant that produces electricity and another form of useful thermal
energy (such as heat or steam), used for industrial, commercial, heating, or cooling purposes" [U.S. DOE, 2006b].
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Final Detailed Study Report Chapter 7 - Preliminary Investigation of Other Industry Segments
plants associated with electricity generation is likely to be less than that discharged by steam
electric plants regulated under the Steam Electric Power Generating effluent guidelines.
The information collected during the detailed study indicates that most industrial plants
commingle the wastewaters associated with the electric generating units with the other plant
process wastewaters. Because the wastewaters are commingled, they may be treated in the
plant's wastewater treatment system. These commingled wastewaters typically have permit
limits based on the industry-specific effluent guidelines; the Steam Electric Power Generating
effluent guidelines limits are typically not used to set BPJ-based limits.
7.2.1 Overview of Industrial Non- Utilities
EPA identified industrial non-utilities for this detailed study through data collected in
2005 by EIA. Industrial plants that operate an electric power generator having at least one MW
of electric generating capacity report to EIA each year. Included in these data is the plant's
primary NAICS code. EPA identified industrial non-utilities in the 2005 EIA data as those
reporting NAICS codes other than 22 - Utilities.
EPA examined the 2005 EIA data to determine the relative size of electric generating
units at industrial non-utilities, as well as the types of fuels used by industrial non-utilities to
generate the steam. EPA also performed a more detailed analysis of the EIA data for the subset
of industrial non-utilities that use fossil fuels to power a steam generator. Section 7.2.2
summarizes the available demographic data for fossil-fueled, steam electric industrial non-
utilities.
According to the 2005 EIA data, there are 855 industrial non-utilities, most of which
(over 75 percent) produce a relatively small amount of electric power (no more than 50 MW per
plant) [U.S. DOE, 2005a]. These 855 industrial non-utilities include plants operating both steam
and non-steam generating units (e.g., stand-alone combustion turbines, internal combustion
engines, and hydraulic turbines) powered by either fossil or non-fossil fuel types. No nuclear-
powered industrial non-utilities were reported to EIA in 2005.
For comparison, only 10 percent of steam electric plants regulated under the Steam
Electric Power Generating effluent guidelines each produce less than 50 MW of electricity. In
fact, nearly half of the Part 423 steam electric plants each generate more than 500 MW of electric
power [U.S. DOE, 2005a]. Section 3.1.2.2 contains additional information on steam electric
plants regulated under the Steam Electric Power Generating effluent guidelines.
Industrial non-utilities may be fueled either by a fossil fuel (e.g., coal, oil, or natural gas)
or an alternative, non-fossil fuel. The fuels used by these industrial non-utilities are often derived
from a by-product of the primary industrial process. These non-utilities may also use a
combination of fossil and non-fossil fuels to power the steam electric generating unit. No
industrial non-utilities were found to use nuclear fuels [U.S. DOE, 2005a].
The following non-fossil fuels were reported to EIA by industrial non-utilities as the
primary fuel for the steam electric generating unit:
• Agricultural Crop By-Products, Straw, Energy Crops;
• Black Liquor;
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Final Detailed Study Report Chapter 7 - Preliminary Investigation of Other Industry Segments
• Municipal Solid Waste;
• Other Biomass Gases (e.g., digester gas, methane);
• Other Biomass Solids (e.g., animal manure and waste, solid by-products);
• Other Fuels (e.g., batteries, chemicals, coke breeze, hydrogen, pitch, sulfur, tar
coal);
• Wood Waste Liquids (e.g., red liquor, sludge wood, spent sulfite liquor); and
• Wood and Wood Waste Solids (e.g., paper pellets, railroad ties, utility poles,
wood chips).
In 2005, 160 steam electric industrial non-utilities reported using at least one of these
non-fossil fuel types. Among these non-fossil fuel types, black liquor and wood and wood waste
solids were the most prevalently used primary fuels for steam electric power generation by
industrial non-utilities [U.S. DOE, 2005a].
As previously mentioned, it is not uncommon for an industrial non-utility to use more
than one type of fuel; in fact, these plants often will use a combination of fossil and non-fossil
fuels to power the same steam electric generating unit. For example, several industrial non-
utilities that reported using natural gas as the primary fuel also reported using black liquor and
other gases as alternates, as did several coal-burning industrial non-utilities. In addition, several
of the 160 primarily non-fossil-fueled industrial non-utilities reported using coal, oil, or natural
gas as alternate fuels for the steam electric generating unit [U.S. DOE, 2005a].
7.2.2 Demographic Data for Fossil-Fueled Industrial Non-Utilities
EPA identified industrial non-utilities through data collected in 2005 by EIA for plants
reporting a primary NAICS code other than 22 - Utilities27. Similar to the analysis of the steam
electric plants regulated by the Steam Electric Power Generating effluent guidelines described in
Section 3.1.2.2, EPA used the NAICS code, prime mover, and energy source information
reported in Form EIA-860 to develop a demographic profile for steam electric industrial non-
utilities. EPA identified the subset of industrial non-utilities in the EIA database that are fossil-
fueled steam electric as those operating at least one prime mover that utilizes steam, produced by
burning a fossil fuel, to generate electricity.
Using the criteria for the prime mover type and fossil fuel described above for plants
reporting a primary purpose/NAICS code other than 22, EPA estimates that 314 fossil-fueled,
steam-electric, industrial non-utilities reported to EIA in 2005. These plants are estimated to
operate 813 stand-alone steam generators or combined cycle systems28, which have a total steam
or combined cycle turbine electric generating capacity of 19,393 MW29 [U.S. DOE, 2005a]. The
total steam or combined cycle turbine electric generating capacity for all industrial non-utilities,
including non-fossil fuels, is 25,512 MW [U.S. DOE, 2005a]; therefore, 76 percent of the
27 Additionally, EPA identified 14 plants reporting a NAICS code of 22 that are, in fact, industrial non-utilities. For
the analyses presented in this report, these 14 plants were placed in the appropriate industrial category and were not
included in the steam electric industry analyses presented in Section 3.1.
28 Refer to Section 3.2.9 for a description of the combined cycle system of electric power generation.
29 The total steam or combined cycle electric generating capacity includes capacity associated with stand-alone
steam turbines, combined cycle steam turbines, combined cycle single shaft turbines, and combined cycle
combustion turbines.
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Final Detailed Study Report Chapter 7 - Preliminary Investigation of Other Industry Segments
industrial non-utility capacity is associated with fossil fuels. The industrial non-utility steam
turbine electric generating capacity, including fossil and non-fossil fuels, is less than four
percent30 of the electricity produced by the steam electric industry regulated under the Steam
Electric Power Generating effluent guidelines.
Because not all of the steam generated by industrial non-utilities is necessarily used to
generate electricity, EPA compared the amount of coal burned by the coal-fired industrial non-
utilities to the amount of coal burned by coal-fired steam electric plants regulated under the
Steam Electric Power Generating effluent guidelines. According to 2005 EIA information, the
average amount of coal burned by an industrial non-utility is 318,000 tons per year (median is
182,000 tons) and the average amount of coal burned by a steam electric plant regulated under
the Steam Electric Power Generating effluent guidelines is 2,155,000 tons per year (median is
1,221,000 tons) [U.S. DOE, 2005b]. Based on these numbers, EPA expects that the amount of
wastewater generated by the industrial non-utilities associated with the steam electric process
operations is substantially less than that generated by steam electric plants regulated under the
Steam Electric Power Generating effluent guidelines.
Table 7-3 summarizes the industries that reported industrial non-utilities to EIA in 2005,
the number of plants, and the number of fossil fuel-burning steam electric generating units. The
top five industries reporting operation of steam electric generating units, ranked by steam electric
generating capacity include:
• Chemical Manufacturing;
• Paper Manufacturing;
• Petroleum and Coal Products Manufacturing;
• Primary Metal Manufacturing; and
• Food Manufacturing [U.S. DOE, 2005a].
The top five industries comprise an estimated 221 non-utilities operating 575 steam or
combined cycle generating units and producing 16,963 MW of electric power (87 percent of the
steam electric generating capacity of all fossil-fueled, steam-electric industrial non-utilities
reported to EIA) [U.S. DOE, 2005a]. The remainder of this section presents more detailed
demographic information for these five industries.
30 EPA estimates that the total steam electric generating capacity of the steam electric industry regulated under the
Steam Electric Power Generating effluent guidelines in 2005 was 762,386 MW (refer to Section 3.1.4.2) [U.S. DOE,
2005a].
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Final Detailed Study Report
Chapter 7 - Preliminary Investigation of Other Industry Segments
Table 7-3. Summary of Fossil-Fueled, Steam Electric Industrial Non-Utilities,
by NAICS Code in 2005
NAICS Code - Description
Number
of Plants
Number of
Electric
Generating
Units a
Total Steam and
Combined Cycle
Turbine Electric
Generating Capacity
(MW)b
Fossil-Fueled and Nuclear Steam Electric Plants Regulated Under 40 CFR Part 423
22 - Utilities
1,187
2,557
762,386
Fossil-Fueled Steam Electric Industrial Non-Utilities
325 - Chemical Manufacturing
322 - Paper Manufacturing
324 - Petroleum and Coal Products Manufacturing
33 1 - Primary Metal Manufacturing
3 1 1 - Food Manufacturing
Total for Top 5 Industries, by Capacity (Percentage of
Total Fossil-Fueled Industrial Non-Utilities)
611 - Educational Services
3 14 - Textile Product Mills
21 1 - Oil and Gas Extraction
212 - Mining (Except Oil and Gas)
3345 - Navigational, Measurement, Electromedical, and
Control Instruments Manufacturing
92 - Public Administration
339 - Miscellaneous Manufacturing
327 - Nonmetallic Mineral Product Manufacturing
622 - Hospitals
336 - Transportation Equipment Manufacturing
221 -Utilities'
326 - Plastics and Rubber Products Manufacturing
481 - Air Transportation
333 - Machinery Manufacturing
3 122 - Tobacco Manufacturing
321 - Wood Product Manufacturing
332 - Fabricated Metal Product Manufacturing
521 - Monetary Authorities - Central Bank
814 - Private Households
514 - Information Services and Data Processing Services
482 - Rail Transportation
561 - Administrative and Support Services
55
81
29
18
38
221
(70%)
33
6
8
3
1
5
2
4
9
2
o
J
1
1
2
2
o
3
1
1
1
1
1
1
129
169
69
53
80
500
(71%)
75
15
12
6
11
15
8
10
16
4
7
4
1
7
3
3
2
2
1
1
2
1
7,535
3,348
2,571
2,383
1,127
16,963
(87%)
770
325
261
238
200
96
90.7
83.3
83.2
64.5
43.9
40
31
24
20.6
14.8
12.5
12
6
4.7
4
2.3
7-14
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Final Detailed Study Report
Chapter 7 - Preliminary Investigation of Other Industry Segments
Table 7-3. Summary of Fossil-Fueled, Steam Electric Industrial Non-Utilities,
by NAICS Code in 2005
NAICS Code - Description
624 - Social Assistance
562212 - Solid Waste Landfill
Total Fossil-Fueled Industrial Non-Utilities
Number
of Plants
1
1
314
Number of
Electric
Generating
Units a
2
1
709
Total Steam and
Combined Cycle
Turbine Electric
Generating Capacity
(MW)b
2
1
19,393
Source: [U.S. DOE, 2005a].
a - The number of electric generating units represents the number of stand-alone steam turbines and the estimated
number of combined cycle systems. EPA estimated the number of combined cycle systems by adding the number of
combined cycle steam turbines and the number of combined cycle single shaft turbines. Typically there are multiple
combustion turbines to a single steam turbine in a combined cycle system; therefore, EPA believes this methodology
is a better representation of the number of combined cycle systems than simply adding the number of combined
cycle combustion and steam turbines.
b - The table includes stand-alone steam turbines, combined cycle steam turbines, combined cycle single shaft
turbines, and combined cycle combustion turbines.
c - Operations included in NAICS code 221 include natural gas distribution, water sewage and other systems, water
supply and irrigation systems, and sewage treatment plants. Based on these descriptions, EPA believes that these
plants should be treated as industrial non-utilities.
7.2.2.1 Prime Movers/Generating Units
Table 7-4 shows the distribution of the types of steam electric prime movers used by
industrial non-utilities within each of the top five industries. The table presents the numbers of
plants and electric generating units and capacities for each type of steam electric prime mover.
Based on the 2005 EIA data, industrial non-utilities generate over half of their electricity (54
percent) through stand-alone steam turbines, which are also the most prevalent type of steam
electric prime mover used by the regulated steam electric plants regulated under the Steam
Electric Power Generating effluent guidelines.
The two exceptions to this among the top five industries are the chemical manufacturing
and the petroleum and coal products manufacturing industries, which reported more electric
generating capacity for combined cycle systems than stand-alone steam turbines in 2005 [U.S.
DOE, 2005a]. Comments received on the preliminary 2006 effluent guidelines program plan
from the American Petroleum Institute (API) indicate that most petroleum refineries use natural
gas or residual gases from the refinery process to power a combustion turbine, the waste heat of
which is used to produce steam either to generate additional electric power or to be used directly
within the refining process [API, 2005]. According to API's description of petroleum refinery
non-utilities, not only are these plants using combined cycle systems, but they are considered to
be cogenerators (i.e., steam is produced both to power a generator and to use in other operations).
7-15
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Final Detailed Study Report
Chapter 7 - Preliminary Investigation of Other Industry Segments
Table 7-4. Distribution of Prime Mover Types Among Fossil-Fueled,
Steam Electric Industrial Non-Utilities
Steam Electric Prime Mover
Number of Plants3
Number of Electric
Generating Units b
Total Steam and Combined
Cycle Turbine Electric
Generating Capacity (MW) c
All Industrial Non-utilities
Stand- Alone Steam Turbine
Combined Cycle System
Total
264
(84%)
102
(32%)
314
625
(88%)
84
(12%)
709
10,378
(54%)
9,015
(46%)
19,393
NAICS 325 - Chemical Manufacturing
Stand- Alone Steam Turbine
Combined Cycle System
Total
41
28
55
97
32
129
1,579
5,955
7,535
NAICS 322 - Paper Manufacturing
Stand- Alone Steam Turbine
Combined Cycle System
Total
78
8
81
164
5
169
3,107
241
3,348
NAICS 324 - Petroleum and Coal Products Manufacturing
Stand- Alone Steam Turbine
Combined Cycle System
Total
21
18
29
50
19
69
756
1,815
2,571
NAICS 331 - Primary Metal Manufacturing
Stand- Alone Steam Turbine
Combined Cycle System
Total
18
0
18
53
0
53
2,383
0
2,383
NAICS 311 - Food Manufacturing
Stand- Alone Steam Turbine
Combined Cycle System
Total
36
4
38
78
2
80
1,108
18.7
1,127
Source: [U.S. DOE, 2005a].
a - Because a single plant may operate multiple generating units of various types, the number of plants by prime
mover type is not additive. The totals reflect the number of industrial non-utilities that are operating at least one
steam electric generating unit powered by a fossil fuel.
b - The number of electric generating units represents the number of stand-alone steam turbines and the estimated
number of combined cycle systems. EPA estimated the number of combined cycle systems by adding the number of
combined cycle steam turbines and the number of combined cycle single shaft turbines. Typically there are multiple
combustion turbines to a single steam turbine in a combined cycle system; therefore, EPA believes this methodology
is a better representation of the number of combined cycle systems than simply adding the number of combined
cycle combustion and steam turbines.
c - The table includes stand-alone steam turbines, combined cycle steam turbines, combined cycle single shaft
turbines, and combined cycle combustion turbines.
7-16
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Final Detailed Study Report
Chapter 7 - Preliminary Investigation of Other Industry Segments
7.2.2.2 Fossil Fuel Types
Table 7-5 shows the distribution of the fossil fuels used by industrial non-utilities by
electric generating capacity, specifically broken out for the top five industries. The 2005 EIA
data demonstrate that fossil-fueled industrial non-utilities generally use either coal or
natural/other gas to fuel their steam electric generating units; however, some industries tend to
use a particular type of fossil fuel more than other types of fuels. For example, most food
manufacturing non-utilities reported using coal, while most petroleum and coal products
manufacturing non-utilities reported using natural/other gas [U.S. DOE, 2005a]. These trends
coincide with the predominant types of generators used in these industries (e.g., nearly all
combined cycle systems are powered by natural/other gas).
Table 7-5. Distribution of Fuel Types Among Fossil-Fueled, Steam Electric
Industrial Non-Utilities
Fossil Fuel a
Number of
Plants b
Number of Electric
Generating Units c
Total Steam and Combined
Cycle Turbine Electric
Generating Capacity (MW) d
All Fossil-Fueled Industrial Non-Utilities
Coal:
Anthracite Coal, Bituminous Coal
(BIT)
Subbituminous Coal (SUB)
Lignite Coal (LIG)
Waste Coal (WC)
Petroleum Coke (PC)
Oil:
Residual Fuel Oil (RFO)
Distillate Fuel Oil (DFO)
Waste/Other Oil (WO)
Natural/Other Gas:
Natural Gas (NG)
Blast Furnace Gas (BFG)
Other Gas (OG)
Total
132
(42%)
104
25
2
1
4
(1%)
29
(9%)
26
2
1
755
(49%)
125
9
21
314
337
(48%)
275
57
4
1
6
(1%)
50
(7%)
45
4
1
376
(44%)
241
28
47
709
6,657
(34%)
5,077
1,142
365
67
797
(1%)
395
(2%)
367
20
8
72,750
(63%)
10,663
834
654
19,393
NAICS 325 - Chemical Manufacturing
Coal (BIT, LIG, and SUB)
Petroleum Coke (PC)
Oil (DFO and WO)
Natural/Other Gas (NG and OG)
Total
18
1
2
35
55
56
2
4
67
129
1,116
46
27
6,346
7,535
7-17
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Final Detailed Study Report
Chapter 7 - Preliminary Investigation of Other Industry Segments
Table 7-5. Distribution of Fuel Types Among Fossil-Fueled, Steam Electric
Industrial Non-Utilities
Fossil Fuel a
Number of
Plants b
Number of Electric
Generating Units c
Total Steam and Combined
Cycle Turbine Electric
Generating Capacity (MW) d
NAICS 322 - Paper Manufacturing
Coal (BIT, SUB, and WC)
Petroleum Coke (PC)
Oil (RFO)
Natural/Other Gas (NG)
Total
38
1
14
29
81
88
2
21
58
169
1,871
90
250
1,137
3,348
NAICS 324 - Petroleum and Coal Products Manufacturing
Petroleum Coke (PC)
Oil (RFO)
Natural/Other Gas (NG and OG)
Total
2
1
27
29
2
1
66
69
61
0.4
2,509
2,571
NAICS 331 - Primary Metal Manufacturing
Coal (BIT, LIG and SUB)
Natural/Other Gas (BFG, NG, and OG)
Total
5
13
18
12
41
53
1,410
973
2,383
NAICS 311- Food Manufacturing
Coal (BIT and SUB)
Oil (RFO)
Natural/Other Gas (NG)
Total
30
1
7
38
63
2
15
80
1,056
8
63
1,127
Source: [U.S. DOE, 2005a].
a - No steam electric generating units operated at industrial non-utilities were reported to use jet fuel, kerosene, coal
synfuel, gaseous propane, or nuclear fuel in the 2005 EIA database.
b - Because a single plant may operate multiple generating units utilizing differing fuel types, the number of plants
by fuel type is not additive. EPA estimates there are 314 industrial non-utilities operating at least one steam electric
generating unit powered by a fossil fuel.
c - The number of electric generating units represents the number of stand-alone steam turbines and the estimated
number of combined cycle systems. EPA estimated the number of combined cycle systems by adding the number of
combined cycle steam turbines and the number of combined cycle single shaft turbines. Typically there are multiple
combustion turbines to a single steam turbine in a combined cycle system; therefore, EPA believes this methodology
is a better representation of the number of combined cycle systems than simply adding the number of combined
cycle combustion and steam turbines.
d - The total steam electric generating capacity shown does not equal the sum of the steam electric capacities for
each fuel type due to rounding errors. The table includes stand-alone steam turbines, combined cycle steam turbines,
combined cycle single shaft turbines, and combined cycle combustion turbines.
7.2.3 Review of Industrial Non- Utility Discharge Permits
EPA reviewed NPDES permits for 28 industrial plants operating a steam electric
industrial non-utility on site to determine the extent to which steam electric process wastewater is
segregated from other process wastewaters and whether Steam Electric Power Generating
effluent guidelines are applied to the wastewaters on the basis of BPJ. These plants use either a
7-18
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Final Detailed Study Report Chapter 7 - Preliminary Investigation of Other Industry Segments
fossil fuel or other non-fossil fuel to power the steam electric generating unit(s), and were
identified within the following four industries:
• Chemical Manufacturing;
• Paper Manufacturing;
• Primary Metal Manufacturing; and
• Petroleum and Coal Products Manufacturing.
EPA found that the NPDES permits for the plants within these industries rarely provide
enough detail about the plant waste streams to identify the steam electric process wastewaters;
however, some permits generally described waste streams that could include the steam electric
waste streams or waste streams from other on-site operations (e.g., "cooling water," "boiler
blowdown"). The final effluent wastewaters from industrial sites are commingled with all plant
wastewater at the point of discharge, if not upstream; therefore, the steam electric wastewaters
are typically commingled with the other plant wastewaters.
The 28 plants are covered by seven existing industrial point source effluent guidelines.
EPA determined that wastewaters discharged from these industrial sites are often regulated only
by the effluent guidelines for the primary industrial process (e.g., Organic Chemicals, Plastics,
and Synthetic Fibers, Petroleum Refining). Rarely are the discharges associated with steam
electricity generation limited specifically with the Steam Electric Power Generating effluent
guidelines limits. Additionally, the Steam Electric Power Generating effluent guidelines limits
are rarely used as a BPJ basis to regulate pollutants that may not be covered under the specific
industrial effluent guideline.
EPA researched three of these seven existing effluent guidelines (i.e., Iron and Steel
Manufacturing, Petroleum Refining, and Pulp, Paper & Paperboard Point Source Categories) to
determine whether the waste streams from the steam electric operations were considered in
developing the final effluent limitations. The Pulp, Paper & Paperboard effluent guidelines (40
CFR Part 430) specifically define Part 430-regulated process wastewater (in certain subparts) as
including wastewaters generated by co-located non-utility power plants (see 40 CFR Part
430.01(m)).
Comments received on the preliminary 2006 effluent guidelines program plan from API
stated that petroleum refinery steam electric generating units primarily generate wastewater from
boiler and cooling tower blowdown and demineralizer streams that are typically permitted as
low-contaminant streams (i.e., streams containing low concentrations of toxics, oxygen demand,
and nonconventional pollutants). API also commented that these streams possess the same
wastewater characteristics as the petroleum refining wastewater with which they are commingled
prior to discharge [API, 2005]. On the preliminary 2008 effluent guidelines program plan, the
American Chemistry Council provided similar comments stating that the wastewaters associated
with the steam electric generating units are considered low-contaminant streams by permit
writers and are controlled by BPJ-based limits [Walls, 2007]
While the Pulp, Paper, & Paperboard effluent guidelines were developed incorporating
wastewaters from on-site steam electric power plants, this is not the case for all industrial
effluent guidelines. For example, the Iron and Steel effluent guidelines (40 CFR Part 420)
identify that wastewaters from the operation of steam electric generating units may be discharged
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Final Detailed Study Report Chapter 7 - Preliminary Investigation of Other Industry Segments
and are identified as non-process wastewaters; however, the effluent guideline does not set limits
for these non-process wastewaters nor incorporate them into the effluent guideline limits.
In many cases, the primary industry effluent guidelines (or the permit for the industrial
plant discharge) either does not address or contains a less stringent limit for the pollutants
included in the Steam Electric Power Generating effluent guidelines. For example, the Pulp,
Paper, & Paperboard effluent guidelines, which include wastewaters generated from on-site
power plants, do not currently regulate chlorine discharges.
7.2.4 Contacts with Industrial Non- Utilities
As part of the detailed study, EPA contacted several companies that operate steam
electric generating units colocated at their industrial plants. EPA contacted these companies to
determine the types of fuels used, process operations, wastewaters generated, and the
handling/treatment of the wastewaters associated with the operation of the steam electric
generating units. EPA contacted at least one company in each of the top five industries, ranked
by electric generating capacity.
From these contacts, EPA identified a primary metal manufacturer with steam electric
generating units at one of its plants that operates similarly to some coal-fired power plants
regulated under the Steam Electric Power Generating effluent guidelines. This non-utility
operates four coal-fired units, each of which has a wet FGD system. The FGD scrubber purge is
transferred to an ash pond for treatment, where it is commingled with fly ash transport and
bottom ash transport waters. The ash pond does not receive any wastewater associated with the
other plant operations. The ash pond effluent is discharged to surface water and this discharge is
required to comply with the Steam Electric Power Generating effluent guidelines limits [Alcoa,
2009].
The food manufacturing company that EPA contacted operates eight plants with coal-
fired electric generating units. EPA only discussed the operation of one of the plants with the
company; however, the contact stated that the operations at the other seven plants are similar.
The plant discussed does not operate any wet FGD systems. Additionally, both the bottom ash
and fly ash are collected using dry handling practices. The cooling tower blowdown generated by
the steam electric process is commingled with the plant's sanitary wastewaters and transferred to
a publicly owned treatment works [ADM, 2009].
The paper manufacturing company that EPA contacted operates electric generating units
powered by several different types of fuels. One of the most common types of fuels used is black
liquor, which is a by-product of the pulping process. The company also burns coal, wood wastes,
tires, and other solid fuels. The company has over 20 paper mills that operate steam electric
generating units, and the operations at these mills differ by site. According to the contact, the
company does not operate any wet FGD systems; however, it does operate a few dry FGD
systems. The company operates a mixture of wet and dry ash handling systems, and some of the
mills operate ash ponds to treat the fly and/or bottom ash transport waters. The other types of
wastewaters generated by the steam electric generating operations consist of boiler blowdown,
cooling water, and process area wash waters. All these wastewaters are commingled with the
other mill wastewaters and treated in a pond or clarifier followed by an aerated stabilization
basin, some of which have activated sludge treatment [International Paper, 2009].
7^20
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Final Detailed Study Report Chapter 7 - Preliminary Investigation of Other Industry Segments
The petroleum refining company that EPA contacted operates three refineries that have
electric generating units on site. These units burn gases that are by-products of the industrial
operations. The flue gas generated from the electric generating units is combined with the other
gases in the plant operations and treated with those gases. The wastewaters generated from the
steam electric generating units are cooling tower blowdown, boiler blowdown, and process area
wash waters. These wastewaters are treated in the plants' wastewater treatment systems, which
typically consist of oil/water separators, an activated sludge biological systems, and clarifiers
[Valero, 2009].
The chemical manufacturing company that EPA contacted operates two plants that have
coal-fired electric generating units on site. One of the plants is only capable of burning coal,
while the other can use oil as a secondary fuel. Both plants generate steam primarily for the
plants' process operations and not for generating electricity (i.e., one plant uses 10 percent of the
steam generated to produce electricity and the other uses 16 percent of the steam to produce
electricity). Neither of the plants operates a FGD systems for sulfur dioxide control. Both plants
operate dry fly ash handling systems. One plant operates a dry bottom ash handling system and
the other operates a wet system and trucks the wet bottom ash to a sand filter and the filtrate is
transferred to the plant's wastewater treatment facility. Both plants generate coal pile runoff,
boiler blowdown, and cooling tower blowdown waste streams. The coal pile runoff is sent
through a settling treatment system prior to discharge. The boiler blowdown and cooling tower
blowdown are discharged directly by one of the plants; the other plant treats the wastes in a
settling pond prior to discharge [Vasavada, 2009].
7.3 Steam and Air Conditioning Supply Plants
As part of the detailed study, EPA reviewed data from other industry segments that may
have similar operations to steam electric plants, but are not currently subject to the Steam
Electric Power Generating effluent guidelines. These industry segments include plants within
SIC Code 4939 (Combination utilities, not elsewhere classified), discussed further in Section 7.4,
and SIC Code 4961 (Steam and air conditioning supply), discussed in this section. EPA reviewed
available discharge data from plants within these SIC codes to determine if these plants have
operations and wastewater characteristics similar to those in the Steam Electric Power
Generating Point Source Category.
This section discusses steam and air conditioning supply plants and the findings of EPA's
examination of the processes and wastewaters generated by their operation. According to the
2002 Economic Census, 63 establishments were engaged in steam and air conditioning supply31
in the United States in 2002 [USCB, 2002]. Types of plants within the Steam and Air
Conditioning Supply sector include the following:
• Air conditioning supply services;
• Cooled air suppliers;
• Distribution of cooled air;
• Chilled water suppliers;
• Geothermal steam production;
31 The 2002 Economic Census is based on the North American Industrial Classification System (NAICS). The
NAICS code for steam and air conditioning supply (22133) corresponds directly to SIC code 4961.
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Final Detailed Study Report Chapter 7 - Preliminary Investigation of Other Industry Segments
• Steam heating systems (suppliers of heat); and
• Steam supply systems, including geothermal.
Many of these plants combust fossil fuels in a boiler to generate steam, which is similar
to the operation at steam electric plants regulated under the Steam Electric Power Generating
effluent guidelines; however, the primary purpose of this steam is not electricity generation. The
steam generated from the process is typically distributed to off-site customers and, therefore, it
does not power a steam turbine/electric generator.
Wastewater generated by these steam and air conditioning supply plants is not currently
regulated by the Steam Electric effluent guidelines, because the plants are not"... engaged in the
generation of electricity...", as defined at 40 CFR Part 423.10. As part of the detailed study, EPA
investigated steam and air conditioning supply plants and compared their processes and types of
wastewaters generated to those of fossil-fueled plants currently regulated by the Steam Electric
Power Generating effluent guidelines. EPA also compared the way the wastewater discharges are
regulated for these plants to the plants subject to the Steam Electric Power Generating effluent
guidelines.
Information that EPA obtained during the detailed study indicate that these steam and air
conditioning supply plants generate similar types of wastewaters as steam electric plants
regulated under the Steam Electric Power Generating effluent guidelines; however, most of the
plants combust natural gas or oil and, therefore, do not generate the quantity of FGD and/or ash
transport wastewaters that are generated by coal-fired power plants. EPA identified that some of
the wastewater discharges contain similar pollutants to those discharged by steam electric plants.
Additionally, some of the wastewaters from these plants are regulated using the Steam Electric
Power Generating effluent guidelines as the basis for BPJ-derived limits. EPA also identified that
there are relatively few of these plants in operation and most of them discharge a relatively small
amount of wastewater compared to the steam electric plants regulated under the Steam Electric
Power Generating effluent guidelines.
The remainder of this section summarizes data and information that were available for
the Steam and Air Conditioning Supply sector during EPA's study of this sector. EPA reviewed
data for SIC code 4961 reported to PCS and ICIS-NPDES32. EPA also reviewed several permits
and contacted three companies that operate steam supply plants to learn about the operations and
wastewaters generated at these plants. These sources provided information about potential types
of wastewater generated by steam supply plants, as well as the relative number of these plants
that are likely to generate and discharge wastewater.
32 In 2007, some states' discharge monitoring report (DMR) data were reported to the PCS database, while the
remaining states reported DMR data to the Integrated Compliance Information System - National Pollutant
Discharge Elimination System (ICIS-NPDES) database.
7^22
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Final Detailed Study Report Chapter 7 - Preliminary Investigation of Other Industry Segments
7.3.1 Wastewater Discharge Characterization Data
EPA extracted effluent monitoring data reported to PCS and ICIS-NPDES in 2007 for
plants within SIC code 4961. Table 7-6 summarizes the data extracted for these plants along with
their calculated total TWPE, which is a loading that accounts for the toxicity of the pollutants
discharged. The Technical Support Document for the Annual Review of Existing Effluent
Guidelines and Identification of Potential New Point Source Categories [U.S. EPA, 2009c],
discusses EPA's method of calculating TWPE. EPA in particular identified whether these
operations reported discharges of chlorine, total residual oxidants (TRO), chlorine-produced
oxidants (CPO), or metals, which are pollutants typically discharged from steam electric plants
regulated under the Steam Electric Power Generating effluent guidelines.
Table 7-6 also indicates whether the plants are classified as "major" or "minor"
dischargers. To provide an initial framework for setting permit issuance priorities, EPA
developed a major/minor classification system for industrial and municipal wastewater
dischargers. Each permitting authority establishes its own definitions, but major dischargers
almost always have the capability to impact receiving waters if not controlled and, therefore,
have been accorded more regulatory attention than minor dischargers. Plants are classified as
major based on an assessment of six characteristics: (1) toxic pollutant potential; (2) flow/stream
flow volume; (3) conventional pollutant loading; (4) public health impact; (5) water quality
factors; and (6) proximity to coastal waters. Facilities with major discharges must report
compliance with NPDES permit limits via monthly Discharge Monitoring Reports (DMRs)
submitted to the permitting authority. Minor discharges may, or may not, adversely impact
receiving water if not controlled. The DMRLoads2007 database includes data only for a limited
set of minor dischargers when the states choose to include these data. As shown in Table 7-6, the
2007 PCS and ICIS-NPDES contain data for 46 steam and air conditioning supply plants, 42 of
which are classified as minor dischargers [U.S. EPA, 2009b]. This suggests that steam and air
conditioning supply plants may discharge relatively small volumes of wastewater and/or
pollutants.
7.3.2 NPDES Permit Review
In researching the operations, waste streams, and existing discharge requirements
currently applied to steam and air conditioning supply wastewaters, EPA reviewed NPDES
permits for four steam and air conditioning supply plants (plants identified with bolded text in
Table 7-6). All four plants generate steam; however, none use the steam to generate electricity.
Some of the plants produce chilled water in addition to steam. The five plants generate
wastewaters that are similar to those of steam electric plants regulated under the Steam Electric
Power Generating effluent guidelines, including boiler blowdown, coal pile runoff, and cooling
tower blowdown; however, the cooling water waste streams and cooling tower blowdown listed
in the permits could be associated with the chilled water production process.
7-23
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Final Detailed Study Report
Chapter 7 - Preliminary Investigation of Other Industry Segments
Table 7-6. Steam and Air-Conditioning Supply Plants Identified in DMRLoads200 7 Database
NIDD
AL0052400
CA0029106
CA0029122
CA0082406
CA8000015
CO0043427
CT0004014
DC0000035
ID0025488
IL0001368
IL0037613
IL0072320
IL0073741
IN0004677
MD0001554
MD0061930
MD0065986
MD0066249
MD0066877
MN0054739
MN0055719
MN0056995
MN0066559
MO0004847
MO0099236
MOO 127825
MT0030651
Name
Powell Avenue Steam Plant
GAFF Power Systems-Site I
GAFF Power Systems-Site V
Alturas High School Geothermal
San Bernardino Geothermal Facility
Thermal Energy Distribution
Hartford Steam Company
GSA - (West Heating Plant)
Boise, City Of
MED Thermal Technologies Inc
MED Thermal Technologies-Pi. #5
SIC Physical Plant, SUIT
Metro Pier & Expo Authority
Citizens Thermal Energy
Trigged-Baltimore Energy Corp
Trigged-Energy Baltimore - SPRY
Housing Authority of Baltimore
Trigged-Baltimore Energy Corp
Trigged-Energy Baltimore - SARA
Energy Park Utility Co
Duluth Steam Cooperative Assoc
North Riverfront Plant
Minnesota Power Rapids Energy
Trigged KC Dist. Energy CUR
BASF Corp Agra Products
University Of MO-Physical
Don Abbey Residence
City
Birmingham
Pittsburg
Pittsburg
Alturas
San Bernardino
Denver County
Hartford
Washington
Boise
Chicago
Chicago
Carbondale
Chicago
Indianapolis
Baltimore
Baltimore
Baltimore
Baltimore
Baltimore
Saint Paul
Duluth
Minneapolis
Grand Rapids
Kansas City
Palmyra
Rolla
Rollins
Type of
Discharger
Minor
Minor
Minor
Minor
Minor
Minor
Major
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Monitoring
Data in
Database?
Y
N
N
N
N
N
Y
Y
N
Y
Y
Y
Y
Y
N
Y
N
N
Y
N
N
N
N
Y
Y
Y
Y
Total
TWPEa
NA
NA
NA
NA
NA
NA
4,645
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Cl/TRO/CPO
Discharged b
Cl
Cl
Cl
Cl
Cl
Cl
Metals
Discharged
Fe, Pb, Zn, Cu
Fe
Cu
Cu
7-24
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Final Detailed Study Report
Chapter 7 - Preliminary Investigation of Other Industry Segments
Table 7-6. Steam and Air-Conditioning Supply Plants Identified in DMRLoads200 7 Database
NIDD
NJ0109673
NY0005134
NY0005151
NY0005177
NY0227153
NY0245097
OK0002461
PA0000493
PA0008427
PA0239542
PA0253235
SD0025569
SD0025798
TX0008851
VA0032000
VA0091995
WA0001503
WI0038296
WI0040282
Name
Central Heat Plant Bldg 2401
59th Street Steam Station
Hudson Ave. Steam Plant
74th Street Steam Plant
South Nassau Communities Hosp
Remington Arms Co, Inc
Trigged - Tulsa Energy Corp
Pittsburgh Allegheny County
NRG Energy Center Hag. Inc
Impact PA Geothermal Well
Tarentum Senior Housing - Geothermal Well
Haakon School District No. 27-1
St Joseph's Indian School
Texas Medical Center Central
US Department Of Defense - Pentagon
Reston Lake Anne Air Condition
Seattle Steam
U W Madison Charter Street
WI University Milwaukee Power
City
New Hanover Twp
New York
Brooklyn
New York
Oceanside
Ilion
Tulsa
Pittsburgh
Harrisburg
Warren
Tarentum
Philip
Chamberlain
Houston
Arlington
Reston
Port of Seattle
Madison
Milwaukee
Type of
Discharger
Major
Major
Minor
Major
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Monitoring
Data in
Database?
Y
Y
Y
Y
N
Y
Y
N
N
N
N
Y
Y
Y
N
N
Y
N
N
Total
TWPEa
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Cl/TRO/CPO
Discharged b
CPO
Cl
Metals
Discharged
Zn
Source: [U.S. EPA, 2009b].
a - TWPE was not calculated for minor plants in the DMRLoads2007 database.
b - Cl - Chlorine; TRO - Total residual oxidants; and CPO - Chlorine produced oxidants (EPA has not developed TWFs for TRO and CPO; therefore, these
loads are not included in TWPE totals).
NA - Not available. The plant is either a minor discharger, in which case ERG does not calculate TWPE, or the plant did not report both concentration and flow
data and/or the plant reported only parameters for which EPA has not developed a TWF (e.g., TSS, BOD5).
Note: The rows with bold text in the table identify the plants for which EPA reviewed NPDES permits.
7-25
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Final Detailed Study Report Chapter 7 - Preliminary Investigation of Other Industry Segments
Some of the permits reviewed showed that the Steam Electric Power Generating effluent
guidelines standards were used as the basis for BPJ limits, although not all of the steam electric
regulated pollutants are necessarily included in the steam and air conditioning supplier permits.
This shows that some permit writers feel the operations at these steam supply plants are similar
enough to the operations at Part 423-regulated steam electric plants that the wastewaters may
have similar characteristics and, therefore, should have the same effluent limitations.
Upon review of the permit for the Hartford Steam Company, EPA learned that, in
addition to steam and chilled water production, the plant used to generate electricity with excess
steam; however, the electricity generation portion of the process has been closed since 1995. The
permit has retained the limits of the Steam Electric Power Generating effluent guidelines as the
basis for the current wastewater discharge requirements. This plant continues to report
significant discharges of chlorine, zinc, copper, and lead, which shows that the wastewaters from
the steam and air conditioning supply operations are discharging chlorine and metals to surface
waters.
7.3.3 Contacts with Steam Supply Companies
During the detailed study, EPA contacted three companies operating a total of 20 plants33
to obtain information on the operations and wastewaters generated at steam supply plants. These
steam supply plants typically provide steam for district heating and cooling purposes in large
cities. Many steam supply plants provide chilled water and/or hot water in addition to providing
steam. Some of the steam supply plants are providing electricity (i.e., they are cogeneration
plants).
From communications with the companies, EPA found that the majority of the steam
supply plants burn either oil or natural gas in their boilers. Because these fuels are generally low
in sulfur, these plants do not operate FGD scrubbers. Steam supply plants that use natural gas as
a fuel do not typically generate any ash or residual solid waste in their boilers and therefore do
not generate any ash transport waters. Some of the oil-fired plants generate a small amount of
ash that they remove from the boiler by periodic washes. One of the oil-fired plants transports its
ash wastewater and/or ash sludge off site to a treatment, storage, and disposal facility.
In addition to ash transport waters that may be generated by oil-fired plants, typical
wastewaters generated at natural gas or oil-fired steam supply plants are:
• Boiler blowdown;
• Cooling water;
• Demineralizer wastewater;
• Equipment drains and overflows; and
• Plants sumps.
According to one of the companies EPA contacted, the steam supply plants operated by
the company neutralize the boiler blowdown and demineralizer wastewaters to meet the pH
limits in their permits. Because most of the steam supply plants are located in large cities, they
33 Of the 20 plants operated by the three steam supply companies, only seven were identified as steam supply plants
reporting SIC code 4961 to PCS or ICIS-NPDES in 2007. The remaining 13 plants are identified either as
combination utilities (SIC Code 4931) or steam electric generating plants.
7^26
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Final Detailed Study Report Chapter 7 - Preliminary Investigation of Other Industry Segments
do not operate treatment ponds due to limited space availability, but typically neutralize the
boiler blowdown in large tanks [Consolidated Edison, 2009; Hartford Steam Company, 2009].
Of the 20 plants that were reviewed, only one plant reported using coal in their boilers.
The plant burns a low-sulfur coal and therefore, does not operate a FGD system. The plant is a
cogeneration plant that generates 5 MW of electricity and provides steam and chilled water for a
commercial district.
7.4 Combination Utility Plants
EPA reviewed available discharge information for plants within SIC Code 4939
(Combination utilities, not elsewhere classified) to determine if these plants have operations and
wastewater characteristics similar to those in the Steam Electric Power Generating Point Source
Category. The U.S. Census Bureau defines combination utilities as:
"Establishments primarily engaged in either providing electric services in combination
with other services, with electric service as the major part though less than 95 percent of
the total or providing gas services in combination with other services, with gas services
as the major part though less than 95 percent." [USCB, 2000]
According to the U.C. Census Bureau's Comparative Statistics, there were 1,989
combination utilities in the United States in 199734 [USCB, 2000]; however, not all of these
plants are relevant to the detailed study. By definition, combination utilities perform services
other than electric power generation, and more specifically services other than steam electric
power generation.
Wastewaters generated by plants classified as combination utilities are likely not
currently subject to existing effluent guidelines; however, combination utilities by definition
include plants that generate electric power, albeit in combination with providing other utility
services. Because at least a portion of these plants are expected to be engaged in the generation
of electricity for distribution and sale, EPA determined that the electric generating activities
performed at some combination utilities might be similar to those at plants regulated by the
Steam Electric Power Generating effluent guidelines, in terms of processes and wastewaters
generated. EPA examined effluent monitoring data reported in DMRs, as well as pollutants
reported to TRI as discharged, and determined that the pollutants are similar in nature to those
discharged by the steam electric plants currently regulated by the Steam Electric Power
Generating effluent guidelines [U.S. EPA, 2005b]. However, the wastewater discharge
characterization data suggests that combination utilities may discharge relatively small volumes
of wastewater and/or pollutants, particularly as compared to those plants regulated under the
Steam Electric Power Generating effluent guidelines.
EPA's review of NPDES permits for five combination utilities revealed that four of these
plants do not produce electricity, even as an auxiliary activity, and the processes and wastewaters
generated by these non-electric generating plants are not similar to those of steam electric plants
34 EPA used 1997 Economic Census data instead of 2002 Economic Census data because the 1997 data was reported
by SIC code and the 2002 data was reported by NAICS code. SIC code 4939 does not have a direct correlation to a
NAICS code; therefore, EPA could not determine the number of combination utilities from the 2002 Economic
Census data.
7^27
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Final Detailed Study Report Chapter 7 - Preliminary Investigation of Other Industry Segments
regulated under the Steam Electric Power Generating effluent guidelines. The wastewater-
generating activities performed at these plants may be classified within other existing SIC codes,
including Electric Services, Sewerage Systems, and Water Supply.
7.4.1 Wastewater Discharge Characterization Data
EPA extracted data reported to TRI in 2005 for all plants within SIC code 4939. EPA
used 2005 TRI data because they were the most recent TRI data for which the plants reported
their SIC code, for years after 2005, plants began reporting NAICS codes. Only 13 combination
utilities reported to TRI, and of these, only one reported a direct release to water (barium and
barium compounds with a TWPE of 0.003). The remaining seven reported no discharge of a TRI
chemical to water [ERG, 2008a]. TRI does not specifically identify the process source(s) of the
wastewater and pollutants discharged.
EPA also extracted effluent monitoring data reported to PCS and ICIS-NPDES in 2007
for plants within SIC code 4939. Table 7-7 summarizes the data extracted for these plants (47
combination utilities) along with their calculated total TWPE, which is a loading that accounts
for the toxicity of the pollutants discharged. The 2009 screening-level analysis report, 2009
Annual Screening-Level Analysis: Supporting the Annual Review of Existing Effluent Limitations
Guidelines and Standards and Identification of Potential New Categories for Effluent
Limitations Guidelines and Standards [U.S. EPA, 2009c], discusses EPA's method of
calculating TWPE. Table 7-7 identifies whether these operations reported discharges of chlorine,
TRO, CPO, or metals, which are pollutants typically discharged from steam electric plants
regulated under the Steam Electric Power Generating effluent guidelines. As shown in Table 7-7,
10 of the 47 combination utilities reported discharges of chlorine.
Table 7-7 also indicates whether the plants are classified as "major" or "minor"
dischargers. To provide an initial framework for setting permit issuance priorities, EPA
developed a major/minor classification system for industrial and municipal wastewater
dischargers. Each permitting authority establishes its own definitions, but major dischargers
almost always have the capability to impact receiving waters if not controlled and, therefore,
have been accorded more regulatory attention than minor dischargers. Plants are classified as
major based on an assessment of six characteristics: (1) toxic pollutant potential; (2) flow/stream
flow volume; (3) conventional pollutant loading; (4) public health impact; (5) water quality
factors; and (6) proximity to coastal waters. Facilities with major discharges must report
compliance with NPDES permit limits via monthly DMRs submitted to the permitting authority.
Minor discharges may, or may not, adversely impact receiving water if not controlled. Therefore,
EPA does not require DMRs for facilities with minor discharges. For this reason, the
DMRLoads2007 database includes data only for a limited set of minor dischargers when the
states choose to include these data. As shown in Table 7-7, 45 of the 47 combination utilities are
classified as minor dischargers [U.S. EPA, 2009b]. This suggests that combination utilities may
discharge relatively small volumes of wastewater and/or pollutants.
7-28
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Final Detailed Study Report
Chapter 7 - Preliminary Investigation of Other Industry Segments
Table 7-7. Combination Utilities Identified in DMRLoads2007 Database
NPDES ID
AR0034363
CA0047953
CO0042447
CT0030279
IA0062421
IL0045527
IL0048593
IL0052817
IL0071030
ILG551012
ILG640079
IN0000311
IN0002941
IN0031011
IN0031836
KY0105091
LAO 116424
LAO 11 9679
LAO 11 9687
ME0102512
MN0041271
MO0000345
NY0005894
NY0026344
NYO 106259
NY0200778
NY0201138
NY0201154
NY0225282
NY0225860
NY0226009
Plant Name
Shumaker Public Service Corp.
Paso Robles WWTP
Rifle Station
City of Stamford
Coats Utility Company
Aqua 11 Inc-Candlewick Lake
Otter Creek Lake Utility Stp
Stonewall Utility Co Stp
Emmett Utilities Inc. Stp
Sheridan Estates Disp Stp
Aqua Illinois-Woodhaven
BPC Manufacturing Operations
Western Electric Co
USDAF USAF Grissom AFB
Gateway Utilities, Inc.
Western Lewis Rectorville Wtr
US 165 North Regional WWTF
North Vermilion WTP
Pecan Island WTP
HampdenWWTF
Franklin Heating Station
Tractebel Power Incorporated
Glenwood Landing Energy Center
Shoreham Combustion Turbine Facility
Covanta Niagara, L.P.
East 60th Street Steam Plant
Consolidated Edison Co Of NY
Astoria Liquified Nat Gas Storage
Brookhaven Combustion Turbine
Shoreham Nuclear Power Station
Southold Internal Combustion
City
East Camden
Paso Robles
Garfield County
Stamford
Fort Dodge
Poplar Grove
Davis
Oakbrook Terrace
Colchester
Quincy
Sublette
Plymouth
Indianapolis
Grissom AFB
Terre Haute
Mason County
West Monroe
Maurice
Kaplan
Hampden
Rochester
Saint Louis
Glenwood Landing
Shoreham
Niagara Falls
New York
Long Island City
Astoria
Wading River
Shoreham
Greenport
Type of
Discharger
Minor
Major
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Major
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Monitoring
Data in
Database?
N
Y
N
N
N
Y
Y
Y
Y
Y
Y
N
N
N
N
N
N
N
N
N
N
N
Y
Y
Y
Y
Y
Y
Y
N
Y
Total
TWPEa
NA
173
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
<1
NA
NA
NA
NA
NA
NA
NA
Cl/TRO/CPO
Discharged b
Cl
Cl
Cl
Cl
Cl
Cl
Cl
Cl
Metals
Discharged
Na, Cu, Se
Al,Fe
Al, Zn
7-29
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Final Detailed Study Report
Chapter 7 - Preliminary Investigation of Other Industry Segments
Table 7-7. Combination Utilities Identified in DMRLoads2007 Database
NPDES ID
NY0226017
NY0226025
NY0226033
NY0259055
NY0265039
NY0266515
NY0267538
NY0268003
NY0270407
NY0270423
NY0271438
OH0041335
PA0020435
PA0061590
PAR900004
UTS000002
Plant Name
Keyspan - East Hampton Icf
Keyspan - Montauk Icf
Southamptom Icf
DTE Tonawanda LLC
White Plains Substation
Brookhaven Energy
Astoria Energy Power Pit
Consolidated Edison Co Of NY
TBGCogen Partners
Bayswater/Jamaica Bay Peak Fac
Tomson Converter Station
Prince Inland Terminal Co Belpre
White Haven WWTP
Eagle Rock Community Assoc
Convanta Delaware Valley LP
Salt Lake City Corporation
City
East Hampton
Montauk
Southampton
Buffalo
White Plains
Yaphank
Astoria
White Plains
Hicksville
Far Rockaway
Shore ham
Belpre
White Haven
Hazleton
Chester
Salt Lake City
Type of
Discharger
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Minor
Monitoring
Data in
Database?
Y
Y
Y
Y
Y
N
Y
Y
Y
Y
Y
N
N
N
N
N
Total
TWPEa
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Cl/TRO/CPO
Discharged b
Cl
Cl
Metals
Discharged
Source: [U.S. EPA, 2009b].
a - TWPE was not calculated for minor plants in the DMRLoads2007 database.
b - Cl - Chlorine; TRO - Total residual oxidants; and CPO - Chlorine produced oxidants (EPA has not developed TWFs for TRO and CPO; therefore, these
loads are not included in TWPE totals).
Plants shown in bold identify plants for which EPA was able to acquire and review the plant's NPDES permit.
NA - Not Available. The plant is either a minor discharger, in which case EPA does not calculate TWPE, or the plant did not report both concentration and flow
data and/or the plant reported only parameters for which EPA has not developed a TWF (e.g., TSS, BOD5).
Note: The rows with bold text in the table identify the plants for which EPA reviewed NPDES permits. EPA had initially selected the five plants for permit
review based on combination utilities identified in the 2002 PCS database; however, two of these five plants are not identified as combination utilities in the
DMRLoads2007 database. Therefore, only three of the plants for which EPA reviewed permits are identified in the table.
7-30
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Final Detailed Study Report Chapter 7 - Preliminary Investigation of Other Industry Segments
7.4.2 NPDES Permit Review
During the detailed study, EPA obtained NPDES permits for five35 plants initially
believed to be combination utilities. EPA reviewed the permits to determine the operations at the
plants, the types of wastewaters generated by the plants, and how the wastewaters were being
permitted.
Through the permit review, EPA identified one of the five combination utilities as an
electric generating plant. The Rifle Station plant in Rifle, Colorado, operates a natural gas-
powered combined cycle system with a total electric generating capacity of 108 MW. According
to the 2003 Summary of Rationale for the permit, the Rifle plant is an electric peaking power
generation plant categorized by the permitter to be within SIC code 4911 - Electric Services.
Until 2002, the plant was operated in conjunction with a large greenhouse that utilized steam
heat provided by the plant. The plant still provides steam heat to the greenhouse; however, the
peaking plant and greenhouse are currently under separate ownership [CDPHE, 2003].
The NPDES permit for this plant also indicated that the cooling tower blowdown
contributes 50 to 70 percent of the total discharge, which is intermittent due to the sporadic
demand for electric power from this peaking plant. The wastewater discharged by this plant is
currently limited by the requirements of the Steam Electric Power Generating effluent
guidelines36, since it meets the applicability at 40 CFR Part 423.10 [CDPHE, 2003].
EPA found the remaining four plants to be wastewater treatment and water supply plants.
None of these plants reported an electric generating unit to the EIA. In addition, the limited
amount of information on the waste streams provided in the permits indicated they had little in
common with the waste streams expected from a steam electric generating plant, as previously
described in Section 3.2. Since these plants do not appear to be "... primarily engaged in the
generation of electricity for distribution and sale..." [40 CFR Part 423.10], they do not meet the
current applicability of the Steam Electric Power Generating effluent guidelines. Further, the
processes and wastewaters generated by these non-electric-generating plants are not similar to
those of steam electric plants regulated under the Steam Electric Power Generating effluent
guidelines.
35 EPA selected these five plants based on combination utilities identified in the 2002 PCS database. Two of these
five plants are not identified as combination utilities in the DMRLoads2007 databases. The other three plants are
listed in Table 7-7.
36 The permit did not address limitations on copper and iron discharged with chemical metal cleaning wastewaters.
-------
Final Detailed Study Report Chapter 8 - References
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8-1
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Final Detailed Study Report Chapter 8 - References
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8-2
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Final Detailed Study Report Chapter 8 - References
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Final Detailed Study Report Chapter 8 - References
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Final Detailed Study Report Chapter 8 - References
172. U. S. EPA. 2006h. National Electric Energy Data System (NEEDS) 2006. "2006 NEEDS
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Final Detailed Study Report Chapter 8 - References
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Final Detailed Study Report Chapter 8 - References
201. Xcel Energy. 2009c. Xcel Energy's Response to Questions Regarding Red Wing Plant.
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