# g EPA 821-R-09-008



# Steam Electric Power Generatin Point Source Category: Final Detailed Study Report

October 2009

### This page intentionally left blank.Final Detailed Study Report Contents



### ii CONTENTS

Page

E XECUTIVE 

### S UMMARY 

### ................................................................................................................... xii

1. I NTRODUCTION AND 

### B ACKGROUND OF THE 

### S TUDY 

### ..........................................................1-1

2. D ATA 

### C OLLECTION 

### A CTIVITIES 

### ........................................................................................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 Po wer 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 (USG S) COALQUAL Database.....................2-22

2.8.3 Literature and Internet Searches ............................................................2-22 2.8.4 Environmental Groups and Other Stakeholders ....................................2-22

3. S TEAM 

### E LECTRIC 

### I NDUSTRY 

### P ROFILE 

### ...............................................................................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 ................................................................3-23Final Detailed Study Report Contents



### CONTENTS (Continued)

Page

iii 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. F LUE 

### G AS 

### D ESULFURIZATION 

### S YSTEMS 

### ...........................................................................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 Wa stewater 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 Ac hieving 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 Treatm ent Industry Profile........................................4-68

4.6.2 Calculation of Loads..............................................................................4-69 4.6.3 Industry Baseline and Treatment Technology Loads ............................4-70

5. C OAL 

### A SH 

### H ANDLING 

### S YSTEMS 

### .......................................................................................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. E NVIRONMENTAL 

### A SSESSMENT OF 

### C OAL 

### C OMBUSTION 

### W ASTEWATER 

### ...........................6-1

6.1 Coal Combustion Wastewater Pollutants.............................................................6-2

6.2 Coal Combustion Wastewater Intera ctions 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 ..............................................................................6-13Final Detailed Study Report Contents



### CONTENTS (Continued)

Page

iv 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. P RELIMINARY 

### I NVESTIGATION OF 

### O THER 

### I NDUSTRY 

### S EGMENTS 

### ......................................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 Electri c Fuel Types and Processes.................7-3 7.1.3 Summary of NPDES Permit Review .......................................................7-9

7.2 Industrial Non-Utilities ......................................................................................7-10

7.2.1 Overview of Industria l Non-Utilities.....................................................7-11 7.2.2 Demographic Data for Fossil-Fuel ed Industrial Non- Utilities ..............7-12

7.2.3 Review of Industrial Non-U tility Discharge Permits.............................7-18

7.2.4 Contacts with Industr ial Non-Utilities...................................................7-20 7.3 Steam and Air Conditioning Supply Plants .......................................................7-21 7.3.1 Wastewater Discharge Ch aracterization 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 Ch aracterization Data .......................................7-28

7.4.2 NPDES Permit Review..........................................................................7-31

8. R EFERENCES 

### .....................................................................................................................8-1Final Detailed Study Report List of Tables



### v LIST OF TABLES

Page

2-1 Summary of the Detaile d Study Site Visits ..................................................................... 2-5

2-2 Summary of the Detaile d Study Sampling Program...................................................... 2-10

2-3 Analytes Included in the Deta iled Study Sampling Program ........................................ 2-11

2-4 Profile of Coal-Fired Power Plants Op erated by Data Request Respondents ............... 2-13

3-1 Distribution of U.S. Electric Genera ting 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 Comb ined 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 Elect ric Effluent Guidelines.......................................... 3-12

3-7 Coal Pile Runoff Generation Repor ted 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 Powe r Plants with Wet FGD Systems.............................. 4-3

4-3 Projected Future Use of FGD Syst ems at Coal-Fired Power Plants................................ 4-5

4-4 FGD Scrubber Purge Flow Rates................................................................................... 4-16

4-5 Influent to FGD Wastewater Tr eatment System Concentrations .................................. 4-19

4-6 FGD Scrubber Purge Self-Monitoring Data .................................................................. 4-25

4-7 FGD Wastewater Treatment Systems Id entified During EPA’s Detailed Study........... 4-44

4-8 Pollutant Concentrations in Sampled Effluent from FGD Wa stewater Treatment Systems ........................................................................................................................ .. 4-57

4-9 Monitoring Data: Pollutant Concentrations in Effluent from Settling Ponds................ 4-64Final Detailed Study Report List of Tables



### LIST OF TABLES (Continued)

Page

vi 4-10 Monitoring Data: Pollutant Concentr ations 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 Treat ment 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 Envi ronmental Impacts from Coal Combustion

Wastewater..................................................................................................................... .. 6-7

7-1 Summary of Alternative-Fueled Stea m 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 M over Types Among Fossil-Fueled,

Steam Electric Industrial Non-Utilities.......................................................................... 7-16

7-5 Distribution of Fuel Types Among Fossi l-Fueled, Steam Electric Industrial NonUtilities...................................................................................................................... ..... 7-17Final Detailed Study Report List of Tables



### LIST OF TABLES (Continued)

Page

vii 7-6 Steam and Air-Conditioning S upply Plants Identified in DMRLoads2007

Database....................................................................................................................... .. 7-24

7-7 Combination Utilities Identified in DMRLoads2007 Database..................................... 7-29Final Detailed Study Report List of Figures



### viii 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 Plan ts for which Data Request Respondents

Provided Technical Information .................................................................................... 2-14

3-1 Types of U.S. Electri c Generating Plants ........................................................................ 3-1

3-2 Steam Electric Proce ss Flow Diagram........................................................................... 3-13

3-3 Typical Wet FGD System.............................................................................................. 3-16

3-4 Diagram of a Recircul ating Cooling System ................................................................. 3-18

3-5 Diagram of Landfill Leachate and Landf ill Runoff Generation and Collection............ 3-24

3-6 Combined Cycle Process Flow Diagram ....................................................................... 3-26

3-7 Wabash River ConocoPhillips E- GasTM 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 Projected 2020)................ 4-6

4-2 Typical Process Flow Diagram for a Li mestone Forced Oxidation FGD System........... 4-8

4-3 Process Flow Diagram for a Lime or Li mestone 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 Hydroxi de and Sulfide Chemical Precipitation System......................................................................................................................... ... 4-29

4-7 Process Flow Diagram for an Anoxic/An aerobic Biological Treatment System .......... 4-31

4-8 Process Flow Diagram for a Vapor -Compression Evaporation System........................ 4-34

4-9 Distribution of FGD Wa stewater Treatment Systems Among Plants Operating Wet FGD Systems.......................................................................................................... 4-47

4-10 Comparison of Distributi on of FGD Wastewater Treat ment Systems by Type of Oxidation System........................................................................................................... 4-48Final Detailed Study Report List of Figures



### LIST OF FIGURES (Continued)

Page

ix 4-11 Distribution of FGD Wastewater Treatment Systems Among Plants that Discharge FGD Wastewater .......................................................................................... 4-49

4-12A Concentration of Arsenic in FGD Sc rubber Purge and Effluent from Chemical Precipitation and Biological Treatment Systems at Belews Creek................................ 4-52

4-13A Concentration of Arsenic in FGD Scr ubber 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 at Belews 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 Sc rubber Purge and Effluent from Chemical Precipitation and Biological Treatment Systems at Belews Creek................................ 4-53

4-13C Concentration of Mercury in FGD Sc rubber 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 at Belews Creek.............................................................................. 4-53

4-13D Concentration of Mercury in E ffluent from Settling Pond and Biological Treatment Systems at Roxboro...................................................................................... 4-53

4-12E Concentration of Selenium in FGD Sc rubber Purge and Effluent from Chemical Precipitation and Biological Treatment Systems at Belews 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 E ffluent from Chemical Precipitation and Biological Treatment Systems at Belews Creek............................................................ 4-54

4-13F Concentration of Selenium in E ffluent from Settli ng Pond and Biological Treatment Systems at Roxboro...................................................................................... 4-54

4-12G Concentration of TDS in FGD Scru bber Purge and Effluent from Chemical Precipitation and Biological Treatment Systems at Belews Creek................................ 4-55

4-13G Concentration of TDS in FGD Scru bber Purge and Effluent from Settling Pond and Biological Treatment Systems at Roxboro ............................................................. 4-55

4-14 Estimated Industry-Level FGD Efflue nt Discharge Loadings By Treatment

Scenario....................................................................................................................... ... 4-71Final Detailed Study Report Acronyms



### x ACRONYMS

AEP American Electric Power

API American Petroleum Institute ASTM American Society fo r Testing and Materials

BAT Best available technology economically achievable

BOD 5 

### Biochemical oxygen demand (5-day)

BPJ Best Professional Judgment

BPT Best practicable control technology currently available

CaCO 3 

### Limestone Ca(OH) 2 

### Lime

CaSO 3 

### Calcium sulfite

CaSO 4 

### Calcium sulfate

CaSO 4 

### • 2H 2 

### O Gypsum

CCR Coal combustion residues

CFR Code of Federal Regulations

CO Carbon monoxide

CO 2 

### Carbon dioxide

COD Chemical oxygen demand

COS Carbonyl sulfide

CPO Chlorine-produced oxidants

CWA Clean Water Act CWTS Constructed wetland treatment system

DBA Dibasic acid (a mixture of gl utaric, succinic, and adipic acid)

DCN Document control number DMR Discharge Monitoring Report

DOE Department of Energy

DRC Dynamic reaction cell

EIA Energy Information Administration

EPA Environmental Protection Agency

EPRI Electric Power Research Institute

ESP Electrostatic precipitator

FGD Flue gas desulfurization gpd Gallons per day

gpm Gallons per minute

gpy Gallons per year

H 2 

### Hydrogen

H 2 

### S Hydrogen sulfide

HEM Hexane Extractable Material HEROTM High-efficiency reverse osmosis HG-AFS Hydride generation and atom ic fluorescence spectrometry HRSG Heat recovery steam generator

ICIS Integrated Compliance Information System IGCC Integrated gasification combined cycle

IPM Integrated Planning Model

MCL Maximum contaminant level MDEA Methyldiethanolamine mgd Million gallons per dayFinal Detailed Study Report Acronyms



### xi MSW Municipal solid waste MW Megawatt

N 2 

### Nitrogen

Na 2 

### CO 3 

### Sodium carbonate

NAICS Northern American Indus try Classification System NEEDS National Electric Energy Data System NETL National Energy Technology Laboratory

NH 3 

### Ammonia (NH 4 

### ) 2 

### SO 4 

### Ammonium sulfate

NH 4 

### HSO 4 

### Ammonium bisulfate NPDES National Pollutant Discharge Elimination System

NO Nitrogen monoxide

NO 2 

### Nitrogen dioxide

NO

x 

### Nitrogen oxides NSPS New source performance standards

OAP Office of Atmospheric Programs OAQPS Office of Air Qualit y 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 Wa ter Sanitation Commission OSWER Office of Solid Waste and Emergency Response

OW Office of Water

PCS Permit Compliance System

PPM Parts per million

PSES Pretreatment standa rds 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

SO 2 

### Sulfur dioxide

SO 3 

### 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 GroupFinal Detailed Study Report Executive Summary



### E XECUTIVE 

### S UMMARY



### This report summarizes the information colle cted and analyzed by the United States Environmental Protection Agency (EPA) to revi ew discharges from the steam electric power generating industry and to determ ine whether the current effluent guidelines for this industry should be revised. EPA’s detailed study of wastew ater discharges and treatment technologies associated with this industry evaluated a range of waste streams and processes. However, the study ultimately focused largely on discharges as sociated with coal as h handling operations and wastewater from flue gas desulfurization (F GD) 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 co llection activities and an alyses conducted over the course of EPA’s detailed study.

The scope of the study included plants cove red by the Steam Electric Power Generating effluent guidelines (40 CFR Part 423) , which is a subset of the enti re electric generating industry.

The Steam Electric Power Generati ng effluent guidelines apply to wastewater discharges from plants primarily engaged in the generation of el ectricity 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 collect ed data about the industry by performing the following activities: conducting s ite visits and wastewater samp ling episodes at steam electric power plants, distributing a questio nnaire to collect data from nine companies (30 coal-fired power plants), reviewing publicly available sour ces of data, and coordi nating with EPA program offices, other government organizations (e.g., state groups and permitting authorities), and industry and other stakeholders.

EPA evaluated several waste streams generate d at power plants, in cluding 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 syst ems (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 Re duction (SCR) NOx controls were identified as potential new waste streams that warrant attention; however, EP A was not able to obtain characterization data

for these wastes.

The use of wet FGD systems to control SO 2 

### 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 trea ting FGD wastewaters, including settling ponds, chemical precipitation sy stems, biological treatm ent systems (anaerobic and aerobic), constructed wetlands, vapor-com pression evaporation systems, and other technologies under investigation. From informa tion 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 suspen ded solids and those metals present in the

xiiFinal Detailed Study Report Executive Summary



### xiii particulate phase from FGD wastewater; however, they are not effective at removing dissolved metals. Other treatment systems, such as chemi cal precipitation and certa in biological treatment systems, are demonstrated to be effective at removing certain dissolved metals from FGD wastewater. EPA also identified operating/manageme nt practices and treatm ent technologies that are used to reduce the discharge of FGD wastewat er, 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, th e 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 requi re “... 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 pro cess 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 we ll as other coal com bustion wastewaters, contain pollutants that can have detrimental im pacts to the environment. EPA reviewed publicly available data to identify documented cases wher e environmental impacts were attributable to releases from surface impoundments or landfill s containing coal combustion residues. EPA determined that there are a number of pollutants present in wastewaters ge nerated at coal-fired power plants that can impact the environmen t, 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 su rface waters, leaching to ground water, and by surface impoundments and constructed wetlands acti ng as attractive nuisances that increase wildlife exposure to the pollutant s contained in the systems. EP A 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 generati ng units at industrial facilities (e.g., chemical plants, petroleum refineries), plants that produce steam for distri bution 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 wa stewaters 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 te rms of pollutants present; however, the volume of the wastewaters generated are much smaller than those generated at plants regulated by the effluent guidelines.Final Detailed Study Report Chapter 1 – Introduction and Background of the Study



### 1. I NTRODUCTION AND 

### B ACKGROUND OF THE 

### S TUDY



### This report summarizes the information colle cted and analyzed by the United States Environmental Protection Agency (EPA) to review discharges from steam electric power generating facilities and to determine whether th e current wastewater di scharge 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 desulf urization (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 overvie w of the steam electric power generating industry and its wastewater discharges, and the data collection activities and analyses

conducted over the course of the st udy. 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 efflue nt limitations guidelines and standards (referred to in this report as “effluent guidelines”) apply to a subset of the electric power industry, namely those plants “pri marily engaged in the generation of electricity for distribution and sale which results primarily from a process ut ilizing fossil-type fuel (c oal, oil, or gas) or nuclear fuel in conjunction w ith 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 Wa ter Act (CWA) to periodically review all effluent guidelines to determine whether revision s are warranted. In addition, section 304(m) of the CWA requires EPA to develop and publish a bienni al 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 Guidel ines Program Plan in 2008 [73 Fed. Reg. 53218; September 15, 2008], in which EPA discussed the status of the detaile d 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 availabl e data reported through the National Pollutant Discharge Elimination System (NPDES) permit program and the Toxics Release Inventory (TRI) indicated that this industry ra nked high in discharges of toxic and nonconventional pollutants [U.S. EPA, 2005b]. Because of these findings, EP A initiated a more detailed study of this category to determine if the efflue nt 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 exis ting 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 thro ugh site visits, wastewater sampling, a data

1-1Final Detailed Study Report Chapter 1 – Introduction and Background of the Study



### request that was sent to a limite d number of companies, and vari ous secondary data sources (see Chapter 2 for more detail about data collection activities).

EPA focused efforts for these data collection activities on certain di scharges from coalfired steam electric power plants (referred to in this report as “coal-fired power plants"). Specifically, these activities focused on: (1) ch aracterizing the mass and concentrations of pollutants in wastewater discharg es from coal-fired power plan ts; (2) identifying the pollutants that comprise a significant portion of the cate gory's toxic-weighted pound equivalent (TWPE) discharge estimate and the corres ponding industrial proce sses responsible for th e release of these pollutants; and (3) evaluating process changes an d treatment technologies available for reducing these pollutant discharges. EPA's review determin ed that most of the toxic loadings for this category are associated with metals and certain ot her constituents, such as selenium, present in wastewater discharges, and that the waste streams contributing th e majority of these pollutants are associated with ash handling and wet FGD systems. Other potential sources of these pollutants include coal pile runoff, metal clean ing wastes, coal washing, leachate from landfills and wastewater impoundments, and certain low-volume wastes.

EPA evaluated pollution prevention practi ces and reviewed examples of water recycle/reuse to iden tify opportunities to addr ess water quality and wa ter quantity issues. Information was compiled for wastewaters gene rated by emerging technologies such as carbon capture/sequestration and coal gasification.

EPA also assessed available information on plan ts that are not currently regulated by the Steam Electric Power Generating effluent guidelin es but that use a steam cycle to generate electricity, such as steam electr ic generating units at industrial facilities and plan ts that use nonfossil 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 th e 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 Atmosphe ric Programs (OAP). EPA also exchanged information with state NPDES permitting authori ties about the characteri stics of power plant wastewater, the availability and implementation of treatment technologies, and water quality

concerns.

This report, Steam Electric Power Generating Poin t Source Category: Final Detailed Study Report (EPA-821-R-09-008; DCN 06390), documents th e 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 Generati ng Point Source Category: 2007/2008 Detailed Study Report (EPA-821-R-08-011; DCN 05516) [U.S . EPA, 2008e], respectively.

1-2Final Detailed Study Report Chapter 1 – Introduction and Background of the Study



### 1-3 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 discussi on 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 opera ting characteristics and wastewater generation, potential control technol ogies for FGD wastewater, and EPA’s pollutant load estimates associated w ith the discharge of FGD wastewaters;

• 

### Chapter 5 discusses ash handling operati ons at coal-fired power plants, the wastewater generated, and ash wastewater treatment;

• 

### Chapter 6 discusses the environmental e ffects of coal combustion wastewaters;

• 

### Chapter 7 discusses plants and processe s that are not regulated by the Steam Electric Power Generating e ffluent guidelines, but th at use a steam cycle to generate electricity; and

• 

### Chapter 8 presents the references cited in this report.Final Detailed Study Report Chapter 2 – Data Collection Activities



### 2. D ATA 

### C OLLECTION 

### A CTIVITIES



### EPA collected and evaluated information fr om various sources in the course of conducting the detailed study of the steam electri c power generating industry. EPA used these data to develop an industry profile, determine wa stewater characteristics and potential pollution control technologies, revi ew the potential pollutant load redu ctions and costs associated with certain treatment technologies, a nd review environmental impacts associated with discharges from this industry. This section discusses the following data collection activities:

• 

### Site visits, including the site selection process, characte ristics of the sites visited, and their locations;

• 

### Wastewater sampling, including informati on about and the locations of plants sampled, types of samples collected, anal ytes included in the sampling program, and analytical methods used;

• 

### Industry questionnaire, including the char acteristics and lo cation of plants responding to the questionnaire, and a descri ption 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 in put 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 pow er 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 wastewat er, or obtained technical info rmation via the questionnaire.

2-1Final 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 focu sed data gathering activities primarily on FGD wastewater treatment and manage ment of ash transport water be cause the FGD and ash transport water stream are the primary sources of meta l discharges from the industry. EPA conducted 34 site visits at steam electric power generati ng plants in 14 states between December 2006 and April 2009.

The purpose of the site visits was to colle ct 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 comp iling 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 Wa ter 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.

2-2Final Detailed Study Report Chapter 2 – Data Collection Activities



### 2-3 From its data collection activ ities, EPA identified 108 plants that as of June 2008 were operating one or more wet FGD systems. 1



### EPA considered the following characteristics to se lect plants for site vi sits (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) a nd/or selective non-catalytic reduction (SNCR) NO

x 

### controls;

• 

### Ash handling systems;

• 

### Ash treatment system; and

• 

### Advanced flue gas mercury controls.

Using these characteristics, EPA identified pl ants 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 condi tions, such as type of FGD system and whether target waste streams are segregated or commi ngled with other wastes, influenced the plant selection process.

The specific objectives of these site visits were to:

• 

### Gather general information a bout each plant’s operations;

• 

### Gather information on pollution preventi on and wastewater treatment/operations;

• 

### Gather plant-specific information to develop sampling plans; and

• 

### Select and evaluate pot ential 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 de tails 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.Final Detailed Study Report Chapter 2 – Data Collection Activities



### Based on information obtained during these s ite visits, EPA selected six plants for wastewater sampling episodes, which ar e discussed further in Section 2.2.

Table 2-1 presents information on the characteris tics of each plant visited during the site visit program. The geographic distribution of th ese plants is illustrated by the map in Figure 2-2

.

Figure 2-2. Locations of Coal-F ired Power Plants Included in EPA’s Site Visit and Sampling Program

2-4Final Detailed Study ReportChapter 2 – Data Collection ActivitiesTable 2-1. Summary of the Detailed Study Site VisitsPlant NameLocation(Reference)Month/Year ofSite VisitCoal TypeFGD SystemaYear FGDBeganOperationSCR/SNCRNOxControlType of FGD WastewaterTreatment SystemFly AshHandling(wet/dry)YatesGeorgia[ERG, 2007f]December 2006Eastern BituminousJet-bubbling reactor, limestoneforced oxidation, no additives (1unit)1992No SCR orSNCRSettling pondWetWansleyGeorgia[ERG, 2007e]December 2006Eastern BituminousInstallation in progress duringsite visitNASCRs on 2unitsVisited prior to installation ofsettling pondWetWidows CreekAlabama[ERG, 2007h; ERG,2007k]December 2006Eastern BituminousSpray tower, limestone forcedoxidationb, no additives (2units)1977 and1981SCRs on bothunits withFGDSettling pondWetConemaughPennsylvania[ERG, 2007l]February 2007Eastern BituminousSpray tower, limestone forcedoxidation, dibasic acid additive(2 units)1994 and1995No SCR orSNCRChemical precipitation (limeaddition, ferric chloride,sodium sulfide, polymer),followed by aerobic sequencingbatch reactorsDryHomer CityPennsylvania[ERG, 2007i; ERG,2007j]February 2007Eastern BituminousSpray tower, limestone forcedoxidation, formic acid additive(1 unit)2001SCRs on 3unitsChemical precipitation (limeaddition, ferric chloride,polymer), followed by aerobicbiological reactorDryPleasant PrairieWisconsin[ERG, 2007d]April 2007Subbituminous(Powder RiverBasin)Spray tower, limestone forcedoxidation, no additives (2 units)2006 and2007SCRs on bothunits withFGDChemical precipitation (limeaddition, organosulfide, ferricchloride, polymer)DryBaillyIndiana[Hall, 2007]April 2007Bituminous (75%),Eastern Bituminous(25%)Spray tower, limestone forcedoxidation, no additives (2 units)1992SCR on oneof the unitswith FGDPolymer addition only; no pHadjustmentDrySeminoleFlorida[Jordan, 2007]April 2007Eastern Bituminous,also burnspetroleum coke as asmall percentage(up to 30%)Spray tower, limestone forcedoxidation, dibasic acid additive(2 units)1984No SCR orSNCRChemical precipitation (limeaddition, ferrous chloride,polymer)DryBig BendFlorida[ERG, 2007b; ERG,2007g]April 2007Eastern Bituminous,also burnspetroleum coke as asmall percentage(typically 1-2%; 5%maximum)Two scrubbers for 4 units (2units per scrubber): (1) spraytower, limestone forcedoxidation, and (2) double loopspray tower, limestone forcedoxidation, dibasic acid additive1985(doubleloop) and2000(spraytower)SCR on oneunit; willinstall SCRson the otherunits over thenext 3 yearsChemical precipitation (limeaddition, ferric chloride,polymer)Dry2-5Final Detailed Study ReportChapter 2 – Data Collection Activities2-6Table 2-1. Summary of the Detailed Study Site VisitsPlant NameLocation(Reference)Month/Year ofSite VisitCoal TypeFGD SystemaYear FGDBeganOperationSCR/SNCRNOxControlType of FGD WastewaterTreatment SystemFly AshHandling(wet/dry)CayugaNew York[Jordan, 2008b]May 2007Eastern BituminousSpray tower, limestone forcedoxidation, formic acid additive(2 units)1995SCR on 1 unitChemical precipitation (limeaddition, ferric chloride,polymer)DryMitchellWest Virginia[ERG, 2007o]May 2007Eastern BituminousSpray tower, limestone forcedoxidation, no additives (2 units)NASCRs on bothunits withFGDChemical precipitation (limeaddition, ferric chloride,polymer)WetCardinalOhio[ERG, 2007n]May 2007SubbituminousInstallation in progress duringsite visitNASCRs on 3unitsCurrently being installedWetBruce MansfieldPennsylvania[U.S. EPA, 2008d]October 2007BituminousVenturi scrubber, magnesiumenhanced lime, inhibitedoxidation (2 units); horizontalspray scrubber, magnesiumenhanced lime, inhibitedoxidation (1 unit); additionalforced oxidation as separateprocess for all 3 units1976,1977, and1980SCRs on 3unitsSurface impoundment (settling)WetRoxboroNorth Carolina[Jordan, 2008a]March 2008Eastern BituminousTray tower, limestone forcedoxidation, no additive (2 unitsoperating, 2 more units plannedfor 2008)2007 and2008)SCRs on 4unitsSettling pond followed by aanaerobic/anoxic biologicaltreatment system for removal ofmetals and nutrientsDry (but wetcapability)Belews CreekNorth Carolina[ERG, 2008h]March 2008Eastern BituminousSpray tower, limestone forcedoxidation (1 unit operating, 1more unit planned for 2008)2008SCRs on 2unitsChemical precipitationfollowed by anaerobic/anoxicbiological treatment forremoval of metals and nutrientsfollowed by a constructedwetland treatment systemDry (but wetcapability)MarshallNorth Carolina[ERG, 2008i]March 2008Eastern Bituminous,additionally burns asmall percentage ofSouth Americancoal (2%)Spray tower, limestone forcedoxidation. (3 scrubbers for 4units)2006 and2007SNCRs on 4unitsClarifier followed by aconstructed wetland treatmentsystemDry (but wetcapability)Mount StormWest Virginia[ERG, 2008p]September 2008BituminousSpray tower, limestone forcedoxidation, no additives (3 units)1995 and2002SCRs on 3unitsNo FGD wastewaterdischarged; FGD solidslandfilled (leachate from FGDlandfill treated by settlingponds and discharged)DryFinal Detailed Study ReportChapter 2 – Data Collection Activities2-7Table 2-1. Summary of the Detailed Study Site VisitsPlant NameLocation(Reference)Month/Year ofSite VisitCoal TypeFGD SystemaYear FGDBeganOperationSCR/SNCRNOxControlType of FGD WastewaterTreatment SystemFly AshHandling(wet/dry)HarrisonWest Virginia[ERG, 2009c]September 2008Eastern BituminousSpray tower, magnesiumenhanced lime inhibitedoxidation (2 units); emulsifiedsulfur added1994SCRs on 3unitsNo FGD wastewaterdischarged; FGD solidslandfilled (leachate from linedportion of FGD landfill flowsinto settling ponds and leachatefrom unlined portion of FGDlandfill is transferred to aconstructed wetlands treatmentsystem and then discharged)DryMountaineerWest Virginia[ERG, 2009u]September 2008Eastern BituminousSpray tower, limestone forcedoxidation, no additives (1 unit)2007SCR on 1 unitChemical precipitation (limeaddition, polymer, ferricchloride)DryGavinOhio[ERG, 2009b]September 2008Eastern BituminousSpray tower, magnesiumenhanced lime inhibitedoxidation (2 units); emulsifiedsulfur added1994 and1995SCRs on 2unitsNo FGD wastewaterdischarged; FGD solidslandfilled (leachate from FGDlandfill collected in settlingponds and discharged)DryDeelyTexas[ERG, 2009o]October 2008NAConsidering dry and limestoneforced oxidation wet scrubbers(2 units)Plannedfor 2012and 2013SCRs plannedon 2 units by2015To be determinedDryCloverVirginia[ERG, 2009d]October 2008Eastern BituminousSpray tower, limestone forcedoxidation (2 units)1995 and1996SNCRs onboth unitsNo FGD wastewaterdischarged; FGD solidslandfilledDryJK SpruceTexas[ERG, 2009o]October 2008Subbituminous(Powder RiverBasin)Spray tower, limestone naturaloxidation, no additives (1 unit -but plans to convert to limestoneforced oxidation in future);spray tower, limestone forcedoxidation, no additives (1 unitplanned)1992, 2010SCR on 1unit; SCRexpected by2015 on otherunitSettling pond followed by aclarifier with polymer addition.DryFayette PowerProject/Sam SeymourTexas[ERG, 2009p]October 2008Subbituminous(Powder RiverBasin)Spray tower, limestone forcedoxidation, no additives (1 unitoperating, 2 units planned)1988 (and2 unitsplanned for2010)No SCRNo FGD wastewater dischargedDryFinal Detailed Study ReportChapter 2 – Data Collection Activities2-8Table 2-1. Summary of the Detailed Study Site VisitsPlant NameLocation(Reference)Month/Year ofSite VisitCoal TypeFGD SystemaYear FGDBeganOperationSCR/SNCRNOxControlType of FGD WastewaterTreatment SystemFly AshHandling(wet/dry)GhentKentucky[ERG, 2009g]December 2008Eastern Bituminous,previously wouldoccasionally burn50/50 mixture ofEasternBituminous/PowderRiver Basin in 2unitsTray tower, limestone forcedoxidation, no additives currentlyused (DBA capability) (3 unitsoperating, 1 unit planned)1994,2007,2008, (and1 unitplanned for2009)SCRs on 2unitsSettling pondWetTrimble CountyKentucky[ERG, 2009j]December 2008Eastern Bituminousin one unit; 70/30mixture of EasternBituminous/PowderRiver Basin forplanned unitSpray tower, limestone forcedoxidation, no additives currentlyused (DBA capability foroperating unit) (1 unit operating,1 unit planned)1990 (1unitplanned for2010)SCRs on 2unitsNo FGD wastewaterdischarged; FGD solids arestored in a settling pond (plantcompletely reuses thewastewater in the settling pond)[Note: configuration oftreatment system will change in2010 to settling pond when newunit begins operation]Wet and drycapabilityCane RunKentucky[ERG, 2009h]December 2008Eastern BituminousSpray tower, lime inhibitedoxidation (2 units); spray tower,lime inhibited oxidation andsodium carbonate dual-alkali (1unit); emulsified sulfur added toall three units1976,1977, and1978No SCRsSettling pondDryMill CreekKentucky[ERG, 2009i]December 2008Eastern BituminousTray tower, limestone forcedoxidation (4 units)1978,1980,1981, and1982SCRs on 2unitsSettling pondDry (but wetcapability)Brandon ShoresMaryland[ERG, 2009k]January 2009Eastern BituminousTray tower, limestone forcedoxidation (planned for 2 units)1 unitplanned for2009 andoneplanned for2010SCRs on 2unitsChemical precipitation (limeaddition, organosulfide, ferricchloride); aerobic/anoxicbiological sequencing batchreactorsDryKenneth C ColemanKentucky[ERG, 2009m]February 2009BituminousTray tower, limestone forcedoxidation (1 scrubber for 3units)2006No SCRsClarifier and filterWetFinal Detailed Study ReportChapter 2 – Data Collection Activities2-9Table 2-1. Summary of the Detailed Study Site VisitsPlant NameLocation(Reference)Month/Year ofSite VisitCoal TypeFGD SystemaYear FGDBeganOperationSCR/SNCRNOxControlType of FGD WastewaterTreatment SystemFly AshHandling(wet/dry)GibsonIndiana[ERG, 2009e]February 2009BituminousSpray tower, limestone forcedoxidation for 3 units (Units 1, 2,and 3); horizontal flow,limestone forced oxidation for 1unit (Unit 5); spray tower,limestone inhibited oxidation for1 unit (emulsified sulfur added)(Unit 4)1982,1995,2006, and2007NoinformationNo FGD wastewater dischargedfrom the Unit 4 and 5 FGDsystems. Chemical precipitation(ferric chloride and polymer)treatment for the FGDwastewater from Units 1, 2, and3. The treated FGD wastewateris sent to the cooling lake andrecycled for plant use. Theplant is constructing a system toinject the treated FGDwastewater into undergroundgeological formations.Wet (3 units)and dry (2units)ParadiseKentucky[ERG, 2009l]February 2009BituminousSpray tower, limestone forcedoxidation (3 units)1982 (2units) and2006 (1unit)SCRs on 2unitsSettling pondWetWabash RiverIndiana[ERG, 2009f; ERG,2009v]February 2009Petroleum coke(IGCC unit);Bituminous (5pulverized coalunits)No FGD systemsNANo SCR orSNCRNAWet(butconvertingone unit todry)Miami FortOhio[ERG, 2009r]April 2009Eastern BituminousSpray tower, limestone forcedoxidation (2 units); no additives2007SCRs on 2unitsChemical precipitation (limeaddition, organosulfide, ferricchloride, polymer)Wet (1 unit)and dry (2units)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, iscontinuously discharged.NA – Not available.Note: The table reflects the data collectedat the time of each individual site visit and does not reflect changes that have occurred since the site visits wereconducted.Final Detailed Study Report Chapter 2 – Data Collection Activities



### 2.2 Wastewater Sampling

EPA conducted a sampling program to character ize untreated wastew aters generated by coal-fired power plants, as well as to evalua te treatment technologies and best management practices for reducing pollutant discharges. EP A developed a “generic” sampling plan [ERG, 2007c] to provide general sampling procedures and methods that were followed when conducting sampling activities. The generic sampli ng 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 sy stems 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 pl ants selected for the sampling program. The plant locations are shown in Figure 2-2

.

Table 2-2. Summary of the Detailed Study Sampling Program

Type of Samples Collected

FGD Treatment System Ash Pond

Plant Name Sampling Episode

No. Date of Sampling Episode Influent In-Process Effluent Influent Effluent

Big Bend 6547 July 2007 9 9

Homer City 6548 August 2007 9 9 9 9 (bottom ash)

Widows

Creek 6549 September

2007 9 9 9 (fly + bottom) 9 (fly + bottom)

Mitchell 6550 October

2007 9 9 9 9 (fly ash + other)

Cardinal 6551 October

2007 9 (fly ash) 9 (fly ash)

Belews Creek 6557 October

2008 9 9 9



### The sampling program consisted of one-day or two-day sampling ep isodes at the six selected plants. EPA prepared sampling episode re ports for each plant, describing the specific sample points, the sample collection methods us ed, 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, 2008l; 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 ch aracteristics of coal-fired pow er plant wastewaters, including contributions from coal, scrubber sorbents, trea tment chemicals, and other sources. Several analytes, such as yttrium, were included in the analyte list because of pr e-established laboratory contracts and perhaps would not have been individually selected for inclusion.

2-10Final Detailed Study Report Chapter 2 – Data Collection Activities



### 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)

Classicals

Biochemical Oxygen Demand (5-day) (BOD 5 ) SM 5210 B SM 5210 B

Chemical Oxygen Demand (COD) a SM 5220 C

Total Suspended Solids (TSS) SM 2540 D SM 2540 D

Total Dissolved Solids (TDS) SM 2540 C SM 2540 C

Sulfate ASTM D516-90 EPA 300.0

Chloride SM 4500–Cl–C EPA 300.0

Ammonia as Nitrogen SM 4500—NH3 F (18th ed.) EPA 350.1

Nitrate/Nitrite as Nitrogen SM 4500-NO3 H b EPA 353.2

Total Kjeldahl Nitrogen (TKN) SM 4500—N, C EPA 351.2

Total Phosphorus EPA 365.3 (Rev 1978) EPA 365.2

Hexane Extractable Material (HEM) EPA 1664A EPA 1664A

Silica Gel Treated Hexane Extractable Ma terial (SGT-HEM) 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) EPA 200.7

EPA 245.1

EPA 245.5 EPA 200.7 c

EPA 200.8 c

EPA 200.8 with DRC d

Low-Level Total and Dissolved Metals (11 Metals: Antimony, Arsenic, Cadmium, Chromium, Copper, Lead, Nickel, Selenium, Silver, Thallium, Zinc) EPA 1638 EPA 1638

EPA 1638 with DRC e

HG-AFS f

Low-Level Total and Dissolved Mercury EPA 1631E EPA 1631E

Hexavalent Chromium ASTM D1687-92 EPA 218.6

Low-Level Hexavalent Chromium EPA 1636 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 Ep isode 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 an alysis 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 colle cted data on the design, operation, and performance of treatment systems at steam electri c plants, specifically regarding system design and day-to-day operation. The sa mpling activities were focused on influent, effluent, and inprocess streams for FGD and ash handling wastew ater treatment systems. During each sampling

2-11Final Detailed Study Report Chapter 2 – Data Collection Activities



### 2-12 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 generate d by or associated with wet ash handling systems and SO 2 

### /NO

x 

### air pollution controls (e.g., wet FGD sy stems, SCR/SNCR). The data were also used to characterize the performance of wastew ater treatment systems.

2.3 Questionnaire (“Data Request”)

EPA collected information from a limited numb er 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 re port as the “data request” [U.S. EPA, 2007a]. The data request complement ed EPA’s site visit and sampling program by obtaining information about wastewater generati on rates and management practices for the FGD and ash transport water waste streams, othe r waste streams not sampled by EPA’s sampling program (e.g., coal pile runoff), and other pow er plant information as described below.

EPA selected nine power companies to re ceive the data request based on specific characteristics of plants they operate. These compan ies 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 compan ies (referred to in this report as “data request respondents”). As shown in Table 2-4 , the data request respondents operated a total of 67 coalfired power plants and pr ovided 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 F GD systems as of October 2007, a nd/or were planning to begin constructing wet FGD systems by December 31, 2010. Th e plants that are most likely to operate FGD systems are those that burn eastern bitumi nous coal, which has re latively high sulfur content, so the vast majority of the data request plants are located in th e 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 2 

### . 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/instal ling (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 reques t respondents in August 2007. One respondent also provided a Part B response for one data request plant in October 2007.Final Detailed Study Report Chapter 2 – Data Collection Activities



### Table 2-4. Profile of Coal-Fired Power Plants Operated by Data Request Respondents

Coal-Fired Power Plan ts Operated by Data Request Respondents Plants for which Data Request Respondents

Provided Technical Information a

Company

Number Total

No. of

Plants Number Currently Operating

Wet FGD Systems b Number Not Currently Operating Wet FGD Systems, But Planning to Begin Constructing by 12/31/2010 b Total

No. of

Plants Number with Segregated FGD

Wastewater Treatment System (Operating) b Number with Wet Fly Ash

Systems

1 10 3 2 5 0 0

2 6 1 1 2 1 1

3 16 2 1 3 0 1

4 8 1 3 4 1 2

5 10 1 4 6 1 6

6 3 3 0 3 0 3

7 8 1 2 3 1 2

8 4 2 0 2 0 0

9 2 2 0 2 0 2

Total 67 16 13 c 30 c 4 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 at one plant by Decem ber 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.



### 2-13Final Detailed Study Report Chapter 2 – Data Collection Activities

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-F ired 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 ope ration during 2006. Part B requested the following information:

• 

### General plant information, includin g address and contact information.

• 

### Steam electric power production inform ation and fuels used for each steam

electric unit that the plant operated in 2006.

• 

### Wastewater generation information, includ ing flow rate data, for the following wastewaters: coal pile runoff; coal pul verizer 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 sy stem 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.

2-14Final 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 fo r each FGD wastewater treatment system

constructed between Januar y 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 m eet certain sample location and analyte

criteria.

In developing the data request, EPA worked with industry trade a ssociations and other EPA program offices to develop que stions that addressed the need s of the detailed study while minimizing respondent burden. Afte r distributing the data request to the nine data request respondents, EPA provided assistance and clarif ication 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 en sure 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 da ta 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 info rmation 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 in formation 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 Natio nal Pollutant Discharge E limination System (NPDES) permits and accompanying fact sheets;

• 

### Input from EPA and state permitting author ities regarding implementation of the Steam Electric Power Generating effluent guidelines;

• 

### Background information on the steam electri c industry from documents prepared during the development of the Steam Electric Power Generating effluent guidelines;

• 

### Information from a survey of the indu stry conducted in support of the Clean Water Act Section 316(b) Cooling Wate r Intake Structures rulemaking;

• 

### Information from EPA’s OAR used to predict impacts from environmental policies;

• 

### Information from EPA’s ORD character izing coal combustion residues (CCRs) and the potential leaching of these CCRs from landfills and surface impoundments;

• 

### Information collected by EPA’s OSWE R regarding surface impoundments or other similar management units th at contain CCRs at power plants.

2-15Final 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 obt ained initial information on reported pollutant releases from the electric generating industr y, 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 e fforts with ongoing research and activities being undertaken by other EPA offices, including the Office of Air and Radiation (OAR), the

Office of Research and Deve lopment (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., indu strial facilities that discharge process wastewaters from any point source into receiving wa ters) to control their discharges according to effluent guidelines and water qua lity-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 st eam electric plants and to determine how the wastewaters are currently regulated (i.e., effluent limitations for sp ecific parameters and the basis for selecting the parameters). As part of th e NPDES permit review, EPA contacted state permit

writers to obtain additional inform ation or clarify permit information.

2.4.2 State Groups and Permitting Authorities

Throughout the detailed study, EPA interacted with states and EPA regional permitting authorities. When contacting and visiting power plants, EPA coordi nated with stat e and regional permit writers. EPA solicited input and suggestio ns from states and permitting authorities on specific power plant characteristics and implemen tation of the Steam Electric Power Generating effluent guidelines. EPA hosted a webcast semina r 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 fr om 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 Docume nts 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 Elect ric Power Generating Point Source Category (referred to in this report as “the 1974 Deve lopment 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 Electri c Power Generating effluent

2-16Final Detailed Study Report Chapter 2 – Data Collection Activities



### guidelines. These development documents cont ain findings, conclusions, and recommendations on control and treatment technology relating to discharges from st eam electric power plants. In this detailed study, EPA used the informa tion presented in the 1974 and 1982 Development Documents for historical background on the Stea m Electric Power Generati ng 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 Wa ter Intake Structures rulemaking, EPA conducted a survey of steam elect ric 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 co de 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 wate r intake structures and cooling water

systems;

• 

### Studies of the potential imp acts from cooling water inta ke structures conducted by the facility; and

• 

### Financial and economic information about the facility.

Although the Section 316(b) su rvey was used to create guidelines for cooling water intake structures, the cooling water system inform ation collected in the survey was useful for the detailed study of the steam el ectric industry. EPA used the info rmation provided by the Section 316(b) survey in the following analyses:

• 

### Linking Energy Information Administration (E IA) 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 Air and Radiation

EPA’s Office of Air and Radiation (OAR) deve lops national programs, technical policies, and regulations for controlling air pollution and radiation exposure. EPA used the 2006 Integrated Planning Model (IPM) database us ed 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 proj ected impacts from environmental policies on the electric power sector. IPM Version 3.0 projects the electric genera ting 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. A dditionally, 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.

2-17Final 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 characte ristics of coal combustion re sidues (CCRs). Specifically, the Office of Research and Developm ent is studying the potential cros s-media transfer of mercury and other metals from flue gas, fly ash, and ot her residues collected from coal-fired boiler air pollution controls and disposed of in landfill s or surface impoundments. The key routes of release being studied are leaching into groundwater or subsequent release in to surface waters, reemission of mercury, and bioaccumulation. The Of fice of Research and Development is also examining the use of CCRs in asphalt, cement, and wallboard production.

This research seeks to better understand poten tial impacts from di sposal practices and beneficial use of CCRs by taking a holistic approach, evaluating life-cycle environmental tradeoffs that compare beneficial use applicatio ns 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 an d the different factors af fecting 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 re search assessing the potential fo r CCRs to impact water quality.

2.4.7 Office of Solid Waste and Emergency Response

EPA’s Office of Solid Waste and Emerge ncy Response (OSWER) recently issued Information Request Letters to electric uti lities that have surface impoundments or similar management units that contain CCRs. EPA’s OS WER is using the data collected from the Information Request Letters to evaluate the th reat 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 a nd FGD ponds at coal-fired power plants.

The OSWER database contains in formation 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 EI A data does not include information about waste disposal practices for those plants with na meplate electric generati ng 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 pon d 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 in formation on CCR surface impoundments and similar waste management units, OSWER directed the reque sts to those plants id entified 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 ove r 200 individual electric util ities and four national trade

associations of electric utilities: the Edison El ectric Institute, the National Rural Electric Cooperative Association, the American Public Power Association, a nd the Nuclear Energy Institute. The individual utility companies operate power plants and other fa cilities that generate,

2-18Final Detailed Study Report Chapter 2 – Data Collection Activities



### transmit, and distribute electric ity to residential, commercial, industrial, and institutional

customers. The Edison Electric Institute is an as sociation of U.S. shareholder-owned electric companies, international aff iliates, and industry associates . The National Rural Electric Cooperative Association is an a ssociation of nonprof it electric cooperatives supplying central station service through generation, transmission, and distribution of electric ity 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 indus try policy on legislative, regulat ory, operational, and technical issues affecting the nuclear energy industry on be half of its member companies. These members include the companies that own and operate co mmercial 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 be half 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 Effl uent Guidelines Program Plan and submitted comments to EPA regarding the detailed study as part of the Preliminary 2008 Effluent Guidelines Program Plan. UWAG al so provided data during a revi ew 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 Electri c 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 facilita te the data collection process. Specifically, EPA coordinated with UWAG on collecting info rmation on power plant characteristics to support site visit select ion, discussing wastewater sampli ng approaches and recommendations, reviewing the data request for cl arity, and collecting existing pe rmit data. At the invitation of individual plants, UWAG also collected sp lit 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 pl ant information to augment data compiled from other data sources described in this chap ter. EPA provided UWAG w ith a list of 96 coalfired 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 y ear, 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 conducte d 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. EP A held several meetings with UWAG to discuss various approaches to th e sampling program, including identifying representative sample points, providing comment on the gene ric sampling plan, and providing recommendations on laboratory analyses and poten tial interferences (particularly with handling influent samples with high concentrations of solids). UWAG participated in the plant pre2-19Final Detailed Study Report Chapter 2 – Data Collection Activities



### sampling site visits and provide d review and comment on site-specific sampling plans. At the invitation of the plants being sampled, UW AG also collected split samples during EPA’s sampling episodes. EPA met with UWAG to di scuss 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 an alytical procedures for the sampling program [Hill, 2008].

2.5.3 Data Request

As discussed in Section 2.3, EPA developed a qu estionnaire (i.e., data request) to collect information on coal-fired power plants. EPA pr ovided 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 woul d understand the questions that EPA included in the request. After EPA distributed the data request to the data reque st respondents, UWAG re quested clarification regarding certain data request que stions 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 NPDES Form 2C

UWAG and EPA coordinated effort s to create a database of selected NPDES Form 2C data from UWAG’s member companies. The NPDE S Form 2C (or an equivalent form used by a state permitting authority) is an application for a permit to discharge wast ewater that must be completed by existing industrial facilities (i ncluding manufacturing, commercial, mining, and silvicultural operations). This form includes facility information, da ta on facility ou tfalls, process flow diagrams, treatment information, and intake and effluent characteristics.

The NPDES Form 2C database contains info rmation about the outfalls of coal-fired power plants that receive FGD, ash handling, or coal pile runoff wast e 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 ou tfalls for sanitary wastes, cooling water, landfill runoff, and other waste streams, in the data base. 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 a nd the plant’s only wet ash handling is for bottom ash sluicing, UWAG did not include its informati on 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 associat ion for the steam electric industry. EPRI conducts research funded by the st eam electric industry and has ex tensively studied wastewater discharges from FGD systems. The trade associ ation provided EPA with the following reports

that summarize the data collect ed during several EPRI studies:

2-20Final Detailed Study Report Chapter 2 – Data Collection Activities



### 2-21 • 

### Flue Gas Desulfurization (FGD) Wastewater Characterization : Screening Study [EPRI, 2006a];

• 

### EPRI Technical Manual: Guidance for Asse ssing 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 wastewat ers and the sampling techniques us ed 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 samp le collection techniques and c onsiderations for laboratory analysis of FGD and ash handling wastewater s. 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 elec tric 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 curre nt 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 capacity 3 

### of one megawatt (MW) or more and are operating or plan to be operating within five years of th e filing of the Annual Electric Generator Report.

The data collected in Form EIA-860 are associ ated only with the design and operation of generators at facilities [U.S. DOE, 2005a]. Fo rm EIA-767 collects information annually from all electric generating facilities with a total existi ng or planned organic-fuel ed or renewable steam electric generating unit that has a nameplate rati ng of 10 MW or larger. The data collected in

Form EIA-767 are associated with the operation and design of the en tire facility. EPA used Form EIA-767 primarily for information on the facili ties operating (or planni ng to operate) FGD systems [U.S. DOE, 2005b]. the

3 DOE defines the generator nameplate capacity as the maximum rated output of a generator under specificconditions designated by the manufacturer. Generator nameplate capacity is usually indicated in units of kilovoltamperes (kVA) and in kilowatts (kW) on a nameplate physically attached to the generator. More generally, generator capacity is the maximum output, commonly expre ssed in megawatts (MW), that generating equipment can supply to system load, adjusted for ambient conditions.Final Detailed Study Report Chapter 2 – Data Collection Activities



### 2-22 2.8 Other Sources

EPA obtained additional information on st eam electric processes, technologies, wastewaters, pollutants, and regulations from s ources 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 e ffluent guidelines planning process, as well as other co ntacts with interested stakeholders.

2.8.1 Wastewater Treatment Equipment Vendors

EPA contacted companies that manufacture, di stribute, or install various components of pollutant removal systems. EPA obtained inform ation 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 (U SGS) COALQUAL Database

Since the middle 1970s, the USGS has mainta ined 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 ma jor, 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 In ternet searches to obtain in formation on various aspects of the steam electric process, both for plants regula ted 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 imp acts of these wastewaters, and applicable regulations. EPA used industry journals, reference texts about the industry, and company press releases obtained from Internet searches. EPA partic ipated in the 2007 and 2008 Intern ational Water Conference and reviewed papers presented at these conferences.

2.8.4 Environmental Groups and Other Stakeholders

EPA received information from several envi ronmental 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 identif ied 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 a ssociated with the pollutants present in power plant wastewaters, and technologi cal controls for reducing or e liminating pollutant discharges from FGD and ash handling systems.Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### 3. S TEAM 

### E LECTRIC 

### I NDUSTRY 

### P ROFILE



### Electric generating plants use various types of prime movers (e.g., combustion turbines, steam turbines, diesel engines) to convert mechanical, chemic al, and/or fission energy into electric energy. Within this populat ion of electric generating plants , there are different types of processes employed to produce elec tricity (e.g., coal-fired power pl ants, wind turbines) and there are different types of companies that operate these electric generating plants (e.g., utilities, industrial plants). The Steam Electric Power Genera ting 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 vari ous 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 guidelin es. The chapter also describes the wastewaters generated by these processes.



### Electric Generating Plants

Industrial Non-Utilities Electric Generating Industry

(Utilities and Non-Utilities)

Steam Electric

Power Generation Non-Steam Electric

Power Generation

Fossil or Nuclear Steam Electric Generating Plants (Steam Electric Power Generating Point Source Category) Non-Fossil and Non-Nuclear Steam Electric Generating Plants



### Figure 3-1. Types of U.S. El ectric Generating Plants

3.1 Overview of the Electric Generating Industry

This section describes the t ypes 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.

3-1Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### 3-2 In general, the companies generating electr ical power are categorized as one of the following types:

1. Utility : Any entity that generates, transm its, and/or distribu tes electricity and recovers the cost of its generation, tran smission and/or dist ribution 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), pl ants 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 generate s, transmits, and/or sells electricity, or sells or trades electricity services and products, where costs are not established and recovered by regulatory authority. Non-utilit y power producers include, but are not limited to, independe nt power producers, power marketers and aggregators, merchant transmission se rvice providers, self-generation entities, and cogeneration firms with Qualifying Facility Status. [U.S. DOE, 2006b]. Like utilities, the primary purpos e of non-industrial non-utili ties is producing electric power for distribu tion and/or sale.

3. Industrial non-utility : Industrial non-utilit ies are similar to non-industrial nonutilities 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 fo r distribution and/or sale.

Industrial non-utilities are generally not included within the scope of the existing Steam Electric Power Generating efflue nt guidelines because they ar e not primarily engaged in producing electricity for distribution and/or sale 4 

### . As described above, these industrial nonutilities typically are industri al plants that are producing, pr ocessing, 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 great er 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 ex cluded them from the discussion of the U.S. electric generating industry for th e purposes of this report. Therefore, information presented on plants comprising the electric gene rating industry include only the utilities and the non-industrial

4 The applicability of the Steam Electric Power Generatin g 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 syst em as the thermodynamic medium.”Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### 3-3 non-utilities, which are generally categorized by the following four North American Industry Classification System (NAICS) codes 5 

### :

• 

### 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 di stribution entities are includ ed in the definition of utilities and non-industrial non-utilities, they are not included in the Steam Electric Power Generating effluent guidelines; ther efore, 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 industr y can be further broken down based on the type of prime mover used to ge nerate electricity. DOE’s Energy Information Administration (EIA) defines a prime mover as the engine, turbine, wa ter wheel, or similar machine that drives an electric generator, or a de vice 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 gene rating electricity using a “... thermal cycle employing the steam water sy stem as a thermodynamic medium,” EPA categorized the prime movers into “steam electric” and “non-steam electric” categories. The steam electric generating units include steam turb ines and combined cycle systems (see Section 3.2 for more details on these types of units). Th e non-steam electric genera ting units include, but are not limited to, combustion turbines, intern al 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 nuc lear fuel to generate the steam used in the turbine. The fossil-type fu els include coal, oil, or gas, and fuels derived from coal, oil, or gas such as petroleum coke, resi dual fuel oil, and distilla te fuel oil. Fossil-type fuels also include blast furnace gas and the produ ct of gasification processes using fossil-based feedstocks such as coal, petroleum coke, and o il. Examples of non-foss il/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 informa tion for the electric generating industry (i.e., excluding industrial non-utilities). EPA an alyzed 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. Ce nsus 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 availa ble, 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 Indu strial Classification (SIC) c odes were used to classify operations. The SIC codes applicable to the Steam Electric Power Generating effluent guidelines are discussed in Chapter 7.Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### 3-4 sources provide the most recent and comprehensive dataset of power plant data available. EPA identified electric generating plants in the EI A database as those reporting NAICS code 22 -

Utilities 6 

### . The 2002 Economic Census data include more specific industry sect or information at the six-digit NAICS code level.

According to the Economic Census, there we re 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 da ta include both steam and non-steam electric generation processes. Table 3-1 presents the distribution of pl ants among each of the electric generating NAICS codes. The Economic Census includes all facilitie s reporting under NAICS code 22. As a result, it includes entities cate gorized 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 Ge nerating Plants by NAICS Code in 2002

NAICS Code – Description Plants

221111 – Hydroelectric Power Generation 416

221112 – Fossil Fuel Electric Power Generation 1,233

221113 – Nuclear Electric Power Generation 78

221119 – Other Electric Power Generation (includes conversion of other forms of energy, such as solar, wind, or tidal power, into el ectrical energy) 411

22111 – Electric Power Ge neration (Total) 2,138

Source: [USCB, 2002].



### EPA also examined the data on electricity ge nerating 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 cap acity operated at 5,267 plants for calendar year 2005 [U.S. DOE, 2005a]. These plants include bo th the electric ge nerating 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 elec tric generating industry regulated by the Steam Electric Power Generating effluent guid elines. As mentioned in Section 3.1.1, these records include data from all pl ants that produce elec tricity, 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 thei r electric generating units to the EIA in Form EIA-860, and each plant identifies a “primary purpos e” code for its operations that is analogous

to their NAICS code. Utilities and non-industria l non-utilities report under the general NAICS

6 NAICS code 22 – Utilities is defined as establishments providing th e 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-utili ties report under the particular NAICS code for their primary manufacturing or service opera tion. Because utilities and non -industrial non-utilities are regulated by the Steam Electric Power Genera ting effluent guidelines, their EIA data are combined in this report.

3.1.2.1 Definition of the Steam Elect ric Power Generating Industry

The Steam Electric Power Generating efflue nt guidelines apply to “...discharges resulting from the operation of a generating unit by an establishment primarily engaged in the generation of electricity for dist ribution and sale which results pr imarily 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 plan ts in the EIA database that use steam electric processes as those operating at least one prime move r that utilizes steam. The followi ng 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 – com bustion 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 ar e regulated by the steam electric effluent guidelines use a fossil or nuclear fuel as th e primary energy source for the steam electric generating unit. In analyzing the EIA data, EPA included plants using th e following EIA-defined nuclear and fossil (or foss il-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 o il, 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 desc ribed above for all plants (utilities and non-industr ial non-utilities) reporting a pr imary purpose/NAICS code of 22,

3-5Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### EPA identified 1,187 steam electric plants regulat ed under the Steam Electric Power Generating effluent guidelines that reporte d to the EIA in 2005. In analyzing the EIA energy source data for the purpose of this report, EPA only identified plan ts/units that reported one of the above energy sources as a “primary” energy source in the 200 5 EIA data. These plants operate an estimated 2,557 stand-alone steam electric ge nerating 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 elect ric prime movers used by plants subject to the Steam Electric Power Genera ting 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 ge nerating units represen ts the number of gene rators/turbines that are used to generate el ectricity 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 prevalen t type of steam electric prime mover used.

In the 2005 EIA database, an estimated 411 plan ts regulated by the Steam Electric Power Generating effluent guidelines re ported 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 no t 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 ofte n 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 pe rcent of the total cap acity regulated by the steam electric effluent gui delines [U.S. DOE, 2005a].

Table 3-3 presents the distribution of fossil and nu clear fuels used to power each type of steam electric prime mover. The number of electric generating un its 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 turbin es, while gas is the primary fuel for nearly all combined cycle systems.

3-6Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### 3-7 Table 3-2. Distribution of Prime Mover Types for Plants Regulated by the Steam Electric Power Generating Effluent Guidelines

Steam Electric Prime Mover Number of

Plants a Number of

Electric Generating Units Total Steam or Combined Cycle Turbine Capacity (MW)

Stand-Alone Steam Turbine 818 (69%) 1,995 (78%) 563,726 (74%)

Combined Cycle Systems b : 411 (35%) 562 (22%) 198,660 (26%)

Combined Cycle Steam Turbine c, d 392 512 70,020

Combined Cycle Single Shaft (steam and combustion turbines share a single shaft) 22 50 9,503

Combined Cycle Combustion Turbine c, d 390 889 119,137

Total 1,187 (100%) 2,557 e
(100%) 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 id entify the number of combined cycle turbines (i.e., prime movers), but could not discern the number of actual co mbined 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 combustio n 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 cycl e combustion turbine, but not a combin ed cycle steam turbine. EPA believes that these six plants likely operate a combined cycle steam turbine; therefor e, 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 no n-fossil/non-nuclear fuel for its thre e combined cycle co mbustion 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.Final Detailed Study ReportChapter 3 – Steam Electric Industry ProfileTable 3-3. Distribution of Fuel Types Usedby Steam Electric Generating UnitsNumber of Electric Generating UnitsFossil or Nuclear FuelaStand-AloneSteam TurbinesCombined Cycle SteamTurbinesb, cCombined CycleSingle ShaftCombined CycleCombustion Turbineb, cTotalCoal:1,1792021,183Anthracite Coal, Bituminous Coal695202699Subbituminous Coal411000411Lignite Coal2900029Coal Synfuel2200022Waste/Other Coal2200022Petroleum Coke1200012Oil:13611020166Residual Fuel Oil125202129Distillate Fuel Oil11801634Waste Oil01023Gas:564499508671,975Natural Gas559495508661,966Blast Furnace Gas50005Other Gas04014Nuclear104000104Total1,995512508892,557dSource: [U.S. DOE, 2005a].a – No steam electric generating units were reported to use jetfuel, 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 combustionturbine, but not a combined cycle steam turbine. EPA believes that these six plantslikely operate a combined cycle steam turbine; therefore, EPA assumed thateach of the six plants operatesone combined cycle steam turbine and counted six additional turbines and six additional plantsto the numbers identified in the2005 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 electricgenerating unit and two internalcombustion electric generatingunits. 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 cyclecombustion turbines. EPA included the combined cycle steam turbines for these plants in the table, but did not include the internal combustion or the combinedcycle combustion turbines using fuels not covered by the effluent guidelines.d – EPA estimated the total number of electric generating units asthe sum of the stand-alone steam turbines and the estimatednumber of combined cyclesystems. EPA did not sum the total number of turbines.3-8Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### 3-9 Table 3-4 presents the distribution of fossil and nu clear fuels used by plants applicable to

the Steam Electric Power Genera ting 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). Th erefore, 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 associat ed with combined cycle units (i.e., combined cycle steam turbine, combined cycl e single shaft, and combined cycle combustion turbine). The stand-alone steam turbines are not included in th e table. The 2005 EIA data show that natural gas is th e predominant fuel source for co mbined cycle units, accounting for 99 percent of the total combined cycle capacity. Th ere 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 generate d by a coal gasification process [U.S. DOE, 2005a]. Section 3.2.10 contains additiona l 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 capacity 7



### . Table

3-6 includes the stand-alone steam turbines and al l the combined cycle system turbines (i.e., combined cycle steam turbine, combined cycl e single shaft, and combined cycle combustion turbine) in the determination of the number of steam electric pl ants 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 comb ined cycle single shaft to estimate the number of stand-alone electric generati ng units and the number of combin ed cycle systems. According to the 2005 EIA data, the largest cap acity plants (>500 MW) comprise nearly half of all steam electric plants, approximately 60 percent of the electric genera ting units, and 87 percent of the steam electric generating capacity for all plants re gulated by the effluent guidelines. Based on the 2005 EIA data, most steam electric plants are eith er 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 nonsteam generators and through the use of non-fossil/non-nuclear energy sources.Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### 3-10 Table 3-4. Types of Fuel Used by Stand- Alone and Combined Cycle Steam Turbines

Fossil or Nuclear Fuel a Number of Plants b Number of Electric Generating Units Total Steam Turbine Capacity (MW) c

Coal: 488 (41%) 1,181 (46%) 329,211 (51%)

Anthracite Coal, Bituminous Coal 280 697 175,271

Subbituminous Coal 173 411 130,300

Lignite Coal 17 29 14,643

Coal Synfuel 10 22 6,960

Waste/Other Coal 20 22 2,037

Petroleum Coke 11 (0.9%) 12 (0.5%) 778 (0.1%)

Oil: 75 (6.3%) 147 (5.7%) 32,219 (5.0%)

Residual Fuel Oil 60 127 30,983

Distillate Fuel Oil 14 19 1,216

Waste Oil 1 1 20

Gas: 619 (52%) 1,113 (44%) 175,455 (27%)

Natural Gas 613 1,104 175,186

Blast Furnace Gas 2 5 152

Other Gas 4 4 117

Nuclear 66 (5.6%) 104 (4.1%) 105,585 (16%)

Total 1,187 (100%) 2,557 (100%) 643,249 (100%)

Source: [U.S. DOE, 2005a]. Note: The table includes only the stan d-alone steam turbines, combined cycl e 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 us e jet fuel, kerosene, or gaseous propane in the 2005 EIA

database. b – Because a single plant may operate multiple electric genera ting 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.Final Detailed Study ReportChapter 3 – Steam Electric Industry Profile3-11Table 3-5. Distribution of Fuel Types for Combined Cycle Units Regulated by the Steam Electric Power Generating EffluentGuidelinesCombined Cycle Steam TurbineCombined Cycle Single Shaft (steamand combustion turbines share asingle shaft)Combined Cycle CombustionTurbineFossil or Nuclear FuelaNumber ofPlantsbNumber ofElectricGeneratingUnitscTotalTurbineCapacity(MW)dNumber ofPlantsbNumber ofElectricGeneratingUnitsTotalTurbineCapacity(MW)cNumber ofPlantsbNumber ofElectricGeneratingUnitseTotalTurbineCapacity(MW)dCoal:2224600022385Anthracite Coal, Bituminous Coal2224600022385Petroleum Coke000000000Oil:1011399000820821Residual Fuel Oil229700012238Distillate Fuel Oil78280000616536Waste Oil11200001246Gas:37949969,37522509,503380867117,932Natural Gas37649569,25822509,503379866117,926Other Gas44117000115Nuclear000000000Total39251270,02022509,503390889119,137Source: [U.S. DOE, 2005a].Note: The table includes only the combinedcycle steam turbines, combined cycle singleshaft, and combinedcycle combustion turbines. The stand-alone steamturbines are not included in this table, but can be found inTable 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, gaseouspropane, 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 plantsby 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 combustionturbine, but not a combined cycle steam turbine. EPA believes that these six plantslikely operate a combined cycle steam turbine; therefore, EPA assumed thateach of the six plants operatesone combined cycle steam turbine and counted six additional turbines and six additional plantsto the numbers identified in the2005 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 steamelectric capacities for each fuel type due to rounding errors.e – One plant in the 2005 EIA database reported having a combined cycle steam turbine electricgenerating unit and two internalcombustion electric generatingunits. 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 cyclecombustion turbines. EPA included the combined cycle steam turbines for these plants in the table, but did not include the internal combustion or the combinedcycle combustion turbines using fuels not covered by the effluent guidelines.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 St eam Electric Effluent Guidelines

Overall Plant

Capacity a 0-50

MW 50-100

MW 100-200

MW 200-300

MW 300-400

MW 400-500

MW >500 MW Total

Total Steam Electric Capacity (MW) 3,033 8,225 20,544 21,075 20,604 27,730 661,476 762,386 b

Percentage of Capacity c 0.4% 1.1% 2.7% 2.8% 2.7% 3.6% 87% 100%

Number of Plants 112 120 152 91 64 67 581 1,187

Percentage of

Plants c 9.4% 10% 13% 7.7% 5.4% 5.6% 49% 100%

Number of Steam Electric Generating

Units d 183 210 257 155 131 148 1,473 2,557

Percentage of

Steam Electric Generating Units c 7.2% 8.2% 10% 6.1% 5.1% 5.8% 58% 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, an d combined cycle

combustion turbines. a – Overall plant capacity includes elect ricity produced by both steam and n on-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 un its as the sum of the stand-alone steam turbines and the estimated number of combined cycle sy stems. 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 usi ng a process that includes: a steam generator (i.e., boiler); a steam turbine/electr ical generator; and a condenser. Figure 3-2 illustrates the stand-alone steam electric process, in which a co mbustible fuel is used as the energy source to generate steam. The Steam Electric Power Gene rating effluent guidelines regulate wastewaters discharged by those steam electric plants that us e 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 electric ity. Section 7.1 of this report discusses steam electric processes that use alternative fuel sources.

3-12Final Detailed Study ReportChapter 3 – Steam Electric Industry ProfileFigure 3-2. Steam ElectricProcess Flow Diagram3-13Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### 3-14 As shown in Figure 3-2 , fuels are fed to a boiler where they are combusted to generate steam. Boilers and their associated subsys tems often include components to improve thermodynamic efficiency by boosting steam temp erature and preheatin g intake air using superheaters, reheaters, economi zers, and air heaters. The hot gases from combustion (i.e., the flue gas) leaves the steam generator subsyste m and passes through partic ulate collection and the sulfur dioxide scrubbing system (if presen t), then is emitted through the stack. The hightemperature, high-pressure steam leaves the boiler and enters the turbine generator where it

drives the turbine blades as it moves from the hi gh-pressure to the low-pr essure stages of the turbine. The spinning of the turbine blades drives the linked generator, pr oducing electricity. The lower-pressure steam leaving the turbine enters th e condenser, where it is cooled and condensed by the cooling water flowing through heat excha nger (condenser) tubes. The water collected in the condenser (condensate) is se nt back to the boiler where it is again converted to steam [Babcock & Wilcox, 2005].

The steam electric process may be used in c onjunction with other processes that use a portion of the thermal energy produced in the bo iler. Cogeneration facili ties, also known as combined heat and power generato rs, are facilities that use ther mal energy to produce electricity and also to produce steam or hot water, typically for use in manufacturing processes or for central heating. Cogeneration tec hnologies are classified as ei ther bottoming-cycle or toppingcycle systems. In a typical bottoming-cycle syst em, high temperature steam is first used in a manufacturing process and then th e waste heat is used to genera te 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 s ource of heat for an industrial or commercial process, such as space heating or food prepar ation. 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 wast e-heat recovery boiler for use in direct heating or producing steam for thermal appli cations [U.S. DOE, 2000b]. Some

of the industrial non-utilities discussed in Sect ion 7.2 are cogeneration plants, and some of the

alternative-fueled 8 

### steam electric plants di scussed in Section 7.1 ma y be cogeneration plants.

The nuclear-fueled steam electric process is similar to the same steam/water system described above. Key differences between the nu clear 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 reactor s. The steam turbine/electric generator and condenser portions of the nuclear-fueled steam el ectric process are the same as those described

for the stand-alone steam electr ic process [U.S. DOE, 2006c].

The remainder of this section discusses th e waste streams generated at steam electric plants. This section also discu sses the combined cycle system process and emerging technologies such as IGCC and carbon capture processes. Ch apters 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 no t fueled by fossil or nuclear

fuel.Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### systems and wastewaters in greater detail, as th ese 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 desi gn, as much as 70 to 80 percent of the ash from a pulverized coal furnace will cons ist 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 collect ed 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 pa rticles drop out of suspension as the flue gas flow changes direction. The fly ash particles that remain en trained in the flue gases are ca rried to the particulate control equipment, such as baghouses and electrostatic pr ecipitators, 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. As h 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 sepa rated 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 conve yed 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 bo ttom 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-fir ed power plants typically genera te 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 comb usted, how it is prepared prior to combustion, and the operating conditions of the boiler. Fly ash and bottom ash transp ort waters typically contain heavy metals, including pr iority pollutants [U.S. EPA, 1982] . Chapter 5 further discusses ash handling operations and wastewater ge neration at coal-fired power plants.

3-15Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### 3.2.2 Flue Gas Desulfurization

Power plants use FGD scrubber systems to remove SO 2 

### from stack emissions. Typically, FGD scrubber systems can remove over 90 percent of the SO 2 

### in the flue gas, and in many cases can remove up to or greater than 99 percen t. 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 SO 2 

### absorption are lime (Ca(OH) 2 

### ) or limestone (CaCO 3 

### ), which react with the sulfur in the flue gas to form calcium sulfite (CaSO 3 

### ). Scrubber systems can be operated with varying levels of oxidation. In forced oxidation systems, the CaSO 3 

### is fully oxidized to produce gypsum (CaSO 4 

### • 2H 2 

### O). Section 4.2 discusses these processes in further detail.

Figure 3-3. Typical Wet FGD System

Limestone forced oxidation systems are th e most common scrubbers operated in the steam electric industry today. Plants that gene rate gypsum using limestone forced oxidation systems can market the gypsum for use in buildin g materials (e.g., wallboard), while plants that do not generate gypsum or onl y partially oxidize the CaSO 3 

### 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, ma y rinse the product cake to reduce the level of chlorides in the final product. This wash wa ter may be reused or potentially treated and discharged. Both sludge by-products, gypsum and CaSO 3 

### , typically require dewatering prior to sale, disposal, or processing for reuse. This dewatering process generate s 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 th at were not removed from the flue gas stream by the electrostatic precipitators (ESPs) may be transferred to the scrubber blowdown and other

downstream wastewaters a nd/or solid products.

3-16Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### 3-17 FGD wastewaters are currently regula ted by the effluent guidelines as low volume wastes generated at steam electric plan ts [40 CFR 423.11(b)]. EPA first id entified FGD wastewater as a potential wastewater for regul ation during the 1982 rulemaking. At that time, EPA concluded

that the available data were not sufficient for characterizing the polluta nt loadings from FGD systems and that additional studies would be n eeded. [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 tec hnology used to control nitrogen oxide (NO

x 

### ) emissions in the flue gas from the boiler. Ammonia (NH 3 

### ) is injected into the flue gas upstream of a catalyst, such as vanadium or titanium. The NO

x 

### in the flue gas (comprising mainly nitrogen monoxide (NO) with lesser am ounts of nitrogen dioxide (NO 2 

### )) reacts with the NH 3 

### in the presence of oxygen and the catalyst to form nitrogen and water:

4NO + 4NH 3 

### + O 2 

### → 4N 2 

### + 6H 2 

### O (3-1)

2NO 2 

### + 4NH 3 

### + O 2 

### → 3N 2 

### + 6H 2 

### O (3-2)

In addition to these primary reactions, a fraction of the SO 2 

### in the flue gas may be oxidized to sulfur trioxide (SO 3 

### ), and other side reactions may produce ammonium sulfate ((NH 4 

### ) 2 

### SO 4 

### ) and ammonium bisulfate (NH 4 

### HSO 4 

### ) as by-products:

SO 2 

### + 1⁄2 O 2 

### → SO 3 

### (3-3)

2NH 3 

### + SO 3 

### + H 2 

### O → (NH 4 

### ) 2 

### SO 4 

### (3-4)

NH 3 

### + SO 3 

### + H 2 

### O → NH 4 

### HSO 4 

### (3-5)

These by-products can foul and corrode downstream equipment. The extent to which they are formed depends upon various factors within th e process, including the sulfur content of the

coal used in the boiler and the amount of excess NH 3 

### in the system. Unreacted NH 3 

### 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 heater 9 

### and other emission control devices such as a FGD scrubber and/or particulate controls (e.g., ESP). Although the SCR does not produce a waste stream, it can affect the characteristi cs of fly ash transport water, air heater wash water, and FGD wastewater. As pr eviously explained, unreacted NH 3 

### and SO 3 

### by-product can create (NH 4 

### ) 2 

### SO 4 

### and NH 4 

### HSO 4 

### , which can deposit in the air heater and must be removed through periodic washes. Ammonia that passes un reacted through the SCR may attach to the particulates in the flue gas a nd be removed from the flue ga s in the air pollution control equipment (e.g., ESP, baghouse, FGD scrubber). Because ammonia is soluble, if the ash collected from the particulate re moval 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.Final Detailed Study Report 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 a mmonia slip, installing an SO 3 

### removal system before the air heater may further reduce the amount of (NH 4 

### ) 2 

### SO 4 

### and NH 4 

### HSO 4 

### formed and deposited in the air heater and, conseque ntly, the amount of NH 3 

### 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 co ndenser. 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 condens er. After it passes thr ough the condenser, the heated water is sent to a cooling tower to lowe r its temperature. The heated water enters the cooling tower at the top and falls down the p acking 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 en hances evaporation. As water evaporates, the latent heat required to evaporate the water is tr ansferred 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 wa ter evaporates in the cooling tower dissolved minerals present in the water remain behind in the system. Ov er 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 th e minerals from the system, which is referred to as “cooling tower blowdown.” Figure 3-4 presents a diagram of a re circulating cooling system.

Figure 3-4. Diagram of a Reci rculating Cooling System

As the cooling water passes through th e condenser, microbiological species (e.g., bacterial slimes and algae) stick to and begi n growing on the condenser tubes. This growth,

3-18Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### 3-19 referred to in the industry as biofouling, reduces heat transfer, decreases flow, and accelerates corrosion of the condenser. Various macro-organism s, such as mussels, mollusks, and clams, can also inhibit condenser performance. Steam el ectric 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 an timicrobials, or other methods (e.g., mechanical, thermal) to control macro-organisms.

Once-through cooling water and cooling tower blowdown may c ontain the following pollutants, often in low concentrations, as a re sult of chlorination and corrosion and erosion of the piping, condenser, and cooling tower material s: chlorine, iron, coppe r, nickel, aluminum, boron, chlorinated organic compounds, susp ended solids, brominated compounds, and nonoxidizing biocides. Although the pollutants present in cooling water-related wa stewaters are often at low concentrations, th e overall pollutant mass discharge may be significant due to the large flow rates of cooling water discha rges at steam electric power plants.

Once-through cooling water is the largest vo lume wastewater discharge at coal-fired power plants. EPA’s data request obtained in formation on once-through cooling water flows from 15 plants. The once-through cooling water fl ow rates at these plants ranged from 178 to 1,860 million gallons per day (mgd), with an aver age 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 th e cooling water flow rate between 92 and 95 percent compared to once-thr ough cooling systems, depending on the water source [U.S. EPA, 2001]. According to information obt ained through the data request, the average cooling tower blowdown flow rate (for 16 coal-f ired power plants and 39 recirc ulating 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 coolin g water flow rate data presented in the 1996 Preliminary Data Study and the 1982 Developm ent 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-th rough cooling systems. Recirculating cooling systems use evaporation to remove heat from the cooling water, and the wa ter 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 evaporati on. There are two types of dry cooling systems for power plant applications: direct dry cooling and indirect dry cooling. Dire ct dry cooling systems use air to directly condense steam, whereas indir ect dry cooling systems use a closed-cycle water cooling system to condense steam, and the he ated water is then cooled by air.

10 The 1982 Development Document states that the averag e 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].Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### After the cooling water has been used to c ondense the steam in the condenser, the oncethrough or recirculating c ooling water is discharged (treated or untreated) to surf ace waters or a POTW, or reused in other processes such as F GD make-up or transporting fly ash or bottom ash to the ash pond.

Some plants use the large flow rates of the cooling water di scharges to help meet their effluent limits for other process wastewaters by d iluting these other process wastes. This dilution allows plants to meet low concentration limits fo r certain metals or othe r 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 cooli ng tower blowdown generated at the plant, including a number of plants that use vapor-compression evaporatio n systems in combination with a final drying process for treatment system residuals, to tr eat cooling tower blowdow n. Section 4.3 describes the operation of vapor-compre ssion evaporation/distillation systems used to treat FGD wastewaters. The systems used to treat cooling to wer 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 ge nerated from the vapor-compression evaporation system is reused for processes such as boiler or cooling water make up.

Several best management practices and treatm ent technologies are av ailable to reduce the discharge of chlorine and other biocides fr om steam electric plants. The 1982 Development Document describes the following four biocide management practi ces 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 need ed to control biofouling;

• 

### Natural decay of total residual oxi dants (TRO)/free available oxidants. Isolate (i.e., shut off) blowdown from cooling system after biocide application until the biocide has naturally decay ed to an acceptable level;

• 

### Dechlorination (Dehalogenation). Add reducing agent, ty pically sulfur dioxide, to the cooling water stream prior to di scharge to consume the oxidizing biocide present; and

• 

### Mechanical cleaning . Clean the condenser tubes using a mechanical operation (e.g., circulate oversized sponge rubber ba lls 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 polluti on control systems, ion exchange water treatment systems, water tr eatment evaporator blowdown, laboratory and sampling streams, boiler blowdown, floor drains , cooling tower basin cleaning wastes, and

3-20Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### recirculating house service wate r systems. See 40 CFR 423.11. The wastewater associated with wet scrubber air pollution control systems are described in section 3.2.2 and chap ter 4 of this report. The 1982 Development Document pres ents information on the generation and

characteristics of boiler blowdow n, boiler feed water treatment wastewaters, and drains and spills. For example, the 1982 Development Docu ment describes that boiler blowdown can be discharged continuously or intermittently to c ontrol the build-up of suspended and dissolved

solids in the boiler water and th at 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 w ith other plant wastewaters for treatment, often in settling ponds. In some cases, low volume wa stewaters 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 settli ng pond effluent from systems that rece ive 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 lim ited to, boiler tube cleaning, boiler fireside cleaning, and air prehea ter cleaning.” (See 40 CFR 423.11). Chemi cals are used to remove scale and corrosion products that accumulate on the boile r tubes and retard heat transfer. The major constituents of boiler cleaning wastes are the meta ls of which the boiler is constructed, typically iron, copper, nickel, and zinc. Bo iler firesides are commonly wash ed 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 preh eaters. 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 infreque ntly 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 initia l treatment in a separate impound ment/basin as necessary to meet NPDES permit limitations such as limitation s 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 wa stes to a concrete basi n 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 cont ractor. Some plants have report ed 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 in cineration, ash basin trea tment, and physical chemical treatment as options for handli ng metal cleaning wastes [U.S. EPA, 1982].

3.2.7 Coal Piles

Coal-fired power plants typically receive the coal via train or barg e; 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 ar ea, referred to as the coal

3-21Final Detailed Study Report 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 ope rate 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 co al pile generates a waste stream that contains pollutants associated with the coal, referred to as coal pile runo ff. The quantity of runoff depends upon the amount of preci pitation, the physi cal location and layout of the pile, and the extent to which water infiltrates the ground unde rneath the pile. Coal pi le 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 respons es. Most of the flow

rates in Table 3-7 were estimated by the plants based on th e amount of rainfall at the plant, the size of the coal pile, and a runoff coefficient (bas ed on plant experiences). The flow rates that arenormalized on a MW basis are based on the plants’ total coal-fired capacity. The average coalfired 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 Plants Average a Median a Range a

Number of days runoff was generated in 2006 b 30 133 124 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/MW c 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 (determi nes 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 electri c 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 NPDE S 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 associat ed with the outfall. The average flow rate for these 7 plants was 213 gpm, but the flow rate s ranged from 25 to 953 gpm [UWAG, 2008]. EPA did not calculate the flow rates in gallons pe r 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 generate d 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 cau se chemical reactions in the coal piles, which will be carried away in the runoff. Coal pile runo ff is typically acidic due to the oxidation of iron sulfide, which produces sulfuric acid, and ferric h ydroxide or ferric sulfate. Coal pile runoff may contain high concentrations of copper, iron, alum inum, nickel, and other constituents present in

3-22Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### coal [U.S. EPA, 1982]. Plants typically direct coal pile runoff wastew aters to a holding pond along with stormwater runoff from ot her areas near the coal pile.

During the site visit program, EPA requested th at 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 ba sed 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 receive s 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 th e 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 va riety 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-si te landfills or surface impoundments. Leachate is the liquid that drains or leaches from a landf ill or an impoundment. Th e two sources of landfill leachate are precipitation that percolates thr ough the waste deposited in the landfill and the liquids contained within the CCR when it wa s placed in the landfill. Surface runoff is precipitation that contacts the landfill wastes a nd flows over the landfill. Landfills typically have some sort of storm water drainage to minimi ze 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 pl ants dispose of the FGD solids (i.e., gypsum or calcium sulfite) in an on-site landfill. Additionall y, many plants transfer fly ash or bottom ash to

an on-site landfill. These FGD solids and ash cont ained in the landfill can contaminate the water

that contacts it and this wastew ater may eventually be discharged as contaminated runoff or

leachate.

3-23Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### Figure 3-5. Diagram of Landfill Leachate a nd Landfill Runoff Generation and Collection

Landfill leachate and surface r unoff 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 ab ility), the characteristics of the leachate and runoff depend upon the types of CCRs that are cont ained in the landfill. EPA’s ORD is currently conducting research evaluating the po tential for pollutants to leach du ring the disposal or use of CCRs. This research is being conducted to iden tify any potential cro ss-media transfers of mercury and other metals and to meet EP A’s commitment in the Mercury Roadmap ( www.epa.gov/hg/roadmap.htm ) to report on the fate of me rcury and other metals from implementation of multi-pollutant control at coal-fi red 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 Co al Combustion Residua ls from Electric Utilities Using Enhanced Sorbents for Merc ury Control [U.S. EPA, 2006a]; and

• 

### Characterization of Coal Combustion Re sidues 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 residue s from the expanded use of wet scrubbers. A third report currently being prep ared will provide data for addi tional CCR samples to cover coal types and air pollution control conf igurations that were not addr essed 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 c ontaining calcium sulfite), blended CCRs (non-gypsum scrubber

3-24Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### residues, fly ash, and lime), and wastewater treatment filter cake. The data compiled in these reports can be used to evaluate the co mposition 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 ditc hes and/or underground pipes. From the collection system, the leachate is tran sported 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 coll ection ponds, while other pl ants 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 pollu tants 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 landfil l as possible and a top layer of top soil on which vegetation is planted. After the c overing is applied to the landfi ll, 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 impound ments (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 discusse d previously. EPA lacks data quan tifying the extent to which the effluent from the surface impoundment collection systems is recycled back to the surface impoundment, rather than discharg ed 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 pr oduce electricity. A combined cycl e system is a combination of one or more combustion turbine electric genera ting units operating in c onjunction 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 pr oduce electricity. The exhaust gase s exiting the combustion turbine still contain useful waste heat, so they are directed to heat rec overy steam generators (HRSGs) to generate steam to drive an additional turbine. Th e 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. T hus, combined cycle systems use steam turbine technology to increase the efficien cy of the combustion turbines. Figure 3-6 illustrates the combined cycle system process.

3-25Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### Figure 3-6. Combined Cycle Process Flow Diagram

The operation of steam electric units within co mbined cycle systems is virtually identical to stand-alone steam electric units, with the exce ption of the boiler. In a combined cycle system,

the combustion turbines and HRSG s functionally take the place of the boiler of a stand-alone steam electric unit. The other two major component s of steam electric generating units within combined cycle systems, the steam turbine/electr ic generator and steam condenser, are virtually

identical to those of stand-alone steam elect ric units. Thus, the wastewaters and pollutants generated from the combined cycle system are th e same as those from the stand-alone steam electric process. These wastewaters include co oling water and steam condensate water treatment

wastes.

Combustion turbines may generate wastew aters from emissions control, equipmentcooling, and equipment cleaning [U.S. EPA, 1996]. Because combustion turbines require cleanburning fuels, combined cycle combustion turbin es 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 proce ss that combines gasification technology with both gas turbine and steam turbine power generati on (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 part iculates, sulfur, and other contaminants and is then combusted in a high-efficiency combustion ga s turbine/generator. Heat from the combustion

turbine exhaust is then extracted in a heat rec overy steam generator to produce steam and drive a steam turbine/generator. IGCC pl ants can achieve higher therm odynamic efficiencies, emit lower levels of criteria air pollutant s, and consume less water than tr aditional coal combustion power plants [Ratafia-Brown, 2002].

3-26Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### According to DOE’s NETL Gasification Worl d Database, 144 plants around the world operated gasification systems that generate electricity as of 2007 and approximately 10 additional gasification plants were planne d to be built between 2008 and 2010. The total 2007 installed global capacity amounts to approxi mately 29,000 MW of electricity [U.S. DOE, 2007a]. NETL reports that there ar e currently 15 operating IGCC projects around the world as of March 2009, four of which are commercial-scale [S tiegel, 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 th e 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 IG CC operations at the currently operating U.S. systems and the wastewaters generated from these systems. Th e majority of information is specific to the Wabash River IGCC gasification process, whic h EPA visited in February 2009. Supplemental information from the Polk process is also in cluded here. The following stages of the Wabash River IGCC gasification process ar e 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 ga ses. Sulfur in the fuel is converted to primarily hydrogen sulfide (H 2 

### S) with a small portion converted to carbonyl sulfide (COS). In the gasifier, mineral ma tter in the fuel forms a molten slag that drops down to the bottom of the gasifier into a water quench ba th. The slag/water slurry is dewatered in a dewatering bin and settler, a nd 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 re moved prior to combusting the syngas.

Particulate matter is removed from the syngas using filter elements.

• 

### Low-temperature heat recovery, ch loride scrubbing, and syngas

moisturization. The particulate-free sour s yngas (i.e., syngas containing a significant amount of sulfur compounds) is sent to a water scrubber that removes

chlorides and trace metals from the s yngas. The syngas then enters the COS hydrolysis unit where COS in the gas is converted to H 2 

### S. The syngas is then cooled, which condenses water from the syngas and tran sfers ammonia (NH 3 

### ), carbon dioxide (CO 2 

### ), and H 2 

### S from the syngas into the condensed “sour” water,

which is transferred to the sour water tr eatment system. The cooled sour syngas is transferred to the acid gas removal sy stem, in which the sulfur compounds are removed, producing sweet syngas (i.e. s yngas with very few sulfur compounds present). The sweet syngas is then moistu rized and superheated prior to use in the

combustion turbine.

3-27Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### • 

### Acid gas removal. The remaining hydrogen sulfide and carbon dioxide in the sour syngas stream are removed in the ab sorber of the acid gas removal system, which uses methyldiethanolamine (MDEA) as a solvent.

• 

### Sulfur recovery. In the sulfur recovery unit, H 2 

### S 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,

CO 2 

### , and H 2 

### S dissolved gases in a two-step st ripping process in which steam is used to drive off the dissolved gases. First, the CO 2 

### and H 2 

### 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 genera tes a “sweet” water stream, which contains 500 to 1,000 ppm chlorides.

Figure 3-7. Wabash River ConocoPhillips E-GasTM Gasification Process

Although it has been treated by st eam stripping, the sweet water stream contains elements from the gasifier such as selenium, chromium, and arsenic. Additionall y, 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 generate d in a traditional coal-f ired unit. At Wabash River, prior to 2002, the sweet wate r was sent to a settling pond but the plant often was unable to meet its permit limits. To resolve this situati on, in 2002 a vapor-compression evaporator system

was installed at Wabash River to treat the sw eet water. The concentrated brine from the evaporator is sent to a rotary drum dryer that concentrates the polluta nts through evaporation and deposits solid waste on the drum as a cake. The sa lt 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

3-28Final 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 gasificati on wastewater settling pond. The effluent from the gasification wastewater settli ng pond is transferred to Wabash River’s ash pond and then discharged. Since operation of th e 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 w ith the operation of the

Wabash River IGCC unit:

• 

### Rotary drum dryer distillate;

• 

### Slag handling wastewater;

• 

### Blowdown 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 to wer 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; Wa bash River Energy, 2000].

The processes and wastewaters generated at th e Polk plant are generally similar to those described above for Wabash River, with a few diffe rences. The major difference is that Polk uses a brine concentrator/evaporator system to treat the gasificati on process wastewater. The only solid product from the brine evaporator is ammoni um chloride, which is tr ansferred to a landfill.

The distillate from the brine concentrate di splaces 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 Polk’s gasi fication process [EPRI, 2007d; Tampa Electric Company, 2008].

Because IGCC syngas contains high concentrations of carbon compared to postcombustion flue gas, CO 2 

### capture is expected to be less expensive for pre-combustion capture from IGCC systems than for post-combustion capture. Altho ugh no current IGCC plants use carbon capture, several technologies have been pr oposed. One is to convert the carbon monoxide in the syngas to carbon dioxide and hydrogen gas using a water gas shif t 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 be ing investigated to reduce or mitigate the contribution of fossil fuel emissions to global warming. Due to potential future regulations on carbon dioxide (CO 2 

### ) emissions, many steam electric power plants are consider ing alternatives available for reducing carbon emissions.

3-29Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### 3-30 There are three main approaches for capturing the CO 2 

### associated with generating electricity: post-combustion, pre- combustion, and oxyfuel combustion.

• 

### In post-combustion capture , the CO 2 

### 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 H 2 

### ) is shifted into CO 2 

### and more H 2 

### and the resulting CO 2 

### 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 cons ists 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 tr ansported to the sequestration site and stored. Processes based on oxyfuel combusti on are sometimes referred to as "zero emission" cycles, because the CO 2 

### stored is not a fracti on 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 CO 2 

### generated during combustion will inevitably end up in the condensed water.

After capture, the CO 2 

### would be transported to a suitabl e storage, or sequestration, site. Approaches under consideration include ge ologic sequestration (injection of the CO 2 

### into an underground geologic formation), ocean se questration (typically injecting the CO 2 

### into the water column at depths to allow dissolution or at deeper depths where the CO 2 

### is denser than water and

would form CO 2 

### “lakes”), and mineral storage where CO 2 

### is exothermically reacted with metal oxides to produce st able carbonates.

DOE’s National Energy Technol ogy 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 t echnologies 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 wa stewaters generated from carbon capture processes or the characte ristics of these wastewaters.

American Electric Power’s (AEP’s) Mountaineer Power Plant and We Energies’ Pleasant Prairie Power Plant are participating in EPRI-l ed pilot tests demonstrating one of Alstom Corporation’s post-combustion carbon capture technologies, the chilled ammonia process [Alstom, 2009]. Alstom has se veral demonstration projects 11 

### either operating or being built for three carbon capture technologies : chilled ammonia, advanced amines, and oxy-combustion. The

Pleasant Prairie Power Plant CO 2 

### capture project started operati ng in 2008 and the Mountaineer

Power Plant CO 2 

### capture and storage pilot project is expe cted to start operating this year. The latter project will be the first phase of the Al stom/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 un der 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]Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### add the first commercial-scale CO 2 

### capture system at one of the AEP plants [Power Magazine, 2008].

The chilled ammonia process planned at Mountaineer absorbs and strips CO 2 

### from flue gas following the FGD process (see Figure 3-8 ). First, the water-saturate d flue gas is cooled and cleaned by refrigerated water inje cted directly into the gas stre am. As the flue gas is cooled, water condenses from the gas, carrying the residu al contaminants with it. The water is then evaporated in cooling towers, which reduces the total flue gas volume prior to entry into the CO 2 

### absorber unit. In the absorber, a dissolved and suspended mix of ammonium carbonate and

ammonium bicarbonate reacts with the flue gas, potentially rem oving 90 percent or more of the

CO 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 CO 2 

### -rich slurry is pumped through a heat exchanger, in which the slu rry is dissolved. The slu rry is then transferred to a high-pressure regenerator, in which a dditional heat is added by a reboiler and the CO 2 

### gas is stripped from the solution. The removed CO 2 

### can be washed, compressed, and sequestered by injection into geologic formations, such as deep sa line aquifers or depleted oil and gas reservoirs. [AWMA, 2008; Power Magazine, 2008].

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-co mbustion carbon capture technologies currently being developed for the in dustry. One such technology is planned to be pilot tested at the Alabama Power Company’s Pl ant Barry beginning in 2011. The pilot test is a partnership between DOE, Mitsubishi Heavy In dustries, EPRI, and Southern Company. The carbon capture technology is an amine solvent based technology developed by Mitsubishi Heavy Industries [POWERnews, 2009].

3-31Final Detailed Study Report Chapter 3 – Steam Electric Industry Profile



### 3-32 3.3 Effluent Guidelines for the Steam Electri c Power Generating Point Source Category

The Clean Water Act establishes a structure for regulating discharg es of pollutants to surface waters of the United States. As part of the implementation of the Act, EPA issues effluent guidelines for industrial dischargers. EP A first issued effluent guidelines for the Steam Electric Power Generating Point Source Category (i .e., the Steam Electric e ffluent guidelines) in 1974 with subsequent revisions in 1977 and 1982. The Steam Electric effluent guidelines are

codified at 40 CFR Part 423 and include lim itations 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 contro l systems, ion exchange water treatment systems, water treatment evaporator blowdown, laboratory and sampling streams, boiler blowdown, floor drains, cooling tower ba sin cleaning wastes, and recirculating house service water systems (sanitary and air conditioning wastes are not included) [40 CFR 423.11(b)].

The current effluent guidelines are summarized in Table 3-8 and are applicable to:

“...discharges resulti ng from the operation of a gene rating unit by an establishment primarily engaged in the genera tion of electricity for distri bution 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 pr imarily use a non-fossil or nonnuclear fuel source (e.g., wood waste, municipal solid waste) to power the steam electric generators, nor do they apply to generating uni ts operated by establis hments that are not primarily engaged in generating elect ricity for distribution and sale.Final Detailed Study ReportChapter 3 – Steam Electric Industry Profile3-33Table 3-8. Current Effluent Guidelines and Standards for the Steam Electric Power Generating Point Source CategoryWaste StreamBPTaBATaNSPSaPSES and PSNSaAll Waste StreamspH: 6-9 S.U.bPCBs: Zero dischargePCBs: Zero dischargepH: 6-9 S.U.bPCBs: Zero dischargePCBs: Zero dischargeLow-VolumeWastesTSS: 100 mg/L; 30 mg/LOil & Grease: 20 mg/L; 15 mg/LTSS: 100 mg/L; 30 mg/LOil & Grease: 20 mg/L; 15 mg/LFly Ash TransportTSS: 100 mg/L; 30 mg/LOil & Grease: 20 mg/L; 15 mg/LZero dischargeZero discharge(PSNS only)No limitation for PSESBottom AshTransportTSS: 100 mg/L; 30 mg/LOil & Grease: 20 mg/L; 15 mg/LTSS: 100 mg/L; 30 mg/LOil & Grease: 20 mg/L; 15 mg/LOnce-ThroughCoolingFree Available Chlorine: 0.5mg/L; 0.2 mg/LTotal Residual Chlorine:If >25 MW: 0.20 mg/Linstantaneous maximum;If < 25 MW, equal to BPTTotal Residual Chlorine:If >25 MW: 0.20 mg/Linstantaneous maximum;If < 25 MW, equal to BPTCooling TowerBlowdownFree Available Chlorine: 0.5mg/L; 0.2 mg/LFree Available Chlorine: 0.5mg/L; 0.2 mg/L126 Priority Pollutants: Zerodischarge, except:Chromium: 0.2 mg/L; 0.2 mg/LZinc: 1.0 mg/L; 1.0 mg/LFree Available Chlorine: 0.5mg/L; /0.2 mg/L126 Priority Pollutants: Zerodischarge, except:Chromium: 0.2 mg/L; 0.2 mg/LZinc: 1.0 mg/L; 1.0 mg/L126 Priority Pollutants: Zerodischarge, except:Chromium: 0.2 mg/L; 0.2 mg/LZinc: 1.0 mg/L; 1.0 mg/LCoal Pile RunoffTSS*: 50 mg/L instantaneousmaximumTSS*: 50 mg/L instantaneousmaximumFinal Detailed Study ReportChapter 3 – Steam Electric Industry Profile3-34Table 3-8. Current Effluent Guidelines and Standards for the Steam Electric Power Generating Point Source CategoryWaste StreamBPTaBATaNSPSaPSES and PSNSaMetal CleaningWastesTSS: 100 mg/L; 30 mg/LOil & Grease: 20 mg/L; 15 mg/LCopper: 1.0 mg/L; 1.0 mg/LIron: 1.0 mg/L; 1.0 mg/LSeeChemical Metal CleaningWastesbelowSeeChemical Metal CleaningWastesbelowSeeChemical Metal CleaningWastesbelowChemicalSeeMetal Cleaning WastesaboveCopper: 1.0 mg/L; 1.0 mg/LIron: 1.0 mg/L; 1.0 mg/LTSS: 100 mg/L; 30 mg/LOil & Grease: 20 mg/L; 15 mg/LCopper: 1.0 mg/L; 1.0 mg/LIron: 1.0 mg/L; 1.0 mg/LCopper: 1.0 mg/L (dailymaximum)Non-chemicalSeeMetal Cleaning WastesaboveReservedReservedReservedSource: [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 effluentguidelines, where two or more waste streams are combined, the total pollutant discharge quantity may not exceed the sum of allowable pollutant quantities foreach 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 2hrs/day/unit. Simultaneous discharge of chlorine from multiple units is prohibited. Limitations are applicable at the dischargefrom an individual unit prior tocombination 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 atthe discharge point to surface waters of the United States and may be subsequentto combination with the discharge from anotherunit.126 Priority Pollutants: zero discharge - 126 priority pollutants from added maintenance chemicals (refer to App. A to 40 CFR 423). At the permitting authority'sdiscretion, compliance with the zero-discharge limitations for the 126 priority pollutants may be determined by engineering calculations, which demonstrate thatthe 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.Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### 4-1 4. F LUE 

### G AS 

### D ESULFURIZATION 

### S YSTEMS



### This chapter presents an overview of flue ga s desulfurization (FGD) systems at coal-fired power plants within the steam electric industr y, with particular emphasis on FGD wastewater characteristics and treatment. This chapter also presents a profile of th e current and projected future use of FGD systems within the industry.

Power plants use FGD systems to control SO 2 

### emissions from the flue gas generated in the plants’ boilers. Wet FGD scrubbers are th e most common type of FGD system; however, approximately 20 percent of electri c generating units serviced by SO 2 

### scrubbers are serviced by dry FGD systems [U.S. DOE, 2005b]. There are severa l 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 predominan tly used in the industr y today. This section also presents some information about other t ypes of FGD systems used at coal-fired power plants, including dry scrubbers, wh ich do not generate wastewaters.

EPA has compiled information on the current an d projected use of FGD systems at coalfired power plants using information collect ed 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. EP A, 2006b] developed by ICF Consulting, Inc., and othe r publicly available information (e.g., company websites, vendor news releases). The collective data from thes e data sources are referred to in this report as

the “combined data set 12 

### .” See Chapter 2 for additional info rmation about EPA’s data collection

activities.

4.1 Coal-Fired FGD System Statistics

This section presents statisti cs on the number and characte ristics of coal-fired power plants that currently operate wet or dry FGD syst ems, or are expected to install an FGD system

in the next decade. Also included in this secti on 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 pl ant characteristics. EPA used information from the combined data set to generate the profile.

Wet FGD systems are in ope ration at 108 plants, treati ng the flue gases from 223 generating units. These 223 electr ic generating units represent th e number of electric generating

units scrubbed and is not exact ly equal to the number of FG D 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 combin ed generating capacity of the wet-scrubbed generating units represents appr oximately 33 percent of the total nationwide coal-fired steam

12 Due to the limited time available upo n receiving the surface impoundment data collected by EPA’s ORCR, the

ORCR data are not included in the combined data set.Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### electric power generating capacit y. 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 coalfired steam electric power genera tion associated with FGD system s, relative to total industry

coal-fired and fossil-fueled st eam electric power generation.

Table 4-1. Scrubbed Coal-Fired Steam Elect ric Power Generation as of June 2008

Industry Category Number of

Plants a Number of Electric Generating Units a,b Capacity (MW) a,c

Fossil-Fueled Steam Electric Power Generation d, e, f 1,120 2,450 657,000

Coal-Fired Steam Electric Power Generation d, f 488 1,180 330,000

Coal-Fired Steam Electric Power Generation with Any FGD System (Wet or Dry) g 146 280 123,000 i

Coal-Fired Steam Electric Power Generation with a Wet FGD System g, h 108 223 108,000 i

Coal-Fired Steam Electric Power Generation with a Dry FGD System g, h 41 57 14,900 i

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 severa l plants use a single FGD scrubber for more than one electric generating unit. c – The capacities presented represent the name plate 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 st eam electric and all combined cycle tu rbines (i.e., combined cycle steam turbine, combined cycle si ngle 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], a nd 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 pl ants 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 s ource. This is to be expected because eastern bituminous coal typically contains a higher sulfur content than ot her coal types, thus producing higher SO 2 

### 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 generati ng units included in the combined data set.

4-2Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### Table 4-2. Characteristics of Coal-Fired Power Plants with Wet FGD Systems

Combined Data Set a

Number of Plants with

Wet FGD Systems Number of Wet Scrubbed Electric Generating Units Wet Scrubbed Capacity b

(MW)

Total 108 223 108,000

Primary Coal Type c

Bituminous 72 161 76,300

Subbituminous 26 48 22,700

Lignite 10 14 9,060

Type of Oxidation System

Forced Oxidation 50 111 61,600

Inhibited or Natural Oxidation 36 62 30,000

No Information 26 50 16,700

Sorbent

Limestone 74 151 78,200

Limestone & Fly Ash 1 1 50

Lime 17 33 11,800

Lime & Fly Ash 2 5 2,750

Magnesium-Enhanced Lime 3 8 7,390

Magnesium Oxide 2 3 896

Fly Ash 3 6 2,360

Soda Ash 1 2 530

Soda Liquor 1 4 2,320

Sodium Carbonate 2 5 938

No Information 3 4 800

NOx Controls

SCR d 40 79 47,000

SNCR 7 15 4,700

None/Other (no SCR/SNCR) 44 80 35,600

No Information 25 49 20,900

Note: All 108 plants are included in the each of the categorie s 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 f or 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 na meplate capacity. The capacities presented have been rounded to three significant figures. Due to rounding, the total capacity may no t equal the sum of the individual capacities. c – Some plants/electric generati ng units use a blend of more than one coal in the electric generating units. This table presen ts information for only the primary type of co al 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 percen t) are serviced by natural or inhibited oxidation systems. EPA does not have information regarding the ty pe 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 sorben t used in wet FGD systems (68 percent of the

4-3Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### 4-4 currently operating electric generating units), fo llowed by lime (17 percent of electric generating units), and magnesium-enhanced lime (4 percent of electric generating un its). 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 re maining 2 percent of electric generating units.

Nearly one-third of the plants reported using additives in th eir FGD systems. Some plants add organic acids, such as diba sic acid (DBA) or formic acid, to improve the sulfur dioxide removal efficiency. Inhibited oxid ation 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 NO

x 

### emissions (35 percent SCR; 7 percent SNCR). See Section 3.2 for detail s regarding the operation of NO

x 

### control systems at power plants.

No plants in the combined data set were id entified as currently operating advanced flue gas mercury controls; however, according to th e 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 ar e 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 numb er and capacity of units that

will be scrubbed in the future.

The use of FGD systems has increased substa ntially since the effl uent guidelines were last revised in 1982. Power plants are expected to continue installi ng 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 compar es the projected scrubbed capacity to the projected total coal-fired capacity. 14 

### EPA models have predicted that over 60 percent of coalfired capacity will be wet scrubbed by 2020. EPA predicts that the industry’s dry scrubbed capacity will increase only slightly into the futu re and that most new FGD systems will be wet scrubbers [ERG, 2008f].

13 EPA projected future generating capacity with FGD systems using IPM Base Ca se 2006 (v.3.0), which reflects the CAMR mercury reduction requirem ents and the CAIR NOx and SO 2 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 wa stewater 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 an d 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].Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### 4-5 Table 4-3. Projected Future Use of FGD Systems at Coal-Fired Power Plants

2009 Capacity

(MW) 2010 Capacity

(MW) 2015 Capacity

(MW) 2020 Capacity

(MW) 2025 Capacity

(MW)

Wet Scrubbed a 136,000 162,000 189,000 231,000 282,000

Dry Scrubbed a 21,000 21,500 30,100 36,700 38,600

Total Scrubbed a 157,000 184,000 219,000 268,000 321,000

Total Coal-Fired Generating Capacity a 316,000 318,000 333,000 371,000 409,000

Percent Wet Scrubbed 43% 51% 57% 62% 69%

Percent Scrubbed (Wet & Dry Combined) 50% 58% 66% 72% 78%

Source: [ERG, 2008f].

a – The capacities presented have been rou nded 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 scru bbed capacity of coal-fired plants currently operating wet FGD syst ems 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 co al. Note that the projec tions for 2020 only include FGD installations for power plants and generatin g 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 li kely to operate wet or dry FGD systems.

Based on communications with industry a nd corroborated by res ponses to the data request, EPA expects that new wet FGD systems w ill 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 requireme nts to reduce stack emissions of NO

x 

### .Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization SystemsSource: [ERG, 2008b; ERG, 2008c; ERG, 2008g; ERG, 2009s; ERG, 2009w].Note: The capacities in the figures represent the plant-level wet scrubbed capacity for the entire plant; they do not representthe plant’s total coal-fired or totalgenerating capacity. The capacities in June2008 figure represent the reported nameplate capacity. The capacities in Projected2020 figure are from estimatesbased on the IPM model, which uses a variety of capacities in itsestimate, but preferentially usessummer and winter capacitybefore nameplate capacity.Figure 4-1. Wet FGD Systems at Coal-FiredPower Plants (Current and Projected 2020)4-6Final 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 fo cused primarily on forced oxidation systems because these types of FGD systems are the most common systems operating segregated wastewater treatment systems prior to disc harging FGD wastewater . In addition, based on discussions with industry repres entatives, 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. Th e limestone forced oxidation FGD system works by contacting the flue gas stream with a liquid slurry stream containing a limestone (CaCO 3 

### ) sorbent, which effects the mass transfer of pollu tants from the flue gas to the liquid stream. Equation 4-1 shows the reaction th at occurs between limestone and sulfur dioxide, producing hydrated calcium sulfite (CaSO 3 

### ) [EPRI, 2006a].

CaCO 3 (s) 

### + SO 2 (g) 

### + 1/2 H 2 

### O → CaSO 3 

### •1/2 H 2 

### O (s) 

### + CO 2 (g) 

### (4-1)

The calcium sulfite is then oxi dized to calcium sulfate (gyps um) by injecting air into the calcium sulfite slurry. Equation 4-2 s hows the reaction producing gypsum (CaSO 4 

### •2H 2 

### O) from calcium sulfite [EPRI, 2006a].

CaSO 3 

### •1/2 H 2 

### O (s) 

### + 1⁄2 O 2 (g) 

### + 3/2 H 2 

### O (l) 

### → CaSO 4 

### •2H 2 

### O (s) 

### (4-2)

During the site visits to power plants, EP A determined that the operation of these limestone forced oxidation systems varies some what 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 spra y or tray tower FGD scrubber, in which the flue gas and the limestone slurry are configured with countercu rrent 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 ga s rises through the absorb er vessel, the spray droplets of the limestone/water sl urry contact the flue gas and absorb the sulfur dioxide. The

limestone and water react with th e sulfur dioxide to produce calc ium sulfite (see Equation 4-1).

To increase the sulfur dioxide removal efficien cy, some plants use additives such as organic acids (e.g., DBA or formic acid) in the FGD syst em. These additives buffer the scrubber slurry, which controls the sulfur dioxide vapor pressure in the scrubber s, thereby maximizing the sulfur dioxide absorption rate [Babcock & Wilcox, 2005]. The scrubbed fl ue gas exits the top of the FGD scrubber through a mist eliminator and then is emitted through the stack.

4-7Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization Systems

Scrubber BlowdownFigure 4-2. Typical Process Flow Diagram for a Limestone Forced Oxidation FGD System4-8Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### 4-9 The spray droplets, some containing the cal cium 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 pu mps pump the slurry from the reaction tank to the various spray levels within the FGD sc rubber. The plant continuously recirculates the slurry in the FGD scrubber. When the percent solids or the chlori des 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, wh ich 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 main tains the solids and chlorides leve ls 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 controll ed varies by plant. Plan ts maintain a chlorides

concentration below the maximum level which th e 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 contro l the FGD system based on the percent solids

because the solids can affect th e operation of the FGD system a nd 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. Of ten, 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 for ce. 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 th e 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 separatio n process is typically tr ansferred to the purge

tank.

The solids-rich stream from the solids separa tion 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 gyps um to its desired moisture content. If the plant intends to market the gypsum for wall board production, then a vacuum belt filter is typically used because it can dr y the gypsum to a lower moisture content than a drum filter. Additionally, the gypsum is usually ri nsed with service water at the beginning of the belt filter to

reduce the chlorides concentration to meet the wa llboard 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.Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### 4-10 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 tr ansferred to a storage area until it is transported off site (for beneficial us e or disposal at an off-site landfill) or to a disposal area on site. The filtrate from the dewa tering 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 separa tion 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 sec ond 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 wa stewater treatment system have two stages of solids separation to minimize the size requirements and/or prevent overloading of the clarifie r. In this case, the solids-lean stream from the second solids separati on 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 purge 16 

### is typically transferred to some type of FGD wastewater treatment system, such as a settli ng pond or a more advanced system (see Section 4.4). It may also be commingled with other wa stewater streams (e.g., co oling water or ash pond wastewater) and discharged. Becau se most FGD treatment systems currently being used do not significantly affect the level of chlorides in th e wastewater, the treated FGD wastewater is not recycled back to the FGD scrubber.

Some plants are able to operate their so lids removal process in a manner that purges sufficient chlorides along with the solids to al low reuse of the FGD wastewater. For example, plants that dispose of their gypsum solids in a landfill do not typi cally 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. Oper ating 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 e nough chlorides with the FGD solids, these plants may then be able to recycle the solids-lean stream from the solids separati on process. Most of the plants that sell the gypsum for be neficial use have to meet chlo ride and fines specifications, and therefore, must operate with a scrubb er purge stream [Sargent & Lundy, 2007].

4.2.2 Inhibited Oxidation FGD System

Both the forced oxidation and inhibited oxida tion FGD systems remove sulfur dioxide from the flue gas; however, in the inhibite d 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, th e scrubber blowdown refers to the sl urry stream exiting the FGD scrubber, which is typically transf erred to a solids separation process. The scrubb er purge refers to the waste stream from the FGD scrubber system (typically from a solids separation process) that is tr ansferred to a wastewater treatment system or discharged. Both the scrubber blowdown and scrubber purge waste streams are depicted in . 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. Figure 4-2Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### 4-11 Many of the plants operating inhibited oxidati on 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 F GD 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 re action between limestone and sulfur dioxide and Equation 4-3 shows the reaction th at occurs between lime and su lfur dioxide, producing hydrated

calcium sulfite.

Ca(OH) 2 (s) 

### + SO 2 (g) 

### → CaSO 3 

### •1⁄2 H 2 

### O (s) 

### + 1⁄2 H 2 

### O (l) 

### (4-3)

The operation and absorption of the SO 2 

### in an inhibited oxidation FGD system is similar to the forced oxidation FGD system. A FGD pro cess 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, el emental 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 scavenge r. Because thiosulfate re acts so readily with the dissolved oxygen, it inhibits th e calcium sulfite from oxidizing to calcium sulfate, thereby generating a calcium sulfite by-produc t 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 separa tion and solids dewatering processes. Figure 4-3 presents a typical process flow diagram for a lime or lime stone inhibited oxidation FGD system. One of the major differences between the forced oxidation a nd inhibited oxidation syst ems is that inhibited oxidation systems are more likely than forced ox idation 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 oxid ation system, the scrubber blowdown is transferred to a solids separa tion process. The calcium sulf ite 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; therefor e, plants operating i nhibited oxidation FGD systems typically use a thickener for the soli ds 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 solid s-rich stream, from the solids separation process contains the calcium sulfite a nd is transferred to a dewatering process which is typically a centrifuge or vacuum drum filter.Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization SystemsFigure 4-3. Process Flow Diagramfor a Lime or Limestone Inhibited Oxidation FGD System4-12Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### The dewatering process removes water from th e calcium sulfite, drying it to its desired

moisture content. The filtrate from the dewateri ng process is transferred to a reclaim tank. The

solid cake from the final dewateri ng 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 genera te 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 pro cess and the filtrate from the dewatering process are ty pically 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 tr eatment system. Because the inhibited oxidation system typically does not generate a saleable soli d product, the solids are ty pically disposed of in

a landfill. Like the limestone forced oxidati on systems that are not beneficially using the gypsum, the plant may be able to recycle the F GD 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 [Sar gent & Lundy, 2007]. However, not all plants operating inhibited oxidation FGD systems completely recycle the F GD wastewater. For example, Louisville Gas & Electric Company’s Cane Run plant stated that th ey 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 additiona l water volume by disc harging 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 oxidat ion 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 su lfite (typically the majority) is oxidized to calcium sulfate using the dissolved oxygen presen t 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 su lfate. 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 inhib ited 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 prod uced, which consist predominantly of calcium sulfate, are transferred to a thir d party distributor for sale (prima rily 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 o ccasionally transfer s the thickener overf low to a settling pond, which is ultimately discharged [ERG, 2009o].

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### Dual-Alkali FGD Systems

The dual-alkali FGD process is different fr om 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, Na 2 

### CO 3 

### ) liquor/solution is fe d 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 gene rate hydrated calcium sulfite. A dditionally, 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 thic kener. The underflow, or solids-rich stream, from the solids separation pr ocess 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-l ean stream, that contains the sodium solution is recycled back to the FGD system as the so rbent for the scrubbing process. Because some of the sodium will leave the system with the solids-r ich 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 absorpti on process in which a lime slurry removessulfur dioxide from the flue gas. These dry FGD systems are also sometimes referred to as semidry FGD systems because a wet slurry is injected in to the flue gas; a dry sorbent is not used in the process. In the dry FGD process, the wet li me slurry, which ranges from approximately 18 to 25 percent solids, is atomized and sprayed into th e spray dryer. The percent solids in the lime slurry is calculated to control the sulfur dioxide rem oval from the flue gas but also allows for essentially all the water to evaporate within th e 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 sp ray droplets at the same time that the heat from the flue gas is evaporating the water from the sp ray 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 precip itator (ESP) or baghouse), which coll ects the solids generated in the spray dryer and some unreacted lime, as well as fl y ash if there is no particulate removal system upstream of the spray dryer. A plant may operate a pre-collection particulat e removal system if it intends to market the fly ash generated. The part iculates removed from the process are usually transferred to a silo for storage until the plant di sposes of the material or transfers it off site. Additionally, the solids removed from the particulate removal pr ocess 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 pro cess are mixed with water to approximately 35 to 45 percent solids and re turned 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].

4-14Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### 4.3 FGD Wastewater Characteristics

This section discusses the pollutant characte ristics and flow rates for FGD wastewaters based on information EPA collected during the deta iled study. Pollutant concentration data are presented for samples collected during the EP A wastewater sampling program and monitoring data provided by the individual plants/companies . These pollutant concen tration data represent information from limestone forced oxidation system s. 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 fo rced oxidation systems, as well as non-forced oxidation systems. Chapter 2 describe s EPA’s data collection activities.

The FGD system works by contacting the flue ga s 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 pollu tants 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 ex iting the FGD scrubber that is not immediately recycled back to the spray/tr ay levels). Depending upon the pollutant, the type of solids separation process and the solids dewatering proce ss used, the pollutants may partition to either the solid phase (i.e., FGD solids) or the aque ous 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 tr eatment system or discharged) is also usually

intermittent. Factors that can aff ect the characteristics and flow rate of the FGD scrubber purge wastewater include the type of coal, scrubbe r 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. Genera lly, burning a higher sulfur coal wi ll lead to a higher flow rate for the scrubber blowdown and scrubber purge. Hi gher sulfur coals produce more sulfur dioxide in the combustion process, which in turn increa ses the amount of sulfur dioxide removed in the FGD scrubber. As a result, more solids are ge nerated 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 system s, which scrub the flue gas from 65 coal-fired electric generating units. The si ze of the plants varies from scrubbed capacities of 300 to 2,700 MW. The average scrubbed capac ity per plant is 1,310 MW, with a median scrubbed capacity of

4-15Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### 1,330 MW/plant. Most of the plants operate lim estone 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 26 448 340 30.0 – 2,300

gpd/plant 26 598,000 410,000 24,300 – 3,310,000

gpy/plant 26 211,000,000 142,000,000 4,980,000

– 1,210,000,000

Normalized Flow Based on Wet-Scrubbed Capacity

gpm/scrubbed MW 26 0.423 0.250 0.0365 – 2.04

gpd/scrubbed MW 26 578 301 19.7 – 2,940

gpy/scrubbed MW 26 202,000 106,000 2,500 – 1,070,000

Source: D ata 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 wastewat er 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, includi ng 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 sc rubber 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 pu rge flow rate exceeding 3 mgd (see Figure 4-4 ). There are three plants that have normalized scrubbe r purge flow rates greater than 2,000 gpd/MW scrubbed. One of the three plants operates a once-through FGD sy stem, as described above. The other two plants operate lime inhi bited oxidation systems that tran sfer the FGD wastewater to a settling pond for treatment. Because these plan ts are generating a calci um sulfite byproduct, which is not marketable, and the scrubber purge is being transferre d to a settling pond for treatment, the plants are transferring the entire scrubber blowdown to th e settling pond (i.e., there is no solids separation process). For this reas on, the normalized scrubber purge flow rate for these plants is larger than the ot her plants because the solids, as well as the water retained in the solids, are included in the scrubber purge flow rate.

4-16Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems

0 0.5

1 1.5

2 2.5

3 3.5Flow Rate (m gd /P lant)

0 500 1,000 1,500 2,000 2,500 3,000 3,500No rm aliz ed F low (gp d/M W S crub bed)



### 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 purg e 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 material s of construction in the FGD system, the FGD system operation, and the air po llution control system s operated upstream of the FGD system. The coal is the source of the majority of the po llutants that are present in the FGD wastewater (i.e., the pollutants present in the coal are likel y to be present in the FGD wastewater). The sorbent used in the FGD system also introdu ces 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 blowdo wn exiting the scrubber will contain fly ash and other particulates. As a result, the FGD scrubbe r purge will likely cont ain increased amounts of pollutants associated with the fly ash.

Research conducted by EPA’s ORD has observe d 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 oxidize d 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 c ould explain why ORD has observed increased leachability of chromium when post-combustion NOx controls are operating [U.S. EPA, 2008c].

The materials of construction in the FGD syst em and the FGD system operation affect the pollutants present in the wastewater, as well as th e levels of the pollutant s. The use of organic

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### 4-18 acid additives contributes to higher levels of BOD5 in the FGD scrubber purge. Additionally, the type of oxidation (i.e., forced oxidation, inhibited oxidation, na tural 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 syst em operations can also affect the levels of pollutants present in the FGD wastewater because as discussed previously, th ey affect the rate at which scrubber purge is generated. For example, the larger the maximum allowable chlorides concentration in the scrubber, the lower the scru bber purge flow rate; ho wever, 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 th e FGD wastewaters that EPA sampled. 17 

### FGD wastewater contains significant concentrations of chlo ride, 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 pu rge 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 f iltrate 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 pur ge 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 collect ed 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 pu rge 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 re garding the sampling event [ERG, 2008l].

17 Note that the influent-to-treatment sample obtained for a given plant does not necessarily represent the unaltered scrubber purge, since the sample collect ed may include both scrubber purge an d treatment system recirculation flow

streams.Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization SystemsTable 4-5. Influent to FGD Wastewater Treatment System ConcentrationsAnalyteMethodUnitBig Bend –Influent to FGDWastewaterTreatmentaHomer City –Influent to FGDWastewaterTreatmentaWidows Creek –FGD ScrubberBlowdownaMitchell –FGD ScrubberPurgeaBelews Creek –FGD ScrubberPurgeaRoutine Total Metals – 200.7Aluminum200.7μg/L31,200289,000234,00017,90033,100RAntimony200.7μg/L62.586.4ND (86.9)28.718.1RArsenic200.7μg/L75.51,59052372.5236Barium200.7μg/L1,59011,900R7,200588651Beryllium200.7μg/L12.928.844.38.043.60RBoron200.7μg/L626,000224,00028,900229,000307,000RCadmium200.7μg/L22415089.219.7ND (0.250)Calcium200.7μg/L6,690,0003,220,0005,990,0003,030,0006,070,000Chromium200.7μg/L7571,4001,36070.784.8RCobalt200.7μg/L172369ND (217)68.014.7RCopper200.7μg/L12081165316437.6Iron200.7μg/L23,500824,000299,00060,60059,100RLead200.7μg/L69.134043610331.2RMagnesium200.7μg/L4,830,0002,760,000321,0001,470,000990,000Manganese200.7μg/L21,900225,0002,78028,8009,020RMercury245.1μg/LND (10.0)24326.567.5NAMolybdenum200.7μg/L6183751,34065.0NANickel200.7μg/L2,0902,560R4895541.59RSelenium200.7μg/L4,1504,000R6522,1302,930RSilver200.7μg/LND (20.0)ND (40.0)ND (86.9)ND (20.0)10.0Sodium200.7μg/L2,530,0001,430,000104,000314,00061,000Thallium200.7μg/LND (10.0)ExcludeND (43.4)ND (10.0)41.2RTitanium200.7μg/L4201,300R8,180377NAVanadium200.7μg/L7247661,58020377.6Yttrium200.7μg/L24558621764.9NA4-19Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization Systems4-20Table 4-5. Influent to FGD Wastewater Treatment System ConcentrationsAnalyteMethodUnitBig Bend –Influent to FGDWastewaterTreatmentaHomer City –Influent to FGDWastewaterTreatmentaWidows Creek –FGD ScrubberBlowdownaMitchell –FGD ScrubberPurgeaBelews Creek –FGD ScrubberPurgeaZinc200.7μg/L1,5401,9003,140885ND (25.0)Routine Dissolved Metals – 200.7Aluminum200.7μg/LND (50.0)ND (50.0)86.6ND (50.0)ND (50.0)Antimony200.7μg/L33.9ND (20.0)ND (20.0)ND (20.0)ND (4.00)Arsenic200.7μg/L18.6ND (10.0)13.9ND (10.0)24.7RBarium200.7μg/L1,820149R257488489RBeryllium200.7μg/LND (5.00)10.5ND (5.00)6.02ND (1.00)Boron200.7μg/L618,000254,00024,100232,000301,000RCadmium200.7μg/L17926.2ND (5.00)ND (5.00)ND (0.250)Calcium200.7μg/L4,470,0001,990,000849,0002,350,0005,370,000Chromium200.7μg/LND (10.0)ND (10.0)18.7ND (10.0)19.2RHexavalent ChromiumD1687-92μg/L24.0ND (2.00)ND (2.00)5.004.20Cobalt200.7μg/LND (50.0)201ND (50.0)ND (50.0)8.40L,RCopper200.7μg/L27.214.5ND (10.0)ND (10.0)ND (2.50)Iron200.7μg/LND (100)ND (100)ND (100)ND (100)ND (25.0)Lead200.7μg/LND (50.0)ND (50.0)ND (50.0)ND (50.0)ND (1.50)Magnesium200.7μg/L4,110,0003,100,000176,0001,370,000955,000RManganese200.7μg/L9,610173,00058327,9008,540Mercury245.1μg/LND (10.0)ND (10.0)ND (2.00)ND (10.0)NAMolybdenum200.7μg/L58130.687622.2NANickel200.7μg/L8511,350ND (50.0)355105RSelenium200.7μg/L3,610656R36646.9105RSilver200.7μg/LND (20.0)ND (20.0)ND (20.0)ND (20.0)7.80Sodium200.7μg/L1,970,0001,440,00076,700324,00058,700Thallium200.7μg/L14.361.214.3ND (10.0)106RTitanium200.7μg/L12.5ND (10.0)ND (10.0)ND (10.0)NAFinal Detailed Study ReportChapter 4 – Flue Gas Desulfurization Systems4-21Table 4-5. Influent to FGD Wastewater Treatment System ConcentrationsAnalyteMethodUnitBig Bend –Influent to FGDWastewaterTreatmentaHomer City –Influent to FGDWastewaterTreatmentaWidows Creek –FGD ScrubberBlowdownaMitchell –FGD ScrubberPurgeaBelews Creek –FGD ScrubberPurgeaVanadium200.7μg/L108ND (20.0)ND (20.0)ND (20.0)2.00RYttrium200.7μg/LND (5.00)6.28ND (5.00)ND (5.00)NAZinc200.7μg/L16.8ND (10.0)ND (10.0)87.8ND (25.0)Low-Level Total Metals – 1631E, 1638, HG-AFSAntimony1638μg/L24.931.151.89.2317.6RArsenic1638μg/L1651,22061759.91,270Arsenic1638 – DRCμg/LNANANANA1,010RArsenicHG-AFSμg/LNANANANA929Cadmium1638μg/L23852.8R86.05.284.84RChromium1638μg/L651L1,2701,380176L256Chromium1638 – DRCμg/LNANANANA262RCopper1638μg/L103747826139188RLead1638μg/L69.935154568.1193RMercury1631Eμg/L16.453324.713885.6Nickel1638μg/L2,5702,8406346501,240Nickel1638 – DRCμg/LNANANANA396RSelenium1638μg/L3,4703,5306511,9908,660Selenium1638 – DRCμg/LNANANANA8,250RSeleniumHG-AFSμg/LNANANANA9,100Thallium1638μg/L39.837.393.86.339.51RZinc1638μg/L1,8702,1302,720730438Zinc1638 – DRCμg/LNANANANA526RLow-Level Dissolved Metals - 1631E, 1636, 1638, HG-AFSAntimony1638μg/L21.9ND (0.400)8.901.973.83Arsenic1638μg/L13724.2R18.020.2133Arsenic1638-DRCμg/LNANANANA17.4RFinal Detailed Study ReportChapter 4 – Flue Gas Desulfurization Systems4-22Table 4-5. Influent to FGD Wastewater Treatment System ConcentrationsAnalyteMethodUnitBig Bend –Influent to FGDWastewaterTreatmentaHomer City –Influent to FGDWastewaterTreatmentaWidows Creek –FGD ScrubberBlowdownaMitchell –FGD ScrubberPurgeaBelews Creek –FGD ScrubberPurgeaArsenicHG-AFSμg/LNANANANA11.4Cadmium1638μg/L19024.53.16ND (1.00)4.47Chromium1638μg/LND (160)ND (16.0)ND (16.0)ND (80.0)19.1Chromium1638-DRCμg/LNANANANAND (5.00)Copper1638μg/LND (40.0)11.3ND (4.00)ND (20.0)ND (5.00)Lead1638μg/LND (10.0)ND (1.00)ND (1.00)ND (0.500)ND (2.00)Mercury1631Eμg/L0.2060.08090.07610.01110.0844Nickel1638μg/L1,0301,45029.6433382Nickel1638-DRCμg/LNANANANA316RSelenium1638μg/L3,280584325443468Selenium1638-DRCμg/LNANANANA412RSeleniumHG-AFSμg/LNANANANA206Thallium1638μg/L39.423.222.54.4711.1RZinc1638μg/LND (100)34.7ND (10.0)16078.6Zinc1638-DRCμg/LNANANANA69.7RClassicalsAmmonia As Nitrogen (NH3-N)4500-NH3Fbmg/L31.54.122.261.891.50Nitrate/Nitrite (NO3-N + NO2-N)353.2mg/LNA54.51.0020.614.7Total Kjeldahl Nitrogen (TKN)4500-N,Cbmg/L51.614.222.313.36.20Biochemical Oxygen Demand(BOD)5210Bmg/L1,370ND (120)17221.0ND (4.00)Chemical Oxygen Demand(COD)5220 Cmg/LNANANANA304Chloride4500-CL-Cbmg/L24,20011,8008327,2009,680Hexane Extractable Material(HEM)1664Amg/LND (6.00)ND (5.00)22.011.0ND (5.00)Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization Systems4-23Table 4-5. Influent to FGD Wastewater Treatment System ConcentrationsAnalyteMethodUnitBig Bend –Influent to FGDWastewaterTreatmentaHomer City –Influent to FGDWastewaterTreatmentaWidows Creek –FGD ScrubberBlowdownaMitchell –FGD ScrubberPurgeaBelews Creek –FGD ScrubberPurgeaSilica Gel Treated HEM (SGTHEM)1664Amg/LNANA6.00END (5.00)ND (5.00)SulfateD516-90bmg/L3,5906,92011,9001,6401,290Total Dissolved Solids (TDS)2540 Cmg/L44,60023,2004,74018,10034,600Total Phosphorus365.3bmg/L0.9902.6410.53.579.90Total Suspended Solids (TSS)2540 Dmg/L4,97013,30025,300E7,3205,200Source: [ERG, 2008l; 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 ofthe analytical methods as “routine” and some of them as “low-level.” EPA designated all of the methods that require the use ofclean hands/dirty hands samplecollection 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 analysisis different than the method presented in the table. SeeTable 2-3for details.DRC – Dynamic reaction cell. For the Belews Creek analysis, a DRCwas 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 10x the blank result.R – MS/MSD % recovery outside method acceptance criteria.Exclude – Results were excluded because theMS/MSD samples had a zero percent recovery.NA – Not analyzed.ND – Not detected (number in parentheses isthe report limit). The sampling episode reports for each of the individual plants contains additional samplinginformation, including analytical resultsfor analytes measured above the detection limit, but below the reporting limit (i.e.,J-values).Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### Widows Creek operates once-though FGD scrubbe rs (i.e., no recirculation of slurry within the absorber), with the scrubber blow down continuously sent to settling ponds. For the Widows Creek sampling episode, EPA collected a f our-hour composite sample of the influent to the FGD settling pond from a diked channel cont aining FGD scrubber blowdown from the two FGD scrubbers. EPA collected the samples from th e 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 th erefore not sending flue gases through the scrubber, the plant continued to transfer wa ter from the scrubber to the FGD settling pond. The flow rate entering the open water area of th e FGD settling pond at th e time of sampling was approximately 1,170 gpm, and plant personnel estimat ed that approximately 390 gpm of the flow rate (one-third of the entire flow) was from th e 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 tran sferred to the system at a flow rate of approximately 500 gpm. The sampling episode report for Mitchell cont ains more detailed information regarding the sampling event [ERG, 2008m].

For the Belews Creek sampling episode, EP A collected a grab sample of the FGD scrubber purge transfer to the FGD wastewater tr eatment 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 colle ction. 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 repor ted 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 i ndustry 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 syst em operated at an individual plant is typically dependent on the permit limits that the plant mu st meet. Section 4.4 describes the wastewater treatment systems planned or currently operate d by coal-fired power plants to treat FGD

wastewaters.

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### 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 1 38 8,200 333,000 μ g/L

Antimony 1 38 4.1 23 μ g/L

Arsenic 4 99 58 5,070 μ g/L

Barium 1 38 110 2,050 μ g/L

Beryllium 1 38 ND (0.7) 113 μ g/L

Boron 3 95 7,410 250,000 μ g/L

Cadmium 2 51 ND (0.5) 302 μ g/L

Chromium 2 51 1.7 350 μ g/L

Cobalt 1 38 6.4 148 μ g/L

Copper 2 43 12.8 456 μ g/L

Iron 3 79 1,100 300,000 μ g/L

Lead 1 38 14.7 252 μ g/L

Magnesium 1 13 1,200,000 1,800,000 μ g/L

Manganese 1 38 339 5,460 μ g/L

Mercury 4 132 ND (0.1) 872 μ g/L

Molybdenum 1 38 ND (2) 250 μ g/L

Nickel 3 67 23.4 710 μ g/L

Selenium 4 158 400 21,700 μ g/L

Silver 3 44 ND (0.2) 65 μ g/L

Thallium 2 46 ND (4) 746 μ g/L

Vanadium 1 38 14.2 14,800 μ g/L

Zinc 4 72 33.1 1,060 μ g/L

Dissolved Metals

Mercury 1 17 60 440 μ g/L

Selenium 2 33 130 3,000 μ g/L

Classicals

BOD 5 1 8 3.40 21.0 mg/L

COD 2 49 140 1,100 mg/L

Total suspended solids 2 111 24.0 14,000 mg/L

Total dissolved solids 3 106 6,500 26,000 mg/L

Sulfate 4 85 780 4,100 mg/L

Chloride 4 104 1,100 13,000 mg/L

Bromide 1 28 43.0 96.0 mg/L

Fluoride 1 37 6.80 57.0 mg/L

Nitrate/nitrite 2 76 ND (10.0) 270 mg/L

Total Kjeldahl nitrogen 2 37 2.80 24.0 mg/L

Total phosphorus 1 1 4.00 4.00 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.



### 4-25Final 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 tr eatment of FGD scrubber purge, as well as operating/management practices that were used to reduce the disc harge of FGD wastewater. This

section describes the fo llowing technologies:

• 

### Settling ponds;

• 

### Chemical precipitation (using hydroxid e 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 wast ewater use settling ponds; however, the use

of more advanced wastewater tr eatment 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 partic ulates 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 lifespan of the pond based on the expected rate of solids buildup within th e 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 br ing it into compliance w ith 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 sufficien tly long residence time; however, settling ponds are not designed to redu ce the amount of dissolved metals in the

wastewater. The FGD wastewater en tering a treatment system contains significant concentrations of several pollutants in the dissolved phase, including boron, manganese, and selenium. These dissolved metals are likely discharged largel y 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 gyps um 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 ca n impact the solubility of metals in the ash pond, thereby potentially leading to increases in the effluent me tal concentrations [EPRI, 2006b].

Section 5.4.1 contains a more detail ed discussion of this topic.

EPA compiled data for plants operating we t FGD systems and wastewater treatment systems used to treat the FGD wastewaters generated. Based on th ese data, settling ponds are the most commonly used systems for managing FGD wa stewater. Most plants using ponds transfer

4-26Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### FGD scrubber purge directly to a settling pond that also treats ot her waste streams, specifically fly ash transport water and/or bot tom ash transport water. Approxima tely one-third of the plants using FGD ponds transfer the FGD scrubber purg e to a settling pond specifically designated to treat FGD wastewater. In these cases, the FGD wa stewater pond effluent is either discharged directly to surface waters (with or without firs t mixing with cooling wate r 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 F GD scrubber purge to a settling po nd for initial solids removal and then transfer the wastewater to a biological treatment system for further treatment.

EPA reviewed information to determine whet her the use of settli ng ponds to treat FGD wastewater was limited to relatively older scr ubbers. Approximately 20 percent of the plants using settling ponds began operating an addition al wet FGD system after 2000. Each of these plants was already operating an other FGD system prior to 2000. This suggests plants do not replace the settling pond treatmen t 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 plan ts currently without sc rubbers have announced that they intend to rely on settling ponds to treat their F GD wastewater. The information compiled by EPA for this study indicates that th e use of pond systems will continue to be significant in the future, with about half of pl ants discharging FGD wa stewater in 2020 using settling ponds.

4.4.2 Chemical Precipitation

In a chemical precipitation wastewater tr eatment system, chemicals are added to the wastewater to alter the physical state of dissolv ed and suspended solids to facilitate settling and removal of the solids. The specific chemical(s) us ed 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 (cal cium hydroxide) is ofte n added to elevate the pH of the wastewater and help precipitate me tals into insoluble meta l 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 th an 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 orga nic matter. The ferric chloride also acts as a coagulant, forming a dense floc that enhances se ttling of the metals precipitate in downstream clarification stages.

In a sulfide precipitation syst em, sulfide chemicals (e.g., trimercapto-s-triazine (TMT), Nalmet®, sodium sulfide) are us ed to precipitate and remove heavy metals, such as mercury. While hydroxide precipitation can remove some h eavy metals, sulfide precipitation can be more

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### 4-28 effective because metal sulfides have lower so lubilities than metal hydr oxides. FGD wastewater chemical precipitation systems may include various configurations of li me, 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 pr ecipitation 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 co ntinuous flow from the equalization tank to reaction tank 1, where the plant adds hydrated lime to raise th e 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 desatura tes 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 precipita tion step, or with a clarification step be tween 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 c oprecipitation. 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. Alte rnatively, 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 wastewat er holding tank and either discharged directly to surface waters or, in mo st 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 wastew ater because the chlorides are at levels that have the potential to corrode downstream equipment.Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization SystemsFigure 4-6. Process Flow Diagram for a Hydroxide and Sulfide Chemical Precipitation System4-29Final 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 sludg e is dewatered using a filter press. The dewatered sludge, or filter cake, is typically sent to an on-site landfil l for disposal. The filtrate from the filter press is transferred to a sump and recycled back to the equalization tank at the be ginning of the treatment

system.

4.4.3 Biological Treatment

Biological wastewater treatment systems us e microorganisms to consume biodegradable soluble organic contaminants and bind much of th e less soluble fractions into floc. 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 tr eat FGD wastewater: aero bic systems to remove

BOD 5 

### and anoxic/anaerobic systems to remove me tals and nutrients. These systems can use fixed film or suspended growth bioreactors, a nd operate as conventiona l flow-through or as sequencing batch reactors (SBRs). The wastewat er treatment processes for each of these biological treatment system s is discussed below.

Aerobic Biological Treatment

An aerobic biological treatment sy stem can effectively reduce BOD 5 

### from wastewaters. In a conventional flow-through design, the wastew ater 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 BOD 5 

### . The digestion of the organic matter produces sludge, which may be dewa tered with a vacuum filter to better manage its ultimate disposal. The treated wastewater from the system ove rflows out of the reactor.

An SBR is a type of activated sludge treatment system that can reduce BOD 5 

### and, when operated to create anoxic zones under certain conditions, can also reduce nitrogen compounds through nitrification and denitrif ication. 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 ope rates 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 reacti on batch. During the aeration and r eaction stage, the reactor is

aerated and the BOD 5 

### 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 th en decanted off the top of the SBR and either transferred to surface water for discharge or tr ansferred 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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### Anoxic/Anaerobic Biological Treatment

Some coal-fired power plants are moving towards using anoxic/a naerobic biological systems to achieve better reductions of certain pollutants (e.g., se lenium, 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 pon d or chemical precipitation system as a pretreatment step to reduce TSS entering the bioreact ors. Additionally, the microorga nisms 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 act ivated 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].

Figure 4-7. Process Flow Diagram for an Anoxi c/Anaerobic Biological Treatment System

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### The bioreactor is designed for plug flow, c ontaining different zone s 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 wastew ater moves down through the bioreactor, it enters an anoxic z one where denitrification occurs as well as chemical reduction of both selenate and selenite, which ar e 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 th e microorganisms. Because the microorganisms are

retained within the bioreactor by the activated carbon bed, the elem ental 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 mu ltiple 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 biorea ctors. Multiple bioreacto rs 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 fluidi zing the carbon bed by flowing water upward through the system, whic h dislodges the particle s fixed within the

activated carbon. The water and so lids overflow from the top of th e bioreactor and are removed from the system. This flush water must be trea ted prior to being discharged because of the elevated levels of solids and selenium [P ickett, 2006]. One plant currently operating an anoxic/anaerobic bioreactor system recycles the fl ush 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 segr egated 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 re lies on using suspended growth flow-through

bioreactors instead of fixed-film bioreactors. Bo th designs share the fundamental processes that

lead to denitrification and re duction of metals in anoxic a nd anaerobic environments. This suspended growth bioreactor system recently completed long-term pilot testing.

SBRs can also be operated to achieve the anoxic/anaerobic conditi ons 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 zone s 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 ope rate anoxic/anaerobic biological SBRs, with startup scheduled to oc cur by 2010. The SBR systems at these plants are expected to be operated in comb ination with chemical precipita tion 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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### 4-33 4.4.4 Constructed Wetlands

A constructed wetland treatment system is an engineered system that uses natural biological processes involving we tland vegetation, soils, and mi crobial activity to reduce the concentrations of metals, nutri ents, and TSS in wastewater. A constructed wetland typically

consists of several cells that contain bacteria and vegetation (e.g., bulru sh, 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 a queous phase of the wastewater, su ch as mercury and selenium, to their elemental state. The targeted metals pa rtition 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 we tlands 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 constructe d wetlands treatment syst em typically must be maintained below 4,000 mg/L. Most plants oper ate 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. EP A has observed that pow er 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 pl ants. 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 reporte dly 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 vaporcompression evaporation system.

Power plants most often use vapor-compre ssion evaporator systems to treat waste streams such as cooling tower blowdown and demi neralizer waste, but th ey 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 vaporcompression evaporator systems [Ra o, 2008; Veolia, 2007; ERG, 2009a].Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization SystemsFGDScrubberPurgeAcidDistillate forReuse/DischargeFeed/DistillateHeat ExchangerDistillateTankDeaeratorVent toAtmosphereBrine Concentrator/Vapor SeparatorMultistageCompressor/BlowerVent toAtmosphereFGD WasteBrineSolutionBrineRecycleConcentrated BrineSlurry to:- Crystallizer;- Spray Dryer; or- Fly Ash ConditioningDistillateLiquid Stream2-Phase StreamLegendGas StreamFigure 4-8. Process Flow Diagram for aVapor-Compression Evaporation System4-34Final 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 sc rubber purge to approximately 6.5. Following pH adjustment, the scrubber purge is sent through a h eat 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 vent ed 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 c oncentrator 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 co ncentrator (i.e., the outsi de of the tubes). The temperature difference between the compresse d 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 di stillate is used for other plant operations that ge nerate 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 liqui d discharge. Therefore, the op eration 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 concentrat or as a result of the gypsum present in the FGD scrubber purge, the brine conc entrator is seeded with calcium sulfate. The calcium salts preferentially precipitate onto the seed crysta ls instead of the tube surfaces of the brine concentrator [Shaw, 2008].

The concentrated brine slurry from the brine co ncentrator 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 t ypically transferred to a final drying process. The brine concentrator can typica lly 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) evapor ation 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 towe r blowdown). For these non-FGD systems, the concentrated brine withdrawn from the sump is typically sent to a forced-circulation cr ystallizer to evaporate the remaining water from the concentrate and gene rate a solid product for disposal. However, the calcium and magnesium salts present in the scrubber purge can pose difficulties for the forcedcirculation crystallizer. To prevent this, the F GD scrubber purge can be pretreated using a limesoftening process (i.e., chemical precipitation) upstream of the brine concentrator. With water softening, the magnesium and calcium ions precip itate out of the purge water and are replaced

4-35Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### with sodium ions, producing an aqueous solution of sodium chloride that can be more effectively

treated with a forced-circulati on crystallizer [Shaw, 2008].

Coal-fired power plants can avoid havi ng to operate the chemical precipitation pretreatment process by using a sp ray dryer to evaporate the residua l 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 c oncentrator 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 plan ts 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 in formation 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, underg round 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 treat ed 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 saleablesolid product from the FGD system (e.g., wallboard-grade gypsum). Because the FGD solid byproduct is not being sold and is most likely di sposed of in a landfill, there are no specific chloride specifications for the material. Theref ore, the plant can operate the FGD system and solids separation/dewatering process such that th e moisture retained with the landfilled solids entrains sufficient chlorides that a separate wast ewater 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 oxi dation FGD systems that do not discharge any FGD wastewaters di rectly 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 operat e 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.

4-36Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



## Case Study I: Coal-Fired Power Plant Water Reuse

Limestone Forced Ox idation FGD System

Dominion Resources’ Mount Storm Plant

The Facility

FGD type: Limestone forced oxidation spray tower

Scrubber chlorides conc.: 40,000 ppm Materials of construction chlorides limit: 120,000 ppm FGD WWT system: None: complete recycle Gypsum destination: Landfill, concre te 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 c ontains 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 botto m of the drum filter is dippe d 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 gyps um. The dry gypsum (20-25% moistu re content) is then scraped

off the drum as it rotates. Th e gypsum collected from the vacu um rotary drum filters is conveyed to the storage area until it is either sent to the on-site landfill, tr ansferred off site to a concrete manufacturer, or transferred off site fo r land application. The filtrate from the vacuum rotary drum filters is either re cycled 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 manufactur er; therefore, the gypsum dried on the vacuum rotary drum filters does not need to meet any pa rticular 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 Inhibi ted Oxidation FGD System Ohio Power Company’s Gene ral James M Gavin Plant

The Facility

FGD type: Magnesium-enhanced lime i nhibited oxidation spray/tray towers Scrubber chlorides conc.: 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 th e thickener contains the calcium sulfite solids and is transferred to centrifuges for final dewate ring. 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 w ith service water. The underflow is fed to a centrifuge to dewater the solids. Th e 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 pa rticular specifications; therefore, it is not washed to remove chlorides prior to dewateri ng. The dewatered calcium sulfite has a moisture content of 40 to 50 percent wa ter (before mixing with fly as h 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 chlo rides 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 th e 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 eva poration 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 fl y ash handling systems need to add water to the fly ash for dust suppression or to improve ha ndling and/or compaction characteristics. EPA has identified one plant that uses FGD wastew ater to condition its dry fly as h. 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 tech nique 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 di spose 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 ch aracteristics of the F GD wastewater, the plant has not been able to continuously inject th e wastewater. The plant operates a chemical precipitation system as pretreatment for the inject ion system. When the plant is not injecting the FGD wastewater, the efflue nt from the chemical precipitation sy stem 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 th e system. The plant need s to sustain continuous injection of the wastewater to avoid chlorides increasing to a level that would promote corrosion of equipment [ERG, 2009e]. A nother plant is also scheduled to begin injecting the FGD wastewater underground la ter 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 pu rge associated with the wet FGD process. As described in Section 4.2.3, the dry FGD proce ss involves atomizing and injecting wet lime slurry, which ranges from approxima tely 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 sy stem, the scrubber purge associated with the wet FGD system can be used as make-up water fo r 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 th e 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/anaerobi c biological treatment system. EPRI is also conducting lab- and pilot-scale studies for other technologies that may be capable of removing metals from FGD wastewater s. EPA obtained limited information regarding these other technologies, which include iron cement ation, reverse osmosis, absorption media, ion exchange, and electro-coagulat ion. Each of these technol ogies 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 wast ewater is raised to form metal hydroxides, and

the wastewater is filtered to re move 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 la boratory- and pilotscale feasibility studies of the technology to evaluate selenium and mercury removal performance [EPRI, 2008b].

4-40Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



## 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 ex iting 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 direct ed 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 discharg ed, the scrubber purge will be reused in the lime slurry feed to the dry FGD system.

Unit 5 is currently operating at th e plant, but its wet FGD system is not yet operating. Once the FGD system is operating, the Unit 5 flue gas wi ll be treated by a cold-side ESP followed by a

wet limestone forced oxidation system. When Unit 6 is not oper ating, the scrubber purge from Unit 5 will be transferred to a chemical precip itation 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 remai nder will be transferred to the wastewater treatment system. Units 5 and 6 operate indepe ndently from each other and, therefore, the wastewater treatment system will allow the plan t 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 us e at power plants, us ually to treat boiler make-up water or cooling tower blowdown wastewat ers. EPRI has identified a high-efficiency reverse osmosis (HEROTM) process which operates at a high pH, a llowing the system to treat high silica wastewaters without scal ing or membrane fouling because silica is more soluble at higher pHs. The wastewater und ergoes a water-softe ning process to rais e the pH of the wastewater prior to en tering the HEROTM system.

Although the HEROTM system has been demonstr ated for use with power plant cooling tower blowdown wastewater, its use for FGD wa stewater is potentially limited due to the osmotic pressure of the FGD wastewater resulting from the high concentrations of chloride and TDS [EPRI, 2007a].

Although many power plants may not be able to use the HEROTM system to treat FGD wastewater, some plants with lower TDS and chlo ride concentrations may be able to do so. The HEROTM system is of particular interest for treating boron from FGD wa stewaters because boron becomes ionized at an elevated pH and, theref ore, 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 ch emical reactions. The designs most commonly used in the drinking water industry use metal-based adsorbents , typically granular fe rric oxide, granular ferric hydroxide, or titan ium-based oxides. The sorption media is usually a single use application that can typically be disposed of in a nonhazardo us landfill after its use. In addition, the singleuse design prevents the plant from needing to further treat the residua ls. According to EPRI, these sorption media have been shown to rem ove 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 pret reat boiler make-up water. Ion exchange systems are designed to re move 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, lea d, mercury, nickel, uranium, vanadium, and zinc. Although the ion exchange pro cess 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 te sting two ion exchange re sins for treatment of FGD wastewater. The plant and th e ion exchange resins tested in the pilot study are focused specifically on the removal of mercury. [EPRI, 2007a].

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### 4-43 Electro-Coagulation

Electro-coagulation uses an electrode to intr oduce an electric charge to the wastewater, which neutralizes the electrically charged collo idal 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 othe r 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 addi tion, EPRI is investig ating various physical treatment technologies, primarily for mercury re moval, including filtration [EPRI, 2008a].

4.4.8 Wastewater Treatment System Use in th e Coal-Fired Steam Electric Industry

Table 4-7 , presents information on the FGD wast ewater treatment systems currently operating (as of June 2008) at plants in cluded in EPA’s combined data set. Table 4-7 also

includes information on FGD wastewater treatm ent 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 we t FGD scrubber systems as of June 2008, representing 175 of the

223 wet-scrubbed coal-fired electr ic 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 th e scrubber (28 plants), using evaporation ponds (3 plants), mixing the FGD wastew ater with dry fly ash (1 plant), or deep well injecting the FGD wastewater (1 plant 19 

### ). Figure 4-9 shows the distributi on of FGD wastewater management/treatment within the group of 84 plants.

18 There is a plant that operates several wet FGD syst ems and for some of the wet FGD systems there is a wastewater discharge; however, the other wet FGD systems operate without discharging. In , 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. Table 4-7

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 continuous ly inject the wastewater.Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization Systems4-44Table 4-7. FGD Wastewater Treatment SystemsIdentified During EPA’s Detailed StudyWet FGD Systems in the Combined Data SetOperating as of June 2008aWet FGD Systems in the Combined Data SetProjected to be Operating in 2020bNumber of Plantswith FGDWastewaterTreatmentSystemsNumber of ElectricGenerating UnitsServiced by FGDWastewaterTreatment SystemsWetScrubbedCapacityc(MW)Number of PlantsWith or Expectedto Operate FGDWastewaterTreatment SystemsProjected Numberof ElectricGenerating UnitsServiced by theTreatmentSystemsProjectedWetScrubbedCapacityc(MW)Settling Ponds296327,700359544,000Combined FGD and Ash Ponds (FGDsolids removal prior)d, e174114,400184816,600Combined FGD and Ash Ponds (No FGDsolids removal prior)d, f241,440241,440FGD Ponds (FGD solids removal prior)e, g484,45071812,500FGD Ponds (No FGD solids removal prior)f, g6107,35082513,400Chemical Precipitation (“Chem Precip”)152714,200245228,300Chem Precip (type unknown)———5115,800Hydroxide Chem Precip101810,500112514,800Hydroxide and Sulfide Chem Precip242,3505116,460Combination Settling Pond and ChemPrecip2389623896Chem Precip and Constructed Wetland1241412414Tank-Based Biological132,150263,294Combination Settling Pond andAnoxic/Anaerobic Biological (designed formetals & nitrogen removal)132,150263,294Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization Systems4-45Table 4-7. FGD Wastewater Treatment SystemsIdentified During EPA’s Detailed StudyWet FGD Systems in the Combined Data SetOperating as of June 2008aWet FGD Systems in the Combined Data SetProjected to be Operating in 2020bNumber of Plantswith FGDWastewaterTreatmentSystemsNumber of ElectricGenerating UnitsServiced by FGDWastewaterTreatment SystemsWetScrubbedCapacityc(MW)Number of PlantsWith or Expectedto Operate FGDWastewaterTreatment SystemsProjected Numberof ElectricGenerating UnitsServiced by theTreatmentSystemsProjectedWetScrubbedCapacityc(MW)Combination Chem Precip and Tank-BasedBiological354,72082312,500Chem Precip and Aerobic Biological(designed for metals and BOD5removal)232,560121,870Chem Precip and Aerobic/AnaerobicBiological (designed for removing nitrogenand selected metals)———4115,260Chem Precip and Anoxic/AnaerobicBiological (designed for metals & nitrogenremoval)———3105,330Chem Precip, Anoxic/Anaerobic Biological(designed for metals & nitrogen removal),and CWTS122,160———Zero Discharge336538,700357543,000Zero Discharge: Recycle All FGD Water285633,800275834,700Zero Discharge: Evaporation Pond341,800341,800Zero Discharge: Conditioning Dry Fly Ash121,140121,140Zero Discharge: Deep Well Injection132,000273,140Zero Discharge: Evaporator &Conditioning Dry Fly Ash———121,580Zero Discharge: Recycled to Dry FGD———12571Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization Systems4-46Table 4-7. FGD Wastewater Treatment SystemsIdentified During EPA’s Detailed StudyWet FGD Systems in the Combined Data SetOperating as of June 2008aWet FGD Systems in the Combined Data SetProjected to be Operating in 2020bNumber of Plantswith FGDWastewaterTreatmentSystemsNumber of ElectricGenerating UnitsServiced by FGDWastewaterTreatment SystemsWetScrubbedCapacityc(MW)Number of PlantsWith or Expectedto Operate FGDWastewaterTreatment SystemsProjected Numberof ElectricGenerating UnitsServiced by theTreatmentSystemsProjectedWetScrubbedCapacityc(MW)Other Handling5125,0105125,010Clarifier1352113521Clarifier and Constructed Wetland142,000142,000Commingled with other Wastewater352,490352,490No Information244815,6008516465,900Subtotal: Wastewater treatment systems forwhich EPA has information availableh8417592,500107237123,000Subtotal: Systems treating FGD wastewaterdischarged to surface watersh5311053,8007416279,900Totalh108223108,000192401189,000a – Source: Combined data set (UWAG-provided data [ERG, 2008g], data request information [U.S. EPA, 2008a], and site visit andsampling information).Includes treatment systems servicing electric generating units identified in the “combined data set” with wet FGD systems operating as of June 2008. ExcludesOSWER 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 andsampling 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 equalthe sum of the individualcapacities. The capacities presented represent thereported 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 flyash transport water). Some plantstransfer 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 donot handle ash wastewaters. The FGD pond may handleother wastewaters along with theFGD scrubber purge, such as low-volume wastes, but the pond cannot receive ash wastewaters tobe considered an FGD pond.h – There are two plants with multiple types of wastewater treatment systems; therefore, there isoverlap in these totals.Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### 4-47 Settling Ponds

34%

Chemical Precipitation

20% A noxic/Anaerobic
Biological

2% Other Handling

6% Zero Discharge

38%



### Figure 4-9. Distribution of FG D Wastewater Treatment Systems Among Plants Operating Wet FGD Systems

Figure 4-10 compares the distribution of FGD wast ewater treatment systems within the group of plants that operate limestone forced oxidation FGD systems, to the group of plants operating inhibited/natural oxida tion FGD systems. EPA has info rmation 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 units 20 

### . A larger percentage of the plants operating forced oxidation FGD systems discharge th e FGD wastewater, relative to plants that operate inhibited and natural oxidation FGD systems. This is largel y 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 chlo rides 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 th is 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.Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### 4-48 (13)

(4) (2) (17) (15)

(0) (1) (2) (12) (22)

0 10 20 30 40 50 60 70

Settling Ponds Chemical
Precipitation Anoxic/

Anaerobic
Biological Other Handling Zero Discharge

FGD Wastewater Treatment TechnologyPercent of Use by Oxidation Type Forced Oxidation Inhibited/Natural Oxidation

(Number of plants shown in parantheses)



### 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 wastewat er, 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 wast ewater 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 precipitati on system, and three use both hydroxide and sulfide precipitation in the treatm ent system. Additionally, two of the 15 hydroxide plants currently have equipmen t installed to also perform a sulfide precipitation step, but are no longe r adding sulfide to the system.

• 

### Two of the 18 plants with chemical pr ecipitation systems also operate aerobic biological reactors following the precipitation system. Both of these plants use

21 For comparison, note that the OSWER data on surface im poundments 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].Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### 4-49 organic acid additives in their FGD sc rubbers to improve the SO2 removal efficiency, increasing the BOD5 con centration in the scrubber purge.

• 

### Two plants operate fixed-film anoxic/anae robic bioreactors. One of these plants also operates a chemical precipitation sy stem (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 plan t uses a constructed wetlands treatment system as the primary treatment mechanism. Two other plants also operate constructed wetland systems; however, th e 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).

Settling Ponds

55% Chemical Precipitation

32% A noxic/Anaerobic
Biological

4% Other Handling

9%



### Figure 4-11. Distribution of FGD Wastewat er 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 wastewat er 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 indi cate that widespread us e 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 wastewater 22 

### . 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 cons idered to under-estimate the actual number of FGD systems that will be installed.Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### wastewater treatment systems either currently ope rating or expected to be operating at these 74 plants:

• 

### Thirty-five plants are expected to trea t 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 clarifie r and one plant is expected to use a constructed wetlands treatment system as the primary treatment mechanism; and

• 

### Three plants are expected to commingl e 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 evalua ted several treatmen t technologies or combinations of treatment technologies that plan ts 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 tr eatment of FGD wastew ater, 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 trea tment for removing additional metals and to reduce nitrogen compounds; and

• 

### Chemical Precipitation/Softening + Evaporation + Crystallization. Chemical precipitation or softening followed by eva poration in a brine concentrator and crystallization for potential eliminati on of the FGD wastewater stream.

EPA used information collected throughout the detailed study in evaluating these technologies, including operat ional 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 plan ts were used to evaluate the performance of the chemical precipitation and biological treatmen t technologies. These data show that chemical precipitation is an effective means for rem oving many metals from the FGD wastewater. Biological treatment, specifically fixed-film anoxi c/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., nitrat es, nitrites). If operate d with a nitrification step, the technology would also be expected to re move ammonia that may be present in the waste stream. Coal-fired power plants have only rece ntly begun to use evaporation/crystallization systems to treat FGD scrubber purge, so EPA wa s 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 tr eatment systems at Duke Energy Carolinas’ Belews Creek Steam Station and Progress Ener gy 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:

4-50Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### 4-51 • 

### FGD scrubber purge;

• 

### Intermediate point preceding the biologi cal treatment stage (i.e., settling pond effluent for Roxboro and chemical precip itation effluent for Belews Creek); and

• 

### Effluent from the anoxic/anaer obic biological treatment system.

The Belews Creek FGD wastewat er 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-precipi tation, and a clarifier and sand filter for solids removal. After the sand filter, the wastewater is transferred to a fixe d-film, anoxic/anaerobic biological treatment system designed to remove metals and nitrogen compounds. Belews Creek operates two stages of the biol ogical reactors in series. Af ter the biological system, the

wastewater is transferred to a constructed wetl and 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 biologi cal treatment system designed to remove metals and nitrogen compounds. The settling pond was designed specifi cally for FGD wastewater, to reduce the wastewater temperature and TSS prior to the bi oreactor. The bioreactor operates with four parallel trains that each has two biological cells in series. Wast ewater flows from the bioreactor to the ash pond discharge can al and is discharged.

The Belews Creek and Roxboro graphs show th at the chemical precipitation system, the settling pond, and the biological tr eatment 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 poll utant concentrations appr oximately an order of magnitude lower than was observed for th e 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 seleni um present in the wastewater, usually is not effectively nor consistently removed by settling ponds or chemical preci pitation. The bioreactor

effluent selenium concentrations at Belews Creek are substantially lower than those observed for

Roxboro’s bioreactor effl uent, presumably due to the chemical precipitation stage providing more effective pretreatment than achieved by th e settling pond. Finally, th e figures show that TDS is not significantly removed by the settling pond, the chemical precipitation system, or the biological treatment system.Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization SystemsBelews Creek Monitoring Data (2008)Roxboro Monitoring Data (2008)4-5205001,0001,5002,0002,5001-Jun 21-Jun 11-Jul 31-Jul 20-Aug 9-Sep 29-Sep 19-Oct

As (ug/L)PurgeChem PrecipBio01,0002,0003,0004,0005,0006,00022-Feb 12-Apr 1-Jun 21-Jul 9-Sep 29-Oct 18-Dec 6-Feb

As (ug/L)PurgeSettling PondBioFigure 4-12A. Concentration of Arsenic in FGD Scrubber Purgeand Effluent from ChemicalPrecipitation and BiologicalTreatment Systems at Belews CreekFigure 4-13A. Concentration of Arsenic in FGD Scrubber Purgeand Effluent from SettlingPond and Biological TreatmentSystems at Roxboro02468101214161-Jun 21-Jun 11-Jul 31-Jul 20-Aug 9-Sep 29-Sep 19-Oct

As (ug/L)Chem PrecipBio05010015020025022-Feb 12-Apr 1-Jun 21-Jul 9-Sep 29-Oct 18-Dec 6-Feb

As (ug/L)Settling PondBioFigure 4-12B. Concentration of Arsenic in Effluent fromChemical Precipitation and Biological Treatment Systems atBelews CreekFigure 4-13B. Concentration of Arsenic in Effluent from SettlingPond and Biological Treatment Systems at RoxboroFinal Detailed Study ReportChapter 4 – Flue Gas Desulfurization SystemsBelews Creek Monitoring Data (2008)Roxboro Monitoring Data (2008)4-530501001502002503003504001-Jun 21-Jun 11-Jul 31-Jul 20-Aug 9-Sep 29-Sep 19-Oct

Hg (ug/L)PurgeChem PrecipBio01002003004005006007008009001,00022-Feb 12-Apr 1-Jun 21-Jul 9-Sep 29-Oct 18-Dec 6-Feb

Hg (ug/L)PurgeSettling PondBioFigure 4-12C. Concentration of Mercury in FGD ScrubberPurge and Effluent from Chemical Precipitation and BiologicalTreatment Systems at Belews CreekFigure 4-13C. Concentration of Mercury in FGD ScrubberPurge and Effluent from Settling Pond and BiologicalTreatment Systems at Roxboro0.000.100.200.300.400.500.601-Jun 21-Jun 11-Jul 31-Jul 20-Aug 9-Sep 29-Sep 19-Oct

Hg (ug/L)Chem PrecipBio012345678
Hg (ug/L)22-Feb 12-Apr 1-Jun 21-Jul 9-Sep 29-Oct 18-Dec 6-FebSettling PondBioFigure 4-12D. Concentration of Mercury in Effluent fromChemical Precipitation and Biological Treatment Systems atBelews CreekFigure 4-13D. Concentration of Mercury in Effluent fromSettling Pond and Biological Treatment Systems at RoxboroFinal Detailed Study ReportChapter 4 – Flue Gas Desulfurization SystemsBelews Creek Monitoring Data (2008)Roxboro Monitoring Data (2008)4-5402,0004,0006,0008,00010,00012,00014,00016,0001-Jun 21-Jun 11-Jul 31-Jul 20-Aug 9-Sep 29-Sep 19-Oct

Se (ug/L)PurgeChem PrecipBio05,00010,00015,00020,00025,00022-Feb 12-Apr 1-Jun 21-Jul 9-Sep 29-Oct 18-Dec 6-Feb

Se (ug/LPurgeSettling PondBio

)Figure 4-12E. Concentration of Selenium in FGD ScrubberPurge and Effluent from Chemical Precipitation and BiologicalTreatment Systems at Belews CreekFigure 4-13E. Concentration of Selenium in FGD ScrubberPurge and Effluent from Settling Pond and BiologicalTreatment Systems at Roxboro0501001502002503003501-Jun 21-Jun 11-Jul 31-Jul 20-Aug 9-Sep 29-Sep 19-Oct

Se (ug/L)Chem PrecipBio05001,0001,5002,0002,5003,000

Se (ug/L22-Feb 12-Apr 1-Jun 21-Jul 9-Sep 29-Oct 18-Dec 6-Feb

)Settling PondBioFigure 4-12F. Concentration of Selenium in Effluent fromChemical Precipitation and Biological Treatment Systems atBelews CreekFigure 4-13F. Concentration of Selenium in Effluent fromSettling Pond and Biological Treatment Systems at Roxboro02,000,0004,000,0006,000,0008,000,00010,000,00012,000,00014,000,00016,000,00018,000,00022-Feb 12-Apr 1-Jun 21-Jul 9-Sep 29-Oct 18-Dec 6-Feb

TDS (ug/L)Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization Systems4-55Belews Creek Monitoring Data (2008)Roxboro Monitoring Data (2008)05,000,00010,000,00015,000,00020,000,00025,000,00030,000,0001-Jun 21-Jun 11-Jul 31-Jul 20-Aug 9-Sep 29-Sep 19-Oct

TDS (ug/L)PurgeChem PrecipBioFigure 4-12G. Concentration of TDS in FGD Scrubber Purgeand Effluent from ChemicalPrecipitation and BiologicalTreatment Systems at Belews CreekFigure 4-13G. Concentration of TDS in FGD Scrubber Purgeand Effluent from SettlingPond and Biological TreatmentSystems at RoxboroBioSettling PondPurgeFinal Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### Table 4-8 presents the pollutant concentrations a ssociated 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 polluta nt concentrations representi ng 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 sy stem is a pond system that consisted of three settling ponds at the time of sampling; howev er, 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 th e wastewater to the first FGD settling pond. The overflow from the first FGD settling pond is transf erred 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-preci pitation. The plan t then adds a flocculating polymer to the wastewater and transfer s 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 sa mple of the effluent downstream of the final holding 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 fo r coagulation and iron co-precip itation, and a clarifier for solids

removal. The FGD wastewater is sent thr ough a first stage of lim e and ferric chloride precipitation followed by a clarifier, and the wastew ater is then treated in a second stage of lime and ferric chloride precip itation followed by a clarifie r. After the second clar ifier, the wastewater is transferred to an aerobic biological treatme nt system designed to remove BOD. After the aerobic biological system, the wast ewater is filtered, transferre d to a final holding tank, and discharged. EPA collected a grab sample of the effluent directly from the final holding tank. [ERG, 2008l].

The Mitchell FGD wastewater treatment syst em 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 clarifie r is transferred to an equalization tank, where treated effluent is recycled by the plant wh en the system is not discharging. After the equalization tank, the plant uses ferric chloride fo r iron co-precipitation and then adds an anionic polymer and transfers the wastewater to a se cond clarifier. The overflow from the second

clarifier is transferred to a final holding tank and either tran sferred to the bottom ash pond and eventually discharged or recycled back to the equalization tank. EPA collect ed a grab sample of the effluent from the discharge line of the final holding tank. [ERG, 2008m].

4-56Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization SystemsTable 4-8. Pollutant Concentrations in SampledEffluent from FGD Wastewater Treatment SystemsSettling PondChemical PrecipitationAnoxic/AnaerobicBiologicalAnalyteMethodUnitWidows Creek –Effluent from FGDPond Systema, bBig Benda, bHomera, bMitchella, bBelews Creekb, cBelews Creekb, dRoutine Total Metals – 200.7Aluminum200.7μg/L111ND (50.0)ND (50.0)ND (50.0)ND (50.0)ND (50.0)Antimony200.7μg/LND (20.0)22.1R<20.8ND (20.0)ND (4.00)ND (4.00)Arsenic200.7μg/L49.5ND (10.0)ND (10.0)<10.3ND (2.00)ND (2.00)Barium200.7μg/L1791,49071.3R433326296RBeryllium200.7μg/LND (5.00)ND (5.00)7.68ND (5.00)ND (1.00)ND (1.00)Boron200.7μg/L31,500369,000191,000208,000291,000283,000RCadmium200.7μg/LND (5.00)24.9ND (5.00)ND (5.00)ND (0.250)ND (0.250)Calcium200.7μg/L987,0004,420,0002,000,0002,380,0005,670,0005,570,000Chromium200.7μg/LND (10.0)ND (10.0)ND (10.0)ND (10.0)25.324.2RCobalt200.7μg/LND (50.0)ND (50.0)ND (50.0)ND (50.0)ND (2.50)ND (2.50)Copper200.7μg/LND (10.0)<10.312.516.2ND (2.50)ND (2.50)Iron200.7μg/LND (100)ND (100)<117318ND (25.0)ND (25.0)Lead200.7μg/LND (50.0)ND (50.0)ND (50.0)ND (50.0)ND (1.50)ND (1.50)Magnesium200.7μg/L189,0002,510,0002,610,0001,280,000983,000950,000Manganese200.7μg/L62360.130,1004,4403,2802,340RMercury245.1μg/LND (2.00)ND (10.0)ND (10.0)ND (10.0)NANAMolybdenum200.7μg/L1,500450R37.622.9NANANickel200.7μg/LND (50.0)221ND (50.0)ND (50.0)21.1ND (1.00)Selenium200.7μg/L2362,910R77183.6R82.5ND (5.00)Silver200.7μg/LND (20.0)ND (20.0)ND (20.0)ND (20.0)7.907.75Sodium200.7μg/L69,5001,590,0001,280,000305,00060,30058,900Thallium200.7μg/LND (10.0)16.8ND (10.0)ND (10.0)62.552.7RTitanium200.7μg/LND (10.0)13.5ND (10.0)<10.1NANAVanadium200.7μg/L42.1ND (20.0)ND (20.0)ND (20.0)2.10ND (0.500)Yttrium200.7μg/LND (5.00)ND (5.00)ND (5.00)ND (5.00)NANAZinc200.7μg/LND (10.0)ND (10.0)ND (10.0)25.4ND (25.0)ND (25.0)4-57Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization SystemsTable 4-8. Pollutant Concentrations in SampledEffluent from FGD Wastewater Treatment SystemsSettling PondChemical PrecipitationAnoxic/AnaerobicBiologicalAnalyteMethodUnitWidows Creek –Effluent from FGDPond Systema, bBig Benda, bHomera, bMitchella, bBelews Creekb, cBelews Creekb, dRoutine Dissolved Metals – 200.7Aluminum200.7μg/LND (50.0)ND (50.0)ND (50.0)ND (50.0)97.0L<78.5LAntimony200.7μg/LND (20.0)20.8TND (20.0)ND (20.0)4.50ND (4.00)Arsenic200.7μg/L46.710.8R,TND (10.0)ND (10.0)6.40L8.70L,RBarium200.7μg/L1911,41070.6R,T389270271RBeryllium200.7μg/LND (5.00)ND (5.00)7.71ND (5.00)ND (1.00)ND (1.00)Boron200.7μg/L29,200397,000184,000199,000306,000284,000RCadmium200.7μg/LND (5.00)19.3ND (5.00)ND (5.00)2.30<0.875Calcium200.7μg/L932,0005,210,0001,930,0002,270,0005,790,0005,760,000Chromium200.7μg/LND (10.0)ND (10.0)ND (10.0)ND (10.0)ND (0.500)<10.7RHexavalent ChromiumD1687-92μg/LND (2.00)ND (2.00)ND (2.00)11.01.57ND (0.500)Cobalt200.7μg/LND (50.0)ND (50.0)ND (50.0)ND (50.0)ND (2.50)ND (2.50)Copper200.7μg/LND (10.0)ND (10.0)11.814.1ND (2.50)ND (2.50)Iron200.7μg/LND (100)ND (100)166RND (100)ND (25.0)<27.9Lead200.7μg/LND (50.0)ND (50.0)ND (50.0)ND (50.0)ND (1.50)ND (1.50)Magnesium200.7μg/L184,0002,930,0002,510,0001,220,000970,000938,000Manganese200.7μg/L543R55.629,1004,1203,2402,310Mercury245.1μg/LND (2.00)ND (10.0)ND (10.0)ND (10.0)NANAMolybdenum200.7μg/L1,470430T35.821.4NANANickel200.7μg/LND (50.0)210ND (50.0)ND (50.0)28.2<2.15Selenium200.7μg/L2262,860R741R71.758.7ND (5.00)Silver200.7μg/LND (20.0)ND (20.0)ND (20.0)ND (20.0)7.708.10Sodium200.7μg/L66,2001,880,0001,230,000300,00059,30058,500Thallium200.7μg/LND (10.0)12.5ND (10.0)ND (10.0)105120RTitanium200.7μg/LND (10.0)13.7ND (10.0)ND (10.0)NANAVanadium200.7μg/L40.0ND (20.0)ND (20.0)ND (20.0)2.500.665RYttrium200.7μg/LND (5.00)ND (5.00)ND (5.00)ND (5.00)NANAZinc200.7μg/LND (10.0)ND (10.0)ND (10.0)ND (10.0)ND (25.0)ND (25.0)4-58Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization SystemsTable 4-8. Pollutant Concentrations in SampledEffluent from FGD Wastewater Treatment SystemsSettling PondChemical PrecipitationAnoxic/AnaerobicBiologicalAnalyteMethodUnitWidows Creek –Effluent from FGDPond Systema, bBig Benda, bHomera, bMitchella, bBelews Creekb, cBelews Creekb, dRoutine Total Metals – 200.8Aluminum200.8μg/LNANANANA61.667.2RAntimony200.8μg/LNANANANA3.600.465Arsenic200.8μg/LNANANANA200194Arsenic200.8 – DRCμg/LNANANANA6.945.47Barium200.8μg/LNANANANA465466RBeryllium200.8μg/LNANANANAND (0.300)ND (0.300)Boron200.8μg/LNANANANA260,000250,000RCadmium200.8μg/LNANANANA1.770.360RCalcium200.8μg/LNANANANA4,920,0005,030,000Chromium200.8μg/LNANANANA13.79.25Chromium200.8 – DRCμg/LNANANANA0.855ND (0.500)Cobalt200.8μg/LNANANANA17.412.1Copper200.8μg/LNANANANA2.131.08Iron200.8μg/LNANANANA173165Iron200.8 – DRCμg/LNANANANAND (50.0)66.9Lead200.8μg/LNANANANAND (0.200)ND (0.200)Magnesium200.8μg/LNANANANA973,000998,000Manganese200.8μg/LNANANANA3,1102,240Manganese200.8 – DRCμg/LNANANANA3,3302,350RNickel200.8μg/LNANANANA159102Nickel200.8 – DRCμg/LNANANANA72.911.5RSelenium200.8μg/LNANANANA1,120803Selenium200.8 – DRCμg/LNANANANA313159RSodium200.8μg/LNANANANA48,20050,000RThallium200.8μg/LNANANANA7.03ND (0.0250)Vanadium200.8μg/LNANANANA113154Vanadium200.8 – DRCμg/LNANANANA3.67<1.934-59Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization SystemsTable 4-8. Pollutant Concentrations in SampledEffluent from FGD Wastewater Treatment SystemsSettling PondChemical PrecipitationAnoxic/AnaerobicBiologicalAnalyteMethodUnitWidows Creek –Effluent from FGDPond Systema, bBig Benda, bHomera, bMitchella, bBelews Creekb, cBelews Creekb, dZinc200.8μg/LNANANANA5.875.89Zinc200.8 – DRCμg/LNANANANAND (2.00)ND (2.00)Routine Dissolved Metals – 200.8Aluminum200.8μg/LNANANANA51.858.7Antimony200.8μg/LNANANANA3.690.430Arsenic200.8μg/LNANANANA194205Arsenic200.8 – DRCμg/LNANANANA8.154.15Barium200.8μg/LNANANANA457459Beryllium200.8μg/LNANANANAND (0.300)ND (0.300)Boron200.8μg/LNANANANA261,000238,000RCadmium200.8μg/LNANANANA1.660.250RCalcium200.8μg/LNANANANA5,050,0004,730,000Chromium200.8μg/LNANANANA13.46.93Chromium200.8 – DRCμg/LNANANANA0.775ND (0.500)Cobalt200.8μg/LNANANANA17.912.2Copper200.8μg/LNANANANA2.20ND (1.00)Iron200.8μg/LNANANANA151138Iron200.8 – DRCμg/LNANANANAND (50.0)59.7Lead200.8μg/LNANANANAND (0.200)ND (0.200)Magnesium200.8μg/LNANANANA1,010,000960,000Manganese200.8μg/LNANANANA3,0802,250Manganese200.8 – DRCμg/LNANANANA3,1402,300RNickel200.8μg/LNANANANA158104Nickel200.8 – DRCμg/LNANANANA74.210.9Selenium200.8μg/LNANANANA1,110711Selenium200.8 – DRCμg/LNANANANA281151Sodium200.8μg/LNANANANA48,70047,100RThallium200.8μg/LNANANANA7.04ND (0.0250)4-60Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization SystemsTable 4-8. Pollutant Concentrations in SampledEffluent from FGD Wastewater Treatment SystemsSettling PondChemical PrecipitationAnoxic/AnaerobicBiologicalAnalyteMethodUnitWidows Creek –Effluent from FGDPond Systema, bBig Benda, bHomera, bMitchella, bBelews Creekb, cBelews Creekb, dVanadium200.8μg/LNANANANA131148Vanadium200.8 – DRCμg/LNANANANA4.66ND (1.00)Zinc200.8μg/LNANANANA6.235.81Zinc200.8 – DRCμg/LNANANANAND (2.00)ND (2.00)Low-Level Total Metals - 1631E, 1638, HG-AFSAntimony1638μg/L11.814.2ND (0.400)<1.373.750.545Arsenic1638μg/L47.668.023.0<25.2197202Arsenic1638 – DRCμg/LNANANANA4.862.51ArsenicHG-AFSμg/LNANANANA2.270.247Cadmium1638μg/L3.7325.8ND (2.00)ND (3.00)1.510.230Chromium1638μg/LND (16.0)ND (80.0)ND (16.0)ND (120)6.065.37Chromium1638 – DRCμg/LNANANANA0.610ND (0.500)Copper1638μg/LND (4.00)ND (20.0)9.67ND (30.0)2.13ND (1.00)Lead1638μg/LND (1.00)ND (5.00)ND (1.00)ND (1.50)ND (0.200)ND (0.200)Mercury1631Eμg/L0.04380.1560.1170.7880.07650.0133Nickel1638μg/L36.238192.1<15511397.1Nickel1638 – DRCμg/LNANANANA54.39.00Selenium1638μg/L2082,500613431T616581Selenium1638 – DRCμg/LNANANANA300191SeleniumHG-AFSμg/LNANANANA1394.93Thallium1638μg/L11.131.116.03.968.43ND (0.0250)Zinc1638μg/LND (10.0)ND (50.0)15.2<83.56.244.87Zinc1638 – DRCμg/LNANANANAND (2.00)ND (2.00)Low-Level Dissolved Metals - 1631E, 1636, 1638, HG-AFSAntimony1638μg/L11.913.7ND (0.400)1.643.730.545Arsenic1638μg/L46.572.422.520.9T196199Arsenic1638 – DRCμg/LNANANANA5.792.63ArsenicHG-AFSμg/LNANANANA2.120.2274-61Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization SystemsTable 4-8. Pollutant Concentrations in SampledEffluent from FGD Wastewater Treatment SystemsSettling PondChemical PrecipitationAnoxic/AnaerobicBiologicalAnalyteMethodUnitWidows Creek –Effluent from FGDPond Systema, bBig Benda, bHomera, bMitchella, bBelews Creekb, cBelews Creekb, dCadmium1638μg/L3.7422.2ND (2.00)ND (1.00)1.530.210Chromium1638μg/LND (16.0)ND (80.0)ND (16.0)ND (80.0)6.235.16Chromium1638 – DRCμg/LNANANANA0.700ND (0.500)Hexavalent Chromium1636μg/L3.20ND (5.00)ND (2.50)ND (2.50)ND (0.500)ND (0.500)Copper1638μg/LND (4.00)ND (20.0)9.39ND (20.0)1.57ND (1.00)Lead1638μg/LND (1.00)ND (5.00)ND (1.00)ND (0.500)ND (0.200)ND (0.200)Mercury1631Eμg/L0.01070.06880.05420.1590.00804<0.00168Nickel1638μg/L33.3L39693.510284.496.2Nickel1638 – DRCμg/LNANANANA43.810.1Selenium1638μg/L2932,560620407651564Selenium1638 – DRCμg/LNANANANA305194SeleniumHG-AFSμg/LNANANANA1372.67Thallium1638μg/L11.031.515.83.998.55ND (0.0250)Zinc1638μg/LND (10.0)ND (50.0)15.7ND (50.0)4.404.93Zinc1638 – DRCμg/LNANANANAND (2.00)ND (2.00)ClassicalsAmmonia As Nitrogen (NH3-N)4500-NH3Fmg/L0.22024.10.2953.491.802.73Nitrate/Nitrite (NO3-N + NO2-N)353.2mg/L0.0945NA36.5R25.414.0ND (0.100)Total Kjeldahl Nitrogen (TKN)4500-N,Cmg/L2.5198.73.049.744.055.77Biochemical Oxygen Demand (BOD)5210Bmg/L<10.0>1,720ND (120)<7.50ND (4.00)9Chemical Oxygen Demand (COD)mg/LNANANANA501451Chloride4500-CL-Cmg/L1,12022,50011,8006,7009,7209,960Hexane Extractable Material (HEM)1664Amg/LND (5.00)6.00ND (5.00)5.00ND (5.00)ND (5.00)Silica Gel Treated HEM (SGT-HEM)1664Amg/LNAND (6.00)NAND (4.00)ND (5.00)ND (5.00)SulfateD516-90mg/L2,0601,9202,7901,7701,2101,2404-62Final Detailed Study ReportChapter 4 – Flue Gas Desulfurization Systems4-63Table 4-8. Pollutant Concentrations in SampledEffluent from FGD Wastewater Treatment SystemsSettling PondChemical PrecipitationAnoxic/AnaerobicBiologicalAnalyteMethodUnitWidows Creek –Effluent from FGDPond Systema, bBig Benda, bHomera, bMitchella, bBelews Creekb, cBelews Creekb, dTotal Dissolved Solids (TDS)2540 Cmg/L5,83040,60022,60017,70034,00033,800Total Phosphorus365.3mg/L0.0115E0.3550.5200.0745ND (0.100)ND (0.100)Total Suspended Solids (TSS)2540 Dmg/L8.00E31.5<5.5017.530.021.3Source: [ERG, 2008l; ERG, 2008m; ERG, 2008n; ERG, 2008o; ERG, 2009q].Note: EPA used several analytical methodsto analyze for metals during the sampling program. For the purposes of sampling program, EPA designated some of the analytical methods as “routine” andsome of them as “low-level.” EPA designated all of the methods that require the useof 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 theaverage 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 andFGD chemical precipitation effluentday 2 measurements, if the analytewas collected on both days of sample collection.d – The FGD effluent results represent theaverage of the FGD effluent day 1, the FGD effluent day 2, and the duplicate of theFGD effluent analytical measurements, if all three measurements werecollected for the analyte. Otherwise, it represents the average of the FGD effluentday 1 and the duplicate of the FGD effluentanalytical 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 10x 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 foranalytes measured above the detection limit,but below the reporting limit (i.e., J-values).Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### 4-64 The Belews Creek FGD wastewat er treatment system consists of an equalization tank, chemical precipitation system, clarifier, anox ic/anaerobic biological treatment system, and

constructed wetland 23 

### . 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 effl uent 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 repo rted concentration data for the analyte at the given effl uent 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 th e same list of analytes [ERG, 2009x].

Table 4-9. Monitoring Data: Pollutant Concen trations in Effluent from Settling Ponds

Analyte Number of

Plants Number of Samples Minimum

Concentration Maximum

Concentration a Units

Total Metals

Aluminum 1 37 ND (50) 632 μ g/L

Antimony 1 37 ND (2) 36 μ g/L

Arsenic 1 37 6.4 201 μ g/L

Barium 1 37 37.5 528 μ g/L

Beryllium 1 37 ND (0.7) 1.02 μ g/L

Boron 1 37 7,950 108,000 μ g/L

Cadmium 1 37 ND (0.5) 6.11 μ g/L

Chromium 1 37 ND (0.61) 2,110 μ g/L

Cobalt 1 37 ND (1.1) 36 μ g/L

Copper 1 37 ND (1.6) 44.4 μ g/L

Iron 1 37 ND (20) 13,000 μ g/L

Lead 1 37 ND (1.9) ND (220) μ g/L

Manganese 1 37 ND (11) 3,210 μ g/L

Mercury 1 36 ND (0.11) 7.32 μ g/L

Molybdenum 1 37 ND (0.11) 47 μ g/L

Nickel 1 37 11.5 2,190 μ g/L

Selenium 1 37 1,180 2,740 μ g/L

Silver 1 37 ND (0.2) 30 μ g/L

Thallium 1 37 ND (0.2) 102 μ g/L

Vanadium 1 37 ND (0.36) 285 μ g/L

Zinc 1 37 ND (3.8) 136 μ g/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.Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### Table 4-9. Monitoring Data: Pollutant Concen trations in Effluent from Settling Ponds

Analyte Number of

Plants Number of Samples Minimum

Concentration Maximum

Concentration a Units

Classicals

COD 1 33 120 370 mg/L

TSS 1 36 2.60 53.0 mg/L

TDS 1 36 9,600 12,000 mg/L

Sulfate 1 34 1,100 1,300 mg/L

Chloride 1 36 3,600 5,300 mg/L

Fluoride 1 36 6.30 10.0 mg/L

Nitrate/nitrite 1 1 12.0 12.0 mg/L

Total Kjeldahl nitrogen 1 1 1.20 1.20 mg/L

Total Phosphorus 1 1 ND (0.050) ND (0.050) 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 Con centrations in Effluent from Chemical Precipitation Systems

Analyte Number of

Plants Number of Samples Minimum

Concentration Maximum

Concentration a Units

Total Metals

Aluminum 1 1 183 183 μ g/L

Antimony 2 8 3.7 28 μ g/L

Arsenic 5 101 1.6 310 μ g/L

Barium 1 1 1,520 1,520 μ g/L

Beryllium 3 52 ND (0.03) 0.94 μ g/L

Boron 2 7 17,000 474,000 μ g/L

Cadmium 3 18 0.07 21.9 μ g/L

Calcium 1 7 670,000 790,000 μ g/L

Chromium 4 48 0.12 69 μ g/L

Cobalt 1 1 ND (10) ND (10) μ g/L

Copper 4 50 1.3 71 μ g/L

Iron 3 16 19 6,000 μ g/L

Lead 4 47 ND (0.07) 11 μ g/L

Magnesium 2 8 ND (3,000) 9,200,000 μ g/L

Manganese 2 7 ND (10) 63,000 μ g/L

Mercury 5 275 0.0019 61 μ g/L

Molybdenum 1 1 63 63 μ g/L

Nickel 5 66 4.7 810 μ g/L

Selenium 6 398 16 18,000 μ g/L

Silver 3 17 0.02 1.64 μ g/L

Sodium 2 7 1,000,000 1,700,000 μ g/L



### 4-65Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### 4-66 Table 4-10. Monitoring Data: Pollutant Con centrations in Effluent from Chemical Precipitation Systems

Analyte Number of

Plants Number of Samples Minimum

Concentration Maximum

Concentration a Units

Thallium 1 1 ND (10) ND (10) μ g/L

Tin 1 1 ND (50) ND (50) μ g/L

Titanium 1 1 ND (50) ND (50) μ g/L

Vanadium 1 1 ND (10) ND (10) μ g/L

Zinc 4 35 1.7 15 μ g/L

Dissolved Metals

Antimony 1 6 4 6 μ g/L

Arsenic 1 23 ND (2.4) 240 μ g/L

Beryllium 1 19 ND (0.19) 0.94 μ g/L

Boron 1 4 17,000 22,000 μ g/L

Cadmium 1 3 0.74 0.74 μ g/L

Calcium 1 5 660,000 710,000 μ g/L

Chromium 1 6 12 27 μ g/L

Copper 1 6 11 36 μ g/L

Iron 1 5 ND (32) ND (8,800) μ g/L

Lead 1 4 ND (0.6) 5.2 μ g/L

Magnesium 1 6 6,200,000 7,400,000 μ g/L

Manganese 1 6 42,000 62,000 μ g/L

Mercury 1 195 0.032 54 μ g/L

Nickel 1 6 170 810 μ g/L

Selenium 1 25 62 4,300 μ g/L

Silver 1 4 0.61 1.9 μ g/L

Sodium 1 5 1,100,000 1,300,000 μ g/L

Zinc 1 5 7.7 17 μ g/L

Classicals

TSS 1 10 3.93 33 mg/L

TDS 1 16 12,000 23,000 mg/L

Sulfate 2 9 930 24,000 mg/L

Chloride 2 21 4,700 20,500 mg/L

Bromide 1 4 180 260 mg/L

Fluoride 1 8 0.91 8.60 mg/L

NH 3 -N 2 27 2.30 65.6 mg/L

Total Nitrogen, as N 1 30 2.05 165 mg/L

HEM 1 6 ND (5.00) ND (5.00) mg/L

n-Hexane 1 29 ND (1.40) 2.70 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.Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems



### Table 4-11. Monitoring Data: Pollutant Con centrations in Effluent from Biological Treatment Systems

Analyte Number of

Plants Number of Samples Minimum

Concentration Maximum

Concentration a Units

Total Metals

Aluminum 1 37 ND (32) 602 μ g/L

Antimony 1 37 ND (2) 92 μ g/L

Arsenic 2 53 ND (10) 93 μ g/L

Barium 1 37 26.2 2,440 μ g/L

Beryllium 1 37 ND (0.7) 1.89 μ g/L

Boron 2 38 7,820 666,000 μ g/L

Cadmium 1 37 ND (0.5) 3.57 μ g/L

Chromium 1 37 ND (1) 4,020 μ g/L

Cobalt 1 37 ND (1.1) 241 μ g/L

Copper 1 37 ND (1.6) 628 μ g/L

Iron 1 37 ND (22) 23,000 μ g/L

Lead 1 37 ND (1.9) 291 μ g/L

Manganese 1 37 52 3,170 μ g/L

Mercury 2 51 ND (0.001) 0.3 μ g/L

Molybdenum 1 37 ND (2) 192 μ g/L

Nickel 2 53 ND (1.8) 3,770 μ g/L

Selenium 2 53 ND (10) 510 μ g/L

Silver 1 37 ND (0.2) 36 μ g/L

Thallium 1 37 ND (0.36) 97 μ g/L

Vanadium 1 37 ND (1) 293 μ g/L

Zinc 2 53 ND (1) 432 μ g/L

Dissolved Metals

Selenium 1 16 ND (10) 18 μ g/L

Classicals

COD 1 33 120 380 mg/L

TSS 1 36 1.10 12.0 mg/L

TDS 2 52 2,500 23,000 mg/L

Sulfate 2 39 970 1,300 mg/L

Chloride 1 36 3,800 5,100 mg/L

Fluoride 1 36 5.30 11.0 mg/L

NO 3 -N + NO 2 -N 1 1 0.056 0.056 mg/L

TKN 1 1 2.70 2.70 mg/L

Total Phosphorus 1 1 0.160 0.160 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.



### 4-67Final 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 ofte n 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 typica lly discharge the FGD purge stream.

EPA used data collected during EPA’s sampli ng 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) a nd the effluent associated with four treatment alternatives: settling ponds; chemical precipitation; biological treatment; and evaporation/crystallization. EPA estimated thes e loads for two model plant sizes, which are

discussed further below. EPA then used these m odel plant loads to estimate industry-wide total pollutant loads for FGD wastew aters being discharged from the coal-fired steam electric industry. EPA also estimated the pollutant remo vals that would be achieved by the industry through installing or upgrading exis ting FGD wastewater controls.

4.6.1 FGD Wastewater Treatment Industry Profile

To estimate FGD wastewater loads for the enti re 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 th at are planning or projected to install wet or dry scrubbers by 2020.

To generate this industry profile, EPA used EI A data to identify power plants that operate

at least one coal-fired electri c generating unit. From the ava ilable information, EPA identified 488 coal-fired power plants that are currently operating a coal-f ired generating unit as well as three additional plants that are either planning or constructing a coal-fir ed generating unit. For each of these 491 plants, EPA then determined wh ether the plant currently operates a wet or dry scrubber (as of June 2008) and whether the plant ha s 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 in formation 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 wastewat er treatment system for the plant, EPA assumed that the plant operates a sett ling pond, which is the most co mmonly 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 mode l 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 tota l wet scrubbed capacity of the plant (i.e., the total capacity of the electric genera ting 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 differe nt 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 “Devel opment of the Current and Future Industry Profile for the Steam Elect ric Detailed Study,” dated October 9, 2009 [ERG, 2009s].

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### For each model plant size, EPA calculated a flow rate to use in the loads calculation for each of the model plants. The memorandum en titled “Technology Option Loads Calculation Analysis for Steam Electric De tailed 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 samp ling program and monitoring data obtained from individual plants to calculate loads associ ated 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 confi gurations and operating characteristics at the plants. EP A first calculated the scrubber purge loads on a pl ant 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 co ncentration 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 plan ts, EPA estimated the settling pond effluent concentrations based on scrubber purge con centrations obtained during EPA’s sampling program. The assumptions used to estimate th e settling pond effluent concentrations are

described in the memorandum entitled “Technol ogy 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 preci pitation and biological treatment technologies, EPA used effluent concentr ation data from plants that represent these treatment technologies. The effluent data from th ese plants were used to determine an average concentration for each pollutant. For the evapor ation/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, settli ng 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 weighti ng 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, a nd effluent from each of the treatment technologies. The

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### 4-70 memorandum entitled “Technology Option Loads Ca lculation Analysis for Steam Electric Detailed Study,” dated October 9, 2009 [ERG, 20 09t], describes the data and methodology used to calculate pollutant loads.

Table 4-12. Treatment Technology Loads by Model Plant Size

Waste Stream/Treatment System Small Model Plant Loads (TWPE/Year) Large Model Plant Loads (TWPE/Year)

FGD Scrubber Purge (prior to treatment) 28,400 97,300

Settling Pond 10,900 37,300

Chemical Precipitation 6,410 22,000

Chemical Precipitation + Biological Treatment 2,650 9,080

Chemical Precipitation + Evaporation 0 0

Source: [ERG, 2009t].



### 4.6.3 Industry Baseline and Treatment Technology Loads

EPA used the FGD wastewater treatment indus try profile information (see Section 4.6.1) and the model plant treatment technology load s (see Section 4.6.2) to estimate the FGD discharge loads associated with the steam electric industry. EP A calculated the loads for the “current” industry, based on the st atus 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 F GD scrubber purge, settling pond effluent, and the three control technologies by multiplying th e 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 s cenario. 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 leve l of treatment technology (i.e., the industry-level chemical precipitation loads assume that all plants operating a settling pond w ill install a chemical precipitation system and all other plants will c ontinue operating with their current system). Figure 4-14 presents a comparison of the total baselin e 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 cons idered to under-estimate the actual number of FGD systems that will be installed.Final Detailed Study Report Chapter 4 – Flue Gas Desulfurization Systems

0 1,140,000

732,000

313,000

0 2,250,000

1,450,000

618,000

0 500,000 1,000,000 1,500,000 2,000,000 2,500,000

Baseline Chemical
Precipitation Chemical
Precipitation and Biological Chemical
Precipitation and
Evaporation

Treatment ScenarioFGD Effluent Discharge Loading (TWPE) Current 2020 (Projected)



### Figure 4-14. Estimated Industry-Level FGD Effluent Discharge Loadings By Treatment

Scenario

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### 5. C OAL 

### A SH 

### H ANDLING 

### S YSTEMS



### Combusting coal in steam electric boilers generates solid, noncombustible constituents of the coal, referred to as ash. The heavier ash part icles that collect on the bottom of the boiler are referred to as bottom ash and may also be calle d slag. The finer ash pa rticles that are light enough to be transferred out of the boiler with th e flue gas exhaust are referred to as fly ash. Some of the particles that are in itially carried with the flue gase s collect in the economizer or air preheater sections of the boiler. Depending on oper ations 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 coalfired 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 ch arged particles then collect on a metal plate with an opposite electric charge. Additionally, some pl ants may use agglomerating agents, such as ammonia, which help small charged ash particles fo rm larger agglomerates that are more readily attracted to the charged plates, improving the rem oval efficiency of the ESPs. As the particles begin to layer on the metal plates, the plates are tapped/rapped to loosen th e 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 ach ieve removals of gr eater than 99.9 percent [Babcock & Wilcox, 2005].

Plants may also use other particulate cont rol technologies, such as baghouse filters. A baghouse system contains several compartments, each containing fabric filter bags that are suspended vertically in the compartment. The ba gs can be quite long (e.g., 40 feet) and small in diameter [Babcock & Wilcox, 2005].

The reverse air system is the baghouse c onfiguration most commonly used by steam electric plants. In this system, th e 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 partic ulates cannot pass and are captur ed on the inside walls of the baghouses. As the baghouses collect more particulat es, the layer of partic ulates becomes thicker and also helps to remove particulates from the fl ue gas. After a specified period of time or once the pressure drop in the baghouses re aches a high set point level, th e plants reverse the flow in a compartment and send clean flue gas from the outsi de of the fabric filte r bags to the inside, which dislodges the particulates. The particulat es 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 SO 2 

### 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 constr icted 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, it s pressure increases and the velo city of the gas increases, which causes the gas and liquid slurry to mix. The greater the pressure drop in th e scrubber, the better

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### the mixing and the better the reaction rate, whic h 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 scrubb er 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 as h into the hoppers, the plant can either handle the fly ash in a dry or wet fashion. In eith er 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 fl y 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 si te 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 e ductors, 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, wh ere it combines with the water flowing through th e 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 continuou sly to maintain the necessary vacuum and prevent solids from se ttling in the piping.

EPA compiled information regarding manageme nt 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-provi ded data, site visits and sampling data, and data request information. Approximately one-t hird 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 handl ing 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, th ese 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 collect ed by EPA’s Office of Solid Waste and Emergency Response (OSWER), which sent letter s to power plants requi ring that they report certain information about waste management units used for the storage or disposal of coal

combustion residues. The OSWER database identif ies 188 plants that ar e operating 398 surface impoundments containing fly ash. Sixty-four of th ese 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 opera te wet bottom ash handling systems than wet fly ash handling systems. Fewer wet fly as h systems are expected because the NSPS promulgated in 1982 prohibit the discharge of wastew ater pollutants from fly ash transport water. Not surprisingly, EPA has found that the steam el ectric units generating wet fly ash transport water tend to be older units, while dry ash handling systems tend to be operated on newer units.

5-2Final Detailed Study Report Chapter 5 – Coal Ash Handling Systems



### EPA identified several plants that have instal led dry fly ash handling systems, either to replace the pre-existing wet handlin g system or to operate as a parallel system. The reasons for installing the dry handling systems include enviro nmental remediation (i.e., discharges from the fly ash ponds caused environmental impacts), econo mic opportunity (e.g., revenues from sale of fly ash), and the need to replace ash ponds appr oaching full storage capacity. Because dry fly ash handling practices do not generate wastewater stre ams, converting to a dry system eliminates the discharge of fly ash transport wa ter 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 Plan ts Included in EPA’s Combined Data Set

Fly Ash Handling Number of Plants a Number of Electric Generating Units b Capacity c
(MW)

Wet-Sluiced 34 (35%) 95 (40%) 38,300 (33%)

Handled Dry or Removed in Scrubber 63 (65%) 128 (54%) 73,600 (63%)

Other – Most Ash Handled Dry or Unknown 7 (7%) 14 (6%) 4,950 (4%)

Total 97 237 117,000

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 handlin g 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 boile r, the lower portion of the boiler slopes inward from the front and rear walls of the boiler, leaving a thre e- 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 preven t 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 bo ttom 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 [B abcock & 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 wa ter. 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 fre quency of bottom ash sluicing depends upon the

5-3Final 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 duratio n 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 particle s are heavier than the fly as h particles, they are more easily separated from the sluice water than the fl y ash particles. A dewatering bin system is a tank-based settling operation that is used to se parate 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 a nd 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 ce nter of the bin and c ontacts 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 th e 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 w ith 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 tr ansport 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 bo ttom 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 th e 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 se t handle at least a portion of their bottom ash dry. The dry bottom ash handling systems that EPA obs erved 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 dr ag 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 as h is often conveyed to a nearby collection area, such as a small bunker outside the boiler bui lding, 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 da ta set (88 percent; 85 plants) operate wet handling systems for bottom ash. EPA also review ed the OSWER data recently collected for

5-4Final 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 c ontain fly ash (212 ponds), FGD wastes (6 ponds), or both (108 ponds). The OSWER database likely does not identif y plants using wet handling systems that employ dewatering bins, unless th e 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 Number of Plants a Number of Electric Generating Units b Capacity c
(MW)

Wet-Sluiced 85 (88%) 214 (90%) 106,000 (91%)

Handled Dry 13 (13%) 22 (9%) 10,200 (9%)

Unknown 1 (1%) 2 (1%) 600 (<1%)

Total 97 238 117,000

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 handlin g 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 transpor t water flow rates reported in the data request responses.

The flow rates that are normalized on a MW ba sis 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 additi on to bottom ash and fly ash. F actors acting to reduce the pond overflow rate include pond losses from infiltra tion through the bottom of the pond or retaining dikes, evaporation, and whether th e water held in the ash pond is recycled back to the plant for reuse. The average fly ash pond overflow flow ra tes collected during the development of the 1982 effluent guidelines are 2,610,000 gpd/plan t and 3,810 gpd/MW [U.S. EPA, 1982].

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### 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 17 5,890 3,000 188 - 27,500

gpd/plant d 17 7,640,000 4,030,000 270,000 - 39,600,000

gpy/plant d 17 2,710,000,000 1,470,000,000 6,480,000

- 14,500,000,000

Normalized Flow Rate based on Total Coal-Fired Capacity

gpm/Coal-Fired MW b, c 17 4.59 4.08 0.291 - 9.38

gpd/Coal-Fired MW c, d 17 5,830 5,140 419 - 11,900

gpy/Coal-Fired MW c, d 17 2,090,000 1,870,000 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 electri c 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 ca nnot 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 trans port water is an intermittent stream from each of the coal-fired units. The bottom ash transp ort water flow rates are typically not as large as the fly ash transport water flow rates. Howeve r, bottom ash transport wa ter 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 coalfired capacity. The average coal-fired capacity pe r 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 co llected during the de velopment of the 1982 effluent guidelines are 2,600,000 gpd/plant a nd 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 effl uent guideline development because the bottom ash pond overflow likely includes ot her plant wastewaters, in a ddition to bottom ash transport

water.

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### Table 5-4. Bottom Ash Transport Water Flow Rates from EPA Data Request Responses

Number of Plants a Average Flow

Rate b Median Flow

Rate b Range of Flow

Rate b

Flow Rate per Plant

gpm/plant c 27 3,370 1,740 358 - 12,600

gpd/plant d 27 3,290,000 2,380,000 253,000

- 18,100,000

gpy/plant d 27 1,190,000,000 810,000,000 92,400,000

- 6,600,000,000

Normalized Flow Rate Based on Total Coal-Fired Capacity

gpm/Coal-Fired MW c, e 27 2.21 1.18 0.479 - 9.38

gpd/Coal-Fired MW d, e 27 1,940 1,600 222 - 7,070

gpy/Coal-Fired MW d, e 27 701,000 585,000 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 th e 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 electri c unit is associated with

coal use. Non-coal-fired units are not included in the capacity calculations.



### The pollutant concentrations in ash transpor t water vary from plan t to plant depending on the coal used, the type of boiler, and the particul ate control system used by the plant. In addition,

the waste stream characteristics also vary in a cyclical fash ion during the di scharges. For example, the fly ash transport water characteri stics vary depending on which of the ash hoppers is being sluiced. The bottom ash transport wa ter characteristics at the beginning of the intermittent sluicing period are likely to be differe nt 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 200.7 μ g/L 94,800 320,000

Antimony 200.7 μ g/L ND (38.0) ND (81.2)

Arsenic 200.7 μ g/L 131 1,520

Barium 200.7 μ g/L 6,080 5,060

Beryllium 200.7 μ g/L 11.3 71.5

Boron 200.7 μ g/L 4,330 2,790

Cadmium 200.7 μ g/L ND (9.50) 39.6

Calcium 200.7 μ g/L 103,000 204,000



### 5-7Final Detailed Study Report Chapter 5 – Coal Ash Handling Systems



### 5-8 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

Chromium 200.7 μ g/L 107 1,300

Cobalt 200.7 μ g/L ND (95.0) 381

Copper 200.7 μ g/L 188 964

Iron 200.7 μ g/L 80,700 298,000

Lead 200.7 μ g/L 208 786

Magnesium 200.7 μ g/L 25,700 35,100

Manganese 200.7 μ g/L 337 1,120

Mercury 245.1 μ g/L 2.66 2.31

Molybdenum 200.7 μ g/L 65.5 333

Nickel 200.7 μ g/L ND (95.0) 739

Selenium 200.7 μ g/L 27.5 ND (20.3)

Sodium 200.7 μ g/L 31,200 69,900

Thallium 200.7 μ g/L ND (19.0) ND (40.6)

Titanium 200.7 μ g/L 7,150 24,900

Vanadium 200.7 μ g/L 346 2,340

Yttrium 200.7 μ g/L 133 521

Zinc 200.7 μ g/L 785 1,220

Routine Metals – Dissolved

Aluminum 200.7 μ g/L 663 283

Antimony 200.7 μ g/L ND (20.0) ND (20.0)

Arsenic 200.7 μ g/L 46.0 86.8

Barium 200.7 μ g/L 178 164

Beryllium 200.7 μ g/L ND (5.00) ND (5.00)

Boron 200.7 μ g/L 2,150 1,380

Cadmium 200.7 μ g/L ND (5.00) ND (5.00)

Calcium 200.7 μ g/L 40,300 94,800

Chromium 200.7 μ g/L ND (10.0) ND (10.0)

Hexavalent Chromium D1687-92 μ g/L ND (2.00) 5.00

Cobalt 200.7 μ g/L ND (50.0) ND (50.0)

Copper 200.7 μ g/L ND (10.0) ND (10.0)

Iron 200.7 μ g/L ND (100) ND (100)

Lead 200.7 μ g/L ND (50.0) ND (50.0)

Magnesium 200.7 μ g/L 7,110 15,200

Manganese 200.7 μ g/L ND (15.0) 40.3

Mercury 245.1 μ g/L ND (0.200) ND (0.200)

Molybdenum 200.7 μ g/L 50.1 243

Nickel 200.7 μ g/L ND (50.0) ND (50.0)

Selenium 200.7 μ g/L 26.8 16.6

Sodium 200.7 μ g/L 13,400 64,400Final Detailed Study Report Chapter 5 – Coal Ash Handling Systems



### 5-9 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

Thallium 200.7 μ g/L ND (10.0) ND (10.0)

Titanium 200.7 μ g/L ND (10.0) ND (10.0)

Vanadium 200.7 μ g/L 66.8 70.7

Yttrium 200.7 μ g/L ND (5.00) ND (5.00)

Zinc 200.7 μ g/L ND (10.0) ND (10.0)

Low-Level Metals – Total

Antimony 1638 μ g/L 13.1 L 33.1

Arsenic 1638 μ g/L 88.9 519

Cadmium 1638 μ g/L ND (20.0) 9.51

Chromium 1638 μ g/L ND (160) 569

Copper 1638 μ g/L 114 719

Lead 1638 μ g/L 104 260

Mercury 1631E μ g/L 1.02 1.16

Nickel 1638 μ g/L ND (200) 291

Selenium 1638 μ g/L ND (200) ND (200)

Thallium 1638 μ g/L ND (4.00) 43.6

Zinc 1638 μ g/L 198 720

Low-Level Metals – Dissolved

Antimony 1638 μ g/L 8.54 17.4

Arsenic 1638 μ g/L 49.5 80.7

Cadmium 1638 μ g/L ND (2.00) ND (1.00)

Chromium 1638 μ g/L ND (16.0) ND (80.0)

Hexavalent Chromium 1636 μ g/L NA NA

Copper 1638 μ g/L ND (4.00) ND (20.0)

Lead 1638 μ g/L ND (1.00) ND (0.500)

Mercury 1631E μ g/L ND (0.000500) 0.000550

Nickel 1638 μ g/L ND (20.0) ND (100)

Selenium 1638 μ g/L ND (100) 21.2

Thallium 1638 μ g/L ND (0.400) 3.10

Zinc 1638 μ g/L ND (10.0) ND (50.0)

Classicals

Ammonia As Nitrogen (NH 3 - N) 4500-

NH3F mg/L 0.400 0.170

Nitrate/Nitrite (NO 3 -N + NO 2 - N) 353.2 mg/L 0.360 2.65

Total Kjeldahl Nitrogen (TKN) 4500-N,C mg/L 7.41 1.01

Biochemical Oxygen Demand (BOD) 5210B mg/L 53.0 ND (2.00)

Chloride 4500-CL-C mg/L 21.4 56.8Final Detailed Study Report Chapter 5 – Coal Ash Handling Systems



### 5-10 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

Hexane Extractable Material (HEM) 1664A mg/L ND (5.00) 7.00

Silica Gel Treated HEM (SGTHEM) 1664A mg/L NA 6.00

Sulfate D516-90 mg/L 58.1 1,110

Total Dissolved Solids (TDS) 2540 C mg/L 224 662

Total Phosphorus 365.3 mg/L 16.6 4.03

Total Suspended Solids (TSS) 2540 D mg/L 9,190 E 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 re presents only the wastewaters associated with six of the eight generating units. The wa stewaters for the other two un its enter the combined ash pond at a diff erent point. E – Sample analyzed outside holding time. L – Sample result between 5x and 10x blank result. NA – Not analyzed. ND – Not detected (number in parenthesis is the repor t limit). The sampling epis ode 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 channe l containing fly ash tran sport water, bottom ash transport water, and several low-volume wastewat ers, including coal pi le runoff overflow, boiler blowdown, nonchemical metal cleani ng wastewater, roof and switc hyard drainage, flow wash water, and miscellaneous cooling water. Due to th e very high flow rates and solids loading of the influent stream and the challenge of safely coll ecting 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 th e wastewater generated from six of the eight units at the plant, which represents approximate ly 42 percent of the plant’s generating capacity. The other two units also generate wastewaters that en ter the ash pond; howeve r, the wastewaters enter the pond at a different location. Plant perso nnel estimated that the flow rate entering the ash pond at the time of sampling for the six un its 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 collect ed a three-hour composite sample of the influent to the fly ash pond. The in fluent to the fly ash pond consis ted 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 st ream and the challenge of safely collecting aFinal 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. Du ring the sampling episode, the plant personnel

estimated the influent flow ra te to the fly ash pond was 9.1 mgd. The sampling episode report for

Cardinal contains more detailed information re garding the sample colle ction procedures [ERG, 2008k].

Table 5-5 shows that the ash trans port water streams contain si gnificant 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 concentra tion 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 as h transport water are large enough that the waste stream typically requires some fo rm of treatment prior to bein g 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 plan ts operating both wet fly as h and wet bottom ash handling systems, the two sluice streams are often co mmingled within the same settling pond system along with other waste streams. For plants oper ating only one wet ash ha ndling 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 wa stewaters. 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. B ecause ash ponds remove solid particulates, they may also be an effective means of removing so me metals from fly ash transport water when these metals are present in particulate form.

Surface impoundments (i.e., ash ponds and F GD 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 ra nged 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 projecte d to continue operating beyond 2045 [EPRI, 1997a].

During the summer, some ash ponds become ther mally stratified. When this occurs, the top layer of the pond is warmer and contains hi gher levels of dissolved oxygen, whereas the bottom layer of the pond is colder and has signi ficantly lower levels of oxygen, often being anoxic. Typically during fall, as the air temperature decrease s, 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 th e bottom of the pond could potentially become

5-11Final Detailed Study Report Chapter 5 – Coal Ash Handling Systems



### resuspended due to the mixing, increasing the c oncentrations 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, whic h 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 ther mal stratification. However, some power plant settling ponds are large (e.g., grea ter 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 wa ter to settling ponds. Sixt y-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 Treatme nt Systems at Plants Included in EPA’s

Combined Data Set

Type of Fly Ash Wastewater Treatment System Number of

Plants Number of

Electric Generating

Units a Capacity (MW) b Number of

Treatment Systems That

Also Receive

FGD Wastewater

Settling pond, fly ash commingled with bottom

ash 22 (58%) 74 (68%) 25,300 (59%) 4

Settling pond, fly ash NOT commingled with

bottom ash 4 (11%) 9 (8%) 7,240 (17%) 1

Settling pond, not known if fly ash is commingled

with bottom ash 10 (26%) 24 (22%) 9,690 (23%) 2

Other (trucked away, no wastewater discharge) 2 (5%) 2 (2%) 747 (2%) 0

Total 38 109 43,000 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 handlin g 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 de watering bins, settling ponds, or both. EPA has observed that most bottom ash settling ponds also r eceive other plant wastew aters. 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 se t that handle the bottom ash with a wet system transfer the bottom ash transport water to a se ttling pond for treatment. Only 18 percent of the plants are operating dewa tering bins prior to the settling pond. As shown in Table 5-7 , there are more plants that keep their bottom ash transport a nd fly ash transport waters segregated than not.

5-12Final Detailed Study Report Chapter 5 – Coal Ash Handling Systems



### Table 5-7. Bottom Ash Transport Wastewater T reatment Systems at Plants Included in

EPA’s Combined Data Set

Type of Bottom Ash Wastewater Treatment System Number of

Plants Number of

Electric Generating

Units Capacity (MW) Number of Treatment Systems

That Also Receive

FGD Wastewater

Dewatering bins, NOT sent to settling pond (not known if commingled with fly ash) 8 18 11,100 0

Dewatering bins, overflow to settling pond (comingled with fly ash) 2 6 3,300 1

Dewatering bins, overflow to settling pond (not comingled with fly ash) 14 28 17,200 3

Dewatering bins, overflow to settling pond (not known if commingled with fly ash) 1 1 176 1

Settling pond (comingled with fly ash) 23 73 25,200 11

Settling pond (not commingled with fly ash) 37 78 44,700 10

Settling pond (not known if commingled with fly ash) 7 14 5,270 2

Unknown 1 2 596 0

Total 93 220 108,000 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 handlin g 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 repor ted 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 th an ash transport water, were cooling tower blowdown, FGD wastewater, and va rious types of low-volume wast es [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 di rect contact with the coal, they often have low pH (i.e., they are acidic wastewaters). According to inform ation 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. A dditionally, EPA determined that all of the 186

5-13Final Detailed Study Report Chapter 5 – Coal Ash Handling Systems



### 5-14 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 plan ts 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 info rmation about waste management units used for the storage or disposal of co al combustion residues. The OSWER data includes information for 214 plants in 35 states operati ng a total of 537 ponds cont aining 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 nati onwide population of 213 pl ants operating 495 ash ponds. Table 5-8 presents summary statistics that iden tify the type of coal combustion residues contained in ash ponds, most of which also receive other power pl ant wastewaters. For completeness, the table also includes informa tion OSWER collected for ponds that receive FGD wastes [Schroeder, 2009].

Table 5-8. Ponds Containing Coal Combustion Residues

Type of CCR Contained in Pond Number of CCR Ponds

Fly ash and bottom ash 212

Fly ash, bottom ash, and FGD 108

Fly ash only 64

Bottom ash only 91

FGD only 42

Fly ash and FGD 14

Bottom ash and FGD 6

Total 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 pon d treatment. EPRI determined that when the

FGD wastewater was mixed with the more dilute ash pond water, the gyps um 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 [E PRI, 2006b]. Additionally, EPRI reported that the FGD wastewater includes high load ings of volatile metals which can impact the solubility of metals in the ash pond, thereby potenti ally 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 repo rtedly do not operate any ponds containing CCR.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 unl ined. 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 as h ponds to control the pH of the ash pond effluent discharge. The current effluent guidelines pH limit for di scharges from steam electric plants is the range of 6.0 to 9.0 S.U. Common chem icals used to control the pH in ash ponds are sodium hydroxide and hydrochl oric acid. Other plants, such as Widows Creek, inject CO 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 Util ities’ 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 overf low 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 main taining the ash ponds. Some plants constantly remove settled ash solid s from the ash pond delta and stack them on the sides of the pond to dewater and build up the he ight of the pond. Alternatively, some plants periodically dredge th e pond to remove the ash from the bottom of the pond and transfer the solids off site for disposal or to an on-site landfi ll, or use the solids to bu ild 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 canno t be directly compared with each other. In addition, the influent con centrations 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 str eams entering the pond system. Table 5-9 shows that the treated ash pond effluent wastewaters cont ain low concentrations of T SS 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 pr edominantly 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 th e two bottom ash ponds operating in parallel. The overflow from the bottom ash ponds is transferred to a clearwell and then disc harged 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 th e clearwell. The average flow rate discharged

5-15Final Detailed Study Report Chapter 5 – Coal Ash Handling Systems



### 5-16 from the clearwell during the sampling epis ode was 0.453 mgd. The samp ling episode report for Homer City contains more detailed informati on regarding the sample collection procedures [ERG, 2008l].

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 inject s carbon dioxide, if needed, to decrease the pH of the wastewater to with in the range of 6.0 to 9.0 S.U. The overflow from the second pond enters the pumping basin, where the treated wast ewater 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 overf low 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 ra te discharged from the pumping basin during the sampling episode was 29.9 mgd. The sampling epis ode report for Widows Creek contains more detailed information regarding the samp le collection procedures [ERG, 2008o].

Mitchell operates a fly ash pond treatment sy stem. The fly ash pond receives the fly ash transport water from Mitchell, fly ash tran sport 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. EP A collected a grab sample of the fly ash pond effluent from the channel discharging to the su rface water. The average flow rate discharged from the fly ash pond during the sampling episod e was 7.8 mgd. The sampling episode report for

Mitchell contains more detailed information re garding the sample collection procedures [ERG, 2008m].Final Detailed Study ReportChapter 5 – Coal Ash Handling SystemsTable 5-9. Ash Pond Effluent ConcentrationsAnalyteMethodUnitHomer City –Effluent from BottomAsh PondaWidows Creek –Effluent fromCombined Ash PondaMitchell – Effluentfrom Fly Ash PondaCardinal – Effluentfrom Fly Ash Ponda, bRoutine Metals - TotalAluminum200.7μg/L3231,070404344Antimony200.7μg/LND (20.0)ND (20.0)24.621.2Arsenic200.7μg/LND (10.0)38.215077.6Barium200.7μg/L101227133165Beryllium200.7μg/LND (5.00)ND (5.00)ND (5.00)ND (5.00)Boron200.7μg/L3962,2102,3501,100Cadmium200.7μg/LND (5.00)ND (5.00)ND (5.00)ND (5.00)Calcium200.7μg/L186,00058,500115,00088,400Chromium200.7μg/LND (10.0)13.515.9ND (10.0)Cobalt200.7μg/LND (50.0)ND (50.0)ND (50.0)ND (50.0)Copper200.7μg/LND (10.0)ND (10.0)ND (10.0)ND (10.0)Iron200.7μg/L355144ND (100)ND (100)Lead200.7μg/LND (50.0)ND (50.0)ND (50.0)ND (50.0)Magnesium200.7μg/L31,8006,68021,00017,900Manganese200.7μg/L128ND (15.0)ND (15.0)64.7Mercury245.1μg/LND (0.200)ND (0.200)ND (0.200)ND (0.200)Molybdenum200.7μg/L19.7143359361Nickel200.7μg/LND (50.0)ND (50.0)ND (50.0)ND (50.0)Selenium200.7μg/L6.0216.217744.5Sodium200.7μg/L106,00021,300526,00070,800Thallium200.7μg/LND (10.0)ND (10.0)ND (10.0)ND (10.0)Titanium200.7μg/LND (10.0)14.5ND (10.0)12.6Vanadium200.7μg/LND (20.0)68.5110104Yttrium200.7μg/LND (5.00)ND (5.00)ND (5.00)ND (5.00)Zinc200.7μg/L21.6ND (10.0)ND (10.0)ND (10.0)5-17Final Detailed Study ReportChapter 5 – Coal Ash Handling SystemsTable 5-9. Ash Pond Effluent ConcentrationsAnalyteMethodUnitHomer City –Effluent from BottomAsh PondaMitchell – Effluentfrom Fly Ash PondaCardinal – Effluentfrom Fly Ash Ponda, bWidows Creek –Effluent fromCombined Ash PondaRoutine Metals - DissolvedAluminum200.7μg/L231357241130LAntimony200.7μg/LND (20.0)ND (20.0)23.920.9Arsenic200.7μg/LND (10.0)30.113874.6Barium200.7μg/L106206128157Beryllium200.7μg/LND (5.00)ND (5.00)ND (5.00)ND (5.00)Boron200.7μg/L3972,2002,2901,090Cadmium200.7μg/LND (5.00)ND (5.00)ND (5.00)ND (5.00)Calcium200.7μg/L192,00055,400113,00087,200Chromium200.7μg/LND (10.0)11.914.1ND (10.0)Hexavalent ChromiumD1687-92μg/LND (2.00)12.07.00<3.50Cobalt200.7μg/LND (50.0)ND (50.0)ND (50.0)ND (50.0)Copper200.7μg/LND (10.0)ND (10.0)ND (10.0)ND (10.0)Iron200.7μg/L106ND (100)ND (100)ND (100)Lead200.7μg/LND (50.0)ND (50.0)ND (50.0)ND (50.0)Magnesium200.7μg/L32,6006,43020,30017,700Manganese200.7μg/L129ND (15.0)ND (15.0)42.9Mercury245.1μg/LND (0.200)ND (0.200)ND (0.200)ND (0.200)Molybdenum200.7μg/L20.2136330352Nickel200.7μg/LND (50.0)ND (50.0)ND (50.0)ND (50.0)Selenium200.7μg/L6.10L15.316243.8Sodium200.7μg/L106,00020,000514,00070,300Thallium200.7μg/LND (10.0)ND (10.0)ND (10.0)ND (10.0)Titanium200.7μg/LND (10.0)ND (10.0)ND (10.0)ND (10.0)Vanadium200.7μg/LND (20.0)64.710899.9Yttrium200.7μg/LND (5.00)ND (5.00)ND (5.00)ND (5.00)Zinc200.7μg/L35.2ND (10.0)ND (10.0)ND (10.0)5-18Final Detailed Study ReportChapter 5 – Coal Ash Handling SystemsTable 5-9. Ash Pond Effluent ConcentrationsAnalyteMethodUnitHomer City –Effluent from BottomAsh PondaMitchell – Effluentfrom Fly Ash PondaCardinal – Effluentfrom Fly Ash Ponda, bWidows Creek –Effluent fromCombined Ash PondaLow-Level Metals - TotalAntimony1638μg/L1.094.3925.821.9Arsenic1638μg/L6.5234.914269.8Cadmium1638μg/LND (0.500)ND (0.500)1.321.14Chromium1638μg/LND (4.00)13.5L20.44.64LCopper1638μg/L2.371.495.472.98Lead1638μg/LND (0.250)0.4900.5800.420Mercury1631Eμg/L0.005110.001570.002120.00125Nickel1638μg/L10.7ND (5.00)11.010.7Selenium1638μg/L5.7417.119145.8Thallium1638μg/L1.321.461.722.84Zinc1638μg/L24.2ND (2.50)10.15.98Low-Level Metals - DissolvedAntimony1638μg/L0.9904.4522.522.4Arsenic1638μg/L5.0029.013168.9Cadmium1638μg/LND (0.500)ND (0.500)1.171.11Chromium1638μg/LND (4.00)12.6L16.04.49LHexavalent Chromium1636μg/L3.0114.717.43.96Copper1638μg/L2.08ND (1.00)4.542.27Lead1638μg/LND (0.250)ND (0.250)ND (0.250)ND (0.250)Mercury1631Eμg/L0.00141ND (0.000500)ND (0.000500)ND (0.000500)Nickel1638μg/L10.4ND (5.00)9.5710.6Selenium1638μg/L5.1615.616145.0Thallium1638μg/L1.311.491.422.87Zinc1638μg/L15.0ND (2.50)9.514.155-19Final Detailed Study ReportChapter 5 – Coal Ash Handling Systems5-20Table 5-9. Ash Pond Effluent ConcentrationsAnalyteMethodUnitHomer City –Effluent from BottomAsh PondaWidows Creek –Effluent fromCombined Ash PondaMitchell – Effluentfrom Fly Ash PondaCardinal – Effluentfrom Fly Ash Ponda, bClassicalsAmmonia As Nitrogen (NH3-N)4500-NH3Fmg/L0.3400.1600.1500.205Nitrate/Nitrite (NO3-N + NO2-N)353.2mg/L37.00.2300.7304.73ETotal Kjeldahl Nitrogen (TKN)4500-N,Cmg/L1.363.39ND (0.100)<0.785LBiochemical Oxygen Demand (BOD)5210Bmg/LND (2.00)4.002.00ND (2.00)Chloride4500-CL-Cmg/L90.020.024060.0Hexane Extractable Material (HEM)1664Amg/LND (5.00)6.00ND (5.00)10.0Silica Gel Treated HEM (SGT-HEM)1664Amg/LNAND (5.00)NAND (4.00)SulfateD516-90mg/L1,29080.71,110494Total Dissolved Solids (TDS)2540 Cmg/L1,2502812,050673Total Phosphorus365.3mg/L1.090.250E0.2000.0870Total Suspended Solids (TSS)2540 Dmg/L5.0012.0E15.06.00Source: [ERG, 2008l; 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 ofthe analytical methods as “routine” and some of them as “low-level.” EPA designated all of the methods that require the use ofclean hands/dirty hands samplecollection 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 ashpond effluent and the duplicate of the ash pond effluent analytical measurements.< – Average result includes atleast one non-detect value. (Calculation usesthe report limit for non-detected results).E – Sample analyzed outside holding time.L – Sample result between 5x and 10x 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 samplinginformation, including analytical resultsfor analytes measured above the detection limit, but below the reporting limit (i.e.,J-values).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 ch annel that discharges to surface water. EPA collected a grab sample of the fly ash pond efflue nt 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 pr ogram, 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 tran sport waters with no discharge. One of these plants is highlighted in Case Study IV.

Additionally, EPA visited two plants with segregated bot tom 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 overf low 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 th e system. One of these plants is highlighted in Case Study V.

Some plants achieve partia l recycle from ash ponds. For example, from information obtained through the data request, EPA estimates th at Georgia Power’s Bowe n plant is recycling approximately 85 percent of the water from its ash pond. This ash pond receives and recycles several types of wastewat ers including bottom ash and fly ash transport water.

5-21Final 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 tota l MW capacity for a ll 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 transpor t water are pumped to Ash Pond A, which was built in 1980 and has a discharge point (Outfall 00 2), but the plant does not typically discharge from the pond. Ash pond A also receives the e ffluent from the coal pile runoff pond and

stormwater collected in Ash P ond 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 th e 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 li ner of the pond. The plant monito rs the levels of the ponds closely and adjusts the make-up water to the sl uicing system to control the level of the ponds. During the rainy season, the plan t keeps the levels lower to al low 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 tran sport water, coal pile runoff, rainfall,

stormwater Recycle destination: Bottom ash trans port water and fly ash transport water

Source: [ERG, 2009m].



### 5-22Final Detailed Study Report Chapter 5 – Coal Ash Handling Systems



### 5-23 

## 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 fr om 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 operate s 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 stormwater runoff and rainfall. Runo ff from the ash handling and precipitator areas (covering approximately six acres) drains into the ponds. Water fr om 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 transpor t water. There is a periodic discharge from the clearwell through the NPDES outfall as needed to maintain the wa ter balance in the system, the frequency of which depends on the amount of rainfa ll that has been received. As one pair of ash settling ponds fills with solids, th e transport water is shifted to the other pair of ponds so that

the settled ash can be removed. The ash settli ng 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: Signifi cant 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].Final Detailed Study Report Chapter 6 – Environmental Assessment of Coal Combustion Wastewater



### 6. E NVIRONMENTAL 

### A SSESSMENT OF 

### C OAL 

### C OMBUSTION 

### W ASTEWATER



### Numerous studies have shown that the pollu tants found in wastewat er associated with coal combustion wastes can impact aquatic orga nisms 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 pers istent and bioaccumulative nature of the pollutants released. The total amount of toxic pollutants curr ently being released in wastewat er discharges from coal-fired power plants is estimated to be significant and ra ises 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 imp acts that pollutants presen t 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 th e combustion wastes to a storage silo or outdoor storage pile to eith er be hauled to a landfill or, depending on the particular residual, sent offsite where it may be used to create benefici al by-products such as drywall or cement. In wet handling systems, botto m ash and fly ash is transported from the boiler and particulate removal units and is typically di sposed 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 ca lled 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 com bustion wastewater incl udes the following waste

streams:

• 

### FGD wastewater (i.e., scr ubber purge) - the wastewat er 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 st ream 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 impound ments or landfills containing coal

combustion residues.

The most common treatment and disposal pr actice for coal combustion wastewater involves pumping the slurried wastes into surface impoundments that serve as a physical treatment to remove particulate material th rough gravitational settling. The coal combustion wastewater present in surface impoundments can include one sp ecific wastewater stream (e.g., fly ash transport water) or a combination of com bustion 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 wast ewater. Some coal-fired power plants have implemented more advanced wastewater treatm ent systems such as chemical precipitation,

6-1Final Detailed Study Report Chapter 6 – Environmental Assessment of Coal Combustion Wastewater



### biological treatment, and evapor ation/distillation to treat the FGD wastewater. Chapter 4 describes these advanced treatment practices in mo re 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 studi es 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 co mposition of coal combustion wastewater, including parent coal composition, type of combustion proce ss, 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, beha vioral and physiological effects in wildlife and aquatic organisms, potential impacts to human he alth (i.e., drinking wate r contamination), and changes to the local habitat [Rowe et al., 2002; Carlson and Adriano, 1993]. The bioaccumulative properties of several coal combus tion wastewater pollutants and long recovery times associated with many of the ecological im pacts 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 st udy is needed to fully understand how these chemically complex waste streams inte ract with the environment [Rowe et al., 2002; NRC, 2006].

This chapter examines the potential impact s 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 charac teristics of coal combustion wastewater and why they are

a threat to the environment. S ection 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 impoundment s 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 wast ewater. Section 6.3 provide s 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 eviden ce indicates that the characte ristics of coal combustion wastewater have the potential to impact human health and the environment. Many of the common pollutants found in coal combustion wastew ater (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

6-2Final Detailed Study Report Chapter 6 – Environmental Assessment of Coal Combustion Wastewater



### addition, some pollutants in coal combustion wast ewater present an incr eased ecological threat due to their tendency to persist in the environm ent and bioaccumulate in organisms, which often results in slow ecological rec overy times following exposure.

Constituents present in coal combustion wastew ater 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, wastew ater concentration, and how orga nisms are exposured to them

in the environment. Table 6-1 lists some of the common pollutants found in coal combustion

wastewater that have been asso ciated with documented environmen tal 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 envi ronmental 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 cite d as causing ecological impacts following exposure to coal combustion wastewater, some of which ha ve been the focus of some state NPDES permit

programs.

Table 6-1. Selected Coal Combustion Wastewater Pollutants

Com pound Pote nti a l Envi ronme n tal Concern a,b,c,d

Arse ni c Fre que nt l y o b s e rve d i n hi g h c once n t r at i o ns i n c o al com bust i on wast e w at er ; causes p o i s o n i ng o f

th e liv er in fish and d e v e l o p m en tal abn o rm al ities; is asso ciated with an in creased risk o f can cer in hu m a n s in t h e liv er an d b l ad d e r.

BOD Can cau s e fish k ills b ecau s e of a lack o f av ai lab l e ox yg en ; i n creases th e tox i city o f o t h e r pol l u t a nt s, s u c h as m e rcury

. Has bee n ass o c i at ed with FGD wastewaters that use orga ni c acids

fo r e nha nce d S O 2 rem o v al in t h e scrubb er.

Boron Fre que ntly obs e rve di n high c once n tratio ns in c o al com bust i on waste w ater; leachate into

gr o u n d w a t e r h a s excee de d st at e dri nki ng w a t e r st an dar d s; hum an ex p o s u r e t o hi g h

conce n t r at i o ns can ca use na us ea, v o m i t i ng, a n d di a r r h ea. C a n be t o xi c t o v e get a t i o n

. Cadm iu m Elevated le vels are c h ara c teris tic of c o al c o m bust i on wast e w at er-i m p acted system s; organism s with elev ated l e v e ls h a v e exhib ited tissu e d a mag e and o r g a n ab norm a l itie s.

C h l o ri des Som e t i m e s obs erve d at hi g h c once n t r at i o ns i n c o al com bust i on wast e w at er ( d epe n dent o n FG D

sy st em pract i ces); el evat e d l e vel s obse r ved i n fi sh wi t h l i v e r a n d bl oo d a b no rm al it i e s.

Chrom i u m Elevated le vels ha ve been obs e rve d i n groundwate r recei vi ng coal c o m b ustion wastewat er leachate; inve rtebrates with el evated le vels requi re m o re e n ergy t o s u pport their m e tabolism and

therefore e xhi bit di m i n i sh ed gr ow th.

Copper Coal com busti on waste w ater can c ont ai n hi g h l e vel s ; i nve rt ebrat e s wi t h el evat ed l e vel s r e qui re

m o re en erg y to sup port th eir metab o lis m a nd t h e r ef o r e e x h i bi t di m i ni shed g r o w t h

. Iron Leachate from im poundm ents ha s cause d ele v ated c o nce n trations i n nearby surface water; biota

wi t h el evat e d l e vel s have ex h i bi t e d s ubl et hal effects includi n g m e tabolic changes and

ab norm a l ities o f th e liv er and k i dn eys.

Lead Co n c en tration s in co al co m b ustio n wastewat er are elev ated in itially, b u t lead settles ou t qu ick l y; leachate has ca use d groundwa ter to e x cee d st ate dri nki ng water standard s. Hum a n expos u re to
hi g h c once n t r a t i ons of l ead i n d r i n ki n g wat e r can ca use seri ous d a m a ge t o t h e b r ai n , ki d n e y s ,

ner v ous sy st em , and re d bl o o d cel l s

. Manga nese Coal com busti on waste w ater leachate has ca us e d elevate d c once n trations in nearby groundwate r and s u rface wa ter; biota with elevated le vels ha ve e xhi bited sublethal effec t s including metabolic

chan ges an d a b no rm al it i e s of t h e l i v e r a n d ki dney s

.



### 6-3Final Detailed Study Report Chapter 6 – Environmental Assessment of Coal Combustion Wastewater



### 6-4 Table 6-1. Selected Coal Combustion Wastewater Pollutants

Compound Potential Environmental Concern a,b,c,d

Mercury Biota with elevated levels have exhibite d sublethal effects including metabolic changes and abnormalities of the liver and kidneys; can conv ert 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.

Nitrogen Frequently observed at elevated levels in coal combustion wastewater; may cause eutrophication of aquatic environments.

pH Acidic conditions are often observed in co al 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.

Phosphorus Frequently observed at elevated levels in coal combustion wastewater; may cause eutrophication of aquatic environments.

Selenium Frequently observed at high concentrations in coal combustion wastewater; readily bioaccumulates; elevated concentrations have cau sed fish kills and nume rous sublethal effects (e.g., increased metabolic rates, decreased grow th 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.

Total dissolved

solids High levels are frequently observed in coal co mbustion wastewater; elevated levels can be a stress on aquatic organisms with potential toxic effects; elevated levels can have impacts on agriculture & wetlands.

Zinc 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/saf ewater/contaminants/index.html#mcls ) 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 combus tion wastewater originate from the parent coal used in the combustion process. Th e toxic potential of se lenium is related to its chemical form (i.e., selenite, selenate, elemental selenium) and solubility. Th e predominate forms of selenium in aquatic systems that receive coal combustion wast ewater 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 [NPS, 1997].

Selenium has been tied to fish kills, and to developmental and reproduc tive failure in fish, reptiles, and birds. In a 1991 study, Sorensen found that selenium levels as low as 3-8 μ g/L in aquatic environments can be life- threatening to fish [NPS, 1997]. Selenium has the potential to

bioaccumulate and can be transferred maternall y. As a result, selenium-related environmental impacts can linger for years even after exposure to coal com bustion wastewater has ceased [Rowe et al., 2002]. Aquatic organisms exposed to coal combustion wastew ater have exhibited elevated selenium concentration in organs such as their kidneys, liver, and gonads, resulting in abnormalities that hinder growth and survival [R owe et al., 2002]. In addition to ecologicalFinal 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 of fish consumption advisories in surface waters and the exceedance of selenium MCLs in groundwa ter, 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-n eutral 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 combus tion wastewater impoundme nts [NRC, 2006]. In addition, EPA has documented several damage cas es where arsenic levels exceeded drinking water standards in groundwater near coal com bustion waste management facilities [U.S. EPA, 2007c]. Groundwater contamination of arsenic at these concentr ations 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 tende ncy to bioaccumulate in aquatic communities and potentially impact higher trophic level orga nisms 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 wastew ater are relatively low, mercury is a highly toxic compound that represents an environmental and human health risk even in small concentrations. One of the primar y 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 fi sh and other organisms and is associated with high rates of reproductive failure. Bacteria found in anaerobic condi tions, 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 rate s increase in acidic and anoxic envi ronments 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 oxidati on 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 wa ters have the potential to decrease dissolved oxygen levels and contribute to fish kills in wa ters that receive coal combustion wastewater. BOD levels can also influence the availability an d toxicity of other coal combustion wastewater

6-5Final Detailed Study Report Chapter 6 – Environmental Assessment of Coal Combustion Wastewater



### constituents such as metals. For example, th e 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 vari es depending on the type of coal and the amount of metal oxides present [NRC, 2006]. A lthough 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, c opper, chromium, lead, nickel, a nd zinc, are highly soluble in acidic, or non-neutral, conditi ons [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 ci rculation between blowdow n cycles exhibit high

concentrations of chlorides. Studies have found that coal combustion wastewater leachate reaching groundwater has caused chloride leve ls to exceed secondary MCLs [NRC, 2006].

Chlorides also contribute to th e high total dissolved solids (T DS) 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 dissolv e due to solubility characteristics.

Nutrients

Nutrient concentrations present in coal com bustion 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 co mbustion 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 ai r pollution controls increases. While the current concentration of nitrogen presen t in coal combustion wastewater from any individual power plant is probably relatively low, the total nitrog en load from a single plant can be significant due to large wastewater flow rate s. There are concerns that nu trient impacts could occur on waterbodies receiving discharges from multiple power plants. This is especially a concern on waterbodies that are nutrient impa ired or in watersheds that co ntribute to downstream nutrient problems. Higher nutrient loads from coal-fired power plants could result in the eutrophication of waters receiving coal combus tion wastewater. Eutrophication is the process where excess nutrients stimulate excessive plant and algal gr owth which can lead to declining dissolved oxygen levels.

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### 6.2 Coal Combustion Wastewater Interactions with the Environment

The interaction of a pollutant source with th e 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 human s 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 at tributable to coal combustion wastewater. Table 6-2 summarizes the number of environmental impact ca ses 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) Impacted Water ResourceSurface ImpoundmentLandfillBoth SurfaceImpoundment andLandfillNot IdentifiedSurface WaterGroundwaterBoth Surface Water andGroundwater

34 30 2 4 10 51 9

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 wetla nds acting as attractive nuisances.

The method of exposure plays an important role in determining the potential effects of

coal combustion wastewater on the environmen t. 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 th e environment and how the pollutants interact with the biological community. This section de scribes the three primary methods through which

coal combustion wastewater inte racts with the environment and explores how each route can affect the potential for environmental im pact from coal combustion wastewater.

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### 6.2.1 Discharges to Surface Waters

Coal combustion wastewater is commonly discharged directly to surface waters following treatment in settling ponds. More recen tly, FGD wastewater at some power plants may be treated using advanced wastewater treatmen t systems employing tanks and similar structures (e.g., chemical precipitation or biol ogical treatment systems) prior to discharge to an ash pond or directly to surface water.

One of the primary factors c ontrolling 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 creati on of hot spots in loti c (i.e., actively-moving water) aquatics systems are of particular concer n 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 toxi c substance through food and exposure to the

environment at a faster rate than the substa nce 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, lo cal 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 im pact the environmental effect of coal combustion wastewater on aqua tic organisms and wildlif e and the role that sediments in surface waters play in the persis tence of these effects in aquatic systems.

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### 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 area s of high pollutant

concentrations and ar e 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 c oncentrations of arsenic, cadmium, chromium, copper, and

selenium. In addition to the accumulation of thes e 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 tran sfer 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, beha vior, energetics, and e ndocrinology in local wildlife [Rowe et al. 2002]. In a 1999 study, Hopkins et al. observ ed that water snakes, which fed on fish and amphibians in the areas cont aminated with coal combustion wastes, had accumulated higher arsenic tissue concentratio ns than their prey [Rowe et al., 2002]. 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 arseni c, selenium, and zinc. The observed fish abnormalities were eventually correlated with high selenium whole-bo dy 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 al so observed that despite the reduction in the selenium concentration present in fish ovaries, reproductive abnormalities remained persistent highlighting the long ecologic al recovery times commonly experienced in lentic systems with high pollutant retention

rates and low sedimentation rates such as Belews Lake [Rowe et al., 2002].



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### Lotic Systems

Lotic systems are water bodies with flowing wa ter 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 provi des 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 combus tion wastewater contamination [Rowe et al., 2002]. Although the discharge of coal co mbustion wastewater into a loti c system has the potential to increase the distribution of pollu tants 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 di scharged to a river may encounter areas of slower moving water downstream where pollutant s would fall out of suspension and concentrate in a limited area. These pockets of higher pollu tant 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 elem ents 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 Wi nfield, 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 re ference location. Bluegill fish liver concentrations were higher than the reference location for ar senic, cadmium, copper, chromium, selenium, and zinc demonstrating th at pollutants from the ash pond discharge are accumulating in fish living downstream from th e Amos Plant. Although currently there is a

limited amount of information available on th e 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 aqua tic environments play a major role in the

residence time of coal combusti on wastewater pollutants. Sedime nts 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 Be lews Lake provided toxic doses of sedimentstored 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 le ntic system to continuously expose and reintroduce bioaccumulative pollutants to aquatic organisms. Th ese 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 pollutant s that are released from sediments over time,

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### and the tissue concentrations of aquatic organism s 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 groundw ater systems through leaching from surface impoundments, landfills, and minefills. Coal com bustion wastewater held in unlined surface impoundments can infiltrate through the subsurfa ce and enter the groundwater system. Unlined landfills and minefills, used to di spose 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 co mbustion wastewater can al so enter the groundwater system when liners fail or when a disposal site is inappropriately situated such that natural groundwater fluctuations come into cont act with the disposed-of waste. As Table 6-2 indicates,

EPA has identified 51 instances where coal combustion wastes and wast ewater 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 [Rowe et al., 2002].

Once in the groundwater system, coal com bustion wastewater pollutants have the potential to migrate from the site at concentrat ions 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) an d 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 re actions followed by slower react ions as alkalinity is leached from the residue pile over time [NRC, 2006].

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### The degree of degradation caused by coal combustion wastewater leaching into groundwater systems depends on the type and concentra tion 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. Gr oundwater models that re quire information on the groundwater chemistry, the mass and form of mi neral phases present at the site, and the dominant microbially mediated geochemical reac tions 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 dis posal 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 Washi ngton, Wisconsin, fly ash had been disposed of in a quarry for over 20 years (1943-1971) prior to the selenium and boron contam ination being reported in a down-gradient private drinking wa ter well [U.S. EPA, 2007c]. This suggests that a longer period of groundwater monitoring may be re quired at some sites to adequate ly assess the full release of contaminants, which can occur over several deca des [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 plan ts 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 co ncentrations 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 contaminatio n and included requirements for the companies to restore th e 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].



### 6-12Final Detailed Study Report Chapter 6 – Environmental Assessment of Coal Combustion Wastewater



### hydraulic properties of the subsurface traveli ng long distances before it encounters a drinking water well or discharges as a spring or as seepage into a str eam, 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 e nough 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]. 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 recreationa l fishing due to elevated selenium levels [Duke Energy, 2007]. Selenium levels in the lake fish presented a hum an 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]. 

### 6.3 Types of Environmental Effects

The discharge of coal combusti on wastewater from coal-fired power plants has caused a wide range of environmental e ffects to local aquatic life. St udies have documented numerous ecological impacts from the intent ional and accidental release of coal combustion wastewaters, as well as through detailed la boratory and field studies exam ining the toxicity of the

characteristics of coal combustion wastewat er. Environmental effects documented in the

literature can be broken into th e following three categories:

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### • 

### Lethal effects – fish kills and mortality to other organisms;

• 

### Sublethal effects – histopathological ch anges, or accumulation of trace elements in tissue, and damage to reproductiv e 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 su ch as altering local habitats, contaminating drinking water, and resulting in fish advisories.

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 blow down, 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 dissolv ed 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 wastewaterderived trace elements may also contribute to lethal effects, this case study indicat es that elevated selenium

concentrations from coal combustion wastewater can result in lethal effects, such as fish kills. 

### 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 combus tion wastewater into the reservoir. The sudden appearance of fish kills and other ecological eff ects, such as developmental abnormalities and reproductive failure, in aquatic systems receivi ng coal combustion wastewater prompted numerous research studies to identify the extent of damage and the sp ecific cause. In a 1981 study conducted by Carolina Power and Light Company, En vironmental Serv ices Station at Hyco Reservoir, scientists concluded that elev ated 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 kill s, the affected environments can experience population and community effects for many years be fore biomass returns to normal levels [Rowe et al., 2002].

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### Laboratory and outdoor mesocosm studies have confirmed th at both acute and chronic exposure to coal combustion wastewater can be leth al 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 th e 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 fi sh) 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 a nd others indicate that

the lethal effects of coal combustion wastew ater 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 co mbustion wastewater can vary widely and include changes that impact gr owth, reproduction, and survival of susceptible organisms.

Numerous vertebrate and inverteb rate species have demonstrated a sensitivity to coal combustion wastewater and develope d sublethal conditions such as incr eased metabolic rates, decreased growth rates, abnormal teeth and fin morphology, accumulation of trace elements in tissue, and reproductive failure [Rowe et al., 2002]. Subletha l effects documented in the literature are primarily linked to exposure to selenium concen trations present in coal combustion wastewater; however, sublethal effects have also been attributed to a num ber 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 sample s collected before and after the discharge of

coal combustion wastewater to the Texas Utilit ies 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 repor ted that elevated selenium concentrations persisted in the livers and kidneys of several species of fish 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 th e reservoir exhibited ovary abnormalities related to elevated selenium concentrations up to ei ght years following the br ief exposure to coal combustion wastewater [Rowe et al., 2002]. A lthough the ash pond discharge was short-lived (i.e., eight months), many of the histopathological effects persisted for y ears after the discharge had ceased [Rowe et al., 2002].

Fish are not the only organisms with documen ted 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 me tabolic rate after eigh t months [Rowe et al., 2002]. Similarly, crayfish captured in the vicinity of the secondary basi n as well as crayfish

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### collected from unpolluted sites a nd exposed to sediments and food collected from the secondary basin both experienced increased metabolic rates and decreased gr owth rates. These changes in metabolism reflect that the organism wastes energy during normal metabolic processes in response to contaminant exposure an d accumulation [Rowe et al., 2002].

Exposure to coal combustion wastewater has caused a number of organisms to experience reproductive failure and other forms of di minished 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 pollutant s to offspring has been observed for several species. A 2001 study conducted by Nagl e 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 de veloping 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 com bustion 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 wa stewater [Rowe et al., 2002]. A st udy of larval bullfrogs living in the D-Area Power Facility’s secondary settling basin found that mo re than 95 percent of

individuals had abnormal oral stru ctures, such as the absence of grazing teeth or entire rows of teeth. Rowe et al.’s 1996 study f ound that these oral malformati ons changed the feeding ecology of the affected individuals, lim iting their feeding niche and subs equently reducing their growth rate [Rowe et al., 2002]. A 1998 study by Raimondo et al. found that larv al bullfrogs also displayed abnormal swimming behavior, which was caused by malformations of their tails [Rowe et al., 2002]. These abnormal larval bullfro gs, living in the sec ondary basin of the DArea, were more frequently preyed upon than were bullfrogs from an un polluted 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 pote ntial to modify higher-order ecol ogical processes (i.e., population and community dynamics) in the surrounding ecosyst ems. Changes to the number of aquatic organisms and wildlife present in a system, intersp ecies interactions, and th e structure of aquatic

communities have all been linked to contaminat ion of aquatic habitats by coal combustion wastewater [Rowe et al., 2002].

Numerous studies have documented the declin e in invertebrates, fi sh, and local wildlife populations following exposure to coal combusti on wastewater [Rowe et al., 2002]. Population effects (i.e., decline in number of organisms present) have been at tributed to lethal effects of pollutants present in coal combustion wastewater , declines in organism survival rates from

abnormalities attributed to coal combustion wastew ater exposure, and declines in the abundance or quality of prey. For example, many species of benthic fish rely on sm all invertebrates as a

6-16Final Detailed Study Report Chapter 6 – Environmental Assessment of Coal Combustion Wastewater



### source of food and, when the food source is dimini shed (i.e., lower inve rtebrate abundance and density), benthic fish exhibit highe r mortality rates and smaller growth than fish exposed to coal

combustion wastewater with hi gh 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 wa stewater. Benthic invertebrates, which graze on detrital material, displayed a lowe r population density as a result. Similarly, benthic fish that prey upon small invertebrates exhibited increase d mortality due to a re duction in available resources, and therefore a decreased population density [Rowe et al., 2002].

In addition to density effects, communities have experienced a lterations 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 bi omass [Rowe et al., 2002]. A study by Garrett and Inman in 1984 found that in the three ye ars after the effluent release was ha lted, planktivorous fish populations remained extremely low, while carnivorous fish populations nearly recovered. This recovery

occurred because carnivorous fish have a more diverse diet than plan ktivorous fish, so food availability increased relatively quickly as th e aquatic system recove red [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 predat ors of the food chain. In 1993, a study conducted by Lemly at Belews Lake found that la rge 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 geographicall y. A 1972 study by Cairns et al. examined the effects of an ash effluent spill from the AEP Clin ch River Power Plant into the Clinch River in Virginia. A dike surrounding an ash settling pond co llapsed, releasing efflue nt 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 organism s [Carlson and Adriano, 1993]. A follow-up survey taken two years after the spill indi cated 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 groundw ater, which have resulted in fish advisories and groundwater that has exceeded SDWA MCLs.

6-17Final Detailed Study Report Chapter 6 – Environmental Assessment of Coal Combustion Wastewater



### 6-18 Metals and other pollutants present in coal combustion wastewater may contaminate actual or potential drinking water sources by l eaching 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 we lls turned green and testing revealed the wells

were contaminated with selenium and sulfate from groundwater contaminat ed with leachate from coal combustion wastewater [NRC, 2006]. EPA closed the residential wells to reduce the risk of human exposure to coal combustion polluta nts [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 sour ce in all cases, the contamination represents a possi ble human health risk due to the potential for groundwater to impact other nearby aquifers and surface wate rs designated as drinking water sources.

EPA has also identified cases of human h ealth concerns related to coal combustion wastewater causing elevated polluta nt concentrations in biota. Fi sh 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 sett ling ponds, which was the likely source of high selenium levels. In response to these elevated levels, the Texas Commissi oner of Health issued a fish advisory that lasted fo r 12 years before it was lifted. A similar case identified by EPA occurred in the Brandy Branch Reservoir in Mars hall, Texas. The cooling reservoir received ash pond effluent from Southwestern Electric Powe r 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, on ce coal combustion wastewater discharges began [U.S. EPA, 2007c]. The Texas Depa rtment of Health issued a fish consumption advisory that lasted from 1992 to 2004 [U.S. EPA, 2007c].Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### 7. P RELIMINARY 

### I NVESTIGATION OF 

### O THER 

### I NDUSTRY 

### S EGMENTS



### As described in Chapter 3, the electric generating industry is generally categorized by NAICS Code 2211. However, prior to the introduc tion of NAICS codes, the electric generating industry had been categorized by three Standa rd Industrial Classifi cation (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 combinat ion 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 el ectric, 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 genera te electricity (e.g., combustion turbines, hydroelectric plants). However, during the detail ed 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 th e effluent guidelines. EPA assessed information regarding the fo llowing types of plants and operations:

• 

### Plants that generate electric power usi ng steam to drive a turbine, but whose energy/heat source used to produce the st eam is not a fossil or nuclear fuel (referred to in this report as “alternat ive-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 distri buting and/or selling that electric power (referred to in this report as “industr ial non-utilities”). Th ese industrial steam electric non-utilities provid e electric power to an indus trial process (e.g., chemical manufacturing, petroleum refi ning) 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 distributi on and/or sale, but that do not primarily use that steam to drive a turbine and pr oduce electric power (referred to in this report as “steam and air c onditioning supply” plants).

7-1Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### • 

### Plants that provide a combination of elect ric power and other utility services (i.e.,

SIC Code 4939 - referred to in this report as “combination utilities”). EPA specifically focused on those combination u tilities that generate electric power by using steam to drive a turbine.

This chapter describes the information EP A obtained during the detailed study regarding these types of operations and resulting wastewat ers. 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 altern ative-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 pro cesses. In this report, alterna tive-fueled steam electric plants refer to those plants that produ ce steam by combusting a solid or gaseous alternative fuel, those that use steam from geothermal reservoirs (geo thermal steam electric plants), and those that produce steam using the sun’s energy (solar steam electric plants).

EPA reviewed NPDES permits for a prioritized s ubset of alternative-fueled steam electric plants to identify sources of wa stewater and determine how wast ewater 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 alterna tive-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 Generatin g effluent guidelines, be cause the electricity does not result “...primarily from a process utilizing fo ssil-type fuel (coal, oil, or gas) or nuclear fuel...”, as defined at 40 CFR Part 423.10. Inform ation that EPA obtaine d during the detailed study indicate that these alternat ive-fueled plants use similar processes to plants that are regulated under the Steam Electric Power Generati ng effluent guidelines. In fact, many of these alternative-fueled plants also combust fossil fuel s as a secondary energy source to generate the steam (40 percent of plants), typically within the same generating unit a nd 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 wast es (e.g., ash transport water), the characteristics of the wastewaters may vary de pending on the type of fuel used by the plant.

During the detailed study, EPA collected l ittle 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 am ount of wastewater to the environment than steam electric plants regulated by the Steam Elect ric Power Generating effluent guidelines. EPA also determined that permits regulating the discharges from alternative-fueled plants vary from plant to plant and are depende nt on both the type of fuel used and the handling of the wastewaters generated. EPA found that some of th e permits reviewed contained few limits based on the Steam Electric Power Generating effluent gui delines, while others wholly incorporate the Steam Electric Power Generating effluent guidelines limits.

7-2Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### 7.1.1 Demographic Data for Alternativ e-fueled Steam Electric Plants

The 2005 EIA database includes 198 plants that reported a NAICS c ode 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 burn ing a fossil fuel as a primary energy source, in addition to the electric generati ng unit(s) burning alterna tive fuels. Seventy-six of the 198 plants reported using both an alternat ive fuel and a fossil fuel to power the same generator (the fossil fuel is re ported as the secondary or tertia ry energy source); however, these secondary fossil fuel energy sources may be servi ng 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 alternativefueled plants produce less than one percent of th e electricity produced by the fossil- and nuclearfueled steam electric plants currently regulated by the Steam Electric Power Generating effluent guidelines. EPA did not in clude geothermal steam electric plants in this calculation because they are assumed not to directly discharge wast ewater [CEPA, 2006d; CEPA, 2006c; U.S. DOE, 2006a]. Table 7-1 presents a breakdown of plant ener gy capacity by fuel type. Section 3.1.2.2 of this report provides additional detail on the de mographics of the Steam Electric Power Generating Point Source Category.

EPA is not aware of any analyses demonstrati ng that pollutant loadi ngs are correlated to electric power generated; however, EPA believes it is reasonable to assume that alternativefueled 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 Electri c Fuel Types and Processes

The steam electric generating process used at al ternative-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 thermodynami c medium to produce electricity. Alternativefueled steam electric plants use steam (which ma y or may not be produced in a boiler) to drive a steam turbine/electric ge nerator 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 Powe r Generating effluent guidelines, they may generate many of the same types of wastewat ers (e.g., ash transport water, boiler blowdown, cooling water). Because there are similar operati ons between the different types of plants, the wastewaters that do not directly contact the fu el (i.e., boiler blowdown, cooling water) may have similar pollutant characteristics. Because these wa stewaters are not associat ed with the fuels used at the plant, they are likely to be similar in characteristics to the wa stewaters generated by the steam electric plants regulated under the Steam Electric Power Generati ng effluent guidelines.

The wastewaters that do contact the fuel (e.g., fuel storage runo ff) or the fuel wastes (ash transport water) may not have similar character istics as the wastewaters generated by steam electric plants regulated under the Steam Electric Power Generati ng effluent guidelines because

the different fuels have different constituents.

7-3Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### Table 7-1. Summary of Alternative-Fueled St eam 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 59 2,270

Wood Solid Waste 66 1,830

Solar 9 400

Landfill Gas 12 261

Agricultural By-products 5 184

Other Biomass Solids 2 58

Tires 2 57

Other Biomass Gas 1 23

Total for Alternative-Fu eled Facilities (excluding Geothermal) 156 b 5,080

Geothermal c 42 2,950

Source: [U.S. DOE, 2005a]. Note: The table includes only the ca pacity associated with stand-alone steam turbines , combined cycle steam turbines, combined cycle sing le shaft turbines, and combin ed 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 wast ewater, potential wastewater pollutants,current operating practices, and current permitting practices for various types of alternativefueled steam electric plants are discussed below by type of fuel.

7.1.2.1 Solid Fuels

Steam electric plants fueled by solid alternat ive fuels (e.g., municipal solid waste (MSW), wood solid waste, agricultural by-products, tires) us e a similar process as those plants that are currently regulated under the Steam Electric Power Generating efflue nt guidelines. These alternative-fueled steam electric plants combus t a solid fuel, typically in a boiler, to produce steam, which powers a steam turbine/electric gene rator. This combustion process generates ash. The steam exiting the turbine is co ndensed with cooling water and the condensate is typically fed back to the boiler. Thus, steam electric plants fu eled by solid alternative fuels generate some of the same types of wastewaters as those curr ently regulated under the Steam Electric Power Generating effluent guidelines. As described in Section 3.2.1, thes e wastewaters include fly ash and/or bottom ash transport wa ter, metal cleaning wastes, onc e-through cooling water and/or recirculating cooling tower blowdown, fuel stor age 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].

7-4Final Detailed Study Report 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 te xtiles. 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 Electri c Power Generating effl uent guidelines, EPA identified one steam electric plant in the United St ates 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 soli d waste in 2005 [U.S. DOE, 2005a]. The 1974 Development Document stated that incinera ting “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 com positions of these ashes vary significantly depending on the type of material that is combus ted and the location that the ash is sampled (e.g., fly ash, bottom ash), EPA noted general di fferences 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 ba rium, cadmium, mercury, molybdenum, nickel, selenium, and zinc than coal ash.

Table 7-2. Comparison of Available Coal As h, Municipal Solid Waste Ash, and Wood Ash Composition Data

Component Coal Ash (ppm) Municipal Solid Waste Ash (ppm) Wood Ash (ppm)

Aluminum 60,000 - 157,000 NIA NIA

Antimony NIA NIA 9 - 11.58

Arsenic 10.4 - 169.6 2.9 - 50 1 - 28.5

Barium 210 - 310 79 - 2,700 130 - 527

Beryllium NIA ND - 2.4 ND - 2

Boron 14 - 618 24 - 174 1 - 16.9

Cadmium 7 - 10 0.18 - 100 1 - 16

Calcium 3,100 - 125,600 NIA NIA

Chloride NIA NIA 382.35 – 3,200

Chromium (III) NIA NIA 43

Chromium (VI) NIA NIA 0.7 - 4

Chromium - Total NIA 12 - 1,500 16.8 - 33.55

Cobalt NIA 1.7 - 91 4.6 - 20

Copper NIA 40 - 5,900 31.3 - 176.5

Cyanide NIA NIA 0.08 - 6



### 7-5Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### 7-6 Table 7-2. Comparison of Available Coal As h, Municipal Solid Waste Ash, and Wood Ash Composition Data

Component Coal Ash (ppm) Municipal Solid Waste Ash (ppm) Wood Ash (ppm)

Iron 3,000 - 163,000 NIA NIA

Lead NIA 31 - 36,600 7.7 - 142.5

Magnesium 900 - 60,200 700 - 16,000 NIA

Manganese NIA 14 - 3,130 NIA

Mercury ND - 0.08 0.05 - 17.5 ND - 0.6

Molybdenum 5.6 - 39.3 2.4 - 290 3.0 - 14

Nickel 123 - 242 13 - 12,910 11 - 50

Phosphorus 300 - 2,800 NIA NIA

Potassium 6,500 - 31,900 NIA 23,220 - 59,918

Selenium 7.6 - 36.1 0.1 - 50 ND - 20

Silicon 302,000 - 331,000 NIA NIA

Silver NIA NIA ND

- 4

Sodium 560 - 1,200 NIA 934.25 - 3,110

Strontium NIA 12 - 640 NIA

Thallium NIA NIA ND

- 70.5

Titanium 7,700 - 11,600 NIA NIA

Vanadium NIA NIA 22 - 27

Zinc 13 - 378 92 - 46,000 130 - 886

Source: [Evangelou, 1996; Otero-Rey, 2003; Narukawa, 2003; Kirk-Othmer, 2000; CEPA, 2006b; WAI, 2003].

ND - Not detected.

NIA – No information available.



### To obtain additional information about the pr ocess operations and wastewaters generated from MSW plants, EPA reviewed EIA informati on and contacted two companies that operate MSW plants. According to information EPA obtai ned from EIA and these two companies, most of these plants operate dry FGD systems and bagh ouses 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 ba ghouse or ESP are handled dry and transported to a landfill. The bottom ash aggregate generated in the boiler is qu enched in a water bath, which is drained, and the quenched aggregate then goes through the meta l 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 discha rge FGD or ash transpor t water waste streams. Additionally, some of the other wastewaters ge nerated during the proc ess (e.g., boiler blowdown, cooling tower blowdown, low-volum e wastewaters) are often reus ed as make-up water for the bottom ash quench process or discharged indirect ly 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 Powe r Generating effluent guidelines [Covanta, 2009; Xcel Energy, 2009c; Xcel Energy, 2009d].Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### Wood Solid Waste

Wood wastes combusted in steam electric proc esses typically consist of chipped lumber and residuals from sawmills or other forest industry operations, including bark, trim ends, sawdust, and planer shav ings [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 di fferences between wood ash and coal ash. Wood ash generally has a lower metal conten t (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 pr ocess 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 remo ve the fly ash, sulfur dioxide, and hydrogen chloride from the flue gas. The particulates that collect in the ba ghouse 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 solid s and reused in the process. Therefore, these types of plants do not generate and/or discharg e any FGD or ash transport water waste streams. The wastewaters that are typically discharged from these plants, indi rectly to municipal wastewater treatment plants in some cases , consist of cooling tower blowdown, boiler blowdown, wash waters associated with opera tion 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 com busted in steam electric processes include bagasse (plant residue) from sugar-refining operati ons, rice hulls, orchard and vineyard prunings, cotton gin trash, and the by-products of ma ny other food and fiber-producing operations. Agricultural wastes are relatively low in meta ls 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 electri c 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 r oughly 25 percent more energy th an coal, by weight. The ash

residues from tire-derived fuel may contain lower heavy metals content than some coals [U.S. EPA, 2006i].

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 natura l gas or other gases and are currently regulated under the Steam Electric Power Generating effluent guidelines. These alternative-fueled steam

7-7Final 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 ge nerate 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 gase ous alternative fuels generate some of the same types of wastewaters as those currently regulated under the Steam Electric Powe r Generating effluent guidelines and described in Section 3.2.1 (e.g., boiler blowdown, cooli ng tower blowdown, lowvolume wastewaters).

Landfill gas, by volume, consists of approxi mately 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 organi c matter. This gas mixture can be captured and processed for use as fuel in steam electric plan ts. During processing, a por tion of the nonmethane components is typically removed fr om landfill gas, which results in a fuel with a higher heating value [U.S. EPA, 2006g; CEC, 2006]. A steam electric plant fueled with landf ill 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 prim arily of methane) and overall process [PDEP, 2006]. Because these gaseous fuel operations do not generate wastewaters that contac t the fuel or fuel wastes like the solid-fueled plants, these plants typical ly only generate wastewaters such as boiler blowdown, cooling water, and other low-volume wa stewaters. These wastewaters generally are expected to have similar characteristics as the wastewaters generated from the plants regulated

under the Steam Electric Power Ge nerating effluent guidelines.

7.1.2.3 Geothermal

In the geothermal steam electric process, geot hermal 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 turb ines is condensed with cooling water and the condensate is injected into the geothermal reserv oir. Geothermal steam el ectric plants generate

steam condensate wastewater and condenser cool ing wastes (typically co oling tower blowdown) [CEPA, 2006d].

EPA addressed geothermal electric generation in deve loping 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 [CEPA, 2006d; CE PA, 2006c]. These plants inject wastewater underground into the geothermal steamfield re servoirs for two major reasons [CEPA, 2006d; CEPA, 2006c; U.S. DOE, 2006a]. Firs t, injecting water in to 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 pro cess 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 [CEPA, 2006d; CEPA, 2006c].

7-8Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### 7.1.2.4 Solar

Solar electric generating plants concentrat e sunlight onto receivers using various reflecting devices. Heat transfer fluid is heated as it flows thro ugh the receivers and is used to create steam, which, in turn, is used to create el ectricity in steam turbines/generators. Most solar electric plants that use parabolic trough reflect ors to concentrate sunlight (such as the Solar Electric Generating Stations plan ts in the Mojave Desert, CA) generate cooling water, boiler blowdown, and demineralizer wastewater. These wa stewaters are typically transferred to an evaporation pond and are not discharged to su rface 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 genera ting plants at that time were developmental; however, EPA acknowledge d 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 of NPDES 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 type s 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 tr ends in the regulation of wastewaters based on alternative fuel type; however, EPA was able to make some general obser vations about the types of wastewaters generated at thes e 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 guide lines. In each of these cases, the process wastewaters are not discharged directly to surf ace waters, whereas direct discharge of these wastewaters is the typical pr actice for plants regulated under the Steam Electric Power Generating effluent guidelines. Sp ecific 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 ma y 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 incorpor ate the requirements of the Steam Electric Power Generating effluent guidelines. These permits are unique in that the plants use a fossil fuel

7-9Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### 7-10 in addition to the alternative fuel to generate el ectricity, or the permit onl y specifies the use of a fossil fuel. In at least one of these cases, th e fossil-fueled steam electric wastewaters have separate limits than the alternativ e-fueled steam electric wastewaters.

7.2 Industrial Non-Utilities

This section describes EPA’s review of plan ts within various indus trial sector s operating steam electric generators that produce electricity and/or therma l output primarily to support the activities performed at the plant. These industrial non-utilities include cogenerators 26 

### , small power plants, and other non-utilit y generators, and generally do not produce electric power for

distribution and/or sale.

EPA reviewed NPDES permits for a prioritized subset of industri al non-utilities to identify sources of wastewater generated from steam electric processes and determine how the wastewater discharges from th ese operations are currently regul ated (e.g., whether the Steam Electric Power Generating effluent guidelines are applied as BP J). Additionally, EPA contacted several companies operating electri c generating units at their indus trial plants to discuss the operations and wastewaters generated from the pl ant 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 gene rate steam that is in turn used (at least in part) to drive an electric generator or turbine. Finally, the st eam 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 processe s are similar, EPA exp ects that industrial nonutilities generate wastewater from the same so urces as do steam electri c plants regulated under

the Steam Electric Power Gene rating effluent guidelines.

Wastewater generated by the st eam electric processes at i ndustrial non-ut ilities is not currently regulated by the Steam Electric Powe r Generating effluent guidelines, because the plants are not “...primarily engaged in the gene ration of electricity fo r distribution and sale ...” With the exception of certain instances (e.g., certain subcateg ories of the Pulp, Paper and Paperboard effluent guidelines ; see 40 CFR Part 430.01(m)), steam electric wastewaters from

industrial non-utilities ar e not directly regulated by effluent guidelines. Information that EPA obtained during the detailed st udy indicate that industrial plan ts 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 typi cally smaller than those at plants regulated under the Steam Electric Power Generating effluent guide lines. Additionally, the industrial non-utilities burning coal as the primary fuel s ource typically burn significantly less

coal than the coal-fired st eam electric plants regulated under the Steam Electric Power Generating effluent guidelines. Be cause 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, comm ercial, heating, or cooling purposes” [U.S. DOE, 2006b].Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### plants associated with electric ity generation is likely to be le ss than that discharged by steam electric plants regulated under the Steam El ectric Power Generating effluent guidelines.

The information collected during the detailed study indicates that mo st 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 co mmingled wastewaters typically have permit limits based on the industry-specific effluent guidelines; the Steam Electric Power Generating effluent guidelines limits are typicall y not used to set BPJ-based limits.

7.2.1 Overview of Industrial Non-Utilities

EPA identified industrial non-utilities for th is detailed study through data collected in 2005 by EIA. Industrial plants that operate an electric power gene rator 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-u tilities, as well as the types of fuels used by i ndustrial non-utilities to generate the steam. EPA also performed a more deta iled analysis of the EIA data for the subset

of industrial non-utilities that use fossil fu els to power a steam generator. Section 7.2.2 summarizes the available demographic data fo r fossil-fueled, steam electric industrial nonutilities.

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 plan ts 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 nuclearpowered industrial non-utilities were re ported to EIA in 2005.

For comparison, only 10 percent of steam el ectric plants regulated under the Steam Electric Power Generating effluent guidelines each produce less th an 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 Electri c Power Generating e ffluent guidelines.

Industrial non-utilities may be fu eled 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-u tilities are often derived from a by-product of the primary industrial pr ocess. These non-utilities may also use a combination of fossil and non-fossil fuels to pow er 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;

7-11Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### 7-12 • 

### Municipal Solid Waste;

• 

### Other Biomass Gases (e.g., digester gas, methane);

• 

### Other Biomass Solids (e.g., animal ma nure 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, sl udge wood, spent sulf ite liquor); and

• 

### Wood and Wood Waste Solids (e.g., paper pell ets, railroad ties, utility poles, wood chips).

In 2005, 160 steam electric industrial non-utilitie s 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 primar y fuels for steam electric power generation by industrial non-utilities [U.S. DOE, 2005a].

As previously mentioned, it is not uncomm on 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 genera ting unit. For example, several industrial nonutilities that reported using natu ral gas as the primary fuel also reported using black liquor and other gases as alternates, as di d several coal-burning industrial non- utilities. In addition, several of the 160 primarily non-fossil-fuel ed industrial non-utilities reporte d using coal, oil, or natural gas as alternate fuels for the steam el ectric generating unit [U.S. DOE, 2005a].

7.2.2 Demographic Data for Fossil-Fuel ed 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 – Utilities 27 

### . Similar to the analysis of the steam electric plants regulated by the Steam Electric Po wer 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 demogra phic profile for steam electric industrial nonutilities. EPA identified the subset of industrial non-util ities in the EIA database that are fossilfueled 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 th an 22, EPA estimates that 314 fossil-fueled, steam-electric, industrial non-util ities reported to EIA in 2005. Th ese plants are estimated to operate 813 stand-alone steam genera tors or combined cycle systems 28 

### , which have a total steam or combined cycle turbine electr ic generating capacity of 19,393 MW 29 

### [U.S. DOE, 2005a]. The total steam or combined cycle tu rbine electric generati ng capacity for all indus trial 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 indu strial 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 co mbined cycle system of electric power generation.

29 The total steam or combined cycle electric generating capacity includes cap acity associated with stand-alone steam turbines, combined cycle steam turbines, combined cycle single sh aft turbines, and combined cycle

combustion turbines.Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### 7-13 industrial non-utility cap acity is associated with fossil fu els. The industrial non-utility steam turbine electric generating capacity, including fo ssil and non-fossil fuels, is less than four

percent 30 

### 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 indus trial non-utilities is necessarily used to generate electricity, EPA compared the amount of coal burned by the coal -fired industrial nonutilities to the amount of coal burned by coal-fired steam el ectric plants regulated under the Steam Electric Power Generating effluent guid elines. 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 burn ed by a steam electric plant regulated under

the Steam Electric Power Genera ting effluent guidelines is 2, 155,000 tons per year (median is 1,221,000 tons) [U.S. DOE, 2005b]. Based on these num bers, EPA expects that the amount of wastewater generated by the indus trial non-utilities associated with the steam electric process operations is substantially less th an that generated by steam elect ric plants regulated under the Steam Electric Power Generating effluent guidelines.

Table 7-3 summarizes the industries that reported industrial non-util ities to EIA in 2005, the number of plants, and the number of fossil fuel-burning steam electric generating units. The top five industries reporting ope ration of steam electric generati ng 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 estim ated 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 i ndustrial non-utilities reported to EIA) [U.S. DOE, 2005a]. The remainde r of this section presents more detailed demographic information for these five industries.

30 EPA estimates that the total steam electric generating capa city of the steam electric i ndustry 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].Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### Table 7-3. Summary of Fossil-Fueled, St eam 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 Electri c Industrial Non-Utilities

325 - Chemical Manufacturing 55 129 7,535

322 - Paper Manufacturing 81 169 3,348

324 - Petroleum and Coal Products Manufacturing 29 69 2,571

331 - Primary Metal Manufacturing 18 53 2,383

311 - Food Manufacturing 38 80 1,127

Total for Top 5 Industries, by Capacity (Percentage of

Total Fossil-Fueled Indu strial Non-Utilities) 221 (70%) 500 (71%) 16,963 (87%)

611 - Educational Services 33 75 770

314 - Textile Product Mills 6 15 325

211 - Oil and Gas Extraction 8 12 261

212 - Mining (Except Oil and Gas) 3 6 238

3345 - Navigational, Measur ement, Electromedical, and Control Instruments Manufacturing 1 11 200

92 - Public Administration 5 15 96

339 - Miscellaneous Manufacturing 2 8 90.7

327 - Nonmetallic Mineral Product Manufacturing 4 10 83.3

622 - Hospitals 9 16 83.2

336 - Transportation Equipment Manufacturing 2 4 64.5

221 - Utilities c 3 7 43.9

326 - Plastics and Rubber Products Manufacturing 1 4 40

481 - Air Transportation 1 1 31

333 - Machinery Manufacturing 2 7 24

3122 - Tobacco Manufacturing 2 3 20.6

321 - Wood Product Manufacturing 3 3 14.8

332 - Fabricated Metal Product Manufacturing 1 2 12.5

521 - Monetary Authorities - Central Bank 1 2 12

814 - Private Households 1 1 6

514 - Information Services and Data Processing Services 1 1 4.7

482 - Rail Transportation 1 2 4

561 - Administrative and Support Services 1 1 2.3



### 7-14Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### 7-15 Table 7-3. Summary of Fossil-Fueled, St eam 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

624 - Social Assistance 1 2 2

562212 - Solid Waste Landfill 1 1 1

Total Fossil-Fueled Industrial Non-Utilities 314 709 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 cycl e systems by adding the number of combined cycle steam turbines and the number of combined cycle single shaft turbines. Ty pically there are multiple combustion turbines to a single steam turbine in a combin ed cycle system; therefore, EPA believes this methodology is a better representation of the number of combined cycl e systems than simply adding the number of combined cycle combustion and steam turbines. b – The table includes stand-alone steam turbines, combin ed cycle steam turbines, co mbined cycle single shaft turbines, and combined cy cle 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 plan ts. 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 wi thin each of the top five industries. The table presents the numbers of plants and electric generating un its 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 st eam 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 pr oducts manufacturing i ndustries, 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 prelim inary 2006 effluent guidelines program plan

from the American Petroleum Ins titute (API) indicate that most pe troleum refineries use natural gas or residual gases from the re finery 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 combin ed cycle systems, but they are considered to be cogenerators (i.e., steam is produced both to po wer a generator and to us e in other operations).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 Plants a 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 264 (84%) 625 (88%) 10,378 (54%)

Combined Cycle System 102 (32%) 84 (12%) 9,015 (46%)

Total 314 709 19,393

NAICS 325 – Chemical Manufacturing

Stand-Alone Steam Turbine 41 97 1,579

Combined Cycle System 28 32 5,955

Total 55 129 7,535

NAICS 322 – Paper Manufacturing

Stand-Alone Steam Turbine 78 164 3,107

Combined Cycle System 8 5 241

Total 81 169 3,348

NAICS 324 – Petroleum and Coal Products Manufacturing

Stand-Alone Steam Turbine 21 50 756

Combined Cycle System 18 19 1,815

Total 29 69 2,571

NAICS 331 – Primary Metal Manufacturing

Stand-Alone Steam Turbine 18 53 2,383

Combined Cycle System 0 0 0

Total 18 53 2,383

NAICS 311 – Food Manufacturing

Stand-Alone Steam Turbine 36 78 1,108

Combined Cycle System 4 2 18.7

Total 38 80 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 cycl e systems by adding the number of combined cycle steam turbines and the number of combined cycle single shaft turbines. Ty pically there are multiple combustion turbines to a single steam turbine in a combin ed cycle system; therefore, EPA believes this methodology is a better representation of the number of combined cycl e systems than simply adding the number of combined cycle combustion and steam turbines. c – The table includes stand-alone steam turbines, combin ed cycle steam turbines, co mbined cycle single shaft turbines, and combined cy cle combustion turbines.



### 7-16Final 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 fu els used by industrial non-utilities by electric generating capacity, spec ifically broken out for the to p five industries. The 2005 EIA

data demonstrate that fossil-fueled industria l 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 repo rted using coal, while most petroleum and coal products manufacturing non-utilities report ed using natural/other gas [U.S . DOE, 2005a]. These trends coincide with the predominant types of genera tors used in these i ndustries (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 Indu strial Non-Utilities

Coal: 132 (42%) 337 (48%) 6,651 (34%)

Anthracite Coal, Bituminous Coal (BIT) 104 275 5,077

Subbituminous Coal (SUB) 25 57 1,142

Lignite Coal (LIG) 2 4 365

Waste Coal (WC) 1 1 67

Petroleum Coke (PC) 4 (1%) 6 (1%) 197 (1%)

Oil: 29 (9%) 50 (7%) 395 (2%)

Residual Fuel Oil (RFO) 26 45 367

Distillate Fuel Oil (DFO) 2 4 20

Waste/Other Oil (WO) 1 1 8

Natural/Other Gas: 155 (49%) 316 (44%) 12,150 (63%)

Natural Gas (NG) 125 241 10,663

Blast Furnace Gas (BFG) 9 28 834

Other Gas (OG) 21 47 654

Total 314 709 19,393

NAICS 325 – Chemical Manufacturing

Coal (BIT, LIG, and SUB) 18 56 1,116

Petroleum Coke (PC) 1 2 46

Oil (DFO and WO) 2 4 27

Natural/Other Gas (NG and OG) 35 67 6,346

Total 55 129 7,535



### 7-17Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### 7-18 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) 38 88 1,871

Petroleum Coke (PC) 1 2 90

Oil (RFO) 14 21 250

Natural/Other Gas (NG) 29 58 1,137

Total 81 169 3,348

NAICS 324 – Petroleum and Coal Products Manufacturing

Petroleum Coke (PC) 2 2 61

Oil (RFO) 1 1 0.4

Natural/Other Gas (NG and OG) 27 66 2,509

Total 29 69 2,571

NAICS 331 – Primary Metal Manufacturing

Coal (BIT, LIG and SUB) 5 12 1,410

Natural/Other Gas (BFG, NG, and OG) 13 41 973

Total 18 53 2,383

NAICS 311- Food Manufacturing

Coal (BIT and SUB) 30 63 1,056

Oil (RFO) 1 2 8

Natural/Other Gas (NG) 7 15 63

Total 38 80 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 un its utilizing differing fuel types, the number of plants by fuel type is not additive. EPA estimates there are 31 4 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 cycl e systems by adding the number of combined cycle steam turbines and the number of combined cycle single shaft turbines. Ty pically there are multiple combustion turbines to a single steam turbine in a combin ed cycle system; therefore, EPA believes this methodology is a better representation of the number of combined cycl e 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 tu rbines, combined cycle steam turbines, combined cycle single shaf t turbines, and combined cycle combustion turbines.



### 7.2.3 Review of Industrial Non-Utility Discharge Permits

EPA reviewed NPDES permits for 28 industr ial plants operati ng a steam electric industrial non-utility on site to de termine 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 aFinal 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 plan ts within these industries rarely provide enough detail about the plant waste streams to id entify the steam electric process wastewaters; however, some permits generally described waste streams that could incl ude the steam electric

waste streams or waste streams from other on- site operations (e.g., “co oling water,” “boiler blowdown”). The final effluent wastewaters from industrial site s are commingled with all plant wastewater at the point of disc harge, if not upstream; therefore, the steam electric wastewaters are typically commingled with the other plant wastewaters.

The 28 plants are covered by seven existing i ndustrial point source effluent guidelines. EPA determined that wastewaters discharged from these industrial sites are often regulated only by the effluent guidelines for the primary industr ial 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 Powe r Generating effluent guidelines limits. Additionally, the Steam Electri c 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 existi ng effluent guidelines (i.e., Iron and Steel Manufacturing, Petroleum Refining, and Pulp, Pape r & Paperboard Point Source Categories) to

determine whether the waste streams from the steam electric operations were considered in developing the final effluent li mitations. The Pulp, Paper & Paperboard effluent guidelines (40 CFR Part 430) specifically define Part 430-regulate d process wastewater (i n certain subparts) as including wastewaters generate d by co-located non-utility po wer plants (see 40 CFR Part 430.01(m)).

Comments received on the preliminary 2006 effl uent guidelines program plan from API stated that petroleum refinery steam electric ge nerating units primarily ge nerate wastewater from boiler and cooling tower blowdown and demineralizer streams that are typically permitted as low-contaminant streams (i.e., streams containi ng low concentrations of toxics, oxygen demand, and nonconventional pollutants). API also comme nted that these streams possess the same

wastewater characteristics as th e petroleum refining wastewater wi th which they are commingled prior to discharge [API, 2005]. On the prelimin ary 2008 effluent guidelines program plan, the American Chemistry Council provided similar commen ts stating that the wa stewaters 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 efflue nt guidelines were de veloped incorporating wastewaters from on-site steam electric power pl ants, this is not the case for all industrial effluent guidelines. For example, the Iron and Steel effluent guideli nes (40 CFR Part 420) identify that wastewaters from the operation of steam electric gene rating units may be discharged

7-19Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### and are identified as non-process wastewaters; howe ver, the effluent guideline does not set limits for these non-process wastewaters nor incorpor ate them into the effl uent guideline limits.

In many cases, the primary industry effluent guidelines (or the permit for the industrial plant discharge) either does not address or co ntains a less stringent limit for the pollutants included in the Steam Electric Power Generating effluent guidelines. For example, the Pulp, Paper, & Paperboard effluent guidelines, whic h include wastewaters ge nerated from on-site power plants, do not currently re gulate 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 colocate d at their industrial plants. EP A contacted these companies to determine the types of fuels used, proce ss 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 comp any 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 opera tes similarly to some coal-fired power plants regulated under the Steam Electric Power Gene rating 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 disc harged to surface water and this discharge is required to comply with the Steam Electric Powe r Generating effluent guidelines limits [Alcoa, 2009].

The food manufacturing company that EPA contacted operates eight plants with coalfired electric generating units. EPA only discussed the operation of one of the plants with the company; however, the contact stated that the op erations at the other seven plants are similar. The plant discussed does not operate any wet FGD systems. Additiona lly, both the bottom ash and fly ash are collected using dry handling pr actices. 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 c ontacted 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 proc ess. 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 syst ems; 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 wate rs. 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 sl udge treatment [International Paper, 2009].

7-20Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### 7-21 The petroleum refining company that EPA cont acted operates three refineries that have electric generating units on site. These units burn gases that ar e 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 t hose gases. The wastewaters generated from the steam electric generating units are cooling towe r blowdown, boiler blowdo wn, and process area

wash waters. These wastewaters are treated in th e plants’ wastewater treatment systems, which typically consist of oil/water se parators, an activated sludge biol ogical 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 we t bottom ash to a sand filter and the filtrate is transferred to the plant’s wastewat er treatment facility. Both plan ts generate coal pile runoff, boiler blowdown, and cooling to wer blowdown waste streams. Th e coal pile runoff is sent through a settling treatment system prior to disc harge. 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 disc harge [Vasavada, 2009].

7.3 Steam and Air Conditioning Supply Plants

As part of the detailed study, EPA reviewed da ta from other industry segments that may have similar operations to steam electric plan ts, but are not currently subject to the Steam Electric Power Generating effluent guidelines. These industry segm ents 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 suppl y), discussed in this section. EPA reviewed available discharge data from plants within thes e SIC codes to determine if these plants have operations and wastewater characteristics sim ilar to those in the Steam Electric Power Generating Point Source Category.

This section discusses steam and air conditioni ng supply plants and the findings of EPA’s examination of the processes and wastewaters generated by their operati on. According to the 2002 Economic Census, 63 establishments were e ngaged in steam and air conditioning supply 31



### in the United States in 2 002 [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.Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### 7-22 • 

### Steam heating systems (suppliers of heat); and

• 

### Steam supply systems, including geothermal.

Many of these plants combust fo ssil fuels in a boiler to generate steam, which is similar to the operation at steam electric plants re gulated 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-s ite customers and, therefore, it does not power a steam turb ine/electric generator.

Wastewater generated by these steam and ai r conditioning supply plants is not currently regulated by the Steam Electric e ffluent guidelines, because the plan ts 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 condi tioning supply plants and compared their processes and types of wastewaters generated to those of fossil-fueled plants currentl y regulated by the Steam Electric Power Generating effluent guidelines. EPA also co mpared the way the wastewater discharges are regulated for these plants to the plants subjec t to the Steam Electric Po wer Generating effluent guidelines.

Information that EPA obtained during the deta iled study indicate that these steam and air conditioning supply plants genera te similar types of wastewater s as steam electric plants regulated under the Steam Electric Power Genera ting 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-f ired power plants. EPA identified that some of the wastewater discharges contain similar pollutant s to those discharged by steam electric plants. Additionally, some of the wastewaters from these plants are regulated us ing 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 operati on 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 da ta 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-NPDES 32 

### . 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 s ources provided information about potential types of wastewater generated by steam supply plants, as well as the re lative 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 Integrat ed Compliance Information System – National Pollutant Discharge Elimination Syst em (ICIS-NPDES) database.Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### 7-23 7.3.1 Wastewater Discharge Characterization Data

EPA extracted effluent monitoring data re ported 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 th at accounts for the toxicity of the pollutants discharged. The Technical Support Document for the Annu al Review of Existing Effluent Guidelines and Identification of Po tential New Point Source Categories [U.S. EPA, 2009c],

discusses EPA’s method of calcu lating TWPE. EPA in particular identified whether these operations reported discharges of chlorine, to tal residual oxidants (TRO ), chlorine-produced oxidants (CPO), or metals, which are pollutants typically discharged from steam electric plants regulated under the Steam Electric Po wer Generating effluent guidelines.

Table 7-6 also indicates whether the plants ar e classified as “major” or “minor” dischargers. To provide an initial framewor k for setting permit issuance priorities, EPA developed a major/minor classification system for industrial and m unicipal wastewater dischargers. Each permitting authority establishes its own definitions, but major dischargers almost always have the capability to impact r eceiving waters if not c ontrolled and, therefore, have been accorded more regulat ory attention than minor discharg ers. Plants are classified as major based on an assessment of six characteris tics: (1) toxic pollutant potential; (2) flow/stream flow volume; (3) conventional po llutant loading; (4) public hea lth impact; (5) water quality factors; and (6) proximity to coastal waters. Facilities with major discharges must report compliance with NPDES permit limits via mont hly 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 st eam 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 rela tively 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 conditioni ng supply wastewaters, EPA reviewed NPDES permits for four steam and air conditioning supply plants (plants identifie d 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 a ddition to steam. The five plants generate

wastewaters that are similar to those of steam electric plants regulated under the Steam Electric Power Generating effluent guidelin es, including boiler blowdown, co al pile runoff, and cooling tower blowdown; however, the cooling water wa ste streams and cooling tower blowdown listed in the permits could be associated with the chilled water production process.Final Detailed Study ReportChapter 7 – Preliminary Investigation of Other Industry SegmentsTable 7-6. Steam and Air-Conditioning Supply Plants Identified inDMRLoads2007DatabaseNIDDNameCityType ofDischargerMonitoringData inDatabase?TotalTWPEaCl/TRO/CPODischargedbMetalsDischargedAL0052400Powell Avenue Steam PlantBirminghamMinorYNAClCA0029106GAFF Power Systems-Site IPittsburgMinorNNACA0029122GAFF Power Systems-Site VPittsburgMinorNNACA0082406Alturas High School GeothermalAlturasMinorNNACA8000015San Bernardino Geothermal FacilitySan BernardinoMinorNNACO0043427Thermal Energy DistributionDenver CountyMinorNNACT0004014Hartford Steam CompanyHartfordMajorY4,645ClFe, Pb, Zn, CuDC0000035GSA - (West Heating Plant)WashingtonMinorYNAID0025488Boise, City OfBoiseMinorNNAIL0001368MED Thermal Technologies IncChicagoMinorYNAIL0037613MED Thermal Technologies-Pl. #5ChicagoMinorYNAClIL0072320SIC Physical Plant, SUITCarbondaleMinorYNAFeIL0073741Metro Pier & Expo AuthorityChicagoMinorYNAIN0004677Citizens Thermal EnergyIndianapolisMinorYNAClMD0001554Trigged-Baltimore Energy CorpBaltimoreMinorNNAMD0061930Trigged-Energy Baltimore – SPRYBaltimoreMinorYNAClCuMD0065986Housing Authority of BaltimoreBaltimoreMinorNNAMD0066249Trigged-Baltimore Energy CorpBaltimoreMinorNNAMD0066877Trigged-Energy Baltimore – SARABaltimoreMinorYNAClCuMN0054739Energy Park Utility CoSaint PaulMinorNNAMN0055719Duluth Steam Cooperative AssocDuluthMinorNNAMN0056995North Riverfront PlantMinneapolisMinorNNAMN0066559Minnesota Power Rapids EnergyGrand RapidsMinorNNAMO0004847Trigged KC Dist. Energy CURKansas CityMinorYNAMO0099236BASF Corp Agra ProductsPalmyraMinorYNAMO0127825University Of MO-PhysicalRollaMinorYNAMT0030651Don Abbey ResidenceRollinsMinorYNA7-24Final Detailed Study ReportChapter 7 – Preliminary Investigation of Other Industry Segments7-25Table 7-6. Steam and Air-Conditioning Supply Plants Identified inDMRLoads2007DatabaseNIDDNameCityType ofDischargerMonitoringData inDatabase?TotalTWPEaCl/TRO/CPODischargedbMetalsDischargedNJ0109673Central Heat Plant Bldg 2401New Hanover TwpMajorYNACPONY000513459thStreet Steam StationNew YorkMajorYNANY0005151Hudson Ave. Steam PlantBrooklynMinorYNANY000517774thStreet Steam PlantNew YorkMajorYNANY0227153South Nassau Communities HospOceansideMinorNNANY0245097Remington Arms Co, IncIlionMinorYNAZnOK0002461Trigged - Tulsa Energy CorpTulsaMinorYNAClPA0000493Pittsburgh Allegheny CountyPittsburghMinorNNAPA0008427NRG Energy Center Hag. IncHarrisburgMinorNNAPA0239542Impact PA Geothermal WellWarrenMinorNNAPA0253235Tarentum Senior Housing - Geothermal WellTarentumMinorNNASD0025569Haakon School District No. 27-1PhilipMinorYNASD0025798St Joseph's Indian SchoolChamberlainMinorYNATX0008851Texas Medical Center CentralHoustonMinorYNAVA0032000US Department Of Defense - PentagonArlingtonMinorNNAVA0091995Reston Lake Anne Air ConditionRestonMinorNNAWA0001503Seattle SteamPort of SeattleMinorYNAWI0038296U W Madison Charter StreetMadisonMinorNNAWI0040282WI University Milwaukee PowerMilwaukeeMinorNNASource: [U.S. EPA, 2009b].a – TWPE was not calculated for minor plants in theDMRLoads2007database.b– Cl – Chlorine; TRO – Total residual oxidants; and CPO – Chlorine produced oxidants (EPA has not developed TWFs for TRO and CPO; therefore, theseloads are not included in TWPE totals).NA – Not available. The plant is either a minor discharger, inwhich case ERG does not calculate TWPE, or the plant did not report both concentration and flowdata 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.Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### 7-26 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 st eam electric plants that the wastewaters may have similar characteristics and, therefore, should have the same effluent limitations.

Upon review of the permit for the Hartfo rd Steam Company, EP A learned that, in addition to steam and chilled water production, the pl ant used to generate electricity with excess steam; however, the electricity ge neration portion of the process has been closed since 1995. The permit has retained the limits of the Steam Elect ric Power Generating effluent guidelines as the basis for the current wastewater discharge re quirements. 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 ar e discharging chlorine and metals to surface

waters.

7.3.3 Contacts with Steam Supply Companies

During the detailed study, EPA contacted th ree companies operating a total of 20 plants 33


### to obtain information on the operations and wastew aters generated at steam supply plants. These steam supply plants typically provide steam for district heating and c ooling 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 th eir boilers. Because these fuels are generally low in sulfur, these plants do not ope rate FGD scrubbers. Steam supply pl ants 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 th e oil-fired plants generate a small amount of ash that they remove from the bo iler 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 generate d by oil-fired plants, typical wastewaters generated at natural gas or oil-fired steam s upply plants are:

• 

### Boiler blowdown;

• 

### Cooling water;

• 

### Demineralizer wastewater;

• 

### Equipment drains and overflows; and

• 

### Plants sumps.

According to one of the companies EPA c ontacted, the steam supply plants operated by the company neutralize the boile r blowdown and demineralizer wa stewaters 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 th ree steam supply companies, only seven were identified as st eam 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.Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### 7-27 do not operate treatment ponds due to limited spac e availability, but t ypically neutralize the boiler blowdown in large tanks [Consolidat ed 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 elect ricity and provides steam and chilled water for a

commercial district.

7.4 Combination Utility Plants

EPA reviewed available di scharge information for pl ants within SIC Code 4939 (Combination utilities, not elsewhere classified) to determine if these plan ts 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 elec tric 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 th an 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 1997 34 

### [USCB, 2000]; however, not all of these plants are relevant to the detailed study. By definition, combination utilities perform services other than electric power genera tion, and more specifically servi ces other than steam electric power generation.

Wastewaters generated by plants classifi ed as combination utilities are likely not currently subject to existing e ffluent guidelines; however, co mbination utilities by definition include plants that generate electric power, al beit in combination with providing other utility services. Because at least a porti on of these plants are expected to be engaged in the generation of electricity for distribution a nd 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 guide lines, in terms of processes and wastewaters generated. EPA examined effluent monitoring da ta 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 cu rrently 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 regul ated under the Steam Electric Power Generating effluent guidelines.

EPA’s review of NPDES permits for five combin ation utilities revealed that four of these plants do not produce electricity, even as an aux iliary activity, and the pr ocesses and wastewaters generated by these non-electric gene rating 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 nu mber of combination utilities from the 2002 Economic

Census data.Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### 7-28 regulated under the Steam Electric Power Gene rating effluent guidelin es. The wastewatergenerating activities performed at these plants may be classified within other existing SIC codes, including Electric Services, Sewera ge 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 bega n reporting NAICS codes. Only 13 combination utilities reported to TRI, and of these, only one reported a dire ct release to water (barium and barium compounds with a TWPE of 0.003). The remaining seven re ported no discharge of a TRI chemical to water [ERG, 2008a]. TRI does not speci fically identify the pro cess 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, wh ich is a loading that accounts for the toxicity of the pollu tants discharged. The 2009 screen ing-level analysis report, 2009 Annual Screening-Level Analysis: Supporting the A nnual 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 typi cally discharged from steam electric plants regulated under the Steam Electric Power Ge nerating 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 ar e classified as “major” or “minor” dischargers. To provide an initial framewor k for setting permit issuance priorities, EPA developed a major/minor classification system for industrial and m unicipal wastewater dischargers. Each permitting authority establishes its own definitions, but major dischargers almost always have the capability to impact r eceiving waters if not c ontrolled and, therefore, have been accorded more regulat ory attention than minor discharg ers. Plants are classified as major based on an assessment of six characteris tics: (1) toxic pollutant potential; (2) flow/stream flow volume; (3) conventional po llutant loading; (4) public hea lth impact; (5) water quality factors; and (6) proximity to coastal waters. Facilities with major discharges must report compliance with NPDES permit limits via monthl y 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 lim ited 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.Final Detailed Study ReportChapter 7 – Preliminary Investigation of Other Industry SegmentsTable 7-7. Combination Utilities Identified inDMRLoads2007DatabaseNPDES IDPlant NameCityType ofDischargerMonitoringData inDatabase?TotalTWPEaCl/TRO/CPODischargedbMetalsDischargedAR0034363Shumaker Public Service Corp.East CamdenMinorNNACA0047953Paso Robles WWTPPaso RoblesMajorY173ClNa, Cu, SeCO0042447Rifle StationGarfield CountyMinorNNACT0030279City of StamfordStamfordMinorNNAIA0062421Coats Utility CompanyFort DodgeMinorNNAIL0045527Aqua Il Inc-Candlewick LakePoplar GroveMinorYNAClIL0048593Otter Creek Lake Utility StpDavisMinorYNAClIL0052817Stonewall Utility Co StpOakbrook TerraceMinorYNAClIL0071030Emmett Utilities Inc. StpColchesterMinorYNAClILG551012Sheridan Estates Disp StpQuincyMinorYNAClILG640079Aqua Illinois-WoodhavenSubletteMinorYNAClIN0000311BPC Manufacturing OperationsPlymouthMinorNNAIN0002941Western Electric CoIndianapolisMinorNNAIN0031011USDAF USAF Grissom AFBGrissom AFBMinorNNAIN0031836Gateway Utilities, Inc.Terre HauteMinorNNAKY0105091Western Lewis Rectorville WtrMason CountyMinorNNALA0116424US 165 North Regional WWTFWest MonroeMinorNNALA0119679North Vermilion WTPMauriceMinorNNALA0119687Pecan Island WTPKaplanMinorNNAME0102512Hampden WWTFHampdenMinorNNAMN0041271Franklin Heating StationRochesterMinorNNAMO0000345Tractebel Power IncorporatedSaintLouisMinorNNANY0005894Glenwood Landing Energy CenterGlenwood LandingMinorYNANY0026344Shoreham Combustion Turbine FacilityShorehamMajorY<1ClNY0106259Covanta Niagara, L.P.Niagara FallsMinorYNAAl, FeNY0200778East 60th Street SteamPlantNew YorkMinorYNAAl, ZnNY0201138Consolidated Edison Co Of NYLong Island CityMinorYNANY0201154Astoria Liquified Nat Gas StorageAstoriaMinorYNANY0225282Brookhaven Combustion TurbineWading RiverMinorYNANY0225860Shoreham Nuclear Power StationShorehamMinorNNANY0226009Southold Internal CombustionGreenportMinorYNA7-29Final Detailed Study ReportChapter 7 – Preliminary Investigation of Other Industry Segments7-30Table 7-7. Combination Utilities Identified inDMRLoads2007DatabaseNPDES IDPlant NameCityType ofDischargerMonitoringData inDatabase?TotalTWPEaCl/TRO/CPODischargedbMetalsDischargedNY0226017Keyspan - East Hampton IcfEast HamptonMinorYNANY0226025Keyspan - Montauk IcfMontaukMinorYNANY0226033Southamptom IcfSouthamptonMinorYNANY0259055DTE Tonawanda LLCBuffaloMinorYNAClNY0265039White Plains SubstationWhite PlainsMinorYNANY0266515Brookhaven EnergyYaphankMinorNNANY0267538Astoria Energy Power PltAstoriaMinorYNAClNY0268003Consolidated Edison Co Of NYWhite PlainsMinorYNANY0270407TBG Cogen PartnersHicksvilleMinorYNANY0270423Bayswater/Jamaica Bay Peak FacFar RockawayMinorYNANY0271438Tomson Converter StationShorehamMinorYNAOH0041335Prince Inland Terminal Co BelpreBelpreMinorNNAPA0020435White Haven WWTPWhite HavenMinorNNAPA0061590Eagle Rock Community AssocHazletonMinorNNAPAR900004Convanta Delaware Valley LPChesterMinorNNAUTS000002Salt Lake City CorporationSalt Lake CityMinorNNASource: [U.S. EPA, 2009b].a – TWPE was not calculated for minor plants in theDMRLoads2007database.b – Cl – Chlorine; TRO – Total residual oxidants; and CPO – Chlorine produced oxidants (EPA has not developed TWFs for TRO andCPO; therefore, theseloads 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 aminor discharger, in which case EPA does not calculate TWPE, or the plant did not report both concentration and flowdata 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 permitreview based on combination utilities identified in the 2002 PCS database; however, two of these five plants are not identifiedas combination utilities in theDMRLoads2007database. Therefore, only three of the plants for which EPA reviewed permits are identified in the table.Final Detailed Study Report Chapter 7 – Preliminary Investigation of Other Industry Segments



### 7-31 7.4.2 NPDES Permit Review

During the detailed study, EPA obtained NPDES permits for five 35 

### plants initially

believed to be combination utili ties. EPA reviewed the permits to determine the operations at the plants, the types of wastewaters generated by th e 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 gaspowered combined cycle system with a total electric generati ng 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 prov ides 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 i ndicated that the cooling tower blowdown contributes 50 to 70 percent of the total discharg e, which is intermittent due to the sporadic demand for electric power from this peaking plan t. The wastewater discharged by this plant is currently limited by the requirements of th e Steam Electric Power Generating effluent guidelines 36 

### , since it meets the applicability at 40 CFR Part 423.10 [CDPHE, 2003].

EPA found the remaining four plants to be wa stewater treatment and water supply plants. None of these plants reported an electric ge nerating unit to the EIA. In addition, the limited amount of information on the waste streams provide d in the permits indicat ed they had little in common with the waste streams expected from a st eam electric generating plant, as previously

described in Section 3.2. Since th ese plants do not appear to be “...primarily engaged in the generation of electricity for di stribution and sale...” [40 CFR Part 423.10], they do not meet the current applicability of the Steam Electric Powe r Generating effluent guidelines. Further, the processes and wastewaters genera ted by these non-electric-generati ng plants are not similar to those of steam electric plants regulated under the Steam Elect ric Power Generating effluent guidelines.

Table 7-7 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 .

36 The permit did not address limitations on copper and iron discharged with chemical metal cleaning wastewaters.Final Detailed Study Report Chapter 8 – References



### 8-1 8. R EFERENCES



### 1. Air and Waste Management Association (AWMA). 2008. CCS with Alstom’s Chilled

Ammonia Process at AEP’s Mountaineer Plant: Paper # 167. Available online at: http://secure.awma.org/presentations/Mega08/Papers/a167_1.pdf . Date accessed: May 29, 2009. DCN 06444.

2. Alcoa Generating Corp. 2009. Telephone c onversation with Danny Wene of Alcoa Generating and T.J. Finseth of Eastern Research Group, Inc. “Alcoa Warrick Operations’

On-site Power Plant.” DCN 06521.

3. Alstom Corporation. 2008. Alstom Annual Information Document (June 2007-June 2008) . Available online at: http://www.alstom.com/home/investors/publications/ annual_information_document/_files/file_43348_50660.pdf . Date accessed: May 29,

2009. DCN 06443.

4. Alstom Corporation. 2009. Alstom Officials Say Prelim inary Data Shows That Carbon Capture Demonstration Project Is Successful . Available online at: http://www.weenergies.com/home/alstom_newsrelease051109.pdf. Date accessed: May 29 , 2009. DCN

06442.

5. API. 2005. Letter from R.E. Claff, American Petroleum Institute, to U.S. EPA Water

Docket. “Comments of the American Petroleu m Institute on the 2006 Effluent Guidelines Program Plan.” (29 November). Docket Number EPA-HQ-OW-2004-0032-1067.

6. Aquatech. 2006. Telephone conversation with Manoj Sharma of Aquatech and T.J. Finseth of Eastern Research Group, Inc. “A quatech Boron Mitigation System.” (11 April). DCN 03639.

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