United States EPA-600/R-01-109 

Environmental Protection 

Agency April 2002 

Research and


Development


CONTROL OF MERCURY EMISSIONS


FROM COAL-FIRED ELECTRIC


UTILITY BOILERS:


INTERIM REPORT


INCLUDING ERRATA DATED 3-21-02


Prepared for


Office of Air Quality Planning and Standards 

Prepared by 

National Risk Management


Research Laboratory


Research Triangle Park, NC 27711

Foreword 

The U.S. Environmental Protection Agency is charged by Congress with 

protecting the Nation's land, air, and water resources. Under a mandate of national 

environmental laws, the Agency strives to formulate and implement actions leading to 

a compatible balance between human activities and the ability of natural systems to 

support and nurture life. To meet this mandate, EPA's research program is providing 

data and technical support for solving environmental problems today and building a 

science knowledge base necessary to manage our ecological resources wisely, 

understand how pollutants affect our health, and prevent or reduce environmental risks 

in the future. 

The National Risk Management Research Laboratory (NRMRL) is the Agency's 

center for investigation of technological and management approaches for preventing 

and reducing risks from pollution that threaten human health and the environment. The 

focus of the Laboratory's research program is on methods and their cost-effectiveness 

for prevention and control of pollution to air, land, water, and subsurface resources, 

protection of water quality in public water systems; remediation of contaminated sites, 

sediments and ground water; prevention and control of indoor air pollution; and 

restoration of ecosystems. NRMRL collaborates with both public and private sector 

partners to foster technologies that reduce the cost of compliance and to anticipate 

emerging problems. NRMRL’s research provides solutions to environmental problems 

by: developing and promoting technologies that protect and improve the environment; 

advancing scientific and engineering information to support regulatory and policy 

decisions; and providing the technical support and information transfer to ensure 

implementation of environmental regulations and strategies at the national, state, and 

community levels. 

This publication has been produced as part of the Laboratory's strategic 

long-term research plan. It is published and made available by EPA's Office of 

Research and Development to assist the user community and to link researchers with 

their clients. 

E. Timothy Oppelt, Director


National Risk Management Research Laboratory


EPA REVIEW NOTICE 

This report has been peer and administratively reviewed by the U.S. Environmental 

Protection Agency, and approved for publication. Mention of trade names or 

commercial products does not constitute endorsement or recommendation for use. 

This document is available to the public through the National Technical Information 

Service, Springfield, Virginia 22161. 
EPA-600/R-01-109 

December 2001 

Control of Mercury Emissions from Coal-


Fired Electric Utility Boilers:


Interim Report


James D. Kilgroe, Charles B. Sedman, Ravi K. Srivastava, 

Jeffrey V. Ryan, C. W. Lee, and Susan A. Thorneloe 

U.S. Environmental Protection Agency


Office of Research and Development


National Risk Management Research Laboratory


Air Pollution Prevention and Control Division


Research Triangle Park, NC 27711

Errata Pages 

for 

EPA-600/R-01-109 

Control of Mercury Emissions from Coal-Fired 

Electric Utility Boilers: Interim Report 

December 2001 

Errata Pages


xvi


xxii 

ES-10


6-3


6-4


6-19


6-21


6-43a 

6-43b 

6-43c 

6-48


6-49


6-51


6-52


March 21, 2002 

i-a 
Abstract 

In December 2000, the U.S. Environmental Protection Agency (USEPA) announced its intent to 

regulate mercury emissions from coal-fired electric utility steam generating plants. This report, 

produced by EPA’s Office of Research and Development (ORD), National Risk Management 

Research Laboratory (NRMRL), provides additional information on mercury emissions control, 

following the release of “ Study of Hazardous Air Pollutant Emissions from Electric Utility 

Steam Generating Plants - Final Report to Congress,” in February 1998. The first three chapters 

describe EPA’s December 2000 decision to regulate mercury under the National Emission 

Standards for Hazardous Air Pollutants (NESHAP) provisions of the Clean Air Act, coal use in 

electric power generation, and mercury behavior in coal combustion. Chapters 4-9 report: new 

information on current electric utility fuels, boilers, and emission control technologies; mercury 

emissions associated with these diverse technology combinations; results and implications of 

tests to evaluate the performance of mercury control technologies and strategies; retrofit control 

cost modeling; and mercury behavior in solid residues from coal combustion. The final chapter 

summarizes current research and identifies future efforts needed to ensure cost-effective control 

of mercury emissions. References are provided at the conclusion of each chapter. 

Preface 

This is an interim report, based on data available as of mid-2001, which in some cases are 

limited. As more data are collected and evaluated, some of the conclusions reached in this report 

may be modified. 

ii 
Contents 

Page


Abstract ....................................................................................................................................... ii


Preface.......................................................................................................................................... ii


Figures.......................................................................................................................................... x


Tables........................................................................................................................................ xiv


Acronyms.................................................................................................................................. xix


Acknowledgements.................................................................................................................. xxii


Executive Summary................................................................................................................ES-1


Chapter 1. Report Background


1.1 Introduction................................................................................................................ 1-1


1.2 Report Purpose .......................................................................................................... 1-2


1.3 NESHAP Statutory Background ............................................................................... 1-2


1.4 Major Findings of EPA Reports to Congress ............................................................ 1-4


1.4.1 Study of HAP Emissions from Electric Utility Steam Generating Units ........ 1-4


1.4.2 Mercury Study Report...................................................................................... 1-5


1.4.3 Great Waters Reports....................................................................................... 1-6


1.5 Information Collection Request to Electric Utility Industry...................................... 1-6


1.6 Regulatory Finding on HAP Emissions from Electric Utility Steam Generating


Units........................................................................................................................... 1-8


1.7 Mercury Emissions Research Programs ................................................................... 1-9


1.8 Relationship to Mercury Emission Control Research for Municipal Waste


Combustors ................................................................................................................ 1-9


1.9 Report Organization................................................................................................. 1-12


1.10 References................................................................................................................ 1-15


Chapter 2. Coal-fired Electric Utility Boilers


2.1 Introduction.................................................................................................................. 2-1


2.2 Coal.............................................................................................................................. 2-1


2.2.1 Coal Property Tests.......................................................................................... 2-1


2.2.1.1 Coal Heating Value.............................................................................. 2-2


2.2.1.2 Coal Proximate Analysis...................................................................... 2-2


2.2.1.3 Coal Ultimate Analysis........................................................................ 2-2


2.2.1.4 Coal Mercury Analysis ........................................................................ 2-3


2.2.2 Coal Classification........................................................................................... 2-3


2.2.3 United States Coal Resources .......................................................................... 2-4


2.2.4 Mercury Content in Coals................................................................................ 2-7


2.3 Coal Cleaning.............................................................................................................. 2-9


2.3.1 Coal Cleaning Processes.................................................................................. 2-9


2.3.2 Mercury Removal by Coal Cleaning ............................................................. 2-10


2.4 Coal-fired Electric Utility Boilers.............................................................................. 2-11


2.4.1 Conventional Coal-fired Electric Utility Power Plants.................................. 2-11


2.4.2 Coal-fired Cogeneration Facilities................................................................. 2-13


iii 
Contents (continued) 

Page


2.4.3 Integrated Coal Gasification Combined Cycle Power Plants ........................ 2-14


2.5 Coal-firing Configurations for Electric Utility Boilers.............................................. 2-14


2.5.1 Pulverized-coal-fired Furnace........................................................................ 2-18


2.5.2 Cyclone Furnace ............................................................................................ 2-18


2.5.3 Fluidized-bed Combustor............................................................................... 2-18


2.5.4 Stoker-fired Furnace ...................................................................................... 2-19


2.5.5 Gasified-coal-fired Combustor ...................................................................... 2-19


2.6 Ash from Coal Combustion ....................................................................................... 2-20


2.7 Coals Burned by Electric Utilities in 1999 ................................................................ 2-22


2.8 References.................................................................................................................. 2-26


Chapter 3. Criteria Air Pollutant Emission Controls for Coal-fired Electric Utility Boilers


3.1 Introduction.................................................................................................................. 3-1


3.2 Criteria Air Pollutants of Concern from Coal Combustion ......................................... 3-2


3.2.1 Particulate Matter............................................................................................. 3-2


3.2.2 Sulfur Dioxide.................................................................................................. 3-3


3.2.3 Nitrogen Oxides............................................................................................... 3-3


3.3 Existing Control Strategies Used for Coal-fired Electric Utility Boilers .................... 3-4


3.4 Particulate Matter Emission Controls................................................................................. 3-5


3.4.1 Electrostatic Precipitators ................................................................................ 3-5


3.4.2 Fabric Filters .................................................................................................... 3-8


3.4.3 Particle Scrubbers .......................................................................................... 3-11


3.4.4 Mechanical Collectors ................................................................................... 3-11


3.5 SO2 Emission Controls ............................................................................................ 3-12


3.5.1 Low-sulfur Coal ............................................................................................ 3-12


3.5.2 Fluidized-bed Combustion with Limestone................................................... 3-14


3.5.3 Wet FGD Systems.......................................................................................... 3-14


3.5.4 Spray Dryer Adsorber.................................................................................... 3-15


3.5.5 Dry Injection .................................................................................................. 3-15


3.5.6 Circulating Fluidized-bed Adsorber .............................................................. 3-15


3.6 NOx Emission Controls.............................................................................................. 3-16


3.6.1 Combustion Controls ..................................................................................... 3-16


3.6.2 Selective Catalytic Reduction........................................................................ 3-18


3.6.3 Selective Noncatalytic Reduction.................................................................. 3-18


3.7 Emission Control Configurations for Coal-fired Electric Utility Boilers.................. 3-19


3.8 References.................................................................................................................. 3-21


Chapter 4. Measurement of Mercury


4.1 Introduction.................................................................................................................. 4-1


4.2 Manual Methods for Hg Measurements ..................................................................... 4-2


4.3 Continuous Emission Monitors for Hg Measurements................................................ 4-8


4.4 Summary, Conclusions, and Recommendations ....................................................... 4-17


iv 
Contents (continued) 

Page


4.5 References.................................................................................................................. 4-19


Chapter 5. Mercury Speciation and Capture


5.1 Introduction.................................................................................................................. 5-1


5.2 General Behavior of Mercury in Coal-fired Electric Utility Boilers ........................... 5-1


5.3 Speciation of Mercury.................................................................................................. 5-3


5.3.1 Gas-phase Oxidation........................................................................................ 5-4


5.3.2 Fly Ash Mediated Oxidation............................................................................ 5-9


5.3.3 Oxidation by Post-combustion NOx Controls ................................................ 5-16


5.3.4 Potential Role of Deposits, Fly Ash, and Sorbents on Mercury Speciation .. 5-16


5.4 Capture of Mercury by Sorbent Injection .................................................................. 5-17


5.4.1 Sorbent Characterization................................................................................ 5-17


5.4.2 Experimental Methods Used in Sorbent Evaluation...................................... 5-18


5.4.2.1 Bench-scale Reactors......................................................................... 5-18


5.4.2.2 Pilot-scale Systems ............................................................................ 5-25


5.4.2.3 Full-scale Tests .................................................................................. 5-25


5.4.3 Research on Sorbent Evaluation .................................................................... 5-26


5.4.3.1 Sorbent Evaluation Using Enhanced-flow Reactors.......................... 5-26


5.4.3.2 Sorbent Evaluation Using Packed-bed Reactors................................ 5-26


5.4.3.3 Sorbent Evaluation Using Fluidized-bed Reactors............................ 5-31


5.5 Sorbent Development................................................................................................. 5-32


5.5.1 Powdered Activated Carbons......................................................................... 5-32


5.5.1.1 Effects of Temperature, Mercury Concentration, and Acid Gases.... 5-32


5.5.1.2 Role of Surface Functional Groups.................................................... 5-33


5.5.1.3 In-flight Capture of Mercury by a Chlorine-impregnated Activated


Carbon................................................................................................. 5-33


5.5.2 Calcium-based Sorbents................................................................................. 5-34


5.5.2.1 Capture of Low Concentrations of Mercury Using Calcium-based


Sorbents............................................................................................... 5-34


5.5.2.2 Simultaneous Control of Hg0

, SO2, and NOx by Oxidized-calcium-


based Sorbents .................................................................................... 5-36


5.5.3 Development of Low-cost Sorbents............................................................... 5-37


5.5.4 Modeling of Sorbent Performance................................................................. 5-38


5.6 Capture of Mercury in Wet FGD Scrubbers.............................................................. 5-39


5.6.1 Wet Scrubbing ............................................................................................... 5-39


5.6.2 Oxidation ....................................................................................................... 5-40


5.6.3 Gas and Liquid Oxidation Reagents .............................................................. 5-45


5.7 Observations and Conclusions................................................................................... 5-45


5.8 References.................................................................................................................. 5-47


v 
Contents (continued) 

Page 

Chapter 6. Mercury Capture by Existing Control Systems Used by Coal-fired Electric Utility 

Boilers


6.1 Introduction.................................................................................................................. 6-1


6.2 EPA ICR Part III Data ................................................................................................. 6-1


6.3 Mercury Content of Utility Coals Burned in 1999 ...................................................... 6-4


6.4 Potential Mercury Capture in Existing Units............................................................... 6-6


6.4.1 Units with an ESP or FF .................................................................................. 6-7


6.4.2 Units with SDA Systems ................................................................................. 6-8


6.4.3 Units with Wet FGD Systems.......................................................................... 6-8


6.4.4 Units with Other Control Devices.................................................................... 6-9


6.5 EPA’s Part III ICR Data Evaluation Approach ........................................................... 6-9


6.5.1 Evaluation Method........................................................................................... 6-9


6.5.2 Measure of Performance ................................................................................ 6-10


6.5.3 Comparison of HgT (Inlet) Using OH Measurement and Coal Hg Data........ 6-14


6.5.4 Development of Data Sets for Coal-boiler-control Classes........................... 6-15


6.5.5 Questionable Nature of OH Speciation Measurements Upstream of


PM Controls................................................................................................. 6-15


6.6 Fuel, Boiler, and Control Technology Effects........................................................... 6-17


6.6.1 Coal Effects.................................................................................................... 6-19


6.6.2 Control Technology Effects........................................................................... 6-21


6.6.3 Post-combustion PM Controls ...................................................................... 6-24


6.6.3.1 Cold-side ESPs .................................................................................. 6-24


6.6.3.2 Hot-side ESPs .................................................................................... 6-30


6.6.3.3 FF Baghouses..................................................................................... 6-33


6.6.3.4 Comparison of ESPs and FFs ............................................................ 6-33


6.6.3.5 Other PM Controls............................................................................. 6-36


6.6.4 Hg Capture in Units with Dry FGD Scrubbers.............................................. 6-37


6.6.5 Hg Capture in Units with Wet FGD Scrubbers ............................................. 6-41


6.6.6 Potential Effects of Post-combustion NOx Controls ..................................... 6-49


6.7 Combustion System Effects....................................................................................... 6-50


6.7.1 Cyclone-fired Boilers..................................................................................... 6-52


6.7.2 Fluidized-bed Combustors............................................................................. 6-54


6.7.3 IGCC Facilities .............................................................................................. 6-56


6.8 National and Regional Emission Estimates ............................................................... 6-57


6.9 Summary and Conclusions ........................................................................................ 6-59


6.10 References................................................................................................................ 6-62


Chapter 7. Research and Development Status of Potential Retrofit Mercury Control Technologies


7.1 Introduction.................................................................................................................. 7-1


7.2 Technology-based Mercury Control Strategies for Existing Coal-fired Electric Utility


Boilers........................................................................................................................ 7-2


7.2.1 Remove Mercury Prior to Burning by Coal Cleaning ..................................... 7-2


vi 
Contents (continued) 

Page


7.2.2 Retrofit Mercury Controls to Existing Air Pollution Control Systems............ 7-3


7.2.3 Integrate Mercury Control Under a Multipollutant Control Strategy.............. 7-4


7.3 Post-combustion Mercury Control Retrofit ................................................................. 7-4


7.3.1 Cold-side ESP Retrofit Options....................................................................... 7-4


7.3.2 Hot-side ESP Retrofit Options......................................................................... 7-5


7.3.3 Fabric Filter Retrofit Options........................................................................... 7-5


7.3.4 Spray Dryer Adsorber Retrofit Options........................................................... 7-6


7.3.5 Wet FGD Scrubber Retrofit Options ............................................................... 7-6


7.3.6 Particle Scrubber Retrofit Options................................................................... 7-6


7.4 Retrofit Control Technology Research and Development Programs .......................... 7-7


7.4.1 MWC Mercury Control Technology ............................................................... 7-7


7.4.2 Pilot-scale Coal-fired Test Facilities................................................................ 7-9


7.5 Mercury Control Retrofits for Existing Coal-fired Electric Utility Boilers Using


ESP or FF Only........................................................................................................ 7-13


7.5.1 Sorbent Injection Configurations................................................................... 7-13


7.5.2 Sorbent Adsorption Theory............................................................................ 7-14


7.5.3 Pilot-scale and Full-scale Research and Development Status ....................... 7-15


7.5.3.1 Coal Fly Ash Reinjection................................................................... 7-15


7.5.3.2 Activated Carbon Sorbent Injection................................................... 7-19


7.5.3.3 Calcium-based Sorbent Injection....................................................... 7-25


7.5.3.4 Multipollutant Sorbent Injection........................................................ 7-28


7.5.3.5 Noble-metal-based Sorbent in Fixed-bed Configuration................... 7-30


7.6 Mercury Control Retrofits for Existing Coal-fired Electric Utility Boilers Using Semi-


dry Adsorbers.......................................................................................................... 7-31


7.6.1 Retrofit Options ............................................................................................. 7-31


7.6.2 Pilot-scale and Full-scale Research and Development Status ....................... 7-31


7.7 Mercury Control Retrofits for Existing Coal-fired Electric Utility Boilers Using Wet


FGD Scrubbers......................................................................................................... 7-31


7.7.1 Retrofit Options ............................................................................................. 7-31


7.7.2 Mercury Absorption Theory .......................................................................... 7-32


7.7.3 Pilot-scale and Full-scale Research and Development Status ....................... 7-32


7.7.3.1 Oxidation Additives........................................................................... 7-32


7.7.3.2 Mercury Oxidation Catalysts ............................................................. 7-33


7.7.3.3 Wet FGD Scrubber Design and Operating Modifications................. 7-37


7.8 Multipollutant Control Technologies......................................................................... 7-43


7.8.1 Corona Discharge........................................................................................... 7-43


7.8.2 Electron Beam Irradiation.............................................................................. 7-44


7.8.3 Oxidant Injection in Flue Gas........................................................................ 7-44


7.8.4 Catalytic Oxidation ........................................................................................ 7-45


7.8.5 Oxidant Addition to Scrubber........................................................................ 7-45


7.8.6 Catalytic Fabric Filters................................................................................... 7-45


7.8.7 Carbon-fiber FFs and ESPs............................................................................ 7-45


vii 
Contents (continued) 

Page 

7.9 Summary.................................................................................................................. 7-46


7.10 References................................................................................................................ 7-47


Chapter 8. Cost Evaluation of Retrofit Mercury Controls for Coal-fired Electric Utility Boilers


8.1 Introduction.................................................................................................................. 8-1


8.2 Cost Estimate Methodology......................................................................................... 8-2


8.2.1 Mercury Control Technologies Evaluated....................................................... 8-3


8.2.2 Model Plant Descriptions................................................................................. 8-5


8.2.3 Computer Cost Model...................................................................................... 8-7


8.2.4 PAC Injection Rate Algorithms....................................................................... 8-7


8.2.5 Cost Estimate Assumptions ............................................................................. 8-9


8.3 Estimated Costs of Reducing Mercury Emissions..................................................... 8-10


8.3.1 Bituminous-coal-fired Boiler Using CS-ESP ................................................ 8-11


8.3.2 Subbituminous-coal-fired Boiler Using CS-ESP........................................... 8-14


8.3.3 Subbituminous-coal-fired Boilers Using FF.................................................. 8-14


8.3.4 Coal-fired Boilers Using SCR for NOx Control ............................................ 8-17


8.4 Impacts of Selected Variables on Mercury Control Costs......................................... 8-17


8.4.1 Acid Dew Point Approach Setting................................................................. 8-17


8.4.2 PAC Recycle.................................................................................................. 8-18


8.4.3 Increased Flue Gas Residence Time .............................................................. 8-18


8.4.4 Use of Composite PAC and Lime Sorbent .................................................... 8-23


8.5 Cost Indications for Other Model Plant Scenarios .................................................... 8-23


8.6 Projection of Future Mercury Control Costs ............................................................. 8-25


8.7 Comparison of Mercury and NOx Control Costs ....................................................... 8-27


8.8 Summary.................................................................................................................... 8-29


8.9 References.................................................................................................................. 8-30


Chapter 9. Coal Combustion Residues and Mercury Control


9.1 Introduction.................................................................................................................. 9-1


9.2 CCR Types................................................................................................................... 9-1


9.3 CCR Mercury Concentrations...................................................................................... 9-2


9.4 Nationwide Management Practices.............................................................................. 9-2


9.4.1 Reuse and Recycling of CCRs......................................................................... 9-6


9.4.2 Land-disposal of CCRs.................................................................................... 9-6


9.5 Current Status of CCR Research Activities................................................................. 9-8


9.6 Future CCR Research Activities and Needs ................................................................ 9-9


9.7 References.................................................................................................................... 9-9


Chapter 10. Conclusions and Recommendations


10.1 Electric Utility Coal Combustion and Air Pollution Control Technologies............ 10-1


10.2 Mercury Measurement Methods.............................................................................. 10-2


10.3 Mercury Speciation and Capture ............................................................................. 10-3


viii 
Contents (concluded) 

Page


10.3.1 Mercury Speciation...................................................................................... 10-3


10.3.2 Development and Evaluation of Sorbents.................................................... 10-4


10.4 Evaluation of EPA ICR Mercury Emission Test Data............................................. 10-4


10.5	 Potential Retrofit Mercury Control Technologies ................................................... 10-6


10.5.1 Cold-side ESP, Hot-side ESP, and FF Systems........................................... 10-6


10.5.2 Semi-dry FGD Scrubbers............................................................................. 10-7


10.5.3 Wet FGD Scrubbers..................................................................................... 10-7


10.6 Costs of Retrofit Mercury Control Technologies .................................................... 10-7


10.7 Coal Combustion Residues and Mercury Control ................................................... 10-8


10.8 Current and Future Research ................................................................................... 10-9


Appendices 

A.	 Summary of Part II EPA ICR Data -- Mercury Content and Selected Fuel Properties


of As-fired Coals and Supplemental Fuels Burned in Coal-fired Electric Utility


Boilers Nationwide in 1999 ........................................................................................ A-1


B.	 Background Material of Methodology Used to Estimate 1999 Nationwide Mercury


Emissions from Coal-fired Electric Utility Boilers ......................................................B-1


C.	 Summary of Part II EPA ICR Data -- Mercury Capture Efficiencies of Existing


Post-combustion Controls Used for Coal-fired Electric Utility Boilers .......................C-1


D. Assessment of Mercury Control Options for Coal-fired Power Plants........................ D-1


ix 
Figures 

Figure Page No. 

2-1.	 Distribution of coal deposits in the continental United States by USGS coal resource


region ........................................................................................................................... 2-6


2-2.	 Simplified schematic of coal-fired electric utility boiler burning pulverized,


low-sulfur coal ............................................................................................................ 2-12


4-1. Diagram of sampling train for Ontario-Hydro Method ................................................ 4-3


4-2.	 Comparison of Hg speciation measured by manual test methods from UND/EERC


pilot-scale evaluation tests firing Blacksville bituminous coal and sampling and


spiking Hg0 at FF inlet .................................................................................................. 4-6


4-3.	 Comparison of gaseous Hg speciation measured by manual test methods from


UND/EERC pilot-scale evaluation tests firing Blacksville bituminous coal and


sampling and spiking Hg0 at FF outlet.......................................................................... 4-7


4-4. Comparison of total Hg results for CEMs at low Hg levels ....................................... 4-15


4-5. Comparison of Hg speciation results for CEMs at low Hg levels .............................. 4-16


5-1. Mercury species distribution in coal-fired electric utility boiler flue gas..................... 5-2


5-2.	 Predicted distribution of Hg species at equilibrium, as a function of temperature for a


starting composition corresponding to combustion of a bituminous coal (Pittsburgh) in


air at a stoichiometric ratio of 1.2 ................................................................................. 5-5


5-3.	 Predicted distribution of Hg species at equilibrium, as a function of temperature for a


starting composition corresponding to combustion of a subbituminous coal (Powder


River Basin) in air at a stoichiometric ratio of 1.2........................................................ 5-6


5-4.	 Effects of SO2 and water vapor on the gas-phase oxidation of Hg0 at 754 °C and at three


different Cl concentrations............................................................................................ 5-8


5-5.	 Hg0 oxidation in the presence of the three- and four-component model fly ashes


containing iron at a bed temperature of 250 °C .......................................................... 5-11


5-6.	 Hg0 oxidation in the presence of the three- and four-component model fly ashes


containing copper at a bed temperature of 250 oC...................................................... 5-12


5-7. Schematic of bench-scale fixed-bed reactor ............................................................... 5-21


x 
Figures (continued) 

Figure Page No. 

5-8. Schematic of the bench-scale flow reactor with methane burner ............................... 5-22


5-9. Schematic of bench-scale fluidized-bed reactor system ............................................. 5-24


5-10.	 Effect of particle size on adsorption for Darco FGD at 100 °C, 86 ppb


Hg0

concentration, and 8.4 s contact time.................................................................... 5-27


5-11. Example of the sampling and measurements taken during testing of the baseline test 

gas with HCl, NO2, and SO2................................................................................................................................ 5-30


5-12.	 Adsorption and subsequent oxidation of gaseous Hg0 in a simulated flue gas at 149 o

C


(300 oF) ....................................................................................................................... 5-42


5-13.	 Adsorption and oxidation of gaseous Hg0 by various catalysts at 149 o

C (300 oF)


and 371o

C (700 oF)...................................................................................................... 5-43


5-14.	 Adsorption and oxidation of gaseous Hg0 by various coal fly ashes at 149 oC (300 oF)


and 371oC (700 oF)...................................................................................................... 5-44


6-1. 1999 ICR data analyses – mercury in fuels .................................................................. 6-5


6-2. Inlet versus outlet mercury concentration for all tests ............................................... 6-12


6-3. Inlet mercury concentration versus percent reduction for all tests ............................ 6-12


6-4. Effect of OH sample filter solids on Hg speciation .................................................... 6-17


6-5.	 Inlet and outlet mercury concentrations for bituminous PC-fired boilers with


CS-ESP ....................................................................................................................... 6-27


6-6. Mercury emissions from bituminous coal-fired PC boilers with CS-ESP.................. 6-28


6-7.	 Mercury emissions for subbituminous- and lignite-fired PC boilers with


CS-ESP ....................................................................................................................... 6-28


6-8.	 Hypothetical effect of inlet and outlet HgT concentration changes on run-to-run HgT


capture......................................................................................................................... 6-30


6-9. Mercury emissions from bituminous-fired PC boilers with HS-ESP ......................... 6-32


xi 
Figures (continued) 

Figure Page No. 

6-10.	 Mercury emissions from subbituminous- and lignite-fired PC boilers with


HS-ESP ...................................................................................................................... 6-32


6-11. Mercury emission reductions for PC-fired boilers with ESPs and FFs ...................... 6-35


6-12. Mercury speciation for PC-fired boilers with ESPs and FFs...................................... 6-35


6-13. Relative mercury speciation for PC-fired boilers with ESPs and FFs........................ 6-36


6-14. Mercury control for dry FGD scrubbers ..................................................................... 6-40


6-15. Mercury speciation for PC boilers with SDA............................................................. 6-40


6-16. Relative mercury speciation for PC boilers with SDA ............................................... 6-41


6-17. Mercury speciation for PC boilers with wet FGD ...................................................... 6-45


6-18. Mercury emissions for PC boilers with wet FGD....................................................... 6-45


6-19. Relative mercury speciation for PC boilers with wet FGD ........................................ 6-46


6-20. Mercury speciation for cyclone-fired boilers.............................................................. 6-53


6-21. Relative mercury speciation for cyclone-fired boilers................................................ 6-53


6-22. Mercury speciation for FBCs...................................................................................... 6-55


6-23. Relative mercury speciation for FBCs........................................................................ 6-55


7-1.	 Schematic of 10-MWe coal-fired Babcock & Wilcox (B&W) Clean Environment


Development Facility (CEDF) as used for Advanced Emissions Control


Development Program (AECDP) ............................................................................... 7-10


7-2.	 Schematic of Particulate Control Module (PCM) at Public Service Company of


Colorado (PSCO) Comanche Station.......................................................................... 7-11


7-3. Schematic of DOE/NETL in-house 500-lb/hr coal combustion test facility .............. 7-12


7-4.	 Hg removal by activated carbon injection measured at AECDP test facility burning


Ohio bituminous coal and using ESP.......................................................................... 7-22


xii 
Figures (concluded) 

Figure Page No. 

7-5.	 Hg removal by limestone injection measured in Combustion 2000 furnace using


mechanical cyclone separator ..................................................................................... 7-26


7-6.	 Hg removal by limestone injection measured at AECDP test facility burning Ohio


bituminous coal and using ESP................................................................................... 7-27


7-7.	 Effect of using H2S as an oxidation additive on wet FGC scrubber Hg removal


measured at AECDP test facility burning Ohio bituminous coal ............................... 7-34


7-8.	 Effect of using EDTA as an oxidation additive on wet FGD scrubber Hg removal


measured at AECDP test facility burning Ohio bituminous coal ............................... 7-35


7-9.	 Effect of oxidation air on wet FGD scrubber Hg removal as measured at AECDP


test facility burning Ohio bituminous coal.................................................................. 7-39


7-10.	 Effect of oxidation air on Hg0 in wet FGD scrubber flue gas as measured at AECDP


test facility burning Ohio bituminous coal.................................................................. 7-40


7-11.	 Effect of ESP operating voltage on wet FGD scrubber Hg removal as measured at


AECDP test facility burning Ohio bituminous coal ................................................... 7-41


7-12.	 Effect of ESP operating voltage on Hg0 in wet FGD scrubber flue gas as measured at


AECDP test facility burning Ohio bituminous coal .................................................. 7-42


8-1.	 Change in total annual cost resulting from addition of ductwork to provide


additional residence time ........................................................................................... 8-22


8-2.	 Change in total annual cost resulting from use of a composite PAC-lime sorbent


instead of PAC ............................................................................................................ 8-24


9-1. Nationwide CCR management practices in the year 1999 .......................................... 9-5


xiii 
Tables 

Table Page No. 

1-1.	 Current research areas related to controlling Hg emissions from coal-fired electric


utility power plants ..................................................................................................... 1-10


2-1.	 Demonstrated reserve base of major coal ranks in the United States estimated by


DOE/EIA ...................................................................................................................... 2-5


2-2.	 Mercury content of selected as-mined coal samples by coal rank and USGS coal


resource region............................................................................................................. 2-8


2-3. Characteristics of coal-firing configurations used for electric utility power plants ... 2-15


2-4.	 Nationwide distribution of electric utility units by coal-firing configuration for the


year 1999 as reported in the Part II EPA ICR data .................................................... 2-17


2-5.	 Nationwide quantities of coals and supplemental fuels burned in coal-fired electric


utility boilers for the year 1999 as reported in the Part II EPA ICR data .................. 2-23


2-6.	 Mercury content of as-fired coals and supplemental fuels burned in coal-fired electric


utility boilers for the year 1999 as reported in the Part II EPA ICR data .................. 2-25


3-1.	 Criteria air pollutant emission control strategies as applied to coal-fired electric utility


boilers in the United States for the year 1999 as reported in the Part II EPA ICR data 3-6


3-2.	 Nationwide distribution of existing PM emission controls used for coal-fired electric


utility boilers for the year 1999 as reported in the Part II EPA ICR data .................... 3-7


3-3. Comparison of PM collection efficiencies for different PM control device types ...... 3-9


3-4.	 Nationwide distribution of existing SO2 emissions controls used for coal-fired electric


utility boilers for the year 1999 as reported in the Part II EPA ICR data ................... 3-13


3-5.	 Nationwide distribution of existing NOx emissions controls used for coal-fired


electric utility boilers for the year 1999 as reported in the Part II EPA ICR data ...... 3-17


3-6.	 Nationwide distribution of post-combustion emission control configurations used for


coal-fired electric utility boilers for the year 1999 as reported in the Part II EPA ICR


data.............................................................................................................................. 3-20


4-1.	 Summary of selected manual test methods evaluated for measurement of Hg in


combustion gases .......................................................................................................... 4-4


xiv 
Tables (continued) 

Table Page No. 

4-2. Results from EPA Method 301 evaluation tests for the Ontario-Hydro Method ........ 4-9


5-1. Percent oxidation of Hg0 by simulated and actual coal-fired electric utility boiler fly


ash .............................................................................................................................. 5-13


5-2. Comparison of bench-scale fixed-bed with entrained-flow reactors .......................... 5-20


5-3. Composition of test gases to simulate coal combustion flue gas used for UND/EERC


bench-scale study........................................................................................................ 5-29


5-4. Mercury removal by lime sorbent injection as measured by EPA bench-scale tests.. 5-35


5-5.	 Simulated flue gas conditions with the most active catalysts and fly ashes indicated


for oxidation of gaseous Hg0 to gaseous Hg2+ ............................................................ 5-41


6-1. Distribution of ICR mercury emission test data by boiler-coal type configurations .... 6-3


6-2.	 Distribution of ICR mercury emission test data for pulverized-coal-fired boilers by


post-combustion emission control device configuration .............................................. 6-4


6-3.	 Comparison of mercury content normalized by heating value in as-fired coals and


supplemental fuels for electric utility boilers in 1999 .................................................. 6-6


6-4. ICR mercury emission test allocations by coal-boiler-control class........................... 6-16


6-5.	 Average mercury capture by existing post-combustion control configurations used for


PC-fired boilers........................................................................................................... 6-19


6-6.	 Effects of coal and control technology inlet and outlet SPF and capture for


PC-fired boilers........................................................................................................... 6-21


6-7.	 Average mercury emission factors and percent reduction for coal-boiler-control


classes ......................................................................................................................... 6-22


6-8. Number of coal-fired utility boilers equipped with particulate matter controls only . 6-24


6-9. Type of fuel used in PC-fired units equipped with CS-ESP....................................... 6-24


6-10. Post-combustion controls: cold-side ESPs ................................................................. 6-25


6-11. Post-combustion controls: hot-side ESPs ................................................................... 6-31


xv 
Errata Page xvi, dated 3-21-02


Tables (continued) 

Table Page 

No. 

6-12. Mercury (HgT) reduction at PC-fired units with FF baghouses ..................................6-33


6-13. Post-combustion controls: FF baghouses...................................................................6-34


6-14. Post-combustion controls: miscellaneous PM controls .............................................6-37


6-15. Post-combustion controls: dry FGD scrubbers ..........................................................6-38


6-16. PC-fired boiler PM controls for wet FGD systems.....................................................6-42


6-17. Post-combustion controls: wet FGD scrubbers........................................................ 6-43a 

6-18. Wet FGD scrubbers burning bituminous coal.............................................................6-47


6-19. Wet FGD scrubbers burning subbituminous coal ...................................................... 6-48


6-20. Wet FGD scrubbers burning TX lignite......................................................................6-49


6-21.	 Potential effects of post-combustion NOx control technologies on mercury capture


in PC-fired boilers burning bituminous coal...............................................................6-49


6-22. Cyclone-fired boilers...................................................................................................6-51


6-23. Fluidized-bed combustors ...........................................................................................6-52


6-24. Comparison of class average HgT reductions for PC- and cyclone-fired boilers........6-54


6-25. Calculated mercury removal in IGCC power plants using bituminous coal...............6-56


6-26	 Nationwide coal burned and mercury emitted from electric utility coal-fired power


plants in 1999. .............................................................................................................6-59


7-1.	 Comparisons of typical uncontrolled flue gas parameters for coal-fired utility


boiler versus municipal waste combustor (MWC)........................................................7-8


7-2.	 Hg removal by native fly ashes measured across PM control devices at PSCO power


plants burning selected western coals .........................................................................7-17


7-3.	 Hg removals by fly ash reinjection measured across PCM at PSCO Comanche power


plant for selected western coals...................................................................................7-18


xvi 
Tables (continued) 

Table Page No. 

7-4.	 Effect of flue gas temperature on fly ash Hg adsorption measured across PCM at


PSCO Comanche power plant burning PRB subbituminous coal ............................. 7-20


7-5.	 Hg removal by activated carbon injection measured at PSE&G Hudson Station


burning low-sulfur bituminous coal and using ESP .................................................. 7-21


7-6.	 Hg removal by activated carbon injection measured at DOE/NETL in-house test


facility burning low-sulfur bituminous coal and using FF.......................................... 7-24


7-7.	 Comparison of Hg removals for activated carbon injection versus limestone


injection measured at AECDP test facility burning Ohio bituminous coal and using


ESP............................................................................................................................. 7-29


7-8.	 Comparison of field test results using flue gas from electric utility boiler firing Texas


lignite versus bench-scale results using simulated flue gas for selected candidate Hg


oxidation catalysts....................................................................................................... 7-36


8-1. Mercury control technologies ....................................................................................... 8-4


8-2. Matrix of model plant scenarios ................................................................................... 8-6


8-3.	 Estimated total annual mercury control costs for bituminous-coal-fired boiler with


existing CS-ESP.......................................................................................................... 8-12


8-4.	 Estimated total annual mercury control costs for subbituminous-coal-fired boiler


with existing CS-ESP.................................................................................................. 8-15


8-5.	 Estimated total annual mercury control costs for subbituminous-coal-fired boiler


with existing FF ......................................................................................................... 8-16


8-6.	 Impact of acid dew point setting on annual mercury control costs for a 500-MWe


electric utility boiler burning bituminous coal............................................................ 8-19


8-7.	 Impact of acid dew point setting on annual mercury control costs for a 500-MWe


electric utility boiler burning subbituminous coal ...................................................... 8-20


8-8.	 Effect of PAC recycle on annual mercury control costs for a 500-MWe electric utility


boiler burning bituminous coal ................................................................................... 8-21


8-9. Projected future mercury control costs ....................................................................... 8-26


xvii 
Tables (concluded) 

Table Page No.


8-10. Comparison of mercury control costs with NOx control costs ................................... 8-28


9-1. Coal combustion residues ............................................................................................. 9-3


9-2. Calculated Hg concentrations in CCRs using EPA ICR data ....................................... 9-3


9-3. Summary of available test data on Hg concentrations in major types of CCRs........... 9-4


9-4. Commercial uses for CCRs generated in 1999............................................................. 9-7


xviii 
Acronyms


ADP Acid Dew Point 

AES Atomic Emission Spectrometry 

AHC Advanced Hybrid Collector 

ASTM American Society for Testing and Materials 

CAA Clean Air Act 

CCR Coal Combustion Residues 

CEM Continuous Emission Monitors 

CFBA Circulating Fluidized-bed Adsorber 

COHPAC Compact Hybrid Particulate Collector 

CS-ESP Cold-side Electrostatic Precipitator 

CuCl Cuprous Chloride 

CVAAS Cold-vapor Atomic Absorption Spectrometry 

CVAFS Cold-vapor Atomic Fluorescence Spectrometry 

DI Dry Injection 

DOE United States Department of Energy 

EPA United States Environmental Protection Agency 

EPRI Electric Power Research Institute 

ESP Electrostatic Precipitator 

ETV Environmental Technology Verification 

FBC Fluidized-bed Combustion 

FF Fabric Filter 

FGD Flue Gas Desulfurization 

HAP Hazardous Air Pollutant 

Hg Mercury 

Hg0 Elemental Mercury 

HgO Mercuric Oxide 

Hg2+ Oxidized or Ionic Mercury 

Hgp Particle-bound Mercury 

HgT Total Mercury 

HgCl2 Mercuric Chloride 

HgSO4 Mercuric Sulfate 

HS-ESP Hot-side Electrostatic Precipitator 

xix 
Acronyms (continued) 

IGCC Integrated Gasification Combined Cycle


ICR Information Collection Request


kWh Kilowatt Hour


LNB Low NOx Burner


MC Mechanical Collector


MESA Mercury Speciation Adsorption


MWC Municipal Waste Combustor


MWe Megawatt Electric


MWFA Mixed Waste Focus Area


NESCAUM Northeast States for Coordinated Air Use Management


NETL National Energy Technology Laboratory (DOE)


NOx Nitrogen Oxides


OAR EPA’s Office of Air and Radiation


OH Method Ontario-Hydro Method


O&M Operation and Maintenance


PAC Powdered Activated Carbon


PFF Polishing Fabric Filter


PM Particulate Matter


PRB Powder River Basin


PS Particle Scrubber


PTFE Polytetrafluoroethylene


QA/QC Quality Assurance/Quality Control


RfD Reference Dose


SC Spray Cooling


SCR Selective Catalytic Reduction


SDA Spray Dryer Adsorber


SEM Scanning Electron Microscope


SNCR Selective Noncatalytic Reduction


xx 
Acronyms (concluded) 

TGM Total Gaseous Mercury 

UND/EERC	 University of North Dakota/Energy and Environmental 

Research Center 

UVDOAS Ultraviolet Differential Optical Absorption Spectroscopy 

Wet FGD Flue Gas Desulfurization by Liquid Scrubbing 

xxi 
Errata Page xxii, dated 4-23-02 

Acknowledgements 

This report summarizes and interprets research sponsored by the U.S. Environmental 

Protection Agency (EPA), the U.S. Department of Energy, the Electric Power Research 

Institute, and other organizations. The Research Triangle Institute (RTI) was instrumental in 

summarizing the Phase I and Phase II Mercury Information Collection Requests. The RTI 

summaries provided: data on equipment used at coal-fired utility electrical generating plants 

in 1999, data on coal characteristics and usage, and estimates of the 1999 annual mercury 

emissions. RTI staff members who made significant contributions to this effort included 

Jeffrey Cole, Paul Peterson, James Turner, and Robert Zerbonia. Many thanks to William H. 

Maxwell of EPA’s Office of Air Quality Planning and Standards, Research Triangle Park, NC, 

who reviewed the draft version of this report and provided many helpful suggestions. 

The report was reviewed by an external peer review panel chaired by Constance L. 

Senior of Reaction Engineering International, Salt Lake City, UT. The panel also included 

Praveen Amar, Director of Science and Policy at NESCAUM, Boston, MA, and Massoud 

Rostam-Abadi, Senior Chemical Engineer at Illinois State Geological Survey and Adjunct 

Professor of Environmental Engineering at the University of Illinois at Urbana-Champaign, 

Champaign, IL. They provided many excellent comments and advice that resulted in 

substantial improvements in the document. 

xxii 
Executive Summary 

Overview 

This report documents current knowledge on the emission and control of mercury (Hg) 

from coal-fired electric utility plants. The purpose of the report is to provide information on the 

status of government and industry efforts in developing improved technologies for the control of 

Hg emissions. 

This is an interim report, which contains information available in the public domain prior 

to June 2001. Since then, the results of additional research have been published. This additional 

information can be found in DOE, EPA, and EPRI reports, in journal articles, and in the 

proceedings of conferences. Two recent conferences provided significant new information on 

the control of Hg emissions -- the A&WMA 2001 Annual Conference (Orlando, FL, June 2001), 

and the A&WMA Specialty Conference on Mercury (Chicago, IL, August 2001). 

The first part of the report (Chapters 1 through 3) is directed to readers outside the 

research community who are interested in Hg emission and Hg control issues. Information is 

provided on: 

•	 Legislative and regulatory background of EPA’s December 2000 decision to regulate 

Hg emissions from coal-fired electric utility generating stations, 

• Studies made in support of EPA's regulatory determination, 

•	 Fuels, combustion technologies, and pollution control technologies used for coal-fired 

steam electric generating units, and 

•	 Research results from an official Information Collection Request (ICR) on the fuels 

and technologies used by the utility industry in 1999 at coal-fired steam electric 

generating stations. 

The second part of the report (Chapters 4 through 10) is directed to all readers. It focuses 

on the review and evaluation of information that has been gathered since the publication of: 

EPA's Mercury Study Report to Congress; EPA’s Study of Hazardous Air Pollutant Emissions 

from Electric Utility Steam Generating Units--Final Report to Congress; and the A&WMA 

ES-1

Critical Review: Mercury Measurement and Its Control. The second part of the report contains 

information on: 

• Hg measurement methods, 

• Forms of Hg (speciation) and the capture of Hg in flue gas from combustion of coal, 

•	 Evaluation of the ICR flue gas data on Hg concentrations upstream and downstream 

of air pollution control devices (APCDs), 

•	 Summary of retrofit control technologies that can be used to limit Hg emissions at 

coal-fired plants currently equipped with particulate matter (PM) control devices, 

and dry or wet flue gas desulfurization (FGD) scrubbing systems, 

•	 Estimates of the costs of controlling Hg emissions by the use of powdered activated 

carbon (PAC), 

•	 Overview of the current coal combustion residue (CCR) management practices and 

the identification of environmental issues requiring additional research, and 

• Conclusions, overview of current research, and research recommendations. 

Detailed supporting information is provided in Appendices. 

Background 

The 1990 Clean Air Act Amendments required EPA to study the health and 

environmental impacts of hazardous air pollutants (HAPs) emitted from electric utility boilers. 

The Agency was also required to conduct a study of the potential health and environmental 

impacts of Hg emitted from anthropogenic sources in the United States. The EPA subsequently 

published an 8-volume Mercury Study Report to Congress in December 1997 and a Study of 

Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Units--Final Report 

to Congress in February 1998. The Hg report to Congress identified coal-fired utility boilers as 

the largest single anthropogenic source of Hg emissions in the United States. The utility HAP 

report indicated that there was a plausible link between Hg emissions from coal-fired boilers and 

health risks posed by indirect exposure to methylmercury. 

In December 2000, EPA announced its intent to regulate HAP emissions from coal- and 

oil-fired electrical generating stations. The decision to regulate HAP emissions from coal-fired 

units was based on: 

ES-2

• A National Academy of Science study on the health effects of methylmercury, 

•	 The collection and analysis of coal- and flue-gas Hg data under an official Information 

Collection Request (ICR), and 

• Studies concerning the status of Hg emission control technologies. 

Three important milestones are incorporated in EPA's decision to regulate HAP 

emissions from coal-fired electric generating units: 

• The proposal of regulations by December 2003, 

• The promulgation of regulations by December 2004, and 

• Compliance with the regulations by December 2007. 

Electric Utility Coal Combustion and Air Pollution Control Technologies 

The EPA ICR data collection effort was conducted in three phases. In Phase I, 

information was collected on the fuels, boiler types, and air pollution control devices (APCDs) 

used at all coal-fired utility boilers in the United States. In Phase II, coal data were collected and 

analyzed by the utility industry for 1,140 coal-fired and three integrated gasification, combined 

cycle (IGCC) electric power generating units. Each coal sample was analyzed for Hg content, 

chlorine (Cl) content, sulfur content, moisture content, ash content, and calorific value. In Phase 

III, flue gas Hg measurements were made using the modified Ontario-Hydro (OH) Method for 

total and speciated Hg. Additional coal samples were collected and analyzed in conjunction with 

the OH Method measurements. 

The EPA ICR data indicated that, in 1999, coal-fired steam electric generating units in the 

U.S. burned 786 million tons of coal of which about 52 percent was bituminous and 37 percent 

was subbituminous. Other fuels included lignite, anthracite coal, reclaimed waste coal, mixtures 

of coal and petroleum coke (pet-coke), and mixtures of coal and tire-derived fuel (TDF). 

Pulverized coal-fired (PC) boilers represent approximately 86 percent of the total number and 90 

percent of total utility boiler capacity. Based on capacity, other types of boilers include cyclonefired boilers (7.6 percent), fluidized-bed combustors (1.3 percent), and stoker-fired boilers (1.0 

percent). 

The 1999 EPA ICR responses indicate that a variety of emission control technologies are 

employed to meet requirements for sulfur dioxide (SO2), nitrogen oxides (NOx), and particulate 

matter (PM). Most utilities control NOx by combustion modification techniques and SO2 by the 

use of compliance coal. For post-combustion controls, 77.4 percent of the units have PM control 

only, 18.6 percent have both PM and SO2 controls, 2.5 percent have PM and NOx controls, and 1.3 

percent have three post-combustion control devices. 

ES-3

The different types of post-combustion control devices are listed below: 

Particulate matter (PM) control technologies include electrostatic 

precipitators (ESPs), fabric filters (FFs) (also called “baghouses”), and 

particulate scrubbers (PS). ESPs and FFs may be classified as either coldside (CS) devices [installed upstream of the air heater where flue gas 

temperatures range from 284 to 320 oF (140 to 160 °C)] or hot-side 

[installed downstream of the air heater and operate at temperatures ranging 

from 662 to 842 oF (350 to 450 °C)]. Based on current information, it 

appears that little Hg can be captured in HS-ESPs. 

SO2 post-combustion control technologies are systems that are classified as 

wet flue gas desulfurization (FGD) scrubbers, semi-dry scrubbers, or dry 

injection. Wet FGD scrubber controls remove SO2 by dissolving it in a 

solution. A PM control device is always located upstream of a wet 

scrubber. PM devices that may be used with wet FGD scrubbers include a 

PS, CS-ESP, HS-ESP, or FF baghouse. Semi-dry scrubbers include spray 

dryer absorption (SDA). Dry injection involves injecting dry powdered 

lime or other suitable sorbent directly into the flue gas. A PM control 

device (ESP or FF) is always installed downstream of a semi-dry scrubber 

or dry injection point to remove the sorbent from the flue gas. 

NOx post-combustion control technologies include selective non-catalytic 

reduction (SNCR) and selective catalytic reduction (SCR) processes. With 

both of these methods, a reducing agent such as ammonia or urea is 

injected into the duct to reduce NOx to N2. SCR operates at lower 

temperatures than SNCR and is more effective at reducing NOx, but it is 

more expensive. 

For PM control, ESPs are used on 84 percent of the existing electric utility coal-fired 

boiler units, and FF baghouses are used on 14 percent of the utility units. Post-combustion SO2 

controls are less common. Wet flue gas desulfurization (FGD) systems are used on 15.1 percent 

of the units; and, dry scrubbers, predominantly spray dryer absorbers (SDA), are used on 4.6 

percent of units that were surveyed. While the application of post-combustion NOx controls is 

becoming more prevalent, only 3.8 percent of units used either selective non-catalytic reduction 

(SNCR) or selective catalytic reduction (SCR) systems in 1999. 

Mercury Measurement Methods 

When the coal is burned in an electric utility boiler, the resulting high combustion 

temperatures vaporize the Hg in the coal to form gaseous elemental mercury (Hg0

). Subsequent 

cooling of the combustion gases and interaction of the gaseous Hg0 with other combustion 

products result in a portion of the Hg being converted to gaseous oxidized forms of mercury 

(Hg2+) and particle-bound mercury (Hgp). The term speciation is used to denote the relative 

ES-4

amounts of these three forms of Hg in the flue gas. The total Hg in flue gas (HgT) is the sum of 

Hgp, Hg2+, and Hg0. It is the ability to measure these forms of Hg, either collectively or 

individually, which distinguishes the capabilities of available measurement methodologies. 

The Hg in flue gas can be measured by either manual sampling methods or by the use of a 

continuous emission monitor (CEM). Manual methods are available for the measurement of HgT 

and the speciation of Hg, including Hgp. CEMs are now available to measure gas-phase HgT. 

Manual Test Methods 

Manual sampling methods for measuring HgT from combustion processes are well 

established. EPA Methods 101A and 29 are routinely used to measure HgT in flue gas from 

incineration and coal combustion. While a validated reference method for the measurement of 

the speciated forms of Hg does not exist, the Ontario-Hydro (OH) method is the de facto method 

of choice. 

Generally, sampling trains used to collect flue gas samples for Hg analysis consist of the 

same components: a nozzle and probe operated to extract a representative sample from a duct or 

stack; a filter to collect PM; and a series of impingers with liquid reagents to capture gas-phase 

Hg. Sampling trains used for speciation measurements sequentially capture Hg2+ and Hg0 in 

different impingers. After sampling, the filter and sorption media are prepared and analyzed for 

Hg in a laboratory. 

While several research methods exist for performing speciated Hg measurements, the OH 

Method is presently the method of choice for measuring Hg species in the flue gas from coalfired utility plants. The OH method has been shown to provide valid Hg speciation 

measurements when samples are taken downstream of an efficient PM control device. However, 

the OH Method can give erroneous speciation measurements for locations upstream of PM 

control devices because of sampling artifacts. 

Fly ash captured by the sampling train filter can absorb Hg2+ and Hg0

. Catalytic 

properties of the fly ash can also oxidize Hg0

, resulting in physical and chemical transformations 

within the sampling train. Transformations caused by the sampling process are called artifacts, 

and the resulting measurements do not accurately reflect critical properties of Hg at the locations 

where the samples were taken. Sampling methods have not yet been developed to overcome 

measurement artifacts associated with high flue gas concentrations of fly ash. 

Continuous Emission Monitors (CEMs) 

Continuous emission monitors (CEMs) are in some respects superior to manual 

measurement methods. CEMs provide a rapid real-time or near real-time response, which can be 

used to characterize temporal process variations that cannot be measured with manual 

measurement methodologies. Mercury CEMs are similar to most combustion process CEMs in 

that a flue gas sample must be extracted from the stack and then transferred to the analyzer for 

ES-5

detection. However, Hg monitoring is complicated by the fact that Hg exists in different forms 

and that quantitative transport of all forms is difficult. 

The CEMs designed to measure total gas-phase Hg (Hg2+ and Hg0) are now routinely 

used in Europe and Japan to measure Hg emissions from incinerators. The Hg concentrations in 

the stack gas from well-controlled emission sources contain negligible amounts of Hgp, and the 

measurement of gas-phase Hg downstream of the emission control devices can be considered to 

be equivalent to the measurement of HgT. 

The detectors in Hg CEMs typically measure Hg0 by the use of cold vapor atomic 

absorption spectroscopy (CVAAS) or cold vapor atomic fluorescence spectroscopy (CVAFS). 

0 HgT concentrations are measured by converting (reducing) all of the Hg2+ in the sample to Hg 

before it enters the detector. Various conversion techniques exist, including thermal, catalytic, 

and wet chemical methods. The wet chemical technique is currently used in commercial 

monitors that are capable of speciation measurement. The use of wet chemical reagents results in 

high operating costs, which are the primary limitation to the Hg CEM’s use as a compliance tool. 

Speciating Hg CEMs are highly valuable as research tools. Several commercially 

available HgT CEMs have been modified to indirectly measure Hg2+ by determining the 0 difference between gas-phase HgT and Hg . Hg CEMs are susceptible to the same PM-related 

measurement artifacts associated with manual measurements, and users of Hg CEMs in high dust 

conditions must consider this problem. 

Regardless of the sampling method, the key to reliable and accurate Hg sampling and 

continuous monitoring is maintaining sample integrity. Flue gases may contain particles that 

change the species of Hg within the sampling train or CEM system. While this does not change 

the total Hg measurement, it may bias the determination of Hg vapor species, which may be used 

to estimate the potential for Hg capture, as well as to assess the performance of control devices. 

Similarly, common flue gas constituents, such as SO2, HCl and NOx, may affect quantitative 

measurement performance. 

Additional research is needed to investigate and overcome measurement obstacles so that 

speciating CEMs can serve as process monitors and as a research tool for evaluating the 

effectiveness of emission controls. Such research can also provide a better understanding of the 

factors that affect Hg speciation. 

Speciation and Capture of Mercury 

Mercury Speciation 

The capture of Hg by flue gas cleaning devices is dependent on Hg speciation. Both Hg0 

and Hg2+ are in vapor-phase at flue gas cleaning temperatures. Hg0 is insoluble in water and 

cannot be captured in wet scrubbers. The predominant Hg2+compounds in coal flue gas are 

weakly to strongly soluble, and the more-soluble species can be generally captured in wet FGD 

ES-6

scrubbers. Both Hg0 and Hg2+ are adsorbed onto porous solids such as fly ash, powdered 

activated carbons (PAC), or calcium-based acid gas sorbents for subsequent collection in a PM 

control device. Hg2+ is generally easier to capture by adsorption than Hg0

. Hgp is attached to 

solids that can be readily captured in ESPs and FFs. 

Flue gas cleaning technologies that are applied on combustion sources employ three basic 

methods to capture Hg: 

• Capture of Hgp in PM control devices; 

•	 Adsorption of Hg0 and Hg2+ onto entrained sorbents for subsequent capture in PM 

control devices; and 

• Solvation of Hg2+ in wet scrubbers. 

The factors that affect the speciation and capture of Hg in coal-fired combustion systems 

include the type and properties of coal, the combustion conditions, the types of flue gas cleaning 

technologies employed, and the temperatures at which the flue gas cleaning systems operate. 

Oxidation reactions that affect the speciation of Hg include homogeneous, gas-phase 

reactions and heterogeneous gas-solid reactions associated with entrained particles and surface 

deposits. Suspected flue gas oxidants involved in Hg0 oxidation include oxygen (O2), ozone (O3), 

hydrochloric acid (HCl), chlorine (Cl), nitrogen dioxide (NO2) and sulfur trioxide (SO3). Many 

of these oxidants are also acid species, which may be significantly impaired by the presence of 

alkaline species in fly ash, such as sodium, calcium and potassium. Heterogeneous oxidation 

reactions may be catalyzed by metals such as iron, copper, nickel, vanadium, and cobalt. 

Conversion of Hg0 to Hg2+ may be followed by adsorption to form Hgp. 

The determination of which mechanisms, oxidants, and catalysts are dominant is crucial 

in developing and implementing Hg control strategies. For example, the impaired oxidation of 

Hg in subbituminous coals and lignites is probably related to lower concentrations of HCl in flue 

gas and high alkalinity of the fly ash. PM collectors and scrubbers reflect this in the low 

removals of Hg in the ICR database. 

Fundamentals of Sorption 

Sorbents used for the capture of Hg can be classified as Hg sorbents or multipollutant 

sorbents. Sorbents evaluated for Hg capture have been manufactured from a number of different 

materials such as lignite, bituminous coal, zeolites, waste biomass, and waste tires. The 

manufacturing process typically involves some type of thermal treatment. Additives are often 

used to produce impregnated sorbents. 

For coal-fired electric utility boiler applications, the use of sorbents to capture gas-phase 

Hg (or gas-phase Hg and acid gases) is limited to the use of finely ground powdered sorbents. 

These sorbents can be injected upstream of PM control devices to collect the sorbent and 

adsorbed Hg. The development of improved sorbents is needed because of poor sorbent 

ES-7

utilization that results from low flue gas concentrations of Hg and short sorbent exposure times 

in units equipped with CS-ESPs. The performance of a sorbent is related to its physical and 

chemical characteristics. The best performing sorbents must be carefully matched to 

performance requirements as defined by the application for which it is to be used. For example, 

properties and performance requirements of sorbents used for capture of SO2 and Hg0 are quite 

different. In a similar fashion, the performance criteria for sorbents used with flue gas from 

bituminous coal will probably be different from the sorbents used with sub-bituminous coals. 

Sorbents are porous materials. The most common physical properties related to sorbent 

performance are surface area, pore size distribution, and particle size distribution. The capacity 

for Hg capture generally increases with increasing surface area and pore volume. The ability of 

Hg and other sorbates to penetrate into the interior of a particle is related to pore size distribution. 

The pores of the sorbent must be large enough to provide free access to internal surface area by 

Hg0 and Hg2+ while avoiding excessive blockage by previously adsorbed reactants. As particle 

size decreases, access to the internal surface area of the particle increases, along with potential 

adsorption rates. Powdered activated carbons used for Hg control typically have diameters of 44 

μm or smaller. 

Mercury can be either physically or chemically adsorbed. Physical adsorption 

(physisorption) typically results from van der Waals and Coulombic (electrostatic) interactions 

between the sorbent and the sorbate. The resulting bonds are weak (typically < 10-15 kcal/mole) 

and are easily reversed. 

Chemical adsorption (chemisorption) involves the establishment of a chemical bond (as 

the result of a chemical reaction, electron transfer). Chemisorption results in stronger bonds than 

physisorption and is not necessarily reversible. Chemical adsorption is also dependent on the 

presence of chemically active sites where the sorbate is chemically bound. Some of the chemical 

constituents of activated carbons influencing Hg capture include: sulfur content, iodine content, 

and chlorine content. Impregnation of carbons with sulfur, iodine, or chlorine can increase the 

reactivity and capacity of sorbents. Hg0 is likely oxidized and sorbed in a rapid two step reaction, 

either chemically by reaction with strong ionic groups such as Cl-, I-, or S= or physically through 

interaction with functional groups in sorbent pores. 

The HgCl2 is readily adsorbed onto both carbon and calcium based sorbents, probably 

by acid-base reactions. Section 5.5 details the fundamental research to develop carbon and 

calcium sorbents for Hg vapor capture. 

Evaluation of Sorbents 

Sorbents may be evaluated by bench-, pilot-scale, or full-scale experiments. The initial 

screening of sorbents has typically been conducted using bench-scale, packed-bed experimental 

reactors. These reactors are used to evaluate the adsorption capacity of sorbents exposed to Hg 

in a synthetic flue gas made from compressed bottled gases. The reactor is held at a 

predetermined temperature, and either Hg0 or HgCl2 is fed into the synthetic flue gas upstream of 

ES-8

the reactor. An on-line Hg analyzer is used to continuously monitor the Hg content of the inlet 

flue gas and of that after exposure to the sorbent fixed bed. These reactors are used to determine 

the effects of temperature and flue gas composition on the performance of sorbents. These 

reactors provide results that are primarily applicable to the capture of Hg in FF baghouses. 

Flow reactors that expose sorbents to flue gas during short residence experiments can be 

used to simulate conditions associated with ESPs. These reactors can be used to explore the rates 

of Hg adsorption and determine the effects of temperature and flue gas composition. The most 

effective screening tests are conducted with reactors that are installed on a slip stream from a 

pilot- or full-scale coal combustion system. Large pilot- or full-scale tests must be used to 

assess the effects of mass transfer limitations (i.e., mixing and diffusion of flue gas constituents) 

and long-term equipment operability. 

Wet FGD Scrubbers 

Oxidized mercury compounds such as HgCl2 are soluble in water and alkaline scrubbing 

solutions. Thus, the oxidized fraction of Hg vapors in flue gas is effectively captured when a 

power plant is operated with wet or semi-dry scrubbers for removing SO2. The elemental 

fraction, on the other hand, is insoluble and is not removed to any significant degree. The 

challenge to Hg removal in wet FGD scrubbers, then, is to find some way to oxidize the 

elemental Hg vapor before it reaches the scrubber or to modify the liquid phase of the scrubber to 

cause oxidation to occur. 

Evaluation of EPA ICR Mercury Emissions Data 

The methods used to evaluate the ICR data were based on two interrelated objectives. The 

first method was to estimate the speciated amount and the geographical distribution of national Hg 

emissions from coal-fired power plants in 1999. The second method was to characterize the 

effects of coal properties, combustion conditions, and flue gas cleaning methods on the speciation 

and capture of Hg. 

Mercury Capture by Existing Air Pollution Control Devices 

The air pollution control technologies now used on pulverized-coal-fired utility boilers 

exhibit average levels of Hg control that range from 0 to 98 percent, as shown in Table ES-1. The 

best levels of control are generally obtained by emission control systems that use FFs. The 

amount of Hg captured by a given control technology is better for bituminous coal than for either 

subbituminous coal or lignite. 

The lower levels of Hg capture in plants firing subbituminous coal and lignite are 

attributed to low fly ash carbon content and the higher relative amounts of Hg0 in the flue gas from 

combustion of these fuels. The average capture of Hg based on OH Method inlet measurements 

in PC fired plants equipped with a cold-side ESP is 35 percent for bituminous coal, 3 percent for 

sub-bituminous coal and near zero for lignite. 

ES-9

Errata Page ES-10, dated 3-21-02 

Table ES-1. Mean mercury emission reduction for pulverized-coalfired boilers. 

Post-combustion Emission 

Controls 

Used for PC Boiler 

Average Mercury Emission Reduction (%) a 

Bituminous-coalfired Subbituminouscoal-fired Lignitefired 

PM Control 

Only 

CS-ESP 36 % 3 % -4 % 

HS-ESP 9 % 6 % not tested 

FF 90 % 72 % not tested 

PS not tested 9 % not tested 

PM Control 

and 

Spray Dryer 

Adsorber 

SDA + ESP not tested 35 % not tested 

SDA + FF 98 % 24 % 0 % 

SDA + FF + 

SCR 98 % not tested not tested 

PM Control 

and 

Wet FGD 

System 

PS + FGD 12 % -8 % 33 % 

CS-ESP + FGD 75 % 29 % 44 % 

HS-ESP + FGD 49 % 29 % not tested 

FF + FGD 98 % not tested not tested 

a) Mean reduction from test 3-run averages for each PC boiler unit in Phase III EPA ICR data base. 

Plants that employ only post-combustion PM controls display average Hg emission 

reductions ranging from 0 to 89 percent. The highest levels of control were observed for units 

with FFs. Decreasing levels of control were shown for units with ESPs, PS, and mechanical 

collectors. 

Units equipped with lime spray dryer absorber scrubbers (SDA/ESP or SDA/FF 

systems) exhibited average Hg captures ranging from 98 percent for units burning bituminous 

coals to 3 percent for units burning subbituminous coal. The predominance of Hg0 in stack gas 

units that are fired with subbituminous coal and lignite results from low levels of Hg0 

oxidization. 

The capture of Hg in units equipped with wet FGD scrubbers is dependent on the 

relative amount of Hg2+ in the inlet flue gas and on the PM control technology used. Average 

Hg captures in wet FGD scrubbers ranged from 23 percent for one PC-fired HS-ESP + FGD 

unit burning subbituminous coal to 97 percent in a PC-fired FF + FGD unit burning 

bituminous coal. The high Hg capture in the FF + FGD unit is attributed to increased 

oxidization and capture of Hg in the FF. 

Mercury captures in PC-fired units equipped with spray dry scrubbers and wet limestone 

scrubbers appear to provide similar levels of control on a percentage reduction basis. However, 

this observation is based on a small number of short-term tests at a limited number of facilities. 

ES-10

Additional testing will be required to characterize the effects of fuel, combustion conditions, and 

APCD conditions on the speciation and capture of Hg. 

National Emission Estimates 

The data used for estimating the national Hg emissions were: (1) the mean Hg content of 

coal burned in any given unit during 1999, (2) the amount of coal burned in that unit during 1999, 

and (3) best match coal-boiler-control device emission factor for the unit. The results of these 

estimates indicated that: 

•	 Coal and related fuels burned in coal-fired utility boilers in 1999 contained 75 tons of 

Hg, and 

•	 Forty-eight tons of Hg was emitted to the atmosphere in 1999 from coal-fired utility 

power plants. 

Multipollutant Controls 

The EPA ICR data indicate that technologies currently in place for control of criteria 

pollutants achieve reductions in Hg emissions that range from 0 to > 90 percent. Current levels 

of Hg control can be increased by application of retrofit technologies or methods designed to 

increase capture of more than one pollutant. This multipollutant approach can utilize the 

synergisms that accrue through the simultaneous application of technologies for NOx and Hg 

control, SO2 and Hg control, or SO2, NOx, and Hg control. 

Bench- and pilot-scale tests have shown that Hg capture in PM control devices generally 

increases as the carbon content of fly ash increases. Increased use of combustion modification 

techniques that increase ash carbon content will generally increase the amount and capture of 

Hgp. 

The EPA ICR data indicate that SCR systems may enhance the oxidation and capture of 

Hg. Recent pilot- and full-scale tests on bituminous coal-fired units equipped with SNCR + CSESP and SCR + SDA/FF systems have confirmed these results. However, improvement in Hg 

capture appears to be highly dependent on the type of coal burned and the design and operating 

conditions of SCR systems. The potential in increased Hg capture associated with the NOx 

control system cannot now be quantified. It is believed, however, that the use of combustion 

modification techniques and post combustion NOx control technologies on NOx state 

implementation plan (SIP) units will also increase the capture of Hg in these units. 

The retrofit of coal-fired electric utility boiler units to control emission of SO2 and fine 

PM is also expected to provide co-benefits in the control of Hg. This is apparent from the 

increased control of Hg on units equipped with FFs, dry FGD scrubbers, and wet FGD scrubbers. 

Mercury or multipollutant sorbents will add minimal capital costs to units that are retrofitted with 

FFs or SDA/FF for control of other pollutants. The use of multipollutant sorbents would be more 

ES-11

costly, but the incremental costs of Hg control would be modest. Technologies designed for use 

on existing wet FGD units could also be used for new scrubbers that are intended to control SO2 

and the precursors to secondary fine PM. 

Generally, the control of Hg emissions via multipollutant control technologies can 

provide a cost-effective method for collectively controlling the various pollutants of concern. 

Potential Retrofit Mercury Control Technologies 

A practical approach to controlling Hg emissions at existing utility plants is to minimize 

capital costs by adapting or retrofitting the existing equipment to capture Hg. Potential retrofit 

options for control of Hg were investigated for units that currently use any of the following post 

combustion emission control methods: (1) ESPs or FFs for control of PM, (2) dry FGD 

scrubbers for control of PM and SO2, and (3) wet FGD scrubbers for the control of PM and SO2. 

ESP and FF Systems 

Least costly retrofit options for the control of Hg emissions from units with ESP or FF are 

believed to include: 

•	 Injection of a sorbent upstream of the ESP or FF. Cooling of the stack gas or 

modifications to the ducting may be needed to keep sorbent requirements at acceptable 

levels. 

•	 Injection of a sorbent between the ESP and a pulsejet FF retrofitted downstream of the 

ESP. This approach will increase capital costs but reduce sorbent costs. 

•	 Installation of a semi-dry circulating fluidized-bed absorber (CFA) upstream of an 

existing ESP used in conjunction with sorbent injection. The CFA recirculates both fly 

ash and sorbent to create an entrained bed with a large number of reaction sites. This 

leads to higher sorbent utilization and enhanced fly ash capture of Hg and other 

pollutants. 

Units equipped with a FF require less sorbent than units equipped with an ESP. ESP 

systems depend on in-flight adsorption of Hg by entrained fly ash or sorbent particles. FFs 

obtain the same in-flight Hg adsorption as ESPs and additional adsorption as the flue gas passes 

through the FF cake. 

In general, the successful application of cost-effective sorbent injection technologies for 

ESP and FF units will depend on: (1) the development of lower cost and/or higher performing 

sorbents, and (2) appropriate modifications to the operating conditions of equipment being 

currently used to control emission of PM, NOx, and SO2. 

ES-12

Semi-Dry FGD Systems 

SDA systems that use calcium-based sorbents are the most common dry FGD systems 

used in the electric utility industry. An aqueous slurry containing the sorbent is sprayed into an 

absorber vessel where the flue gas reacts with the drying slurry droplets. The resulting, particleladen, dry flue gas then flows to an ESP or a FF where fly ash and SO2 reaction products are 

collected. 

CFAs are “vertical duct absorbers” that allow simultaneous gas cooling, sorbent injection 

and recycle, and gas absorption by flash drying of wet lime reagents. It is believed that CFAs can 

potentially control Hg emissions at costs lower than those associated with use of spray dryers. 

Dry FGD systems are already equipped to control emissions of SO2 and PM. The 

modification of these units by the use of appropriate sorbents for the capture of Hg and other air 

toxics is considered to be the easiest retrofit problem to solve. 

Wet FGD Systems 

Wet FGD systems are typically installed downstream of an ESP or FF. Wet limestone 

FGD scrubbers are the most commonly used scrubbers on coal-fired utility boilers. These FGD 

units are expected to capture more than 90 percent of the Hg2+ in the flue gas entering the 

scrubber. Consequently, existing wet FGD scrubbers may lower Hg emissions between 20 and 

80 percent, depending on the speciation of Hg in the inlet flue gas. 

Improvements in wet scrubber performance in capturing Hg depend primarily on the 

oxidation of Hg0 to Hg2+. This may be accomplished by (1) the injection of appropriate 

oxidizing agents or (2) the installation of fixed oxidizing catalysts upstream of the scrubber to 

promote oxidization of Hg0 to soluble species. 

An alternative strategy for controlling Hg emissions from wet FGD scrubbing systems is 

to inject sorbents upstream of the PM control device. In wet FGD systems equipped with ESPs, 

performance gains are limited by the in-flight oxidization of Hg0 and the in-flight capture of Hg2+ 

and Hg0. In systems equipped with FFs, increased oxidization and capture of Hg can be achieved 

as the flue gas flows through the FF. Increased oxidization of Hg0 in the FF will result in 

increased Hg removal in the downstream scrubber. 

Multipollutant Control Methods 

From a long-term perspective, the most cost-effective Hg controls will be those 

implemented with a multipollutant emission control scheme, wherein Hg sorbents also remove 

other pollutants, and catalysts and absorbers are employed to remove bulk contaminants such as 

NO and SO2. Mercury is also removed as a consequence of using particular bulk gas sorbents, 

catalysts, particle collectors, and absorbers. Therefore, while sorbents injected upstream of PM 

collectors may be readily employed for Hg control, the best long-term schemes will result from 

ES-13

modifying or adding control systems for other pollutants that also control Hg emissions. Chapter 

9 discusses several applications under development. 

Costs of Retrofit Mercury Control Technologies 

Preliminary annualized costs of Hg controls using powdered activated carbon (PAC) 

injection have been estimated based on recent pilot-scale evaluations with commercially 

available adsorbents (see Table ES-2). These control costs range from 0.305 to 3.783 mills/kWh, 

with the highest costs associated with plants having hot-side electrostatic precipitators (HSESPs). For plants representing 89 percent of current capacity and using controls other than HSESPs, the costs range from 0.305 to 1.915 mills/kWh. Assuming a 40 percent reduction in 

sorbent costs by use of a composite lime-PAC sorbent for Hg removal, cost projections range 

from 0.18 to 2.27 mills/kWh with higher costs again being associated with plants using HSESPs. 

Table ES-2. Estimates of current and projected annualized operating costs for 

retrofit mercury emission control technologies. 

Coal Type 

(sulfur content) 

Existing 

APCD a 

Retrofit 

Mercury Control b 

Current Cost 

(mills/kWh) 

Projected Cost 

(mills/kWh) 

CS-ESP+FGD PAC 0.727 – 1.197 0.436 – 0.718 

FF+FGD PAC 0.305 – 0.502 0.183 – 0.301 Bituminous 

(3% S) 

HS-ESP+FGD PAC+PFF 1.501 – NAc 0.901 – NAc 

CS-ESP SC+PAC 1.017 – 1.793 0.610 – 1.076 

FF SC+PAC 0.427 – 0.753 0.256 – 0.452 Bituminous 

(0.6% S) 

HESP SC+ PAC+PFF 1.817 – 3.783 1.090 – 2.270 

CS-ESP SC+PAC 1.150 – 1.915 0.69 – 1.149 

FF SC+PAC 0.423 – 1.120 0.254 – 0.672 Subbituminous 

(0.5% S) 

HESP SC+PAC+PFF 1.419 – 2.723 0.851 – 1.634 

a)	 CS-ESP = cold-side electrostatic precipitator; HS-ESP = hot-side electrostatic precipitator; FF= fabric filter; 

FGD = flue gas desulfurization 

b) PAC=powdered activated carbon; SC=spray cooling; PFF=polishing fabric filter 

c) NA = not available 

In comparison, the estimated annual costs of Hg controls, as a function of plant size, lie 

mostly between the costs for low-NOx burners (LNBs) and selective catalytic reduction (SCR) 

systems. The costs of Hg control will dramatically diminish if retrofit hardware and sorbents are 

employed for control of other pollutants such as NOx, SO2, or fine PM. 

The performance and cost estimates of PAC injection-based Hg control technologies 

presented in this document are based on relatively few data points from pilot-scale tests and are 

considered to be preliminary. However, based on pilot-scale tests and the results of ICR data 

ES-14

evaluations, better sorbents and technologies now being developed will reduce the costs of Hg 

controls beyond current estimates. 

Within the next 2 to 3 years, the evaluation of retrofit technologies at plants where cocontrol is being practiced will lead to a more thorough characterization of the performance and 

costs of Hg control. Future cost studies will focus on the development of performance and cost 

information needed to refine cost estimates for sorbent injection based controls, will develop cost 

estimates for wet scrubbing systems that employ methods for oxidizing Hg0

, and will determine 

the costs of various multipollutant control options. 

The issue of Hg in residues will also be examined to address concerns related to the 

release of captured Hg species into the environment. These evaluations will be conducted in 

conjunction with the development and evaluation of air pollution emission control technologies. 

Coal Combustion Residues and Mercury Control 

Operation of power plants results in solid discharges including fly ash, bottom ash, boiler 

slag, and FGD residues. These residues already contain Hg, presumably bound Hg that is 

relatively insoluble and non-leachable. In 1998, approximately 108 million tons of coal 

combustion residues (CCRs) were generated. Of this amount, about 77 million tons were 

landfilled and about 31 million tons were utilized for beneficial uses. 

Increased control of Hg emissions from coal-fired power plants may change the amount 

and composition of CCRs. Such changes may increase the potential for release of Hg to the 

environment from either landfilling or uses of CCRs. Mercury volatilization from CCRs in 

landfills and/or surface impoundments is expected to be low due to the low temperatures 

involved and the existence of relatively small surface area per unit volume of residue. For Hg 

control retrofits involving dry or wet FGD scrubbers, the residues are typically alkaline and the 

acid leaching potential of Hg from these residues is expected to be minimal. 

There are several commercial uses of CCR where available data on which to characterize 

the Hg emission potential are lacking. The following CCR uses are given a priority for 

developing additional data in order to characterize the ultimate fate of Hg: 

• The use of fly ash in cement production, 

• The volatilization and leaching of residues used for structural fills, 

• Leaching of residues exposed to the acidic conditions during mining applications, 

•	 Volatilization of Hg during the production of wallboard from gypsum in wet scrubber 

residues, 

•	 Mercury volatilization during the production and application of asphalt with fly ash 

fillers, and 

•	 Leaching or plant uptake of Hg from fly ash, bottom ash, and FGD sludge that are used as 

soil amendments. 

ES-15

Current and Planned Research 

DOE, EPA, EPRI, the utility industry, and the control technology industry are funding 

research on the control of Hg emissions from coal-fired boilers. A major portion of this research 

is being funded under cooperative agreements with DOE. These agreements include cost sharing 

by EPRI and other industrial partners. Research on these projects is being jointly coordinated 

under DOE's, EPA's, and EPRI's Hg control technology programs. These research efforts will be 

used to: 

•	 Develop hazardous air pollution Maximum Achievable Control Technology (MACT) 

requirements for electric utility generating units, 

•	 Optimize control of Hg emissions from units that must comply with more stringent 

NOx emission requirements under the NOx SIP, and 

•	 Develop technologies that can be used to control emissions under multipollutant 

control legislation options that are currently being considered. 

Current research efforts include three full-scale test projects, six pilot-scale test projects 

on coal-fired units, the evaluation of Hg CEMs, supporting research on the speciation and 

capture of Hg, and research on CCRs and CCBs. This research includes: 

• One full-scale ESP sorbent injection project with tests at four sites, 

• One full-scale wet FGD scrubber project at two sites, 

•	 One full-scale project on the effects of SNRC, SCR, and SO3 conditioning 

systems at five sites, 

• On-going research on the development and use of Hg CEMs, 

• On-going speciation, capture, and sorbent development research, and 

•	 Small Business Administration projects on development of sorbents, and 

measurement methods. 

Six new pilot-scale DOE projects have been announced in FY2001. These are: 

• Advance particulate collector with sorbent injection (North Dakota-EERC) 

• Evaluation of Hg0 oxidization catalysts (URS Radian Group) 

• Spray cooling and multipollutant sorbents (CONSOL) 

• Evaluation of multipollutant sorbents and CFBA (SRI) 

• Electrical discharge multi-pollution control system (Power Span) 

• Evaluation of advanced sorbents (Apogee Scientific) 

ES-16

Conclusions and Recommendations 

Additional efforts are planned to characterize the behavior of Hg in coal combustion 

systems. Further research is needed on the speciation and capture of Hg and on the stability of 

Hg in CCRs and residue by-products. Studies on the control capabilities and costs of potential 

Hg retrofit technologies currently under pilot-scale development are being continued and 

appropriate control technologies are to be evaluated on full-scale units. Additionally, an 

evaluation of the co-control of Hg with available PM, SO2, and NOx controls is needed. 

Mercury measurement and monitoring capabilities must be consistent with the regulatory 

approaches being considered; e.g., speciated vs. total Hg emissions. Field activities need to be 

coordinated to (1) improve the emissions data base, (2) develop the technologies most 

appropriate for Agency goals (e.g., Hg-specific vs. multipollutant), and (3) refine cost data and 

cost-performance models based on actual field experience. 

Finally, EPA must continue to work closely with DOE, EPRI and the utility industry to 

develop Hg and multipollutant control technologies. Collaboration will help ensure that all of 

the scientific knowledge, engineering skills, and financial resources needed to develop control 

technologies and establish the most cost-effective regulatory requirements are available. 

Current and future research should focus on: 

• Control of emissions for units with ESPs, 

• Control of Hg emissions from subbituminous coals and lignite, 

• Evaluation of CFA systems, 

•	 Demonstration of Hg control for units with SDA/ESP and SDA/FF systems, 

0 • Development of Hg oxidizing methods for wet FGD systems, 

•	 Evaluation additives for the oxidization of Hg0 and the sequestration 

of Hg2+ in wet scrubbers, 

• Enhancement of fly ash capture by combustion modification techniques, 

• Optimization of NOx controls for Hg control, 

•	 Control of Hg and other air toxic emissions from units equipped with SCR 

and wet FGD scrubbers, 

• Use and evaluation of Hg CEMs, 

• Tests with CEMs to study the variability of Hg emissions, 

• Effects of coal blending on Hg capture, and 

• Effects of cyclone-, stoker-, and fluidized-bed combustion on Hg control. 

ES-17

Chapter 1 

Report Background 

1.1 Introduction 

Mercury (Hg) is a metallic element that can be released into the atmosphere from both 

anthropogenic (i.e., made by humans) and natural sources. Ambient Hg concentrations in the air 

are typically very low. Human exposure by direct inhalation of Hg in the air is not the 

predominant public health concern for this metal. However, the Hg in ambient air eventually can 

be re-deposited on land surfaces or directly into rivers, lakes, and oceans. Mercury that enters 

bodies of water by direct deposition from the air or runoff from land surfaces ultimately is 

transformed by biological processes into a highly toxic form of Hg (methylmercury [MeHg]) that 

concentrates in fish and other organisms living in these waters. A study by the National 

Academy of Sciences (NAS) concluded that human exposure to MeHg from eating contaminated 

fish and seafood is associated with adverse health effects related to neurological and 

developmental damage varying in severity depending on the Hg concentrations in the ingested 

food.1 An extreme example of these health effects cited by this study is the high-dosage 

exposure from the consumption of MeHg-contaminated fish by the residents living near 

Minamata Bay in Japan in the 1950s that resulted in fatalities and severe neurological damage. 

The largest anthropogenic source of Hg emissions in the United States is the Hg released 

from burning coal to produce steam for generating electricity. Mercury naturally occurs in trace 

amounts in all coal deposits. When coal is burned in a steam boiler or a furnace, most of the Hg 

bound in the coal is released during the combustion process as gaseous elemental mercury (Hg0). 

Subsequent cooling of the combustion gases and interaction of the gaseous Hg0

 with other 

combustion products result in a portion of the Hg being converted to gaseous oxidized forms of 

mercury (Hg2+) and particle-bound mercury (Hgp). 

Coal-fired electric utility power plants currently do not use air pollution controls 

specifically designed to reduce Hg emissions to the atmosphere. However, certain control 

technologies now used at coal-fired electric utility power plants to reduce other air pollutant 

emissions (particulate matter [PM], sulfur dioxide [SO2], nitrogen oxides [NOx]) also reduce Hg 

emissions with varying levels of effectiveness. Methods for enhancing Hg removal by these 

existing controls are being studied. New control technologies to specifically control Hg 

emissions from coal combustion are being developed. Multipollutant control technologies that 

will achieve both high Hg removal and effective control of PM, SO2, and NOx are being 

investigated. 

1-1


2 
The Clean Air Act (CAA) directs the U.S. Environmental Protection Agency (EPA) to 

regulate emissions of air toxics from stationary sources by establishing national air emission 

standards for hazardous air pollutants (NESHAP). Mercury is one of the compounds listed under 

CAA Section 112 as a hazardous air pollutant (HAP). The EPA Administrator has found that it 

is appropriate and necessary to establish a NESHAP regulating HAP emissions, including Hg, 

from coal-fired electric utility power plants. 

1.2 Report Purpose 

The EPA Office of Research and Development (ORD) National Risk Management 

Research Laboratory (NRMRL) has prepared this Hg emission control technology report. The 

overall purpose of the report is to review and evaluate recent scientific data and new knowledge 

about control technologies that potentially can be used to reduce Hg emissions from coal-fired 

electric utility power plants. The first part of the report is directed to readers outside the research 

community involved in Hg emission control issues by providing background information 

regarding EPA’s NESHAP decision, the use of coal for electrical power generation, and Hg 

behavior in coal combustion gases. The second part of the report is directed to all readers and 

focuses on a review and evaluation of new information that has been gathered by the EPA since 

the Agency’s reports to Congress related to the control of Hg emissions from electric utility 

power plants. Also included in this report are summaries of the results to date from companion 

NRMRL studies investigating the costs of retrofitting potential Hg control technologies to 

existing coal-fired electric utility power plants in the United States and Hg behavior in the ash 

and other solid residues from coal combustion. 

The remainder of Chapter 1 provides a summary of the statutory authority and past major 

studies completed by the EPA that led to the Agency’s regulatory finding on the HAP emissions 

from electric utility power plants. Background on major research programs investigating Hg 

emissions from coal combustion is presented. This chapter concludes with a description of 

topics presented in Chapters 2 through 10 of this report. 

1.3 NESHAP Statutory Background 

Title III of the CAA regulates stationary sources that emit HAPs. Section 112 in Title III 

was comprehensively amended in 1990. Under the amended CAA Section 112(b), Congress 

listed specific chemicals, compounds, and groups of chemicals as HAPs. Mercury is one of the 

chemicals included on this HAP list. The EPA is directed by Section 112 to regulate the HAP 

emissions from stationary sources by establishing “national emission standards for hazardous air 

pollutants@ or ANESHAP.@ The EPA develops and promulgates individual NESHAPs for specific 

categories of stationary sources. The NESHAP for a given source category is codified under its 

own subpart in the Code of Federal Regulations under part 63 to title 40. 

1-2

Section 112 of the CAA established specific directives as to how the EPA must develop 

NESHAPs. The statute requires that each NESHAP must require the maximum degree of HAP 

emission reduction that is achievable, taking into consideration the cost of achieving such an 

emission reduction and any non-air quality health and environmental impacts and energy 

requirements. The control technology that achieves this level of HAP emission control is called 

Amaximum achievable control technology@ or AMACT.@ 

The 1990 CAA Amendments include several provisions in Section 112 that specifically 

address the regulation of HAP emissions from electric utility steam generating units. First, CAA 

Section 112(a) defines the term Aelectric utility steam generating unit@ to mean 

A. . . any fossil fuel fired combustion unit of more than 25 megawatts that serves a 

generator that produces electricity for sale. A unit that cogenerates steam and 

electricity and supplies more than one-third of its potential electric output capacity 

and more than 25 megawatts electrical output to any utility power distribution 

system for sale shall be considered an electric utility steam generating unit.@ 

Section 112(n)(1)(A) directs the EPA to perform a study and report to Congress about the 

hazards to public heath reasonably anticipated to occur as result of exposure to HAP emissions 

from electric utility steam generating units. After considering the result of this study, the EPA 

must determine whether regulation of electric utility steam generating units under Section 112 is 

appropriate and necessary. In July 1995, the EPA submitted its draft version of the report for 

peer review and, concurrently, released that version of the report for public review and comment. 

The EPA completed the final report and submitted to it Congress in February 1998.3 

A related directive in Section 112(n)(1)(B) requires the EPA to perform a second study 

and report to Congress about Hg emissions from electric utility steam generating units, municipal 

waste combustion units, and other sources including area sources. This section directs the EPA=s 

study to consider the rate and mass of the Hg emissions from these sources, the health and 

environmental effects of such emissions, the technologies that are available to control such 

emissions, and the cost of these technologies. The EPA completed this study and submitted its 

final report to Congress in December 1997.4 

The 1990 CAA amendments to Section 112 also direct the EPA to perform additional 

studies that include analyses of Hg emissions from electric utility steam generating units. 

Included among these studies is the requirement under CAA Section 112(m) for the EPA to study 

the atmospheric deposition of HAPs to the Great Lakes, Chesapeake Bay, Lake Champlain, and 

coastal waters. This group of surface water bodies collectively is referred to as the AGreat 

Waters.@ Section 112(m) directs the EPA to investigate the contribution of atmospheric 

deposition to pollutant loadings in the Great Waters; environmental and public health effects of 

atmospheric pollution deposited to these waters; and the sources of the pollutants deposited to 

these waters. Three reports to Congress on the atmospheric deposition of pollutants to the Great 

Waters have been prepared to date (May 1994, June 1997, and June 2000).5,6,7 

1-3

In addition to requiring the EPA to prepare the above cited reports, Congress directed the 

EPA to fund an independent evaluation conducted by the NAS of the available data related to the 

health impacts of MeHg and provide recommendations for the reference dose (RfD) to be used 

for health impact analyses. The RfD is the amount of a chemical which, when ingested daily 

over a lifetime, is anticipated to be without adverse health effects to humans, including sensitive 

subpopulations. The NAS conducted an 18-month study of the available data on the health 

effects of MeHg and published a report of its findings in 2000.1 On the basis of its evaluation, 

the NAS committee’s consensus is that the value of EPA’s current RfD for MeHg is a 

scientifically appropriate level for the protection of public health. 

1.4 Major Findings of EPA Reports to Congress 

1.4.1 Study of HAP Emissions from Electric Utility Steam Generating Units 

The findings of the EPA=s study of the hazards to public heath reasonably anticipated to 

occur as result of exposure to HAP emissions from electric utility steam generating units are 

presented in the two-volume report titled Study of Hazardous Air Pollutant Emissions from 

Electric Utility Steam Generating Units--Final Report to Congress.

3

 The assessment for Hg in 

the report includes a description of Hg emissions, deposition estimates, control technologies, and 

a dispersion and fate modeling assessment that includes predicted levels of Hg in various media 

(including soil, water, and freshwater fish) based on modeling from four representative utility 

plants using hypothetical scenarios. The EPA did not evaluate human or wildlife exposures to 

Hg emissions from utilities in that report. With regard to non-inhalation exposures (e.g., 

ingestion) to other HAPs, the report presents a limited qualitative discussion of arsenic, 

cadmium, dioxins, and lead. 

Based on information and analyses available at the time the report was prepared, electric 

utility steam generating units can emit a significant number of the HAPs listed in CAA Section 

112(b). However, except for Hg, electric utility steam generating units are responsible for a very 

small percentage of the total nationwide emissions of these particular HAPs. The EPA 

concluded that Hg emitted from coal-fired steam generating units is the HAP of greatest potential 

concern for electric utility steam generating units. For two other HAPs (arsenic and dioxin), the 

EPA=s analysis concluded that further evaluations and review are needed to better characterize 

the impacts of these HAP emissions from coal-fired steam generating units. 

Nickel emissions are the only HAP emissions of potential concern from oil-fired electric 

utility steam generating units. The EPA acknowledged that there are significant uncertainties 

concerning the chemical forms of nickel emitted from these units and the health effects of those 

various nickel compounds. At the time the study was prepared, the EPA projected that future 

nationwide nickel emissions from oil-fired steam generating units would decrease because of 

anticipated declining use of oil by utilities for electric power generation. 

1-4

The impacts due to HAP emissions from natural-gas-fired steam generating units are 

negligible based on the results of the study. The EPA concluded that no further evaluation is 

needed of HAP emissions from natural-gas-fired electric utility steam generating units. 

The EPA identified uncertainties that make it difficult to quantify the magnitude of the 

risks due to Hg emissions from coal-fired electric utility steam generating units, and identified 

the research areas where more information is needed to gain a better understanding of the risks 

and impacts of these Hg emissions. Included among the research areas that the EPA 

recommended for further evaluation were: 1) collection and assessment of additional data on the 

Hg content of various types of coals; 2) collection and assessment of additional data on Hg 

emissions from coal-fired steam generating units; 3) collection and assessment of additional 

information on control technologies or pollution prevention options; and 4) further review of the 

available data on the health impacts associated with exposure to Hg. Following completion of 

the report, the EPA initiated studies addressing the identified research needs. 

1.4.2 Mercury Study Report 

The findings of the EPA=s assessment of the magnitude of Hg emissions from sources in 

the United States, the health and environmental implication of those emissions, and the 

availability and costs of control technologies are presented in the eight-volume report titled 

Mercury Study Report to Congress.

4 The report provides an extensive analysis of the public 

health impacts and environmental impacts resulting from Hg emissions to the atmosphere and 

deposition on surface waters and land. The findings of the report related to Hg emissions from 

electric utility steam generating units and other anthropogenic sources in the United States (as 

discussed in Volume II of the report) are summarized below. 

Mercury cycles in the environment occur as a result of both natural processes and human 

activities (anthropogenic sources). The EPA prepared a nationwide inventory of annual Hg 

emissions from anthropogenic sources in the United States. This inventory was based on the 

period 1994-1995 and estimated the total annual nationwide emissions of Hg to be 144 

megagrams (158 tons). Most of these emissions (approximately 87 percent) are produced when 

waste or fuels containing Hg are burned. Four specific source categories account for 

approximately 80 percent of the total nationwide anthropogenic emissions: coal-fired electric 

utility boilers (33 percent), municipal waste combustors (19 percent), industrial and commercial 

boilers (18 percent), and medical waste incinerators (10 percent). Another 10 percent of the Hg 

emissions were estimated to be from manufacturing sources that use Hg as a processing agent, 

product ingredient, or where Hg is present as a trace constituent in a process raw material. The 

largest manufacturing sources are chloro-alkali plants and Portland cement manufacturing plants. 

The remaining 3 percent of the emissions were estimated to be released from area and 

miscellaneous sources. 

In the report, the EPA also assessed future trends in Hg emissions. Emissions from two of 

the significant combustion sources identified in the 1994-95 nationwide inventory are predicted 

to decline significantly when the national emission standards for municipal waste combustors 

1-5

(MWCs) and medical waste incinerators are fully implemented. Industrial use of Hg was found 

to be declining in those manufacturing sectors where acceptable substitute materials can be used 

(e.g., use of electronic thermometers in place of Hg thermometers, elimination of Hg additives in 

paints and pesticides, reduced use of Hg in batteries). 

1.4.3 Great Waters Reports 

The findings of the EPA=s study of the atmospheric HAP deposition to the Great Waters 

are presented in a series of three reports to Congress; the first report dated May 1994, the second 

report dated June 1997, and the third report dated June 2000. The HAPs of concern emitted from 

electric utilities addressed by the Great Waters study include lead, cadmium, dioxins, and, in 

particular, Hg. 

The first Great Waters report to Congress noted that the water bodies are polluted by 

HAPs that originate from both local and distant sources; however, more data are needed to 

identify the specific sources of the pollutants. The report recommendations were the following: 

1) the EPA should strive to reduce emissions of the pollutants of concern through 

implementation of the CAA; 2) a comprehensive approach should be taken, both within the EPA 

and with other agencies, to reduce and preferably prevent pollution in air, water, and soil; and 3) 

the EPA should continue to support research for emissions inventories, risk assessment, and 

regulatory benefits assessment. 

The second Great Waters report to Congress confirmed, and provided additional support 

for, the findings of the first report that persistent and bioaccumulative toxic pollutants and 

excessive nitrogen can adversely affect the environmental conditions of the Great Waters. 

Electric utilities and mobile sources are identified by the report based on air modeling studies and 

emissions data as major contributors of nitrogen oxides to the Chesapeake Bay and its watershed. 

The most recent Great Waters report to Congress presents updated scientific and 

programmatic information to support and build upon the broad conclusions presented in the first 

two reports. Specific to Hg, fate and transport modeling and exposure assessments presented in 

the report predict that the anthropogenic contribution of the total amount of MeHg in fish is, in 

part, the result of Hg releases from combustion and industrial sources. Furthermore, 

consumption of fish is the dominant pathway of exposure to MeHg for fish-consuming humans 

and wildlife. 

1.5 Information Collection Request to Electric Utility Industry 

The EPA=s 1998 report to Congress on HAP emissions from electric utility steam 

generating units identified additional information needed to gain a better understanding of the 

risks, impacts, and control of Hg emissions from coal-fired steam generating units. As part of the 

Agency=s effort to gather this information, the EPA conducted an information collection project 

beginning in late 1998 to survey all coal-fired steam generating units meeting the CAA Section 

1-6

112(a) definition that were operating in the United States.8

 This information collection provided 

the EPA with data on the Hg content and amount of coal burned by these units during the 1999 

calendar year. As part of the information request, the EPA also selected a subset of the coal-fired 

electric utility steam generating units at which field-source testing was performed to obtain Hg 

emission data for the air pollutant control devices now being used for these units. 

There were three parts to the EPA information collection effort. Part I of this effort 

consisted of gathering the information to first identify the location of each coal-fired steam 

generating unit meeting the CAA Section 112(a) definition that was operating in the United 

States. The EPA sent information collection requests (ICRs) to the owners and operators of 

approximately 1,100 facilities that potentially could be operating coal-fired steam generating 

units. Information requested in the Part I questionnaire sent to each of these facilities included 

the type of coal burned, the method of firing the coal, and the methods used for control of air 

pollutants. Based on the ICR responses, 1,143 coal-fired steam generating units that meet the 

CAA Section 112(a) definition were identified at 461 facilities. These coal-fired steam 

generating units were located across the entire nation in 47 of the 50 states, with the exceptions 

being Idaho, Rhode Island, and Vermont. 

Part II of the information collection effort, during calendar year 1999, consisted of 

gathering information on the quantities, Hg content, and other selected properties of coal burned 

by each of the 1,143 coal-fired steam generating units. The owner or operator of each coal-fired 

steam generating unit provided to the EPA, on a quarterly basis, analysis results for samples of 

the coal fired in the steam generating unit. These analyses were performed according to a 

demonstrably acceptable protocol and reported the Hg content of the coal burned and other 

important coal properties (e.g., coal heating value and the sulfur, ash, moisture, and chlorine 

contents). Each owner or operator also reported data on the total amount of coal burned on a 

monthly basis during 1999. 

Part III of the information collection effort consisted of conducting Hg emission source 

testing at selected electric utility power plants operating coal-fired steam generating units. The 

test locations were selected by the EPA to approximate the nationwide distribution of coal-fired 

steam generating units by type of boiler, coal burned, and air emission controls used. The testing 

at each location was performed by the facility owner or operator (or a source testing contractor 

hired by the facility). At each of the selected test locations, measurements were made of the Hg 

content in the inlet and outlet gas stream for the farthest downstream control device used on the 

unit. The testing followed an EPA-approved sampling protocol and included three sample runs 

at each sampling location. Samples of the coal burned during the source test were also collected. 

Each test was completed and a final test report was provided to the EPA. The EPA review of the 

test reports ultimately found acceptable test results for 80 coal-fired steam generating units. 

All of the nationwide industry survey data (information collected for Part I of the survey), 

coal analysis data (information collected for Part II of the survey), and Hg emission testing (data 

collected for Part III of the survey) are available to the public on the EPA web site, 

<http://www.epa.gov/ttn/atw/combust/utiltox/utoxpg.html>. Selected information from the ICR 

1-7

data base are also summarized in chapters of this report as related to characterizing the coal 

properties, control configurations, and Hg emissions from existing coal-fired electric utility 

steam generating units. In this report, the term “EPA ICR data” is used to refer to the 

compilation of coal-fired electric utility power plant, coal property, and Hg emissions data 

gathered by this nationwide information collection project. 

1.6 Regulatory Finding on HAP Emissions from Electric Utility Steam Generating Units 

On December 20, 2000, the EPA published in the Federal Register a notice (65 FR 79825) 

presenting the EPA Administrator’s finding as to whether regulation of emissions of HAP from 

fossil-fuel-fired electric utility steam generating units is appropriate and necessary. This finding 

is based on the results of EPA’s reports to Congress, the EPA’s analysis of the ICR responses, 

and other information the Agency subsequently collected concerning HAP emissions from 

electric utility steam generating units. 

Based on the available information, the Administrator concluded that Hg is both a public 

health concern and a concern in the environment. The EPA’s analysis shows that coal-fired 

electric utility steam generating units are the largest source of Hg emissions to the atmosphere in 

the United States. Further, the Administrator concluded that there is a plausible link between 

MeHg concentrations in fish and Hg emissions from these coal-fired steam generating units. 

Therefore, the Administrator found that it is appropriate and necessary to regulate HAP 

emissions, including Hg, from coal-fired electric utility steam generating units under CAA 

Section 112 (i.e., establish a NESHAP), because the implementation of other requirements under 

the CAA will not adequately address the serious public health and environmental hazards arising 

from these emissions. As a result, the EPA added coal-fired electric utility steam generating 

units to the list of source categories under CAA Section 112(c). 

In its 1998 report to Congress, the EPA found that nickel emissions are the only HAP of 

potential concern from oil-fired electric utility steam generating units. The Administrator found 

that there remained uncertainties regarding the extent of the public health impact from nickel 

emissions from oil-fired electric utility steam generating units. Therefore, the EPA also added 

oil-fired electric utility steam generating units to the CAA Section 112(c) source category list. 

The Administrator found that regulation of HAP emissions from natural-gas-fired electric 

utility steam generating units is not appropriate or necessary. Because the EPA believes that the 

CAA Section 112(a)(8) definition of electric utility steam generating units excludes stationary 

combustion turbines, the Administrator’s finding for natural-gas-fired electric utility steam 

generating units does not apply to stationary combustion turbines. 

In response to the regulatory finding, the EPA has begun development of a NESHAP to 

specifically control HAP emissions from coal-fired electric utility steam generating units. The 

current schedule for this rule is to propose a NESHAP for the source category by December 15, 

2003, and take final action on the rule by December 15, 2004. 

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1.7 Mercury Emissions Research Programs 

Mercury emissions from combustion sources including coal-fired electric utility power 

plants have been the subject of extensive research and study throughout the 1990s by government 

agencies, the electric utility industry, and university researchers. Researchers at the U.S. 

Department of Energy’s (DOE) National Energy Technology Laboratory (NETL) (previously 

known as the Federal Energy Technology Center) have prepared a comprehensive literature 

search and review summarizing the data and findings of many of these studies published in 

1999.9 

Currently, the EPA, the DOE/NETL, and the Electric Power Research Institute (EPRI) are 

funding major on-going research work on Hg emissions from coal combustion. Each 

organization conducts these projects “in-house” as well as through contracts with university 

researchers and private companies. In addition, the EPA, the DOE/NETL, and EPRI are 

collaborating on a number of joint projects. The on-going projects range from fundamental 

studies based on bench-scale laboratory experiments and computer modeling to field test 

programs at coal-fired electric utility power plants. Table 1-1 presents a summary overview of 

the research topics being investigated. Major objectives of these research efforts include: 

$ Improving the test methods for measuring Hg emissions from coal-fired electric 

utility boilers and other coal combustion systems. The current focus of this effort is 

development of continuous emission monitors (CEMs) to measure Hg. 

$ Understanding the chemical, physical, and operating factors that affect Hg behavior in 

combustion gases and residues from burning coal. 

$ Developing cost-effective techniques for controlling Hg that can be readily retrofitted 

to existing coal-fired electric utility power plants. 

$ Developing Hg control technologies for application to new coal-fired electric utility 

power plants. 

$ Developing multipollutant control technologies that will control Hg emissions 

together with SO2 or NOx emissions. 

1.8 Relationship to Mercury Emission Control Research for Municipal Waste Combustors 

The EPA has identified MWCs as the second largest source category of Hg emissions in 

the United States after coal-fired electric utility steam generating units.4 The control of Hg 

emissions from MWCs has been, and continues to be, the subject of research in both the United 

States and Europe. 

1-9

Table 1-1. Current research areas related to controlling Hg emissions from coal-fired 

power plants. 

1-10


Major Research 

Research Area 

DOE EPA 

Hg content of coals 4

Coal cleaning methods for Hg removal 4 

Hg behavior and speciation in coal combustion gases 4 4 

Hg measurement and monitoring in coal combustion gases 4 4 

Hg adsorption on fly ash in coal combustion gases 4 

Improving Hg capture by conventional wet scrubber systems 4 4 

Improving Hg capture by conventional particulate control devices 4

Hg capture using activated carbon sorbent injection 4 4 

Hg capture using other Hg-specific sorbents 4

Hg capture using multipollutant sorbents 4

Hg behavior in solid residues from Hg control systems 4 4 

Hg control costs and economics 4 4 

4 4 4 4 4 
An MWC is an enclosed combustion unit used to burn municipal solid waste for the 

purpose of reducing the volume of waste that must be disposed in a landfill. Many people also 

refer to these combustion units as waste incinerators. Although an MWC may function as a 

simple incinerator, more commonly these combustion units are equipped with heat recovery 

equipment that is used for producing steam. The steam is used in a variety of different ways 

depending on the facility location including generating electrical power, industrial process steam, 

or district heating systems. Other terms sometimes used to refer to this type of MWC facility 

include Aresource recovery facility@ and Awaste-to-energy plant.@ 

The EPA and some states have established regulations to reduce the level of Hg emissions 

from MWC facilities operating in the United States. To comply with these regulations, a 

combination of control strategies, including the application of add-on control devices, are now in 

use for new and existing MWC facilities. Direct transfer to coal-fired electric utility steam 

generating units of all of the specific control strategies that are used to meet the Hg emission 

regulations for MWC facilities is not feasible, effective, or practical because of the distinct 

differences between the two categories of combustion sources (e.g., properties of the fuel burned; 

the design, operation, and scale of the combustion unit; and the characteristics of the postcombustion gases). Nevertheless, understanding how Hg emissions are controlled in an MWC 

does provide useful information to help identify potential Hg control technologies for coal-fired 

electric utility steam generating units and to assess the performance and costs of using these 

controls. 

In the United States, the municipal solid waste that can be burned in MWCs is primarily 

composed of household, commercial, and institutional refuse. These wastes cannot include any 

hazardous wastes regulated under subtitle C of the Resource Conservation and Recovery Act 

(RCRA). However, small amounts of Hg may be in certain discarded consumer products that are 

not RCRA hazardous wastes and are burned in MWCs (e.g., batteries, some fluorescent bulbs, 

electrical switches, thermometers). Most of this Hg is released during the combustion process 

and remains in combustion gases vented from the MWCs. 

Mercury emissions from MWC facilities in the United States are decreasing for three 

major reasons. First, Section 129 of the CAA requires the EPA to develop national emission 

standards for Hg (and a number of other pollutants) being emitted from MWC facilities. The 

EPA finalized the standards as new source performance standards (NSPS) and Emission 

Guidelines (EG) under 40 CFR part 60 in October 1995. The NSPS (subpart Eb) applies to those 

MWCs constructed after September 20, 1994 (i.e., Anew sources@); the EG (subpart Cb) applies 

to those MWCs built before this date (i.e., Aexisting sources@). For Hg, the same emission limit 

of 0.08 milligram per dry standard cubic meter (mg/dscm) applies to both new and existing 

MWC facilities. 

In addition to the Federal standards and emission guidelines, individual states with 

significant numbers of MWC facilities operating within their jurisdiction have enacted legislation 

controlling Hg emissions from these MWC facilities. Several states (e.g., Florida and New 

Jersey) have established Hg emission limits for MWCs, effectively requiring these units to use a 

1-11

specific control technology. Some states have enacted regulations limiting or banning the sale of 

certain Hg-containing products that, when discarded, would have been mixed in refuse burned in 

an MWC. These regulations differ from state to state, with Minnesota having the most extensive 

set of restrictions on the disposal of Hg-containing products. 

The third reason for the decline in Hg emissions from MWC facilities is the trend by 

manufacturers to limit or discontinue the use of Hg in many products that ultimately are mixed in 

the waste burned in MWCs. These products include household alkaline batteries and interior and 

exterior paints. Other products that traditionally have used Hg (e.g., Hg thermometers and 

thermostats) are increasingly being replaced by digital, electronic versions that do not require Hg 

components. 

Despite the reductions in the Hg content of the waste burned, MWCs still need to use 

add-on emission controls to capture Hg in the combustion gases exhausted from the combustor. 

Mercury removal from the combustion gases using these control systems can vary depending on 

the combination of controls used and the site-specific conditions. The injection of powdered 

activated carbon into the gas upstream of a particulate matter control device is a common method 

currently used in the United States to control Hg emissions from MWCs. In Europe, wet 

scrubbing systems are commonly used to control MWC Hg emissions. Because of factors such 

as the differences in flue gas characteristics and duct configurations (discussed further in 

Chapter 7), the Hg control technologies now used for MWCs cannot be directly transferred to 

coal-fired utility boilers. However, the commercial experience with MWC Hg emission controls 

does point to potential control technologies that should be investigated further for application to 

coal-fired electric utility power plants. 

1.9 Report Organization 

The remainder of this report consists of nine chapters (Chapters 2 through 10) presenting 

background information, recent research findings, and the current status of research studies 

related to Hg emission behavior and control in coal-fired electric utility power plants. Each 

chapter addresses specific topics related to the application of Hg emission control technologies to 

coal-fired steam generating units. Appendices are presented at the end of the report to support 

and supplement information presented in the chapters. 

Chapter 2 

Coal-fired Electric Utility Boilers 

Chapter 2 presents an overview of the coals burned and combustion technologies 

used for electric power generation. The design and operating characteristics of the 

different types of coal-fired boilers used by electric utilities in the United States 

are presented. The properties of the coal burned by electric utilities in the year 

1999 are summarized using information compiled from the EPA ICR database. 

1-12

Chapter 3


Criteria Air Pollutant Emission Controls for


Coal-fired Electric Utility Boilers


Chapter 3 presents a summary review of the different air pollution control devices 

(APCDs) currently used at coal-fired electric utility power plants to meet criteria 

air pollutant emissions standards. The nationwide distribution of APCD 

configurations used at these power plants to comply with the air standards is 

presented using information from the EPA ICR database. 

Chapter 4


Measurement of Mercury


Chapter 4 discusses the principles, applications, and limitations of Hg 

measurement methodologies, particularly with respect to understanding and 

interpreting the ICR data. The chapter discusses the Ontario-Hydro method and 

other manual test methods available for measuring Hg in coal combustion flue 

gas. This chapter introduces the principles and issues related to Hg continuous 

emission monitors (CEMs) and their use as a valuable research tool. 

Chapter 5


Mercury Speciation and Capture


Chapter 5 provides an introduction to Hg chemistry and behavior of Hg as it 

leaves the combustion zone of the furnace and passes in the flue gas through the 

downstream boiler sections, air heater, and air pollution control devices. Recent 

laboratory research on Hg chemistry in coal combustion flue gas is summarized. 

Mercury speciation is discussed as related to coal properties, combustion 

conditions, flue gas composition, fly ash properties, time/temperature profile 

between the boiler and air pollution control devices, and post-combustion flue gas 

cleaning methods. Results from recent studies on the mechanisms for capturing 

Hg by adsorption of gaseous Hg, by solid particles in the flue gas, and by 

absorption capture of Hg by alkaline solutes/slurries are analyzed. 

Chapter 6


Mercury Capture by Existing Control Systems Used by


Coal-fired Electric Utility boilers


Chapter 6 discusses the level of Hg capture achieved by the air emission control 

devices now in use at coal-fired electric utility power plants to meet Federal and 

state air emission standards for particulate matter, sulfur oxides, and nitrogen 

oxides. The results of the Hg emission source testing compiled in the Part III 

EPA ICR data are presented and analyzed. The methods used to evaluate these 

1-13

Hg emissions data are described to meet two interrelated objectives. First, an 

analysis of the EPA ICR data is presented as used for EPA’s estimate of 

nationwide Hg emissions from coal-fired electric utility power plants in 1999. 

Second, the EPA ICR data are analyzed to characterize the effects of coal 

properties, combustion conditions, and flue gas cleaning methods on the 

speciation and capture of Hg. 

Chapter 7


Research and Development Status of


Potential Retrofit Mercury Control Technologies


Chapter 7 discusses potential retrofit control technologies for increasing Hg 

emission capture levels in the air pollutant control systems now in use at existing 

coal-fired electric utility power plants. The use of activated carbon and other dry 

sorbents for Hg emission control is discussed. Current knowledge is summarized 

regarding the enhancement of Hg capture by existing particulate matter control 

devices and wet scrubbing systems. Recent pilot-scale and full-scale test data for 

Hg capture by potential retrofit control technologies are presented. This chapter 

also summarizes the status of emerging Hg and multipollutant control 

technologies that are being developed for the control of Hg emissions from coal 

combustion. 

Chapter 8


Cost Evaluation of Retrofit Mercury Controls for


Coal-fired Electric Utility Boilers


Chapter 8 presents a preliminary evaluation of total annual costs to apply potential 

activated carbon injection-based control technologies to existing coal-fired 

electric utility power plants. The evaluation is based on estimating the control 

costs using a computer model for a series of model plant scenarios. The cost 

estimate methodology and assumptions are described. The cost estimates are 

presented and discussed. 

Chapter 9 

Coal Combustion Residues and Mercury Control 

The EPA/NRMRL presently is conducting a life-cycle analysis project to help 

evaluate any potential environmental trade-offs and to ensure that there is not an 

increased environmental risk from the management of coal combustion residues 

(CCRs) resulting from the implementation of Hg control technologies at coal-fired 

electric utility power plants. In support of this evaluation, the NRMRL is 

gathering data and information to assess future increases in Hg concentrations in 

1-14

CCRs resulting from application of Hg emissions control requirements to coalfired electric utility boilers. Chapter 9 summarizes some of the CCR information 

gathered by NRMRL to date and identifies the major data gaps and priorities of 

EPA’s research to ensure that Hg controlled at the coal-fired electric utility power 

plant stack is not later released from CCRs in an amount that is problematic for 

the environment. 

Chapter 10


Conclusions and Recommendations


Chapter 10 summarizes the major findings of this report and presents 

recommendations for further work, which would benefit the understanding of Hg 

behavior in the coal combustion processes at electric utility power plants. 

1.10 References 

1. 	 National Research Council. Toxicological Effects of Methylmercury. Committee on the 

Toxicological Effects of Methylmercury Board on Environmental Studies and Toxicology, 

Commission on Life Sciences. National Academy Press, Washington, DC, 2000. Available 

at: < http://www.nap.edu/books/0309071402/html/ >. 

2. 	 Mishima, Akio. Bitter Sea: The Human Cost of Minamata Disease. Kosei Publishing Co., 

Tokyo, Japan, 1992. 

3. 	 French, C.L., W.H. Maxwell, W.D. Peters, G.E. Rice, O.R. Bullock, A.B. Vasu, R. Hetes, 

A. Colli, C. Nelson, and B.F. Lyons. Study of Hazardous Air Pollutant Emissions from 

Electric Utility Steam Generating Units -- Final Report to Congress, Volumes 1-2. EPA453/R-98-004a and b. Office of Air Quality Planning and Standards, Research Triangle Park, 

NC. February 1998. Available at: 

< http://www.epa.gov/ttn/atw/combust/utiltox/utoxpg.html >. 

4. 	 Keating, M.H., K.R. Mahaffey, R. Schoeny, G.E. Rice, O.R. Bullock, R.B. Ambrose, Jr., 

J. Swartout, and J.W. Nichols. Mercury Study Report to Congress, Volumes I-VIII. EPA452/R-97-003 through 010. Office of Air Quality Planning and Standards and Office of 

Research and Development, Research Triangle Park, NC. December 1997. Available at: 

< http://www.epa.gov/airprogm/oar/mercury.html >. 

5. 	 U.S. Environmental Protection Agency. Deposition of Air Pollutants to the Great Waters: 

First Report to Congress. EPA-453/R-93-055. Office of Air Quality Planning and 

Standards, Research Triangle Park, NC. May 1994. 

1-15

6. 	 Ackermann, J., M. McCullough, E. Ginsburg, D. Byrne, and L. Driver. Deposition of Air 

Pollutants to the Great Waters: Second Report to Congress. EPA-453/R-97-011. Office of 

Air Quality Planning and Standards, Research Triangle Park, NC. June 30, 1997. Available 

at: < http://www.epa.gov/oar/oaqps/gr8water/2ndrpt >. 

7. 	 Lacy, G. and D. Evarts. Deposition of Air Pollutants to the Great Waters: Third Report to 

Congress. EPA-453/R-00-005. Office of Air Quality Planning and Standards, Research 

Triangle Park, NC. June 2000. Available at: 

< http://www.epa.gov/oar/oaqps/gr8water/3rdrpt >. 

8. 	 U.S. Environmental Protection Agency. Database of information collected in the Electric 

Utility Steam Generating Unit Mercury Emissions Information Collection Effort. OMB 

Control No. 2060-0396. Office of Air Quality Planning and Standards, Research Triangle 

Park, NC. April 2001. Available at: 

< http://www.epa.gov/ttn/atw/combust/utiltox/utoxpg.html >. 

9. 	 Brown, T. D., D.N. Smith, R.A. Hargis, Jr., and W.J. O’Dowd. “1999 Critical Review: 

Mercury Measurement and Its Control: What We Know, Have Learned, and Need to Further 

Investigate,” Journal of the Air & Waste Management Association, June 1999. pp. 1-97. 

Available at: < http://www.lanl.gov/projects/cctc/resources/pdfsmisc/haps/CRIT991.pdf >. 

1-16

Chapter 2


Coal-fired Electric Utility Boilers


2.1 Introduction 

The steam produced in a boiler can be used to drive a steam turbine that, in turn, spins an 

electric generator. In a conventional steam boiler used for electrical power generation, water is 

heated under pressure to form high-temperature, high-pressure steam. The heat required to 

produce steam can be supplied by burning a fossil fuel inside an enclosed space in the boiler. 

Electricity generation in the Unities States relies extensively on burning coal in steam boilers. 

This chapter presents an overview of the use of coal by electric utilities for power 

generation. An introduction to the properties of coal and coal resources in the United States is 

presented. The major components and general operation of a conventional coal-fired electric 

utility boiler are described. A profile of the different coal-firing configurations used by electric 

utility power plants in the United States is presented based on analysis of the Part II EPA ICR 

data. Ash produced by coal combustion is described. The chapter concludes with a summary of 

the Part II EPA ICR data for the mercury content of the coals burned by electric utility power 

plants in 1999. Air pollutant emissions and the control strategies currently used for these 

coal-fired electric utility power plants are discussed in Chapter 3. 

2.2 Coal 

Coal is a combustible “rock” composed of organic and mineral materials that have 

formed over time by vegetative decay and mineral deposition. The principal chemical 

constituents of coal are carbon, hydrogen, oxygen, nitrogen, and sulfur. Coal also contains 

incombustible mineral matter and trace amounts of metallic elements, oxides, and rare gases. The 

properties of a given coal deposit vary depending on a variety of site-specific factors including 

the type of vegetative matter from which the coal formed, the age of the deposit, and the 

conditions under which the coal formed. 

2.2.1 Coal Property Tests 

Standardized tests for determining the properties of coal have been adopted by the 

American Society for Testing and Materials (ASTM).1 These ASTM methods are widely used in 

2-1

the United States by coal producers, electric utility companies, and government agencies to 

obtain coal property data for many purposes including classifying coal resources, designing coal 

combustion equipment, pricing coal, and monitoring coal shipment quality. Standardized 

procedures for collecting coal samples for analysis also have been established by ASTM 

methods. 

2.2.1.1 Coal Heating Value 

One of the key properties of coal is the quantity of heat that can be released when the coal 

is burned. The heating value of coal is determined using one of several ASTM test methods 

(e.g., ASTM D2015 or D3286). These tests involve burning a coal sample in a bomb calorimeter 

and measuring the temperature rise following the procedure specified in the method. As used in 

the United States, heating value is most commonly expressed in units of British thermal units per 

pound of coal (Btu/lb). Heating value can also be expressed in units of joules per kilogram, 

kilojoules or kilocalories per kilogram, or calories per gram. Also, heating value may be reported 

as higher heating value (HHV) or lower heating value (LHV). The HHV is the value measured 

by the actual test. The LHV is calculated by subtracting the heat of water vaporization from the 

value measured in the bomb calorimeter. 

2.2.1.2 Coal Proximate Analysis 

The proximate analysis is a widely used test procedure for determining for a given coal the 

total moisture, volatile matter, fixed carbon, and ash contents expressed on a weight-percent 

basis. The protocol for performing a proximate analysis for coal is established by ASTM D3172 

that specifies the overall procedure to be followed and the other specific ASTM test methods to 

be used. The analysis involves performing a series of tests in a specific order on a given coal 

sample. First, the total moisture of the coal is determined by drying the sample in an oven 

according to ASTM test method 3173. The difference in weight before and after drying is the 

amount of moisture in the coal. 

Volatile matter is not naturally present in coal. However, combustible gases (e.g., 

hydrogen, methane, and other hydrocarbons) are formed by thermal decomposition when the coal 

sample is heated under controlled temperature and time conditions. The conditions are specified 

in ASTM test method 3175. The difference in weight before and after heating the coal sample 

for a second time in a furnace is the amount of volatile matter contained in the coal. The coal 

sample is then completely burned under conditions specified in ASTM test method 3174. The 

weight of the noncombustible matter remaining after combustion is the ash content in the coal. 

The percentage of fixed carbon is obtained by subtracting from 100 percent the sum of the 

percentages of total moisture, volatile matter, and ash. 

2.2.1.3 Coal Ultimate Analysis 

The second analysis procedure commonly performed is the ultimate analysis. This 

analysis determines the composition of the coal based on elemental constituents. The protocol 

2-2

for performing a coal ultimate analysis is established by ASTM D3176 which specifies the 

overall procedure to be followed and the specific ASTM test methods to be used. As defined in 

ASTM D3176, the elements determined are total carbon, total hydrogen, total sulfur, total 

nitrogen, and total oxygen. Determination of ash is included in the analysis. The quantity of 

chlorine present in the coal is also commonly included as part of the ultimate analysis. However, 

the contents of mercury and other trace constituents in the coal are not included in the results 

from a coal ultimate analysis. 

2.2.1.4 Coal Mercury Analysis 

A separate analysis must be conducted to determine the Hg content of coal. Several 

ASTM test methods are available for measuring the total Hg concentration in a coal sample. 

Two methods are established by ASTM D6414 “Standard Test Method for Total Mercury in Coal 

and Coal Combustion Residues by Acid Extraction or Wet Oxidation/Cold Vapor Atomic 

Absorption.” The lower quantitative limits for these methods are, respectively, 0.02 ppm and 

0.03 ppm. A third, commonly used method is ASTM D3684 “Standard Test Method for Total 

Mercury in Coal by the Oxygen Bomb Combustion/Atomic Absorption Method” with a lower 

quantitative limit of 0.06 ppm. An interlaboratory study conducted by EPRI evaluated the use of 

these three analytical methods to measure coal Hg content for submitting data to the EPA ICR.2 

The study indicated that all three methods had certain limitations, especially when used to 

analyze very low Hg content coals and coal ashes. However, the study concluded that the 

uncertainty in these methods should not have a significant impact on the use of the data collected 

by the EPA ICR for nationwide Hg emission estimates. 

2.2.2 Coal Classification 

Over the years, a number of coal classification systems have been developed by the United 

States Geological Survey (USGS) and others. These coal classification systems allow 

assessments of coal resources and provide data for designing coal combustion equipment.3 In the 

United States, coals are classified using a hierarchy ranking coals relative to other coals based on 

the degree of metamorphism (effectively, the geological age of the coal and the conditions under 

which the coal formed). These classification criteria have been standardized by ASTM method 

D-388. Under the ASTM method, coals are divided into four major categories called “ranks.” 

Each rank is further subdivided into groups. The basic ranking criteria are coal heating value, 

volatile matter content, fixed carbon content, and agglomerating behavior. The coal ranks are 

summarized below. 

Anthracite coal. The highest rank class of coal that is defined to be a nonagglomerating 

coal having more than 86 percent fixed carbon and less than 14 percent volatile matter on 

a dry, mineral-matter-free basis. This coal rank is subdivided into three groups based on 

decreasing fixed carbon and increasing volatile matter content: meta-anthracite, 

anthracite, and semianthracite. 

2-3

Bituminous coal. The second highest rank of coal defined to be high in carbonaceous


matter, having less than 86 percent fixed carbon, and a 14 percent volatile matter on a


dry, mineral-matter-free basis, and a heating value of more than 10,500 Btu/lb on a moist,


mineral-matter-free basis. This coal can be either agglomerating or nonagglomerating.


The rank is subdivided into five bituminous coal groups on the basis of decreasing heat


content and fixed carbon and increasing volatile matter: low-volatile bituminous coal,


medium-volatile bituminous coal, and high-volatile bituminous coals A, B, and C.


Subbituminous coal. The third-highest rank of coal defined to be nonagglomerating coals


having a heating value of more than 8,300 Btu/lb but less than 11,500 Btu/lb on a moist,


mineral-matter-free basis. This rank of coal is subdivided on the basis of decreasing heat


value into three groups: subbituminous A coal (10,500 to 11,500 Btu/lb),


subbituminous B coal (9,500 to 10,500 Btu/lb), and subbituminous C coal (8,300 to 9,500


Btu/lb). Note that the heating value range for the upper-end subbituminous A coals


overlaps with the heating value range for the lower-end high-volatile bituminous C coals.


Lignite. The lowest rank of coal defined to consist of brownish-black coal having heating


values less than 8,300 Btu/lb on a moist, mineral-matter-free basis. This rank of coal is


subdivided into two groups: lignite A (6,300 to 8,300 Btu/lb) and lignite B (less than


6,300 Btu/lb).


2.2.3 United States Coal Resources 

Coal is the most abundant fossil fuel in the United States. The DOE Energy Information 

Administration (EIA), the Federal government agency responsible for estimating coal resources 

in the United States, estimates that the demonstrated reserve base of coal in the United States is 

approximately 508 billion tons.4 The distribution of this coal by major coal rank is presented in 

Table 2-1. Over half of the coal reserve base is classified as bituminous coal. Another third of 

the reserves are classified as subbituminous coal. 

Not all of the coal identified in the demonstrated reserve base can be extracted from the 

ground for a variety of reasons. Of the estimated 508 billion tons of demonstrated coal reserves, 

the DOE EIA estimates that approximately 275 billion tons of coal can be recovered by standard 

mining technologies, assuming that a market and an adequate selling price exist for this coal. 

In the United States, coal deposits have been found in 36 states. Figure 2-1 shows the 

distribution of coal resources in the United States by coal region as designated by the USGS. 

Coal resources in the Eastern United States are concentrated primarily along the Appalachian 

Mountains and are estimated by the DOE EIA to contain 108 billion tons. The major deposits of 

bituminous coals are concentrated in the Central Appalachian region comprised of eastern 

Kentucky, western Virginia, and southern West Virginia. Most of the anthracite coal resources 

in the United States are located in eastern Pennsylvania (Pennsylvania Anthracite and Northern 

Appalachian regions). 

2-4

Table 2-1. Demonstrated reserve base of major coal ranks in the United States 

estimated by DOE/EIA (source: Reference 4). 

Coal Rank 

Estimated 

U.S. Demonstrated 

Coal Reserves 

(billion tons) 

Percentage of 

U.S Demonstrated 

Coal Reserves 

Anthracite 8 % 

Bituminous 271 53 % 

Subbituminous 185 36 % 

Lignite 44 9 % 

Total 508 100 % 

2 

2-5

2-6


Figure 2-1. Distribution of coal deposits in the continental United States by USGS 

region (source: Reference 5). 
The coal regions in the Central United States (Eastern Interior, Western Interior, Texas, 

and Mississippi regions) are estimated by the DOE EIA to contain 160 billion tons of coal. Most 

of the coal deposits in these regions are bituminous coal (largest deposits in the Eastern Interior 

region). A band of lignite deposits occur along the Gulf Coast (Texas and Mississippi regions) 

with the largest deposits in eastern Texas. 

The coal reserves in the Western United States coal regions are estimated by the DOE EIA 

to be 240 billion tons. Subbituminous coal is the most prevalent coal type with the major 

deposits located throughout Montana and Wyoming (Powder River, Bighorn Basin, Wind River, 

and Green River – Hams Fork regions) and in northwestern New Mexico (San Juan River 

region). Large deposits of lignite are found in eastern Montana and North Dakota (Fort Union 

region). Bituminous coal is found mostly in the coal regions in Colorado and Utah (Uinta, Raton 

Mesa, and Southwest Utah regions). 

2.2.4 Mercury Content in Coals 

Mercury is a naturally occurring impurity contained in coal in trace amounts. It can occur 

in coal in several forms. Most of the Hg is believed to be present in combination with sulfide 

minerals, particularly pyrite. The mercury-pyrite association accounts for as much as 65 to 70 

percent of the Hg in some coals. Mercury is also associated with other ash-forming minerals and 

with the organic fraction in coal. On the order of 25 to 35 percent of the Hg in coal is typically 

associated with the organic material. 

Data on the Hg content of “in-the-ground” coals are available in the USGS COALQUAL 

database.6 One study evaluated the Hg content of coals using this database and selecting coal 

types representing major coal producing regions in the United States.7 The data from the study 

are summarized in Table 2-2. The average concentration of Hg in the coal samples ranged from 

0.08 to 0.22 μg/g. These data show that the Hg content of coals is not constant but varies 

depending on the coal deposit. The data also show that Hg content is not a function of coal rank 

(i.e., one coal type does not have inherently lower Hg concentrations than another coal type). 

A comparison of the Hg concentrations in the different coals cannot be directly related to 

the amount of Hg emissions emitted from boilers burning these coals. Other coal properties and 

how the coal is prepared prior to firing in a boiler affect the theoretical potential level of Hg 

emissions that would occur in the absence of applying any Hg emissions controls. In other 

words, one cannot conclude that burning a coal with higher as-mined Hg concentration will 

necessarily result in higher Hg emissions from a coal-fired electric utility boiler. 

Coals with higher heating values require less coal to be burned in a boiler on a mass basis 

to produce a given electricity output. For two coals with the same Hg content but different 

heating values, burning the coal with the higher heating value in a given boiler will result in less 

Hg being emitted in boiler combustion gases per unit of electricity output. On an equal energy 

basis, the Hg content of the bituminous and subbituminous coals listed in Table 2-2 span the 

2-7

Table 2-2. Mercury content of selected as-mined coal samples by coal rank and U

region (source: table prepared by summarizing and interpreting coal data presente

Coal Rank USGS Coal Resource Region 

Hg 

Concentration 

(ppm) 

Heating Value 

(Btu/lb) 

Anthracite Pennsylvania Anthracite 0.18 12,440 

Uinta 0.08 10,800 

Raton Mesa 0.09 12,320 

Eastern Interior 0.10 11,400 

Western Interior 0.18 10,970 

Bituminous 

Appalachian 0.20 12,790 

San Juan River 0.08 9,610 

Hams River 0.09 10,570 

Green River 0.09 9,580 

Powder River 0.10 8,090 

Southwest Utah 0.10 9,290 

Subbituminous 

Wind River 0.19 9,560 

Fort Union 0.13 6,360 

Lignite 

Texas and Mississippi 0.22 6,490 

2-8

same general range of values. No trend is apparent from these data; both bituminous and 

subbituminous coals are found at the lower and upper ends of the range. For example, a 

bituminous coal from the Raton Mesa region and a subbituminous coal from the Green River 

region each have an average Hg content of 6.6 lb per 1012 Btu. At the other end of the range, a 

bituminous coal from the Western Interior region has an average Hg content of 16.1 lb per 

1012 Btu and a subbituminous coal from the Wind River region has an average Hg content of 

18.7 lb per 1012 Btu. On the other hand, the Hg contents reported for the two lignite coals listed 

in Table 2-2 are significantly higher than any of the bituminous and subbituminous coals (an 

average of 21.8 lb per 1012 Btu for Fort Union lignite and 36.4 lb per 1012 Btu for Gulf Coast 

lignite). 

Another key reason why the Hg content of as-mined coals cannot be related to Hg 

emissions is the as-mined coal frequently is not burned in an electric utility boiler as it comes 

directly from the mine. The as-mined, or raw, coal often is first processed at a coal preparation 

plant to remove non-coal impurities in order to provide the coal purchaser with a uniform coal 

that meets a predetermined, contractual set of specifications. These processes commonly are 

collectively referred to as “coal cleaning.” Depending on the properties of the coal and the type 

of process used, coal cleaning can reduce the Hg content of the coal that is ultimately fired in the 

electric utility boiler. 

2.3 Coal Cleaning 

2.3.1 Coal Cleaning Processes 

Raw coal from a mine contains separate rock, clay, and other minerals. After the coal is 

mined, it may first pass through a series of processes known as coal preparation or coal cleaning 

before it is shipped to an electric utility power plant. The coal is processed for three main 

reasons: 1) to reduce the ash content; 2) to increase the heating value; and 3) to reduce the sulfur 

content to ultimately lower emissions of sulfur dioxide when the coal is burned in the utility 

boiler. The removal of impurities from the coal also helps to reduce power plant maintenance 

costs and to extend the service life of the boiler system. 

Coal cleaning processes currently in use separate the organic fraction of the as-mined coal 

from the mineral materials according to the differences in either the density-based or surfacebased characteristics of the different materials. Physical coal cleaning typically involves a series 

of process steps including: 1) size reduction and screening, 2) gravity separation of coal from 

sulfur-bearing mineral impurities, and 3) dewatering and drying. 

Bituminous coals from mines in the Eastern and Midwestern United States frequently are 

cleaned to meet the electric utility customer’s specifications for heating value, ash content, and 

sulfur. It is estimated that about three-fourths (77 percent) of these coals are cleaned prior to 

shipment to an electric utility power plant.8 The subbituminous and lignite coals from mines in 

the Western United States routinely are not cleaned before shipment to an electric utility power 

2-9

plant, but in special cases these types of coals can be cleaned. For example, some of 

subbituminous coal from mines in the Powder River coal region (a major source of coal for many 

electric utilities) is cleaned for shipment to electric utility customers. 

2.3.2 Mercury Removal by Coal Cleaning 

Conventional coal cleaning methods will also remove a portion of the Hg associated with 

the incombustible mineral materials but not the Hg associated with the organic carbon structure 

of the coal. Any reduction in Hg content of the coal shipped to an electric utility power plant 

obtained from the Hg removed by coal cleaning processes transfers the removed Hg to the coal 

cleaning wastes. Limited data have been gathered on the level of Hg removed by conventional 

coal cleaning methods. 

A review of test data for 26 bituminous coal samples from coal seams in four states 

(Illinois, Pennsylvania, Kentucky, and Alabama) prepared for EPA’s Mercury Study Report to 

8 Congress indicates a wide range in the amount of Hg removed by coal cleaning. In some cases, 

analysis of coal samples from the same coal seam also showed considerable variability. Analysis 

of five of the coal samples showed no Hg removal associated with conventional coal cleaning 

while the remaining 21 coal samples had Hg reductions ranging from approximately 3 to 64 

percent. The average Hg reduction for all of the data was approximately 21 percent. 

Other studies have reported higher average Hg reductions for Eastern and Midwestern 

bituminous coals. One study tested 24 samples of cleaned coal.7 These data also showed a wide 

range in Hg reduction rates. The average decrease in Hg reduction on an energy basis was 37 

percent, with values ranging from 12 to 78 percent. On a mass basis, the average Hg reduction 

from coal cleaning was 30 percent. A higher Hg reduction was reported on an energy basis than 

on a mass basis because the coal cleaning raises the heating value per unit mass of the coal, as 

well as removing Hg. A second study of the effects of coal cleaning on Hg content for three 

9 Ohio coals reported reductions in Hg content of the coals ranging from 36 to 47 percent. 

The variation in Hg reductions observed from the test data might be a function of the type 

of process used to clean a given coal and the proportion of Hg in the coal that is present in 

combination with pyrite (iron disulfide). Coal-cleaning processes that make separations 

according to the density differential of particles are generally more effective in removing Hg 

associated with pyrite than are surface-based processes. The heavier pyrite is easily removed by 

density-based processes, but not by surface-based processes where the similar surface 

characteristics of pyrite and the organic matter make separation of the two components difficult. 

For coals that have larger portions of Hg associated with pyrite, density-based cleaning processes 

are expected to have higher Hg removals. However, some coals may contain large portions of 

Hg associated with the organic fraction of the coal; Hg removal in these cases would be expected 

to be substantially lower since the organic fraction of coal is not removed during cleaning. 

Additional reductions in Hg can probably be achieved by using more intensive coal cleaning 

methods. Several advanced coal cleaning techniques being investigated to improve Hg removal 

are discussed in Chapter 7. 

2-10

2.4 Coal-fired Electric Utility Boilers 

The large steam boilers used by electric utilities are also referred to as “steam generators,” 

“steam generating units,” or simply “boilers.” As discussed in Chapter 1, CAA Section 112(a) 

defines the term Aelectric utility steam generating unit@ to include those units that cogenerate 

steam and electricity and supply more than one-third of its potential electric output capacity and 

more than 25 megawatts electrical output to any utility power distribution system for sale. For 

simplicity in the remainder of this report, the term “electric utility boiler” is used to mean 

“electric utility steam generating unit” as defined in CAA Section 112(a)(8). 

A total of 1,143 coal-fired units meeting the CAA definition of an "electric utility steamgenerating unit" were reported in the Part II EPA ICR data to be in the United States in 1999.10 

More than one boiler unit is often operated at an electric utility power plant. The 1,143 units 

were located at a total of 461 facilities. These facilities can be categorized in three facility types: 

conventional coal-fired electric utility power plants, coal-fired cogeneration facilities, and 

integrated coal gasification and combined cycle (IGCC) power plants. 

2.4.1 Conventional Coal-fired Electric Utility Power Plants 11,12 

A conventional electric utility power plant burns coal in a boiler unit solely for the 

purpose of generating steam for electrical power production. A total of 1,122 coal-fired electric 

utility boilers were reported in the Part II EPA ICR data to be operating at conventional electric 

utility power plants. Each of these boilers was designed to meet plant load and performance 

specifications by burning coals within a specific range of coal properties (e.g., heating value, ash 

content and characteristics, and sulfur content). While the specific equipment and design of a 

coal-fired electric utility boiler will vary from plant to plant, the same basic process is used to 

generate electricity. Figure 2-2 presents a simplified schematic of the major components of a 

coal-fired electric utility boiler operated at a conventional electric utility power plant. 

Coal typically is delivered to a power plant by railcars, trucks, or barges. At some power 

plants located near the mine supplying the coal, coal is delivered by a slurry pipeline or an 

extended conveyor system. Also, a few power plants burn imported coal that is delivered to the 

facility by ship. The delivered coal is unloaded and stored in outdoor storage piles or covered 

storage structures such as silos or bins. Depending on how the coal is burned in the boiler (e.g., 

in a bed or burned in suspension), the coal is crushed or pulverized before being fed to the boiler. 

A conventional coal-fired electric utility boiler consists of multiple sections, each of which 

serves a specific purpose. The coal is ignited and burned in the section of the boiler called the 

“furnace chamber.” Blowing ambient air into the furnace chamber provides the oxygen required 

for combustion. The carbon and hydrogen comprising the coal are oxidized at the high 

temperatures produced by combustion to form the primary combustion products of carbon 

dioxide (CO2

) and water (H2O). Sulfur in the coal is oxidized to form SO2. Molecular nitrogen 

in the combustion air and nitrogen bound in the coal react with oxygen in certain sections of the 

combustion zone in the furnace chamber to form NOx. Small amounts of other gaseous 

2-11

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�������� Particulate Collection Device Furnace Chamber 

Condenser 

Generator 

Multi-stage 

Steam 

Turbine 

Steam 

Drum 

Superheater 

Burners 

Forced Draft Fan 

Reheater 

Economizer 

Air 

Heater 

air 

Coal 

Silo 

flue gas 

heated combustion air 

high-pressure steam 

reheated 

steam 

boiler 

feedwater 

2-12


Coal 

Pulverizer 

Figure 2-2. Simplified schematic of coal-fired electric utility boiler burning pulverize
combustion products form from other impurities in the coal. These hot combustion products are 

vented from the furnace in a gas stream called collectively Aflue gas.@ Additionally, most but not 

all the carbon in the coal is burned in the furnace. Unburned or partially burned solid carbon 

particles are entrained and vented from the furnace in the flue gas. 

The walls of the furnace chamber are lined with vertical tubes containing water. Heat 

transfer from the hot combustion gases in the furnace boils the water in the tubes to produce 

high-temperature, high-pressure steam. This steam flows from the boiler to a steam turbine. In 

the turbine, the thermal energy in the steam is converted to mechanical energy to drive a shaft 

that spins a generator, which produces electricity. After the steam exits the turbine, it is 

condensed and the water is pumped back to the boiler. 

To improve overall energy conversion efficiency, modern coal-fired electric utility boilers 

contain a series of heat recovery sections. These heat recovery sections are located downstream 

of the furnace chamber and are used to extract additional heat from the flue gas. The first heat 

recovery section contains a "superheater," which is used to increase the steam temperature. The 

second heat recovery section contains a "reheater," which reheats the steam exhausted from the 

first stage of the turbine. This steam is then returned for another pass thorough a second stage of 

the turbine. The reheater is followed by an "economizer," which preheats feed water to the boiler 

tubes in the furnace. The final heat recovery section is the "air heater," which preheats ambient 

air used for combustion of the coal. 

A portion of all coals is composed of mineral matter that is noncombustible. This matter 

forms the ash that continuously must be removed from the operating utility boiler. The ash 

collection points and removal systems used for a given boiler unit are dependent on the ash 

properties and content in the coal-fired, the boiler design, and the air pollution control devices 

used. The removal and handling of the coal ash is discussed further in Section 2.6. 

The flue gas exhausted from the boiler passes through air pollution control equipment and 

is vented to the atmosphere through a tall stack. The types and configurations of air pollution 

controls currently used for coal-fired electric utility boilers are discussed in Chapter 3. 

2.4.2 Coal-fired Cogeneration Facilities 

Approximately six percent of the boiler units are at cogeneration facilities, which are 

owned and operated by independent power producers or industrial companies. Of the 1,143 total 

coal-fired electric utility boilers reported in the EPA Part II ICR data, 68 are classified as 

cogeneration units. The total generating capacity of these cogeneration units is 867 MWe. There 

are more coal-fired boilers in the United States operating as cogeneration units; however, these 

units do not meet the criteria specified in the CAA definition of a steam-generating unit (i.e., the 

cogeneration unit is rated below 25 MWe or less than one-third of the unit’s electrical output is 

sold). These units were not surveyed for the EPA ICR database. 

2-13

Operation of a cogeneration facility differs from the operating configuration of the 

conventional electric utility power plant shown in Figure 2-2. Two basic cogeneration unit 

configurations are used: the Atopping@ mode or the Abottoming@ mode. In the topping 

cogeneration configuration, steam produced by the coal-fired electric utility boiler is used first to 

generate electricity and then all or part of the exhaust heat is subsequently used for an industrial 

process. The bottoming cogeneration configuration reverses this sequence using waste heat 

generated by an industrial process to produce steam in a heat recovery boiler for driving a steam 

turbine and generating electricity. All of the cogeneration boiler units listed in the EPA ICR data 

operate using the topping mode configuration. 

2.4.3 Integrated Coal Gasification Combined Cycle Power Plants 

The IGCC power plants represent a new technology and are different from conventional 

electric utility power plants in two major characteristics. First, the IGCC power plants do not 

burn the coal in its solid form. Instead, the coal is first converted to a combustible gas using a 

coal gasification process at the facility site. Second, the IGCC power plants generate electricity 

using two separate thermal cycles and associated turbines referred to as a "combined cycle" 

operation. The coal-derived gas from the gasification process is first burned in a gas turbine that 

drives an electrical generator. The exhaust gases from this gas turbine pass through a heat 

recovery boiler to generate steam to power a steam turbine that drives a second electrical 

generator. Three IGCC power plants have been built in the United States. The operation of these 

power plants is discussed further in Section 2.5.5. 

2.5 Coal-firing Configurations for Electric Utility Boilers 

Coal can be burned in a boiler using one of three basic techniques: burning coal particles 

in suspension, burning large coal chunks in a fuel bed, or in a two-step process in which the coal 

is first converted to a synthetic gas which is then fired in the boiler. Five basic firing 

configurations are used to burn coal for electric power generation: pulverized-coal-fired furnace, 

cyclone furnace, fluidized-bed combustor, stoker-fired furnace, and gasified-coal-fired 

combustor. A general comparison of the different coal-firing configurations used for electric 

utility power plants is presented in Table 2-3. 

Table 2-4 shows the distribution of the 1,143 coal-fired electric utility boilers listed in the 

EPA ICR data by coal-firing configuration. Pulverized-coal-fired designs account for the vast 

majority of the coal-fired electric utility boilers both in terms of total number of units 

(approximately 86 percent) and nationwide generating capacity. Cyclone furnaces are used to 

burn coal in approximately eight percent of the units. Fluidized-bed combustors are used for 

about four percent of the coal-fired electric utility boilers. Stoker-fired furnaces account for 

about three percent of the total number of coal-fired electric utility boilers but provide less than 

one percent of the total coal-fired megawatts. Only three IGCC units have been built in the 

United States. 

2-14

Table 2-3. Characteristics of coal-firing configurations used for electric utility power pla

Coal-firing 

Configuration Coal Combustion Process Description Distinctive Design/Operating 

Wall-fired 

An array of burn

horizontally, anone wall or opp

the furnace des

Pulverized-coalfired furnace 

Coal is ground to a fine powder that is pneumatically fed to a burner where it is mixed with combustion air and then blown into the furnace. The pulverized-coal 

particles burn in suspension in the furnace. Unburned 

and partially burned coal particles are carried off with the flue gas. Tangential-fired 

(Corner-fired) 

Multiple burners opposite cornera fireball that mand expands to 

Cyclone 

furnace 

Coal is crushed into small pieces and fed through a 

burner into the cyclone furnace. A portion of the combustion air enters the burner tangentially creating a 

whirling motion to the incoming coal. 

Designed to burn low-ash fusion coals and 

the form of a molten slag. 

Bubbling fluidized bed 

(BFB) 

Operates at relavelocities and wparticles. Air in fluidize the bed the form of bub

Fluidized-bed 

combustor 

Coal is crushed to fine particles. The coal particles are 

suspended in a fluidized bed by upward-blowing jets of air. The result is a turbulent mixing of combustion air 

with the coal particles. Typically, the coal is mixed with 

an inert material (e.g., sand, silica, alumina) and a 

sorbent such as limestone (for SO2 emission control). 

The unit can be designed for combustion within the bed 

to occur at atmospheric or elevated pressures. Operating temperatures for FBC are in the range of 850 

to 900 °C. 

Circulating 

fluidized bed 

(CFB) 

Operates at higand with finer-bdefined bed sur

volume, hot cyc

recirculate entragas to maintain 

combustion effi

2-15

Table 2-3. (continued). 

Coal-firing 

Configuration Coal Combustion Process Description Distinctive Design/Operating 

Spreader-stoker 

A flipping mech

the furnace abocoal particles bheavier coal lumburn in a fuel be

Underfeed Coal fed by pus

feed through un

Stoker-fired 

furnace 

Coal is crushed into large lumps and burned in a fuel bed on a moving, vibrating, or stationary grate. Coal is pushed, dropped, or thrown onto the grate by a 

mechanical device called a “stoker.” 

Traveling grate 

Coal is fed by g

and leveled by furnace entranc

Gasified-coalfired combustor 

Synthetic combustible gas derived from an on-site coal gasification process is burned in a gas turbine 

combustor. The hot combustion gases turn the gas turbine blades mounted on a shaft that drives an 

electric generator. The hot exhaust gases from the gas 

turbine pass through a waste heat boiler to produce steam for driving a steam turbine/generator unit. 

Gasified-coal-fired combustors are unique configurations because a gaseous fuel is bcoal. 

2-16

Table 2-4. Nationwide distribution of electric utility units by coal-firing 

configuration for the year 1999 as reported in the Part II EPA ICR data (source: 

Reference 10). 

Coal-firing 

Configuration 

Nationwide 

Total Number of 

Units 

Percent of 

Nationwide Total 

Percent of 

Nationwide 

Electricity 

Generating 

Capacity 

Pulverized-coal-fired furnace 979 85.6 % 90.1 % 

Cyclone furnace 87 7.6 % 7.6 % 

Fluidized-bed combustor 42 3.7 % 1.3 % 

Stoker-fired furnace 32 2.8 % 1.0 % 

Gasified-coal-fired combustor 3 0.3 % < 0.1 % 

Nationwide Total 1,143 100 % 100 % 

2-17

2.5.1 Pulverized-coal-fired Furnace 

To burn in a pulverized-coal-fired furnace, the coal must first be pulverized in a mill to 

the consistency of talcum powder (i.e.; at least 70 percent of the particles will pass through a 

200-mesh sieve). The pulverized coal is generally entrained in primary air before being fed 

through the burners to the combustion chamber, where it is fired in suspension. Pulverized-coal 

furnaces are classified as either dry or wet bottom, depending on the ash removal technique. Dry 

bottom furnaces fire coals with high ash fusion temperatures, and dry ash removal techniques are 

used. In wet bottom (slag tap) furnaces, coal with a low ash fusion temperature is fired, and 

molten ash is drained from the bottom of the furnace. 

Pulverized-coal-fired furnaces are further classified by the firing position of the burners. 

Wall-fired boilers are characterized by rows of burners on one or more walls of the furnace. The 

two basic forms of wall-fired furnaces are single-wall (having burners on one wall) or opposed 

(having burners on walls that face each other). Circular register burners and cell burners are 

types of burner configurations used in both single-wall and opposed-wall-fired units. A circular 

register burner is a single burner mounted in the furnace wall, separated from other burners so 

that it has a separate, distinct flame zone. Cell burners are several circular register burners 

grouped closely together to concentrate their distinct flame zones. 

Tangential-fired boilers are based on the concept of a single flame envelope and project 

both fuel and combustion air from the corners of the furnace. The flames are directed on a line 

tangent to a small circle lying in a horizontal plane at the center of the furnace. This action 

produces a fireball that moves in a cyclonic motion and expands to fill the furnace. 

2.5.2 Cyclone Furnace 

Cyclone furnaces use burner design and placement (i.e., several water-cooled horizontal 

burners) to produce high-temperature flames that circulate in a cyclonic pattern. The coal is not 

pulverized but instead crushed to a 4-mesh size. The crushed coal is fed tangentially, with 

primary air, to a horizontal cylindrical combustion chamber. In this chamber, small coal particles 

are burned in suspension, while the larger particles are forced against the outer wall. The high 

temperatures developed in the relatively small furnace volume, combined with the low fusion 

temperature of the coal ash, causes the ash to form a molten slag, which is drained from the 

bottom of the furnace through a slag tap opening. 

2.5.3 Fluidized-bed Combustor 

Fluidized-bed combustion increasingly is being used for coal-fired electric utility power 

plants. A variety of coals, including those with high concentrations of ash, sulfur, and nitrogen, 

can be burned in a fluidized-bed combustor (FBC). The term "fluidized" refers to the state of the 

bed materials (fuel or fuel and inert material [or sorbent]) as gas passes through the bed. In a 

typical FBC, combustion occurs when coal, with inert material (e.g., sand, silica, alumina, or ash) 

and a sorbent such as limestone, is suspended through the action of primary combustion air 

2-18

which is distributed below the combustor floor. The gas cushion between the solids allows the 

particles to move freely, giving the bed a liquid-like characteristic (i.e., fluidized). In an FBC, 

crushed coal (between 1⁄4 and 3/8 inches in diameter) is injected into a bed above a grate-like air 

distributor. Air is injected upward through the grate, lifting and suspending the solid particles. 

Inert materials such as sand or alumina are often mixed with the coal to maintain the bed in a 

fluidized state. Limestone particles can also be added to the bed to adsorb sulfur dioxide 

produced during combustion (discussed in Chapter 3). 

2.5.4 Stoker-fired Furnace 

Stoker-firing of coal is used for the oldest furnace designs in the electric utility industry, 

being first introduced to the industry in the late 1800s. Today, this design is used by only a few 

of the operating power plants. New power plants are not expected to adopt this design. In stoker 

furnaces, coal is burned on a bed at the bottom of the furnace. The bed of coal burns on a grate. 

Heated air passes upward through openings in the grate. Stokers are classified according to the 

way coal is fed to the grate; the three general classes in use today are underfeed stokers, overfeed 

stokers, and spreader stokers. Underfeed stokers feed coal by pushing it upward through the 

bottom of the grate. In overfeed stokers, the coal is deposited directly on the grate from a 

gravity-fed bin. In spreader stokers, a flipping mechanism throws the coal into the furnace above 

the grate; in this method, fine coal particles burn in suspension while heavier particles fall to the 

grate and burn. Additional combustion air is added above the grate to support suspension 

burning. Overfeed stokers can burn every type of coal except caking bituminous coal; spreader 

stokers can burn all types of coal except anthracite. 

2.5.5 Gasified-coal-fired Combustor 

Unlike the four coal-firing configurations discussed above, IGCC power plants do not 

burn solid coal. In place of the coal-fired boiler used at a conventional coal-fired electric utility 

power plant, at an IGCC power plant a coal gasification unit is used coupled with a gas turbine 

combustor and heat recovery boiler. The solid coal is gasified by a process in which a coal/water 

slurry is reacted at high temperature and pressure with oxygen (or air) and steam in a vessel (the 

gasifier) to produce a combustible gas. This combustible gas is composed of a mixture of carbon 

dioxide and hydrogen and is often referred to as a synthetic gas or Asyngas.@ Molten ash flows 

out of the bottom of the gasifier into a water-filled sump where it forms a solid slag. The syngas 

is cleaned and conditioned before being burned in a gas turbine that drives an electrical 

generator. The hot combustion gases from the gas turbine are exhausted directly through a heat 

recovery boiler (i.e., no combustion takes place in the boiler) to produce steam that is then 

expanded through a steam turbine that drives a second generator to produce more electrical 

power. 

The generation of electricity using the IGCC process offers a number of advantages 

compared to using conventional coal-fired boilers including higher thermal conversion 

efficiencies (e.g., more kilowatt-hours of electricity generated per kilogram of coal burned), 

greater fuel flexibility (e.g., capability to use a wider variety of coal grades), and improved 

2-19

control of particulate matter and SO2 emissions without the need for post-combustion control 

devices (e.g., almost all of the sulfur and ash in the coal is removed during the gasification 

process). Three IGCC power plant projects have been constructed in the United States as part of 

the DOE=s Clean Coal Technology Program, a joint government-industry cost-share technology 

development program. These facilities are the 250 MWe Tampa Electric Company Polk Power 

Project, the 307 MWe Wabash River Coal Gasification Repowering Project, and the 107 MWe 

Sierra Pacific Pinon Pine IGCC Power Project. Two of the facilities currently are operating (the 

Polk and Wabash River IGCC facilities). The Pinon Pine IGCC facility presently is shut down 

because of recurring problems with particulate matter in the syngas causing premature gas 

turbine blade erosion.13 

In IGCC applications, the syngas from the gasifier is cleaned and conditioned before it is 

burned in the gas turbine using several different techniques. For example, at the Wabash River 

IGCC facility, the syngas from the coal gasifier passes through a series of gas cleaning and 

conditioning steps including a barrier filter for particulate removal, a water scrubber for gas 

cooling, and an amine scrubber for removal of reduced-sulfur species. In contrast, at the Polk 

IGCC facility, a hot-gas cleaning process is used and the syngas from the coal gasifier is not 

cooled before it is burned in the gas turbine. 

2.6 Ash from Coal Combustion 

Coal contains inorganic matter that does not burn including oxides of silicon, aluminum, 

iron, and calcium. This noncombustible matter forms ash when the coal is burned. Burning of 

coal in electric utility boilers generates large quantities of ash that must be removed and disposed 

of. The finer, lighter ash particles are entrained in the combustion gases and vented from the 

furnace section with the flue gas. This portion of the coal ash is referred to as “fly ash.” The 

coarser, heavier ash particles fall to the bottom of the furnace section in the boiler unit. This 

portion of the coal ash is referred to as "bottom ash." The proportion of fly ash to bottom ash 

generated in a coal combustion unit varies depending on how the coal is burned. 

In general, the fly ash is collected as a dry material at several points downstream of the 

furnace section. These points include collection hoppers beneath the boiler economizer, air 

heater, and the particulate matter control devices (other than wet scrubbers). From the collection 

hopper, the fly ash is conveyed using a mechanical system, vacuum system, pneumatic system, or 

combination of these systems to a storage silo. If a wet scrubbing system is used for air pollutant 

control, fly ash is captured and removed in the scrubber wastewaters. 

For most boiler designs, the bottom ash is collected in a pit or hopper at the bottom of the 

boiler furnace. The ash is collected in the form of either a dry material or a molten slag 

depending on whether the furnace operating temperature is above the ash fusion temperature (i.e., 

the temperature at which the mineral compounds composing the ash melt). The ash is 

continuously removed from the ash pit using a mechanical, pneumatic, or hydraulic conveyance 

system. 

2-20

When coal is burned in a pulverized-coal furnace, on the order of 60 to 80 percent of the 

total ash generated is fly ash. The high amount of fly ash results because the coal enters the 

furnace in a fine powder form that burns rapidly in suspension resulting in many tiny, lightweight 

ash particles that can easily be carried out of the furnace section with the flue gas. The heavier 

ash particles fall to the bottom of the furnace where they are removed. Two pulverized-coal 

boiler design approaches are used to collect bottom ash. The more frequently used design 

approach, commonly referred to as a “dry-bottom” furnace, collects the ash as essentially a dry 

material. For the typical dry-bottom furnace, the ash and slag particles fall into a water-filled 

hopper. The water serves several purposes including providing an air seal to prevent the 

infiltration of ambient air into the furnace, solidifying molten slag particles, and facilitating ash 

handling. The ash is then continuously removed from the ash pit using either a mechanical or an 

hydraulic conveyance system. The other design approach, referred to as a “wet-bottom” furnace, 

positions the coal burners on the furnace wall to maintain the ash that collects on the furnace 

floor in a molten state. The slag is drained through a slag tap opening into a slag tank. 

The cyclone furnace is specifically designed to burn low-ash fusion coals and retains most 

of the ash in the form of a molten slag. The molten slag collects in a trough on the bottom of 

furnace and is continually drained through a slag tap opening into a slag tank. Water in the slag 

tank solidifies the ash for disposal. Only 20 to 30 percent of the ash produced by burning coal in 

a cyclone furnace is entrained as fly ash. 

By nature of the fluidized-bed combustion process, most of the ash in the coal leaves the 

fluidized-bed combustor as fly ash. Because the temperatures in the FBC remain below the ash 

fusion temperature, formation of slag is avoided. Bottom ash is removed as a dry material to 

maintain the fluidized bed at a constant level. The ash removal system can be either a 

mechanical or pneumatic system. 

In stoker-fired furnaces where the coal is burned in a fuel bed, most of the ash remains on 

the grate and is removed as bottom ash. Some smaller ash particles are entrained in the upward 

flow of combustion air through the grate and exit the furnace section as fly ash. The spreader 

stoker has a greater proportion of the ash entrained as fly ash (up to 50 percent of the ash) than 

the other stoker types (on the order of 20 percent fly ash). This occurs because the spreader 

stoker mechanically throws the crushed coal across the top of the grate. This allows the smaller 

coal fines in the incoming coal to burn in suspension before falling to the grate. This produces 

the small, lightweight ash particles that are carried out of the furnace section with the flue gas. 

No ash is produced when burning syngas derived from coal in an IGCC power plant. The 

ash contained in the coal is removed by the gasification process that is used to produce the 

syngas. Before the syngas can be burned in the gas turbine, the gas must be precleaned to 

remove all types of particulate matter in order to prevent premature wear and destruction of the 

turbine blades. 

2-21

2.7 Coals Burned by Electric Utilities In 1999 

The EPA ICR Part II survey collected data on the coal, coal wastes, and some 

supplemental fuels burned in each coal-fired electric utility boiler operating in the United States 

during the entire calendar year 1999. Coal samples were analyzed for, at a minimum, the higher 

heating value (HHV) and the coal sulfur, ash, Hg, moisture, and chlorine content. Samples were 

collected every third to twelfth fuel shipment in each month of 1999, depending on the statistical 

characteristics of initial analysis results for each boiler unit. Either the coal shipper or the power 

plant operator could take the sample if the samples were collected at a point after any coal 

cleaning had been completed. Thus, Aas-shipped@ or Aas-received@ coals are considered to be 

equivalent to Aas-fired@ coals, and Hg analyses from such samples are assumed to represent the 

quantity of Hg entering the boiler. 

In 1999, a nationwide total of approximately 786 million tons of coal and supplemental 

fuels were burned in coal-fired electric utility boilers that met the CAA Section 112(a) definition 

of an electric utility steam generating unit (i.e., boiler units of more than 25 megawatts that serve 

a generator that produces electricity for sale). Table 2-5 shows the nationwide distribution of the 

coal burned by rank as reported by the respondents to the EPA ICR (i.e., the power plant owners 

and operators). 

Most electric utility power plants burn either bituminous or subbituminous coals. Half of 

the coals burned by the electric utility industry in 1999 were bituminous coal (52 percent of the 

total nationwide tonnage). Approximately one-third of the coals burned were subbituminous 

coals (36.5 percent of the total nationwide tonnage). Some power plants reported burning both 

bituminous and subbituminous coals. At most of these facilities, the two coal types are blended 

together before firing in the boiler unit. A few of the facilities switch between the two coal types 

for firing in the boiler unit to address site-specific circumstances. The vast majority of the 

bituminous or subbituminous coals were supplied from mines in the United States. However, 

imported coals were burned in 1999 at a few power plant locations. Ten plants, located near Gulf 

of Mexico or Atlantic Ocean seaports, imported bituminous coal from South America and three 

plants located in Hawaii and Florida imported subbituminous coal from Indonesia. 

In general, the burning of lignite or anthracite coals by electric utilities is limited to those 

power plants that are located near the mines supplying the coal. Lignite accounted for 

approximately 6.5 percent of the total coal tonnage burned at electric utility power plants in 

1999. A total of 17 electric utility power plants reported burning lignite. All of these facilities 

are located near the coal deposits from which the lignite is mined in Texas, Louisiana, Montana, 

or North Dakota. Similarly, burning of anthracite coal in 1999 was limited to a few power plants 

located close to the anthracite coal mines in eastern Pennsylvania. The coal-fired electric utility 

boilers at these facilities burned either newly mined anthracite coal or waste anthracite coal 

reclaimed from mine waste piles. 

Table 2-5 also shows that small amounts of supplemental fuels (e.g., petroleum coke or 

tire derived fuel [TDF] chips) also were co-fired with coal in some coal-fired electric utility 

2-22

Table 2-5. Nationwide quantities of coals and supplemental fuels burned in 

coal-fired electric utility boilers for the year 1999 as reported in the Part II EPA 

ICR data (source: Reference 10). 

Fuel Type 

Total Tonnage 

Burned 

(million tons) 

Percentage 

by Weight 

Bituminous coal 406 51.7% 

Subbituminous coal 287 36.5% 

Lignite 51 6.5% 

Bituminous/subbituminous coal mixture 24 3.0% 

Bituminous coal/petroleum coke mixture 6 0.7% 

Waste anthracite coal 5 0.6% 

Waste bituminous coal 4 0.5% 

Petroleum coke 2 0.3% 

Other (a) 1 < 0.2% 

Total 786 100% 

(a)	 Mixes of anthracite, bituminous, and waste bituminous fuel, tires, subbituminous coal and petroleum 

coke, or waste subbituminous coal. 

2-23

boilers. At these facilities, the supplemental fuels are mixed with coal before firing in the boiler 

unit. These supplemental fuels typically have heating values higher than that of coal and serve to 

boost the overall heating value of the fuel mix burned in the boiler unit. Less than 0.5 percent of 

the total fuel tonnage burned in 1999 consisted of supplemental fuels. 

Selected properties of the coal and supplemental fuel burned nationwide in coal-fired 

electric utility boilers in 1999, as reported in the EPA ICR Part II data, are summarized by fuel 

type in Appendix A. Table 2-6 presents a summary of the Hg content data reported for the coals 

and supplemental fuels as fired in the boiler units. The EPA ICR data do not identify the coal 

resource regions from which the coal burned in a given boiler unit was mined. However, 

consistent with the Hg content data for as-mined coals presented in Table 2-2, the data presented 

in Table 2-6 indicate that there is no general relationship between coal rank and Hg content of the 

coal. For bituminous, subbituminous, and lignite coals, the Hg concentrations reported in the 

EPA ICR data ranged from trace amounts to upper levels of approximately 1 ppm. 

A review of the EPA ICR data suggests that there is no direct correlation between the 

sulfur content of a coal and its Hg content. In other words, Ahigh@ sulfur coals are not necessarily 

Ahigh@ Hg coals. Trace concentrations of Hg were reported for coals with high-sulfur contents. 

Conversely, Hg concentrations at the upper end of the concentration ranges also were reported 

for high sulfur-content coals. This observation is consistent with previous studies of the Hg 

content in coal based on a much smaller database. For example, an earlier study comparing the 

sulfur and Hg concentrations in 153 samples of coal shipments found no relationship between the 

sulfur and Hg concentrations in these coals.14 

2-24

Table 2-6. Mercury content of as-fired coals and supplemental fuels burned in co

utility boilers for the year 1999 as reported in the Part II EPA ICR data (source: Re

Hg Concentration 

(ppm dry) 

F

(l

Fuel Type 

Number of 

Samples 

Analyzed 

Range Mean Ran

Bituminous coal 27,793 0.0 - 1.3 0.11 0.07 - 1

South American bituminous coal (a) 270 0.01 - 0.42 0.08 0.70 – 

Subbituminous coal 8,180 0.008 - 0.9 0.07 0.66 - 

Indonesian subbituminous coal (b) 78 0.02 - 0.1 0.03 1.54 – 

Lignite coal 1,047 0.02 - 0.75 0.11 1.84 - 

Anthracite coal 65 0.06 - 0.23 0.14 5.02 – 

Waste anthracite coal 426 0.04 - 0.54 0.19 8.39 - 

Waste bituminous coal 572 0.03 - 1.18 0.46 2.47 - 1

Waste subbituminous coal 53 0.07 - 0.35 0.12 5.81 - 

Petroleum coke 1,150 0.0009 - 0.5 0.05 0.06 - 

Tire-derived fuel 149 0.01 - 0.33 0.056 0.60 - 

2-25


(a) Bituminous coal imported from South America and burned at 10 power plants.


(b) Subbituminous coal imported from Indonesia and burned at three power plants in Hawaii and Florida.

2.8 References 

1.	 American Society for Testing and Materials. 2000 Annual Book of ASTM Standards. West 

Conshohocken, PA. December 2000. 

2.	 Electric Power Research Institute. Evaluation of Methods for Analysis of Mercury and 

Chlorine in Coal. EPRI Report 1000287, Palo Alto, CA. September 2000. 

3. Wood, G. H., Jr., T.M. Kehn, M.D. Carter, and W.C. Culbertson. Coal Resource 

Classification System of the U.S. Geological Survey. U.S. Geological Survey Circular 891, 

1983. Available at: < http://energy.er.usgs.gov/products/papers/C891/index.htm >. 

4.	 U.S. Department of Energy, Energy Information Administration. U.S. Coal Reserves: 1997 

Update. DOE/EIA-0529(97). Office of Coal, Nuclear, Electric and Alternate Fuels, Office of 

Integrated Analysis and Forecasting, Washington, DC. February 1999. Available at: 

< http://www.eia.doe.gov/cneaf/coal/reserves/front-1.html >. 

5.	 J. Tully. Coal Resource Regions of the Conterminous United States. U.S. Geological Survey 

Open-File Report 96-279. July 6, 1996. Available at: 

< http://energy.er.usgs.gov/products/openfile/OF96-279/ >. 

6.	 Bragg, L.J., J.K. Oman, S.J. Tewalt, C.J. Oman, N.H. Rega, P.M. Washington, and R.B. 

Finkelman. U.S. Geological Survey Coal Quality (COALQUAL) Database: Version 2.0. U.S. 

Geological Survey Open-File Report 97-134. June 15, 2001. Available at: 

< http://energy.er.usgs.gov/products/databases/CoalQual/index.htm >. 

7.	 Toole-O’Neil, B., S.J. Tewalt, R.B. Finkleman, and R. Akers. “Mercury Concentration in 

Coal--Unraveling the Puzzle.” Fuel, 78, 47-54 (1999). 

8. Keating, M.H., K.R. Mahaffey, R. Schoeny, G.E. Rice, O.R. Bullock, R.B. Ambrose, Jr., 

J. Swartout, and J.W. Nichols. Mercury Study Report to Congress, Volume I I. EPA-452/R97-004b. Office of Air Quality Planning and Standards and Office of Research and 

Development, Research Triangle Park, NC. December 1997. Available at: 

< http://www.epa.gov/airprogm/oar/mercury.html >. 

9.	 McDermott Technology, Inc.. Mercury Emission Results--Coal Content, Emissions and 

Control. Alliance, OH. Available at: 

< 

http://www.mtiresearch.com/aecdp/mercury.html#Coal%20Composition%20and%20Coal%2 

0Cleaning >(accessed July 2001). 

2-26

10.	 U.S. Environmental Protection Agency. Database of information collected in the Electric 

Utility Steam Generating Unit Mercury Emissions Information Collection Effort. OMB 

Control No. 2060-0396. Office of Air Quality Planning and Standards. Research Triangle 

Park, NC. April 2001. Available at: 

< http://www.epa.gov/ttn/atw/combust/utiltox/utoxpg.html >. 

11.	 Singer, J.G. (Ed.). Combustion Fossil Power. Fourth Edition. Combustion Engineering, 

Inc., Windsor, CT. 1991. 

12. French, C.L., W.H. Maxwell, W.D. Peters, G.E. Rice, O.R. Bullock, A.B Vasu, R. Hetes, 

A. Colli, C. Nelson, and B.F. Lyons. Study of Hazardous Air Pollutant Emissions from 

Electric Utility Steam Generating Units -- Final Report to Congress, Volume 1. EPA-453/R98-004a. Office of Air Quality Planning and Standards, Research Triangle Park, NC. 

February 1998. Available at: < http://www.epa.gov/ttn/atw/combust/utiltox/utoxpg.html >. 

13. Cargill, P., G. DeJonghe, T. Howsley, B. Lawson, L. Leighton, and M. Woodward. Pinon 

Pine IGCC Project: Final Technical Report to the Department of Energy. DOE Award No. 

DE-FC21-92MC29309, Sierra Pacific Resources, Sparks, NV, January 2001. Available at: 

< http://www.lanl.gov/projects/cctc/resources/pdfs/pinon/PinonFinalReport022201.pdf >. 

14. Baker, S.S. EPRI Mercury in Coal Study: A Summary Report for Utilities That Submitted 

Samples Update. Prepared for EPRI Utility Air Regulatory Group by Systems Applications 

International Corporation, San Diego, CA. June 1994. pp. D-1 to D-4. 

2-27

Chapter 3


Criteria Air Pollutant Emission Controls for


Coal-fired Electric Utility Boilers


3.1 Introduction 

The EPA uses "criteria pollutants" as indicators of ambient air quality. For each criteria 

air pollutant, the EPA has established maximum concentrations for specific exposure periods 

above which adverse effects on human health may occur. Under authority of the CAA, these 

threshold concentrations for the criteria air pollutants are codified as the national ambient air 

quality standards (NAAQS). The EPA has set NAAQS for six criteria air pollutants: carbon 

monoxide (CO), lead (Pb), nitrogen dioxide (NO2), ozone (O3), particulate matter (PM), and 

sulfur dioxide (SO2). 

Estimates of national emissions for criteria air pollutants prepared by the EPA show that 

electric utility power plants that burn coal are significant emission sources of SO2, nitrogen 

oxides (NOx), and PM.1 Electric utility power plants are the Nation’s largest source of SO2 

emissions, contributing approximately 68 percent of the estimated total national SO2 emissions in 

1998 (most recent year for which national estimates are available). Over 90 percent of these SO2 

emissions are coal-fired electric utility boilers. Electric utilities contributed 25 percent of total 

national NOx emissions in 1998. Again coal combustion is the predominant source of NOx 

emissions from the electric utilities (almost 90 percent of the estimated NOx emissions). Coalfired electric utility power plants also are one of the largest industrial sources of PM emissions. 

In general, the high combustion efficiencies achieved by coal-fired electric utility boilers result in 

low emissions of CO and volatile organic compounds (a precursor for the photochemical 

formation of ozone in the atmosphere). Lead is listed as a HAP in addition to being listed as a 

criteria air pollutant. Lead emissions from electric utility boilers were evaluated as part of EPA’s 

report to Congress on HAP emissions from electric utility power plants (discussed in Section 

1.4.1). 2 The EPA found that electric utility boilers contribute a very small percentage of the 

nationwide Pb emissions. 

All coal-fired electric utility power plants in the United States use control devices to 

reduce PM emissions. Many coal-fired electric utility boilers also are required to use controls for 

SO2 and NOx emissions depending on site-specific factors such as the properties of the coal 

burned, when the power plant was built, and the area where the power plant is located. As 

discussed in Chapter 6, certain control technologies used to reduce criteria air pollutant 

3-1

emissions from coal-fired electric utility boilers also remove some of the mercury (Hg) from the 

flue gas. In addition, the existing control configuration used for a given coal-fired electric utility 

boiler to meet criteria air pollutant emissions standards directly can affect the applicability, 

performance, and costs of retrofitting additional Hg controls to the unit. 

The purpose of this chapter is to present a summary review of the different control 

technologies currently used by coal-fired electric utility boilers to meet the applicable criteria air 

pollutant emissions standards. The nationwide distribution of control configurations used at 

coal-fired electric utility power plants to comply with these standards is presented using 

information from the EPA ICR database. The impact or influence of these control configurations 

on control of Hg emissions is discussed in the Chapter 6. 

3.2 Criteria Air Pollutants of Concern from Coal Combustion 

3.2.1 Particulate Matter3,4 

Dust, dirt, soot, smoke, and liquid droplets are directly emitted into the air from 

anthropogenic sources as well as natural sources such as forest fires and windblown dust. This 

type of PM sometimes is called “primary particulate matter.” In addition, gaseous air pollutants 

(e.g., sulfur dioxide, nitrogen oxides, and volatile organic compounds) are considered to be PM 

precursors causing “secondary particulate matter” through complex transformations that occur in 

the ambient environment. Human exposure to concentrations of PM at various levels results in 

effects on breathing and respiratory symptoms, aggravation of existing respiratory and 

cardiovascular disease, alterations in the body's defense systems against foreign materials, 

damage to lung tissue, carcinogenesis, and premature death. The people most sensitive to the 

effects of PM include individuals with chronic obstructive pulmonary or cardiovascular disease 

or influenza, asthmatics, the elderly, and children. Particulate matter also contributes to visibility 

impairment in the United States. 

Primary PM emissions from coal-fired electric utility boilers consist primarily of fly ash. 

Ash is the unburned carbon char and the mineral portion of combusted coal. The amount of ash 

in the coal, which ultimately exits the boiler unit as fly ash, is a complex function of the coal 

properties, furnace-firing configuration, and boiler operation. For the dry-bottom, pulverizedcoal-fired boilers, approximately 80 percent of the total ash in the as-fired coal will exit the boiler 

as fly ash. Wet-bottom, pulverized-coal-fired boilers emit significantly less fly ash: on the order 

of 50 percent of the total ash exits the boiler as fly ash. In a cyclone furnace boiler, most of the 

ash is retained as liquid slag; thus, the quantity of fly ash exiting the boiler is typically 20 to 30 

percent of the total ash. However, the high operating temperatures unique to these designs may 

also promote ash vaporization and larger fractions of submicron fly ash compared to dry bottom 

designs. Fluidized-bed combustors emit high levels of fly ash since the coal is fired in 

suspension and the ash is present in dry form. Spreader-stoker-fired boilers can also emit high 

levels of fly ash. However, overfeed and underfeed stokers emit less fly ash than spreader 

stokers, since combustion takes place in a relatively quiescent fuel bed. 

3-2

In addition to the fly ash, PM emissions from a coal-fired electric utility power plant 

result from reactions of the SO2 and NOx compounds as well as unburned carbon particles carried 

in the flue gas from the boiler. The SO2 and NOx compounds are initially in the vapor phase 

following coal combustion in the furnace chamber but can partially chemically transform in the 

stack, or near plume, to form fine PM in the form of nitrates, sulfur trioxide (SO3), and sulfates. 

Firing configuration and boiler operation can affect the fraction of carbon (from unburned coal) 

contained in the fly ash. In general, the high combustion efficiencies achieved by pulverizedcoal-fired boilers and cyclone-fired boilers result in relatively small amounts of unburned carbon 

particles in the exiting combustion gases. Those pulverized-coal-fired electric utility boilers that 

use special burners for NOx control (discussed in Section 3.7) tend to burn coal less completely; 

consequently, these furnaces tend to emit a higher fraction of unburned carbon in the combustion 

gases exiting the furnace. 

Another potential source of PM in the flue gas from a coal-fired electric utility boiler is 

the use of a dry sorbent-based control technology. Solid sorbent particles are injected into the 

combustion gases to react with the air pollutants and then recaptured by a downstream control 

device. Sorbent particles that escape capture by the control device are emitted as PM to the 

atmosphere. Control technologies using sorbent injection are discussed in Chapter 7. 

3.2.2 Sulfur Dioxide 3,4 

Exposure of people to SO2 concentrations above threshold levels affects their breathing 

and may aggravate existing respiratory and cardiovascular disease. Sensitive populations include 

asthmatics, individuals with bronchitis or emphysema, children, and the elderly. Sulfur dioxide 

is also a primary contributor to acid deposition, or acid rain, which causes acidification of lakes 

and streams and can damage trees, crops, historic buildings, and statues. In addition, SOx 

compounds in the air contribute to visibility impairment. In the United States, SO2 is primarily 

emitted from the combustion of fossil fuels and by metallurgical processes. 

Coal deposits contain sulfur in amounts ranging from trace quantities to as high as 

eight percent or more. Most of this sulfur is present as either pyritic sulfur (sulfur combined with 

iron in the form of a mineral that occurs in the coal deposit) or organic sulfur (sulfur combined 

directly in the coal structure). During combustion, sulfur compounds in coal are oxidized to 

gaseous SO2 or SO3. When firing bituminous coal, almost all of the sulfur present in coal will be 

emitted as gaseous sulfur oxides (on average 98 percent). The more alkaline nature of ash in 

some subbituminous coals causes a portion of the sulfur in the coal to react to form various 

sulfate salts; these salts are emitted as fly ash or retained in the boiler bottom ash. Generally, the 

percentage of sulfur in the as-fired coal that is converted to sulfur oxides during combustion does 

not vary with the utility boiler design or operation. 

3.2.3 Nitrogen Oxides 4, 5 

Nitrogen dioxide (NO2) is a highly reactive gas. The major mechanism for the formation 

of NO2 in the atmosphere is the oxidation of nitric oxide (NO) when exposed to solar radiation. 

3-3

These two chemical species are collectively referred to as nitrogen oxides (NOx). Exposure of 

people to NO2 can irritate the lungs, cause bronchitis and pneumonia, and lower resistance to 

respiratory infections. Nitrogen oxides are an important precursor together with volatile organic 

compounds in the photochemical formation of ozone in the atmosphere. Ozone is a criteria 

pollutant and the major component of smog. Nitrogen dioxide is also a primary contributor to 

acid rain. The major NOx emissions sources are transportation vehicles and stationary 

combustion units. 

Both NO and NO2 are formed during coal combustion by oxidation of molecular nitrogen 

that is present in the combustion air or nitrogen compounds contained in the coal. Overall, total 

NOx formed during combustion is composed predominantly of NO mixed with small quantities 

of NO2 (typically less than 10 percent of the total NOx formed). However, once NO formed 

during coal combustion is emitted to the atmosphere, the NO is oxidized to NO2. 

The NOx formed during coal combustion by oxidation of molecular nitrogen (N2) in the 

combustion air is referred to as “thermal NOx.” The oxidation reactions converting N2 to NO and 

NO2 become very rapid once gas temperatures rise above 1,700 °C (3,100 °F). Formation of 

thermal NOx in a coal-fired electric utility boiler is dependent on two conditions occurring 

simultaneously in the combustion zone: high temperature and an excess of combustion air. A 

boiler design feature or operating practice that increases the gas temperature above 1,700 °C, the 

gas residence time at these temperatures, and the quantity of excess combustion air will affect 

thermal NOx formation. The formation of NOx by oxidation of nitrogen compounds contained in 

the coal is referred to as “fuel NOx.” The nitrogen content in most coals ranges from 

approximately 0.5 to 2 percent. The amount of nitrogen available in the coal is relatively small 

compared with the amount of nitrogen available in the combustion air. However, depending on 

the combustion conditions, significant quantities of fuel NOx can be formed during coal 

combustion. 

3.3 Existing Control Strategies Used for Coal-fired Electric Utility Boilers 

Electric utilities must comply with applicable Federal standards and programs that 

specifically regulate criteria air emissions from coal-fired electric utility boilers. These 

regulations and programs include New Source Performance Standards (NSPS), the CAA Title IV 

Acid Rain Program, and the CAA Title V Operating Permits Program. The EPA has delegated 

authority to individual state and local agencies for implementing many of these regulatory 

requirements. In addition, individual states have established their own standards and 

requirements for those power plants that operate within their jurisdictions. Electric utility 

companies use one or a combination of the following three control strategies to comply with the 

specific set of requirements applicable to a given coal-fired boiler. 

Pre-combustion Controls. Control measures in which fuel substitutions are made or fuel 

pre-processing is performed to reduce pollutant formation in the combustion unit. 

3-4

Combustion Controls. Control measures in which operating and equipment 

modifications are made to reduce the amount of pollutants formed during the combustion 

process; or in which a material is introduced into the combustion unit along with the fuel 

to capture the pollutants formed before the combustion gases exit the unit. 

Post-combustion Controls: Control measures in which one or more air pollution control 

devices are used at a point downstream of the furnace combustion zone to remove the 

pollutants from the post-combustion gases. 

Table 3-1 shows the distribution of emissions control strategies for PM, SO2, and NOx 

used for coal-fired electric utility boilers in 1999 as reported in the Part II EPA ICR data.6 All 

coal-fired electric utility boilers in the United States are controlled for PM emissions by using 

some type of post-combustion controls. These particulate emission control types are discussed in 

Section 3.4. Approximately two-thirds of the total coal-fired electric utility boilers use add-on 

controls for SO2 emissions. Most of these controlled units use either a pre-combustion or a postcombustion control strategy for SO2 emissions. The methods used for controlling SO2 emissions 

from coal-fired electric utility boilers are discussed in Section 3.5. Although approximately twothirds of the coal-fired electric utility boilers are controlled for NOx emissions, these units are not 

necessarily the same units controlled for SO2 emissions. The predominant strategy for 

controlling NOx emissions is to use combustion controls. Section 3.6 discusses the application of 

NOx emission controls to coal-fired electric utility boilers. 

3.4 Particulate Matter Emission Controls 

Four types of control devices are used to collect PM emissions from coal-fired electric 

utility boilers: electrostatic precipitators, fabric filters, mechanical collectors, and particle 

scrubbers. Table 3-2 presents the 1999 nationwide distribution of PM controls on coal-fired 

electric utility boilers by total number of units and by percentage of nationwide electricity 

generating capacity. Electrostatic precipitators are the predominant control type used on coalfired electric utility boilers both in terms of number of units (84 percent) and total generating 

capacity (87 percent). The second most common control device type used is a fabric filter. 

Fabric filters are used on about 14 percent of the coal-fired electric utility boilers. Particle 

scrubbers are used on approximately three percent of the boilers. The least used control device 

type is a mechanical collector. Less than one percent of the coal-fired electric utility boilers use 

this type of control device as the sole PM control. Other boilers equipped with a mechanical 

collector use this control device in combination with one of the other PM control device types. 

3.4.1 Electrostatic Precipitators 4,7 

Electrostatic precipitator (ESP) control devices have been used to control PM emissions 

for over 80 years. These devices can be designed to achieve high PM collection efficiencies 

(greater than 99 percent), but at the cost of increased unit size. An ESP operates by imparting an 

electrical charge to incoming particles, and then attracting the particles to oppositely charged 

3-5

Table 3-1. Criteria air pollutant emission control strategies as applied to 

coal-fired electric utility boilers in the United States for the year 1999 as reported 

in the Part II EPA ICR data (source: Reference 6). 

Percentage of Coal-fired Electric Utility Boilers Using Control Strategy 

as Reported in Phase II EPA ICR Data a,b 

Criteria 

Air Pollutant 

Meet Applicable 

Standards 

Without 

Additional 

Controls 

Pre-combustion 

Controls 

Combustion 

Controls 

Post-combustion 

Controls 

Particulate 

matter 0 % 0 % 0 % 100 % 

Sulfur 

dioxide 37 % 40 % 3 % 20 % 

Nitrogen 

oxides 40 % 0 % 57 % 3 % 

(a) Approximately 1.5 % of the boilers use a combination of pre-combustion and post-combustion SO2 controls. 

(b) Approximately 1% of the boilers using post-combustion NO controls also use some type of combustion x 

controls. 

3-6

Table 3-2. Nationwide distribution of existing PM emission controls used for 

coal-fired electric utility boilers for the year 1999 as reported in the Part II EPA 

ICR data (source: Reference 6). 

Phase II EPA ICR Data 

PM 

Control Type 

Abbreviation 

Code 

Number 

of Boilers 

Percent of 

Nationwide 

Total Number 

of Units 

Percent of 

Nationwide 

Electricity 

Generating 

Capacity 

Electrostatic precipitator 

(Cold-side) CS- ESP 822 (a) 72.1 % 74.7 % 

Electrostatic precipitator 

(Hot-side) HS-ESP 122 10.8 % 11.3 % 

Fabric filter FF 155 (b) 13.6 % 9.4 % 

Particle scrubber PS 23 (c) 2.0% 3.0 % 

Mechanical collector (d) MC 5 0.4 % 0.2 % 

Multiple control device 

combinations (e) 13 1.1 % 1.4 % 

Nationwide Total 1,140 (f) 100 % 100 % 

(a) Includes 10 boilers with cold-side ESP in combination with upstream mechanical collector.


(b) Includes eight boilers with baghouse in combination with upstream mechanical collector.


(c) Includes two boilers with particle scrubber in combination with upstream mechanical collector.


(d) Boilers using mechanical collector as only PM control device.


(e) Boilers using a combination of two or more different control device types other than mechanical


collectors. Includes two boilers that use a hot-side ESP in series with a cold-side ESP. 

(f) Does not include the three IGCC units. 

3-7

metal plates for collection. Periodically, the particles collected on the plates are dislodged in 

sheets or agglomerates (by rapping the plates) and fall into a collection hopper. The dust 

collected in the ESP hopper is a solid waste that must be disposed of. 

The effectiveness of particle capture in an ESP depends largely on the electrical resistivity 

of the particles being collected. An optimum value exists for a given ash. Above and below this 

value, particles become less effectively charged and collected. Table 3-3 presents the PM 

collection efficiency of an ESP compared with the other control device types. Coal that contains 

a moderate to high amount of sulfur (more than approximately three percent) produces an easily 

collected fly ash. Low-sulfur coal produces a high-resistivity fly ash that is more difficult to 

collect. Resistivity of the fly ash can be changed by operating the boiler at a different 

temperature or by conditioning the particles upstream of the ESP with sulfur trioxide, sulfuric 

acid, water, sodium, or ammonia. In addition, collection efficiency is not uniform for all particle 

sizes. For coal fly ash, particles larger than about 1 to 8 μm and smaller than about 0.3 μm (as 

opposed to total PM) are typically collected with efficiencies from 95 to 99.9 percent. Particles 

near the 0.3 μm size are in a poor charging region that reduces collection efficiency to 80 to 95 

percent. 

An ESP can be used at one of two locations in a coal-fired electric utility boiler system. 

For many years, every ESP was installed downstream of the air heater where the temperature of 

the flue gas is between 130 and 180 °C (270 and 350 °F). An ESP installed at this location is 

referred is as a "cold-side" ESP. However, to meet SO2 emission requirements, many electric 

utilities switched to burning low-sulfur coal (discussed in the Section 3.5.1). These coals have 

higher electrical ash resistivities, making the fly ash more difficult to capture downstream of the 

air heater. Therefore, to take advantage of the lower fly-ash resistivities at higher temperatures, 

some ESPs are installed upstream of the air heater, where the temperature of the flue gas is in the 

range of 315 to 400 °C (600 to 750 °F). An ESP installed upstream of the air heater is referred to 

as a "hot-side" ESP. 

3.4.2 Fabric Filters4,8 

Fabric filters (FF) have been used for fly ash control from coal-fired electric utility boilers 

for about 30 years. This type of control device collects fly ash in the combustion gas stream by 

passing the gases through a porous fabric material. The buildup of solid particles on the fabric 

surface forms a thin, porous layer of solids or a filter, which further acts as a filtration medium. 

Gases pass through this cake/fabric filter, but the fly ash is trapped on the cake surface. The 

fabric material used is typically fabricated in the shape of long, cylindrical bags. Hence, fabric 

filters also are frequently referred to as "baghouses." 

Gas flow through a FF becomes excessively restricted if the filter cake on the bags 

becomes too thick. Therefore, the dust collected on the bags must be removed periodically. The 

type of mechanism used to remove the filter cake classifies FF design types. Depending on the 

FF design type, the dust particles will be collected either on the inside or outside of the bag. For 

designs in which the dust is collected on the inside of the bags, the dust is removed by either 

3-8

Table 3-3. Comparison of PM collection efficiencies for different PM control 

device types (source: Reference 4) 

Representative PM 

PM Mass Collection Efficiency Range

Control Type 

Total 

PM 

PM 

less than 0.3 μm 

Electrostatic precipitator 

(Cold-side) 99 to 99.7 % 80 to 95 % 

Electrostatic precipitator 

(Hot-side) 99 to 99.7 % 80 to 95 % 

Fabric filter 99 to 99.9 % 99 to 99.8% 

Particle scrubber 95 to 99 % 30 to 85 % 

Mechanical collector 70 to 90 % 0 to 15 % 

3-9

mechanically shaking the bag (called a "shaker type" FF) or by blowing air through the bag from 

the opposite side (called a "reverse-air" FF). An alternate design mounts the bags over internal 

frame structures, called "cages" to allow collection of the dust on the outside of the bags. A 

pulsed jet of compressed air is used to cause a sudden stretching then contraction of the bag 

fabric dislodging the filter cake from the bag. This design is referred to as a "pulse-jet" FF. The 

dislodged dust particles fall into a hopper at the bottom of the baghouse. The dust collected in 

the hopper is a solid waste that must be disposed of. 

An FF must be designed and operated carefully to ensure that the bags inside the collector 

are not damaged or destroyed by adverse operating conditions. The fabric material must be 

compatible with the gas stream temperatures and chemical composition. Because of the 

temperature limitations of the available bag fabrics, location of an FF for use in a coal-fired 

electric utility boiler is restricted to downstream of the air heater. In general, fabric filtration is 

the best commercially available PM control technology for high-efficiency collection of small 

particles (see Table 3-3). 

Electrostatic stimulation of fabric filtration (ESFF) involves a modified fabric filter that 

uses electrostatic charging of incoming dust particles to increase collection efficiency and reduce 

pressure drop compared to fabric filters without charging. Filter bags are specially made to 

include wires or conductive threads, which produce an electrical field parallel to the fabric 

surface. Conductors can also be placed as a single wire in the center of the bag. When the bags 

are mounted in the baghouse, the conductors are attached to a wiring harness that supplies 

electricity. As particles enter the field and are charged, they form a porous mass or cake of 

agglomerates at the fabric surface. Greater porosity of the cake reduces pressure drop, while the 

agglomeration increases efficiency of small particle collection. Cleaning is required less 

frequently, resulting in longer bag life. For felted or nonwoven bags, the field promotes 

collection on the outer surface of the fabric, which also promotes longer bag life. Filtration 

velocity can be increased so that less fabric area is required in the baghouse. The amount of 

reduction is based on an economic balance among desired performance, capital cost, and 

operating costs. A number of variations exist on the ESFF idea of combining particle charging 

with fabric filtration. 

The University of North Dakota, Energy and Environmental Research Center 

(UND/EERC) has developed another type of combined control device called the Advanced 

Hybrid Collector (AHC).9 A charging (and collection) section can also be placed ahead of the 

bags in a fabric filter. This approach is used in the AHC along with the use of membrane fabrics 

(woven or felted fabrics having a membrane laminated to the filtration surface of the fabric). 

The membrane is typically polytetrafluoroethylene (PTFE). With about 90 percent of the mass of 

particles collected in the electrostatic charging and collection section of the AHC, the load on the 

fabric filter part of the system is much reduced. With a membrane fabric for the bags, it is likely 

that filtration velocity can be increased significantly. 

3-10

3.4.3 Particle Scrubbers4 

Particle scrubbers operate by shattering streams of water into small droplets that collide 

with and trap solid particles contained in the flue gas or by forcing the gases into intimate contact 

with water films. The particle-laden droplets or water films coalesce and are collected in a sump 

at the bottom of the scrubber. The three basic types of particle scrubbers are venturi scrubbers, 

preformed spray scrubbers, and moving-bed scrubbers. Venturi scrubbers are the type most 

commonly used for coal-fired electric utility boilers. This scrubber design transports the particleladen flue gas through a constriction where violent mixing takes place. Water is introduced 

either at or upstream of the constriction. Preformed spray scrubbers are usually vertical cylinders 

with flue gas passing upward through droplets sprayed from nozzles near the top of the unit. 

Moving-bed scrubbers have an upper chamber in which a bed of low-density spheres (often 

plastic) is irrigated by streams of water from above. Gas passing upward through the bed agitates 

the wetted spheres, which continually expose fresh liquid surfaces for particle transfer. 

Regardless of the scrubber design, all particle scrubber systems generate wastewaters from the 

scrubber blowdown that must be treated and discharged. 

Particle scrubbers are more sensitive to particle size distribution in the flue gas than either 

an ESP or an FF. In general, particle scrubbers are not as effective as these other control devices 

at collecting small particles (see Table 3-3). Also, while a venturi particle scrubber will have a 

lower initial cost for a given boiler unit application than either an ESP or an FF, the high pressure 

drop required for the scrubber to achieve a high collection efficiency results in high operating 

costs. These factors, in large part, account for the low use of particle scrubbers at coal-fired 

utilities. 

3.4.4 Mechanical Collectors4 

Mechanical collectors are the oldest, simplest, and least efficient of the four types of PM 

control devices. The collectors used for utility boilers are generally in the form of groups of 

cylinders with conical bottoms (multicyclones). Flue gas entering the cylinder tangentially to the 

wall is imparted with a circular motion around the cylinder’s axis. Particles in the gas stream are 

forced toward the wall by centrifugal force, then downward through a discharge at the bottom of 

the cone. Collection efficiency for a typical multicyclone can be about 70 to 75 percent for 

10-μm particles, but can drop to less than 20 percent for smaller 1-μm particles. Mechanical 

collectors can be efficient for relatively large particles because their settling velocity is high 

compared to fine particles. In a cyclone, larger particles are forced through the gas stream 

towards the outer wall because of their mass and inertia, while small particles have insufficient 

mass to be much affected. Electrically charging particles tends to agglomerate them, especially 

small particles, with the resulting larger agglomerates having increased mass over the individual 

small particles. In charged mechanical collectors, a charging section is placed ahead of a 

mechanical collector, and collection efficiency for smaller particles is significantly increased. 

3-11

3.5 SO2 Emission Controls 

Sulfur dioxide emissions from most coal-fired electric utility boilers are controlled using 

either of two basic approaches. The first approach is to use pre-combustion measures, namely, 

the firing coal that contains lower amounts of sulfur. The low-sulfur coal may be naturally 

occurring or the result of coal cleaning. The other approach is to remove the sulfur compounds 

from the flue gas before the gas is discharged to the atmosphere. These post-combustion 

processes are collectively called “flue gas desulfurization” or “FGD” systems. All FGD systems 

can be further classified as wet or dry flue gas scrubbing systems. A third control approach 

available for those coal-fired electric utility boilers using a fluidized-bed combustor is to burn the 

coal together with limestone. An FBC can be characterized as a boiler type with inherently lower 

SO2 emissions. In this report, however, combustion of coal in fluidized-bed with limestone is 

also considered to be an SO2 combustion control method. The SO2 control approaches include a 

number of different technology subcategories that are now commercially used in the United 

States, Europe, or Pacific Rim countries. 

Table 3-4 presents the 1999 nationwide distribution of SO2 controls used for coal-fired 

electric utility boilers by total number of units and by percentage of nationwide electricity 

generating capacity. For approximately one-third of the boilers, no SO2 controls were reported in 

the Part II EPA ICR data. The other two-thirds of the units reported using some type of control 

to meet the SO2 emission standards applicable to the unit. Pre-combustion control by burning a 

low-sulfur content coal was reported for approximately 40 percent of the boilers. Postcombustion control devices for SO2 removal are used for approximately 20 percent of the boilers. 

Wet FGD systems are the most commonly used post-combustion control technique. The newer 

technologies of spray dryer systems or dry injection are limited in their application to existing 

units. The remaining 3 percent of the boilers use fluidized-bed combustion with limestone. 

3.5.1 Low-sulfur Coal 

A coal with sufficiently low sulfur content that when burned in the boiler meets the 

applicable SO2 emission standards without the use of additional controls is sometimes referred to 

as “compliance coal.” Coals naturally low in sulfur content may be mined directly from the 

ground. Alternatively, the sulfur content of coal fired in the boiler may be lowered first by 

cleaning the coal or blending coals obtained from several sources. However, burning low-sulfur 

coal may not be a technically feasible or economically practical SO2 control alternative for all 

boilers. In some cases, a coal with the required sulfur content to meet the applicable standard 

may not be available or cannot be fired satisfactorily in a given boiler unit design. Even if such a 

coal is available, use of the low-sulfur coal that must be transported long distances from the mine 

may not be cost-competitive with burning higher sulfur coal supplied by closer mines and using a 

post-combustion control device. 

Various coal cleaning processes may be used to reduce the sulfur content of the coal. A 

significant portion of the pyritic sulfur minerals mixed with the mined coal can usually be 

3-12

Table 3-4. Nationwide distribution of existing SO2 emissions controls used for 

coal-fired electric utility boilers for the year 1999 as reported in the Part II EPA 

ICR data (source: Reference 6). 

Phase II EPA ICR Data 

SO2 Control Type Abbreviation 

Code 

Number 

of Boilers 

Percent of 

Nationwide 

Total Number 

of Units 

Percent of 

Nationwide 

Electricity 

Generating 

Capacity 

Burn low-sulfur coal 

(“compliance coal”) 

LSC 455 39.9 % 38.2 % 

Wet FGD system FGD 173 (a) 15.2 % 23.8 % 

Spray dryer system SDA 52 (b) 4.6% 3.4 % 

Fluidized-bed coal combustion 

with limestone (a) FBC 37 (c) 3.2% 1.1 % 

Dry injection DI 2 0.2 % < 0.1 % 

No controls reported (d) 421 36.9 % 33.5 % 

Nationwide Total 1,140 (e) 100 % 100 % 

(a) Includes one FBC boiler unit using a wet FGD system.


(b) Includes three FBC boilers using spray dryer systems.


(c) FBC boilers using no downstream post-combustion SO2

 controls.


(d) Entry in ICR response indicated none or was left blank.


(e) Does not include the three IGCC units.


3-13

removed by physical gravity separation or surface property (flotation) methods. However, 

physical coal cleaning methods are not effective for removing the organic sulfur bound in coal. 

Another method of reducing the overall sulfur content of the coal burned in a given boiler unit is 

to blend coals with different sulfur contents to meet a desired or target sulfur level. 

3.5.2 Fluidized-bed Combustion with Limestone 

One of the features of FBC boilers is the capability to control SO2 emissions during the 

combustion process. This is accomplished by adding finely crushed limestone to the fluidized 

bed. During combustion, calcination of the limestone (reduction to lime by subjecting to heat) 

occurs simultaneously with the oxidation of sulfur in the coal to form SO2. The SO2, in the 

presence of excess oxygen, reacts with the lime particles to form calcium sulfate. The sulfated 

lime particles are removed with the bottom ash or collected with the fly ash by a downstream PM 

control device. Fresh limestone is continuously fed to the bed to replace the reacted limestone. 

3.5.3 Wet FGD Systems 

The SO2 in flue gas can be removed by reacting the sulfur compounds with a solution of 

water and an alkaline chemical to form insoluble salts that are removed in the scrubber effluent. 

These processes are called “wet FGD systems” in this report. Most wet FGD systems for control 

of SO2 emissions from coal-fired electric utility boilers are based on using either limestone or 

lime as the alkaline source. At some of these facilities, fly ash is mixed with the limestone or 

lime. Several other scrubber system designs (e.g., sodium carbonate, magnesium oxide, dual 

alkali) are also used by a small percentage of the total number of boilers. 

The basic wet limestone scrubbing process is simple and is the type most widely used for 

control of SO2 emissions from coal-fired electric utility boilers. Limestone sorbent is 

inexpensive and generally locally available throughout the United States. In a wet limestone 

scrubber, the flue gas containing SO2 is brought into contact with a limestone/water slurry. The 

SO2 is absorbed into the slurry and reacts with limestone to form an insoluble sludge. The 

sludge, mostly calcium sulfite hemihydrate and gypsum, is disposed of in a pond specifically 

constructed for the purpose or is recovered as a salable byproduct. 

The wet lime scrubber operates in a similar manner to the wet limestone scrubber. In a 

wet lime scrubber, flue gas containing SO2 is contacted with a hydrated lime/water slurry; the 

SO2 is absorbed into the slurry and reacts with hydrated lime to form an insoluble sludge. The 

hydrated lime provides greater alkalinity (higher pH) and reactivity than limestone. However, 

lime-scrubbing processes require appropriate disposal of large quantities of waste sludge. 

The SO2 removal efficiencies of existing wet limestone scrubbers range from 31 to 

97 percent, with an average of 78 percent. The SO2 removal efficiencies of existing wet lime 

scrubbers range from 30 to 95 percent. For both types of wet scrubbers, operating parameters 

affecting SO2 removal efficiency include liquid-to-gas ratio, pH of the scrubbing medium, and 

the ratio of calcium sorbent to SO2. Periodic maintenance is needed because of scaling, erosion, 

3-14

and plugging problems. Recent advancements include the use of additives or design changes to 

promote SO2 absorption or to reduce scaling and precipitation problems. 

3.5.4 Spray Dryer Adsorber 

A spray dryer adsorber (sometimes referred to as wet-dry or semi-dry scrubbers) operates 

by the same principle as wet lime scrubbing, except that the flue gas is contacted with a fine mist 

of lime slurry instead of a bulk liquid (as in wet scrubbing). For the spray dryer absorber process, 

the combustion gas containing SO2 is contacted with fine spray droplets of hydrated lime slurry 

in a spray dryer vessel. This vessel is located downstream of the air heater outlet where the gas 

temperatures are in the range of 120 to 180 °C (250 to 350 °F). The SO2 is absorbed in the slurry 

and reacts with the hydrated lime reagent to form solid calcium sulfite and calcium sulfate as in a 

wet lime scrubber. The water is evaporated by the hot flue gas and forms dry, solid particles 

containing the reacted sulfur. These particles are entrained in the flue gas, along with fly ash, 

and are collected in a PM collection device. Most of the SO2 removal occurs in the spray dryer 

vessel itself, although some additional SO2 capture has also been observed in downstream 

particulate collection devices, especially fabric filters. This process produces dry reaction waste 

products for easy disposal. 

The primary operating parameters affecting SO2 removal are the calcium-reagent-tosulfur stoichiometric ratio and the approach to saturation in the spray dryer. To increase overall 

sorbent use, the solids collected in the spray dryer and the PM collection device may be recycled. 

The SO2 removal efficiencies of existing lime spray dryer systems range from 60 to 95 percent. 

3.5.5 Dry Injection 

For the dry injection process, dry powdered lime (or another suitable sorbent) is directly 

injected into the ductwork upstream of a PM control device. Some systems use spray 

humidification followed by dry injection. This dry process eliminates the slurry production and 

handling equipment required for wet scrubbers and spray dryers, and produces dry reaction waste 

products for easier disposal. The SO2 is adsorbed and reacts with the powdered sorbent. The dry 

solids are entrained in the combustion gas stream, along with fly ash, and then collected by the 

PM control device. The SO2 removal efficiencies of existing dry injection systems range from 

40 to 60 percent. 

3.5.6 Circulating Fluidized-bed Adsorber 

In the circulating fluidized-bed adsorber (CFBA), the flue gas flows upward through a 

bed of sorbent particles to produce a fluid-like condition in the bed. This condition is obtained 

by adjusting gas flow rate sufficiently to support the particles, but not carry them out of the 

system. Characteristics of the bed are high heat and mass transfer, because of high mixing rates, 

and particle-to-gas contact. These conditions allow the CFBA’s bed of sorbent particles to 

remove a sorbate from the gas stream with high effectiveness. In a CFBA, material is withdrawn 

from the bed for treatment (such as desorption) then re-injected into the bed. Currently, CFBAs 

3-15

are used with limestone and ash as sorbents for SO2 control, but they also have the capability to 

remove Hg from the flue gas. The SO2 removal ranges for CFBAs from 80 to 98 percent. 

3.6 NOx Emission Controls 

Control techniques used to reduce NOx formation include combustion and postcombustion control measures. Combustion measures consist of operating and equipment 

modifications that reduce the peak temperature and excess air in the furnace. Post-combustion 

control involves converting the NOx in the flue gas to molecular nitrogen and water using either a 

process that requires a catalyst (selective catalytic reduction) or a process that does not use a 

catalyst (selective noncatalytic reduction). 

Table 3-5 presents the 1999 nationwide distribution of NOx controls used for coal-fired 

electric utility boilers by total number of units and by percentage of nationwide electricity 

generating capacity. Approximately one-third of the boilers do not use additional NOx controls. 

The other two-thirds of the units use additional controls to meet the applicable NOx standards. 

The predominant control NOx strategy is to use one or more combustion control techniques. 

Post-combustion NOx reduction technologies (both catalytic and noncatalytic) accounted for only 

a small percentage of the NOx emission controls used in 1999 (approximately three percent of the 

total units). However, a number of electric utilities are considering the addition of these types of 

controls to their coal-fired boilers to comply with new NOx emission control requirements. 

3.6.1 Combustion Controls 

A variety of combustion control practices can be used including low NOx burners, 

overfire air, off-stoichiometric firing, selective or biased burner firing, reburning, and 

burners-out-of-service. Control of NOX also can be achieved through staged combustion (also 

called air staging). With staged combustion, the primary combustion zone is fired with most of 

the air needed for complete combustion of the coal. The remaining air needed is introduced into 

the products of the partial combustion in a second combustion zone. Air staging lowers the peak 

flame temperature, thereby reducing thermal NOx, and reduces the production of fuel NOx by 

reducing the oxygen available for combination with the fuel nitrogen. Staged combustion may be 

achieved through methods that require modifying equipment or operating conditions so that a 

fuel-rich condition exists near the burners (e.g., using specially designed low-NOx burners, 

selectively removing burners from service, or diverting a portion of the combustion air). In 

cyclone boilers and some other wet bottom designs, combustion occurs with a molten ash layer 

and the combustion gases flow to the main furnace; this design precludes the use of low NOx 

burners and air staging. Low-NOx burners may be used to lower NOx emissions by about 25 to 

55 percent. Use of overfire air (OFA) as a single NOx control technique reduces NOx by 15 to 

50 percent. When OFA is combined with low-NOx burners, reductions of up to 60 percent may 

result. The actual NOx reduction achieved with a given combustion control technique may vary 

from boiler to boiler. 

3-16

Table 3-5. Nationwide distribution of existing NOx emissions controls used for 

coal-fired electric utility boilers for the year 1999 as reported in the Part II EPA 

ICR data (source: Reference 6). 

Phase II EPA ICR Data 

NO x Control Type Abbreviation 

Code Nationwide 

Number 

of 

Boilers 

Nationwide 

Percentage 

of 

Boilers 

Percent of 

Nationwide 

Electricity 

Generating 

Capacity 

Combustion controls -

low-NO x burners CC-LNB 404 35.4 % 43.0 % 

Combustion controls -

low-NO x burners + overfire air CC-LNB/OFA 84 7.4 % 10.4 % 

Combustion controls ­

overfire air CC-OFA 79 6.9 % 10.6 % 

Other combustion controls (a) CC 83 7.3 % 5.6 % 

Selective noncatalytic reduction SNCR 32 2.8 % 0.6 % 

Selective catalytic reduction SCR 6 0.5 % 1.3 % 

No controls reported (b) 452 39.7% 28.5 % 

Nationwide Total 1,140 (c) 100 % 100 % 

(a) Combustion controls other than low-NO burners or overfire air. The controls include burners-out-of service, x 

flue gas recirculation, off-stoichiometric firing, and fluidized-bed combustion. 

(b) Entry in ICR response indicated “none,” “not applicable,” or was left blank. 

(c) Does not include the three IGCC units. 

3-17

 Just as the combustion air to the primary combustion zone can be reduced, part of the 

fuel may be diverted to create a secondary flame with fuel-rich conditions downstream of the 

primary combustion zone. This combustion technique is termed reburning and involves injecting 

10 to 20 percent of the fuel after the primary combustion zone and completing the combustion 

with overfire air. The fuel injected downstream may not necessarily be the same as that used in 

the primary combustion zone. In most applications of reburning, the primary fuel is coal and the 

reburn fuel is natural gas (methane). 

Other ways to reduce NOx formation by reducing peak flame temperature include using 

flue gas recirculation (FGR), reducing boiler load, injecting steam or water into the primary 

combustion zone, and increasing spacing between burners. By using FGR to return part of the 

flue gas to the primary combustion zone, the flame temperature and the concentration of oxygen 

in the primary combustion zone are reduced. 

Temperatures can also be reduced in the primary combustion zone by increasing the space 

between burners for greater heat transfer to heat-absorbing surfaces. Another combustion control 

technique involves reducing the boiler load. In this case, the formation of thermal NOx generally 

decreases directly with decreases in heat release rate; however, reducing the load may cause poor 

air and fuel mixing and increase CO and soot emissions. 

3.6.2 Selective Catalytic Reduction 

The selective catalytic reduction (SCR) process uses a catalyst with ammonia gas (NH3) 

to reduce the NO and NO2 in the flue gas to molecular nitrogen and water. The ammonia gas is 

diluted with air or steam, and this mixture is injected into the flue gas upstream of a metal 

catalyst bed (composed of vanadium, titanium, platinum, or zeolite). In the reactor, the reduction 

reactions occur at the catalyst surface. The SCR catalyst bed reactor is usually located between 

the economizer outlet and air heater inlet, where temperatures range from 230 to 400 °C (450 to 

750 °F). 

3.6.3 Selective Noncatalytic Reduction 

The selective noncatalytic reduction (SNCR) process is based on the same basic 

chemistry of reducing the NO and NO2 in the flue gas to molecular nitrogen and water but does 

not require the use of a catalyst to prompt these reactions. Instead, the reducing agent is injected 

into the flue gas stream at a point where the flue gas temperature is within a very specific 

temperature range. Currently, two SNCR processes are commercially available: the THERMAL 

DeNOx

7

 and the NOxOUT7. The THERMAL DeNOx

7

 uses ammonia gas as the reagent and 

requires the gas be injected where the flue gas temperature is in the range of 870 to 1090 °C 

(1,600 to 2,000 °F). Consequently, the ammonia gas is injected at a location upstream of the 

economizer. However, if the ammonia is injected above 1,090 °C (2,000 oF), the ammonia will 

oxidize and form more NOx. Once the flue gas temperature drops below the optimum 

temperature range, the effectiveness of the process drops significantly. By adding hydrogen gas 

or other chemical enhancers, the reduction reactions can be sustained to temperatures down to 

3-18

approximately 700 °C (1,300 °F). The NOxOUT7

 is a similar process but uses an aqueous urea 

solution as the reagent in place of ammonia. 

Using nitrogen-based reagents requires operators of SNCR systems to closely monitor 

and control the rate of reagent injection. If injection rates are too high, NOx emissions may 

increase, and stack emissions of ammonia in the range of 10 to 50 ppm may also result. A 

portion (usually around 5 percent) of the NO reduction by SNCR systems results from 

transformation of NO to N2O, which is a global warming gas. 

3.7 Emission Control Configurations for Coal-fired Electric Utility Boilers 

Mercury can exist in several forms in the flue gas from a coal-fired electric utility boiler 

(discussed in Chapter 5). The distribution of these Hg forms in the flue gas stream can be altered 

when reagents for post-combustion pollutant control processes are introduced into the flue gas. 

Also, as will be discussed in Chapter 6, some of the existing post-combustion control devices 

already in use at coal-fired electric utility power plants to meet PM and SO2 emission standards 

also control Hg emissions with varying levels of effectiveness. Control measures can be 

implemented that may enhance the capture of Hg by these control devices. Other Hg control 

measures can be implemented in conjunction with control devices already in place at a given 

facility. Therefore, understanding which types of post-combustion control devices how electric 

utilities currently are implementing at their coal-fired power plants is useful when investigating 

potential Hg control measures for these facilities. 

Table 3-6 presents the 1999 nationwide distribution of post-combustion control device 

configurations used for coal-fired electric utility boilers. For approximately 70 percent of the 

boilers, the only control device used downstream of the furnace is an ESP. If the unit is subject 

to SO2 and/or NOx emission limit standards, these units do burn low-sulfur coals to meet the SO2 

emission limit and use some type of NOx combustion controls to meet the NOx emission limit. 

Approximately 25 percent of the boilers use some combination of post-combustion control 

devices. The most common configuration used is an ESP with a downstream wet scrubber for 

SO2 control. Less than 2 percent of the units use a combination of PM, SO2, and NOx postcombustion control devices. 

3-19

Table 3-6. Nationwide distribution of post-combustion emission control 

configurations used for coal-fired electric utility boilers for the year 1999 as 

reported in the Part II EPA ICR data (source: Reference 6). 

Post-combustion 

Control Strategy 

Post-Combustion Emission Control Device Configuration 

Phase II EPA ICR Data 

PM control SO2 control NO x control 

E 

S 

P 

F 

F 

P 

S 

M 

C 

W 

S 

S 

D 

A 

D 

I 

S 

C 

R 

S 

N 

C 

R 

Number 

of boilers 

Percent of 

nationwide 

total number 

Post-combustion 

PM controls 

only 

4 791 69.4% 

4 80 7.0% 

4 4 6 0.5 % 

4 5 0.4 % 

4 4 4 0.4 % 

4 2 0.2 % 

4 2 (a) 0.2 % 

Post-combustion 

PM controls 

and 

SO2 controls 

4 4 133 11.7 % 

4 4 38 3.3% 

4 4 18 1.6 % 

4 4 13 1.1 % 

4 4 4 0.4 % 

4 4 3 0.2 % 

4 4 2 0.2 % 

4 4 4 1 0.1 % 

Post-combustion 

PM controls 

and 

NO x controls 

4 4 12 1.0 % 

4 4 11 0.9 % 

4 4 1 0.1 % 

Post-combustion 

PM controls, 

SO2 controls, 

and 

NO x controls 

4 4 4 6 0.5 % 

4 4 4 4 0.4 % 

4 4 4 2 0.2% 

4 4 4 1 0.1 % 

4 4 4 1 0.1 % 

Total 1,140 (b) 100 % 

(a) Units using hot-side ESP in series with a cold-side ESP. Counted as Amultiple control device combination@ in Table 3-2. 

(b) Does not include the three IGCC units. 

3-20

3.8 References 

1.	 Nizich, S.V., A.A. Pope, and L.M. Driver. National Air Pollutant Emissions Trends, 

1900-1998, U.S. EPA and the States: Working Together for Cleaner Air, EPA-454/R00-002 (NTIS PB2000-108054). Office of Air Quality Planning and Standards, 

Research Triangle Park, NC. March 2000. 

2.	 French, C.L., W.H. Maxwell, W.D. Peters, G.E. Rice, O.R. Bullock, A.B Vasu, R. 

Hetes, A. Colli, C. Nelson, and B.F. Lyons. Study of Hazardous Air Pollutant Emissions 

from Electric Utility Steam Generating Units -- Final Report to Congress, Volume 1. 

EPA-453/R-98-004a. Office of Air Quality Planning and Standards, Research Triangle 

Park, NC. February 1998. Available at: 

< http://www.epa.gov/ttn/atw/combust/utiltox/utoxpg.html >. 

3.	 U.S. Environmental Protection Agency. Air Quality Criteria for Particulate Matter and 

Sulfur Oxides, Volunes 1-3, EPA/600/8-82/029a-c. (NTIS PB84-156777). Office of 

Health and Environmental Assessment, Environmental Criteria and Assessment Office, 

Research Triangle Park, NC. 1982. 

4.	 Buonicore, A.J., and W.T. Davis (eds.). Air Pollution Engineering Manual. Air & 

Waste Management Association. Van Nostrand Reinhold, New York, NY. 1992. 

5.	 U.S. Environmental Protection Agency. Air Quality Criteria for Oxides of Nitrogen, 

Volumes 1-3, EPA/600/8-91/049a-c (NTIS PB92-176361; 95-124525; 95-124517), 

Office of Health and Environment Assessment, Environmental Criteria and Assessment 

Office, Research Triangle Park, NC. 1991. 

6.	 U.S. Environmental Protection Agency. Database of information collected in the 

Electric Utility Steam Generating Unit Mercury Emissions Information Collection 

Effort. OMB Control No. 2060-0396. Office of Air Quality Planning and Standards. 

Research Triangle Park, NC. April 2001. Available at: 

< http://www.epa.gov/ttn/atw/combust/utiltox/utoxpg.html >. 

7.	 Woodward, K. Stationary Source Control Techniques Document for Fine Particulate 

Matter, EPA/425/R-97-001 (NTIS PB99-116493). Office of Air Quality Planning and 

Standards, Research Triangle Park, NC. October 1998. 

8.	 Turner, J.H., and J.D. McKenna. Fabric Filter Baghouses I - Theory, Design, and 

Selection. ETS, Inc., Roanoke, VA. 1989. 

9.	 Center for Air Toxic Metals (CATM). Technical Focus – Advanced Hybrid Particulate 

Collector, Fourth Annual Meeting. Grand Forks, ND. September 16-17, 1997. 

3-21

Chapter 4 

Measurement of Mercury 

4.1 Introduction 

Accurate measurements of the various forms of Hg present in flue gas from a coal-fired 

electric utility boiler are important: to characterize and determine facility and/or fuel-type 

absolute emissions, for understanding the behavior of Hg in combustion processes and 

combustion configurations, and to evaluate the removal efficiency of control technologies for Hg. 

A variety of measurement techniques, both manual and continuous monitoring, are available for 

measuring total Hg and select, speciated forms. It is the latter need and ability that is most 

critical to supporting the understanding of Hg behavior and its control. 

Because of the importance of these measurements, particularly speciated Hg 

measurements, research on Hg measurement techniques and performance is an integral 

component of the overall Hg control research strategy. The science of speciated Hg 

measurements from coal-fired electric utility boilers has only recently been investigated, with the 

majority of research on the subject occurring within the last 5 years. This research has examined 

the development and performance of both manual and continuous emission monitor 

measurements. Much of this work began with examining and understanding measurement 

performance under very controlled and simplistic conditions, primarily through the use of 

blended gases in a laboratory setting. This afforded the ability to investigate specific 

measurement variables and issues individually. Based on this knowledge, experimentation 

expanded to pilot-scale combustion systems where gases/Hg species of interest could be doped 

into the combustion system, and measurement performance characterized. Though still 

simplistic, this approach results in a measurement environment that more closely represents realworld measurement scenarios. Ultimately, investigations moved to pilot-scale coal combustion 

test units, and finally to full-scale, field applications. At each step, the measurement complexity 

increases. The complexities associated with the combustion of different coal types, relative 

amounts of coal combustion emissions (e.g., SOX, NOX, HCl, Cl2, PM), and pollution control 

device availability and configuration all have an impact on the ability to perform quality Hg 

1 measurements. 

The purpose of this chapter is to provide an understanding of the principles, applications, 

and limitations of Hg measurement methodologies, particularly with respect to understanding 

and interpreting the Part III EPA ICR data. This chapter also serves to introduce principles and 

4-1

issues related to Hg CEMs and their use as a valuable research tool. The following sections 

provide a summary of the approaches and state-of-the art of manual and continuous emission 

measurement methods and issues associated with performing Hg measurements from coal-fired 

electric utility boilers. 

4.2 Manual Methods for Hg Measurements 

Manual methods are well established for measuring total Hg emissions from a variety of 

combustion sources. The EPA Method 101A2

 and Method 29 3 were developed to measure total 

Hg emissions (particulate phase and gas phase) from combustion sources such as sewage sludge 

incinerators and municipal waste combustors. These reference methods were developed and 

used to support total Hg regulatory needs. A reference method for speciated Hg measurement 

does not exist, essentially because there are no regulations requiring speciated Hg emissions 

measurements. However, a valid, accepted methodology was needed to characterize the 

emissions from coal-fired electric utility power plants to better assess the contribution from this 

category as well as potential risk. The Ontario-Hydro Method 4 (called the OH Method in this 

report) presently is the method of choice for measuring Hg species in the flue gas from coal-fired 

electric utility plants. This method has been submitted to the American Society for Testing and 

Materials (ASTM) for acceptance as a standard reference method.1 The Hg emission data 

collected for the Part III EPA ICR were measured using the OH Method. 

Generally, all sampling trains consist of the same sampling components: a nozzle and 

probe operated isokinetically for extracting a representative sample from the stack or duct, a filter 

to collect particulate matter, and a liquid solution and/or reagent to capture gas-phase Hg. After 

sampling, the filter and sorption media are prepared and analyzed for Hg in a laboratory. 

Figure 4-1 shows a diagram of the sampling train used for the OH Method. 

Several of the manual methods, including the OH Method, being developed for speciated 

Hg measurements from combustion sources have been adapted/modified from accepted test 

methods for measuring total Hg. Measurement of total Hg is based on the concept that all forms 

of gaseous Hg can be captured with a strong oxidizing solution such as potassium permanganate. 

The speciation is accomplished relying on the solubility and insolubility of the gaseous Hg 

species. To speciate gaseous Hg into the oxidized Hg (Hg2+) and elemental Hg (Hg0

) forms, 

multiple solutions/reagents are used. The Hg2+ form is considered to be readily soluble in 

aqueous solutions, while Hg0 is essentially insoluble.

1 When the aqueous solutions are 

positioned immediately after the filter, the Hg2+ is captured and the Hg0 passes through to the 

oxidizing solution where it is then captured. These solutions are analyzed separately to 

determine the distribution of oxidized and Hg0 within the sampling train. Table 4-1 presents a 

comparison of the different manual test methods, their configuration, and the solutions used that 

have been investigated for measuring speciated Hg. 

The OH Method, along with the other test methods listed in Table 4-1, were thoroughly 

evaluated to determine their appropriateness for performing speciated Hg measurements from 

4-2

Figure 4-1. Diagram of sampling train for Ontario-Hydro Method (source: 

Reference 4). 

4-3

Table 4-1. Summary of selected manual test methods evaluated for measurement of Hg in co

Sampling Train Configuration Impinger Configuration Manual (number of impingers - impinger set solutio

Test 

Method Front-half collection 

(PM and Hgp) 

Back-half collection 

(gaseous Hg) First Set 

Second Set 

Third 

EPA Method 29 glass fiber filter impinger solutions 2 3-H2

O2 1 dry 2 H2SO

EPA Method 101A a glass fiber filter impinger solutions 3 2SO4-KMnO4 none used none 

EPA Method 101B 

(draft) glass fiber filter impinger solutions 2 ater 1 HNO3-H2

O2 2 2SO

Ontario-Hydro Method glass fiber filter impinger solutions 3 l 1 HNO3-H2

O2 3 2SO

Tris-Buffer Method glass fiber filter impinger solutions 2 c 2 2SO4-KMnO4 none 

MESA Method glass wool d sorbent beds 2 l-soda lime 2 iodated carbon none 

HNO

H

deionized w

H

KC

H

tris solution 

H

KC

4-4


a. Test method developed and validated by EPA for measuring Hg emissions from chlor-alkali plants.
b. CVAA = Cold-vapor atomic absorption.
c. Tris solution is tris(hydroxymethyl) aminomethane in a solution of ethylenediaminetetracetic acid in water. 


d. 	

Glass wool is only used to trap particulate matter and prevent its carry-over to the sorbent beds. 

The glass fiber filter in the other t

collect and quantitate particulate matter.


e. 

CVAFS = Cold-vapor atomic fluorescence spectrometry.

coal-fired combustion sources.1 The University of North Dakota, Energy and Environmental 

Research Center (UND/EERC) performed a thorough, parametric evaluation of these methods 

under a variety of laboratory and pilot-scale test conditions, including the combustion of 

multiple, representative coal varieties. A detailed presentation of these tests and their results are 

contained in two comprehensive reports.1,5 

Initial experimental work focused on EPA Method 29. These results indicated that 

Method 29 exhibited speciation measurement biases under some conditions.1

 The testing 

expanded to include the Mercury Speciation Adsorption (MESA) Method, Tris-Buffer Method, 

draft EPA Method 101B, and OH Method.1 Pilot-scale coal combustion experiments were then 

performed in conjunction with the dynamic spiking of Hg0 or mercuric chloride into the duct at 

various locations within the post-combustion facility. Samples by the respective methods were 

collected at sampling locations both upstream and downstream of particulate control systems. 

These tests were used to isolate the most appropriate methods for further, more definitive testing. 

It was during the initial dynamic Hg spiking tests that effects from fly ash on the quality 

of speciated measurements were observed. Speciated Hg measurements using the OH Method 

and Tris-Buffer Method where the gas sampling and dynamic spiking of Hg0 took place at the 

inlet and outlet of the PM control device indicated that significant oxidation of the Hg0 occurred 

as a result of reactivity with the coal fly ash (see Figures 4-2 and 4-3). 

The effects of PM on Hg speciation can be significant, particularly at sampling locations 

upstream of PM control devices. The flue gas upstream of a PM control device contains a high 

concentration of PM (relative to flue gas downstream of a PM control device). When sampling 

takes place upstream of a PM control device, the sampling train filter has the potential to collect 

a high loading of fly ash (due to the high concentration of PM in the flue gas). The speciated Hg 

measurement can be biased in two ways. The fly ash on the filter can adsorb gaseous Hg from 

the flue gas as it passes through the filter. Reactive fly ashes can also oxidize gaseous Hg0 

entering the filter. When adsorption and/or oxidation occur across the filter, they alter the 

distribution of total Hg and/or gaseous Hg measured. For example, if particles on the filter 

adsorb gaseous Hg, the filter will contain a greater amount of Hgp than if no adsorption had taken 

place; in this case, the sampling-train method will overestimate the amount of Hgp in the flue gas 

and underestimate the gaseous Hg, thus, the total distribution of Hg will be altered. 

Alternatively, fly ash on the filter can oxidize gaseous Hg0

 to Hg2+ (without adsorption) 

overestimating the amount of Hg2+ in the flue gas. Thus, the distribution of gaseous Hg will be 

altered. The rates of these transformations are dependent on the properties of the coal and 

resulting fly ash, the amount of fly ash, the temperature, the flue gas composition, and the 

sampling duration. As a result, the magnitude of these biases varies significantly and cannot be 

uniformly assessed. It is for this reason, that ICR measurements performed at the inlet of PM 

control systems possess a large degree of uncertainty. A more detailed discussion of the 

implications of fly ash speciation biases on the ICR data is presented in Chapter 6. 

A final series of pilot-scale tests were conducted to more definitively evaluate the two 

most promising methods identified as a result of the initial dynamic spiking experiments 

4-5

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Method 101A Method Method 

MANUAL TEST METHOD 

Figure 4-2. Comparison of Hg speciation measured by manual test methods from 

UND/EERC pilot-scale evaluation tests firing Blacksville bituminous coal and 

sampling and spiking Hg0

 at FF inlet (source: graph prepared using test data 

presented in Appendix B to Reference 1). 

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Particle-bound Hg as measured by method 

Hg CONCENTRATION ( μg/Nm3 ) 

4-6

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Method 101A Method Method 

MANUAL TEST METHOD 

Figure 4-3. Comparison of gaseous Hg speciation measured by manual test 

methods from UND/EERC pilot-scale evaluation tests firing Blacksville 

bituminous coal and sampling and spiking Hg0 at FF outlet (source: graph 

prepared using test data presented in Appendix B to Reference 1). 

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Hg C

ONCENTR

ATION ( μg/N

m3 ) 

4-7

discussed above.1

 Both Draft EPA Method 101B and the OH Method were selected for formal 

EPA Method 301 validation testing. Method 301 is EPA’s accepted guidance for validation of 

source testing methodologies.6 For these validation tests, all sampling and dynamic spiking of 

Hg0

 and HgCl2 into a flue gas stream were performed at the outlet of the high efficiency fabric 

filter (FF), while burning a blend of Ohio No. 5 and Ohio No. 6 coals.1 Validation testing was 

not performed at the PM control device inlet location. 

A summary of the Method 301 validation results is shown in Table 4-2. The tests 

verified that both the OH Method and the draft EPA Method 101B achieved acceptable 

performance as defined by Method 301.1

 The precision of the OH Method for total gaseous Hg 

was determined to be less than 11 percent relative standard deviation (RSD) for Hg 

concentrations greater than 3 μg/Nm3 and less than 34 percent RSD for Hg concentrations less 

than 3 μg/Nm3

. These values were within the acceptable range, based on the criteria established 

in EPA Method 301 (less than 50 percent RSD). In all cases, the laboratory bias for these tests 

based on a calculated correction factor was not statistically significant, though some oxidation 

(less than 15 percent) of the Hg0 spike was observed even when spiking and sampling was done 

at the outlet of the fabric filter. The draft EPA Method 101B also met Method 301 validation 

requirements, though it did not perform as well as the OH Method.1 As a result, the OH Method 

was selected as the most appropriate method for Hg speciation measurements in coal 

combustion gases.1 

Final approval by the ASTM of the OH Method as an international test procedure is still 

pending as of the date of this report. The OH Method, in its current draft form, is available from 

the EPA Office of Air Quality Planning and Standards (OAQPS) Emission Measurement Center 

(EMC).4 The draft version of the OH Method submitted to ASTM states that the method is 

applicable for sampling elemental, oxidized, and particle-bound Hg at the inlet and outlet of 

emission control devices and is suitable for measuring Hg concentrations ranging from 

approximately 0.5 to 100 μg/Nm3.

4 Measurement sensitivity/detection levels can be extremely 

important where control technology performance is being determined in relatively low Hg coal 

content applications. 

In summary, while several manual methods for Hg speciating measurements exist, the 

OH Method is the most thoroughly examined and accepted of these methods, and has met EPA 

Method 301 validation requirements. Application to air pollution control device inlet locations 

should be considered with caution due to the known catalytic and sorptive effects of certain coal 

fly ash PM. These measurement artifacts do not affect the use of the OH Method for total Hg 

measurements. 

4.3 Continuous Emission Monitors for Hg Measurements 

Continuous emission monitors (CEMs) are preferable for multiple reasons to using 

manual methods for measuring Hg. A CEM is capable of providing a real-time or near-real-time 

response for Hg measurements. A CEM can be used to obtain continuous Hg measurements 

4-8

Table 4-2. Results from EPA Method 301 evaluation tests for the Ontario-Hydro 

Method (sources: References 1 and 4). 

Total Vapor-Phase Hg Oxidized Hg Elemental Hg OntarioHydro 

Method a Mean b 

, 

μg/Nm 3 

Standard 

Deviation 

RSDc 

, 

% 

Mean b 

, 

μg/Nm 3 

Standard 

Deviation 

RSD, 

% 

Mean b , 

μg/Nm 3 

Standard 

Deviation 

RSD, 

% 

Baseline 23.35 2.05 8.79 21.24 2.13 10.02 2.11 0.65 30.69 

Hg0 Spike 

(15.0 μg/Nm 3

) 38.89 2.00 5.13 23.32 2.08 8.94 15.57 1.09 6.97 

HgCl2 Spike 

(19.9 μg/Nm 3

) 42.88 2.67 6.23 40.22 2.87 7.14 2.66 0.89 33.31 

a. The correction factor in all cases was not statistically significant and is not shown. b. For each mean result, there were 12 replicate samples (four quad trains). 

c. RSD = Relative standard deviation. 

4-9

over long periods in time. Conversely, manual methods are capable of only infrequent 

“snapshot” Hg measurements over time. As a result, CEMs are able to distinguish the magnitude 

and duration of short-term emission characteristics as well as perform long-term emission 

measurements to truly characterize a process’s temporal emissions. Again, manual methods are 

not capable of performing these functions. It is for these reasons that Hg CEMs are extremely 

valuable tools supporting the understanding and control of Hg emissions from coal-fired electric 

utility power plants. This section discusses the state-of-the-art of using CEMs for Hg 

measurements and the associated measurement issues. 

In general, Hg CEMs are a relatively new and yet unproven technology. Although CEMs 

that measure total Hg only are used to support regulatory applications in several European 

countries, the use of these CEMs is limited. Several total Hg CEMs are available commercially 

and are primarily of European origin.7, 8 In the United States., Hg CEMs have been limited to 

research applications with respect to coal-fired combustion emissions monitoring. As with the 

manual methods, CEMs capable of Hg speciation measurement are of the most value to 

supporting research on the characterization and control of Hg emissions from coal-fired electric 

utility boilers. The speciating Hg CEMs currently available should be considered prototypes. 

The CEMs being developed for measuring Hg are similar to most other types of CEMs 

used for combustion processes in that the combustion gas sample typically must be extracted 

from the stack and then transferred to the analyzer for detection. However, continuous Hg 

monitoring is complicated by the fact that Hg exists in different forms (i.e., Hg0, Hg2+, and Hgp) 

and that quantitative transport of all these forms is difficult. 

Typically, Hg CEMs measure (i.e., detect) only Hg0. These CEMs measure total Hg 

through the use of a conversion system that converts (reduces) the gaseous non-elemental or Hg2+ 

forms to Hg0 for detection. Mercuric chloride is considered to be the primary oxidized form of 

Hg, though recent research suggests that other oxidized forms of Hg do indeed exist.9,10 

Although particulate-bound Hg can also be reduced to the gaseous elemental form, particulate 

sample delivery issues make this impractical. As a result, for most commercially available 

CEMs, the total Hg measured is in fact total gaseous Hg (TGM). 

The conversion of gaseous, non-Hg0 is commonly accomplished using a liquid reducing 

agent (e.g., stannous chloride). This technique is least preferable, though more established. The 

use of wet chemical reagents is considered to be a limitation to Hg CEM use. The wet chemicals 

typically possess corrosive properties and require frequent replenishment. The spent reagents 

may possess hazardous properties that result in waste disposal concerns. In addition, the 

11 reducing ability of reagents such as stannous chloride can be affected by high levels of SO2. 

In addition to the more established wet chemistry conversion methods, dry conversion 

methods are also available. These techniques use high temperature catalysts or thermal reduction 

units to not only convert non-Hg0

, but also condition the sample for analysis by removing 

selective interferants. This approach does much to minimize the size of the conversion system as 

well as maintenance requirements. However, these systems have not been well characterized for 

4-10

coal combustion gas Hg measurement applications. 

Because the particulate form is difficult to transfer and is also often a measurement 

interferant, the particulate is typically filtered out and Hgp remains unmeasured. This could 

potentially impart a negative bias to the total Hg measurements. This bias could be further 

amplified as certain types of particulate may actually capture gas-phase Hg. This may not be a 

significant issue for sources where Hgp is not present in appreciable quantities, but may be a 

significant issue for high particulate-emitting sources (e.g., sources with minimal PM control) or 

in cases where the Hg measurements are conducted upstream of PM control devices. Therefore, 

the capability of a CEM to measure Hgp is important and should not be ignored. 

Similarly, there are known complications with the quantitative transfer of mercuric 

chloride.9 Mercuric chloride (HgCl2) is water soluble and reactive with many surfaces. Losses 

due to adsorption are the major concern. As a result, recent emphasis has been placed on 

locating the non-Hg0 conversion systems as close as possible to the source so that the elemental 

form is transferred from the source to the detection unit instead of transporting the oxidized 

forms long distances. 

In general, Hg CEMs can be distinguished by their Hg measurement detection principle. 

Detection systems include: cold-vapor atomic absorption spectrometry (CVAAS); cold-vapor 

atomic fluorescence spectrometry (CVAFS); in-situ ultraviolet differential optical absorption 

spectroscopy (UVDOAS); and atomic emission spectrometry (AES).1,7,8,9 

The majority of Hg CEM systems employ CVAAS or CVAFS as the detection technique. 

These detection techniques are susceptible to measurement interferences resulting from the 

presence of common combustion process emissions. Gases such as NOX, SO2, HCl, and Cl2 can 

act as measurement interferants as well as degrade the performance of concentrating devices 

(e.g., gold amalgams). As such, conditioning systems and/or techniques that remove or negate 

the effects of these interfering gases prior to sample delivery to the detector are required. The 

SO2 is a major spectral interferant with most CVAA detection systems. The effects of SO2 are 

commonly negated through the use of a gold trap. The sample gas is directed through a gold 

trap, where the Hg amalgams with the gold surface. Once the trap is loaded, it is heated and 

flushed with a SO2-free carrier gas to the detector. The trapping also serves to improve 

measurement sensitivity by concentrating the sample. A trapping device is required of CVAFS 

systems to achieve optimum sensitivity; not because of the concentrating aspect, but because the 

carrier gas will enable maximum sensitivity. Oxygen and nitrogen have spectral quenching 

effects that suppress measurement sensitivity. Conditioning of the sample gas prior to reaching 

the gold trap is often required. HCl and NOX in combination can poison the gold surface, 

preventing amalgamation with the Hg. Removal of both or either of these constituents is 

required. 

An alternative to the Hg0 measurement approach is AES. With this technique, the Hg is 

ionized by a high-energy source (e.g., plasma) and the emission energy detected. The advantage 

to this technique is that all forms of Hg, including particulate-bound Hg, are capable of being 

4-11

ionized and detected. Although this technology is not quite as developed, another major 

advantage of AES is that the ionization source and detector can be located directly at the source, 

avoiding sample delivery issues. In addition, AES is not as susceptible to spectral interferences 

from common flue gas constituents. 

Speciated Hg measurements are important to characterize combustion process emissions 

and evaluate Hg control strategies. While there are no commercially available CEMs that 

directly measure the various speciated forms of Hg, several total gaseous Hg CEMs, both 

commercial and prototype, have been enhanced to indirectly measure speciated Hg (the elemental 

and oxidized forms) by determining the difference between Hg0 and total gaseous Hg. This 

difference is recognized as the oxidized form. Separate Hg measurements are made before and 

after the conversion step in order to calculate the oxidized form. This indirect speciation method 

is referred to as “speciation by difference.” Based on the current understanding that the oxidized 

species of primary interest is mercuric chloride and that mercuric chloride is the dominant form 

of oxidized Hg present, the “speciation by difference” technique is considered an acceptable 

approach to obtaining speciated Hg measurements. 

A key to performing the speciated Hg measurement is being able to perform reliable Hg0 

measurements. The Hg2+ must be removed without adding to the true amount of Hg0 in the 

sampled gas stream. This is often accomplished using a liquid reagent to remove the watersoluble Hg2+. These reagents also may serve to neutralize the effects of measurement 

interferants. The greatest concern is the reliability of the speciated Hg measurement. 

Measurement artifacts exist that bias the speciation, primarily by over-reporting the level of the 

oxidized species. The largest cause of this bias comes from the reactivity of certain types of PM 

(as discussed in Section 4.2). The PM may possess catalytic properties whereby, at the 

conditions of Hg CEM PM filtering environments, Hg0 can be oxidized across the PM surface. 

This is not an issue from a TGM measurement standpoint (unless transport of oxidized Hg is an 

issue). However, it may have major implications when measuring Hg in gas streams possessing 

high PM loadings. This bias is minimized in low PM loading gas streams, consistent with Hg 

measurements downstream of PM control devices. Another potentially significant source of 

speciated Hg measurement bias takes place in the liquid phase. In combustion gases where Cl2 is 

present, under certain conditions the Cl2 may react in the liquid phase to oxidize Hg0

.

12 There is 

evidence that this problem can be mitigated. 

As stated previously, the current, primary application of Hg CEMs is as a research 

tool/process monitor. Speciating Hg CEMs are integral to the DOE/EPA/EPRI Hg control 

technology development and evaluation research program. These Hg CEMs are used to 

characterize existing Hg emissions and distributions, including control technology performance. 

More importantly, these speciating Hg CEMs are used to better understand and optimize 

potential Hg control technologies so that absolute emissions can be established through OH 

sampling. Ultimately, it is desired to accept the quality and performance of Hg CEMs and 

measurements data so as to replace the reliance on OH measurements. Several pilot-scale and 

field tests have been performed specifically to evaluate and determine the measurement 

performance of both total and speciating Hg CEMs. 

4-12

Several tests have been conducted specifically to evaluate total Hg CEMs as a compliance 

assurance tool. The first such test, sponsored by the EPA Office of Solid Waste (OSW), 

evaluated the performance of three Hg CEMs to measure total Hg emissions from a cement kiln 

that burned hazardous waste as a fuel.13 Measurement performance was evaluated following the 

proposed “Performance Specification 12 -- Specifications and Test Procedures for Total 

Mercury Continuous Monitoring Systems in Stationary Sources” (PS-12).14 At the time, this was 

a relatively new test procedure and had yet to be implemented. In fact, the guidance called for 

Hg0 and HgCl2 gas standards that had yet to be developed and proven. The tests were only 

marginally successful. None of the Hg CEMs tested met the performance test requirements. 

Based on the test results, the EPA/OSW concluded that Hg CEMs should not be considered as a 

compliance tool for hazardous waste combustors.13 In retrospect, the harshness of the cement 

kiln’s exhaust gas stream was concluded as a major cause of the test program’s lack of 

success.8,13 The cement kiln chosen for the EPA/OSW Hg CEM testing was not equipped with 

acid gas controls and had relatively high PM loading, resulting in severe interferences and 

operational difficulties for the CEMs. 

The DOE Mixed Waste Focus Area (MWFA) has sponsored several tests determining the 

measurement performance of a single total Hg CEM under hazardous waste incineration 

conditions.15,16 Measurement performance was also evaluated following PS 12. These tests 

demonstrated not only Hg CEM performance, but also that additional elements of the PS 12 test 

procedures could be implemented. A prototype Hg0 compressed gas standard was used for the 

first time. While these tests have been relatively successful, they are still limited in scope and 

application. 

The EPA’s Environmental Technology Verification (ETV) Program, in collaboration 

with the NRMRL, has completed testing of four commercially available Hg CEMs from three 

vendors using the unique capabilities of NRMRL’s pilot-scale combustion test facility. These 

tests examined the measurement performance of both total and speciated Hg CEMs under two 

distinct and diverse combustion conditions. Coal and chlorinated waste combustion conditions 

were simulated. These verification tests used PS 12 as guidance, but also considered specific 

measurement issues of interest and innovative approaches that better examined these issues. The 

pilot-scale tests were unique in that specific measurement issues were investigated as variables. 

The pilot-scale combustion facility enabled independent control of Hg concentration and species. 

As a result, the total Hg measurement could be challenged by the distribution of oxidized and 

Hg0

. Interference flue gas constituents were also independently examined. The ETV testing 

made use of several new quality assurance and quality control (QA/QC) tools. Newly developed 

Hg0 compressed gas standards were used to determine Hg CEM calibration drift and system bias. 

As a result, not only were Hg CEMs evaluated, but also improved techniques for evaluating Hg 

CEMs were demonstrated. Performance data for the participating Hg CEMs are not yet 

available. 

The UND/EERC has evaluated the performance of Hg CEMs during field tests at eight 

different coal-fired electric utility power plants representing facilities that burn lignite, 

subbituminous coal, or bituminous coal.11,17 A variety of air pollution control devices and 

4-13

configurations were encountered, including ESPs, FFs, wet FGD scrubbers, spray dryer 

absorbers, and venturi scrubbers. For these tests, the Hg CEMs evaluated demonstrated the 

ability to measure total gaseous Hg within +20 percent of the OH Method measurements. The 

field-testing also examined the measurement performance of several Hg CEMs at low stack Hg 

emissions levels. These tests demonstrated a distinct advantage of the AF-based systems over 

the AA-based system (see Figure 4-4). Below concentrations of 5 μg/m3

, the AA-based systems 

exhibited higher signal to noise ratios. At these concentrations, the AF-based systems are a 

better choice. 

The EPA/OAQPS/EMC has recently initiated a study to determine the measurement 

performance of two commercially available total Hg CEMs at a coal-fired electric utility power 

plant. Measurements of performance will be recorded to determine potential monitoring 

applications based on measurement performance achieved. Data from this study, and future 

studies of Hg CEM measurement performance at additional source categories, should aid in the 

future crafting of a performance specification for application of total Hg CEMs to a variety of 

different Hg emission source categories. 

Performance testing of Hg CEMs has focused primarily on total Hg CEMs; total Hg 

CEMs are the most widely available commercially. However, with respect to the development 

and evaluation of Hg control technologies for coal-fired electric utility power plants, the most 

urgent need is for a speciating Hg monitor. As stated previously, the primary use of speciating 

Hg CEMs is as a research tool though application as a process monitor is also appealing. Of 

those speciating Hg CEMs in use, most are commercially available total or Hg0 CEMs modified 

for use as a speciating Hg CEM. Very few speciating Hg CEMs are available commercially. 

The major distinction among speciating Hg CEMs is not the analyzer or detection principle, but 

the approach for managing potential interferants and method for converting oxidized forms of Hg 

to the detectable, elemental form. 

Performance testing of speciating Hg CEMs to support Hg control technology research 

has also been performed under pilot- and field-scale operations and research continues in this 

area. Work performed by the UND/EERC has also focused on the research and development of 

speciating Hg CEMs, particularly the development and evaluation of pretreatment/conversion 

systems that can be used with multiple, commercially available Hg CEMs. The EERC has used 

speciating Hg CEMs to support field measurement activities in conjunction with OH Method 

measurements. Figure 4-5 compares the measurement performance of several speciating Hg 

CEMs to OH Method measurements made during testing at a coal-fired electric utility power 

plant. 

A key to assessing measurement performance and validating measurement data quality is 

the development Quality Assurance/Quality Control (QA/QC) tools such as elemental and 

oxidized Hg gas standards. The tools are needed for instrument calibration, continuing 

calibration or drift checks, and system bias checks. The EPA/ORD has been active in the 

development of both elemental and HgCl2 gas standards. A commercial compressed gas standard 

for Hg0 has been evaluated for stability and accuracy. While the stability of the Hg0 compressed 

4-14

Figure 4-4. Comparison of total Hg results for CEMs at low Hg levels. 

(Reprinted from "State-of-the-Art of Mercury Continuous Emission Monitors for Coal-Fired Systems." 

Conference on Air Quality II Mercury, Trace Elements, and Particulate Matter, McLean, VA, September 

2000, by D. L. Laudal and N. B. French, with permission of the University of North Dakota Energy & 

Environmental Research Center as copyright owner.) 

4-15

Figure 4-5. Comparison of Hg speciation results for CEMs at low Hg levels. 

(Reprinted from "State-of-the-Art of Mercury Continuous Emission Monitors for Coal-Fired Systems." 

Conference on Air Quality II Mercury, Trace Elements, and Particulate Matter, McLean, VA, September 

2000, by D. L. Laudal and N. B. French, with permission of the University of North Dakota Energy & 

Environmental Research Center as copyright owner.) 

4-16

gas standard has been confirmed, techniques for establishing the standard’s true concentration 

have not. As a result, quantitative use of the standard is limited. Similarly, acceptance of a 

HgCl2 standard is valuable: this standard is used to assess Hg conversion system effectiveness as 

well as overall sampling system delivery efficiency and reactivity, parameters not challenged by 

an Hg0 gas standard. This is particularly relevant in measurement applications where oxidized 

Hg may be the predominant Hg form present. Moreover, several Hg CEMs vendors have 

developed QA/QC capabilities to perform their own instrument calibration drift and system bias 

checks from internal Hg0 gas sources. These capabilities are needed for routine daily operational 

performance verification. 

In summary, Hg CEMs are currently the tool of choice for evaluating the performance of 

candidate Hg control technologies. As different control technologies are evaluated, the 

associated measurement issues are encountered and addressed. Measurement issues are primarily 

associated with the oxidized Hg conversion systems as well as particulate bias effects, 

particularly at pollution control device inlet measurement locations. Both wet chemistry and dry 

conversion/conditioning systems are used to support these control technology research programs. 

It is the conversion/conditioning system that requires the most attention during operation of Hg 

CEM systems. It is also this frequent need for attention that limits their application to short 

measurement intervals. As a result, consideration as a compliance assurance tool is hindered. 

Clearly, in order to function as a dedicated process monitor and/or compliance tool, additional 

research is needed to develop and/or evaluate more reliable and less labor intensive Hg 

conversion/sample conditioning systems. These objectives are likely to be furthered as a result 

of control technology demonstration and evaluation activities. 

4.4 Summary, Conclusions, and Recommendations 

Valid and reliable Hg measurements, by either manual methods or using CEMs, are 

critical to the characterization and future reduction of Hg emissions from coal-fired electric 

utility power plants. Although these measurement techniques are tools that support a larger 

research objective, the quality, applicability, and specificity of these measurements directly 

impact the ability to conduct Hg emission control research. Measurement techniques that 

determine both the Hg2+ and Hg0

 gaseous forms of Hg are preferred over those techniques that 

can measure only total gaseous Hg. Conversely, speciated Hg measurement techniques are more 

complex and more susceptible to measurement biases. Although viable measurement techniques 

exist and measurement performance has been demonstrated for certain measurement situations, 

acceptable measurement techniques are not available to meet all measurement needs. Additional 

research and development is still needed to enable quality measurements from all necessary 

measurement environments. 

The OH Method is the only manual method that is currently recognized in the United 

States for speciated Hg measurements in coal combustion gases. The OH Method appears to 

provide valid speciation results at sampling locations downstream of PM control devices in 

4-17

which most of the fly ash has been removed from the gas stream. However, measurements made 

upstream of PM control devices are susceptible to measurement artifacts that bias the 

measurements of the different Hg species causing potential uncertainty in results. However, 

these artifacts do not affect the measurement of total Hg. 

A limited number of both private prototype and commercial Hg CEMs are available for 

the measurement of total gas-phase Hg and to a lesser extent, speciated gas-phase Hg. Because 

of the diversity and severity of associated measurement environments, numerous measurement 

obstacles exist (e.g., PM artifacts, interferences, conversion systems, sample 

conditioning/delivery) that have not been adequately addressed, particularly with respect to 

speciated measurements. While Hg CEMs are used being used as a tool by researchers, these 

devices are not yet suitable for routine Hg monitoring applications at coal-fired electric utility 

power plants. As a research tool, Hg CEMs are suitable for short-term measurement needs. 

However, the technology has not advanced to the extent that acceptable, long-term measurement 

performance has been demonstrated. This must be accomplished for Hg CEMs to be considered 

suitable for any purpose beyond use as a research tool. The primary obstacle is the lack of 

sample conditioning/conversion systems suitable for long-term, minimal attention operation. 

Improved methods for the sampling and analysis are critical to support the development 

of Hg emission control technologies, for use for Hg monitoring and control (process control), and 

for potential use as compliance tools. Specifically, research is needed to: 

1.	 Develop improved sample conditioning/conversion systems (particularly dry, non-wet 

chemical) capable of long-term, minimal maintenance, operation, 

2.	 Develop and demonstrate improved Hg CEM measurement techniques that address 

known and potential measurement obstacles (e.g., PM artifacts, interferences/biases, 

conversion systems, sample conditioning/delivery), 

3.	 Develop accepted QA/QC tools (e.g., elemental and oxidized Hg gas standards) for 

validating instrument performance and data quality, 

4.	 Develop and verify a manual test method suitable for measuring total and speciated 

Hg at sampling locations upstream of PM control devices, 

5.	 Develop and verify a manual test method (e.g., modified OH Method) that can 

simultaneously measure speciated Hg and other trace metals, 

6.	 Develop and demonstrate measurement techniques that are capable of directly 

identifying and quantifying trace levels of individual ionic species of Hg [e.g., HgCl2, 

HgCl, HgS, HgSO4, Hg (NO3) 2], 

4-18

7.	 Verify the ability of Hg CEMs to accurately measure total gas-phase Hg and speciated 

gas-phase Hg at diverse stack conditions representative of fuel type and pollution 

control device configurations (e.g., downstream of PM control devices and wet FGD 

scrubbers), 

8.	 Verify the ability of Hg CEMs to accurately measure total gas-phase Hg and speciated 

gas-phase Hg at measurement locations upstream of PM control devices, 

9.	 Demonstrate Hg CEM long-term monitoring performance, including operational 

requirements, 

10. Identify and evaluate alternative, cost-effective semi-continuous methods for 

measuring the stack emission of total Hg, and 

11. Demonstrate the use of Hg CEMs and semi-continuous monitoring methods as 

potential Hg emission compliance tools. 

4.5 References 

1.	 Electric Power Research Institute. Evaluation of Flue Gas Mercury Speciation Methods, 

Final Report TR-108988, Palo Alto, CA, December 1997. 

2.	 U.S. Environmental Protection Agency. “Method 101A—Determination of Particulate and 

Gaseous Mercury Emissions from Stationary Sources.” Code of Federal Regulations, Title 

40, Part 61, Appendix B. 

3.	 U.S. Environmental Protection Agency . “Method 29--Determination of Metals Emissions 

from Stationary Sources.” Code of Federal Regulations, Title 40, Part 60, Appendix A. 

4.	 “Standard Test Method for Elemental, Oxidized, Particle-Bound, and Total Mercury in Flue 

Gas Generated from Coal-Fired Stationary Sources (Ontario-Hydro Method), October 27, 

1999. Available at: < http://www.epa.gov/ttn/emc/prelim/pre-003.pdf >. 

5.	 Electric Power Research Institute. A State-of-the-Art Review of Flue Gas Mercury 

Speciation Methods, Final Report TR-107080, Palo Alto, CA, December 1996. 

6.	 U.S. Environmental Protection Agency. “Method 301 - Field Validation of Pollutant 

Measurement Methods from Various Waste Media.” Code of Federal Regulations, Title 40, 

Parts 63, Appendix A. 

7.	 Ryan, J.V. “Development and Evaluation of Mercury CEMS for Combustion Emissions 

Monitoring.” In Proceedings of 17th Annual Waste Testing and Quality Assurance 

Symposium, Arlington, VA. August 15, 2001. 

4-19

8.	 French, N., S. Priebe, and W. Haas, Jr. “State-of-the-art mercury CEMS.” Analytical 

Chemistry News & Features, 470-475A (July 1, 1999). 

9.	 Hedges, S., J. Ryan, and R. Stevens. Workshop on Source Emission and Ambient Air 

Monitoring of Mercury, Bloomington, MN, September 13-14, 1999. EPA/625/R-00/002 

(NTIS PB2001-100963). National Risk Management and National Exposure Research 

Laboratory, Cincinnati, OH. June 2000. 

10.	 Brown, T. D., D.N. Smith, R.A. Hargis, Jr., and W.J. O’Dowd. “1999 Critical Review: 

Mercury Measurement and Its Control: What We Know, Have Learned, and Need to 

Further Investigate,” Journal of the Air & Waste Management Association, June 1999. pp. 

1-97. Available at: 

< http://www.lanl.gov/projects/cctc/resources/pdfsmisc/haps/CRIT991.pdf >. 

11.	 Laudal, D. L., T. D. Brown, and P. Chu, “Testing of a Mercury Continuous Emission 

Monitor at Three Coal-Fired Electric Utilities.” Paper presented at the 92nd Annual 

Meeting and Exposition of the Air & Waste Management Association, St. Louis, MO, June 

1999. 

12.	 Linak, W. P., J. V. Ryan, B.S. Ghorishi, and J. O. L. Wendt. Issues Related to Solution 

Chemistry in Mercury Sampling Impingers. Journal of the Air & Waste Management 

Association, 51: 688-698 (2001). 

13.	 U. S. Environmental Protection Agency, Draft Mercury Continuous Emissions Monitor 

System Demonstration, Volume I: Holnam, Inc., Hazardous Waste Burning Kiln, Holly Hill, 

SC. Office of Solid Waste and Emergency Response, Washington, DC. March 1998. 

14.	 U. S. Environmental Protection Agency. Draft Performance Specification 12 -

Specifications and Test Procedures for Total Mercury Continuous Monitoring Systems in 

Stationary Sources, Office of Air Quality Planning and Standards, Emission Measurement 

Center, Research Triangle Park, NC. Proposed April 19, 1996. Available at: 

< http://www.epa.gov/ttn/emc/propperf.html >. 

15.	 Gibson, L. V., J. E. Dunn, R. L. Baker, W. Sigl, and I. Skegg, “Field Evaluation of a Total 

Mercury Continuous Emission Monitor at a U. S. Department of Energy Mixed Waste 

Incinerator.” Paper presented at the 92nd Annual Meeting and Exposition of the Air and 

Waste Management Association, St. Louis, MO, June 1999. 

16.	 Baker, R. L. “Are We Ready for Meeting Continuous Emission Monitoring Requirements 

for Total Mercury Combustion Sources?” Paper presented at the 93rd Annual Meeting and 

Exposition of the Air and Waste Management Association, Salt Lake City, UT, June 2000. 

4-20

17.	 Laudal, D.L., and N.B. French, “State-of-the-Art of Mercury Continuous Emission Monitors 

for Coal-Fired Systems.” Conference on Air Quality II Mercury, Trace Elements, and 

Particulate Matter, McLean, VA, September 2000. 

4-21

Chapter 5 

Mercury Speciation and Capture 

5.1 Introduction 

The source of Hg emissions from coal-fired electric utility boilers is the Hg that naturally 

exists in coal and is released during the combustion process. As discussed in Chapter 2, the Hg 

content of a coal varies by coal type and where it is mined. When the coal is burned in an 

electric utility boiler, most of the Hg bound in the coal is released into the combustion product 

gases. This chapter provides an introduction to Hg chemistry and behavior of Hg as it leaves the 

combustion zone of the furnace and passes in the flue gas through the downstream boiler 

sections, air heater, and air pollution control devices. Recent research on Hg chemistry in coalfired electric utility boiler flue gas is summarized. 

5.2 General Behavior of Mercury in Coal-fired Electric Utility Boilers 

The majority of Hg in coal exists as sulfur-bound compounds and compounds associated 

with the organic fraction in coal. Small amounts of elemental Hg may also be present in the 

coal. Figure 5-1 presents a simplified schematic of the coal combustion process. The primary 

products of coal combustion are carbon dioxide (CO2) and water (H2O). In addition, as 

discussed in Chapter 3, significant quantities of the pollutants sulfur dioxide (SO2) and nitrogen 

oxides (NOX) are also formed. When the coal is burned in an electric utility boiler, the resulting 

high combustion temperatures in the vicinity of 1,500 °C (2,700 °F) vaporize the Hg in the coal 

to form gaseous elemental Hg. Subsequent cooling of the combustion gases and interaction of 

the gaseous elemental Hg with other combustion products result in a portion of the Hg being 

converted to other forms. 

There are three basic forms of Hg in the flue gas from a coal-fired electric utility boiler: 

(1) elemental Hg (represented by the symbol Hg0

 in this report); (2) compounds of oxidized Hg 

(collectively represented by the symbol Hg2+ in this report); and (3) particle-bound mercury 

(represented by the symbol Hgp in this report). Oxidized mercury compounds in the flue gas 

from a coal-fired electric utility boiler may include mercury chloride (HgCl2), mercury oxide 

(HgO), and mercury sulfate (HgSO4). Some researchers refer to oxidized mercury compounds 

collectively as ionic mercury. This is because, while oxidized mercury compounds may not exist 

as mercuric ions in the boiler flue gas, these compounds are measured as ionic mercury by the 

5-1

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Major 

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Mercury 

Species 

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N2 

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140 oC 

Hg0 

S

Figure 5-1. Mercury species distribution in coal-fired electric utility boiler flue 

gas. 

5-2

speciation test method used to measure oxidized Hg (discussed in Chapter 4). Similarly, 

particle-bound Hg is referred to as particulate mercury by some researchers. The term particlebound mercury is the preferred and is used in this report to emphasize that the mercury is bound 

to a solid particle. 

The term speciation is used to denote the relative amounts of these three forms of Hg in 

the flue gas of the boiler. At present, speciation of Hg in the flue gas from a coal-fired electric 

utility is not well understood. A number of laboratory and field studies have been conducted, or 

are ongoing, to improve the understanding of the transformation of Hg0

 to the other Hg forms in 

the flue gas downstream of the boiler furnace. Data obtained to date indicate that combinations 

of site-specific factors affect the speciation of Hg in the flue gas. These factors include: 

• Type and properties of the coal burned. 

• Combustion conditions in the boiler furnace. 

• Boiler flue gas temperature profile. 

• Boiler flue gas composition. 

• Boiler fly ash properties. 

• Post-combustion flue gas cleaning technologies used. 

The current understanding of the mechanisms by which Hg0

 transforms to Hg2+ and Hgp 

in the flue gas from coal-fired electric utility boilers is discussed in subsequent sections of this 

chapter. It is important to understand how Hg speciates in the boiler flue gas because the overall 

effectiveness of different control strategies for capturing Hg often depends on the concentrations 

of the different forms of Hg present in the boiler flue gas. This topic will be discussed in detail 

in Chapters 6 and 7. 

5.3 Speciation of Mercury 

As mentioned above, high temperatures generated by combustion in the boiler furnace 

vaporize Hg in the coal. The resulting gaseous Hg0

 exiting the furnace combustion zone can 

undergo subsequent oxidation in the flue gas by several mechanisms. The predominant oxidized 

Hg species in boiler flue gases is believed to be HgCl2. Other possible oxidized species may 

include HgO, HgSO4, and mercuric nitrate monohydrate Hg(NO3)2•H2O. The potential 

mechanisms for oxidation of Hg0 in the boiler flue gas include: 

• Gas-phase oxidation. 

• Fly ash mediated oxidation. 

• Oxidation by post-combustion NOx controls. 

Each of these oxidation mechanisms is discussed in the following sections. 

5-3

5.3.1 Gas-phase Oxidation 

As mentioned above, Hg in coal is believed to completely vaporize and convert into 

gaseous Hg0 in the combustion zone of a boiler system. As gaseous Hg0 travels with the flue gas 

in the boiler, it can undergo gas-phase oxidation to form gaseous Hg2+, most of which is believed 

to be HgCl2. Recent research 1 has speculated that the major gas-phase reaction pathway to form 

gaseous HgCl2 is the reaction of gaseous Hg0

 with gaseous atomic chlorine (Cl). The latter is 

formed when chlorine in coal vaporizes during combustion. 

At the furnace exit, the temperature of the flue gas is typically in the vicinity of 1400 oC 

(2552 oF). The flue gas cools as it passes through the heat exchanging equipment in the postcombustion region. At the outlet of the air heater (the last section of heat exchanging 

equipment), the temperature of the flue gas ranges from 127 to 327 °C (261 to 621oF). Chemical 

equilibrium calculations predict that gas-phase oxidation of Hg0 to Hg2+ starts at about 677 oC 

(1251 oF) and is essentially complete by 427 oC (801 oF). Based on these results, Hg should exist 

entirely as Hg2+ downstream of the air heater. However, flue-gas measurements of Hg at air 

heater outlets indicate that gaseous Hg0

 is still present at this location, and that Hg2+ ranges from 

5 to 95 percent of the gas-phase Hg. These data suggest that, due to kinetic limitations, the 

oxidation of Hg0 does not reach completion. 

As mentioned previously, gas-phase oxidation of Hg0

 is believed to take place via 

reaction with gaseous Cl. At furnace flame temperatures, a major portion of the chlorine in the 

coal exists as gaseous chlorine atoms, but as gas cools in post-combustion, the chlorine atoms 

combine to form primarily hydrogen chloride (HCl) and minor amounts of molecular chlorine 

(Cl2). The rapid decrease in Cl concentration results in "quenched" Hg2+ concentrations 

corresponding to equilibrium values around 527 oC (981 oF). 

Figures 5-2 and 5-3 show predicted distributions of Hg species in coal-fired electric 

utility flue gas as a function of flue gas temperature. The predicted distributions are based on 

equilibrium calculations of gas-phase oxidation of Hg0 in flue gas from the combustion of a 

bituminous coal 1 and a subbituminous coal 2, respectively. Figure 5-2 shows that 80 percent of 

gaseous Hg0

 is oxidized to HgCl2 by 527 oC (981oF). Figure 5-3 indicates no oxidation of Hg0 at 

or above 527 oC (981oF). As mentioned above, the gas-phase oxidation of Hg0

 is believed to be 

kinetically limited, proceeding only to equilibrium levels around 527 oC (981 oF). 

The difference in the equilibrium oxidation levels at 527 °C (800 K) in Figures 5-2 and 

5-3 is attributed to the different chlorine levels in the model coals used in the calculations. The 

calculated data in Figure 5-2 are based on a bituminous coal with a relatively high chlorine 

concentration of several hundred parts per million by weight (ppmw). In contrast, the calculated 

data in Figure 5-3 are based on a typical western subbituminous coal with a relatively low 

chlorine content of 26 ppmw. Research indicates that coals with relatively high chlorine 

contents tend to produce more Hg2+ than coals with relatively low chlorine contents.3 

5-4

Figure 5-2. Predicted distribution of Hg species at equilibrium, as a function of 

temperature for a starting composition corresponding to combustion of a 

bituminous coal (Pittsburgh) in air at a stoichiometric ratio of 1.2 (source: 

Reference 2). 

5-5

Figure 5-3. Predicted distribution of Hg species at equilibrium, as a function of 

temperature for a starting composition corresponding to combustion of a 

subbituminous coal (Powder River Basin) in air at a stoichiometric ratio of 1.2 

(source: Reference 2). 

5-6

In addition to being kinetically limited by Cl concentration, recent research conducted at 

EPA has found that gas-phase oxidation of Hg0

 is also inhibited by the presence of SO2 and 

water vapor. 4 As shown in Figure 5-1, SO2 and water vapor are constituents in the flue gas from 

coal-fired electric utility boilers. Figure 5-4 shows results from bench-scale experiments 

examining the effects of SO2 and water vapor on the oxidation of gaseous Hg0

. These 

experiments were carried out using a simulated flue gas containing a base composition of 40 

parts per million by volume (ppmv) Hg0, 5 mole % carbon dioxide (CO2), 2 mole % oxygen (O2), 

and a balance of nitrogen (N2); the temperature of the flue gas was 754 oC (1,389 oF). The 

effects of SO2, water vapor, and HCl were studied by adding these constituents to the base flue 

gas. HCl was added to the simulated flue gas at three concentrations typical of coal combustion 

flue gas (50, 100, and 200 ppmv); SO2 and water vapor were added with the HCl at 500 ppmv 

and 1.7 mole %, respectively. 

As shown in Figure 5-4, the oxidation of Hg0 was inhibited by the presence of SO2 and 

water vapor. HCl is not believed to react directly with Hg0 to cause its oxidation (a chlorinating 

agent such as atomic chlorine or Cl2 is needed). HCl may produce trace quantities of the 

chlorinating agent in the flue gas. It is speculated that SO2 and water vapor may inhibit gasphase oxidation of Hg0

 by scavenging the chlorinating agent. 

In addition to experimental studies, research has also been reported on the development 

of a kinetic model that is used to better understand the reaction mechanism involved in gas-phase 

Hg oxidation. A detailed chemical kinetics model using a chemical mechanism consisting of 60 

reactions and 21 chemical species was developed recently to predict Hg speciation in combustion 

flue gas. 5 The speciation model accounts for the chlorination and oxidation of key flue gas 

components, including Hg0. The performance of the model is very sensitive to temperature. For 

low reaction temperatures (< 630 oC), the model produced only trace amounts of Cl and Cl2 from 

HCl, leading to a drastic under-prediction of Hg chlorination compared with experimental data. 

For higher reaction temperatures, model predictions were in good accord with experimental data. 

For conditions that produce an excess of Cl and Cl2 relative to Hg, chlorination of Hg is 

determined by the competing influences of the initiation step, Hg + Cl → HgCl, and the 

recombination reaction, 2Cl → Cl2. If the Cl recombination is faster, Hg chlorination will 

eventually be determined by the slower pathway Hg + Cl2 → HgCl2. 

Another attempt has been made to formulate an elementary reaction mechanism for gasphase Hg oxidation.6 The proposed eight-step Hg oxidation mechanism quantitatively describes 

the reported extents of Hg oxidation for broad ranges of HCl and temperature. In the proposed 

mechanism, Hg is oxidized by a Cl atom recycle process, and, therefore, the concentrations of 

both Cl and Cl2 are important. Once a pool of Cl atoms is established, Hg0 is first oxidized by Cl 

into HgCl, which, in turn, is oxidized by Cl2 into HgCl2. The second step regenerates Cl atoms. 

Since the concentrations of Hg species are small in coal combustion flue gases, independent 

reactions establish and sustain the pool of Cl atoms. The pool is governed by the chemistries of 

moist CO oxidation, Cl species transformations, and nitrogen oxide (NO) production. The model 

predictions show that O2 weakly promotes homogeneous Hg oxidation, whereas moisture is a 

strong inhibitor as it inhibits the decomposition of HCl to Cl2. NO was identified as an effective 

inhibitor for Hg0 oxidation through its effect on reducing the concentration of hydroxyl (OH) 

5-7

Figure 5-4. Effects of SO2 and water vapor on the gas-phase oxidation of Hg0

 at 

754 °C and at three different HCl concentrations. 

5-8

in the flue gas. The formation of HOCl from OH and Cl is essential for the oxidation of Hg, 

which oxidizes HgCl into HgCl2 and OH. The elimination of OH via OH+NO+M = HONO+M 

is believed to inhibit Hg0 oxidation. 

5.3.2 Fly Ash Mediated Oxidation 

In fabric filtration, flue gas penetrates a layer of fly ash as it passes through the filtering 

unit. The intimate contact between the flue gas and the fly ash on the filter provides an 

opportunity for the latter to oxidize some of the incoming gaseous Hg0. However, this 

phenomenon does not occur across ESPs because the flue gas does not pass through a collected 

layer of fly ash (see Chapter 3 for a description of the operation of FFs and ESPs). 

Certain fly ashes have been shown to promote oxidation of Hg0 across a FF more actively 

than others. For example, fly ashes from bituminous coals tend to oxidize Hg0 at higher rates 

than fly ashes from subbituminous coals and lignite. Differences in oxidation appear to be 

attributable to the composition of the fly ash, the presence of certain flue gas constituents, and 

the operating conditions of FFs. 

Bench-scale tests were conducted at EPA to investigate the effects of fly ash composition 

and flue gas parameters on the oxidation of gaseous Hg0.

4,7 In these experiments, a simulated 

flue gas containing Hg0 (and other species) was passed through a fixed bed of simulated or actual 

coal fly ash, and oxidation of Hg0

 was measured across the reactor. Experimental results 

indicated two possible reaction pathways for fly-ash-mediated oxidation of Hg0. One possible 

pathway is the oxidation of gaseous Hg0

 by fly ash in the presence of HCl, and the other is the 

oxidation of gaseous Hg0 by fly ash in the presence of NOX. The research also reflected that the 

iron content of the ash appeared to play a key role in oxidation of Hg0. This EPA research is 

described in the ensuing paragraphs. 

Coal fly ash is a mixture of metal oxides found in both crystalline and amorphous forms. 

Glasses are common ash constituents, composed primarily of the oxides of silicon and aluminum 

(known as aluminosilicate glasses) that can contain a significant amount of cations such as iron, 

sodium, potassium, calcium, and magnesium. Iron oxide (in the form of magnetite or hematite) 

is also as commonly found in ash as calcium oxide and calcium sulfate. In the presence of 

sufficiently high flue-gas concentrations of HCl or Cl2, metallic oxides in fly ash may be 

converted to metal chlorides such as cuprous chloride (CuCl). Three-component model fly ashes 

were prepared by adding Fe2O3 or CuO at various weights to a base mixture of Al2O3 and SiO2. 

An additional three-component fly ash was prepared by adding CuCl to a base mixture of Al2O3 

and SiO2. Municipal waste combustion fly ashes contain significant amounts of copper 

compared to coal combustion fly ashes that contain only trace levels of copper. Model fly ashes 

were prepared and tested in order to understand the effect of differences in copper content on the 

oxidation of Hg0

. Four-component fly ashes were prepared by adding various weights of CaO, 

and Fe2O3 or CuO to a base mixture of Al2O3 and SiO2. Actual coal fly ashes were obtained 

from the combustion of three different coals (two subbituminous and one bituminous) from a 

pilot-size, pulverized-coal-fired furnace. 

5-9

Model flue gas compositions were simulated to represent the temperature and 

composition of coal-fired electric utility flue gas as it enters a FF. The temperature of coal 

combustion flue gas as it enters a FF typically ranges from 150 °C (302 °F) to 250 °C (482 °F). 

Potentially important flue gas species (in terms of Hg0

 oxidation) include chlorine (primarily in 

the form of HCl at FF temperatures), NOX (primarily in the form of NO at FF temperatures), SO2, 

and water vapor. The base flue gas consisted of 40 ppbv Hg0, 2 mole % O2, 5 mole % CO2, and 

the balance N2 at a temperature of 250 °C (482 °F). HCl (50 ppmv), NO (200 ppmv), SO2 

(500 ppmv), and/or water vapor (1.7 mole %) were added to the base gas to determine their 

effect on oxidation. About 10 percent of NO2 (10 ppmv) was measured when 200 ppmv of NO 

was added to the base flue gas which contains 2 mole % of O2. The mixture of NO and NO2 in 

flue gas is referred to collectively as NOX. Table 5-1 shows the simulated and actual fly ashes 

and simulated flue gas tested. 

Oxidation Behavior of Model Fly Ashes. HCl and NOX were identified as the active 

components in flue gases for the oxidation of Hg0. NOX were more active than HCl. Cupric oxide 

(CuO) and ferric oxide (Fe2O3) were identified as the active components in model fly ashes for 

Hg0 oxidation. In the presence of NOX, inert components of model fly ashes such as alumina 

(A12O3) and silica (SiO2) appeared to become active in oxidation of Hg0

. Steady-state oxidation 

of Hg0 promoted by the four-component model fly ashes (containing calcium oxide, CaO) was 

reached at much slower rates compared to those obtained using the three-component model fly 

ashes that contained no CaO (Figures 5-5 and 5-6). The partial removal of gas-phase HCl by 

CaO in the CaO-containing model fly ashes may have reduced the available chlorinating agent 

and resulted in slower oxidation of Hg0. 

Oxidation Behavior of Actual Coal Fly Ashes. As shown in Table 5-1, the Blacksville fly 

ash (derived from a bituminous coal) completely oxidized Hg0 in the presence of NO (base + 

NO), but showed little oxidation in the presence of HCl (base + HCl). 7 The Comanche fly ash 

(derived from a subbituminous coal) did not oxidize Hg0

 in the presence of NO or HCl. The 

Absaloka coal (derived from a subbituminous coal) showed 30 to 35 percent oxidation of Hg0 in 

the presence of NO, but no oxidation in the presence of HCl. It is believed that the high 

reactivity of the Blacksville coal in NO is related to its relatively high Fe2O3 concentration (22 

percent); this observation is in agreement to that seen for the high iron (approximately 14 

percent) three- and four-component model fly ashes. 

More tests were conducted recently at EPA on actual fly ash samples with different coal 

ranks and iron contents in order to get a better understanding of the effects of iron in coal fly 

ashes on speciation of Hg. 8 It was observed that one subbituminous (3.7 percent iron) and three 

lignite coal fly ash (1.5 to 5.0 percent iron) samples tested with low iron content did not oxidize 

Hg0

 in the presence of NO and HCl. However, a bituminous coal fly ash sample (Valmont 

Station) with a low iron content (2.3 percent iron) completely oxidized Hg0 in the presence of 

NO and HCl. It was also found that, upon adding Fe2O3 to the low iron content subbituminous 

and lignite fly ash samples to reach an iron content similar to that of the Blacksville sample, 

significant Hg0

 oxidation reactivity was measured (33 to 40 percent oxidation of Hg0) for these 

iron-doped samples. 

5-10

Figure 5-5. Hg0

 oxidation in the presence of the three- and four-component model 

fly ashes containing iron at a bed temperature of 250 °C (source: Reference 4). 

5-11

Figure 5-6. Hg0

 oxidation in the presence of the three- and four-component model 

fly ashes containing copper at a bed temperature of 250 °C (source: Reference 4). 

5-12

Table 5-1. Percent oxidation of Hg0 by simulated and actual coal-fired electric 

utility boiler fly ash (source: Reference 4). 

% Oxidation of Hg0 by fly ash 

Fly Ash Composition 

(by weight percentages) Base a Base 

+ HCl 

Base 

+ 

HCl, 

SO2 

Base 

+ 

HCl, 

SO2

, 

H2

O 

Base 

+ NO 

Base 

+ NO, 

SO2 

2-Component Model Fly Ash 

22% Al2O3 + 78% SiO2 

b 0 9 4 

5-Component Model Fly Ashes 

19% Al2O3, + 67% SiO2 + 14% Fe2O3 0 92 8 4 3 0 

22% Al2O3 + 77% SiO2 + 1% Fe2O3 67 43 37 48 26 

22% Al2O3 + 78% SiO2 + 0.1% Fe2O3 15 11 3 

22% Al2O3 + 77% SiO2 + 1% CuO 93 9 4 0 6 

22% Al2O3 + 78% SiO2 + 0.1% CuO 92 6 3 5 3 

22% Al2O3 + 72% SiO2 + 7% CaO 0 0 13 14 0.86 13 

22% Al2O3 + 78% SiO2 + 0.1% CuCl 87 77 23 

4-Component Model Fly Ashes 

21% Al2O3 + 71% SiO2, + 1% CuO + 7% CaO 91 82 43 

18% Al2O3, + 63% SiO2 + 13% Fe2O3 + 6% CaO 87 3 9 

3

8 5 9 8

8 8 7 1

8 6 3

9 4

Actual Fly Ash Samples 

Blacksville coal fly ash (bituminous) 

22% Fe2O3, 6% CaO 6 100 

Comanche coal fly ash (subbituminous) 

5% Fe2

O3, 32% CaO 0 

Absaloka coal fly ash (subbituminous) 

4% Fe2

O3, 24% CaO 30-35 

0 

(a) 	Base gas consisted of 40 ppbv Hg0, 2 mole% O2, 5 mole% CO2, and balance N2 at a temperature of 523 K. 

HCl, NO, SO2

, and water vapor were added to the base gas in the following concentrations 50 ppmv, 200 

ppmv, 200 ppmv, and 1.7 mole%, respectively. 

(b) Blank cells mean test not conducted. 

5-13

The physical, chemical, and carbon properties of the Blacksville and Valmont samples 

were also characterized. It was found that the two fly ash samples have different unburned 

carbon contents (3.4 percent for Valmont and 16.8 percent for Blacksville). Based on this 

finding, it appears that iron content may not be the only ash-related factor that affects the Hg0 

oxidation reactivity of bituminous coal fly ashes. The effect of physical properties, such as 

surface area, and the effects of chemical properties, such as sodium content and alkalinity, in the 

fly ash may also determine the propensity of different fly ashes to oxidize Hg in flue gas. 

Research for obtaining a better understanding of the roles of NOX and Fe2O3 in the 

heterogeneous oxidation of Hg0 was reported recently by UND/EERC.9 In UND/EERC’s 

reported research, the effects of NOX and hematite (α-Fe2O3) on Hg transformations were studied 

by injecting them into actual coal combustion flue gases produced from burning bituminous 

(Blacksville), subbituminous (Absaloka), and lignite (Falkirk) coals in a 7-kW combustion 

system. It was found that the Blacksville fly ash has high Fe2O3 content (12.1 percent), and the 

Absaloka and Falkirk fly ashes have significantly lower Fe2O3 contents (4.5 and 7.9 percent, 

respectively). Portions of the Fe2O3 in Blacksville and Falkirk fly ashes are present as 

maghemite (γ-Fe2O3), and a portion of the Fe2O3 in Absaloka fly ash is present as hematite (αFe2O3). The flue gas generated from the combustion of Blacksville coal contained Hg2+ as the 

predominant Hg species (77 percent), whereas Absoloka and Falkirk flue gases contained 

predominantly Hg0

 (84 and 78 percent, respectively). Injections of NO2 (80 to 190 ppm) at 440 

to 880 oC and α-Fe2O3 (6 and 15 percent) at 450 oC into Absoloka and Falkirk coal combustion 

flue gases did not change Hg speciation. The UND/EERC researchers suggested that the lack of 

transformation from Hg0 to Hg2+ in the 7-kW combustion system was possibly due to 

components of either Absoloka and Falkirk coal combustion flue gases, or their fly ashes, 

inhibiting the α-Fe2O3 catalyzed heterogeneous oxidation of Hg0 by NOX. The researchers also 

believed that an abundance of Hg2+ in Blacksville coal combustion flue gas and γ-Fe2O3 in the 

corresponding fly ash, and the inertness of injected α-Fe2O3 with respect to heterogeneous Hg0 

oxidation in Absoloka and Falkirk flue gases, are indications that γ-Fe2O3 rather than α-Fe2O3 

catalyzes Hg2+ formation. 

A study of the role of fly ash in the speciation of Hg in coal combustion flue gases was 

reported by Iowa State University.10 In this study, bench-scale laboratory tests were performed 

in a simulated flue gas stream using two fly ash samples obtained from the ESPs of two fullscale coal-fired electric utility boilers. One fly ash was derived from burning a western 

subbituminous coal (Powder River Basin) while the other was derived from an eastern 

bituminous coal (Blacksville). Each of the two samples was separated into three subsamples 

with particle sizes greater than 10, 3, and 1 μm using three cyclones. The amount of sample 

collected in these three size ranges was 85 to 90 percent, 10 to15 percent, and 1 percent of the 

total ash, respectively. Only the two largest sized subsamples were tested for Hg0

 oxidation 

reactivity. The Blacksville sample was also separated into strongly magnetic (20 percent), 

weakly magnetic (34 percent), and nonmagnetic (46 percent) fractions using a hand magnet for 

testing Hg0

 oxidation reactivity of the individual fractions. Since magnetism of the fly ash 

samples is contributed mainly by iron oxides in the samples, the iron oxide content of the 

magnetically separated samples is in the following order: strongly magnetic > weakly magnetic > 

nonmagnetic. The low iron content PRB fly ash is nonmagnetic and was not magnetically 

5-14

separated for testing. Scanning electron microscopy with energy-dispersive x-ray analysis 

(SEM-EDX) was used to examine the surface morphology and chemical composition of the fly 

ash samples. X-ray diffraction (XRD) was also used to examine the mineralogical composition 

of the whole and fractionated fly ash samples. XRD identifies only crystalline components of 

the samples. This is important since coal combustion fly ashes typically contain a considerably 

amount of glassy, amorphous material. 

It was observed that, although the fly ashes tested were chemically and mineralogically 

different, there were no large differences in the catalytic potential for oxidizing Hg0

.

10 The 

Blacksville fly ash tended to show somewhat more catalytic reactivity (16 to 19 percent Hg0 

oxidation) than the PRB fly ash (4 to 10 percent Hg0 oxidation). The researchers of this project 

suggested that the difference in reactivity could be due largely to the larger surface area (3.4 

m2

/g) of the Blacksville fly ash compared to that (1.5 m2/g) of the PRB fly ash. It was found 

from the SEM-EDX analyses that the iron-rich (highly magnetic) phases in the greater than 10 

μm size fraction of the Blacksville sample contained about 25 percent (atomic) Fe, 10 percent 

each of Al and Si, 2 percent Ca, and lesser amounts of Na, S, K, and Ti. The nonmagnetic 

Blacksville fly ash fraction in the greater than 10 μm size range contained only 4 percent Fe, 10 

percent Al, 20 percent Si, and lesser amounts of Na, S, K, and Ti. For the PRB fly ash (all 

nonmagnetic), both the greater than 10 μm and greater than 3 μm fractions contained about 3 

percent Fe, 10- 20 percent Al and Si, about 10 percent Ca, and 2 percent or less of Mg, S, K, and 

Ti. The XRD results showed that the whole Blacksville ash contained primarily quartz (SiO2), 

mullite (3Al2O3•2SiO2), magnetite (Fe3O4), hematite (Fe2O3), and a trace of lime (CaO). The 

PRB fly ash contained mostly quartz and lesser amounts of lime, periclase (MgO), and calcium 

aluminum oxide (Ca3Al2O6). No magnetite or hematite was found in this ash. It is interesting to 

note that the nonmagnetic fractions actually showed substantially higher amounts of oxidized Hg 

than the magnetic fractions. The reported test results of this study indicated that the nonmagnetic 

fraction resulted in 24 percent of the Hg being oxidized, while 3 percent of the Hg oxidized when 

using the magnetic ash. It has been suspected that the magnetic (iron-rich) fraction in fly ash 

would be more catalytic than the nonmagnetic (aluminosilicate-rich) fraction because of its 

mineralogy (predominantly iron oxides), and possibly because the magnetic phase tends to be 

enriched in transition metals that could also serve as Hg0 oxidation catalysts. However, under 

the experimental conditions employed in this study, the test results do not support this. It was 

found that the surface area of the nonmagnetic fraction is about four times that of the magnetic 

fraction. From this study it appears that surface area is a dominant factor in determining the 

ash’s Hg0 oxidation reactivity. 

Because major differences were not observed with the two fly ashes, a set of tests 

involving a full factorial design was conducted using only the Blacksville fly ash in order to 

apply statistical techniques for identifying the important factors in determining Hg0 oxidation.10 

The statistical analysis results indicated that the composition of the simulated flue gas used in the 

tests and whether or not ash was present in the gas stream were the two most important factors. 

The presence of HCl, NO, NO2, and SO2 and all two-way gas interactions of the four gases listed 

above were found statistically significant for Hg0

 oxidation. The HCl, NO2, and SO2 appeared to 

contribute to Hg0

 oxidation, while the presence of NO appeared to suppress Hg0 oxidation. NO2 

was found to be the most important of the four reactive gases tested; next were HCl and NO. 

5-15

However, the effect of NO depended on whether NO2 was present. Although the presence of 

NO2 was statistically significant as a main factor, it was found more important in its interactions 

with other gas components. Based on the statistical analysis results, the researchers of this 

project concluded that the interactions of flue gases with fly ash to cause Hg0

 oxidation are 

extremely complex, and the difficulty in understanding the Hg chemistry in coal combustion flue 

gases is not surprising. It is noted that the EPA study showed significant Hg oxidation reactivity 

of the Blacksville ash, while studies at UND/EERC and Iowa State University show little Hg 

oxidation reactivity of Blacksville ash. Since the ash samples used in the above studies were 

generated at three different plant operating conditions, these conditions may play an important 

role in contributing to the reactivity of the ashes. 

5.3.3 Oxidation by Post-combustion NOX Controls 

There are indications that post-combustion NOX controls SCR and SNCR may oxidize 

some of the Hg0 in the flue gas of a coal-fired electric utility boiler. The research on this issue is 

ongoing. For current understanding of this subject, the reader is referred to Chapter 6. 

5.3.4 Potential Role of Deposits, Fly Ash, and Sorbents on Mercury Speciation 

Gaseous Hg (both Hg0 and Hg2+) can be adsorbed by the solid particles in the coal-fired 

electric utility boiler flue gas. Adsorption is the phenomenon where a vapor molecule in a gas 

stream contacts the surface of a solid particle and is held there by attractive forces between the 

vapor molecule and the solid. Solid particles are present in all coal-fired electric utility boiler 

flue gas as a result of the ash that is generated during combustion of the coal. Ash that exits the 

furnace with the flue gas is called fly ash. Other types of solid particles may be introduced into 

the flue gas stream (e.g., lime, powdered activated carbon) for pollutant emission control. Both 

types of particles may adsorb gaseous Hg in the boiler flue gas. This section addresses the 

adsorption of gaseous Hg by fly ash. Adsorption of Hg by sorbent particles introduced into the 

flue gas stream and subsequently captured in a downstream PM control device is discussed in 

Chapter 6 as related to specific control technologies that may be implemented to increase overall 

Hg removal from the boiler flue gas. 

Gaseous Hg can be adsorbed by fly ash in the flue gas (sometimes called "in-flight" 

adsorption). In-flight adsorption of gaseous Hg by fly ash occurs in the post-combustion region 

where the flue gas contains its highest concentration of fly ash (i.e., prior to the first PM control 

device). The type of coal from which a fly ash originates appears to strongly influence its ability 

to adsorb Hg. Pilot-scale 11 and field data 12 have indicated that fly ashes from subbituminous 

coals (specifically, those from the Powder River Basin in Wyoming) adsorb more gaseous Hg 

than fly ash from lignite and bituminous coals. Test data show 30 percent in-flight adsorption of 

gaseous Hg by fly ashes from boilers burning these subbituminous coals compared to 10 to 20 

percent adsorption by the fly ashes from boilers burning lignite or bituminous coals. It has been 

suggested that the measured removals of Hg by fly ash can be inflated based on the sampling 

method, but in most cases are below 15 percent. General trends indicate that in-flight field 

capture of Hg from combustion of subbituminous coals is higher than from combustion of 

bituminous coals.13 

5-16

The carbon content of fly ash is another parameter that may influence adsorption of 

gaseous Hg (the carbon in fly ash is unburned coal). Conditions that result in increased amounts 

of carbon in fly ash tend to increase the amount and subsequent capture of particle-bound Hg. 

Hg has been found to concentrate in the carbon-rich fraction of fly ash.14,15 For similar coals, 

both laboratory 16 and pilot- and large-scale data 11 have shown a positive correlation between 

adsorption of gas-phase Hg and carbon content in fly ash. A research project conducted at fullscale coal-fired electric utility boilers in Colorado indicates that certain fly ashes adsorb 

significant levels of Hg from flue gas. Chapter 7 describes the methodology and results of this 

study in detail. Many of these fly ashes have carbon content greater than 7 percent, but one lowcarbon content fly ash has also been identified. This research project and the possibility of using 

fly ash re-injection for Hg control is discussed in Chapter 6. 

Gaseous Hg also can be adsorbed by fly ash collected on the surface of a FF. In a FF, 

there is contact of gaseous Hg in the flue gas with the collected layer of fly ash on the FF bags as 

the gases flow through the FF. Pilot-scale tests of a low-carbon fly ash (less than 0.5 percent 

carbon) showed that the fly ash adsorbed 65 percent of the gaseous Hg0

 entering a FF; the data 

indicate that fly ash properties other than just carbon content may affect adsorption. The tested 

fly ash was produced from the combustion of a subbituminous coal from the Powder River Basin 

in Wyoming. Western subbituminous coals generally contain high concentrations of CaO and 

tend to adsorb high levels of Hg0. At this time, the mechanisms by which these Western coals 

adsorb Hg0 are not known; however, the CaO content may be a factor. It has been shown in a 

pilot-scale study that combustion of western coals tends to produce relatively high particle-bound 

Hg emissions.17 

5.4 Capture of Mercury by Sorbent Injection 

Mercury can be captured and removed from a flue gas stream by injection of a sorbent 

into the exhaust stream with subsequent collection in a PM control device such as an electrostatic 

precipitator or a fabric filter. The implementation of this type of Hg control strategy requires the 

development, characterization, and evaluation of low-cost and efficient Hg sorbents. 

Experimental methods for characterization and evaluation are presented below. Further, efforts 

to develop better sorbents, with greater capacity and lower cost, are also discussed. 

5.4.1 Sorbent Characterization 

Sorbents are characterized by their physical and chemical properties. The most common 

physical characterization is surface area. The interior of a sorbent particle is highly porous. The 

surface area of sorbents is determined using the Brunauer, Emmett, and Teller (BET) method of 

N2 adsorption.18 Nitrogen is adsorbed at the normal boiling point of –195.8 °C and the surface 

area is determined based on mono-molecular coverage. Surface areas of sorbents range from 5 

m2/g for Ca-based sorbents to over 2000 m2/g for highly porous activated carbons. Mercury 

capture often increases with increasing surface area of the sorbent. However, recent research 19 

has suggested that pore surface area in the micropores is more important than the total surface 

area for the removal of part per billion concentrations of Hg from coal combustion flue gases. 

5-17

Particle size distribution is another physical characteristic that is used to describe 

sorbents. Activated carbons that are used for Hg control are powdered with a size on the order of 

44 μm or less. Particle size is measured using sieves or a scanning electron microscope (SEM). 

Generally, the smaller the particle size of an activated carbon, the better the access to the surface 

area and the faster the rate of adsorption kinetics. Careful consideration of particle size 

distribution can provide significant operating benefits, both in fabric filter applications, where 

pressure drop must be considered, and in ESP (or duct injection) applications, where mass 

transfer limitations in the short residence time mean that adsorption is a function of sorbent 

particle size. 

Determination of the pore size distribution of an activated carbon is an extremely useful 

way of understanding the performance characteristics of the material. Pore sizes are based on the 

diameter of the pore and are categorized using the following IUPAC conventions: micropores 

<2 nm, mesopores 2-50 nm, and macropores >50 nm. Micropore volume can be estimated from 

CO2 adsorption at 273 K using the Dubinin-Radushkevich (DR) equation. Total pore volume 

can be determined using N2 adsorption. 

Some of the chemical properties of activated carbons that influence Hg capture include 

sulfur content, iodine content, chlorine content, and water content. Functional groups of a 

sorbent have been shown to play an important role in adsorption behavior. Many carbon-oxygen 

functional groups have been identified in activated carbon including carbonyl, carboxyl, quinone, 

lactones, and phenol groups. Many methods have been used to study the functional groups 

present in carbonaceous materials including neutralization of bases, direct analysis of the oxide 

layer by chemical reaction, infrared spectroscopy, and x-ray photoelectron spectroscopy. For 

example, specific surface oxygen functional groups can be estimated by using the data measured 

from the base titration based on the following assumptions: NaHCO3 titrates carboxyl groups; 

NaOH titrates carboxyl, lactone, and phenol groups; CO2 is a decomposition product of carboxyl 

and lactone groups; and CO is a decomposition product of phenol and carbonyl groups.20 The 

NaOH and HCl titration values can estimate the acidity and basicity of a carbon, respectively. 

5.4.2 Experimental Methods Used in Sorbent Evaluation 

In order to evaluate the performance of a specific Hg sorbent, several types of 

experimental reactors are used. The first step is testing in a bench-scale reactor system, which 

may be a fixed-bed, entrained-flow, or a fluidized-bed system. Sorbents that perform well in 

bench-scale tests are then tested in a pilot-scale system and may eventually be tested in a fullscale system. These systems are discussed below. 

5.4.2.1 Bench-scale Reactors 

Bench-scale reactors are the smallest category of reactors, hence the term “bench-scale.” 

There are several types of bench-scale reactors that are used to evaluate Hg sorbents. The first 

type that will be discussed is a fixed-bed or packed-bed system. This type of reactor simulates 

Hg0

 capture that would occur in a FF. Another type of bench-scale reactor is an entrained-flow 

5-18

reactor, which simulates in-flight capture of Hg0

 upstream of an ESP. It is important to highlight 

the major differences between these two reactors as shown in Table 5-2. 

Fixed-bed Reactor. A schematic of the experimental apparatus used by EPA to study the 

capture of Hg0 and HgCl2 is shown in Figure 5-7. A detailed description of the apparatus can be 

found elsewhere.21 In this system the Hg vapor generated is carried into a manifold by a nitrogen 

stream where it is mixed with SO2, HCl, CO2, O2, and water vapor (as required by each 

particular experiment). The sorbent to be studied (approximately 0.02 g diluted with 2 g inert 

glass beads; bed length of approximately 2 cm) is placed in the reactor and maintained at the 

desired bed temperature by a temperature controller. A furnace kept at 850 °C is placed 

downstream of the reactor to convert any Hg2+ (as in HgCl2) to Hg0. According to 

thermodynamic predictions, the only Hg species that exists at this temperature is Hg0.

22 Quality 

control experiments, in the absence of HCl in the simulated flue gas, also showed that all the 

HgCl2 could be recovered as Hg0

 across this furnace. The presence of the furnace enables 

detection of non-adsorbed HgCl2 as Hg0 by the on-line ultraviolet (UV) Hg0 analyzer, thus 

providing actual, continuous Hg0

 or HgCl2 capture data by the fixed bed of sorbent. The UV Hg0 

analyzer used in this system responds to SO2 as well as Hg0. Signal effects due to SO2 are 

corrected by placing an on-line SO2 analyzer (UV) downstream of the Hg0 analyzer and 

subtracting the measured SO2 signal from the total response of the Hg analyzer; the SO2 analyzer 

is incapable of responding to Hg in the concentration range generally used. 

In each test, the fixed bed is exposed to the Hg-laden gas for 7 hours or until 100 percent 

breakthrough (saturation) is achieved (whichever comes first). During this period the exit 

concentration of Hg is continuously monitored. The instantaneous removal of Hg0 or HgCl2 at 

any time (t) is obtained as follows: 

Instantaneous removal at time t (%) = 100*[(mercury)in-(mercury)out]/(mercury)in. 

The specific amount of Hg uptake (q, cumulative removal up to time t; weight Hg 

species/weight sorbent) is determined by integrating and evaluating the area under the removal 

curves. Selected experiments conducted using this experimental setup have been run in duplicate 

and indicated a range of +10% about the mean in the experimental results. It was found that 

differences in equilibrium Hg0

/HgCl2 capacities, at 200-300 mg/Nm3 inlet concentration, are 

statistically significant if the Hg0

/HgCl2 capacities are at least + 10 percent different from one 

another. 

Entrained-flow Reactor. An example of a bench-scale entrained-flow reactor 23 is shown 

in Figure 5-8. This EPA reactor is constructed of quartz and is 310.5 cm long with an inside 

diameter of 4 cm. Three gas-sampling ports are located along the length of the reactor and are 

labeled SP1, SP2, and SP3. The reactor is heated with three Lindberg, 3-zone electric furnaces 

in series. The baseline Hg0 concentration is measured in the absence of activated carbon using 

an ultraviolet (UV) analyzer (Buck Scientific, model 400A). Once the baseline is established, 

activated carbon is fed into the top of the reactor using a fluidized-bed feeder (0.2-0.5 std. 

L/min). The gas-phase Hg0

 concentration is then measured at one of the sample ports by pulling 

a gas sample (0.5 std. L/min) through a 1 μm filter to remove any particles, then through a 

5-19

Table 5-2. Comparison of bench-scale fixed-bed with entrained-flow reactors. 

Test Condition Fixed-Bed Reactor Entrained-Flow Reactor 

Simulation of capture in Fabric filter Upstream of an ESP 

Sorbent exposure Minutes/Hours/Days Less than 4 seconds 

Sorbent evaluation based on Breakthrough or uptake capacity Reactivity 

5-20

Figure 5-7. Schematic of bench-scale fixed-bed reactor (source: Reference 21). 

5-21

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Air 

Hg /N2 

Buck Hg 

Analyzer 

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N2 

Fluidized Bed Feeder 

Lindberg 

3-Zone 

Furnaces 

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Carbon 

Trap 

SP 1 

SP 2 

SP 3 

Filter Reducing 

Furnace 

Pump 

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Dilution N2 

NO 

Air/H2O 

SO2 

SO2 /O2 

Analyzer 

Nafion 

Drier 

0

Carbon 

Trap 

Figure 5-8. Schematic of bench-scale flow reactor with methane burner (source: 

Reference 23). 

5-22

reducing furnace to convert any oxidized Hg to Hg0

. The reduction method is described 

elsewhere. 21 After the reducing furnace, the gas is dried using a Nafion gas sample dryer 

(Perma Pure, Inc.) and is finally sent to a Buck analyzer. 

Initial tests are conducted using nitrogen (N2) as the carrier gas with later tests performed 

in a flue gas from a methane flame. In the N2 carrier gas tests, industrial grade N2 (1 std. L/min) 

flows over a Hg0

 permeation tube that is housed in a permeation oven (VICI Medtronic’s, model 

190) to generate a Hg0

-laden gas stream. The N2/Hg0 stream is diluted with a second N2 stream 

(12 std. L/min) to the desired concentration before entering the top of the reactor. Other gases 

(SO2, NOX, O2, water vapor) can be blended into the N2 carrier gas in the mixing manifold. 

A fluidized-bed feeder is used to inject sorbent into the reactor. An inlet line of N2 is 

used to fluidize and carry the activated carbon to the reactor. The carbon feed rate is adjusted by 

varying the amount of N2 (0.2 to 0.5 std. L/min) entering the feeder. 

Because the UV analyzer used to detect Hg0

 is sensitive to particles, a filter is used to 

remove any carbon that may have been carried with the gas. Tests have been conducted to 

determine if carbon particles accumulate on the filter, as this would act like a packed bed and the 

reactor’s removal of Hg0 would be a combination of in-flight and filter (packed-bed) capture. In 

these tests, activated carbon was injected in the absence of Hg0, and a gas sample was pulled 

through the filter. After 1 minute, Hg0

 was added to the gas stream to see if there was a lag in 

the time it takes for the baseline to return. The results were the same as for a blank filter, 

suggesting that the filter does not have an effect on the results. 

The total flow through the reactor is typically 13 std. L/min, which gives residence times 

of 5.2, 11.5, and 17.7 s at ports SP1, SP2, and SP3, respectively. The velocity of the particles 

through the reactor is assumed to be the same as that of the gas flow since the terminal velocity 

of the particles is smaller than the velocity of the gas through the reactor by a factor of 3. 

Fluidized-bed Reactor. Another type of bench-scale reactor that is used to evaluate 

sorbents is a fluidized-bed reactor, 24 shown in Figure 5-9. The advantage of this type of reactor 

is the extended contact time between the sorbent and the Hg-laden gas. Bench-scale Hg removal 

tests can be performed on a fluidized-bed reactor apparatus. In a typical experiment, an 

Hg/NO/SO2 mixture, nitrogen, and dry air are metered through rotameters to produce 12 scfh of 

a dry simulated flue gas of 300 ppmv NOX, 600 ppmv SO2, 8 percent O2, and varying Hg 

concentrations. This gas is preheated to reaction temperature (80 °C) and humidified with 

vaporized water to an average 10.5 mol % water. The resulting wet simulated flue gas is then 

passed through a vertical reactor loaded with fluidized sorbent and sand, and then passed through 

a filter to remove any entrained particulate to protect the downstream equipment. The reactor 

and filter assembly are housed in an oven maintained at 80 °C. The test stand is equipped with a 

bypass of the reactor and filter assembly to allow for bias checks. Sorbent is exposed to 

simulated flue gas for 30 minutes. Water is removed from the spent flue gas with a NAFIONTM 

Dryer. Dry gas is then serially analyzed with Hg, SO2, and NOx continuous emission monitors 

(CEMs). 

5-23

Figure 5-9. Schematic of bench-scale fluidized-bed reactor system (source: 

Reference 24). 

5-24

5.4.2.2 Pilot-scale Systems 

Initial design and testing is done in bench-scale reactors. Once the fundamentals of Hg 

capture have been tested in a bench-scale system, the next step is to move up to a larger or pilotscale system. The main difference between bench- and pilot-scale systems involves testing 

sorbents in a more realistic situation involving coal combustion flue gas. This gas is generated in 

a pilot-scale combustor that contains a FF or ESP for particulate control. An example of this is 

the pilot-scale combustor operated by DOE (see Figure 7-3). This system burns coal at a rate of 

500 lb/hr and is equipped with a FF. Sorbents, such as activated carbon, are injected upstream of 

the PM control device. Mercury removal is determined by gas-phase sampling upstream of the 

sorbent injection point and downstream of the PM control device. 

Pilot-scale Hg removal can also be examined using a flue gas slipstream from a full-scale 

unit. An ESP or FF is attached to the slipstream and tested. A portable FF was developed by 

EPRI and called a COHPAC (COmpact Hybrid PArticulate Collector) unit. 26 This unit was 

tested for Hg removal using activated carbon. The URS Corporation (formerly Radian 

International) also developed a reactor system that uses a slipstream of actual flue gas withdrawn 

from a power plant to evaluate sorbents or catalysts in a fixed bed. 27 It should be noted that the 

slipstream reactor, which uses actual coal combustion flue gas, does not always produce the 

same Hg captive behavior of a sorbent that a similar laboratory system does using simulated flue 

gas. 28 It is important to perform pilot-scale tests prior to conducting full-scale tests to eliminate 

uncertainties and costly redesign of a process. With the data collected in the pilot-scale studies, 

full-scale tests can be initiated. 

5.4.2.3 Full-scale Tests 

Most of work to date in Hg control has been done in bench- or pilot-scale systems. These 

reduced-scale systems provide insight into many issues, but cannot fully account for the impacts 

that additional control technologies have on plant-wide equipment. Therefore, it is necessary to 

scale up and perform full-scale tests to document actual performance in a full-scale boiler. These 

tests are based on the results obtained in bench- and pilot-scale tests. Screening tests in benchand pilot-scale systems identify sorbents that are effective in capturing Hg. These sorbents are 

then tested in a full-scale coal-fired electric utility power plant to determine full-scale 

performance. 

Each full-scale unit is unique in terms of the pollution control equipment that is present 

as well as the operating conditions. Some of the factors that are evaluated include: 

• Type of particulate control equipment that is used (ESP or FF), 

• Impact of cake thickness and cleaning frequency in a FF, and 

•	 Removal of Hg by the fly ash in the system. Subbituminous coal ashes have been 

shown to be effective in capturing Hg. 

5-25

5.4.3 Research on Sorbent Evaluation 

5.4.3.1 Sorbent Evaluation Using Enhanced-flow Reactors 

A flow reactor was designed to simulate Hg0 capture through a duct or ESP and to obtain 

kinetic rate constants for the adsorption of Hg0 onto sorbents. Several researchers have predicted 

that, under certain conditions, dispersed-phase capture would be limited by mass transfer. 29,30 

Calculations were performed to determine the required operating conditions to minimize external 

mass transfer effects in the flow reactor, and experimental tests were performed to verify these 

calculations.23,31,32 The first test involved changing the diffusion coefficient by changing the gas 

in the system from N2 to helium (He) and to argon (Ar) while holding all other parameters 

constant (particle size, residence time, temperature, and Hg0 concentration). The diffusion 

coefficient increased by an order of magnitude by changing the gas from N2 to He. Using a 

lignite-based commercially available carbon (Norit FGD) at 100 °C and a Hg0

 concentration of 

86 ppb, Hg0

 removal was 6 percent at a carbon to Hg ratio (C:Hg) of 1,500:1 and increased to 30 

percent at a C:Hg of 8,000:1. Experimental results were similar when He was used as compared 

to N2. If external mass transfer were controlling, then a higher Hg0

 removal would have been 

obtained using He, since the mass transfer coefficient increased. 

A second test involved using two commercially available activated carbons, Norit FGD 

and Calgon WPL at 100 °C and 124 ppb Hg0 in dry N2. Removal for the FGD carbon ranged 

from 9 percent (C:Hg=2200:1) to 23 percent (C:Hg=6400:1). Removal for the WPL carbon 

ranged from 11 percent (C:Hg=340) to 94 percent (C:Hg=5000:1). If dispersed-phase capture in 

the flow reactor were film-mass-transfer limited, the two activated carbons would have removed 

similar amounts of Hg0 at a given C:Hg, assuming each carbon had sufficient Hg0 capacity. 

The flow reactor has been used to examine the effect of temperature, particle size, 

residence time, carbon type, and gas composition on Hg0

 removal.31-33 The effect of particle 

size on Hg0

 removal for Darco FGD at 100 °C and a Hg0 concentration of 86 ppb is shown in 

Figure 5-10. Several particle sizes (4-8, >8-16, >16-24, and >24-44 μm) were injected into the 

flow reactor at C:Hg ratios ranging from 2000 to 11,000:1. The gas was sampled at SP2, 

resulting in a gas contact time of 8.4 s. Figure 5-11 shows that greater Hg0 removal is achieved 

by increasing the feed rate and by decreasing the particle size. At a C:Hg of 5000:1, a 5 percent 

reduction was obtained with the >24-44 μm size fraction as compared to a 20 percent reduction 

with the 4-8 μm fraction. Thus by using a smaller particle a higher removal can be obtained at a 

given C:Hg. Both external and internal mass transfers are dependent on particle size: the effect 

of mass transfer increases with an increase in particle size. 

5.4.3.2 Sorbent Evaluation Using Packed-bed Reactors 

Recent bench-scale studies at the University of North Dakota=s Energy and 

Environmental Research Center (UND/EERC) have focused on the interactions of gaseous flue 

gas constituents on the adsorption capacity of activated carbon for Hg.34 Bench-scale studies 

were performed using a fixed bed of carbon. The tested carbon was a commercially available 

lignite-based activated carbon (LAC) commercially known as Darco FGDTM from Norit 

5-26

Figure 5-10. Effect of particle size on adsorption for Darco FGD at 100 °C, 

86 ppb Hg0

 concentration, and 8.4 s contact time (source: Reference 31). 

5-27

Americas, Inc. A simulated flue gas containing a nominal concentration of 15 μg/Nm3

 of 

gaseous Hg0 was passed through the fixed bed of carbon. In addition to Hg, the baseline test gas 

contained 6 percent O2, 12 percent CO2, 8 percent H2O, and the balance N2. Various flue gas 

constituents (SO2, HCl, NO, and NO2) were added individually and in combination to the 

baseline test gas to determine the effects of flue gas constituents on Hg adsorption. Temperature 

effects were also examined. Table 5-3 shows the various compositions of gas tested. 

For each adsorption test, a Hg CEM was used to monitor total or elemental Hg. 

Measurements were alternated between the inlet and outlet locations of the test bed. For a given 

test, measurements took place primarily at the outlet location; however, occasionally the inlet 

location was tested to confirm that a constant concentration of gaseous Hg0

 was entering the test 

bed. For each test, the analyzer was set to measure total gaseous Hg at the outlet; however, 

occasionally the analyzer was set to measure only gaseous Hg0 at the outlet. The purpose of 

measuring only gaseous Hg0 at the outlet was to determine if any incoming gaseous Hg0 was 

being oxidized by carbon in the bed (evident if the concentration of gaseous Hg0

 in the outlet gas 

was less than the concentration of total gaseous Hg in the outlet gas). 

For adsorption to take place (assuming attractive forces exist between a particular 

gaseous specie and sorbent), the adsorbing specie must have sufficient time to reach the surface 

of a sorbent and diffuse into its pores (where most adsorption takes place). If any of the 

adsorbing specie in a gas stream passing through a fixed bed of sorbent cannot reach the surface 

of the sorbent (mainly its pore surfaces), the specie will pass through the bed unadsorbed. 

Researchers conducted preliminary tests to show that the gaseous Hg in the test gas had 

sufficient time (under the conditions tested) to contact the sorbent and to diffuse into its pores. 

Proving this point was important since some of the adsorption tests showed immediate 

breakthrough of Hg in the outlet gas. In these cases, immediate breakthrough was not due to 

insufficient contact time but rather the carbon's inability to adsorb all of the gaseous mercury. 

Figure 5-11 shows an example of the sampling and measurements taken during testing of 

the baseline test gas with HCl, NO2, and SO2 (as noted in the graph, SO2 was added to the 

baseline test gas 2.5 hours after the start of the test). Except where noted, the Hg concentrations 

in Figure 5-11 are those in the outlet test gas and represent concentrations of total gaseous Hg. 

Mercury concentrations in the graph are quantified as a percentage of the inlet concentration of 

gaseous Hg0

. The percentage of Hg in the outlet test gas is called percent breakthrough. Figure 

5-11 indicates that the analyzer sampled and measured total gaseous Hg in the outlet gas at all 

times during testing except at approximately 5.2 hours, at which time the analyzer sampled and 

measured Hg in the inlet gas. At approximately 5.15 hours the analyzer measured gaseous Hg0 

instead of total gaseous Hg in the outlet test gas; the drop in the concentration curve at this time 

from approximately 150 percent to zero percent indicates that Hg in the outlet test gas consisted 

entirely of gaseous Hg2+. Thus, while only gaseous Hg0

 was in the test gas entering the carbon 

bed, the Hg0 was oxidized to Hg2+ as it passed through the bed. (Why some of the outlet 

concentrations of total gaseous Hg exceeded 100 percent of the inlet Hg concentration for this 

run is explained further on in this section.) 

5-28

Table 5-3. Composition of test gases to simulate coal combustion flue gas used 

for UND/EERC bench-scale study (source: Reference 34). 

SO2 ppmv HCl ppmv NO ppmv NO2 ppmv 

Baseline test gas a 

0 0 0 0 

Baseline test gas plus 1 additional gas 

1600 0 0 0 

0 50 0 0 

0 0 300 0 

0 0 0 20 

Baseline test gas plus 2 additional gases 

1,600 50 0 0 

1,600 0 300 0 

1,600 0 0 20 

0 50 0 20 

0 50 300 0 

0 0 300 20 

Baseline test gas plus 3 additional gases 

1,600 50 300 0 

1,600 50 0 20 

1,600 0 300 20 

0 50 300 20 

Baseline test gas plus 4 additional gases 

1600 50 300 20 

(a) Prior to adding SO2

, HCl, NO, and/or NO2, the baseline test gas contained 15 μg/nm3 of gaseous Hg0; 

6 percent O2

; 12 percent CO2; 8 percent H2O; and the balance N2. 

5-29

Figure 5-11. Example of the sampling and measurements taken during testing of 

the baseline test gas with HCl, NO2, and SO2. (source: Reference 34). 

5-30

Graphs of the adsorption tests with the 15 remaining gases in Table 5-3 can be found 

elsewhere; 13 the cited graphs are similar to Figure 5-11 in that Hg concentrations (primarily 

outlet concentrations of total gaseous Hg) are plotted versus the time of the adsorption test. 

The following summarizes the detailed test results: 

•	 When the sorbent was exposed to the baseline gas only, the sorbent initially captured 

10 to 20 percent of the incoming gaseous Hg0; the rest of the Hg passed through the 

bed (i.e., was not adsorbed). 

•	 When the sorbent was exposed to SO2 in addition to the baseline gas, Hg capture 

improved slightly. 

•	 Under exposure of the sorbent to HCl, NO, or NO2 added one at a time to the baseline 

gas, the Hg capture of the sorbent improved to 90 to 100 percent. 

•	 An apparently significant interaction between SO2 and NO2 gases and the sorbent 

caused a rapid breakthrough of Hg as well as conversion of the Hg to its volatile 

oxidized form. This effect occurred at both 107 and 163 oC (225 and 325 oF) and with 

or without the presence of HCl and NO. 

•	 In the presence of all four acid gases (SO2, HCl, NO, and NO2), rapid breakthrough 

and oxidation of the Hg occurred at both 107 and 163 oC (225 and 325 oF). This 

suggests that the interactions between the sorbent and NO2 and SO2 gases produced 

poor sorbent performance, which may be a major effect. This may be likely to occur 

over a variety of conditions typical of coal-fired electric utility boilers, and represents 

a hurdle that must be overcome to achieve effective Hg control by carbon adsorption. 

The UND/EERC is continuing to investigate the interactions of gaseous flue gas 

constituents on the adsorption capacity of activated carbon for Hg. In addition, other types of 

sorbents are being developed and investigated under similar simulated flue gas conditions. Other 

gaseous flue gas constituents are also being examined to assess their impact on the adsorption of 

Hg. 

5.4.3.3 Sorbent Evaluation Using Fluidized-bed Reactors 

Under DOE=s Small Business Innovative Research (SBIR) Program, Environmental 

Elements Corporation (EEC) has been developing a circulating fluidized bed (CFB)

24 to promote 

agglomeration of fine PM, allowing for its capture in an ESP. In addition, a single injection of 

iodide-impregnated activated carbon was added to the fluidized bed to adsorb gaseous Hg. High 

residence time, as a result of particle recirculation, allows for effective utilization of the carbon 

and high collection of the fine particles. Laboratory tests with heated air indicate that, with a high 

density of fly ash at a 4-second residence time within the bed, fine particle emissions are reduced 

by an order of magnitude. 

5-31

Results from the laboratory-scale testing indicate that spiked gaseous Hg0

 was 

significantly reduced when passed through the fluidized bed of fly ash (50 percent Hg removed) 

with a further reduction to essentially zero, when activated carbon was injected into the bed 

(25 μg/m3 to zero) at 110 oC (230 oF). The iodide-impregnated activated carbon was fully 

utilized after greater than 2 hours within the bed. An adsorption capacity was calculated to be 

770 μg/g for the carbon and 480 μg/g for the bed of ash. Other field tests were conducted at 

Public Service Electric and Gas= Mercer Station with similar results.24 

5.5 Sorbent Development 

The implementation of an effective and efficient Hg control strategy using sorbent 

injection requires the development of low-cost and efficient Hg sorbents. Of the known Hg 

sorbents, activated carbon and calcium-based sorbents have been the most actively studied. 

However, improved versions of these sorbents and new classes of Hg sorbents can be expected, 

as this is still a very active field. 

5.5.1 Powdered Activated Carbons 

Activated carbons have been extensively studied for their Hg capture capability. 

Activated carbon is the reference sorbent for Hg control in municipal waste combustors. Many 

factors may affect the adsorptive capability of the activated carbon sorbent. These include the 

temperature and composition of the flue gas, the concentration of Hg in the exhaust stream, and 

the physical and chemical characteristics of the activated carbon (or functionalized/impregnated 

carbon). Some specific efforts at understanding these effects are given below. 

5.5.1.1 Effects of Temperature, Mercury Concentration, and Acid Gases 

The effects of bed temperature, Hg concentration, presence of acid gases (HCl and SO2), 

and presence of water vapor on the capture of Hg0 and HgCl2 by thermally activated carbons 

(FGD and PC-100) and Ca-based sorbents [Ca (OH) 2 and a mixture of Ca(OH) 2 and fly ash] 

were examined in a fixed-bed, bench-scale system.

21 Sorption studies indicated an abundance of 

HgCl2 adsorption sites in calcium-based sorbents. Increasing the HgCl2 concentration increased 

its uptake, and increasing the bed temperature decreased its uptake. Gas-phase HgCl2 

concentration had a very strong effect on its adsorption, while bed temperature had a small 

influence on adsorption. The observed temperature and concentration trends suggest that the 

process is adsorption-controlled and that the rate of HgCl2 capture is determined by how fast 

molecules in the vicinity of the active sites are being adsorbed. Mixtures of Ca(OH)2 and fly ash 

with 7 times higher surface area than Ca(OH)2 and a totally different pore size distribution 

exhibited identical HgCl2 capture to that of Ca(OH)2. The presence of acid gases (1000 ppm SO2 

and 50 ppm HCl) drastically decreased the uptake of HgCl2 by Ca(OH)2. The inhibition effect of 

SO2 was more drastic that HCl, and essentially controlled the HgCl2 uptake. It was hypothesized 

that the inhibition effect is due to competition between these acid gases and HgCl2 for the 

available alkaline sites. 

5-32

Sorption studies further indicated that the available active sites for capturing Hg0

 in the 

activated carbons are limited, suggesting that it is more difficult to control Hg0 emissions than 

HgCl2 emissions. Increasing the Hg0

 inlet concentration and decreasing the bed temperature 

increased the saturation capacities of the activated carbons, the time needed to reach this 

capacity, and the initial rate of Hg0 uptake. Unlike HgCl2 capture by Ca(OH)2, bed temperature 

had a very strong effect on the Hg0

 adsorption by the activated carbons, and gas-phase Hg0 

concentration had a small influence on such adsorption. PC-100, with twice the surface area of 

FGD, consistently exhibited higher saturation capacities (3-4 times higher) than FGD. The 

presence of acid gases had a positive effect on the capture of Hg0

 by a lignite-coal-based 

activated carbon (FGD) and had no influence on Hg0 capture by a bituminous-coal-based 

activated carbon (PC-100). This difference was related to a higher concentration of Ca (acid gas 

sorbent) in FGD. It appears that adsorption of these acid gases by FGD creates active S and Cl 

sites, which are instrumental in capturing Hg0, through formation of S-Hg and Cl-Hg bonds in 

the solid phase (chemisorption). These results indicate that the optimum region for the control of 

Hg0 by injection of activated carbon is upstream of the acid gas removal system. 

5.5.1.2 Role of Surface Functional Groups 

The content of oxygenated acidic and alkaline surface functional groups (SFGs) on the 

surface of two activated carbons was manipulated to investigate their role in Hg0

 and HgCl2 

capture.35 Acidic SFGs on the surface of activated carbons were neutralized by a variety of 

alkaline washes. The alkaline-treated activated carbon showed no enhancement in Hg0

 and 

HgCl2 capture, thus indicating that acidic SFGs play no role in capturing Hg species. The 

alkaline SFGs content was increased by a thermal treatment process. The thermally treated 

activated carbons did not exhibit any improvement with regard to their Hg0 and HgCl2 capture 

capabilities as compared to the untreated ones. The activated carbons were then treated with a 

very dilute HCl solution to decrease their alkaline SFGs content. The HCl-treated activated 

carbon showed a very significant improvement in its Hg0 and HgCl2 capture capabilities. This 

observation was contrary to the initial hypothesis that alkaline sites are needed to capture acidic 

HgCl2 from the flue gas. It was then hypothesized that HCl treatment increases the number of 

active surface chlorine sites, which subsequently enhance Hg0 and HgCl2 capture. An analytical 

technique, Energy-Dispersive X-ray Spectroscopy (EDXS), was used to quantify surface Cl sites. 

A strong correlation between the increased amount of surface Cl and Hg0/HgCl2 uptake 

enhancement was observed. The role of SFGs containing Cl atoms in providing Hg0/HgCl2 

active sites was established. Future investigation using SEM/EDXS and Fourier Transform 

Infrared (FTIR) will focus on understanding the nature of Cl bonds on the surface of carbon, so 

that more effective Hg species sorbents can be manufactured. 

5.5.1.3 In-flight Capture of Mercury by a Chlorine-impregnated Activated Carbon 

Activated carbon duct injection seems to be the most promising Hg control technology 

for coal-fired electric utility boilers equipped with ESPs. In this technology, the injected 

activated carbon removes Hg only while contacting the flue gas during very limited sorbent/gas 

contact time (<3 seconds). Prior investigations have shown that very high, and rather costly, 

carbon-to-Hg weight ratios (>50,000) are needed to achieve adequate Hg removal. In order to 

5-33

reduce the operating cost of the carbon injection process, either a more efficient sorbent that can 

operate at a lower carbon-to-Hg weight ratio or a lower-cost activated carbon (or possibly both) 

are required. In this study33, a cost-effective Cl-impregnation process was successfully 

implemented on an inexpensive virgin activated carbon. The Cl-impregnated carbon was 

produced in a 5 pound large batch, and its in-flight Hg0 removal efficiency was evaluated in a 

flow reactor (as previously discussed in Section 5.4.2.1) with gas/solid contact times of 3 to 

4 seconds. The Hg0 removal efficiency of more than 80 percent was obtained in a flue gas 

containing the effluent of natural gas combustion doped with coal combustion levels of NOX and 

SO2 at carbon-to-Hg weight ratios of about 3000. Hg0 removal was rather insensitive to the 

adsorption temperature in the range of 100-200 oC. Cost analysis showed that this Climpregnation process can produce a very active and cost-effective activated carbon that can be 

used as a practical sorbent in a duct injection control technology in ESP-equipped coal-fired 

electric utility boilers. Preliminary cost estimates indicated that approximately 53 percent 

reduction of the total annual cost of Hg control could be possible when using Cl-impregnated 

FGD in lieu of virgin activated carbon. Future investigations would be focused on evaluating the 

Cl-impregnated activated carbon in a pilot-scale, 21-kW (90,000-Btu/hr) refractory-lined, 

furnace fired with pulverized coal.33 

5.5.2 Calcium-based Sorbents 

Work conducted by EPA and ARCADIS Geraghty & Miller, Inc. [funded by the Illinois 

Clean Coal Institute (ICCI)] indicates that the injection of calcium-based sorbents into flue gas 

can result in significant removal of Hg.36,37 Researchers examined the high-temperature/shortgas-phase residence time removal of Hg using injection of lime while burning an Illinois #6 coal 

in a pilot-scale combustor. The lime was injected as a slurry at a calcium-to-sulfur (Ca:S) ratio 

of 2.0 mol/mol at 968 oC (1775 oF). Under these conditions, 77 percent of the total Hg was 

removed from the flue gas (Table 5-4). Based on these results, they concluded, "injection of 

lime in the high temperature regions of coal-fired processes upstream of air pollution control 

systems can efficiently transfer Hg from the gas to the solid phase." Summaries of work follow. 

5.5.2.1 Capture of Low Concentrations of Mercury Using Calcium-based Sorbents 

The capture of Hg0

 and mercuric chloride (HgCl2), the Hg species identified in coal flue 

gas, by three types of calcium-based sorbents differing in their internal structure, was examined 

in a packed-bed, bench-scale study under simulated flue gas conditions for coal-fired electric 

utility boilers.38 The results obtained were compared with Hg0

 and HgCl2 capture by an 

activated carbon (FGD) under identical conditions. Tests were conducted with and without SO2 

to evaluate the effect of SO2 on Hg0 and HgCl2 control by each of the sorbents. 

The Ca-based sorbents showed insignificant removal of Hg0

 in the absence of SO2. 

However, in the presence of SO2, Hg0 capture was enhanced for the three Ca-based sorbents. It 

was postulated that the reaction of hydrated lime with SO2 would result in pore mouth closure as 

evidenced by the sharp drop in the SO2 removal rate after the initial 10 minutes of exposure. 

Despite the loss of internal surface area, the relatively high uptake of Hg0, observed for these 

sorbents in the presence of SO2, suggests that Hg0 and SO2 do not compete for the same active 

5-34

Table 5-4. Mercury removal by lime sorbent injection as measured by EPA benchscale tests (source: Reference 36). 

Test Total Hg Concentration, 

μg/dscm 

Total Gaseous Hg, 

percent 

Total Particle-bound Hg, 

percent 

Baseline 5.7 100 0 

Lime sorbent injection 8.0 23 77 

5-35

sites, and that the sites for Hg0

 capture are influenced positively by the presence of SO2. 

Moreover, the capture of Hg0 in the presence of SO2 increased with sorbent surface area and 

internal pore structure. 

Conversely, the three Ca-based sorbents showed decreased removal of HgCl2 in the 

presence of SO2. In the absence of SO2, roughly 25 percent of the incoming HgCl2 was captured. 

The alkaline sites in the Ca-based sorbents were postulated to be instrumental in the capture of 

acidic HgCl2. SO2 not only competed for these alkaline sites but also, as mentioned, likely 

closed pores with subsequent reduction in accessibility of the interior of the Ca-based sorbent 

particles to the HgCl2 molecules. 

It was hypothesized that the capture of Hg0 in the presence of SO2 may occur through a 

chemisorption mechanism, while the nature of the adsorption of HgCl2 molecules may be 

explained through a physisorption mechanism. The effect of temperature studies further 

supported this hypothesis. Increasing the system temperature caused an increase in Hg0 uptake 

by the sorbents in the presence of SO2. However, the increase in temperature resulted in a 

significant decrease in the HgCl2 uptake in the absence or presence of SO2. Increased sorbent 

surface area and internal pore structure had no observable effect on HgCl2 capture in the 

presence of SO2. 

With the relatively large quantities of Ca needed for SO2 control at coal-fired electric 

utility boilers, the above results suggest that Ca-based sorbents, modified by reaction with fly 

ash, can be used to control total Hg emissions and SO2 cost effectively. The most effective 

calcium-based sorbents are those with significant surface area (for SO2 and HgCl2 capture) and 

pore volume (for Hg0 capture). 

5.5.2.2 Simultaneous Control of Hg0, SO2, and NOX by Oxidized-calcium-based Sorbents 

Multipollutant sorbents have been developed that can remove both Hg0 and Hg+2 as 

effectively as FGD activated carbon in fixed-bed simulations of coal-fired electric utility boiler 

flue gas at 80 o

C.39 Oxidant-enriched, calcium-based sorbents proved far superior to activated 

carbon with respect to SO2 uptake on the same fixed-bed simulations. These oxidant-enriched, 

calcium-based sorbents also performed better with respect to NOX and SO2 uptake than baseline 

lime hydrates for fixed- and fluid-bed simulations at 80 oC. 

Preliminary economic analyses suggest that silicate sorbents with oxidants are 20 percent 

of the cost of activated carbon for Hg removal, while oxidant-enriched lime hydrates offer 

reduced, but significant savings. Credits for SO2 and NOX increase the savings for multipollutant 

sorbents over activated carbon. 

The apparent superiority of multipollutant lime and silicate hydrates enhanced with 

oxidants has been confirmed at conditions typical of gas-cooled, semi-dry adsorption processes 

on boilers; performance of sorbents at higher-temperature conditions of duct sorbent injection 

technologies remains to be evaluated. Planned field evaluations of both semi-dry adsorption and 

5-36

duct sorbent injection will allow better economic and performance comparisons of activated 

carbon sorbents to that of oxidant-enriched lime and silicate hydrates. 

A technology for the efficient capture of Hg through in furnace injection of a calciumbased sorbent has been developed by McDermott Technologies recently. A discussion of the 

full-scale tests of the technology is presented in Chapter 7. 

5.5.3 Development of Low-cost Sorbents 

Since 1995, EPRI has supported a sorbent development program for removal of Hg 

emissions from coal-fired electric utility power plants at several research organizations including 

Illinois State Geological Survey (ISGS), University of Illinois (UI), and URS Corporation. The 

development of effective Hg sorbents that can be produced at lower costs than existing 

commercial activated carbons is the main objective of the program. The development efforts 

were documented in three EPRI Reports.40-42 A significant number of sorbents were derived 

from a variety of precursor materials, including coal, biomass, waste tire, activated carbon fibers, 

fly ash, and zeolite, through this work. Different preparation methods were used to determine 

the effects of sorbent properties, such as pore size distribution, pore volume, surface area, 

particle size, and sulfur content, on the ability to remove Hg. The effects of different processing 

methods, including steam activation, grinding, size-fractionation, and sulfur-impregnation, on 

sorbent performance were also investigated in laboratory tests. Promising low-cost sorbents 

were further evaluated in actual flue gas at several full-scale coal-fired electric utility power 

plants. 

Results of the EPRI sorbent development work showed that effective sorbents can be 

prepared from inexpensive precursor materials using simple activation steps. One notable 

example is that a char produced from corn fiber, a by-product from a corn-to-ethanol production 

process, showed a Hg0

 adsorption capacity over twice that of the commercial FGD carbon 

sorbent, after the char was activated in CO2 at 865 o

C for 3.5 hours.40 Inactivated corn char had 

no capacity for HgCl2, and only a low capacity for Hg0. It appears that the composition of the 

flue gas has a significant effect on the Hg adsorption capacities of the coal-derived activated 

carbons.41 The EPRI-funded study found that the presence of acid gases (SO2 and HCl) inhibits 

Hg0

 and HgCl2 adsorption for both lignite- and bituminous-coal-derived activated carbons. 

However, research conducted by EPA showed that the presence of acid gases enhanced the 

capture of Hg0 by a lignite activated carbon and had no influence on the adsorption by a 

bituminous-coal-derived activated carbon.21 In a later more extensive follow-up study funded by 

EPRI and ICCI, the effects of acid gases on the HgCl2 and Hg0 adsorption capacities of activated 

carbons were found to vary, depending on the precursor materials and characteristics of the 

carbons.43 For example, carbons derived from tire and corn fiber had much higher HgCl2 and 

Hg0 adsorption capacities when they were tested in a high-SO2 concentration flue gas simulating 

the combustion of Eastern bituminous coals compared to those when they were tested in the lowSO2 concentration flue gas simulating Western subbituminous coal combustion. Complex 

interactions occurring between the characteristics of the carbons and the acid gases may lead to 

the observed varying effects of the acid gases on Hg adsorption behaviors of the carbon sorbents. 

5-37

More fundamental research is needed to understand and predict the effects of acid gases on the 

performance of sorbents derived from different precursor materials. 

The most effective sorbents were obtained by the sulfur-impregnation of activated 

carbons derived from waste material and carbon fibers.40 Researchers at the University of 

Pittsburgh demonstrated that impregnation of heteroatoms such as sulfur44 and chloride45 is an 

effective method to improve the vapor-phase Hg adsorption capacities of activated carbons. It 

has been suggested that sorbent-impregnation studies should focus on highly microporous 

sorbents since the presence of active surface functional groups, sulfur as an example, in the 

micropores through impregnation is likely to provide the most reactive sites for Hg adsorption 

from coal combustion flue gas.19 They stressed that the micropore surface area of sorbent is an 

important physical property for vapor-phase Hg adsorption. Most of the commercial activated 

carbons are used for liquid-phase applications and contain a large mesopore surface area, in 

addition to micropores, that are less effective for adsorption of ppb levels of Hg from coal 

combustion flue gases. EPA researchers46 have observed the importance of active functional 

groups in the micropores for vapor-phase Hg adsorption. After treating an activated carbon with 

an aqueous sulfuric solution, they found that most of the mesopores of the carbon are filled with 

water due to the presence of the hydroscopic sulfuric acid, and the carbon becomes a highly 

microporous sorbent. The Hg0 adsorption capacity of the sulfuric-acid-treated carbon is much 

higher than that of the as-received carbon due to the presence of the active sulfuric acid 

functional groups in the micropores of the treated carbon. 

The most recent research conducted by ISGS, UI, and URS Corporation showed that 

relatively low surface area microporous biomass-based carbon sorbents, such as those derived 

from pistachio nut shells and from corn fiber, are as effective as the commercial FGD carbon 

sorbent for Hg adsorption.43 They found that the Hg adsorption capacities of the biomass-based 

carbon sorbents, which contained negligible (0.09 percent) sulfur, are comparable to those of the 

coal- and tire-derived carbons that have substantial sulfur contents (0.98 to 2.1 percent). The 

biomass-based carbon sorbents also have very little chlorine functional groups. It appears that 

more oxygen, another heteroatom, remained in the biomass-based carbon sorbents after the 

pyrolysis of the oxygen-rich biomass from the carbon-making process contributing to the 

significant Hg adsorption capacities of such sorbents. It has been suggested recently by EPA 

researchers

47 that the Hg0

 adsorption capacity of an activated carbon is correlated to the 

concentrations of the oxygen functional groups of the carbon. They changed the oxygen 

functional group concentrations of a carbon by heating the carbon sample to 900 oC in an inert 

atmosphere to remove the functional groups. Also, more oxygen functional groups were 

introduced to the carbon sample by oxidizing the carbon sample in an aqueous nitric acid 

solution. They suggested that lactone and carbonyl groups introduced during the oxidization of 

the carbon by nitric acid treatment might be the active sites for Hg0 adsorption. 

5.5.4 Modeling of Sorbent Performance 

The Hg adsorption data produced from bench-scale tests provide a relative indication of 

performance for different sorbents; however, the actual Hg removal performance of the sorbents 

in full-scale systems cannot be predicted based on bench-scale results alone. To predict Hg 

5-38

removal in full-scale systems, mass transfer considerations have to be combined with laboratory 

data. Such an approach was applied by by EPRI recently to develop a model for predicting 

sorbent performance in full-scale systems.48 The model is also capable of determining when 

mass transfer limits Hg removal and when it is limited by sorbent capacity. By incorporating the 

appropriate mass transfer expressions, the model relates the adsorption characteristic data for a 

given sorbent tested under a given set of flue gas conditions in the laboratory to the expected Hg 

removal performance across a FF or an ESP. 

Results of the sorbent performance predicted by the model agree reasonably well with 

data of the same sorbent measured by pilot-scale tests for both ESP and FF applications. The 

pilot-scale facilities used for the tests consisted of an ESP with a 160-acfm wire-tube ESP, and a 

FF with a 4000-acfm transportable pulse-jet FF operating in the COHPAC configuration. 

Results of the pilot-scale tests and modeling both showed that a carbon sorbent with 15 μm 

diameter and 1000 μg/g Hg adsorption capacity achieved about 80 percent Hg removal in a FF 

operated at about 140 o

C (280 oF) with 3 lb/Macf sorbent injection rate and cleaning cycle of 45 

min. However, test and modeling results both showed that Hg removal decreases to less than 20 

percent when the same sorbent was injected upstream of an ESP under conditions similar to the 

above. 

Laboratory tests which have been conducted to evaluate the adsorption characteristics of 

potential sorbents for Hg removal seem to suggest that reactivity of the sorbent might be more 

important than its equilibrium adsorption capacity for sorbent injection. Currently, an ESP is 

more widely used than a FF as a PM control device for coal-fired electric utility boilers in the 

United States. Sorbent reactivity is the important parameter determining Hg removal when 

injecting a powdered sorbent upstream of an ESP, where adsorption of Hg occurs mainly inflight with short residence times (about 2 seconds). When injecting sorbent upstream of a FF, 

additional Hg removal can occur due to the presence of accumulated sorbent in the filter cake, 

resulting in improved mass transfer and sorbent utilization. Sorbent capacity becomes a more 

important parameter than reactivity in such cases. 

5.6 Capture of Mercury in Wet FGD Scrubbers 

5.6.1 Wet Scrubbing 

Mercuric chloride is readily soluble in water. Thus, the oxidized fraction of Hg vapors in 

flue gas is efficiently removed when a power plant is operated with a wet scrubber for removing 

SO2. The elemental fraction, on the other hand, is insoluble and is not removed to any 

significant degree. A DOE-funded study49 conducted by CONSOL, Inc. showed that the nominal 

Hg removal for wet FGD systems on units firing bituminous coals is approximately 55 percent, 

with the removal of Hg2+ between 80 and 95 percent. Studies conducted by McDermott 

Technologies, Inc. at its 10-MWe research facility suggested a possible conversion of the Hg2+ 

captured in the scrubbing media and reemissions as Hg0.

50 McDermott Technologies performed 

follow up tests to investigate the use of additives to prevent the conversion of adsorbed Hg2+ to 

gaseous Hg0

.

51 These tests are described in more detail in Chapter 7. 

5-39

5.6.2 Oxidation 

The challenge to Hg removal in wet scrubbers for SO2 is to find some way to oxidize the 

elemental Hg vapor before it reaches the scrubber or to modify the liquid-phase of the scrubber 

to cause oxidation to occur there. 

URS Radian International has conducted various laboratory and field-test studies to 

investigate adsorption and catalytic oxidation of gaseous Hg0

 in coal-fired electric utility flue 

gas. The results of the bench-scale testing are discussed below. The additional pilot- and fullscale testing conducted by URS Radian International are discussed in Chapter 7. 

Different compositions of catalysts and fly ashes were tested in a bench-scale, fixed-bed 

configuration to identify materials that adsorb and/or oxidize gaseous Hg0.

52 Mixing sand with a 

particular catalyst or fly ash created fixed beds of sorbents. A simulated coal-fired electric utility 

boiler flue gas containing gaseous Hg0 was then passed through the bed. The flue gas was tested 

at the inlet and outlet of each sorbent bed to determine Hg adsorption and/or oxidation across the 

bed. Table 5-5 lists the simulated flue gas conditions and the most active catalysts and fly ashes 

identified during testing for oxidation of gaseous Hg0. 

Figure 5-12 is an example of the adsorption/oxidation of gaseous Hg0 with time by one of 

the iron catalysts in Table 5-5. In this figure, the oxidation of gaseous Hg0 increases as the 

breakthrough of Hg from the catalyst bed increases (breakthrough is quantified as a percentage 

of the incoming Hg). At 100 percent breakthrough when the catalyst is no longer adsorbing any 

of the incoming Hg (i.e., the catalyst has reached its equilibrium adsorption capacity for the 

incoming Hg0), all of the Hg0 passing through the bed is being oxidized to Hg2+. 

Figure 5-13 shows adsorption/oxidation results for all of the catalysts in Table 5-5. 

Adsorption and oxidation of gaseous Hg0 was greater at 149 oC (300 oF) than at the higher 

temperature of 371 o

C (700 oF). The adsorption and oxidation activity of the activated carbon 

was considered the highest among the materials tested because a lower mass was utilized during 

the tests compared to the other materials. 

Figure 5-14 shows the adsorption/oxidation results for the fly ashes from Table 5-5. Like 

the catalysts, the fly ashes showed higher adsorption and oxidation of gaseous Hg0

 at 149 oC 

(300 oF) than at 371 oC (700 oF); for this reason, only the lower temperature results are shown in 

Figure 5-14. The subbituminous and bituminous coal fly ashes generally showed higher 

oxidation rates than the lignite coal fly ashes. As seen, the #2 bituminous coal fly ash had 

varying adsorption and oxidation rates depending upon where the fly ash samples were collected. 

Samples collected from the hoppers of the first field of the ESP indicated lower oxidation of 

gaseous Hg0 but a higher adsorption of Hg compared to the finer fly ash collected in the fifth and 

final field of the ESP. Although not shown, fly ash captured by a cyclone in the Hg speciation 

sampling train indicated a higher adsorption but no oxidation of the gaseous Hg0

. Fly ash from 

the fifth field of the ESP indicated the highest rate of oxidation and the lowest size-fractionated 

particles. This may be associated with the size differences of the fly ash and/or the surface 

5-40

Table 5-5. Simulated flue gas conditions with the most active catalysts and fly 

ashes indicated for oxidation of gaseous Hg0

 to gaseous Hg2+(source: 

Reference 52). 

Parameter Baseline 

Conditions 

Most Active 

Catalysts 

Most Active 

Fly Ashes 

Fixed-bed Temperature 300 and 700 oF Fe #1 (1000 mg) Subbituminous #1 

Hg0 Injection 45 to 60 μg/Nm 3 Pd #1 (1000 mg) Subbituminous #2 

Oxygen 7 percent Fe #2 (200 mg) Bituminous #1 

Carbon Dioxide 12 percent Fe #3 (200 mg) Bituminous #2-Field 1a 

Moisture 7 percent NOX Catalysts 

(1000 mg) Bituminous #2-Field 5a 

Sulfur Dioxide 1600 ppmv Fe #4 (1000 mg) Bituminous #3 

HCl 50 ppmv Pd #2 (1000 mg) Lignite #1 

Gas Flow Rate 1 L/min Carbon (20 mg) Oil-Fired #1 

(a) Fly ash collected at the first and fifth field of the ESP at the EPRI ECTC. 

5-41

Figure 5-12. Adsorption and subsequent oxidation of gaseous Hg0

 in a simulated 

flue gas at 149 oC (300 oF) (source: Reference 52). 

5-42

Figure 5-13. Adsorption and oxidation of gaseous Hg0

 by various catalysts at 

149 o

C (300 oF) and 371 oC (700 oF) (source: Reference 52). 

5-43

Figure 5-14. Adsorption and oxidation of gaseous Hg0

 by various coal fly ashes at 

149 oC (300 oF) and 371 oC (700 oF) (source: Reference 52). 

5-44

chemistry of the finer fly ash being enriched in trace metals or other condensed or adsorbed 

compounds from the flue gas during the combustion of the bituminous coal. 

5.6.3 Gas and Liquid Oxidation Reagents 

Argonne National Laboratory has been investigating the use of oxidizing agents that 

could potentially convert gaseous Hg0

 into more soluble species that would be absorbed in wet 

FGD systems.53 Current research is focused on a process concept that involves introduction of 

an oxidizing agent into the flue gas upstream of the scrubber. The oxidizing agent employed is 

NOXSORBJ, which is a commercial product containing chloric acid and sodium chlorate. 

When a dilute solution of this agent was introduced into a gas stream containing gaseous Hg0

 and 

other typical flue-gas species at 300 oF (149 oC), it was found that nearly 100 percent of the 

gaseous Hg0 was removed from the gaseous phase and recovered in process liquids. A 

significant added benefit was that approximately 80 percent of the NO was removed at the same 

time. Thus, the potential exists for a process that combines removal of SO2, NO, Hg0

, and, 

perhaps, PM. 

Continuing laboratory research efforts are acquiring the data needed to establish a mass 

balance for the process. In addition, the effects of such process parameters as reagent 

concentration, SO2 concentration, NO concentration, and reaction time (residence time) are being 

studied. For example, SO2 has been found to decrease slightly the amount of gaseous Hg0 

oxidized while appearing to increase the removal of NO from the gaseous phase. Preliminary 

economic projections, based on the results to date, indicate that the chemical cost for NO 

oxidation could be less than $5,000/ton NO removed; while for gaseous Hg0 oxidation, it would 

be about $20,000/lb Hg0

 removed. These results will be refined as additional experimental 

results are obtained. 

5.7 Observations and Conclusions 

When coal is burned in an electric utility boiler, the resulting high combustion 

temperatures in the vicinity of 1500 oC (2700 oF) vaporize the Hg in the coal to form gaseous Hg0. 

Subsequent cooling of the combustion gases and interaction of the gaseous Hg0

 with other 

combustion products result in a portion of the Hg being converted to other forms, viz., Hg2+ and 

Hgp. The term speciation is used to denote the relative amounts of these three forms of Hg in the 

flue gas of the boiler. It is important to understand how Hg speciates in the boiler flue gas 

because, as discussed in Chapters 6 and 7, the overall effectiveness of different control strategies 

for capturing Hg often depends on the concentrations of the different forms of Hg species present 

in the boiler flue gas. 

The speciation of Hg results from oxidation of Hg0

 in the boiler flue gas, with the 

predominant oxidized Hg species believed to be HgCl2. The mechanisms for this oxidation 

include gas-phase oxidation, fly-ash-mediated oxidation, and oxidation by post-combustion NOX 

controls. Data reveal that gas-phase oxidation is kinetically limited and occurs due to reactions 

5-45

of Hg with oxidizers such as Cl and Cl2. Research also suggests that gas-phase oxidation may be 

inhibited by the presence of NO, SO2, and water vapor. 

Certain fly ashes have been shown to promote oxidation of Hg0

 more than others. The 

differences in oxidation appear to be attributable to the composition of the fly ash and the 

presence of certain flue gas constituents. The results of bench-scale research conducted at EPA 

reflect that the presence of HCl and NOX in flue gas and iron in fly ash assists in oxidation. 

Other research indicates that γ-Fe2O3 may be causing Hg2+ formation, and that surface area may 

be a dominant factor in this regard. Also, there are indications that HCl, NO2, and SO2 in the 

flue gas may contribute to Hg0

 oxidation, while the presence of NO may suppress Hg0 oxidation. 

The understanding of Hg speciation in the flue gas of coal-fired electric utility boilers is 

far from being mature, and research and development efforts are currently underway to develop 

more information. 

Mercury can be captured and removed from a flue gas stream by injection of a sorbent 

into the exhaust stream with subsequent collection in a PM control device such as an electrostatic 

precipitator or a fabric filter. However, adsorptive capture of Hg from flue gas is a complex 

process that involves many variables. These include the temperature and composition of the flue 

gas, the concentration of Hg in the exhaust stream, and the physical and chemical characteristics 

of the sorbent (and associated functional group). The implementation of an effective and 

efficient Hg control strategy using sorbent injection requires the development of low-cost and 

efficient Hg sorbents. Of the known Hg sorbents, activated carbon and calcium-based sorbents 

have been the most actively studied. However, improved versions of these sorbents and new 

classes of Hg sorbents can be expected, as this is still a very active field of study. 

Adsorption of elemental Hg is enhanced by the presence of functional groups and/or 

catalytically active sites (that oxidize the Hg to Hg2+). Oxidation of elemental Hg to ionic 

species by the catalytic components that may be present in fly ash (especially iron compounds) is 

a critical step before adsorption of the species by the fly ash or some injected sorbents. Both the 

oxidant and binding sites for the adsorption of elemental Hg may also be provided by the 

injected sorbents. Also, alkaline components of the fly ash exhibit sorptive properties for 

oxidized Hg. Fly ashes, which contain higher unburned carbon contents, such as those produced 

from low-NOX burner systems, may have significant catalytic and sorptive properties. The 

unburned carbon appears to have some oxidant/adsorption sites similar to those that existed in 

the activated carbon sorbents. 

Activated carbon binding sites may be enhanced by impregnation with an active additive 

(e.g., S, Cl, I) or pretreatment (e.g., with H2SO4 or HCl). It appears that the presence of 

hetroatoms, such as sulfur and chlorine, on the activated carbon surfaces greatly enhance the 

adsorption of Hg. Other non-carbon-based sorbents may be enhanced by oxidant/catalyst 

additions. The enhancement is caused by the oxidation of the elemental Hg either by the added 

oxidant or by the added catalyst to the sorbents. A promising alternative appears to be the 

replacement of the coal-based activated carbons with a low cost, high-capacity, reactive sorbent. 

Such sorbents are currently under development. 

5-46

Oxidized Hg is readily absorbed by alkaline solutes/slurries or adsorbed by alkaline PM 

(or by sorbents). Flue gas desulfurization systems, which use alkaline materials to neutralize the 

acidic SO2 gas, remove oxidized Hg effectively in the flue gas. Current research is focusing on 

optimization of the existing desulfurization systems as a retrofit technology for controlling 

oxidized Hg emissions and on development of new multipollutant control technologies for 

simultaneously controlling both SO2 and oxidized Hg emissions. 

5.8 References 

1.	 Senior, C.L., A.F. Sarofim, T. Zong, J.J. Helble, and R. Mamani-Paco. Gas phase 

transformation of mercury in coal-fired power plants. Fuel Processing Technology, 63, 

(2-3): 197-214 (2000). 

2.	 Senior, C.L., L.E. Bool, J. Morency, F. Huggins, G.P. Huffman, N. Shah, J.O.L.Wendt, F. 

Shadman, T. Peterson, W. Seames, B. Wer, A.F. Sarofim, I. Olmeze, T. Zeng, S. Growley, 

A. Kolker, C.A. Palmer, R. Finkelman, J.J. Helble, and M.J. Wornat. Toxic substances from 

coal combustion – a comprehensive assessment. Physical Science, Inc., Final Report 

(Contract No. DE-AC-22-95, PC 951011, U.S. Department of Energy, Federal Energy 

Technology Center). September 1997. 

3.	 Senior, C.L., J.J. Helble, and A.F. Sarofim. “Predicting the speciation of mercury emissions 

from coal-fired power plants.” Paper presented at the Conference on Air Quality II: Mercury, 

Trace Elements, and Particulate Matter, McLean, VA. September 19-21, 2000. 

4.	 Ghorishi, S.B., C.W. Lee, and J.D. Kilgroe. “Mercury speciation in combustion systems: 

studies with simulated flue gases and model fly ashes.” Paper presented at the 92nd Annual 

Meeting of Air & Waste Management Association, St. Louis, MO. June 20-24, 1999. 

5.	 Edwards, J.R., R.K. Srivastava, and J.D. Kilgroe. A study of gas-phase mercury speciation 

using detailed chemical kinetics. Published in Journal of Air & Waste Management 

Association, 5: 869-877 (2001). 

6.	 Niksa, S., J.J. Helble, and N. Fujiwara. “Interpreting laboratory test data on homogeneous 

mercury oxidation in coal-derived exhausts.” Paper presented 94th Annual Meeting of the 

Air & Waste Management Association, Paper # 86, Orlando, FL. June 24 -28, 2001. 

7.	 Lee, C. W., J.D. Kilgroe, and S.B. Ghorishi. “Speciation of mercury in the presence of coal 

and waste combustion fly ashes.” Presented at the 93rd Annual Meeting of the Air & Waste 

Management Association, Salt Lake City, UT. June 18-22, 2000. 

8.	 Lee, C.W., R.K. Srivastava, J.D. Kilgroe, and S.B. Ghorishi. “Effects of iron content in coal 

combustion fly ashes on speciation of mercury.” Paper presented at the 94th Annual Meeting 

of the Air & Waste Management Association, Paper # 156, Orlando, FL. June 24 -28, 2001. 

5-47

9.	 Galbreath, K.C., C.J. Zygarlicke, D.L. Toman, and R.C. Schulz. “Effects of NOX and αFe2O3 on mercury transformations in a 7-kW coal combustion system.” Paper presented at 

the 94th Annual Meeting of the Air & Waste Management Association, Paper # 767, 

Orlando, FL. June 24 -28, 2001. 

10. Norton, G.A., H. Yang, R.C. Brown, D.L. Laudal, G.E. Dunham, J. Erjave, and J.M. Okoh. 

“Role of fly ash on mercury chemistry in simulated flue gas streams.” Paper presented at the 

94th Annual Meeting of the Air & Waste Management Association, Paper # 164, Orlando, 

FL. June 24 -28, 2001. 

11. Haythornthwaite, S., S. Sjostrom, T. Ebner, J. Ruhl, R. Slye, J. Smith, T. Hunt, R. Chang, 

and T.D. Brown. “Demonstration of dry carbon-based sorbent injection for mercury control 

in utility ESP’s and baghouses.” In Proceedings of the EPRI/DOE/EPA Combined Utility 

Air Pollutant Control Symposium, EPRI TR-108683-V3; Washington, DC. August 25-29, 

1997. 

12. Laudal, D.L., M.K. Heidt, T.D. Brown, and B.R. Nott. “Mercury speciation: a comparison 

between method 29 and other sampling methods.” Presented at the 89th Annual Meeting of 

the Air & Waste Management Association, Nashville, TN, Paper 96-W64A.04. June 1996. 

13. Brown, T. D., D.N. Smith, R.A. Hargis, Jr., and W.J. O’Dowd. “1999 Critical Review: 

Mercury Measurement and Its Control: What We Know, Have Learned, and Need to Further 

Investigate,” Journal of the Air & Waste Management Association, June 1999. pp. 1-97. 

Available at: < http://www.lanl.gov/projects/cctc/resources/pdfsmisc/haps/CRIT991.pdf >. 

14. Li, Z., and J.Y. Hwang. “Mercury distribution in fly ash compounds.” Presented at the Air 

& Waste Management Association Annual Meeting, Toronto, Ontario, Canada. June 8-13, 

1997. 

15. Huggins, F.E., N. Yap, G.P. Huffman, and J.K. Neathery. “Investigation of mercury 

adsorption on Cherokee fly-ash using XAFS spectroscopy.” Presented at the 93rd Annual 

Meeting of the Air & Waste Management Association, Salt Lake City, UT. June 18-22, 2000. 

16. Carey, T.R., O.W. Hargrove, Jr., C.F. Richardson, R. Chang, F.B. Meserole. Performance of 

Activated Carbon for Mercury Control in Utility Flue Gas Using Sorbent Injection, In 

Proceedings of the EPRI/DOE/EPA Combined Utility Air Pollutant Control Symposium, 

Washington, DC; EPRI TR-108683-V3. August 25B29, 1997. 

17. Galbreath, K.C., and C.J. Zygarlicke. Mercury transformation in coal combustion flue gas. 

Fuel Processing Technology, 65-66: 289-310 (2000). 

5-48

18. Brunauer, S., P.H. Emmett, and E. Teller, J. Am. Chem. Soc., 60, 309. 1938. 

19. Hsi C., J. Rood, M. Rostam-Abadi, S. Chen, and R. Chang. “Effects of sulfur impregnation 

temperature on the properties and mercury adsorption capacities of activated carbon fibers 

(ACFs).” Environmental Science and Technology, 35, 2785-2791. 2001. 

20. Bansal R.C., J.B. Donnet, and F. Stoecki. Active Carbon. New York, NY, and Basel, 

Switzerland: Marcel Dekker. 1988. 

21. Ghorishi, S.B., and B.K. Gullett. Sorption of mercury species by activated carbons and 

calcium-based sorbents: effect of temperature, mercury concentration and acid gases. Waste 

Management & Research, 16: 6: 582-593. 1998. 

22. Krishman, S.V., B.K. Gullett, and W. Jozewicz. Sorption of Elemental Mercury by 

Activated Carbons. Environmental Science and Technology, 28(8): 1506-1512 (1994). 

23. Serre, S.D., B.K. Gullett, and S.B. Ghorishi. Entrained-flow adsorption of mercury using 

activated carbon. Journal of the Air & Waste Management Association, 51: 733-741 (May 

2001). 

24. Helfritch, D.G., P.L. Feldman, and S.J. Pass. “A circulating fluid bed fine particulate and 

mercury control concept.” Presented at the EPRI/DOE/EPA Combined Utility Air Pollutant 

Control Symposium, Washington DC. August 1997. 

25. Hargis, R.A., W.J. O’Dowd, and H.W. Pennline. “Sorbent injection for mercury removal in 

a pilot-scale coal combustion unit.” Presented at the 93rd Annual Meeting of the Air & 

Waste Management Association, Salt Lake City, UT. June 18-22, 2000. 

26. Waugh, E.G., B.K. Jenson, L.N. Lapatrick, F.X. Gibbons, S. Sjostrom, J. Ruhl, R. Slye, and 

R.A. Chang. “Mercury control in utility ESP’s and FFs through dry carbon based sorbent 

injection pilot-scale demonstration.” In Proceedings of the EPRI/DOE/EPA Combined 

Utility Air Pollutant Control Symposium. Washington, DC, EPRI TR-108683-V3). August 

23-29, 1997. 

27. Carey, T.R., C. Richardson, R. Chang, and F.B. Meserole. “Assessing sorbent injection 

mercury control effectiveness.” Paper presented at the 1999 Spring National Meeting of the 

American Institute of Chemical Engineers, Houston, TX. March 14-18, 1999. 

28. Sjostrom, S., T. Ebner, T. Ley, R. Slye, C. Richardson, T. Machalek, M. Richardson, R. 

Chang, and F. Meserole. “Assessing the performance of mercury sorbents in coal 

combustion flue gas.” Paper presented at the 94th Annual Meeting of the Air & Waste 

Management Association, Orlando, FL. June 24-28, 2001. 

5-49

29. Rostam-Adadi, M., S.G. Chen, H-C. His, M. Rood, R. Chang, T.Carey, B. Hargrove, C. 

Richardson, W. Rosenhoover, and F. Meserole. “Novel vapor phase mercury sorbents.” In 

Proceedings of the First EPRI/DOE/EPA Combined Utility Air Pollution Control Symposium 

(The Mega Symposium), Washington, DC, August 25-29, 1997. 

30. White, D.M., W.E. Kelly, M.J. Stucky, J.L. Swift, and M.A. Palazzolo. Emission test report: 

field test of carbon injection for mercury control, Camden County Municipal Waste 

Combustor, EPA/600/R-93/181 (NTIS PB94-101540), U.S. EPA, Air and Energy 

Engineering Research Laboratory, Research Triangle Park, NC. September 1993. 

31. Serre, S.D., B.K. Gullett, and S.B. Ghorishi. “Elemental mercury capture by activated carbon 

in a flow reactor.” Paper presented at 93rd Annual Meeting of the Air & Waste Management 

Association, Salt Lake City, UT. June 18-22, 2000. 

32. Serre, S.D., B.K. Gullett, and Y. H. Li. “The effect of water (vapor-phase and carbon) on 

elemental mercury removal in a flow reactor.” Paper presented at 94th Annual Meeting of 

the Air & Waste Management Association, Paper # 164, Orlando, FL. June 24 -28, 2001. 

33. Ghorishi, S.B., R. Keeney, W. Jozewicz, S. Serre, and B. Gullett. “In-flight capture of 

elemental mercury by a chlorine-impregnated activated carbon.” Paper # 731 presented at 

the 94th Annual Meeting of Air & Waste Management Association, Orlando, FL. June 24-

28, 2001. 

34. Brown, T. D., D.N. Smith, R.A. Hargis, Jr., and W.J. O’Dowd. “1999 Critical Review: 

Mercury Measurement and Its Control: What We Know, Have Learned, and Need to Further 

Investigate,” Journal of the Air & Waste Management Association, June 1999. pp. 1-97. 

35. Ghorishi, S.B., R.M. Keeney, and B.K. Gullett. “Role of surface functional groups in the 

capture of elemental mercury and mercuric chloride by activated carbons.” In Proceedings 

of the Air Quality II Conference, McLean, VA. September 19-21, 2000. 

36. Gullett, B.K., S.B. Ghorishi, K. Raghunathan, and K. Ho. Removal of Coal-Based Volatile 

Trace Elements: Mercury and Selenium, Final Technical Report. September 1, 1995, through 

August 31, 1996. 

37. Ghorishi, S.B., and C.B. Sedman. “Combined Mercury and Sulfur Oxides Control Using 

Calcium-Based Sorbents.” Paper presented at the EPRI/DOE/EPA Combined Utility Air 

Pollutant Control Symposium, Washington, DC. August 25-29, 1997. 

38. Ghorishi, S.B., and C.B. Sedman. Low concentration mercury sorption mechanisms and 

control by calcium-based sorbents: application in coal-fired processes, Journal of the Air & 

Waste Management Association, 48: 1191-1198, 1998. 

5-50

39. Ghorishi, S.B., C. Singer, W. Jozewicz, C. Sedman, and R. Srivastava. “Simultaneous control 

of Hg0

, SO2, and NOx by novel oxidized calcium-based sorbents.” Paper # 243, Presented at 

the 94th Annual meeting of the Air & Waste Management Association. June 24-28, Orlando, 

FL, 2001. 

40. EPRI Report 1000454. Development and evaluation of low cost mercury sorbents. 

November 2000. 

41. EPRI Report TE-114043. Development and evaluation of mercury sorbents. November 

1999. 

42. EPRI Report TR-110532. Development and evaluation of low-cost sorbents for removal of 

mercury emissions from coal combustion flue gas. September 1998. 

43. Rostam-Abadi, M., S. Chen, A.A. Lizzio, H-C. His, C.M.B. Lehmann, M. Rood, R. Chang, 

C. Richardson, T. Machalek, and M. Richardson. “Development of low-cost sorbents for 

mercury removal from utility flue gas.” Paper presented at U.S. EPA/DOE/EPRI Combined 

Power Plant Air Pollutant Control Symposium, and the Air & Waste Management 

Association Specialty Conference on Mercury Emissions: Fate, Effects, and Control, 

Chicago, IL. August 20-23, 2001. 

44. Korpiel, J.A., and R.D. Vidic. Effect of sulfur impregnation method on activated carbon 

uptake of gas-phase mercury. Environmental Science and Technology, 31: 2319-2326 

(1997). 

45. Vidlic, R. D. and D.P. Siler. Vapor-phase elemental mercury adsorption by activated carbon 

impregnated with chloride and chelating agents. Carbon. 3-14 (2001). 

46. Li, Y. H., S.D. Serre, C.W Lee, and B.K. Gullett. “Elemental mercury adsorption by 

activated carbon treated with sulfuric acid.” Presented at the U.S. EPA/DOE/EPRI 

Combined Power Plant Air Pollutant Control Symposium, and the Air & Waste Management 

Association Specialty Conference on Mercury Emissions: Fate, Effects, and Control, 

Chicago, IL. August 20 -23, 2001. 

47. Li, Y. H., C.W. Lee, and B.K. Gullett. “Characterization of activated carbons’ physical and 

chemical properties in relation to their mercury adsorption.” Presented at the American 

Carbon Society CARBON ’01, An International Conference on Carbon, University of 

Kentucky Center for Applied Energy Research, Lexington, KY. July 14 - 19, 2001. 

48. Meserole, F., C. F. Richardson, T. Machalek, M. Richardson, and R. Chang. "Predicted 

Costs of Mercury Control at Electric Utilities Using Sorbent Injection." Presented at U. S. 

EPA/DOE/EPRI Combined Power Plant Air Pollutant Control Symposium, and the Air & 

Waste Management Association Specialty Conference on Mercury Emissions: Fate, Effects, 

and Control, Chicago, IL, August 20-23, 2001. 

5-51

49. DeVito, M.S., and W.A. Rosenhoover. “Hg flue gas measurements from coal-fired utilities 

equipped with wet scrubbers.” Presented at 92nd Annual Meeting of the Air & Waste 

Management Association, St. Louis, MO. June 20-24, 1999. 

50. Redinger, K.E., A. Evans, R. Bailey, and P. Nolan. “Mercury emissions control in FGD 

systems.” Presented at the EPRI/DOE/EPA Combined Air Pollutant Control System, 

Washington, DC. August 25-29, 1997. 

51. McDermott Phase III Study Section, McDermott Technologies, Inc. Advanced Emissions 

Control Development Program Phase III - Approved Final Report, prepared for the U.S. 

Department of Energy (US DOE-FETC contract DE-FC22-94PC94251-22) and Ohio Coal 

Development Office (grant agreement CDO/D-922-13). July 1999. Available at: 

< http://www.osti.gov/dublincore/servlets/purl/756595-LACvcL/webviewable/756595.pdf >. 

52. Hargrove, O.W., Jr., T.R. Carey, C.F. Richardson, R.C. Sherupa, F.B. Meserole, R.G. Rhudy, 

and T.D. Brown. “Factors affecting control of mercury by wet FGD.” Paper presented at the 

EPRI/DOE/EPA Combined Utility Air Pollutant Control Symposium. Washington DC. 

August 25-29, 1997. 

53. Livengood, C.D., and M.H. Mendelsohn. “Process for combined control of mercury and 

nitric oxide.” Presented at the EPRI/DOE/EPA Combined Utility Air Pollutant Control 

Symposium, Atlanta, GA. August 16-20, 1999. 

5-52

Chapter 6 

MERCURY CAPTURE BY EXISTING CONTROL SYSTEMS USED BY 

COAL-FIRED ELECTRIC UTILITY BOILERS 

6.1 INTRODUCTION 

Existing coal-fired electric utility boilers in the United States use a variety of emission 

control technologies to meet air standards for sulfur dioxide (SO2), nitrogen oxides (NOX), 

and particulate matter (PM). The EPA’s ICR data presented in Chapter 3 of this report 

indicate that most electric utilities are controlling NOX emissions from their coal-fired boilers 

by combustion modification techniques and controlling SO2 emissions by burning low-sulfur 

coal. All of the coal-fired electric utility boilers use some type of post-combustion control 

device to meet PM emission standards. Of these PM controls, electrostatic precipitators 

(ESPs) are the predominant control type used on coal-fired boiler units (83 percent) with the 

second most common control device being a fabric filter (14 percent). Use of postcombustion SO2 controls is less common: approximately 20 percent of the boiler units use 

either wet flue gas desulfurization (FGD) systems (15 percent) or spray dryer absorber (SDA) 

systems (5 percent). While the use of either selective non-catalytic reduction (SNCR) or 

selective catalytic reduction (SCR) on coal-fired electric utility boilers for NOX emission 

control presently is very limited (less than 4 percent), the application of these postcombustion NOX controls is becoming more prevalent. 

The implementation of post-combustion controls is not specifically intended to 

control mercury emissions from coal-fired utility boilers. However, these controls capture 

mercury in varying degrees depending on the control technologies used and the mercury 

speciation at the inlet to the control device(s). This chapter discusses mercury capture by 

existing post-combustion control systems used by coal-fired utility boilers. An estimate of 

nationwide mercury emissions from existing coal-fired utility boilers is presented. The 

mechanisms by which existing post-combustion control systems capture mercury are 

reviewed. The ICR mercury emission test data for mercury capture by the existing postcombustion control systems used for coal-fired utility boilers are presented and discussed. 

6.2 EPA ICR PART III DATA 

As introduced in Chapter 1 of this report, the EPA conducted a three-part data 

collection effort to gather information about the coal-fired utility boilers operating in the 

United States in 19991. The Part I ICR data consist of information on the coal types burned, 

the boiler furnace types, and the air pollutant control devices used for the 1,143 coal-fired 

utility boilers in the United States having a capacity equal to or greater than 25 MWe. These 

data are summarized and discussed in Chapters 2 and 3 of this report. The Part II ICR data 

6-1

consist of information on the quantity, mercury content, and other selected properties of coal 

burned by each of the identified 1,143 boiler units during calendar year 1999. A summary and 

evaluation of these data are presented in Section 2.7 and Appendix A of this report. For Part 

III of the information collection effort, the EPA selected a subset of the coal-fired electric 

utility boilers for which field source testing was performed to obtain mercury emission data 

for the air pollutant control devices now being used for these units. This chapter presents a 

summary and analysis of the emissions data collected by Part III of EPA’s information 

collection effort. 

The EPA ICR Part III data are composed of mercury emission source test results for 80 

coal-fired electric utility boilers. These boiler units were selected by the EPA to be generally 

representative of the nationwide population of coal-fired utility boilers according to the type of 

boiler used, the type of coal burned, and the air emission controls used. For each of the tested 

boiler units, the flue gas mercury measurements were generally made at the inlet and outlet of 

control device(s). The mercury measurements were made using the OH Method for speciated 

mercury (this test method is discussed in Section 4.1 of this report). Also, samples of the coal 

being burned in the boiler unit during the source test were collected and analyzed for mercury 

content. 

For boiler units that use a control configuration consisting of a single PM control 

device, the flue gas samples were collected at the inlet to the PM control device and in the 

stack. For units using SDA systems, the flue gas measurements were made at the inlet to the 

SDA and in the stack. For units using an ESP or FF followed by a wet FGD scrubber, the flue 

gas measurements were taken at the inlet to the wet scrubber inlet (i.e., downstream of the PM 

control device) and in the stack. For units equipped with a PS and a wet FGD scrubber, 

measurements were made at the inlet to the PS device and in the stack. 

Of the three IGCC plants located in the United States, two of the plants (Polk Power 

Station and Wabash River Repowering Project) were included as part of the Part III ICR test 

program. At both facilities, combustion gas measurements using the OH Method were made 

at the exhaust stack of the gas turbines. During testing, coal feed rates to the coalgasification units were recorded. Coal samples were collected during testing and analyzed 

for total mercury. 

A summary of 81 boiler and coal type configurations for which mercury emission data 

were collected is given in Table 6-1. Of these boiler units, 65 were pulverized-coal-fired 

(PC-fired) boilers. Such boilers account for the vast majority of the 1,143 coal-fired electric 

utility boilers operating in the United States in terms of both total units and nationwide 

generating capacity as shown Table 2-4. 

6-2

Errata Page 6-3, dated 3-21-02 

Table 6-1


Distribution of ICR Mercury Emission Test Data


By Boiler-coal Type Configurations


Number of Boiler Units Tested 

Fuel Burned In Boiler Unit Boiler Unit 

Type Bituminous 

Coal 

Subbituminous 

Coal Lignite Other(a) 

Total 

Number of 

Units 

Tested 

Pulverized-coalfired 26 29 9 1 65 

Cyclone-fired 3 2 0 7 

Fluidized-bed 

Combustor 1 2 2 5 

Stoker-fired 2 0 0 2 

IGCC (b) 2 0 0 2 

Total Number 

of Units Tested 34 31 13 3 81 

2 

0 

0 

0 

(a) Some units used coal wastes or a blend of fuels. 

(b) Integrated coal gasification combined cycle unit. 

A summary of the flue gas cleaning devices installed on the PC-fired test units is given 

in Table 6-2 as a function of type of fuel burned in each unit in 1999. These data show that: 

• A total of 28 test units were equipped with a CS-ESP (14), HS-ESP (8), or FF (6). 

• The 11 dry FGD units were equipped with either a SDA/ESP (3) or SDA/FF (8). 

•	 The 20 wet FGD units were equipped with a PS + Wet FGD (6), CS-ESP + Wet 

FGD (6), HS-ESP + Wet FGD (6), or FF + Wet FGD (2). 

• Two units were equipped with a CS-ESP + FF. 

• One was equipped with a PS. 

6-3

Errata Page 6-4, dated 3-21-02 

Table 6-2


Distribution of ICR Mercury Emission Test Data for Pulverized-coal-fired


Boilers By Post-combustion Emission Control Device Configuration


Postcombustion 

Control 

Strategy 

Post-combustion 

Emission Control 

Device 

Configuration 

Number of Boiler Units Tested 

Fuel Burned In Boiler Unit 

Total Bituminous 

Coal 

Subbituminous 

Coal Lignite Other 

PM Control Only 

CS-ESP 7 5 1 1 14 

HS-ESP 4 4 0 0 8 

FF 4 2 0 0 6 

CS-ESP + FF 0 0 2 0 2 

PS 0 1 0 0 1 

PM Control and 

Dry SO2 Scrubber 

System 

SDA + CS-EP 0 3 0 0 3 

SDA + FF 3 3 2 0 8 

DI + CS-ESP 1 0 0 0 1 

PM Control and 

Wet SO2 Scrubber 

System 

PS + wet FGD 1 4 1 0 6 

CS-ESP + wet FGD 1 3 2 0 6 

HS-ESP + wet FGD 1 5 0 0 6 

FF + wet FGD 2 0 0 0 2 

Other Control Device Configuration 2 0 0 0 2 

Number of Units Tested 27 29 8 1 65 

PM Controls SO2 Controls


CS-ESP = cold-side electrostatic precipitator DI = dry injection


HS-ESP = hot-side electrostatic precipitator FGD = flue gas desulfurization system


FF = fabric filter SDA = spray dryer adsorber system


PS = particle scrubber


6.3 MERCURY CONTENT OF UTILITY COALS BURNED IN 1999 

The analysis results of more than 39,000 coal samples were reported in the Part II ICR 

data. These results include the mercury content of as-fired coals and supplemental fuels 

burned in electric utility boilers in 1999. A comparison of the mercury contents of the 

different major coal types and supplemental fuels burned by electric utilities in 1999 and 

normalized by fuel heating value is shown Figure 6-1. Waste bituminous coal and waste 

anthracite had the highest mercury contents expressed in lb Hg/1012 Btu. The mercury content 

of the bituminous coal, subbituminous coal, and lignite (the three most commonly used fuels) 

was generally less than 15 1b/1012 Btu. Statistical information on each type of fuel burned in 

coal-fired utility boilers is presented in Table 6-3. 

6-4

× 

50 

100 150 200 

× 

× 

× 

× × 

× 

× 

× 

× × × × 

Hg lb /10

12 Btu 

6-5


0 

Bituminous 

South 

American 

Subbituminous Lignite 

Petroleum 

Tires Waste Waste Indonesian Waste Bituminous

Coke Anthracite Subbitumino

No. of Analyses 27,884 270 8,193 78 1,047 1,149 149 377 575 53 

Fuel Type 

Figure 6-1. 1999 ICR data analyses – mercury in fuels. 
Table 6-3


Comparison of Mercury Content Normalized By Heating Value


In As-fired Coals and Supplemental Fuels for Electric Utility Boilers in 1999


Ratio of Mercury to Fuel Heat Content 

(lb Hg per 1012 Btu) 

Fuel Type 

Number 

of 

Analyses Range Mean Median 

Standard 

Deviation 

Anthracite coal 114 5.02 – 35.19 15.28 13.37 6.23 

Bituminous coal 27,884 0.04 – 103.81 8.59 7.05 6.69 

South American bituminous coal (a) 270 0.70 – 66.81 5.94 4.91 5.28 

Subbituminous coal 8,193 0.39 – 71.08 5.74 5.00 3.59 

Indonesian subbituminous coal (b) 78 0.79 – 4.61 2.51 2.39 0.86 

Lignite 1,047 0.93 – 75.06 10.54 7.94 9.05 

Waste anthracite coal 377 2.49 – 73.02 29.31 27.77 11.94 

Waste bituminous coal 575 2.47 –172.92 60.50 53.32 44.35 

Waste subbituminous coal 53 5.81 – 30.35 11.42 10.79 4.66 

Petroleum coke 1,149 0.06 – 32.16 23.18 2.16 3.18 

Tire-derived fuel 149 0.38 – 19.89 3.58 2.79 2.78 

(a) Bituminous coal imported from South America and burned at one power plant in Florida and one power 

plant in Texas. 

(b) Subbituminous coal imported from Indonesia and burned at a coal-fired power plant in Hawaii. 

6.4 POTENTIAL MERCURY CAPTURE IN EXISTING UNITS 

Mercury capture in existing units depends on Hg speciation at the inlet to the control 

device(s) and the type(s) of control technologies used. Units that burn bituminous coals have 

relatively high concentrations of Hg2+ at the inlet to the control device(s). Units that burn 

subbituminous coal or lignite typically have relatively low concentrations of Hg2+ and high 

concentrations of Hg0 at the inlet to the control device(s). 

The effects of coal and combustion conditions are attributed primarily to the flue gas 

composition and properties of fly ash that affect the speciation and capture of Hg. While OH 

measurements made upstream of PM control devices do not always provide quantitatively 

accurate information on Hg speciation, they do provide semi-quantitative information relative 

to the amounts of Hgp, Hg2+, and Hg0

 in flue gas from the combustion of different types of 

6-6

coals. They also provide useful information on the potential for the oxidization of the Hg0

 and 

the capture of the resulting reaction products in downstream control devices. 

The relatively high concentrations of chlorine in bituminous coals are believed to 

result in the oxidization of Hg0

 to form Hg2+, primarily HgCl2. By contrast, both subbituminous 

coal and lignite have lower amounts of chlorine and higher amounts of alkaline material 

(calcium and sodium) than bituminous coals. Chlorine from the combustion of subbituminous 

coal and lignite tends to react with the alkaline materials in flue gas, and little if any chlorine 

is available for the oxidization of Hg. Therefore, flue gas from combustion of subbituminous 

coal and lignite tends to have relatively low concentrations of Hg 2+. 

6.4.1 Units with an ESP or FF 

Approximately 77 percent of the coal-fired utility boilers currently operating in the 

United States are equipped with only an ESP or an FF. Gaseous mercury (both Hg0 and Hg2+) 

can potentially be adsorbed on fly ash and be collected in a downstream ESP or FF. The 

modern ESPs or FFs that are now used on most coal-fired units achieve very high capture 

efficiencies for total particulate matter (see Table 3-3). As a consequence, these PM control 

devices are also effective in capturing Hgp in the boiler flue gases. 

The degree to which mercury can be adsorbed onto fly ash for subsequent capture in 

PM control is dependent on the speciation of mercury, the flue gas concentration of fly ash, 

and the properties of fly ash. It is currently believed that mercury is primarily adsorbed onto 

the unburned carbon in fly ash (see Section 5.3). Approximately 80 percent of the coal ash in 

PC-fired boilers is entrained with the flue gas as fly ash. PC-fired boilers with low-NOX 

burners have higher levels of carbon in the fly ash with a correspondingly higher potential for 

mercury adsorption. Cyclone and stoker boilers tend to have high levels of carbon in the fly 

ash, but have lower flue gas concentrations of fly ash than PC-fired boilers. Fly ash 

concentrations in fluidized-bed combustors tend to be higher than those in PC-fired boilers. 

Also, the carbon content of fluidized-bed combustor fly ash is generally higher than that of 

PC-boiler fly ash. 

The syngas from a coal gasifier is composed mainly of hydrogen, carbon monoxide, 

carbon dioxide, and nitrogen. This gas also contains vaporous trace elements, such as 

mercury, as well as dust and aerosols containing trace elements. The source of mercury in 

syngas is the mercury that is naturally present in coal and is released during the gasification 

processes, which typically takes place at 950 o

C (1750 oF). Mercury that is not retained in the 

solid residue from the gasification process is released almost exclusively as Hg0

. 

Gas-phase mercury in units equipped with an ESP can be adsorbed on the entrained 

fly ash upstream of the ESP. The gas-phase mercury in units equipped with a FF can be 

adsorbed by entrained fly ash or it can be adsorbed as the flue gas passes through the filter 

cake on the surface of the FF. The degree to which gaseous mercury adsorbs on the filter 

cake typically depends on the speciation of gaseous mercury in the flue gas; in general, 

gaseous Hg2+ is easier to adsorb than gaseous Hg0 (see discussion in Section 5.3.1). 

6-7

6.4.2 Units with SDA Systems 

An SDA system operates by the same principle as a wet FGD system using a lime 

scrubbing agent, except that the flue gas is mixed with a fine mist of lime slurry instead of a 

bulk liquid (as in wet scrubbing). The SO2 is absorbed in the slurry and reacts with the 

hydrated lime reagent to form solid calcium sulfite and calcium sulfate. The heat of the flue 

gas, leaving dry solid particles of calcium sulfite and calcium sulfate, evaporates the water in 

the mist. Entrained particles (unreacted sorbent particles, reaction products, and fly ash) are 

captured in the downstream PM control device (either an ESP or FF). 

The performance of SDA systems in controlling SO2 emissions is dependent on the 

difference between the SDA outlet temperature and the corresponding flue gas water vapor 

saturation temperature. SDA systems on coal-fired boilers typically operate about 20 oF 

(11 oC) above the saturation temperature (i.e., a 20 oF [11 oC] approach to saturation 

temperature). The relatively low flue gas temperatures afforded by SDA systems increase the 

potential for mercury capture. The caking or buildup of moist fly ash deposits, which can 

plug the SDA reactor and coat downstream surfaces, dictates the minimum flue gas 

temperatures, which can be employed at the outlet of SDAs. 

Hgp is readily captured in SDA systems. Both Hg0

 and Hg2+ can potentially be 

adsorbed on fly ash, calcium sulfite, or calcium sulfate particles in the SDA. They can also 

be adsorbed and captured as the flue gas passes through the ESP or FF, whichever is used for 

PM control. In addition, gaseous Hg2+ may be absorbed in the slurry droplets and react with 

the calcium-based sorbents within the droplets. Nearly all of the Hgp can be captured in the 

downstream PM control device. If the PM control device is a FF, there is the potential for 

additional capture of gaseous mercury as the flue gas passes through the bag filter cake 

composed of fly ash and dried slurry particles. 

6.4.3 Units with Wet FGD Systems 

Approximately 15 percent of coal-fired utility boilers in the United States use wet 

FGD systems to control SO2 emissions. In each of these systems, a PM control device is 

installed upstream of the wet FGD scrubber. PM control devices used with wet FGD 

scrubbers include particulate scrubbers (PS), CS-ESPs, HS-ESPs, and FF baghouses. As 

described in Chapter 3, wet FGD systems remove gaseous SO2 from flue gas by absorption. 

In wet scrubbers, gaseous species are mixed with a liquid in which they are soluble. For SO2 

absorption, gaseous SO2 is mixed with a caustic slurry, typically water and limestone or water 

and lime. 

Gaseous compounds of Hg2+ are generally water-soluble and can absorb in the 

aqueous slurry of a wet FGD system. However, gaseous Hg0 is insoluble in water and 

therefore does not absorb in such slurries. When gaseous compounds of Hg2+ are absorbed in 

the liquid slurry of a wet FGD system, the dissolved species are believed to react with 

6-8

dissolved sulfides from the flue gas, such as H2S, to form mercuric sulfide (HgS); the HgS 

precipitates from the liquid solution as sludge. In the absence of sufficient sulfides in the 

liquid solution, a competing reaction that reduces/converts dissolved Hg2+ to Hg0 is believed 

to take place. When this conversion takes place, the newly formed (insoluble) Hg0 is 

transferred to the flue gas passing through the wet FGD system. The transferred Hg0 

increases the concentration of Hg0 in the flue gas passing through the wet FGD (since the 

incoming Hg0 is not absorbed), thereby resulting in a higher concentration of gaseous Hg0 in 

the flue gas exiting the wet FGD compared to that entering. Transition metals in the slurry 

(originating from the flue gas) are believed to play an active role in the conversion reaction 

since they can act as catalysts and/or reactants for reducing oxidized species. 

Recent research on the capture of mercury in wet scrubber systems is discussed in 

Section 5.6. 

6.4.4 Units with Other Control Devices 

Some units use PS systems, primarily venturi scrubbers, to control PM emissions. 

Capture of Hg in these systems is limited to soluble Hg compounds such as HgCl2. PS 

systems are typically poor fine PM collectors and, if Hgp in the flue gas is associated with 

fine PM, capture of Hgp by such scrubbers may be poor. Hg0

 is insoluble and will not 

typically be captured by the scrubber. It is possible to capture Hg2+ in the wet scrubbers, but 

the scrubber chemistry, and the manner in which the scrubber is operated, will determine 

whether it is effectively removed, or whether it is stripped, from the scrubbing liquor. 

Stripping can occur if the Hg2+ is not adsorbed on the particles, or reacted chemically with 

liquid-phase reactants within the scrubber. 

Mechanical collectors such as cyclones do a poor job of capturing fine PM, and 

mercury capture in these control devices should be limited to the capture of Hgp associated 

with particles larger than 10 μm. 

6.5 EPA’S PART III ICR DATA EVALUATION APPROACH 

The methods used to evaluate the Part III ICR data were based on two interrelated 

objectives. The first objective was to estimate the amount, speciation, and geographical 

distribution of national mercury emissions from coal-fired power plants in 1999. The second 

was to characterize the effects of coal properties, combustion conditions, and flue gas cleaning 

methods on the speciation and capture of mercury. The satisfaction of the first objective 

involved the development of mercury emission factors as a function of the type of coal burned, 

the type of boiler, and the air pollution control device(s) used. 

6.5.1 Evaluation Method 

The development of emission factors for different classes of coal-fired units was based 

on hypotheses derived from current understanding of mercury speciation and capture, as 

discussed in Chapter 5. The hypotheses are: 

6-9

•	 Mercury speciation and capture are dependent on the coal properties, combustion 

conditions, and flue gas cleaning methods that are used for any specific test unit, 

•	 Hg2+ is more readily absorbed in aqueous media than Hg0, and therefore can be 

captured in wet scrubbers, while Hg0

 cannot, 

•	 Gas-phase mercury can be adsorbed onto the unburned carbon in fly ash, which can 

catalyze oxidation of Hg0

, 

• Hgp can be readily captured in an ESP or an FF, 

• The potential for mercury capture increases with decreasing flue gas temperatures, and 

•	 Flue gas from combustion of bituminous coals typically has a higher fraction of 

Hg2+ than the gas from subbituminous and lignite coals. 

Combinations of coal, boiler, and control technologies that are expected to behave in 

a similar manner with respect to speciation and capture of mercury can be grouped into data 

sets called coal-boiler-control technology classes or bins. Many of these data sets in the ICR 

database consist of tests at one or two units, and this small number of samples results in 

relatively large uncertainties concerning the central values and variability of the underlying 

populations. However, the mean values and statistical behavior of the classes with a large 

number of test units can be investigated, and the results can be compared with the results of 

classes with a small number of test sites. If the relative behavior of the large and small data 

sets is consistent with our theoretical expectations, then we can have some confidence that 

the speciation and capture estimates for the smaller sets are reasonable. 

The ICR Part III emission data were sorted into coal-boiler-control classes. Next, the 

data in each class were evaluated for consistency, and the data between classes were evaluated 

according to the postulated behavior criteria given above. With few exceptions, the differences 

in speciation and capture of mercury between the different classes were consistent with the 

above-hypothesized behavior. Based on this observation, emission factors were developed for 

use in estimating the amount and speciation of mercury emissions from coal-fired electric 

utility boilers in 1999. The data in the coal-boiler-control classes were also used to conduct 

further evaluations of the effects of coal properties, combustion conditions, and flue gas 

cleaning conditions on the control of mercury emissions at existing coal-fired power plants. 

6.5.2 Measures of Performance 

Measures used to evaluate the effect of the coal, boiler, and control device variables 

on the capture of mercury included the inlet and outlet concentrations of Hgp, Hg2+, Hg0

, and 

HgT, and the reduction of HgT. Emission factors, defined in this report to be the fraction of 

mercury emitted to the atmosphere relative to the amount that enters the first air pollution 

control device, were also calculated and used to evaluate the emission of speciated Hg and 

6-10

HgT. 

The fraction of HgT captured in air pollution control device(s) can be used 

interchangeably with the emission factor for HgT [EMFT]: 

EMFT = 1 - Capture HgT 

Where the fractional capture is: 

Capture HgT = [ HgT (inlet) - HgT(outlet)]/HgT(inlet) = 1 - HgT(outlet)/HgT(inlet) 

And the percentage reduction (%Red) across the control device(s) is: 

%Red = 100 x [1 - HgT(outlet)/HgT(inlet) ] 

The %Red can be determined from either (1) the inlet and outlet concentrations of 

HgT as measured by the OH Method, or (2) inlet concentration estimates made from Part III 

coal samples and outlet concentrations obtained with the OH Method. When the OH 

measurements are used to evaluate the reduction in emissions or emission factors, the inlet 

and outlet concentrations must be expressed on a common basis μm/dscm at 3% O2) or lb of 

Hg/1012 Btu of coal burned to account for air in-leakage through fans or across the air 

pollution control device(s). 

The results of the OH Method emission tests for HgT are shown in Figures 6-2 and 

6-3. Figure 6-2 is a scatter plot of the inlet versus the outlet concentrations of HgT. In 

general, the outlet HgT concentration increases with increasing inlet HgT concentrations. The 

increasing outlet HgT concentrations that appear linear with respect to HgT inlet 

concentrations are indicative of a constant percentage reduction across the control device(s). 

ESPs exhibit this type of performance for the control of PM. These types of devices are 

called constant reduction devices. Note that there are also a number of data points distributed 

just above the x-axis; i.e., zero outlet concentration. These data points are indicative of 

constant outlet devices with low emission concentrations. FF baghouses tend to operate like 

constant outlet devices. 

Figure 6-3 is a scatter plot showing inlet HgT concentration versus percent reduction 

in HgT across the control device(s). There are no discernable trends in the capture of HgT as a 

function of inlet concentration. The negative emission reductions represent cases for which 

the outlet HgT concentration is higher than the inlet concentration. This can result from one 

or a combination of factors. For example, negative emission reductions can occur when (1) 

temperature changes within the test unit increase the desorption of Hg, (2) ESP rapping 

cycles result in the reentrainment of Hgp, and (3) small differences between Hg inlet and 

outlet concentrations cannot be accurately quantified because of imprecision in the OH 

Method. 

6-11

0 

10 

20 

30 

40 

50 

60 

0 20 0 60 0 100 120 140 160 

Inlet Hg(T) Concentration, μg/m3 

Outlet Hg(T) Concentration, μg/m3 

4 8

Fig. 6-2. Inlet versus outlet mercury concentration for all tests. 

-150 

-100 

-50 

0 

50 

100 

150 

0 20 0 0 0 100 120 140 160 

Inlet Hg(T) Concentration, μg/m 3 

Outlet Hg(T) Concentration, μg/m 3 

4 6 8

Fig. 6-3. Inlet mercury concentration versus percent reduction for all tests. 

6-12

Emission factors for speciated Hg can be developed by dividing or normalizing the 

stack Hg species by the concentration of HgT at the inlet to the first control device. In the 

development of these emission factors, it is assumed that all of the Hg in the as-burned coal is 

equal to the value of HgT measured at the inlet sampling location by the OH method. The 

emission factors for Hgp (EMFp), Hg2+ (EMF2+), and Hg0

 (EMF0) are calculated by: 

EMFp = Hgp (outlet) / HgT (inlet), 

EMF2+ = Hg2+ (outlet) / HgT (inlet), and 

EMF0 = Hg0 (outlet) / HgT (inlet). 

For situations where HgT (outlet) is higher than HgT (inlet), the stack emission factors are 

calculated by replacing the HgT (inlet) value with the corresponding HgT (outlet) value: 

EMFp = Hgp (outlet)/HgT (outlet), [for HgT (outlet) > HgT (inlet)], 

EMF2+ 

= Hg2+ (outlet)/HgT (outlet), [for HgT (outlet) > HgT (inlet)], and 

EMF0 = Hg0 (outlet)/HgT (outlet), [for HgT (outlet) > HgT (inlet)]. 

In the latter case, it should be noted that EMFp + EMF2+ + EMF0 = 1. 

In addition to the above emission factors, speciation factors (SPFs) are calculated and 

used to characterize Hg speciation at both the inlet and outlet sampling locations. The SPFs 

represent the fractions of HgT in the inlet or outlet samples that are present as Hgp, Hg2+, or 

Hg0. For the inlet sampling train: 

SPFp = Hgp (inlet) / HgT (inlet), 

SPF2+

 = Hg2+ (inlet) / HgT (inlet), and 

SPF0

 = Hg0 (inlet) / HgT (inlet). 

For the outlet sampling train: 

SPFp = Hgp (outlet) / HgT (outlet), 

SPF2+

 = Hg2+ (outlet) / HgT (outlet), and 

SPF0

 = Hg0 (outlet) / HgT (outlet). 

In all cases: 

SPFp + SPF2+ + SPF0

 = 1. 

6-13

Emission factors and speciation factors for units equipped with an ESP, FF, PM 

scrubber, mechanical collector, SDA/ESP, or SDA/FF were calculated using inlet OH 

measurements for HgT and outlet OH measurements for speciated and HgT. For units with 

wet FGD scrubbing systems, emission factors were determined by multiplying the average 

emission factor for the PM control device that precedes the scrubber by the emission factors 

for the scrubber as determined by OH measurements. For example, the estimated EMFs for a 

PC-fired boiler burning subbituminous coal and equipped with cold-side ESP and wet FGD 

system are calculated as follows: 

The class average CS-ESP EMFT for a PC-boiler firing subbituminous coal is 0.91, 

and the class average wet FGD EMFT for a PC-boiler firing subbituminous coal is 

0.71. The EMFT across both control devices is therefore: 

EMFT (CS-ESP + FGD) = EMFT (CS-ESP) x EMFT (FGD) 

= 0.91 x 0.71 = 0.65. 

The corresponding level of control across both devices is: 

%Reduction (CS-ESP + FGD) = 100 * [1- EMFT (CS-ESP + FGD)] 

= 100 (1- 0.65) = 35 %. 

Emission factors for coal gasification units were calculated using the Hg content of 

the feed coal and the OH measurements made in the stack. 

6.5.3 Comparisons of HgT (Inlet) Using OH Measurement and Coal Hg Data 

Emission factors for speciated and total Hg relative to inlet Hg concentrations can be 

determined using two methods. The first method uses the HgT inlet concentrations from OH 

sampling train measurements. The second method involves the calculation of total Hg inlet 

values using coal Hg data and sampling train data (flue gas flow rate, moisture concentration, 

O2 concentration, and temperature). 

Emission factor estimates determined using the OH Method train data and the ICR Part 

II coal data often give significantly different results. The best estimate can sometimes be 

obtained by discarding outliers, by reviewing the test reports for tests conditions that can lead 

to questionable results, and by comparison of the results relative to tests at other test sites. In 

some cases, it is not possible to arrive at a best estimate, and there is a significant amount of 

uncertainty leading to a range of estimates. 

Mercury capture (percent reduction in emissions) and emission factors for Hgp, Hg2+, 

Hg0

, and HgT were then calculated using the average stack values for each data set as 

determined by both coal and OH Method sample train data. Emission factors based on the 

OH Method sampling train data provided the most consistent results. The inlet 

6-14

concentrations and percentage reduction reflected in the body of this report correspond 

primarily to test results obtained using the OH Method. 

6.5.4 Development of Data Sets for Coal-boiler-control Classes 

As described earlier, unit classes are defined as those combinations of coal, boiler, 

and control technologies that are expected to provide similar results in the speciation and 

capture of Hg. Data sets for different classes of units were developed by sorting the unit tests 

by coal type, boiler type, NOX control method, PM control method, and SO2 control method. 

Data sets were consolidated whenever the joint sets appeared to provide the same results as 

the initial groupings. Thus, wall- and tangentially fired PC boilers were consolidated into a 

single conventional PC boiler set. Units that reported no NOX controls were consolidated with 

low-NOX burners, overfire-air staging, and concentric firing systems. 

6.5.5 Questionable Nature of OH Speciation Measurements Upstream of PM Controls 

Initial evaluations of the Part III ICR data dealt with comparisons of the coal-boilercontrol classes using the results of OH speciation measurements at both the inlet and outlet 

sampling locations. Comparisons were also made of the results obtained using either the Part 

III ICR coal data or the inlet OH data to evaluate emission reduction trends. The comparison 

of speciation at the inlet and outlet locations produced, in some cases, results contrary to the 

expected behavior of Hg between the inlet and outlet of the control devices. 

Previous research has shown that the OH sampling method provides valid 

measurements for HgT at both the inlet to flue gas cleaning devices and in the stack. Also, the 

OH Method has been shown to provide valid Hg speciation measurements when samples are 

taken downstream of an efficient PM control device. However, the OH Method can give 

erroneous speciation measurements for locations upstream of PM control devices. 

The OH sampling train consists of a probe, a particulate filter, a series of impingers, a 

gas flow meter, and a sample pump. The filter captures particulate matter and Hgp, while the 

downstream impingers separate Hg2+ from Hg0

. Fly ash captured by the sampling train filter 

can absorb gas-phase Hg (Hg2+ and Hg0

) and oxidize Hg0 resulting in physical and chemical 

transformations within the sampling train. The rates of these transformations are dependent 

on the properties of fly ash, the amount of fly ash, the temperature, the flue gas composition, 

and the sampling duration. Samples collected downstream of efficient PM control devices do 

not contain enough fly ash to significantly alter Hg speciation within the sampling train, but 

samples collected upstream of PM control devices can give erroneous results because of flyash-induced transformations. 

6-15

Table 6-4


ICR Mercury Emission Test Allocations by Coal-boiler-control Class


No. 

Ea Group Coal-boiler Control Class No. of 

Test 

Runs 

Test Unit Name 

(Bold numbers in parentheses indicate no. 

of test runs) 

2 

3 

4 

5 

6 

1 

2 

3 

4 

1 

2 

3 

4 

1 

2 

1 

2 

3 

4 

5 

6 

7 

1 

2 

3 

4 

5 

6 

7 

8 

9 

1 

2 

3 

4 

5 

6 

1 

2 

3 

4 

5 

6 

1 

POST-COMBUSTION CONTROLS: COLD-SIDE ESPS 

Bituminous Coal, PC Boiler with CS-ESP 

Bituminous Coal and Pet Coke, PC Boiler with CS-ESP 

Bituminous Coal, PC Boiler with SNCR and CS-ESP 

Subbituminous Coal, PC Boiler with CS-ESP 

Subbituminous/ Bituminous Coal, PC Boiler with CS-ESP 

Lignite, PC Boiler with CS-ESP 

POST-COMBUSTION CONTROLS: HOT-SIDE ESPS 

Bituminous Coal, PC Boiler with HS-ESP 

Subbituminous Coal, PC Boiler (Dry Bottom) with HS-ESP 

Subbituminous Coal, PC Boiler (Wet Bottom) with HS-ESP 

Subbituminous/ Bituminous Coal, PC Boiler with HS-ESP 

POST-COMBUSTION CONTROLS: FF BAGHOUSES 

Bituminous Coal, PC Boiler with FF Baghouse 

Bituminous Coal/Pet. Coke, PC Boiler with FF Baghouse (Measurements not valid, disregard) 

Bituminous/Subbituminous Coal, PC Boiler with FF Baghouse 

Subbituminous Coal, PC Boiler with FF Baghouse 

POST-COMBUSTION CONTROLS: MISCELLANEOUS PM CONTROLS 

TX Lignite, PC Boiler with CS-ESP and FF (COHPAC) 

Subbituminous Coal, PC Boiler with PM Scrubbers 

POST-COMBUSTION CONTROLS: DRY FGD SCRUBBERS 

Bituminous Coal, PC Boiler with DSI and CS-ESP 

Subbituminous Coal, PC Boiler with CS-ESP/SDA 

Bituminous Coal, PC Boiler with SDA/FF 

Bituminous Coal, PC Boiler with SCR and SDA/FF 

Subbituminous Coal, PC Boiler with SDA/FF 

ND Lignite, PC Boiler with SDA/FF 

Bituminous Coal, Stoker with SDA/FF 

POST-COMBUSTION CONTROLS: WET FGD SCRUBBERS 

Bituminous Coal, PC Boiler with PS and Wet FGD Scrubbers 

Subbituminous Coal, PC Boiler with PS and Wet FGD Scrubbers 

ND Lignite, PC Boiler with PS and Wet FGD Scrubbers 

Bituminous Coal, PC Boiler with CS-ESP and Wet FGD Scrubbers 

Subbituminous Coal, PC Boiler with CS-ESP and Wet FGD Scrubbers 

TX Lignite, PC Boiler with CS-ESP and Wet FGD Scrubbers 

Bituminous Coal, PC Boiler with HS-ESP and Wet FGD Scrubbers 

Subbituminous Coal, PC Boiler with HS-ESP and Wet FGD Scrubbers 

Bituminous Coal, PC Boiler with FF and Wet FGD Scrubber 

CYCLONE-FIRED BOILERS 

Lignite, Cyclone Boiler with CS-ESP 

Subbituminous Coal/Pet. Coke, Cyclone Boiler with HS-ESP 

Lignite, Cyclone Boiler with Mechanical Collector 

Lignite, Cyclone Boiler with SDA/FF 

Bituminous Coal, Cyclone Boiler with PS and Wet FGD Scrubbers 

Bituminous Coal, Cyclone Boiler with CS-ESP and Wet FGD Scrubbers 

FLUIDIZED-BED COMBUSTORS 

Lignite, FBC with CS-ESP 

Anthracite Coal Waste, FBC with FF 

Bituminous Coal Waste, FBC with FF 

Bituminous Coal/Pet. Coke, FBC with SNCR and FF 

Subbituminous Coal, FBC with SCR and FF 

Lignite, FBC with CS-FF 

21 

6 

3 

9 

3 

3 

9 

6 

6 

3 

6 

3 

3 

6 

6 

3 

3 

9 

3 

6 

9 

6 

3 

3 

12 

3 

6 

9 

6 

6 

12 

6 

2 

3 

3 

2 

3 

3 

3 

3 

3 

3 

3 

3 

Brayton Point 1 (3), Brayton Point 3 (3), Gibson 0300 

(3), Gibson 1099 (3), Meramec (3), Jack Watson (3), 

Widow Creek (3) 

Presque Isle 5 (3), Presque Isle 6 (3) 

Salem Harber (3) 

Montrose (3), George Neal South (3), Newton (3) 

St. Clair (3) 

Stanton 1 (3) 

Cliffside (3), Gaston (3), Dunkirk (3) 

Cholla 3 (3), Columbia (3) 

Platte (3), Presque Isle 9 (3) 

Clifty (3) 

Sammis (3), Valmont (3) 

Valley (3) 

Shawnee (3) 

Boswell 2 (3), Comanche (3) 

Bigbrown (3), Monticello 1-2 (3) 

Boswell 3 (3) 

Washington (3) 

GRDA (3), Laramie 3 (3), Wyodak (3) 

Mecklenburg (3) 

Logan (3), SEI (3) 

Craig 3 (3), Rawhide (3), NSP Sherburne (3) 

Antelope Valley (3), Stanton 10 (3) 

Dwayne Collier (3) 

Bruce Mansfield (3) 

Boswell 4 (3), Cholla 2 (3), Colstrip (3), Lawrence (3) 

Lewis and Clark (3) 

AES Cayuga (3), Big Bend (3) 

Jim Bridger (3), Laramie River 1 (3), Sam Seymore (3) 

Monticello 3 (3), Limestone (3) 

Charles Lowman (3), Morrow (3) 

Coronado (3), Craig 1 (3), Navajo (3), San Juan (3) 

Clover (3), Intermountain (3) 

Leland Olds (2) 

Nelson Dewey (3) 

Bay Front (3) 

Coyote (2) 

Lacygne (3) 

Bailly (3) 

R.M. Heskett (3) 

Kline Township (3) 

Scrubgrass (3) 

Stockton Cogen (3) 

AES Hawaii (3) 

TNP (3) 

The effects of filtered solids on a filter in the OH sampling train are shown in Figure 6-4. 

These test results were obtained from pilot-scale coal combustion experiments conducted by the 

DOE Federal Energy Technology Center (FETC) [now the National Energy Technology 

Laboratory (NETL)]. The OH sampling train speciation data shown in Figure 6-4 were 

collected simultaneously in two different manners. In the first, tests designated by the symbols 

OH-n (n=1, 2, 3...), samples were collected by running the sampling train in the prescribed 

method by collecting an isokinetic sample with the probe nozzle facing upstream. In the second 

manner, tests designated by MOH-n (n=1, 2, 3, ...) were run with the probe nozzle facing 

downstream so that the PM entering the train would be minimal2

. 

6-16

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OH-1

MOH-1

OH-2

MOH-2

OH-3

MOH-3

OH-4

MOH-4

OH-5

MOH-5

OH-6

MOH-6

OH-7

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Figure 6-4. Effect of OH sample filter solids on Hg speciation. 

The results of these experiments show that, for each of the simultaneous runs, the values of 

HgT can be considered to be equal when taking into account sample variations resulting from the 

imprecision of the OH Method. However, the samples taken with the probe facing upstream 

indicated higher concentrations of Hgp and Hg2+ than the samples with the nozzles facing 

downstream. This provides evidence that PM collected on the filter of the train facing upstream 

resulted in the oxidization and adsorption of Hg as flue gas passed through the sampling train. 

This and other evidence indicate that in some cases the use of the OH Method to collect 

speciation samples upstream of PM control devices provides questionable results3. 

6.6 FUEL, BOILER, AND CONTROL TECHNOLOGY EFFECTS 

Based on current understanding of speciation and capture of mercury, it is believed that 

the ICR data represent a number of subpopulations corresponding to fuel-boiler-control 

combinations. Sections 6.6 and 6.7 provide an interpretation of physical and chemical 

phenomena that can be used to characterize the roles that coal, combustion, and flue gas 

cleaning variables play in the speciation and capture of Hg. Section 6.8 provides a summary 

of national emission estimates that were based on data described in Sections 6.6 and 6.7. 

Conclusions are provided in Section 6.9. 

The interpretations in Sections 6.6 and 6.7 are based on previous bench-, pilot-, and 

full-scale tests, plus a number of different modeling efforts related to speciation and capture of 

Hg in coal-fired boilers. While we have attempted to provide an internally consistent 

interpretation of the data, some of the observed results are inconsistent with the current 

theories on the behavior of Hg. In these instances, either our interpretations may be incorrect 

and other factors may account for the apparent discrepancies in results, or the data may be 

incorrect. It is believed that some discrepancies result from questionable OH Method or from 

6-17

errors in reporting test results. 

The evaluation of ICR Phase III data indicates that air pollution control technologies 

now used on coal-fired utility boilers exhibit levels of control that range from 0 to 99 percent 

reduction of HgT. The level of control varies with the coal, combustion conditions, and flue 

gas cleaning methods used at individual sites. In some instances, there is substantial variation 

in the three tests conducted at individual sites. The run-to-run variations at any given site can 

result from actual variations in emissions or with problems associated with the measurement 

method. 

The OH Method is relatively complex, and measurement method problems can result 

from errors that occur: 

• during the collection of samples, 

• in extracting samples from the sampling train, 

•	 from the chemical extraction of Hg from the nozzle and probe wash, from the sample 

train filter, and from the different impingers, 

• from Hg analysis, and 

• from data reduction and transcription. 

Some errors are inevitable in spite of the best efforts of everyone involved in the measurement 

process. 

In statistical terms, the OH data represent a very small number of samples of the 

underlying population. Each individual test represents the average of flue gas concentration of 

speciated Hg during a short “snapshot” in time. Run-to-run variations at any given site result 

from temporal variations in coal properties, combustion conditions, and emission control 

technology process conditions. There are also site-to-site variations within a given coalboiler-control class and variations between classes. Even considering these sample population 

variations, the ICR data provide a great deal of information, when evaluated in the context of 

current knowledge on the behavior of Hg in coal-fired electrical generating units. 

Table 6-5 shows differences in the average reduction in HgT emissions for coal-boilercontrol classes that burn pulverized coal. Plants that employ only post-combustion PM 

controls display class average HgT emission reductions ranging from 1 to 90 percent. Units 

with FFs obtained the highest average levels of control. Decreasing average levels of control 

were generally observed for units equipped with a CS-ESP, HS-ESP, and PS. For units 

equipped with dry scrubbers, the class average HgT emission reductions ranged from 2 to 98 

percent. The estimated class average reductions for wet FGD scrubbers were similar and 

ranged from 10 to 98 percent. 

For PC-fired boilers, the amount of Hg captured by a given control technology is 

greater for bituminous coal than for either subbituminous coal or lignite. For example, the 

average capture of Hg based on OH inlet measurements in PC-fired plants equipped with a 

CS-ESP is 36 percent for bituminous coal, 9 percent for subbituminous coal, and 1 percent for 

lignite. 

6-18

Errata Page 6-19, dated 3-21-02 

Table 6-5


Average Mercury Capture by Existing Post-combustion Control


Configurations Used for PC-fired Boilers


Postcombustion 

Control 

Strategy 

Post-combustion 

Emission 

Control Device 

Configuration 

Average Mercury Capture by Control Configuration 

Coal Burned in Pulverized-coal-fired Boiler Unit 

Bituminous Coal Subbituminous 

Coal Lignite 

PM Control Only 

CS-ESP 36 % 3 % -4 % 

HS-ESP 9% 6% not tested 

FF 90 % 72 % not tested 

PS not tested 9 % not tested 

PM Control and 

Spray Dryer 

Adsorber 

SDA+ESP not tested 35 % not tested 

SDA+FF 98 % 24% 0% 

SDA+FF+SCR 98 % not tested not tested 

PM Control and 

Wet FGD 

System(a) 

PS+FGD 12% -8 % 33% 

CS-ESP+FGD 74 % 29 % 44 % 

HS-ESP+FGD 50 % 29 % not tested 

FF+FGD 98 % not tested not tested 

(a) Estimated capture across both control devices


CS-ESP = cold-side electrostatic precipitator HS-ESP = hot-side electrostatic precipitator


FF = fabric filter PS = particle scrubber


SDA = spray dryer adsorber system


6.6.1 Coal Effects 

While OH speciation measurements may not provide an accurate characterization of 

the speciation at the inlet sampling location, transformations within the sampling train provide 

an indication of the fly ash reactivity, and potential for Hg adsorption. SPFs for selected coalboiler-control classes are summarized in Table 6-6. The data in Table 6-6 are class average 

SPFs for PC-fired boilers at the inlet and outlet sampling locations. Data are shown for 

bituminous, subbituminous, ND lignite, and TX lignite. Relatively high levels of SPFp at the 

inlet indicate that the Hg was either present as Hgp in the flue gas, or it was readily absorbed 

by fly ash on the sampling train filter. Relatively high levels of Hg2+ at the inlet indicate that 

Hg at the inlet sampling location was either already oxidized or oxidized as the flue gas passed 

through the sampling train. Relatively high levels of measured Hg0 indicate that there were 

relatively high levels of Hg0 in the inlet flue gas. 

The units burning bituminous coal exhibited relatively high levels of SPFp and SPF 2+ 

in the inlet samples. It is hypothesized that high levels of SPFp + SPF2+, or alternatively low 

SPF0, in the inlet sampling train indicates a high probability that Hg can be readily captured in 

downstream APCD(s). For the bituminous-coal-fired units, values of SPFp and SPF 2+ ranged 

from 0.03 to 0.92, while values of SPF0 ranged from 0.01 to 0.37. The HS-ESP unit exhibited 

the highest level of Hg0 followed by units equipped with SDA/FF systems. HS-ESP units 

6-19

operate at temperatures where Hg0

 is not easily oxidized or captured. The SDA/FF units 

exhibited a 98 percent capture of HgT, and the relative concentrations of the SPF2+ and SPF0 

measurements at the stack sampling location were 0.22 and 0.77, respectively. This could 

result from the efficient capture of Hg2+ in these units. 

The PC-fired units burning subbituminous coal exhibit inlet SPF0

 values ranging from 

0.44 to 0.84. The summed SPFp + SPF2+ values for the CS-ESP and HS-ESP units were 

similar. Both of these classes of units exhibited HgT captures of 9 percent. The moderately 

low HgT captures for the SDA/ESP (38 percent) and SDA/FF (25 percent) are reflected by the 

summed inlet SPFp + SPF 2+ values for these units. The units with FF systems (72 percent 

average capture) had measured average inlet SPF0

 values of 44 percent. 

There were a limited number of tests for units firing lignite. The units burning ND 

lignites tend to have a higher SPF0

 values than units burning TX lignites. The CS-ESP units 

burning ND lignite exhibited an average inlet SPF0

 value of 0.98. While there was no 

comparable test unit that fired TX lignite, a unit equipped with a CS-ESP + FF exhibited an 

average inlet SPF0

 of 0.60. While the inlet measurements for the CS-ESP + FF unit were 

taken downstream of the CS-ESP, a higher SPF0 would have been expected if the TX lignite 

were to provide similar speciation results as the ND lignite. Moderate to average SPF0 values 

(0.47) were also noted for the CS-ESP + wet FGD units using TX lignite. Inlet measurements 

for these units were also made downstream of a CS-ESP. 

The similarities between inlet and outlet SPF values can also be used to identify 

instances where the measured inlet speciation values provide a good estimate of the true Hg 

speciation in the flue gas at the inlet sampling location. Units with similar inlet and outlet 

SPFs are identified by an (a) in Table 6-6. These cases correspond to tests in which the 

capture of HgT is < 25 percent for many of the units firing subbituminous coals and ND 

lignite (e.g., comparison of the respective inlet and outlet values for SPFp). 

6-20

Errata Page 6-21, dated 3-21-02 

Table 6-6


Effects of Coal and Control Technology Inlet and Outlet SPF


and Capture for PC-fired Boilers


Coal-Control Class 

Inlet Outlet % Red 

SPFp SPF2+ SPF0 SPFp SPF2+ SPF0 HgT 

Bituminous 

CS-ESP 0.35 0.58 0.07 0.02 0.78 0.20 36 

SNCR and CS-ESP 0.92 0.03 0.05 0.20 0.35 0.45 91 

HS-ESP (a) 0.09 0.53 0.37 0.04 0.59 0.37 9 

FF 0.92 0.04 0.04 0.01 0.52 0.47 90 

SDA/FF 0.59 0.28 0.15 0.01 0.22 0.77 98 

SCR and SDA/FF 0.82 0.17 0.01 0.05 0.46 0.48 98 

Subbituminous 

CS-ESP (a) 0.05 0.25 0.70 0.00 0.31 0.69 3 

HS-ESP (a) 0.02 0.15 0.83 0.00 0.17 0.83 6 

FF 0.33 0.23 0.44 0.01 0.87 0.12 72 

SDA/ESP 0.13 0.26 0.61 0.00 0.05 0.94 35 

SDA/FF (a) 0.01 0.06 0.84 0.01 0.05 0.94 24 

ND Lignite 

CS-ESP (a) 0.01 0.01 0.98 0.00 0.04 0.96 -4 

SDA/FF (a) 0.03 0.04 0.93 0.00 0.03 0.97 0 

TX Lignite 

CS-ESP + FF 0.09 0.31 0.60 0.00 0.70 0.30 NA 

CS-ESP + Wet FGD 0.00 0.52 0.47 0.01 0.14 0.85 44 

(a) Units with similar inlet and outlet SPF values. 

6.6.2 Control Technology Effects 

Control technology effects are inseparable from coal and boiler effects. In the 

following sections, post-combustion control technology effects will be evaluated in terms of 

the three major types of controls currently used for coal-fired utility boilers: PM controls, dry 

FGD scrubbing controls, and wet FGD controls. These evaluations will be discussed initially 

in terms of control technology and coal effects on PC-fired boilers. The speciation and capture 

of Hg from cyclone-fired combustors, FBCs, and IGCC units will then be discussed. 

A summary of test results for each of the coal-boiler-control classes for which ICR Hg 

emission data were collected is given in Table 6-7. The data include information on the 

number of tests for each class, the average emission factors for Hgp, Hg

2+, Hg0

, and HgT, and 

the average and range of HgT emission reductions. 

6-21

μ

Table 6-7


Average Mercury Emission Factors and Percent Reduction for Coal-boiler-control Clas

No. 

Ea Group 

COAL-BOILER-CONTROL CLASS No. of 

Tests 

HgT, μg/dscm Average Bin EMF (a) 

Inlet Outlet Hgp Hg2+ Hg0 H

POST-COMBUSTION CONTROLS: COLD-SIDE ESPs 

1 Bituminous Coal, PC Boiler with CS-ESP 21 13.82 10.31 0.04 0.48 0.15 0.

2 Bituminous Coal and Pet Coke, PC Boiler and CS-ESP 6 4.47 1.73 0.01 0.19 0.20 0.

3 Bituminous Coal, PC Boiler with SNCR and CS-ESP 3 4.41 0.41 0.02 0.03 0.04 0.

4 Subbituminous Coal, PC Boiler with CS-ESP 9 10.05 9.57 0.00 0.31 0.66 0.

5 Subbituminous/ Bituminous Coal, PC Boiler with CS-ESP 3 6.79 5.36 0.00 0.20 0.59 0.

6 Lignite, PC Boiler with CS-ESP 3 11.67 12.06 0.00 0.04 1.00 1.

POST-COMBUSTION CONTROLS: HOT-SIDE ESPs 

1 Bituminous Coal, PC Boiler with HS-ESP 9 9.07 7.95 0.05 0.53 0.33 0.

2 Subbituminous Coal, PC Boiler (Dry Bottom) with HS-ESP 6 9.12 8.41 0.00 0.16 0.77 0.

3 Subbituminous Coal, PC Boiler (Wet Bottom) with HS-ESP 6 10.63 10.92 0.00 0.09 0.95 1.

4 Subbituminous/ Bituminous Coal, PC Boiler with HS-ESP 3 14.51 9.57 0.02 0.32 0.32 0.

POST-COMBUSTION CONTROLS: FF BAGHOUSES 

1 Bituminous Coal, PC Boiler with FF Baghouse 6 8.13 0.64 0.00 0.07 0.03 0.

2 Bituminous Coal/Pet. Coke, PC Boiler with FF Baghouse (Measurements not valid, disregard) 3 2.20 2.31 0.02 0.77 0.19 0.

3 Bituminous/Subbituminous Coal, PC Boiler with FF Baghouse 3 4.61 1.38 0.00 0.13 0.16 0.

4 Subbituminous Coal, PC Boiler with FF Baghouse 6 7.80 2.42 0.00 0.24 0.04 0.

POST-COMBUSTION CONTROLS: MISCELLANEOUS CONTROLS 

1 TX Lignite, PC Boiler with CS-ESP and FF (COHPAC) 6 50.05 59.65 0.00 0.75 0.40 1.

2 Subbituminous Coal, PC Boiler with PM Scrubbers 3 6.18 5.63 0.00 0.01 0.90 0.

POST-COMBUSTION CONTROLS: DRY FGD SCRUBBERS 

1 Bituminous Coal, PC Boiler with DSI and CS-ESP 3 17.03 9.32 0.00 0.37 0.18 0.

2 Subbituminous Coal, PC Boiler with CS-ESP/SDA 9 12.64 7.78 0.01 0.05 0.99 1.

3 Bituminous Coal, PC Boiler with SDA/FF 3 13.59 0.24 0.00 0.00 0.02 0.

4 Bituminous Coal, PC Boiler with SCR and SDA/FF 6 15.22 0.28 0.00 0.01 0.01 0.

5 Subbituminous Coal, PC Boiler with SDA/FF 9 9.56 7.39 0.01 0.03 0.72 0.

6 ND Lignite, PC Boiler with SDA/FF 6 9.65 9.69 0.00 0.04 0.96 1.

7 Bituminous Coal, Stoker with SDA/FF 3 2.39 0.14 0.01 0.01 0.03 0.

6-22

μ

Table 6-7 (cont’d)


Average Mercury Emission Factors and Percent Reduction for Coal-boiler-control Clas

No. 

Ea Group 

COAL-BOILER-CONTROL CLASS No. of 

Tests 

HgT, μg/dscm Average Bin EMF (a) 

Inlet Outlet Hgp Hg2+ Hg0 H

POST-COMBUSTION CONTROLS: WET FGD SCRUBBERS 

1 Bituminous Coal, PC Boiler with PS and Wet FGD Scrubbers 3 11.15 9.75 0.00 0.17 0.70 0.

2 Subbituminous Coal, PC Boiler with PS and Wet FGD Scrubbers 12 6.30 6.42 0.02 0.06 1.00 1.3 ND Lignite, PC Boiler with PS and Wet FGD Scrubbers 3 23.64 15.09 0.00 0.02 0.65 0.

4 Bituminous Coal, PC Boiler with CS-ESP and Wet FGD Scrubbers 6 7.77 2.64 0.00 0.03 0.31 0.

5 Subbituminous Coal, PC Boiler with CS-ESP and Wet FGD Scrubbers 9 11.22 8.24 0.00 0.02 0.72 0.

6 TX Lignite, PC Boiler with CS-ESP and Wet FGD Scrubbers 6 44.03 25.00 0.00 0.08 0.48 0.

7 Bituminous Coal, PC Boiler with HS-ESP and Wet FGD Scrubbers 6 10.46 5.83 0.01 0.18 0.39 0.

8 Subbituminous Coal, PC Boiler with HS-ESP and Wet FGD Scrubbers 12 5.12 3.74 0.01 0.03 0.74 0.

9 Bituminous Coal, PC Boiler with FF and Wet FGD Scrubbers 6 1.88 0.50 0.01 0.08 0.19 0.

CYCLONE-FIRED BOILERS 

1 Lignite, Cyclone Boiler with CS-ESP 2 6.80 5.60 0.00 0.16 0.77 0.

2 Subbituminous Coal/Pet. Coke, Cyclone Boiler with HS-ESP 3 2.77 3.00 0.02 0.08 1.00 1.

3 Lignite, Cyclone Boiler with Mechanical Collector 3 3.33 4.98 0.25 0.76 0.56 1.

4 Lignite, Cyclone Boiler with SDA/FF 2 17.82 16.34 0.00 0.01 0.90 0.

5 Bituminous Coal, Cyclone Boiler with PS and Wet FGD Scrubbers 3 9.88 7.57 0.01 0.04 0.72 0.

6 Bituminous Coal, Cyclone Boiler with CS-ESP and Wet FGD Scrubbers 3 5.61 3.11 0.00 0.06 0.49 0.

FLUIDIZED-BED COMBUSTORS (FBCs) 

1 Lignite, FBC with CS-ESP 3 10.46 5.95 0.03 0.06 0.53 0.

2 Anthracite Coal Waste, FBC with FF 3 44.69 0.12 0.00 0.00 0.00 0.3 Bituminous Coal Waste, FBC with FF 3 128.83 0.13 0.00 0.00 0.00 0.

4 Bituminous Coal/Pet. Coke, FBC with SNCR and FF 3 2.24 0.12 0.01 0.02 0.02 0.5 Subbituminous Coal, FBC with SCR and FF 3 1.71 0.73 0.00 0.01 0.41 0.

6 Lignite, FBC with CS-FF 3 35.98 15.11 0.00 0.31 0.12 0.

6-23


(a) See Section 6.5.2 for discussion of emission factors. 
6.6.3 Post-combustion PM Controls 

In 1999, 72 percent of the coal-fired electric utility boilers in the U.S. used postcombustion controls that consisted only of PM controls. The Phase I ICR revealed that there 

were 890 units that used only post-combustion PM controls. This included 791 units using 

either CS- or HS-ESPs and 80 units that used FF baghouses. The number of boiler units in the 

U.S. equipped only with PM controls is shown in Table 6-8 along with the number of test 

units in each PM control category. 

Table 6-8


Number of Coal-fired Utility Boilers Equipped with Particulate Matter Controls Only


Particulate Matter 

Control Number of Units 

Utility Industry Test Units 

CS- or HS-ESP (a) 791 25 

Two ESPs in series 2 2 

Fabric Filter 80 12 

ESP w/ Fabric Filter 6 2 

Particulate Scrubber 5 1 

ESP w/ Particulate 

Scrubber 4 0 

Mechanical Collector 2 1 

(a) 14 CS-ESPs and 9 HS-ESPs were tested 

6.6.3.1 Cold-side ESPs 

A total of 14 PC-fired units equipped with CS-ESPs were tested. The types of fuels 

that were used in these tests are given in Table 6-9. 

Table 6-9


Type of Fuel Used in PC-fired Units Equipped with CS-ESP


Type of Fuel No. of Test Units 

Bituminous 8 

Bituminous & Pet. Coke 2 

Subbituminous 3 

Subbituminous/Bituminous 1 

Total 14 

One of the units burning bituminous coal was also equipped with an SNCR system for 

NOX control. One cyclone-fired unit that burned lignite was also tested. The results of Hg 

emission tests on PC-fired units equipped with a CS-ESP are given in Table 6-10. 

6-24

Table 6-10


Post-combustion Controls: Cold-side ESPs


Plant ID Run Hg p In Hg 2+ In Hg° In Hg T In Hg T In Hg p Out Hg 2+ Out Hg° Out HG T Out %R H T %R Hg T 

No. OH OH OH OH Coal OH OH OH OH OH Coal 

Bituminous Coal, PC Boiler with CS-ESP 

Brayton Point 1 1 2.01 3.34 0.32 5.68 6.80 0.77 3.83 0.23 4.84 14.73 28.86 

Brayton Point 1 2 2.61 3.69 0.25 6.55 4.21 0.75 3.19 0.25 4.18 36.11 0.68 

Brayton Point 1 3 2.17 3.50 0.26 5.93 5.01 0.77 3.02 0.24 4.02 32.19 19.64 

Average 2.27 3.51 0.28 6.05 5.34 0.76 3.35 0.24 4.35 27.68 16.39 

Brayton Point 3 1 3.14 3.67 0.36 7.17 8.55 0.78 3.18 0.46 4.43 38.21 48.20 

Brayton Point 3 2 1.83 3.14 0.34 5.31 5.30 0.96 2.47 0.37 3.80 28.47 28.27 

Brayton Point 3 3 1.40 3.26 1.60 6.26 5.58 0.01 3.43 1.70 5.15 17.70 7.71 

Average 2.12 3.36 0.77 6.25 6.48 0.59 3.03 0.85 4.46 28.13 28.06 

Gibson 0300 1 1.94 31.74 4.39 38.08 13.69 0.00 32.03 7.51 39.54 -3.85 -188.83 

Gibson 0300 2 1.25 38.06 2.92 42.23 13.33 0.01 32.21 5.80 38.01 9.98 -185.13 

Gibson 0300 3 1.75 44.44 1.65 47.85 13.53 0.01 42.87 4.17 47.05 1.66 -247.76 

Average 1.65 38.08 2.99 42.72 13.52 0.01 35.70 5.83 41.54 2.60 -207.24 

Gibson 1099 1 5.53 10.33 2.34 18.20 14.00 0.03 6.06 5.03 11.12 38.92 20.62 

Gibson 1099 2 27.57 3.78 1.25 32.60 15.09 0.05 8.41 5.00 13.46 58.69 10.76 

Gibson 1099 3 4.60 11.02 1.58 17.20 14.69 0.03 11.03 4.65 15.71 8.68 -6.93 

Average 12.57 8.38 1.72 22.67 14.59 0.04 8.50 4.90 13.43 35.43 8.15 

Meramec 1 7.61 0.49 0.14 8.23 8.46 0.00 0.76 0.80 1.56 81.01 81.54 

Meramec 2 9.34 1.36 0.44 11.15 10.72 0.01 2.20 1.13 3.35 69.97 68.77 

Meramec 3 5.65 1.93 0.62 8.19 5.89 0.00 1.51 0.79 2.30 71.96 60.99 

Average 7.53 1.26 0.40 9.19 8.36 0.00 1.49 0.91 2.40 74.32 70.43 

Jack Watson 1 3.60 1.22 0.92 5.74 4.70 0.05 2.57 1.87 4.49 21.71 4.39 

Jack Watson 2 4.91 1.16 0.25 6.32 5.67 0.05 2.99 0.89 3.94 37.70 30.53 

Jack Watson 3 4.64 0.60 0.23 5.46 6.20 0.06 2.92 0.89 3.88 29.04 37.45 

Average 4.38 0.99 0.47 5.84 5.52 0.05 2.83 1.22 4.10 29.48 24.13 

Widows Creek 1 3.36 0.44 0.54 4.34 3.11 0.14 1.48 0.78 2.40 44.75 22.95 

Widows Creek 2 2.98 0.45 0.51 3.94 2.67 0.01 1.28 0.68 1.97 50.00 26.25 

Widows Creek 3 2.87 0.47 0.50 3.83 2.15 0.01 0.65 0.67 1.34 65.11 37.81 

Average 3.07 0.45 0.51 4.04 2.64 0.06 1.14 0.71 1.90 53.29 29.00 

Average 4.80 8.00 1.02 13.82 8.06 0.22 8.00 2.09 10.31 35.85 -4.44 

Minimum 1.25 0.44 0.14 3.83 2.15 0.00 0.65 0.23 1.34 -3.85 -247.76 

Maximum 27.57 44.44 4.39 47.85 15.09 0.96 42.87 7.51 47.05 81.01 81.54 

STDEV 5.62 13.05 1.09 13.86 4.35 0.34 12.01 2.24 13.67 23.90 88.31 

Bituminous Coal and Pet Coke, PC Boiler with CS-ESP 

Presque Isle 5 1 4.56 0.48 0.14 5.17 4.27 0.01 0.72 1.06 1.80 65.29 57.92 

Presque Isle 5 2 3.60 0.66 0.57 4.82 3.48 0.00 0.82 1.02 1.84 61.87 47.14 

Presque Isle 5 3 5.06 0.45 0.12 5.63 3.93 0.02 0.71 0.91 1.64 70.84 58.19 

Average 4.40 0.53 0.27 5.21 3.89 0.01 0.75 1.00 1.76 66.00 54.42 

Presque Isle 6 1 2.73 0.63 0.17 3.52 2.29 0.06 0.84 0.70 1.60 54.54 30.10 

Presque Isle 6 2 2.97 0.72 0.25 3.94 4.34 0.03 1.00 0.93 1.96 50.29 54.87 

Presque Isle 6 3 2.96 0.62 0.17 3.75 3.85 0.03 0.73 0.81 1.57 58.00 59.17 

Average 2.89 0.65 0.20 3.74 3.49 0.04 0.86 0.81 1.71 54.28 48.05 

Average 3.65 0.59 0.24 4.47 3.69 0.02 0.81 0.90 1.73 60.14 51.23 

Minimum 2.73 0.45 0.12 3.52 2.29 0.00 0.71 0.70 1.57 50.29 30.10 

Maximum 5.06 0.72 0.57 5.63 4.34 0.06 1.00 1.06 1.96 70.84 59.17 

STDEV 0.96 0.11 0.17 0.86 0.75 0.02 0.11 0.13 0.15 7.44 11.25 

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2) : % Reduction for OH Train and Coal Data 

(continued) 

6-25

Table 6-10 (cont’d) 

Post-combustion Controls: Cold-side ESPs 

Plant ID Run Hgp In Hg 2+ In Hg° In Hg T In Hg T In Hg p Out Hg 2+ Out Hg° Out HG T Out %R H T %R Hg T 

No. OH OH OH OH Coal OH OH OH OH OH Coal 

Bituminous Coal, PC Boiler with SNCR and CS-ESP Salem Harbor 1 4.12 0.32 0.32 4.76 3.44 0.07 0.28 0.27 0.62 87.07 82.11 

Salem Harbor 2 4.09 0.04 0.16 4.29 2.35 0.10 0.07 0.15 0.32 92.57 86.40 

Salem Harbor 3 3.96 0.06 0.15 4.17 3.27 0.08 0.08 0.14 0.29 93.06 91.16 

Average 4.06 0.14 0.21 4.41 3.02 0.08 0.14 0.19 0.41 90.90 86.55 

Subbituminous Coal, PC Boiler with CS-ESP Montrose 1 1.94 1.85 6.00 9.79 44.90 0.03 2.57 5.48 8.08 17.46 82.01 

Montrose 2 0.91 2.52 4.93 8.36 51.99 0.02 2.60 5.94 8.56 -2.31 83.54 

Montrose 3 1.63 2.85 4.68 9.16 47.76 0.02 2.30 5.69 8.01 12.54 83.22 

Average 1.49 2.41 5.20 9.10 48.21 0.02 2.49 5.70 8.22 9.23 82.92 

George Neal So. 1 0.17 4.78 6.34 11.29 8.96 0.03 4.07 5.47 9.58 15.18 -6.90 

George Neal So. 2 0.07 4.35 8.24 12.66 7.82 0.06 4.60 6.87 11.53 8.89 -47.37 

George Neal So. 3 0.02 3.53 3.77 7.32 10.19 0.02 4.74 6.39 11.15 -52.29 -9.36 

Average 0.09 4.22 6.12 10.42 8.99 0.04 4.47 6.24 10.75 12.04 -21.21 

Newton 1 0.04 0.58 9.70 10.32 9.07 0.00 2.26 8.07 10.33 -0.10 -14.00 

Newton 2 0.04 0.63 9.85 10.52 8.05 0.00 1.66 7.13 8.80 16.33 -9.28 

Newton 3 0.08 1.65 9.26 11.00 9.34 0.00 2.04 8.03 10.07 8.46 -7.82 

Average 0.05 0.95 9.61 10.61 8.82 0.00 1.99 7.74 9.73 8.23 -10.36 

Average 0.54 2.53 6.98 10.05 22.01 0.02 2.98 6.56 9.57 2.69 17.12 

Minimum 0.02 0.58 3.77 7.32 7.82 0.00 1.66 5.47 8.01 -52.29 -47.37 

Maximum 1.94 4.78 9.85 12.66 51.99 0.06 4.74 8.07 11.53 17.46 83.54 

STDEV 0.76 1.50 2.34 1.61 19.75 0.02 1.16 1.02 1.30 21.75 50.89 

SPF 0.05 0.25 0.69 1.00 1.00 0.00 0.31 0.69 1.00 

Subbituminous/ Bituminous Coal, PC Boiler with CS-ESP St Clair 1 2.53 2.29 1.97 6.79 16.26 0.01 1.35 3.01 4.37 35.63 73.13 

St Clair 2 2.87 2.13 1.40 6.39 14.36 0.01 1.39 3.74 5.14 19.65 64.24 

St Clair 3 0.98 1.94 4.28 7.20 17.71 0.01 1.33 5.24 6.57 8.71 62.89 

Average 2.13 2.12 2.55 6.79 16.11 0.01 1.35 4.00 5.36 21.33 66.75 

Lignite, PC Boiler with CS-ESP Stanton 1 1 0.04 0.15 11.96 12.15 31.51 0.04 0.42 11.16 11.62 4.42 63.13 

Stanton 1 2 0.13 0.13 10.81 11.06 41.24 0.02 0.43 11.68 12.14 -9.70 70.56 

Stanton 1 3 0.08 0.05 11.66 11.79 19.94 0.01 0.45 11.97 12.43 -5.41 37.67 

Average 0.08 0.11 11.48 11.67 30.89 0.02 0.44 11.60 12.06 -3.57 57.12 

Hg Speciation at Inlet and Outlet (μg/dscm@ 3% O2 ) : % Reduction for OH Train and Coal Data 

The test units with a CS-ESP display significant run-to-run differences (variations) in 

the HgT (inlet), HgT (outlet), and % HgT reduction. These differences may result from the 

changing HgT inlet concentrations, changing boiler and control device operating conditions, or 

sampling and analysis problems. Two important variables that affect Hg capture are changes 

in Hg inlet concentration and unit operating temperatures. 

Run-to-run variations for test units burning bituminous coal in PC-fired boilers 

equipped with CS-ESPs are shown in Figure 6-5. While the class average HgT reduction for 

these units was 36 percent, the run-to-run emission reductions in HgT range from 0 to 81 

percent. All inlet and outlet HgT concentrations for the Widow Creek, Jack Watson, Brayton 

3, and Brayton 1 were similar. The Meramec plant exhibited relatively high HgT reductions as 

did run 2 on Gibson 1099. Gibson 0300 exhibited high stack gas concentrations of HgT, and 

run 1 on Gibson 0300 had a higher outlet HgT concentration than at the inlet. The unit-to-unit 

variations in HgT emission reductions for these same units are shown in Figure 6-6. The 

average emission reduction for the seven 3-run tests shown in Figure 6-6 is still 37 percent, 

but unit-to-unit emission reductions range from 3 percent for Gibson 0300 to 74 percent for 

Meramec. The speciation of Hg for the bituminous coals is predominantly Hg2+. 

6-26

6-27

In Figure 6-6, there are two unit test averages given for Gibson. Both averages are for

the same unit, Gibson 0300. e for Gibson 1099 is for tests conducted in

October 1999, while the average for Gibson 0300 is for tests conducted in March 2000. 

tests in October and March used coal from the same source. e unit reductions in HgT

for the October and March tests were 35 and 3 percent, respectively. The apparent

discrepancy in the test results led plant engineers to investigate. ation indicated

that steam-cleaning of the air preheater during the collection of OH samples was the probable

cause of these inconsistencies.

The Hg speciation and HgT reductions for PC-fired units equipped with CS-ESPs and

burning subbituminous coal and lignite are shown in Figure 6-7. Hg emission reductions for

the units range from -4 to 12 percent, exhibiting little if any Hg capture. relative

concentrations of Hg0

 in the stack gas are higher than those observed for units firing

bituminous coal.

0 10 030 0 0 0

Brayton 1

Brayton 3

Gibson 0300

Gibson 1099

Meramec

Jack Watson

Widow Creek

Unit

Total Mercury Concentration,μg/dscm @ 3% O2

Inlet Outlet

Figure 6-5. Inlet and outlet mercury concentrations for bituminous PC-fired boilers with

CS-ESP.

The unit averag

The

Averag

The investig

The

2 4 5 6
6-28

0 5 10 15 20 25 30 35 40 45

Brayton 1

[28%]

Brayton 3

[28%]

Gibson 0300

[3%]

Gibson 1099

[35%]

Meramec

[74%]

Jack Watson

[30%]

Widow Creek

[53%]

Mercury Concentration, μg/dscm @ 3% O2

Hg(p) Out Hg(2+) Out Hg(0) Out

Unit [Hg Reduction, %]

Figure 6-6. Mercury emissions from bituminous-coal-fired PC boilers with CS-ESP.

0 4 8 10 12 14

Montrose [9%]

George Neal South

[12%]

Newton [8%]

Stanton 1 [-4%]

Unit [Hg Reduction,%]

Mercury Concentration, μg/dscm @ 3% O2

Hg(p) Out Hg(2+) Out Hg(0) Out

Figure 6-7. Mercury emissions for subbituminous- and lignite-fired PC boilers with

CS-ESP.

2 6
Run-to-run variations on a given unit can be attributed to operating variables such as 

inlet Hg concentrations, operating temperature, soot blowing, reentrainment losses within an 

ESP, or the imprecision of the OH Method. 

Mercury outlet concentrations can be expressed by: 

HgT (outlet) = HgT (inlet) – Hgp (captured in the control device) 

+ Hgp (reentrained and escapes the control device) 

- Hg0 or Hg2+ (adsorbed and captured within the control device) 

+ Hgp, Hg2+, or Hg0 (desorbed or is reentrained and escapes capture) 

Deposits or captured fly ash between the inlet and outlet sampling location (the stack) 

can adsorb or desorb gas-phase Hg, depending on time-dependent changes in the inlet Hg 

concentration and operating temperatures downstream of the inlet sampling location. 

Temperature effects can be understood by considering the deposits and collected fly ash 

between the inlet and stack locations to be a complex system that adsorbs and desorbs Hg. If 

the system has reached equilibrium in terms of operating conditions, there will be a constant 

relationship between the inlet and outlet concentrations of Hg. Increases in operating 

temperatures within the system can increase the rate at which Hg is desorbed, resulting in 

increased outlet concentrations relative to the inlet concentrations. Temperature decreases can 

increase Hg adsorption within the system. This can cause a decrease in the Hg outlet 

concentrations relative to the inlet concentrations. 

Temporal changes in inlet and outlet Hg concentrations are the result of hysteresis or 

history effects. Hypothetical changes in Hg reduction for three tests on a single unit that could 

occur because of the time lag between changing inlet and outlet Hg concentrations are 

illustrated in Figure 6-8. In this illustration, Hg emission reductions during runs 1, 2, and 3 

averaged 30, -15, and 40 percent, respectively. The -15 percent indicates that the measured 

outlet Hg concentrations were higher than the inlet concentrations. 

6-29

HgT 

Run 1 Run 2 Run 3

HgT Red. = 30 % HgT Red. = 40 % HgT Red. = -15 % 

Inlet 

Time 

Figure 6-8. Hypothetical effect of inlet and outlet HgT concentration changes on run-torun HgT capture. 

Changes in the fly ash carbon content, changes in unit operating conditions such as 

load, and diurnal changes in temperature may also result in hysteresis effects. The ICR tests 

for each unit represent a snapshot in time. Additional OH Method tests or tests with Hg 

CEMs are needed over an extended period of time to more fully characterize the effects of 

coal, combustion, and control technology variables on stack emissions of Hg. 

6.6.3.2 Hot-side ESPs 

Eight ICR units that burn pulverized coal and that were equipped with an HS-ESP 

were tested. Three of these units burned bituminous coal; four burned subbituminous coal; 

and one burned subbituminous and bituminous coal. A ninth, a cyclone-fired unit equipped 

with an HS-ESP, burned subbituminous coal and petroleum coke. Hg test data for the eight 

PC-fired units are given in Table 6-11. 

6-30

Table 6-11 

Post-combustion Controls: Hot-side ESPs 

Average 0.14 3.11 11.25 14.51 7.84 0.26 4.71 4.60 9.57 34.03 -22.29 

As shown in Figure 6-9, the units that fired bituminous coal exhibited average 

emission reductions of 18 percent (Dunkirk), -17 percent (Gaston), and 27 percent (Cliffside). 

In Figure 6-10, the HS-ESP units that burned subbituminous coal and lignite exhibit Hg 

emission reductions of 2 percent (Cholla), -1 percent (Columbia), -3 percent (Platte), and -6 

percent (Presque Isle). Stack concentrations of Hg0

 were substantially higher for the units 

burning subbituminous coal than for those burning bituminous coal. 

Hot-side ESPs tend to exhibit poor capture because they operate over a temperature 

range where the oxidization and adsorption of Hg0

 is limited. 

Hg Speciation at Inlet and Outlet (μg/dscm@ 3% O2 ) : % Reduction for OH Train and Coal Data 

Plant ID Run Hgp In Hg 2+ In Hg° In Hg T In Hg T In Hg p Out Hg 2+ Out Hg° Out HG T Out %R H T %R Hg T 

No. OH OH OH OH Coal OH OH OH OH OH Coal 

Bituminous Coal, PC Boiler with HS-ESP Cliffside 1 0.17 3.72 3.31 7.20 5.43 0.41 2.79 3.95 7.14 0.86 -31.58 

Cliffside 

Cliffside 

Average 

2 

3 

0.09 

0.08 

3.54 

4.15 

3.33 

7.27 

6.95 

11.49 

3.84 

8.80 

0.10 

0.10 

2.27 

3.97 

1.95 

2.54 

4.31 38.00 

6.61 42.51 

-12.17 

24.94 

Gaston 1 

0.11 

4.28 

3.80 

0.86 

4.63 

2.64 

8.55 

7.77 

6.02 

5.20 

0.20 

0.74 

3.01 

4.70 

2.81 

2.34 

6.02 27.12 

7.78 -0.19 

-6.27 

-49.56 

Gaston 

Gaston 

2 

3 

2.57 

0.43 

0.71 

3.94 

3.56 

2.83 

6.84 

7.20 

6.27 

4.70 

0.40 

1.15 

5.80 

4.73 

3.47 

2.04 

9.66 -41.37 

7.92 -10.00 

-54.19 

-68.41 

Average 

Dunkirk 1 

2.42 

0.09 

1.84 

8.56 

3.01 

2.82 

7.27 

11.47 

5.39 

10.06 

0.76 

0.21 

5.08 

6.89 

2.62 

3.67 

8.46 -17.19 

10.77 6.08 

-57.39 

-7.09 

Dunkirk 2 0.01 8.91 1.43 10.36 10.30 0.08 4.57 2.46 7.12 31.27 30.90 

Dunkirk 3 0.01 9.15 3.20 12.36 9.65 0.03 6.40 3.82 10.25 17.08 -6.26 

Average 

Average 

Minimum 

0.04 

0.86 

0.01 

8.87 

4.84 

0.71 

2.48 

3.38 

1.43 

11.40 

9.07 

6.84 

10.00 

7.14 

3.84 

0.11 

0.36 

0.03 

5.95 

4.68 

2.27 

3.32 

2.92 

1.95 

9.38 18.14 

7.95 9.36 

4.31 -41.37 

5.85 

-19.27 

-68.41 

Maximum 4.28 9.15 7.27 12.36 10.30 1.15 6.89 3.95 10.77 42.51 30.90 

STDEV 1.52 3.28 1.59 2.30 2.55 0.37 1.54 0.80 2.02 26.41 34.54 

Subbituminous Coal, PC Boiler (Dry Bottom) with HS-ESP Cholla 3 1 0.07 0.37 1.93 2.37 51.98 0.01 0.51 1.87 2.40 -1.30 95.39 

Cholla 3 2 0.51 0.32 0.46 1.28 54.43 0.01 0.01 1.00 1.02 20.42 98.12 

Cholla 3 3 0.45 0.43 0.61 1.49 40.48 0.01 0.39 1.27 1.67 -12.28 95.87 

Average 

Columbia 1 

0.34 

0.01 

0.37 

0.93 

1.00 

14.27 

1.71 

15.22 

48.96 

9.85 

0.01 

0.00 

0.30 

2.74 

1.38 

11.71 

1.70 2.28 

14.45 5.02 

96.46 

-46.78 

Columbia 

Columbia 

2 

3 

0.01 

0.01 

5.82 

0.46 

13.40 

14.65 

19.24 

15.12 

10.30 

10.35 

0.00 

0.00 

2.16 

2.65 

11.82 

12.68 

13.98 27.34 

15.34 -1.47 

-35.71 

-48.18 

Average 

Average 

Minimum 

0.01 

0.18 

0.01 

2.41 

1.39 

0.32 

14.11 

7.55 

0.46 

16.52 

9.12 

1.28 

10.17 

29.57 

9.85 

0.00 

0.01 

0.00 

2.51 

1.41 

0.01 

12.07 

6.73 

1.00 

14.59 10.30 

8.14 6.29 

1.02 -12.28 

-43.56 

26.45 

-48.18 

Maximum 0.51 5.82 14.65 19.24 54.43 0.01 2.74 12.68 15.34 27.34 98.12 

STDEV 0.23 2.18 7.21 8.26 21.77 0.00 1.24 5.87 7.09 14.88 76.82 

Subbituminous Coal, PC Boiler (Wet Bottom) with HS-ESP Platte 

Platte 

1 

2 

0.03 

0.02 

4.15 

1.92 

9.82 

11.31 

14.00 

13.25 

11.10 

9.65 

0.01 

0.01 

1.45 

0.78 

8.76 

16.86 

10.23 26.93 

17.65 -33.20 

7.88 

-82.85 

Platte 3 0.03 4.39 11.63 16.04 6.05 0.01 1.51 14.90 16.43 -2.40 -171.57 

Average 

Presque Isle 9 1 

0.03 

0.04 

3.48 

0.14 

10.92 

6.70 

14.43 

6.89 

8.93 

9.86 

0.01 

0.00 

1.25 

0.57 

13.51 

6.30 

14.77 -2.89 

6.88 0.10 

-82.18 

30.22 

Presque Isle 9 2 0.01 0.14 6.89 7.05 8.92 0.00 0.67 6.74 7.41 -5.23 16.87 

Presque Isle 9 3 0.01 0.10 6.43 6.55 9.91 0.00 0.54 6.38 6.92 -5.76 30.11 

Average 

Average 

Minimum 

0.02 

0.02 

0.01 

0.13 

1.80 

0.10 

6.68 

8.80 

6.43 

6.83 

10.63 

6.55 

9.56 

9.25 

6.05 

0.00 

0.01 

0.00 

0.59 

0.92 

0.54 

6.47 

9.99 

6.30 

7.07 -3.63 

10.92 -3.26 

6.88 -33.20 

25.73 

-28.22 

-171.57 

Maximum 0.04 4.39 11.63 16.04 11.10 0.01 1.51 16.86 17.65 26.93 30.22 

STDEV 0.01 2.03 2.41 4.27 1.72 0.01 0.44 4.69 4.91 19.13 82.08 

Subbituminous/Bituminous Coal, PC Boiler with HS-ESP Clifty 3 0.01 3.41 11.46 14.87 7.84 0.07 5.50 3.80 9.37 36.99 -19.53 

Clifty 1 0.40 2.35 11.17 13.92 8.02 0.70 3.60 4.67 8.96 35.58 -11.78 

Clifty 2 0.02 3.58 11.13 14.73 7.66 0.01 5.04 5.34 10.39 29.51 -35.57 

6-31

����

���������������������

�����������

������

������

μ

μ

Hg(p) Out Hg(2+) Out Hg(0) Out 

Dunkirk [18%] 

Unit [Hg Reduction,%] 

Unit [Hg Reductio

n, %] 

Gaston [-17%] 

Cliffside [27%] 

0 2 4 6 8 10 

Mercury Concentration, μg/dscm @ 3% O2 

Figure 6-9. Mercury emissions from bituminous-fired PC boilers with HS-ESP. 

����

����

��������������������� ���������������������

�����������

�����������

������

������

Hg(p) Out Hg(2+) Out Hg(0) Out 

Presque Isle 9 [-6%] 

Platte [-3%] 

Columbia [-1%] 

Cholla 3 [2%] 

0 2 4 6 8 10 12 14 16 

Mercury Concentration, μg/dscm @ 3% O2 

Figure 6-10. Mercury emissions for subbituminous- and lignite-fired PC boilers with HSESP. 

6-32

6.6.3.3 FF Baghouses 

Six PC-fired units with FF baghouses were tested. The results of one test unit (Valley) 

were omitted from the results because of data quality problems. The unit name, type of coal 

burned, and reduction in HgT are given in Table 6-12 for the five units with valid test data. 

Table 6-12


Mercury (HgT) Reduction at PC-fired Units with FF Baghouses


Unit Coal Reduction in HgT, 

% 

Sammis Bituminous 92 

Valmont Bituminous 87 

Shawnee Bituminous/subbituminous 70 

Boswell 2 Subbituminous 83 

Comanche Subbituminous 62 

Detailed test results for the five units listed in Table 6-12 are given in Table 6-13. The 

average run-to-run HgT reductions for the FF units ranged from 53 to 92 percent. The class 

average emission reductions for the two bituminous-coal-fired units was 90 percent, the 

average for the single unit that fired bituminous and subbituminous coals was 70 percent, and 

the class average for the two units that fired subbituminous coal was 72 percent. There were 

generally high stack concentrations of Hg2+ for all FF units. Hg0

 can be oxidized as it passes 

through the FF, either from reactions with fly ash on the filter cake or from reactions with bag 

filter material. This can lead to relatively low concentrations of Hg0

 in the stack gas. These 

observations may not apply to all bag filter materials, or units that burn either lignite or 

subbituminous coal. 

6.6.3.4 Comparison of ESPs and FFs 

The average unit-to-unit reductions in HgT in the inlet and outlet of PC-fired units 

equipped with a CS-ESP, HS-ESP, or FF baghouse are shown in Figure 6-11. Stack 

concentrations and speciation results are shown in Figure 6-12. SPF results are shown in 

Figure 6-13. 

The best Hg capture is exhibited for units equipped with a FF (72 to 90 percent 

average reductions). This is followed by units that are equipped with a CS-ESP and that burn 

bituminous coal or bituminous coal and petroleum coke (35 to 54 percent average reductions). 

Poor capture (-4 to 9 percent average reductions) is shown for all units that are equipped with 

a HS-ESP and for units that are equipped with a CS-ESP and burn either subbituminous coal 

or lignite. Units, which exhibit poor HgT capture, display higher SPF0

 values than units that 

have good HgT capture. In units that burn bituminous coal or bituminous coal and petroleum 

6-33

coke, Hg2+ constitutes more than half of the total Hg in the stack gas. This is also true for the 

unit that is equipped with a FF and burns subbituminous coal. 

Table 6-13


Post-combustion Controls: FF Baghouses


Hg Speciation at Inlet and Outlet (μg/dscm@ 3% O2) : % Reduction for OH Train and Coal Data 

Plant ID Run Hgp In Hg 2+ In Hg° In Hg T In Hg T In Hg p Out Hg 2+ Out Hg° Out HG T Out %R H T %R Hg T 

No. OH OH OH OH Coal OH OH OH OH OH Coal 

Bituminous Coal, PC Boiler with FF Baghouse Sammis 1 11.78 0.48 0.61 12.86 6.64 0.01 0.49 0.61 1.11 91.37 83.28 

Sammis 2 15.35 0.50 0.54 16.38 9.54 0.01 0.58 0.55 1.14 93.04 88.05 

Sammis 3 14.62 0.51 0.52 15.65 9.55 0.02 0.51 0.57 1.10 92.97 88.48 

Average 13.92 0.50 0.55 14.97 8.58 0.01 0.53 0.57 1.12 92.46 86.60 

Valmont 1 0.92 0.12 0.18 1.22 0.80 0.00 0.12 0.04 0.16 86.98 80.04 

Valmont 2 0.92 0.07 0.14 1.12 0.44 0.00 0.10 0.02 0.12 89.53 73.26 

Valmont 3 1.23 0.10 0.17 1.51 0.60 0.00 0.21 0.03 0.24 84.15 60.16 

Average 1.02 0.10 0.17 1.29 0.61 0.00 0.14 0.03 0.17 86.89 71.16 

Average 7.47 0.30 0.36 8.13 4.59 0.01 0.34 0.30 0.64 89.67 78.88 

Minimum 0.92 0.07 0.14 1.12 0.44 0.00 0.10 0.02 0.12 84.15 60.16 

Maximum 15.35 0.51 0.61 16.38 9.55 0.02 0.58 0.61 1.14 93.04 88.48 

STDEV 7.16 0.22 0.22 7.59 4.49 0.01 0.22 0.30 0.52 3.54 10.76 

Bituminous Coal/Pet. Coke, PC Boiler with FF Baghouse (Measurements not valid, disregard) Valley 1 0.04 1.44 1.21 2.69 0.95 0.11 2.02 0.41 2.54 5.67 -165.84 

Valley 2 0.05 1.49 0.45 1.99 1.33 0.04 1.55 0.42 2.00 -0.70 -50.84 

Valley 3 0.04 1.22 0.67 1.92 1.52 0.00 1.89 0.52 2.41 -25.15 -58.75 

Average 0.04 1.38 0.78 2.20 1.27 0.05 1.82 0.45 2.31 -6.73 -91.81 

Bituminous/Subbituminous Coal, PC Boiler with FF Baghouse Shawnee 1 3.18 0.58 0.72 4.48 2.39 0.01 0.63 0.84 1.49 66.73 37.66 

Shawnee 2 3.01 0.98 0.66 4.65 4.29 0.02 0.61 0.75 1.37 70.51 68.03 

Shawnee 3 3.44 0.57 0.67 4.68 2.66 0.01 0.60 0.68 1.28 72.62 51.82 

Average 3.21 0.71 0.68 4.61 3.11 0.01 0.61 0.76 1.38 69.95 52.50 

Subbituminous Coal, PC Boiler with FF Baghouse Boswell 2 2 1.99 1.26 1.46 4.71 4.35 0.00 0.35 0.23 0.59 87.45 86.43 

Boswell 2 3 0.83 1.15 2.49 4.46 5.20 0.00 0.58 0.12 0.70 84.32 86.54 

Boswell 2 1 2.75 1.81 1.60 6.16 8.35 0.07 1.26 0.14 1.47 76.06 82.34 

Average 1.85 1.41 1.85 5.11 5.97 0.03 0.73 0.16 0.92 82.61 85.10 

Comanche 1 1.81 3.93 5.71 11.46 15.91 0.00 3.33 0.27 3.60 68.58 77.37 

Comanche 3 5.27 1.28 3.67 10.22 14.24 0.00 3.20 0.33 3.52 65.52 75.26 

Comanche 2 2.59 1.45 5.77 9.82 17.08 0.00 3.99 0.65 4.65 52.67 72.80 

Average 3.23 2.22 5.05 10.50 15.74 0.00 3.51 0.42 3.92 62.26 75.14 

Average 2.54 1.81 3.45 7.80 10.86 0.01 2.12 0.29 2.42 72.43 80.12 

Minimum 0.83 1.15 1.46 4.46 4.35 0.00 0.35 0.12 0.59 52.67 72.80 

Maximum 5.27 3.93 5.77 11.46 17.08 0.07 3.99 0.65 4.65 87.45 86.54 

STDEV 1.50 1.06 1.94 3.06 5.59 0.03 1.57 0.20 1.72 12.91 5.85 

6-34

6-35

Mercury Concentration, μg/dscm @ 3% O2

0 4 8 10 12 14 16

Bit/FF

[90%]

Sub/FF

[72%]

Bit/CS-ESP

[36%]

Sub/CS-ESP

[3%]

Lig/CS-ESP

[-4%]

Bit/HS-ESP

[9%]

Sub/HS-ESP

[6%]

Sub(wet)/HS-ESP

[-3%]

Coal/APCD [Hg Reduction,%]

Inlet Outlet

Figure 6-11. Mercury emission reductions for PC-fired boilers with ESPs and FFs.

0 4 8 10 12 14

Bit/FF

[90%]

Sub/FF

[72%]

Bit/CS-ESP

[36%]

Sub/CS-ESP

[3%]

Lig/CS-ESP

[-4%]

Bit/HS-ESP

[9%]

Sub/HS-ESP

[6%]

Sub(wet)/HS-ESP

[-3%]

Coal/APCD [Hg Reduction,%]

Hg(p) Out Hg(2+) Out Hg(0) Out

Stack Concentrations of Mercury, μg/dscm @ 3% O2

Figure 6-12. Mercury speciation for PC-fired boilers with ESPs and FFs.

2 6

2 6
6-36

0% 20% 40% 60% 80% 100%

Bit/FF

[90%]

Sub/FF

[72%]

Bit/CS-ESP

[36%]

Sub/CS-ESP

[3%]

Lig/CS-ESP

[-4%]

Bit/HS-ESP

[9%]

Sub/HS-ESP

[6%]

Sub(wet)/HS-ESP

[-3%]

Coal/APCD [Hg Reduction,%]

Relative Mercury Concentration in Stack, %

Hg(p) Out Hg(2+) Out Hg(0) Out

0 20 40 60 80 100

Figure 6-13. Relative mercury speciation for PC-fired boilers with ESPs and FFs.

6.6.3.5 Other PM Controls

Other PM control methods that were tested included two units firing TX lignite and

equipped with a CS-ESP followed by a pulse-jet FF baghouse, and one PC-fired unit burning

subbituminous coal and equipped with a PM scrubber (see Table 6-14). e

HgT reduction across the PM scrubber on this latter unit was 9 percent.

At the Bigbrown and Monticello units, the inlet and outlet Hg measurements were

made across the baghouse. between three runs for the Monticello

unit, and the data may not be valid. igbrown exhibited negligible HgT capture across the FF.

While some Hgp and Hg2+ may have been captured in the upstream ESP, the low amounts of

fly ash captured in the downstream FF probably account for the lack of HgT capture in the

baghouse.

The three-run averag

There is little consistency

B
Table 6-14


Post-combustion Controls: Miscellaneous PM Controls


Hg Speciation at Inlet and Outlet (μg/dscm@ 3% O2) : % Reduction for OH Train and Coal Data 

Plant ID Run Hg p In Hg 2+ In Hg° In Hg T In Hg T In Hg p Out Hg 2+ Out Hg° Out HG T Out %R H T %R Hg T 

No. OH OH OH OH Coal OH OH OH OH OH Coal 

TX Lignite, PC Boiler with CS-ESP and FF (COHPAC) 

Bigbrown 1 2.59 8.35 31.24 42.18 50.86 0.01 16.58 25.20 41.80 0.92 17.82 

Bigbrown 2 0.54 10.37 27.31 38.21 49.95 0.01 17.66 25.47 43.13 -12.88 13.65 

Bigbrown 3 0.14 14.14 21.93 36.21 46.92 0.01 18.49 22.12 40.62 -12.20 13.42 

Average 1.09 10.95 26.83 38.87 49.24 0.01 17.58 24.26 41.85 -7.68 14.96 

Monticello 1-2 1 15.97 22.54 8.82 47.34 53.79 0.17 32.01 1.58 33.76 28.69 37.23 

Monticello 1-2 2 0.37 14.82 46.29 61.48 54.09 0.11 78.08 14.93 93.11 -51.46 -72.13 

Monticello 1-2 3 7.97 22.74 44.19 74.90 84.65 0.08 86.89 18.51 105.48 -40.84 -24.61 

Average 8.10 20.03 33.10 61.24 64.18 0.12 65.66 11.67 77.45 -21.20 -19.83 

Average 4.60 15.49 29.96 50.05 56.71 0.07 41.62 17.97 59.65 -13.63 -2.44 

Minimum 0.14 8.35 8.82 36.21 46.92 0.01 16.58 1.58 33.76 -51.46 -72.13 

Maximum 15.97 22.74 46.29 74.90 84.65 0.17 86.89 25.47 105.48 28.69 37.23 

STDEV 6.31 6.03 14.07 15.16 13.94 0.07 32.27 8.99 31.13 26.49 39.61 

Subbituminous Coal, PC Boiler with PM Scrubber Boswell 3 1 0.01 0.25 6.06 6.32 5.00 0.00 0.05 5.82 5.87 7.16 -17.51 

Boswell 3 2 0.01 0.31 6.00 6.32 6.38 0.00 0.06 5.39 5.45 13.81 14.54 

Boswell 3 3 0.06 0.62 5.21 5.89 5.79 0.00 0.06 5.51 5.58 5.25 3.60 

Average 0.03 0.39 5.76 6.18 5.72 0.00 0.06 5.57 5.63 8.74 0.21 

6.6.4 Hg Capture in Units with Dry FGD Scrubbers 

Thirteen units with dry scrubbing systems were tested. One unit uses dry sorbent 

injection in combination with a CS-ESP, three units use SDA/ESP systems, and the 

remaining nine units are equipped with SDA/FF systems. Two of the units equipped with 

SDA/FFs were also equipped with a SCR system. Hg emission test results for the dry 

scrubber units are summarized in Table 6-15. 

At the Port Washington unit, sorbent is injected downstream of the air preheater. OH 

inlet measurements were made upstream of the preheater, and outlet measurements were 

made in the duct downstream of the CS-ESP. The average capture of HgT for the Port 

Washington dry sorbent injection unit was 45 percent. The SPF2+ and SPF0

 values for this 

unit fell within the range of values exhibited by PC-fired boilers that are equipped with a CSESP and burn bituminous coal. The three pulverized subbituminous-coal-fired units 

equipped with a SDA/ESP system exhibited average HgT captures of 25 percent (GRDA), 40 

percent (Laramie 3), and 41 percent (Wyodak). 

As mentioned above, nine units equipped with a SD/FF system were tested. One unit 

firing bituminous coal had a HgT capture of 98 percent. The two units firing bituminous coal 

and also equipped with an SCR system had a class average HgT capture of 99 percent. Three 

SDA/FF units fired with subbituminous coal had HgT captures of 36, 32, and 5 percent. 

6-37

Table 6-15


Post-combustion Controls: Dry FGD Scrubbers


Hg Speciation at Inlet and Outlet (μg/dscm@ 3% O2) : % Reduction for OH Train and Coal Data 

Plant ID Run Hg p In Hg 2+ In Hg° In Hg T In Hg T In Hg p Out Hg 2+ Out Hg° Out HG T Out %R H T %R Hg T 

No. OH OH OH OH Coal OH OH OH OH OH Coal 

Bituminous Coal, PC Boiler with DSI and CS-ESP Washington 1 0.00 4.33 11.63 15.97 13.01 0.00 6.41 3.06 9.47 40.68 27.22 

Washington 2 0.00 7.75 11.02 18.77 13.36 0.00 5.84 3.05 8.90 52.61 33.42 

Washington 3 0.00 6.40 9.95 16.36 13.33 0.04 6.52 3.04 9.59 41.37 28.06 

Average 0.00 6.16 10.86 

Subbituminous Coal, PC Boiler with CS-ESP/SDA GRDA 1 0.13 4.42 7.77 

17.03 

12.31 

13.24 

11.22 

0.02 

0.01 

6.26 

1.55 

3.05 

5.58 

9.32 44.89 

7.13 42.06 

29.56 

36.42 

GRDA 2 0.53 2.97 6.50 9.99 10.73 0.01 1.28 11.12 12.42 -24.23 -15.70 

GRDA 3 0.51 8.78 3.71 13.01 12.24 0.01 0.34 5.41 5.76 55.72 52.94 

Average 

Laramie 3 1 

0.39 

0.03 

5.39 

0.22 

5.99 

0.63 

11.77 

0.88 

11.40 

15.03 

0.01 

0.03 

1.06 

0.10 

7.37 

3.87 

8.44 24.51 

4.00 0.00 

24.55 

73.40 

Laramie 3 2 1.69 0.52 8.53 10.75 17.67 0.03 0.04 4.52 4.58 57.35 74.05 

Laramie 3 3 4.55 0.44 9.28 14.27 14.94 0.03 0.04 5.27 5.35 62.53 64.22 

Average 

Wyodak 1 

2.09 

2.49 

0.39 

3.88 

6.15 

11.63 

8.63 

18.00 

15.88 

4.46 

0.03 

0.05 

0.06 

0.07 

4.56 

9.97 

4.64 39.96 

10.09 43.95 

70.56 

-126.38 

Wyodak 2 3.05 4.71 9.42 17.17 6.41 0.05 0.17 10.11 10.32 39.87 -61.16 

Wyodak 3 2.25 3.57 11.51 17.34 8.17 0.05 0.25 10.11 10.41 39.99 -27.41 

Average 

Average 

Minimum 

2.60 

1.69 

0.03 

4.05 

3.28 

0.22 

10.85 

7.67 

0.63 

17.50 

12.64 

0.88 

6.34 

11.21 

4.46 

0.05 

0.03 

0.01 

0.16 

0.43 

0.04 

10.06 

7.33 

3.87 

10.27 41.27 

7.78 35.25 

4.00 -24.23 

-71.65 

7.82 

-126.38 

Maximum 4.55 8.78 11.63 18.00 17.67 0.05 1.55 11.12 12.42 62.53 74.05 

STDEV 1.54 2.72 3.60 5.28 4.32 0.02 0.57 2.91 3.06 28.72 70.07 

Bituminous Coal, PC Boiler with SDA/FF Mecklenburg 1 11.34 3.40 6.16 20.91 11.52 0.00 0.07 0.09 0.16 99.23 98.60 

Mecklenburg 2 5.66 4.21 0.02 9.89 13.28 0.00 0.07 0.23 0.31 96.91 97.70 

Mecklenburg 3 6.90 3.04 0.02 9.96 11.50 0.00 0.01 0.23 0.24 97.60 97.92 

Average 7.97 3.55 2.07 

Bituminous Coal, PC Boiler with SCR and SDA/FF 

13.59 12.10 0.00 0.05 0.18 0.24 97.91 98.07 

Logan 

Logan 

1 

2 

12.87 

12.74 

7.22 

4.36 

0.21 

0.35 

20.31 

17.46 

18.28 

18.14 

0.02 

0.02 

0.08 

0.13 

0.16 

0.17 

0.26 98.71 

0.32 98.16 

98.57 

98.23 

Logan 3 12.45 4.59 0.25 17.29 17.51 0.01 0.04 0.17 0.22 98.72 98.74 

Average 

SEI 

SEI 

1 

2 

12.69 

13.48 

9.47 

5.39 

0.30 

0.25 

0.27 

0.14 

0.18 

18.35 

13.92 

9.90 

17.98 

11.79 

11.74 

0.02 

0.01 

0.01 

0.09 

0.34 

0.09 

0.16 

0.13 

0.12 

0.27 98.53 

0.48 96.56 

0.22 97.79 

98.51 

95.94 

98.13 

SEI 3 12.01 0.25 0.16 12.42 11.97 0.02 0.08 0.11 0.21 98.34 98.28 

Average 

Average 

Minimum 

11.66 

12.17 

9.47 

0.26 

2.83 

0.25 

0.16 

0.22 

0.14 

12.08 

15.22 

9.90 

11.83 

14.90 

11.74 

0.01 

0.02 

0.01 

0.17 

0.13 

0.04 

0.12 

0.14 

0.11 

0.30 97.56 

0.28 98.05 

0.21 96.56 

97.45 

97.98 

95.94 

Maximum 13.48 7.22 0.35 20.31 18.28 0.02 0.34 0.17 0.48 98.72 98.74 

STDEV 1.41 2.98 0.08 3.82 3.38 0.00 0.11 0.03 0.10 0.81 1.03 

(continued) 

6-38

Table 6-15 (cont’d) 

Post-combustion Controls: Dry FGD Scrubbers 

Hg Speciation at Inlet and Outlet (μg/dscm@ 3% O2) : % Reduction for OH Train and Coal Data 

Plant ID Run Hg p In Hg 2+ In Hg° In Hg T In Hg T In Hg p Out Hg 2+ Out Hg° Out HG T Out %R H T %R Hg T 

No. OH OH OH OH Coal OH OH OH OH OH Coal 

Subbituminous Coal, PC Boiler with SDA/FF 

Craig 3 1 0.57 0.65 0.20 1.42 1.20 0.00 0.04 0.90 0.94 33.79 21.49 

Craig 3 2 0.92 0.50 0.17 1.60 1.06 0.00 0.04 0.89 0.93 41.83 11.88 

Craig 3 3 0.90 0.23 0.12 1.25 0.93 0.00 0.03 0.82 0.86 31.67 7.38 

Average 0.80 0.46 0.16 1.42 1.06 0.00 0.04 0.87 0.91 35.76 13.58 

Rawhide 1 0.25 1.38 12.46 14.09 8.09 0.12 0.76 10.80 11.68 17.16 -44.36 

Rawhide 2 1.92 0.83 12.85 15.59 7.33 0.01 0.69 9.91 10.60 32.03 -44.61 

Rawhide 3 3.76 0.46 14.79 19.01 9.24 0.03 0.98 9.00 10.01 47.31 -8.41 

Average 1.98 0.89 13.37 16.23 8.22 0.05 0.81 9.90 10.76 32.16 -32.46 

NSP Sherburne 1 0.03 0.53 10.92 11.48 8.29 0.12 0.20 8.42 8.74 23.81 -5.43 

NSP Sherburne 2 0.03 0.23 10.92 11.18 8.27 0.14 0.18 12.09 12.40 -10.94 -49.92 

NSP Sherburne 3 0.03 0.19 10.24 10.46 7.73 0.27 0.24 9.84 10.35 1.05 -34.01 

Average 0.03 0.32 10.69 11.04 8.10 0.18 0.20 10.12 10.50 4.64 -29.78 

Average 0.93 0.56 8.07 9.56 5.79 0.08 0.35 6.96 7.39 24.19 -16.22 

Minimum 0.03 0.19 0.12 1.25 0.93 0.00 0.03 0.82 0.86 -10.94 -49.92 

Maximum 3.76 1.38 14.79 19.01 9.24 0.27 0.98 12.09 12.40 47.31 21.49 

STDEV 1.23 0.37 6.08 6.63 3.59 0.09 0.36 4.68 4.97 18.96 27.38 

ND Lignite, PC Boiler with SDA/FF Antelope Valley 1 0.16 0.38 7.80 8.34 13.85 0.01 0.25 omit NA NA NA 

Antelope Valley 2 0.21 0.42 7.82 8.45 16.03 0.02 0.79 8.16 8.98 -6.27 44.01 

Antelope Valley 3 0.16 0.16 7.67 8.00 12.50 0.02 0.33 6.97 7.32 8.49 41.45 

Average 0.18 0.29 7.75 8.22 14.27 0.02 0.56 7.56 8.15 1.11 42.73 

Stanton 10 1 0.22 0.24 10.23 10.70 12.82 0.02 0.40 10.14 10.56 1.24 17.63 

Stanton 10 2 0.27 0.36 9.86 10.49 15.63 0.01 0.17 10.58 10.76 -2.54 31.15 

Stanton 10 3 0.50 0.69 9.45 10.64 9.45 0.01 0.01 10.81 10.83 -1.77 -14.61 

Average 0.33 0.43 9.85 10.61 12.63 0.01 0.19 10.51 10.72 -1.02 11.39 

Average 0.27 0.38 9.01 9.65 13.29 0.02 0.34 9.33 9.69 -0.17 23.93 

Minimum 0.16 0.16 7.67 8.00 9.45 0.01 0.01 6.97 7.32 -6.27 -14.61 

Maximum 0.50 0.69 10.23 10.70 16.03 0.02 0.79 10.81 10.83 8.49 44.01 

STDEV 0.13 0.20 1.18 1.32 2.67 0.01 0.29 1.69 1.53 5.53 23.91 

Bituminous, Stoker with SDA/FF Dwayne Collier 1 2.19 0.03 0.06 2.28 3.37 0.06 0.02 0.08 0.16 92.84 95.16 

Dwayne Collier 2 2.14 0.18 0.42 2.75 3.48 0.03 0.03 0.09 0.15 94.48 95.64 

Dwayne Collier 3 1.99 0.03 0.11 2.13 3.29 0.01 0.03 0.06 0.10 95.43 97.04 

Average 2.11 0.08 0.20 2.39 3.38 0.03 0.03 0.08 0.14 94.25 95.95 

The average HgT captures in two units firing lignite were 1 and -1 percent. A single 

stoker-fired boiler burning bituminous coal had a total average Hg capture of 94 percent. 

The reduction in emissions for each SDA test class is shown in Figure 6-14. The 

stack concentrations of Hgp, Hg2+, Hg0

, and HgT are shown in Figure 6-15 along with the 

average total HgT capture for each SDA class. The relative Hg speciation for the same coalfired boiler classes is shown in Figure 6-16. The predominance of Hg0

 in the stack emissions 

from units fired with subbituminous coal and lignite is attributed to low levels of Hg0 

oxidization and the relative ease of Hg2+ capture. 

6-39

6-40

0 2 4 6 8 10 12 14 16

Bit, SDA/FF

[98%]

Sub, SDA/FF

[24%]

Lig, SDA/FF

[0%]

Sub, SDA/ESP

[35%]

Coal/APCD [Hg Reduction,%]

Mercury Concentration, μg/dscm @ 3% O2

Inlet Outlet

Figure 6-14. Mercury control for dry FGD scrubbers.

0 4 8 10 12

Bit, SDA/FF

[98%]

Sub, SDA/FF

[24%]

Lig, SDA/FF

[0%]

Sub, SDA/ESP

[35%]

Coal/APCD [Hg Reduction,%]

Mercury Concentration, μg/dscm @ 3% O2

Hg(p) Out Hg(2+) Out Hg(0) Out

Figure 6-15. Mercury speciation for PC boilers with SDA.

2 6
6-41

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Bit, SDA/FF

[98%]

Sub, SDA/FF

[24%]

Lig, SDA/FF

[0%]

Sub, SDA/ESP

[35%]

Coal/APCD [Hg Reduction,%]

Relative Mercury Concentration in Stack, %

 0 10 20 30 40 50 60 70 80 90 100

Hg(p) Out Hg(2+) Out Hg(0) Out

Figure 6-16. Relative mercury speciation for PC boilers with SDA.

6.6.5 Hg Capture in Units with Wet FGD Scrubbers

The wet FGD scrubber systems that were tested consisted of units equipped with four

PM control device configurations. urations are expected to have

different effects on the speciation and capture of Hg. urations included

units equipped with a PS, a CS-ESP, an HS-ESP, or a FF baghouse. nlet and outlet

measurements on the PS + wet FGD units were made across both control devices. nlet

measurements on the systems with an ESP or FF were made between the PM control device

and the FGD scrubber. Outlet measurements were made in the stack.

A total of 23 units with wet FGD systems were tested. 

systems to control particulate emissions, eight used CS-ESPs, six used HS-ESPs, and two

used FF baghouses. -one of the test units burned pulverized coal. 

units burned bituminous coal in cyclone-fired boilers. 

scrubber, and the other had a CS-ESP. The number of PC-fired test units in each coal-control

class is shown in Table 6-16. 

These different config

These different config

I

I

Seven units used PM scrubber

Twenty The other two test

One unit was equipped with a PM

(Also see Tables 6-4 and 6-6.)
Table 6-16 

PC-fired Boiler PM Controls for Wet FGD Systems 

PM 

Control 

Number of Test Units 

Totals 

Bit. Subbit. Lignite 

PS 1 4 1 6 

CS-ESP 2 3 2 7 

HS-ESP 2 4 0 6 

FF 2 0 0 2 

21 

The results of emission tests on wet FGD systems are summarized in Table 6-17. The 

next to last column in Table 6-17 shows the percent reduction in HgT across the wet FGD 

scrubber as determined by the OH sampling train measurements. The last column is an 

estimate of the reduction in HgT across the PM control device and wet FGD scrubber. These 

estimates were made using the class PM average coal-boiler-control EMF that is applicable to 

each test unit (see Section 6.5.2). 

Class average emission test results for the PC-fired boilers with wet FGD units are 

shown in Figures 6-17, 6-18, and 6-19. Each of these figures is based on capture estimates 

across the PM control device and wet FGD scrubber combinations. Figure 6-17 shows the 

class average stack concentrations of Hgp, Hg2+, and Hg0

. Figure 6-18 shows the average 

inlet and outlet concentrations of HgT and percent reduction for each class. Figure 6-19 

shows the relative mercury speciation for PC-boilers with wet FGD scrubbers. 

6-42

μ

Errata Page 6-43, dated 3-21-02


Table 6-17 

Post-combustion Controls: Wet FGD Scrubbers 

Hg Speciation at Inlet and Outlet ( μ g/dscm@3%O2): % Reduction for OH Train and Coal Data 

Plant ID Run No. 

Hgp In 

OH 

Hg2+ In 

OH 

Hgo In 

OH 

HgT In 

OH 

HgT 

In Coal 

Hgp Out 

OH 

Hg2+ Out 

OH 

Hgo Out 

OH 

HgT Out 

OH 

%R HgT 

OH 

%R HgT 

Coal 

Bituminous Coal, PC Boiler with PS and Wet FGD Scrubber 

Bruce Mansfield 1 0.27 8.65 1.58 10.50 10.93 0.04 1.89 7.01 8.95 14.81 18.11 

Bruce Mansfield 2 0.73 9.84 2.08 12.65 8.93 0.06 2.73 7.96 10.76 14.94 -20.57 

Bruce Mansfield 3 0.27 8.34 1.70 10.31 11.82 0.04 1.22 8.29 9.55 7.42 19.25 

Average 0.42 8.94 1.79 11.15 10.56 0.05 1.95 7.76 9.75 12.39 5.60 

Subbituminous Coal, PC Boiler with PS and Wet FGD Scrubber 

Boswell 4 1 0.11 0.33 5.05 5.48 6.98 0.02 0.10 5.53 5.65 -3.08 19.00 

Boswell 4 2 2.98 1.07 1.47 5.53 6.63 0.20 0.44 5.89 6.53 -18.25 1.41 

Boswell 4 3 2.75 0.55 1.16 4.45 7.93 0.28 0.59 5.57 6.43 -44.40 18.91 

Average 1.95 0.65 2.56 5.15 7.18 0.17 0.38 5.66 6.21 -21.91 13.11 

Cholla 2 1 0.42 0.97 4.68 6.07 6.99 0.15 0.21 3.93 4.29 29.30 38.59 

Cholla 2 2 1.11 0.93 2.62 4.66 6.37 0.19 0.14 4.67 5.01 -7.51 21.38 

Cholla 2 3 0.41 2.06 2.99 5.46 5.09 0.11 0.14 4.22 4.46 18.29 12.27 

Average 0.65 1.32 3.43 5.40 6.15 0.15 0.16 4.27 4.59 13.36 24.08 

Colstrip 1 1.78 2.29 1.08 5.15 7.63 0.05 0.42 9.13 9.60 -86.54 -25.89 

Colstrip 2 1.94 2.37 6.37 10.68 7.98 0.02 0.45 11.03 11.51 -7.74 -44.19 

Colstrip 3 1.63 2.86 5.39 9.88 7.93 0.02 0.39 2.13 2.54 74.27 67.94 

Average 1.78 2.51 4.28 8.57 7.85 0.03 0.42 7.43 7.88 -6.67 -0.71 

Lawrence 1 0.23 1.65 4.99 6.86 6.24 0.01 0.49 6.37 6.87 -0.07 -10.01 

Lawrence 2 0.53 0.63 4.41 5.58 5.47 0.08 0.53 6.71 7.32 -31.14 -33.75 

Lawrence 3 0.24 0.65 4.96 5.86 6.03 0.09 0.51 6.20 6.81 -16.21 -12.96 

Average 0.33 0.98 4.79 6.10 5.91 0.06 0.51 6.42 7.00 -15.81 -18.91 

Average 1.18 1.36 3.76 6.30 6.77 0.10 0.37 5.95 6.42 -7.76 4.39 

Minimum 0.11 0.33 1.08 4.45 5.09 0.01 0.10 2.13 2.54 -86.54 -44.19 

Maximum 2.98 2.86 6.37 10.68 7.98 0.28 0.59 11.03 11.51 74.27 67.94 

STDEV 1.02 0.85 1.82 1.96 0.98 0.09 0.17 2.34 2.40 39.47 31.96 

ND Lignite, PC Boiler with PS and Wet FGD Scrubber 

Lewis and Clark 1 1.15 16.47 11.65 29.27 15.33 0.06 0.50 13.86 14.42 50.75 5.98 

Lewis and Clark 2 1.68 13.64 8.43 23.75 15.54 0.00 0.35 14.19 14.55 38.74 6.41 

Lewis and Clark 3 1.41 6.28 10.20 17.89 18.96 0.00 0.50 15.81 16.31 8.81 13.94 

Average 1.41 12.13 10.09 23.64 16.61 0.02 0.45 14.62 15.09 32.77 8.78 

CONTINUED 

6-43a 
μ

Errata Page 6-43b, dated 3-21-02


Table 6-17 (cont'd) 

Post-combustion Controls: Wet FGD Scrubbers 

Hg Speciation at Inlet and Outlet ( μ g/dscm@3%O2): % Reduction for OH Train and Coal Data 

Plant ID 

Run 

No. 

Hgp In 

OH 

Hg2+ In 

OH 

Hgo In 

OH 

HgT In 

OH 

HgT 

In Coal 

Hgp Out 

OH 

Hg2+ Out 

OH 

Hgo Out 

OH 

HgT 

Out OH 

%R HgT 

Wet 

FGD* 

%R HgT 

PM+FGD 

* 

Bituminous Coal, PC Boiler with CS-ESP and Wet FGD Scrubber 

AES Cayuga 2 0.00 6.40 2.58 8.98 11.87 0.00 0.18 2.70 2.88 67.91 76.06 

AES Cayuga 1 0.00 5.87 2.24 8.11 10.70 0.00 0.36 2.73 3.09 61.88 71.56 

AES Cayuga 3 0.00 5.55 2.95 8.50 10.80 0.00 0.18 3.08 3.26 61.63 71.38 

Average 0.00 5.94 2.59 8.53 11.12 0.00 0.24 2.83 3.08 63.81 73.00 

Big Bend 1 0.09 4.86 2.40 7.34 17.52 0.05 0.21 2.18 2.44 66.70 75.16 

Big Bend 2 0.05 4.92 2.31 7.29 11.25 0.00 0.12 1.75 1.87 74.37 80.88 

Big Bend 3 0.02 4.26 2.13 6.41 12.01 0.03 0.23 2.05 2.31 64.01 73.15 

Average 0.05 4.68 2.28 7.01 13.59 0.03 0.19 1.99 2.21 68.36 76.39 

Average 0.03 5.31 2.43 7.77 12.36 0.01 0.22 2.41 2.64 66.08 74.70 

Minimum 0.00 4.26 2.13 6.41 10.70 0.00 0.12 1.75 1.87 61.63 71.38 

Maximum 0.09 6.40 2.95 8.98 17.52 0.05 0.36 3.08 3.26 74.37 80.88 

STDEV 0.03 0.78 0.30 0.94 2.59 0.02 0.08 0.50 0.53 4.78 3.56 

Subbituminous Coal, PC Boiler with CS-ESP and Wet FGD Scrubber 

Jim Bridger 1 0.05 2.49 5.21 7.74 no coal flow 0.06 0.25 6.63 6.95 10.32 14.60 

Jim Bridger 2 0.44 2.04 5.64 8.12 no coal flow 0.05 0.29 6.51 6.85 15.64 19.67 

Jim Bridger 3 0.07 1.78 4.50 6.35 no coal flow 0.03 0.20 5.92 6.15 3.06 7.69 

Average 0.19 2.10 5.12 7.41 not included 0.05 0.25 6.36 6.65 9.68 13.99 

Laramie River 1 1 0.25 3.14 7.52 10.91 13.52 0.02 0.29 4.86 5.18 52.57 54.83 

Laramie River 1 2 0.04 2.16 8.35 10.55 15.45 0.00 0.12 5.73 5.85 44.54 47.18 

Laramie River 1 3 0.02 3.08 7.53 10.63 15.71 0.01 0.03 4.48 4.52 57.53 59.56 

Average 0.10 2.79 7.80 10.70 14.90 0.01 0.15 5.02 5.18 51.55 53.86 

Sam Seymour 1 0.03 3.00 9.10 12.13 60.48 0.06 0.24 12.25 12.54 1.51 1.51 

Sam Seymour 2 0.01 4.08 13.10 17.19 43.20 0.11 0.29 13.33 13.74 23.90 23.90 

Sam Seymour 3 0.01 5.39 11.96 17.35 51.04 0.06 0.35 11.99 12.39 31.99 31.99 

Average 0.01 4.16 11.38 15.56 51.58 0.07 0.29 12.53 12.89 19.13 19.13 

Average 0.10 3.02 8.10 11.22 33.24 0.04 0.23 7.97 8.24 26.78 28.99 

Minimum 0.01 1.78 4.50 6.35 13.52 0.00 0.03 4.48 4.52 1.51 1.51 

Maximum 0.44 5.39 13.10 17.35 60.48 0.11 0.35 13.33 13.74 57.53 59.56 

STDEV 0.15 1.13 2.94 3.88 20.84 0.03 0.10 3.50 3.59 21.09 20.83 

*Note the column title changes from coal to Wet FGD and PM+FGD CONTINUED 

6-43b 
Errata Page 6-43c, dated 3-21-02


(Intentionally Blank) 

6-43c 
Table 6-17 (cont’d) 

Post-combustion Controls: Wet FGD Scrubbers 

0.07 4.24 8.09 6.28 28.12 

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2 ) : % Reduction for OH Train and Coal Data 

Plant ID Run Hgp In Hg 2+ In Hg° In Hg T In Hg T In Hg p Out Hg 2+ Out Hg° Out HG T Out %R H T %R Hg T 

No. OH OH OH OH Coal OH OH OH OH Wet FGD PM+FGD 

TX Lignite, PC Boiler with CS-ESP and wet FGD Scrubber Monticello 3 1 0.19 16.49 29.39 46.07 61.96 0.31 6.50 29.45 36.25 21.31 21.31 

Monticello 3 2 0.11 19.77 28.15 48.03 63.13 0.18 0.44 25.52 26.14 45.57 45.57 

Monticello 3 

Average 

3 0.13 25.83 27.21 53.16 76.52 0.24 7.26 23.10 30.60 42.44 42.44 

Limestone 1 

0.14 

0.01 

20.70 

23.55 

28.25 

13.38 

49.09 

36.94 

67.20 

14.49 

0.24 

0.04 

4.73 

2.69 

26.02 

15.96 

31.00 36.44 

18.69 49.40 

36.44 

49.40 

Limestone 

Limestone 

2 

3 

0.01 

0.02 

24.55 

28.15 

13.11 

14.11 

37.68 

42.29 

20.84 

15.29 

0.33 

0.12 

3.18 

1.27 

16.23 

17.18 

19.74 47.59 

18.58 56.07 

47.59 

56.07 

Average 

Average 

Minimum 

0.02 

0.08 

0.01 

25.42 

23.06 

16.49 

13.54 

20.89 

13.11 

38.97 

44.03 

36.94 

16.87 

42.04 

14.49 

0.17 

0.20 

0.04 

2.38 

3.56 

0.44 

16.46 

21.24 

15.96 

19.01 51.02 

25.00 43.73 

18.58 21.31 

51.02 

43.73 

21.31 

Maximum 0.19 28.15 29.39 53.16 76.52 0.33 7.26 29.45 36.25 56.07 56.07 

STDEV 

Bituminous Coal, PC Boiler with HS-ESP and wet FGD Scrubber 

0.11 2.76 5.63 7.32 11.89 11.89 

Charles Lowman 1 2.64 3.33 2.09 8.06 23.49 0.06 1.68 3.39 5.13 36.44 44.29 

Charles Lowman 2 1.55 3.98 2.17 7.69 21.50 0.07 1.86 3.50 5.44 29.31 38.03 

Charles Lowman 3 3.45 3.55 2.02 9.01 23.94 0.05 2.06 3.19 5.30 41.18 48.44 

Average 

Morrow 1 

2.55 

0.05 

3.62 

10.80 

2.09 

4.41 

8.26 

15.27 

22.98 

5.48 

0.06 

0.05 

1.87 

2.06 

3.36 

5.00 

5.29 35.64 

7.11 53.46 

43.58 

59.20 

Morrow 2 0.01 8.31 4.10 12.42 5.42 0.03 1.79 4.50 6.31 49.18 55.45 

Morrow 3 0.03 6.98 3.32 10.33 5.38 0.04 1.12 4.55 5.71 44.70 51.52 

Average 

Average 

Minimum 

0.03 

1.29 

0.01 

8.70 

6.16 

3.33 

3.94 

3.02 

2.02 

12.67 

10.46 

7.69 

5.43 

14.20 

5.38 

0.04 

0.05 

0.03 

1.65 

1.76 

1.12 

4.68 

4.02 

3.19 

6.38 49.11 

5.83 42.38 

5.13 29.31 

55.39 

49.49 

38.03 

Maximum 3.45 10.80 4.41 15.27 23.94 0.07 2.06 5.00 7.11 53.46 59.20 

STDEV 1.50 3.05 1.08 2.91 9.65 0.02 0.35 0.75 0.75 8.74 7.66 

Subbituminous Coal, PC Boiler with HS-ESP and wet FGD Scrubber Coronado 1 0.03 0.99 2.19 3.20 4.45 0.02 0.04 3.56 3.61 -12.95 -0.87 

Coronado 2 0.03 0.82 1.86 2.71 4.76 0.08 0.07 1.83 1.98 26.82 34.64 

Coronado 3 0.03 1.09 1.87 2.99 3.86 0.11 0.13 3.08 3.32 -11.30 0.60 

Average 

Craig 1 1 

0.03 

0.04 

0.96 

0.33 

1.97 

3.61 

2.96 

3.97 

4.36 

2.45 

0.07 

0.00 

0.08 

0.13 

2.82 

2.13 

2.97 0.86 

2.26 43.05 

11.46 

49.14 

Craig 1 2 0.04 0.29 2.52 2.85 2.79 0.00 0.11 2.09 2.20 22.93 31.17 

Craig 1 3 0.04 0.16 1.99 2.19 2.30 0.01 0.09 2.03 2.14 2.44 12.87 

Average 

Navajo 1 

0.04 

0.03 

0.26 

2.91 

2.71 

3.55 

3.01 

6.49 

2.51 

4.37 

0.01 

0.05 

0.11 

0.04 

2.08 

3.67 

2.20 22.81 

3.76 42.00 

31.06 

48.20 

Navajo 

Navajo 

2 

3 

0.03 

0.03 

0.45 

0.62 

3.93 

3.50 

4.41 

4.16 

2.63 

2.63 

0.02 

0.01 

0.04 

0.04 

3.79 

3.77 

3.85 12.65 

3.82 8.25 

21.99 

18.06 

Average 

San Juan 1 

0.03 

0.02 

1.33 

6.25 

3.66 

5.81 

5.02 

12.08 

3.21 

7.94 

0.03 

0.05 

0.04 

0.45 

3.75 

7.14 

3.81 20.97 

7.64 36.74 

29.42 

43.50 

San Juan 2 0.08 3.31 4.26 7.65 8.69 0.08 0.38 4.79 5.25 31.35 38.69 

San Juan 3 0.02 5.07 3.62 8.70 11.00 0.05 0.31 4.66 5.02 42.31 48.48 

Average 

Average 

Minimum 

0.04 

0.03 

0.02 

4.87 

1.86 

0.16 

4.56 

3.23 

1.86 

9.47 

5.12 

2.19 

9.21 

4.82 

2.30 

0.06 

0.04 

0.00 

0.38 

0.15 

0.04 

5.53 

3.54 

1.83 

5.97 36.80 

3.74 20.36 

1.98 -12.95 

43.56 

28.87 

-0.87 

Maximum 0.08 6.25 5.81 12.08 11.00 0.11 0.45 7.14 7.64 43.05 49.14 

STDEV 0.02 2.05 1.19 3.02 2.86 0.04 0.14 1.52 1.64 20.32 18.15 

Bituminous Coal, PC Boiler with FF and wet FGD scrubber Clover 1 0.06 1.00 1.11 2.17 29.21 0.05 0.42 0.42 0.88 59.42 96.78 

Clover 

Clover 

Average 

2 

3 

0.03 

0.08 

1.11 

1.16 

1.99 

0.62 

3.13 

1.86 

41.19 

49.02 

0.02 

0.06 

0.34 

0.05 

0.17 

0.14 

0.53 83.13 

0.25 86.76 

98.66 

98.95 

Intermountain 1 

0.06 

0.01 

1.09 

1.01 

1.24 

0.20 

2.39 

1.22 

39.81 

2.00 

0.04 

0.01 

0.27 

0.03 

0.24 

0.25 

0.55 76.43 

0.29 76.15 

98.13 

98.11 

Intermountain 2 0.01 1.08 0.24 1.33 1.97 0.01 0.07 0.46 0.54 59.67 96.80 

Intermountain 3 0.01 1.36 0.22 1.58 3.09 0.01 0.08 0.41 0.50 68.68 97.52 

Average 

Average 

Minimum 

0.01 

0.03 

0.01 

1.15 

1.12 

1.00 

0.22 

0.73 

0.20 

1.38 

1.88 

1.22 

2.35 

21.08 

1.97 

0.01 

0.03 

0.01 

0.06 

0.16 

0.03 

0.37 

0.31 

0.14 

0.44 68.16 

0.50 72.30 

0.25 59.42 

97.48 

97.80 

96.78 

Maximum 0.08 1.36 1.99 3.13 49.02 0.06 0.42 0.46 0.88 86.76 98.95 

STDEV 0.03 0.13 0.71 0.70 21.47 0.02 0.17 0.14 0.23 11.66 0.92 

6-44

μ

μ

Bit, CS-ESP+wet FGD [66%] 

Sub, CS-ESP+wet FGD [27%] 

Lig, CS-ESP+wet FGD [44%] 

Sub, HS-ESP+wet FGD [20%] 

Hg(p) Out Hg(2+) Out Hg(0) Out 

Bit, HS-ESP+wet FGD [42%] 

Co

al/APCD [Hg Reductio

n,%] 

Bit, FF+wet FGD [72%] 

Lig, PM+wet FGD [33%] 

Sub, PM+wet FGD [-8%] 

Bit, PM+wet FGD [12%] 

0 5 10 15 20 25 30 

Mercury Concentration, μg/dscm @ 3% O2 

Figure 6-17. Mercury speciation for PC boilers with wet FGD. 

Sub, HS-ESP+wet FGD [20%] 

Inlet Outlet 

Coal/APCD [Hg Reduction ,%] Bit, HS-ESP+wet FGD [42%] 

Lig, CS-ESP+wet FGD [44%] 

Sub, CS-ESP+wet FGD [27%] 

Bit, CS-ESP+wet FGD [66%] 

Bit, FF+wet FGD [72%] 

Lig, PM+wet FGD [33%] 

Sub, PM+wet FGD [-8%] 

Bit, PM+wet FGD [12%] 

0 5 10 15 20 25 30 35 40 45 50 

Mercury Concentration, μg/dscm @ 3% O2 

Figure 6-18. Mercury emissions for PC boilers with wet FGD. 

6-45

Sub, HS-ESP+wet FGD [20%] 

Hg(p) Out Hg(2+) Out Hg(0) Out 

Coal/APCD [Hg Reduction ,%] 

Bit, HS-ESP+wet FGD [42%] 

Lig, CS-ESP+wet FGD [44%] 

Sub, CS-ESP+wet FGD [27%] 

Bit, CS-ESP+wet FGD [66%] 

Bit, FF+wet FGD [72%] 

Lig, PM+wet FGD [33%] 

Sub, PM+wet FGD [-8%] 

Bit, PM+wet FGD [12%] 

0 10 20 30 40 50 60 70 80 90 100 

Relative Mercury Concentration in Stack, % 

Figure 6-19. Relative mercury speciation for PC boilers with wet FGD. 

The best levels of HgT capture are exhibited by units burning bituminous coal and 

equipped with a FF (98 percent), CS-ESP (75 percent), or HS-ESP (50 percent). The higher 

capture levels for bituminous-fired boilers equipped with the CS-ESP, HS-ESP, or FF control 

devices are consistent with the high levels of Hg0

 oxidization associated with these coal-boiler 

control classes (see Figures 6-12 and 6-13). The very high levels of Hg capture exhibited by 

the bituminous-coal-fired boiler units with a FF and wet FGD system can be attributed to high 

levels of Hg0

 oxidization and to the capture or conversion of Hgp and Hg2+ as flue gas passes 

through the FF cake. Estimates of HgT capture across the wet FGD and PM + wet FGD 

combinations are shown in Table 6-18 for units burning bituminous coal. Detailed data for 

these units are given in Table 6-17. The best control is exhibited by wet FGD systems 

equipped with a FF followed by units equipped with a CS-ESP and a HS-ESP. 

The HgT capture in one test unit burning bituminous coal and equipped with a PM 

scrubber + wet FGD system averaged 12 percent. Hg at the outlet of the scrubber was 

predominantly Hg0

. 

6-46

Table 6-18


Wet FGD Scrubbers Burning Bituminous Coal


Controls and Test Unit Reduction in HgT, % 

FF + Wet FGD FGD PM + FGD 

Clover 76 98 

Intermountain 68 97 

Average 72 98 

CS-ESP + Wet FGD 

Big Bend 68 76 

AES Cayuga 64 73 

Average 66 75 

HS-ESP + Wet FGD 

Charles R. Lowman 36 44 

Morrow 49 55 

Average 43 50 

The estimated capture of HgT in wet FGD units burning subbituminous coals is given 

in Table 6-19. The four PS units were Boswell 4, Cholla 2, Colstrip, and Lawrence. The inlet 

and outlet HgT data appeared reasonable except for runs 1 and 2 on Colstrip. All tests on 

Lawrence and Boswell 4 had HgT outlet concentrations higher than the corresponding HgT 

inlet concentrations. Cholla 2, which had HgT emission reductions ranging from -8 to 29 

percent, appeared to exhibit hysterisis effects. One unit, Lewis and Clark, burned a ND 

lignite. This unit also appeared to exhibit hysterisis effects, with successive HgT reductions 

for the three tests of 51, 39, and 9 percent. The declining reductions in HgT capture were 

mirrored by inlet reductions of HgT and Hg2+. 

The erratic nature and differences in capture for the CS-ESP units are probably due to 

differences in the subbituminous coals being burned and the differences in the scrubber 

operating conditions. Except for the Coronado tests, the test results on HS units were fairly 

consistent. It is not known whether the sampling and analysis results from the Coronado unit 

are incorrect or whether differences in the coal and operating conditions caused the lower HgT 

capture results. 

6-47

Errata Page 6-48, dated 3-21-02 

Table 6-19


Wet FGD Scrubbers Burning Subbituminous Coal


Controls 

and Test Unit 

Reduction 

in HgT,% 

PS + Wet FGD FGD PM + FGD 

Boswell 4 NA -22 

Cholla 2 NA 13 

Colstrip NA -7 

Lawrence NA -16 

Average -8 

HS-ESP + Wet FGD 

Coronado 1 11 

Craig 1 23 31 

Navajo 21 29 

San Juan 37 44 

Average 20 29 

CS-ESP + Wet FGD 

Jim Bridger 10 14 

Laramie 1 52 54 

Sam Seymour 19 19 

Average 27 29 

Two units, burning TX lignite and equipped with a CS-ESP, exhibited average HgT 

captures of 46 percent (see Table 6-20). The SPF2+ for limestone was 0.65 and the SPF2+ for 

Monticello 3 was 0.42, indicating moderately high relative concentrations of Hg2+ at the 

scrubber inlets of these two units. TX lignites appear to have a higher oxidization and capture 

potential than ND lignites. 

6-48

Errata Page 6-49, dated 3-21-02 

Table 6-20


Wet FGD Scrubbers Burning TX Lignite


Controls and Test Unit Reduction in HgT,% 

CS-ESP + Wet FGD FGD PM + FGD* 

Limestone 51 51 

Monticello 3 36 36 

Average 44 44 

*Estimated 

6.6.6 Potential Effects of Post-combustion NOX Controls 

Post-combustion NOX controls convert NOX in the boiler flue gases to molecular 

nitrogen and water using a catalytic process (selective catalytic reduction) or a noncatalytic 

process (selective noncatalytic reduction). For both processes, a reducing agent (usually 

ammonia) is injected into the boiler flue gas at a point upstream of any post-combustion PM 

or SO2 control device. A limited amount of data is available in the ICR Hg emission database 

regarding the potential effects of these post-combustion NOX controls on Hg capture. These 

data are presented in Table 6-21. Test results for pulverized-coal boilers burning bituminous 

coal with either SNCR or SCR systems are compared to the results of tests on similarly 

controlled units that do not use post-combustion NOX controls. 

Table 6-21


Potential Effects of Post-combustion NOX Control Technologies on Mercury Capture in


PC-fired Boilers Burning Bituminous Coal


Post-combustion 

Controls 

Postcombustion 

NOX Control 

Number of 

Pulverizedcoal-fired 

Boiler Units 

Tested 

Average Mercury 

Capture by Control 

Configuration 

CS-ESP none 6 36% 

SNCR 1 91% 

SDA + FF none 2 98% 

SCR 1 98% 

Tests on the single pulverized-coal boiler unit using a CS-ESP with SNCR shows an 

average Hg capture that is significantly higher than the six units tested with a CS-ESP using 

no post-combustion NOX controls (91 percent with SNCR versus 36 percent without SNCR). 

It was reported that the fly ash from the boiler unit using SNCR contained unusually high 

levels of carbon. Because data are available only for this one test, it is not known whether 

6-49

the high levels of Hg capture indicated by the test results are attributable to the high fly ash 

carbon content, the use of an SNCR system, a combination of both, or some other sitespecific factor. 

A comparison of tests for pulverized-coal boiler units using an SDA with an FF 

shows no discernable difference in Hg capture with or without the use of an SCR for postcombustion NOX control. An average Hg capture of 98 percent was measured by the tests on 

the one unit equipped with an SCR compared to 98 percent Hg capture for the two similar 

units without SCR systems. Because of the very high levels of Hg capture by all of the tested 

control configurations, it is not possible to determine the effect of SCR on Hg capture. 

Recent tests on a pilot-scale, pulverized-coal combustor, which was equipped with an 

SCR and a CS-ESP, showed increased Hg capture when bituminous coals were burned but 

not when a subbituminous coal was burned. Mercury emission reductions were observed 

when the SCR system was operated normally with the injection of ammonia upstream of the 

SCR catalyst. Improvement of Hg capture was also noted when ammonia was injected, but 

the SCR catalyst was bypassed. These tests provide evidence that SNCR and SCR systems 

may enhance Hg capture under some conditions. 

6.7 COMBUSTION SYSTEM EFFECTS 

LNBs and combustion modification techniques are believed to increase the unburned 

carbon in fly ash and increase the adsorption of Hg onto collectable fly ash. Since neither the 

fly ash carbon content nor the LOI was measured during the ICR field test, it is not possible 

to evaluate Hg capture performance benefits that accrue from the use of NOX control 

combustion modification techniques. The ICR field test program included tests on six 

different unit classes using cyclone-fired boilers and six unit classes with FBCs. The results 

of ICR tests on units with cyclone-fired boilers and FBCs are shown in Tables 6-22 and 6-23, 

respectively. 

6-50

Errata Page 6-51, dated 3-21-02


Table 6-22 

Cyclone-fired Boilers 

Average 0.06 2.85 2.70 5.61 4.56 0.00 0.35 2.75 3.11 54.43 30.97 

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2) : % Reduction for O-H Train and Coal Data 

Plant ID Run Hgp In Hg2+ In Hg In HgT In HgT In Hgp Out Hg2+ Out Hg Out HGT Out %R HT %R HgT 

No. O-H O-H O-H O-H Coal O-H O-H O-H O-H O-H Coal 

ND Lignite, Cyclone Boiler with CS-ESP 

Leland Olds 1 0.56 0.23 3.30 4.09 5.63 0.00 0.82 4.04 4.86 -18.68 13.66 

Leland Olds 2 0.26 0.46 8.80 9.51 10.18 0.00 1.09 5.26 6.35 33.26 37.64 

Leland Olds 3 2.85 0.81 4.77 8.43 7.94 0.00 1.60 LS NA NA NA 

Average 0.41 0.34 6.05 6.80 7.90 0.00 0.95 4.65 5.60 7.29 25.65 

Subbituminous/Pet. Coke, Cyclone Boiler with HS-ESP 

Nelson Dewey 1 0.01 0.49 3.20 3.69 6.62 0.10 0.26 3.33 3.69 0.13 44.27 

Nelson Dewey 2 0.01 0.24 2.19 2.43 6.47 0.04 0.16 2.40 2.60 -6.90 59.83 

Nelson Dewey 3 0.01 0.12 2.06 2.18 6.09 0.04 0.25 2.44 2.73 -24.95 55.22 

Average 0.01 0.28 2.48 2.77 6.39 0.06 0.22 2.72 3.00 -10.57 53.11 

Lignite, Cyclone Boiler with Mechanical Collector 

Bay Front 1 0.76 0.78 2.17 3.70 3.58 1.19 0.60 1.91 3.69 0.34 -2.95 

Bay Front 2 1.08 0.67 1.94 3.69 3.01 0.86 2.75 1.80 5.40 -46.54 -79.21 

Bay Front 3 0.09 0.77 1.74 2.60 3.36 0.48 3.57 1.78 5.84 -125.00 -73.79 

Average 0.64 0.74 1.95 3.33 3.32 0.84 2.30 1.83 4.98 -57.07 -51.99 

Lignite, Cyclone Boiler with SDA/FF 

Coyote 1 0.69 1.62 13.68 15.99 10.51 0.08 0.04 13.97 14.10 11.81 -34.23 

Coyote 2 1.18 2.98 13.90 18.06 18.55 0.14 0.24 LS NA NA NA 

Coyote 3 1.69 3.07 14.91 19.66 11.39 0.08 0.44 18.06 18.58 5.48 -63.12 

Average 1.19 2.34 14.29 17.82 10.948803 0.08 0.24 16.02 16.34 8.64 -48.673625 

Bituminous, Cyclone Boiler with PS and Wet FGD Scrubbers 

Lacygne 1 6.70 3.99 1.30 12.00 no inlet flow 0.04 0.44 8.74 9.22 23.18 no inlet flow 

Lacygne 2 6.52 3.34 0.60 10.46 no inlet flow 0.05 0.43 7.41 7.89 24.53 no inlet flow 

Lacygne 3 5.98 0.59 0.61 7.18 no inlet flow 0.09 0.41 5.10 5.59 22.17 no inlet flow 

Average 6.40 2.64 0.84 9.88 0.06 0.43 7.08 7.57 23.29 

Bituminous, Cyclone Boiler with CS-ESP and wet FGD Scrubber 

Bailly 1 0.04 3.18 2.57 5.79 4.41 0.00 0.36 2.85 3.22 54.24 27.09 

Bailly 2 0.04 2.37 2.95 5.36 5.20 0.00 0.31 2.62 2.93 54.95 43.53 

Bailly 3 0.09 3.01 2.58 5.68 4.08 0.00 0.39 2.78 3.17 54.11 22.31 

6-51

Errata Page 6-52, dated 3-21-02 

Table 6-23 

Fluidized Bed Combustors 

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2) : % Reduction for O-H Train and Coal Data 

Plant ID Run Hgp In Hg2+ In Hg° In HgT In HgT In Hgp Out Hg2+ Out Hg Out HgT Out %R HT %R HgT 

No. O-H O-H O-H O-H Coal O-H O-H O-H O-H O-H Coal 

Lignite, FBC with CS-ESP 

R.M. Heskett 1 4.73 5.39 3.83 13.95 13.54 1.06 1.44 4.57 7.07 49.29 47.76 

R.M. Heskett 2 2.93 0.96 2.61 6.50 12.68 0.07 0.41 5.31 5.78 11.09 54.40 

R.M. Heskett 3 7.43 0.44 3.08 10.94 11.11 0.05 0.18 4.74 4.98 54.49 55.19 

Average 5.03 2.26 3.17 10.46 12.44 0.39 0.68 4.87 5.95 38.29 52.45 

Anthracite Waste, FBC with FF 

Kline Township 1 44.54 0.12 0.45 45.11 148.68 0.00 0.06 0.06 0.12 99.74 99.92 

Kline Township 2 43.12 0.06 0.40 43.58 212.95 0.00 0.06 0.06 0.12 99.73 99.95 

Kline Township 3 44.97 0.06 0.34 45.37 153.77 0.00 0.06 0.06 0.12 99.74 99.92 

Average 44.21 0.08 0.40 44.69 171.80 0.00 0.06 0.06 0.12 99.74 99.93 

Bituminous Waste, FBC with FF 

Scrubgrass 1 184.04 0.68 0.19 184.91 100.09 0.00 0.07 0.08 0.15 99.92 99.85 

Scrubgrass 2 124.11 0.42 0.09 124.62 101.35 0.00 0.05 0.07 0.12 99.91 99.89 

Scrubgrass 3 76.68 0.22 0.07 76.97 100.25 0.00 0.04 0.07 0.11 99.85 99.89 

Average 128.28 0.44 0.12 128.83 100.56 0.00 0.05 0.07 0.13 99.89 99.88 

Bituminous/Pet. Coke, FBC with SNCR and FF 

Stockton Cogen 1 2.71 0.06 0.06 2.83 1.68 0.02 0.04 0.05 0.11 96.09 93.39 

Stockton Cogen 2 1.56 0.07 0.06 1.69 1.44 0.03 0.05 0.05 0.13 92.16 90.80 

Stockton Cogen 3 2.08 0.06 0.06 2.20 1.66 0.03 0.05 0.05 0.12 94.48 92.67 

Average 2.12 0.07 0.06 2.24 1.59 0.03 0.05 0.05 0.12 94.25 92.29 

Subbituminous, FBC w ith SCR and FF 

AES Hawaii 1 0.26 0.04 1.29 1.59 3.77 0.00 0.02 0.68 0.70 55.84 81.39 

AES Hawaii 2 0.35 0.17 1.38 1.90 3.72 0.00 0.02 0.90 0.92 51.35 75.16 

AES Hawaii 3 0.36 0.11 1.18 1.64 2.51 0.00 0.02 0.55 0.58 64.91 77.06 

Average 0.32 0.10 1.28 1.71 3.33 0.00 0.02 0.71 0.73 57.37 77.87 

Lignite, FBC with CS-FF 

TNP 1 21.65 8.68 7.42 37.74 63.81 0.04 12.13 4.74 16.91 55.20 73.50 

TNP 2 10.65 4.51 6.09 21.25 44.22 0.03 6.78 2.94 9.76 54.07 77.93 

TNP 3 28.12 13.78 7.04 48.94 95.04 0.04 13.54 5.07 18.66 61.88 80.37 

Average 20.14 8.99 6.85 35.98 67.69 0.04 10.82 4.25 15.11 57.05 77.27 

6.7.1 Cyclone-fired Boilers 

Mercury capture and stack gas speciation for cyclone-fired boilers are shown in 

Figures 6-20 and 6-21. The percentage of total Hg capture in these units appears to be similar 

to the Hg captured in pulverized-coal-fired units burning similar fuels and equipped with 

comparable air pollution control devices (see Table 6-24). Except for the unit equipped with 

a mechanized collector, the Hg in flue gas consisted primarily of Hg0

. 

6-52

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μ

Relative Mercury Concentration in Stack, % 

Mercury Concentration, 

μg/dscm @ 3% O2 18 

16 

14 

12 

10 

8 

6 

4 

2 

0 

Bit/CS-ESP/Wet- Lignite/CS-ESP Lig/MC (-57) Bit/PS (23) Sub-Pet/HS-ESP Lignite/SDA/FF 

FGD (54) (7) (-11) (9) 

Hg(p) Out Hg(2+) Out Hg(0) Out 

Coal/APCD (Hg Reduction, %) 

Figure 6-20. Mercury speciation for cyclone-fired boilers. 

100 

90% 

80% 

70% 

60% 

50% 

40% 

30% 

20% 

10% 

0% 

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Bit/CS- Lignite/CS-ESP Lig/MC (-57) Bit/PS (23) Sub-Pet/HS-ESP Lignite/SDA/FF 

ESP/Wet-FGD (7) (-11) (9) 

(54) Coal/APCD (Hg Reduction, %) 

Figure 6-21. Relative mercury speciation for cyclone-fired boilers. 

Hg(0) Out 

Hg(2+) Out 

Hg(p) Out 

6-53

Table 6-24


Comparison of Class Average


HgT Reductions for PC- and Cyclone-fired Boilers


Unit Class 

Reduction in HgT, % 

Cyclone PC-Fired 

Lignite, CS-ESP 9 36 

Subbituminous/Pet Coke, HS-ESP 0 7 

Lignite, Multicyclone 0 NA 

ND Lignite, SDA/FF 7 2 

Bituminous, PM scrubber + wet FGD 23 12 

Bituminous, CS-ESP + wet FGD 54 81 

6.7.2 Fluidized-bed Combustors 

Six fluidized-bed combustors were tested on the ICR program. Test results for the 

fluidized-bed units are shown in Figures 6-22 and 6-23. All of the units injected limestone 

into the FBC to control SO2 emissions. One unit was equipped with a CS-ESP while the 

remaining five units were equipped with a FF. One of the FF units was also equipped with an 

SNCR system. The unit equipped with the CS-ESP burned lignite. The capture of HgT for 

this unit averaged 38 percent. The reduction in HgT for units equipped with FF systems 

depended primarily on the type of fuel that was burned. The one unit that burned 

subbituminous coal was equipped with an SCR system and a FF. Inlet and outlet HgT 

concentrations for the two valid runs on this unit were 1.7 and 0.7 μg/dscm, respectively, 

resulting in a 57 percent capture efficiency. One unit that burned waste anthracite had an 

average HgT reduction efficiency of 99.7 percent, while another unit burning bituminous coal 

and petroleum coke had an average reduction of 94 percent. 

The best performance for any unit tested during the Part III ICR program exhibited 

average HgT inlet concentrations of 185 μg/dscm, outlet concentrations of 0.15 μg/dscm, and 

an average HgT reduction of 99.9 percent. 

6-54

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μ

12 

Relative Mercury Concentration in Stack, % 

Mercury Concentration, 

μg/dscm @ 3% O2

10 

8 

6 

4 

2 

0 

Hg(p) Out 

Hg(2+) Out 

Hg(0) Out 

Lignite/CS-ESP Ant (waste)/FF Bit-Pet/FF (94) Bit (waste)/FF Sub/SCR/FF (57) Lig/FF (57) 

(38) (99) (99) 

Coal/APCD (Hg Reduction, %) 

Figure 6-22. Mercury speciation for FBCs. 

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����������� �����������

����������� �����������

�����������

����������� �����������

Lignite/CS-ESP Ant (waste)/FF Bit-Pet/FF (94) Bit (waste)/FF Sub/SCR/FF Lig/FF (57) 

(38) (99) (99) (57) 

Coal/APCD (Hg Reduction, %) 

Figure 6-23. Relative mercury speciation for FBCs. 

Hg(0) Out 

����� Hg(2+) Out 

Hg(p) Out 

100% 

90% 

80% 

70% 

60% 

50% 

40% 

30% 

20% 

10% 

0% 

6-55

μ

- - - - -

6.7.3 IGCC Facilities 

Table 6-25 summarizes the emission source test data and coal analysis data for the 

Tampa Electric Company Polk Power Project and Wabash River Coal Gasification 

Repowering Project. A more detailed presentation of the test data is included in Appendix C 

of this report. Coal data were used to calculate inlet feed rates of total Hg to the coalgasification units. The total Hg in the exhaust gas from the gas turbine was determined by 

summing the three Hg species obtained using the OH Method during each test run (i.e., Hgp, 

Hg2+, and Hg0). 

Table 6-25


Calculated Mercury Removal in IGCC Power Plants Using Bituminous Coal


IGCC 

Facility 

Test 

Run 

Coal Fed to Gasifer Gas Turbine Exhaust Gas Stream 

Overall 

Mercury 

Removal 

(%) 

Coal 

Flow 

Rate 

(kg/hr, 

dry) 

Total Hg 

Content 

(ppm, 

dry) 

Total Hg 

Feed 

Rate 

(kg/hr) 

Gas Stream 

Flow Rate 

(dscm/hr) 

Total Hg 

Content c 

(μg/dscm) 

Total Hg 

Emission 

Rate 

(kg/hr) 

Tampa 

Electric 

Company 

Polk Power 

Project 

Run 1 91,454 ND a 0.0091 b 1,430,191 3.94 d 0.0056 38 

Run 2 88,707 ND a 0.0089 b 1,453,617 3.86 d 0.0056 37 

Run 3 71,373 ND a 0.0071 b 1,414,052 3.68 d 0.0052 27 

3-Run 

Average 83,845 0.0084 1,432,620 3.83 d 0.0055 34 

Wabash River 

Coal 

Gasification 

Repowering 

Project 

Run 1 90,663 0.064 0.0058 1,372,064 2.57 e 0.0035 40 

Run 2 89,629 0.068 0.0061 1,385,884 2.60 e 0.0036 41 

Run 3 89,493 0.070 0.0063 1,352,458 2.76 e 0.0037 41 

3-Run 

Average 89,928 0.067 0.0061 1,370,135 2.64 e 0.0036 41 

(a) No mercury was detected by the test method used to analyze the coal.


(b) Feed rate calculated assuming total mercury content of the coal is at the detection limit for the analytical method (0.1 ppm).


(c) Total mercury content of the gas turbine exhaust stream determined using Ontario-Hydro Method results.


(d) No particle-bound mercury was detected by the Ontario-Hydro Method. To calculate total Hg content, it is assumed that particle-bound


mercury concentration in gas stream is negligible. It is reasonable to assume that, consistent with good IGCC operating practices, the 

total particle concentration of the syngas burned in the gas turbine needs to be very low in order to prevent premature wear of the gas 

turbine blades. 

(e)	 No particle-bound mercury or oxidized mercury was detected by the Ontario-Hydro Method. To calculate total Hg content it is assumed 

that particle-bound mercury and oxidized mercury concentrations in the gas stream are negligible. At the Wabash River facility the 

syngas is cleaned and conditioned before burning in the gas turbine by a barrier filter for particulate removal, a water scrubber for gas 

cooling, and an amine scrubber for removal of reduced-sulfur species. It is reasonable to assume that these filtration and scrubbing 

processes remove the particle-bound and oxidized mercury from the gas stream. 

The operating difficulties experienced at the Pinon Pine IGCC facility demonstrate that 

good operating practices dictate the need for the concentration of particulate matter in the 

syngas to be continuously maintained at very low levels to prevent premature gas turbine 

blade erosion. The OH Method measurements obtained at both of the tested IGCC facilities 

are consistent with this operating practice. In both cases, the OH Method detected no particlebound Hg in the gas turbine exhaust gas. With very low numbers of particles in the syngas 

6-56

stream to begin with, the elemental Hg released during the coal gasification process has very 

few opportunities to be adsorbed on solid particles to form particle-bound Hg. 

The OH Method test results show that elemental Hg is the predominant species in the 

gas turbine exhaust gas. For the Polk IGCC facility, the measured distribution of gaseous Hg 

species was approximately 90 percent elemental Hg and 10 percent Hg2+. For the Wabash 

River IGCC facility, no Hg2+ was detected by the OH Method (i.e., 100 percent of the HgT in 

the exhaust gas stream was in the form of Hg0

). One possible explanation for these results is 

the different gas cleaning processes used at the two IGCC facilities. The syngas from the 

coal gasifier at the Wabash River IGCC facility is cleaned and conditioned using a system 

that includes a water scrubber for gas cooling and an amine scrubber for removal of reducedsulfur species. Oxidized Hg is water-soluble and is readily absorbed by a wet scrubbing 

system. However, Hg0 is insoluble and passes through a wet scrubbing system. Thus, it is 

reasonable to expect that the water and amine scrubbers used at the Wabash River IGCC 

facility effectively remove the oxidized Hg in the syngas before it is burned in the gas 

turbine. 

The Polk IGCC facility uses a hot gas-cleaning system. There is no wet scrubbing 

process to remove any Hg2+ from the syngas before it is burned. The syngas is not cooled and 

remains at elevated temperatures until it is fed to the gas turbine. It cannot be determined 

from the test data how the elevated syngas temperatures and combustion process in the gas 

turbine combustors affect Hg speciation. However, it is believed that any Hg2+ in the syngas 

will be converted back to Hg0

 when the syngas is burned. The degree of oxidization will 

probably be limited by the combustion gas composition and the rate at which it is cooled 

before it is emitted to the atmosphere. 

The last column in Table 6-25 provides an estimate of the overall amount of Hg in the 

coal removed by the IGCC process. Based on these two tests, approximately one-third of the 

Hg in the coal is removed. The Hg that remains in the combustion gas is primarily Hg0

. 

6.8 NATIONAL AND REGIONAL EMISSION ESTIMATES 

Estimates of the nationwide Hg emissions provide an indication of the overall level of 

Hg capture being achieved by existing control systems used by coal-fired utility boilers in the 

United States. A number of different approaches can be used for these estimates. The EPA 

evaluated four different methods for estimating nationwide Hg emissions using information 

from the ICR database. The method selected as being the best is outlined below: 

•	 ICR Part II coal data were used to determine the average Hg content and the 

amount of coal burned in each of 1143 units supplying data for 1999. 

•	 Mercury in the flue gas from coal burned in each boiler unit in 1999 was 

calculated assuming that all of the Hg in the coal was in the flue gas leaving the 

furnace. 

6-57

•	 Each unit was assigned a coal-boiler-control class that best met the characteristics 

of the unit. 

•	 Total Hg in the boiler flue gas for each unit was multiplied by the class emission 

factors for speciated and total Hg that had been assigned to the unit. 

•	 Total and speciated Hg emissions for each unit were added to provide estimates of 

national Hg emissions from coal-fired utility boilers in 1999. 

Computer runs using this procedure resulted in estimated national Hg emissions in 

1999 of 43.5 tons. 

Using the EPA’s ICR database, EPRI independently estimated the nationwide Hg 

emissions from existing coal-fired utility boilers in the United States to be in the range of 45 

to 48 tons in 1999. EPRI selected a different estimation methodology than the one used by 

EPA. EPRI’s method is based on a model that correlates the level of Hg emissions with the 

amount of chlorine in coal and the ratio of chlorine to sulfur in the coal for the case of units 

with cold-side ESPs. Both the EPA and EPRI estimate that approximately 75 tons of Hg was 

in coals burned in1999. 

After EPA announced its decision to develop the NESHAP, the transfer of data from 

the field test reports to the emission databases was rechecked for errors. It was found that 

several test units had been assigned to the wrong coal-boiler-control classes. Also, the results 

of a number of tests failed data quality requirements and were removed from the analysis set. 

Subsequent computer evaluations resulted in the following estimates: 

•	 48 tons of Hg was emitted to the atmosphere from coal-fired utility boilers in 

1999, and 

• 27 tons of Hg was captured by existing flue gas cleaning devices. 

Nationwide, approximately 25 tons (52 percent) of Hg was emitted from the 

combustion of bituminous coal, followed by 17 tons (36 percent) from the combustion of 

subbituminous coals, and 4 tons (8 percent) from the combustion of lignite. The total 

amounts of Hg emitted compared to the tonnage and types of coal burned in 1999 are 

presented in Table 6-26. 

6-58

Table 6-26 

Nationwide Coal Burned and Mercury Emitted 

From Electric Utility Coal-fired Power Plants in 1999 

Coal Type 

Nationwide 

Total Coal 

Tonnage 

Burned In 1999 

(dry tons) (a) 

Percent of 

Total Coal 

Burned 

Nationwide 

Total Mercury 

Emitted in 1999 

(tons) 

Percent of 

Total Mercury 

Emitted 

Bituminous 427,572,000 56 25 52 

Subbituminous 279,227,000 36 17 36 

Lignite 50,932,000 7 4 8 

Other 10,756,000 1 2 4 

Total 768,487,000 100 48 100 

(a) 	For wet tons (as received), nationwide total is 928,398,000 tons in 1999. 

Percentages for wet tons are 50% bituminous, 41% subbituminous, and 8% lignite. 

6.9 SUMMARY AND CONCLUSIONS 

Previous research has shown that the capture of Hg by flue gas cleaning devices is 

dependent on Hg speciation. Both Hg0 and Hg2+ are in a vapor phase at flue gas cleaning 

temperatures. Hg0

 is insoluble in water and cannot be captured in wet scrubbers. The 

predominant Hg2+compounds in coal flue gas are weakly-to-strongly soluble and can be 

generally captured in wet FGD scrubbers. Both Hg0

 and Hg2+can be adsorbed onto porous 

solids such as fly ash, PAC, or calcium-based acid gas sorbents for subsequent collection in a 

PM control device. Hg2+ is generally easier to capture by adsorption than Hg0

. Hgp is attached 

to solids that can be readily captured in ESPs and FFs. 

The evaluation of ICR data provides valuable insights into relationships between the 

speciation and capture of Hg, the type of coal burned, the types of boilers used, and the types 

of post-combustion technologies used for flue gas cleaning. The evaluation of ICR data 

indicates that the behavior of Hg in conventional PC-fired utility boilers is primarily 

dependent on the type of coal burned and the control technologies used at each site. This 

behavior is consistent with the ensuing interpretations. 

6-59

Bituminous Coals 

The Hg0 in flue gas from the combustion of bituminous coal is readily oxidized and 

converted to Hgp or Hg2+. The best technologies for controlling corresponding Hg emissions 

are dry or wet FGD scrubbers along with post-combustion PM controls. Dry scrubbing 

systems that use a SDA/FF are superior in performance to those that use a SDA/ESP. In 

SDA/FF systems, Hg can be absorbed on PM in the SDA, and particulate- and gas-phase Hg 

can be captured as it passes through the FF and its associated filter cake. SDA/ESP systems 

depend on the in-fight capture of Hg. 

A PM control device always precedes wet FGD scrubbers. Four types of PM control 

devices are commonly used: FFs, CS-ESPs, HS-ESPs, and PM scrubbers. Units equipped 

with a FF exhibit the best capture followed by units equipped with a CS-ESP, HS-ESP, and 

PM scrubbers. Units that are equipped with FF + wet FGDs can capture Hg in FF and can 

convert Hg0 to Hg2+ for subsequent capture in the scrubber. Hg capture in CS-ESP + wet FGD 

systems depends on the degree of Hg capture and oxidization as the flue gas passes through 

the CS-ESP. Hg capture in units equipped with HS-ESPs is generally lower than the capture 

in CS-ESPs because HS-ESPs operate at temperatures where the oxidization and capture of 

Hg is limited. The single test unit equipped with a PS + wet FGD system exhibited an average 

HgT capture of 12 percent. 

Subbituminous Coals 

Some subbituminous coals exhibit little, if any, Hg0 oxidization in PC-fired boilers. 

Others display moderate amounts of Hg0

 oxidization. The use of low NOX burners tends to 

increase the amount of unburned carbon and the potential for capturing gas-phase Hg. The 

ICR data show that the oxidization of Hg0

 can occur from gas-phase reactions or gas/solid 

reactions with fly ash or surface deposits in power plants. The unburned carbon in fly ash can 

oxidize Hg0

 or adsorb gas-phase Hg. Hg2+is believed to be more readily captured by 

adsorption than Hg0

. Because of temperature considerations, the adsorption of Hg onto fly ash 

in units equipped with CS-ESPs is believed to occur as the flue gas flows through the air 

preheater and the ducting that leads to the ESP. Additional adsorption can also occur within 

the ESP. 

Flue gas from the combustion of bituminous coal contains moderate to high levels of 

Hg2+, primarily in the form of HgCl2. 

The EPA ICR database provides a massive amount of information that can be mined for 

additional information. However, its usefulness is limited by the uncertainty of some of the 

measurements and by information that the data set does not contain. Some of the uses and 

limitations of the ICR data are summarized below. The data provide: 

•	 Reasonable estimates of National and Regional emissions for Hgp, Hg2+, Hg0

, and 

HgT. They cannot be used to predict the total and speciated Hg emissions of 

individual plants. 

6-60

•	 Information against which hypotheses and models of the speciation and capture of Hg 

in coal-fired boilers can be tested. It cannot be used to identify or confirm specific 

mechanisms that control the speciation and capture of Hg. 

•	 Information needed to guide the development of control technologies and identify 

effective strategies for the control of Hg emissions. 

Cautions: 

•	 Mercury speciation measurements made with the OH Method upstream of the PM 

control devices should be used with caution. PM collected on the sampling train filter 

can result in physical and chemical transformations with the sampling train – with the 

result that OH Method speciation results do not accurately characterize the different 

forms of Hg in the flue gas where the samples were collected. The OH Method 

samples for HgT accurately reflect the concentration of HgT in the flue gas where the 

sample was collected. Also the samples collected at the inlet to air pollution control 

devices may not accurately represent the average Hg concentration because of flow 

stratifications near the sampling location. 

•	 At low inlet and outlet concentrations, the precision of the OH Method can obscure 

real differences between these concentrations. When the capture across the control 

devices is being evaluated, the underlying imprecision of the measurements can show 

dramatic positive or negative reductions in emissions. 

•	 It is believed that the positive variations in flue gas temperature can result in desorption of Hgp collected within PM control devices, resulting in flue gas 

concentrations of Hg that are higher at the outlet than at the inlet. Reentrainment of 

Hgp during rapping cycles of an ESP can also result in outlet concentrations that are 

higher than the inlet. 

•	 There is uncertainty in the central values and statistical characteristics of the OH 

measurements. The samples represent a short snapshot in time, and the effects of 

long-term variations in coal properties and plant operating conditions are unknown. 

•	 The adsorption of Hg onto fly ash is highly dependent on fly ash properties and 

particularly on the fly ash carbon content. The lack of information on coal and fly 

ash properties limits the ability to evaluate the effects of LNBs on the capture of Hg. 

6-61

6.10 REFERENCES 

1.	 U.S. Environmental Protection Agency. Database of information collected in the 

Electric Utility Steam Generating Unit Mercury Emissions Information Collection 

Effort. OMB Control No. 2060-0396. Office of Air Quality Planning and Standards. 

Research Triangle Park, NC. Available at: 

< http://www.epa.gov/ttn/atw/combust/utiltox/utoxpg.html >. 

2.	 Hargis, R., W. O’Dowd, and H. Pennline. “Sorbent Injection for Mercury Removal in 

a Pilot-Scale Coal Combustion Unit.” Presented at the 93rd Annual Meeting of the 

Air & Waste Management Association, Salt Lake City, UT. June 18-22, 2000. 

3.	 Haythornthwaite, S., T. Hunt, M. Fox, J. Smith, G. Anderson, and C. Grover. 

“Investigation and Demonstration of Dry Carbon-Based Sorbent Injection for 

Mercury Control,” Quarterly Report under DOE Contract No. DE-AC-22-

96PC95256, December 1998. 

6-62

Chapter 7


Research and Development Status of


Potential Retrofit Mercury Control Technologies


7.1 Introduction 

The Part III EPA ICR data show that ESP and FF control devices currently used to meet 

PM emission standards do capture particle-bound mercury (Hgp) from coal-fired electric utility 

boilers (see Chapter 6). The data also suggest that SDA and wet FGD scrubbers in place to meet 

SO2 emission standards do capture oxidized mercury (Hg2+). However, these data also show that 

the air pollution control devices presently used at most electric utility power plants are not very 

effective in capturing elemental mercury (Hg0). Consequently, to achieve further reductions in 

Hg emissions from existing coal-fired electric utility power plants, additional Hg reduction 

strategies must be implemented. 

Potential Hg control strategies may be technology based (e.g., adding Hg emissions 

control devices), economics based (e.g., Hg emissions trading programs), or national energy 

policy based (e.g., switching from coal to alternative energy sources for electrical power 

production). This chapter discusses technology-based control strategies available for reducing 

Hg emissions from existing coal-fired electric utility power plants (Section 7.2). Current 

research and development is focused on retrofitting Hg control technologies to the coal-fired 

electric utility power plant’s existing air pollution control systems (Section 7.3). This retrofit 

approach offers the potential for reduced costs of implementing Hg controls by enhancing the 

capability of the air pollution control equipment already in place to capture more Hg. 

Building on the results of laboratory- and bench-scale research studies (discussed in 

Chapter 5), additional studies have been, and currently are being, conducted using pilot-scale test 

facilities to further investigate the more promising retrofit Hg control technologies (Section 7.4). 

For the many existing coal-fired electric utility boilers that are equipped with only ESPs or FFs, 

retrofit technologies under development are based on injecting sorbents into the flue gas 

upstream of the control device (Section 7.5). Retrofit technologies to improve wet FGD scrubber 

performance in capturing Hg are based on promoting oxidization of Hg0 to soluble species by the 

addition of oxidizing agents or the installation of fixed oxidizing catalysts upstream of the 

scrubber (Section 7.6). The high levels of Hg control already achieved by the few existing 

boilers using SDA for control of PM and SO2 may be further enhanced by coinjection of a 

second sorbent (Section 7.7). From a long-term perspective, the most cost-effective Hg controls 

may be those implemented under a multipollutant emission control strategy. New 

7-1

multipollutant control technologies, which potentially are effective in controlling Hg emissions, 

are under development (Section 7.8). 

7.2 Technology-based Mercury Control Strategies for Existing Coal-fired Electric Utility 

Boilers 

7.2.1 Remove Mercury Prior to Burning by Coal Cleaning 

Reducing the amount of Hg in the coal burned in electric utility boilers would reduce the 

level of Hg emissions from these boilers without the need for additional post-combustion Hg 

controls. Switching coal suppliers to obtain coals with lower Hg contents raises complex 

economic and national energy policy issues that are beyond the scope of this report. 

Physical cleaning of coal (discussed in Chapter 2) has traditionally been used at coal 

preparation plants to remove mineral matter (i.e., a source of coal combustion ash) and mineralbound sulfur (pyrite) from the mined coal. Mercury and other trace metals are also removed by 

this cleaning depending on whether these metals are associated with the organic carbon structure 

of coal or coal mineral inclusions. However, the existing commercially available coal-cleaning 

methods remove only a portion of the Hg associated with the non-combustible mineral matter in 

the coal and none of the Hg associated with the organic carbon structure of the coal. 

Consequently, conventional physical coal cleaning can remove only a limited portion of the Hg 

content of specific coals and may not be applicable to all coals. 

There is the potential for additional Hg reductions in the coal from several advanced 

physical coal-cleaning processes using selective agglomeration or column froth flotation now 

being developed. For example, MicrocelTM is a type of column froth flotation available through 

ICF Kaiser and Control International. The company is the exclusive licensee for use of the 

technology for coal deposits east of the Mississippi River and has sold units for commercial 

operation in Virginia, West Virginia, and Kentucky. Ken-FloteTM is another type of column 

froth flotation cell coal-cleaning technology that is commercially available. Results of benchscale studies indicate that the combination of conventional with advanced coal-cleaning 

techniques removes from 40 to 82 percent of the Hg contained in samples of raw coal.1,2 

Advanced coal-cleaning processes using naturally occurring microbes and mild chemical 

treatments to reduce the Hg content in coal have been investigated under DOE-funded benchscale studies. The results of these tests indicate that these chemical and biological coal-cleaning 

processes have the potential for further reduction in the Hg content of coals. However, DOE 

viewed the processes as potentially high-cost control technologies, and DOE currently is not 

funding development of these types of coal-cleaning technologies.3 

From a near-term perspective, some reduction of the Hg content in certain coals burning 

at existing coal-fired electric utility power plants can be achieved by physical coal-cleaning 

processes. However, there are no easily identifiable coal deposits or coal types that will reliably 

benefit from cleaning, with respect to reducing Hg content. In addition, even with 

7-2

implementation of widespread coal cleaning for Hg emissions control, significant quantities of 

Hg will remain in the coal after cleaning; this will require that other control techniques be used 

to achieve additional reductions in Hg emissions. 

7.2.2 Retrofit Mercury Controls to Existing Air Pollution Control Systems 

In addition to reducing the amount of Hg in the coal before it is burned in a coal-fired 

electric utility boiler, a second technology-based alternative is to remove more of the Hg in the 

boiler flue gas before it is vented out the stack. One strategy is to retrofit or adapt control 

technologies to the facility’s existing air pollution control systems to increase the amount of Hg 

captured by these systems rather than install new, separate Hg control devices. The strategy 

offers the potential advantage of reducing the costs of implementing the Hg controls by 

enhancing the capability of the air pollution control equipment already in place to capture more 

Hg. 

The existing air pollution controls used for a given coal-fired electric utility boiler 

depends on site-specific factors including the properties of the coal burned, age and size of the 

boilers, the geographic location of the facility, individual state regulatory requirements, and 

preferences of the facility owner or operator. For approximately 70 percent of the existing coalfired electric utility boilers in the United States, the control device used is an ESP (see Table 3-6 

in Chapter 3). These power plants typically burn low-sulfur coals to control SO2 emissions and 

use combustion modifications for NOX emissions control. Most boilers use a “cold-side” ESP 

where the control device is installed downstream of the boiler air heater (discussed in Section 

3.4.1). Some of the boilers use a “hot-side” ESP where the control device is installed upstream 

of the boiler air heater. A small number of existing boilers (7 percent) that fire low-sulfur coal 

use FFs instead of ESPs. In general, FFs are being used at these coal-fired electric utility power 

plants to obtain better PM control or to solve ESP performance problems associated with highresistivity fly ash. A FF can be used only downstream of the boiler air heater because of 

temperature limitations of the fabric filter bags. 

Post-combustion SO2 emissions controls are used at approximately 27 percent of existing 

coal-fired electric utility boilers. The SO2 control technology most commonly used for these 

boilers is a wet FGD scrubber. In all cases, a PM control device, usually an ESP, precedes a 

scrubber. Wet FGD scrubbers remove gaseous SO2 from flue gas by absorption. In absorption, 

gaseous species are contacted with a liquid in which they are soluble. For SO2 absorption, 

gaseous SO2 is contacted with a caustic slurry, typically water and limestone or water and lime. 

The newer semi-dry SO2 scrubber technologies currently are used at small number of the existing 

coal-fired utility boilers (about 5 percent). However, for retrofit Hg control, these semi-dry 

scrubbers have the advantage of an existing sorbent delivery system coupled with, in most cases, 

a downstream FF to collect the reacted sorbent already in place. A detailed discussion of 

potential retrofit options and current research and development status is presented in following 

sections. 

7-3

7.2.3 Integrate Mercury Control Under a Multipollutant Control Strategy 

The most cost-effective, long-term Hg controls may be those implemented as part of a 

multipollutant control strategy. Selection and deployment of new SO2, NOX, and fine PM 

controls, which also control or contribute to the control of gaseous Hg in coal combustion flue 

gas, may reduce or eliminate the need for Hg-specific controls. For example, installation of a 

wet or semi-dry FGD unit should reduce oxidized Hg emissions by 90 to 95 percent over 

previous levels; adding upstream NOX controls, which assist in oxidation of Hg0, would further 

reduce total Hg emissions. Replacing or supplementing existing ESPs with FFs will likely 

remove additional Hg, especially for bituminous coal applications. 

The remaining majority, Sections 7.3 through 7.7, discusses control technologies that 

reduce Hg emissions by improving the performance of existing air pollution control devices to 

capture the Hg in coal combustion flue gas. Section 7.8 discusses new multipollutant control 

technologies (other than serial SOX-NOX-PM control devices), which are under development and 

are potentially applicable to electric utility coal-fired electric utility power plants. 

7.3 Post-combustion Mercury Control Retrofit 

Retrofits that reduce Hg emissions from existing electric utility coal-fired electric utility 

power plants are implemented by modifying existing post-combustion emission control 

techniques already in place. Potential retrofit options are identified and discussed below. 

Options that are discussed may not be technically feasible or economically practical to install and 

operate at all facilities. 

7.3.1 Cold-side ESP Retrofit Options 

Add Flue Gas Cooling. Lowering the flue gas temperature entering the ESP assists 

natural fly ash sorption of Hg as well as improves the performance of any sorbents injected 

upstream for Hg control. However, the acid dew point temperature limits gas cooling when the 

flue gas has significant HCl or H2SO4 formation potential. 

Add Sorbent Injection. Gaseous Hg can be converted to Hgp by adsorption onto solid 

particles in flue gas. Injecting sorbents into the flue gas upstream of the ESP increases the 

amount of Hg captured in the form of Hgp. This modification may require adding ducting 

between the sorbent injection point and the ESP, and adding a gas absorber/humidifier upstream 

of the ESP. This approach also may be limited by the ability of the ESP to collect highresistivity sorbents. For coal-fired electric utility boilers with marginally performing ESPs that 

have difficulty meeting opacity requirements and may not be candidates for a sorbent injection 

retrofit, the following option may be preferred. 

Add Downstream FF with Sorbent Injection. Adding a FF downstream of the existing 

ESP, while a more expensive retrofit option, allows a significant portion of the fly ash to be 

collected without reacted sorbent and enhances overall PM control efficiency where ESP 

performance is marginal. Further, because the FF would have a much lower particulate loading, 

7-4

the collecting surface can be smaller (higher air-to-cloth ratio) or have longer cleaning cycles 

(good for sorbent performance and bag life). 

ESP Modifications. Potential ESP modifications include converting the last field of the 

ESP to a wet ESP or a very compact pulsejet FF. These conversions would likely be made 

because of PM collection improvements needed, rather than Hg control considerations; 

nonetheless, associated Hg control benefits would also be likely. 

7.3.2 Hot-side ESP Retrofit Options 

Convert to Cold-side ESP with Sorbent Injection. Adding flue gas cooling is not an 

option for a hot-side ESP because of its location upstream of the air preheater. The only 

potential retrofit option for Hg capture without adding a new downstream PM control device is 

to convert the existing ESP from a hot-side configuration to a cold-side configuration. 

Depending on the plant layout and ESP design, this may be possible by reconfiguring the ducting 

and retuning the ESP to operate at the lower temperature. Adding sorbent injection with the 

modification would further improve Hg capture. The lower flue gas temperature entering the 

ESP enhances the adsorption of gaseous Hg onto fly ash or sorbent (if injected upstream) and 

subsequent collection of the particulate Hg in the ESP. 

Add Downstream FF with Sorbent Injection. The same as for a cold-side ESP, adding a 

FF downstream of the existing ESP, while a more expensive retrofit option, allows a significant 

portion of the fly ash to be collected without reacted sorbent. 

7.3.3 Fabric Filter Retrofit Options 

Add Flue Gas Cooling. As is the case for ESPs, lowering the flue gas temperatures 

entering the FF enhances the adsorption of gaseous Hg onto fly ash or sorbent (if injected 

upstream). Again, the acid dew point temperature limits gas cooling when the flue gas has 

significant HCl or H2SO4 formation potential. 

Add Sorbent Injection. Use of sorbent injection may require some internal FF 

modifications to ensure good sorbent performance. In general, existing FFs were not designed as 

adsorbers, so some modifications may be in order to ensure that sorbent particles stay entrained 

and become part of the filter cake. This may be accomplished by removing baffles, changing the 

point of gas entry, increasing gas velocity, or using smaller sorbent particles. Operating 

requirements of the FF may require more frequent cleaning with the additional sorbent loading. 

FF Modifications. Potential FF retrofit options include replacing fabric bags with 

catalytic bags that oxidize Hg0 to Hg++ and Hgp or adding electrostatic augmentation to increase 

the bag cleaning cycle interval time and hence increase sorbent/gas contact time. This last 

improvement would be especially beneficial with higher-cost, high-capacity sorbents. 

7-5

7.3.4 Spray Dryer Absorber Retrofit Options 

Use Oxidation Additives. Existing SDA systems already achieve very high Hg removal 

on certain coals but show poor performance on other coals. Possible causes are low oxidation 

potential resulting from high alkaline fly ash content as well as low effective carbon content in 

fly ash. Therefore possible performance improvements include producing a higher carbon 

content fly ash by NOX combustion control modifications, direct addition of activated carbon to 

the absorber with lime, and addition of oxidants to the absorber. 

Replace Existing ESP with FF Control Device. Where the PM control device used for 

the absorber is an ESP, replacement of the unit with a FF would likely improve Hg removal as a 

result of enhanced PM control as well as greater conversion of Hg2+ to Hgp. 

7.3.5 Wet FGD Scrubber Retrofit Options 

Use Oxidation Additives. Oxidation of the gaseous Hg0 to gaseous Hg2+ can potentially 

increase the total Hg removed by wet scrubbing since gaseous Hg2+ is more readily captured by 

these systems than gaseous Hg0. Several flue gas additives and scrubbing additives are being 

developed to increase the conversion of Hg0 to Hg++ prior to the scrubber inlet. Flue gas and 

scrubber additives are also being developed for use in preventing the conversion of absorbed 

Hg2+ to gaseous Hg0 in wet FGD systems. The one caution is that increasing oxidants upstream 

or within the scrubber may also oxidize other species such as SO2 and NO/NO2 to sulfuric and 

nitric acid aerosols. 

Add Fixed Oxidizing Catalysts Upstream of Scrubber. Improvements in wet scrubber 

performance in capturing Hg may be accomplished by installation of fixed oxidizing catalysts 

upstream of the scrubber to promote oxidization of Hg0 to soluble species. Potential catalysts 

currently are being tested. 

Wet FGD Scrubber Modifications. Several studies of pilot-scale wet FGD systems 

suggest that modifying the scrubber operation and design (as well as the control and design of 

upstream ESPs) may improve the capture of gaseous Hg2+ and reduce the conversion of absorbed 

Hg2+ to Hg0. Specifically, these studies have found that the liquid-to-gas ratio and tower design 

of a wet FGD unit affect the absorption of gaseous Hg2+, while the oxidation air influences the 

conversion of absorbed Hg2+ back to Hg0 which is then emitted to the atmosphere in the scrubber 

exhaust gas. 

7.3.6 Particle Scrubber Retrofit Options 

A few existing power plants use wet scrubbers exclusively for control of PM emissions. 

Knowledge gained in the enhancing control of Hg emissions from wet FGD scrubbers by 

operating modifications also may be useful in improving the Hg removal performance of these 

particle scrubbers. 

7-6

7.4 Retrofit Control Technology Research and Development Programs 

None of the retrofit options discussed in Section 7.3 are routinely being used by the 

electric utility industry at this time. In addition, the Hg emissions control technologies that are 

successfully used for municipal waste combustors (MWCs) in the United States and Europe 

cannot be directly retrofitted to existing coal-fired electric utility boilers. Differences in flue gas 

properties, combustion unit design, and other factors (discussed in Section 7.4.1) prevent the Hg 

control devices now used for MWCs to be directly installed at coal-fired electric utility power 

plants. Consequently, development of effective retrofit control technologies for coal-fired 

electric utility boilers is the subject of bench-scale, pilot-scale, and full-scale test programs. 

Chapter 5 discusses laboratory studies investigating potential Hg control techniques for coalfired electric utility boilers. To further develop the most promising of these control techniques 

for full-scale application to coal-fired electric utility boilers, pilot-scale and full-scale research 

studies are being funded by the EPA, DOE, EPRI, state agencies, and private companies. 

Section 7.4.2 describes several pilot-scale test units that are being used for research and 

development programs. Building upon the results obtain using these test facilities, a number of 

full-scale test programs currently are being conducted to provide a more thorough 

characterization of the performance and potential for widespread commercial application of 

specific retrofit Hg control technologies. 

7.4.1 MWC Mercury Control Technology 

Injection of activated carbon into the flue gas from a MWC and collecting the reacted 

sorbent in a downstream FF is one Hg control method widely used for MWCs.4,5 Mercury 

removal levels in excess of 90 percent are achieved. However, the level of Hg control achieved 

by adding sorbents into the flue gas from a particular combustion unit is influenced by the 

particular characteristics of the flue gas from that unit including flue gas temperature, flow rate, 

Hg content, and chloride Hg content. Table 7-1 compares selected properties of the flue gas 

from a coal-fired utility boiler with those for a MWC flue gas. As shown in this table, Hg 

concentrations in MWC flue gas streams may be up to several orders of magnitude greater than 

those seen in utility flue gas streams. In addition, MWC flue gas contains mostly Hg2+

, while 

flue gas from coal-fired electric utility boilers can have substantial amounts of Hg0

, which 

generally is less likely to be adsorbed. Additionally the flue gas ductwork for a coal-fired utility 

boiler is substantially larger and more complex (multiple passes) than for a MWC, therefore duct 

injection of a sorbent is more complicated and its performance more difficult to predict for a 

coal-fired utility boiler due to variations in temperatures, residence time, and other factors. 

Similarly, the wet scrubber technology used by European MWCs is not directly 

applicable to controlling emissions from coal combustion. European MWCs typically have twostage scrubbers consisting of a low-pH water scrubber to control hydrochloric acid (HCl) 

emissions, produced as a result of the large quantities of plastics in the garbage burned, followed 

by an alkaline scrubber to control SO2 emissions. In contrast, wet scrubbing systems typically 

used by the electric utility industry in the United States to control SO2 emissions resulting from 

burning high sulfur coal consist of a single-stage wet scrubber using a limestone or lime 

scrubbing agent. As a consequence, there are significant differences in the underlying chemistry 

7-7

Table 7-1. Comparisons of typical uncontrolled flue gas parameters for coal-fired 

utility boiler versus municipal waste combustor (MWC). 

Flue Gas 

Parameter Coal-fired Electric Utility Boiler Municipal Waste Combustor 

Temperature 

(

o

C) 121 to 177 177 to 299 a 

Hg Content 

(μg/dscm) 1 to 25 400 to 1,400 b 

Chloride Content 

(μg/dscm) 1,000 to 140,000 200,000 to 400,00 a 

Flow Rate 

(dscm/min) 11,000 to 4,000,000 80,000 to 200,000 a 

(a) Temperature, chloride content, and flow rate data taken or determined from Reference 6 

(b) Mercury content data taken from Reference 4. 

7-8

of the scrubbing systems used for MWCs compared to those currently in use at coal-fired electric 

utility power plants. 

7.4.2 Pilot-scale Coal-fired Test Facilities 

To date, most of the retrofit control technology development has been conducted using 

pilot-scale test units that simulate full-scale coal-fired electric utility boiler combustion 

conditions. The DOE Federal Energy Technology Center, the Ohio Coal Development Office 

(OCDO), and McDermott Technology, Inc., jointly funded one program titled the Advanced 

Emissions Control Development Program (AECDP). This test program was conducted in three 

phases using a 10 MW coal-fired test faculty.7,8,9 The test facility is capable of testing a full-flow 

ESP, a partial-flow pulsejet FF, and a wet FGD scrubber. All testing under the AECDP was 

performed firing Ohio bituminous coals. Figure 7-1 shows a schematic of the test facility. 

Specific AECDP test results related to specific retrofit options are discussed later in this chapter 

under the relevant topic headings. 

For a DOE cooperative agreement test program, the project team of Public Service 

Company of Colorado (PSCO), ADA Technologies, and EPRI fabricated a pilot-scale 

particulate control module (PCM) to investigate Hg control in actual coal combustion flue gas by 

different dry sorbents.10 Figure 7-2 shows a schematic of the PCM. The PCM draws a 

slipstream of flue gas (600 actual cubic feet per minute) from the 350-MWe coal-fired electric 

utility boiler (Unit 2) at PSCO’s Comanche Station power plant. This boiler is an opposed-fired, 

pulverized-coal boiler firing Powder River Basin (PRB) subbituminous coal. Flue gas can be 

drawn either from the inlet (high particulate loading) or the outlet (essentially particle free) of the 

full-size Unit 2 reverse-gas FF. In addition, the PCM can be configured as an ESP, a reverse-gas 

or pulse-jet FF, and as EPRI's TOXICON pulse-jet FF. Gaseous Hg is injected into the flue gas 

to the PCM along with recycled fly ash and/or sorbent; the solids can be injected at various 

locations upstream of the PCM to investigate the effects of Hg adsorption at different in-flight 

residence times (0.5 to 3 seconds). The PCM is also equipped with in-duct heating and water 

spraying to investigate the effects of Hg adsorption at different temperatures. Specific results 

from testing using the PCM are discussed later in this chapter under the relevant topic headings. 

The DOE National Energy Technology Laboratory (NETL) is conducting in-house 

research studies using a 500-lb/hr coal combustion unit to simulate a pulverized-coal-fired 

electric utility boiler.11,12 Figure 7-3 shows a schematic of the DOE/NETL coal combustion test 

facility. The system consists of a wall-fired, pulverized-coal furnace equipped with a watercooled convection system, a recuperative air heater, spray dryer, sorbent injection duct (SID) test 

section, and FF. Sorbent can be injected at numerous locations along the SID test section; this 

allows for a wide range of sorbent in-duct residence times relative to the FF and to the SID fluegas sampling locations. 

7-9

Figure 7-1. Schematic of 10-MWe coal-fired Babcock & Wilcox (B&W) Clean 

Environment Development Facility (CEDF) as used for Advanced Emissions 

Control Development Program (AECDP) (source: Reference 9). 

7-10

Figure 7-2. Schematic of Particulate Control Module (PCM) at Public Service 

Company of Colorado (PSCO) Comanche Station (source: Reference 10). 

7-11

Figure 7-3. Schematic of DOE/NETL in-house 500-lb/hr coal combustion test 

facility (source: Reference 12). 

7-12

7.5	 Mercury Control Retrofits for Existing Coal-fired Electric Utility Boilers Using ESP or 

FF Only 

The focus of research and development for existing coal-fired electric utility boilers 

equipped only with an ESP or FF has been the use of dry sorbent injection. As discussed in 

Chapter 5, gaseous Hg can be adsorbed onto solid particles in the flue gas. A solid particle that 

absorbs gaseous species is called a “sorbent.” The flue gas from every electric utility boiler that 

directly burns coal (i.e., all boilers except for IGCC units) contains fly ash particles that adsorb 

gaseous Hg in the flue gas to various degrees. Other types of solid particles can be injected into 

the flue gas for the purpose of adsorbing gaseous Hg. Materials being investigated as possible 

sorbents for Hg control include activated carbon, calcium-based and sodium-based (trona) 

sorbents, various clays and zeolites, alkaline-earth sulfides, and lime and lime-silica 

multipollutant sorbents. An alternative sorbent-based Hg control approach that has been 

investigated is passing the flue gas through a fixed bed of a noble-metal-based sorbent. 

7.5.1 Sorbent Injection Configurations 

In general, four retrofit configurations are possible for injecting dry sorbent particles into 

the flue gas from a coal-fired utility boiler. It may not be technically feasible to implement one 

or more of these configurations at a given existing coal-fired power plant because of site-specific 

factors such as the existing flue gas duct configuration, availability of space to add additional 

ducting or new control device, use of a wet FGD scrubber, or other plant layout and operation 

considerations. 

Configuration A - Sorbent injection into the flue gas duct upstream of existing ESP or FF. 

Cooling of the flue gas upstream of the sorbent injection point or modifications to the 

ducting may be needed. 

Configuration B - Sorbent injection into the flue gas duct downstream of the existing PM 

control device followed by a new FF (to collect the reacted sorbent), with or without flue 

gas cooling upstream of the injection point. This configuration requires higher capital 

costs but reduces sorbent costs compared to Configuration A. The configuration also 

allows the fly ash collected by the upstream PM control device to be sold without being 

mixed with the injected sorbent. 

Configuration C - Sorbent injection into a circulating fluidized-bed absorber (CFA) 

upstream of the existing ESP or FF, with or without flue gas cooling upstream of the 

CFA. The advantage to using a CFA is that it recirculates reacted materials with fresh 

sorbent to create an entrained bed with a high number of reaction sites resulting in higher 

sorbent utilization and enhanced capture of Hg and other pollutants. 

Configuration D - Sorbent injection into a CFA downstream of the existing PM control 

device and followed by a new FF (to collect the reacted sorbent). Like Configuration B, 

this configuration allows the fly ash collected by the upstream PM control device to be 

sold without being mixed with the injected sorbent. 

7-13

The level of Hg capture using sorbent injection with a downstream ESP depends on inflight adsorption of Hg by entrained sorbent particles. Mercury capture in a downstream FF 

occurs by this same in-flight adsorption process as well as a second mechanism when flue gas 

must pass through the filter cake collected on the FF bags. This filter cake contains a mixture of 

previously captured fly ash and sorbent particles, and provides good contact between gaseous Hg 

and captured particles. Filter cake retention times between bag cleaning cycles may be as long 

as 60 minutes, greatly increasing the adsorption of Hg on the sorbent particles. This compares 

with the relatively short time that in-flight adsorption occurs upstream of the control device 

(nominal times for in-flight adsorption are 0.5 to 1.5 seconds). In addition, FFs generally are 

more efficient than ESPs in collecting fine particles and any associated Hgp (see Table 3-3). The 

extra contact time and higher collection efficiency provided by a FF reduces the amount of 

sorbent needed for adsorption compared to what is needed for an ESP to achieve a given level of 

control. 

Cooling the flue gas before the sorbent injection point can improve Hg adsorption by the 

sorbent, which in turn may reduce the amount of sorbent needed for a given level of control. 

However, the temperature to which the flue gas may be cooled is limited because sulfuric acid 

(and perhaps hydrochloric acid) mists may be formed if the flue gas temperature drops below the 

acid dew point(s) of the flue gas. For all four configurations, sorbent capacity may be 

maximized by recycling and reinjecting sorbent and fly ash collected in the PM control device(s) 

located downstream of the injection point. 

7.5.2 Sorbent Adsorption Theory 

Gas-phase adsorption occurs when a gaseous specie contacts the surface of a solid and is 

held there by attractive forces between the gaseous specie and the solid. In adsorption 

terminology, the gaseous specie being adsorbed is called the "adsorbate," and the solid is called 

the "adsorbent" or "sorbent." While all solids have the potential to adsorb gaseous species, 

adsorption is not very pronounced unless a solid has a large surface area. As a result, most solids 

for gas-phase adsorption are highly porous and in the form of particles or granules. The porosity 

of the solids provides large amounts of internal surface area where most adsorption takes place. 

When a gaseous specie is adsorbed onto the surface of a solid particle, the gaseous specie 

becomes a particle-bound specie. 

Gas-phase adsorption may be classified as chemisorption or physical adsorption 

depending on the nature of the attractive force between the adsorbate and sorbent. In 

chemisorption, the adsorbate reacts with the surface of the sorbent, thus, the attractive force 

between the adsorbate and sorbent is similar to a chemical bond. Chemisorption often involves 

the use of sorbents impregnated with compounds that are reactive with the adsorbate. In physical 

adsorption, the attractive force between an adsorbate and sorbent is electrostatic in nature 

(similar to the attraction between metal filings and a magnet, where the metal filings are 

analogous to the adsorbate and the magnet is analogous to the sorbent). Different adsorbates 

have different attractive forces for a given sorbent due to differences in molecular weight, 

normal boiling point (or vapor pressure), degree of unsaturation, polarity, and structural 

configuration. When a sorbent is exposed to more than one adsorbate, preferential adsorption 

7-14

tends to take place due to differences in the attractive forces between the different adsorbates and 

the sorbent particles. 

Equilibrium adsorption capacity is the maximum amount of adsorbate a given mass of 

sorbent can hold at a given temperature and adsorbate gas concentration. Generally, the 

adsorption capacity of a sorbent for a given adsorbate increases with increased adsorbate 

concentration and decreases with increases adsorption temperature. 

In a dynamic adsorption system (i.e., an adsorption system involving a moving gas 

stream), a gas stream containing one or more adsorbates is passed through a fixed or fluidized 

bed of sorbent particles or the sorbent particles are injected directly into the gas stream. In 

dynamic adsorption systems, the contact time between the sorbent particles and the adsorbate in 

the gas stream is critical. While contact time does not affect the equilibrium adsorption capacity 

of the sorbent, it directly affects the sorbent’s ability to capture the adsorbate from the gas 

stream. Maximum capture of adsorbate from the gas stream will not take place unless the 

adsorbate has sufficient time to contact the sorbent and diffuse into its pores. Thus, increasing 

the contact time increases Hg capture by the sorbent. 

7.5.3 Pilot-scale and Full-scale Research and Development Status 

The laboratory studies of using dry sorbents for Hg control based on bench-scale reactor 

testing are discussed in Section 5.4. This section discusses the results from field studies testing 

different sorbents in pilot-scale or full-scale systems. 

7.5.3.1 Coal Fly Ash Reinjection 

As discussed in Chapter 5, fly ash generated naturally when burning certain coals in a 

utility boiler adsorbs some of the gaseous Hg in the flue gas. The adsorption of gaseous Hg by 

the fly ash vented in the flue gas from the boiler, referred to by some researchers as “native fly 

ash,” is believed to occur at active sites on the ash surface similar to those on sorbent (e.g., fly 

ash carbon analogous to activated carbon or fly ash alkaline species akin to injected lime). As 

part of the DOE cooperative agreement test program to investigate dry sorbents, the project team 

of PSCO, ADA Technologies, and EPRI evaluated Hg removal rates by the fly ash in the flue 

gas from burning two types of Western coals and the potential for Hg removal by reinjection of 

low levels of collected fly ash back into the flue gas upstream of the particulate control device.10 

The use of reinjected fly ash for Hg control avoids the potentially adverse impact on the 

commercial viability of selling the fly ash collected in the downstream particulate control 

devices. The use of activated carbon as a Hg sorbent may increase the level of carbon in the 

collected fly ash/activated carbon mixture above allowable maximum levels for some 

commercial fly ash applications (e.g., sale of fly ash for use as a concrete additive). 

Full-scale testing was conducted at three PSCO coal-fired electric utility power plants to 

characterize gaseous Hg removal by the native fly ash in flue gas at each facility; a boiler using a 

FF for PM control was tested. At one facility, a second boiler using an ESP was also tested. 

Two of the three power plants burned subbituminous coal from the Powder River Basin (PRB), 

7-15

and the other burned a Colorado-mined bituminous coal. Flue gas measurements were taken 

concurrently at the inlet and outlet of each particulate control device. At two of the power 

plants, testing was conducted in both the summer and winter in order to investigate the effect of 

ambient temperature on the adsorption of Hg on the fly ash. 

Results of the full-scale tests are summarized in Table 7-2. Mercury removal measured 

across the three FFs ranged from 61 to 99 percent. Mercury removal across the ESP was 

significantly lower at 28 percent. The two boilers units demonstrating Hg removals above 

80 percent (Arapahoe 4 and Cherokee 3) were equipped with low-NOX burner retrofits. The use 

of these burners often causes elevated levels of unburned carbon in the fly ash. Measuring 

unburned carbon by the "loss-on-ignition" (LOI) test, the fly ashes from Arapahoe 4 and 

Cherokee 3 had LOI contents approximately 7 to 14 times higher than the fly ashes from the 

other two boilers. The Hg levels measured for the Cherokee 3 unit was essentially the same in 

both summer and winter, indicating no adverse temperature effects on adsorption. In contrast, 

the Arapahoe 4 tests showed better adsorption at cooler test conditions (i.e., winter versus 

summer). 

To examine the use of fly ash reinjection for Hg emissions controls, a series of pilot-scale 

tests were conducted by collecting the fly ash samples from the three power plants and injecting 

the collected fly ash into the PCM located at the Comanche Station (discussed in Section 7.4.2). 

For the recycled fly ash tests, the PCM was configured as a reverse-gas FF and drew fly-ash-free 

flue gas from the outlet side of the FF serving the coal-fired boiler. The flue gas was spiked with 

gaseous Hg to produce a Hg concentration of approximately 10 μg/Nm3

. The gaseous Hg 

concentration was sampled at the inlet and outlet of the PCM using a Hg continuous emissions 

monitor (Perkin Elmer MERCEM). Recycled fly ash was injected into the flue gas just 

downstream of the inlet sampling port. Except during one test, the injected fly ash samples were 

not treated in any way to enhance their Hg-adsorbing properties. For one test, a sample of fly 

ash from the Comanche 2 unit was treated with a hot nitrogen purge in an attempt to desorb any 

Hg on the ash particles. 

Table 7-3 summarizes Hg removal data for the fly ashes tested. Reinjected 

subbituminous coal fly ash removed 84 to 86 percent of the gaseous Hg across the PCM. In 

contrast, reinjecting fly ash from the boiler burning bituminous coal showed only a 10 percent 

removal of gaseous Hg. The removal efficiency for bituminous coal fly ash was increased to 31 

percent when this ash was thermally pretreated to desorb Hg before injection into the PCM. The 

results in Table 7-3 show that the recycled fly ashes from the Cherokee and Arapahoe boilers had 

additional capacity to adsorb gaseous Hg (beyond what they had adsorbed from their source flue 

gas), while the untreated recycled fly ash from the Comanche 2 boiler appeared to be saturated or 

no longer reactive. The LOI contents of the Cherokee 3 and Arapahoe 4 fly ash samples were 8 

and 14 percent, respectively. The LOI contents of the Comanche 2 fly ash samples were 0.3 to 

0.4 percent. As was observed during the full-scale testing, fly ashes with the highest LOI 

contents (those from the Arapahoe 4 and Cherokee 3 boilers) adsorbed more Hg than fly ashes 

with lower LOI contents (those from the Comanche 2 boiler). 

7-16

Table 7-2. Hg removal by native fly ashes measured across PM control devices at 

PSCO power plants burning selected western coals (source: Reference 10). 

Power Plant Type of Coal 

Burned 

PM Control 

Device 

Ash Carbon 

Content 

(% LOIb

) 

Gaseous Hg 

Removal 

(%) 

PSCOa 

Cherokee 

Bituminous 

(Colorado) 

Reverse-gas FF 

(Boiler Unit #3) 7.6 98 (summer) 99 (winter) 

ESP 

(Boiler Unit #1) <1 28 

PSCO 

Arapahoe 

Subbituminous 

(Powder River 

Basin) 

Reverse-gas FF 

(Boiler Unit #4) 14.4 62 (summer) 82 (winter) 

PSCO 

Comanche 

Subbituminous 

(Powder River 

Basin) 

Reverse-gas FF 

(Boiler Unit #2) 0.4 61 

(a) PSCO = Public Service Company of Colorado 

(b) LOI = Loss on ignition 

7-17

Table 7-3. Hg removals by fly ash reinjection measured across PCM at PSCO 

Comanche power plant for selected western coals (source: Reference 10). 

Reinjected Fly Ash 

Coal Source 

(PSCO power plant) 

Flue Gas 

Temperature 

( o

F) 

Ash 

Reinjection 

Rate 

(grains/acf) 

Ash 

Carbon 

Content 

(% LOIa

) 

Gaseous Hg 

Removal 

(%) 

PRB Subbituminous coal 

(Arapahoe 4) 320 0.13 14.4 84 

PRB Subbituminous coal 

(Cherokee 3) 320 0.33 7.6 86 

280 1.13 0.42 10 

Colorado 

Bituminous coal 

(Comanche 2) 

280 1.21 0.26 31 b 

(a) LOI = Loss on ignition 

(b) Deadsorbed ash. 

7-18

In addition to evaluating the adsorption capacity of recycled fly ashes, several tests were 

made using the PCM to evaluate the effects of temperature on fly ash adsorption. For the 

temperature tests, fly-ash-laden flue gas was extracted from the inlet of the FF serving the 

Comanche 2 boiler and passed through the PCM; gaseous Hg was injected upstream of the PCM. 

Hg adsorption across the PCM was monitored as the temperature of the flue gas through the 

PCM was varied. Table 7-4 summarizes the results of the temperature tests. For the baseline 

tests (no heating or cooling), the temperature of the flue gas through the PCM was in the range of 

135 o

C (275 oF); at this temperature, the Comanche 2 fly ash removed 20 to 40 percent of the 

gaseous Hg present in the flue gas. When the flue gas was heated to around 152 oC (305 oF), the 

fly-ash Hg removal dropped to zero, while spray cooling to reduce the flue gas temperature to 

about 110 oC (230 oF) increased the Hg removal to around 60 percent. As expected, the data from 

these tests show that adsorption is greatly affected by temperature, with adsorption increasing 

with decreasing flue gas temperature. 

7.5.3.2 Activated Carbon Sorbent Injection 

The most frequently tested activated carbon for Hg removal from coal combustion gases 

has been a commercially available carbon manufactured by Norit Americas, Inc. (trade name 

Darco FGDTM). The Darco FGDTM carbon is produced from lignite specifically for the removal 

of heavy metals and other contaminants from MWC flue gas streams. Other commercially 

available activated carbons and experimental carbons also have been tested. 

A full-scale test program jointly funded by EPRI and Public Service Electric and Gas 

(PSE&G) evaluated the potential of activated carbon injection for Hg control.13 The tests were 

performed at the PSE&G Hudson Generating Station, which fires low-sulfur bituminous coal and 

uses an ESP for PM control. Two types of activated carbon were tested, the Darco FGDTM 

carbon and an experimental carbon identified as AC-1. Results from these tests are shown in 

Table 7-5. The data indicate a distinct reduction in total Hg removal efficiency with increased 

temperature. The maximum Hg removal measured was 83 percent using the Darco FGDTM 

carbon at a C:Hg ratio of 45,000:1 and an ESP operating temperature of 221 oF. Full-scale ESP 

operation at this low temperature is not practical, however, due to potential problems with acid 

condensation. 

Sorbent injection using Darco FGDTM carbon and an ESP was also tested as part of the 

AECDP Phase III studies.9 For this test, the coal burned was an Ohio bituminous coal. The 

carbon was injected upstream of the ESP, with an approximate in-flight particle residence time 

of 1 second. The injection temperature was approximately 204 oC (400 oF) and the ESP inlet 

temperature was about 174 o

C (345 oF). The carbon flow rate was approximately 14 lb/hr, which 

is equivalent to a C:Hg mass ratio of 9,000:1. Both particulate and gaseous Hg species were 

measured at the inlet and outlet of the ESP during the carbon injection test. The test results are 

presented in Figure 7-4. Also shown in this figure are baseline Hg concentrations measured 

before any injection tests. Compared to the baseline condition, injection of the activated carbon 

resulted in a total Hg removal of 53 percent. Carbon injection at the test conditions had no effect 

on the removal of gaseous Hg0, suggesting that Hg removal appears to be a result of the capture 

7-19

Table 7-4. Effect of flue gas temperature on fly ash Hg adsorption measured 

across PCM at PSCO Comanche power plant burning PRB subbituminous coal 

(source: Reference 10). 

Test Condition 

Flue Gas 

Temperature 

(

o

C) 

Gaseous 

Hg Removal 

(%) 

Baseline 135 20 to 40 

Heated flue gas 152 0 

Cooled flue gas 110 60 

7-20

Table 7-5. Hg removal by activated carbon injection measured at PSE&G Hudson 

Station burning low-sulfur bituminous coal and using ESP (source: Reference 

13). 

Sorbent 

Tested 

ESP Operating 

Temperature 

(

o

F) 

Sorbent Injection 

Ratio 

(C:Hg) 

Total Hg 

Removal Range 

(%) 

255 0 3 

Baseline 

(no sorbent injection) 

268 –278 0 0 

240 – 255 11,500:1 13 to 17 

240 – 255 20,000:1 41 to 42 

220 –235 45,000:1 76 to 83 

275 –280 27,000:1 14 to 38 

Darco FGDTM 

Activated Carbon 

270 –275 45,000:1 28 to 45 

240 –250 18,000:1 33 to 45 

240 – 250 45,000:1 56 to 58 

Experimental 

Activated Carbon 

AC-1 

280 29,000:1 28 

7-21

Figure 7-4. Hg removal by activated carbon injection measured at AECDP test 

facility burning Ohio bituminous coal and using ESP (source: Reference 9). 

7-22

of gaseous Hg2+ (onto or into the particulate phase) and then the subsequent removal of the 

particulate in the ESP. 

The DOE/NETL also tested injecting Darco FGDTM carbon for Hg control using the 

DOE/NETL in-house coal combustion test facility.

11 For these tests, low-sulfur bituminous coal 

was burned based on the rationale that this is a coal-type likely be burned in utility power plants 

that do not have flue gas desulfurization systems. Throughout testing, the furnace was operated 

to achieve high combustion efficiency with low levels of unburned carbon in the fly ash. 

Unburned carbon levels in the fly ash under baseline conditions were generally less than two 

percent. Flue gas measurements of Hg were conducted at the FF inlet using the OH Method, and 

a Modified Ontario-Hydro Method (MOH Method). The modified method samples the flue gas 

non-isokinetically whereas the former samples the flue gas isokinetically. Stack measurements 

downstream of the FF were made for speciated Hg using the OH Method and total Hg using EPA 

Method 101A. Analysis of coal and ash deposits was made using ASTM D3684. The MOH 

Method was used at the inlet to minimize PM collection during sampling. Eliminating entrained 

PM in the sample flue gas allowed researchers to determine in-duct Hg removals. In addition, 

the effect of filtered solids on Hg speciation was deduced by comparison with the Hg speciation 

measured with the OH Method. 

Test results measured using the DOE/NETL test facility for sorbent injection upstream of 

a FF using the Darco FGDTM 

carbon are presented in Table 7-6. Total Hg removals measured 

ranged from 39 to 86 percent at injection C:Hg ratios of 2, 600:1 to 10, 300:1. The test results 

show a general trend where the total Hg removal increased with increasing C:Hg ratios. A 

second commercially available activated carbon has also been tested for possible Hg control 

using the NETL test facility.

12 Mercury removals of 30 to 40 percent were measured injecting 

Calgon FluePac TM activated carbon at C:Hg injection ratios of 2,500:1 to 5,100:1. The 

DOE/NETL in-house research also shows no significant in-duct removals of Hg under the test 

conditions, and Hg0 appears to be oxidized by the filter cake. On-going research on activated 

carbon injection using the DOE/NETL test facility includes tests to quantify the effects of 

humidification and FF pressure drop on Hg removal, evaluating novel sorbents, determining 

sorbent effectiveness downstream of a FF with and without recycle, and comparing Hg removals 

using sorbent injection with ESP versus FF.12 

A multiple-site, full-scale field test program is currently being conducted under a 

DOE/NETL cooperative agreement to obtain performance and cost data for using activated 

carbon injection to reduce Hg emissions from existing coal-fired electric utility power plants 

equipped only with an ESP or FF for post-combustion air pollution controls.14 The DOE/NETL 

is working in partnership with ADA-ES, PG&E National Energy Group (NEG), Wisconsin 

Electric, a subsidiary of Wisconsin Energy Corp., Alabama Power Company, a subsidiary of 

Southern Company, EPRI, and Ontario Power Generation on a field evaluation program at four 

power plant facilities. Other organizations participating in this test program as team members 

include EPRI, Apogee Scientific, URS Radian, Energy & Environmental Strategies, Physical 

Sciences, Inc., Southern Research Institute, Hamon Research-Cottrell, Environmental Elements 

Corporation, Norit Americas, and EnviroCare International. The first test site is a boiler unit at 

the Alabama Power Gaston facility that burns various low-sulfur bituminous coals and is 

7-23

Table 7-6. Hg removal by activated carbon injection measured at DOE/NETL inhouse test facility burning low-sulfur bituminous coal and using FF (Source: 

Reference 11). 

Mass Balance (%) Test 

Run ID 

Fabric Filter 

Temperature 

(

o

F) 

Sorbent 

Injection 

Ratio 

(C:Hg) 

Total 

Hg 

Removal 

(%) Fabric Filter Overall 

9907-1 

(baseline) 294 0 2.7 103.2 79.4 

9907-2 294 9,500:1 86.0 77.4 78.6 

9907-3 265 10,300:1 82.3 130.1 76.7 

9907-4 268 6,200:1 75.1 80.0 98.1 

9908-1 

(baseline) 296 0 35.0 84.4 67.1 

9908-2 296 2,600:1 38.8 100.6 90.8 

9908-3 296 5,400:1 64.0 94.7 89.1 

9908-4 270 2,900:1 54.2 103.2 86.8 

7-24

equipped with a hot-side ESP followed by a COHPAC FF. Testing at this site was conducted in 

the spring of 2001.15 The next test site being tested is a boiler unit at the Wisconsin Electric 

Pleasant Prairie facility that burns PRB subbituminous coal and uses a cold-side ESP for PM 

control. The other two sites are scheduled to be tested in 2002, and are the PG&E NEG Salem 

Harbor and Brayton Point facilities that burn low-sulfur bituminous coals and are equipped with 

cold-side ESPs. 

7.5.3.3 Calcium-based Sorbent Injection 

An alternative to using activated carbon is to use a calcium-based sorbent. Laboratory 

studies conducted by the EPA and Acurex Environmental Corporation (funded by the State of 

Illinois, ICCI) indicated that the injection of calcium-based sorbents into flue gas could result in 

significant removal of Hg (discussed in Section 5.3). Other benefits associated with the use of 

limestone injection for Hg control include an incremental amount of SO2 removal and a high 

probability for SO3 removal. Flue gas Hg removal using furnace limestone injection was 

evaluated as part of a study conducted by McDermott Technology, Inc. titled Combustion 2000 

Project/Low Emission Boiler System Program.16 In this study, limestone was injected into the 

upper furnace firing Ohio bituminous coal at a temperature of about 1,204 oC (2,200 oF). The 

Ca:S ratio was set at 1.40 mol/mol. An 80 percent efficient cyclone was then used to collect the 

fly ash and calcined lime. At this location the flue gas temperature was approximately 163 oC 

(325 oF). The Hg concentration in the flue gas was measured downstream of the cyclone using 

the OH Method. The measured Hg concentrations for the baseline (no limestone injection) and 

the six limestone injection tests are shown in Figure 7-5. The data show that the Hg 

concentration in the flue gas was significant lower when limestone was injected compared to the 

baseline. The overall average Hg reduction for the six limestone injection runs was 82 percent. 

The researchers note that using more efficient ESP or FF PM control devices with collection 

efficiencies of greater than 99 percent in place of a cyclone (see Table 3-3) is expected to 

provide an additional increase in Hg removal. 

Based on the test results from the EPA/Acurex ICCI studies and the Combustion 2000 

Project/Low Emission Boiler System Program, McDermott Technology, Inc. conducted 

additional limestone injection tests during Phase III of the AECDP.9 The same limestone 

previously tested in the Combustion 2000 program was used for the Phase III tests. Two 

limestone flow rates were tested. The flow rates chosen for the limestone injection tests were 

200 lb/hr (Ca:S = 0.35 mol/mol) and 25 lb/hr (Ca:S = 0.04 mol/mol). An injection temperature 

target of 1,149 oC to 1260 oC (2,100 oF to 2,300 oF) was chosen as the optimum range to 

calcine the limestone (CaCO3) into lime (CaO). It was assumed that CaO would be more 

reactive with Hg, as it is with SO2, because of the increased surface area and reactivity. 

Limestone was injected upstream of an ESP. The ESP inlet flue gas temperature was 177 oC 

(350 oF). Mercury concentrations were determined at the inlet and outlet of the ESP with 

triplicate Ontario Hydro measurements. One set of triplicate measurements was performed prior 

to sorbent injection to provide a baseline set of comparison data. 

Figure 7-6 shows the Hg partitioning and speciation for three sets of Hg measurement 

locations: 1) at the ESP inlet without limestone injection (baseline); 2) at the ESP inlet with 

7-25

Figure 7-5. Hg removal by limestone injection measured in Combustion 2000 

furnace using mechanical cyclone separator (source: Reference 9). 

7-26

Figure 7-6. Hg removal by limestone injection measured at AECDP test facility 

burning Ohio bituminous coal and using ESP (Source: Reference 9) 

7-27

limestone injection of 200 lb/hr; and 3) at the ESP outlet with limestone injection of 200 lb/hr. 

As shown in Figure 7-6, the total Hg in the flue gas at the ESP inlet with and without limestone 

injection is about the same. Limestone injection substantially increases the Hgp, thereby 

substantially reducing gaseous Hg2+. The Hgp is then removed by the ESP, providing an overall 

Hg removal of 53 percent compared to the baseline condition. Reducing the limestone feed rate 

to 25 lb/hr showed the same Hg partitioning trends observed for 200 lb/hr but with a reduction in 

total Hg removal. An overall Hg removal of 41 percent compared to the baseline condition was 

measured. The increased removal provided by limestone injection compared to the baseline 

appears to be a result of the capture of Hg2+ by the CaO particulate (onto or into the particulate 

phase) and the subsequent removal of the particulate in the ESP. Limestone injection had no 

apparent effect on the Hg0. 

Table 7-7 presents a summary comparison of limestone sorbent injection test results with 

the activated carbon injection results from the AECDP Phase III studies (discussed in 

Section 7.5.3.2). The table shows that limestone sorbent injection at 200 lb/hr achieved an 

equivalent level of total Hg removal with activated carbon injection. The difference in sorbentto-Hg ratios for these two tests is about a factor of 15. Based on the test results, the researchers 

concluded that activated carbon is a more effective sorbent than limestone on a mass basis; 

however, because the cost of activated carbon typically is an order of magnitude more than the 

cost for limestone, limestone is more effective on a sorbent cost basis. 

7.5.3.4 Multipollutant Sorbent Injection 

The EPRI/PSE&G Hudson sorbent injection study discussed in section 7.5.3.2 included 

measurement of Hg removal by coinjection of activated carbon with calcium-based sorbents for 

SO2 control.13 The calcium-based sorbents tested were sodium bicarbonate and hydrated lime. 

With the coinjection of either of the calcium-based sorbents, the researchers reported 

improvement in the adsorption of gaseous Hg by the activated carbon. 

A study of the coinjection of a sodium-based sorbent with activated carbon showed that 

the removal of gaseous Hg by the native fly ash and the activated carbon was impeded 

when the sodium sesquicarbonate was coinjected. As part of the AECDP Phase III studies using 

the PCM at the PSCO Comanche Station, tests were conducted to investigate whether any 

synergistic removal of Hg or impairment of SO2 removal occurs when injecting both activated 

carbon for Hg control and sodium sesquicarbonate for SO2 control into the flue gas and collected 

in a FF.17,18 The activated carbon tested was Darco FGDTM. 

When no sorbent (carbon or sodium) was injected into the flue gas, the measured Hg 

removal across the PCM by the native fly ash ranged from 41 to 76 percent at the respective 

temperatures of 162 oC (324 oF) and 138 oC (280 oF). When activated carbon was injected into 

the flue gas with no sodium sesquicarbonate, measured Hg removal across the PCM was 

74 percent at 162 oC (324 oF). When sodium sesquicarbonate was injected into the flue gas with 

no activated carbon injection, gaseous Hg removal percentages were in the negative range (i.e., 

test measurements indicated an increase in Hg concentrations at the PCM outlet compared to the 

inlet). When both activated carbon and sodium sesquicarbonate were injected into the flue gas, 

7-28

Table 7-7. Comparison of Hg removals for activated carbon injection versus 

limestone injection measured at AECDP test facility burning Ohio bituminous 

coal and using ESP ( Source: Reference 9). 

Sorbent Injected Upstream of ESP 

Parameter Limestone Activated 

Carbon 0.35 Ca:S mass ratio 0.04 Ca:S mass ratio 

Sorbent injection rate 14 lb/hr 200 lb/hr 25 lb/hr 

Sorbent:Hg mass ratio 9,000:1 125,000:1 16,000:1 

Sorbent injection 

temperature (0

F) 400 2,200 2,200 

ESP operating 

temperature (0

F) 345 350 350 

Total Hg removal (%) 53 53 41 

7-29

Hg removal percentages ranged from -104 to 22 percent. The SO2 removal percentages did not 

appear to be either impeded or improved with the coinjection of the activated carbon. 

Based on the limited data, the researchers speculated that the impediment of Hg capture 

occurred either because of inhibition of the sorbent mechanism or because the addition of sodium 

increased the level of NO2 in the flue gas. During the sodium sesquicarbonate tests, NO2 in the 

flue gas increased from 5 to 41 ppmv, with the higher values associated with the higher 

temperatures tested. If the increase in the NO2 levels was real, researchers are questioning 

whether NO2 had a negative impact on Hg removal and subsequent Hg desorption in the flue gas. 

Nitrogen dioxide is a strong oxidizer, which may have stripped Hg from the internal surfaces of 

the PCM, resulting in higher Hg measured at the outlet than the inlet (thus explaining the 

negative removal efficiencies for Hg). If this were the case, the effect would diminish over time 

as the Hg on the walls of the pilot unit came into equilibrium with the flue gas. No tests were 

run with sufficient time to observe this effect, and credible Hg data were not available in real 

time. 

The negative impact of the sodium sesquicarbonate injection on Hg removal by activated 

carbon injection is contrary to the results reported for the Hudson Station power plant tests where 

injecting either sodium bicarbonate or hydrated lime with activated carbon improved the 

activated carbon=s Hg adsorption capability. The Hudson data were taken over a single test day, 

and the two power plants tested burned different coal types with different fly ash properties and 

flue gas compositions (eastern bituminous coal at Hudson versus PRB subbituminous at 

Comanche). Drawing any definite conclusions regarding coinjection of alkaline materials and 

activated carbon based on these two tests would be conjecture. 

7.5.3.5 Noble-metal-based Sorbent in Fixed-bed Configuration 

ADA Technologies Inc. (ADA) has patented a sorbent process for Hg control in coal 

combustion flue gas, trade name Mercu-RETM. Unlike the dry sorbent injection processes 

previously discussed, the Mercu-RETM process is based on the adsorption of the Hg by noble 

metals in a fixed-bed, regeneration of the sorbents by thermal means, and recovering the 

desorbed Hg for commercial recycle or disposal.19, 20 Laboratory testing of the noble-metal 

sorbent showed that the sorbent captured virtually all of the Hg0 and mercuric chloride injected 

into a simulated coal combustion flue gas. During 1999, the noble-metal sorbent was tested for 

6 months using a flue gas slipstream from the PSE&G Hudson Station. The acid gases in the 

flue gas degraded the performance of the noble-metal sorbent. The field data suggested that 

there are limitations on the commercial application of using noble-metal sorbents for removal of 

Hg from coal combustion flue gas without upstream acid gas controls installed. Laboratory 

testing indicated that sorbent capacity can be recovered by scrubbing acid gases from flue gas 

prior to the sorbent bed. Additional testing is being conducted to determine if noble-metal 

sorbents can be used effectively on scrubbed flue gas. 

7-30

7.6 Mercury Control Retrofits for Existing Coal-fired Electric Utility Boilers Using SemiDry Absorbers 

7.6.1 Retrofit Options 

Spray dryer absorber systems are the most common semi-dry scrubbers currently being 

used at electric utility coal-fired electric utility power plants. With this control technology, a 

slurry of hydrated or slaked lime is sprayed into an absorber vessel where the flue gas reacts with 

the drying slurry droplets. The resulting particle-laden dry flue gas then flows to an ESP or an 

FF where fly ash and SO2 reaction products are collected. In some cases, water-soluble sodiumbased sorbents are used instead of calcium-based sorbents. SDA systems can also provide 

opportunities for injection of other dry sorbents for Hg or multipollutant control schemes. 

In a dry sorbent injection (DSI) system, a sorbent is injected into a flue gas duct upstream 

of the PM collector. In many cases water is injected upstream of the sorbent injection location to 

increase flue gas moisture content. This water spray, called spray humidification, reduces the 

flue gas temperature and increases the sorbent reactivity. DSI systems can also provide 

opportunities for injection of Hg or multipollutant sorbents. A circulating fluid-bed absorber 

(CFA) is effectively a Avertical duct absorber@ that allow simultaneous gas cooling, sorbent 

injection and recycle, and gas sorption by flash drying of wet lime reagents. It is believed that 

CFAs can potentially control Hg emissions at costs lower than those associated with use of spray 

dryers. With these absorbers, opportunities for use of advanced sorbents appear to be more 

favorable than for DSI, due to the improved sorbent utilization by re-circulation, recycle, and 

flash evaporative cooling. 

7.6.2 Pilot-scale and Full-scale Research and Development Status 

Full-scale tests on eastern bituminous coals (i.e., a 180 MWe boiler with a SDA-FF 

control system and a 55 MWe boiler with CFA-FF controls) were conducted in September 

2000.21 The EPA Method 101A was used for absorber inlet Hg measurements and the OH 

Method for the boiler stacks. Both units averaged over 97 percent Hg removal in the respective 

control systems based on outlet and inlet flue gas measurements. Using the raw coal analysis 

and the stack OH Method measurements, each system removed about 95 percent of total Hg. 

Further Hg/multipollutant testing of SDA and CFA units are planned in DOE-EPRI-EPA pilot 

and field test programs. 

7.7	 Mercury Control Retrofits for Existing Coal-fired Electric Utility Boilers Using Wet 

FGD Scrubbers 

7.7.1 Retrofit Options 

Wet FGD scrubbers are typically installed downstream of an ESP or FF. Removal of PM 

from the flue gas before it enters the wet scrubber reduces solids in the scrubbing solution and 

avoids chemistry problems that may be associated with fly ash. In the United States, plants that 

use wet limestone scrubbers for SO2 control generally capture more than 90 percent of the Hg2+ 

7-31

in the flue gas entering the scrubber. Consequently these FGD scrubbers may lower Hg 

emissions by about 20 to more than 80 percent, depending on the speciation of Hg in the inlet 

flue gas. 

Improvements in wet scrubber performance in capturing Hg depend primarily on the 

oxidation of Hg0 to Hg2+. This may be accomplished by the injection of appropriate oxidizing 

agents or installation of fixed oxidizing catalysts to promote oxidization of Hg0 to soluble 

species. Oxidation of gaseous Hg0 to gaseous Hg2+ 

can potentially increase the total Hg removed 

by wet scrubbing and sorbent systems since gaseous Hg2+ is more readily captured by these 

systems than gaseous Hg0. Several flue gas additives and scrubbing additives are being 

developed for this purpose. Flue gas and scrubber additives are also being developed for use in 

preventing the conversion of absorbed Hg2+ to gaseous Hg0 in wet FGD systems. 

An alternative strategy for controlling Hg emissions from wet FGD scrubbing systems is 

to inject sorbents upstream of the PM control device. In units equipped with FFs this allows for 

increased Hg capture and oxidization of Hg0 as the flue gas flows through the filter cake. 

Increased oxidization afforded by FFs results in increased Hg removal in the downstream 

scrubber. In FGD units equipped with ESPs, performance gains are limited by sorbent injection 

and Hg adsorption rates. 

7.7.2 Mercury Absorption Theory 

Gaseous Hg0 is insoluble in water and therefore does not absorb in the aqueous slurry of a 

wet FGD system. Gaseous compounds of Hg2+ 

are water-soluble and do absorb in such slurries. 

When gaseous compounds of Hg2+ are absorbed in the liquid slurry of a wet FGD system, the 

dissolved species are believed to react with dissolved sulfides to form mercuric sulfide (HgS); 

the mercuric sulfide precipitates from the liquid solution as a sludge. In the absence of sufficient 

sulfides in the liquid solution, a competing reaction that reduces/converts dissolved Hg2+ to Hg0 

is believed to take place. When this conversion takes place, the newly formed (insoluble) Hg0 is 

transferred to the flue gas passing through the wet FGD unit. The transferred Hg0 increases the 

concentration of Hg0 in the flue gas passing through the wet FGD unit (since the incoming Hg0 is 

not absorbed) giving rise to a higher concentration of gaseous Hg0 in the flue gas exiting the wet 

FGD than entering it. Transition metals in the slurry (originating from the flue gas) are 

suspected to play an active role in the conversion reaction since they can act as catalysts and/or 

reactants for reducing oxidized species 

7.7.3 Pilot-scale and Full-scale Research and Development Status 

7.7.3.1 Oxidation Additives 

As part of the AECDP Phase III studies, tests were conducted to investigate two potential 

chemical additives for controlling the conversion of oxidized Hg to the elemental form, and 

enhancing the control of Hg in a pilot-scale wet FGD system.9 The first additive was gaseous 

H2S. The selection of H2S as a potential additive was based on the possibility that a sulfidedonating species could assist in capturing Hg2+.A H2S gas stream at a concentration of about 2 

7-32

ppm was injected into the flue gas entering the scrubber. The Hg concentrations of gaseous Hg2+ 

and gaseous Hg0 measured at the wet scrubber inlet and outlet for the baseline and H2S injection 

tests are shown in Figure 7-7. Gaseous Hg removal by the wet scrubber increased with the 

addition of H2S (at about 2 ppm) from 46 to 71 percent. This increase was attributed mainly to a 

decrease in the conversion of Hg2+ to gaseous Hg0. 

The second additive tested was ethylenediaminetetraacetic acid (abbreviated EDTA). 

This chemical was selected because EDTA is strong chelating agent. Chelating agents react with 

metallic ions to form soluble nonionic compounds. Because, transition metals may act as a 

catalyst in the conversion of Hg2+ to gaseous Hg0 in wet FGD scrubbers, their chemical binding 

may reduce the conversion. For the test, EDTA was added to the scrubbing slurry. The Hg 

concentration of gaseous Hg2+ and gaseous Hg0 measured at the wet scrubber inlet and outlet for 

the ESP baseline and EDTA additive tests is shown in Figure 7-8. The total Hg removal 

increased to 73 percent with the addition of EDTA. Under a new cooperative agreement with 

DOE/NERL, McDermott Technologies, Inc. is conducting a full-scale test program of using 

scrubber additives to achieve increased Hg removal at two power plants burning high-sulfur 

Ohio bituminous coal: 1) Michigan South Central Power Agency's (MSCPA) 55-MWe Endicott 

Station located in Litchfield, MI, and 2) Cinergy's 1300-MWe Zimmer Station located near 

Cincinnati, OH.22 

7.7.3.2 Mercury Oxidation Catalysts 

Under a DOE/NETL cooperative agreement, laboratory and field tests were conducted to 

investigate catalytic oxidation of gaseous Hg0 in coal-fired electric utility boiler flue gas.23 The 

project tested the actual rate to convert gaseous Hg0 to a soluble form using different candidate 

catalysts under simulated and actual coal combustion flue gas conditions. The results of the 

bench-scale studies are discussed in Chapter 5. Additional extended tests with the most-active 

catalysts and fly ash were conducted in the field to assess their adsorption and/or oxidation of Hg 

in an actual coal-fired boiler flue gas.

24 These tests were conducted in a fixed-catalyst-bed test 

rig using a flue gas slipstream from a electric utility boiler firing a Texas lignite. Total Hg 

concentrations in the flue gas slipstream varied from 7 to 35 μg/Nm3, with the gaseous Hg0 

concentrations varying from 4 to 18 μg/Nm3. The inlet gaseous Hg2+ also was variable, ranging 

from 30 to 80 percent of the total, and the concentrations of SO2 and NOX varied considerably 

during the testing period. The catalysts and fly ash were exposed to flue over periods ranging 

from 3,480 to 3,490 hours. Table 7-8 presents the oxidation results over the 5-month-plus period 

of testing. For the values of the catalyst field measurements shown in the table, the Hg0 

oxidation measured across the sand “blank” was subtracted from the actual measured Hg0 

oxidation for each catalyst. In general, the field test results indicate that while the initial Hg0 

oxidation percentages achieved by the catalysts matched the percentages measured in the 

laboratory tests, the metal-based and some carbon-based catalysts were deactivated after a 

relatively short time exposure to the actual coal combustion flue gas. The researchers identified 

sulfur trioxide and selenium (or selenium compounds) as possible flue gas constituents that 

rapidly deactivate the iron-based and other metal catalysts. Additional bench-scale laboratory 

tests conducted as part of the study indicate that regeneration of spent catalysts should be 

possible. 

7-33

Figure 7-7. Effect of using H2S as an oxidation additive on wet FGD scrubber Hg 

removal measured at AECDP test facility burning Ohio bituminous coal (source: 

Reference 9). 

7-34

Figure 7-8. Effect of using EDTA as an oxidation additive on wet FGD scrubber 

Hg removal measured at AECDP test facility burning Ohio bituminous coal 

(source: Reference 9). 

7-35

Table 7-8. Comparison of field test results using flue gas from electric utility 

boiler firing Texas lignite versus bench-scale results using simulated flue gas for 

selected candidate Hg oxidation catalysts (Source: adapted from Reference 24). 

Field Test Results a,b 

Test Parameters 

Laboratory 

Bench-Scale 

Results at hour 

24 

at hour 

1,000 

at hour 

2,400 

at hour 

3,055 

at hour 

3,477 

Catalyst Type Percent of Hg 0 Oxidized Across Catalyst Bed 

Sand (non-catalyst blank) 3% 3.3-8.1% 7% 9–12 % 23 % 0 % 

Activated carbon #1 (1st Bed) 100 % 100 % 66 % 45 % 0 % 89 % 

Activated carbon #1(2nd Bed) 100 % 100 % 81% 42 – 59 % 0 % 0 % 

Activated carbon #2 96 % 97 % not 

recorded 76 % % 6 % 

Pd#1 91 % 90 % not 

recorded 82 % 0 % 0 % 

SB #5 (fly ash) 4/70 % c 100 % 36% 82 % 73% 0% 

Test Conditions 

Catalyst Bed Temp. oC (oF) 149 (300) 149 (300) 149 (300) 149 (300) 104 (220) 149 (300) 

Inlet Hg 0 (μg/Nm 3) 50 3.7 - 16.2 5.4 8.3 - 9.3 17.8 3.7 

Total Hg (μg/Nm 3) 50 7.0 - 26.1 9.8 15 - 27 31 - 35 27 

0 7

a All catalyst oxidation values corrected for the sand blank oxidation values. b Number of hours passing flue gas through the catalyst materials c Laboratory tests using SB#5 (fly ash) were conducted in a simulated flue gas with HCl (70 percent oxidation 

with 1 ppmv of HCl) and without HCl (4 percent oxidation). 

7-36

A pilot-scale field test program is currently being conducted under a DOE/NETL 

cooperative agreement to obtain addition data on the potential commercial application of Hg 

oxidation catalysts to enhance Hg capture by an existing wet FGD system downstream of highefficiency ESP.25 This study is testing selected catalysts previously identified as being effective 

by the DOE-sponsored studies in a commercial form in larger pilot-scale units for longer periods. 

The DOE/NETL is working in partnership with URS Group, Inc., EPRI, and two electric utility 

companies, Great River Energy and City Public Service of San Antonio, TX. The first test site is 

the Great River Energy Coal Creek Station, which fires North Dakota lignite. The second site 

the City Public Service of San Antonio’s J.K. Spruce Plant, which fires a PRB subbituminous 

coal. The pilot-scale tests will continue for over a year at each of two sites. 

7.7.3.3 Wet FGD Scrubber Design and Operating Modifications 

Several studies of pilot-scale wet FGD scrubbers suggest that modifying the operation 

and design of the scrubber unit as well as the upstream ESP may improve the capture of gaseous 

Hg2+ and reduce the conversion of absorbed Hg2+ to Hg0

. Specifically, these studies have found 

that the liquid-to-gas ratio and tower design of a wet FGD unit affect the absorption of gaseous 

Hg2+, while the oxidation air influences the conversion of absorbed Hg2+. The operating voltage 

of ESPs upstream of wet FGD systems has also been shown to influence the latter. The 

remainder of this section summarizes these findings. 

Scrubber Liquid-to-gas Ratio. The liquid-to-gas ratio (L/G ratio) of a wet FGD system is 

dictated by the desired removal efficiency to control SO2 emissions. The selected L/G ratio also 

can impact the removal efficiency of gaseous Hg2+. In general, high efficiency FGD systems 

(95+ percent SO2 removal) are designed with L/G ratios in the range of 120 to 150 gallons (gal.) 

of aqueous slurry per 1,000 actual cubic feet (acf) of gas flow. In two separate pilot-scale 

studies26 increasing the L/G ratio from approximately 40 to 125 gal./1,000 acf increased the 

removal efficiency of gaseous Hg2+ from 90 to 99 percent. However, increasing the L/G ratio 

did not affect the removal of gaseous Hg0

, which was close to zero percent. Similar studies were 

conducted prior to these studies and produced similar findings.23,27 

Scrubber Tower Design. Most of the existing wet FGD systems in the United States use 

either an open-spray tower or tray tower design. In one study of wet FGD systems, where the 

composition of the flue gas was mostly gaseous Hg2+, the tray tower design removed from 85 to 

95 percent of the total Hg, whereas the open spray tower design removed from 70 to 85 percent 

of the total Hg. 

28 This study suggests that a tray tower design is more effective in removing 

gaseous Hg2+ from boiler flue gas than an open spray tower design for a given SO2 removal 

level. 

Scrubber Oxidation Air. When SO2 is absorbed in the scrubbing slurry of a wet FGD 

system, the dissolved SO2 reacts with lime or limestone to form insoluble sulfate/sulfite sludge; 

the sulfate reaction consumes oxygen, which is present in the flue gas. Some wet FGD systems 

add air to the system to increase the amount of oxygen available for the reaction; the additional 

oxygen accelerates the reaction between SO2 and lime or limestone. 

7-37

The effect of oxidation air on FGD Hg removal was investigated as part of the AECDP 

Phase III studies by conducting test runs at baseline, intermediate and low levels of oxidation 

air.9 Figure 7-9 compares wet scrubber inlet and outlet Hg concentration measured for the base 

case and the runs at a mid- and low-level of oxidation air. The bars include the elemental and 

oxidized fractions of the total gaseous Hg. The relative amounts of Hg0 at the inlet and outlet did 

not change significantly for the three tests. However, the amount of absorbed Hg2+ converted to 

Hg0 decreased as the oxidation air decreased. This point is further illustrated in Figure 7-10 that 

shows only the gaseous Hg0 for the three tests. For the baseline test, gaseous Hg0 increased by 

265 percent across the wet scrubber. This improved to a 76 percent increase for the second test, 

and only two percent for the low oxidation air test. Total gaseous-phase Hg removal improved 

from 46 percent for the base case to 80 percent for the low oxidation air case. These normalized 

oxidation air stoichiometry results show a strong relationship between oxidation air and wet 

scrubber Hg removal for a wet FGD system. The researchers of this study hypothesize that low 

oxidation air must somehow inhibit the reduction of absorbed Hg2+, or provide a species needed 

to sequester the absorbed Hg2+ in the slurry. The researchers also note that the level to which the 

scrubber oxidation air can be reduced at a given coal-fired electric utility power plant is highly 

site-specific specific and depends on several factors such as scaling considerations and gypsum 

purity requirements. 

Voltage of ESP Upstream of Scrubber. The effect of ESP operating power on wet 

scrubber Hg removal was investigated as part of the AECDP Phase III studies.9 Concentrations 

of gaseous Hg2+ and gaseous Hg0 were measured at the inlet and outlet of the wet FGD system 

for three different ESP operating conditions. For the first operating condition (the baseline 

operation), the pilot-scale ESP was operated with three of its four fields in service, and the power 

was set to maintain an outlet particulate loading of 0.02 to 0.03 lb/MBtu (below the PM limit of 

the New Source Performance Standard for utility boilers). In the second operating condition, the 

ESP voltage was increased by 60 percent above the baseline voltage. In the third operating 

condition, the ESP power was turned off and an FF was used for PM control upstream of the wet 

FGD system. For all three operating conditions, triplicate measurements of Hg were made at the 

inlet and outlet of the pilot-scale wet FGD system. 

Figure 7-11 compares the concentrations of gaseous Hg2+ and gaseous Hg0 measured at 

the inlet and outlet of the wet FGD system for the three different ESP operating conditions. 

Since the Hg measurements were taken downstream of the ESP and FF, very little Hgp was 

measured; thus, Hgp measurements are not shown in the Figure 7-11. Figure 7-12 presents only 

gaseous Hg0 for the same three ESP conditions as those in Figure 7-11. The figures clearly show 

that the operating voltage of the ESP has a direct, negative impact on the wet scrubber Hg 

control performance. The proportion of gaseous Hg2+ and gaseous Hg0 at the wet scrubber inlet 

is the same for all three tests. However, for the high-power test, the amount of gaseous Hg0 

significantly increased across the wet scrubber. The gaseous Hg0 remains constant for the 

no-power test, which is the observed behavior when the scrubber is preceded by the FF. This 

indicates that the electric field affects some component of the flue gas, which, in turn, has a 

negative impact on wet scrubber chemistry. 

7-38

Figure 7-9. Effect of oxidation air on wet FGD scrubber Hg removal as measured 

at AECDP test facility burning Ohio bituminous coal (source: Reference 9). 

7-39

Figure 7-10. Effect of oxidation air on Hg0 in wet FGD scrubber flue gas as 

measured at AECDP test facility burning Ohio bituminous coal (source: 

Reference 9) . 

7-40

Figure 7-11. Effect of ESP operating voltage on wet FGD scrubber Hg removal as 

measured at AECDP test facility burning Ohio bituminous coal (source: 

Reference 9). 

7-41

Figure 7-12. Effect of ESP operating voltage on Hg0 in wet FGD scrubber flue gas 

as measured at AECDP test facility burning Ohio bituminous coal (Source: 

Reference 9). 

7-42

7.8 Multipollutant Control Technologies 

This section presents a summary of control systems being commercially offered or 

developed for multipollutant emissions control. The current status of many systems is based 

upon reports that targeted one or two pollutants. A caution here is that, when evaluating the best 

system for a specific application, it is important to consider both: 1) how a given system affects 

the emissions of all pollutants, and 2) how that system affects the long-term performance, 

operation, and cost of other downstream systems, including ductwork, heat exchangers, stacks, 

and other emission control equipment. To date no comprehensive long-term evaluations of the 

multipollutant systems described below have been conducted. 

7.8.1 Corona Discharge 

Generation of an intense corona discharge (ionization of air by a high voltage electrical 

discharge) in the boiler flue gas upstream of an ESP and wet scrubber is being investigated with 

respect to improving PM control by oxidation of a portion of the entering SO2 to SO3.

29 The 

corona discharge creates oxygen-carrying reactive species, which, in turn, oxidize the Hg0 in the 

flue gas (i.e., convert Hg0 to Hg2+). The increased SO3 both improves ESP collection of PM and 

acts to convert Hg0 to Hg2+ which may then be captured by an alkaline FGD scrubber 

downstream. Representative reactions for SO2 oxidation by corona discharge include: 

O2 + e- --> 2 O + eO2 + O --> O3 

SO2 + O3 --> SO3 + O2 

SO3 + H2O --> H2SO4 

Similarly, for NO, 

NO + e- --> NONO + NO- --> NO2 +N+ eO2 + e- --> 2 O + eO2 + O --> O3 

H2O+O3 --> 2 OH + O2 

NO2 + OH --> HNO3 

Environmental Elements Corporation is developing a process based on corona discharge 

that recovers the oxidized sulfur and nitrogen compounds as marketable sulfuric and nitric acids 

in wet ESP sections and or/absorbers. A slipstream pilot plant has been installed at Alabama 

Power Miller Plant (Unit 3). Initial tests indicated 80 percent Hg removal and complete 

oxidation of Hg0 at 10 and 20 W/cfm, respectively. 

Powerspan Corporation is developing a single, integrated pollution control device that 

uses a proprietary technology called Electro-Catalytic OxidationTM or ECOTM to control SO2, 

NOX, Hg, and fine PM in coal-fired boiler flue gas.30 The first stage of the device uses a 

dielectric barrier discharge to convert NOX and SO2 to acids and to oxidize Hg0. A condensing, 

7-43

wet ESP is used to collect acid mists, fine PM, and Hg. The effluent from the wet ESP is 

processed to produce salable byproducts (e.g., concentrated acids, gypsum for wallboard 

manufacture, and ammonia for fertilizer). Before entering the ECOTM unit, flue gas passes 

through a conventional ESP to remove the majority of the ash particles. In partnership with 

FirstEnergy Corporation, Powerspan has built a pilot-scale ECO test facility at FirstEnergy's R.E. 

Burger Plant near Shadyside, OH.31 This test facility processes a slipstream of flue gas from a 

150-MW boiler unit burning high-sulfur eastern bituminous coal. The test results showed a Hg 

emission reduction of 68 percent. Under a new DOE cooperative agreement, Powerspan and 

FirstEnergy are conducting a research project using the ECOTM pilot test facility to optimize the 

technology's Hg removal capability while maintaining the performance of the ECOTM unit for 

removal of nitrogen oxides, sulfur dioxide, and fine PM.32 In addition, Powerspan and 

FirstEnergy are currently constructing an $11.9 million ECO commercial demonstration unit at 

FirstEnergy's Eastlake Plant near Cleveland, OH. The project is being cofunded by a $3.5 

million grant from the Ohio Coal Development Office. 

7.8.2 Electron Beam Irradiation 

The E-Beam Process has been offered commercially since the 1980s and is now used in 

Japan and China.33 The chemical reactions are identical to corona discharge, except that the 

power source is a battery of irradiating electron “guns” and the oxidation products then enter a 

semi-dry absorption system with ammonia reagent and are converted to ammonium sulfate and 

nitrate salts suitable for use as a fertilizer. It is presumed that the Hg solids would also be 

present in the fertilizer as contaminants. The polishing reactions for E-Beam are: 

NH4OH + HNO3 --> NH4NO3 + H2O 

2 NH4OH + H2SO4 --> (NH4)2SO4 +2H2O 

7.8.3 Oxidant Injection in Flue Gas 

A number of proposed schemes would add an oxidant such as chlorine, peroxide, or 

ozone to the flue gas upstream of an absorber. Again the reaction products would be similar to 

corona or electron beam, and the recovered products could range from weak acids to 

sulfate/nitrate fertilizers or lower-value soil amendments; trace Hg salts would likely be 

contained within these products. An example of ozone injection is the Lo-TOx.

34 The ISCA is a 

chlorine-based system producing byproduct acids. Hydrogen peroxide and other chlorine-based 

oxidation schemes have been investigated but have not been proposed for commercial use.35 

Typical oxidation reactions are: 

7-44

Hydrogen Peroxide: 

H2O2 --> 2 OH 

H2O2 + OH --> HO2 + H2O 

NO + OH --> NO2 +H 

NO + OH --> HNO2 

NO + HO2 --> HNO3 

NO2 + OH --> HNO3 

7.8.4 Catalytic Oxidation 

Ozone: 

NO + O3 --> NO2 + O2 

2 NO2 + O3 --> N2O5 + O2 

SO2 + O3 --> SO3 + O2 

N2O5 + H2O --> 2 HNO3 

SO2 + N2O5 --> SO3 +2NO2 

Catalysts can be employed in higher temperature regimes to speed up oxidation of SO2 

and NOX, but not Hg0. However, increasing the SO3 and NO2/N2O4/N2O5 concentrations will 

likely result in increased conversion of Hg0 to Hg2+ downstream, as acid gases and PM are 

removed in control devices. Lower temperature catalysis (less than 500 oF) would likely directly 

oxidize Hg0 to Hg2+. Thus, any number of catalytic oxidation schemes that produce byproduct 

acids would likely remove a substantial portion of total Hg with the acids as a Hg salt -- chloride, 

sulfate, or nitrate. A number of catalytic technologies are under commercial development; an 

example of this class - SNOx - has been evaluated under DOE’s Clean Coal Technology 

Program. At least one current DOE-sponsored project is examining the effectiveness of an 

oxidation catalyst upstream of wet FGD scrubber to decrease total Hg emissions.36 

7.8.5 Oxidant Addition to Scrubber 

One current DOE test program is measuring the effectiveness of a Hg oxidant added to 

the liquor of commercial wet scrubbers. The EPA is sponsoring similar research, which will 

culminate in a pilot-scale slipstream evaluation of oxidant addition.37 Another DOE-sponsored 

project is investigating the use of oxidated-lime and lime-silica sorbents to a semi-dry circulating 

bed absorber for combined SO2, NOX, and Hg control.38 Other combinations of sorbents injected 

upstream of an efficient PM collector such as the EPRI Toxecon

TM 

process may be used for a 

multiple pollutant control strategy centered around PM control. 

7.8.6 Catalytic Fabric Filters 

Some pilot-scale efforts have reported substantial oxidation of Hg within a FF, 

presumably by catalytic action of certain fibers or residual fly ash imbedded within the fabric.

39 

Several investigations are being made into woven carbon fibers or other catalytic materials 

integrated into the bag filters for a combined Hg/PM control device. 

7.8.7 Carbon-fiber FFs and ESPs 

Carbon-fiber FFs are commercially available. Carbon-fiber ESP plates are being 

investigated under a study sponsored the Ohio Coal Development Office. While combined 

Hg/PM control using this approach would be initially effective, the Hg capacity would be 

7-45

realized in a relatively short time period; therefore, means of regenerating the carbon active sites 

without replacing the fabric filter bags or ESP plates have to be devised. 

7.9 Summary 

A practical approach to controlling Hg emissions at existing utility plants is to minimize 

capital costs by adapting or retrofitting existing equipment to capture Hg. Potential retrofit 

options for control of Hg were investigated for units that currently use the following post 

combustion emission control methods: (1) ESPs or FFs for control of PM, (2) dry FGD scrubbers 

for control of PM and SO2, and (3) wet FGD scrubbers for the control of PM and SO2. 

Hg Control Retrofits for ESP and FF 

ESPs and FFs are either cold-side or hot-side devices. Hot-side devices are installed 

upstream of the air heater while cold-side devices are installed downstream. Flue gas 

temperatures in hot-side devices typically range from 350 to 450 o

C while cold-side devices 

typically operate at temperatures ranging from 140 to 160 o

C. Based on current information, it 

appears that little Hg can be captured in hot-side ESPs or FFs. 

Least-cost retrofit options for the control of Hg emissions from units with ESP or FF are 

believed to include: 

•	 Injection of a sorbent upstream of the ESP or FF. Cooling of the stack gas or 

modifications to the ducting may be needed to keep sorbent requirements at 

acceptable levels. 

•	 Injection of a sorbent between the ESP and a pulsejet FF retrofitted downstream of 

the ESP. This approach will increase capital costs but reduce sorbent costs. 

•	 Installation of a semi-dry CFA upstream of an existing ESP used in conjunction with 

sorbent injection. The CFA recirculates both fly ash and sorbent to create an 

entrained bed with a large number of reaction sites. This leads to higher sorbent 

utilization and enhanced fly ash capture of Hg and other pollutants. 

Units equipped with a FF require less sorbent than units equipped with an ESP. ESP 

systems depend on in-flight adsorption of Hg by entrained fly ash or sorbent particles. The FFs 

obtain in-flight capture and capture as the flue gas passes through the FF. 

In general, the successful application of cost-effective sorbent injection technologies for 

ESP and FF units will depend on: (1) the development of lower cost and/or higher performing 

sorbents, and (2) appropriate modifications to the operating conditions or equipment being 

currently used to control emission of PM, NOX, and SO2. 

7-46

Mercury Control Retrofits for Wet FGD Scrubbers 

Wet FGD scrubbers are typically installed downstream of an ESP or FF. Wet limestone 

FGD scrubbers are the most commonly used scrubbers on coal-fired electric utility boilers. 

These FGD units generally capture more than 90 percent of the Hg2+ in the flue gas entering the 

scrubber. Consequently, existing wet FGD scrubbers may lower Hg emissions by about 20 

percent to more than 80 percent, depending on the speciation of Hg in the inlet flue gas. 

Improvements in wet scrubber performance in capturing mercury depend primarily on the 

oxidation of Hg° to Hg2+. This may be accomplished by 1) the injection of appropriate oxidizing 

agents, or 2) the installation of fixed oxidizing catalysts upstream of the scrubber to promote 

oxidization of Hg0 to soluble species. 

An alternative strategy for controlling Hg emissions from wet FGD scrubbers is to inject 

sorbents upstream of the PM control device. In wet FGD systems equipped with ESPs, 

performance gains are limited by the in-flight oxidization of Hg0

, and the in-flight capture of 

Hg2+ and Hg°. In systems equipped with FFs, increased oxidization and capture of Hg can be 

achieved as the flue gas flows through the FF. Increased oxidization of Hg° in the FF will result 

in increased Hg removal in the downstream scrubber. 

Mercury Control Retrofits for Semi-dry FGD Systems 

SDA systems that use calcium-based sorbents are the most common dry FGD systems 

used in the utility industry. An aqueous slurry containing the sorbent is sprayed into an absorber 

vessel where the flue gas reacts with the drying slurry droplets. The resulting, particle-laden, dry 

flue gas then flows to an ESP or a FF where fly ash and SO2 reaction products are collected. 

CFAs are “vertical duct absorbers” that allow simultaneous gas cooling, sorbent injection 

and recycle, and gas absorption by flash drying of wet lime reagents. It is believed that CFAs 

can potentially control Hg emissions at costs lower than those associated with use of spray 

dryers. 

Dry FGD systems are already equipped to control emissions of SO2 and PM. The 

modification of these units by the use of appropriate sorbents for the capture of Hg and other air 

toxics is considered to be the easiest retrofit problem to solve. 

7.10 References 

1.	 Smit, F. J., G.L. Shields, and C.J. Mahesh. "Reduction of Toxic Trace Elements in Coal By 

Advanced Cleaning." Presented at the Thirteenth Annual International Pittsburgh Coal 

Conference, September 3-7, 1996. 

7-47

2.	 Topical Report No. 5 Trace Element Removal Study." Prepared for U.S. Department of 

Energy’s Pittsburgh Technology Center by ICF Kaiser Engineers, Fairfax, VA. March 1995. 

3.	 Brown, T. D., D.N. Smith, R.A. Hargis, Jr., and W.J. O’Dowd. “1999 Critical Review: 

Mercury Measurement and Its Control: What We Know, Have Learned, and Need to Further 

Investigate,” Journal of the Air & Waste Management Association, June 1999. pp. 1-97. 

4.	 Nebel, K. L., D.M. White, W.H. Stevenson, and M.G. Johnston. A Summary of Mercury 

Emissions and Applicable Control Technologies for Municipal Solid Waste Combustors. 

U.S. EPA, Office of Air Quality Planning and Standards, Research Triangle Park, NC. 

September 1991. 

5.	 Getz, N. P., B.T. Ian, and C.K. Amos. “Demonstrated and Innovative Control Technologies 

for Lead, Cadmium and Mercury for Municipal Waste Combustors,” Proceedings of the Air 

& Waste Management Association 85th Annual Meeting and Exhibition, Kansas City, MO. 

1992. 

6.	 Brown, B., and K. Felsvang. "Control of Mercury and Dioxin Emissions from United States 

and European Municipal Waste Incinerators by Spray Dryer Absorption Systems," in 

Proceedings of the Municipal Waste Combustion International Specialty Conference, Air 

and Waste Management Association, VIP-19, Tampa, FL, pp 685-705, April 1991. 

7.	 Babcock & Wilcox Alliance Research Center. Advanced Emissions Control Development 

Program Phase I – Approved Final Report prepared for the U.S. Department of Energy 

(U.S. DOE-FETC contract DE-FC22-94PC94251) and Ohio Coal Development Office 

(grant agreement CDO/D-922-13), July 1996. 

8.	 McDermott Technologies, Inc. Advanced Emissions Control Development Program 

Phase II – Approved Final Report, prepared for the U.S. Department of Energy (U.S. DOEFETC contract DE-FC22-94PC94251) and Ohio Coal Development Office (grant agreement 

CDO/D-922-13), RDD:98:43509-500-200:01R, April 1998. Available at: 

<http://www.lanl.gov/cgibin/byteserver.pl/projects/cctc/resources/pdfsmisc/haps/M9800501 

5.pdf >. 

9.	 McDermott Technologies, Inc. Advanced Emissions Control Development Program 

Phase III – Approved Final Report, prepared for the U.S. Department of Energy (U.S. DOEFETC contract DE-FC22-94PC94251—22) and Ohio Coal Development Office (grant 

agreement CDO/D-922-13). July 1999. Available at: 

< http://www.osti.gov/dublincore/servlets/purl/756595-LACvcL/webviewable/756595.pdf >. 

10. Grover, C., J. Butz, S. Haythornthwaite, J. Smith, M. Fox, T. Hunt, R. Chang, T. Brown, and 

E. Prestbo. "Mercury Measurements Across Particulate Collectors of PSCO Coal-fired 

Electric Utility Boilers," EPRI/DOE/EPA Mega-Symposium, Atlanta, GA. August 1999. 

7-48

11. Hargis, R. A., W.J. O’Dowd, and H.W. Pennline. “Sorbent Injection for Mercury Removal 

in a Pilot-scale Coal Combustion Unit,” presented at the 93th Annual Meeting & Exhibition 

of the Air & Waste Management Association, Salt Lake City, UT. June 2000. 

12. U.S. Department of Energy, National Energy Technology Laboratory. In-House Research 

on Mercury Measurement and Control at NETL. Pittsburgh, PA . November 2001. Available 

at: < http://www.fetc.doe.gov/coalpower/environment/mercury/pubs/poster.pdf >. 

13.	 Waugh, E.G., B.K. Jensen, L.N. Lapatnick, F.X. Gibbons, S. Sjostrom, J. Ruhl, R. Slye, and 

R. Chang. “Mercury control in utility ESPs and baghouses through dry carbon-based sorbent 

injection pilot-scale demonstration,” In Proceedings of the EPRI/DOE/EPA Combined 

Utility Air Pollutant Control Symposium, EPRI TR-108683-V3; Washington, DC, August 

25-29, 1997. 

14. Durham, M.D, C.J. Bustard, R. Schlager, C. Martin, S. Johnson, and S. Renninger. “Field 

Test Program to Develop Comprehensive Design, Operating and Cost Data for Mercury 

Control Systems on Non-Scrubbed Coal-Fired Boilers,” presented at the Air & Waste 

Management Association 2001 Annual Conference and Exhibition, Orlando, FL. June 24-28, 

2001. 

15. Bustard, C. J., M. Durham, C. Lindsey, T. Starns, K. Baldrey, C. Martin, S. Sjostrom, R. 

Slye, S. Renninger, and L. Monroe, “Full-Scale Evaluation of Mercury Control with Sorbent 

Injection and COHPAC at Alabama Power E.C. Gaston,” presented at the A&WMA 

Specialty Conference on Mercury Emissions: Fate, Effects, and Control and the U.S. 

EPA/DOE/EPRI Combined Power Plant Air Pollutant Control Symposium: The Mega 

Symposium, Chicago, IL. August 20-23, 2001. 

16. Madden, D.A., and M.J. Holmes. “B&W’s E-LIDS TM Process – Advanced SOx, 

Particulate, and Air Toxics Control for the Year 2000,” presented at the 1998 EPRI-DOEEPA Combined Utility Air Pollutant Control Symposium, Washington, DC. August 25-29, 

1997. 

17.	 Sjostrom, S., J. Smith, T. Hunt, R. Chang, and T. D. Brown. "Demonstration of Dry CarbonBased Sorbent Injection for Mercury Control in Utility ESPs and Baghouses." Presented at 

the Air & Waste Management Association’s 90th Annual Meeting & Exhibition, Toronto, 

Ontario, Canada. June 8-13, 1997. 

18. Haythornthwaite, S., S. Sjostrom, T. Ebner, J. Ruhl, R. Slye, J. Smith, T. Hunt, R. Chang, 

and T.D. Brown. “Demonstration of Dry Carbon-Based Sorbent Injection for Mercury 

Control in Utility ESPs and FFs,” in Proceedings of the EPRI/DOE/EPA Combined Utility 

Air Pollutant Control Symposium; Washington, DC; EPRI TR-108683-V3. August 25-29, 

1997. 

7-49

19. Roberts, D.L., J. Albiston, T. Broderick, C. Greenwell, and R. Stewart. Novel Process for 

Removal and Recovery of Vapor Phase Mercury, Phase I Final Report under Contract DEAC22-95PC95257 to DOE Federal Energy Technology Center, Pittsburgh, PA. September 

1997. 

20. Turchi, C.S., J. Albiston, T.E. Broderick, and R.M. Stewart. “Removal of Mercury from 

Coal-Combustion Flue Gas Using Regenerable Sorbents,” presented at the 92nd Annual 

Meeting of the Air & Waste Management Association, St. Louis, MO. June 1999. 

21.	 ARCADIS Geraghty & Miller. Roanoke Valley Energy Facility Mercury Testing. Research 

Triangle Park, NC. November 6, 2000. 

22. U.S. Department of Energy, National Energy Technology Laboratory. “Full-Scale Testing of 

Enhanced Mercury Control in Wet FGD,” November 2001. Available at 

< http://www.fetc.doe.gov/coalpower/environment/mercury/index.html >. 

23. Hargrove, O.W., Jr., T.R. Carey, C.F. Richardson, R.C. Skarupa, F.B. Meserole, R.G. Rhudy, 

and T.D. Brown. “Factors Affecting Control of Mercury by Wet FGD,” Presented at the 

EPRI/DOE/EPA Combined Utility Air Pollutant Control Symposium, Washington, DC. 

August 1997. 

24. Blythe, G.M, T.R.Carey, C.F. Richardson , F.B. Meserole, R.G. Rhudy, and T.D. Brown. 

“Enhanced Control of Mercury by Wet Flue Gas Desulfurization Systems,” Presented at the 

92nd Annual Meeting & Exhibition of the Air & Waste Management Association, St. Louis, 

MO. June 1999. 

25. U.S. Department of Energy, National Energy Technology Laboratory. “Pilot Testing of 

Mercury Oxidation Catalysts,” Pittsburgh, PA. November 2001. Available at: 

< http://www.fetc.doe.gov/coalpower/environment/mercury/index.html >. 

26. Redinger, K. E., A. P. Evans, R. T. Bailey, and P. S. Nolan. "Mercury Emissions Control in 

FGD Systems,” presented at the EPRI/DOE/EPA Combined Air Pollutant Control 

Symposium, Washington, DC. August 25-29, 1997. 

27.	 Hargrove, O.W., Jr., J.R. Peterson, D.M. Seeger, R.C. Skarupa, and R.E. Moser. “Update of 

EPRI Wet FGD Pilot-Scale Mercury Emissions Control Research,” presented at the 

EPRI/DOE International Conference on Managing Hazardous and Particulate Pollutants, 

Toronto, Canada. August 15-17, 1995. 

28.	 Electric Power Research Institute. Electric Utility Trace Substances Synthesis Report -

Volume 3: Appendix O, Mercury in the Environment. EPRI TR-104614-V3, Project 

3081,3297. November 1994. 

7-50

29. Helfritch, D.J., and P.L. Feldman. “Flue Gas Mercury Control by Means of Corona 

Discharge,” Paper 99-157, Air & Waste Management Association 92nd Annual Meeting, 

St. Louis, MO. June 20-24, 1999. 

30.	 McLarnon, C. R., M. L. Horvath, and P. D. Boyle. “Electro-Catalytic Oxidation Technology 

Applied to Mercury and Trace Elements Removal from Flue Gas,” presented at Conference 

on Air Quality II, McLean, VA. September 20, 2000. 

31.	 McLarnon, C. R, and M. D. Jones. “Electro-Catalytic Oxidation Process for Multi-Pollutant 

Control at FirstEnergy’s R.E. Burger Generating Station,” presented at Electric Power 2000, 

Cincinnati, OH. April 5, 2000. 

32. U.S. Department of Energy, National Energy Technology Laboratory. “Non-thermal Plasma 

Based Removal of Mercury,” November 2001. Available at 

< http://www.fetc.doe.gov/coalpower/environment/mercury/index.html >. 

33. Hirona, S. “Simultaneous SO2, SO3 and NOX Removal by Commercial Application of the 

EBA Process,” presented at the EPRI/DOE/EPA Combined Utility Air Pollution Control 

Symposium, Atlanta, GA, EPRI TR-113187-V2, pp 8-1 through 8-14. August 1999. 

34.	 Anderson, M.H., A.P. Skelley, E. Goren, and J. Cavello. “A Low Temperature Oxidation 

System for the Control of NOX Emissions Using Ozone Injection,” presented at the Institute 

of Clean Air Companies Forum 98: Cutting NOX Emissions, Durham, NC. March 18-20, 

1998. 

35.	 Livengood, C.D., and M.H. Mendelsohn. “Process for Combined Control of Mercury and 

Nitric Oxide,” presented at the EPRI/DOE/EPA Combined Utility Air Pollution Control 

Symposium, Atlanta, GA, EPRI TR-113187-V2, pp 19-30 through 19-41. August 1999. 

36.	 Richardson, C.F., G.M. Blythe, T.R. Carey, R.G. Rhudy, and T.D. Brown. “Enhanced 

Control of Mercury by Wet FGD Systems,” EPRI/DOE/EPA Combined Utility Air Pollution 

Control Symposium, Atlanta, Georgia, EPRI TR-113187-V3, pp 20-41 through 20-54, 

August 1999. 

37.	 Roy, S., and G.T. Rochelle. Chlorine Absorption in S (IV) Solutions. EPA-600/R-01-054 

(NTIS PB2001-107826), National Risk Management Research Laboratory, Research 

Triangle Park, NC . August 2001. 

38.	 Ghorishi, S.B., C.F. Singer, W.S. Jozewicz, R.K. Srivastava, and C.B. Sedman. 

“Simultaneous Control of Hg0

, SO2, and NOX by Novel Oxidized Calcium-Based Sorbents,” 

Paper # 243, presented at the 94th AWMA Annual Meeting, Orlando, FL. June 2001. 

7-51

39.	 McManus, T.J., R.O. Agbede, and R.P. Khosah. “Conversion of Elemental Mercury to the 

Oxidized Form in a Baghouse,” Paper 98-WP79A.07, presented at the A&WMA 91st 

Annual Meeting, San Diego, CA. June 14-18, 1998. 

7-52

Chapter 8


Cost Evaluation of Retrofit Mercury Controls for


Coal-fired Electric Utility Boilers


8.1 Introduction 

A practical approach to controlling Hg emissions at existing coal-fired electric utility 

power plants is to minimize control costs by adapting or retrofitting existing air pollution control 

equipment to capture Hg. As discussed in Chapter 3, coal-fired electric utility power plants 

currently use a wide variety of technologies to control the emission of criteria air pollutants (e.g., 

PM, SO2, and NOX emissions). Generally, the air pollution control methods and configurations 

used for a given coal-fired electric utility boiler depend on the type of coal burned, age and size 

of the boiler unit, and the power plant location. 

Potential retrofit technologies for the control of Hg emissions from existing coal-fired 

electric utility boilers are discussed in Chapter 7. Control technologies using injection of 

powdered activated carbon (PAC) into the flue gas have been applied successfully on municipal 

waste combustors to reduce Hg emissions. Pilot-scale testing indicates that these technologies 

offer the potential to provide significant Hg removal from the flue gas of coal-fired electric utility 

boilers. This chapter discusses an initial evaluation of annual Hg control costs based on the 

retrofit of PAC injection-based control technologies to a series of model plant scenarios (not 

actual full-scale applications) representative of the coal-fired electric utility power plants 

operating in the United States. It is worth noting that, while performance and cost of only PACrelated technologies were evaluated, other non-PAC-based Hg control technologies are expected 

to be available in the future. For example, enhanced Hg oxidation using oxidants or catalysts 

followed by wet scrubbing may become available. Also, the role of an SCR-FGD combination 

may become more cost effective and attractive. The information presented in this chapter was 

used in the EPA’s recent regulatory determination regarding Hg and other air toxics. 

The cost estimates of the PAC injection-based Hg control technologies presented in this 

chapter are based on relatively few data points from pilot-scale tests and, therefore, are 

considered to be preliminary estimates. As discussed in Section 8.2, factors that are known to 

affect adsorption of Hg on activated carbon include speciation of Hg in the flue gas, flue gas and 

ash characteristics, and the degree of mixing between the flue gas and activated carbon. The 

effects of these factors may not be entirely accounted for in the relatively few pilot-scale data 

points available for this evaluation. Successful testing of a control approach at small pilot plants 

8-1

does not necessarily guarantee successful implementation of the approach in full-scale systems. 

Temporary wall effects at small scale will generally not be realized at full scale. Appropriate 

mass transfer associated with mixing and the number, placement, and design of reagent and 

sorbent injection equipment may also need to be determined. Further, potential longer-term 

problems such as deposits, fouling, and corrosion of the control equipment are frequently not 

addressed by pilot-scale tests because of shorter-term, non-continuous operation. Ongoing 

research is expected to address these issues to improve the potential of using sorbents for Hg 

control in coal-fired boilers. 

Coal-fired electric utility power plants are currently required to reduce emissions of NOX, 

SO2, and PM. The EPA has also revised the National Ambient Air Quality Standards (NAAQS) 

for PM and ozone. These revisions may require electric utility sources to adopt control measures 

aimed at reducing concentrations of fine PM in the atmosphere. In addition, as discussed above, 

the EPA has recently expressed its intent to regulate Hg emissions from these sources. Adding to 

these environmental requirements and activities, Congress is introducing bills aimed at 

developing legislation requiring simultaneous reductions in emissions of multiple emissions. 

Improved sorbents and other methods for controlling Hg and multipollutant (e.g., Hg and NOX) 

emissions are also under development by DOE, EPA, EPRI, the electric industry, and equipment 

vendors. These development activities include large demonstration programs that are underway 

under the sponsorship of DOE/NETL and industrial participants. The demonstrations are 

focused on full-scale testing of powdered activated carbon injection and modifications to flue gas 

cleaning systems aimed at improving Hg capture. 

It is expected that, when the research and development activities being conducted by 

DOE, EPA, EPRI, and others are completed, there will be many more control options for Hg and 

multipollutants with attendant benefits in improved cost effectiveness. 

8.2 Cost Estimate Methodology 

The methodology used for the Hg control cost evaluation consists of the following six 

steps: 

• First step, a set of model plant and Hg control scenarios was defined; 

•	 Second step, cost estimates were made for selected scenarios using a cost model 

developed collaboratively by the DOE and the EPA; 

• Third step, the cost impacts of selected variables were examined; 

•	 Fourth step, the cost model results were used to develop indications of costs for those 

model plant scenarios for which data on PAC use are currently not available; 

• Fifth step, potential future improvements in the cost estimates were examined; and 

•	 Sixth step, in order to place Hg control costs in perspective, these costs were 

compared to current costs of applying NOX controls to coal-fired electric utility 

boilers. 

8-2

8.2.1 Mercury Control Technologies Evaluated 

The cost evaluation is based primarily on the application of potential PAC injection-based 

control technologies. These technologies were selected because sufficient pilot-scale data are 

available to make reasonable estimates of the Hg capture efficiency of the technologies. Mercury 

capture performance data are currently not available for other potential Hg control technologies 

(e.g., use of catalysts to oxidize Hg0 in wet scrubber systems) that conceivably could be applied 

to coal-fired electric utility boilers at this time. Table 8-1 lists the PAC injection-based Hg control 

technologies defined for this study. Pilot-scale applications of most of these technologies have 

been reported in published literature.

1,2,3,4,5,6 

PAC injection-based retrofit control technologies ESP-1, ESP-3, ESP-4, ESP-6, and 

ESP-7 are applicable to coal-fired electric utility boilers equipped with a cold-side ESP. 

In ESP-1, PAC is injected between the air preheater and the cold-side ESP (CS-ESP, i.e., 

an ESP located downstream of the boiler=s air preheater). This configuration is the simplest to 

install, requiring only PAC injection equipment upstream of the ESP. Activated carbon 

consumption is expected to be relatively high because the high temperature of the flue gas would 

inhibit adsorption of Hg onto PAC. 

In ESP-3, PAC is injected downstream of the CS-ESP and is collected using a polishing 

fabric filter (PFF). This technology permits recycling of the PAC sorbent to increase its 

utilization. Typically, this recycling is achieved by transferring a portion of used sorbent from 

the PM control device (e.g., PFF) to the sorbent injection location using a chain or a belt 

conveyor, mixing the used sorbent with fresh sorbent, and injecting the resulting sorbent mixture 

into the flue gas. Further, the technology provides a contact bed (i.e., filter cake on PFF) for 

increased adsorption of Hg. 

ESP-4 is similar to ESP-1, but adds spray cooling (SC) upstream of the PAC injection 

location. Cooling the flue gas aids adsorption and reduces PAC injection requirements. 

However, adding too much water to the flue gas could cause acid condensation, which would 

corrode ductwork and equipment. In the cost modeling conducted for this work, flue-gas 

temperatures are not allowed to reach the acid dewpoint (i.e., the temperature at which the acidic 

components in the flue gas would condense). 

ESP-6 is similar to ESP-3, but provides SC upstream of PAC injection. Cooling the flue 

gas aids adsorption and reduces PAC injection requirements. Also, use of PFF permits sorbent 

recycling, leading to improved sorbent utilization. 

ESP-7 is the same as ESP-6 except for the addition of a second sorbent, lime. In addition 

to Hg removal, this technology would remove acid gases from the flue gas. Pilot-scale results 

have indicated that this may result in significant lowering of PAC injection rates. 

8-3

Table 8-1. Mercury control technologies. 

Mercury Control Technologies b

Existing Post-combustion 

Control Devices 

Used for 

Coal-fired Boiler Unit a,b Identification 

Code Additional Control Equipment Installed 

ESP-1 PAC injection 

ESP-3 PAC injection + PFF 

ESP-4 SC + PAC injection 

ESP-6 SC + PAC injection + PFF 

CS-ESP 

ESP-7 SC + PAC injection + lime injection + PFF 

HS-ESP HESP-1 SC + PAC injection + PFF 

FF-1 PAC injection 

FF 

FF-2 SC + PAC injection 

SDA + FF SD/FF-1 PAC injection 

SDA + CS-ESP SD/ESP-1 PAC injection 

(a) Existing controls may include wet FGD scrubber system or post-combustion NOX controls such as selective 

catalytic reduction (SCR) and selective noncatalytic reduction (SNCR). 

(b) CS-ESP = cold-side electrostatic precipitator 

HS-ESP = hot-side electrostatic precipitator 

FF = fabric filter 

PAC = powdered activated carbon 

PFF = polishing fabric filter 

SC = spray cooling 

SDA = spray dryer adsorber system 

8-4

In HESP-1, SC, PAC injection, and a PFF are added downstream from a hot-side ESP (an 

ESP located upstream of the boiler=s air preheater). This configuration is identical to ESP-6, only 

the location of the ESP is different. 

Two PAC injection-based retrofit controls are applicable to coal-fired electric utility 

boilers equipped with a fabric filter. FF-1 is the fabric filter analogue of ESP-1. However, Hg 

collection should be better than that in ESP-1 because the FF provides added residence time and 

a contact bed (filter cake on the bags) for increased adsorption of Hg. FF-2 is the fabric filter 

analogue of ESP-4; spray cooling and PAC injection are installed upstream of an existing fabric 

filter. As with ESP-4, cooling reduces PAC requirements, which reduces total annual PAC costs 

for FF-2 compared to FF-1. 

Finally, use of a PAC injection in combination with an existing spray dryer adsorber 

system for SO2 control was evaluated. In SD/FF-1, PAC is injected into the flue gas of a boiler 

that uses a SDA + FF combination. In this configuration, only PAC injection equipment is added 

to the existing air pollution control system, with the SDA providing flue gas cooling. SD/ESP-1 

is similar to SD/FF-1 except that an ESP is used in place of an FF for particulate collection. The 

advantages are similar to those of SD/FF-1; however, larger amounts of PAC may be needed to 

achieve performance levels comparable to those achieved by SD/FF-1. 

8.2.2 Model Plant Descriptions 

Costs for installing and operating the Hg control technologies described in Table 8-1 are 

estimated by combining these control configurations with appropriate model plant descriptions 

representing plants firing different types of coal on varying boiler sizes. Eighteen different 

model plant descriptions or Ascenarios@ were defined for the cost evaluation. Table 8-2 lists these 

scenarios. 

Approximately 75 percent of the existing coal-fired electric utility boilers in the United 

States are equipped with an ESP for the control of PM.7 The remaining boilers employ fabric 

filters, particulate scrubbers, or other equipment for control of PM. Additionally, units firing 

medium-to-high sulfur coals may use FGD technologies to meet their SO2 control requirements. 

Generally, larger units firing high-sulfur coals employ wet FGD, and smaller units firing 

medium-sulfur coals use SDAs. While developing the model plant scenarios, these PM and SO2 

control possibilities were taken into account. It may be worth noting that, since the majority of 

boilers use an ESP for PM control, most Hg control technology applications would likely take 

place on such boilers and would reflect pertinent performance and costs. 

The two coal-fired boiler sizes (expressed as gross electricity output), used for the model 

plant scenarios listed in Table 8-2, were selected to approximately span the range of typical 

electric utility boiler sizes, and to be consistent with the model plant sizes used in previous cost 

studies.1 It was also envisioned that the use of post-combustion NOX controls (i.e., SCR or 

SNCR) may enhance oxidation of Hg in flue gas and result in the Acobenefit@ of 

8-5

1

23456789

101112131415161718

Table 8-2. Matrix of model plant scenarios. 

M Coal Burned odel 

Plant 

Scenario 

Gross 

Electricity 

Output Type Sulfur content 

Existing Post-combustion 

PM and SO2 

Control Devices 

Applica

Mercury C

Retro

Configura

(see Tabl

975 MWe Bituminous 3 % CS-ESP + wet FGD ESP-1, E975 MWe Bituminous 3 % FF + wet FGD FF-1 

975 MWe Bituminous 3 % HS-ESP + wet FGD HESP975 MWe Bituminous 0.6 % CS-ESP ESP-4, E

975 MWe Bituminous 0.6 % FF FF-2 

975 MWe Bituminous 0.6 % HS-ESP HESP

975 MWe Subbituminous 0.5 % CS-ESP ESP-4, E975 MWe Subbituminous 0.5 % FF FF-2 975 MWe Subbituminous 0.5 % HS-ESP HESP

100 MWe Bituminous 3 % SDA + CS-ESP SD/ES

100 MWe Bituminous 3 % SDA + FF SD/FF

100 MWe Bituminous 3 % HS-ESP + wet FGD HESP

100 MWe Bituminous 0.6 % CS-ESP ESP-4, E

100 MWe Bituminous 0.6 % FF FF-2 

100 MWe Bituminous 0.6 % HS-ESP HESP100 MWe Subbituminous 0.5 % CS-ESP ESP-4, E

100 MWe Subbituminous 0.5 % FF FF-2 

100 MWe Subbituminous 0.5 % HS-ESP HESP

8-6

increased Hg removal in wet FGD systems. This is especially relevant since many SCR 

applications are expected to take place in the next few years and, in response to SO2 reduction 

requirements, more wet FGD systems may be installed. However, at the time of this study, some 

data on this co-benefit were available for SCR applications only. Since SCR is a capitalintensive technology, generally its use is more cost-effective for larger boilers. Accordingly, in 

this work, the Hg co-benefit resulting from SCR use was evaluated for model plant scenarios 1, 

2, and 3, utilizing large (975 MWe) boilers and wet FGD. 

8.2.3 Computer Cost Model 

The DOE/NETL developed a cost model for estimating the costs of Hg control options 

for coal-fired electric utility boilers. This cost model, called the NETL Mercury Control Cost 

Model, can provide capital and operating and maintenance (O&M) costs estimated in year 2000 

constant dollars for the application of selected Hg control configurations to coal-fired electric 

utility boilers. The model has been used for other studies conducted to characterize the costs 

associated with using PAC injection on coal-fired electric utility boilers.8 For this evaluation, the 

EPA collaborated with the DOE to modify this cost model to incorporate the PAC injection rate 

algorithms described in the following section. An overview of the modified version of the NETL 

Mercury Control Cost Model used for this cost evaluation is presented in Appendix D to this 

report. This model is hereafter referred to simply as the cost model. 

8.2.4 PAC Injection Rate Algorithms 

The current understanding is that Hgp is well collected in PM or SO2 control systems, Hg0 

is not so well collected, and Hg2+ is collected to a greater or lesser degree depending on 

characteristics of the control device and conditions within it. Therefore, for a specified Hg 

removal requirement, the rate of PAC injection needed will depend, in part, on the ability of 

existing controls to remove the three forms of Hg. The major factor affecting the cost of PAC 

injection-based technologies is the rate of PAC injection needed for the required Hg removal 

efficiency. In general, this rate depends on the time of contact between carbon particle and flue 

gas, the properties of the carbon (particle size, micropore surface area, pore size distribution, and 

Hg adsorption capacity), the temperature of the flue gas, and the type of coal-fired in the boiler. 

For this work, PAC injection rates at specific flue gas temperatures and Hg removal efficiencies 

achieved in pilot-scale tests were fitted to the form of Equation (8-1) with curve-fit parameters a, 

b, and c (see Attachment 2 in Appendix D). For each technology for which pilot-scale test data 

are available, separate correlations of Hg removal efficiency and PAC injection rate were 

determined for bituminous and subbituminous coals. These coals are predominantly used at 

electric utility boilers and, therefore, were chosen for this work. 

a Mercury Removal Efficiency (%) = 100 − (Eq. 8-1)

[PAC Injection Rate (lb /106 acf )+ b] c 

8-7

Equation 8-1 can be used to calculate the PAC injection rate (lb/106 acf) needed to 

achieve a specified Hg removal efficiency (percent) for the control technology of interest. Note 

that Hg removal efficiency (percent) is based on total Hg (the sum of Hg0, Hg

2+

, and Hgp) 

removed from the flue gas and is defined as 

(Eq.8-2) 

Mercury Removal Efficiency (%) = 100 × (Emissionin − Emissionout ) 

Emissionin 

where:	 Emissionin = total flue gas Hg concentration at the inlet to the first air pollution 

control device; and 

Emissionout = total flue gas Hg concentration at the outlet of the last air pollution 

control device. 

Preliminary analysis of the Pat III EPA ICR data 9 reflected that, at boilers firing 

bituminous coals and using a CS-ESP for PM capture, higher levels (more than 50 percent) of Hg 

were being removed with fly ash than were found in earlier pilot-scale tests (see Attachment 2 in 

Appendix D). Accordingly, for each of technologies ESP-1, ESP-3, ESP-4, and ESP-6, two 

separate sets of correlations, relating PAC injection rate (lb/106 acf) to Hg removal efficiency 

(percent), were created for use with bituminous-coal-fired boilers. The first of these sets, 

hereafter referred to as the pilot-scale PAC injection rate, was derived using presently available 

pilot-scale test data. The other set, hereafter referred to as the ICR/pilot-scale PAC injection rate, 

was derived using preliminary ICR results for fly ash capture of Hg (i.e., no PAC injection) and 

pilot-scale results for PAC injection. 

Note that the above data-fitting procedure resulted in correlations of PAC injection rate 

(lb/106 acf) versus Hg removal efficiency (percent), as a function of flue gas temperature, for all 

of the technologies except: (1) FF-1, FF-2, and SD/FF-1, applied on boilers firing bituminous 

coals, for which no data are available; (2) HESP-1, applied on boilers firing either bituminous or 

subbituminous coals, for which no data are available; and (3) ESP-7, applied on boilers firing 

either bituminous or subbituminous coals. The only available data on ESP-7 are from a pilotscale application on a boiler firing a bituminous coal.10 Since these data reflect that more than 90 

percent of the Hg can be removed by injecting relatively small amounts of PAC with lime, in this 

work, application of ESP-7 was evaluated at 90 percent Hg removal efficiency in a sensitivity 

analysis. 

The algorithms describing sorbent injection rates for various technologies can be found in 

Attachment 2 in Appendix D. The PAC injection rate algorithms could not be determined for the 

retrofit configurations defined for model plant scenarios 2, 3, 5, 6, 9, 11, 12, 14, 15, and 18. As 

such, costs for these model plant configurations cannot be estimated using the cost model. 

8-8

8.2.5 Cost Estimate Assumptions 

To estimate the costs for the model plant configurations using the cost model, the 

following specifications were used. 

(1) Mercury concentration in the flue gas for each model plant scenario is 10 μg/Nm3

. This 

concentration has been used in previous cost studies1,8 and is in the range of mean 

concentrations (1.7-50.1 μg/dscm) determined from ICR data for pulverized-coal-fired 

electric utility boilers equipped with different air pollution controls.9 Note also that the 

corresponding median and mean concentrations are 9.1 and 11.4 μg/dscm, respectively. 

(2) For each of retrofit configurations ESP-1, ESP-3, ESP-4, and ESP-6, two separate sets of 

correlations, relating PAC injection rate (lb/106 acf) to Hg removal efficiency (percent), 

were created for use with bituminous-coal-fired boilers. The first of these sets, hereafter 

referred to as the pilot-scale PAC injection rate, was derived using presently available 

pilot-scale test data. The other set, hereafter referred to as the ICR/pilot-scale PAC 

injection rate, was derived using preliminary EPA ICR results for fly ash capture of Hg 

(i.e., no PAC injection) and pilot-scale results for PAC injection. Accordingly, two sets 

of cost estimates for applying retrofit configurations ESP-1, ESP-3, ESP-4, and ESP-6 

were made: one estimate used the pilot-scale PAC injection rate, and the other used the 

ICR/pilot-scale PAC injection rate. 

(3) PAC injection rate correlations generally reflect that PAC injection requirements increase 

nonlinearly with increases in Hg removal efficiency. To characterize the impact of this 

behavior, wherever possible, model plant costs were estimated for Hg removal 

efficiencies of 60, 70, 80, and 90 percent. 

(4) In general, for any given Hg removal requirement, the PAC injection rate decreases if the 

temperature of the flue gas is lowered. For this reason, the flue gas is cooled by water 

injection in some of the retrofit configurations (see Table 8-1). However, injecting water 

into an acidic flue gas can lead potentially to corrosion of downstream equipment. To 

avoid this corrosion, an approach to acid dew point (ADP) of 18 o

F was used for the 

retrofit configurations with spray cooling (i.e., ESP-4, ESP-6, ESP-7, and FF-2).11 For 

these retrofit configurations, the extent of SC provided was determined based on the 

temperature of the flue gas before cooling and the temperature nearest to the above 

approach to ADP for which a PAC injection rate correlation was available. Note that, in 

the high-sulfur coal applications with relatively high ADPs, this constraint resulted in no 

SC if the SO2 control technology was wet FGD. However, in applications using SDAs 

for SO2 control, SC is inherent and acid gases are removed prior to PAC injection; 

therefore, this constraint was not applied. 

(5) No data are currently available for recycling of sorbent in technology applications 

utilizing PAC injection and PFF. Accordingly, no sorbent recycle was used in retrofit 

configurations ESP-3 and ESP-6. 

8-9

(6) Mercury speciation in the flue gas from bituminous-coal-fired boilers is assumed to be 70 

percent of the total Hg being oxidized, with 30 percent being Hg0

. The corresponding 

assumption for boilers firing subbituminous coals is 25 percent oxidized with 75 percent 

Hg0. These Hg speciation percentages were determined from a preliminary analysis of 

ICR data (see Attachment 2 in Appendix D). 

(7) Wet FGD systems are assumed to remove 100 percent of Hg2+ 

and no Hg0. This is based 

on the fact that mercuric chloride (the assumed major oxidized species) is soluble in 

water, while Hg0 is insoluble. It is anticipated that ongoing research on wet scrubbers 

will result in improved performance through the use of reagents or catalysts to convert Hg 

to chemical compounds that are soluble in aqueous-based scrubbers. 

(8)	 Use of SCR is assumed to increase Hg2+ content in flue gas by 35 percent for both 

bituminous- and subbituminous-coal-fired boilers. This increase in mercury oxidation 

was determined from a preliminary analysis of ICR data as follows. As explained above, 

oxidized mercury content in flue gas from bituminous-coal-fired boilers is assumed to be 

70 percent. Also, ICR data revealed that SCR application with SDA at one plant firing 

bituminous coal resulted in greater than 95 percent mercury removal. It is hypothesized 

that virtually all of the mercury removed at this plant was oxidized mercury. Based on 

these considerations, it is assumed that SCR increases oxidized mercury content by 

35 percent (also see Attachment 2 in Appendix D). Currently, research and development 

efforts are underway to investigate the effects of SCR on Hg oxidation. A more mature 

set of findings regarding SCR impacts are expected from these efforts. 

(9) For each of the model plant scenarios, a plant capacity factor of 65 percent was used. 

(10) The cost of PAC is assumed to be $1.00 per kilogram.12 

Other specifications are described in Attachments 1, 2, and 3 in Appendix D. 

8.3 Estimated Costs of Reducing Mercury Emissions 

This section describes the estimates of total annual cost determined using the cost model 

for application of Hg controls to those model plant scenarios for which PAC injection rate 

algorithms could be determined (i.e., model plant scenarios 1, 4, 7, 8, 10, 13, 16, and 17). It is 

important to note that cost estimates presented in this section are based on currently available 

data and, as explained later, may be improved with R&D efforts and as long-term operating data 

from full-scale demonstrations become available. 

In general, capital costs of PAC injection-based Hg control technologies comprise a 

relatively minor fraction of the total annual costs of these technologies; the major fraction is 

associated with the costs related to the use of PAC.12 As an example, for application of SC+PAC 

injection (ESP-4) to achieve 80 percent Hg reduction on a 975-MWe boiler firing bituminous 

8-10

coal and using an ESP, the capital cost contributes about 23 percent of the total annual cost. 

Therefore, for such technologies, the cost assessment should be based on total annual costs. 

Accordingly, total annual costs of controlling Hg emissions from coal-fired electric utility boilers 

are examined in this section. These costs include annualized capital charge, annual fixed 

operation and maintenance (O&M) costs, and annual variable O&M costs. Note that Reference 

12 provides an examination of the contribution of various cost elements, including cost of PAC, 

to total annual cost of Hg controls. 

8.3.1 Bituminous-coal-fired Boiler Using CS-ESP 

Several of the Hg control technologies listed in Table 8-1 are potential options for 

reducing Hg emissions from a electric utility boiler that fires bituminous coal and already is 

using an ESP for PM control. For boilers firing low-sulfur bituminous coals, these options 

include configurations ESP-4 (SC + PAC injection) and ESP-6 (SC + PAC injection + PFF). For 

large boilers firing high-sulfur bituminous coals, the options include configurations ESP-1 (PAC 

injection + wet FGD) and ESP-3 (PAC injection + PFF + wet FGD). For smaller boilers 

(typically less than 300 MW), these options include configuration SD/ESP-1 (SDA + PAC 

injection + ESP). For each of these cases, cost estimates were determined using the cost model. 

Table 8-3 presents the estimated total annual Hg control costs for a bituminous-coal-fired 

boiler with existing CS-ESP. The table presents two sets of cost estimates. The first set of 

estimates was made based on levels of Hg capture on fly ash using PAC injection rates derived 

from the available pilot-scale test data. A subsequent review of the Part III EPA ICR data 

(discussed in Section 6.2), however, suggests that levels of Hg capture higher than those 

measured in the pilot-scale tests may be occurring. Consequently, the cost estimates based solely 

on pilot test data for Hg control technologies applied to bituminous-coal-fired boilers using ESP 

may be overstating the costs. Therefore, a second set of estimates is presented based on the 

preliminary ICR results for fly ash capture of Hg (i.e., no PAC injection) in combination with the 

pilot-scale results for PAC injection. 

For ESP-4 applied to low-sulfur (0.6 percent) bituminous coal and using pilot-scale PAC 

injection rates, the estimated total annual cost ranges from 2.81 mills/kWh for a 100-MWe boiler 

removing 90 percent of the total Hg to 0.53 mill/kWh for a 975-MWe boiler removing 60 percent 

of the total Hg. The corresponding costs with ICR/pilot-scale PAC injection rates are 1.65 

mills/kWh for the 100-MWe boiler and 0.24 mill/kWh for the 975-MWe boiler. 

In general, these results reflect that, for a given boiler, the total annual cost increases nonlinearly with increases in the Hg reduction requirement in concert with the behavior of the PAC 

injection rate algorithms (see Attachment 2 in Appendix D). A comparison of results obtained 

with pilot-scale and ICR/pilot-scale PAC injection rates also indicates that research and 

development efforts aimed at ensuring broad availability of relatively high levels of fly ash 

capture of Hg have the potential of providing significant reductions in Hg control costs. 

8-11

Table 8-3. Estimated total annual mercury control costs for bituminous-coal-fired 

boiler with existing CS-ESP. 

Total Annual Mercury Control 

Costs 

( ill/kWh t d) 

Model 

Plant 

Scenario 

Model Plant 

Size 

Coal 

Sulfur 

Content 

Mercury 

Control 

Retrofit 

Configuration 

(see Table 8-1) 

Mercury 

Capture 

Efficiency Pilot-scale data a ICR/pilot data b 

90 % 2.594 0.427 

80 % 0.727 0.006 d 

70 % 0.006 c 0.006 ESP-1 d

60 % 0.006 c 0.006 d 

90 % 2.086 1.416 

80 % 1.501 0.006 d 

70 % 1.273 0.006 d 

1 975 MWe high sulfur 

(3 %) 

ESP-3 

60 % 0.006 c 0.006 d 

90 % 1.966 0.883 

80 % 1.017 0.464 

70 % 0.696 0.319 ESP-4 

60 % 0.533 0.240 

90 % 2.381 1.735 

80 % 1.817 1.485 

70 % 1.625 1.397 

4 975 MWe low sulfur 

(0.6 %) 

ESP-6 

60 % 1.528 1.353 

90 % 1.925 1.094 

80 % 1.197 0.759 

70 % 0.945 0.637 10 100 MWe high sulfur 

(3 %) SD/ESP-1 

60 % 0.815 0.008 

90 % 2.810 1.647 

80 % 1.793 1.184 

70 % 1.442 1.018 ESP-4 

60 % 1.262 0.922 

90 % 4.966 3.080 

80 % 3.783 2.798 

70 % 3.170 2.695 

13 100 MWe low sulfur 

(0.6 %) 

ESP-6 

60 % 2.957 2.637 

(a)	 Mercury capture efficiency of Hg controls based on fly ash using PAC injection rates derived from the available pilot-scale 

test data. 

(b)	 Mercury capture efficiency of mercury controls based on preliminary EPA ICR results for fly ash capture of Hg (i.e., no PAC 

injection) in combination with the pilot-scale results for PAC injection. 

(c)	 The cost of monitoring Hg emissions is 0.006 mill/kWh. Based on 70% of total Hg being oxidized, 0% Hg removal with fly 

ash, and all Hg2+ being removed in wet FGD scrubber system, a minimum of 70% of total Hg is captured by existing control 

system(s). Therefore, add-on of PAC injection is not needed to meet target Hg control efficiency of 70% or lower. 

(d) The cost of monitoring Hg emissions is 0.006 mill/kWh. Based on 70% of total Hg being oxidized, 58% mercury removal 2+ with fly ash, and all Hg being removed in wet FGD scrubber system, approximately 87% of total Hg is captured by 

existing control system(s). Therefore, Add-on of PAC injection is not needed to meet target mercury control efficiency. 

8-12

Another option for boilers firing low-sulfur bituminous coals is to utilize ESP-6 for Hg 

control. For this option, using the pilot-scale PAC injection rates, the estimated total annual cost 

ranges from 4.966 mills/kWh for the 100-MWe boiler removing 90 percent of total Hg to 1.528 

mills/kWh for the 975-MWe boiler removing 60 percent of total Hg. The corresponding costs 

with ICR/pilot-scale PAC injection rates are 3.08 mills/kWh for the 100-MWe boiler and 1.353 

mills/kWh for the 975-MWe boiler. In general, these results reflect that the ESP-6 control option 

is more expensive than ESP-4 because of the capital cost associated with the PFF. To make this 

control option more cost-effective, R&D efforts are needed to develop less expensive PFF 

designs and high capacity sorbents, which may be recycled sufficiently to improve sorbent 

utilization. 

As seen in Table 8-3, for ESP-1 application on a large (975-MW) high-sulfur bituminouscoal-fired boiler that uses wet FGD for SO2 control, using pilot-scale PAC injection rates, the 

estimated total annual cost ranges from 2.594 mills/kWh for removing 90 percent of the total Hg 

to 0.006 mill/kWh (cost of monitoring of Hg emissions) for removing 70 percent of the total Hg. 

The costs with ICR/pilot-scale PAC injection rates are 0.427 mill/kWh for 90 percent removal 

and 0.006 mill/kWh for about 87 percent removal. Note that, with the assumptions of this work, 

a minimum of 70 percent of total Hg is removed in wet FGD systems if no Hg is removed with 

fly ash (pilot-scale test results) and a minimum of about 87 percent is removed if about 

58 percent of Hg is removed with fly ash (preliminary ICR data analyses results). These results 

reflect that, if significant amounts of Hg can be captured along with fly ash in ESPs and in wet 

FGD systems, costs of achieving high levels of Hg removal would be quite low. Considering 

these results, R&D efforts are needed to ensure that these Hg capture mechanisms are broadly 

available. 

Another option for large boilers firing high-sulfur bituminous coals and using wet FGDs 

is to utilize ESP-3 for Hg control. Using this option on a 975-MWe boiler, with pilot-scale PAC 

injection rates, the estimated total annual cost ranges from 2.086 mills/kWh for removing 

90 percent of the total Hg to 1.273 mills/kWh for removing 70 percent of the total Hg. The costs 

with ICR/pilot-scale PAC injection rates are 1.416 mills/kWh for removing 90 percent of the 

total Hg and 0.006 mill/kWh for about 87 percent removal. Interestingly, this control option is 

more cost-effective than the one using PAC injection (ESP-1) at 90 percent Hg removal. 

However, at or below 80 percent removal, this option is more expensive because the PAC 

injection rate decreases more rapidly than the capital cost of PFF. It may be possible to make this 

option competitive across a wide range of Hg removal efficiencies by conducting R&D efforts 

directed towards reducing both PFF capital cost and operating cost through sorbent recycling. 

Finally, as seen in Table 8-3, for ESP-1 application on a relatively small boiler (100-MW) 

that fires a high-sulfur bituminous coal and uses an SDA for SO2 control, with pilot-scale PAC 

injection rates, the estimated total annual cost ranges from 1.925 mills/kWh for removing 

90 percent of the total Hg to 0.815 mill/kWh for removing 60 percent of the total Hg. The 

corresponding costs with ICR/pilot-scale PAC injection rates are 1.094 and 0.008 mills/kWh, 

respectively. A significant increase in costs is observed on increasing the Hg control requirement 

from 80 to 90 percent. Again, considering the differences in total annual costs obtained using 

8-13

ICR/pilot-scale and pilot-scale PAC injection rates, R&D efforts are needed, aimed at providing 

broad availability of relatively high levels of fly ash capture of Hg. 

8.3.2 Subbituminous-coal-fired Boiler Using CS-ESP 

Shown in Table 8-4 are two potential options to reduce total Hg emissions from boilers 

that fire subbituminous coals and use ESPs for PM control. These options include SC + PAC 

injection (ESP-4) and SC + PAC injection + PFF (ESP-6). 

For ESP-4 application on boilers firing subbituminous coals, estimated total annual costs 

range from 3.232 mills/kWh for a 100-MWe boiler removing 90 percent of the total Hg to 0.473 

mill/kWh for the 975-MWe boiler removing 60 percent of the total Hg. Further, total annual cost 

appears to drop sharply as the Hg removal requirement is reduced from 90 to 80 percent due to 

the nonlinear nature of the PAC injection rate algorithms. 

For ESP-6 application on boilers firing subbituminous coals, the estimated total annual 

cost ranges from 2.754 mills/kWh for a 100-MWe boiler removing 90 percent of the total Hg to 

1.405 mills/kWh for the 975-MWe boiler removing 60 percent of the total Hg. Interestingly, this 

control option is more cost-effective than the one using SC + PAC injection (ESP-4) at 90 

percent Hg removal. However, at or below 80 percent removal, this option is more expensive 

because the PAC injection rate decreases more rapidly than capital costs of PFF. These results 

again indicate possibilities of making this option competitive by reducing both the PFF capital 

cost and operating cost through sorbent recycling. 

A comparison of the results shown in Tables 8-4 and 8-3 reveals that applications of 

SC+PAC injection (ESP-4) to achieve high Hg reductions could cost more for boilers firing 

subbituminous coals compared to boilers firing bituminous coals. Further, in general, relatively 

few FGDs would be used on subbituminous-coal-fired boilers. Considering these factors, 

research and development efforts are needed to ensure that cost-effective control of Hg is 

achieved at these boilers. 

8.3.3 Subbituminous-coal-fired Boilers Using FF 

As seen in Table 8-5, for boilers firing subbituminous coals and utilizing SC + PAC 

injection (FF-2) for Hg control, the estimated total annual cost ranges from 1.120 mills/kWh for 

a 100-MWe boiler removing 90 percent of the total Hg to 0.219 mill/kWh for the 975-MWe 

boiler removing 60 percent of the total Hg. These cost estimates reflect that the combination of 

SC + PAC injection + FF is very efficient in removing Hg from the boiler flue gas. 

8-14

Table 8-4. Estimated total annual mercury control costs for 

subbituminous-coal-fired boiler with existing CS-ESP. 

Model 

Plant 

I.D. 

Model 

Plant 

Size 

Coal 

Sulfur 

Content 

Mercury 

Control 

Retrofit 

Configuration 

(see Table 8-1) 

Mercury 

Capture 

Efficiency 

Total Annual Mercury 

Control Costs 

(mills/kWh generated) 

90 % 2.384 

80 % 1.150 

70 % 0.731 

ESP-4 

60 % 0.473 

90 % 1.444 

80 % 1.419 

70 % 1.410 

7 975 MWe 0.5 % 

ESP-6 

60 % 1.405 

90 % 3.232 

80 % 1.915 

70 % 1.460 

ESP-4 

60 % 1.174 

90 % 2.754 

80 % 2.723 

70 % 2.712 

16 100 MWe 0.5 % 

ESP-6 

60 % 2.703 

8-15

Table 8-5. Estimated total annual mercury control costs for 

subbituminous-coal-fired boiler with existing FF. 

Model 

Plant 

I.D. 

Model 

Plant 

Size 

Coal 

Sulfur 

Content 

Mercury 

Control 

Retrofit 

Configuration 

(see Table 8-1) 

Assumed 

Mercury 

Capture 

Efficiency 

Total Annual Mercury 

Control Costs 

(mills/kWh generated) 

90 % 0.423 

80 % 0.299 

70 % 0.226 

8 975 MWe 0.5 % FF-2 

60 % 0.219 

90 % 1.120 

80 % 0.977 

70 % 0.888 

17 100 MWe 0.5 % FF-2 

60 % 0.879 

8-16

8.3.4 Coal-fired Boilers Using SCR for NOX Control 

As mentioned before, this work assumes that flue gas resulting from bituminous coal 

combustion has an oxidized-Hg content of 70 percent, and SCR augments this by 35 percent. 

This leads to a total of 94.5 percent of total Hg being Hg2+ after SCR. Using the results of ICR 

data analysis, about 58 percent of the total Hg is captured along with fly ash in an ESP, and all of 

the remaining Hg2+ is captured in a wet FGD system. Thus, a total Hg capture of 97.6 percent is 

achieved. The cost of this removal is 0.006 mill/kWh, which is simply the cost of monitoring the 

Hg emissions. On the other hand, using pilot-scale test results, no Hg is captured along with fly 

ash in ESPs and all of the Hg

2+ is captured in wet FGDs. Therefore, a total Hg capture of 94.5 

percent is achieved, and the cost of this removal is again 0.006 mill/kWh; i.e., the cost of 

monitoring the Hg emissions. 

It may be mentioned that, since the majority of boilers use cold-side ESPs, the most 

frequently occurring costs would be those related to technology applications on such boilers. 

Based on this work, these costs would range between 0.727 and 1.915 mills/kWh. 

8.4 Impacts of Selected Variables on Mercury Control Costs 

The impacts of certain selected variables on Hg control costs were examined by 

performing sensitivity analyses using the cost model with the pilot-scale PAC injection rates. 

These analyses are summarized below with a more detailed discussion of the analyses presented 

in Attachment 3 in Appendix D. A model plant size of 500 MWe was used in these analyses. 

This size was selected because it is approximately the midpoint of the range of 100- and 975-

MWe boiler sizes used for the model plant cost estimates. 

Note that, in general, the cost of sorbent constitutes an important component of the total 

annual cost. This cost is likely to fall in the future because of the many active research programs 

aimed at producing low-cost sorbents. While a sensitivity analysis with respect to this cost was 

not conducted in this work, Reference 12 provides an examination of the contribution of various 

cost elements, including the cost of PAC, to the total annual cost of Hg controls. 

8.4.1 Acid Dew Point Approach Setting 

Adsorption of Hg on PAC is dependent on the temperature of the flue gas at the point 

where the PAC is injected. The acid dew point (ADP) is the temperature of the flue gas at which 

acidic components will condense. It is important to keep the flue gas temperature above the ADP 

because below the ADP, acid mist will form in the flue gas and corrode the downstream ducting 

and control equipment. In determining the estimates of Hg control costs for the model plant 

scenarios presented in Section 8.2, the approach to ADP was kept at 10 o

C (18 oF), resulting in a 

flue gas temperature of ADP + 10 oC. Some investigators have expressed concern that, in some 

cases, this approach may be too low to prevent corrosion of downstream equipment, especially 

for those Hg control retrofit configurations where spray cooling is used. To test the sensitivity of 

8-17

the cost estimate results to the ADP approach setting, annual Hg control costs were computed 

using the cost model for a set of Hg control applications with SC using a boiler size of 500 MWe 

and burning low-sulfur coals for the nominal flue gas temperature of ADP + 10 oC (ADP + 18 oF) 

and a higher temperature of ADP + 22.2 o

C (ADP + 40 oF). 

As seen in Table 8-6, for a 500-MWe boiler firing low-sulfur bituminous coal and using 

ESP-4, the total annual cost increase ranges from 126.3 to 38.2 percent. Again for the same 

boiler using ESP-6, the cost increase ranges from 18.8 to 2 percent. Interestingly, the results for 

subbituminous coal presented in Table 8-7 reflect that the total annual cost decreases with an 

increase in approach to ADP. This is due to a significant decrease in water injection 

requirements, while PAC injection does not increase much to provide the required Hg removal. 

These results indicate that, for a bituminous-coal-fired boiler using a CS-ESP, changes in the 

ADP approach can influence estimated costs significantly. However, the same is not true for 

subbituminous-coal-fired boilers. 

8.4.2 PAC Recycle 

As discussed in Section 8.2, estimates of Hg control costs for model plant scenarios using 

PFF obtained using no sorbent recycle, are, in general, higher than those of other options. A 

sensitivity analysis was conducted to examine the impact of increasing PAC utilization in ESP-3 

and ESP-6 retrofit configurations on associated costs. Specifically, cost estimates were obtained 

with 20 percent of the PAC being recycled in the following applications evaluated with a 500-

MWe boiler: model plant 1 retrofitted with ESP-3; model plant 4 retrofitted with ESP-6; and 

model plant 7 retrofitted with ESP-6. 

The results shown in Table 8-8 reflect that a recycle rate of 20 percent does not have 

much of an impact on total annual costs estimated by the cost model. This is because the capital 

cost of the new PFF is the dominant cost component. To utilize the benefits of increased PAC 

utilization, higher recycle rates would be needed, but such rates would require that sorbents used 

have relatively high adsorption capacities. 

8.4.3 Increased Flue Gas Residence Time 

Adsorption of Hg on PAC is dependent on the time of contact between the flue gas and 

the PAC. In general, about half of the existing electric utility boilers have a flue gas residence 

time in the duct of 1 second, and about 30 percent have a time of 2 seconds.13 Although it is not 

entirely clear at this time as to how much time is needed for particular levels of Hg capture, in 

this sensitivity analysis the impact of adding ductwork to increase the flue gas residence time by 

1 second on the cost of Hg control was evaluated as a conservative measure. This analysis was 

conducted using the model plant 4 with a 500-MWe boiler retrofitted with ESP-4. 

The results shown in Figure 8-1 reflect that the impact of adding ductwork on the total 

annual cost is quite small. The increase in cost ranges from 16.4 percent at the lowest cost 

8-18

Table 8-6. Impact of acid dew point setting on annual mercury control costs for a 

utility boiler burning bituminous coal. 

Coal Burned in Boiler Unit Total Annual 

(mills/

Type Sulfur Content 

Existing 

Post-combustion 

PM and SO2 

Control Devices 

Mercury Control 

Retrofit 

Configuration 

(see Table 8-1) 

Mercury 

Capture 

Efficiency Acid dew poin

+ 18 oF 

90 % 2.095 80 % 1.132 70 % 0.804 

Bituminous low sulfur (0.6 %) CS-ESP ESP-4 

60 % 0.637 

90 % 2.650 80 % 2.075 70 % 1.879 

Bituminous low sulfur (0.6 %) CS-ESP ESP-6 

60 % 1.779 

8-19

Table 8-7. Impact of acid dew point setting on annual mercury control costs for a 5

utility boiler burning subbituminous coal. 

8-20


Coal Burned in Boiler Unit Total Annual 

(mills/

Type Sulfur Content 

Existing 

Post-combustion 

PM and SO2 

Control Devices 

Mercury Control 

Retrofit 

Configuration 

(see Table 8-1) 

Mercury 

Capture 

Efficiency Acid dew poin

+18 oF 

90 % 2.513 80 % 1.261 70 % 0.835 

Subbituminous low sulfur (0.5 %) CS-ESP ESP-4 

60 % 0.571 

90 % 1.693 80 % 1.667 70 % 1.658 

Subbituminous low sulfur (0.5 %) CS-ESP ESP-6 

60 % 1.652 

90 % 0.520 80 % 0.392 70 % 0.315 

Subbituminous low sulfur (0.5 %) FF FF-2 

60 % 0.308 
Table 8-8. Effect of PAC recycle on annual mercury control costs for a 500-MWe el

burning bituminous coal. 

8-21


Coal Burned in Boiler Unit Total Annual 

(mills/

Type Sulfur Content 

Existing 

Post-combustion 

PM and SO2 

Control Devices 

Mercury Control 

Retrofit 

Configuration 

(see Table 8-1) 

Assumed 

Mercury 

Capture 

Efficiency No Recycle 

90 % 2.324 80 % 1.727 70 % 0.006 a 

high sulfur 

(3 %) CS-ESP + wet FGD ESP-3 

60 % 0.006 a 

90 % 2.650 80 % 2.075 70 % 1.879 

Bituminous 

low sulfur 

(0.6 %) CS-ESP ESP-6 

60 % 1.779 

90 % 1.693 80 % 1.667 70 % 1.658 

Subbituminous low sulfur (0.5 %) CS-ESP ESP-6 

60 % 1.652 

(a) The cost of monitoring of Hg emissions is 0.006 mill/kWh. Add-on of PAC injection is not needed to meet tar

Based on 70% of total Hg being oxidized, 0% Hg removal with fly ash, and all Hg2+ being removed in wet FGD sc

of 70% of total Hg is captured by existing control system. 
MODEL PLANT 4, ESP-4, 500 MW, Bituminous Coal, 0.6% Sulfur, 

With and Without Added Ductwork 

0.25 

0.50 

0.75 

1.00 

1.25 

1.50 

1.75 

2.00 

2.25 

2.50 

40 50 60 70 80 90 100 

Total Hg Removed, % 

Total Annual Cost, mills/kWh 

W/O Ductwork 

W/ Ductwork 

Figure 8-1. Change in total annual cost resulting from addition of ductwork to 

provide additional residence time. 

8-22

0.535 mill/kWh to 4.3 percent at the highest cost of 2.095 mills/kWh. Based on this analysis, it 

appears that addition of ductwork is not a sensitive cost parameter. 

8.4.4 Use of Composite PAC and Lime Sorbent 

As discussed above, high levels of Hg have been removed in pilot-scale tests using lime 

and PAC with PFF.10 To assess the potential economic impact, this analysis was based on 

removing 90 percent of Hg from model plant 4 with a 500-MWe boiler retrofitted with ESP-7 

and using a composite PAC-lime sorbent, with a PAC-to-lime mass ratio of 2:19. The results of 

this analysis shown in Figure 8-2 reflect that use of the composite sorbent lowers the total annual 

cost by 34.7 to 38.1 percent. 

8.5 Cost Indications for Other Model Plant Scenarios 

As discussed in Section 8.2.4, since data are not available on Hg control technology 

applications involving HS-ESPs or boilers firing bituminous coals and using FFs, PAC injection 

rate algorithms could not be developed for these applications. Consequently, cost estimates for 

these applications (i.e., model plant scenarios 2, 3, 5, 6, 9, 11, 12, 14, 15, and 18) could not be 

obtained using the cost model. In this section, estimates of cost for these latter applications are 

developed using the estimates described in previous sections. 

Cooling the flue gas after the air preheater, injecting PAC, and collecting the spent PAC 

in a downwind PFF may achieve Hg control on boilers equipped with HS-ESPs. This 

configuration is identical to ESP-6, with only the location of the ESP being different. Therefore, 

Hg reduction performance and costs should be similar to those found for ESP-6. However, on 

boilers equipped with HS-ESPs and firing high-sulfur bituminous coals, application of SC may 

not be possible due to corrosion concerns; for such boilers, Hg control may be achieved using 

ESP-3. With these considerations, cost of Hg control technology applications involving 

HS-ESPs are: model plant 3 costs are the same as those for model plant 1 with ESP-3; model 

plant 6 costs are the same as those for model plant 4 with ESP-6; model plant 9 costs are the 

same as those for model plant 7 with ESP-6; model plant 12 costs are the same as those for 

model plant 12 with ESP-3; model plant 15 costs are the same as those for model plant 13 with 

ESP-6; and model plant 18 costs are the same as those for model plant 16 with ESP-6. 

The combination of PAC injection and FF provides better sorbent utilization than the 

corresponding PAC injection and ESP combination because FF provides added residence time 

and a contact bed for increased adsorption of Hg. This superior performance of FF has been 

validated in full-scale tests on MWCs and pilot-scale tests on coal-fired combustors. Field tests 

have shown that it takes 2 to 3 times more PAC to achieve the same performance on MWCs 

equipped with SDAs and ESPs than with SDAs and FFs.14 As a result of increased sorbent 

utilization, the total annual cost of a PAC injection and FF application would be lower than that 

of the corresponding PAC injection and ESP combination. An analysis of cost data for ESP-4 

applications on Model plant scenarios 7 and 16 and FF-2 applications on Model plant scenarios 8 

and 17 (see Tables 8- 4 and 8-5) reveals that, in reducing Hg emissions between 

8-23

MODEL PLANT 4, ESP-6 & 7, 500 MW, Bituminous Coal, 0.6% Sulfur, 

Comparison of PAC and Lime-PAC Sorbents 

1.50 

1.75 

2.00 

2.25 

2.50 

2.75 

40 50 60 70 80 90 100 

Total Hg Removed, % 

Total Annual Cost, mills/kWh 

ESP-6, AC sorbent 

ESP-7, Lime-AC Sorbent 

Figure 8-2. Change in total annual cost resulting from use of a composite 

PAC-lime sorbent instead of PAC. 

8-24

60 and 90 percent using FFs instead of ESPs, the total annual cost decreases by an average 

of about 70 percent for the 975-MWe boiler and 45 percent for the 100-MWe boiler. 

Considering these numbers, an average about 58 percent decrease in total annual cost may 

be expected if FFs are used in place of ESPs for Hg removal. 

8.6 Projection of Future Mercury Control Costs 

Shown in Table 8-9 is a summary of costs of Hg control technology applications 

developed in previous sections. This summary presents current estimates of costs developed 

using the pilot-scale PAC injection rates and projections based on use of potentially more 

effective sorbents. The following assumptions were used in developing these estimates. 

(1) A Hg capture of 80 percent is obtained in technologies using ESPs and 90 percent in 

technologies using FFs. This assumption is based on the consideration that it is more 

cost-effective to remove Hg on boilers equipped with FFs. 

(2) For technology applications on bituminous-coal-fired boilers using ESPs, current 

estimates are based on levels of Hg capture on fly ash derived from pilot-scale test data. 

ICR data, however, reflect that levels of capture higher than those seen in pilot-scale tests 

may be occurring. In this light, these cost estimates may be conservative. 

(3) Current estimates for boilers using HS-ESPs, as well as boilers firing bituminous coals 

and using FFs, are based on the information presented in Section 8.4. For other cases, 

these estimates are based on the results obtained with the cost model. 

(4) Results of sensitivity analyses presented in Section 8.3, especially impacts of increase in 

approach-to-ADP at boilers firing bituminous coals and using ESP-4, are not included in 

the current estimates because the estimates are preliminary in nature and because it is not 

clear whether such an increase is broadly applicable. Generally an approach of ADP + 

18 o

F is considered to be optimum.11 Where a higher approach is desired, use of ESP-6 

may be less expensive. 

(5) Finally, sensitivity analyses reflect that using a potentially more effective sorbents (e.g., a 

composite PAC + lime) may remove Hg cost effectively. Although some data are 

available for applications using a PAC + lime sorbent with PFF, there does not appear to 

be any significant technical constraint to using such sorbents in other applications. 

Consequently, projected Hg control costs are based on using such more-effective 

sorbents. Specifically, sensitivity analyses reflected that a 35 to 40 percent decrease in 

total annual cost might be experienced if a PAC + lime sorbent is used. Since these 

indications are based on using PFF, the capital cost of which is a dominant component of 

the corresponding total annual cost, in applications without PFF greater benefits may be 

possible. Considering these factors, a 40 percent reduction in total annual cost is used to 

arrive at the cost projections shown in Table 8-9. Note that current research to develop 

more effective sorbents should in the near future provide such sorbents. 

8-25

Table 8-9. Projected future mercury control costs. 

Coal Burned Total Annual Mercur

(mills/kWh g

Type Sulfur Content 

Existing 

PM and SO2 

Control Devices (a) 

Applicable 

Mercury Control(s) 

(see Table 8-1) Current Estimate 

(from Tables 8-3 and 8

Bituminous 3 % CS-ESP + wet FGD ESP-1, SD/ESP-1 0.727 - 1.197 Bituminous 3 % FF + wet FGD FF-1 0.305 - 0.502 Bituminous 3 % HS-ESP + wet FGD ESP-3 1.501 (b) Bituminous 0.6 % CS-ESP ESP-4 1.017 - 1.793 Bituminous 0.6 % FF FF-2 0.427 - 0.753 Bituminous 0.6 % HS-ESP HESP-1 1.817 - 3.783 

Subbituminous 0.5 % CS-ESP ESP-4 1.150 - 1.915 Subbituminous 0.5 % FF FF-2 0.423 - 1.120 Subbituminous 0.5 % HS-ESP HESP-1 1.419 - 2.723 

8-26


(a) CS-ESP = cold-side electrostatic precipitator 

HS-ESP = hot-side electrostatic precipitator FF = fabric filter 

wet FGD = wet flue gas desulfurization system 

(b) Boiler size range is 975-100 MW. 

(c) NA = not available 
The 40 percent reduction in cost described above simply indicates the potential cost savings that 

may be possible once more effective sorbents are available. 

Earlier, EPA=s Office of Air and Radiation (OAR) conducted preliminary analyses examining 

potential pollution control options for the electric utility power industry to lower the emissions of its 

15 most significant air pollutants, including Hg. These analyses were conducted using the Integrated 

Planning Model (IPM),16 which was supplemented with previously developed estimates of 

performance and cost of Hg emission control technologies. These estimates were based on using lime 

with PAC injection. In these previous estimates, Hg control costs ranged from 0.17 to 1.76 

mills/kWh for boilers ranging in size from 100 to 1000 MW.

12 As seen from Table 8-10, the range 

of projected cost estimates (i.e., 0.183 to 2.27 mills/kWh) is comparable to the range of previously 

developed estimates. 

Finally, it is noted that, in the wake of recent NOX control regulations, many plants are 

planning to install SCRs. As discussed in Section 8.3.2, Hg control costs may be negligible at 

bituminous-coal-fired plants using SCR and wet FGD where Hg2+ content in the flue gas is 95 percent 

and higher as a result of fuel and combustion conditions and an increase in Hg oxidation due to SCR. 

8.7 Comparison of Mercury and NOX Control Costs 

An understanding of Hg control costs may be gained by comparing them with costs of 

currently used controls for NOX. In the U.S., commercial NOX control technologies are being used to 

comply with emission reduction requirements. Therefore, the costs associated with these NOX 

controls are being experienced at full-scale applications. A comparison of Hg control costs with costs 

of currently used NOX controls provides insight into how far or near the Hg control costs are from 

costs that are presently being experienced at full-scale applications to control another pollutant. 

Table 8-10 presents the ranges of total annual costs in 2000 constant dollars for the Hg 

controls examined in this work and for two currently used NOX control technologies; i.e., low NOX 

burner (LNB) and SCR. The LNB and SCR costs were derived from the information in Reference 

16. The NOX control costs presented are for applications on dry-bottom, wall-fired pulverized-coal 

boilers ranging in size from 100 to 1000 MWe and being operated at a capacity factor of 0.65. In 

general, costs associated with LNB and SCR are expected to span the costs of currently used NOX 

controls; therefore, these costs were chosen for comparison with Hg control costs. 

As seen from Table 8-10, total annual costs for Hg controls lie mostly between applicable 

costs for LNB and SCR. However, Table 8-9 shows total annual costs of Hg controls to be higher for 

the minority of plants using HS-ESPs. Excluding these costs, both currently estimated and projected 

Hg control costs are in the spectrum of LNB and SCR costs. 

8-27

Table 8-10. Comparison of mercury control costs with NOX control costs. 

Air Pollutant 

Controlled Control Technology 

Total Annual Control Cost 

Range 

(mills/kWh generated) 

Hg PAC injection 0.305 B 3.783 (a) 

0.183 to 2.270 (b) 

NOX 

Low-NO x burners 0.210 B 0.827 (c) 

Selective catalytic reduction 1.846 B 3.619 (c) 

(a) Current estimate of costs from Tables 8-3 and 8-4.


(b) Projected costs from Table 8-9.


(c) Actual costs from Reference 16.


8-28

8.8 Summary 

Preliminary estimates of costs of PAC injection-based Hg control technologies for coal-fired 

electric utility boilers have been determined. These estimates include those based on currently 

available data from pilot-scale PAC injection tests, as well as projections for future applications of 

more effective sorbents. Estimates based on currently available data range from 0.305 to 3.783 

mills/kWh. However, the higher costs are associated with the minority of plants using HS-ESPs. If 

these costs are excluded, the estimates range from 0.305 to 1.915 mills/kWh. Cost projections, 

developed based on using a composite lime-PAC sorbent for Hg removal, range from 0.183 to 2.270 

mills/kWh with the higher costs being associated with the minority of plants using HS-ESPs. 

For technology applications on bituminous-coal-fired boilers using ESPs, current estimates 

are based on levels of Hg capture on fly ash derived from pilot-scale test data. The EPA ICR data, 

however, reflect that levels of capture higher than those seen in pilot-scale tests may be occurring. In 

this light, the cost estimates for technology applications on bituminous-coal-fired boilers using ESPs 

may be conservative. 

Results of sensitivity analyses conducted on the total annual cost of Hg controls reflect that: 

(1) addition of ductwork to increase residence time does not have a significant impact on cost, (2) a 

sorbent recycle rate of 20 percent is not adequate to reflect significant improvement in sorbent 

utilization, (3) increasing the approach to ADP from ADP + 10 o

C to ADP + 22.2 oC can have a 

significant impact on total annual costs of Hg controls applicable to bituminous-coal-fired boilers, 

and (4) a composite sorbent containing a mixture of PAC and lime offers great promise of 

significantly reduced control costs. 

A comparison of Hg control costs with those of NOX controls reveals that total annual costs 

for Hg controls lie mostly between applicable costs for LNB and SCR. As mentioned above, 

estimates of total annual cost are higher where applicable to the minority of plants using HS-ESPs. 

Excluding these costs, both currently estimated and projected Hg control costs are in the spectrum of 

LNB and SCR costs. 

The performance and cost estimates of the PAC injection-based Hg control technologies 

presented in this paper are based on relatively few data points from pilot-scale tests and, therefore, are 

considered to be preliminary. Factors that are known to affect the adsorption of Hg on PAC or other 

sorbent include the speciation of Hg in flue gas, the effect of flue gas and ash characteristics, and the 

degree of mixing between the flue gas and the sorbent. This mixing may be especially important 

where the sorbent has to be injected in relatively large ducts. The effect of these factors may not be 

entirely accounted for in the relatively few pilot-scale data points that comprised the basis for this 

work. Ongoing research is expected to address these issues and to improve the cost effectiveness of 

using sorbents for Hg control. Research is also needed on ash and sorbent residue to evaluate Hg 

retention and the potential for release back into the environment. 

8-29

8.9 References 

1. Keating, M.H., K.R. Mahaffey, R. Schoeny, G.E. Rice, O.R. Bullock, R.B. Ambrose, J. Swartout, 

and J.W. Nichols. Mercury Study Report to Congress, Volumes I-VIII. EPA-452/R-97-003 

through 010. Office of Air Quality Planning and Standards and Office of Research and 

Development, Research Triangle Park, NC. December 1997. Available at: 

< http://www.epa.gov/airprogm/oar/mercury.html >. 

2. French, C.L., W.H. Maxwell, W.D. Peters, G.E. Rice, O.R. Bullock, A.B. Vasu, R. Hetes, 

A. Colli, C. Nelson, and B.F. Lyons. Study of Hazardous Air Pollutant Emissions from Electric 

Utility Steam Generating Units -- Final Report to Congress, Volume 1. EPA-453/R-98-004a 

(NTIS PB98-131774). Office of Air Quality Planning and Standards, Research Triangle Park, 

NC. February 1998. Also available at: 

< http://www.epa.gov/ttn/atw/combust/utiltox/utoxpg.html >. 

3. Waugh, E.G., B.K. Jensen, L.N. Lapatnick, F.X. Gibbons, S. Sjostrom, J. Ruhl, R. Slye, and R. 

Chang. "Mercury Control in Utility ESPs and Fabric Filters Through Dry Carbon-Based Sorbent 

Injection Pilot-Scale Demonstration." EPRI/DOE/EPA Combined Air Pollutant Control 

Symposium, Particulates and Air Toxics. Volume 3, EPRI TR-108683-V3. Electric Power 

Research Institute, Palo Alto, CA. August 1997. pp. 1-15. 

4. Haythornthwaite, S.M., J. Smith, G. Anderson, T. Hunt, M. Fox, R. Chang, and T. Brown. APilotScale Carbon Injection for Mercury Control at Comanche Station.@ Presented at the A&WMA 

92nd Annual Meeting & Exhibition. St. Louis, MO. June 1999. 

5. Haythornthwaite, S.M., S. Sjostrom, T. Ebner, J. Ruhl, R. Slye, J. Smith, T. Hunt, R. Chang, and 

T.D. Brown. "Demonstration of Dry Carbon-Based Sorbent Injection for Mercury Control in 

Utility ESPs and Fabric Filters." EPRI/DOE/EPA Combined Air Pollutant Control Symposium, 

Particulates and Air Toxics, Volume 3. EPRI TR-108683-V3, Electric Power Research Institute, 

Palo Alto, CA. August 1997. 

6. Redinger, K.E., A.P. Evans, R.T. Bailey, and P.S. Nolan. “Mercury Emissions Control in FGD 

Systems.” EPRI/DOE/EPA Combined Air Pollutant Control Symposium, Particulates and Air 

Toxics, Volume 3. EPRI TR-108683-V3, Electric Power Research Institute, Palo Alto, CA. 

August 1997. 

7. Brown, T.D., D.N. Smith, R.A Hargis, and W.J. O=Dowd. A1999 Critical Review, Mercury 

Measurement and Its Control: What We Know, Have Learned, and Need to Further Investigate,@ 

Journal of the Air & Waste Management Association, June 1999. pp. 1-97. 

8. Brown, T.D., W. O'Dowd, R. Reuther, and D. Smith. “Control of Mercury Emissions from 

Coal-Fired Power Plants: A Preliminary Cost Assessment,” in Proceedings of the Conference on 

Air Quality, Mercury, Trace Elements, and Particulate Matter, Energy & Environmental Research 

Center, McLean, VA. December 1998. pp. 1-18. 

8-30

9. U.S. Environmental Protection Agency. Electric Utility Steam Generating Unit Mercury 

Emissions Information Collection Effort, OMB Control No. 2060-0396. Office of Air Quality 

Planning and Standards, Research Triangle Park, NC. Available at: 

< http://www.epa.gov/ttn/atw/combust/utitox/utoxpg.htm1 >. 

10. Butz, J.R., R. Chang, E.G. Waugh, B.K. Jensen, and L.N. Lapatnick. “Use of Sorbents for Air 

Toxics Control in a Pilot-Scale COHPAC Baghouse,” presented at the A&WMA 92nd Annual 

Meeting & Exhibition, St. Louis, MO. June 1999. 

11. Dotson, R.L., F.A Sodhoff, and T.A. Burnett. Lime Spray Dryer Flue Gas Desulfurization 

Computer Model Users Manual. EPA-600/8-86-016 (NTIS PB87-140968). U.S. Environmental 

Protection Agency. Air and Energy Engineering Research Laboratory, Research Triangle Park, 

NC. June 1986. p. 15. 

12. Srivastava, R.K., C.B. Sedman, and J.D. Kilgroe. “Preliminary Performance and Cost Estimates 

of Mercury Emission Control Options for Electric Utility Boilers.” Presented at the A&WMA 

93rd Annual Conference & Exhibition, Salt Lake City, UT. June 2000. 

13. U.S. Department of Energy. DOE=s Duct Injection Survey Results. Pittsburgh Energy 

Technology Center, Pittsburgh, PA. August 1988. 

14.	 Kilgroe, J.D. “Control of Dioxin, Furan, and Mercury Emissions from Municipal Waste 

Combustors,” Journal of Hazardous Materials, 47, 1996. pp.163-194. 

15. U.S. Environmental Protection Agency. Analysis of Emissions Reduction Options for the 

Electric Power Industry. Office of Air and Radiation, Washington, DC, March 1999. Available 

at: < http://www.epa.gov/capi/multipol/mercury.htm >. 

16. U.S. Environmental Protection Agency. Analyzing Electric Power Generation Under CAAA. 

Office of Air and Radiation. Washington, DC. March 1998. Available at: 

< http://www.epa.gov/capi >. 

8-31

Chapter 9


Coal Combustion Residues and Mercury Control


9.1 Introduction 

The burning of coal in electric utility boilers generates residual materials including fly 

ash, bottom ash, boiler slag, and wet FGD scrubber solids/sludges. These residual materials are 

collectively referred to as “coal combustion residues” (CCRs). Currently, about 70 percent of the 

CCRs are land-disposed and the other 30 percent are reused or recycled for commercial uses such 

as production of wallboard, cement, and asphalt. Use of Hg emission control technologies on 

coal-fired electric utility boilers will probably increase the amount of Hg in certain types of 

CCRs, and could also change the composition and physical properties of these materials, possibly 

impacting their suitability for commercial reuse and recycling applications. Many of the 

potential retrofit Hg control technologies for coal-fired electric utility power plants discussed in 

Chapter 7 remove Hg from the flue gas and concentrate the captured Hg into CCRs (i.e., fly ash 

collected by PM control devices or solids/sludges generated by wet FGD scrubbers). Concern 

has been raised as to whether the Hg in the CCRs may later be re-released back to the 

environment. 

A life-cycle evaluation is being conducted by NRMRL to help evaluate any potential 

environmental trade-offs and to ensure that there is not an increased environmental risk for the 

management of CCRs resulting from Hg control technologies. In support of this evaluation, the 

NRMRL is gathering data and information to assess future increases in Hg concentrations in 

CCRs resulting from application of Hg emissions control requirements to coal-fired electric 

utility boilers. This chapter summarizes some of the CCR information gathered by NRMRL to 

date and identifies the major data gaps and priorities of EPA’s research to ensure that Hg 

controlled at the coal-fired electric utility power plant stack is not later released from CCRs in an 

amount that is problematic for the environment. 

9.2 CCR Types 

The coal combustion process generates many different types of residues. At a given 

power plant, CCRs can be grouped as those generated on a continuous basis in high-volume 

quantities and those generated either continuously or intermittently in low-volume quantities. 

These low-volume CCRs include those resulting from maintenance and coal cleaning. However, 

9-1

the focus of this chapter is on high-volume CCRs. High-volume CCRs include the bottom ash or 

slag removed directly from the boiler furnace and the fly ash collected by downstream PM 

control devices. For those coal-fired electric utility boilers using wet FGD scrubbers for SO2 

emissions control, large quantities of scrubber solid wastes and sludges are generated. 

Nationwide quantities of high-volume CCRs generated in 1999 from coal combustion are 

available from data prepared by the American Coal Ash Association (ACAA).1 Table 9-1 

summarizes the characteristics and nationwide generation quantities for the major types of CCRs 

resulting from combustion of coal in power plants. 

9.3 CCR Mercury Concentrations 

An initial review by NRMRL indicated that limited laboratory data were available on Hg 

concentrations in CCRs. Therefore, a nationwide Hg mass balance approach was taken to 

estimate Hg concentrations in CCRs. This Hg mass balance approach used data from the EPA 

Parts II and III ICR data bases on coal Hg concentrations and control device Hg capture 

efficiencies. The EPA ICR data were used with additional ACAA data on CCR generation rates, 

to estimate Hg concentrations in various CCRs. The Hg concentrations estimated with the 

nationwide mass balance approach are shown in Table 9-2. Table 9-2 shows calculated mean, 5th 

percentile, and 95th percentile values for Hg concentrations in CCRs. Mercury concentrations are 

projected to be highest in fly ash, with a mean value of 0.33 ppm, and a 95th percentile value of 

1.2 ppm. Mercury concentrations in wet FGD scrubber solids/sludges are calculated to have a 

mean value of 0.20 ppm, and a 95th percentile value of 0.72 ppm. Mercury concentrations in 

bottom ash and boiler slag were calculated to be much lower, with mean values of 0.067 ppm, 

and 0.042 ppm, respectively. 

Subsequent to performing the nationwide Hg mass balance to determine Hg 

concentrations in CCRs, more extensive laboratory data became available from the Electric 

Power Research Institute (EPRI) and the University of North Dakota Environmental and Energy 

Research Center (UND/EERC). A summary of available laboratory measurements of Hg in 

CCRs is shown in Table 9-3. The laboratory measurements in Table 9-3 generally show good 

correlation with the nationwide mercury mass balance predictions in Table 9-2. For example, the 

EPRI fly ash data (382 samples) have a mean mercury concentration of 0.44 ppm, with a 95th 

percentile value of 1.13 ppm, and the UND/EERC data (20 samples) have a mean Hg 

concentration of 0.22 ppm, and a 95th percentile value of 1.03 ppm. Both these sets of data 

correlate well with fly ash calculations obtained by the nationwide Hg mass balance, which 

indicates a mean concentration of 0.33 ppm, and 95th percentile value of 1.2 ppm. 

9.4 Nationwide Management Practices 

A summary comparison of the quantities and management techniques for various CCRs is 

presented in Figure 9-1. The CCRs are either land-disposed (in a monofill or surface 

9-2

Table 9-1. Coal combustion residues. 

Coal 

Combustion 

Residue 

Description 

Average Quantity 

Generated Per 

Ton of Coal Burned a 

Total Nationwide 

Quantity Generated 

in 1999 b 

Fly ash 

Fine, powdery non-combustible mineral matter 

in the boiler flue gas and collected by 

electrostatic precipitator or fabric filter 

160 lb/ton 63,000,000 tons 

Bottom ash 

Dark gray, granular, porous non-combustible 

mineral matter heavier than fly ash and 

collected in bottom of the boiler furnace. 

40 lb/ton 17,000,000 tons 

Boiler slag 

Coarse, black, glassy mineral matter 

that forms when molten bottom ash contacts 

quenching waters in wet-bottom furnaces. 

100 lb/ton 3,000,000 tons 

Wet FGD 

scrubber 

solids/sludges 

Solid material or sludge generated by 

scrubbing processes used to 

remove sulfur from the flue gases. 

350 lb/ton 25,000,000 tons 

(a) Source: Reference 2. 

(b) Source: Reference 1. 

Table 9-2. Calculated Hg concentrations in CCRs using EPA ICR data. 

Hg Concentration (ppm) a Coal 

Combustion 

Residue 5th Percentile Mean 95th Percentile 

Fly ash 0.062 0.33 1.2 

Bottom ash 0.019 0.067 0.16 

Boiler slag 0.012 0.042 0.10 

Wet FGD scrubber 

solids/sludges 0.038 0.20 0.72 

(a) Changes in Hg control technology requirements for coal-fired electric utility power plants will cause changes 

in the Hg concentration in fly ash and wet FGD scrubber solids/sludges. 

9-3 
Table 9-3. Summary of available test data on Hg concentrations in major types of CCRs. 

Hg Concentration (ppm) Coal 

Combustion 

Residue 

Test Data Source 

(Reference) 

Number 

of 

Samples Min. 5th Percentile Median Mean 

EPRI (Reference 3) 382 0.0002 0.0002 0.09 0.44 

UND/EERC (Reference 4) 20 <0.002 0.002 0.076 0.22 

EPA (Reference 5) 

(fine fly ash) n.r. a 0.005 n.r. 0.10 n.r. 

EPA (Reference 5) 

(mechanical hopper) n.r. 0.008 n.r. 0.073 n.r 

Fly ash 

EPA (Reference 5) 

(1993 data) n.r. 0.013 n.r. 0.10 n.r 

EPA (Reference 5) 12 0.003 n.r. 0.009 n.r 

Bottom ash 

EPA (Reference 6) 

(combined bottom ash and slag) n.r. 0.005 n.r. 0.023 n.r 

Boiler slag EPA (Reference 5) 12 0.005 n.r 0.023 n.r 

Wet FGD solids/sludges EPA (Reference 5) 15 0.073 n.r 4.8 n.r 

9-4


(a) n.r. = not reported. 
70 

60 

50 

40 

30 

20 

10 

0 

fly ash bottom ash boiler slag FGD material 

Commercial use 

Land-disposed 

Figure 9-1. Nationwide CCR management practices in the year 1999 (source: 

graph prepared using data from Reference 1). Annual disposal or use (millions of tons per year) 

9-5

impoundment) or are being used for commercial applications. In the United States in the year 

1999, approximately 110 million tons of CCRs were generated. Approximately one-third (31 

percent) of these materials were reused or recycled in various commercial uses, with the 

remainder being land-disposed. 

9.4.1 Reuse and Recycling of CCRs 

The primary commercial uses of CCRs are listed in Table 9-4. The table presents how 

each of four types of high-volume CCRs were used for commercial application in 1999. The use 

of fly ash as a replacement ingredient for concrete or grout is the most common use for any CCR. 

In this application, the fly ash can serve as a replacement for sand or as a partial replacement for 

Portland cement in the concrete mix. Significant amounts of fly and bottom ash are used for 

structural fills (e.g., creation of highway embankments). The addition of CCR to form a road 

base allows for greater long-term strength development than conventional materials. Bottom ash 

is used as a substitute for salt for road de-icing operations. Almost all of the boiler slag 

generated in 1999 was used as blasting grit or roofing granules. Wet FGD scrubber solid wastes 

and sludges that do not contain high levels of fly ash can be used either directly or, with 

additional processing, in the production of gypsum wallboard. The substitution of wet FGD 

scrubber solids/sludges for natural gypsum in wallboard manufacturing has been growing rapidly. 

For some commercial uses of CCRs, there is concern regarding the potential re-release of 

Hg, particularly for those uses involving high-temperature processes. In cement manufacturing, 

for example, the high temperatures in the cement kiln will revolatilize the Hg contained in the 

coal fly ash that is used as a material substitute. Questions exist regarding the fraction of Hg in 

the fly ash that may be emitted when fed to a cement kiln. Other commercial processes that 

expose CCRs to elevated temperatures include wallboard manufacturing (during the drying 

process) and when CCRs are used as fillers in asphalt. 

For some of the other commercial uses, it appears unlikely that significant Hg in CCRs 

would be re-introduced into the environment. For example, Hg is unlikely to be re-volatilized or 

leached from concrete, flowable fill, or structural fill. However, the various commercial uses 

will be evaluated to determine if there is any significant increase in environmental risk as a result 

of changes occurring to CCRs. 

9.4.2 Land-disposal of CCRs 

There are currently approximately 600 waste disposal units (monofills or surface 

impoundments) being used for disposal of CCRs from electric utility coal-fired electric utility 

power plants in the United States.5 The monofills used for these residues may be located either 

on-site at the power plant or off-site. Surface impoundments are almost exclusively located at 

the power plant site. While the distribution of units presently is about equal between monofills 

and surface impoundments, there is an increased trend to use monofills as the primary disposal 

method. 

9-6

Table 9-4. Commercial uses for CCRs generated in 1999 (source: data from Reference 

Coal Combustion Residue 

Fly ash Bottom ash Boiler slag Wet FGD solids/s

Commercial 

Application or Use 

tons % tons % tons % tons 

Concrete/grout 10,000,000 49 700,000 13 11,000 0.5 290,000 

Waste stabilization/solidification 1,900,000 9.3 69,000 1.3 0 0 16,000 

Structural fill 3,200,000 15 1,400,000 26 52,000 2.2 580,000 

Mining applications 1,500,000 7.3 150,000 2.8 10,000 0.4 230,000 

Raw feed for cement clinker 1,300,000 6.1 160,000 2.9 0 0 0 

Road base/subbase 1,200,000 5.9 1,100,000 20 5,500 0.2 17,000 

Flowable fill 850,000 4.1 13,000 0.2 0 0 0 

Other 460,000 2.2 450,000 8.3 76,000 3.2 180,000 

Mineral filler 160,000 0.8 63,000 1.2 12,000 0.5 0 

Soil modification 78,000 0.4 17,000 0.3 13,000 0.5 2,100 

Agriculture 78,000 0.4 43,000 0.8 0 0 80,000 

Snow and ice control 3,200 0.1 1,100,000 20 51,000 2.2 0 

Blasting grit/roofing granules 0 0 160,000 2.9 2,100,000 90 0 

Wallboard 0 0 0 0 0 0 3,100,000 

Nationwide Total a 21,000,000 100 5,400,000 100 2,300,000 100 4,500,000 

9-7


(a) Sum of individual values may not equal total due to rounding. 
On May 22, 2000, the EPA made the regulatory determination that the disposal of CCRs 

does not warrant regulation under subtitle C of RCRA and retained the hazardous waste 

exemption for these materials provided under RCRA section 3001(b)(3)(C).7 However, the 

EPA also determined that national regulations under subtitle D of RCRA are warranted for CCRs 

when they are disposed of in landfills or surface impoundments, and that regulations under 

subtitle D of RCRA [and/or possibly modifications to existing regulations established under 

authority of the Surface Mining Control and Reclamation Act (SMCRA)] are warranted when 

these materials are managed in surface or underground mines. The national regulations will 

apply to disposal of coal combustion wastes that are generated at electric utility and independent 

power producing facilities and managed in surface impoundments, landfills, and mines. 

The EPA will re-evaluate the risk posed by managing coal combustion residues if levels 

of Hg or other hazardous constituents change due to any future Clean Air Act air pollution 

control requirements for coal burning utilities. When any rulemaking under the Clean Air Act 

proceeds to the point where an assessment of the likely changes to the character of CCRs is 

completed, EPA will evaluate the implications of these changes relative to existing or planned 

national RCRA regulations governing these materials and take appropriate action. 

9.5 Current Status of CCR Research Activities 

The EPA/NRMRL is preparing a report on characterization and management of CCRs 

from coal-fired electric utility power plants. The report examines changes in the Hg content of 

CCRs that potentially could occur as the result of implementing different control technologies to 

reduce stack emissions of Hg from coal-fired electric utility power plants. This report is 

scheduled to be published in the near future. 

Test methods to characterize CCRs and to determine Hg volatilization and leaching from 

CCRs in various management practices are being reviewed by EPA/NRMRL. The goal of this 

review is to ensure that leaching and volatilization testing conducted by all parties, inside and 

outside of the EPA, is uniform and appropriate. 

Multiple-site, full-scale field test programs are currently being conducted under a 

DOE/NETL cooperative agreement to obtain performance and cost data for using different Hg 

control technologies to reduce Hg emissions from existing coal-fired electric utility power plants 

(discussed in Chapter 7). As part of these test programs, field data are being collected that will 

help determine changes in the Hg content of CCRs as a result of implementing these Hg controls 

technologies. In addition, CCR commercial applications requiring elevated temperature 

processes, such as cement manufacturing and wallboard production, are being evaluated to 

determine the amount of Hg revolatilization that occurs, and the impacts of this revolatilization 

on the environment. 

The EPA/NRMRL is planning to prepare a report, scheduled for publication in 2003, 

presenting data and other information relating to changes to CCRs as a result of implementing 

9-8

different Hg control technologies. This report will also help identify any potential concerns due 

to increased environmental risk from the management of CCRs resulting from Hg control 

measures. 

9.6 Future CCR Research Activities and Needs 

Coordination with industry and others will continue to identify available data and 

information that will help to characterize any changes to CCRs as a result of Hg control measures. 

Different methods are being used to characterize CCRs which result in data of questionable value. 

The EPA ORD/NRMRL is working closely with EPA/OSW to identify methods for 

characterizing CCRs to identify potential changes to CCRs as a result of Hg control measures. 

Samples of the resulting CCRs from the on-going full-scale field test programs of different 

Hg control technologies will be collected to characterize the resulting CCRs and to identify any 

changes occurring to CCRs that would increase environmental risk from waste management and 

potential commercial applications. 

Questions regarding the potential release of Hg from land-disposal result in the need to 

conduct field test measurements to ensure that Hg is not being emitted through either biological 

processes or leaching. Opportunities will be identified to help address questions regarding any 

increased environmental risk due to changes occurring to CCRs. 

Questions also exist relating to CCRs being used in high-temperature processes such as 

cement manufacturing and wallboard production. Effort is needed to determine the amount of Hg 

that may be released during the manufacturing process and other life-cycle stages, including final 

disposal in a landfill. 

9.7 References 

____________________________ 

1.	 American Coal Ash Association. Coal Combustion Products (CCPs) Production and Use 

Survey - 2000. Syracuse, NY. Available at: 

< http://216.22.250.39/CCP%20Survey/CCP%20Survey.htm >. 

2.	 Butalia, T., W. Wolfe, W. Dick, D. Limes, and R. Stowell. Coal Combustion Products—Ohio 

State University Fact Sheet. 1999. Available at: < 

http://www.ag.ohio-state.edu/~ohioline/aex-fact/0330.html. > 

3.	 Ladwig, K. Electric Power Research Institute, Palo Alto, CA. Personal communication 

presenting total composition of mercury in fly ash based on EPRI’s PISCES database, May 

29, 2001. 

9-9

______________________________________________________________________________


4.	 Hassett, D. J., D.F. Pflughoeft-Hassett, D.L. Laudal, and J.H. Pavlish. Mercury Release from 

Coal Combustion By-Products to the Environment. Energy & Environmental Research 

Center, University of North Dakota, Grand Forks, ND, 2000. 

5.	 U.S. Environmental Protection Agency. Report to Congress: Wastes from the Combustion of 

Fossil Fuels: Volume 2B. Methods, Findings and Recommendations. EPA-530-R-99-010. 

Office of Solid Waste and Emergency Response, Washington, DC. 1999. 

6.	 U.S. Environmental Protection Agency. Report to Congress: Wastes from the Combustion of 

Coal by Electric Utility Power Plants. EPA/530-SW-88-002 (NTIS PB88-177977). Office 

of Solid Waste and Emergency Response, Washington, DC. 1988. 

7.	 U.S. Environmental Protection Agency. Regulatory Determination on Wastes from the 

Combustion of Fossil Fuels; Final Rule. Federal Register, Vol. 65, No. 99. pp.32213-32237. 

May 22, 2000. 

8.	 U.S. Environmental Protection Agency. Technical Background Document for the Report to 

Congress on Remaining Wastes from Fossil Fuel Combustion: Industry Statistics and Waste 

Management Practices. Office of Solid Waste and Emergency Response, Washington, DC. 

1999. Available at: < http://www.epa.gov/epaoswer/other/fossil/index.htm >. 

9-10

Chapter 10 

Conclusions and Recommendations 

10.1 Electric Utility Coal Combustion and Air Pollution Control Technologies 

The diversity of coals and combustion technologies used for electrical utility steam 

generating units (i.e., coal-fired boilers) is reflected in data gathered from Phases I and II of the 

EPA’s formal information collection request (ICR) to the electric utility industry. In 1999, 

electric utility coal-fired boilers in the United States burned 786 million tons of coal of which 

about 52 percent was bituminous coal, 37 percent was subbituminous coal, and 9 percent was 

lignite. Other fuels burned in electric utility coal-fired boilers included mixtures of bituminous 

and subbituminous coal, mixtures of coal and petroleum coke (pet-coke), reclaimed coal wastes, 

and mixtures of coal and tire-derived fuel (TDF). 

There were 1,140 coal-fired boiler units that burned coal by conventional methods and 

three units that used gasification to produce a fuel gas. Pulverized-coal-fired (PC) boilers, by far 

the largest group of coal-fired boiler units, represent approximately 86 percent of the total 

number of units and 90 percent of the total utility boiler capacity. Based on capacity, other types 

of boilers include cyclone-fired boilers (7.6 percent), fluidized-bed combustors (1.3 percent), and 

stoker-fired boilers (1.0 percent). 

The Part II EPA ICR responses indicate that a variety of air emission control technologies 

are employed to meet requirements for control of sulfur dioxide (SO2), nitrogen oxides (NOX), 

and particulate matter (PM). Most utilities control NOX by combustion modification techniques 

and control SO2 by the use of compliance coals. For post-combustion controls, 77.4 percent of 

units by number have PM control only, 18.6 percent have both PM and SO2 controls, 2.5 percent 

have PM and post-combustion NOX controls, and 1.3 percent have three post-combustion control 

devices. 

For PM emissions control of electric utility coal-fired boilers, electrostatic precipitators 

(ESPs) are used on 84 percent of the units and fabric filters (FFs) on 14 percent. Postcombustion SO2 controls are less common. Wet flue gas desulfurization (FGD) scrubbers are 

used on 15.1 percent of the units, and spray dryer absorbers (SDA) are used on 4.6 percent of the 

units surveyed. In 1999, while the application of post-combustion NOX controls was becoming 

more prevalent, only 3.8 percent of the units used either selective non-catalytic reduction 

(SNCR) or selective catalytic reduction (SCR) systems. 

10-1

10.2 Mercury Measurement Methods 

Reliable and valid speciated and total Hg measurements, by either manual test methods or 

continuous emission monitors (CEMs), are critical to the characterization and future reduction of 

Hg emissions from coal-fired powered plants. Although viable measurement techniques exist for 

certain measurement scenarios, acceptable measurement techniques are not available to meet all 

measurement needs. Additional research and development is needed to enable quality 

measurements from various measurement environments. 

The Ontario-Hydro (OH) Method is the only manual test method that currently is 

recognized in the United States for the collection of speciated Hg emissions data from the 

combustion of coal. The OH Method appears to provide valid speciation results at sampling 

locations downstream of PM control devices where most of the fly ash has been removed. 

However, measurements made upstream of PM control devices are susceptible to measurement 

artifacts that bias speciation measurements, causing significant uncertainty in results. 

A limited number of CEMs exist (both commercial and prototype) for the measurement 

of total gas-phase Hg and, to a lesser extent, speciated gas-phase Hg. Also, demonstration of 

acceptable measurement performance under field applications is limited. Because of the 

diversity and severity of associated measurement environments, numerous measurement 

obstacles exist (e.g., PM artifacts, interferences, Hg2+ 

conversion systems, sample 

conditioning/delivery) that have not been adequately addressed, particularly with respect to 

speciated measurements. While experts use Hg CEMs as a research tool, the Hg CEMs are not 

currently suitable for routine use on power plants in the United States. 

Improved methods for the sampling and analysis are critical for: the development and 

evaluation of Hg emission control technologies; use as Hg control technology process controls; 

and potential use as compliance tools. Research is specifically needed to: 

•	 Develop and verify a manual test method that is suitable for measuring total and 

speciated Hg at sampling locations upstream of PM control devices, 

•	 Develop and verify a manual test method that can simultaneously measure speciated 

Hg and other hazardous trace metals, 

•	 Develop and demonstrate measurement techniques that are capable of directly 

identifying and quantifying trace levels of individual ionic species of Hg [e.g., HgCl2, 

HgCl, HgO, HgS, HgSO4, and Hg(NO3)2], 

•	 Develop and demonstrate improved Hg CEM measurement techniques that address 

known and potential measurement obstacles (e.g., PM artifacts, interferences/biases, 

conversion systems, and sample conditioning/delivery), 

10-2

•	 Verify the ability of Hg CEMs to accurately measure total gas-phase Hg and 

speciated gas-phase Hg at diverse stack conditions representative of fuel type and 

pollution control device configurations (e.g., downstream of PM control devices, dry 

FGD scrubbers, and wet FGD scrubbers), 

•	 Verify the ability of Hg CEMs to accurately measure total gas-phase Hg and 

speciated gas-phase Hg upstream of PM control devices, 

•	 Demonstrate Hg CEM long-term monitoring performance and operational 

requirements, 

•	 Identify and evaluate CEMs capable of measuring SO3 and other hazardous air 

pollutant emissions, 

•	 Identify and evaluate alternative, cost-effective semi-continuous methods for 

measuring the stack emission of total Hg, and 

•	 Demonstrate the use of Hg CEMs and semi-continuous monitoring methods as 

potential Hg emission compliance tools. 

10.3 Mercury Speciation and Capture 

10.3.1 Mercury Speciation 

When the coal is burned in an electric utility boiler, the resulting high combustion 

temperatures vaporize the Hg in the coal to form gaseous elemental mercury (Hg0

). Subsequent 

cooling of the combustion gases and interaction of the gaseous Hg0 with other combustion 

products result in a portion of the Hg being converted to gaseous oxidized forms of mercury 

(Hg

2+) and particle-bound mercury (Hgp). The term speciation is used to denote the relative 

amounts of these three forms of Hg in the flue gas of the boiler. It is important to understand 

how Hg speciates in the boiler flue gas because the overall effectiveness of different control 

strategies for capturing Hg often depends on the concentrations of the different forms of Hg 

species present in the boiler flue gas. 

In general, Hg speciation is dependent on: 1) coal properties, 2) combustion conditions, 

3) the flue gas composition, 4) fly ash properties, 5) the time/temperature profile between the 

boiler and air pollution control devices, and 6) the flue gas cleaning methods, if any, in use. The 

mechanisms by which Hg0 is oxidized in flue gas are believed to include gas-phase reactions, fly 

ash or deposit-mediated reactions, and oxidation reactions in post-combustion NOX control 

systems. Data reveal that gas-phase oxidation is kinetically limited and occurs due to reactions 

of Hg with oxidizers such as Cl and Cl2. Research also suggests that gas-phase oxidation may be 

inhibited by the presence of NO, SO2, and water vapor. 

10-3

Certain fly ashes have been shown to promote oxidation of Hg0 more than others. The 

differences in oxidation appear to be attributable to the composition of the fly ash and the 

presence of certain flue gas constituents. The results of bench-scale research conducted at EPA 

indicate that the presence of HCl and NOX in flue gas and iron in fly ash assists in oxidation. 

Other research indicates that γ-Fe2O3 may be causing Hg2+ formation and that surface area may 

be a dominant factor in this regard. Also, there are indications that HCl, NO2, and SO2 in the 

flue gas may contribute to Hg0 oxidation, while the presence of NO may suppress Hg0 oxidation. 

10.3.2 Development and Evaluation of Sorbents 

Mercury can be captured and removed from a flue gas stream by injection of a sorbent 

into the exhaust stream with subsequent collection in a particulate matter (PM) control device 

such as an ESP or a FF. However, adsorptive capture of Hg from flue gas is a complex process 

that involves many variables. These include the temperature and composition of the flue gas, the 

concentration of Hg in the exhaust stream, and the physical and chemical characteristics of the 

sorbent (and associated functional groups). The implementation of an effective and efficient Hg 

control strategy using sorbent injection requires the development of low-cost and efficient Hg or 

multipollutant sorbents. Of the known Hg sorbents, activated carbons and calcium-based 

sorbents have been the most actively studied. 

Oxidized mercury is readily absorbed by alkaline solutes/slurries or adsorbed by alkaline 

particulate matter (or by sorbents). Flue gas desulfurization systems, which use alkaline 

materials to neutralize the acidic SO2 gas, remove Hg2+ effectively in the flue gas. Current 

research is focusing on optimization of the existing desulfurization systems as a retrofit 

technology for controlling Hg2+ emissions and on development of new multipollutant control 

technologies for simultaneously controlling both SO2 and Hg emissions. Sorbents containing 

oxidizing agents are also being developed for the oxidization and capture of Hg0. 

10.4 Evaluation of EPA ICR Mercury Emission Test Data 

The air pollution control technologies used on coal-fired utility boilers exhibit levels of Hg 

control that range from 0 to 99 percent. The best levels of control are generally obtained by 

emission control systems that use FFs. Since Hg emission control technologies are not currently 

used by the utility industry, the capture of Hg by existing controls results from: 1) adsorption of 

Hg onto fly ash with subsequent capture of Hgp in a PM control device; 2) adsorption of Hg by 

the alkaline sorbents used in dry scrubbers; or 3) the capture of Hg 2+ in wet scrubbers. 

The amount of Hg captured by a given control technology is better for bituminous coal 

than for either subbituminous coal or lignite. The lower levels of Hg capture in plants firing subbituminous coal and lignite are attributed to low fly ash carbon content, and the higher relative 

amounts of Hg0 in the flue gas are due to the combustion of these fuels. 

Combinations of coal, boiler, and control technologies that are expected to behave in a 

similar manner with respect to speciation and capture of mercury can be grouped into data sets 

10-4

called coal-boiler-control technology classes. Accordingly, the ICR Part III emission data were 

sorted into appropriate coal-boiler-control classes. Next, the data in each class were evaluated for 

consistency, and the data between classes were evaluated based on the current understanding of 

speciation and capture of mercury. With few exceptions, the differences in data between the 

different classes were consistent with this understanding. 

Plants that employ only post-combustion PM controls display Hg emission reductions 

ranging from 0 to 93 percent. The lower levels of control were observed for units with FFs. 

Decreasing levels of control were shown for units with ESPs, PM scrubbers, and mechanical 

collectors. 

Units equipped with dry scrubbers (SDA/ESP or SDA/FF systems) exhibited average Hg 

captures ranging from 98 percent for units burning bituminous coals to 3 percent for units burning 

subbituminous coal. The poor Hg capture in units firing subbituminous coal is attributed to the 

predominance of Hg0 in the flue gas from these units. 

The capture of Hg in units equipped with wet FGD scrubbers is primarily dependent on 

the relative amount of Hg2+ in the inlet flue gas. Average Hg captures in wet FGD scrubbers 

ranged from 33 percent, for one PC-fired ESP + FGD unit burning subbituminous coal, to 96 

percent in a PC-fired FF + FGD unit burning bituminous coal. The high Hg capture in the FF + 

FGD unit is attributed to the increased oxidization and capture of Hg in the FF. 

The EPA ICR data base provides a massive amount of data that can be mined for additional 

information. However, the usefulness of these data is limited by the uncertainty of some of the 

measurements and/or the information that the data set does not contain. Some of the uses and 

limitations of the EPA ICR data are summarized below. 

The EPA ICR data provide: 

•	 Reasonable estimates of national and regional emissions for total Hg, Hg0

, Hg

2+, 

and Hgp. The data cannot be used to predict the total and speciated Hg emissions of 

individual coal-fired power plants. 

•	 Data for testing hypotheses and models that predict speciation and capture of Hg in 

coal-fired boilers. The data cannot be used to identify or confirm specific 

mechanisms that control the speciation and capture of Hg. 

•	 Information needed to guide the development of control technologies and identify 

effective strategies for the control of Hg emissions. 

Caution should be used in interpreting the EPA ICR data since: 

•	 Adsorption of Hg onto fly ash is highly dependent on fly ash properties, particularly 

on the fly ash carbon content. The lack of information on coal and fly ash 

properties greatly limits the usefulness of the ICR data. 

10-5

•	 Results of Hg speciation measurements made with the OH Method upstream of PM 

control devices should be used with great caution. PM collected on the sampling 

train filter can result in physical and chemical transformations (e.g., sample 

artifacts) within the sample train. 

•	 Because of the limited number of samples, there is a great deal of uncertainty in the 

central values and statistical characteristics of the ICR data. The flue gas Hg tests 

represent a short snapshot in time, and the effects of long-term variations in coal 

properties and plant operating conditions are unknown. 

•	 At low inlet and outlet concentrations, the imprecision of the OH Method can 

obscure real differences between inlet and outlet concentrations. 

10.5 Potential Retrofit Mercury Control Technologies 

A practical approach to controlling Hg emissions at existing utility plants is to minimize 

capital costs by adapting or retrofitting the existing equipment to capture Hg. For units that 

currently use only PM controls, dry FGD scrubbers, or wet FGD scrubbers, there are three 

potential retrofit options: 1) Cold-side ESP, hot-side ESP, and FF systems; 2) Dry FGD systems; 

and 3) Wet FGD systems. 

10.5.1 Cold-side ESP, Hot-side ESP, and FF Systems 

The most cost-effective retrofit options for the control of Hg emissions from units, 

currently equipped with only an ESP or FF, include: 

•	 Injection of a sorbent upstream of a cold-side ESP or FF. Cooling of the stack gas 

and/or modifications to the ducting may be needed to keep sorbent requirements at 

acceptable levels. 

•	 Injection of a sorbent between a cold- or hot-side ESP and a pulsejet FF retrofitted 

downstream of the ESP. This approach will increase capital costs but reduce 

sorbent costs. 

•	 Installation of a semi-dry CFA upstream of an existing cold-ESP used in 

conjunction with sorbent injection. The CFA recirculates both fly ash and sorbent 

to create an entrained bed with a high number of reaction sites. This leads to higher 

sorbent utilization and enhanced fly ash capture of Hg and other pollutants. 

Units equipped with a FF require less sorbent than units equipped with an ESP. ESP 

systems depend on in-flight adsorption of Hg by entrained fly ash or sorbent particles. FFs 

obtain both in-flight and fixed-bed capture as the flue gas passes through the FF. 

10-6

In general, cost-effective sorbent injection technologies for cold-side ESP units will 

depend on: (1) the development of lower cost and/or higher performing sorbents, and (2) 

appropriate modifications to the operating conditions or equipment being currently used to 

control emissions of PM, NOX, and SO2. 

It is believed that the above technologies will be available for use on boiler units that 

must comply with the Clean Air Act hazardous air pollutant (HAP) maximum achievable control 

technology (MACT) requirements for electric utility steam-generating units. The performance 

and cost of these technologies are yet to be determined. 

10.5.2 Semi-dry FGD scrubbers 

Semi-dry FGD scrubbers are already equipped to control emissions of SO2 and PM. The 

modification of these units by the use of appropriate sorbents for the capture of Hg and other air 

toxics is considered to be the easiest retrofit problem to solve. SDA/FF systems are capable of 

higher levels of Hg control than SDA/ESP systems. 

10.5.3 Wet FGD Scrubbers 

Improvements in wet FGD scrubber performance in capturing Hg depend primarily on 

the oxidation of Hg0 to Hg2+. This may be accomplished by 1) the injection of appropriate 

oxidizing agents, or 2) the installation of fixed oxidizing catalysts upstream of the scrubber to 

promote oxidization of Hg0 to soluble Hg compounds. 

An alternative strategy for controlling Hg emissions from wet FGD scrubbing systems is 

to inject sorbents upstream of the PM control device. Better performance can be expected for 

units equipped with FFs than those equipped with ESPs. SCR systems used with wet FGD 

scrubbers may enhance Hg capture in the scrubber. 

Additional research is needed on the oxidization of Hg0 and the removal and 

sequestration of Hg collected in the scrubbing liquid. 

10.6 Costs of Retrofit Mercury Control Technologies 

Preliminary annualized costs of Hg controls using powdered activated carbon (PAC) 

injection have been estimated based on recent pilot-scale evaluations with commercially 

available sorbents. These control costs range from 0.305 to 3.783 mill/kWh, with the highest 

costs associated with plants having hot-side electrostatic precipitators (HS-ESPs). For plants 

representing approximately 89 percent of current plant capacity and using controls other than 

HS-ESPs, the costs range from 0.305 to 1.915 mill/kWh. Assuming a 40 percent reduction in 

sorbent costs by use of a composite lime-PAC sorbent for Hg removal, cost projections range 

from 0.183 to 2.27 mill/kWh, with higher costs again being associated with the plants using 

HS-ESPs. 

10-7

In comparison, the estimated annual costs of Hg controls, as a function of plant size, lie 

mostly between the costs for low-NOX burners (LNBs) and selective catalytic reduction (SCR) 

systems. The costs of Hg control will dramatically diminish if retrofit hardware and sorbents are 

employed for control of other pollutants such as NOX, SO2, or fine PM. 

The performance and cost estimates of PAC injection-based Hg control technologies 

presented in this report are based on relatively few data points from pilot-scale tests and are 

considered to be preliminary. However, based on data from pilot-scale tests and the results of 

ICR data evaluations, it is expected that better sorbents and technologies now being developed 

will reduce the costs of Hg controls beyond current estimates. 

Within the next 2-3 years, it is expected that the evaluation of retrofit technologies at 

plants where co-control is being practiced will lead to a more thorough characterization of the 

performance and costs of Hg control. Future cost studies will focus on the development of 

performance and cost information needed to: 1) refine cost estimates for sorbent injection based 

controls, 2) develop cost estimates for wet scrubbing systems that employ methods for oxidizing 

Hg0

, and 3) determine the costs of various multipollutant control options. 

The issue of Hg in many power plant residues will also be examined to address concerns 

related to the release of captured Hg species into the environment. These evaluations will be 

conducted in conjunction with the development and evaluation of air pollution emission control 

technologies. 

10.7 Coal Combustion Residues and Mercury Control 

Power plant operations result in solid discharges including fly ash, bottom ash, boiler 

slag, and FGD residues. These residues already contain Hg, presumably bound Hg that is 

relatively insoluble and non-leachable. In 1998, approximately 108 million tons of coal 

combustion residues (CCRs) were generated. Of this amount, about 77 million tons were landfilled and about 31 million tons were utilized for beneficial uses. 

Increased control of Hg emissions from coal-fired power plants may change the amount 

and composition of CCRs. Such changes may increase the potential for release of Hg to the 

environment from either land filling (approximately 70 percent) or commercial uses 

(approximately 30 percent) of CCRs. Mercury volatilization from CCRs in landfills and/or 

surface impoundments is expected to be low due to the low temperatures involved and minimal 

gas-to-solid interfaces within impacted wastes. For Hg control retrofits involving dry or wet 

FGD scrubbers, the residues are typically alkaline and the acid leaching potential of Hg from 

these residues is expected to be minimal. 

There are several commercial uses of CCR where available data on which to characterize 

the Hg emission potential are lacking. The following CCR uses are given a priority for 

developing additional data in order to characterize the ultimate fate of Hg: 

• Use of fly ash in cement production, 

10-8

• Volatilization and leaching of residues used for structural fills, 

• Leaching of residues exposed to acidic conditions during mining applications, 

•	 Volatilization of Hg during the production of wallboard from gypsum in wet 

scrubber residues, 

•	 Mercury volatilization during the production and application of asphalt with fly ash 

fillers, and 

•	 Leaching or plant uptake of Hg from fly ash, bottom ash, and FGD sludge that are 

used as soil additives. 

10.8 Current and Future Research 

It is important to continue collaborative Hg research efforts between DOE, EPA, EPRI, 

and the utility industry. The focus of these efforts should be to provide scientific and 

engineering data that support the Administration's Energy Plan and that can be used to: 

•	 Develop HAP MACT requirements for coal-fired electric utility steam generating 

units. 

•	 Optimize control of Hg emissions from units that must comply with more stringent 

NOX emission requirements under the NOX state implementation plan (SIP) call. 

•	 Develop technologies that can be used to control emissions under multipollutant 

control legislation that is under consideration by the Congress. 

Current and future research is needed to: 

• Control Hg emissions for units now equipped only with ESPs. 

•	 Develop cost-effective sorbents to control emissions from subbituminous coals and 

lignite. 

• Control Hg0 emissions from subbituminous coals and lignite. 

• Determine the effects of coal blending on Hg speciation and capture. 

•	 Evaluate the enhancement of fly-ash capture by combustion modification 

techniques. 

10-9

• Develop Hg0 oxidizing methods for wet FGD systems. 

• Optimize NOX controls for Hg control. 

• Evaluate controls for non-PC fired units. 

•	 Control Hg, SO3, and other air toxic emissions from units equipped with SCR and 

wet FGD scrubbers. 

• Demonstrate Hg control for units with SD/ESP and SD/FF. 

• Demonstrate Hg control in wet FGD systems. 

•	 Determine the effects of cyclone, stoker, and fluidized-bed combustion systems on 

Hg control. 

• Minimize the effects of Hg controls on power plant operability. 

• Conduct tests with CEMs to study the variability of Hg emissions. 

•	 Characterize and control the stability of Hg and other hazardous trace metals in 

CCRs and byproducts. 

10-10

Appendix A


Summary of Part II EPA ICR Data


Mercury Content and Selected Fuel Properties of


As-fired Coals and Supplemental Fuels


Burned in Coal-fired Electric Utility Boilers


Nationwide in 1999


Table A-1. Selected properties of anthracite coal burned in 1999.......................................... A-2


Table A-2. Selected properties of bituminous coal burned in 1999........................................ .A-2


Table A-3. Selected properties of South American bituminous coal burned in 1999 ............. A-3


Table A-4. Selected properties of subbituminous coal burned in 1999.................................. .A-3


Table A-5. Selected properties of Indonesian subbituminous coal burned in 1999................. A-4


Table A-6. Selected properties of lignite burned in 1999 ........................................................ A-4


Table A-7. Selected properties of waste anthracite coal burned in 1999................................. A-5


Table A-8. Selected properties of waste bituminous coal burned in 1999 .............................. A-5


Table A-9. Selected properties of waste subbituminous coal burned in 1999......................... A-6


Table A-10. Selected properties of petroleum coke burned in 1999.......................................... A-6


Table A-11. Selected properties of tire-derived fuel burned in 1999 ........................................ A-7


Table A-12. Comparison of mercury content by fuel type as burned in 1999 ........................... A-8


Table A-13. Comparison of mercury content with fuel heat content as burned in 1999 ........... A-9


A-1

Table A-1. Selected properties of anthracite coal burned in 1999. 

Fuel Property Range Mean Median Standard deviation 

Mercury, lb/1012 Btu dry 5.02 - 35.19 15.28 13.37 6.23 

Mercury, ppm dry 0.06 - 0.31 0.16 0.16 0.05 

Sulfur, % dry 0.44 - 2.01 0.67 0.60 0.22 

Heat content, Btu/lb dry 5,721 - 14,376 10,944 11,598 1,660 

Ash, % dry 9.86 - 56.07 24.41 20.26 10.43 

Chlorine, ppm dry 100 - 807 384.04 382.5 169.97 

Table A-2. Selected properties of bituminous coal burned in 1999. 

Fuel Property Range Mean Median Standard deviation 

Mercury, lb/1012 Btu dry 0.04 - 103.81 8.59 7.05 6.69 

Mercury, ppm drya 0.0 - 1.3 0.11 0.091 0.09 

Sulfur, % dry 0.07 -13.92 1.70 1.22 1.14 

Heat content, Btu/lb dry 8,068 - 21,503 13,196 13,181 712 

Ash, % dry 0.11 - 40.37 11.13 10.86 3.33 

Chlorine, ppm dryb 2.5 - 11,000 1,031 905 879 

(a) Includes 112 values reported at the non-detect level; 2 the non-detect level has been used in the analyses. 

(b)	 Includes 940 values reported at the non-detect level; 2 the non-detect level has been used in the analyses. 

Four analyses did not report chlorine content. 

A-2

Table A-3. Selected properties of South American bituminous coal burned in 1999. 

Fuel Property Range Mean Median Standard deviation 

Mercury, lb/1012 Btu dry Mercury, 

lb/1012 Bt d M lb/1012 

0.70 - 66.81 5.94 4.91 5.28 

Mercury, ppm dry 0.01 - 0.95 0.08 0.0642 0.07 

Sulfur, % dry 0.45 - 1.44 0.77 0.75 0.14 

Heat content, Btu/lb dry 11,515 - 17,195 13,678 13,701 490 

Ash, % dry 2.03 - 16.32 6.81 6.66 1.90 

Chlorine, ppm drya 45 - 1,521 286.71 264.5 180.91 

(a) Includes 7 values reported at the non-detect level; 2 the non-detect level has been used in the analyses. 

Table A-4. Selected properties of subbituminous coal burned in 1999. 

Fuel Property Range Mean Median Standard deviation 

Mercury, lb/1012 Btu dry 0.39 - 71.08 5.74 5.00 3.59 

Mercury, ppm drya 0.005 - 0.9 0.07 0.06 0.04 

Sulfur, % dry 0.02 - 3.12 0.48 0.45 0.25 

Heat content, Btu/lb dry 7,636 - 14,401 11,969 12,060 672 

Ash, % dry 0.43 - 31.75 7.90 7.15 3.63 

Chlorine, ppm dryb 1 - 5,800 108.51 50 235.27 

(a) Includes 193 values reported at the non-detect level; 2 the non-detect level has been used in the analyses. 

Two analyses did not report mercury content due to lost samples. 

(b) Includes 3,961 values reported at the non-detect level; 2 the non-detect level has been used in the 

analyses. One analysis did not report chlorine content. 

A-3

Table A-5. Selected properties of Indonesian subbituminous coal burned in 1999. 

Fuel Property Range Mean Median Standard deviation 

Mercury, lb/1012 Btu dry 0.79 - 4.61 2.51 2.39 0.86 

Mercury, ppm drya 0.01 - 0.05 0.03 0.03 0.01 

Sulfur, % dry 0.059 - 0.68 0.31 0.30 0.17 

Heat content, Btu/lb dry 10,840 - 13,157 12,501 12,532 337 

Ash, % dry 1.15 - 12.44 5.26 6.46 3.79 

Chlorine, ppm dryb 25 - 400 90.79 100 68.65 

(a) Includes 4 values reported at the non-detect level; 2 the non-detect level has been used in the analyses. 

(b) Includes 19 values reported at the non-detect level; 2 the non-detect level has been used in the analyses. 

Table A-6. Selected properties of lignite burned in 1999. 

Fuel Property Range Mean Median Standard deviation 

Mercury, lb/1012 Btu dry 0.93 - 75.06 10.54 7.94 9.05 

Mercury, ppm drya 0.01 - 0.75 0.10 0.08 0.09 

Sulfur, % dry 0.35 - 3.47 1.30 1.21 0.44 

Heat content, Btu/lb dry 7,022 - 11,943 10,026 10,205 784 

Ash, % dry 8.93 - 39.10 19.45 18.75 6.42 

Chlorine, ppm dryb 25 - 1,380 166.09 101.00 199.60 

(a) Includes 133 values reported at the non-detect level; 2 the non-detect level has been used in the analyses. 

(b) Includes 361 values reported at the non-detect level; 2 the non-detect level has been used in the analyses. 

A-4

Table A-7. Selected properties of waste anthracite coal burned in 1999. 

Fuel Property Range Mean Median Standard deviation 

Mercury, lb/1012 Btu dry 2.49 - 73.02 29.31 27.77 11.94 

Mercury, ppm drya 0.02 - 0.54 0.19 0.17 0.08 

Sulfur, % dry 0.25 - 1.96 0.51 0.44 0.20 

Heat content, Btu/lb dry 2,998 - 10,941 6,687 6,889 2,002 

Ash, % dry 22.34 - 72.41 49.13 47.77 12.54 

Chlorine, ppm dryb 11.6 - 1,855 231.29 102.20 241.36 

(a) Includes two values reported at the non-detect level; 2 the non-detect level has been used in the analyses. 

(b) Includes 21 values reported at the non-detect level; 2 the non-detect level has been used in the analyses. 

Table A-8. Selected properties of waste bituminous coal burned in 1999. 

Fuel Property Range Mean Median Standard deviation 

Mercury, lb/1012 Btu dry 2.47 - 172.92 60.50 53.32 44.35 

Mercury, ppm dry 0.03 - 1.18 0.46 0.45 0.30 

Sulfur, % dry 0.74 - 7.73 2.38 2.38 0.88 

Heat content, Btu/lb dry 5,194 - 13,370 8,753 7,929 2,153 

Ash, % dry 7.89 - 61.49 37.54 41.43 13.03 

Chlorine, ppm dry 29.77 - 4,277 847.92 848.00 493.75 

A-5

Table A-9. Selected properties of waste subbituminous coal burned in 1999. 

Fuel Property Range Mean Median Standard deviation 

Mercury, lb/1012 Btu dry 5.81 - 30.35 11.42 10.79 4.66 

Mercury, ppm dry 0.07 - 0.35 0.12 0.11 0.05 

Sulfur, % dry 0.83 - 3.59 1.95 1.82 0.69 

Heat content, Btu/lb dry 7,849 - 11,801 10,506 10,704 927 

Ash, % dry 11.17 - 38.52 20.53 19.35 6.40 

Chlorine, ppm drya 50 - 100 53.77 50 13.33 

(a) Includes 49 values reported at the non-detect level; 2 the non-detect level has been used in the analyses. 

Table A-10. Selected properties of petroleum coke burned in 1999. 

Fuel Property Range Mean Median Standard deviation 

Mercury, lb/1012 Btu dry 0.06 - 32.16 23.18 2.16 3.18 

Mercury, ppm drya 0.0009 - 0.5 0.045 0.03 0.05 

Sulfur, % dry 0.54 - 7.91 4.88 5.18 1.58 

Heat content, Btu/lb dry 10,892 - 16,463 15,233 15,319 439.29 

Ash, % dry 0.04 - 27.53 0.64 0.40 1.17 

Chlorine, ppm dryb 7 - 3,000 203.70 110 269.93 

(a) Includes 131 values reported at the non-detect level; 2 the non-detect level has been used in the analyses. 

(b) Includes 169 values reported at the non-detect level; 2 the non-detect level has been used in the analyses. 

A-6

Table A-11. Selected properties of tire-derived fuel burned in 1999. 

Fuel Property Range Mean Median Standard deviation 

Mercury, lb/1012 Btu dry 0.38 - 19.89 3.58 2.79 2.78 

Mercury, ppm drya 0.006 - 0.33 0.05 0.04 0.04 

Sulfur, % dry 0.86 - 2.8 1.56 1.58 0.26 

Heat content, Btu/lb dry 11,457 - 17,035 15,261 15,890 1,384 

Ash, % dry 0.75 - 23.14 7.50 5.91 4.49 

Chlorine, ppm dryb 100 - 6,483 1,059 800 933 

(a) Includes four values reported at the non-detect level; 2 the non-detect level has been used in the analyses. 

(b)	 Includes three values reported at the non-detect level; 2 the non-detect level has been used in the 

analyses. 

A-7

Table A-12. Comparison of mercury content by fuel type as burned in 1999. 

Fuel Type 

Number of 

analyses 

Mercury Concentration in Fuel (ppm) 

Range Mean Median Standard 

deviation 

Anthracite Coal 114 0.06 - 0.31 0.16 0.16 0.05 

Bituminous Coal 27,883 0.0 - 1.3 0.11 0.09 0.09 

South American 

Bituminous Coal 269 0.01 - 0.95 0.08 0.06 0.07 

Subbituminous Coal 8,190 0.005 - 0.9 0.07 0.06 0.04 

Indonesian 

Subbituminous Coal 78 0.01 - 0.05 0.03 0.03 0.01 

Lignite Coal 1,047 0.01 - 0.75 0.10 0.08 0.09 

Waste 

Anthracite Coal 377 0.02 - 0.54 0.19 0.17 0.08 

Waste 

Bituminous Coal 575 0.03 - 1.18 0.46 0.45 0.30 

Waste 

Subbituminous Coal 53 0.07 - 0.35 0.12 0.11 0.05 

Petroleum Coke 1,149 0.0009 - 0.05 0.049 0.03 0.05 

Tire-derived fuel 149 0.006 - 0.33 0.054 0.04 0.04 

A-8

Table A-13. Comparison of mercury content with fuel heat content as burned in 1999. 

Fuel Type 

Number of 

analyses 

Ratio of Mercury to Fuel Heat Content (lb Hg/trillion Btu) 

Range Mean Median Standard 

deviation 

Anthracite Coal 114 5.02 - 35.19 15.28 13.37 6.23 

Bituminous Coal 27,883 0.04 - 103.81 8.59 7.05 6.69 

South American 

Bituminous Coal 269 0.70 - 66.81 5.94 4.91 5.28 

Subbituminous Coal 8,190 0.39 - 71.08 5.74 5.00 3.59 

Indonesian 

Subbituminous Coal 78 0.79 - 4.61 2.51 2.39 0.86 

Lignite Coal 1,047 0.93 - 75.06 10.54 7.94 9.05 

Waste 

Anthracite Coal 377 2.49 - 73.02 29.31 27.77 11.94 

Waste 

Bituminous Coal 575 2.47 - 172.92 60.50 53.32 44.35 

Waste 

Subbituminous Coal 53 5.81 - 30.35 11.42 10.79 4.66 

Petroleum Coke 1,149 0.06 - 32.16 23.18 2.16 3.18 

Tire-derived fuel 149 0.38 - 19.89 3.58 2.79 2.78 

A-9

Appendix B


Background Material of Methodology Used


To Estimate 1999 National Mercury


Emissions from Coal-fired Electric


Utility Boilers


B-1





















C-1

Appendix C

Summary of Part II EPA ICR Data

Mercury Capture Efficiencies of Existing

Post-combustion Controls

Used for Coal-fired

Electric Utility Boilers

Table C-1. Post-combustion controls: cold-side ESPs ............................................................ C-2

Table C-2. Post-combustion controls: hot-side ESPs ...............................................................C-4

Table C-3. Post-combustion controls: fabric filters..................................................................C-5

Table C-4. Post-combustion controls: miscellaneous PM controls ..........................................C-6

Table C-5. Post-combustion controls: dry FGD scrubbers using ESP......................................C-7

Table C-6. Post-combustion controls: dry FGD scrubbers using FF........................................C-8

Table C-7. Post-combustion controls: wet FGD scrubbers.....................................................C-10

Table C-8. Cyclone-fired boilers.............................................................................................C-13

Table C-9. Fluidized-bed combustion.....................................................................................C-14
C-2

Table C-1. Post-combustion controls: cold-side ESPs.

(continued)

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2) : % Reduction for O-H Train and Coal Data

Plant ID Run Hgp In Hg2+ In Hg° In HgT In HgT In Hgp Out Hg2+ Out Hg° Out HGT Out %R HT %R HgT

No. O-H O-H O-H O-H Coal O-H O-H O-H O-H O-H Coal

Bituminous Coal, PC Boiler with CS-ESP

Brayton Point 1 1 2.01 3.34 0.32 5.68 6.80 0.77 3.83 0.23 4.84 14.73 28.86

Brayton Point 1 2 2.61 3.69 0.25 6.55 4.21 0.75 3.19 0.25 4.18 36.11 0.68

Brayton Point 1 3 2.17 3.50 0.26 5.93 5.01 0.77 3.02 0.24 4.02 32.19 19.64

Average 2.27 3.51 0.28 6.05 5.34 0.76 3.35 0.24 4.35 27.68 16.39

Brayton Point 3 1 3.14 3.67 0.36 7.17 8.55 0.78 3.18 0.46 4.43 38.21 48.20

Brayton Point 3 2 1.83 3.14 0.34 5.31 5.30 0.96 2.47 0.37 3.80 28.47 28.27

Brayton Point 3 3 1.40 3.26 1.60 6.26 5.58 0.01 3.43 1.70 5.15 17.70 7.71

Average 2.12 3.36 0.77 6.25 6.48 0.59 3.03 0.85 4.46 28.13 28.06

Gibson 0300 1 1.94 31.74 4.39 38.08 13.69 0.00 32.03 7.51 39.54 -3.85 -188.83

Gibson 0300 2 1.25 38.06 2.92 42.23 13.33 0.01 32.21 5.80 38.01 9.98 -185.13

Gibson 0300 3 1.75 44.44 1.65 47.85 13.53 0.01 42.87 4.17 47.05 1.66 -247.76

Average 1.65 38.08 2.99 42.72 13.52 0.01 35.70 5.83 41.54 2.60 -207.24

Gibson 1099 1 5.53 10.33 2.34 18.20 14.00 0.03 6.06 5.03 11.12 38.92 20.62

Gibson 1099 2 27.57 3.78 1.25 32.60 15.09 0.05 8.41 5.00 13.46 58.69 10.76

Gibson 1099 3 4.60 11.02 1.58 17.20 14.69 0.03 11.03 4.65 15.71 8.68 -6.93

Average 12.57 8.38 1.72 22.67 14.59 0.04 8.50 4.90 13.43 35.43 8.15

Meramec 1 7.61 0.49 0.14 8.23 8.46 0.00 0.76 0.80 1.56 81.01 81.54

Meramec 2 9.34 1.36 0.44 11.15 10.72 0.01 2.20 1.13 3.35 69.97 68.77

Meramec 3 5.65 1.93 0.62 8.19 5.89 0.00 1.51 0.79 2.30 71.96 60.99

Average 7.53 1.26 0.40 9.19 8.36 0.00 1.49 0.91 2.40 74.32 70.43

Jack Watson 1 3.60 1.22 0.92 5.74 4.70 0.05 2.57 1.87 4.49 21.71 4.39

Jack Watson 2 4.91 1.16 0.25 6.32 5.67 0.05 2.99 0.89 3.94 37.70 30.53

Jack Watson 3 4.64 0.60 0.23 5.46 6.20 0.06 2.92 0.89 3.88 29.04 37.45

Average 4.38 0.99 0.47 5.84 5.52 0.05 2.83 1.22 4.10 29.48 24.13

Widows Creek 1 3.36 0.44 0.54 4.34 3.11 0.14 1.48 0.78 2.40 44.75 22.95

Widows Creek 2 2.98 0.45 0.51 3.94 2.67 0.01 1.28 0.68 1.97 50.00 26.25

Widows Creek 3 2.87 0.47 0.50 3.83 2.15 0.01 0.65 0.67 1.34 65.11 37.81

Average 3.07 0.45 0.51 4.04 2.64 0.06 1.14 0.71 1.90 53.29 29.00

Average 4.80 8.00 1.02 13.82 8.06 0.22 8.00 2.09 10.31 35.85 -4.44

Minimum 1.25 0.44 0.14 3.83 2.15 0.00 0.65 0.23 1.34 -3.85 -247.76

Maximum 27.57 44.44 4.39 47.85 15.09 0.96 42.87 7.51 47.05 81.01 81.54

STDEV 5.62 13.05 1.09 13.86 4.35 0.34 12.01 2.24 13.67 23.90 88.31

Bituminous Coal and Pet Coke, PC Boiler with CS-ESP

Presque Isle 5 1 4.56 0.48 0.14 5.17 4.27 0.01 0.72 1.06 1.80 65.29 57.92

Presque Isle 5 2 3.60 0.66 0.57 4.82 3.48 0.00 0.82 1.02 1.84 61.87 47.14

Presque Isle 5 3 5.06 0.45 0.12 5.63 3.93 0.02 0.71 0.91 1.64 70.84 58.19

Average 4.40 0.53 0.27 5.21 3.89 0.01 0.75 1.00 1.76 66.00 54.42

Presque Isle 6 1 2.73 0.63 0.17 3.52 2.29 0.06 0.84 0.70 1.60 54.54 30.10

Presque Isle 6 2 2.97 0.72 0.25 3.94 4.34 0.03 1.00 0.93 1.96 50.29 54.87

Presque Isle 6 3 2.96 0.62 0.17 3.75 3.85 0.03 0.73 0.81 1.57 58.00 59.17

Average 2.89 0.65 0.20 3.74 3.49 0.04 0.86 0.81 1.71 54.28 48.05

Average 3.65 0.59 0.24 4.47 3.69 0.02 0.81 0.90 1.73 60.14 51.23

Minimum 2.73 0.45 0.12 3.52 2.29 0.00 0.71 0.70 1.57 50.29 30.10

Maximum 5.06 0.72 0.57 5.63 4.34 0.06 1.00 1.06 1.96 70.84 59.17

STDEV 0.96 0.11 0.17 0.86 0.75 0.02 0.11 0.13 0.15 7.44 11.25
C-3

Table C-1. (continued).

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2) : % Reduction for O-H Train and Coal Data

Plant ID Run Hgp In Hg2+ In Hg° In HgT In HgT In Hgp Out Hg2+ Out Hg° Out HGT Out %R HT %R HgT

No. O-H O-H O-H O-H Coal O-H O-H O-H O-H O-H Coal

Bituminous Coal, PC Boiler with SNCR and CS-ESP

Salem Harbor 1 4.12 0.32 0.32 4.76 3.44 0.07 0.28 0.27 0.62 87.07 82.11

Salem Harbor 2 4.09 0.04 0.16 4.29 2.35 0.10 0.07 0.15 0.32 92.57 86.40

Salem Harbor 3 3.96 0.06 0.15 4.17 3.27 0.08 0.08 0.14 0.29 93.06 91.16

Average 4.06 0.14 0.21 4.41 3.02 0.08 0.14 0.19 0.41 90.90 86.55

Subbituminous Coal, PC Boiler with CS-ESP

Montrose 1 1.94 1.85 6.00 9.79 44.90 0.03 2.57 5.48 8.08 17.46 82.01

Montrose 2 0.91 2.52 4.93 8.36 51.99 0.02 2.60 5.94 8.56 -2.31 83.54

Montrose 3 1.63 2.85 4.68 9.16 47.76 0.02 2.30 5.69 8.01 12.54 83.22

Average 1.49 2.41 5.20 9.10 48.21 0.02 2.49 5.70 8.22 9.23 82.92

George Neal So. 1 0.17 4.78 6.34 11.29 8.96 0.03 4.07 5.47 9.58 15.18 -6.90

George Neal So. 2 0.07 4.35 8.24 12.66 7.82 0.06 4.60 6.87 11.53 8.89 -47.37

George Neal So. 3 0.02 3.53 3.77 7.32 10.19 0.02 4.74 6.39 11.15 -52.29 -9.36

Average 0.09 4.22 6.12 10.42 8.99 0.04 4.47 6.24 10.75 12.04 -21.21

Newton 1 0.04 0.58 9.70 10.32 9.07 0.00 2.26 8.07 10.33 -0.10 -14.00

Newton 2 0.04 0.63 9.85 10.52 8.05 0.00 1.66 7.13 8.80 16.33 -9.28

Newton 3 0.08 1.65 9.26 11.00 9.34 0.00 2.04 8.03 10.07 8.46 -7.82

Average 0.05 0.95 9.61 10.61 8.82 0.00 1.99 7.74 9.73 8.23 -10.36

Average 0.54 2.53 6.98 10.05 22.01 0.02 2.98 6.56 9.57 2.69 17.12

Minimum 0.02 0.58 3.77 7.32 7.82 0.00 1.66 5.47 8.01 -52.29 -47.37

Maximum 1.94 4.78 9.85 12.66 51.99 0.06 4.74 8.07 11.53 17.46 83.54

STDEV 0.76 1.50 2.34 1.61 19.75 0.02 1.16 1.02 1.30 21.75 50.89

SPF 0.05 0.25 0.69 1.00 1.00 0.00 0.31 0.69 1.00

Subbituminous/ Bituminous Coal, PC Boiler with CS-ESP

St Clair 1 2.53 2.29 1.97 6.79 16.26 0.01 1.35 3.01 4.37 35.63 73.13

St Clair 2 2.87 2.13 1.40 6.39 14.36 0.01 1.39 3.74 5.14 19.65 64.24

St Clair 3 0.98 1.94 4.28 7.20 17.71 0.01 1.33 5.24 6.57 8.71 62.89

Average 2.13 2.12 2.55 6.79 16.11 0.01 1.35 4.00 5.36 21.33 66.75

Lignite, PC Boiler with CS-ESP

Stanton 1 1 0.04 0.15 11.96 12.15 31.51 0.04 0.42 11.16 11.62 4.42 63.13

Stanton 1 2 0.13 0.13 10.81 11.06 41.24 0.02 0.43 11.68 12.14 -9.70 70.56

Stanton 1 3 0.08 0.05 11.66 11.79 19.94 0.01 0.45 11.97 12.43 -5.41 37.67

Average 0.08 0.11 11.48 11.67 30.89 0.02 0.44 11.60 12.06 -3.57 57.12
C-4

Table C-2. Post-combustion controls: hot-side ESPs.

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2) : % Reduction for O-H Train and Coal Data

Plant ID Run Hgp In Hg2+ In Hg° In HgT In HgT In Hgp Out Hg2+ Out Hg° Out HGT Out %R HT %R HgT

No. O-H O-H O-H O-H Coal O-H O-H O-H O-H O-H Coal

Bituminous Coal, PC Boiler with HS-ESP

Cliffside 1 0.17 3.72 3.31 7.20 5.43 0.41 2.79 3.95 7.14 0.86 -31.58

Cliffside 2 0.09 3.54 3.33 6.95 3.84 0.10 2.27 1.95 4.31 38.00 -12.17

Cliffside 3 0.08 4.15 7.27 11.49 8.80 0.10 3.97 2.54 6.61 42.51 24.94

Average 0.11 3.80 4.63 8.55 6.02 0.20 3.01 2.81 6.02 27.12 -6.27

Gaston 1 4.28 0.86 2.64 7.77 5.20 0.74 4.70 2.34 7.78 -0.19 -49.56

Gaston 2 2.57 0.71 3.56 6.84 6.27 0.40 5.80 3.47 9.66 -41.37 -54.19

Gaston 3 0.43 3.94 2.83 7.20 4.70 1.15 4.73 2.04 7.92 -10.00 -68.41

Average 2.42 1.84 3.01 7.27 5.39 0.76 5.08 2.62 8.46 -17.19 -57.39

Dunkirk 1 0.09 8.56 2.82 11.47 10.06 0.21 6.89 3.67 10.77 6.08 -7.09

Dunkirk 2 0.01 8.91 1.43 10.36 10.30 0.08 4.57 2.46 7.12 31.27 30.90

Dunkirk 3 0.01 9.15 3.20 12.36 9.65 0.03 6.40 3.82 10.25 17.08 -6.26

Average 0.04 8.87 2.48 11.40 10.00 0.11 5.95 3.32 9.38 18.14 5.85

Average 0.86 4.84 3.38 9.07 7.14 0.36 4.68 2.92 7.95 9.36 -19.27

Minimum 0.01 0.71 1.43 6.84 3.84 0.03 2.27 1.95 4.31 -41.37 -68.41

Maximum 4.28 9.15 7.27 12.36 10.30 1.15 6.89 3.95 10.77 42.51 30.90

STDEV 1.52 3.28 1.59 2.30 2.55 0.37 1.54 0.80 2.02 26.41 34.54

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2) : % Reduction for O-H Train and Coal Data

Plant ID Run Hgp In Hg2+ In Hg° In HgT In HgT In Hgp Out Hg2+ Out Hg° Out HGT Out %R HT %R HgT

No. O-H O-H O-H O-H Coal O-H O-H O-H O-H O-H Coal

Subbituminous Coal, PC Boiler (Dry Bottom) with HS-ESP

Cholla 3 1 0.07 0.37 1.93 2.37 51.98 0.01 0.51 1.87 2.40 -1.30 95.39

Cholla 3 2 0.51 0.32 0.46 1.28 54.43 0.01 0.01 1.00 1.02 20.42 98.12

Cholla 3 3 0.45 0.43 0.61 1.49 40.48 0.01 0.39 1.27 1.67 -12.28 95.87

Average 0.34 0.37 1.00 1.71 48.96 0.01 0.30 1.38 1.70 2.28 96.46

Columbia 1 0.01 0.93 14.27 15.22 9.85 0.00 2.74 11.71 14.45 5.02 -46.78

Columbia 2 0.01 5.82 13.40 19.24 10.30 0.00 2.16 11.82 13.98 27.34 -35.71

Columbia 3 0.01 0.46 14.65 15.12 10.35 0.00 2.65 12.68 15.34 -1.47 -48.18

Average 0.01 2.41 14.11 16.52 10.17 0.00 2.51 12.07 14.59 10.30 -43.56

Average 0.18 1.39 7.55 9.12 29.57 0.01 1.41 6.73 8.14 6.29 26.45

Minimum 0.01 0.32 0.46 1.28 9.85 0.00 0.01 1.00 1.02 -12.28 -48.18

Maximum 0.51 5.82 14.65 19.24 54.43 0.01 2.74 12.68 15.34 27.34 98.12

STDEV 0.23 2.18 7.21 8.26 21.77 0.00 1.24 5.87 7.09 14.88 76.82

Subbituminous Coal, PC Boiler (Wet Bottom) with HS-ESP

Platte 1 0.03 4.15 9.82 14.00 11.10 0.01 1.45 8.76 10.23 26.93 7.88

Platte 2 0.02 1.92 11.31 13.25 9.65 0.01 0.78 16.86 17.65 -33.20 -82.85

Platte 3 0.03 4.39 11.63 16.04 6.05 0.01 1.51 14.90 16.43 -2.40 -171.57

Average 0.03 3.48 10.92 14.43 8.93 0.01 1.25 13.51 14.77 -2.89 -82.18

Presque Isle 9 1 0.04 0.14 6.70 6.89 9.86 0.00 0.57 6.30 6.88 0.10 30.22

Presque Isle 9 2 0.01 0.14 6.89 7.05 8.92 0.00 0.67 6.74 7.41 -5.23 16.87

Presque Isle 9 3 0.01 0.10 6.43 6.55 9.91 0.00 0.54 6.38 6.92 -5.76 30.11

Average 0.02 0.13 6.68 6.83 9.56 0.00 0.59 6.47 7.07 -3.63 25.73

Average 0.02 1.80 8.80 10.63 9.25 0.01 0.92 9.99 10.92 -3.26 -28.22

Minimum 0.01 0.10 6.43 6.55 6.05 0.00 0.54 6.30 6.88 -33.20 -171.57

Maximum 0.04 4.39 11.63 16.04 11.10 0.01 1.51 16.86 17.65 26.93 30.22

STDEV 0.01 2.03 2.41 4.27 1.72 0.01 0.44 4.69 4.91 19.13 82.08

Subbituminous/Bituminous Coal, PC Boiler with HS-ESP

Clifty 3 0.01 3.41 11.46 14.87 7.84 0.07 5.50 3.80 9.37 36.99 -19.53

Clifty 1 0.40 2.35 11.17 13.92 8.02 0.70 3.60 4.67 8.96 35.58 -11.78

Clifty 2 0.02 3.58 11.13 14.73 7.66 0.01 5.04 5.34 10.39 29.51 -35.57

Average 0.14 3.11 11.25 14.51 7.84 0.26 4.71 4.60 9.57 34.03 -22.29
C-5

Table C-3. Post-combustion controls: fabric filters.

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2) : % Reduction for O-H Train and Coal Data

Plant ID Run Hgp In Hg2+ In Hg° In HgT In HgT In Hgp Out Hg2+ Out Hg° Out HGT Out %R HT %R HgT

No. O-H O-H O-H O-H Coal O-H O-H O-H O-H O-H Coal

Bituminous Coal, PC Boiler with FF

Sammis 1 11.78 0.48 0.61 12.86 6.64 0.01 0.49 0.61 1.11 91.37 83.28

Sammis 2 15.35 0.50 0.54 16.38 9.54 0.01 0.58 0.55 1.14 93.04 88.05

Sammis 3 14.62 0.51 0.52 15.65 9.55 0.02 0.51 0.57 1.10 92.97 88.48

Average 13.92 0.50 0.55 14.97 8.58 0.01 0.53 0.57 1.12 92.46 86.60

Valmont 1 0.92 0.12 0.18 1.22 0.80 0.00 0.12 0.04 0.16 86.98 80.04

Valmont 2 0.92 0.07 0.14 1.12 0.44 0.00 0.10 0.02 0.12 89.53 73.26

Valmont 3 1.23 0.10 0.17 1.51 0.60 0.00 0.21 0.03 0.24 84.15 60.16

Average 1.02 0.10 0.17 1.29 0.61 0.00 0.14 0.03 0.17 86.89 71.16

Average 7.47 0.30 0.36 8.13 4.59 0.01 0.34 0.30 0.64 89.67 78.88

Minimum 0.92 0.07 0.14 1.12 0.44 0.00 0.10 0.02 0.12 84.15 60.16

Maximum 15.35 0.51 0.61 16.38 9.55 0.02 0.58 0.61 1.14 93.04 88.48

STDEV 7.16 0.22 0.22 7.59 4.49 0.01 0.22 0.30 0.52 3.54 10.76

Bituminous Coal/Pet. Coke, PC Boiler with FF (Measurements not valid, disregard)

Valley 1 0.04 1.44 1.21 2.69 0.95 0.11 2.02 0.41 2.54 5.67 -165.84

Valley 2 0.05 1.49 0.45 1.99 1.33 0.04 1.55 0.42 2.00 -0.70 -50.84

Valley 3 0.04 1.22 0.67 1.92 1.52 0.00 1.89 0.52 2.41 -25.15 -58.75

Average 0.04 1.38 0.78 2.20 1.27 0.05 1.82 0.45 2.31 -6.73 -91.81

Bituminous/Subbituminous Coal, PC Boiler with FF

Shawnee 1 3.18 0.58 0.72 4.48 2.39 0.01 0.63 0.84 1.49 66.73 37.66

Shawnee 2 3.01 0.98 0.66 4.65 4.29 0.02 0.61 0.75 1.37 70.51 68.03

Shawnee 3 3.44 0.57 0.67 4.68 2.66 0.01 0.60 0.68 1.28 72.62 51.82

Average 3.21 0.71 0.68 4.61 3.11 0.01 0.61 0.76 1.38 69.95 52.50

Subbituminous Coal, PC Boiler with FF

Boswell 2 2 1.99 1.26 1.46 4.71 4.35 0.00 0.35 0.23 0.59 87.45 86.43

Boswell 2 3 0.83 1.15 2.49 4.46 5.20 0.00 0.58 0.12 0.70 84.32 86.54

Boswell 2 1 2.75 1.81 1.60 6.16 8.35 0.07 1.26 0.14 1.47 76.06 82.34

Average 1.85 1.41 1.85 5.11 5.97 0.03 0.73 0.16 0.92 82.61 85.10

Comanche 1 1.81 3.93 5.71 11.46 15.91 0.00 3.33 0.27 3.60 68.58 77.37

Comanche 3 5.27 1.28 3.67 10.22 14.24 0.00 3.20 0.33 3.52 65.52 75.26

Comanche 2 2.59 1.45 5.77 9.82 17.08 0.00 3.99 0.65 4.65 52.67 72.80

Average 3.23 2.22 5.05 10.50 15.74 0.00 3.51 0.42 3.92 62.26 75.14

Average 2.54 1.81 3.45 7.80 10.86 0.01 2.12 0.29 2.42 72.43 80.12

Minimum 0.83 1.15 1.46 4.46 4.35 0.00 0.35 0.12 0.59 52.67 72.80

Maximum 5.27 3.93 5.77 11.46 17.08 0.07 3.99 0.65 4.65 87.45 86.54

STDEV 1.50 1.06 1.94 3.06 5.59 0.03 1.57 0.20 1.72 12.91 5.85
C-6

Table C-4. Post-combustion controls: miscellaneous PM controls.

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2) : % Reduction for O-H Train and Coal Data

Plant ID Run Hgp In Hg2+ In Hg° In HgT In HgT In Hgp Out Hg2+ Out Hg° Out HGT Out %R HT %R HgT

No. O-H O-H O-H O-H Coal O-H O-H O-H O-H O-H Coal

TX Lignite, PC Boiler with CS-ESP and FF (COHPAC)

Bigbrown 1 2.59 8.35 31.24 42.18 50.86 0.01 16.58 25.20 41.80 0.92 17.82

Bigbrown 2 0.54 10.37 27.31 38.21 49.95 0.01 17.66 25.47 43.13 -12.88 13.65

Bigbrown 3 0.14 14.14 21.93 36.21 46.92 0.01 18.49 22.12 40.62 -12.20 13.42

Average 1.09 10.95 26.83 38.87 49.24 0.01 17.58 24.26 41.85 -7.68 14.96

Monticello 1-2 1 15.97 22.54 8.82 47.34 53.79 0.17 32.01 1.58 33.76 28.69 37.23

Monticello 1-2 2 0.37 14.82 46.29 61.48 54.09 0.11 78.08 14.93 93.11 -51.46 -72.13

Monticello 1-2 3 7.97 22.74 44.19 74.90 84.65 0.08 86.89 18.51 105.48 -40.84 -24.61

Average 8.10 20.03 33.10 61.24 64.18 0.12 65.66 11.67 77.45 -21.20 -19.83

Average 4.60 15.49 29.96 50.05 56.71 0.07 41.62 17.97 59.65 -13.63 -2.44

Minimum 0.14 8.35 8.82 36.21 46.92 0.01 16.58 1.58 33.76 -51.46 -72.13

Maximum 15.97 22.74 46.29 74.90 84.65 0.17 86.89 25.47 105.48 28.69 37.23

STDEV 6.31 6.03 14.07 15.16 13.94 0.07 32.27 8.99 31.13 26.49 39.61

Subbituminous Coal, PC Boiler with PM Scrubber

Boswell 3 1 0.01 0.25 6.06 6.32 5.00 0.00 0.05 5.82 5.87 7.16 -17.51

Boswell 3 2 0.01 0.31 6.00 6.32 6.38 0.00 0.06 5.39 5.45 13.81 14.54

Boswell 3 3 0.06 0.62 5.21 5.89 5.79 0.00 0.06 5.51 5.58 5.25 3.60

Average 0.03 0.39 5.76 6.18 5.72 0.00 0.06 5.57 5.63 8.74 0.21
C-7

Table C-5. Post-combustion controls: dry FGD scrubbers using ESP.

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2) : % Reduction for O-H Train and Coal Data

Plant ID Run Hgp In Hg2+ In Hg° In HgT In HgT In Hgp Out Hg2+ Out Hg° Out HGT Out %R HT %R HgT

No. O-H O-H O-H O-H Coal O-H O-H O-H O-H O-H Coal

Bituminous Coal, PC Boiler with DSI/CS-ESP

Washington 1 0.00 4.33 11.63 15.97 13.01 0.00 6.41 3.06 9.47 40.68 27.22

Washington 2 0.00 7.75 11.02 18.77 13.36 0.00 5.84 3.05 8.90 52.61 33.42

Washington 3 0.00 6.40 9.95 16.36 13.33 0.04 6.52 3.04 9.59 41.37 28.06

Average 0.00 6.16 10.86 17.03 13.24 0.02 6.26 3.05 9.32 44.89 29.56

Subbituminous Coal, PC Boiler with SDA/CS-ESP

GRDA 1 0.13 4.42 7.77 12.31 11.22 0.01 1.55 5.58 7.13 42.06 36.42

GRDA 2 0.53 2.97 6.50 9.99 10.73 0.01 1.28 11.12 12.42 -24.23 -15.70

GRDA 3 0.51 8.78 3.71 13.01 12.24 0.01 0.34 5.41 5.76 55.72 52.94

Average 0.39 5.39 5.99 11.77 11.40 0.01 1.06 7.37 8.44 24.51 24.55

Laramie 3 1 0.03 0.22 0.63 0.88 15.03 0.03 0.10 3.87 4.00 0.00 73.40

Laramie 3 2 1.69 0.52 8.53 10.75 17.67 0.03 0.04 4.52 4.58 57.35 74.05

Laramie 3 3 4.55 0.44 9.28 14.27 14.94 0.03 0.04 5.27 5.35 62.53 64.22

Average 2.09 0.39 6.15 8.63 15.88 0.03 0.06 4.56 4.64 39.96 70.56

Wyodak 1 2.49 3.88 11.63 18.00 4.46 0.05 0.07 9.97 10.09 43.95 -126.38

Wyodak 2 3.05 4.71 9.42 17.17 6.41 0.05 0.17 10.11 10.32 39.87 -61.16

Wyodak 3 2.25 3.57 11.51 17.34 8.17 0.05 0.25 10.11 10.41 39.99 -27.41

Average 2.60 4.05 10.85 17.50 6.34 0.05 0.16 10.06 10.27 41.27 -71.65

Average 1.69 3.28 7.67 12.64 11.21 0.03 0.43 7.33 7.78 35.25 7.82

Minimum 0.03 0.22 0.63 0.88 4.46 0.01 0.04 3.87 4.00 -24.23 -126.38

Maximum 4.55 8.78 11.63 18.00 17.67 0.05 1.55 11.12 12.42 62.53 74.05

STDEV 1.54 2.72 3.60 5.28 4.32 0.02 0.57 2.91 3.06 28.72 70.07
C-8

Table C-6. Post-combustion controls: dry FGD scrubbers using FF.

(continued)

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2) : % Reduction for O-H Train and Coal Data

Plant ID Run Hgp In Hg2+ In Hg° In HgT In HgT In Hgp Out Hg2+ Out Hg° Out HGT Out %R HT %R HgT

No. O-H O-H O-H O-H Coal O-H O-H O-H O-H O-H Coal

Bituminous Coal, PC Boiler with SDA/FF

Mecklenburg 1 11.34 3.40 6.16 20.91 11.52 0.00 0.07 0.09 0.16 99.23 98.60

Mecklenburg 2 5.66 4.21 0.02 9.89 13.28 0.00 0.07 0.23 0.31 96.91 97.70

Mecklenburg 3 6.90 3.04 0.02 9.96 11.50 0.00 0.01 0.23 0.24 97.60 97.92

Average 7.97 3.55 2.07 13.59 12.10 0.00 0.05 0.18 0.24 97.91 98.07

Bituminous Coal, PC Boiler with SCR and SDA/FF

Logan 1 12.87 7.22 0.21 20.31 18.28 0.02 0.08 0.16 0.26 98.71 98.57

Logan 2 12.74 4.36 0.35 17.46 18.14 0.02 0.13 0.17 0.32 98.16 98.23

Logan 3 12.45 4.59 0.25 17.29 17.51 0.01 0.04 0.17 0.22 98.72 98.74

Average 12.69 5.39 0.27 18.35 17.98 0.02 0.09 0.16 0.27 98.53 98.51

SEI 1 13.48 0.30 0.14 13.92 11.79 0.01 0.34 0.13 0.48 96.56 95.94

SEI 2 9.47 0.25 0.18 9.90 11.74 0.01 0.09 0.12 0.22 97.79 98.13

SEI 3 12.01 0.25 0.16 12.42 11.97 0.02 0.08 0.11 0.21 98.34 98.28

Average 11.66 0.26 0.16 12.08 11.83 0.01 0.17 0.12 0.30 97.56 97.45

Average 12.17 2.83 0.22 15.22 14.90 0.02 0.13 0.14 0.28 98.05 97.98

Minimum 9.47 0.25 0.14 9.90 11.74 0.01 0.04 0.11 0.21 96.56 95.94

Maximum 13.48 7.22 0.35 20.31 18.28 0.02 0.34 0.17 0.48 98.72 98.74

STDEV 1.41 2.98 0.08 3.82 3.38 0.00 0.11 0.03 0.10 0.81 1.03

Subbituminous Coal, PC Boiler with SDA/FF

Craig 3 1 0.57 0.65 0.20 1.42 1.20 0.00 0.04 0.90 0.94 33.79 21.49

Craig 3 2 0.92 0.50 0.17 1.60 1.06 0.00 0.04 0.89 0.93 41.83 11.88

Craig 3 3 0.90 0.23 0.12 1.25 0.93 0.00 0.03 0.82 0.86 31.67 7.38

Average 0.80 0.46 0.16 1.42 1.06 0.00 0.04 0.87 0.91 35.76 13.58

Rawhide 1 0.25 1.38 12.46 14.09 8.09 0.12 0.76 10.80 11.68 17.16 -44.36

Rawhide 2 1.92 0.83 12.85 15.59 7.33 0.01 0.69 9.91 10.60 32.03 -44.61

Rawhide 3 3.76 0.46 14.79 19.01 9.24 0.03 0.98 9.00 10.01 47.31 -8.41

Average 1.98 0.89 13.37 16.23 8.22 0.05 0.81 9.90 10.76 32.16 -32.46

NSP Sherburne 1 0.03 0.53 10.92 11.48 8.29 0.12 0.20 8.42 8.74 23.81 -5.43

NSP Sherburne 2 0.03 0.23 10.92 11.18 8.27 0.14 0.18 12.09 12.40 -10.94 -49.92

NSP Sherburne 3 0.03 0.19 10.24 10.46 7.73 0.27 0.24 9.84 10.35 1.05 -34.01

Average 0.03 0.32 10.69 11.04 8.10 0.18 0.20 10.12 10.50 4.64 -29.78

Average 0.93 0.56 8.07 9.56 5.79 0.08 0.35 6.96 7.39 24.19 -16.22

Minimum 0.03 0.19 0.12 1.25 0.93 0.00 0.03 0.82 0.86 -10.94 -49.92

Maximum 3.76 1.38 14.79 19.01 9.24 0.27 0.98 12.09 12.40 47.31 21.49

STDEV 1.23 0.37 6.08 6.63 3.59 0.09 0.36 4.68 4.97 18.96 27.38
C-9

Table C-6. (continued).

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2) : % Reduction for O-H Train and Coal Data

Plant ID Run Hgp In Hg2+ In Hg° In HgT In HgT In Hgp Out Hg2+ Out Hg° Out HGT Out %R HT %R HgT

No. O-H O-H O-H O-H Coal O-H O-H O-H O-H O-H Coal

ND Lignite, PC Boiler with SDA/FF

Antelope Valley 1 0.16 0.38 7.80 8.34 13.85 0.01 0.25 omit NA NA NA

Antelope Valley 2 0.21 0.42 7.82 8.45 16.03 0.02 0.79 8.16 8.98 -6.27 44.01

Antelope Valley 3 0.16 0.16 7.67 8.00 12.50 0.02 0.33 6.97 7.32 8.49 41.45

Average 0.18 0.29 7.75 8.22 14.27 0.02 0.56 7.56 8.15 1.11 42.73

Stanton 10 1 0.22 0.24 10.23 10.70 12.82 0.02 0.40 10.14 10.56 1.24 17.63

Stanton 10 2 0.27 0.36 9.86 10.49 15.63 0.01 0.17 10.58 10.76 -2.54 31.15

Stanton 10 3 0.50 0.69 9.45 10.64 9.45 0.01 0.01 10.81 10.83 -1.77 -14.61

Average 0.33 0.43 9.85 10.61 12.63 0.01 0.19 10.51 10.72 -1.02 11.39

Average 0.27 0.38 9.01 9.65 13.29 0.02 0.34 9.33 9.69 -0.17 23.93

Minimum 0.16 0.16 7.67 8.00 9.45 0.01 0.01 6.97 7.32 -6.27 -14.61

Maximum 0.50 0.69 10.23 10.70 16.03 0.02 0.79 10.81 10.83 8.49 44.01

STDEV 0.13 0.20 1.18 1.32 2.67 0.01 0.29 1.69 1.53 5.53 23.91

Bituminous, Stoker with SDA/FF

Dwayne Collier 1 2.19 0.03 0.06 2.28 3.37 0.06 0.02 0.08 0.16 92.84 95.16

Dwayne Collier 2 2.14 0.18 0.42 2.75 3.48 0.03 0.03 0.09 0.15 94.48 95.64

Dwayne Collier 3 1.99 0.03 0.11 2.13 3.29 0.01 0.03 0.06 0.10 95.43 97.04

Average 2.11 0.08 0.20 2.39 3.38 0.03 0.03 0.08 0.14 94.25 95.95
C-10

Table C-7. Post-combustion controls: wet FGD scrubbers.

(continued)

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2) : % Reduction for O-H Train and Coal Data

Plant ID Run Hgp In Hg2+ In Hg° In HgT In HgT In Hgp Out Hg2+ Out Hg° Out HGT Out %R HT %R HgT

No. O-H O-H O-H O-H Coal O-H O-H O-H O-H O-H Coal

Bituminous Coal, PC Boiler with PS and Wet FGD Scrubber

Bruce Mansfield 1 0.27 8.65 1.58 10.50 10.93 0.04 1.89 7.01 8.95 14.81 18.11

Bruce Mansfield 2 0.73 9.84 2.08 12.65 8.93 0.06 2.73 7.96 10.76 14.94 -20.57

Bruce Mansfield 3 0.27 8.34 1.70 10.31 11.82 0.04 1.22 8.29 9.55 7.42 19.25

Average 0.42 8.94 1.79 11.15 10.56 0.05 1.95 7.76 9.75 12.39 5.60

Subbituminous Coal, PC Boiler with PS and Wet FGD Scrubber

Boswell 4 1 0.11 0.33 5.05 5.48 6.98 0.02 0.10 5.53 5.65 -3.08 19.00

Boswell 4 2 2.98 1.07 1.47 5.53 6.63 0.20 0.44 5.89 6.53 -18.25 1.41

Boswell 4 3 2.75 0.55 1.16 4.45 7.93 0.28 0.59 5.57 6.43 -44.40 18.91

Average 1.95 0.65 2.56 5.15 7.18 0.17 0.38 5.66 6.21 -21.91 13.11

Cholla 2 1 0.42 0.97 4.68 6.07 6.99 0.15 0.21 3.93 4.29 29.30 38.59

Cholla 2 2 1.11 0.93 2.62 4.66 6.37 0.19 0.14 4.67 5.01 -7.51 21.38

Cholla 2 3 0.41 2.06 2.99 5.46 5.09 0.11 0.14 4.22 4.46 18.29 12.27

Average 0.65 1.32 3.43 5.40 6.15 0.15 0.16 4.27 4.59 13.36 24.08

Colstrip 1 1.78 2.29 1.08 5.15 7.63 0.05 0.42 9.13 9.60 -86.54 -25.89

Colstrip 2 1.94 2.37 6.37 10.68 7.98 0.02 0.45 11.03 11.51 -7.74 -44.19

Colstrip 3 1.63 2.86 5.39 9.88 7.93 0.02 0.39 2.13 2.54 74.27 67.94

Average 1.78 2.51 4.28 8.57 7.85 0.03 0.42 7.43 7.88 -6.67 -0.71

Lawrence 1 0.23 1.65 4.99 6.86 6.24 0.01 0.49 6.37 6.87 -0.07 -10.01

Lawrence 2 0.53 0.63 4.41 5.58 5.47 0.08 0.53 6.71 7.32 -31.14 -33.75

Lawrence 3 0.24 0.65 4.96 5.86 6.03 0.09 0.51 6.20 6.81 -16.21 -12.96

Average 0.33 0.98 4.79 6.10 5.91 0.06 0.51 6.42 7.00 -15.81 -18.91

Average 1.18 1.36 3.76 6.30 6.77 0.10 0.37 5.95 6.42 -7.76 4.39

Minimum 0.11 0.33 1.08 4.45 5.09 0.01 0.10 2.13 2.54 -86.54 -44.19

Maximum 2.98 2.86 6.37 10.68 7.98 0.28 0.59 11.03 11.51 74.27 67.94

STDEV 1.02 0.85 1.82 1.96 0.98 0.09 0.17 2.34 2.40 39.47 31.96

ND Lignite, PC Boiler with PS and Wet FGD Scrubber

Lewis and Clark 1 1.15 16.47 11.65 29.27 15.33 0.06 0.50 13.86 14.42 50.75 5.98

Lewis and Clark 2 1.68 13.64 8.43 23.75 15.54 0.00 0.35 14.19 14.55 38.74 6.41

Lewis and Clark 3 1.41 6.28 10.20 17.89 18.96 0.00 0.50 15.81 16.31 8.81 13.94

Average 1.41 12.13 10.09 23.64 16.61 0.02 0.45 14.62 15.09 32.77 8.78
C-11

Table C-7. (continued).

(continued)

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2) : % Reduction for O-H Train and Coal Data

Plant ID Run Hgp In Hg2+ In Hg° In HgT In HgT In Hgp Out Hg2+ Out Hg° Out HGT Out %R HT %R HgT

No. O-H O-H O-H O-H Coal O-H O-H O-H O-H Wet FGD PM+FGD

Bituminous Coal, PC Boiler with CS-ESP and wet FGD Scrubber

AES Cayuga 2 0.00 6.40 2.58 8.98 11.87 0.00 0.18 2.70 2.88 67.91 76.06

AES Cayuga 1 0.00 5.87 2.24 8.11 10.70 0.00 0.36 2.73 3.09 61.88 71.56

AES Cayuga 3 0.00 5.55 2.95 8.50 10.80 0.00 0.18 3.08 3.26 61.63 71.38

Average 0.00 5.94 2.59 8.53 11.12 0.00 0.24 2.83 3.08 63.81 73.00

Big Bend 1 0.09 4.86 2.40 7.34 17.52 0.05 0.21 2.18 2.44 66.70 75.16

Big Bend 2 0.05 4.92 2.31 7.29 11.25 0.00 0.12 1.75 1.87 74.37 80.88

Big Bend 3 0.02 4.26 2.13 6.41 12.01 0.03 0.23 2.05 2.31 64.01 73.15

Average 0.05 4.68 2.28 7.01 13.59 0.03 0.19 1.99 2.21 68.36 76.39

Average 0.03 5.31 2.43 7.77 12.36 0.01 0.22 2.41 2.64 66.08 74.70

Minimum 0.00 4.26 2.13 6.41 10.70 0.00 0.12 1.75 1.87 61.63 71.38

Maximum 0.09 6.40 2.95 8.98 17.52 0.05 0.36 3.08 3.26 74.37 80.88

STDEV 0.03 0.78 0.30 0.94 2.59 0.02 0.08 0.50 0.53 4.78 3.56

Subbituminous Coal, PC Boiler with CS-ESP and wet FGD Scrubber

Jim Bridger 1 0.05 2.49 5.21 7.74 no coal flow 0.06 0.25 6.63 6.95 10.32 14.60

Jim Bridger 2 0.44 2.04 5.64 8.12 no coal flow 0.05 0.29 6.51 6.85 15.64 19.67

Jim Bridger 3 0.07 1.78 4.50 6.35 no coal flow 0.03 0.20 5.92 6.15 3.06 7.69

Average 0.19 2.10 5.12 7.41 not included 0.05 0.25 6.36 6.65 9.68 13.99

Laramie River 1 1 0.25 3.14 7.52 10.91 13.52 0.02 0.29 4.86 5.18 52.57 54.83

Laramie River 1 2 0.04 2.16 8.35 10.55 15.45 0.00 0.12 5.73 5.85 44.54 47.18

Laramie River 1 3 0.02 3.08 7.53 10.63 15.71 0.01 0.03 4.48 4.52 57.53 59.56

Average 0.10 2.79 7.80 10.70 14.90 0.01 0.15 5.02 5.18 51.55 53.86

Sam Seymour 1 0.03 3.00 9.10 12.13 60.48 0.06 0.24 12.25 12.54 1.51 1.51

Sam Seymour 2 0.01 4.08 13.10 17.19 43.20 0.11 0.29 13.33 13.74 23.90 23.90

Sam Seymour 3 0.01 5.39 11.96 17.35 51.04 0.06 0.35 11.99 12.39 31.99 31.99

Average 0.01 4.16 11.38 15.56 51.58 0.07 0.29 12.53 12.89 19.13 19.13

Average 0.10 3.02 8.10 11.22 33.24 0.04 0.23 7.97 8.24 26.78 28.99

Minimum 0.01 1.78 4.50 6.35 13.52 0.00 0.03 4.48 4.52 1.51 1.51

Maximum 0.44 5.39 13.10 17.35 60.48 0.11 0.35 13.33 13.74 57.53 59.56

STDEV 0.15 1.13 2.94 3.88 20.84 0.03 0.10 3.50 3.59 21.09 20.83

TX Lignite, PC Boiler with CS-ESP and wet FGD Scrubber

Monticello 3 1 0.19 16.49 29.39 46.07 61.96 0.31 6.50 29.45 36.25 21.31 21.31

Monticello 3 2 0.11 19.77 28.15 48.03 63.13 0.18 0.44 25.52 26.14 45.57 45.57

Monticello 3 3 0.13 25.83 27.21 53.16 76.52 0.24 7.26 23.10 30.60 42.44 42.44

Average 0.14 20.70 28.25 49.09 67.20 0.24 4.73 26.02 31.00 36.44 36.44

Limestone 1 0.01 23.55 13.38 36.94 14.49 0.04 2.69 15.96 18.69 49.40 49.40

Limestone 2 0.01 24.55 13.11 37.68 20.84 0.33 3.18 16.23 19.74 47.59 47.59

Limestone 3 0.02 28.15 14.11 42.29 15.29 0.12 1.27 17.18 18.58 56.07 56.07

Average 0.02 25.42 13.54 38.97 16.87 0.17 2.38 16.46 19.01 51.02 51.02

Average 0.08 23.06 20.89 44.03 42.04 0.20 3.56 21.24 25.00 43.73 43.73

Minimum 0.01 16.49 13.11 36.94 14.49 0.04 0.44 15.96 18.58 21.31 21.31

Maximum 0.19 28.15 29.39 53.16 76.52 0.33 7.26 29.45 36.25 56.07 56.07

STDEV 0.07 4.24 8.09 6.28 28.12 0.11 2.76 5.63 7.32 11.89 11.89
C-12

Table C-7. (continued).

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2) : % Reduction for O-H Train and Coal Data

Plant ID Run Hgp In Hg2+ In Hg° In HgT In HgT In Hgp Out Hg2+ Out Hg° Out HGT Out %R HT %R HgT

No. O-H O-H O-H O-H Coal O-H O-H O-H O-H Wet FGD PM+FGD

Bituminous Coal, PC Boiler with HS-ESP and wet FGD Scrubber

Charles Lowman 1 2.64 3.33 2.09 8.06 23.49 0.06 1.68 3.39 5.13 36.44 44.29

Charles Lowman 2 1.55 3.98 2.17 7.69 21.50 0.07 1.86 3.50 5.44 29.31 38.03

Charles Lowman 3 3.45 3.55 2.02 9.01 23.94 0.05 2.06 3.19 5.30 41.18 48.44

Average 2.55 3.62 2.09 8.26 22.98 0.06 1.87 3.36 5.29 35.64 43.58

Morrow 1 0.05 10.80 4.41 15.27 5.48 0.05 2.06 5.00 7.11 53.46 59.20

Morrow 2 0.01 8.31 4.10 12.42 5.42 0.03 1.79 4.50 6.31 49.18 55.45

Morrow 3 0.03 6.98 3.32 10.33 5.38 0.04 1.12 4.55 5.71 44.70 51.52

Average 0.03 8.70 3.94 12.67 5.43 0.04 1.65 4.68 6.38 49.11 55.39

Average 1.29 6.16 3.02 10.46 14.20 0.05 1.76 4.02 5.83 42.38 49.49

Minimum 0.01 3.33 2.02 7.69 5.38 0.03 1.12 3.19 5.13 29.31 38.03

Maximum 3.45 10.80 4.41 15.27 23.94 0.07 2.06 5.00 7.11 53.46 59.20

STDEV 1.50 3.05 1.08 2.91 9.65 0.02 0.35 0.75 0.75 8.74 7.66

Subbituminous Coal, PC Boiler with HS-ESP and wet FGD Scrubber

Coronado 1 0.03 0.99 2.19 3.20 4.45 0.02 0.04 3.56 3.61 -12.95 -0.87

Coronado 2 0.03 0.82 1.86 2.71 4.76 0.08 0.07 1.83 1.98 26.82 34.64

Coronado 3 0.03 1.09 1.87 2.99 3.86 0.11 0.13 3.08 3.32 -11.30 0.60

Average 0.03 0.96 1.97 2.96 4.36 0.07 0.08 2.82 2.97 0.86 11.46

Craig 1 1 0.04 0.33 3.61 3.97 2.45 0.00 0.13 2.13 2.26 43.05 49.14

Craig 1 2 0.04 0.29 2.52 2.85 2.79 0.00 0.11 2.09 2.20 22.93 31.17

Craig 1 3 0.04 0.16 1.99 2.19 2.30 0.01 0.09 2.03 2.14 2.44 12.87

Average 0.04 0.26 2.71 3.01 2.51 0.01 0.11 2.08 2.20 22.81 31.06

Navajo 1 0.03 2.91 3.55 6.49 4.37 0.05 0.04 3.67 3.76 42.00 48.20

Navajo 2 0.03 0.45 3.93 4.41 2.63 0.02 0.04 3.79 3.85 12.65 21.99

Navajo 3 0.03 0.62 3.50 4.16 2.63 0.01 0.04 3.77 3.82 8.25 18.06

Average 0.03 1.33 3.66 5.02 3.21 0.03 0.04 3.75 3.81 20.97 29.42

San Juan 1 0.02 6.25 5.81 12.08 7.94 0.05 0.45 7.14 7.64 36.74 43.50

San Juan 2 0.08 3.31 4.26 7.65 8.69 0.08 0.38 4.79 5.25 31.35 38.69

San Juan 3 0.02 5.07 3.62 8.70 11.00 0.05 0.31 4.66 5.02 42.31 48.48

Average 0.04 4.87 4.56 9.47 9.21 0.06 0.38 5.53 5.97 36.80 43.56

Average 0.03 1.86 3.23 5.12 4.82 0.04 0.15 3.54 3.74 20.36 28.87

Minimum 0.02 0.16 1.86 2.19 2.30 0.00 0.04 1.83 1.98 -12.95 -0.87

Maximum 0.08 6.25 5.81 12.08 11.00 0.11 0.45 7.14 7.64 43.05 49.14

STDEV 0.02 2.05 1.19 3.02 2.86 0.04 0.14 1.52 1.64 20.32 18.15

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2) : % Reduction for O-H Train and Coal Data

Plant ID Run Hgp In Hg2+ In Hg° In HgT In HgT In Hgp Out Hg2+ Out Hg° Out HGT Out %R HT %R HgT

No. O-H O-H O-H O-H Coal O-H O-H O-H O-H Wet FGD PM+FGD

Bituminous Coal, PC Boiler with FF and wet FGD scrubber

Clover 1 0.06 1.00 1.11 2.17 29.21 0.05 0.42 0.42 0.88 59.42 96.78

Clover 2 0.03 1.11 1.99 3.13 41.19 0.02 0.34 0.17 0.53 83.13 98.66

Clover 3 0.08 1.16 0.62 1.86 49.02 0.06 0.05 0.14 0.25 86.76 98.95

Average 0.06 1.09 1.24 2.39 39.81 0.04 0.27 0.24 0.55 76.43 98.13

Intermountain 1 0.01 1.01 0.20 1.22 2.00 0.01 0.03 0.25 0.29 76.15 98.11

Intermountain 2 0.01 1.08 0.24 1.33 1.97 0.01 0.07 0.46 0.54 59.67 96.80

Intermountain 3 0.01 1.36 0.22 1.58 3.09 0.01 0.08 0.41 0.50 68.68 97.52

Average 0.01 1.15 0.22 1.38 2.35 0.01 0.06 0.37 0.44 68.16 97.48

Average 0.03 1.12 0.73 1.88 21.08 0.03 0.16 0.31 0.50 72.30 97.80

Minimum 0.01 1.00 0.20 1.22 1.97 0.01 0.03 0.14 0.25 59.42 96.78

Maximum 0.08 1.36 1.99 3.13 49.02 0.06 0.42 0.46 0.88 86.76 98.95

STDEV 0.03 0.13 0.71 0.70 21.47 0.02 0.17 0.14 0.23 11.66 0.92
C-13

Table C-8. Cyclone-fired boilers.

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2) : % Reduction for O-H Train and Coal Data

Plant ID Run Hgp In Hg2+ In Hg° In HgT In HgT In Hgp Out Hg2+ Out Hg° Out HGT Out %R HT %R HgT

No. O-H O-H O-H O-H Coal O-H O-H O-H O-H O-H Coal

ND Lignite, Cyclone Boiler with CS-ESP

Leland Olds 1 0.56 0.23 3.30 4.09 5.63 0.00 0.82 4.04 4.86 -18.68 13.66

Leland Olds 2 0.26 0.46 8.80 9.51 10.18 0.00 1.09 5.26 6.35 33.26 37.64

Leland Olds 3 2.85 0.81 4.77 8.43 7.94 0.00 1.60 LS NA NA NA

Average 0.41 0.34 6.05 6.80 7.90 0.00 0.95 4.65 5.60 7.29 25.65

Sub-bituminous/Pet. Coke, Cyclone Boiler with HS-ESP

Nelson Dewey 1 0.01 0.49 3.20 3.69 6.62 0.10 0.26 3.33 3.69 0.13 44.27

Nelson Dewey 2 0.01 0.24 2.19 2.43 6.47 0.04 0.16 2.40 2.60 -6.90 59.83

Nelson Dewey 3 0.01 0.12 2.06 2.18 6.09 0.04 0.25 2.44 2.73 -24.95 55.22

Average 0.01 0.28 2.48 2.77 6.39 0.06 0.22 2.72 3.00 -10.57 53.11

Lignite, Cyclone Boiler with Mechanical Collector

Bay Front 1 0.76 0.78 2.17 3.70 3.58 1.19 0.60 1.91 3.69 0.34 -2.95

Bay Front 2 1.08 0.67 1.94 3.69 3.01 0.86 2.75 1.80 5.40 -46.54 -79.21

Bay Front 3 0.09 0.77 1.74 2.60 3.36 0.48 3.57 1.78 5.84 -125.00 -73.79

Average 0.64 0.74 1.95 3.33 3.32 0.84 2.30 1.83 4.98 -57.07 -51.99

Lignite, Cyclone Boiler with SDA/FF

Coyote 1 0.69 1.62 13.68 15.99 10.51 0.08 0.04 13.97 14.10 11.81 -34.23

Coyote 2 1.18 2.98 13.90 18.06 18.55 0.14 0.24 LS NA NA NA

Coyote 3 1.69 3.07 14.91 19.66 11.39 0.08 0.44 18.06 18.58 5.48 -63.12

Average 1.19 2.34 14.29 17.82 10.95 0.08 0.24 16.02 16.34 8.64 -48.67

Bituminous, Cyclone Boiler with PS and Wet FGD Scrubbers

Lacygne 1 6.70 3.99 1.30 12.00 no inlet flow 0.04 0.44 8.74 9.22 23.18 no inlet flow

Lacygne 2 6.52 3.34 0.60 10.46 no inlet flow 0.05 0.43 7.41 7.89 24.53 no inlet flow

Lacygne 3 5.98 0.59 0.61 7.18 no inlet flow 0.09 0.41 5.10 5.59 22.17 no inlet flow

Average 6.40 2.64 0.84 9.88 no inlet flow 0.06 0.43 7.08 7.57 23.29 no inlet flow

Bituminous, Cyclone Boiler with CS-ESP and wet FGD Scrubber

Bailly 1 0.04 3.18 2.57 5.79 4.41 0.00 0.36 2.85 3.22 54.24 27.09

Bailly 2 0.04 2.37 2.95 5.36 5.20 0.00 0.31 2.62 2.93 54.95 43.53

Bailly 3 0.09 3.01 2.58 5.68 4.08 0.00 0.39 2.78 3.17 54.11 22.31
C-14

Table C-9. Fluidized-bed combustion.

Hg Speciation at Inlet and Outlet (μg/dscm@ 3%O2) : % Reduction for O-H Train and Coal Data

Plant ID Run Hgp In Hg2+ In Hg° In HgT In HgT In Hgp Out Hg2+ Out Hg° Out HGT Out %R HT %R HgT

No. O-H O-H O-H O-H Coal O-H O-H O-H O-H O-H Coal

Lignite, FBC with CS-ESP

R.M. Heskett 1 4.73 5.39 3.83 13.95 13.54 1.06 1.44 4.57 7.07 49.29 47.76

R.M. Heskett 2 2.93 0.96 2.61 6.50 12.68 0.07 0.41 5.31 5.78 11.09 54.40

R.M. Heskett 3 7.43 0.44 3.08 10.94 11.11 0.05 0.18 4.74 4.98 54.49 55.19

Average 5.03 2.26 3.17 10.46 12.44 0.39 0.68 4.87 5.95 38.29 52.45

Anthracite Waste, FBC with FF

Kline Township 1 44.54 0.12 0.45 45.11 148.68 0.00 0.06 0.06 0.12 99.74 99.92

Kline Township 2 43.12 0.06 0.40 43.58 212.95 0.00 0.06 0.06 0.12 99.73 99.95

Kline Township 3 44.97 0.06 0.34 45.37 153.77 0.00 0.06 0.06 0.12 99.74 99.92

Average 44.21 0.08 0.40 44.69 171.80 0.00 0.06 0.06 0.12 99.74 99.93

Bituminous Waste, FBC with FF

Scrubgrass 1 184.04 0.68 0.19 184.91 100.09 0.00 0.07 0.08 0.15 99.92 99.85

Scrubgrass 2 124.11 0.42 0.09 124.62 101.35 0.00 0.05 0.07 0.12 99.91 99.89

Scrubgrass 3 76.68 0.22 0.07 76.97 100.25 0.00 0.04 0.07 0.11 99.85 99.89

Average 128.28 0.44 0.12 128.83 100.56 0.00 0.05 0.07 0.13 99.89 99.88

Bituminous/Pet. Coke, FBC with SNCR and FF

Stockton Cogen 1 2.71 0.06 0.06 2.83 1.68 0.02 0.04 0.05 0.11 96.09 93.39

Stockton Cogen 2 1.56 0.07 0.06 1.69 1.44 0.03 0.05 0.05 0.13 92.16 90.80

Stockton Cogen 3 2.08 0.06 0.06 2.20 1.66 0.03 0.05 0.05 0.12 94.48 92.67

Average 2.12 0.07 0.06 2.24 1.59 0.03 0.05 0.05 0.12 94.25 92.29

Subbituminous, FBC with SCR and FF

AES Hawaii 1 0.26 0.04 1.29 1.59 3.77 0.00 0.02 0.68 0.70 55.84 81.39

AES Hawaii 2 0.35 0.17 1.38 1.90 3.72 0.00 0.02 0.90 0.92 51.35 75.16

AES Hawaii 3 0.36 0.11 1.18 1.64 2.51 0.00 0.02 0.55 0.58 64.91 77.06

Average 0.32 0.10 1.28 1.71 3.33 0.00 0.02 0.71 0.73 57.37 77.87

Lignite, FBC with CS-FF

TNP 1 21.65 8.68 7.42 37.74 63.81 0.04 12.13 4.74 16.91 55.20 73.50

TNP 2 10.65 4.51 6.09 21.25 44.22 0.03 6.78 2.94 9.76 54.07 77.93

TNP 3 28.12 13.78 7.04 48.94 95.04 0.04 13.54 5.07 18.66 61.88 80.37
Appendix D

Assessment of Mercury Control Options

for

Coal-fired Power Plants

D-1

List of Attachments 

Attachment 1. Description of National Energy Technology Laboratory

Control Performance and Cost Model ......................... D-4

Attachment 2. Description of Mercury Control Performance Algorithms

Used in the National Energy Technology Laboratory

Mercury Control Performance and Cost Model........... D-33

Attachment 3. Summary of Mercury Control Cases Analyzed with

National Energy Technology Laboratory Mercury

Control Performance and Cost Model.......................... D-42

Attachment 4. Results of all Model Runs .............................................. D-48

D-3
ATTACHMENT 1


Description of


National Energy Technology Laboratory


Mercury Control Performance and Cost Model


D-4

Description of the National Energy Technology Laboratory 

Mercury Control Performance and Cost Model 

1. Model Description 

The National Energy Technology Laboratory (NETL) Mercury Control Performance and Cost Model (MCPCM) is 

an Excel spreadsheet model that can be used to assess the performance and cost of mercury (Hg) control systems 

that utilize activated carbon injection (ACI) and other methods. The primary goal of the model is to calculate key 

performance parameters that are then used to calculate detailed capital costs and O&M costs of a mercury control 

technology for either of two types of power plant applications – either a bituminous or subbituminous coal-fired 

power plant configuration. This overview describes the model layout, its specific capabilities, and its current 

limitations. 

1.1 MCPCM Layout 

The spreadsheet model is currently divided into seven (7) different, functional sheets that are integrated together to 

perform the costing goal defined above. The five sheets are identified below: 

Hg Control Scenario Definition Sheet Characterization of Control Technology Retrofit 

Configurations 

Hg Control Performance Models Sheet Performance Algorithms for Different Control 

Technology Retrofit Configurations 

Application Input Sensitivity Sheet User Data Input 

Technical Model Results Sheet PowerPlant and Mercury Control Technical Performance 

Results 

Combustion Calculations Sheet Power Plant Performance Calculations 

Capital Cost Model Sheet Capital Cost Calculations 

System Economic Model Sheet O&M Cost Calculations and Levelized Cost Calculations 

1.1.1 Hg Control Scenario Definition Sheet 

This sheet documents the different mercury control technology retrofit scenarios that can potentially be evaluated by 

the model. The information provided for each scenario is presented below: 

Scenario Number: Number, no units


This number uniquely identifies each control scenario within the program.


Configuration Designation: Abbreviation that identifies a control technology scenario, e.g., ESP-1 (activated 

carbon injection upstream of ESP with no spray cooling) 

Configuration Definition: Brief description that uniquely defines a control technology scenario, e.g., ESP-1, “ACI 

upstream of existing ESP” 

Comment: Further descriptive information that qualifies the functionality of the control technology scenario within 

the model. 

Data Sources: Identifies and documents specific data and information sources used to establish the performance of 

a control technology. 

D-5

1.1.2 Hg Control Performance Models Sheet 

This sheet contains performance models for each control technology configuration identified in the Hg Control 

Scenario Definition Sheet (as currently available). These models currently calculate total sorbent feed (lb/MMacf 

of flue gas) based on a specified total mercury control efficiency (e.g., 50%) and flue gas temperature. 

Currently, each control configuration (e.g., ESP-1) makes use of separate algorithms for mid- to high-sulfur 

bituminous coals (e.g., Pittsburgh (Pgh) #8) and Western subbituminous coals (e.g., Wyoming PRB). Therefore, the 

coal type that is specified in the Application Input Sensitivity Sheet will determine the specific algorithm that is 

used for a specified control configuration and application case. These algorithms were developed based on curvefitting available pilot- and full-scale test data. The data sources are also documented in the sheet. 

1.1.3 Application Input Sensitivity Sheet 

This sheet is intended as the primary user interface to run up to 20 different mercury control cases simultaneously. 

For each control case, the sheet defines the desired mercury control requirements, a specific power plant variant of 

either of two power plant application types, and some key economic parameters used for costing purposes. 

Additional parametric changes can be made to the model to add greater evaluation flexibility, but these need to be 

made within the other functional sheets of the model. Model parameters included here are: 

1.1.3.1 Mercury Control Parameters 

Case Number: Numerical value, Fixed (e.g., 1,2, etc.) –


Sequentially identifies each application case. Up to 20 cases can be specified.


Hg Removal Configuration Type: Numerical entry by user (e.g., 1,2, etc.) --


Specifies the mercury control configuration as documented in the Hg Control Scenario Definition Sheet. The user


must select a configuration type.


Hg Control Flue Gas Temperature Specification: Number, units = o

F (e.g., 250)


Specifies the temperature at which mercury control is to take place. The program calculates this temperature as


follows:


Control Temperature = Flue Gas Acid Dew Point Temperature (o

F) + 18 oF 

(For Configurations 1 to 11) 

Control Temperature = 200 o

F 

(Current default for all other configurations) 

Injection of cooling water can be used to lower the flue gas temperature below the power plant air heater outlet


temperature for configurations 1 to 11. Configurations 12 to 18 incorporate wet or dry scrubbing, which yield a


relatively low flue gas temperature at their outlet. A default temperature of 200 o

F is currently used because it


represents a value that is below the lower limit of the algorithms contained in the Hg Control Scenario Definition


Sheet.


Mercury Concentration: Number, units = μg/Nm3

 (e.g., 10)


The total mercury concentration within the flue gas at the exit of the air heater. The user specifies this value.


Mercury Speciation as % Hgo

: Number as a percentage, no units (e.g., 50)


The percentage of total mercury that is elemental mercury. The difference is assumed to be oxidized mercury in the


form of HgCl2. The user specifies this value.


D-6

Total SI (sorbent injection) Mercury Removal Efficiency - % of Hg Removed: Number as a percentage, no 

units (e.g., 50) 

The percentage of total mercury that is removed by the control technology.


SI Mercury Removal Efficiency - % Hgo

 Removed: Number as a percentage, no units (e.g., 50)


The percentage of elemental Hg that is removed by the control technology. This value is currently assumed to be


calculated by the performance model, but this capability is currently not available.


ACI Mercury Removal Efficiency - % HgCl2 Removed: Number as a percentage, no units (e.g., 50)


The percentage of HgCl2 that is removed by the control technology, but this capability is currently not available.


Sorbent Injection Ratio: Number, units = lb/MMacf (e.g., 3)


The primary feed of sorbent (based on lb sorbent per MMacf of flue gas) that corresponds to the specified Hg


removal efficiency. The configuration performance model calculates this value.


Sorbent Recycle Split: Percent, no units (e.g., 10)


The ratio of recycled spent sorbent to total sorbent feed into the flue gas (expressed as a percentage). This value is


currently assumed to be calculated by the performance model, but this capability is currently not available.


FGD Mercury Removal Efficiency - % Hgo

 Removed: Number as a percentage, no units (e.g., 50)


The percentage of Hg0

 (in the flue gas) that is removed by an existing wet FGD system. Mercury removal via an


FGD system can be incorporated manually if desired. This is permitted as an option in case the user wants to


combine FGD with other mercury removal technologies such as ACI. Set values equal to zero if no wet FGD exists


or mercury control scenarios 14 - 18 are being used. If utilized, total mercury control is calculated within the


"Technical Model Results Sheet."


FGD Mercury Removal Efficiency - % HgCl2 Removed: Number as a percentage, no units (e.g., 50)


The percentage of HgCl2 (in the flue gas) that is removed by the wet FGD system. Mercury removal via an FGD


system can be incorporated manually if desired. This is permitted as an option in case the user wants to combine


FGD with other mercury removal technologies such as ACI. Set value equal to zero if no wet FGD exists or


mercury control scenarios 14 - 18 are being used. If utilized, total mercury control is calculated within the


"Technical Model Results Sheet."


0 If Hg speciation is unknown set value equal to “% Hg removal efficiency.” For example, if total Hg removal via 0 FGD is to be set at 80% and speciation is unknown, then set both Hg and HgCl2 removal efficiencies equal to the


80% value.


Fabric Filter Pressure Drop: Number, units = inches H2O (e.g., 6)


Differential pressure across baghouse tubesheet. Input a value if a pulse-jet FF will be added to the plant after the


primary particulate collector to collect Hg sorbent. This applies to retrofit scenarios 3, 6, 7, 8, and 11.


Fabric Filter Air/cloth Ratio: Number, units = ft/min (e.g., 12)


Ratio of volumetric gas flow into baghouse (ft3

/min) to total bag surface area (ft

2

). Input a value if a pulse-jet FF


will be added to the plant after the primary particulate collector to collect Hg sorbent. This applies to retrofit


scenarios 3, 6, 7, 8, and 11.


Fabric Filter Particle Collection Efficiency: Number as a percentage, no units (e.g., 99.98)


Mass flow of particulate into baghouse/mass flow of particulate emitted from baghouse. Input a value if a pulse-jet


FF will be added to the plant after the primary particulate collector to collect Hg sorbent. This applies to retrofit


scenarios 3, 6, 7, 8, and 11.


1.1.3.2 Power Plant Design Parameters 

D-7

Gross Power Plant Size: Number, units = MWe (e.g., 500)


Gross power plant electricity output (excludes plant auxiliary power).


Reference Power Plant Type: Alphanumeric entry (HS or LS)


HS refers to the high sulfur reference power plant and LS refers to the low sulfur reference plant.


Plant Capacity Factor: Number as a percentage, no units (e.g., 65)


Ratio of the energy generated during some time period to the total energy that could have been generated had the


plant run at its full rating over the entire time period.


Power Plant Coal Type: Alphanumeric entry (e.g., Pgh #8)


Select a coal type from a menu list of six coals. The coal types are Illinois #6, Wyoming PRB, Texas Lignite, Utah


Bituminous (LS), Appalachian (HS), Pittsburgh #8, and bituminous process derived fuel (LS). The Combustion


Calculations Sheet contains detailed analysis data for each coal (cell range AE61 to AP141).


1.1.3.3 Economic Assessment Parameters 

Levelized Carrying Charge Rate: Number, no units (e.g., 0.133)


The levelized amount of revenue per dollar of investment in the mercury control system that must be collected in


order to pay the carrying charges on the investment.


Sorbent Unit Cost: Number, units = $/lb (e.g., 0.5)


Unit cost of the activated carbon or other sorbent, including the cost of the material and shipping.


Waste Disposal Removal Service?: Yes or No


This logical question is asked to identify the need to treat the mercury laden AC as hazardous waste. Yes =


hazardous, in which case the AC is removed and processed to remove the mercury; a processing cost can be


specified by the user. No = non-hazardous, in which case the AC is disposed of with the fly ash; a disposal cost


can be specified by the user.


Normal Waste Disposal Cost: Number, units =$/ton (e.g., 30)


Unit cost of disposing non-hazardous power plant waste, such as fly ash. Use of a negative number indicates a


waste byproduct credit.


Hazardous Waste Disposal Cost: Number, units =$/ton (e.g., 1,750)


Unit cost of disposing hazardous power plant waste materials. AC is removed and processed to remove the


mercury.


Power Cost: Number, units =$/MW-Hr (e.g., 25)


Unit cost of power the plant charges for running auxiliary equipment.


Mercury By-Product Cost: Number, units =$/ton (e.g., 50)


Unit cost of recovered mercury that could be sold in the marketplace.


1.1.4 Technical Model Results Sheet 

The purpose of this sheet is to document the case study input data for the power plant and the mercury control 

technology, as well as the results of the performance calculations from the Power Plant Combustion Model Sheet. 

Up to twenty case studies can be simultaneously created and documented in the sheet. Two reference power plants 

are documented; additional changes to the reference plant design and operating conditions can be made in this sheet 

in order to modify plant performance. 

D-8

For the power plant definition, the sheet uses the input data from the Application Input Sensitivity Sheet and 

combines it with the reference plant data to create a specific plant for each case study. For example, if the high 

sulfur power plant gross power rating is input as 900 MWe in the input sensitivity sheet, then this overrides the 

reference plant rating of 541.9 MWe; plant auxiliary power is scaled accordingly. Sheet data for the reference 

plants should not be changed unless modifications are needed to simulate a different plant. For example, if a 

different net heat rate were desired, then the reference plant value would need to be replaced with a new value. 

The mercury control data inputs are taken directly from both the Input Sensitivity Sheet and the Hg Control 

Performance Models Sheet and are listed for the sake of documentation and use by other parts of the spreadsheet. 

Calculated power plant performance results from the Power Plant Combustion Model Sheet are returned to this 

sheet for documentation and use by the sheet to calculate specific performance results for the mercury control 

technology. 

This sheet also uses results returned from the Combustion Model Sheet to calculate the flue gas acid dew point. 

This is an important design parameter given the significant influence of temperature on sorbent-based mercury 

control. While test data indicates that lower temperatures enhance mercury capture from the flue gas, reducing the 

gas temperature (via water injection) must be limited to a specified temperature approach to the acid dew point. 

Maintaining the gas temperature at such an increment will help prevent corrosion within the ductwork and 

particulate control devices. The sulfuric acid dew point calculation is based on the following algorithms: 

1000/Tdp = 2.276-0.0294*ln(PH2O)-.0858*ln(PH2SO4) + 0.0062*ln(PH2O)*ln(PH2SO4) 

Where, 

Tdp = Acid Dew Point 

PH2O = Partial pressure of water in the flue gas 

PH2SO4 = Partial pressure of sulfuric acid in the flue gas 

The dew point is in degree K and partial pressures in mm Hg.


For example, if a flue gas contains 12 % volume of water vapor and 0.02 % volume SO2 and say 2 % of SO2


converts to SO3, compute the sulfuric acid dew point.


Gas pressure = 10 in wg or (10/407) =0.02457 atmg or 1.02457 atma.


PH2O =0.12 * 1.02457 * 760 = 93.44 mm Hg.


ln(PH2O) = 4.537


PSO3 = PH2SO4.


PSO3 = 0.02 * .0002 * (64/80) * 760 * 1.02457 = 0.0024917


ln(SO3) = -6


Note that 2 % conversion is on weight basis and hence we multiplied and divided by the molecular weights of SO2


and SO3 in the above calculation.


1000/Tdp = 2.276 - 0.0294 * 4.537 + 0.0858 * 6-0.0062 * 4.537 * 6 = 2.489


Or Tdp=402 K or 129 C or 264 F


The percent conversion of SO2 to SO3 is calculated in the Combustion Model Sheet based on an algorithm that


accounts for the sulfur in the coal and specific ash constituents (Fe2O3).


1.1.5 Combustion Calculations Sheet 

The purpose of this sheet is to take the power plant case study design and operating data from the Technical Model 

Results Sheet and calculate the power plant technical performance parameters, such as combustion gas constituent 

flows and total gas flows at strategic boiler locations (e.g., after the air heater). Also, if flue gas cooling via water 

D-9

injection is specified by the user (by specifying a flue gas temperature lower than the reference plant’s post air 

heater temperature), then this sheet will calculate the quantity of water required via energy balance calculations. 

This sheet also contains the coal analysis data described previously. The coal types are Illinois #6, Wyoming PRB, 

Texas Lignite, Utah Bituminous (LS), Appalachian (HS), Pittsburgh #8, and bituminous process derived fuel (LS). 

Detailed analysis data for each coal can be found within cell range AE61 to AP141. 

1.1.6 Capital Cost Model Sheet 

The Capital Cost Model Sheet makes use of the power plant and mercury control performance data to calculate the 

capital costs associated with a case study’s mercury control design configuration. The costing currently covers the 

following equipment sections: 

Spray Cooling Water System


Sorbent Injection System


Sorbent Recycle System


Pulse-Jet Baghouse and Accessories


Ash/Spent Sorbent Handling System


Continuous Emissions Monitoring System (CEMS) Upgrade


A total mercury control system cost is calculated from the following cost components: 1) equipment, 2) related 

materials, 3) field and indirect labor, 4) sales tax, 5) base erected cost, 6) Engineering design, 7) process and project 

contingencies, and 8) general facilities. Maintenance costs are also calculated as a percentage of the bare erected 

cost (e.g., 2%). This sheet also contains an “Economic Master Table” in which a number of key costing parameters, 

such as contingency factors, can be changed and incorporated into the case study calculations. Twenty case studies 

can be handled simultaneously in this sheet. 

1.1.7 System Economic Model Sheet 

This sheet calculates mercury control system O&M, total system investment, total system capital requirement, and 

then levelizes the capital and O&M to establish single value for $/lb of mercury removed. Twenty case studies can 

be handled simultaneously in this sheet. 

1.1.7.1 Mercury Control System O&M Costs 

Operating Labor: cost of system operating and administrative personnel; unit labor rates and manpower 

requirements/shift are specified in the case study O&M table and can be specified independently for each case 

study. 

Maintenance Labor: 40% of the total maintenance cost calculated in the Capital Cost Model Sheet 

Maintenance Material: 60% of the total maintenance cost calculated in the Capital Cost Model Sheet 

Administrative and Support Labor: Calculated as a percentage (labor overhead charge rate) of the sum of the 

operating and maintenance labor cost; overhead charge specified in the case study O&M table and can be specified 

independently for each case study. 

Consumable values are taken from the Technical Model Results Sheet. The O&M cost consists of the following 

consumable components: 

Water (for flue gas humidification), gallons/Hr: unit cost = $/1000 gallons (e.g., 0.80), specified in case study 

table 

D-10

--

Sorbent (e.g., Activated Carbon), tons /Hr: unit cost = $/ton (e.g., 1,100), specified in case study table 

Incremental Power, kW-Hr: unit cost = $/MW-Hr (e.g., 30), specified in case study table


Fan power accounts for the added pressure drop across the mercury control equipment, such as the fabric filter.


Sorbent injection system power is required to transport the sorbent to the flue gas duct. Humidification system


power is required to pump water to an injection grid in the ductwork.


Waste Disposal, tons/Hr: unit cost = $/ton (e.g., 30), specified in case study table


Waste AC is generated by the mercury control system. This mercury-laden AC must be disposed of or processed


for mercury removal and recovery. This material can be disposed of with the rest of the plant’s fly ash or it can be


processed separately if deemed a hazardous material.


Mercury Byproduct, lb/Hr: unit cost = $/ton (e.g., 30), specified in case study table


If the spent AC is processed for recovery of mercury, then a by-product credit can be applied. This will be applied


only if the user has designated the spent AC as hazardous waste material.


1.1.7.2 Total Mercury Control System Capital Requirement 

The total calculated investment in the mercury control system includes the total capital investment calculated in the 

Capital Cost Model Sheet, interest during construction (AFUDC), and the following additional cost components: 

Royalty allowance -- possible technology royalty charges may apply 

Preproduction Costs covers the cost of operator training, equipment checkout, major modifications to 

equipment, extra maintenance, and inefficient use of consumables. Calculated as 1 month of fixed operating costs 

(O&M labor, admin and support labor, and maintenance materials); 1 month of variable operating costs (all 

consumables) at full capacity; and 2 % of the total system investment. 

Inventory Capital -- value of initial inventory of activated carbon that is capitalized. This accounts for an initial 

storage supply of AC (e.g., 30 day supply). 

Initial Catalysts and Chemicals Charge -- the initial cost of any catalysts or chemicals contained in the process 

equipment, but not in storage. Does not apply to the mercury control systems. 

1.1.7.3 Levelized Cost of Mercury Control 

The total cost of mercury control must account for the total capital requirement (expressed as $/kW) and the total 

operating and maintenance expenses (expressed as mills/kWh). In order to calculate an annualized cost that 

accounts for both of these, the capital requirement is annuitized via use of the “Levelized Carrying Charge Rate.” 

The Levelized Carrying Charge Rate assumes a 30-year operating period and accounts for return on debt, return on 

equity, income taxes, book depreciation, property tax, and insurance payments. The Levelized Carrying Charge 

Rate is specified in this sheet in the section called “Financial Data-Factors.” It is multiplied times the total system 

capital requirement to derive the annualized value and converted to units of mills/kWh based on the annual 

operating hours of the plant (capacity factor x 8,760 h/yr). 

The first-year O&M costs that are calculated in this sheet are also levelized in order to account for both apparent 

and real escalation rates of labor, materials, and consumables over the expected operating time period (e.g., 30 

years). A levelization factor is specified in this sheet in the section called “Financial Data-Factors.” It is 

multiplied by the total O&M cost. 

The levelized carrying charge and the levelized O&M are summed to yield a total annualized cost which is divided 

by the annual mercury removed in order to derive a unique cost of removal with units of $/ton mercury removed. 

D-11

2. DOCUMENTATION OF REFERENCE POWER PLANTS USED IN MERCURY CONTROL 

MODEL. 

Two (2) representative power plant applications are being employed in this study to investigate the mercury control 

costs for the baseline designs as well as parametric variations of these baseline plants. These plants are 

characterized as: 

1)	 Plant firing high-sulfur, bituminous coal (Pgh #8) with low-NOX burners for NOX control, coldside ESP for particulate control, and a wet FGD system for SO2 control. 

2)	 Plant firing low-sulfur coal with low-NOX burners for NOX control and a cold-side ESP for 

particulate control. 

This section develops the basic specifications for each power plant variant: plant size, coal analysis, boiler 

performance parameters, flue gas mass/volumetric flow rates, gas constituents (including HCl), gas 

temperature/pressure profiles, total mercury concentration, and mercury speciation. 

High Sulfur Power Plant Reference Case 

The high sulfur reference coal (PC) plant design is comprised of a balanced draft, natural circulation steam 

generator, providing steam for a turbine generator set, condensing at 2.5 inches Hg absolute back pressure at the 

design point. The plant design and performance reflect current commercial practice in the U.S. utility industry. The 

turbine-generator is a tandem compound machine, with high pressure (HP), intermediate pressure (IP), and low 

pressure (LP) sections. The LP turbine is comprised of two double flow sections exhausting downward into the 

condenser sections. The plant uses a 2400 psig/1000 o

F/1000 oF single reheat steam power cycle. The boiler and the 

turbine are designed for a main steam flow of 3,621,006 pounds of steam per hour at 2520 pounds per square inch, 

gauge (psig) and 1000 o

F at the superheater outlet, throttled to 2415 pounds per square inch, absolute (psia) at the 

inlet to the high pressure turbine. The cold reheat flow is 3,233,808 lb/hr of steam at 590 psia and 637 o

F, which is 

reheated to 1000 o

F before entering the intermediate pressure turbine section. The net plant output power, after 

plant auxiliary power requirements are deducted, is nominally 508 MWe. The overall net plant higher heating value 

(HHV) efficiency is nominally 36.8 percent. Refer to Table 2-1 for the plant performance summary information. 

Applicable Federal, State, and Local environmental standards relating to air, water, solid waste and noise have been 

designed into the high sulfur reference plant. Projected plant air emissions are identified in Table 2-2. The wet, 

limestone FGD system ensures an SO2 emission rate of less than 0.371 lb/MMBtu (92% reduction). The use of low 

NOX burner technology, combined with over fire air, results in NOX emissions of less than 0.30 lb/MMBtu. The 

control or reduction of N2O has not been addressed in this design because N2O levels are presently unregulated. 

The flue gas scrubber is a wet limestone type system, with scrubbing and demisting occurring in the same vessel. 

An organic acid is added to the circulating reagent to enhance the scrubbing performance. Air is blown into the 

scrubber module sump to promote forced oxidation of the sulfite to sulfate. The gypsum byproduct is dried to a 

cake-like consistency in a train of centrifuges, and is ready to landfill. 

D-12


2.1 
TABLE 2-1


HIGH SULFUR PLANT PERFORMANCE SUMMARY - 100 PERCENT LOAD


STEAM CYCLE 

Throttle Pressure, psig 

Throttle Temperature, o

F 

Reheat Outlet Temperature o

F 

2,400 

1,000 

1,000 

POWER SUMMARY 

3600 rpm Generator 

GROSS POWER, kWe (Generator terminals) 541,900 

AUXILIARY LOAD SUMMARY, kWe 

Pulverizers 

Primary Air Fans 

Forced Draft Fans 

Induced Draft 

Seal Air Blowers 

Main Feed Pump (Note 1) 

Steam Turbine Auxiliaries 

Condensate Pumps 

Circulating Water Pumps 

Cooling Tower Fans 

Coal Handling 

Limestone Handling & Reagent Prep. 

FGD Pumps and Agitators 

Ash Handling 

Dewatering Centrifuges (FGD byproduct) 

Precipitators 

Soot Blowers (Note 2) 

Miscellaneous Balance of Plant (Note 3) 

Transformer Loss 

2,000 

1,840 

1,350 

7,500 

60 

2,400 

900 

1,100 

5,070 

2,400 

230 

1,160 

3,000 

2,000 

1,100 

1,100 

neg. 

2,000 

1,300 

TOTAL AUXILIARIES, kWe 

Net Power, kWe 

Net Efficiency, % HHV 

Net Heat Rate, Btu/kWh (HHV) 

34,100 

507,800 

36.8 

9,279 

CONDENSER COOLING DUTY, 106

 Btu/hr 2,350 

CONSUMABLES 

As-Received Coal Feed, lb/hr 

Sorbent, lb/hr 

378,550 

46,790 

Note 1 - Driven by auxiliary steam turbine, electric equivalent not included in total.


Note 2 - Soot blowing medium is boiler steam. Electric power consumption is negligible.


Note 3 - Includes plant control systems, lighting, HVAC, etc.


D-13

TABLE 2-2


HS PLANT AIR EMISSIONS - 65% CAPACITY FACTOR


lb/MMBtu Tons/Year 

SOX 0.46 5,880 

NOX 0.30 3,840 

Particulate 0.01 125 

The following indicates the state point conditions at various flue gas stream locations; 

Flue gas mass flow rate, boiler exit 4,966,633 lb/hr (1,561,834 acfm) 

Flue gas temperature at boiler exit 290 o

F 

Flue gas temperature at ESP exit 290 o

F 

Flue gas temperature at FGD exit 128 o

F 

The flue gas composition and temperatures at various points of the gas stream are detailed in Table 2-3. This data 

was calculated using the ACI Mercury Control Cost Model described in Section 3. 

2.1.1 Plant Site Ambient Conditions 

The plant site is assumed to be in the Ohio River Valley of western Pennsylvania/eastern Ohio/ northern West 

Virginia. The site consists of approximately 300 usable acres, not including ash disposal, within 15 miles of a 

medium sized metropolitan area, with a well established infrastructure capable of supporting the required 

construction workforce. 

The site is within Seismic Zone 1, as defined by the Uniform Building Code, and the ambient design conditions will 

be: 

Pressure 14.4 psia 

Dry bulb temperature 60 o

F 

Dry bulb temperature range (-) 10 to (+) 110 o

F 

Wet bulb temperature 52 o

F 

2.1.2 Fuel and Sorbent Composition 

The plant performance will be based on the Pittsburgh #8 Coal and Greer limestone compositions and data listed in 

Tables 2-4 and 2-5. Unit start-up will use No.2 fuel oil. 

D-14

TABLE 2-3


HIGH SULFUR (HS) REFERENCE POWER PLANT GAS STREAM DATA


Boiler & Plant Data Summary PGH #8 (HS) 

Btu Input Rate (MMBtu/h) 4,711.88 

Coal Input Rate (tons/h) 188.337 

Coal Mass-Energy Ratio (lb/MMBtu) 79.94 

MMBtu/hr Out of Boiler 4,162.49 

Flue Gas @ Economizer Outlet (SCFM/MMBtu) 12,503 

Flue Gas @ Economizer Outlet (SCFM) 981,877 

Wet Flue Gas @ Economizer Outlet (lb/h) 4,598,641 

Wet Air Based on Economizer Outlet (SCFM) 934,407 

Wet Air Based on Economizer Outlet (lb/h) 4,260,670 

Total Air, % (Economizer Outlet) 120.0 

Excess Air, % (Economizer Outlet) 20.0 

Flue Gas @ Air Heater Outlet (SCFM/MMBtu) 13,753 

Flue Gas @ Air Heater Outlet (SCFM) 1,080,065 

Wet Flue Gas @ Air Heater Outlet (lb/h) 5,042,924 

Wet Air Based on Air Heater Outlet (SCFM) 1,031,843 

Wet Air Based on Air Heater Outlet (lb/h) 4,704,952 

Wet Air Leakage @ Air Heater (SCFM) 97,436 

Wet Air Leakage @ Air Heater (lb/h) 444,283 

Equivalent Total Air, % (Air Heater Outlet) 132.5 

Equivalent Excess Air, % (Air Heater Outlet) 32.5 

Wet Flue Gas @ Air Heater Outlet (ACFM) 1,689,826 

Air Heater Outlet Flue Gas Temperature, o

F 290 

Air Heater Outlet Pressure, inches Hg. 29.31 

Fly Ash (ton/h) 15.48 

Bottom Ash (ton/h) 3.87 

Total Ash (ton/h) 19.35 

NOTE: Standard Conditions = 60 o

F, 29.92 inches Hg 

D-15

TABLE 2-4


GREER LIMESTONE ANALYSIS


Dry Basis, % 

Calcium Carbonate, CaCO3 80.4 

Magnesium Carbonate MgCO3 3.5 

Silica, SiO2 10.32 

Aluminum Oxide, Al2O3 3.16 

Iron Oxide, Fe2O3 1.24 

Sodium Oxide, Na2O 0.23 

Potassium Oxide, K2O 0.72 

Balance 0.43 

D-16

TABLE 2-5


PITTSBURGH NO. 8 COAL ANALYSIS


Constituent Air Dry, % Dry, % As Received, % 

Carbon 71.88 73.79 69.36 

Hydrogen 4.97 4.81 5.18 

Nitrogen 1.26 1.29 1.22 

Sulfur 2.99 3.07 2.89 

Ash 10.30 10.57 9.94 

Oxygen 8.60 6.47 11.41 

Total 100.00 100.00 100.00 

Dry Basis, % As Received, % 

Moisture ----- 6.00 

Ash 10.57 9.94 

Volatile Matter 38.20 35.91 

Fixed Carbon 51.23 48.15 

Total 100.00 100.00 

Cl, ppm in Coal 650 

Hg, ppb in Coal 78 + 24 

Sulfur 3.07 2.89 

Btu Content 13,244 12,450 

Moisture and Ash Free (MAF), Btu 14,810 

Ash Analysis, % 

Silica, SiO2 48.1 

Aluminum Oxide, AlO3 22.3 

Iron Oxide, Fe2O3 24.2 

Titanium Dioxide, TiO2 1.3 

Calcium Oxide, CaO 1.3 

Magnesium Oxide, MgO 0.6 

Sodium Oxide, Na2O 0.3 

Potassium Oxide, K2O 1.5 

Sulfur Trioxide, SO3 0.8 

Phosphorous Pentoxide, P2O5 0.1 

Total 100.5 

Ash Fusion Temperature, o

F 

Reducing Oxidizing 

Atmosphere Atmosphere 

Initial Deformation 2015 2570 

Spherical 2135 2614 

Hemispherical 2225 2628 

Fluid 2450 2685 

D-17

μ

2.1.3 Air Quality Standards 

The plant pollution emission requirements for the High Sulfur Reference Case reflect current environmental 

emissions standards for a plant sited in a non-attainment area with respect to ambient air standards for ozone. Table 

2-2 presents emissions for the plant without site sensitive NOX reduction enhancements. 

2.1.4 Flue Gas Acid Dew Point.1.4 

Based on a flue gas SO3 concentration of 22 ppm and a water concentration of 7.65% at the exit of the air heater, the


acid dew point is estimated to be approximately 280 o

F.


2.1.5 Mercury Emission Assumptions


Table 2-6, presented below, provides basic data for baseline and variant mercury emissions.


TABLE 2-6 

MERCURY EMISSIONS DATA 

Total Mercury 

Concentration 

(μg/Nm3

) 

Total Mercury 

Emissions Rate 

(g/h) 

Total Annual Mercury 

Release1 

(Kg/yr) 

10 

(Baseline) 

18.35 104.4 

3 5.5 31.3 

30 55.05 313.2 

1. Based on a 65% plant capacity factor. 

Low Sulfur Power Plant Reference Case 

The low sulfur reference pulverized coal (PC) plant design utilizes a balanced draft, natural circulation type, 

pulverized coal subcritical fired boiler, providing steam for a turbine generator set. The boiler design and 

performance reflect current commercial practice in the U.S. utility industry. The turbine-generator is a tandem 

compound machine, with high pressure (HP), intermediate pressure (IP), and low pressure (LP) sections. The LP 

turbine is comprised of two double flow sections exhausting downward into the condenser sections. The low sulfur 

reference plant uses a 2400 psig/1000 o

F/1000 oF single reheat steam power cycle. The boiler and the turbine are 

designed for a main steam flow of 2,734,000 pounds of steam per hour at 2520 psig and 1000 o

F at the superheater 

outlet, throttled to 2415 psia at the inlet to the high pressure turbine. The cold reheat flow is 2,425,653 lb/hr of 

steam at 604 psia and 635 o

F, which is reheated to 1000 oF before entering the intermediate pressure turbine section. 

The net plant output power, after plant auxiliary power requirements are deducted, is nominally 404 MWe. The 

overall net plant higher heating value (HHV) efficiency is nominally 39.1 percent. Refer to Table 2-7 for the plant 

performance summary information. 

The plant also is designed to meet applicable Federal, State, and Local environmental standards relating to air, 

water, solid waste and noise. The plant has baseline SO2 emissions of about 0.70 lb/MMBtu, and it is designed to 

utilize in-duct spray drying of lime to provide a removal efficiency of 50%. Lime slurry is sprayed into the flue gas 

duct, where it dries and captures SO2 as a particle. The particulate is then collected in the electrostatic precipitator 

D-18


2.2 
for disposal. If placed in service, the FGD system results in a SO2 emission rate of less than 0.35 lb/MMBtu; the 

current investigation assumes that the FGD system will not be in operation. The use of low NOX burner technology, 

combined with over-fire air, results in NOX emissions of less than 0.30 lb/MMBtu. The control or reduction of N2O 

has not been addressed in this design because N2O levels are presently unregulated. 

The low Sulfur Case Reference plant achieves a net plant efficiency of 39.1%, which is an increase of over 6% 

above that achieved by the High Sulfur Reference plant (36.8%). This increase in efficiency is achieved although 

the units are virtually identical in terms of size, boiler selection, steam cycle configuration, heat sink, and other 

considerations. The net efficiency improvements are due to the following: 

•	 The low sulfur reference auxiliary plant load is lower than the high sulfur plant’s auxiliary load. This 

reduction occurs because of the reduced ID fan power requirements, which result from the elimination of 

the pressure losses due to a scrubber. In addition, elimination of the reagent and byproduct handling 

systems associated with a wet scrubber reduce the auxiliary load but is offset by the atomizing air 

compressors for the duct injection system. 

•	 The low sulfur plant gas temperature leaving the boiler is set at 270 o

F versus 290 oF for the high sulfur 

plant. This reduction in exhaust temperature, which improves the boiler efficiency, is feasible because of 

the low SO2 concentrations in the gas leaving the boiler, and the gas passes directly into the duct injection 

system that is upstream of the ESP. 

2.2.1 Plant Site Ambient Conditions 

The plant site is assumed to be in the Ohio River Valley of western Pennsylvania/eastern Ohio/ northern West 

Virginia. The site consists of approximately 300 usable acres; not including ash disposal, within 15 miles of a 

medium sized metropolitan area, with a well established infrastructure capable of supporting the required 

construction workforce. The site is within Seismic Zone 1, as defined by the Uniform Building Code, and the 

ambient design conditions will be: 

Pressure 14.4 psia 

Dry bulb temperature 60 o

F 

Dry bulb temperature range -10 to +110 o

F 

Wet bulb temperature 52 o

F 

D-19

TABLE 2-7 

LOW SULFUR POWER PLANT PERFORMANCE SUMMARY -

100 PERCENT LOAD 

STEAM CYCLE 

Throttle Pressure, psig 

Throttle Temperature, o

F 

Reheat Outlet Temperature 

2,400 

1,000 

1,000 

POWER SUMMARY 

3600 rpm Generator 

GROSS POWER, kWe (Generator terminals) 427,060 

AUXILIARY LOAD SUMMARY, kWe 

Pulverizers 

Primary Air Fans 

Forced Draft Fans 

Induced Draft 

Seal Air Blowers 

Main Feed Pump (Note 1) 

Steam Turbine Auxiliaries 

Condensate Pumps 

Circulating Water Pumps 

Cooling Tower Fans 

Coal Handling 

Limestone Handling & Reagent Prep. 

Ash Handling 

Atomizing Air compressors (Duct Injection) 

Precipitators 

Soot Blowers (Note 2) 

Miscellaneous Balance OF Plant (Note 3) 

Transformer Loss 

1,600 

1,410 

1,020 

3,230 

50 

8,660 

800 

800 

3,400 

1,800 

180 

230 

1,600 

2,700 

900 

neg. 

2,000 

1,020 

TOTAL AUXILIARIES, kWe 

Net Power, kWe 

Net Efficiency, % HHV 

Net Heat Rate, Btu/kWh (HHV) 

22,740 

404,320 

39.1 

8,726 

CONDENSER COOLING DUTY, 106

 Btu/h 1,722 

CONSUMABLES 

As-Received Coal Feed, lb/h 

Sorbent, lb/h 

299,204 

4,277 

Note 1 - Driven by auxiliary steam turbine, electric equivalent shown. 

Note 2 - Soot blowing medium is boiler steam. Electric power consumption is negligible. 

Note 3 - Includes plant control systems, lighting HVAC, etc. 

D-20

2.2.2 Fuel and Sorbent Composition 

The plant performance will be based on a, sub-bituminous, western Powder River Basin (PRB) coal that has 

undergone a moisture reduction and stabilization process. The coal analysis and data are listed in Tables 2-8 and 2-

9. Unit start-up will use No.2 fuel oil. 

2.2.3 Air Quality Standards 

The plant pollution emission requirements for the Low Sulfur Reference Case adhered to Federal and State control 

emission regulations. Although, some environmental regulations may apply on a site specific basis (National 

Environmental Policy Act, Endangered Species Act, National Historic Preservation Act, etc.) will not be considered 

in this project. The following ranges will generally cover most cases: 

SOX: 92 to 95% reduction


NOX: 0.2 to 0.45 lb per MMBtu


Particulate: 0.015 to 0.03 lb per MMBtu


Opacity: 10 to 20 percent


2.2.4 Flue Gas Acid Dew Point. 

Based on a flue gas SO3 concentration of 0.5 ppm and a water concentration of 6.5% at the exit of the air heater, the 

acid dew point is estimated to be approximately 175 o

F. 

2.2.5 Mercury Emission Assumptions 

Table 2-10 provides basic data for baseline and variant mercury emissions. 

2.2.6 LS Reference Power Plant Gas Stream Data 

The following indicates the state point conditions at various flue gas stream locations. 

Flue gas mass flow rate, boiler exit 3,821,126 lb/hr (1,309,735 cfm) 

Flue gas temperature at AH exit 270 o

F 

Flue gas temperature at ESP exit 270 o

F 

The flue gas composition and temperatures at various points of the gas stream are detailed in Table 2-11. This data 

was calculated using the MCPCM described in Section 1 and coal properties for a low sulfur processed derived 

PRB coal. 

D-21

TABLE 2-8


TYPICAL PROCESSED PRB COAL ANALYSIS


Constituent Dry, % As Received, % 

Moisture ------- --------

Carbon 75.25 70.98 

Hydrogen 3.46 4.00 

Nitrogen 1.13 1.07 

Sulfur 0.56 0.53 

Ash 8.19 7.72 

Oxygen 11.41 15.70 

Total 100.00 100.00 

Dry Basis, % As Received, % 

Moisture ----- 4.83 

Ash 8.19 7.72 

Volatile Matter 27.00 25.72 

Fixed Carbon 64.81 61.73 

Total 100.00 100.00 

Sulfur 0.56 0.53 

Btu Content 12,389 11,791 

Moisture and Ash Free (MAF), Btu Content 13,494 

Ash Analysis, % 

Silica, SiO2 22.5 

Aluminum Oxide, Al 13.8 

Iron Oxide, 7.4 

Titanium Dioxide, TiO2 0.8 

Calcium Oxide, MgO 26.6 

Magnesium Oxide, MgO 5.9 

Sodium Oxide, Na2O 1.8 

Potassium Oxide, K2O 0.2 

Sulfur Trioxide, SO3 19.3 

Phosphorous Pentoxide, P2O5 0.6 

Strontium Oxide, SrO 0.4 

Barium Oxide, BaO 0.6 

Manganese Oxide, Mn4 0.1 

Total 100.00 

Ash Fusion Temperature, o

F 

Reducing Oxidizing 

Atmosphere Atmosphere 

Initial Deformation 2295 2395 

Spherical 2300 2405 

Hemispherical 2305 2415 

2310 2425 

D-22

μ

TABLE 2-9


COMPARISON OF FEED COAL AND MODIFIED COAL BASIS


Feed Coal Process Derived Fuel 

Heating Value (Btu/lb) 12,740 13,840 

Carbon (%) 73.4 84.0 

Hydrogen (%) 5.5 3.6 

Nitrogen (%) 1.1 1.3 

Volatiles (%) 47.0 32.0 

TABLE 2-10


MERCURY EMISSIONS DATA


Total Mercury 

Concentration 

(μg/Nm3

) 

Total Mercury 

Emissions Rate 

(g/Hr) 

Total Annual Mercury 

Release1 

(Kg/Yr) 

10 

(Baseline) 

13.8 78.5 

3 3.5 23.5 

30 138 235.5 

1. Based on a 65% plant capacity factor. 

D-23

TABLE 2-11


LS REFERENCE POWER PLANT GAS STREAM DATA


Boiler & Plant Data Summary LS PDF (LS) 

Btu Input Rate (MMBtu/h) 3,528.10 

Coal Input Rate (tons/h) 150.739 

Coal Mass-Energy Ratio (lb/MMBtu) 85.45 

MMBtu/hr Out of Boiler 3,119.59 

Flue Gas @ Economizer Outlet (SCFM/MMBtu) 12,656 

Flue Gas @ Economizer Outlet (SCFM) 744,192 

Wet Flue Gas @ Economizer Outlet (lb/h) 3,518,066 

Wet Air Based on Economizer Outlet (SCFM) 710,817 

Wet Air Based on Economizer Outlet (lb/h) 3,241,152 

Total Air, % (Economizer Outlet) 120.0 

Excess Air, % (Economizer Outlet) 20.0 

Flue Gas @ Air Heater Outlet (SCFM/MMBtu) 13,795 

Flue Gas @ Air Heater Outlet (SCFM) 811,169 

Wet Flue Gas @ Air Heater Outlet (lb/h) 3,821,126 

Wet Air Based on Air Heater Outlet (SCFM) 777,281 

Wet Air Based on Air Heater Outlet (lb/h) 3,544,213 

Wet Air Leakage @ Air Heater (SCFM) 66,464 

Wet Air Leakage @ Air Heater (lb/h) 303,061 

Equivalent Total Air, % (Air Heater Outlet) 131.2 

Equivalent Excess Air, % (Air Heater Outlet) 31.2 

Wet Flue Gas @ Air Heater Outlet (ACFM) 1,309,735 

Air Heater Outlet Flue Gas Temperature, o

F 314 

Air Heater Outlet Pressure, inches Hg. 29.31 

Fly Ash (ton/h) 9.83 

Bottom Ash (ton/h) 2.46 

Total Ash (ton/h) 12.28 

NOTE: Standard Conditions = 60 o

F, 29.92 inches Hg 

D-24

3. Bituminous and Subbituminous Coals Used in Mercury Control Model Runs 

EPA’s mercury control technology application matrix cites three different coals for the model runs. The 

purpose of this section is to identify and document these three coals. 

The two bituminous coals are from West Virginia – ultimate analysis and ash analysis data were obtained 

from the USGS Coal Quality Database. The high sulfur coal has a 3% sulfur content (by weight) and a 

HHV of 12,721 Btu/Lb, while the other has a 0.6% S content (by weight) and a HHV of 14,224 Btu/Lb. 

The subbituminous coal is from Wyoming’s Powder River Basin (PRB) and was already contained in the 

model’s coal library. Data originally came from EPRI’s FGD Cost Program. This coal has a coal sulfur 

content of 0.5% (by weight) and a HHV of 8,335 Btu/Lb. 

TABLE 3-1


Bituminous and Subbituminous Coals Used in Mercury Control Model Runs


WYOMING PRB (LS) 

COAL ULTIMATE ANALYSIS 

(ASTM, as received, weight percent) 

Moisture 

Carbon 

Hydrogen 

Nitrogen 

Chlorine 

Sulfur 

Ash 

Oxygen 

TOTAL 

Mott Spooner HHV (Btu/lb) 

Acid Dew Point, o

F 

COAL ASH ANALYSIS 

SiO2 

Al2O3 

TiO2 

Fe2O3 

CaO 

MgO 

Na2O 

K2O 

P2O5 

SO3 

Other Unaccounted for 

TOTAL 

30.40% 

47.85% 

3.40% 

0.62% 

0.03% 

0.48% 

6.40% 

10.82% 

100.00% 

8,335 

224 

WYOMING PRB (LS) 

31.60% 

15.30% 

1.10% 

4.60% 

22.80% 

4.70% 

1.30% 

0.40% 

0.80% 

16.60% 

0.80% 

100.00% 

E. Bituminous (HS) 

3.10% 

69.82% 

5.00% 

1.26% 

0.12% 

3.00% 

9.00% 

8.70% 

100.00% 

12,721 

215 

E. Bituminous (HS) 

29.00% 

17.00% 

0.74% 

36.00% 

6.50% 

0.83% 

0.20% 

1.20% 

0.22% 

7.30% 

1.01% 

100.00% 

E. Bituminous (LS) 

2.20% 

78.48% 

5.50% 

1.30% 

0.12% 

0.60% 

3.80% 

8.00% 

100.00% 

14,224 

292 

E. Bituminous (LS) 

51.00% 

30.00% 

1.50% 

5.60% 

4.20% 

0.76% 

1.40% 

0.40% 

1.80% 

2.60% 

0.74% 

100.00% 

D-25

4. COST ESTIMATION BASIS 

4.1 Introduction 

This section defines the methodology used to estimate capital and O&M costs within the NETL Mercury 

Control Performance and Cost Model. Two different spreadsheets within the model provide for cost 

estimation. The Capital Cost Model Sheet makes use of the power plant and mercury control performance 

data to calculate the capital costs associated with a case study’s mercury control design configuration. The 

costing covers the following equipment sections: 

•	 Spray Cooling Water System (Equipment: water storage tank, pumps, transport piping, and 

injection grid with nozzles, and control system) 

•	 Solid Sorbent Storage and Injection System (Equipment: silo pneumatic loading system, 

storage silos, hoppers, blowers, transport piping, control system) 

• Sorbent Recycle System (Equipment: hoppers, blowers, transport piping, control system) 

•	 Pulse-Jet Fabric Filter and Accessories (Equipment: pulse-jet FF, filter bags, ductwork, dampers, 

and MCCs and instrumentation and PLC controls for baghouse operation. Excludes Ash Removal 

System, power distribution and power supply, and distributed control system) 

• Sorbent Disposal System (Equipment: hoppers, blowers, transport piping, control system) 

• CEMS Upgrade 

• Flue Gas Desulfurization (FGD) System (cost algorithms are currently not provided) 

• FGD System Enhancements (cost algorithms are currently not provided) 

• Circulating Fluidized Bed Absorber System (cost algorithms are currently not provided) 

A total mercury control system cost is calculated from the following cost components: 1) equipment, 2) 

related materials, 3) field and indirect labor, 4) sales tax, 5) engineering and home office fees, 6) process 

and project contingencies, 7) retrofit factors, and 9) general facilities. Maintenance costs are also 

calculated as a percentage of the bare erected cost (e.g., 2%). Section 4.2 fully describes the methodology 

used to estimate the total installed retrofit capital cost. Section 4.3 defines specific algorithms used 

calculate specific equipment and installation labor costs. 

The System Economic Model Sheet calculates mercury control system O&M, total system investment, 

total system capital requirement, and then levelizes the capital and O&M to establish single value for $/lb of 

mercury removed. Twenty case studies are handled simultaneously in this sheet. Sections 4.4 and 4.5 

fully describe the methodology used to estimate these costs. 

4.2 Capital Cost Estimation Basis 

The cost of each equipment section, as identified in Section 4.1, is estimated according to the following 

procedure: 

Bare Installed Retrofit Cost = (Process Equipment + Related Field Materials + Field Labor + 

Indirect Field Costs + Sales Tax) x Retrofit Factor 

Equipment, field materials and field labor are specified via algorithms.


Indirect field costs are calculated as percentage of field labor (7% currently specified).


D-26

Sales tax is calculated as a percentage of the sum of the four cost elements (0% currently 

specified) 

Retrofit Factor (accounts for retrofit difficulty) = 1.15 (Specified by EPA on 4/4/00) 

Engineering & Home Office Overhead/Fees = Bare Installed Retrofit Cost x E&HO Percentage 

EH&O Percentage = 10% (Specified by EPA on 4/4/00) 

Process Contingency = Bare Installed Retrofit Cost x Process Contingency Percentage 

Process Contingency Percentage = 5% (Specified by EPA on 4/4/00) 

Project Contingency = (Bare Installed Retrofit Cost + Engineering & Home Office 

Overhead/Fees + Process Contingency) x Project Contingency Percentage 

Project Contingency Percentage = 15% (Specified by EPA on 4/4/00) 

Total Cost of Each Equipment Section = Bare Installed Retrofit Cost + Engineering & Home 

Office Overhead/Fees + Process Contingency + Project Contingency 

The total capital cost of the mercury control system is calculated to include the sum of all equipment 

sections and the total cost of general facilities as follows: 

General Facilities Cost = (Bare Installed Retrofit Cost x General Facilities Percentage 

General Facilities Percentage = 5% (Specified by EPA on 4/4/00) 

Project Contingency Percentage defined above 

___________________________________________________________________________ 

Total Control Capital Cost = Sum of Equipment Section Total Costs + General Facilities Cost 

4.3 Equipment and Installation Labor Cost Estimation 

This section of the memo defines the equipment cost algorithms used in the Capital Cost Model Sheet. 

Each equipment section is defined separately below. Costs are updated from their baseline year values via 

use of the Chemical Engineering Annual Plant Index (CEI). The costing algorithms relate to a December 

1998 baseline for which the CI value equals 389.5. The ratio of the current index value (e.g., December 

1999) and the baseline value therefore yields a cost inflator that adjusts control costs to the specified year. 

4.3.1 Spray Cooling Water System 

Process Equipment (x $1000), $E 

$E = 1900 x (GPM/215)0.65 x CEI/389.5 

GPM = Water flow in gallons/minute 

Field Materials (x $1000), $FM 

$FM = 1700 x (GPM/215)0.65 x CEI/389.5 

D-27

Field Labor (x $1000), $FL 

$FL = 1500 x (GPM/215)0.65 x CEI/389.5 

Indirect Field Costs (x $1000), $IF 

$IF = $FL x 0.07 

Bare Installed Cost (x $1000) = $E + $FM + $FL + $IF 

Example:	 GPM = 27.4 gpm (Cools flue gas from 290 F to 270 F, 472 MWe,net) 

CEI = 399.7 (November 1999) 

Bare Installed Cost (x $1000) = 511 + 457+ 404 + 28 = 1,611 or $3.41/kW 

4.3.2	 Solid Sorbent Injection System 

Process Equipment (x $1000), $E 

$E = 400 x ((SF x 1000/454)/5486)0.65 x CEI/389.5 

SF = Sorbent Feed, Kg/Hr 

Field Materials (x $1000), $FM 

$FM = 900 x ((SF x 1000/454)/5486)0.65 x CEI/389.5 

Field Labor (x $1000), $FL 

$FL = 2600 x ((SF x 1000/454)/5486)0.65 x CEI/389.5 

Indirect Field Costs (x $1000), $IF 

$IF = $FL x 0.07 

Bare Installed Cost (x $1000) = $E + $FM + $FL + $IF 

Example:	 SF = 157 Kg/Hr (Based on 3.73 lb/MMacf, 472 MWe,net) 

CEI = 399.7 (November 1999) 

Bare Installed Cost (x $1000) = 68+ 153 + 442 + 31 = 799 or $1.69/kW 

4.3.3 Sorbent Recycle System 

Process Equipment (x $1000), $E 

$E = 1200 x (RR/13) x CEI/389.5 

RR = Recycle (sorbent and ash), Tons/Hr 

D-28

Field Materials (x $1000), $FM


$FM = $E


Field Labor (x $1000), $FL


$FL = $E


Indirect Field Costs (x $1000), $IF


$IF = $FL x 0.07


Bare Installed Cost (x $1000) = $E + $FM + $FL + $IF 

4.3.4 Pulse-Jet Fabric Filter and Accessories 

Process Equipment (x $1000), $E 

$E = 4800 x ((GFR/ACR)/84,326))0.80 x CEI/389.5 

GFR = Flue Gas Flow Rate, acfm 

ACR = PJFF air/cloth ratio, ft

3

/min/ft

2 

Field Materials (x $1000), $FM 

$FM = 500 x ((GFR/ACR)/84,326))0.80 x CEI/389.5 

Field Labor (x $1000), $FL 

$FL = 2700 x ((GFR/ACR)/84,326))0.80 x CEI/389.5 

Indirect Field Costs (x $1000), $IF 

$IF = $FL x 0.07 

Bare Installed Cost (x $1000) = $E + $FM + $FL + $IF 

Example:	 GFR = 1,547,360 acfm (Based on 472 MWe,net) 

ACR = 10 ft

3

/min/ft

2 

CEI = 399.7 (November 1999) 

Bare Installed Cost (x $1000) = 8,006+ 834 + 4,503 + 315 = 15,707 or $33/kW 

4.3.5 Sorbent Disposal System 

Process Equipment (x $1000), $E 

$E = 100 x (DS/6) x CEI/389.5 

DS = Disposal Solids (spent sorbent and ash), Tons/Hr 

D-29

Field Materials (x $1000), $FM


$FM = 2 x $E


Field Labor (x $1000), $FL


$FL = 6 x $E


Indirect Field Costs (x $1000), $IF


$IF = $FL x 0.07


Bare Installed Cost (x $1000) = $E + $FM + $FL + $IF 

4.3.6	 CEMS Upgrade 

Process Equipment (x $1000), $E 

$E = 10 x (MW/290.4)0.75 x CEI/389.5 

MW = Power Plant Application Net Capacity, MWe,net 

Field Materials (x $1000), $FM 

$FM = 0 

Field Labor (x $1000), $FL 

$FL = 1.2 x $E 

Indirect Field Costs (x $1000), $IF 

$IF = $FL x 0.07 

Bare Installed Cost (x $1000) = $E + $FM + $FL + $IF 

4.4 Mercury Control System O&M Cost Estimation 

4.4.1 O&M Cost Parameters 

The O&M cost consists of the following labor and maintenance components: 

Operating Labor: cost of system operating and administrative personnel; unit labor rates and 

manpower requirements/shift are specified in the case study O&M table and can be specified 

independently for each case study. 

Maintenance Labor: 40% of the total maintenance cost calculated in the Capital Cost Model 

Sheet 

Maintenance Material: 60% of the total maintenance cost calculated in the Capital Cost Model 

Sheet 

D-30

Administrative and Support Labor: Calculated as a percentage (labor overhead charge rate) of 

the sum of the operating and maintenance labor cost; overhead charge specified in the case study 

O&M table and can be specified independently for each case study. 

Consumable values are taken from the Technical Model Results Sheet. The O&M cost consists of the 

following consumable components: 

Water (for flue gas humidification), gallons/Hr: unit cost = $/1000 gallons (e.g., 0.80), 

specified in case study table 

Water quantity is taken from Combustion Calculations Sheet. 

Sorbent (e.g., Activated Carbon), tons /Hr: unit cost = $/ton (e.g., 1,100), specified in case study 

table 

Sorbent unit cost is an input in the Application Input Sensitivity Sheet 

Incremental Power, kW-Hr: unit cost = $/MW-Hr (e.g., 30), specified in case study table 

Fan power accounts for the added pressure drop across the mercury control equipment, such as the 

fabric filter. AC injection system power required to transport sorbent to flue gas duct. 

Humidification system power required to pump water to an injection grid in the ductwork. 

Waste Disposal, tons/Hr: unit cost = $/ton (e.g., 30), specified in case study table 

Waste sorbent is generated by the mercury control system. This mercury-laden sorbent must be disposed of 

or processed for mercury removal and recovery. For some design configurations, spent sorbent is captured 

with the fly ash and must be disposed of with the ash at the cost of ash disposal. For some design 

configurations, spent sorbent is collected with residual ash from the ESP. This material can be disposed of 

with the rest of the plant’s fly ash or it can be processed separately if deemed a hazardous material. 

The user specifies sorbent to be hazardous or non-hazardous in the Application Input Sensitivity 

Sheet. Unit costs for both conventional and hazardous waste disposal are also specified there. 

Mercury Byproduct, lb/Hr: unit cost = $/ton (e.g., 30), specified in case study table 

If the spent sorbent is processed for recovery of mercury, then a by-product credit can be applied. 

This will be applied only if the user has designated the spent AC as hazardous waste material. 

4.4.2 Key O&M Cost Parameter Values 

Labor:


Operating Labor Rate (base) -- $25/Hr (specified by EPA 4/4/00)


Total Operating Jobs – 0.833 OJ/Shift


Consumables:


Water – 0.42 Mills/gallon (specified by EPA 4/4/00)


Activated Carbon -- $1/Kg (specified by EPA 4/4/00)


Sorbent Storage Capacity – 30 days (specified by EPA 4/4/00)


Electricity – 25 Mills/kW-Hr (specified by EPA 4/4/00)


Waste Disposal (ash, AC, mercury) -- $30/Ton


Waste Disposal (Hazardous waste designation) -- $1700/Ton


D-31

Plant Capacity Factor – 65% (specified by EPA 4/4/00) 

4.5 Total Mercury Control System Capital Requirement 

The total calculated investment in the mercury control system includes the total capital investment 

calculated in the Capital Cost Model Sheet, interest during construction (AFUDC), and the following 

additional cost components: 

Royalty allowance -- possible technology royalty charges may apply 

Preproduction Costs -- covers the cost of operator training, equipment checkout, major 

modifications to equipment, extra maintenance, and inefficient use of consumables. Calculated as 

1 month of fixed operating costs (O&M labor, admin and support labor, and maintenance 

materials); 1 month of variable operating costs (all consumables) at full capacity; and 2 % of the 

total system investment. 

Inventory Capital -- value of initial inventory of activated carbon that is capitalized. This 

accounts for an initial storage supply of AC (e.g., 30 day supply). 

Initial Catalysts and Chemicals Charge -- the initial cost of any catalysts or chemicals contained 

in the process equipment, but not in storage. Does not apply to the mercury control systems. 

4.5.1 Levelized Cost of Mercury Control 

The total cost of mercury control must account for the total capital requirement (expressed as $/kW) and 

the total operating and maintenance expenses (expressed as mills/kW-Hr). In order to calculate an 

annualized cost that accounts for both of these, the capital requirement is annuitized via use of the 

“Levelized Carrying Charge Rate.” The Levelized Carrying Charge Rate assumes a 30 year operating 

period and accounts for return on debt, return on equity, income taxes, book depreciation, property tax, and 

insurance payments. The Levelized Carrying Charge Rate is specified in this sheet in the section called 

“Financial Data-Factors.” It is multiplied times the total system capital requirement to derive the 

annualized value and converted to units of mills/kW-Hr based on the annual operating hours of the plant 

(capacity factor x 8,760 hrs/yr). 

The first-year O&M costs that are calculated in this sheet are also levelized in order to account for both 

apparent and real escalation rates of labor, materials, and consumables over the expected operating time 

period (e.g., 30 years). A levelization factor is specified in this sheet in the section called “Financial 

Data-Factors.” It is multiplied by the total O&M cost. 

The levelized carrying charge and the levelized O&M are summed to yield a total annualized cost which is 

divided by the annual mercury removed in order to derive a unique cost of removal with units of $/ton 

mercury removed. 

4.5.2 Financial Parameter Values 

Apparent General Escalation Rate – 2.9%/Year


Royalty Allowance -- $0


Levelized Carrying Charge Rate – 0.133


Federal Income Tax Rate – 34%


Weighted Cost of Capital (after tax) – 9.4%


Design and Construction – 1 year


Book Life – 30 Years


D-32

ATTACHMENT 2


Description of


Mercury Control Performance Algorithms Used in the


National Energy Technology Laboratory


Mercury Control Performance and Cost Model


D-33

Description of Mercury Control Performance Algorithms Used in the 

NETL Mercury Control Performance and Cost Model 

The purpose of this report is to document the mercury control performance models that are currently incorporated 

into the NETL Mercury Control Cost Model. CMU staff based on available pilot- and full-scale data has developed 

these models, in the form of basic curve-fitting algorithms. The algorithms calculate the activated carbon feed 

(Lb/MMacf basis) required to achieve specified mercury removal efficiency for a particular control method (e.g., 

activated carbon injection upstream of an existing ESP). The performance prediction is based solely on control 

method, flue gas temperature and coal type (bituminous vs. subbituminous). 

1. Mercury Control Retrofit Configurations: ESP-1, ESP-4, SD/ESP-1, and SD/ESP-2 

Description: Activated carbon injected upstream of existing ESP. ESP-1 -- no flue gas temperature 

control, ESP-4 – flue gas temperature control via water injection. 

1.1 Bituminous Coal 

Coal Source: Eastern bituminous coal, West Virginia (< 1%S and 0.1% chlorine) 

Data Sources: 

PROJECT: ADA Technologies/Public Service Electric and Gas Company/EPRI -- Mercury Control 

in Utility ESPs and Baghouses through Dry Carbon-Based Sorbent Injection Pilot-Scale 

Demonstration 

Pilot-Scale Tests: 160 acfm slipstream from the 620 MWe Hudson Generating Station, Unit 2,


opposed-fired furnace, Eastern bituminous coal from West Virginia (< 1%S and 0.1% chlorine), ESP


SCA = 287 ft

2

/Kacfm


Literature Source: Waugh, E., B. Jensen, L. Lapatnick, F. Gibbons, S. Sjostrom, J. Ruhl, R. Slye,


and R. Chang, “Mercury Control in Utility ESPs and Baghouses through Dry Carbon-Based Sorbent


Injection Pilot-Scale Demonstration,” EPRI-DOE-EPA Combined Utility Air Pollutant Control


Symposium, August 1997.


ICR Data: Baseline removal due to ash alone is from preliminary ICR report data compiled by


Dennis Smith, DOE/NETL (5/1/00)


- Low sulfur bit coal ash removes constant 57% mercury


- Total removal is 57% from ash and 0 ==> 43% from ACI


- Baseline mercury removal (ash alone) is an average of 2 plants with 250F inlet and 4


plants with >300F inlet, both approximately 57% 

- Correlation for 225F not included; no baseline removal available and temperature below 

H2SO4 dewpoint. 

ICR Results and Pilot-Scale Test Results Combined: 

- Mercury removal due to ash for both temperatures is 57% and is not a function of ACI 

- Mercury removal due to ACI is not a function of ash but is a function of temperature 

- The two removals can be combined: 57% from ash and between 0% and 43% from ACI 

D-34

Algorithm 1: Incorporates ICR Results 

Hg Removal = 100 – [a/(ACI+b)c

] 

Coefficient Flue Gas Temperature, o

F 

225 250 275 

a 55.536 159.27 494.64 

b 1.4351 3.6838 11.554 

c 1 1 1 

R^2 (error) 0.99 0.85 0.82 

ACI Range 

(Lb/MMacf) 

0 - 5 0 - 5 0 - 5 

Algorithm 2: Excludes ICR Results 

Hg Removal = 100 – [a/(ACI+b)c] 

Coefficient Flue Gas Temperature, o

F 

225 250 275 

a 128.69 370.98 1218.6 

b 1.4284 3.6937 12.14 

c 1 1 1 

R^2 (error) 0.99 0.85 0.89 

ACI Range 

(Lb/MMacf) 

0 - 5 0 - 5 0 - 5 

Where, 	 a,b,c = numerical coefficients 

ACI = Activated Carbon Injection Feed rate, Lb/MMacf 

Hg Removal = % total mercury removed, inlet to outlet 

1.2 Subbituminous Coal 

Coal Source: PRB Subbituminous coal 

Data Source: 

PROJECT: Pilot-Scale Carbon Injection for Mercury Control at Comanche Station 

Pilot-Scale Tests: 600 acfm slipstream from the 350 MWe Comanche Station, Unit 2 PSCo, 

opposed-fired furnace, PRB coal from Belle Ayr mine, Pulse-Jet with A/C ratio = 12 ft/min, most 

fly ash removed upstream, Flue gas contained little HCl, 275 to 325 ppm SO2 (@ 3% O2 dry), 180 

to 250 ppm NOx (@ 3% O2 dry) 

Literature Source: AWMA 99-524, S.M. Haythornthwaite, J. Smith, G. Anderson, T. Hunt, M. 

Fox, R. Chang, T. Brown, 1999 

D-35

--

Algorithm: 

Hg Removal = 100 – [a/(ACI+b)c

] 

Coefficient Flue Gas Temperature, o

F 

230 280 300 345 

a 1373.11 247.772 296.714 319.587 

b 32.1071 3.3867 4.2911 3.6636 

c 1 1 1 1 

R^2 (error) - 0.89 0.84 0.83 

ACI Range 

(Lb/MMacf) 

0 - 1 0 - 5 0 - 5 0 - 5 

Where, a,b,c = numerical coefficients 

ACI = Activated Carbon Injection Feed rate, Lb/MMacf 

Hg Removal = % total mercury removed, inlet to outlet 

2. Mercury Control Retrofit Configurations: ESP-3, ESP-6 

Description: Pulse-Jet FF (PJFF) retrofitted after existing ESP. Activated carbon injected upstream of PJFF. 

ESP-3 -- no flue gas temperature control, ESP-6 -- flue gas temperature control via water 

injection. 

2.1 Bituminous Coal 

Coal Source: Eastern bituminous coal, West Virginia (< 1%S and 0.1% chlorine) 

Data Source: 

PROJECT:	 ADA Technologies/Public Service Electric and Gas Company/EPRI Mercury 

Control in Utility ESPs and Baghouses through Dry Carbon-Based Sorbent Injection 

Pilot-Scale Demonstration 

Pilot-Scale Tests: 4,000 acfm slipstream from the 620 MWe Hudson Generating Station, Unit 2, 

opposed-fired furnace, Eastern bituminous coal from West Virginia (< 1%S and 0.1% chlorine), 

Pulse-jet FF installed downstream of cold ESP, A/C ratio = 12 ft/min, tests conducted with AC 

and fly ash 

Literature Source: Waugh, E., B. Jensen, L. Lapatnick, F. Gibbons, S. Sjostrom, J. Ruhl, R. Slye, 

and R. Chang, “Mercury Control in Utility ESPs and Baghouses through Dry Carbon-Based 

Sorbent Injection Pilot-Scale Demonstration,” EPRI-DOE-EPA Combined Utility Air Pollutant 

Control Symposium, August 1997. 

ICR Results and Pilot-Scale Test Results Combined: 

- Mercury removal due to ash for both temperatures is 57% and is not a function of ACI 

- Mercury removal due to ACI is not a function of ash but is a function of temperature 

- The two removals can be combined: 57% from ash and between 0% and 43% from ACI 

D-36

Algorithm 1: Incorporates ICR Results 

Hg Removal = 100 – [a/(ACI+b)c

] 

Coefficient Flue Gas Temperature, o

F 

240 285 285 

a 51.038 159.4 159.4 

b 1.3194 3.5606 3.5606 

c 1 1 1 

R^2 (error) 0.73 0.66 0.66 

ACI Range 

(Lb/MMacf) 

0 - 5 0 - 5 0 - 5 

Where, 	 a,b,c = numerical coefficients 

ACI = Activated Carbon Injection Feed rate, Lb/MMacf 

Hg Removal = % total mercury removed, inlet to outlet 

Algorithm 2: Excludes ICR Results 

Hg Removal = 100 – [a/(ACI+b)c

] 

Coefficient Flue Gas Temperature, o

F 

240 285 

a 118.69 370.69 

b 1.3194 3.5606 

c 1 1 

R^2 (error) 0.73 0.66 

ACI Range 

(Lb/MMacf) 

0 - 5 0 - 5 

Where, 	 a,b,c = numerical coefficients 

ACI = Activated Carbon Injection Feed rate, Lb/MMacf 

Hg Removal = % total mercury removed, inlet to outlet 

2.2 Subbituminous Coal 

Coal Source: PRB Subbituminous coal 

Data Source: 

PROJECT: ADA Technologies/PS Colorado/EPRI/NETL – Pilot-Scale Demonstration of Dry 

Carbon-Based Sorbent Injection for Hg Control in Utility ESPs and FFs – Phase I 

Pilot-Scale Tests: 600 acfm slipstream from the 350 MWe Comanche Station, Unit 2 PSCo, 

opposed-fired furnace, PRB coal from Belle Ayr mine, Pulse-Jet with A/C ratio = 12 ft/min, most 

fly ash removed upstream, Flue gas contained little HCl, 275 to 325 ppm SO2 (@ 3% O2 dry), 180 

to 250 ppm NOX (@ 3% O2 dry) 

Literature Source: Ebner, T., J. Ruhl, R. Slye, J. Smith, T. Hunt, R. Chang, and T. Brown, “ 

Demonstration of Dry Carbon-Based Sorbent Injection for Mercury Control in Utility ESPs and 

Baghouses,” EPRI-DOE-EPA Combined Utility Air Pollutant Control Symposium, August 1997. 

D-37

Algorithm: 

Hg Removal = 100 – [a/(ACI+b)c

] 

Coefficient Flue Gas Temperature, o

F 

250 280 300 

a 4.2774 27.5595 148.0419 

b 0.04793 0.31345 0.92051 

c 1 1 1 

R^2 (error) 0.99 0.8 0.96 

ACI Range 

(Lb/MMacf) 

0 – 3 0 – 3 0 – 3 

Where,	 a,b,c = numerical coefficients 

ACI = Activated Carbon Injection Feed rate, Lb/MMacf 

Hg Removal = % total mercury removed, inlet to outlet 

3. Mercury Control Retrofit Configurations: FF-1, FF-2, SD/FF-1, and SD/FF-2 

Description:	 Activated carbon injected upstream of existing reverse-gas baghouse. FF-1 -- no flue gas 

temperature control, FF-2 – flue gas temperature control via water injection. 

3.1 Bituminous Coal 

No data for bituminous coal applications. 

3.2 Subbituminous Coal 

Coal Source: PRB coal from Belle Ayr mine 

Data Source: 

PROJECT: ADA Technologies/PS Colorado/EPRI/NETL – Pilot-Scale Demonstration of Dry 

Carbon-Based Sorbent Injection for Hg Control in Utility ESPs and FFs 

Pilot-Scale Tests: 600 acfm slipstream from the 350 MWe Comanche Station, Unit 2 PSCo, 

opposed-fired furnace, PRB coal from Belle Ayr mine, Flue gas contained little HCl, 275 to 325 

ppm SO2 (@ 3% O2 dry), 180 to 250 ppm NOx (@ 3% O2 dry) 

Literature Source: AWMA 99-524, S.M. Haythornthwaite, J. Smith, G. Anderson, T. Hunt, M. 

Fox, R. Chang, T. Brown, 1999 

D-38

Algorithm: 

Hg Removal = 100 – [a/(ACI+b)c

] 

Coefficient Flue Gas Temperature, o

F 

230 275 330 

a 266.119 23.20196 27.9742 

b 11.1359 0.43006 0.31913 

c 1 1 1 

R^2 (error) 0.03 0.88 0.87 

ACI Range 

(Lb/MMacf) 

0 - 1 0 - 5 0 - 5 

Where, 	 a,b,c = numerical coefficients 

ACI = Activated Carbon Injection Feed rate, Lb/MMacf 

Hg Removal = % total mercury removed, inlet to outlet 

4. Mercury Control Retrofit Configurations: WS-1 

Description: Existing ESP for particulate control and wet FGD for SO2 control. 

4.1 Bituminous Coal 

Coal Source: Bituminous coal 

Data Source: 

Mercury Speciation and Wet FGD removal: Memo from D. Smith, DOE/NETL, 4/29/2000 

Methodology: 

• Hg speciation for Bituminous coal: 70% oxidized, 30% elemental 

•	 Existing ESP assumed to remove Hg at rate predicted by ESP-1, ESP-4 algorithm for 

bituminous coal (Section 1.1) 

• Wet FGD removes 100% of oxidized Hg and 0% elemental Hg 

4.2 Subbituminous Coal 

Coal Source: Subbituminous coal 

Data Source: 

Mercury Speciation and Wet FGD removal: Memo from D. Smith, DOE/NETL, 4/29/2000 

Methodology: 

• Hg speciation for subbituminous coal: 25% oxidized, 75% elemental 

•	 Existing ESP assumed to remove Hg at rate predicted by ESP-1, ESP-4 algorithm for 

subbituminous coal (Section 1.2) 

• Wet FGD removes 100% of oxidized Hg and 0% elemental Hg 

5. Mercury Control Retrofit Configurations: WS-2 

Description: Existing SNCR for NOx control, existing ESP for particulate control and wet FGD for SO2 

control. 

5.1 Bituminous Coal 

D-39

Coal Source: Bituminous coal 

Data Source: 

Mercury Speciation and Wet FGD removal: Memo from D. Smith, DOE/NETL, 4/29/2000 

Impact of SNCR: Not specified 

Methodology: 

• Hg speciation for Bituminous coal: 70% oxidized, 30% elemental 

•	 Existing ESP assumed to remove Hg at rate predicted by ESP-1, ESP-4 algorithm 

(Section 1.1) 

• SNCR installation increases oxidized Hg by 0% (e.g., 70% total) 

• Wet FGD removes 100% of oxidized Hg and 0% elemental Hg 

5.2 Subbituminous Coal 

Coal Source: Subbituminous coal 

Data Source: 

Mercury Speciation and Wet FGD removal: Memo from D. Smith, DOE/NETL, 4/29/2000 

Impact of SNCR: Not specified 

Methodology: 

• Hg speciation for subbituminous coal: 25% oxidized, 75% elemental 

•	 Existing ESP assumed to remove Hg at rate predicted by ESP-1, ESP-4 algorithm for 

subbituminous coal (Section 1.2) 

• SNCR installation increases oxidized Hg by 0% (e.g., 25% total) 

• Wet FGD removes 100% of oxidized Hg and 0% elemental Hg 

6. Mercury Control Retrofit Configurations: WS-3 

Description:	 Existing SCR for NOX control, existing ESP for particulate control and wet FGD for SO2 

control. 

6.1 Bituminous Coal 

Coal Source: Bituminous coal 

Data Source: 

Mercury Speciation and Wet FGD removal: Memo from D. Smith, DOE/NETL, 4/29/2000 

Impact of SCR: Mercury control phone meeting 4/28/2000 

Methodology: 

• Hg speciation for Bituminous coal: 70% oxidized, 30% elemental 

•	 Existing ESP assumed to remove Hg at rate predicted by ESP-1, ESP-4 algorithm 

(Section 1.1) 

• SCR installation increases oxidized Hg by 35% (e.g., 94.5% total) 

• Wet FGD removes 100% of oxidized Hg and 0% elemental Hg 

D-40

6.2 Subbituminous Coal 

Coal Source: Subbituminous coal 

Data Source: 

Mercury Speciation and Wet FGD removal: Memo from D. Smith, DOE/NETL, 4/29/2000 

Impact of SCR: Mercury control phone meeting 4/28/2000 

Methodology: 

• Hg speciation for subbituminous coal: 25% oxidized, 75% elemental 

•	 Existing ESP assumed to remove Hg at rate predicted by ESP-1, ESP-4 algorithm for 

subbituminous coal (Section 1.2) 

• SCR installation increases oxidized Hg by 35% (e.g., 33.75% total) 

• Wet FGD removes 100% of oxidized Hg and 0% elemental Hg 

7. Mercury Control Retrofit Configurations: ESP-7, Combined AC + Lime Sorbent 

Description: Pulse-Jet FF (PJFF) retrofitted after existing ESP. Combined activated carbon/Lime sorbent 

injected upstream of PJFF. 

7.1 Bituminous Coal 

Coal Source: Bituminous coal 

Data Source: 

Butz, J.R., R. Chang, E.G. Waugh, “Use of Sorbents for Air Toxics Control in a Pilot-Scale 

COHPAC Baghouse," paper presented at the Air and Waste Management Association’s 92nd 

annual meeting and exhibition, June 20-24, 1999, St. Louis, Mo. 

Methodology: 

• Assumes AC:Lime ratio = 2:19 

• Assume 90%+ Hg Removal based on ADA Technologies tests at PSE&G 

• 1- 4 lb/MMacf Sorbent Concentration yields 90-95% Hg Removal 

D-41

ATTACHMENT 3


Summary of Mercury Control Cases Analyzed with National


Energy Technology Laboratory


Mercury Control Performance and Cost Model


D-42

Summary of Mercury Control Cases Analyzed with NETL’s Mercury Control 

Performance and Cost Model 

The purpose of this document is to summarize the mercury control cases evaluated with NETL’s Mercury 

Control Performance and Cost Model. 

1. Original Cases Designated by EPA 

Table 1 identifies the original matrix of cases that were designated by EPA for evaluation. Of those 

designated in the table, the following model plant types were actually evaluated: 1, 4, 7, 8, 10, 13, 16, and 

17. The others were not assessed due to lack of control performance data or similarity to another model 

plant type. Table 2 describes the mercury control retrofit scenario configurations used in Table 1. 

2. EPA Evaluation Requirements 

For each combination of model plant and pertinent mercury control technology (see Tables 1 and 2), EPA 

requested estimates of capital cost ($/kW), fixed O&M cost (mills/kWh), and variable O&M cost 

(mills/kWh) using the EPRI TAG methodology. These cost estimates were in 1999 constant dollars. EPA 

also designated the following analysis assumptions: 

(1) Mercury removal of 50%, 60%, 70%, 80%, and 90% for each of the model plants; 

(2)	 Flue gas temperature at activated carbon injection location of 150 C for cases without spray cooling 

(SC) and an approach to saturation of 10 degrees celsius (18 degrees F) for cases with SC; 

(3) plant capacity factor of 65%; 

(4) activated carbon cost of $1.0/kg; 

(5) water cost of 0.42 mills/gallon; 

(6) energy cost 25 mills/kWh; 

(7) 30 days of sorbent storage; 

(8) labor cost of $25/h; and 

(6) other economic assumptions 

(i) general facilities – 5% of direct process capital (DPC) 

(ii) engineering and home office expense – 10% of DPC 

(iii) process contingency – 5% of DPC 

(iv) project contingency – 15% of DPC + (i) + (ii) + (iii) 

(v) pre-production cost – 2% of total plant investment (TPI) 

(vi) retrofit factor – 1.15 

(vii) fixed O&M – 1.5% of TPI 

D-43

TABLE 1


ORIGINAL MERCURY CONTROL CASES DESIGNATED BY EPA


MODEL 

PLANT 

# 

POWER 

PLANT 

SIZE 

(MW) 

COAL 

EXISTING 

PLANT 

EMISSION 

CONTROLS 

MERCURY 

CONTROL(S) 

CO-BENEFIT 

CASE(S) 

with 

Typea S% 

1 975 Bit 3 ESP + FGD ESP-1, ESP-3 SCR 

2 975 Bit 3 FF + FGD FF-1 SCR 

3 

Same as 1 

975 Bit 3 HESP + FGD HESP-1 SCR 

4 975 Bit 0.6 ESP ESP-4, ESP-6 SCR 

5 975 Bit 0.6 FF FF-2 SCR 

6 

Same as 4 

975 Bit 0.6 HESP HESP-1 SCR 

7 975 Subbit 0.5 ESP ESP-4, ESP-6 SCR 

8 975 Subbit 0.5 FF FF-2 SCR 

9 975 Subbit 0.5 HESP HESP-1 SCR 

10 100 Bit 3 SD + ESP SD/ESP-1 

11 100 Bit 3 SD + FF SD/FF-1 

12 100 Bit 3 HESP + FGD HESP-1 

13 100 Bit 0.6 ESP ESP-4, ESP-6 

14 100 Bit 0.6 FF FF-2 

15 

Same as 13 

100 Bit 0.6 HESP HESP-1 

16 100 Subbit 0.5 ESP ESP-4, ESP-6 

17 100 Subbit 0.5 FF FF-2 

18 

Same as 16 

100 Subbit 0.5 HESP HESP-1 

a. Bit = bituminous coal; Subbit = subbituminous coal. 

D-44

Table 2


Mercury Control Technology Retrofit Scenarios


CASE EXISTING EQUIPMENT RETROFIT SCENARIO 

ESP-1 Cold-side ESP (ESP) ACI 

ESP-3 ACI + PFF 

ESP-4 SC + ACI 

ESP-6 SC + ACI + PFF 

ESP-7 SC + AC + lime + PFF 

ESP-8 SC + ACI + CFBA 

ESP-9 SC + AC + lime + CFBA 

HESP-1 Hot-side ESP (HESP) SC + ACI + PFF 

FF-1 Fabric filter (FF) ACI 

FF-2 SC + ACI 

FF-3 SC + AC + lime + PFF 

SD/FF-1 Spray dryer (SD) + FF ACI 

SD/ESP-1 SD + ESP ACI 

WS-1 ESP + wet scrubber (WS) 

WS-2 SNCR + ESP + WS 

WS-3 SCR + ESP + WS 

SCR-SD-1 SCR + SD + FF 

D-45

3. Sensitivity Cases 

In addition to the original cases described above, EPA also requested five sensitivity cases that are 

described below. 

3.1 Power Plant Size 

The purpose of this sensitivity analysis was to add 500 MWe cases for Model Plant Applications 1, 4, 7, 8. 

This work was originally completed on 6/6/2000. The sensitivity runs were updated on 6-14-2000 to 

correct a programming error. The results are presented via table and graphs in Excel file “Mercury 

Control Results 6-15-00.xls.” 

3.2 Mercury Control Operating Temperature 

The purpose of this sensitivity analysis was to change the mercury control operating temperature to: Acid Dew 

Point (ADP) + 40 F for the following cases: 

Plant 4, 500 MW 

Plant 7, 500 MW 

Plant 8, 500 MW 

Plant 13, 100 MW 

Plant 16, 100 MW 

Plant 17, 100 MW 

High sulfur cases are not impacted by the change. 975 MW cases were not run. 

This work was originally completed on 6/6/2000. The sensitivity runs were updated on 6-14-2000 to 

correct a programming error. The results are presented via table and graphs in Excel file “Mercury 

Control Results 6-15-00.xls.” 

3.3 COHPAC with Recycle 

The purpose of this sensitivity analysis was to add 20% recycle of AC to the COHPAC-type mercury 

control scenarios (ESP-3 and ESP-6). This sensitivity applies only to retrofit scenarios ESP-3 and ESP-6. 

Mercury control temperature was set at ADP+18 F (ADP+40 F cases were not run) for the following model 

plant applications: 

Plant 1, 500 MW (ESP-3) 

Plant 4, 500 MW (ESP-6) 

Plant 7, 500 MW (ESP-6) 

Plant 13, 100 MW (ESP-6) 

Plant 16, 100 MW (ESP-6) 

This work was originally completed on 6/6/2000. The sensitivity runs were updated on 6-14-2000 to 

correct a programming error. The results are presented via table and graphs in Excel file “Mercury 

Control Results 6-15-00.xls.” 

D-46

3.4 Addition of Ductwork to Increase Flue Gas Residence Time 

The purpose of this sensitivity analysis was to add the capital cost of additional ductwork to the cost of 

mercury control for a specified model plant application. The model plant application that was selected was 

Plant 4, ESP-4, 500 MW. The following assumptions were used to complete this effort: 

Application: Plant 4, ESP-4, Ductwork added upstream of ESP 

Results presented with and without added ductwork 

Plant sizes: 975, 500 and 100 MWe 

Type of ductwork: carbon steel, polymer-lined, insulated (reflects a conservative 

selection of material) 

Cost of ductwork: $134/sq ft 

Installation labor: 0.8 hrs/sq ft 

Number of ducts: 2 

Duct gas velocity: 2800 ft/min 

Retrofit factor: 1.3 

Gas residence time in new duct: 1 second 

This work was completed on 6/14/2000. The capital costing results indicate the following: 

975 MW application: $2.51/kW for 2 ducts @ 47 feet long (22.3 ft x 22.3 ft) 

500 MW application: $3.50/kW for 2 ducts @ 47 feet long (16 ft x 16 ft) 

100 MW application: $5.54/kW for 2 ducts @ 47 feet long (10 ft x 10 ft) 

The complete cost results are presented via table and graphs in Excel file “Mercury Control Results 6-15-

00.xls” (Plant 4, W&WO Added Ductwork). 

3.5 Use of a Combined AC/Lime Sorbent 

The purpose of this sensitivity analysis was to assess the potential economic impact of using a sorbent 

consisting of AC and lime. The assumptions were: 

Application: Model Plant 4, ESP-6, AC sorbent (50-90% Removal); Model Plant 4, ESP-7, 

AC-Lime Sorbent (90%+ removal) 

Plant size: 500 MWe 

AC sorbent Cost = $908/Ton 

AC+Lime Sorbent Cost = $149/Ton, Assumes AC:Lime ratio = 2:19 

ESP-7 Sensitivity Cases Assume 90%+ Hg Removal based on ADA Technologies tests at PSE&G 

ESP-7 Sensitivity Cases run for 1, 2, 3, and 4 lb/MMacf Sorbent Concentration 

ESP-6 Comparison Cases Run for 50, 60, 70, 80, 90% Hg Removal 

The complete cost results are presented via table and graphs in Excel file “Mercury Control Results 6-15-

00.xls” (Plant 4, 500 MW, Lime-AC Sorbent). 

D-47

ATTACHMENT 4


Results of all Model Runs


D-48

Table 1. Mercury Control Technology Retrofit Configurations 

Mercury Control Existing Equipment (a,b) Retrofit Technology (a) 

ESP-1 ESP ACI 

ESP-3 ACI + PFF 

ESP-4 SC + ACI 

ESP-6 SC + ACI + PFF 

ESP-7 SC + AC + lime + PFF 

ESP-8 SC + ACI + CFBA 

ESP-9 SC + AC + lime + CFBA 

HESP-1 HESP 

SC + ACI + PFF 

FF-1 FF ACI 

FF-2 SC + ACI 

FF-3 SC + AC + lime + PFF 

SD/FF-1 SD + FF ACI 

SD/ESP-1 SD + ESP ACI 

a. ESP = cold-side electrostatic precipitator; HESP = hot-side electrostatic precipitator; FF= fabric filter; SD = spray dryer; 

ACI = activated carbon injection; PFF = polishing fabric filter. 

b. Existing equipment may include wet scrubber and NOx controls such as selective catalytic reduction (SCR). 

D-49

Table 2. Mercury Control Technology Applications and Cobenefits Definition 

Model 

Plant # 

Power 

Plant 

Size, 

MWe 

Coal 

Type 

Coal 

Sulfur 

Content, 

%S 

Existing 

Controls 

Mercury 

Controls 

CoBenefit 

Case(s) with 

1 975 Bit 3 ESP + FGD ESP-1, ESP-3 SCR 

2 975 Bit 3 FF + FGD FF-1 SCR 

3 975 Bit 3 HESP + FGD HESP-1 SCR 

4 975 Bit 0.6 ESP ESP-4, ESP-6 

5 975 Bit 0.6 FF FF-2 

6 975 Bit 0.6 HESP HESP-1 

7 975 Subbit 0.5 ESP ESP-4, ESP-6 

8 975 Subbit 0.5 FF FF-2 

9 975 Subbit 0.5 HESP HESP-1 

10 100 Bit 3 SD + ESP SD/ESP-1 SCR 

11 100 Bit 3 SD + FF SD/FF-1 SCR 

12 100 Bit 3 HESP + FGD HESP-1 SCR 

13 100 Bit 0.6 ESP ESP-4, ESP-6 

14 100 Bit 0.6 FF FF-2 

15 100 Bit 0.6 HESP HESP-1 

16 100 Subbit 0.5 ESP ESP-4, ESP-6 

17 100 Subbit 0.5 FF FF-2 

18 100 Subbit 0.5 HESP HESP-1 

a. Bit = bituminous coal; Subbit = subbituminous coal. 

b. Mercury controls are shown in Table 1. 

D-50

RESULTS FOR MODEL PLANTS 1 AND 4 DATE: 5/22/00


(Accounts for ICR Data Modification)
Comments:


1) Model Plant 1, ESP-1: Minimum Hg removal = 87% for ESP and FGD Combination with Eastern Bituminous Coals 

2) Model Plant 1, ESP-1: Minimum Hg removal = 97.6% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals 

3) Model Plant 1, ESP-3: Minimum Hg removal = 86.6% for ESP and FGD Combination with Eastern Bituminous Coals 

4) Model Plant 1, ESP-3: Minimum Hg removal = 97.6% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals 

5) Model Plant 4, ESP-4: Minimum Hg removal = 58% for ESP with Eastern Bituminous Coals 

7) Model Plant 4, ESP-6: Minimum Hg removal = 61.3% for ESP with Eastern Bituminous Coals 

See plot of results below table 

D-51


Model 

Plant # 

1 

Plant 

Size, 

MWe 

975 

Total 

Mercury 

Removed, 

% 

87.16% 

Coal 

Type 

Bit 

Coal 

Sulfur 

Content, 

% by Wt 

3 

Existing 

Pollutant 

Controls 

ESP, FGD 

Hg Control 

Configuration 

ESP-1 

Added 

Equipment 

for Hg 

Control 

None 

Co-Benefit 

Cases with 

N/A 

Comments 

No FG Cooling 

MERCURY 

SORBENT 

INJECTION 

RATIO 

lb/MMacf 

0.00 

Capital 

Cost, $/kW 

0.11 

Levelized 

Carrying 

Charges, Mills/kWHr 

0.002 

Fixed 

O&M Cost, 

Mills/kW-Hr 

0.000 

Va

O&

Mills

0

1 975 90.00% Bit 3 ESP, FGD ESP-1 SI System N/A No FG Cooling 3.29 2.48 0.058 0.040 01 975 95.00% Bit 3 ESP, FGD ESP-1 SI System N/A No FG Cooling 18.12 8.54 0.200 0.048 01 975 97.64% Bit 3 ESP, FGD ESP-1 SI System SCR No FG Cooling 0.00 0.11 0.002 0.000 0

1 975 86.58% Bit 3 ESP, FGD ESP-3 SI System, PJFF N/A No FG Cooling 0.00 43.45 1.015 0.116 0

1 975 90.00% Bit 3 ESP, FGD ESP-3 SI System, PJFF N/A No FG Cooling 1.22 44.59 1.041 0.118 0

1 975 95.00% Bit 3 ESP, FGD ESP-3 SI System, PJFF N/A No FG Cooling 6.00 47.10 1.100 0.121 0

1 975 97.54% Bit 3 ESP, FGD ESP-3 SI System, PJFF SCR No FG Cooling 0.00 43.45 1.015 0.116 0

4 975 58.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 0.00 5.88 0.137 0.047 0

4 975 60.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 0.06 6.01 0.140 0.047 0

4 975 70.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 0.79 6.67 0.156 0.048 0

4 975 80.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 2.24 7.54 0.176 0.050 0

4 975 90.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 6.61 9.53 0.223 0.052 0

4 975 61.30% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 0.00 46.02 1.075 0.121 0

4 975 70.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 0.38 46.50 1.086 0.122 0

4 975 80.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 1.23 47.11 1.100 0.122 0

4 975 90.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 3.78 48.46 1.132 0.124 0

4 975 95.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 8.89 50.59 1.182 0.127 0
ECONOMIC RESULTS -- GRAPHICAL FORMAT 

MODEL PLANT #1 

MERCURY CONTROL COST -- MODEL PLANT 1 (Highest Value of Hg 

Removal Includes SCR), 975 MWe, Bituminous Coal, 3% Sulfur 

1.416 

0.427 0.006 

1.956 

0.006 

1.274 1.924 

1.274 

0.000 0.500 1.000 1.500 2.000 2.500 

86% 88% 90% 92% 94% 96% 98% 100% 

Total Hg Removed, % 

Total Annual Cost, Mills/kW-H ESP-1 ESP-3 

D-52
 MODEL PLANT #4 

MERCURY CONTROL COST -- MODEL PLANT 4, 975 MWe, 

Bituminous Coal, 0.6% Sulfur 

1.397 1.485 

0.464 

0.883 

1.735 

1.353 

2.222 

0.240 

0.232 

0.319 0.000 

0.500 1.000 1.500 2.000 2.500 

55% 65% 75% 85% 95% 

Total Hg Removed, % 

Total Annual Cost, Mills/kW-H ESP-6 ESP-4 
RESULTS FOR MODEL PLANTS 1 AND 4 (ADP+40) DATE: 6/6/00


(Utilizes Original Performance Algorithms -- Excludes ICR Data Modification)


Comments:


1) Model Plant 1, ESP-1: Minimum Hg removal = 70% for ESP and FGD Combination with Eastern Bituminous Coals 

2) Model Plant 1, ESP-1: Minimum Hg removal = 94.5% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals 

3) Model Plant 1, ESP-3: Minimum Hg removal = 70% for ESP and FGD Combination with Eastern Bituminous Coals 

4) Model Plant 1, ESP-3: Minimum Hg removal = 94.5% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals 

See plot of results below table 

Model 

Plant # 

1 

Plant Size, 

MWe 

500 

Total 

Mercury 

Removed, 

% 

70.00% 

Coal Type 

Bit 

Coal 

Sulfur 

Content, 

% by Wt 

3 

Existing 

Pollutant 

Controls 

ESP, FGD 

Hg Control 

Configuration 

ESP-1 

Added 

Equipment 

for Hg 

Control 

None 

Co-Benefit 

Cases with 

N/A 

Comments 

No FG Cooling 

MERCURY 

SORBENT 

INJECTION 

RATIO 

lb/MMacf 

0.00 

Capital 

Cost, $/kW 

0.12 

Levelized 

Carrying 

Charges, Mills/kWHr 

0.003 

Fixed 

O&M Cost

Mills/kW-H

0.000 

1 500 80.00% Bit 3 ESP, FGD ESP-1 SI System N/A No FG Cooling 6.14 4.61 0.108 0.078 1 500 90.00% Bit 3 ESP, FGD ESP-1 SI System N/A No FG Cooling 24.42 12.54 0.293 0.089 1 500 94.50% Bit 3 ESP, FGD ESP-1 SI System SCR No FG Cooling 0.00 0.12 0.003 0.000 1 500 70.00% Bit 3 ESP, FGD ESP-3 SI System, PJFF N/A No FG Cooling 0.00 49.65 1.160 0.163 

1 500 80.00% Bit 3 ESP, FGD ESP-3 SI System, PJFF N/A No FG Cooling 2.00 51.64 1.206 0.166 

1 500 90.00% Bit 3 ESP, FGD ESP-3 SI System, PJFF N/A No FG Cooling 7.56 54.83 1.281 0.170 

1 500 94.50% Bit 3 ESP, FGD ESP-3 SI System, PJFF SCR No FG Cooling 0.00 49.65 1.160 0.163 

4 500 50.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+40F 5.31 7.95 0.186 0.084 

4 500 60.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+40F 7.96 9.22 0.215 0.086 

4 500 70.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+40F 12.37 11.13 0.260 0.088 

4 500 80.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+40F 21.19 14.55 0.340 0.093 

4 500 90.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+40F 47.64 23.42 0.547 0.103 

4 500 50.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+40F 1.98 51.91 1.212 0.166 

4 500 60.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+40F 2.98 52.53 1.227 0.167 

4 500 70.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+40F 4.65 53.46 1.249 0.168 

4 500 80.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+40F 8.00 55.10 1.287 0.170 

4 500 90.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+40F 18.05 59.25 1.384 0.176 

D-53

ECONOMIC RESULTS S GRAPHICAL FORMAT


MODEL PLANT # 1


M ER C U R Y C O N T R O L C O ST -- M O D EL PLAN T 1 (H ighe st Value of H g 

R e mov al Include s SC R ), 500 M We , B ituminous C oal, 3% S ulfur 

0.800 

1.489 

1.727 

0.006 

2.695 

0.006 

2.324 

1.489 

0.000 0.500 1.000 1.500 2.000 2.500 3.000 

65% 70% 75% 80% 85% 90% 95% 100% 

Total Hg R em oved, % 

Total Annual Cost, Mills/kW-H ESP-1 ESP-3 

D-54
MODEL PLANT # 4


MERCUR Y CONTROL COST -- MODEL PLAN T 4,500 MWe, 

B ituminous C oal, 0.6% S ulfur 

2.307 

1.715 1.816 1.982

3.263 

2.282 

4.741 

1.030 0.774 

1.451 

0.000 0.500 1.000 1.500 2.000 2.500 3.000 3.500 4.000 4.500 5.000 

40% 50% 60% 70% 80% 90% 100% 

T otal M e rcury R e moved, % 

Annual Mercury Control Cost, 

Mills/kW-Hr 

ESP-6 ESP-4 
RESULTS FOR M

ODEL PLANTS 1 AND 4 (w Recycle for ESP-3 and ESP-6) 06/06/2000


(Utilizes Original Performance Algorithms -- Excludes ICR Data Modification)


Comments:


1) Model Plant 1, ESP-1: Minimum Hg removal = 70% for ESP and FGD Combination with Eastern Bituminous Coals 

2) Model Plant 1, ESP-1: Minimum Hg removal = 94.5% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals 

3) Model Plant 1, ESP-3: Minimum Hg removal = 70% for ESP and FGD Combination with Eastern Bituminous Coals 

4) Model Plant 1, ESP-3: Minimum Hg removal = 94.5% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals 

See plot of results below table 

D-55


Model 

Plant # 

1 

Plant Size, 

MWe 

500 

Total 

Mercury 

Removed, 

% 

70.00% 

Coal Type 

Bit 

Coal 

Sulfur 

Content, 

% by Wt 

3 

Existing 

Pollutant 

Controls 

ESP, FGD 

Hg Control 

Configuration 

ESP-1 

Added 

Equipment 

for Hg 

Control 

None 

Co-Benefit 

Cases with 

N/A 

Comments 

No FG Cooling 

MERCURY 

SORBENT 

INJECTION 

RATIO 

lb/MMacf 

0.00 

Capital 

Cost, $/kW 

0.12 

Levelized 

Carrying 

Charges, Mills/kWHr 

0.003 

Fixed 

O&M Cost, 

Mills/kW-Hr 

0.000 

V

O&

Mi

1 500 80.00% Bit 3 ESP, FGD ESP-1 SI System N/A No FG Cooling 6.14 4.61 0.108 0.078 

1 500 90.00% Bit 3 ESP, FGD ESP-1 SI System N/A No FG Cooling 24.42 12.54 0.293 0.089 

1 500 94.50% Bit 3 ESP, FGD ESP-1 SI System SCR No FG Cooling 0.00 0.12 0.003 0.000 

1 500 70.00% Bit 3 ESP, FGD ESP-3 SI System, PJFF N/A No FG Cooling 0.00 49.67 1.160 0.163 

1 500 80.00% Bit 3 ESP, FGD ESP-3 SI System, PJFF N/A No FG Cooling 2.00 51.39 1.200 0.165 

1 500 90.00% Bit 3 ESP, FGD ESP-3 SI System, PJFF N/A No FG Cooling 7.56 54.15 1.265 0.169 

1 500 94.50% Bit 3 ESP, FGD ESP-3 SI System, PJFF SCR No FG Cooling 0.00 49.67 1.160 0.163 

4 500 50.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 1.94 9.23 0.216 0.087 

4 500 60.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 2.95 9.86 0.230 0.088 

4 500 70.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 4.64 10.79 0.252 0.090 

4 500 80.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 8.03 12.44 0.291 0.092 

4 500 90.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 18.17 16.62 0.388 0.097 

4 500 50.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 1.07 54.33 1.269 0.170 

4 500 60.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 1.66 54.71 1.278 0.171 

4 500 70.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 2.65 55.26 1.291 0.172 

4 500 80.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 4.63 56.23 1.313 0.173 

4 500 90.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 10.58 58.64 1.370 0.177 
ECONOMIC RESULTS S GRAPHICAL FORMAT


MODEL PLANT # 1


M ERC UR Y C O N T R O L C O ST -- M O DEL PLAN T 1 (Highe st Value of Hg 

R e mov al Include s SCR ), 500 M We , B ituminous Coal, 3% Sulfur 

0.800 

1.491 

1.686 

0.006 

2.695 

0.006 

2.173 1.491 

0.000 0.500 1.000 1.500 2.000 2.500 3.000 

65% 70% 75% 80% 85% 90% 95% 100% 

Total Hg Rem oved, % 

Total Annual Cost, Mills/kW-H ESP-1 ESP-3 

D-56
MODEL PLANT # 4


ME R C U R Y CON TROL COS T -- MODEL PLAN T 4,500 MW e, 

B ituminous C oal, 0.6% S ulfur 

1.989 1.132 

1.829 

1.697 1.747

2.457 

2.095 

0.535 0.637

0.804 

0.000 0.500 1.000 1.500 2.000 2.500 3.000 

40% 50% 60% 70% 80% 90% 100% 

T otal M ercury Re mov ed, % 

Total Annual Cost, Mills/kW-H ESP-6 ESP-4 
RESULTS FOR MODEL PLANTS 1 AND 4 06/05/2000 

(Utilizes Original Performance Algorithms -- Excludes ICR Data Modification) 

Comments: 

1) Model Plant 1, ESP-1: Minimum Hg removal = 70% for ESP and FGD Combination with Eastern Bituminous Coals 

2) Model Plant 1, ESP-1: Minimum Hg removal = 94.5% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals 

3) Model Plant 1, ESP-3: Minimum Hg removal = 70% for ESP and FGD Combination with Eastern Bituminous Coals 

4) Model Plant 1, ESP-3: Minimum Hg removal = 94.5% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals 

See plot of results below table 

D-57


Model 

Plant # 

1 

Plant Size, 

MWe 

500 

Total 

Mercury 

Removed, 

% 

70.00% 

Coal Type 

Bit 

Coal 

Sulfur 

Content, 

% by Wt 

3 

Existing 

Pollutant 

Controls 

ESP, FGD 

Hg Control 

Configuration 

ESP-1 

Added 

Equipment 

for Hg 

Control 

None 

Co-Benefit 

Cases with 

N/A 

Comments 

No FG Cooling 

MERCURY 

SORBENT 

INJECTION 

RATIO 

lb/MMacf 

0.00 

Capital 

Cost, $/kW 

0.12 

Levelized 

Carrying 

Charges, Mills/kWHr 

0.003 

Fixed 

O&M Cost, 

Mills/kW-Hr 

0.000 

O

M

1 500 80.00% Bit 3 ESP, FGD ESP-1 SI System N/A No FG Cooling 6.14 4.61 0.108 0.078 

1 500 90.00% Bit 3 ESP, FGD ESP-1 SI System N/A No FG Cooling 24.42 12.54 0.293 0.089 

1 500 94.50% Bit 3 ESP, FGD ESP-1 SI System SCR No FG Cooling 0.00 0.12 0.003 0.000 

1 500 70.00% Bit 3 ESP, FGD ESP-3 SI System, PJFF N/A No FG Cooling 0.00 49.65 1.160 0.163 

1 500 80.00% Bit 3 ESP, FGD ESP-3 SI System, PJFF N/A No FG Cooling 2.00 51.64 1.206 0.166 

1 500 90.00% Bit 3 ESP, FGD ESP-3 SI System, PJFF N/A No FG Cooling 7.56 54.83 1.281 0.170 

1 500 94.50% Bit 3 ESP, FGD ESP-3 SI System, PJFF SCR No FG Cooling 0.00 49.65 1.160 0.163 

4 500 50.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 1.94 9.23 0.216 0.087 

4 500 60.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 2.95 9.86 0.230 0.088 

4 500 70.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 4.64 10.79 0.252 0.090 

4 500 80.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 8.03 12.44 0.291 0.092 

4 500 90.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 18.17 16.62 0.388 0.097 

4 500 50.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 1.07 54.48 1.273 0.171 

4 500 60.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 1.66 54.91 1.283 0.171 

4 500 70.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 2.65 55.55 1.298 0.172 

4 500 80.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 4.63 56.67 1.324 0.174 

4 500 90.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 10.58 59.46 1.389 0.178 
ECONOMIC RESULTS S GRAPHICAL FORMAT


MODEL PLANT # 1


M ERCURY CO NT RO L CO ST -- M O DEL PLAN T 1 (H ighe st Value of Hg 

R e mov al Include s SC R), 500 M We , B ituminous Coal, 3% Sulfur 

0.800 

1.489 

1.727 

0.006 

2.695 

0.006 

2.324 

1.489 

0.000 0.500 1.000 1.500 2.000 2.500 3.000 

65% 70% 75% 80% 85% 90% 95% 100% 

Total Hg Rem oved, % 

Total Annual Cost, Mills/kW-H ESP-1 ESP-3 

D-58
 MODEL PLANT # 4


MERCURY CONTROL COST -- MODEL PLAN T 4,500 MW e, 

B ituminous C oal, 0.6% Sulfur 

1.779 1.879 

2.075 1.132 

1.717 

2.650 

2.095 

0.637 0.535 0.804 

0.000 0.500 1.000 1.500 2.000 2.500 3.000 

40% 50% 60% 70% 80% 90% 100% 

T otal M e rcury R e mov e d, % 

Total Mercury Removed, 

Mills/kW-Hr 

ESP-6 ESP-4 
RESULTS FOR MODEL PLANTS 1 AND 4 05/22/2000 

(Utilizes Original Performance Algorithms -- Excludes ICR Data Modification) 

Comments: 

1) Model Plant 1, ESP-1: Minimum Hg removal = 70% for ESP and FGD Combination with Eastern Bituminous Coals 

2) Model Plant 1, ESP-1: Minimum Hg removal = 94.5% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals 

3) Model Plant 1, ESP-3: Minimum Hg removal = 70% for ESP and FGD Combination with Eastern Bituminous Coals 

4) Model Plant 1, ESP-3: Minimum Hg removal = 94.5% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals 

See plot of results below table 

D-59


Model 

Plant # 

1 

Plant Size, 

MWe 

975 

Total 

Mercury 

Removed, 

% 

70.00% 

Coal Type 

Bit 

Coal 

Sulfur 

Content, 

% by Wt 

3 

Existing 

Pollutant 

Controls 

ESP, FGD 

Hg Control 

Configuration 

ESP-1 

Added 

Equipment 

for Hg 

Control 

None 

Co-Benefit 

Cases with 

N/A 

Comments 

No FG Cooling 

MERCURY 

SORBENT 

INJECTION 

RATIO 

lb/MMacf 

0.00 

Capital 

Cost, $/kW 

0.11 

Levelized 

Carrying 

Charges, Mills/kWHr 

0.002 

Fixed 

O&M Cost, 

Mills/kW-Hr 

0.000 

O

M

1 975 80.00% Bit 3 ESP, FGD ESP-1 SI System N/A No FG Cooling 6.14 3.85 0.090 0.042 

1 975 90.00% Bit 3 ESP, FGD ESP-1 SI System N/A No FG Cooling 24.42 10.73 0.251 0.050 

1 975 94.50% Bit 3 ESP, FGD ESP-1 SI System SCR No FG Cooling 0.00 0.11 0.002 0.000 

1 975 70.00% Bit 3 ESP, FGD ESP-3 SI System, PJFF N/A No FG Cooling 0.00 43.43 1.014 0.116 

1 975 80.00% Bit 3 ESP, FGD ESP-3 SI System, PJFF N/A No FG Cooling 2.00 45.08 1.053 0.119 

1 975 90.00% Bit 3 ESP, FGD ESP-3 SI System, PJFF N/A No FG Cooling 7.56 47.78 1.116 0.122 

1 975 94.50% Bit 3 ESP, FGD ESP-3 SI System, PJFF SCR No FG Cooling 0.00 43.43 1.014 0.116 

4 975 50.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 1.94 7.37 0.172 0.049 

4 975 60.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 2.95 7.90 0.185 0.050 

4 975 70.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 4.64 8.70 0.203 0.051 

4 975 80.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 8.03 10.10 0.236 0.053 

4 975 90.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 18.17 13.72 0.320 0.057 

4 975 50.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 1.07 47.00 1.098 0.122 

4 975 60.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 1.66 47.37 1.106 0.123 

4 975 70.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 2.65 47.90 1.119 0.124 

4 975 80.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 4.63 48.84 1.141 0.125 

4 975 90.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 10.58 51.23 1.197 0.128 
ECONOMIC RESULTS S GRAPHICAL FORMAT


MODEL PLANT # 1


M ERCURY CO NT RO L CO ST -- M O DEL PLAN T 1 (H ighe st Value of Hg 

R e mov al Include s SC R), 975 M We , B ituminous Coal, 3% Sulfur 

0.727 

1.273 

1.501 

0.006 

2.594 

0.006 

2.086 

1.273 

0.000 0.500 1.000 1.500 2.000 2.500 3.000 

65% 70% 75% 80% 85% 90% 95% 100% 

Total Hg Rem oved, % 

Total Annual Cost, Mills/kW-H ESP-1 ESP-3 

D-60
 MODEL PLANT # 4


M E R C U R Y C O N T R O L CO S T -- M O DE L P L A N T 4 , 9 7 5 M W e , 

B itu m in o u s C o a l, 0 .6 % S u lfu r 

1.528 1.625 

1.817 1.017 

1.468 

2.381 

1.966 

0.533 0.434 0.696 

0.000 0.500 1.000 1.500 2.000 2.500 3.000 

45 % 5 0 % 55 % 6 0 % 65 % 7 0 % 75 % 8 0 % 85 % 9 0 % 95 % 1 0 0 

% 

T o ta l H g R e m o v e d , % 

Total Annual Cost, Mills/kW-H E S P -6 E S P -4 
RESULTS FOR MODEL PLANTS 7 AND 8 (w Recycle for ESP-6)	 DATE: 

6/6/00 

Comments: 

1) Model Plant 7, ESP-4: Minimum Hg removal = 56.2% for ESP with Western Subbituminous Coals 

2) Model Plant 8, FF-2: Minimum Hg removal = 50

% for Reverse-Gas FF with Western Subbituminous Coals 

See plot of results below table 

D-61


Model 

Plant # 

7 

Plant Size, 

MWe 

500 

Total Mercury 

Removed, % 

56.20% 

Coal Type 

Subbit 

Coal 

Sulfur 

Content, 

% by Wt 

0.5 

Existing 

Pollutant 

Controls 

ESP 

Hg Control 

Configuration 

ESP-4 

Added 

Equipment 

for Hg 

Control 

SI System, WI System 

Co-Benefit Cases with 

N/A 

Comments 

FG Cooling, 

ADP+18F 

MERCURY 

SORBENT 

INJECTION 

RATIO 

lb/MMacf 

0.00 

Capital 

Cost, $/kW 

6.59 

Levelized 

Carrying 

Charges, Mills/kWHr 

0.154 

Fixed 

O&M Cost, 

Mills/kW-Hr 

0.083 

V

O&

Mi

7 500 60.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 2.36 8.79 0.205 0.086 

7 500 70.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 4.87 10.27 0.240 0.088 

7 500 80.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 9.00 12.34 0.288 0.091 

7 500 90.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 21.39 17.55 0.410 0.098 

7 500 50.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.04 55.15 1.288 0.172 

7 500 60.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.06 55.19 1.289 0.172 

7 500 70.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.09 55.25 1.290 0.172 

7 500 80.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.17 55.34 1.293 0.172 

7 500 90.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.38 55.57 1.298 0.173 

8 500 50.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.01 6.65 0.155 0.083 

8 500 60.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.04 6.74 0.157 0.083 

8 500 70.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.09 6.84 0.160 0.083 

8 500 80.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.73 7.56 0.177 0.085 

8 500 90.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 1.89 8.47 0.198 0.086 
ECONOMIC RESULTS S GRAPHICAL FORMAT


MODEL PLANT # 7


M E R C U R Y C O N T R O L C O S T -- M O DE L P L A N T 7 , 5 0 0 M W e , 

S u b b itu m in o u s C o a l, 0 .5% S u lfu r 

1.6 8 6 

2.5 1 3 

0.5 7 1 

0.3 0 0 

0.8 3 5 1.2 6 1 

1.6 5 0 1 .6 52 1.6 5 7 1.6 6 4 

0.0 0 0.5 0 1.0 0 1.5 0 2.0 0 2.5 0 3.0 0 

45 % 5 0 % 55 % 6 0 % 65 % 7 0 % 75 % 8 0 % 85 % 9 0 % 95 % 1 0 0 % 

To ta l Hg Re m o ve d , % 

Total Annual Cost, Mills/kW-H ESP-4 ESP-6 

D-62
 MODEL PLANT # 8


M E RC URY CO NT RO L CO S T -- M O D E L P LAN T 8, 500 M We, 

S ubb itumin ous C oal, 0.5% S ulfu r 

0.520 

0.303 0.308 0.315 

0.392 

0.25 0.30 0.35 0.40 0.45 0.50 0.55 

40% 5% 50% 5% 60% 5% 70% 5% 80% 5% 90% 5% 100% 

Total Hg R em oved, % 

Total Annual Cost, Mills/kW-H FF -2 

4 5 6 7 8 9
RESULTS FOR MODEL PLANTS 7 AND 8 DATE: 06/06/2000 

Comments: 1) Model Plant 7, ESP-4: Minimum Hg removal = 56.2% for ESP with Western Subbituminous Coals 

2) Model Plant 8, FF-2: Minimum Hg removal = 50

% for Reverse-Gas FF with Western Subbituminous Coals 

See plot of results below table 

D-63


Model 

Plant # 

7 

Plant Size, 

MWe 

500 

Total Mercury 

Removed, % 

56.20% 

Coal Type 

Subbit 

Coal 

Sulfur 

Content, 

% by Wt 

0.5 

Existing 

Pollutant 

Controls 

ESP 

Hg Control 

Configuration 

ESP-4 

Added 

Equipment 

for Hg 

Control 

SI System, WI System 

Co-Benefit 

Cases with 

N/A 

Comments 

FG Cooling, 

ADP+18F 

MERCURY 

SORBENT 

INJECTION 

RATIO 

lb/MMacf 

0.00 

Capital 

Cost, $/kW 

6.59 

Levelized 

Carrying 

Charges, Mills/kWHr 

0.154 

Fixed 

O&M Cost, 

Mills/kW-Hr 

0.083 

7 500 60.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 2.36 8.79 0.205 0.086 

7 500 70.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 4.87 10.27 0.240 0.088 

7 500 80.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 9.00 12.34 0.288 0.091 

7 500 90.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 21.39 17.55 0.410 0.098 

7 500 50.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.04 55.15 1.288 0.172 

7 500 60.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.06 55.20 1.289 0.172 

7 500 70.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.09 55.26 1.291 0.172 

7 500 80.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.17 55.37 1.293 0.172 

7 500 90.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.38 55.64 1.300 0.173 

8 500 50.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.01 6.65 0.155 0.083 

8 500 60.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.04 6.74 0.157 0.083 

8 500 70.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.09 6.84 0.160 0.083 

8 500 80.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.73 7.56 0.177 0.085 

8 500 90.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 1.89 8.47 0.198 0.086 
ECONOMIC RESULTS S GRAPHICAL FORMAT


MODEL PLANT # 7


M E R C U R Y C O N T R O L CO S T -- M O DE L P L AN T 7, 5 0 0 M W e , 

S u b b itu m in o u s C o al, 0 .5 % S u lfu r 

2.51 3 

0.57 1 

0.30 0 

0.83 5 1.26 1 

1.69 3 

1.65 0 1.65 2 1.65 8 1.66 7 

0.00 0.50 1.00 1.50 2.00 2.50 3.00 

45% 5 0% 55% 6 0% 65% 7 0% 75% 8 0% 85% 9 0% 95% 1 00 % 

Tota l Hg Re m o ve d, % 

Total Annual Cost, Mills/kW-H ESP -4 ESP -6 

D-64
MODEL PLANT # 8


M E RCURY CO NT RO L C O S T -- M O DE L P LAN T 8, 500 M We , 

S ubbituminous C oal, 0.5% S ulfur 

0.520 

0.303 0.308 0.315 

0.392 

0.25 0.30 0.35 0.40 0.45 0.50 0.55 

40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100% 

Total Hg R em oved, % 

Total Annual Cost, Mills/kW-H FF-2 
RESULTS FOR MODEL PLANTS 7 AND 8 (ADP+40) DATE: 6/6/00 

Comments: 

1) Model Plant 7, ESP-4: Minimum Hg removal = 56.2% for ESP with Western Subbituminous Coals 

2) Model Plant 8, FF-2: Minimum Hg removal = 50% for Reverse-Gas FF with Western Subbituminous Coals 

See plot of results below table 

D-65


Model 

Plant # 

7 

Plant Size, 

MWe 

500 

Total 

Mercury 

Removed, 

% 

56.20% 

Coal Type 

Subbit 

Coal 

Sulfur 

Content, 

% by Wt 

0.5 

Existing 

Pollutant 

Controls 

ESP 

Hg Control 

Configuration 

ESP-4 

Added 

Equipment for 

Hg Control 

SI System, WI 

System 

Co-Benefit 

Cases with 

N/A 

Comments 

FG Cooling, 

ADP+40F 

MERCURY 

SORBENT 

INJECTION 

RATIO 

lb/MMacf 

0.00 

Capital 

Cost, $/kW 

3.92 

Levelized 

Carrying 

Charges, Mills/kWHr 

0.092 

Fixed 

O&M Cost, 

Mills/kW-Hr 

0.078 

7 500 60.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+40F 2.36 4.83 0.113 0.079 

7 500 70.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+40F 4.87 6.15 0.144 0.081 7 500 80.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+40F 9.00 8.22 0.192 0.084 7 500 90.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+40F 21.39 13.42 0.313 0.090 

7 500 50.00% Subbit 0.5 ESP ESP-6 SI System, WI System, PJFF N/A FG Cooling, ADP+40F 0.04 51.17 1.195 0.165 7 500 60.00% Subbit 0.5 ESP ESP-6 SI System, WI System, PJFF N/A FG Cooling, ADP+40F 0.06 51.28 1.198 0.164 7 500 70.00% Subbit 0.5 ESP ESP-6 SI System, WI System, PJFF N/A FG Cooling, ADP+40F 0.09 51.44 1.201 0.165 

7 500 80.00% Subbit 0.5 ESP ESP-6 SI System, WI System, PJFF N/A FG Cooling, ADP+40F 0.17 51.70 1.208 0.166 

7 500 90.00% Subbit 0.5 ESP ESP-6 SI System, WI System, PJFF N/A FG Cooling, ADP+40F 0.38 52.36 1.223 0.167 8 500 50.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+40F 0.01 2.57 0.060 0.076 

8 500 60.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+40F 0.04 2.75 0.064 0.076 8 500 70.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+40F 0.09 2.95 0.069 0.076 8 500 80.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+40F 0.73 3.44 0.080 0.077 8 500 90.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+40F 1.89 4.35 0.102 0.078 
ECONOMIC RESULTS S GRAPHICAL FORMAT


MODEL PLANT # 7


M E R C U R Y C O N T R O L C O S T -- M O DE L P L A N T 7 , 5 0 0 M W e , 

S ubb itum in o u s C o a l, 0 .5 % S u lfur 

2.3 9 2 

1.5 4 1 1.5 5 0 1.5 6 7 1.6 8 3 

0.4 7 8 

0.3 3 6 

0.7 1 4 1.1 4 0 

1.5 9 7 

0.2 5 0.7 5 1.2 5 1.7 5 2.2 5 2.7 5 

45 % 5 0 % 55 % 6 0 % 65 % 7 0 % 75 % 8 0 % 85 % 9 0 % 95 % 1 0 0 % 

To ta l Hg Re m o ve d , % 

Total Annual Cost, Mills/kW-H ESP-4 ESP-6 

D-66
 MODEL PLANT # 8


M E R CURY CO NT RO L CO S T -- M O DE L P LAN T 8, 500 M We, 

S ubbituminous C oal, 0.5% S ulfur 

0.399 

0.197 0.185 0.216 

0.271 

0.15 0.20 0.25 0.30 0.35 0.40 0.45 

40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100% 

Total Hg R em oved, % 

Total Annual Cost, Mills/kW-H FF-2 
RESULTS FOR MODEL PLANTS 7 AND 8 DATE: 05/22/2000 

Comments: 1) Model Plant 7, ESP-4: Minimum Hg removal = 56.2% for ESP with Western Subbituminous Coals 

2) Model Plant 8, FF-2: Minimum Hg removal = 50% for Reverse-Gas FF with Western Subbituminous Coals 

See plot of results below table 

D-67


Model 

Plant # 

7 

Plant Size, 

MWe 

975 

Total Mercury 

Removed, % 

56.20% 

Coal Type 

Subbit 

Coal 

Sulfur 

Content, 

% by Wt 

0.5 

Existing 

Pollutant 

Controls 

ESP 

Hg Control 

Configuration 

ESP-4 

Added 

Equipment for 

Hg Control 

SI System, WI 

System 

Co-Benefit 

Cases with 

N/A 

Comments 

FG Cooling, 

ADP+18F 

MERCURY 

SORBENT 

INJECTION 

RATIO 

lb/MMacf 

0.00 

Capital 

Cost, $/kW 

5.25 

Levelized 

Carrying 

Charges, Mills/kWHr 

0.123 

Fixed 

O&M Cost, 

Mills/kW-Hr 

0.046 

7 975 60.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 2.36 7.07 0.165 0.049 

7 975 70.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 4.87 8.32 0.194 0.050 

7 975 80.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 9.00 10.09 0.236 0.053 

7 975 90.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 21.39 14.61 0.341 0.058 

7 975 50.00% Subbit 0.5 ESP ESP-6 SI System, WI System, PJFF N/A FG Cooling, ADP+18F 0.04 47.74 1.115 0.124 

7 975 60.00% Subbit 0.5 ESP ESP-6 SI System, WI System, PJFF N/A FG Cooling, ADP+18F 0.06 47.78 1.116 0.124 

7 975 70.00% Subbit 0.5 ESP ESP-6 SI System, WI System, PJFF N/A FG Cooling, ADP+18F 0.09 47.83 1.117 0.124 

7 975 80.00% Subbit 0.5 ESP ESP-6 SI System, WI System, PJFF N/A FG Cooling, ADP+18F 0.17 47.92 1.119 0.124 

7 975 90.00% Subbit 0.5 ESP ESP-6 SI System, WI System, PJFF N/A FG Cooling, ADP+18F 0.38 48.14 1.124 0.125 

8 975 50.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.01 5.30 0.124 0.046 

8 975 60.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.04 5.37 0.125 0.046 

8 975 70.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.09 5.45 0.127 0.046 

8 975 80.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.73 6.04 0.141 0.047 

8 975 90.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 1.89 6.80 0.159 0.048 
ECONOMIC RESULTS S GRAPHICAL FORMAT


MODEL PLANT # 7

M E R C U R Y C ON T R O L CO S T -- M ODE L P L AN T 7, 9 75 M W e , S u b b itu m in o u s Co al, 

0.5% S u lfu r 

2.384 

1.403 1.405 1.410 1.444 

0.473 

0.212 

0.731 

1.150 

1.419 

0.00 0.50 1.00 1.50 2.00 2.50 3.00 

45% 5 0% 55% 6 0% 65% 7 0% 75% 8 0% 85% 9 0% 95% 1 00 % 

Tota l Hg Re m o ve d, % 

Total Annual Cost, Mills/kW-H ESP-4 ESP-6 

D-68
MODEL PLANT # 8


M E RCURY C O NT RO L C O S T -- M O DE L P LAN T 8, 975 M We , S ubbituminous Coal, 0.5% 

Sulfur 

0.423 

0.214 0.219 0.226 

0.299 

0.20 0.25 0.30 0.35 0.40 0.45 

40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100% 

Total Hg R em oved, % 

Total Annual Cost, Mills/kW-H FF -2 
RESULTS FOR MODEL PLANTS 10 AND 13 DATE: 5/22/00 

Comments: 

1) Model Plant 10, DS/ESP-1: Minimum Hg removal = 57.2% for DS/ESP Combination with Eastern Bituminous Coals 

2) Model Plant 10: Capital Cost Only Includes Sorbent Injection Equipment (accounts for storage/transfer of sorbent) 3) Model Plant 13, ESP-4: Minimum Hg removal = 58.8% for ESP with Eastern Bituminous Coals 4) Model Plant 13, ESP-6: Minimum Hg removal = 61.3% for ESP with Eastern Bituminous Coals 

See plot of results below table 

D-69


Model 

Plant # 

10 

Plant Size, 

MWe 

100 

Total 

Mercury 

Removed, 

% 

57.20% 

Coal 

Type 

Bit 

Coal 

Sulfur 

Content, 

% by Wt 

3 

Existing 

Pollutant 

Controls 

DS, ESP 

Hg Control 

Configuration 

DS/ESP-1 

Added 

Equipment for 

Hg Control 

SI System 

Co-Benefit 

Cases with 

N/A 

Comments 

Costs for SI 

Equipment Only 

MERCURY 

SORBENT 

INJECTION 

RATIO 

lb/MMacf 

0.00 

Capital 

Cost, $/kW 

0.18 

Levelized 

Carrying 

Charges, Mills/kWHr 

0.004 

Fixed 

O&M Cost, 

Mills/kW-Hr 

0.000 

O

M

10 100 60.00% Bit 3 DS, ESP DS/ESP-1 SI System N/A Costs for SI Equipment Only 0.00 0.18 0.004 0.000 

10 100 70.00% Bit 3 DS, ESP DS/ESP-1 SI System N/A Costs for SI Equipment Only 0.42 1.58 0.037 0.363 

10 100 80.00% Bit 3 DS, ESP DS/ESP-1 SI System N/A Costs for SI Equipment Only 1.34 2.95 0.069 0.365 

10 100 90.00% Bit 3 DS, ESP DS/ESP-1 SI System N/A Costs for SI Equipment Only 4.12 5.84 0.136 0.370 

13 100 58.80% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 0.00 13.11 0.306 0.378 

13 100 60.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 0.06 13.39 0.313 0.378 

13 100 70.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 0.79 14.72 0.344 0.381 

13 100 80.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 2.24 16.40 0.383 0.383 

13 100 90.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 6.61 20.05 0.468 0.389 

13 100 61.30% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 0.00 76.37 1.784 0.495 

13 100 70.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 0.38 77.36 1.807 0.497 

13 100 80.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 1.23 78.56 1.835 0.499 

13 100 90.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 3.78 81.10 1.894 0.503 

13 100 95.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 8.89 84.94 1.984 0.509 
ECONOMIC RESULTS S GRAPHICAL FORMAT


MODEL PLANT # 10


MERCURY CONTROL COST -- MODEL PLANT 10, 100 MWe, 

Bituminous Coal, 3% Sulfur 

0.008 

0.008 

0.637 

0.759 

1.094 

0.00 0.20 0.40 0.60 0.80 1.00 1.20 

50% 60% 70% 80% 90% 100% 

Total Hg Removed, % 

Total Annual Cost, Mills/kW-H DS/ESP-1 

D-70
MODEL PLANT # 13


ME R C U R Y C ON TR OL C OS T -- MOD E L P L AN T 13, 100 MW e, 

B itu minous C o al, 0.6% S u lfur 

1.647 

0.922 

0.909 

1.018 1.184 

3.611 

3.080 

2.637 2.695 2.798

0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 

50% 60% 70% 80% 90% 100% 

Total Hg Removed, % 

Total Annual Cost, Mills/kW-H ESP-4 ESP-6 
RESULTS FOR MODEL PLANTS 10 AND 13 (ADP+40) DATE: 6/6/00 

Comments: See plot of results below table 

D-71


Model 

Plant # 

10 

Plant Size, 

MWe 

100 

Total 

Mercury 

Removed, 

% 

50.00% 

Coal Type 

Bit 

Coal 

Sulfur 

Content, 

% by Wt 

3 

Existing 

Pollutant 

Controls 

DS, ESP 

Hg Control 

Configuration 

DS/ESP-1 

Added 

Equipment 

for Hg 

Control 

SI System 

Co-Benefit 

Cases with 

N/A 

Comments 

Costs for SI 

Equipment Only 

MERCURY 

SORBENT 

INJECTION 

RATIO 

lb/MMacf 

1.15 

Capital 

Cost, $/kW 

2.69 

Levelized 

Carrying 

Charges, Mills/kWHr 

0.063 

Fixed 

O&M Cost, 

Mills/kW-Hr 

0.365 

10 100 60.00% Bit 3 DS, ESP DS/ESP-1 SI System N/A Costs for SI Equipment Only 1.79 3.49 0.081 0.366 

10 100 70.00% Bit 3 DS, ESP DS/ESP-1 SI System N/A Costs for SI Equipment Only 2.86 4.64 0.108 0.368 

10 100 80.00% Bit 3 DS, ESP DS/ESP-1 SI System N/A Costs for SI Equipment Only 5.01 6.62 0.155 0.371 

10 100 90.00% Bit 3 DS, ESP DS/ESP-1 SI System N/A Costs for SI Equipment Only 11.44 11.49 0.268 0.379 

13 100 50.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+40F 5.31 13.49 0.315 0.377 

13 100 60.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+40F 7.96 15.43 0.360 0.380 

13 100 70.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+40F 12.37 18.31 0.428 0.385 

13 100 80.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+40F 21.19 23.36 0.546 0.392 13 100 90.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+40F 47.64 36.04 0.842 0.410 13 100 50.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+40F 1.98 73.77 1.723 0.490 

13 100 60.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+40F 2.98 74.76 1.746 0.491 

13 100 70.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+40F 4.65 76.20 1.780 0.493 

13 100 80.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+40F 8.00 78.71 1.839 0.497 

13 100 90.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+40F 18.05 84.91 1.983 0.506 
ECONOMIC RESULTS S GRAPHICAL FORMAT


MODEL PLANT # 10


MERCU RY CONTROL C OST -- MODEL PLAN T 10, 100 MWe, 

Bituminous Coal, 3% Sulfur 

0.815 

0.734 

0.945 

1.197 

1.925 

0.50 0.70 0.90 1.10 1.30 1.50 1.70 1.90 2.10 

40% 50% 60% 70% 80% 90% 100% 

Total Hg Removed, % 

Total Annual Cost, Mills/kW-H DS/ESP-1 

D-72
 MODEL PLANT # 13


ME R C U R Y C ON T R OL C OS T -- MOD E L P L AN T 13, 100 MW e, 

B itu minous C o al, 0.6% S u lfur 

3.3 62 

5.5 07 

1.6 28 1.3 55 

2.0 74 

2.9 48 

2.8 34 3.0 13 

4.3 71 

2.7 24 

0.5 0 1.5 0 2.5 0 3.5 0 4.5 0 5.5 0 6.5 0 

40% 50% 60% 70% 80% 90% 100% 

Total Hg Rem oved, % 

Total Annual Cost, Mills/kW-H ES P-4 ES P-6 
Sensitivity Results: Plants 4, ESP-4, W & WO Ductwork for Added Residence Time DATE: 6/14/00


Comments:


Application: Plant 4, ESP-4, Ductwork added upstream of ESP


Results presented with and without added ductwork


Plant sizes: 975, 500 and 100 MWe


Type of ductwork: carbon steel, polymer-lined, insulated (reflects a conservative selection of material)


Cost of ductwork: $134/sq ft


Installation labor: 0.8 hrs/sq ft


Number of ducts: 2


Duct gas velocity: 2800 ft/min


Retrofit factor: 1.3


Gas residence time in new duct: 1 second


See plot of results below table


Model 

Plant # 

4 

Plant 

Size, 

MWe 

975 

Total 

Mercury 

Removed, 

% 

50.00% 

Coal Type 

Bit 

Coal 

Sulfur 

Content, 

% by Wt 

0.6 

Existing 

Pollutant 

Controls 

ESP 

Hg Control 

Configuration 

ESP-4 

Added 

Equipment 

for Hg 

Control 

SI System, 

WI System 

Co-Benefit 

Cases with 

N/A 

Comments 

FG Cooling, 

ADP+18F 

MERCURY 

SORBENT 

INJECTION 

RATIO 

lb/MMacf 

1.94 

Capital 

Cost, 

$/kW 

7.37 

Levelized 

Carrying 

Charges, 

Mills/kW-Hr 

0.17 

Fixed 

O&M Cost, 

Mills/kW-Hr 

0.049 

Variable 

O&M Cost, 

Mills/kW-Hr 

0.027 

Consuma 

bles, 

Mills/kWHr 

0.185 

Total 

Annual 

Cost, 

Mills/kWHr 

0.434 

4 975 60.00% Bit 0.6 ESP ESP-4 SI System, 

WI System N/A FG Cooling, ADP+18F 2.95 7.90 0.18 0.050 0.027 0.271 0.533 

4 975 70.00% Bit 0.6 ESP ESP-4 SI System, 

WI System N/A FG Cooling, ADP+18F 4.64 8.70 0.20 0.051 0.028 0.414 0.696 

4 975 80.00% Bit 0.6 ESP ESP-4 SI System, 

WI System SCR FG Cooling, ADP+18F 8.03 10.10 0.24 0.053 0.029 0.700 1.017 

4 975 90.00% Bit 0.6 ESP ESP-4 SI System, 

WI System N/A FG Cooling, ADP+18F 18.17 13.72 0.32 0.057 0.031 1.557 1.966 

4 975 50.00% Bit 0.6 ESP ESP-4 

SI System, 

WI System, 

Ductwork 

N/A FG Cooling, 

ADP+18F 1.94 10.04 0.23 0.050 0.027 0.185 0.496 

4 975 60.00% Bit 0.6 ESP ESP-4 

SI System, 

WI System, 

Ductwork 

N/A FG Cooling, 

ADP+18F 2.95 10.57 0.25 0.050 0.027 0.271 0.596 

4 975 70.00% Bit 0.6 ESP ESP-4 

SI System, 

WI System, 

Ductwork 

N/A FG Cooling, 

ADP+18F 4.64 11.37 0.27 0.051 0.028 0.414 0.759 

4 975 80.00% Bit 0.6 ESP ESP-4 

SI System, 

WI System, 

Ductwork 

N/A FG Cooling, 

ADP+18F 8.03 12.77 0.30 0.053 0.029 0.700 1.080 

4 975 90.00% Bit 0.6 ESP ESP-4 

SI System, 

WI System, 

Ductwork 

N/A FG Cooling, 

ADP+18F 18.17 16.39 0.38 0.058 0.031 1.557 2.029 

4 500 50.00% Bit 0.6 ESP ESP-4 SI System, 

WI System N/A FG Cooling, ADP+18F 1.94 9.23 0.22 0.087 0.047 0.185 0.535 

4 500 60.00% Bit 0.6 ESP ESP-4 SI System, 

WI System N/A FG Cooling, ADP+18F 2.95 9.86 0.23 0.088 0.047 0.271 0.637 

4 500 70.00% Bit 0.6 ESP ESP-4 SI System, 

WI System N/A FG Cooling, ADP+18F 4.64 10.79 0.25 0.090 0.048 0.414 0.804 

4 500 80.00% Bit 0.6 ESP ESP-4 SI System, 

WI System N/A FG Cooling, ADP+18F 8.03 12.44 0.29 0.092 0.049 0.700 1.132 

4 500 90.00% Bit 0.6 ESP ESP-4 SI System, 

WI System N/A FG Cooling, ADP+18F 18.17 16.62 0.39 0.097 0.052 1.557 2.095 

4 500 50.00% Bit 0.6 ESP ESP-4 

SI System, 

WI System, 

Ductwork 

N/A FG Cooling, 

ADP+18F 1.94 12.95 0.30 0.088 0.047 0.185 0.623 

4 500 60.00% Bit 0.6 ESP ESP-4 

SI System, 

WI System, 

Ductwork 

N/A FG Cooling, 

ADP+18F 2.95 13.58 0.32 0.088 0.048 0.271 0.724 

4 500 70.00% Bit 0.6 ESP ESP-4 

SI System, 

WI System, 

Ductwork 

N/A FG Cooling, 

ADP+18F 4.64 14.52 0.34 0.090 0.048 0.414 0.891 

4 500 80.00% Bit 0.6 ESP ESP-4 

SI System, 

WI System, 

Ductwork 

N/A FG Cooling, 

ADP+18F 8.03 16.17 0.38 0.092 0.050 0.700 1.219 

4 500 90.00% Bit 0.6 ESP ESP-4 

SI System, 

WI System, 

Ductwork 

N/A FG Cooling, 

ADP+18F 18.17 20.43 0.48 0.098 0.053 1.557 2.185 

13 100 50.00% Bit 0.6 ESP ESP-4 SI System, 

WI System N/A FG Cooling, ADP+18F 1.94 16.08 0.38 0.383 0.206 0.185 1.150 

13 100 60.00% Bit 0.6 ESP ESP-4 SI System, 

WI System N/A FG Cooling, ADP+18F 2.95 17.08 0.40 0.385 0.207 0.271 1.262 

13 100 70.00% Bit 0.6 ESP ESP-4 SI System, 

WI System N/A FG Cooling, ADP+18F 4.64 18.54 0.43 0.387 0.208 0.414 1.442 

13 100 80.00% Bit 0.6 ESP ESP-4 SI System, 

WI System SCR FG Cooling, ADP+18F 8.03 21.06 0.49 0.391 0.210 0.700 1.793 

13 100 90.00% Bit 0.6 ESP ESP-4 SI System, 

WI System N/A FG Cooling, ADP+18F 18.17 27.30 0.64 0.400 0.215 1.557 2.810 

13 100 50.00% Bit 0.6 ESP ESP-4 

SI System, 

WI System, 

Ductwork 

N/A FG Cooling, 

ADP+18F 1.94 21.98 0.51 0.383 0.206 0.185 1.288 

13 100 60.00% Bit 0.6 ESP ESP-4 

SI System, 

WI System, 

Ductwork 

N/A FG Cooling, 

ADP+18F 2.95 22.97 0.54 0.385 0.207 0.271 1.400 

13 100 70.00% Bit 0.6 ESP ESP-4 

SI System, 

WI System, 

Ductwork 

N/A FG Cooling, 

ADP+18F 4.64 24.43 0.57 0.387 0.209 0.414 1.580 

13 100 80.00% Bit 0.6 ESP ESP-4 

SI System, 

WI System, 

Ductwork 

N/A FG Cooling, 

ADP+18F 8.03 26.96 0.63 0.391 0.211 0.700 1.931 

13 100 90.00% Bit 0.6 ESP ESP-4 

SI System, 

WI System, 

Ductwork 

N/A FG Cooling, 

ADP+18F 18.17 33.19 0.78 0.400 0.216 1.557 2.948 

D-73

ECONOMIC RESULTS S GRAPHICAL FORMAT 

MODEL PLANT # 4, 975 MW 

MERCURY CONTROL COST -- MODEL PLANT 4, ESP-4, 975 MWe, Bituminous 

Coal, 0.6% Sulfur, With and Without Added Ductwork 

0.596 

1.966 

0.434 0.533

0.696 

0.759 1.017

0.496 

2.029 

1.080 

0.25 

0.50 

0.75 

1.00 

1.25 

1.50 

1.75 

2.00 

2.25 

40% 50% 60% 70% 80% 90% 100% 

Total Hg Removed, % 

Total Annual Cost, Mills/kW-Hr 

975 MW, No Ductwork 

975 M<W, W Ductwork 

MODEL PLANT #4, 500 MW 

MERCURY CONTROL COST -- MODEL PLANT 4, ESP-4, 500 MWe, 

Bituminous Coal, 0.6% Sulfur, With and Without Added Ductwork 

0.724 

1.132 

0.804 

0.535 

0.637 

2.095 

1.219 

2.185 

0.623 

0.891 

0.25 

0.50 

0.75 

1.00 

1.25 

1.50 

1.75 

2.00 

2.25 

2.50 

40% 50% 60% 70% 80% 90% 100% 

Total Hg Removed, % 

Total Annual Cost, Mills/kW-Hr 

500 MW, No Ductwork 

500 M<W, W Ductwork 

MODEL PLANT #4, 100 MW 

MERCURY CONTROL COST -- MODEL PLANT 4, ESP-4, 100 MWe, 

Bituminous Coal, 0.6% Sulfur, With and Without Added Ductwork 

2.810 

1.262 1.150 

1.442 

1.793 

1.400 

1.580 

1.288 

2.948 

1.931 

0.75 

1.00 

1.25 

1.50 

1.75 

2.00 

2.25 

2.50 

2.75 

3.00 

3.25 

40% 50% 60% 70% 80% 90% 100% 

Total Hg Removed, % 

Total Annual Cost, Mills/kW-Hr 

100 MW, No Ductwork 

100 MW, W Ductwork 

D-74

RESULTS FOR MODEL PLANTS 10 AND 13 (Recycle for ESP-6) DATE: 6/6/00 

Comments: 

See plot of results below table 

D-75


Model 

Plant # 

10 

Plant 

Size, 

MWe 

100 

Total 

Mercury 

Removed, 

% 

50.00% 

Coal 

Type 

Bit 

Coal 

Sulfur 

Content, 

% by Wt 

3 

Existing 

Pollutant 

Controls 

DS, ESP 

Hg Control 

Configuration 

DS/ESP-1 

Added 

Equipment 

for Hg 

Control 

SI System 

Co-Benefit 

Cases with 

N/A 

Comments 

Costs for SI 

Equipment Only 

MERCURY 

SORBENT 

INJECTION 

RATIO 

lb/MMacf 

1.15 

Capital 

Cost, $/kW 

2.69 

Levelized 

Carrying 

Charges, Mills/kWHr 

0.063 

Fixed 

O&M Cost, 

Mills/kW-Hr 

0.365 

10 100 60.00% Bit 3 DS, ESP DS/ESP-1 SI System N/A Costs for SI Equipment Only 1.79 3.49 0.081 0.366 

10 100 70.00% Bit 3 DS, ESP DS/ESP-1 SI System N/A Costs for SI Equipment Only 2.86 4.64 0.108 0.368 

10 100 80.00% Bit 3 DS, ESP DS/ESP-1 SI System N/A Costs for SI Equipment Only 5.01 6.62 0.155 0.371 

10 100 90.00% Bit 3 DS, ESP DS/ESP-1 SI System N/A Costs for SI Equipment Only 11.44 11.49 0.268 0.379 

13 100 50.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 1.94 16.08 0.376 0.383 

13 100 60.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 2.95 17.08 0.399 0.385 

13 100 70.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 4.64 18.54 0.433 0.387 

13 100 80.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 8.03 21.06 0.492 0.391 13 100 90.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 18.17 27.30 0.638 0.400 

13 100 50.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 1.07 78.11 1.824 0.498 

13 100 60.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 2.65 79.59 1.859 0.500 

13 100 70.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 4.63 81.10 1.894 0.503 

13 100 80.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 10.58 84.78 1.980 0.508 

13 100 90.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 22.47 90.73 2.119 0.517 
ECONOMIC RESULTS S GRAPHICAL FORMAT


MODEL PLANT # 10


MERCURY CONTROL COST -- MODEL PLANT 10, 100 MWe, 

Bituminous Coal, 3% Sulfur 

0.815 

0.734 

0.945 

1.197 

1.925 

0.50 0.70 0.90 1.10 1.30 1.50 1.70 1.90 2.10 

40% 50% 60% 70% 80% 90% 100% 

Total Hg Removed, % 

Total Annual Cost, Mills/kW-H DS/ESP-1 

D-76
MODEL PLANT # 13


ME R C U R Y C ON TR OL C OS T -- MOD E L P L AN T 13, 100 MW e, 

B itu minous C o al, 0.6% S u lfur 

2.9 03 

2.8 10 

1.2 62 

1.1 50 

1.4 42 

1.7 93 

3.5 78 

3.0 77 

4.5 44 

2.7 56 

0.5 0 1.0 0 1.5 0 2.0 0 2.5 0 3.0 0 3.5 0 4.0 0 4.5 0 5.0 0 

40% 50% 60% 70% 80% 90% 100% 

Total Hg Rem oved, % 

Total Annual Cost, Mills/kW-H ES P-4 ES P-6 
RESULTS FOR MODEL PLANTS 10 AND 13 DATE: 5/22/00 

Comments: 

See plot of results below table 

D-77


Model 

Plant # 

10 

Plant 

Size, 

MWe 

100 

Total 

Mercury 

Removed, 

% 

50.00% 

Coal 

Type 

Bit 

Coal 

Sulfur 

Content, 

% by Wt 

3 

Existing 

Pollutant 

Controls 

DS, ESP 

Hg Control 

Configuration 

DS/ESP-1 

Added 

Equipment 

for Hg 

Control 

SI System 

Co-Benefit 

Cases with 

N/A 

Comments 

Costs for SI 

Equipment Only 

MERCURY 

SORBENT 

INJECTION 

RATIO 

lb/MMacf 

1.15 

Capital 

Cost, $/kW 

2.69 

Levelized 

Carrying 

Charges, 

Mills/kW-Hr 

0.063 

Fixed 

O&M Cost, 

Mills/kW-Hr 

0.365 

O

M

10 100 60.00% Bit 3 DS, ESP DS/ESP-1 SI System N/A Costs for SI Equipment Only 1.79 3.49 0.081 0.366 

10 100 70.00% Bit 3 DS, ESP DS/ESP-1 SI System N/A Costs for SI Equipment Only 2.86 4.64 0.108 0.368 

10 100 80.00% Bit 3 DS, ESP DS/ESP-1 SI System N/A Costs for SI Equipment Only 5.01 6.62 0.155 0.371 

10 100 90.00% Bit 3 DS, ESP DS/ESP-1 SI System N/A Costs for SI Equipment Only 11.44 11.49 0.268 0.379 

13 100 50.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 1.94 16.08 0.376 0.383 13 100 60.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 2.95 17.08 0.399 0.385 13 100 70.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 4.64 18.54 0.433 0.387 

13 100 80.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 8.03 21.06 0.492 0.391 13 100 90.00% Bit 0.6 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 18.17 27.30 0.638 0.400 

13 100 50.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 1.07 78.36 1.830 0.498 

13 100 60.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 2.65 80.07 1.870 0.501 

13 100 70.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 4.63 81.81 1.911 0.504 

13 100 80.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 10.58 86.06 2.010 0.510 

13 100 90.00% Bit 0.6 ESP ESP-6 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 22.47 92.95 2.171 0.520 
ECONOMIC RESULTS S GRAPHICAL FORMAT


MODEL PLANT # 10


MERCURY CONTROL COST -- MODEL PLANT 10, 100 MWe, 

Bituminous C oal, 3% S ulfur 

0.815 

0.734 

0.945 

1.197 

1.925 

0.50 0.70 0.90 1.10 1.30 1.50 1.70 1.90 2.10 

40% 50% 60% 70% 80% 90% 100% 

Total Hg Removed, % 

Total Annual Cost, Mills/kW-H DS/ESP-1 

D-78
MODEL PLANT # 13


M E R C U R Y C O N T R O L COS T -- M O DE L P L ANT 1 3 , 100 M W e, 

B itu m in ous C o al, 0.6% S u lfur 

2.9 5 7 

3.7 8 3 

1.7 9 3 

1.4 4 2 

1.1 5 0 

1.2 6 2 

2.7 7 9 2.8 1 0

4.9 6 6 

3.1 7 0 

0.5 0 1.0 0 1.5 0 2.0 0 2.5 0 3.0 0 3.5 0 4.0 0 4.5 0 5.0 0 5.5 0 

40% 50% 60% 70% 80% 90% 100% 

T o ta l Hg Re m o v e d , % 

Total Annual Cost, Mills/kW-Hr ESP -4 ESP -6 
RESULTS FOR MODEL PLANTS 16 AND 17 05/22/2000 

Comments: 

1) Model Plant 16, ESP-4: Minimum Hg removal = 56.2% for ESP with Western Subbituminous Coals 

2) Model Plant 17, FF-2: Minimum Hg removal = 75.7

% for Reverse-Gas FF with Western Subbituminous Coals 

See plot of results below table 

D-79


Model 

Plant # 

16 

Plant Size, 

MWe 

100 

Total 

Mercury 

Removed, 

% 

56.20% 

Coal Type 

Subbit 

Coal 

Sulfur 

Content, 

% by Wt 

0.5 

Existing 

Pollutant 

Controls 

ESP 

Hg Control 

Configuration 

ESP-4 

Added 

Equipment 

for Hg 

Control 

SI System, WI System 

Co-Benefit 

Cases with 

N/A 

Comments 

FG Cooling, 

ADP+18F 

MERCURY 

SORBENT 

INJECTION 

RATIO 

lb/MMacf 

0.00 

Capital 

Cost, $/kW 

11.63 

Levelized 

Carrying 

Charges, 

Mills/kW-Hr 

0.272 

Fixed 

O&M Cost, 

Mills/kW-Hr 

0.375 

16 100 60.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 2.36 15.21 0.355 0.381 

16 100 70.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 4.87 17.52 0.409 0.385 

16 100 80.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 9.00 20.68 0.483 0.390 

16 100 90.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 21.39 28.38 0.663 0.401 

16 100 50.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.04 78.65 1.837 0.499 

16 100 60.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.06 78.73 1.839 0.498 

16 100 70.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.09 78.84 1.841 0.499 

16 100 80.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.17 79.02 1.846 0.500 

16 100 90.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.38 79.46 1.856 0.500 

17 100 50.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.01 11.73 0.274 0.376 17 100 60.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.04 11.88 0.278 0.376 17 100 70.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.09 12.05 0.282 0.377 17 100 80.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.73 13.25 0.310 0.379 17 100 90.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 1.89 14.71 0.344 0.381 
ECONOMIC RESULTS S GRAPHICAL FORMAT


MODEL PLANT # 16


M E R C U R Y C O N T R O L CO S T -- M O DE L P L AN T 16 , 1 00 M We, 

S ub bitumin ous C oal, 0.5% S u lfur 

3.232 

1.174 

0.868 

1.460 1.915 

2.703 2.712 2.701 2.754 2.723 

0.50 1.00 1.50 2.00 2.50 3.00 3.50 

40% 50% 60% 70% 80% 90% 100% 

Total Hg R em oved, % 

Total Annual Cost, Mills/kW-H ESP-4 ESP-6 

D-80
MODEL PLANT # 17


M E R C U R Y C O N T R O L C OS T -- M OD E L P L AN T 17, 100 M W e, 

S u bbitu m in o u s C o a l, 0 .5 % S u lfur 

1.120 

0.872 0.879 0.888 

0.977 

0.85 0.90 0.95 1.00 1.05 1.10 1.15 

40 

% 

45 

% 

50 

% 

55 

% 

60 

% 

65 

% 

70 

% 

75 

% 

80 

% 

85 

% 

90 

% 

95 

% 

100 

% 

To ta l Hg Re m o ve d , % 

Total Annual Cost, Mills/kW-H FF-2 
RESULTS FOR M

ODEL PLANTS 16 AND 17 (Recycle for ESP-6) DATE: 6/6/00 

Comments: 

1) Model Plant 16, ESP-4: Minimum Hg removal = 56.2% for ESP with Western Subbituminous Coals 

2) Model Plant 17, FF-2: Minimum Hg removal = 75.7

% for Reverse-Gas FF with Western Subbituminous Coals 

See plot of results below table 

D-81


Model 

Plant # 

16 

Plant Size, 

MWe 

100 

Total Mercury 

Removed, % 

56.20% 

Coal Type 

Subbit 

Coal 

Sulfur 

Content, 

% by Wt 

0.5 

Existing 

Pollutant 

Controls 

ESP 

Hg Control 

Configuration 

ESP-4 

Added 

Equipment 

for Hg 

Control 

SI System, WI System 

Co-Benefit 

Cases with 

N/A 

Comments 

FG Cooling, 

ADP+18F 

MERCURY 

SORBENT 

INJECTION 

RATIO 

lb/MMacf 

0.00 

Capital 

Cost, $/kW 

11.63 

Levelized 

Carrying 

Charges, 

Mills/kW-Hr 

0.272 

Fixed 

O&M Cost, 

Mills/kW-Hr 

0.375 

O

M

16 100 60.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 2.36 15.21 0.355 0.381 

16 100 70.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 4.87 17.52 0.409 0.385 

16 100 80.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 9.00 20.68 0.483 0.390 

16 100 90.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+18F 21.39 28.38 0.663 0.401 

16 100 50.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.04 78.64 1.837 0.499 

16 100 60.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.06 78.70 1.838 0.498 

16 100 70.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.09 78.80 1.841 0.499 

16 100 80.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.17 78.96 1.844 0.500 

16 100 90.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+18F 0.38 79.30 1.852 0.500 

17 100 50.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.01 11.73 0.274 0.376 

17 100 60.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.04 11.88 0.278 0.376 

17 100 70.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.09 12.07 0.282 0.377 

17 100 80.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 0.73 13.28 0.310 0.379 

17 100 90.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+18F 1.89 14.67 0.343 0.381 
ECONOMIC RESULTS S GRAPHICAL FORMAT


MODEL PLANT # 16


M E R C U R Y C O N T R O L CO S T -- M O D E L P LAN T 16, 100 M We, 

S ubbitu minous C o al, 0.5% S u lfu r 

3.232 

1.174 

0.868 

1.460 1.915 

2.701 2.703 2.710 

2.744 

2.719 

0.50 1.00 1.50 2.00 2.50 3.00 3.50 

40% 50% 60% 70% 80% 90% 100% 

Total Hg R em oved, % 

Total Annual Cost, Mills/kW-H ESP-4 ESP-6 

D-82
MODEL PLANT # 17


M E R C U R Y C O N T R O L CO S T -- M O DE L P L A N T 1 7 , 1 0 0 M W e , 

S u b b itu m in o u s C o a l, 0 .5 % S u lfu r 

1.118 

0.872 0.879 0.889 

0.978 

0.85 0.90 0.95 1.00 1.05 1.10 1.15 

40 

% 

45 

% 

50 

% 

55 

% 

60 

% 

65 

% 

70 

% 

75 

% 

80 

% 

85 

% 

90 

% 

95 

% 

10 0 

% 

To ta l Hg Rem o ve d , % 

Total Annual Cost, Mills/kW-H FF-2 
RESULTS FOR MODEL PLANTS 16 AND 17 (ADP+40) 05/22/2000 

Comments: 

1) Model Plant 16, ESP-4: Minimum Hg removal = 56.2% for ESP with Western Subbituminous Coals 

2) Model Plant 17, FF-2: Minimum Hg removal = 50

% for Reverse-Gas FF with Western Subbituminous Coals 

See plot of results below table 

D-83


Model 

Plant # 

16 

Plant Size, 

MWe 

100 

Total 

Mercury 

Removed, 

% 

56.20% 

Coal Type 

Subbit 

Coal 

Sulfur 

Content, 

% by Wt 

0.5 

Existing 

Pollutant 

Controls 

ESP 

Hg Control 

Configuration 

ESP-4 

Added 

Equipment 

for Hg 

Control 

SI System, WI System 

Co-Benefit 

Cases with 

N/A 

Comments 

FG Cooling, 

ADP+40F 

MERCURY 

SORBENT 

INJECTION 

RATIO 

lb/MMacf 

1.32 

Capital 

Cost, $/kW 

6.84 

Levelized 

Carrying 

Charges, Mills/kWHr 

0.160 

Fixed 

O&M Cost, 

Mills/kW-Hr 

0.366 

V

O&

Mi

16 100 60.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+40F 2.62 8.28 0.194 0.368 

16 100 70.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+40F 4.87 10.33 0.241 0.372 

16 100 80.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+40F 9.00 13.49 0.315 0.376 

16 100 90.00% Subbit 0.5 ESP ESP-4 SI System, WI System N/A FG Cooling, ADP+40F 21.39 21.18 0.495 0.388 

16 100 50.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+40F 0.13 71.70 1.675 0.486 

16 100 60.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+40F 0.21 71.89 1.679 0.485 

16 100 70.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+40F 0.34 72.15 1.685 0.487 

16 100 80.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+40F 0.59 72.59 1.696 0.488 

16 100 90.00% Subbit 0.5 ESP ESP-6 

SI System, 

WI System, 

PJFF 

N/A FG Cooling, ADP+40F 1.36 73.65 1.720 0.489 

17 100 50.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+40F 0.03 4.63 0.108 0.363 

17 100 60.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+40F 0.11 4.92 0.115 0.364 

17 100 70.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+40F 0.26 5.26 0.123 0.364 

17 100 80.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+40F 0.73 6.06 0.142 0.366 

17 100 90.00% Subbit 0.5 FF FF-2 SI System, WI System N/A FG Cooling, ADP+40F 1.89 7.52 0.176 0.368 
ECONOMIC RESULTS S S GRAPHICAL FORMAT


MODEL PLANT # 16


M E RCURY CO NT RO L CO S T -- M O DE L P LAN T 16, 100 M We, 

S u bbitumino us C oal, 0.5% S ulfur 

2.515 2.525 2.546 

3.030 

1.003 

0.848 

1.259 1.714 

2.677 

2.580 

0.50 1.00 1.50 2.00 2.50 3.00 3.50 

40% 50% 60% 70% 80% 90% 100% 

Total Hg R em oved, % 

Total Annual Cost, Mills/kW-H ESP -4 ESP -6 

D-84
MODEL PLANT # 17


M E R C U R Y C O N T R O L C O S T -- M O DE L P L A N T 1 7 , 1 0 0 M W e , 

S u b b itu m in o u s C o al, 0.5% S u lfu r 

0.919 

0.675 0.691

0.713 

0.776 

0.65 0.70 0.75 0.80 0.85 0.90 0.95 

45% 55% 65% 75% 85% 95% 

To ta l Hg Re m o ve d , % 

Total Annual Cost, Mills/kW-H FF-2 
Sensitivity Results: Plant 4, ESP-6 & ESP-7, No ICR Mod, Combined Lime-Carbon Sorbent DATE: 6/14/00 

500 MW 

Comments: 

Application: Plant 4, ESP-6, AC sorbent (50-90% Removal); Plant 4, ESP-7, AC-Lime Sorbent (90%+ removal) 

Plant size: 500 MWe AC sorbent Cost = $908/Ton AC-Lime Sorbent Cost = $149/Ton, Assumes C:Lime ratio = 2:19 

ESP-7 Sensitivity Cases Assume 90%+ Hg Removal based on ADA Technologies tests at PSE&G 

ESP-7 Sensitivity Cases run for 1, 2, 3, 4 lb/Mmacf Sorbent Concentration 

ESP-6 Comparison Cases Run for 50, 60, 70, 80, 90% Hg Removal 

See plot of results below table 

D-85


Model 

Plant # 

4 

Plant 

Size, 

MWe 

500 

Total 

Mercury 

Removed, 

% 

50.00% 

Coal Type 

Bit 

Coal 

Sulfur 

Content, 

% by Wt 

0.6 

Existing 

Pollutant 

Controls 

ESP 

Hg Control 

Configuration 

ESP-6 

Added 

Equipment 

for Hg 

Control 

SI System, WI System 

Co-Benefit 

Cases with 

N/A 

Comments 

FG Cooling, 

ADP+18F 

MERCURY 

SORBENT 

INJECTION 

RATIO 

lb/MMacf 

1.07 

Capital 

Cost, $/kW 

54.48 

Levelized 

Carrying 

Charges, 

Mills/kW-Hr 

1.27 

Fixed O&M 

Cost, 

Mills/kW-Hr 

0.171 

4 500 60.00% Bit 0.6 ESP ESP-6 SI System, WI System N/A FG Cooling, ADP+18F 1.66 54.91 1.28 0.171 

4 500 70.00% Bit 0.6 ESP ESP-6 SI System, WI System N/A FG Cooling, ADP+18F 2.65 55.55 1.30 0.172 

4 500 80.00% Bit 0.6 ESP ESP-6 SI System, WI System N/A FG Cooling, ADP+18F 4.63 56.67 1.32 0.174 

4 500 90.00% Bit 0.6 ESP ESP-6 SI System, WI System N/A FG Cooling, ADP+18F 10.58 59.46 1.39 0.178 

4 500 90.00% Bit 0.6 ESP ESP-7 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 1.00 54.33 1.27 0.171 

4 500 90.00% Bit 0.6 ESP ESP-7 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 2.00 54.94 1.28 0.172 

4 500 90.00% Bit 0.6 ESP ESP-7 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 3.00 55.46 1.30 0.173 

4 500 90.00% Bit 0.6 ESP ESP-7 

PJFF, SI 

System, WI 

System 

N/A FG Cooling, ADP+18F 4.00 55.93 1.31 0.173 
ECONOMIC RESULTS S GRAPHICAL FORMAT


MODEL PLANT # 4, 500 MW, Comparison of ESP-6 and ESP-7


MERCURY CONTROL COST -- MODEL PLANT 4, ESP-6 & 7, 500 MWe, Bituminous 

Coal, 0.6%Sulfur, Comparison of AC Sorbent and Lime-AC Sorbent 

2.650 

1.779 1.717 

1.879 

2.075 1.672 1.702 

1.640 

1.731 

1.50 1.75 2.00 2.25 2.50 2.75 

40% 50% 60% 70% 80% 90% 100% 

Total Hg Removed, % 

Total Annual Cost, Mills/kW-Hr "ESP-6, AC sorbent ESP-7, Lime-AC Sorbent 

D-86
MODEL PLANT # 4, 100 MW 

MERCURY CONTROL COST -- MODEL PLANT 4, ESP-4, 100 MWe, 

Bituminous Coal, 0.6% Sulfur, With and Without Added Ductwork 

2.810 

1.262 1.150 

1.442 

1.793 

1.400 

1.580 

1.288 

2.948 

1.931 

0.75 1.00 1.25 1.50 1.75 2.00 2.25 2.50 2.75 3.00 3.25 

40% 50% 60% 70% 80% 90% 100% 

Total Hg Removed, % 

Total Annual Cost, Mills/kW-Hr 100 MW, No Ductwork 100 MW, W Ductwork