EPA-600/R-05/034 

March 2005 

Multipollutant Emission 

Control Technology Options 

for Coal-fired Power Plants 
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 is the agency’s center for investigation of 

technological and management approaches for reducing risks from threats to human health and the 

environment. The focus of the laboratory's research program is on methods for the prevention and control 

of pollution to air, land, water, and subsurface resources, protection of water quality in public water 

systems; remediation of contaminated sites and groundwater; and prevention and control of indoor air 

pollution. The goal of this research effort is to catalyze development and implementation of innovative, 

cost-effective environmental technologies; develop scientific and engineering information needed by EPA 

to support regulatory and policy decisions; and provide technical support and information transfer to 

ensure effective implementation of environmental regulations and strategies. 

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. 

Sally Gutierrez, 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-05/034 

March 2005 

Multipollutant Emission Control Technology Options 

for Coal-fired Power Plants

Prepared by: 

E. Stratos Tavoulareas 

Energy Technologies Enterprises Corporation 

1112 Towlston Road 

McLean, VA 22105 

and 

Wojciech Jozewicz 

ARCADIS G&M, Inc. 

4915 Prospectus Drive, Suite F 

Durham, NC 27713 

EPA Contract No. 68-C-99-201, Work Assignment 6-13 

EPA Project Officer: Ravi K. Srivastava 

National Risk Management Research Laboratory 

Research Triangle Park, NC 27711 

Prepared for: 

U.S. Environmental Protection Agency 

Office of Research and Development 

Washington, DC 20460 

and 

U.S. Environmental Protection Agency 

Office of Air and Radiation 

Washington, DC 20460
Abstract 

This report presents and analyzes various existing and novel control technologies designed to achieve 

multi-emission [sulfur dioxide (SO2), nitrogen oxide (NOX), and mercury (Hg)] reductions. Summary 

descriptions are included of 27 multi-emission control technologies that have reached a stage of 

development beyond pilot scale. These can broadly be divided into: environmental control options (postcombustion controls), advanced power generation options, and power plant upgrading and operating 

options. For each evaluated technology, the report includes background information, applicability, status 

of commercialization, any secondary environmental impacts of the technologies, identification of primary 

process variables that impact performance relative to NOX, SO2, and Hg, as well as capital and operation 

and maintenance costs. 

More than half of the technology options listed are in the commercial or early commercial stage (15 out of 

27). However, nearly all the technology options in the commercial stage are proven SO2 control 

technologies, which also appear to remove Hg. Some technologies, such as Advanced Silicate and 

Confined Zone Dispersion, have been tested in either the pilot or demonstration scale in the early phase of 

the U.S. Department of Energy’s Clean Coal Technology program, but have not been adopted by 

industry. Some of these technologies could become more cost-effective as environmental requirements 

evolve. Activated coke, electro-catalytic oxidation, EnviroScrub, and the combination of flue gas 

desulfurization with LoTOx or selective catalytic reduction exhibit the potential to significantly control 

(above 80 percent) all three pollutants (SO2, NOX, and Hg). 

Although the report is limited to addressing technologies with a certain level of maturity, the authors 

expect a rapid technological evolution in the development and commercialization of several multiemission control technologies not addressed in this report. 

ii 
Acknowledgments 

ARCADIS would like to acknowledge the many contributors to this document without whose efforts this 

report would not be complete. In particular, we wish to acknowledge the technical guidance provided by 

Dr. Ravi Srivastava of EPA’s National Risk Management Research Laboratory, Office of Research and 

Development, and many helpful discussions with Mr. Reynaldo Forte and Mr. Sikander Khan, both of 

EPA’s Clean Air Markets Division, Office of Air and Radiation. Helpful suggestions were received from 

Mr. Kevin Culligan and Ms. Mary Jo Krolewski of EPA’s Clean Air Markets Division. 

iii 
Table of Contents 

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

Acknowledgments........................................................................................................................................iii

Table of Contents.........................................................................................................................................iv

List of Tables ...............................................................................................................................................vi

List of Figures..............................................................................................................................................vi

List of Acronyms ........................................................................................................................................vii

Conversion of Units.....................................................................................................................................ix

Metric Prefixes.............................................................................................................................................ix

Chapter 1 Introduction......................................................................................................................1-1

1.1 Intended Use and Organization of this Report...........................................................................1-1

1.2 Background................................................................................................................................1-2

1.3 Human Health and Environmental Impacts...............................................................................1-2

1.3.1 Fine Particles....................................................................................................................1-2

1.3.2 Ground-Level Ozone .......................................................................................................1-3

1.3.3 Acid Deposition ...............................................................................................................1-3

1.3.4 Visibility ..........................................................................................................................1-3

1.3.5 Mercury............................................................................................................................1-4

1.4 Multi-emission Control Options ................................................................................................1-4

1.5 References..................................................................................................................................1-5

Chapter 2 Characterization of U.S. Power Plants and Associated Emissions..................................2-1

2.1 SO2 Emissions from Coal-Fired Power Plants...........................................................................2-2

2.2 NOX Emissions from Coal-Fired Power Plants..........................................................................2-4

2.3 Mercury Emissions from Coal-Fired Power Plants ...................................................................2-8

2.4 CO2 Emissions from Coal-Fired Power Plants ..........................................................................2-9

2.5 References................................................................................................................................2-10

Chapter 3 Multi-emission Control Technologies and Options for Coal-fired Power Plants...........3-1

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

3.2 Environmental Control Options.................................................................................................3-3

3.2.1 SO2 and Mercury Control ................................................................................................3-3

3.2.1.1 Dry Scrubbers..............................................................................................................3-3

3.2.1.1.1 Conventional Dry Scrubbers...................................................................................3-3

3.2.1.1.2 Advanced Dry Scrubbers ........................................................................................3-8

3.2.1.2 Sorbent Injection .......................................................................................................3-12

3.2.1.2.1 Activated Carbon with Particulate Controls..........................................................3-13

3.2.1.2.2 SO2 Sorbents .........................................................................................................3-19

3.2.1.2.3 Combined Mercury and SO2 Sorbents..................................................................3-24

3.2.1.3 Wet Scrubbers ...........................................................................................................3-27

3.2.1.3.1 Wet Scrubbers with Mercury Oxidation Processes...............................................3-28

3.2.1.3.2 Wet Scrubbers with Wet ESP ...............................................................................3-31

3.2.1.3.3 Plasma-Enhanced ESP (PEESP)...........................................................................3-34

3.2.1.4 MerCAP.....................................................................................................................3-36

3.2.2 SO2 and NOX Control ...................................................................................................3-38

3.2.2.1 Electron Beam Process..............................................................................................3-38

3.2.2.2 ROFA-ROTAMIX (Mobotec)...................................................................................3-42

3.2.2.3 SNOX .........................................................................................................................3-45

iv 
3.2.2.4 SOX-NOX-Rox Box (SNRB) .....................................................................................3-49

3.2.2.5 THERMALONOX and FLU-ACE Process...............................................................3-51

3.2.3 SO2, NOX, and Mercury Control....................................................................................3-53

3.2.3.1 Activated Coke ..........................................................................................................3-53

3.2.3.2 Electro-Catalytic Oxidation (ECO) ...........................................................................3-57

3.2.3.3 SCR and Wet FGD ....................................................................................................3-63

3.2.3.4 EnviroScrub Pahlman................................................................................................3-67

3.2.3.5 LoTOx .......................................................................................................................3-69

3.2.3.6 K-Fuel........................................................................................................................3-74

3.2.4 Advanced Power Generation Technology Options........................................................3-78

3.2.4.1 Circulating Fluidized Bed Technology......................................................................3-78

3.2.4.2 Integrated Gasification Combined Cycle ..................................................................3-82

3.2.4.3 Pressurized Fluidized Bed Combustion (PFBC) .......................................................3-86

3.2.4.4 Supercritical Pulverized Coal Plant...........................................................................3-90

3.2.5 Power Plant Upgrading and Operating Options.............................................................3-94

3.2.5.1 Fuel Blending and Cofiring .......................................................................................3-94

3.2.5.2 Plant Efficiency Improvements...............................................................................3-100

3.2.5.3 Power Plant Optimization........................................................................................3-103

Chapter 4 Summary..........................................................................................................................4-1

v 
List of Tables 

Table 2-1. Emissions in 2001 from Coal and Non-coal Units ...................................................................2-2

Table 2-2. SO2 Emissions from Units with FGD Installed in 1990-1999..................................................2-4

Table 2-3. 1999 NOX Emissions for Title IV Affected Units ....................................................................2-6

Table 2-4. Mean Mercury Emission Reduction for Pulverized-coal-fired Boilers ....................................2-8

Table 3-1. Average Mercury Reductions for Spray Dryer and ESP-FF per Coal Rank from ICR Data ...3-5

Table 3-2. Duct Injection of Lime Slurry ................................................................................................3-20

Table 3-3. Duct Injection of Dry Lime ....................................................................................................3-21

Table 3-4. Duct Injection of Sodium .......................................................................................................3-21

Table 3-5. Summary of MerCAP Field Sites...........................................................................................3-37

Table 3-5 Sintering Plants Utilizing Activated Coke...............................................................................3-55

Table 3-6. Selected SCR Test Results .....................................................................................................3-65

Table 3-7. Mercury Data for Various Coals ............................................................................................3-71

Table 3-8. CFB Units larger than 200 MW .............................................................................................3-80

Table 3-9. Commercial-Size IGCC Power Plants....................................................................................3-83

Table 3-10. PFBC Plants and Operating Experience...............................................................................3-88

Table 3-11. Power Plants with Supercritical Design Parameters.............................................................3-91

Table 3-12. Equivalent Availability for Subcritical and Supercritical Power Plants...............................3-92

Table 3-14. Main O&M Impacts and Potential Mitigations ....................................................................3-98

Table 4-1. Summary Descriptions of 27 Multi-emission Control Technologies for Coal-fired Units ......4-3

List of Figures 

Figure 2-1. Major sources of SO2 and NOX emissions in 2001 and of mercury emissions in 1998 ..........2-1

Figure 2-2. Annual SO2 emissions for coal-fired units..............................................................................2-3

Figure 2-3. Annual NOX emissions for coal-fired units.............................................................................2-5

Figure 2-4. Annual CO2 emissions for coal-fired units..............................................................................2-9

Figure 3-1. Mercury removal across spray dryer and ESP-FF from ICR data...........................................3-5

Figure 3-2. Mercury removal versus activated carbon loading in a pilot scale ESP and baghouse.........3-16

Figure 3-3. E-Beam process schematic....................................................................................................3-39

Figure 3-4. NOX emissions from Cape Fear Unit 5: comparison before and after ROFA.......................3-44

Figure 3-5. SNOX process schematic .......................................................................................................3-46

Figure 3-6. Activated coke process flow diagram ...................................................................................3-54

Figure 3-7. ECO process flow diagram ...................................................................................................3-59

Figure 3-8. ECO power consumption versus NOX ..................................................................................3-62

Figure 3-8. Schematic diagram of LoTOxTM system ...............................................................................3-70

Figure 3-9. NOX with LoTOx at MCO’s 25 MW-thermal gas and coal fired boiler ...............................3-72

Figure 3-10. K-Fuel PMR technology .....................................................................................................3-75

Figure 3-11. K-Fuel thermal separation unit............................................................................................3-75

Figure 3-12. CFB process schematic .......................................................................................................3-79

Figure 3-13. PFBC conceptual design .....................................................................................................3-87

vi 
List of Acronyms 

AC Activated carbon 

ACI Activated carbon injection 

ADVACATE Advanced Silicate 

AFBC Atmospheric fluidized bed combustor 

APCD Air pollution control device 

BOP Balance of plant 

Btu British thermal unit 

CAAA Clean Air Act Amendments of 1990 

CCT Clean Coal Technology 

CDS Circulating Dry Scrubbing 

CEDF Clean Environment Development Facility 

CFB Circulating fluidized-bed 

CFD Computerized Fluid Dynamics Modeling 

CO2 Carbon dioxide 

COHPAC Compact hybrid particulate collector 

CZD Confined-zone Dispersion 

DBA Dibasic Acid 

DOE Department of Energy 

ECO Electro-catalytic Oxidation 

EdF Electricite de France 

EIA Energy Information Administration 

EOY End of year 

EPA Environmental Protection Agency 

EPRI Electric Power Research Institute 

E-SOX ESP enhanced for SO2 removal 

ESP Electrostatic precipitator 

ESP-CS Cold-side electrostatic precipitator 

ESP-HS Hot-side electrostatic precipitator 

FF Fabric filter 

FGD Flue Gas Desulfurization 

GSA Gas Suspension Absorption 

HALT Hydrate Addition at Low Temperature 

HAP Hazardous air pollutant 

Hg Mercury 

HHV Higher heating value 

HP Horse power 

HRSG Heat recovery steam generator 

HYPAS Hybrid pollution abatement system 

ICR Information collection request 

IDS In-duct scrubbing 

IGCC Integrated gasification combined cycle 

IPM Integrated planning model 

kWh Kilowatt hour 

KRW Kellogg Rust Westinghouse 

lb Pound-mass 

vii 
LOI Loss-on-ignition 

MM Million (106

) 

MSW Municipal solid waste 

MW Megawatt (electric) 

NAAQS National Ambient Air Quality Standards 

NOX Nitrogen oxides 

NSPS New source performance standards 

NSR New source review 

OFA Overfire Air 

O&M Operation and maintenance 

PAC Powdered activated carbon 

PC Pulverized coal 

PEESP Plasma-enhanced ESP 

PFBC Pressurized fluidized-bed combustion 

PM Particulate matter 

PS Particulate scrubber 

PSD Prevention of significant deterioration 

RAP Rapid absorption process 

RCFB Reflux circulating fluidized bed 

ROFA Rotating opposed air 

SCR Selective catalytic reduction 

SDA Spray dryer absorber 

SIP State implementation plan 

SNCR Selective non-catalytic reduction 

SO2 Sulfur dioxide 

SRG SO2-rich gas 

TAG Technical assessment guide 

TVA Tennessee Valley Authority 

TOXECON ACI combined with COHPAC 

UNFCCC United Nations Framework Convention on Climate Change 

WESP Wet electrostatic precipitator 

WSA Wet gas sulfuric acid condenser 

viii 
Conversion of Units 

Multiply By To Obtain 

POWER 

Watts 1 Newton-meter/second or Joule/second 

Watts 0.05692 Btu/minute 

Watts 1.341 x 10-3 Horsepower 

ENERGY 

Joules 1 Watt-seconds or Newton-meters 

Kilowatt-hours 

(kWh) 

3415 Btu 

Kilowatt-hours 1.341 Horsepower-hours 

Kilowatt-hours 3.60 x 106 Joules 

Btu 1,054 Joules 

MASS 

Kilograms 2.2046 Pounds 

Pounds 0.4536 Kilograms 

Ton (short or US) 2000 Pounds 

Tonne (metric ton) 1.1023 Ton (short or US) 

Metric Prefixes 

Prefix Symbol Value 

Tera T 1012

Giga G 109

Mega M 106

Kilo k 103

Hecto h 102

Deka da 10 

Deci d 10-1

Centi c 10-2

Milli m 10-3

Micro μ 10-6

ix 
x 
Chapter 1

Introduction 

Recent changes in the structure of the electric utility industry, including the shift towards restructuring, 

the growing demand for electricity generation, and environmental needs, are driving additional reductions 

of multiple pollutants. Historically, industry has developed and implemented control technologies in 

incremental steps to mitigate emissions of sulfur dioxide (SO2), oxides of nitrogen (NOX), particulate 

matter (PM), and other pollutants, as driven by air pollution requirements. Control technologies that are 

capable of simultaneously reducing emissions of multiple pollutants may offer the potential to achieve 

this at lower cost and reduced footprint when compared to conventional controls. 

This report presents and analyzes various existing and novel control technologies designed to achieve 

multi-emission reductions. Having up-front knowledge of environmental performance, cost, and 

limitations of multi-emission control technologies can help power companies select effective and less 

expensive compliance strategies at individual plants, compared with compliance choices made when the 

requirements are addressed individually. 

1.1 Intended Use and Organization of this Report 

The intended use for this report is to provide the current state-of-the art information on the multi-emission 

control technologies and options that are available for coal-fired power plants with a capacity of 25 

megawatts-electric (MW) or larger in the United States. For the purposes of this report, multi-emission 

control technologies are those capable of simultaneously controlling emissions of at least two of these 

three pollutants, NOX, SO2, and mercury, from electric utility sources. This evaluation includes 

background information, applicability, status of commercialization, any secondary environmental impacts 

of the technologies, identification of primary process variables that impact performance relative to NOX, 

SO2, and mercury, as well as capital and operation and maintenance (O&M) costs, if available. In addition 

to simultaneously controlling at least two of the SO2, NOX, and mercury emissions, some technologies 

reviewed under this study promise to enable reductions of the carbon emissions that result from coalbased electricity production. Such capability is viewed as an additional benefit and discussed for each 

applicable technology, given that reducing carbon emissions would be advantageous to the fulfillment of 

U.S. commitments under the United Nations Framework Convention on Climate Change (UNFCCC) and 

would further the President’s commitment to reduce greenhouse gas intensity in the United States by 18 

percent over the next decade.1

The audience for this report is expected to comprise persons: (1) engaged in air pollution related research 

and development (R&D) efforts, (2) responsible for developing and implementing emission control 

strategies at sources, (3) and involved in developing air regulations, as well as (4) the interested public. 

The report is organized into four chapters. The first chapter provides general background information on 

air emissions from coal-fired power plants and multi-emission control technologies. The second chapter 

characterizes U.S. power plants of 25 MW or greater and their respective air emissions. Chapter 3 

presents evaluation summaries of 27 multi-emission control technologies. These summaries include 

details on the technology, commercial readiness and industry experience, emission control performance, 

future outlook, as well as capital and O&M costs. Chapter 4 is a summary of the report. 

1-1 
1.2 Background

Electricity is critical to the well functioning of the residential, commercial, and industrial sectors in the 

United States. More than 3,170 traditional electric utility plants and 2,110 non-utility power plants are 

responsible for ensuring an adequate and reliable source of electricity to consumers in their service 

territories.2

 While electricity plays a critical role in sustaining the nation’s economic growth, the 

unintended by-products of electricity generation can have an undesirable effect on the environment and 

public health. Most of these health impacts result from emissions produced through the combustion of 

fossil fuels (coal, oil, and natural gas), which supply about 70 percent of the nation’s requirements for 

electricity generation. 

As a result, the focus of recent regulatory actions has been to require power plants to reduce emissions of 

NOX and SO2. The revisions of the National Ambient Air Quality Standards (NAAQS) for PM and ozone 

may also limit power plant emissions. These revisions may require electric utility sources to adopt control 

measures designed to reduce concentrations of fine PM in the atmosphere. Fine PM is PM at or below 2.5 

micrometer in size (PM2.5). In addition, EPA has recently proposed a rule that calls for regulation of 

mercury emissions from electric utility coal-fired plants. Concurrently, legislation has been proposed in 

both the previous and current Congresses that would require simultaneous reductions of multiple 

emissions, and the Administration’s National Energy Policy3

 recommends the establishment of 

“mandatory reduction targets for emissions of three main pollutants: sulfur dioxide, nitrogen oxides, and 

mercury.” 

This report focuses on control technologies that promise to simultaneously control more than one 

pollutant from coal-burning power plants. The report focuses on emissions from coal-fired power plants 

since these plants generate about 50 percent of the electricity used in the United States. The coal-burning 

electric power industry is a major source of various air pollutant emissions including SO2, NOX, and 

mercury. In addition, the combustion of fossil fuels contributes to CO2 emissions to the atmosphere. 

1.3 Human Health and Environmental Impacts 

Over the last 30 years, the reduction of emissions from the electric power sector has led to significant 

human health and environmental benefits. Title IV of the Clean Air Act Amendments of 1990 (CAAA), 

for example, has reduced acid deposition by approximately 25 percent and substantially reduced airborne 

particulate matter.1

 At the same time, the U.S. economy has expanded, and the amount of electricity 

supplied to consumers has grown significantly. In spite of the progress made to date, the electric power 

industry is still a significant source of SO2, NOX, and mercury emissions (see Chapter 2). These pollutants 

continue to pose threats to human health and the environment as described below. 

1.3.1 Fine Particles 

Emissions of SO2 and NOX lead to the formation of fine particles (particles less than 2.5 micrometers). 

Most fine particles, namely sulfates and nitrates, are formed when SO2, NOX and volatile organic 

compounds and ammonia react in the air. Fine particles can travel for long distances in the air before 

 

1 Title IV of the Clean Air Act Amendments of 1990, Acid Deposition Control, sets a goal of reducing annual SO2 emissions by 10 million tons below 1980 levels and a 2 million ton annual 

reduction in NOX emissions by the year 2000 from fossil fuel-fired power plants. The program affects existing utility units serving generators with an output capacity of greater than 25 

megawatts and all new utility units. To achieve these reductions, the law required a two-phase tightening of the restrictions. Phase I was from 1995-1999 and affected 263 units at 110 

mostly coal-burning electric utility plants located in 21 eastern and midwestern states. An additional 182 units joined Phase I of the program as substitution or compensating units, 

bringing the total of Phase I affected units to 445. Phase II, which began in the year 2000, tightened the annual emissions limits imposed on these large, higher emitting plants and also 

set restrictions on smaller, cleaner plants fired by coal, oil, and gas, encompassing over 2,000 units in all. 

1-2 
being deposited far away from where the emissions took place. Fine particles pose serious threats to 

public health because their size allows them to easily reach the most sensitive parts of the lungs. Scientific 

studies have linked fine particles (alone or in combination with other air pollutants) with a series of 

significant health problems, including premature death. 

1.3.2 Ground-Level Ozone 

Ozone is formed when emissions of NOX and volatile organic compounds (VOCs) react in the presence of 

sunlight. Ground-level ozone is the primary component of smog and tends to be a problem over broad 

regional areas, particularly in the eastern United States and some urban areas including Los Angeles and 

Houston. Ozone can damage lung tissue, reduce lung function, and adversely sensitize the lungs to other 

irritants. Long-term exposures to ozone can cause repeated inflammation of the lung, impairment of lung 

defense mechanisms, and irreversible changes in lung structure, which can lead to premature aging of the 

lungs or chronic respiratory illnesses such as emphysema and chronic bronchitis. Ozone can also 

aggravate asthma, causing more frequent and severe asthma attacks. 

1.3.3 Acid Deposition 

Acid deposition results from the reaction of SO2 and NOX air-borne emissions with water, oxygen, and 

oxidants to form various acidic compounds. It occurs both as wet deposition through acidic rain, fog, and 

snow and as dry deposition through acidic gases and particles. Acid deposition lowers the pH of sensitive 

lakes and streams to toxic levels. Lower pH can impact entire ecosystems through changes in the food 

chain. Acid deposition causes release of aluminum from soil, which is also very toxic to fish. It can 

directly affect forest ecosystems by damaging plant tissue involving leaching of foliar calcium2

 in certain 

plants. In other cases, multiple pollutants such as ozone, SO2, and NOX can combine to weaken trees and 

make them vulnerable to other threats, such as pests, that cause mortality. 

Atmospheric deposition is a rapidly growing anthropogenic source of biologically available nitrogen in 

estuarine and near-coastal ecosystems. Depending on the location, from 10 to 80 percent of new nitrogen 

inputs to coastal waters along the east and Gulf coasts of the United States are of atmospheric origin.4

This nitrogen contributes to eutrophication of these waters, which results in one or more undesirable 

ecological impacts. These impacts include algae blooms, massive die-offs of estuarine and marine plants 

and animals (including fish), loss of biological diversity, and degradation or loss of essential coastal 

ecosystem habitat (such as sea grass beds). These ecological changes impact commercial and recreational 

fisheries and reduce our ability to use and enjoy coastal ecosystems. Recent studies also link atmospheric 

nitrogen deposition, coastal eutrophication, and harmful algal blooms with human health impacts.5-8

1.3.4 Visibility 

Visibility impairment is another undesirable by-product of air pollution. Visibility is generally defined as 

the degree to which the atmosphere is transparent to visible light; visibility impairment is a reduction in 

visual range and atmospheric discoloration. Regional haze obscures the clarity, color, texture, and form of 

what is seen. The same fine particles that adversely affect human health are the primary cause of regional 

haze. Visibility is of more concern in national parks and wilderness areas. 

 

2 Leaching of foliar calcium from the needles of red spruce, which reduces the cold tolerance of individual trees, has contributed to the decline of high-altitude red spruce forests 

throughout eastern North America. Recent studies indicate that foliar calcium loss may occur with other species as well. 

1-3 
1.3.5 Mercury 

Mercury cycles in the environment as a result of natural and human activities. Most anthropogenic 

mercury emissions to the air come from stationary combustion sources, including waste and fossil fuel 

combustion. About 64 percent (48 tons) of the mercury in the coal burned in power generation plants in 

1999 was emitted to the atmosphere.9

 The percent contribution to total anthropogenic mercury emissions 

from power generation is expected to become even greater as coal-fired generation increases and the final 

mercury standards for municipal waste combustors and medical and hazardous waste incinerators are 

fully implemented. Current releases are adding to the mercury that already exists in land, water, and air, 

both naturally and as a result of previous human activities. 

Mercury in combustors exists in elemental, ionic, or particulate forms. Elemental mercury can be widely 

dispersed and transported for many miles, whereas ionic mercury, which is soluble in aqueous solutions, 

and particulate mercury are typically deposited close to the emissions source. Once mercury is deposited 

in lakes, rivers, and oceans, it is converted to methylmercury by aquatic organisms and bioaccumulates in 

the food chain, resulting in high concentrations in predatory fish. In the United States, most human 

exposure to mercury is the result of consumption of fish contaminated with methylmercury. Adverse 

effects of mercury on fish, birds and mammals include death, reduced reproductive success, impaired 

growth and development, and behavioral abnormalities. 

While EPA has already taken action to reduce mercury emissions from other major sources such as 

municipal waste combustors, medical waste incinerators and hazardous waste combustors, coal-fired 

power plants’ mercury emissions into the air remain uncontrolled. The EPA took the first step towards 

controlling mercury emissions from the power generation sector on December 14, 2000 by issuing a 

finding that mercury emissions from the coal-fired power plants should be controlled. Based on this 

determination, the agency proposed the “Utility Mercury Reductions Rule” in December 2003, which 

calls for significant reductions of mercury from the utility coal-fired power plants. 

1.4 Multi-emission Control Options 

This report addresses multi-emission control technologies that have reached a stage of development 

beyond pilot scale. It includes those technologies that integrate in-situ or post-combustion controls of at 

least two of the SO2, NOX, and mercury pollutants, either in one process or a combination of coordinated 

and complementary processes. In addition, the report includes new coal-fired electricity-generating 

technologies, which are inherently more efficient than conventional coal-fired power plants or have the 

potential to generate lower emission of air pollutants and CO2. The report also looks at power plant 

improvements capable of reducing emissions and producing higher energy efficiencies. 

It is envisioned that the report will assist the electric power industry in selecting emission control options 

for power plants. Information on environmental performance, cost, commercialization barriers, and other 

relevant factors on these technologies could enable power companies to choose less expensive air 

pollution compliance approaches, compared to controlling individual emissions through a series of 

controls in succession, each targeting a different pollutant. In certain cases, such as in a constrained plant 

layout, multi-emission control technologies may represent the most practical method of providing the 

necessary environmental benefits. 

This report is limited to coal-fired power plant emission controls and power generation technologies and 

does not include consideration of other power generating options such as systems based on renewable 

energy sources. The authors do recognize that these latter options do offer tremendous potential in 

reducing air pollution, and suggest they be addressed under separate efforts. 

1-4 
1.5 References 

1. Energy Information Agency. International Energy Outlook, U.S. Greenhouse Gas Intensity 

Target. http://tonto.eia.doe.gov/FTPROOT/forecasting/0484(2003).pdf. (accessed Dec 1, 2004). 

2. Overview of the Electric Power Industry; Energy Information Agency, U.S. Department of 

Energy: Washington, DC, Sept 2000 (1998 survey data). 

3. Bush, G. W. Remarks by the President on National Energy Policy in Photo Opportunity with 

Cabinet Members: 2001; ISBN 0-16-050814-2; Report of the National Energy Policy 

Development Group, U.S. Government Printing Office: Washington, DC, May 16, 2001. 

http://www.whitehouse.gov/energy/ (accessed Dec 1, 2004). 

4. Valigura, R. A.; Alexander, R. B.; Castro, M. S.; Meyers, T. P.; Paerl, H. W.; Stacey, P. E.; 

Turner, R. E. Nitrogen Loading in Coastal Water Bodies: An Atmospheric Perspective; American 

Geophysical Union, 2000. 

5. Paerl, H. W.; Whitall, D. R. Anthropogenically-derived Atmospheric Nitrogen Deposition, 

Marine Eutrophication and Harmful Algal Bloom Expansion: Is There a Link? Ambio 1999, 28. 

6. Epstein, P. R. Positive Incentives for an Energy Transition. In: Global Environment Facility 

(GEF), Valuing the Global Environment: Actions and Investments for a 21st Century; Global 

Environmental Facility: Washington, DC, 1998; 98-99. 

7. Burkholder, J. M.; Glasgow, H. B., Jr. Pfesteria Piscicida and Other Pfesteria-like 

Dinoflagellates: Behavior, Impacts and Environmental Controls. Limnol. Oceanogr. 1997, 42, 

1052-1075. 

8. Paerl, H. W. Coastal Eutrophication and Harmful Algal Blooms: Importance of Atmospheric 

Deposition and Groundwater as "New" Nitrogen and Other Nutrient Sources. Limnol. Oceanogr. 

1997, 42, 1154-1165. 

9. Kilgroe, J. D.; Sedman, C. B.; Srivastava, R. K.; Ryan, J. V.; Lee, C.W., Thorneloe, S. A. Control 

of Mercury Emissions from Coal-Fired Electric Utility Boilers, Interim Report; EPA-600/R-01-

109 (NTIS PB2002-105701); National Risk Management Research Laboratory: Research 

Triangle Park, NC, Dec 2001. 

1-5 
1-6 
Chapter 2

Characterization of U.S. Power Plants and Associated Emissions 

As a preview to discussing multi-emission control technologies, it is beneficial to characterize the 

magnitude and sources of the emissions that drive the need for these technologies. Sulfur dioxide (SO2), 

nitrogen oxides (NOX), and mercury are generated not only from electricity generation but also from a 

number of sectors of the economy. Figure 2-1 presents the 2001 estimates of SO2 and NOX and 1998 

estimates of mercury emissions from major economic sectors in the United States.1

 During 2001, fuel 

combustion-electric utilities contributed 69 percent of the total SO2 emitted and 22 percent of the NOX. 

18%

9%

4%

69%

<1%

Transportation

Industrial 

processing

Fuel 

combustionelectric utility

Other 

stationary 

combustion Miscellaneous

22%

17%

5%

55%

1%

35%

42%

14%

4%

5%

2001 SO2 Emissions

LEGEND 1998 Mercury Emissions

2001 NOX Emissions

Figure 2-1. Major sources of SO2 and NOX emissions in 2001 and of mercury emissions in 1998. 

2-1 
Since the majority of U.S. power plant capacity is regulated under Title IV of the CAAA,2,3 the data for 

NOX, SO2, and CO2 collected under this title provide a good representation of these emissions. Title IV of 

the Clean Air Act covers all boiler units with capacity greater than 25 MW, excluding a small percentage 

of units classified as co-generating units. Title IV affected a total of 2,638 units in 2001, from which 

1,089 are considered coal-fired units based on burning over 50 percent coal as the primary fuel. Emissions 

data for Title IV affected units is available at EPA Clean Air Market Division’s website.4

Table 2-1 summarizes the 2001 total emissions data for all Title IV affected units, apportioned by two 

broad primary fossil fuel type categories (coal and non-coal). Non-coal units affected by Title IV include 

those that burn liquid or gaseous fossil fuel (oil, diesel, natural gas, etc.) or other solid fuel, such as wood, 

as their primary fuel. The data reflect the predominance of coal use by U.S. facilities. Of the totals in 

2001, coal accounts for 95 percent of SO2 emissions, 90 percent of NOX emissions, and 86 percent of CO2

emissions. Note that data on mercury emissions is not collected under Title IV. Coal units also account 

for 79 percent of the total heat input. 

Table 2-1. Emissions in 2001 from Coal and Non-coal Units5

Coal Non-Coal Total 

SO2 (Tons) 10,052,279 581,799 10,634,077 

NOX (Tons) 4,235,104 464,770 4,699,874 

CO2 (Tons) 2,049,776,430 344,080,879 2,393,857,309 

However, in 1999, the EPA conducted an Information Collection Request (ICR)6

 to obtain information on 

mercury emissions from the U.S. coal-fired electric utility steam generating facilities. The ICR collected 

general information and data on quantity of fuel consumed, quantity of mercury of that fuel, and mercury 

speciation in flue gas before and after air pollution control devices upstream of the stack. This ICR 

identified 1140 boilers of 25 MW or greater capacity including cogenerators that supplied more than onethird of their potential electric output capacity to utility distribution systems for sale. The ICR effort 

further identified the breakdown of these units as 979 pulverized coal-fired, 87 cyclone-fired, 42 

fluidized-bed combustors, and 32 stoker-fired boilers. The information on mercury emissions presented in 

this report is based on EPA’s 1999 ICR. 

2.1 SO2 Emissions from Coal-Fired Power Plants 

SO2 emissions from coal-fired power plants increased slightly between 1996 and 1997 by about 400,000 

tons. Despite this emissions increase, a sharp decrease of about 2,650,000 tons or 21 percent occurred 

between 1997 and 2001. Sulfur dioxide emissions from 1996 to 2001 are illustrated in Figure 2-2.1

2-2 
12.24

12.61

12.47

11.68

10.60

9.96

9.5

10

10.5

11

11.5

12

12.5

13

1996 1997 1998 1999 2000 2001

SO2 Emissions (Million Tons)

Figure 2-2. Annual SO2 emissions for coal-fired units. 

Emissions of SO2 are highly dependent on the sulfur content in the coal burned and the emissions control 

system employed. Emissions control systems are typically based on dry or wet flue gas desulfurization 

(FGD). FGD technologies are based on the use of sorbents to scrub SO2 from the flue gas and are 

conventionally classified as throwaway and regenerable depending on how the sorbent is treated, and 

further into wet or dry FGDs. In wet processes, wet slurry waste or by-product is produced, and flue gas 

leaving the absorber is saturated with moisture. In dry processes, dry waste material is produced and flue 

gas leaving the absorber is not saturated. 

SO2 emission rates for 60 units that had FGD technologies installed between 1990 and 1999 are presented 

in Table 2-2.7-9 Wet limestone and wet lime FGDs were the two most installed control technologies for 

these units. Emission rates varied widely among the different technologies and coal types. 

2-3 
Table 2-2. SO2 Emissions from Units with FGD Installed in 1990-1999 

FGD Type Number of 

Unitsa Fuels Burnedb Average SO2

Emission 

(lb/MMBtu) 

Maximum SO2

Emission 

(lb/MMBtu) 

Minimum SO2

Emission 

(lb/MMBtu) 

Annual 

SO2

Emission 

(tons) 

Dry Lime 2 Bit. 0.32 0.47 0.17 1,848 

Dry Lime 4 Lignite 0.61 1.09 0.40 36,818 

Dry Lime 8 Subbit. 0.28 0.61 0.09 36,477 

Dual Alkali 2 Bit. 0.65 0.84 0.46 11,253 

Dual Alkali 1 Lignite 1.02 1.02 1.02 21,863 

Sodium 

Based 8 Bit. 0.70 1.93 0.05 18,878 

Sodium 

Based 1 Subbit. 0.43 0.43 0.43 1,858 

Wet Lime 24 Bit. 0.55 1.12 0.08 163,936 

Wet Lime 4 Bit./petcoke 0.47 0.53 0.37 30,912 

Wet Lime 2 Bit./subbit. 0.39 0.57 0.20 8,896 

Wet Lime 4 Lignite 0.89 1.15 0.35 78,118 

Wet Lime 8 Subbit. 0.42 0.51 0.14 49,743 

Wet 

Limestone 50 Bit. 0.59 3.02 0.05 369,087 

Wet 

Limestone 9 Bit./petcoke 0.45 0.73 0.05 65,006 

Wet 

Limestone 5 Bit./subbit. 0.53 0.89 0.22 50,883 

Wet 

Limestone 3 Bit./subpetcoke 0.45 0.57 0.22 16,320 

Wet 

Limestone 1 Bit./tires 0.24 0.24 0.24 978 

Wet 

Limestone 5 Lignite 0.89 1.14 0.56 120,824 

Wet 

Limestone 3 Lignite/subbit. 1.06 1.16 0.87 101,745 

Wet 

Limestone 23 Subbit. 0.39 0.76 0.08 178,358 

a

 FGD units under construction in 1999, or known not to be operating, were not included in the unit counts. 

This included 3 wet limestone, 2 dry lime FGD, and 1 dry limestone FGD. 

b

 Data from EPA’s 2001 ICR; bit. = bituminous coal; subbit. = subbituminous coal; petcoke = petroleum coke. 

2.2 NOX Emissions from Coal-Fired Power Plants 

Annual NOX emissions for coal-fired units regulated under Title IV are shown in Figure 2-3.1

 These 

emissions steadily declined from 1997 to 2001 by about 1,470,000 tons. 

2-4 
5.60 5.64 5.44

4.84

4.54

4.17

0

1

2

3

4

5

6

7

1996 1997 1998 1999 2000 2001

NOx Emissions (Million Tons)

Figure 2-3. Annual NOX emissions for coal-fired units. 

NOX is formed during most combustion processes by one or more of three chemical mechanisms: (1) 

“thermal” NOX resulting from oxidation of atmospheric molecular nitrogen, (2) “fuel” NOX resulting 

from oxidation of chemically bound nitrogen in the fuel, and (3) “prompt” NOX resulting from reaction 

between atmospheric molecular nitrogen and hydrocarbon radicals. In fuel-lean combustion of nitrogenfree fuels, thermal NOX is the primary component of NOX emissions. Thermal NOX formation is quite 

sensitive to temperature and can be controlled by appropriately controlling peak temperature in the 

furnace. In fuel-lean combustion of fuels containing nitrogen, fuel NOX contributes significantly to total 

NOX emissions, depending on the percentage of nitrogen in the fuel. Formation of fuel NOX depends on 

the availability of oxygen to react with the nitrogen during coal devolatilization and the initial stages of 

combustion. Under fuel-rich conditions, the formation of NOX may compete with the formation of 

molecular nitrogen (N2) and may result in a reduction of NOX emissions. Prompt NOX contributes a 

relatively minor fraction of total NOX emissions for both nitrogen-free and nitrogen-containing fuels. 

The factors described above that dictate NOX formation (devolatilization of fuel-bound nitrogen, oxygen 

concentration, and flame temperature) can all be adjusted by controlling the rate at which the fuel and air 

mix. This allows staging the combustion process, such that an initial fuel-rich zone is followed by a 

burnout zone that is high enough in oxygen to complete the combustion process, but low enough in 

temperature to minimize thermal NOX production. Combustion modification NOX controls utilize this 

combustion staging. 

In general, NOX control technologies are categorized as being either primary control technologies or 

secondary control technologies. Primary control technologies reduce the formation of NOX in the primary 

combustion zone. In contrast, secondary control technologies destroy the NOX present in the flue gas from 

the primary combustion zone. Primary control technologies being used in the United States are low NOX

burner (LNB) and overfire air (OFA). 

The secondary NOX control technologies in use on U.S. coal-fired utility boilers include reburning, 

selective non-catalytic reduction (SNCR), and selective catalytic reduction (SCR). More than 100 boilers 

either have used, or will use, these technologies to achieve the desired NOX reductions. The NOX

2-5 
reductions achieved, or projected, at these applications range from 20 to more than 80 percent. Table 2-3 

summarizes the 1999 NOX emissions and emission rates for units regulated under Title IV.10

Table 2-3. 1999 NOX Emissions for Title IV Affected Units 

Boiler Type 

(Coal Units Only) 

Number 

of Units NOX Control 

Average NOX

Emission 

(lb/MMBtu) 

Maximum 

NOX Emission 

(lb/MMBtu) 

Minimum NOX

Emission 

(lb/MMBtu) 

Annual NOX

Emission 

(tons) 

Arch-fired 9 Uncontrolled 0.74 0.91 0.25 11,170 

Cell burner 2 Low NOX Burner Technology 0.62 0.71 0.52 39,125 

3 Low NOX Burner Technology for 

Cell Burners 0.46 0.46 0.46 20,067 

1 

Low NOX Burner Technology 

with Overfire Air (Dry Bottom 

Boilers Only) 

0.39 0.39 0.39 8,089 

1 Other 0.61 0.61 0.61 13,044 

29 Uncontrolled 0.75 1.41 0.43 464,518 

Circulating 

fluidized bed 2 Other 0.21 0.22 0.20 2,536 

4 Uncontrolled 0.37 0.47 0.19 1,368 

Cyclone 1 Combustion Modification with 

Fuel Reburning 0.77 0.77 0.77 2,831 

1 Other 0.93 0.93 0.93 3,259 

1 Overfire Air 1.12 1.12 1.12 23,579 

1 Selective Catalytic Reduction 0.47 0.47 0.47 4,627 

1 Selective Non-catalytic 

Reduction 0.69 0.69 0.69 3,226 

84 Uncontrolled 0.96 1.81 0.26 708,760 

Dry bottom turbofired 2 Low NOX Burner Technology 0.39 0.40 0.37 16,110 

3 

Low NOX Burner Technology 

with Overfire Air (Dry Bottom 

Boilers Only) 

0.59 0.62 0.54 18,078 

2 Overfire Air 0.43 0.44 0.42 13,128 

5 Uncontrolled 0.41 0.43 0.37 18,813 

Dry bottom 

vertically-fired 2 Low NOX Burner Technology 0.48 0.73 0.22 4,316 

3 Overfire Air 0.51 0.51 0.51 3,855 

21 Uncontrolled 0.77 1.16 0.37 64,234 

(continued) 

2-6 
Table 2-3 (concluded) 

Boiler Type 

(Coal Units Only) 

Number 

of Units NOX Control 

Average NOX

Emission 

(lb/MMBtu) 

Maximum 

NOX Emission 

(lb/MMBtu) 

Minimum NOX

Emission 

(lb/MMBtu) 

Annual NOX

Emission 

(tons) 

Dry bottom wallfired 153 Low NOX Burner Technology 0.43 0.81 0.18 848,965 

41 

Low NOX Burner Technology 

with Overfire Air (Dry Bottom 

Boilers Only) 

0.45 0.71 0.30 182,191 

1 

Low NOX Burner Technology 

with Overfire Air & Selective 

Catalytic Reduction 

0.17 0.17 0.17 1,641 

3 Other 0.36 0.37 0.36 16,083 

4 Overfire Air 0.46 0.51 0.37 25,737 

5 Selective Non-catalytic 

Reduction 0.36 0.40 0.30 4,003 

213 Uncontrolled 0.57 1.11 0.20 539,907 

Stoker (coal and 

wood) 15 Uncontrolled 0.40 0.57 0.32 2,008 

Tangentially-fired 5 Combustion Modification with 

Fuel Reburning 0.42 0.44 0.37 6,893 

45 Low NOX Burner Technology 0.34 0.45 0.13 202,120 

31 

Low NOX Burner Technology 

with Close-coupled and 

Separated OFA 

0.36 0.63 0.16 146,046 

40 Low NOX Burner Technology 

with Close-coupled OFA 0.37 0.67 0.17 181,774 

26 Low NOX Burner Technology 

with Separated OFA 0.38 0.71 0.18 104,590 

22 Other 0.41 0.72 0.23 163,214 

10 Overfire Air 0.34 0.49 0.23 70,431 

2 Selective Non-catalytic 

Reduction 0.39 0.47 0.30 2,795 

254 Uncontrolled 0.43 0.86 0.24 800,505 

Wet bottom turbofired 1 Low NOX Burner Technology 0.53 0.53 0.53 6,242 

2 Overfire Air 0.46 0.47 0.45 5,606 

2 Uncontrolled 0.93 1.13 0.73 15,496 

Wet bottom 

vertically-fired 2 Uncontrolled 0.90 0.93 0.86 456 

Wet bottom wallfired boiler 3 Low NOX Burner Technology 0.37 0.47 0.32 23,852 

1 Other 0.45 0.45 0.45 10,351 

2 Selective Non-catalytic 

Reduction 0.79 0.82 0.76 12,759 

18 Uncontrolled 0.73 0.86 0.43 80,549 

2-7 
2.3 Mercury Emissions from Coal-Fired Power Plants 

Coal-fired power plants represent a significant source of mercury emissions into the atmosphere. EPA has 

estimated that a total of 48 tons of mercury was emitted from coal-fired power plants in the United States 

in 1999.11 Another analysis has estimated the total amount of mercury emissions from U.S. coal-fired 

plants to be 45 tons in 1999. This weight consists of 18 tons of oxidized mercury, 26 tons of elementary 

mercury (Hg0

), and less than 1 ton of particulate-bound mercury.12 This latter analysis also estimates the 

total amount of mercury in the fuel entering these power plants at 75 tons in 1999. 

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 2-4.4

 The best levels of control are 

generally obtained by emission control systems that use fabric filters (FF). 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 inlet measurements in pulverized coal (PC)-fired plants equipped with a 

cold-side electrostatic precipitator (ESP) is 35 percent for bituminous coal, 3 percent for sub-bituminous 

coal, and near zero for lignite. 

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. Lower levels of 

control were shown for units with ESPs and other controls. 

Table 2-4. Mean Mercury Emission Reduction for Pulverized-coal-fired Boilers 

Average Mercury Emission Reduction (%) a

Post-Combustion Emission 

Controls 

Used for PC Boiler 

Bituminous 

Coal-fired 

Subbituminous 

Coal-fired 

Lignite 

Fired 

ESP-CSb 35 3 0 

ESP-HS 14 12 Not tested 

FF 89 73 Not tested 

PM Control 

Only 

PS 12 0 33 

SDA and ESP Not tested 50 Not tested 

SDA and FF 98 23 17 

PM Control 

and 

Spray Dryer 

Adsorber SDA, FF, and SCR 97 Not tested Not tested 

ESP-CS and FGD 81 30 42 

ESP-HS and FGD 45 25 Not tested 

PM Control 

and 

Wet FGD 

System FF and FGD 97 Not tested Not tested 

a

 Mean reduction from 3-run test averages for each PC boiler unit in ICR Phase III database. 

b

 Refer to Acronyms, page vii for definitions. 

2-8 
Units equipped with lime spray dryer absorber scrubbers and with ESP or FF 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 hot-side ESP (ESP-HS) and FGD unit burning sub-bituminous 

coal to 97 percent in a PC-fired FF and FGD unit burning bituminous coal. The high Hg capture in the FF 

and 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. Additional testing will be required to 

characterize the effects of fuel, combustion conditions, and air pollution control device (APCD) 

conditions on the speciation and capture of Hg. 

2.4 CO2 Emissions from Coal-Fired Power Plants 

Carbon dioxide emissions from the combustion of fossil fuels are mainly driven by the source of energy 

and its carbon content. Sources of energy include natural gas, diesel oil, biomass, and coal. The amount of 

carbon in fuels varies significantly by fuel type, and coal contains the highest amount of carbon per unit 

of useful energy, resulting in the highest rate of CO2 emissions per kilowatt-hour of electricity. 

Title IV does not require control of CO2 emissions; it only requires that they be measured and reported. 

Figure 2-4 summarizes emissions from these units for 1996 to 2001.4

 Emissions of CO2 from all Title IV 

affected units increased by 2.5 percent from 1996 to 1997. In 1998, CO2 emissions increased by 1.5 

percent. The CO2 emissions remained the same between 1998 and 1999, but in 2000, CO2 emissions rose 

by 1.9 percent. In 2001, CO2 emissions fell below the 1997 level. 

2.01

2.06

2.09 2.09

2.13

2.05

1.95

2.00

2.05

2.10

2.15

1996 1997 1998 1999 2000 2001

CO2 Emissions (Billion Tons)

Figure 2-4. Annual CO2 emissions for coal-fired units. 

2-9 
2.5 References 

1. National Air Quality and Emissions Trends Report. U.S. Environmental Protection Agency, 

Office of Air Quality Planning and Standards. http://www.epa.gov/air/airtrends/aqtrnd03/. 

(accessed Dec 1, 2004) 

2. Acid Rain Program: Nitrogen Oxides Emission Reduction Program, Direct Final Rule. Fed. 

Regist. 1995, 60 (71). 

3. Acid Rain Program: Nitrogen Oxides Emission Reduction Program: Final Rule. Fed. Regist. 

1996, 61(245). 

4. Emissions Scorecard for Acid Rain Program Units, Including SO2, NOX, CO2, and Heat Input, 

2001; U.S. Environmental Protection Agency, Clean Air Markets Division: Washington, DC. 

http://www.epa.gov/airmarkets/emissions/score01/index.html (accessed Dec 1, 2004). 

5. National Totals of SO2, NOX, CO2, and Heat Input for Coal Fired and Non-Coal Fired Title IV 

Affected Units from 1996 through 2001. http://www.epa.gov/airmarkets/emissions/score01/ 

table1.pdf (accessed Dec 1, 2004). 

6. Electric Utility Steam Generating Unit Mercury Emissions Information Collection Effort; OMB 

Control No. 2060-0396; U.S. Environmental Protection Agency, Office of Air Quality Planning 

and Standards: Research Triangle Park, NC, April 2001. 

7. Hg ICR Part II, Coal Analysis Results; U.S. Environmental Protection Agency, Emissions 

Standards Division: Washington, DC, June 2001. http://utility.rti.org/backgroundinfo.cfm

(accessed Dec 1 , 2004). 

8. Electric Power Annual Report 1999, Volume 2; DOE/EIA-0348 (99)/2; U.S. Energy Information 

Administration: Washington, DC, Oct 2000. http://www.eia.doe.gov/cneaf/electricity/epav2/ 

epav2.pdf (accessed Dec 1, 2004). 

9. Annual Steam-Electric Plant Operation and Design Data; EIA-767 Form Data File; U.S. Energy 

Information Administration: Washington, DC, 1999. http://www.eia.doe.gov/cneaf/electricity/ 

page/eia767.html (accessed Dec 1, 2004). 

10. 1999 Emissions Scorecard; U.S. Environmental Protection Agency, Clean Air Markets Division: 

Washington, DC, 1999; Appendix B, Table B1. 

http://www.epa.gov/airmarkets/emissions/score01/ (accessed Dec 1, 2004). 

11. Kilgroe, J. Control of Mercury Emissions from Coal-Fired Utility Boilers. Presented at the 

MACT Working Group Meeting, Washington, DC, Aug 1, 2001. http://www.epa.gov/ttn/ 

atw/combust/utiltox/utoxpg.html#MAC (accessed Dec 1, 2004). 

12. Chu, P.; Behrens, G; Laudal, D. Estimating Total and Speciated Mercury Emissions from U.S. 

Coal Fired Power Plants. Proceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air 

Pollutant Control Symposium: The MEGA Symposium and The A&WMA Specialty Conference 

on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001. 

2-10 
Chapter 3

Multi-emission Control Technologies and 

Options for Coal-fired Power Plants 

3.1 Introduction 

This section provides a summary description of the technologies identified as multi-emission control 

technologies and which have reached a stage of development beyond pilot scale. The technologies 

selected satisfy the following definition established for this report: Multi-emission control technologies 

are defined as options which integrate pre-combustion, in-situ or post-combustion controls of at least two 

of the SO2, NOX,, and mercury pollutants, either in one process or a combination of coordinated and 

complementary (synergistic) processes.

There were no constraints set as to the percentage reduction of each emission, such as: there should be a 

significant reduction of more than 80 or 90 percent. As a result, options such as advanced power 

generation technologies, power plant rehabilitation or upgrading, fuel switching or blending and power 

plant optimization were included in the multi-emission control category. These technologies were 

included to emphasize that there are multiple options a power company may use to control multiple 

pollutants in addition to the post-combustion control options, which are the focus in most cases. For 

example, utilizing a high plant efficiency technology, such as supercritical pulverized coal firing, is 

beneficial for all emissions (compared to the conventional subcritical pulverized coal technology), even 

though, by itself, it does not reduce emissions by more than 10-12 percent. 

In addition to the above definition, two other criteria were applied in selecting the technologies described 

in this report. These were: (1) there should be at least one installation in operation in a power plant 

worldwide as of July 1, 2001, and (2) while it is acceptable for the technology to be used even in a slipstream (not the entire power plant), the size of the technology installation should be at least 5 MW or 

equivalent. 

Using the above definition and criteria, a literature search was done (using technical papers from 

conferences, the internet, technical reports by organizations such as DOE, EPA, and EPRI, and contacting 

vendors and utilities) and the technologies presented in this section were identified. The technologies 

were grouped into: 

 environmental control options (in-situ and post-combustion controls), 

 advanced power generation options, and 

 power plant upgrading and operating options. 

Environmental controls include processes that control SO2-mercury, SO2-NOX, and SO2-NOX-mercury 

emissions. Injection of activated carbon in front of electrostatic precipitators (ESPs) and fabric filters 

(FFs) was also included, because of the significant role it may play in controlling mercury from existing 

power plants. Activated carbon can also be combined with other technologies, such as sorbent injection, 

to provide multiple emissions control. 

Advanced power generation technologies include circulating fluidized bed combustion (CFB), integrated 

gasification combined cycle (IGCC), pressurized fluidized bed combustion (PFBC) and supercritical 

pulverized coal. In the category of plant upgrading and operating changes, the report includes: fuel 

3-1 
blending or cofiring, plant upgrading and efficiency improvements, and optimization. Some of these 

options require extensive plant modifications, such as boiler conversion from coal to natural gas or 

repowering of an existing coal-fired power unit to combined cycle unit burning natural gas. Others, such 

as optimization, are strictly plant-operating adjustments. Most of these options are very site-specific, 

especially with regard to the potential emission reduction and the required costs. As such, this report 

generically describes plant upgrading to raise the awareness about its potential and provides general 

guidelines with regard to its potential. More site-specific analyses are needed (beyond the scope of this 

document) to develop more accurate estimates. 

A number of technologies did not satisfy the above definition and selection criteria. Many of these are 

under investigation at the laboratory or pilot scale. For others, adequate information is not available. 

Examples of such technologies include: Pioneer Technologies’ Non-thermal Plasma Arc technology, 

Consummator’s plasma arc by-product recovery, Phoenix’s retrofit slagging combustor, ISCA’s Cl2

injection, and BioDeNOX, which uses bacteria to reduce NOX emissions in FGDs by adding FeEDTA and 

ethanol. These, and other technologies, may emerge in a relatively short period of time depending on the 

results of on-going laboratory and pilot tests, as well as the demand for multi-emission controls. Others 

may never reach commercial stage either because of technical problems they will face or because of 

unfavorable economics relative to competing options. Finally, there are technologies which were 

demonstrated in the past and for which recent information is not available. These technologies, such as 

LIMB, NOXSO, or Milliken Clean Coal, are not discussed in this report. 

For each technology, the following information is provided wherever possible: 

 brief technology description, 

 commercial readiness and industry experience, 

 emission control performance, 

 O&M impacts, 

 costs, 

 issues associated with the technology, and 

 references. 

The description of each technology included in this section is brief, but references are provided if the 

reader is interested in more detailed information. Performance and cost of selected technologies for 

mercury and multipollutant control have been discussed in more detail elsewhere.1

A significant effort was made to obtain costs, both capital and O&M. Cost ranges were provided for 

technologies that have reached maturity because significant information is available. If no adequate 

information was available in the literature, cost estimates that are provided are based on the authors’ 

experience. 

The costs reflect End of Year (EOY) 2000 US dollars, unless otherwise indicated. When the basis is 

different from EOY2000, the costs are adjusted using the Chemical Engineering Annual Plant Index 

(CEI). Considering that the cost data are based on literature reviews and other publicly available 

information, it should be noted that the level of uncertainty is of the order of –30 to +80 percent, as noted 

in EPRI’s Technical Assessment Guide (EPRI TAG) when referring to the accuracy of estimates based on 

development stage of the technology and the design and cost basis. 

3-2 
In addition to the costs, an attempt is made in the report to provide also a size (in MW) to which the costs 

correspond. No scale-up correlations are provided (costs vs plant size), because some of the technologies 

may not follow the standard scale-up rules. Furthermore, there are other factors that may affect costs 

equally or more than plant size. Some of these factors include coal composition and emission reduction 

requirements. 

References 

1. Staudt, J.E. and Jozewicz, W., Performance and Cost of Mercury and Multipollutant Emission 

Control Technology Applications on Electric Utility Boilers, EPA-600/R-025-2003, U.S. 

Environmental Protection Agency, Research Triangle Park, NC, August 6, 2003. 

3.2 Environmental Control Options 

3.2.1 SO2 and Mercury Control 

3.2.1.1 Dry Scrubbers 

Dry scrubbing technology is a flue gas desulfurization (FGD) method capable of reducing multiple 

pollutants (specifically SO2 and mercury) and is typically used in low- to medium-sulfur coal-fired power 

plants. “Dry” refers to the fact that the flue gas and the refuse (ash and solid reaction products) leaving the 

scrubber are not saturated with water vapor as in wet FGD (wet scrubbers). The technology is suitable for 

new and retrofit applications. Dry scrubbers have been installed on utility and industrial boilers, as well as 

hazardous and municipal waste incinerators. In general, dry scrubbers fall into several categories 

associated with the type of vessel or reactor used. The following sections describe the most common and 

available technologies – conventional spray dryer and fluidized bed. 

3.2.1.1.1 Conventional Dry Scrubbers 

Conventional Dry FGD (Spray Dryer Absorbers) Summary 

Status Commercial 

SO2 Reduction (%) 90 to 95 

NOX Reduction (%) --- 

Hg Reduction (%) 0 to 95 

Cost 

Capital ($/kW) 150 - 230 for a 300 MW plant 

Fixed O&M ($/kW-yr) 1.5 – 7 

Variable O&M (mills/kWh) 0.2 - 0.7 

Applicability SO2 and Hg control for low- to-medium-sulfur coals 

Issues 

Hg removal can vary significantly with coal type, operating 

conditions, and other pollution control devices present in the 

plant 

Technology Description 

In conventional spray dryer technology, a slurry of alkaline reagent (most often lime slurry or hydrated 

lime) is atomized via rotary atomizers or, alternatively, pneumatic nozzles and injected into a vessel 

where it reacts with the SO2 in the flue gas to produce calcium sulfate or sulfite products. The vessel must 

be appropriately sized to allow sufficient residence time (~ 10 seconds) for droplet evaporation and SO2

capture to take place. 

3-3 
In addition, spray dryers have been shown to reduce mercury in the flue gas.1-3 In this case, the more 

complex chemistry and speciation forms of the mercury make it more difficult to fully understand the 

processes and reactions that take place. However, fly ash, lime and activated carbon-based sorbents all 

provide varying degrees of affinity to adsorb vapor-phase mercury present in the flue gas. 

The relatively simple designs of the spray dryers include a cylindrical vessel with conical bottom. The 

atomizer may be located either at the top or the bottom and spraying into the moving flue gas flow. Flue 

gas exiting the spray dryer is directed to a downstream ESP or FF, where the dry material is then either 

collected in its entirety for disposal or may be partially re-introduced into the absorber as part of the slurry 

mixture to enhance the overall efficiency of process. 

This technology has been used predominantly on low- and medium-sulfur coals, but can be applied to 

plants burning higher-sulfur coal, too. The reason for this application flexibility is mainly economic; 

spray dryers have lower costs and can achieve reasonable SO2 removal for low- and medium-sulfur coal. 

For high-sulfur coal, the costs (both capital and O&M) increase substantially and cannot compete easily 

with wet FGDs. In all cases, two factors need to be considered. The capacity of the existing particulate 

control device (in retrofit situations) needs to be checked to make sure that the increase in particulate 

loading can be accommodated (the quantity of sorbent is proportional to the SO2 concentration and the 

desired reduction sought, therefore it increases with higher sulfur and reductions required). Also, the 

existing ash handling system may not be able to handle the increased amount of ash and adjustments may 

be required because of the properties of the ash (unreacted CaO combined with water and moisture 

releases heat and may create handling problems). 

The quantity of sorbent for a given application is typically referred to in terms of calcium-to-sulfur ratio 

or stoichiometry and ranges from about 1.0 to >2.0 for SO2 removals of 75 to 95 percent. For 80 percent 

SO2 removal, calcium-to-sulfur ratio is in the lower end of this range. Also, when a baghouse is used 

downstream of the spray dryer, it reduces further the required sorbent (lower calcium-to-sulfur ratio), as it 

provides more residence time (in some cases up to 10-15 minutes) for the unreacted sorbent to react 

further. 

Commercial Readiness and Industry Experience 

Spray dryers are a commercial and well-established technology in the United States and abroad, with over 

11,000 MW and 7,000 MW of installed capacity, respectively.4

 The technology was first used in the early 

1980’s, and has been deployed in bituminous, subbituminous, and lignite applications. Significant 

experience was gained in the United States through extensive testing programs such as those conducted at 

TVA's Shawnee Station, EPRI’s Environmental Control Technology Center, Northern States Power's 

Riverside Station, and B&W’s Alliance Research Center.5

Emission Control Performance 

Spray dryers are capable of very high SO2 reductions (up to 95 percent). Data from IEA’s coal research 

indicate SO2 reductions from 70 to 96 percent with a median value of 90 percent, comparable to that of 

wet FGD technology. This performance reflects applications with coals less than 2 percent sulfur.4

 Most 

U.S. applications of dry scrubbing (spray dryer or baghouse) have been for western subbituminous coal 

with sulfur contents of <1 percent. 

Information and experience with mercury is less available than for SO2. However, a number of test 

programs as well as the recent EPA’s Mercury Information Collection Request (ICR) program have 

yielded some insight into the potential mercury reductions in spray dryers.1-3 It is important to recognize 

that the performance of the spray dryers is typically reported together with the associated particulate 

control device (ESP or FF). In other words, mercury reductions are reported from the inlet to the spray 

3-4 
dryer to the outlet of the ESP or FF. In a 1994 study,6

 spray dryers were documented to capture mercury 

in a wide but not fully understood range (6 – 96 percent) based on data for seven installations on coalfired power plants. Although at that time, mercury speciation was not measured, the amount of mercury 

removal increased with coal chlorine content suggesting that spray dryers preferentially remove oxidized 

mercury. The wide range in the reduction values indicates more research is needed to understand 

completely the physical and chemical processes taking place in the control devices. 

More recently, EPA’s ICR has documented mercury reductions from spray dryer-ESP-FF systems using 

different rank coals (from bituminous to lignite). Figure 3-1 presents the results for spray dryer and ESPFF combinations from the ICR test program. Total mercury reductions across the system are plotted 

against chlorine content of the coal (an indicator of the likely fraction of elemental vs oxidized gas-phase 

mercury in the flue gas). The large variation in the data is evident. Mercury reduction ranges from a low 

of less than 10 to over 95 percent at the high end. Factors that impact overall performance are not yet 

fully understood. Table 3-1 presents average reductions for spray dryer and ESP-FF system by coal rank 

from the ICR data. Hg Removal, % 

Coal Chlorine Content, ppm dry 

SDA/ESP 

SDA/FF 

Figure 3-1. Mercury removal across spray dryer and ESP-FF from ICR data.2

Table 3-1. Average Mercury Reductions for Spray Dryer and ESP-FF per Coal Rank from ICR Data 

Coal Rank 

Configuration Bituminous Sub-Bituminous Lignite 

SDA-ESP Not available 53% Not available 

SDA-FF 83% 22% 25% 

3-5 
O&M Impacts 

O&M impacts include: 1. additional pressure loss associated with the spray dryer vessel and associated 

auxiliary power; 2. increased solids loading, which impacts the performance of the downstream 

particulate collector (mainly ESP) and ash handling system, and may increase the corrosion of the 

particulate collector and downstream ductwork; and 3. stack corrosion due to low approach-to-saturation 

temperatures. The magnitude of these impacts is a function of the specific design and operating 

conditions, and whether the ESP or FF is new or existing. Also, water usage is increased mainly for 

conditioning of the ash. 

Capital Costs 

Spray dryers represent a significant capital cost addition to a power plant. Costs have been reported in the 

150 to 230 $/kW range.7-9 For example in 1996 EPRI’s TAG10 provided capital costs for a 300 MW unit 

ranging from 154 to 232 $/kW and representing a variety of coals as well as geographical locations in the 

United States As with other technologies, prices have tended to decrease as improvements to the 

technology have occurred. 

O&M Costs 

Fixed O&M costs are reported in the 1.5 - 7 $/kW-yr range11-13 for a range of coal sulfur contents of about 

0.4 to 1 percent. 

Variable O&M are reported,11 in the range of about 0.2 to 0.7 mills/kWh, for the same sulfur content 

range. 

Issues Associated with Dry Scrubbing; Future Outlook 

The efficiency of mercury removal by dry scrubbers is related to mercury speciation, as well as a number 

of other factors. Additional information on mercury speciation and operating parameters in spray dryerequipped power plants is necessary to better understand and predict mercury reduction performance. 

“Dedicated” mercury sorbents such as activated carbon should increase mercury capture potential. 

References 

1. Afonso, R. Assessment of Mercury Removal by Existing Air Pollution Control Devices in Full 

Scale Power Plants. Proceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air 

Pollutant Control Symposium: The MEGA Symposium and The A&WMA Specialty Conference 

on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001. 

2. Chu, P.; Behrens, G.; Laudal, D. Estimating Total and Speciated Mercury Emissions from US 

Coal-fired Power Plants. Proceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air 

Pollutant Control Symposium: The MEGA Symposium and The A&WMA Specialty Conference 

on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001. 

3. Weilert, C.V. Analysis of ICR Data for Mercury Removal from Wet and Dry FGD. Proceedings 

of the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant Control Symposium: The 

MEGA Symposium and The A&WMA Specialty Conference on Mercury Emissions: Fate, 

Effects, and Control, Chicago, IL, Aug 20-23, 2001. 

4. Jozewicz, W.; Singer, C.; Srivastava, R. K.; Tsirigotis, P. E. Status of SO2 Scrubbing 

Technologies. Proceedings of the U.S. EPA/DOE/EPRI Combined Utility Air Pollutant Control 

Symposium: The MEGA Symposium, Atlanta, GA, Aug 16-20, 1999. 

3-6 
5. Guidelines for Particulate Control for Advanced SO2 Control Processes; EPRI TR-104594; Palo 

Alto, CA, Dec 1994. 

6. Gleiser, R.; Felsvang, K. Mercury Emission Reduction Using Activated Carbon with Spray Dryer 

Flue Gas Desulfurization. Presented at the American Power Conference, Chicago, IL, April 1994. 

7. Keeth, R. J; Ireland, P.; Radcliffe, P. Utility Response to Phase I and Phase II Acid Rain 

Legislation – An Economic Analyses. Proceedings of the EPRI/DOE/EPA 1995 SO2 Control 

Symposium, Miami, FL, 1995. 

8. Krause, T.; Rosenquist, W. Environmental Control Technologies for Our Next Generation of 

Coal Plants. Proceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant 

Control Symposium: The MEGA Symposium and The A&WMA Specialty Conference on 

Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001. 

9. Martinelli, R. Dry Scrubber/fabric Filter Retrofit: the Hayden Emissions Control Project. 

Proceedings of the US EPA/DOE/EPRI Combined Utility Air Pollutant Control Symposium: The 

MEGA Symposium, Atlanta, GA, Aug 16-20, 1999. 

10. Ramachadran, G. EPRI Technical Assessment Guide; EPRI Report No. P-6587-L; Palo Alto, CA, 

1989; 1 (rev 6). 

11. Weilert, C. V. Statistical Analyses of FGD System Operating Costs: Update for 1993-1997. 

Proceedings of the US EPA/DOE/EPRI Combined Utility Air Pollutant Control Symposium: The 

MEGA Symposium, Atlanta, GA, Aug 16-20, 1999. 

12. Blythe, G. EPRI FGD Operating and Maintenance Survey. Proceedings of the US EPA/DOE/ 

EPRI Combined Utility Air Pollutant Control Symposium: The MEGA Symposium, Atlanta, GA, 

Aug 16-20, 1999. 

13. Felsvang, K.; Boscak, V.; Andersen, P. Mercury Reduction Control Options. Proceedings of the 

U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant Control Symposium: The MEGA 

Symposium and The A&WMA Specialty Conference on Mercury Emissions: Fate, Effects, and 

Control, Chicago, IL, Aug 20-23, 2001. 

3-7 
3.2.1.1.2 Advanced Dry Scrubbers 

Advanced Dry FGD (CFB Absorbers) Summary 

Status Pilot to Commercial 

SO2 Reduction, % 90 - 98 

NOX Reduction, % --- 

Hg Reduction, % 0 to 95 

Cost 

Capital ($/kW) 50 – 150 (depending on the type of technology used) 

Fixed O&M ($/kW-yr) <1 – 3 (based on 1- 2 percent of capital) 

Variable O&M (mills/kWh) 0.2 - 0.7 

Applicability SO2-Hg control for low to medium sulfur coals (same as 

spray dryers) 

Issues 

Hg removal may vary significantly with coal type, operating 

conditions, and other pollution control devices present in the 

plant (similar to spray dryers) 

Technology Description 

Advances in dry scrubbing technology have focused on the general concept of increasing gas-solids 

mixing, hence reducing residence times in the absorber and allowing for more rapid evaporative cooling 

(1-2 seconds vs about 10 seconds in the conventional spray dryer). From a configuration perspective, 

these designs, for the most part, represent variations of Circulating Fluid Bed (CFB) technology with 

differentiating design features specific to each vendor. As in conventional spray dryers, lime slurry or 

hydrated lime are the typical sorbents used. A generic description is presented below, followed by brief 

descriptions of specific technologies offered by the major vendors. They include Circulating Dry 

Scrubbing (CDS) offered by LURGI, Gas Suspension Absorbers by FLS Miljo, Reflux Circulating 

Fluidized Bed Absorbers (RCFB) by WULFF GmbH, and Rapid Absorption Process (RAP) by Beaumont 

Environmental. 

CFB Absorber Technology

The CFB absorber is a vertical reactor where a dense material bed of recycle products (ash and sorbent) 

ensures high gas-solids contact and more rapid cooling. The flue gas flows upward through the bed, with 

sorbent typically being sprayed as a slurry into the gas upstream of the bed. Product recycle is 

accomplished through a dedicated cyclone integral to the system, or directly from the final particulate 

collection device (ESP or FF). 

CDS – LURGI1-3

This technology uses a circulating fluid bed to establish a zone of high particle density. This bed is 

enhanced with activated carbon for mercury adsorption. Carbon utilization is enhanced due to the high 

residence time in the bed, while fine particles tend to agglomerate through "collisions" in the bed, 

facilitating their subsequent capture in a conventional ESP or FF. The technology is used with hydrated 

lime injection for control of acid gases. 

GSA – FLS Miljo4,5

Gas Suspension Absorption (GSA) uses a cyclone (designed for about 90 percent particulate removal) to 

recycle products into a dense bed which allows for rapid evaporative cooling as with the other 

technologies. This, in turn allows for lower temperatures [less than 11 °C (20 °F) approach to saturation 

3-8 
temperatures]. Flue gas from the boiler flows directly into the bottom of the GSA vessel. Simultaneously, 

lime-slaked slurry is atomized into the reactor, flowing upward with the flue gas. The lime content of the 

slurry is varied, depending on the SO2 removal objectives. 

GRAF – WULFF GmbH6,7

The RCFB introduces an internal reflux within the circulating fluidized bed designed to increase the gassolid mixing and sorbent residence time. This reflux (recirculation) within the RCFB reactor is equivalent 

to approximately 30 – 50 percent of the external product recirculation (from the downstream ESP or FF). 

As with the other technologies, gas temperature is controlled via internal water injection and SO2

reduction via the amount of sorbent supply. 

RAP - Beaumont8,9

The Rapid Absorption Process uses a flash drying reactor technology combined with an external mixing 

chamber. In the flash drying process, recycle is accomplished through the final particulate control (ESP or 

FF). This reduces total pressure drop through the system. Differently from circulating fluid beds, lime 

slurry is introduced into in a recycle transfer bin where it is mixed with recycle products, and then 

introduced into the reactor. Rapid cooling occurs as the products are introduced into the reactor, allowing 

for close-to-saturation temperatures and lower residence times. 

Commercial Readiness and Industry Experience 

While not widely used in the U.S. at present, the four CFB-based technologies are commercial, with 

installations in the U.S. and abroad. The RAP technology has undergone pilot-scale tests and has been 

demonstrated at a facility in Ohio combined with a low temperature NOX removal system. 

CDS - LURGI 

The first commercial installation in the U.S. was deployed in 1995 at Black Hills Power and Light’s Neil 

Simpson Station, Unit 2 on Powder River Basin coal. This is an 80 MW, coal-fired unit. The CFB was 

installed in a system arrangement with an ESP for particulate control. A 55 MW unit was installed in 

1995 at the Roanoke Valley Energy Facility on eastern bituminous coal. The CFB reactor has been tested 

for multi-emission control in pilot scale at the 321 MW coal-fired boiler at PSE&G’s Mercer Station, 

using activated carbon and lime for mercury and SO2 control, respectively. Testing was carried out daily 

during a three-month period. 

GSA – FLS Miljo

FLS Miljo offers GSA commercially, with over 35 installations worldwide in operation since 1986. In the 

U.S., GSA was demonstrated as part of DOE’s Clean Coal Technology (CCT) program, at TVA’s Center 

for Emissions Research. This program evaluated GSA and ESP as well as GSA and FF system 

configurations. More recently, a GSA retrofit was implemented to a 130 MW boiler at the Xiaolongtan 

power station in China. Demonstration of GSA on Boiler #9 (500,000 lbs.hr of 1,275 psig, 950 °F steam) 

at the City of Hamilton, OH showed SO2 control exceeding 90 percent.10

GRAF – WULFF GmbH

WULFF GmbH commercially offers the RCFB. The technology is in full commercial use in plants 

ranging from 3 to 300 MW and firing various fuels for the simultaneous removal of SO2 and mercury. 

Commercial Single module 660 MW system for a coal-fired plant is available.11

RAP - Beaumont 

The technology is currently being demonstrated at the SRI’s combustion test facility. In addition, a fullscale demonstration program at the Medical College of Ohio is currently proceeding. 

3-9 
SO2 and Mercury Emission Control Performance 

In general, the advanced scrubbers are capable of >90 percent SO2 reduction.12,13 With respect to mercury 

control, less information is available, but high removal rates (such as in conventional spray dryers) have 

been reported. Results will vary (as seen from the spray dryer data) depending on many operational 

factors such as solids concentration, temperatures, type of sorbent, or downstream particulate control 

device (ESP vs FF). 

CDS - LURGI 

Results from the Neil Simpson Station retrofit indicated around 95 percent SO2 reduction in the CFB and 

ESP system, using coal with sulfur content varying from 0.2 percent to 1.2 percent. EPA-sponsored tests14

at the Roanoke Valley unit in September of 2000 indicated total mercury removal of 97 percent. At the 

Mercer Station, results for the CFB without activated carbon injection, indicated 50 percent capture of the 

mercury vapor. Mercury was reduced by 80 percent when the CFB was injected with iodine-impregnated 

activated carbon (at 1000:1 AC-to-Hg ratio). 

GSA – FLS Miljo15

Results from the demonstration project at TVA under the CCT showed overall SO2 removal efficiency of 

about 95 percent in the GSA and FF configuration at Ca to S ratio of 1.4, and about 90 percent in the 

GSA and ESP configuration with the same Ca to S ratio. The results of mercury removal tests in the GSA 

ranged from about 41.5 to 89.5 percent, without the use of activated carbon. The significant difference in 

removal efficiencies was attributed to variations in the residual carbon in the fly ash and the chlorine 

content of the coal. 

GRAF – WULFF GmbH

SO2 removal efficiency in the RCFB is reported from several plants to be in the 85 to 99 percent range. At 

the Dessau Heat and Power Station (operating on brown coal), SO2 reduction was 90 – 96 percent. At the 

Strakonice plant in the Czech Republic, the desulfurization efficiency ranged between 85 and 95 percent. 

At the Theiss 2000 Power Station in Austria, SO2 capture ranged from 90 to 99 percent. All three projects 

were carried out during the late 1990s through 2000. According to WULFF GmbH, mercury reduction 

using activated carbon in the RCFB can reach 98 percent. Mercury removal without activated carbon 

injection can reach up to 80 percent. 

RAP - Beaumont 

The technology is currently being piloted at a combustion test facility. Initial results were as high as 95 

percent removal, but formal testing and demonstration on various coals and varying conditions will be 

part of a continuing program. According to Beaumont, at the Medical College of Ohio, the test program 

will investigate SO2 reductions from 70 to 95 percent and sorbent utilization will be documented. Recycle 

rates and other variables for various coals are planned. 

O&M Impacts 

O&M impacts are similar to those of conventional spray dryers. For example, increased pressure loss, 

increased auxiliary power, increased solids loading, and its impact on the downstream particulate 

collector (ESP or FF) and ash handling equipment, corrosion of the downstream equipment, ductwork and 

stack due to low approach-to-saturation temperatures, and increased water requirements for ash 

conditioning. Because of better drying capability, the RAP technology, with lower exit moisture content, 

may minimize low temperature corrosion concerns. The magnitude of these impacts is a function of 

specific designs and operating conditions and whether the ESP or FF is new or existing.

Capital Costs 

Capital costs vary from a low of 50 $/kW (for a 150 MW plant) estimated by Beaumont, to about 150 

$/kW as reported for GSA from the CCT program.16 Capital cost for Lurgi CDS were estimated to be 140 

3-10 
$/kW.16 According to GRAF GmbH, the capital cost for the RCFB at the 275 MW Theiss 2000 plant in 

Austria was 90 $/kW. 

O&M Costs 

Fixed O&M costs are not well documented but should fall in the general area of about 1 – 2 percent of 

capital cost (EPRI TAG Guidelines). This would translate to a range of about 1 - 3 $/kW-yr. 

Variable O&M costs are expected to be similar or lower than those for spray dryers, therefore about 0.2-

0.7 mill/kW-hr,10,12,17,18 corresponding to a sulfur content range of 0.4 – 1 percent. 

Issues Associated with Advanced Dry Absorbers; Future Outlook 

Similar to spray dryers, SO2 performance is well documented for the three CFB-based absorbers. Mercury 

capture can potentially be >90 percent but is not well understood at present. Opportunity to add 

“dedicated” mercury sorbent will increase overall mercury removal potential. 

References 

1. Helfritch, D. J.; Feldman, P. L.; Pass, S. J. A Circulating Fluid Bed Fine Particulate and Mercury 

Control Concept. Proceedings of the EPRI-DOE-EPA Combined Utility Air Pollution Control 

Symposium: The MEGA Symposium, Washington, DC, Aug 25-29, 1997.

2. Helfritch, D. J.; Feldman, P. L.; Waugh, E. The Pilot Scale Testing of a Circulating Fluid Bed for 

Mercury Adsorption and Particle Agglomeration. Proceedings of the EPRI-DOE-EPA Combined 

Utility Air Pollution Control Symposium: The MEGA Symposium, Atlanta, GA, Aug 16-20, 

1999. 

3. Lavely, L. L.; Toher, J.; Schild, V. First North American Circulating Dry Scrubber and 

Precipitator Remove High Levels of SO2 and Particulate. Proceedings of the EPRI-DOE-EPA 

Combined Utility Air Pollution Control Symposium: The MEGA Symposium, Washington, DC, 

Aug 25-29, 1997. 

4. Burnett, T. A.; Norwood, V. M.; Puschaver, E. J.; Hsu, F. E.; Bhagat, B. M.; Marchant, S. K.; 

Pukanic, G. W. 10- MW Demonstration of the AirPol Gas Suspension Absorption Flue Gas 

Desulfurization Process. Proceedings of The 1993 SO2 Control Symposium, Boston, MA, Aug 

24-27, 1993. 

5. Felsvang, K.; Lund, C.; Kumar, S.; Bechoux, E.; Hoffman, D. Mercury Reduction Control 

Options. Proceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant Control 

Symposium: The MEGA Symposium and The A&WMA Specialty Conference on Mercury 

Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001. 

6. Graf, R.; Zimmer, S. Dry Flue Gas Scrubbing in Heat and Power Stations: Operating Experience 

with Medium- and Large-Size Units. Proceedings of the Pittsburgh Coal Conference, Pittsburgh, 

PA, Sept 11-15, 2000. 

7. Graf, R.; Zimmer, S. High Efficiency Circulating Fluid Bed Scrubber. Proceedings of the U.S. 

EPA-DOE-EPRI Combined Power Plant Air Pollutant Control Symposium: The MEGA 

Symposium and The A&WMA Specialty Conference on Mercury Emissions: Fate, Effects, and 

Control, Chicago, IL, Aug 20-23, 2001. 

8. Gross, W. Advances in Semi-Dry Absorption for Multipollutant Control. Proceedings of the U.S. 

EPA-DOE-EPRI Combined Power Plant Air Pollutant Control Symposium: The MEGA 

3-11 
Symposium and the A&WMA Specialty Conference on Mercury Emissions: Fate, Effects, and 

Control, Chicago, IL, Aug 20-23, 2001. 

9. Lutwen, R. C.; Fitzpatrick, T.; Knott, D.; Goss, W. L.; Ferrell, R.; Suchak, N. Rapid Absorption 

Process SO2 Reduction System LoTOx NOX Reduction System. Installation at: Medical College 

of Ohio, Powergen, May 2001. 

10. Kumar, K. S; Sisler, P. Airpol Gas Suspension Absorber System Project; Final Report; City of 

Hamilton, Ohio, March 2003. 

11. Graff, R. E.; Seitz, A.; Gao, X. F. Advanced, Large-capacity, Commercial Technology for 

Multipollutant Control. Proceedings of the Combined Utility Air Pollutant Control Symposium: 

The MEGA Symposium, Washington, DC, May 19-21, 2003. 

12. Keeth, R.; Ireland, P.; Radcliffe, P. Economic Evaluation of 28 FGD Processes. Proceedings of 

the1991 SO2 Control Symposium, Washington, DC, Dec 3-6, 1991. 

13. Jozewicz, W.; Singer, C.; Srivastava, R. K.; Tsirigotis, P. E. Status of SO2 Scrubbing 

Technologies. Proceedings of the US EPA/DOE/EPRI Combined Utility Air Pollutant Control 

Symposium: The MEGA Symposium, Atlanta, GA, Aug 16-20, 1999. 

14. ARCADIS Geraghty and Miller. Roanoke Valley Energy Facility Mercury Testing, Test Report;

Nov 6, 2000. 

15. 10- MW Demonstration of Gas Suspension Absorption, Clean Coal Technology Demonstration 

Program, Program Update; U.S. Department of Energy: Washington, DC, Oct 1997. 

16. Guidelines for Particulate Control for Advanced SO2 Control Processes; EPRI TR-104594; Palo 

Alto, CA, Dec 1994. 

17. Krause, T.; Rosenquist, W. Environmental Control Technologies for Our Next Generation of 

Coal Plants. Proceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant 

Control Symposium: The MEGA Symposium and The A&WMA Specialty Conference on 

Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001. 

18. Weilert, C.V. Statistical Analyses of FGD System Operating Costs: Update for 1993-1997. 

Proceedings of the US EPA/DOE/EPRI Combined Utility Air Pollutant Control Symposium: The 

MEGA Symposium, Atlanta, GA, Aug 16-20, 1999. 

3.2.1.2 Sorbent Injection 

Sorbent injection processes refer to the use of sorbent materials, typically in a powder or slurry form, 

which are injected into the flue gas upstream of a particulate control device. A key difference between 

these processes and those described in the previous section (dry scrubbers) is that in the latter, a dedicated 

reactor (the scrubber) is used to maximize the desired reactions, whereas in sorbent injection, the 

reactions occur in the flue gas duct and the downstream particulate control device. Inherently, 

performance of sorbent injection is directly related to the type of particulate control used with it (ESP or 

FF), as these devices offer additional “opportunity” for the reactions to take place, through residence or 

“contact” time. 

3-12 
Sorbent injection technologies can be characterized by the type of sorbent they utilize and by the type of 

pollutant they address. For example, activated carbon may be used for mercury control or calcium-based 

sorbent may be used for SO2 control. Other differentiating features may include details on sorbent 

preparation, injection approach, and integration with the particulate control device, etc. 

Sorbent injection technologies received significant “attention” in the US in the 1980’s, being developed 

as lower-cost and lower efficiency alternatives for SO2 control. More recently, the technology has seen 

renewed interest, development and demonstration activities, driven by EPA’s December 2000 

determination to control emissions of mercury from power plants. 

The following sections describe several sorbent injection processes using different sorbents to achieve 

mercury or SO2 reductions. 

3.2.1.2.1 Activated Carbon with Particulate Controls 

Activated Carbon with Particulate Controls Summary 

Status Pilot to commercial 

SO2 Reduction None 

NOX Reduction None 

Hg Reduction 50 – 90 % 

Cost 

Capital ($/kW) 3 to >8 (for the carbon injection system only, low end of 

range for FF and COHPAC, high end for ESP application) 

Fixed O&M ($/kW-yr) 1 – 2 

Variable O&M (mills/kWh) 0.2 – 2 

Applicability Retrofit and new units with ESP or FF 

Issues 

Not widely demonstrated at full scale on coal-fired plants, 

ash salability, particulate control effect on performance, 

impact of coal type 

Technology Description 

The technology involves the injection of an activated carbon (or alternative non-carbon sorbent) powder 

into the flue gas duct, somewhere between the air preheater and the ESP or FF. This is typically in the 

120-175 °C (250-350 °F) range. Vapor-phase mercury is adsorbed onto the activated carbon, which is 

then collected in the ESP or FF. The mercury-activated carbon interaction continues to occur in the ESP 

or FF, where, in fact, the majority of the adsorption takes place. The technology can be used in 

conjunction with flue gas temperature control, usually accomplished through the injection of water 

droplets (spray cooling) into the flue gas. This can be done to optimize the temperature at which the 

activated carbon-mercury adsorption occurs. Lower approach-to-saturation temperatures favor the 

process. 

A variation of this technology was developed and patented by EPRI. Named TOXECON, it is based on 

the combination of an ESP and a high air-to-cloth pulse-jet baghouse with sorbent injection technology 

(ACI plus COHPAC). This approach applies to retrofit situations where an ESP already exists and 

focuses on improving the efficiency of sorbent injection by providing high efficiency particulate 

collection as well as a good "contact" scheme for the sorbent and mercury, such as in the FF. 

3-13 
The most commonly studied sorbent for mercury control has been activated carbon. This material has 

been successfully used as a sorbent in municipal and hazardous waste combustors.1

 Activated carbon is 

carbon that has been “treated” to reflect certain properties such as surface area, pore volume, and pore 

size. Activated carbon can be manufactured from a variety of sources, including lignite, peat, coal, and 

wood. More commonly, steam is used for activation, which requires carbonization at high temperatures in 

an oxygen-lean environment. As some carbon atoms are vaporized, the desired highly porous activated 

carbon is produced. Commercially, activated carbon is available in a range of particle sizes, as well as 

other performance characteristics.2

 Furthermore, special activated carbon products such as iodine and 

sulfur impregnated are also available, and have been studied.3,4 Sorbents are often compared in terms of 

“capacity” and “reactivity.” These are a function of many parameters including surface area and porosity. 

Reactivity refers to the initial rate of reaction. Capacity refers to its ability to adsorb mercury in terms of 

mass of mercury captured per mass of sorbent. 

Commercial Readiness and Industry Experience 

To date, several pilot scale test programs and demonstrations have been conducted. Also, full-scale 

demonstration programs were completed to evaluate the performance, cost, and impacts of activated 

carbon injection. The program, sponsored by DOE, investigated several plant configurations, coals, and 

sorbents. This experience, combined with the experience gained in the 1980’s with sorbent injection for 

SO2 control, provides a sound basis for designing and implementing the technology. 

The following are some of the pilot and full-scale demonstrations that were conducted: 

 Public Service of Colorado, Comanche Station – pilot scale ESP, FF, and COHPAC and TOXECON5

 PSE&G Hudson Station – pilot scale COHPAC and TOXECON6

 Alabama Power, Gaston Plant – full scale COHPAC and TOXECON7

 WEPCO, Pleasant Prairie – full scale ESP7

 PGE NEG, Salem Harbor Station – full scale ESP7

 PGE NEG, Brayton Point Station – full scale dual ESPs7

The other component of the technology – activated carbon – is a commercially available product widely 

used in industry. Another source of carbon-based sorbent may be coal fly ash. Coal ash with varying 

carbon levels has shown utility as a mercury sorbent.8

 However, properties of unburned carbon that 

contribute to mercury sorption are still not well understood. It is expected that fly ash-derived sorbents 

may become, in some cases, a cost-effective alternative to activated carbon. In addition, sorbents for 

mercury may also be produced from other inexpensive materials, such as corn-derived biomass and waste 

tires.9

Emission Control Performance 

Approximately 86 percent of the coal-fired utility boilers currently operating in the United States are 

equipped with only an ESP or an FF, with ESP as the predominant PM emission control device. 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 PM. As a consequence, these PM control devices are also effective in capturing PMbound mercury (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, the properties of fly ash and the temperature of the flue gas in the PM control 

device. 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 

3-14 
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

. The very intimate 

contact between the gas and collected PM (which can act as a sorbent for the gas-phase mercury) that 

occurs in a FF significantly enhances the gas-phase mercury collection efficiency of the FF over what is 

possible with an ESP.10

The Information Collection Request (ICR) data showed that, for both bituminous and subbituminous 

coals, mercury collection in boilers equipped only with FFs was much higher than for boilers equipped 

only with ESPs. ICR data reflected that plants which employ only post-combustion PM controls display 

average Hg emission reductions ranging from 0 percent to 89 percent. The highest levels of control were 

observed for units with FFs. Decreasing levels of control were shown for units with ESPs, particulate 

scrubbers, and mechanical collectors. The average mercury reduction for two PC-fired units equipped 

with a FF baghouse and burning bituminous coal averaged 90 percent while two similarly equipped units 

burning subbituminous coals displayed an average mercury reduction of 72 percent. The average capture 

of Hg for PC-fired plants equipped with a cold-side ESP was 35 percent for bituminous coal, 3 percent for 

subbituminous coal, and near zero for lignite.11 

This effect also contributes to much more efficient collection of mercury when powdered activated carbon 

(PAC) is injected for additional mercury control upstream of a FF as opposed to injection upstream of an 

ESP. New hybrid ESP-FF technologies, such as the Combined Hybrid Particle Collector (COHPAC), 

offer ways to cost-effectively retrofit ESP’s with FF and realize this benefit. The COHPAC approach also 

offers the benefit enabling segregation of injected PAC from much of the collected fly ash. The overall 

performance of the activated carbon injection technology is a function of many factors, including sorbent 

characteristics as well as plant configuration and operating conditions. Mercury reductions of 80 – 90 

percent were documented at Alabama Power, Gaston Station for activated carbon with COHPAC.12,13

Reduction levels from 50 to 90 percent are possible for the range of technology configurations and 

activated carbons available. Model predictions14 for various configurations, sorbent characteristics, and 

operating conditions confirm this range of performance. If COHPAC is added to an existing ESP, in 

addition to the mercury reduction, particulates (including PM2.5) are reduced, too.15

Laboratory, pilot scale, and modeling programs16-18 have indicated that the following parameters can 

affect the ultimate performance of the technology: 

 sorbent type and properties, 

 gas-phase mercury species (Hg0 or HgCl2), 

 temperature, 

 concentration of acid gases (HCl, SO2, NO, NO2) in the flue gas, 

 overall residence time, and 

 dispersion of the sorbent in the flue gas. 

 Further, the overall performance of the technology is a function of the quantity of sorbent required to 

achieve a desired result as can be observed below. Figure 3-2 contrasts pilot-scale ESP data (open 

symbols) with baghouse data (closed symbols) for sorbent injection and the same eastern bituminous 

coal burned at PSE&G’s Hudson Station.19 As expected, given the better contact between sorbent and 

gas in a FF, the data confirm a higher mercury capture for the same sorbent loading. 

Recent review and modeling20 of full-scale data obtained during field tests at Gaston, Pleasant Prairie, 

Brayton Point, and Salem Harbor power plants produced the following findings: 

3-15 
 PAC injection followed by a FF results in much lower injection concentrations being necessary for a 

given level of mercury reduction than for PAC injection followed by a cold-side ESP. 

 Sorbent selection appears to have little effect on performance when PAC injection is followed by a 

FF, but it appears to have a significant effect when PAC injection is followed by an ESP. 

 Loss-on-ignition (LOI) and temperature can have a significant effect on the mercury removal by 

existing equipment. 

 In some cases PAC injection without a downstream FF may not be able to achieve mercury removal 

rates of 90 percent or more regardless of PAC injection concentration. 

Figure 3-2. Mercury removal versus activated carbon loading in a pilot scale ESP (open symbols) and 

baghouse (closed symbols).19

O&M Impacts 

The major potential O&M impacts associated with the activated carbon injection involve the following: 

 increased particulate loading to the ESP or FF; this is not expected to be significant enough to affect 

performance, especially for the case of the FF, 

 increased carbon content and different particle size distribution which may affect ESP and FF 

performance or operation factors such as entrainment, dust cake pressure loss, 

 increased carbon content of fly ash may affect its salability, 

 low flue gas temperatures (if spray cooling is used) affecting SO3 dew point and, thus, intensifying 

corrosion and reducing bag life, 

 auxiliary power for activated carbon injection, even though the amount is relatively small, and 

 disposal and utilization of ash; testing at a number of DOE-funded demonstration projects indicates 

that AC injection does not affect the leaching properties of the ash to require changes in its disposal. 

However, if the ash is utilized or sold for construction applications, the increased concentration of 

carbon may affect the ability of the utility to sell it. 

3-16 
Capital Costs 

Capital costs will vary significantly for applications with a FF or COHPAC vs those with an ESP. This is 

because of the significantly higher activated carbon requirements (may be a factor of 10) for ESP 

applications and the associated costs for sorbent storage. According to ADA-ES,7

 the costs for the carbon 

injection system will vary from about $2/kW for a FF and COHPAC configuration, to >$6/kW for ESP 

applications. If spray cooling is used, the additional cost is estimated at $1 - 2/kW. COHPAC’s capital 

costs are estimated to be between 57 and 59 $/kW for mercury removal between 50 and 90 percent, 

respectively.20 

O&M Costs 

Fixed O&M costs are estimated to be in the range of $1-2/kW-yr for a nominal plant size of 100 - 200 

MW. Variable O&M will be driven by sorbent cost. Hence FF and COHPAC applications are estimated 

at 0.15-0.2 mills/kWh, with ESP potentially up to 2 mills/kWh. Variable O&M costs for COHPAC are 

estimated to be between 0.24 and 0.39 mills/kWh for mercury removal between 50 and 90 percent, 

respectively.20 

Issues Associated with Activated Carbon Injection; Future Outlook 

At present, the technology is being demonstrated at full scale in several different applications. No 

significant “setbacks” have been identified. Due to its low capital cost, ease of retrofit, and compatibility 

with both ESP’s and FF’s, it is expected that carbon injection may become an efficient approach for 

retrofit in power plant applications without a combination of NOX controls and scrubbers that may 

provide significant mercury capture of their own. 

If the technology were used on a wide scale basis, deployment of new kilns and furnaces would be 

necessary to increase the production of activated carbon to meet the potential market for coal-fired 

boilers. The current market for activated carbon is 250,000 tons per year. Once mercury regulations are 

fully implemented, this could increase the demand. 

References 

1. Environmental Regulation and Technology Innovation: Controlling Mercury Emissions from 

Coal-Fired Boilers; NESCAUM: Boston, MA, Sept 2000. http://www.nescaum.org/pdf/hg-execsumm.pdf (accessed Dec 1, 2004). 

2. Brown, T. D.; Smith, D. N.; Hargis, R. A.; O'Dowd, W. J. Mercury Measurement and Its Control: 

What We Know, Have Learned, and Need to Further Investigate. J. Air Waste Manage. Assoc.

1999, 1-97. 

3. Hsi, H.; Rostam-Abadi, M.; Rood, M. J.; Chen, S. Mercury Removal from Simulated Flue Gases 

with Illinois Coal-Derived Activated Carbon (ICDAC). Presented at the A&WMA 91st Annual 

Meeting and Exhibition, San Diego, CA, June 14-18, 1998; Paper 98-RA79B.03. 

4. Hsi, H.; Rostam-Abadi, M.; Rood, M. J.; Chen, S.; Chang, R. Preparation of Sulfur-Impregnated 

Activated Carbon Filters (ACFs) for Removal of Mercury Vapor from Simulated CoalCombustion Flue Gases. Presented at the A&WMA 93rd Annual Meeting and Exhibition, Salt 

Lake City, UT, June 19-22, 2000. 

5. Waugh, E.; Jensen, B.; Lapatnick. L.; Gibbons, F.; Sjostrom, S.; Ruhl, J.; Slye, R.; Chang, R. 

Mercury Control in Utility ESPs and Baghouses Through Dry Carbon-based Sorbent Injection3-17 
Pilot Scale Demonstration Flue Gas Using Sorbent Injection. Proceedings of the EPRI-DOE-EPA 

Combined Utility Air Pollutant Control Symposium, Washington, DC, Aug 28, 1997. 

6. Hunt, T.; Haythornthwaite, S.; Sjostrom, S.; Ebner, T.; Ruhl, J.; Slye, R.; Smith, J.; Chang, R.; 

Brown, T. Demonstration of Dry Carbon-Based Sorbent Injection for Mercury Control in Utility 

ESPs and Baghouses. Proceedings of the EPRI-DOE-EPA Combined Utility Air Pollutant 

Control Symposium, Washington, DC, Aug 28, 1997. 

7. Durham, M. D.; Bustard, J.; Schlager, R.; Martin, C.; Johnson, S.; Renninger, S. Controlling 

Mercury from Coal-Fired Utility Boilers: A Field Test. Environ. Manage. 2001, 27-33. 

8. Butz, J.; Smith, J.; Grover, C.; Haythornthwaite, S.; Fox, M.; Hunt, T.; Chang, R.; Brown, T.D. 

Coal Fly Ash as a Sorbent for Mercury. Proceedings of the Mercury in the Environment Specialty 

Conference, Air & Waste Management Association, Minneapolis, MN, Sept 15-17, 1999. 

9. Rostam-Abadi, M.; Chen, S.; Lizzio, A.; His, H.; Lehmann, C. M. B.; Rood, M. J.; Chang, R.; 

Richardson, C.; Machalek, T.; Richardson, M. Development of Novel Sorbents for Mercury 

Removal from Utility Flue Gas. Proceedings of the U.S. EPA-DOE-EPRI Combined Power Plant 

Air Pollutant Control Symposium: The MEGA Symposium and The A&WMA Specialty 

Conference on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001. 

10. Studt, J. E.; Jozewicz, W. Performance and Cost of Mercury and Multipollutant Emission 

Control Technology Applications on Electric Utility Boilers; EPA-600/R-03-110; Research 

Triangle Park, NC, Oct 2003. 

11. Control of Mercury Emissions from Coal-Fired Electric Utility Boilers: Interim Report Including 

Errata Dated 3-31-02; EPA-600/R-01-109; April 2002. 

12. Bustard C. J.; Durham, M.; Lindsey, C.; Starns, T.; Baldrey, K.; Martin, C.; Sjostrom, S.; Slye, 

R.; Renninger, S.; Monroe, L. Full-Scale Evaluation of Mercury Control with Sorbent Injection 

and COHPAC at Alabama Power E. C. Gaston. Proceedings of the U.S. EPA-DOE-EPRI 

Combined Power Plant Air Pollutant Control Symposium: The MEGA Symposium and The 

A&WMA Specialty Conference on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, 

Aug 20-23, 2001. 

13. Bustard, J.; Renninger, S.; Chang, R.; Miller, R.; Monroe, L.; Sjostrom, S. Results of Activated 

Carbon Injection for Mercury Control Upstream of a COHPAC Fabric Filter. Proceedings of the 

Combined Utility Air Pollutant Control Symposium: The MEGA Symposium, Washington, DC, 

May 19-21, 2003. 

14. Carey, T.; Richardson, C.; Meserole, F. B.; Chang, R. Estimating Electric Utility Mercury 

Control Costs Using Sorbent Injection. Proceedings of the EPRI-DOE-EPA Combined Utility Air 

Pollutant Control Symposium, Atlanta, GA, Aug 16-20, 1999. 

15. Miller, R.; Morris, W. J. Effective Use of COHPAC Technology as a Multi-Pollutant Control 

Technology. Proceedings of the US EPA/DOE/EPRI Combined Utility Air Pollutant Control 

Symposium: The MEGA Symposium, Chicago, IL, Aug 20-23, 2001. 

16. Carey, T. R; Hargrove, O. W.; Richardson, C. F.; Chang, R.; Meserole, F. B. Factors Affecting 

Mercury Control in Utility Flue Gas Using Activated Carbon. J. Air Waste Manage. Assoc. 1998,

48, 1166-1174. 

3-18 
17. Miller, E. S.; Dunham, G. E.; Olson, E. S.; Brown, T. D. Mercury Sorbent Development for CoalFired Boilers. Presented at the Conference on Air Quality, McLean, VA, Dec 1-4, 1998. 

18. Afonso, R.; Sjostrom, S.; Chang, R.; Renninger, S. Results of Activated Carbon Injection 

Upstream of ESP for Mercury Control. Proceedings of Combined Utility Air Pollutant Control 

Symposium: The MEGA Symposium, Washington, DC, May 19-21, 2003. 

19. Butz, J. R.; Chang, R.; Waugh, E. G.; Jensen, B. K.; Lapatnick, L. N. Use of Sorbents for Air 

Toxics Control in a Pilot-scale COHPAC Baghouse. Presented that 92nd Annual Meeting and 

Exhibition of the Air & Waste Management Association, St. Louis, MO, June 20-24, 1999. 

20. Staudt, J. E.; Jozewicz, W.; Srivastava, R. K. Modeling Mercury Control with Powdered 

Activated Carbon. Proceedings of the Combined Power Plant Air Pollutant Control Symposium: 

The MEGA Symposium, Washington, DC, May 2003. 

3.2.1.2.2 SO2 Sorbents 

SO2 Sorbents Summary 

Status Pilot scale to pre-commercial demonstration 

SO2 Reduction 40 – 85 % 

NOX Reduction None 

Hg Reduction NA 

Cost 

Capital ($/kW) 25 – 120 for 500 MW plant 

Fixed O&M ($/kW-yr) 1.6 – 7 

Variable O&M (mills/kWh) 0.5 – 1 

Applicability Units with ESP or FF for particulate control 

Issues 

Calcium-based compounds not used commercially in coal 

fired plants. Waste disposal issue with sodium-based 

compounds. Potential impacts on ESP or FF. 

Technology Description 

SO2 sorbent injection technologies include several variations based on the point of injection (furnace, 

economizer, ductwork upstream of an ESP or FF) and the sorbent type (calcium vs sodium based). In all 

cases, the major premise is that, by using the existing system as the “reactor,” significant cost savings can 

be achieved in situations where the SO2 reductions of 40 – 50 percent are appropriate. In this section, the 

focus is on technologies involving the injection of a calcium- or sodium-based sorbent into the flue gas 

duct, somewhere between the air preheater and the ESP or FF (commonly referred to as “dry duct 

injection”). This is typically in the 120-175 °C (250-350 °F) range. SO2 reacts with the sorbent to produce 

a mixture of sulfate and sulfite salts, which are then collected in the ESP or FF. The sorbent is either 

injected as atomized slurry, or as a powder separate from the water injection. Low approach-to-saturation 

temperatures enhance the ensuing reactions, therefore maximizing the SO2 reductions. Several different 

approaches to the technology have been developed and are described briefly below.1

Duct Injection - Lime Slurry

The duct injection of lime slurry is a process similar to a conventional spray dryer. The main difference is 

the elimination of the large reaction vessel by the direct spraying of lime slurry into the ductwork between 

3-19 
the air heater and the particulate control device. To offset the fact that the ductwork provides a much 

shorter residence time than the spray dryer vessel, slurry is atomized into very fine droplets in the duct 

injection process. The slurry droplets in such a fine mist dry out before reaching the particulate control 

device or prior to coming into contact with the duct walls, as required for proper operation. Two-fluid (air 

and slurry) atomizing spray nozzles are commonly used to provide the small droplets. Lime slurry 

injection was shown to provide slightly higher SO2 removals than duct injection of dry hydrated lime. 

Specialized processes and additives to improve the performance of the lime slurry injection process were 

developed at several commercial enterprises. They include Bechtel's Confined-Zone Dispersion (CZD) 

process, using pressure-hydrated dolomitic lime; General Electric's In-Duct Scrubbing (IDS) process, an 

in-duct spray drying system based on a rotary atomizer; and EPA's E-SOX process, consisting of an array 

of spray nozzles fitted into a cavity created by removing the internals from the first field of an ESP. 

Duct Injection - Dry Lime with Humidification

The use of dry hydrated lime requires separate injection of water, upstream or downstream of the lime 

injection point, to activate the lime. The water is finely atomized to enhance evaporation and to avoid 

wetting the duct walls. As with lime slurry, a number of commercial processes were developed including: 

 Dravo’s HALT Process – the Hydrate Addition at Low Temperature process which included the 

addition of NaOH to the water spray to enhance the lime-SO2 reaction 

 CONSOL’s Coolside Process – similar to the HALT 

 EPA’s ADVACATE Process – ADVACATE uses an advanced sorbent produced by reacting lime 

and fly ash at elevated temperature 

 EPRI’s HYPAS – the Hybrid Pollution Abatement System injects hydrated lime and water between 

an ESP and a downstream FF 

Duct Injection - Sodium Compounds

The use of sodium-based processes not requiring water was developed primarily for water-scarce regions 

such as in certain western states. Tests of various sodium compounds, including nahcolite, trona, soda 

ash, sodium bicarbonate, and sodium sesquicarbonate were conducted at a number of locations. The 

sodium sorbent is pulverized and injected into the flue gas through an array of nozzles located in the 

ductwork. 

Commercial Readiness and Industry Experience 

These technologies were tested or demonstrated extensively during the mid 1980’s but never gained wide 

commercial acceptance. However, significant experience was gained regarding various sorbents as well as 

several injection approaches. Tables 3-2, 3-3, and 3-4 identify some of the test or demonstration and 

commercial programs.

Table 3-2. Duct Injection of Lime Slurry

Process Developer Test Site Reference 

Confined-Zone Dispersion (CZD) Bechtel Seward Station 2 

In-Duct Scrubbing (IDS) General Electric Muskingum River Station 3 

E-SOX U.S. EPA Burger Station 4 

3-20 
Table 3-3. Duct Injection of Dry Lime 

Process Developer Test Site Reference 

Hydrate Addition at Low Temperature 

(HALT) Dravo Lime Company Toronto Station 5 

Coolside Conoco Edgewater 6 

Advanced silicate (ADVACATE) U.S. EPA Edgewater Station (sorbent) 

TVA Shawnee (process) 

7 

Hybrid Pollution Abatement System 

(HYPAS) EPRI EPRI High-Sulfur Test Center 8 

Table 3-4. Duct Injection of Sodium 

Utility or Operator Plant and Location Reference 

Public Service Company of Colorado Cameo Unit No. 1 Grand Junction, CO 9 

City of Colorado Springs Ray D. Nixon Unit No. 1 Fountain, CO 10 

Public Service Company of Colorado Cherokee Unit No. 4 Denver, CO 11 

Wisconsin Electric Power Company Port Washington Unit No. 3 Port Washington, WI 12 

Emission Control Performance 

The results from the various programs indicated SO2 reductions in the range of 40 to about 85 percent, 

depending on sorbent type and stoichiometry, amount of recycle, temperature, and plant configuration. 

Little information is available on mercury reduction from these programs. 

O&M Impacts 

The major potential O&M impacts associated with SO2 sorbent injection involve the following: 

 increased particulate loading to the ESP or FF, 

 different particle size distribution which may affect ESP and FF performance because of entrainment 

or dust cake pressure loss, 

 impact of sodium injection reaction products or lowered gas temperatures on particulate resistivity, 

mostly resulting in an improved ESP performance, 

 low flue gas temperatures (if spray cooling is used) affecting SO3 dew point and, thus, intensifying 

corrosion and reducing bag life, 

 impact on plume visibility from formation of NO2 (for sodium-based sorbents), 

 increased solid waste flow rate and associated auxiliary power; potentially, more operating problems 

may be experienced in the ash handling system if the right precautions are not taken to address the 

different properties of the ash when it includes unreacted sorbent, 

 In case of sodium-based sorbents, disposal of solid waste needs to take into account the solubility of 

sodium compounds in water and associated concerns with the handling of sodium-containing leachate 

from the landfills, and 

 increased water consumption mainly due to ash conditioning. 

3-21 
Capital Costs 

Capital costs for these processes vary over a wide range from $25 to 50/kW (FY 1990)13-15 to 70-120 

$/kW (FY 1990) for a 500 MW plant. Because there is no commercial application of these technologies, it 

is difficult to address the accuracy of these projections. 

O&M Costs 

O&M costs are not readily available. Fixed O&M is expected to be similar to or lower than spray dryers. 

Therefore, the same range of $1.6-7/kW-yr is presented.16 Variable O&M costs are expected to be 

somewhat higher than those for conventional spray dryers (lower reagent effectiveness), therefore in the 

range of 0.5-1 mills/kWh for the same range of coal sulfur content of 0.4 to 1 percent. 

Issues Associated with SO2 Sorbent Injection; Future Outlook 

The technology did not gain commercial acceptance as part of the compliance strategies for Phase I and II 

of the CAAA of 1990. In the future, broad compliance strategies and increased use of low sulfur coals 

may make this technology an attractive option for smaller units, plant or system “bubble” strategies, or in 

combination with activated carbon or other multipollutant sorbents to address mercury emissions. 

References 

1. Guidelines for Particulate Control for Advanced SO2 Control Processes; EPRI TR-104594; 

Electric Power Research Institute: Palo Alto, CA, Dec 1994. 

2. Bechtel National, Inc. Desulfurization of Flue Gas by the Confined Zone Dispersion Process; 

Final Report; Submitted to the U.S. Department of Energy, DOE Contract No. DE-AC22-

85PC81009, April 1988. 

3. Samuel, E. A.; Murphy, K. R.; Demian, A. A 12-MW Pilot Study of In-Duct Scrubbing (IDS) 

Using a Rotary Atomizer; Final Report; Submitted to the U.S. Department of Energy, DOE 

Contract No. DE-AC22-85PC81010, Jan 1989. 

4. Redinger, K. E.; Hovis, L.; Owens, F.; Chang, J. C. S.; Wilkinson, J. Results from the E-SOX 

5-MW Pilot Demonstration. Proceedings of the 1990 SO2 Control Symposium, New Orleans, LA, 

May 8-11, 1990. 

5. Babu, M.; Forsythe, R. C.; College, J.; Herbert, R.; Kanary, D.; Lee, K. 5-MW Toronto HALT 

Pilot Plant; Final Report; Submitted to the U.S. Department of Energy, DOE Contract No. 

DE-AC22-85PC81012, Dec 1988. 

6. Statnick, R.; Kanary, D. A.; Yopon, H.; McCoy, D.; Withum, J.; Kudlac, G. Coolside Process 

Demonstration at the Ohio Edison Company Edgewater Unit 4-Boiler 13. Proceedings of the 

1990 SO2 Control Symposium, New Orleans, LA, May 8-11, 1990. 

7. Jozewicz, W.; Chang, J. C. S.; Brna, T.; Sedman, C. B. Characterization of Advanced Sorbents 

for Dry SO2 Control. React. Solids 1988, 6, 243. 

8. Rhudy, R. G.; Carr, R. C. Pilot-Scale Evaluation of the HYPAS SO2 and Particulate Matter 

Removal Process. Presented at the Sixth Annual Coal Preparation, Utilization, and Environmental 

Control Contractors Conference, Pittsburgh, PA, Aug 1990. 

9. Muzio, L.; Offen, G. R. Dry Sorbent Emission Control Technologies. J. Air Pollut. Control 

Assoc. 1987, 37, 642. 

3-22 
10. Ablin, D. W.; Hammond, J. J.; Watts, D. B.; Ostop, R. L.; Hooper, R. G. Full Scale 

Demonstration of Dry Sodium Injection Flue Gas Desulfurization at City of Colorado Springs, 

Ray D. Nixon Power Plant. Proceedings of the 1986 Joint Symposium on Dry SO2 and 

Simultaneous SO2/NOX Control Technologies, Volume 2, EPA-600/9-86-029b (NTIS PB87-

120457), Air and Energy Engineering Research Laboratory: Research Triangle Park, NC, Oct 

1986. 

11. Fox, M. R.; Hunt, T.;G. Flue Gas Desulfurization Using Dry Sodium Injection. Proceedings of 

the 1990 SO2 Control Symposium, New Orleans, LA, May 8-11, 1990. 

12. Coughlin, T.; Schumacher, P.; Hooper, A. R. Injection of Dry Sodium Bicarbonate to Trim Sulfur 

Dioxide Emissions. Proceedings of the 1990 SO2 Control Symposium, New Orleans, LA, May 

8-11, 1990. 

13. Bechtel Corporation. Confined Zone Dispersion Project: Final Technology Report, Clean Coal 

Technology Demonstration Program, Program Update; U.S. Department of Energy: Washington, 

DC, March 1999. 

14. Frazier, W.; Ireland, P.; Brown, G.; Radcliffe, P. Site Specific Evaluation of Six Sorbent Injection 

Processes. Proceedings of The FGD and Dry SO2 Control Symposium, St. Louis, MO, Oct 25-28, 

1988. 

15. Smith, P. V. Dry Sorbent Injection and Acid Rain Compliance. Presented at: Power-Gen ’90, 

Environmental Trends and Issues, Orlando, FL, Dec 4-6, 1990. 

16. Weilert, C. V. Statistical Analyses of FGD System Operating Costs: Update for 1993-1997. 

Proceedings of the US EPA/DOE/EPRI Combined Utility Air Pollutant Control Symposium: The 

MEGA Symposium, Atlanta, GA, Aug 16-20, 1999. 

17. Brusger, E.; Wayland, R. Clean Air Response: A Guidebook to Strategies; EPRI, GS-7105; Dec 

1990. 

18. Meserole, F.; Richardson, C. F.; Machalek, T.; Richardson, M.; Chang, R. Predicted Costs of 

Mercury Control at Electric Utilities Using Sorbent Injection. Proceedings of the U.S. 

EPA/DOE/EPRI Combined Utility Air Pollutant Control Symposium: The MEGA Symposium, 

Chicago, IL, Aug 20-23, 2001. 

19. Singer, C.; Ghorishi, B; Sedman, C. B. Lime Based Multi-Pollutant Sorbents. Proceedings of the 

U.S. EPA/DOE/EPRI Combined Utility Air Pollutant Control Symposium: The MEGA 

Symposium, Chicago, IL, Aug 20-23, 2001. 

3-23 
3.2.1.2.3 Combined Mercury and SO2 Sorbents 

Combined Mercury and SO2 Sorbents Summary 

Status Pilot scale to commercial 

SO2 Reduction, % 40 – 85 

NOX Reduction NA 

Hg Reduction, % Up to 90 

Cost 

Capital ($/kW) 28 – 58 for a nominal 500 MW plant 

Fixed O&M ($/kW-yr) 2.6 – 9 

Variable O&M (mills/kWh) 0.7 – 3 

Applicability Units with ESP or FF for particulate control 

Issues Not used commercially, potential impacts on ESP or FF 

Technology Description 

As described in Sections 3.2.1.2.1 and 3.2.1.2.2, the basic technologies for sorbent injection involve the 

injection of a sorbent into the flue gas at temperatures in the range of 120-175 °C (250-350 °F) and before 

the particulate collection device (ESP or FF). Several actual methods of injection, such as dry powder and 

atomized slurry, have been developed to optimize the processes as a function of specific requirements and 

conditions. The technologies for combined or multipollutant sorbent injection involve the same 

approaches as described in the previous sections. The approaches may involve using sorbents together 

(activated carbon plus hydrated lime) or single, multipollutant-capability sorbents. In this section, a brief 

summary of combined and multipollutant sorbents is provided. 

Commercial Readiness and Industry Experience 

Data from the mercury ICR1-3 program demonstrated that dry scrubbers remove mercury and SO2, 

suggesting the ability of calcium-based sorbents to enhance mercury capture in addition to SO2. Pilot test 

programs have documented the performance of combined sorbents.4-7 Much laboratory activity has 

focused on the development of novel and enhanced sorbents.8,9 Based on this experience, sorbent 

injection technology for combined SO2-mercury reduction represents a viable, although not fully 

quantified approach for multi-emission control. 

Emission Control Performance

Calcium-based sorbents have been characterized most extensively.8,10 Co-injection of activated carbon 

and calcium-based sorbents in air pollution control equipment has been known to increase the removal of 

mercury from flue gas. This was first demonstrated in spray dryer absorber (SDA) systems on full-scale 

coal-fired power plants.11 There has been pilot work on injection of calcium-based sorbents upstream of a 

baghouse4

 and into a specialized fluidized bed reactor.6 Combining activated carbon with hydrated lime 

can reduce the amount of carbon required (for an equivalent mercury removal) by one-half to one-third. 

Pilot tests of limestone furnace injection, followed by a cyclone separator, also showed good removal of 

mercury from flue gas in a pilot-scale unit burning eastern bituminous coals.12

Laboratory investigations of calcium-based sorbents for mercury control8,10 have shed light on the 

mechanisms involved that offer the potential for more efficient use of such sorbents across a range of 

applications. Fly ash, hydrated lime, and ADVACATE (a trademarked, pressurized fly ash-lime mixture) 

have been tested for mercury sorption in a fixed-bed reactor.10 All calcium-based sorbents captured HgCl2

from simulated flue gas at 100 °C (although less than commercial activated carbon). Addition of SO2 to 

3-24 
the gas mixture decreased the sorption of HgCl2, suggesting that there is competition for the same alkaline 

sites between the two species. In contrast, the calcium-based sorbents showed little or no removal of Hg0

in the absence of SO2. Addition of SO2 to the gas greatly enhanced the uptake of elemental mercury, 

suggesting the possibility of some chemical reaction on the surface. Increased sorbent surface area and 

internal pore volume also increased the capture of elemental mercury by calcium-based sorbents. More 

recently, hydrated lime and silicates have been evaluated for mercury, NOX, and SO2 capture in benchscale tests. Oxidant-enhanced silicate sorbents indicated enhanced mercury capture. The practical 

significance of these results is that it is possibly more effective to separate the injection of sorbents 

dedicated to bulk acid gas removal (lower cost alkaline sorbents) from the higher porosity, oxidantenhanced sorbents for mercury control.8,9 Unfortunately, while these studies offer a great deal of new 

understanding about the chemical and physical interactions between the flue gas, mercury, and sorbent, 

the results cannot yet be directly translated to full-scale performance. 

Pilot-scale testing at PSE&G Hudson Station4,7 with activated carbon, sodium, and calcium sorbents in a 

COHPAC and TOXECON configuration has shown the ability to inject activated carbon simultaneously 

with other sorbents. Activated carbon performance was enhanced when tested with hydrated lime. Similar 

mercury capture of >80 percent was obtained with much lower levels of activated carbon (about a factor 

of 4) when combined with hydrated lime. In other tests using sodium sesquicarbonate and sodium 

bicarbonate injection, SO2 reduction was up to about 90 percent for the bicarbonate and about 20 percent 

for sesquicarbonate. In other tests at PSE&G’s Mercer Station,6

 injection of activated carbon and hydrated 

lime into a fluid bed reactor resulted in mercury removals of up to 80 percent with iodine-impregnated 

carbon at a ratio of 1000:1 and about 67 percent for non-impregnated carbon at a ratio of 2000:1. SO2

removal with hydrated lime was about 70 percent with 100 percent sorbent utilization. 

In summary, combined and multipollutant sorbent use with sorbent injection technology is neither used 

nor quantified in full-scale applications. However, based on information from activated carbon and SO2

sorbent technologies, it is expected that combined performance will be similar to that of the individual 

technologies, while the development of new sorbents may optimize the utilization and efficiency of future 

technology applications. 

O&M Impacts 

The major potential O&M impacts associated with combined and multipollutant sorbent injection include 

the following: 

 increased particulate loading to the ESP or FF, 

 impact of reaction products on particulate resistivity and associated ESP performance, 

 low flue gas temperatures (if spray cooling is used) affecting SO3 dew point and, thus, intensifying 

corrosion and reducing bag life, 

 impact on plume visibility from formation of NO2 (for sodium-based sorbents), 

 increased carbon content and different particle size distribution which may affect ESP and FF 

performance (entrainment, dust cake pressure loss), and 

 impact of increased carbon content on fly ash salability. 

Capital Costs 

No information on capital costs is available for multipollutant sorbent injection technologies. However, it 

can be extrapolated that at one extreme the combination of activated carbon and SO2 sorbent injection 

technologies would cost no more (likely less) than the sum of the two. In this case, the range of about 

$28-58/kW would apply. In practice, economies would exist in design, construction, and installation of 

such multipollutant control technologies. 

3-25 
O&M Costs 

O&M costs are not directly available. However, following the same rationale as above, the combined 

technologies would have costs as follows: 

 Fixed O&M in the range of $2.6 – 9/kWh 

 Variable O&M in the range of 0.7 – 3 mills/kWh. 

These are predicated on a coal sulfur range of 0.4 to 1 percent.13

Issues associated with Combined Mercury and SO2 Sorbent Injection; Future Outlook 

The same issues apply as for the application of the individual activated carbon and SO2 sorbent injection 

technologies. 

References 

1. Afonso, R. Assessment of Mercury Removal by Existing Air Pollution Control Devices in Full 

Scale Power Plants. Proceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air 

Pollutant Control Symposium: The MEGA Symposium and The A&WMA Specialty Conference 

on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001. 

2. Chu, P.; Behrens, G.; Laudal, D. Estimating Total and Speciated Mercury Emissions from US 

Coal-fired Power Plants. Proceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air 

Pollutant Control Symposium: The MEGA Symposium and The A&WMA Specialty Conference 

on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001. 

3. Weilert, C. Analysis of ICR Data for Mercury Removal from Wet and Dry FGD. Proceedings of 

the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant Control Symposium: The MEGA 

Symposium and The A&WMA Specialty Conference on Mercury Emissions: Fate, Effects, and 

Control, Chicago, IL, Aug 20-23, 2001. 

4. Butz, J. R.; Chang, R.; Waugh, E. G.; Jensen, B. K.; Lapatnick, L. N. Use of Sorbents for Air 

Toxics Control in a Pilot-scale COHPAC Baghouse. Presented at the 92nd Annual Meeting and 

Exhibition of the Air & Waste Management Association, St. Louis, MO, June 20-24, 1999. 

5. Helfritch, D. J.; Feldman, P. L.; Pass, S. J. A Circulating Fluid Bed Fine Particulate and Mercury 

Control Concept. Proceedings of the EPRI-DOE-EPA Combined Utility Air Pollution Control 

Symposium: The MEGA Symposium, Washington, DC, Aug 25-29, 1997. 

6. Helfritch, D. J.; Feldman, P.; Waugh, E. The Pilot-scale Testing of a Circulating Fluid Bed for 

Mercury Adsorption and Particle Agglomeration. Proceedings of the U.S. EPRI-DOE-EPA 

Combined Utility Air Pollution Control Symposium: The MEGA Symposium, Atlanta, GA, Aug 

16-20, 1999. 

7. Waugh, E. G.; Jensen, B. K.; Lapatnick, L. N.; Gibbons, F. X.; Sjostrom, S.; Ruhl, J.; Slye, R.; 

Chang, R. Mercury Control in Utility ESPs and Baghouses Through Dry Carbon-Based Sorbent 

Injection - Pilot-scale Demonstration. Proceedings of the U.S. EPA-DOE-EPRI Combined Power 

Plant Air Pollutant Control Symposium: The MEGA Symposium, Washington, DC, Aug 1997. 

8. Ghorishi, B. S.; Singer, C.; Sedman, C. B. Preparation and Evaluation of Modified Lime and 

Silica-Lime Sorbents for Mercury Vapor Emissions Control. Proceedings of the U.S. EPRI-DOE3-26 
EPA Combined Power Plant Air Pollutant Control Symposium: The MEGA Symposium, Atlanta, 

GA, Aug 16-20, 1999. 

9. Singer, C.; Ghorishi, B. S.; Sedman, C. B. Lime-based Multipollutant Sorbents. Proceedings of 

the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant Control Symposium: The MEGA 

Symposium and The A&WMA Specialty Conference on Mercury Emissions: Fate, Effects, and 

Control, Chicago, IL, Aug 20-23, 2001. 

10. Ghorishi, S. B.; Sedman, C. B. Low Concentration Mercury Sorption Mechanisms and Control by 

Calcium-based Sorbents: Application to Coal-fired Processes. J. Air Waste Manage. Assoc. 1998,

48, 1191-1198. 

11. Laudal, D. L. Mercury Speciation Sampling at Cooperative and United Power Associations, Coal 

Creek Station; Final Report; Energy & Environmental Research Center: University of North 

Dakota, Jan 1999. 

12. Amrhein, G. T.; Holmes, M. J.; Bailey, R. T.; Kudlac, G. A.; Downs, W.; Madden, D. A. 

Advanced Emissions Control Development Program, Phase III; Approved Final Report; DOE 

Contract DE-FC22-94PC94251, July 1999. 

13. Weilert, C. V. Statistical Analyses of FGD System Operating Costs: Update for 1993-1997. 

Proceedings of the U.S. EPA/DOE/EPRI Combined Utility Air Pollutant Control Symposium: 

The MEGA Symposium, Atlanta, GA, Aug 16-20, 1999. 

3.2.1.3 Wet Scrubbers 

Wet desulfurization refers to the most widely used SO2 control technology worldwide (approximately 220 

GW of installed capacity) and in the United States (approximately 84 GW of installed capacity),1

commonly known as wet scrubbers or wet FGD. Wet scrubbers have been shown to be efficient devices 

in capturing oxidized mercury in the flue gas.1-7 This fact has triggered a number of developments geared 

towards understanding and promoting the oxidation of elemental mercury in the flue gas of wet-scrubberequipped plants as a means of maximizing the mercury capture within the wet scrubber. These efforts 

have focused mostly on catalyst-enhanced oxidation and reagent injection approaches for mercury 

oxidation. In addition, and as a result of developments in wet precipitator technology (WESP) and the 

compatibility of WESPs with wet scrubbers, the wet scrubber-WESP combination represents another 

system approach to combined SO2 and mercury capture. Because these various processes are predicated 

on well-known, conventional and widely used wet scrubber technology, the basic wet scrubber 

technology description is presented in this section to avoid repetition. The “add-on” technology 

components are discussed in their respective sections. 

Technology Description - Wet Scrubber 

The most commonly used wet scrubber technology uses a wet limestone process to remove SO2 from the 

flue gas with in-situ forced oxidation to produce a gypsum-grade by-product. This is typically 

accomplished in a vertical vessel with flue gas cooling and reaction with limestone slurry to produce a 

mix of calcium sulfite and sulfate. Through controlled oxidation of the reaction products, a salable byproduct in the form of commercial grade gypsum (hydrated calcium sulfate) may be produced. The 

intimate contact between gas and liquid is ensured through different design approaches, usually involving 

several counter flow spray levels and mass transfer “trays” to optimize gas-liquid interactions. The 

technology has evolved over the years through “mechanical” improvements, which have included better 

gas and liquid distribution within the scrubber, droplet size and size distribution, as well as “chemistry” 

improvements such as the addition of organic acids [adipic acid or dibasic organic acid (DBA) used most 

often], which not only improve overall SO2 capture but also help the settling characteristics of the waste 

3-27 
products. Several commercial variations of the technology exist based on reagent type, vessel design, etc. 

Because oxidized vapor-phase mercury is water soluble (whereas, elemental mercury is not), the intense 

gas-liquid mass transfer in wet scrubbers is potentially an excellent mercury control mechanism. 

3.2.1.3.1 Wet Scrubbers with Mercury Oxidation Processes 

Wet FGD with Mercury Oxidation Processes Summary 

Status Under development, Pilot-scale testing 

SO2 Reduction, % 95 

NOX Reduction NA 

Hg Reduction, % >80 

Cost 

Capital ($/kW) 160 – 275 for a nominal 400 MW plant 

Fixed O&M ($/kW-yr) 1.2 – 14 (scrubber only) 

Variable O&M (mills/kWh) 0.1 – 1 

Applicability Wet Scrubber Plants 

Issues Full scale demonstration underway, insufficient information 

at present 

The two major areas of development underway in the area of mercury oxidation in the flue gas, upstream 

of wet scrubbers involve catalytic oxidation5,7 and oxidation resulting from reagent injection.6,8 One other 

approach injects chlorine into the flue gas to form HgCl2 upstream of the wet scrubber. 

Catalytic Oxidation

This approach involves the deployment of a catalyst in the flue gas (similar to the use of SCR for NOX

control) to oxidize elemental mercury. While catalyst development and testing are at the laboratory scale, 

full-scale application would likely involve a conventional support structure (honeycomb) placed between 

the particulate control device and the wet scrubber. A number of catalyst materials have been investigated 

at several test sites including carbon, palladium, iron, and high carbon fly ash8

 with varying degrees of 

success. Full-scale application of the technology envisions the catalyst to be exposed to flue gas in an area 

of low velocity [~1.5 m/s (5 ft/s)], possibly downstream of the last field of an ESP.5,9

Reagent-based Oxidation

This technology involves the introduction of dedicated reagents into the flue gas or the scrubber itself. In 

both cases, the objective is to promote the conversion of elemental mercury to an oxidized form (most 

often HgCl2). The flue gas injection approach is expected to promote the conversion of HCl to Cl2 in the 

flue gas, thereby providing a pathway for the formation of HgCl2. The direct scrubber injection approach 

involves the addition of small amounts of a proprietary reagent into the scrubber recirculation system.6

Details are not publicly available at present. 

Commercial Readiness and Industry Experience 

Catalytic Oxidation

At present, the technology is at laboratory- and pilot-scale development. Laboratory- and pilot-scale tests 

funded by the DOE and EPRI have identified several catalyst materials successful in oxidizing elemental 

mercury. Further testing of these catalysts has focused on two issues associated with the catalytic 

oxidation process: (1) catalyst life and (2) the applicability of the process for the U.S. electric utility 

industry.5,7 Results to date suggest that larger scale testing is warranted at this time. 

3-28 
Reagent-based Oxidation

Reagent tests have been conducted for wet scrubber enhancement at B&W’s Clean Environment 

Development Facility (CEDF). In the course of several tests, a reagent was found which allowed for over 

80 percent mercury removal while having no negative effects on scrubber operation.6

 The technology was 

later demonstrated at the 55 MW Endicott Station (limestone forced oxidation system). Further tests of 

the technology at Zimmer Station (magnesium enhanced lime) demonstrated average Hg removal across 

wet FGD of 51 percent.10 

Emission Control Performance 

Catalytic Oxidation

In laboratory- and pilot-scale tests, several of the catalysts tested exhibited levels of elemental mercury 

oxidation in the 70 to 95 percent range. In particular, palladium, carbon, and high-carbon fly ash-based 

catalysts exhibited high levels of oxidation. Further, tests to address catalyst longevity, while preliminary, 

indicate that the palladium catalyst, and three of the five catalysts tested retained better than 70 percent 

oxidation of the inlet elemental mercury at the end of the 5-month test period.5

 Palladium catalyst showed 

little deactivation after approximately 4,000 hours of operation. 

Reagent-based Oxidation

Results from two series of testing indicated that high levels of mercury removal (up to 86 percent) were 

repeatedly achieved with small amounts of proprietary reagents with no adverse effects on scrubber 

operation or SO2 removal. This is in comparison to baseline (no reagent) removal of mercury across the 

scrubber of about 72 percent.10

O&M Impacts 

There is not sufficient information at present to assess the impacts of the oxidation process itself. In the 

case of catalytic oxidation, the presence of the catalyst could have a minimum impact on flue gas pressure 

loss. The wet FGD adds additional pressure drop and increases the auxiliary power consumption by up to 

1.5-2.5 percent. 

Capital Costs 

Wet scrubber: $160-273/kW;11 as low as $103/kW reported12

Catalytic oxidation: estimated for 400 MW plant to be about $5/kW5

Reagent Injection: NA 

O&M Costs 

Wet scrubber 

 Fixed O&M: $1.2-14/kW-yr13 (for a range of coal sulfur from 0.4 to about 3.5 percent) 

 Variable O&M: 0.1-1 mill/kWh13 (for a range of coal sulfur from 0.4 to about 3.5 percent) 

Catalytic oxidation: estimated for 400 MW plant to be about $3.5/kW-yr.5

 This is total O&M and includes 

the catalyst cost, which is treated as an O&M expense, projected as catalyst replacement every 3 years. 

Issues Associated with the Technology; Future Outlook 

Catalytic Oxidation 

Further pilot-scale testing is needed for periods of 1 to 3 years to more clearly understand catalyst life, as 

several catalyst candidates appear to warrant such testing. Further testing of the potential for oxidation of 

other flue gas elements, including SO2 and NO, should be carried out. Parallel research to characterize the 

stability and fate of mercury in the FGD sludge or gypsum is ongoing. 

3-29 
Reagent-based Oxidation

Potential for re-emission of elemental mercury from the scrubber’s tank, and means to prevent it, are 

being investigated.14 

References 

1. Jozewicz, W.; Smouse, S. Review of Advanced FGD Technologies and Associated Co-Benefits. 

Presented at the 21st Annual International Pittsburgh Coal Conference, Osaka, Japan, Sept 13-17, 

2004. 

2. Bielawski, G. T.; How Low Can We Go? Proceedings of the U.S. EPA-DOE-EPRI Combined 

Power Plant Air Pollutant Control Symposium: The MEGA Symposium and The A&WMA 

Specialty Conference on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 

2001. 

3. Fahlke, J.; Bursik, A. Impact of the State-of-the-Art of Flue Gas Cleaning on Mercury Species 

Emissions from Coal-Fired Steam Generators. Water, Air, Soil Pollut. 1995, 80, 209-215. 

4. Licata, A.; Fey, W. Advance Technology to Control Mercury Emissions. Proceedings of the U.S. 

EPA-DOE-EPRI Combined Power Plant Air Pollutant Control Symposium: The MEGA 

Symposium and The A&WMA Specialty Conference on Mercury Emissions: Fate, Effects, and 

Control, Chicago, IL, Aug 20-23, 2001. 

5. Blythe, G. M.; Richardson, C. F.; Rhudy, R. G. Catalytic Oxidation of Mercury in Flue Gas for 

Enhanced Removal in Wet FGD Systems. Proceedings of the U.S. EPA-DOE-EPRI Combined 

Power Plant Air Pollutant Control Symposium: The MEGA Symposium and The A&WMA 

Specialty Conference on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 

2001. 

6. Milobowski, M. G. Wet FGD Enhanced Mercury Control for Coal-Fired Utility Boilers. 

Proceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant Control 

Symposium: The MEGA Symposium and The A&WMA Specialty Conference on Mercury 

Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001. 

7. Richardson, C. F. Enhanced Control of Mercury by Wet FGD Systems. Proceedings of the U.S. 

EPA/DOE/EPRI Combined Utility Air Pollutant Control Symposium: The MEGA Symposium, 

Atlanta, GA, Aug 16-20, 1999. 

8. Nolan, P. S. Development of Mercury Emissions Control Technologies for the Power Industry. 

Proceedings of the U.S. EPA/DOE/EPRI Combined Utility Air Pollutant Control Symposium: 

The MEGA Symposium, Atlanta, GA, Aug 16-20, 1999. 

9. Blythe, G.; Richardson, C. F; Rhudy, R. G. Catalytic Oxidation of Mercury for Enhanced 

Removal of wet FGD Systems. Proceedings of the U.S. EPA/DOE/EPRI Combined Utility Air 

Pollutant Control Symposium: The MEGA Symposium, Chicago, IL, Aug 20-23, 2001. 

10. McDermott Technology, Inc. Full-Scale Testing of Enhanced Mercury Control Technologies for 

Wet FGD Systems – Final Report; Submitted to the Ohio Coal Development Office, May 2003. 

11. Keeth, R. J. Utility Response to Phase I and Phase II Acid Rain Legislation – an Economic 

Analysis. Proceedings of the EPRI/DOE/EPA 1995 SO2 Control Symposium, Miami, FL, March 

28-31, 1995. 

3-30 
12. Miller, M.; Webster, L.; Rader, P.; Bussell, C. Centralia WFGD System, State-of-the-art SO2

Compliance. Proceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant 

Control Symposium: The MEGA Symposium and The A&WMA Specialty Conference on 

Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001. 

13. Weilert, C. V. Statistical Analyses of FGD System Operating Costs: Update for 1993-1997. 

Proceedings of the U.S. EPA/DOE/EPRI Combined Utility Air Pollutant Control Symposium: 

The MEGA Symposium, Atlanta, GA, Aug 16-20, 1999. 

14. Chang, J.; Ghoroshi, B. Why Flue Gas Elementary Mercury Concentration Increases Across a 

Wet Scrubber. Proceedings of the Combined Utility Air Pollutant Control Symposium: The 

MEGA Symposium, Washington, DC, May 19-21, 2003. 

3.2.1.3.2 Wet Scrubbers with Wet ESP 

Wet FGD with Wet ESP Summary 

Status Commercially available, being tested in power plant 

applications 

SO2 Reduction, % 99 

NOX Reduction NA 

Hg Reduction, % Up to 80 

Cost 

Capital ($/kW) 10 – 25 (WESP only) for a nominal 400 MW plant 

Fixed O&M ($/kW-yr) 0.5 – 1.5 

Variable O&M (mills/kWh) --- 

Applicability Integration with wet scrubbers, retrofit dry ESPs, new units 

Issues Few applications in power industry, potentially expensive 

alloys required 

Technology Description 

Wet ESP

Wet Electrostatic Precipitators (WESPs), like dry ESPs, operate in a three-step process: charging of the 

entering particles, collection of the particles on the surface of an oppositely charged surface, and finally, 

cleaning the collection surface. Both technologies employ separate charging and collection systems. 

However, unlike dry ESPs, in the WESP the collecting surface is cleaned with water as opposed to 

mechanically. As a result, the two technologies differ in the nature of particles that can be removed, the 

overall efficiency of removal, and the design and maintenance parameters.1

 While dry ESPs are typically 

limited to power levels of 100-500 watts per 0.47 m3

/s (1,000 cfm), WESPs can handle power levels as 

high as 2,000 watts per 0.47 m3

/s (1,000 cfm). As a result, WESPs can handle a wide variety of pollutants 

and flue gas conditions and are highly efficient on submicrometer particles and acid mist. WESPs have 

also been found to be most efficient in treating flue gases with high moisture content or sticky particulate 

matter. As a result of the wet cleansing of the collection system, particulate matter does not accumulate 

on the ESP collection electrodes, therefore mitigating particle re-entrainment.1,2

WESPs can be configured for vertical or horizontal gas flows in tubular or plate designs. Tubular designs 

offer smaller footprints and, in general, are more efficient than the plate type. 

3-31 
WESP Integration with Wet Scrubber

WESPs are compatible and easily integrated into a system design with a wet scrubber.3

 In fact, integration 

of the WESP within the wet scrubber is a design option with many synergisms and attractive features,4

 compact footprint, considering that the scrubber and the WESP could share a common casing, 

 ability to integrate the handling of the wash water and solids from the WESP with scrubber slurry, 

avoiding the need for separate tank and blowdown system, and 

 ability to collect the fine sulfuric acid mist that typically escapes the scrubber due to its very small 

droplet size. 

Commercial Readiness and Industry Experience 

WESPs have been used for almost a century as standard technology in abating the submicrometer particle 

SO3 mist in sulfuric acid plants.5

 It was until recently, however, a relatively unknown technology to the 

electric power industry. An up-flow tubular design WESP has been retrofit at Northern States Power 

Company’s Sherco Station in a wet scrubber-WESP configuration. In addition, a horizontal flow, plate 

WESP system was recently installed at Potomac Electric Power Company’s Dickerson Generating 

Station, converting an existing dry ESP to hybrid operation by replacing the third field of the existing 

ESP to wet operation.1

In 1986, the first commercial WESP application on a U.S. power plant took place when AES Deepwater, 

a 155 MW cogeneration plant firing petroleum coke as the primary fuel, was equipped with a WESP. The 

other air pollution control equipment included a dry ESP and a wet scrubber. The WESP was installed 

mainly for removing relatively high levels of sulfur trioxide. With the WESP in operation, the plume 

opacity at the plant is generally 10 percent or less.6

 Two more power plant applications are underway 

presently: (1) 2.35 m3

/s (5,000 cfm) slipstream at the Bruce Mansfield Station and (2) a plate type WESP 

for integration with Powerspan’s ECO technology to be demonstrated at First Energy’s R.E. Burger plant. 

The WESP at the Mansfield Station is achieving greater than 95 percent removal of SO3 and PM2.5 and 

stack flow with near-zero opacity.7,8

Emission Control Performance 

When integrated with upstream technology, including wet scrubbers, multiple pollutants can be removed 

by WESPs. A hazardous waste facility fit with a two-stage tubular WESP following a scrubber achieved 

99.9 percent removal of acid gases, dioxins, furans, PM2.5, and metals. It achieved 78 percent removal of 

mercury.1,2 At a mining operation, a combined scrubber and WESP system achieved an SO2 removal of 

99 percent.1,2

Tests at the Sherco Station (WESP retrofit to the outlet section of the wet scrubber) allowed the scrubber 

to maintain a 70 percent SO2 reduction, while keeping particulate emissions at 0.01 lb/MMBtu and 

opacity under 10 percent. Full conversion of all the plant’s scrubber modules with WESPs is now 

underway. 

In pilot scale tests at Southern Research Institute,9

 a plate type WESP yielded the following removal 

results: 

 SO2: 10 – 25 percent 

 SO3: ~ 65 percent 

 PM: 90 – 99 percent 

 Hg: ~ 30 percent 

3-32 
O&M Impacts 

When WESP is integrated with a wet FGD, there are no significant O&M impacts other than auxiliary 

power requirements; in this case, the wastewater from the WESP is handled together with the FGD 

wastes. Auxiliary power is higher than dry ESPs by a factor as WESP operating power could reach 2,000 

Watts per 1,000 cfm, while dry ESP power ranges form 100 to 500 watts per 1,000 cfm.10,11

Capital Costs 

According to vendors,12 capital costs are estimated in the range of $10 - 25/kW depending on unit size, 

flue gas conditions, and overall design configuration. If special alloys are necessary, due to acid gas 

concentrations, the costs could be considerably higher. Non-metal materials are being investigated with 

the potential for cost reduction. Note that these costs refer to the WESP only, not the SO2 scrubber. 

O&M Costs 

According to vendors, there in no appreciable increase in O&M costs. O&M for WESP is estimated to be 

less than half when compared to a dry ESP. A general estimate of about $1/kW-yr was provided for fixed 

O&M cost including the increased power consumption. 

Issues Associated with the Technology; Future Outlook 

Several conditions determine the efficiency of a WESP system and should be considered in each specific 

design. These include air distribution, sparking, and corona current suppression. Integration with wet 

scrubbers can offer significant advantages to wet scrubber operations, specifically in sulfuric acid mist 

control. Material performance will be key to overall cost of the technology. Expensive alloys may reduce 

market appeal. 

References 

1. Altman, R. Wet Electrostatic Precipitation Demonstrating Promise for Fine Particulate Control: 

Croll-Reynolds Clean Air Technologies. Power Eng. Jan 2001. 

2. Altman, R. Wet Electrostatic Precipitation Demonstrating Multiple Pollutant Control in Industrial 

Applications Holds Promise for Coal-Fired Utility Emission Reduction of Acid Mist, PM2.5, and 

Mercury. Proceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant Control 

Symposium: The MEGA Symposium and The A&WMA Specialty Conference on Mercury 

Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001. 

3. Buckley, W.P.; Altshuler, B. Sulfuric Acid Mist Generation in Utility Boiler Flue Gas. Presented 

at the ICAC Forum’03, Nashville, TN, Oct 2003. 

4. Bielawski, G. T. How Low Can We Go? Proceedings of the U.S. EPA-DOE-EPRI Combined 

Power Plant Air Pollutant Control Symposium: The MEGA Symposium and The A&WMA 

Specialty Conference on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 

2001. 

5. Staehle, R. C.; Triscori, R. J.; Ross, G.; Kumar, S.; Cothon, R. Wet Electrostatic Precipitators for 

High Efficiency Control of Fine Particulates and Sulfuric Acid Mist. Presented at the ICAC 

Forum’03, Nashville, TN, Oct 2003. 

6. Kumar, K. S.; Mansour, A. Wet ESP for Controlling Sulfuric Acid Plume Following an SCR 

System. Presented at the ICAC Forum 2002, Houston, TX, Feb 12-13, 2002. 

7. Srivastava, R.; Miller, A.; Erickson, C.; Jambhekar, R. Emission of Sulfur Trioxide from CoalFired Power Plants. Presented at PowerGen 2002, Orlando, FL, Dec 2002. 

3-33 
8. Reynolds, J.; Buckley, W.; Ray, I. Advances in Wet Electrostatic Precipitation Technology at 

Fossil Fuel Power Plants for Multipollutant Control. Presented at the ICAC Forum’03, Nashville, 

TN, Oct 2003. 

9. Monroe, L. S. Testing of a Combined Dry and Wet Electrostatic Precipitator for Control of Fine 

Particle Emissions from a Coal-Fired Boiler. Proceedings of the U.S. EPA/DOE/EPRI Combined 

Power Plant Air Pollution Control Symposium: The MEGA Symposium, Washington, DC, Aug 

25-29, 1997. 

10. Altman, R.; Offen, G.; Buckley, W.; Isaac, R. Wet Electrostatic Precipitation/Demonstrating 

Promise for Fine Particulate Control – Part 1. Power Eng. Magazine Jan 2001. 

11. Altman, R.; Buckley, W.; Isaac, R. Wet Electrostatic Precipitation/Demonstrating Multiple 

Pollutant Control in Industrial Applications Holds Promise for Coal-fired Utility Emission 

Reduction of Mist, PM2.5 and Mercury. Proceedings of the U.S. EPA/DOE/EPRI Combined 

Utility Air Pollutant Control Symposium: The MEGA Symposium, Chicago, IL, Aug 20-23, 

2001. 

12. Croll-Reynolds Clean Air Technologies. Air Pollution Control Systems; Brochure 5M798; 1998. 

3.2.1.3.3 Plasma-Enhanced ESP (PEESP) 

PEESP Summary 

Status Bench scale 

SO2 Reduction, % (>90 with FGD) 

NOX Reduction, % NA 

Hg Reduction, % Up to 90 

Cost 

Capital ($/kW) < $5/kW for retrofit of Wet ESP 

Fixed O&M ($/kW-yr) NA 

Variable O&M (mills/kWh) NA 

Applicability Both new and retrofit applications 

Issues Early stage of development; demonstration and further 

assessment of the technology is needed 

Technology Description 

Wet Electrostatic Precipitators (Wet ESP) have demonstrated that they can remove multiple pollutants. 

For example, pilot scale dry-wet ESP (addition of a wet ESP field in a dry ESP without PEESP) funded 

by the Electric Power Research Institute (EPRI)1

 in a 1995 demonstrated the following removals: 95 

percent particulate, 20 percent SO2, 35 percent hydrogen chloride, 45 percent hydrogen fluoride, and 50 

percent oxidized mercury. In 2001, a wet ESP pilot unit funded by Croll-Reynolds and First Energy 

demonstrated greater than 90 percent removal of PM2.5 and SO3 mist in a two-field electrical 

configuration2

 with the ESP after an FGD system. In addition, 40 percent removal of elemental mercury 

and greater than 70 percent removal of particulate and oxidized mercury were achieved in a single 

electrical field configuration. 

3-34 
The ability of Wet ESP to remove elemental mercury can be enhanced further through Plasma-Enhanced 

ESP (PEESP) technology. PEESP oxidizes vapor phase elemental mercury into oxidized form and then 

removes it within the Wet ESP process. This technology involves injection of a reagent gas mixture, 

through a corona discharge needle that is attached to the central electrode within an electrostatic field. 

Injection into the area surrounding the sharp discharge point results in generation of hydroxyl radicals, 

ozone and other reactive compounds. These react with elemental mercury vapor to form oxidized mercury 

particles. These negatively charged particles are attracted to the positively charged collecting electrode 

where they are collected. The mercuric oxide particles and other absorbed pollutants are removed during 

the wash-down cycle of the Wet ESP. 

PEESP can be incorporated in an existing Wet ESP by modifying the central electrode to inject the 

reagent gas. 

Commercial Readiness and Industry Experience 

The technology has been tested at bench scale. Scale-up to pilot scale size of 5,000 actual cubic feet per 

minute (ACFM) is planned and testing will commence later in 2004. 

Emission Control Performance 

The supplier projects that up to 90 percent total mercury removal can be achieved at pilot and full scale. 

Bench scale testing3

 demonstrated mercury removal efficiencies up to 83 percent. 

O&M Impacts 

O&M impacts are not known, mainly because of the lack of information, but are expected to be minimal 

since the PEESP technology is a passive device retrofitted within a wet ESP. There are no significant 

impact expected on pressure drop and performance of upstream equipment. 

Costs 

Capital costs for Wet ESPs are estimated at $20-$35 per kW depending upon the difficulty of the 

installation at a site. The cost to retrofit the PEESP technology within a wet ESP is less than $5 per kW, 

as it requires only modification of the central discharge electrode. 

O&M costs are not available presently because of the technology is at an early stage of development. 

Issues Associated with the Technology; Future Outlook 

There has been limited mercury removal experience with Wet ESPs. What has been reported shows some 

oxidation of elemental mercury and capture of particulate and oxidized forms of mercury similar to that 

for PM2.5.

4

 The PEESP technology seeks to enhance oxidation of elemental mercury to improve total 

mercury removal. The technology is still at an early development stage (bench scale towards pilot plant) 

and requires further demonstration and techno-economic assessment to develop a more comprehensive 

picture of its cost-effectiveness. Additionally, further investigation is needed regarding the water 

chemistry within the wet ESP to keep the oxidized mercury from being reduced back to elemental 

mercury. 

References 

1. Altman, R.; Buckley, W.; Ray, I. Multi-Pollutant Control with Dry-Wet Hybrid ESP Technology. 

Proceedings of the Combined Utility Air Pollutant Control Symposium: The MEGA Symposium, 

Washington, DC, May 19-21, 2003. 

2. Reynolds, J. Membrane-Based Wet ESP Technology; First Quarterly Report dated 12/31/02; 

funded by DOE’s NETL office. 

3-35 
3. Montgomery, J. L.; Battelson, D. M.; Whitworth, C. G.; Ray, I.; Buckley, W.; Reynolds, J.; 

Altman, R. Plasma-Enhanced Electrostatic Precipitation Technology for Control of Elemental 

Mercury. Presented at Power-Gen 2002, Orlando, FL, Dec 2002. 

4. Wet Electrostatic Precipitation Demonstrating Promise for Fine Particulate Control. Power Eng. 

Magazine Jan 2001. 

5. Montgomery, J. L.; Battelson, D. M.; Whitworth, C. G.; Ray, I.; Buckley, W.; Reynolds, J.; 

Altman, R. Latest Developments of the Plasma-Enhanced Electrostatic Precipitator for Mercury 

Removal in Offgas. Proceedings of the Combined Power Plant Air Pollutant Control Symposium: 

The MEGA Symposium, Washington DC, May 19-22, 2003. 

6. Battleson, D. Latest Developments of the Plasma-Enhanced ESP for Mercury Removal in Offgas. 

Proceedings of the Combined Utility Air Pollutant Control Symposium: The MEGA Symposium, 

Washington, DC, May 19-21, 2003. 

3.2.1.4 MerCAP 

MerCAP Process Summary 

Status Early pilot plant testing 

SO2 Reduction, % Existing scrubber 

NOX Reduction, % NA 

Hg Reduction >80% for 10 ft long plates spaced 0.5 inches apart 

Cost 

Capital ($/kW) 18.8 $/kW for a 250 MW plant 

Fixed O&M ($/kW-yr) 0.46 – 0.87 mills/kWh 

Variable O&M (mills/kWh) 0.19 mills/kWh 

Applicability New power plants and retrofits 

Issues Did not perform well in unscrubbed gas 

Mercury Control via Adsorption Process (MerCAP) concept is to place fixed sorbent-coated structures 

into a flue gas stream at temperature below 400 oF to adsorb mercury and then periodically regenerate 

them and recover the captured mercury. Slip-stream field tests of this concept were conducted at four 

different sites with the in-situ probes with various spacing and gold coatings (different thickness and 

support plates). The in-situ probes were designed and fabricated to allow testing of full-length (10-foot 

long) plates. Table 3-5 summarizes the test conditions and results at the four sites. The sites included two 

PRB units, one equipped with an ESP (probe located downstream of the ESP) and one with a wet 

particulate scrubber (WPS) (probe located upstream of the WPS in full dust loading) and two North 

Dakota lignite units, one equipped with an ESP (probe located downstream of ESP) and one with a spray 

dryer-baghouse (probe located downstream of spray dryer-baghouse).1,2

3-36 
Table 3-5. Summary of MerCAP Field Sites

Fuel Composition 

Site 

ID Plant Coal Type 

S (%) Cl 

(ppm) 

Test 

Location 

HCl at 

Test 

Location 

(est. ppm) 

SO2 at 

Test 

Location 

Initial 

Mercury 

removal, 

% (ppm) 

S2 

Pleasant 

Prairie 

Subbituminous 0.5 14 ESP 

Outlet < 10 

280-340 

0-24 

S9 Laskin Subbituminous 0.4 <50 WPS Inlet 0.7 200-400 20 

L1 Coal 

Creek ND Lignite 1 20 ESP Outlet <10 1000 10 

L2 Stanton ND Lignite 0.06 30 FF Outlet <10 100 55-89 

Two long-term slip-stream tests are planned for a period August 2004 through January 2005. At Great 

River Energy’s Stanton Station, which burns North Dakota lignite, sorbent structures will be retrofitted 

into a single compartment in the Unit 10 baghouse enabling reaction with a 6 MW equivalence of flue 

gas. At Southern Company Services’ Plant Yates, which burns Eastern bituminous coal, gold-coated 

plates will be configured as a mist eliminator located downstream of a 1 MW pilot wet absorber, which 

receives flue gas from Unit 1.1

Additional tests will evaluate the ability to thermally regenerate the gold-coated plates. The results of this 

study will provide data required for assessing the feasibility and estimating the costs of a full-scale 

MerCAP process for flue gas mercury removal. The study will provide information about optimal 

operating conditions for different flue gas conditions, the effectiveness of sorbent regeneration, and the 

ability of the gold sorbent to hold up to flue gas over an extended period. In addition, if successful, the 

novel approach of incorporating MerCAP structures in existing baghouse compartments will demonstrate 

a cost-effective means for achieving mercury control using existing baghouse technologies.

Commercial Readiness and Industry Experience 

The technology has been tested at pilot scale. 

Emission Control Performance 

Tests indicate that given the right flue gas conditions, MerCAP with gold coated plates around 10 ft long 

and spaced 0.5 inches apart can remove more than 80 percent of mercury. In the tests conducted to date in 

flue gas derived from low rank fuels, this performance was achieved downstream of a spray dryerbaghouse. Similar results have recently been obtained in other tests conducted downstream of a wet 

absorber in bituminous-derived flue gas. Developer claims that higher removals (>90 percent) for the 

short term should be achievable by increasing plate length, decreasing plate spacing, or reducing gas 

velocities.2

O&M Impacts 

A factor that may reduce cost is the use of sorbent material that is cheaper or has higher mercury 

capacities than gold. Development work is needed to evaluate these options to reduce costs as well as to 

establish sorbent capacity, regeneration frequency, and sorbent life expectancy for the range of power 

plant configurations and coals burned. Projected additional pressure drop is less than 2” of H2O for plateto-plate spacing of 1-inch and a gas velocity of 60 ft/s. 

Costs 

The capital costs for a MerCAP system with 90 percent mercury control, 3-month regeneration, and 100 

percent redundancy is estimated at $4.7 million for a 250 MW unit (this corresponds to $18.8/kW). Of the 

3-37 
capital cost, $2.3 million is the gold media and its substrate. For 1-year regeneration and lower mercury 

capacity (10 percent compared to 15 percent of the weight of gold), the costs are $14.9 million for a 250 

MW unit (this corresponds to $59/kW) with $12.6 million in gold media and substrate cost.2

O&M costs are estimated by a preliminary engineering economic study to range from 0.46 to 0.87 

mills/kWh and 0.19 mills/kWh for fixed and variable component, respectively. The amount and cost of 

the sorbent media is the major cost component for a MerCAP installation.2

Issues Associated with the Technology; Future Outlook 

MerCAP with gold as the sorbent surface did not perform well in non-scrubbed flue gas. Mercury 

removal effectiveness, although low in non-scrubbed gases, also did not appear to degrade over time in 

flue gas. It is uncertain at this point whether the low effectiveness is due to specific flue gas components, 

which reduced the gold capacity for mercury in the gases tested, or due to an effect of temperature, or to a 

combination of both. Sorbent materials other than gold are also being tested as alternate coatings. Some of 

the materials may be more effective or offer a cost-effective alternative to gold for specific flue gas 

conditions.

2

References 

1. Control Technology Evaluation of MerCAPTM for Power Plant Mercury Control. 

http://www.netl.doe.gov/coal/E&WR/mercury/control-tech/mercap.html (accessed Dec 1, 2004). 

2. Sjostrom, S.; Chang, R.; Strohfus, M.; Johnson, D.; Hagley, T.; Ebner, T.; Slye, R.; Richardson, 

C.; Belba, V. Development and Demonstration of Mercury Control by Adsorption Process 

(MerCAPTM). Presented at the MEGA Symposium, Washington, DC, May 2003. 

3.2.2 SO2 and NOX Control 

3.2.2.1 Electron Beam Process 

Electron Beam Process Summary 

Status Early commercialization stage 

SO2 Reduction, % >95 

NOX Reduction, % Up to 90 

Hg Reduction NA 

Cost 

Capital ($/kW) 180 – 250 for 100 – 300 MW 

Fixed O&M ($/kW-yr) NA 

Variable O&M (mills/kWh) NA 

Applicability New power plants and retrofits 

Issues Demonstration is required. High auxiliary power requirement 

is the main barrier. 

Technology Description 

The electron beam (E-beam) process is capable of removing simultaneously SO2 and NOX and involves 

cooling of the flue gas, injection of ammonia, and then irradiation by high-energy electrons.1-5 As Figure 

3-3 shows, the E-beam process equipment is placed after the ESP. The first component is an evaporative 

spray cooler, where the flue gas is cooled to 60-66 °C (140-150 °F). The spray cooler is operated with a 

3-38 
dry bottom (all the water injected into the flue gas is evaporated). In addition, gaseous ammonia is 

injected into the flue gas either before or after the spray cooler. 

The main component of the E-beam process is a chamber where the flue gas is irradiated by a beam of 

high-energy electrons, while water is added to counteract the temperature rise. The irradiation also 

generates hydroxyl radicals and oxygen atoms, which oxidize the SO2 and NOX. These oxidized species 

mix with water in the flue gas to form sulfuric acid and nitric acid, which are neutralized by the ammonia. 

The by-products of the E-beam process are solid ammonium sulfate and ammonium sulfate-nitrate, which 

are collected downstream of the E-beam chamber by an ESP or a baghouse, and can be used as fertilizer 

after processing into a granular product. The by-product particles are small and sticky and pose some 

problems to both ESPs and FFs. A combination of ESP-FF has been proposed as more effective. In 

addition, use of inert materials has been considered to make it easier to clean the bags of the baghouse. 

FAN

AIRHEATER

FAN

FAN

Figure 3-3. E-Beam process schematic. 

Commercial Readiness and Industry Experience 

The technology is in an early commercialization stage with a number of demonstration plants in 

operation, but no operating commercial applications. Ebara International Corp. is actively promoting this 

technology, but others are preparing to offer related systems (primarily different methods for producing 

the ionization energy). The main reason for limited acceptance of the technology is that it is more 

expensive (relative to other competing options such as FGDs) as an SO2 removal process only. Future 

market acceptance of this technology will depend on whether it is cheaper than the combination of 

individual SO2 and NOX controls for the levels of SO2 and NOX emissions required. Another major factor 

3-39 
will be the price that can be obtained for the fertilizer by-product. Should it be possible to sell the 

fertilizer by-product, this revenue stream would possibly help partially offset O&M costs. 

Pilot-scale testing was conducted at Indianapolis Power & Light’s Stout station in an 8 MW slipstream in 

1986. Similarly, the process was tested in 1992 at Chubu Electric Power Company’s Nishi-Nagoya plant 

on a slipstream (12,000 Nm3

/h) of the 200 MW boiler firing Australian coal. The emission reductions 

achieved were: 92 percent SO2 and 60 percent NOX. After the successful operation of this plant, Chubu 

decided to install the E-beam process in the Nishi-Nagoya 1 unit, which burns high-sulfur residual oil. 

Also, the E-beam process was demonstrated at the Chengdou Power Plant in Sichuan Province, China. 

The plant is 90- MW and has been operating since July 1997. SO2 removals have been in the mid-80 

percent range and NOX removal was between 15 and 20 percent using low-to-high-sulfur bituminous coal 

(600 – 2500 ppm inlet SO2).6

Emission Control Performance 

The E-beam process is capable of achieving SO2 removals of 95 percent or greater and NOX removals of 

about 90 percent. High SO2 removals require a minimal E-beam dose, generally much lower than the Ebeam dose necessary for NOX removal. Once the minimum E-beam dose is achieved, the primary factors 

affecting SO2 removal are flue gas temperature and ammonia stoichiometry. The E-beam dosage required 

for 90 percent SO2 removal is a minimum of 1.0 mrad. 

The removal of NOX depends primarily on the E-beam dosage; temperature and SO2 concentration are of 

secondary importance. Higher NOX removals require higher radiation dosages. A dose of about 0.3–0.6 

mrad is required to achieve 50 percent NOX removal, and 90 percent NOX removal requires at least 2.7 

mrad according to the data obtained to date.7,8 Higher NOX removals are obtained at higher temperatures, 

contrary to SO2 removal. Higher SO2 concentrations also improve NOX removal, making the process 

better suited for high-sulfur applications. Furthermore, additional particulates are removed in the new 

ESP or FF. 

O&M Impacts 

The energy requirement for E-beam depends greatly on the NOX reduction being sought; when significant 

NOX reduction is not required, the auxiliary power for the E-beam process may range from 2 to 3 percent 

of the total plant output. The Chengdou demonstration plant consumed about 2 percent of the plant energy 

for an SO2 removal of 80 percent and NOX removal of 10 percent. When NOX reduction is above 60 

percent, the auxiliary power may reach 5 percent.

Particulate collection by either ESP or baghouse can be problematic if appropriate steps are not taken to 

overcome the stickiness of the particulates. 

Capital Costs 

Ebara projects capital costs for a 100-300 MW plant in the $180-250/kW range.1

O&M Costs 

The main O&M costs are related to the auxiliary power requirements and the ammonia injection. Early 

studies project that the total O&M costs are 11-15 mills/kWh resulting in levelized costs (including cost 

of capital) of 16 to 22 mills/kWh.1

These costs do not include capital and O&M costs associated with by-product treatment, such as 

granulation, or revenue from the sale of the by-products. A concept has been proposed for the fertilizer 

production companies to provide the ammonia needed to the power plant and receive the “upgraded” 

solid nitrogen granular fertilizer (net credit of $1 million per year or 3-4 mills/kWh). Ebara claims that 

3-40 
this concept would result in significant savings, but detailed cost estimates have not been developed and it 

has not been applied anywhere. 

Issues Associated with the Technology; Future Outlook 

The technology has yet to reach commercial stage and there is uncertainty regarding its cost and longterm reliability. Also, the process currently uses a significant amount of electricity, up to 5 percent of the 

plant output depending on the required NOX removal. 

References 

1. Hirano, S.; Aoki, S.; Izutsu, M.; Yuki, Y. Simultaneous SO2, SO3, and NOX Removal by 

Commercial Application of the EBARA Process. Proceedings of the EPRI-DOE-EPA Combined 

Utility Air Pollution Control Symposium: The MEGA Symposium, Atlanta, GA, Aug 16-20, 

1999. 

2. Chmielewski, A. G.; Dobrowolski, A.; Iller, E.; Tyminski, B.; Zakrzewska-Trznadel, G.; Zimek, 

Z.; Licki, J. Development and Application Experience with Technology of SO2 and NOX

Removal from Flue Gas by Electron Beam Irradiation. Proceedings of the EPRI-DOE-EPA 

Combined Utility Air Pollution Control Symposium: The MEGA Symposium, Atlanta, GA, Aug 

16-20, 1999. 

3. Saku, S. Electron Beam Flue Gas Treatment System. Presented at the Asia-Pacific Workshop on 

Water and Air Treatment by Advanced Oxidation Technologies, Ibaraki, Japan, Dec 1998. 

4. Maezawa, A.; Iizuka, Y. Electron Beam Flue Gas Treatment Process Technology. Presented at 

the International Congress of Acid Snow and Rain, Niigata, Japan, Oct 1997. 

5. Izutsu, M.; Okabe, R. Final Development to Commercialize EBARA Process. Presented at the 

Second Symposium on Non-thermal Plasma Technology for Pollution Control, Brazil, Oct 1997. 

6. Technology Assessment of Clean Coal Technologies for China. Electric Power Production;

World Bank ESMAP and AESEG Technical Paper 011, May 2001. 

7. FGD Handbook. International Energy Agency Coal Research, London, 1994. 

http://www.caer.uky.edu/iea/ieacr65.shtml (accessed Dec 1, 2004) 

8. Frank, N. W.; Hirano, S. Combined SO2/NOX Removal by Electron-beam Processing. Presented 

at the 4th Symposium on Integrated Environmental Control, Washington, DC, March 2-4, 1988. 

3-41 
3.2.2.2 ROFA-ROTAMIX (Mobotec) 

ROFA-ROTAMIX Summary 

Status 

ROFA and ROTAMIX commercially available for NOX

reduction; ROTAMIX demonstrated on a 150 MW coal-fired 

unit 

SO2 Reduction, % 69 with Trona, 64 with limestone 

NOX Reduction, % 

40 – 60 with ROFA; 

up to 80 with ROTAMIX 

Additional removal with Trona (11) or limestone (4) 

Hg Reduction, % 67 with Trona, 89 with limestone 

Cost 

Capital ($/kW) ROFA: $20-25/kW for 100 and 200 MW plants 

ROTAMIX: $25-30/kW for units in the 100 - 200 MW range 

Fixed O&M ($/kW-yr) 0.5 - 1.0 

Variable O&M (mills/kWh) Depends on the use of ammonia or SO2 control absorbent 

Applicability Existing plants, especially older units less than 300 MW 

Issues 

ROFA has been demonstrated up to 175 MW scale. Also, 

the potential increases in boiler slagging and fouling and 

erosion of boiler tube surfaces with the injection of sorbents 

for SO2 and Hg control have not been resolved. 

Technology Description 

Mobotec offers three NOX control technologies: (1) the Rotating Opposed Fire Air (ROFA) system, (2) 

the ROTAMIX, and (3) in-duct SCR that may be used in conjunction with the previous two systems. This 

report includes description of the ROFA and ROTAMIX. According to the vendor, these two 

technologies are generally designed as one system; therefore, they are considered a multi-emission control 

option. The in-duct SCR is an independent NOX control option. 

ROFA System

The ROFA system incorporates asymmetrically placed ROFA air nozzles (in concept similar to overfire 

air), which contribute to mixing of the flue gas in the furnace by introducing turbulence. One or more 

levels of nozzles are placed asymmetrically in opposite walls, usually higher than those used in 

conventional overfire air systems. The ROFA system is designed for 20-40 percent of the total airflow 

and uses a booster fan to provide the required pressure and achieve adequate air penetration into the 

furnace.1

ROTAMIX

ROTAMIX is used in conjunction with ROFA and involves injection of various chemicals or additional 

fuel (for example, reburn gas) to remove NOX, SO2, and heavy metals (including mercury). In addition to 

the ROFA ports, lances are provided to inject the chemicals. So far, Mobotec has used urea and ammonia 

for NOX reduction, CaCO3 for SO2 control, and is considering adsorbents for mercury control. 

Computational fluid dynamic (CFD) modeling is used to take into account site-specific considerations, 

determine the optimal design characteristics for each boiler, and determine the placement of the ROFA 

boxes. 

3-42 
Commercial Readiness and Industry Experience 

The ROFA-ROTAMIX system is considered commercial. There are 18 installations in the U.S. and 17 in 

Sweden (mainly stoker-fired, fluidized-bed, and dry-bottom boilers burning coal, heavy fuel oil, wood 

wastes, and municipal waste). In the U.S., ROFA-ROTAMIX has been recently installed at Carolina 

Power & Light’s (CP&L) Cape Fear 5 and 6, T-fired boilers burning pulverized eastern bituminous coal. 

Cape Fear 5 is a single furnace boiler generating 154 MW. Cape Fear 6 is a twin furnace generating 172 

MW.2

 In Sweden, the combination of ROFA-ROTAMIX has been installed in a 78 MW coal-fired stoker 

boiler (Jordberga plant of Danisco Sugar Ltd.). In the Jordberga plant, a 90 percent reduction of SO2 was 

achieved using CaCO3. 

Emission Control Performance 

The 17 ROFA retrofits in Sweden (mainly stoker-fired, fluidized-bed, and dry-bottom boilers burning 

coal, heavy fuel oil, wood wastes, and municipal waste) achieved an average of 50 percent NOX reduction 

with ROFA, while maintaining CO emissions and reducing excess O2. 

As Figure 3-4 shows, CP&L’s Cape Fear 5, a T-fired boiler burning pulverized eastern bituminous coal 

and generating 154 MW of power, achieved 55 percent NOX reduction at full load and up to 69 percent at 

low loads. Also, the level of excess oxygen was reduced from 5.5 to 3.7 percent at full load resulting in 

higher boiler and plant efficiency. This reduction of the excess oxygen did not adversely affect CO 

emissions. They were also reduced from 50-90 ppm to less than 20 ppm. Adverse impacts included a 

small increase in unburned carbon in the fly ash or LOI (from 3 to 5 percent), approximately 11 °C 

(20 °F) superheat and reheat temperature reduction and increased auxiliary power due to the high-volume 

ROFA fan [820 kW (1100 HP)]. 

The combination of ROFA-ROTAMIX at Jordberga (78 MW coal-fired stoker boiler in Sweden) 

achieved 40 percent NOX reduction and 90 percent SO2 reduction.1

 The same performance (especially 

with regard to the SO2 reduction) has not been confirmed in pulverized coal boilers, which operate at 

significantly higher temperatures than stokers. 

The combination of ROFA-ROTAMIX has been installed in CP&L’s 154 MW coal-fired Unit 5 at the 

Cape Fear Generating Station for the multipollutant technology evaluation program. The program 

included injection of CaCO3 to determine the effect on SO2 and Hg reduction and injection of trona to 

determine the effect on NOX, SO2, HCl, and Hg reduction. SO2 reductions of 69 percent were achieved 

with trona and 64 percent with CaCO3. Mercury reductions of 89 percent were achieved with limestone 

and 67 percent with Trona.3-6

Key factors affecting the performance of the ROFA and ROTAMIX systems are: 

 height between top burner and furnace outlet which determines whether the ROFA system can be 

accommodated and there is adequate residence time for complete combustion, 

 furnace dimensions, which will impact the degree of penetration of the air into the furnace, and 

 temperature at the top of the boiler. 

3-43 
0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

40 60 80 100 120 140 160 180

NO

X Emissions, lb/MMBtu 

Gross Electrical Power, MWe

Before ROFA 

After ROFA 

Figure 3-4. NOX emissions from Cape Fear Unit 5: comparison before and after ROFA. 

O&M Impacts 

The limited experience with ROFA systems in the U.S. indicates that there are positive and negative 

O&M impacts. On the positive side, combustion efficiency and CO emissions have improved. Also, 

excess oxygen has been reduced resulting in higher boiler and plant efficiency. On the negative side, 

reduction in superheat and reheat temperatures have been experienced. At Cape Fear, outlet steam 

temperatures declined by 11 °C (20 °F) (an equivalent of 0.40 percent reduction in plant efficiency). 

However, the O&M impacts are very site-specific (usually depend on the boiler design, operating 

condition, and fuel characteristics), and one site is not adequate to generalize the potential impacts of 

ROFA for coal-fired boilers. 

Impact that needs to be taken into account is the increased auxiliary power due to the high-volume ROFA 

fan, estimated (by the vendor) to be approximately 0.3 percent of the plant output. A 150- MW boiler 

requires a fan with a 450-750 kW (600-1,000 HP) motor. 

There will be a similar increase in auxiliary power due to ROFA-ROTAMIX, plus there will be the use of 

chemicals such as ammonia, urea, or CaCO3. 

Costs 

Typical costs for ROFA average around $20 – 25/kW for boilers between 100 and 200 MW.2

 The retrofits 

take approximately 8 months from order to final installation. A 2-week outage is expected for installation 

of the system. 

Capital costs of ROFA-ROTAMIX range between $25 and 30/kW for boilers between 100 and 200 MW. 

The installation costs ($/kW) are projected to be lower for larger boilers. 

3-44 
Issues Associated with the Technology; Future Outlook 

The performance of ROFA in large boilers may degrade, as the boiler dimensions increase and either the 

air penetration will be less efficient or a more powerful fan would be required to achieve the same 

efficiency. CFD modeling completed for boiler sizes up to 550 MW indicate satisfactory performance. 

Presently, ROFA has been demonstrated up to the 172 MW scale. Slagging of the superheater by sorbent 

(CaCO3 and Trona) and ash was found to be a problem during the Unit 5 Cape Fear Generating Station 

tests. Also, the effect of long-term injection of such sorbents on boiler tube erosion is not known. 

References 

1. Moberg, G.; Blid, J. O.; Wallin, S.; Fareid, T.; Ralston, J. Combined DeNOX/DeSOX and 

Additional NOX Reduction by Cleaning Flue Gas Condensate from Ammonia. Presented at the 

PowerGen International Conference, New Orleans, LA, Nov 30 – Dec 2, 1999. 

2. MobotecUSA – Installations. http://www.mobotecusa.com/projects/installations.htm (accessed 

Dec 1, 2004). 

3. Haddad, E.; Shilling, M. Installation of Combined Combustion and Post Combustion NOX

Control Technologies at Cape Fear Station and the Future Application of the System for 

Mitigation of Other Pollutants. Proceedings of the US EPA/DOE/EPRI Combined Utility Air 

Pollutant Control Symposium: The MEGA Symposium, Chicago, IL, Aug 20-23, 2001. 

4. Ralston, J.; Haddad, E.; Moberg, G. Full-scale Evaluation of Various Sorbents to Reduce MultiPollutants: NOX, SO2 and Mercury. Proceedings of the Combined Utility Air Pollutant Control 

Symposium: The MEGA Symposium, Washington, DC, May 19-21, 2003. 

5. Ralston, J.; Haddad, E.; Green, G.; Castagnero, S.; Full-scale Evaluation of Multipollutant 

Reduction Technology. Proceedings of the ICAC Forum’03, Nashville, TN, Oct 2003. 

6. Haddad, E.; Ralston, J.; Green, G.; Castagnero, S. Full-scale Evaluation of Multipollutant 

Reduction Technology. Proceedings of the MEGA Symposium, Washington, DC, May 2003. 

3.2.2.3 SNOX

TM

SNOX Summary 

Status Early commercial stage; two commercial plants in operation 

in Europe 

SO2 Reduction, % Above 90 

NOX Reduction, % Above 90 

Hg Reduction, % Zero 

Cost 

Capital ($/kW) 270 – 315 for 300 – 500 MW plant 

Fixed O&M ($/kW-yr) NA 

Variable O&M (mills/kWh) NA 

Applicability Both new and retrofit applications 

Issues Cost-effectiveness 

3-45 
Technology Description 

As shown in Figure 3-5, the SNOX process involves removing particulates from the flue gas that leaves 

the boiler in a high-efficiency fabric filter (baghouse) to minimize the cleaning frequency of the sulfuric 

acid catalyst in the downstream SO2 converter.1-3 The ash-free gas is reheated to 725-752 °F (385-400 °C) 

mainly in a gas to gas heat exchanger, and NOX is reduced with small quantities of ammonia in the first of 

two catalytic reactors where the NOX is converted to nitrogen and water vapor. If the heat available in the 

gas stream is not adequate, supplemental heating maybe used (see preheat burner in front of the baghouse 

or the SO3 reactor). The SO2 is oxidized to SO3 in a second catalytic converter (SO3 Reactor). Then, the 

gas passes through a novel glass-tube condenser (WSA: Wet gas Sulfuric Acid condenser) that allows the 

SO3 to hydrolyze to concentrated sulfuric acid. 

Because the SO2 catalyst follows the NOX catalyst, any unreacted ammonia (slip) is oxidized in the SO2

catalyst to nitrogen and water vapor. According to the supplier, downstream fouling by ammonia 

compounds is eliminated, permitting operation at higher than normal stoichiometry. These higher 

stoichiometries allow smaller catalyst volumes and higher reduction efficiencies. 

Slipstream 

Figure 3-5. SNOX process schematic. 

Commercial Readiness and Industry Experience 

The technology is in an early commercial stage with five demonstration projects completed in the earlyand mid-1990s.4-7 The first commercial plant started operation in 1999. Initially, the technology was 

tested at a pilot plant of Elsam (Danish utility) in a flue gas stream of 10,000 Nm3

/h. From 1991 to 1993, 

the following demonstrations took place: 

3-46 
 Gela (Italy) of Enichem SpA; Gas: 100,000 Nm3

/h with 600-4,000 ppm SO2 and 500 ppm NOX in the 

inlet 

 Vodskov (Denmark) of ELSAM; Gas: 1,000,000 Nm3/h (approximately 305 MW) with 200-2,000 

ppm SO2 and 550 ppm NOX in the inlet 

 Niles (USA) of Ohio Edison; Gas: 132,000 Nm3/h with 2,000 ppm SO2 and 500-700 ppm NOX in the 

inlet 

 Vresova (Czech Republic) of Sokolovska Uhelna A.G.; Gas: 54,000 Nm3/h with 2.4-3.6 H2S and 200 

ppm NOX in the inlet 

 Kawasaki plant (Japan) of Asahi Chemical Industry Ltd; Gas: 50,000 Nm3/h with 5.7 percent SO2 and 

100 ppm NOX in the inlet 

The U.S. demonstration was conducted at Ohio Edison's Niles Station in Niles, OH in a 35- MW 

equivalent slipstream of flue gas from the 108- MW Unit No. 2 boiler, which burned a 3.4 percent sulfur 

Ohio coal. 

In addition to the Vodskov plant, which has been operating for several years, a new commercial size plant 

was built and started operation in 1999 at AGIP Petroli SAP’s Gela plant in Italy. It treats 1,000,000 

Nm3

/h of flue gas from a petroleum-coke-firing facility having 2,380 - 4,600 ppm SO2 and 330 ppm NOX

in the inlet of the SNOX process.3

 The Gela plant is designed for 94 percent SO2 removal and 90 percent 

NOX removal. 

Emission Control Performance 

SO2 and NOX removal efficiencies above 90 percent have been achieved. At Ohio Edison's Niles 

demonstration, SO2 removal was approximately 94 percent with inlet concentrations averaging about 

2,000 ppm SO2 and NOX removal was 95 percent with inlet NOX in the 500 - 700 ppm range.4

 In addition, 

particulates are expected to be reduced, relative to the original system with ESP. 

SO2 removal is controlled by the efficiency of the SO2-to-SO3 oxidation, which occurs as the flue gas 

passes through the oxidation catalyst beds. Control is accomplished through the space velocity and bed 

temperature. Space velocity governs the amount of catalyst necessary at design flue gas flow conditions, 

and the gas and bed temperatures have to be high enough to activate the SO2 oxidation reaction. 

Particulates are very low, usually below 1 mg/Nm3

. At Niles, air toxics were tested and showed high 

capture efficiency of some trace elements in the baghouse. A significant portion of the boron and almost 

all of the mercury escaped to the stack. Selenium and cadmium were effectively captured in the acid 

drain, as were organic compounds. 

O&M Impacts 

While no systematic assessment of O&M impacts has been carried out, it is expected that the following 

impacts would need to be taken into account: 

 Fuel (most likely natural gas) requirements for the heaters 

 Increased auxiliary power which is going to affect the plant efficiency and heat rate 

 Safety issues associated with ammonia storage and feed system 

3-47 
Costs 

Costs for retrofitting a 500 MW plant with the SNOX process are projected to be 305 $/kW (EOY 1995 

dollars) resulting in 6.1 mills/kWh levelized costs3

 (over a 15-year period). Using the CEI (Chemical 

Engineering Annual Plant Index), the adjusted cost in EOY 2000 dollars is 315 $/kW. Presently, the 

supplier projects that the SNOX process could be retrofitted on a 300 MW power plant in the US for 

approximately 270 $/kW. 

Issues Associated with the Technology; Future Outlook 

The main issue associated with the technology is its cost-effectiveness in reducing SO2 and NOX relative 

to competing technologies. 

References 

1. Clean Coal Technology Demonstration Program: Update 2000; U.S. DOE, National Energy 

Technology Laboratory: Pittsburgh, PA, April 2001; 5-74. 

2. SNOX Flue Gas Cleaning Demonstration Project: A DOE Assessment; U.S. DOE/NETL2000/1125: Pittsburgh, PA, June 2000. 

3. Bruno, L.; Ricci, R. Application of SNOX technology at the Gela power plant in Sicily. Presented 

at the PowerGen 2000 Europe, Helsinki, Finland, June 20-22, 2000. 

4. Final Report for Niles Demonstration, Vol. II: Project Performance and Economics; DE-FC22-

90PC8955; U.S. DOE: Washington, DC, July 1996. 

5. Final Report for Niles Demonstration, Vol. I: Public Design; DOE/PC/8955-T21 (NTIS: 

DE96050312); U.S. DOE: Washington, DC, July 1996. 

6. A Study of Toxic Emissions from a Coal-fired Power Plant Utilizing the SNOX Innovative Clean 

Coal Technology Demonstration, Vols. 1 and 2; DOE/PC/93251-T3; U.S. DOE: Washington, 

DC, July 1994. 

7. Andeasen, J.; Laursen, J. K.; Bendixen, O. R. SNOX Plant in Full-scale Operation. Modern Power 

Systems Magazine, April 1992. 

 

3

 Other assumptions: credit was assumed for sale of sulfuric acid at 25 $/ton and for heat recovery from the SNOX

process for use in the boiler at 2.00 $/MMBtu 

3-48 
3.2.2.4 SOX-NOX-Rox Box (SNRBTM) 

SNRB Summary 

Status Pilot stage 

SO2 Reduction, % 80 – 90 

NOX Reduction, % 90 

Hg Reduction, % Zero 

Cost 

Capital ($/kW) 253 for 150 MW retrofit 

Fixed O&M ($/kW-yr) NA 

Variable O&M (mills/kWh) NA 

Applicability Both new and retrofit applications 

Issues Requires demonstration 

Technology Description 

The SNRB process combines the removal of SO2, NOX, and particulates in one unit - a high-temperature 

baghouse.1,2 It operates in the 425-455 °C (800-850 °F) temperature range and is placed before the air 

heater. SO2 removal is accomplished using either calcium- or sodium-based sorbent, sodium carbonate 

(Na2CO3), and sodium bicarbonate (NaHCO3), injected into the flue gas upstream of the baghouse. NOX

removal is accomplished by injecting ammonia (NH3) to selectively reduce NOX in the presence of a 

selective catalytic reduction (SCR) catalyst, which is placed on the high-temperature ceramic filter bags 

of the baghouse. Also, the baghouse removes particulates, its primary design function. 

Commercial Readiness and Industry Experience 

The SNRB technology requires further demonstration on a 50-100 MW scale. It has been demonstrated 

successfully on a 5- MW slipstream at Ohio Edison’s Burger No. 5 (a 156- MW boiler burning highsulfur bituminous coal) boiler. 

Emission Control Performance 

Four different sorbents were tested at the Burger pilot project including hydrated lime, sugar-hydrated 

lime, lignosulfonate-hydrated lime, and sodium bicarbonate. The results achieved can be summarized as 

follows:1,2 

 SO2 removal efficiency of 80 percent with commercial-grade hydrated lime at a calcium-to-sulfur 

(Ca-to-S) molar ratio of 2.0 and temperature of 425-455 °C (800-850 °F), 

 SO2 removal efficiency of 90 percent with sugar-hydrated and lignosulfonate-hydrated lime at a Cato-S ratio of 2.0 and temperature of 425-455 °C (800 - 850 °F), 

 SO2 removal efficiency of 80 percent with sodium bicarbonate at a sodium-to-sulfur (Na2-to-S) molar 

ratio of 1.0 and temperature of 220 °C (425 °F), 

 SO2 emissions were reduced to less than 1.2 lb/MMBtu, 80-85% SO2 reduction, with 3-4 percent 

sulfur coal with a Ca-to-S molar ratio as low as 1.5 and Na2-to-S ratio of 1.0, 

 Injection of calcium-based sorbents directly upstream of the baghouse at 440-480 °C (825-900 °F) 

resulted in higher overall SO2 removal than injection farther upstream at temperatures up to 650 °C 

(1,200 °F), 

 NOX reduction of 90 percent was achieved with an NH3-to-NOX ratio of 0.9 and temperature of 

425-455 °C (800-850 °F), and 

3-49 
 Also, 99.9 percent particulate removal has been demonstrated. 

In summary, 80 - 90 percent SO2 removal, 90 percent NOX removal, and similar levels of control for 

some air toxics were demonstrated. However, a demonstration on a larger scale (50 - 100 MW) is needed 

to assess the performance and economics of this technology. 

O&M Impacts 

The only potential O&M impact relates to effects on the FFs (mainly life expectancy). The SNRB filters 

are ceramic, incorporating a catalyst for NOX control, and their reliability is affected by both mechanical 

and thermal stresses due to cycling (changing operating conditions) and cleanup of the bags. To address 

these concerns, a 3,800-hour durability test of three fabric filters was completed2

 at the Filter Fabric 

Development Test Facility in Colorado Springs, CO, in December 1992. No signs of failure were 

observed. All of the demonstration tests were conducted using 3M Company Nextel ceramic fiber filter 

bags or Owens Corning Fiberglas S-Glass filter bags. No excessive wear or failures occurred in over 

2,000 hours of elevated-temperature operation. 

In most cases, SNRB is expected to be placed before the air heater, where the flue gas temperature is 

adequate [425-455 °C (800-850 °F)]. In case, the temperature is lower, flue gas heating may be required 

and the consumption of natural gas or oil needs to be taken into account, as an additional O&M impact. 

Costs 

The supplier estimates that capital costs for a 150- MW retrofit would be $253/kW (constant US$ 1994), 

assuming 3.5 percent sulfur coal, baseline NOX emissions of 1.2 lb/MMBtu, 65 percent capacity factor, 

and 85 percent SO2 and 90 percent NOX removal. Levelized cost over 15 years (constant U.S.$, 1994) is 

estimated to be 12.1 mills/kWh or equivalent to $553/ton of SO2 plus NOX removed. 

Issues Associated with the Technology; Future Outlook 

Considering that the technology has not been demonstrated, there are some uncertainties associated with 

both the emission control potential and its economics. Since the Burger pilot program in the mid-1990s, 

the supplier has not pursued further development of the technology because there was no demand for 

multi-emission control technologies. With the pending multipollutant control regulation, demand may 

increase for technologies such as SNRB. 

References 

1. Clean Coal Technology Demonstration Program: Update 2000; US DOE, National Energy 

Technology Laboratory: Pittsburgh, PA, April 2001; 9-13. 

2. Evans, A. P.; Kudlac, G. A.; Wolkinson, J. M.; Chang, R. SOX-NOX-Rox Box – High 

Temperature Baghouse Performance. Presented at the 10th Particulate Control Symposium, 

Washington, DC, April 5-8, 1993. 

3-50 
3.2.2.5 THERMALONOX and FLU-ACE Process 

THERMALONOX and FLU-ACE Process Summary 

Status In demonstration 

SO2 Reduction, % Up to 95 

NOX Reduction, % Up to 90 

Hg Reduction, % NA 

Cost 

Capital ($/kW) THERMALONOX: $35/kW for 500 MW; FLU-ACE: Not 

available 

Fixed O&M ($/kW-yr) NA 

Variable O&M (mills/kWh) 1.43* 

Applicability Applicable to both new plants and retrofits 

Issues Need demonstration to confirm performance and reliability 

on large scale, as well as economics. 

 *Assumed to be only for the THERMALNOX process 

Technology Description 

The THERMALONOX and FLU-ACE process is a two-step process.1,2 The first step is the gas phase 

chemical reaction converting nitrogen monoxide (NO) into nitrogen dioxide (NO2). This is accomplished 

by direct phosphorus (P4) liquid injection into the flue gas, which causes the release of ozone (O3) that 

oxidizes NO into NO2. This NO to NO2 conversion takes place in a specially designed reactor normally 

placed upstream of a wet scrubbing process. 

The prevailing chemical reactions are: 

P4 + O2 Æ P4O + O 

P4On + O2 Æ P4On+1 + O, where n is 1 through 9 

2NO + (O+O3) Æ 2 NO2 + O2 

2 NO2 + H2O Æ NO2 + NO3 + H2 

In the second step the NO2 is removed, as a water-soluble gas in the wet FGD process. In addition, as in 

the phosphoric acid manufacturing process, the solid P4O10 particles that are formed in the duct from the 

first step, upon entering the wet FGD process are instantly hydrated and hydrolyzed to form the dibasic 

phosphate (H2PO4

-

) and the mono-basic phosphate (HPO4

2-) anions. 

This second step could be accomplished by a wet FGD process (especially if it already exists) or the FLUACE process, a condensing reactive scrubber, which is also offered by Thermal Energy. The supplier 

projects 90 percent nitrogen dioxide removal efficiency by wet FGD and 98 percent by FLU-ACE. If the 

FGD cannot achieve the required NOX reduction, a FLU-ACE reactor can be added to boost the NOX

reduction above 90 percent and remove other pollutants such as mercury, VOCs, and fine particulates. 

The by-products of the THERMALONOX process are non-toxic nitrogen and phosphate compounds used 

as fertilizers and animal food additives. 

The P4 liquid is maintained at a constant temperature of 60 °C (140 °F) in the P4 injection tank and is 

pumped continuously through a steam-traced closed piping circuit connecting the P4 injection tank to the 

P4 atomization nozzle injection location in the flue gas duct. The P4 injection rate is individually 

controlled to each nozzle via corresponding P4 liquid flow control valves and atomizing steam pressure 

3-51 
control valves to maintain optimum P4 droplet size, physical dispersion, and chemical reaction in the duct. 

Atomization is done using steam, compressed air, or an aqueous emulsion of phosphorus. 

When THERMALONOX is used, the existing wet FGD process must absorb the additional nitrogen and 

phosphorus compounds generated. The system must also deal with the additional nitrogen and 

phosphorus species in solution. These compounds must be controlled to maintain proper scrubber 

operation to optimize NO2 and SO2 absorption and to control and maintain the by-product quality, 

whether it is for gypsum production or landfill. 

Commercial Readiness and Industry Experience 

The technology is in the early demonstration stage. There were plans to install it at American Electric 

Power’s Conesville plant (a 375 MW unit), but the project was suspended on September 27, 2001, during 

initial start-up. Tests were expected to last for 8-12 weeks with the target NOX reduction of 75 percent. 

In parallel with the Conesville demonstration, Thermal Energy is carrying out an R&D program to test the 

THERMALONOX process with an existing FLU-ACE scrubber near Ottawa, Canada. 

Emission Control Performance 

Thermal Energy projects 80-90 percent NOX removal for THERMALONOX with conventional FGD.1

 A 

combination of THERMALONOX and FLU-ACE is projected to achieve 98 percent NOX removal. In 

both cases, SO2 removal is projected to be in the 90 – 95 percent range. 

Key parameters affecting the THERMALONOX process are the flue gas temperature and oxygen 

concentration, which affect the reaction rate for converting NO to NO2, and therefore the reaction time 

required to achieve the desirable conversions (usually 99 percent). For a typical coal-fired power plant 

with flue gas at 140-160 °C (280-320 °F) and 4-5 percent excess oxygen, the required reaction time is 

about 1 second. The NOX to P4 ratio is projected by the supplier to be in the 3.0 - 4.0 range. 

O&M Impacts 

Potential O&M impacts are associated with the ability to control the spontaneous reaction of the 

phosphorus and flue gas to produce ozone. Also, if there is no market for the wastes, the ability to dispose 

of phosphate compounds needs to be assessed. 

Costs 

Thermal Energy projects the cost of THERMALONOX for a 500 MW coal-fired plant to be 

approximately $35/kW.1

Variable O&M are projected to be 1.43 mills/kWh.1

 

Issues Associated with the Technology; Future Outlook 

The main issues and uncertainties associated with the technology are: 

 Confirmation of pilot scale results and projected economics in utility scale demonstration and 

subsequently commercial projects. 

 The ability to control the spontaneous reaction of the phosphorus and ability of the flue gas to 

produce ozone in large scale needs to be demonstrated. 

 Disposal of phosphate compounds needs to be assessed including the impact of phosphorus injection 

on by-product properties and economics. 

3-52 
References 

1. Hinke, T. V. Utility NOX Control with Elemental Phosphorus. Proceedings of the U.S. EPADOE-EPRI Combined Power Plant Air Pollutant Control Symposium: The MEGA Symposium 

and The A&WMA Specialty Conference on Mercury Emissions: Fate, Effects, and Control, 

Chicago, IL, Aug 20-23, 2001. 

2. Leading Edge Environmental Compliance & Energy Conservation Solutions; Thermal Energy 

International, Inc., Nepean, Ontario, Canada: http://www.thermalenergy.com/. (accessed Dec 1, 

2004). 

3. Hinke, T. Utility NOX Control with Elemental Phosphorus. Proceedings of the U.S. 

EPA/DOE/EPRI Combined Utility Air Pollutant Control Symposium: The MEGA Symposium, 

Chicago, IL, Aug 20-23, 2001. 

3.2.3 SO2, NOX, and Mercury Control 

3.2.3.1 Activated Coke 

Activated Coke Summary 

Status Commercial 

SO2 Reduction, % 90 – 98 

NOX Reduction, % 15 – 80 (depends on SO2 reduction) 

Hg Reduction, % 90 – 99 

Cost 

Capital ($/kW) 120 – 200 for 300 – 1,000 MW 

Fixed O&M ($/kW-yr) 8 – 13 

Variable O&M (mills/kWh) 1.3 – 2.1 

Applicability Both new and retrofit applications 

Issues Demonstration of the combined SO2-NOX-Hg control is 

needed in the United States 

Technology Description 

The activated coke process,1-3 shown in Figure 3-6, involves three steps: (1) adsorption, (2) desorption, 

and (3) (optional) by-product recovery. In the first step (adsorption), flue gas passes through a bed of 

activated coke slowly moving downwards in a two-stage adsorber. The activated coke consists of carbon 

with large porous inner surface area. In the first stage, sulfur dioxide is removed by adsorption into the 

activated coke where it forms sulfuric acid or ammonium hydrogen sulfate (NH4HSO4); the latter in case 

ammonia is injected in addition to the presence of activated coke. These compounds are maintained in the 

coke inner surface at temperatures ranging from 100 to 180 °C (212 to 356 °F). The adsorber acts also as 

a particulate control device reducing particulates below 30 mg/Nm3

 (0.0124 grain/scf) when the inlet is 

kept below 200 mg/Nm3

 (0.0827 grain/scf). 

In the second stage of the adsorption process, the activated coke acts as a catalyst in the decomposition of 

NOX to nitrogen and water after injection of ammonia in the activated coke bed. The chemical reaction 

occurs in the 100-180 °C (212-356 °F) temperature range. 

3-53 
Activated coke is a carbonaceous material produced by steam activation (at approximately 900 °C). It has 

high mechanical strength against abrasion and crushing. Its surface area is 150-250 m2

/g, less than the 

conventional activated carbon but much higher than the metallurgical coal.

As the activated coke is loaded with sulfuric acid, its adsorption capacity declines. To regenerate the 

activated coke, it is conveyed by a bucket elevator to a desorber. In the desorber the sulfuric acid or 

ammonium hydrogen sulfate (NH4HSO4) is decomposed to nitrogen, sulfur dioxide, and water. The 

regenerator is heated to 380-500 °C (716– 932 °F) temperature range through an external air heater, 

which consumes either oil or natural gas. Utilization of flue gas for this purpose is possible to reduce fuel 

requirements and associated costs, but has not been implemented. After cooling, the activated coke passes 

through a vibrating screen to eliminate smaller particles (fines) and then it is recycled back into the 

adsorber. 

Cooling 

water 

Figure 3-6. Activated coke process flow diagram7

SO2-rich gas can be reduced to H2S in a reduction column and then elemental sulfur can be produced in a 

Claus unit (typical process for sulfur production). Alternatively, sulfuric acid can be produced. 

Mercury can be removed also by adsorption. Once adsorbed on the coke, mercury must be collected in a 

form suitable for disposal or recovery. Mercury is absorbed on the coke up to 1.7 mg/g-coke at the 

temperature below 180 °C. Due to the temperature profile within the regenerator, mercury-rich coke can 

be found in the middle section of the regenerator. The mercury concentration in this area increases over 

time and removal of the mercury-rich coke is required once every few years (1-3 years depending on the 

percentage sulfur and mercury in the coal). The coke removed, representing approximately 1 percent of 

3-54 
the total coke in the system, is sent to special facilities, which recover the mercury and sell it for 

commercial applications. 

The mercury recovery facilities use various methods one of them being the use of a selenium filter, which 

absorbs the mercury from the flue gas and forms HgSe, a chemically stable compound. The selenium 

filter technology is commercial and can achieve up to 98 percent Hg collection efficiency during the filter 

life (usually 4-5 years). Once spent, the selenium filter has to be disposed of in a hazardous waste facility. 

Other methods of mercury removal or disposal are also considered, such as SO2-rich gas (SRG) off-gas, 

sulfuric acid plant off-gas, and SRG scrubber waste water. 

Commercial Readiness and Industry Experience 

The process is commercially available in Japan and Germany. It was originally developed by Deutsche 

Montan Technologie (formerly Bergbau-Forschung GmbH) and demonstrated at a 158,000 m3

/s (93,000 

scfm) plant, the Kellerman generating station of STEAG GmbH. Mitsui Mining Co., Ltd. of Japan 

obtained a license from Deutsche Montan Technologie and tested it in a pilot facility from 1981 to 1983.4

Installations of the Mitsui activated coke process in Japan5,6 and Germany include the following (designed 

for both SO2 and NOX control unless otherwise indicated): 

 31,775 Nm3/h at Mitsui’s power generating station (1984) 

 236,000 Nm3/h at Idemitsu Kosan’s refinery on a residual fluidized bed catalytic cracking process 

(1987) 

 451,000 and 659,000 Nm3/h boilers at EVO GmbH’s Arzberg power station in Germany (1987) 

 323,000 Nm3/h at Hoechst AG’s power station in Frankfurt, Germany (1989) 

 10,000 Nm3/h at Electric Power Development Corp.’s (EPDC) Wakamatsu power station (1990) 

 1,157,000 Nm3/h (350 MW) AFBC boiler at the Electric Power Development Corp. Takehara power 

station (1995), designed only for NOX reduction and achieved above 80 percent NOX reduction 

Sumitomo of Japan has also developed its own activated coke technology and provided a commercial 

system for the Electric Power Development Corp. Isogo station, a 600 MW power plant burning lowsulfur coal (flue gas flow rate of 1,806,000 Nm3

/h). The activated coke process is designed for 95 percent 

SO2 removal and 30% NOX reduction. 

Sumitomo also has utilized this technology in sintering plants of steel-making industry for SO2, NOX and 

dioxin control. The following Table 3-5 provides the size and start-up year for sintering plants utilizing 

Sumitomo’s process. 

Table 3-5 Sintering Plants Utilizing Activated Coke 

Customer Emission Removed 

Gas Volume 

[Nm3/h] Start up 

A SO2 900,000 1987 

B SO2, NOX, Dust 1,300,000 1999 

C Dioxin, Dust 1,552,000 2003 

D SO2, NOX, Dust 1,300,000 2003 

E SO2, NOX, Dust, Dioxin 1,350,000 2004 

F SO3, NOX, Dust 1,650,000 2004 

3-55 
Emission Control Performance 

SO2 control efficiency has ranged from 90 to 98 percent and the NOX control efficiency from 15 to 80 

percent.1,5,6 NOX reduction is higher for lower SO2 concentrations at the inlet of the adsorber. For 

example, 1000 ppm SO2 concentration may result in NOX reduction in the 15 – 40 percent range, while 

200 ppm SO2 concentration will raise NOX reduction to above 70 percent. NOX reduction is also affected 

by the amount of ammonia injected (NH3-to-NOX ratio typically in 0.5-1.0 range results in above 70 

percent NOX reduction), the oxygen concentration of the flue gas (lower excess O2 results in lower NOX

reduction), and the inlet gas temperature. 

Based on pilot-scale tests carried out by Sumitomo and measurements by EPDC at its Matsushima power 

station, 90 – 99 percent mercury removal is projected. These tests resulted in >99 percent mercury 

reduction at operating temperatures of 150 to 180 °C. Mercury reduction data from the remaining 

installations are not available, because these systems were not designed with mercury control in mind, but 

rather for SO2 and NOX control; hence, mercury was removed, but no data were kept regarding mercury 

capture efficiencies. 

O&M Impacts 

Due to the high heat capacity of the activated coke system, it takes longer than a conventional plant to 

reach the operating temperature of the de- NOX process, which means that either NOX emissions will be 

higher during start up or the ramp-up rate of the plant will be limited. Other O&M impacts are not known, 

mainly because of the lack of information and experience in the United States. Required auxiliary power 

is estimated to be 0.70 percent of the gross output, compared to 1.0-2.5 percent for a wet FGD. 

Capital Costs 

According to the suppliers, capital costs (including by-product equipment) are projected to be in the $120 

– 200/kW range for a unit 300 – 1,000 MW in capacity, gas temperature 150-165 °C (300-330 °F), and 

gas inlet conditions: SOX 500 – 1,000 ppm, NOX 170 – 260 ppm and dust 140 – 200 mg/Nm3

. The capital 

costs include all equipment (including mercury control and acid production) fully installed and 

operational. 

O&M Costs 

Fixed costs are expected to be in the $8-13/kW-yr range. Operating costs (including electricity, active 

coke, NH3, and fuel) are projected to be 1.3-2.1 mills/kWh (assumptions: activated coke: $833 per ton; 

ammonia: $223 per ton; electricity: 35 mills/kWh; cost of labor: 50,000 $/year-person). As the sulfur 

content in the coal increases above the 2 percent level, the O&M costs may increase substantially mainly 

due to the increase in activated coke costs. 

Issues Associated with the Technology; Future Outlook 

During start-up, it takes longer to bring up the temperature in the De-NOX system; so, NOX reduction in 

cycling units may suffer during start-up unless they are designed to utilize an external heat source to 

preheat the De-NOX reactor. 

References 

1. Electric Power Development Corp. Isogo Thermal Power Station/Outline of Facilities; Brochure 

describing the Isogo power station, 2000. 

2. Mitsui Mining Co., Ltd. Dry Type Desulfurization and Denitrification Technology for Coal-fired 

Power Plants; Brochure, May 2000. 

3-56 
3. Olson, D. G.; Tsuji, K.; Shiraishi, I. The Reduction of Gas Phase Air Toxics from Combustion 

and Incineration Sources Using the MET-Mitsui-BF Activated Coke Process. Presented at the 

1999 International Ash Utilization Symposium in Lexington, KY, Oct 18-20, 1999.

4. Ogaki, M.; Fujitsu, H.; Komatsubara, Y.; Ida, S. Catalytic Activity of Coke Activated with 

Sulfuric Acid for the Reduction of Nitric Oxide. Fuel 1983, 62, 325. 

5. Tsuji, K.; Shiraishi, I. Combined Desulfurization, Denitrification, and Reduction of Air Toxics 

Using Activated Coke: 1. Activity of Activated Coke. Fuel 1997, 75, 549. 

6. Tsuji, K.; Shiraishi, I. Combined Desulfurization, Denitrification and Reduction of Air Toxics 

Using Activated Coke: 2. Process Applications and Performance of Activated Coke. Fuel 1997,

76, 555. 

7. Watanabe, T.; Murayama, H.; Saito, I.; Morimoto, K.; Shibata, T. Coal-fired Power Stations and 

Gas Clean up Processes using Activated Coke for the 21st Century – Multi-Pollutant Control 

Technology. Presented at the 28th International Conference on Coal Utilization & Fuel Systems, 

Clearwater, FL, March 9-13, 2003. 

3.2.3.2 Electro-Catalytic Oxidation (ECO) 

ECO Summary 

Status In demonstration 

SO2 Reduction, % 98 

NOX Reduction, % 90 

Hg Reduction, % 90 

CO2 Change, % 5 increase 

Cost 

Capital ($/kW) 200 for 500 MW plant 

Fixed O&M ($/kW-yr) 6.83 

Variable O&M (mills/kWh) 1.5 projected 

Applicability Both new and retrofit applications 

Issues 50 MW demonstration in progress 

Technology Description 

The ECO process, shown in Figure 3-7,1

 treats flue gas in three steps to achieve multipollutant removal. 

First, a majority of the ash in the flue gas stream is removed in a conventional dry ESP. Following the 

ESP, a barrier discharge reactor oxidizes the gaseous pollutants to higher oxides. For example, nitric 

oxide is reacted to form nitric acid, sulfur dioxide is converted to sulfuric acid, and mercury is oxidized to 

mercuric oxide. Products of the oxidation process are then captured in a wet electrostatic precipitator 

(WESP) that also collects fine particulate matter. Liquid effluent from the WESP may be treated to 

remove collected ash and then delivered to a system to produce concentrated sulfuric and nitric acids for 

sale. The ECO system is designed for retrofit into the last fields of an existing ESP. If the ESP does not 

have adequate space to fit the ECO system, some or all components could be built downstream of the 

ESP. In the latter case, the downtime of the plant is reduced, but additional space (footprint) is needed. 

3-57 
The sulfuric and nitric acids produced and captured in the WESP effluent can be made into salable byproducts such as concentrated acids, gypsum, or fertilizer. 

Oxidation of gaseous pollutants in the barrier discharge reactor is the key component of the ECO process. 

Oxidation is accomplished through generation of a non-thermal discharge or plasma. In a dielectric 

barrier discharge, energetic electrons are produced throughout the reactor without heating the gas stream 

to high temperatures, requiring considerably less energy than plasma discharges. Dielectric barrier 

discharges can be operated over a wide range of temperatures and pressures and have been widely used 

for commercial ozone (O3) generation.2-5

To form a barrier discharge, a dielectric insulating material is placed between two discharge electrodes. 

Typically, the material (glass or ceramic) has a high dielectric strength and high dielectric constant and 

covers one of the two electrodes. High voltage applied to the electrodes causes the gas in the gap to break 

down. Presence of the dielectric barrier prevents this breakdown from forming an arc with its resulting 

energy consumption. Instead, breakdown is in an array of thin filament current pulses, or 

“microdischarges.” They are well distributed spatially over the discharge gap. Typical duration of a 

microdischarge is of the order of a few nanoseconds, and electron energies range from 1 to 10 electron 

volts. 

The electron energies formed in the microdischarge are ideal for generating gas-phase radicals, such as 

hydroxyl (OH) and atomic oxygen (O) through collision of electrons with water and oxygen molecules 

present in the flue gas stream: 

 O2 + e → O + O + e 

 H2O + e → OH + H + e 

 O + H2O → 2OH 

In a flue gas stream, these radicals simultaneously oxidize NOX, SO2, and Hg to form nitric acid (HNO3) 

and NO2, sulfuric acid (H2SO4), and mercuric oxide (HgO), respectively. The above reactions leading to 

radical formation and the subsequent oxidation reactions can be made to occur at a low temperature 

65-150 °C (150-300 °F). 

The presence of a dielectric barrier allows for several possible electrode configurations, including coaxial 

cylinders, cylindrical electrodes with plates, and parallel plate electrodes. Different reactor designs have 

little effect on overall conversion efficiency. This allows for spacing that reduces the potential for 

plugging of the reactor and results in a minimal pressure drop across the reactor. Aerosols formed by the 

oxidation reactions, including HgO, HNO3, and H2SO4, exit the barrier discharge reactor in the flue gas 

stream. At this point the gas enters a condensing WESP where collection of the aerosols, fine PM, and 

other air toxic compounds is accomplished. 

The by-products of the ECO process are raw sulfur and nitric and sulfuric acids, which can be used in the 

industry for fertilizer and gypsum production. Of course, the extent to which these by-products would be 

actually used depends on economics (supply and demand of competing products) in the local market 

(around the power plant). 

Commercial Readiness and Industry Experience 

The technology is in the demonstration stage. It was originally tested at laboratory scale (1 and 100 scfm). 

Then, it was tested at pilot scale at First Energy’s R.E. Burger No. 5 unit6,7 (a 156 MW unit), where a 

slipstream of equivalent to approximately 1 MW was used to assess the performance of the ECO process. 

The 1 MW pilot scale tests have been carried out since early 2002. 

3-58 
Presently, Powerspan has installed and begun testing a commercial demonstration unit at First Energy’s 

R.E. Burger plant.8

 The technology is being tested at a slipstream (110,000 scfm or 7.4 percent of the total 

flue gas) equivalent to 50 MW. The unit burns a variety of fuels including Ohio coal with 2-4 percent 

sulfur.9

 

Emission Control Performance 

At First Energy’s R.E.Burger No. 5 unit (1 MWslipstream), the technology achieved the following 

emission reductions:9

 90 percent NOX reduction, 

 98 percent SO2 reduction, and 

 90 percent mercury reduction. 

Solids

and Dissolved Minerals Disposal 

Distillation

Unit

Dilute Acid 

Figure 3-7. ECO process flow diagram. 

It should be pointed out that these results were achieved with 337 ppm NOX in the inlet of the ECO 

system, approximately 40 percent higher than a similar installation with low-NOX burners. 

3-59 
The early results from 50 MW demonstration (by Powerspan Corp.) achieved the following: 

 Greater than 90 percent NOX conversion in the reactor, total reduction of 65 percent, hindered by 

absorber performance 

 Greater than 98 percent SO2 reduction, often >99 percent 

 Mercury measuring equipment being installed 

O&M Impacts 

The main O&M impact of the ECO process is the auxiliary power consumption. Powerspan estimates that 

approximately 3 percent of the plant’s output is needed for the ECO process to reduce inlet NOX of 0.30 

lb/MMBtu down to 0.05 lb/MMBtu.8

Also, cooling water is required for the WESP and is assumed to be provided by the cooling water system 

of the plant. Finally, heating for the acid recovery and ash drying is required and is expected to be 

provided by the plant’s auxiliary system. While these do not present any technical challenge, they will 

have some impact on the plant mass and energy balances, as well as the plant’s overall efficiency. At this 

point, there is not enough information to assess the magnitude of this impact, but it is not expected to be 

substantial. 

The list of consumables and the by-products of the ECO process is given below.10 

Consumables: 

 Electric power for the barrier discharge reactor, pumps and blowers. The power for the discharge 

reactor is related to the NOX reduction desired. 

 Heat for the by-product crystallizer. 

 Ammonia reagent – this can be estimated as roughly two moles of ammonia per mole of SO2

removed. Additional amine is provided by other chemicals discussed below. 

 Make-up water for the absorption tower – about 1 gpm per MW – no special quality specification. 

 Carbon filters for mercury removal from the liquid discharge of the absorber. 

 Additional, proprietary chemicals that provide the balance of the amine for the conversion of NOX to 

ammonium nitrate and SO2 to ammonium sulfate. These are estimated at around $150/ton of NOX

removed and $15/ton of SO2 removed. 

By Products: 

 Ammonium nitrate and ammonium sulfate crystals that can be sold as fertilizer. Typically, for 90 

percent reduction for every mole of inlet NOX, 0.40 moles of ammonium nitrate are produced and for 

every mole of SO2 reduced, one mole of ammonium sulfate is produced. 

 Mercury captured on the activated carbon (a waste to be disposed of) at a cost of about $1000/lb of 

mercury captured. 

 A small amount of coal fly ash that was not captured by the ESP is filtered out of the liquid stream to 

the fertilizer crystallizer. 

 Water vapor. 

Costs 

The cost of the demonstration project at First Energy’s R.E. Burger (equivalent 50 MW scale) was 

$18 million.8

 This is equivalent to $200/kW for 500 MW unit. AmerenUE, Sargent & Lundy, 

3-60 
Wheelabrator, The Andersons, and Powerspan performed a detailed cost estimate of an ECO unit at 

AmerenUE's Sioux plant. The capital cost of an ECO system for this 510 MW installation was estimated 

at $120,400,000, inclusive of process equipment, general facilities, owner’s costs, and contingencies. This 

also included the fertilizer plant and balance of plant modifications. It is the only comprehensive, fullscale cost analysis that has been made publicly available. Therefore, a cost of $200/kW is a reasonable 

estimate to use.10,11

Variable operating cost for ECO is the cost of power and other consumables such as ammonia and 

specialty chemicals. Ammonia consumption is determined by the molar ratio and specialty chemical costs 

are estimated at $150/ton of NOX removed and about $15/ton of SO2 removed. Carbon filter replacement 

costs and the costs of disposal of used carbon filters are estimated at $1000/lb of mercury removed. 

Fertilizer value, which produces a revenue stream that offsets a portion of the cost, is approximated at 

$110/ton of fertilizer produced. The ammonium sulfate and ammonium nitrate fertilizer are widely traded 

commodity chemicals and their value will depend largely on market conditions at the time and transport 

costs. Fixed operating costs include an estimated 1.5 percent of process capital per year plus three 

operators and one maintenance person per shift. The manpower needs are not expected to be a significant 

function of unit size.10

The power for the dielectric barrier discharge reactor is largely determined by the amount of NO 

oxidation needed and the gas flow. To increase the amount of NOX removed by the ECO process, it is 

necessary to increase reactor power. So, for a given percent of NOX reduction, the reactor power is 

roughly proportional to the NOX mass flow. Therefore, to achieve a low outlet NOX level while 

minimizing power demand, it is best to start with a low NOX level from the boiler. As a result, one would 

typically use an ECO system in combination with low NOX burners or other devices to minimize NOX

into the ECO reactor. Based upon available information, reactor power (in W/scfm) can be assumed to be 

equal to the lesser of 20 W/scfm or 58.22•(NOX) – 6.2431, where NOX is measured in lb/MMBtu. This is 

shown in Figure 3-8 below. Reactor power could potentially be higher than 20 watts/scfm. However, this 

would likely be unattractive when compared to reducing NOX by other means such as low NOX burners.10

Other power demands include fan power to overcome about 9 inches of water total pressure drop 

(calculated as actual volume flow times pressure drop with an assumed fan efficiency of 65 percent) and 

another estimated 0.75 percent of plant output for auxiliary loads for the absorber and fertilizer plants.10 

Issues Associated with the Technology; Future Outlook 

As the process is scaled up, the main uncertainties are whether it can achieve the performance (emission 

reduction), which was achieved at smaller scale. Also, the costs and cost-effectiveness of the process is 

uncertain and may be adversely impacted by relatively high auxiliary power requirements. Finally, some 

uncertainty exists with regard to the scalability of the by-products both in terms of their suitability in 

meeting market specifications and price. Technology remains in the demonstration phase; therefore, 

performance and costs remain uncertain, especially for large-scale projects. 

3-61 
Figure 3-8. ECO power consumption versus NOX. 

References 

1. McLarnon, C. R.; Jones, M. D. Pilot Testing and Scale-up of a Multipollutant Control 

Technology at FirstEnergy. Presented at the Power-Gen International Conference, Orlando, FL, 

Nov 15, 2000. 

2. Kogelschatz, U.; Eliasson, B.; Egli, W. Dielectric-Barrier Discharges Principle and Applications. 

Proceedings of the International Conference on Phenomena in Ionized Gases, Toulouse, France, 

July 1997. 

3. Penetrante, B.; Schultheis, S. Non-Thermal Plasma Techniques for Pollution Control. 

Proceedings of the NATO Advanced Research Workshop, Cambridge, England, Sept 1992. 

4. McLarnon, C.; Penetrante, B. Effect of Gas Composition on the NOX Conversion Chemistry in 

Plasma. SAE Technical Paper Series 982433, San Francisco, CA, Oct 1998. 

5. McLarnon, C.; Penetrante, B. Effect of Reactor Design on the Plasma Treatment of NOX. SAE 

Technical Paper Series 982434, San Francisco, CA, Oct 1998. 

6. McLarnon, C. R.; Jones, M. D. Electro-catalytic Oxidation Process for Multipollutant Control at 

FirstEnergy’s R.E. Burger Generating Station. Presented at the Electric Power 2000 Conference, 

Cincinnati, OH, April 5, 2000. 

7. McLarnon, C. R.; Horvath, M. L.; Boyle, P. H. Electro-catalytic Oxidation Technology Applied 

to Mercury and Trace Elements Removal from Flue Gas. Presented at the Conference on Air 

Quality II, McLean, VA, Sept 20, 2000. 

8. Boyle, P.D., Operation of 50-MW ECO Commercial Demonstration Unit at FirstEnergy’s R.E. 

Burger Plant. Presented at the Electric Power 2004, Baltimore, MD, March, 2004. 

y = 58.22x - 6.2431

0

5

10

15

20

25

0.1 0.2 0.3 0.4 0.5

x (lb/MMBTU)

Power for 90% reduction, 

watts/scfm

NO NOX (lb/MMBTU)

Power for 90 percent reduction,

W/scfm

NOX (lb/MMBtu) 

3-62 
9. Boyle, P. D.; Steen, D.; Dovale, A. J. Commercial Demonstration of ECO Multipollutant Contro

Technology. Presented at the ICAC Forum’03, Nashville, TN, Oct 2003. 

l 

03-110; U.S. EPA: 

Research Triangle Park, NC, Oct 2003. 

11.

 Pollutant Control Symposium: The MEGA Symposium, 

Washington, DC, May 19-21, 2003. 

3.2.3.3

SCR and Wet FGD Summary 

10. Studt, J. E.; Jozewicz, W. Performance and Cost of Mercury and Multipollutant Emission 

Control Technology Applications on Electric Utility Boilers; EPA-600/RMcLarnon, C.; Steen, D. Combined SO2, NOX PM and Hg Removal from Coal-fired Boilers. 

Proceedings of the Combined Utility Air

SCR and Wet FGD 

Status Commercial 

SO2 Reduction, % 95 

NOX Reduction, % 90 – 95 

Hg Reduction, % 40—90% depending on coal type 

Cost 

Capital ($/kW) SCR: 50-140; Wet FGD: 160-275 for a nominal 400 MW 

plant 

Fixed O&M ($/kW-yr) SCR: 0.5 – 1.4; Wet FGD: 1.2 – 14 

Variable O&M (mills/kWh) SCR: 0.75 – 4; Wet FGD: 0.1 – 1 

Applicability Plants with SCR and wet scrubber technologies 

Issues 

Need additional confirmation of mercury oxidation levels in 

the SCR 

Technology Description 

Selective Catalytic Reduction (SCR) – NOX Control 

CR technology1

 reduces NOX through a catalytically enhanced reaction of NOX with ammonia, reducing 

. This reaction takes place on the surface of a catalyst, which is “housed” in a 

is uniformly distributed over the catalyst as well as 

es the 

noz in the flue gas and then through the catalyst. 

S

NOX to water and nitrogen

“reactor” vessel. The reactor ensures that the flue gas 

determines the flue gas velocity. Typical catalyst materials are titanium-oxide and vanadium-oxide on a 

“coated” substrate structure that may take forms such as plate or honeycomb. SCR system configuration 

is generally referred to in accordance with the location of the SCR relative to the power plant: 

 “high-dust” – SCR located between the economizer and the air preheater, upstream of the ESP 

 “low-dust” – SCR located between a hot-side ESP and the air preheater 

 “tail-end” – SCR located downstream of the air preheater, ESP, and FGD. This approach requir

flue gas to be reheated prior to entering the SCR 

Ammonia (anhydrous or aqueous) is injected into the flue gas upstream of the SCR reactor through a 

zle grid designed to ensure its uniform distribution

SCR – Mercury Control

The contribution of SCR technology to mercury reduction comes from the fact that SCRs have been

2-5 shown (also discussed in Section 3.2.1.3) to oxidize elemental mercury. Thus, there is synergism with 

3-63 
wet scrubbers, which are effective in capturing oxidized mercury. In fact, the SCR-wet scrubber 

combination is conceptually similar to the approaches discussed in the wet scrubber section (catalyticand reagent-based mercury oxidation upstream of a wet scrubber). 

Wet Scrubber 

As explained before in Section 3.2.1.3, the most commonly used wet scrubber technology uses a wet 

mestone process with in-situ forced oxidation to remove SO2 from the flue gas while producing a 

y-product. This is accomplished typically in a vertical vessel with flue gas contacting and 

y be 

ly 

ater 

llent means of 

ercury control. Wet FGD is a mature technology that offers potential for a very effective mercury 

nology is widely used commercially worldwide. In Germany, 

r example, essentially all coal-fired boilers are quipped with SCR technology combined with wet 

d worldwide. In the United States the technology is 

5

 examples of pilot-scale activities. Full-scale testing is taking place at 

arious sites as well.

y used in conjunction with wet FGD technology, and the combination has yielded 

tal mercury capture exceeding 80 percent.4,7 In tests conducted at Grosskraftwerk Mannheim AG in 

 content in the flue gas from 77 to 95 

e 

of the SCR catalyst at typical SCR temperatures, while at lower (air preheater outlet) 

mperatures, oxidized mercury levels rose from 81.9 to 94.1 percent.2

esting 

 catalyst may not be fully 

nderstood. Table 3-6, taken from Reference 3, summarizes some of the results. However, the mercury 

li

gypsum-grade b

reacting with limestone slurry to produce a mixture of calcium sulfite and sulfate. Through controlled

oxidation of the reaction products, a salable by-product in the form of commercial grade gypsum ma

produced. The intimate contact between gas and liquid is enhanced through different design approaches, 

usually involving several counterflow spray levels and mass transfer “trays” to optimize gas-liquid 

interactions. The technology has evolved over the years through “mechanical” improvements, which have

included better gas and liquid distribution within the scrubber, better controlled droplet size and size 

distribution, as well as “chemistry” improvements such as the addition of organic acids which not on

improve overall SO2 capture but also help the settling characteristics of the waste products. Several 

commercial variations of the technology exist based on reagent type, vessel design, etc. 

The intense gas-liquid mass transfer, combined with the fact that oxidized, vapor-phase mercury is w

soluble (elemental mercury is not), is what allows wet scrubbers to be potentially an exce

m

control via minor process modifications. 

Commercial Readiness and Industry Experience 

Similar to wet FGD technology, SCR tech

fo

scrubbers. Over 50,000 MW of capacity is deploye

being deployed at a rapid pace at present.6

 Therefore, both SCR (for NOX control) and wet scrubbers are 

readily commercially available. 

With respect to SCR performance on mercury oxidation, testing is on-going at pilot- and full-scale sites.2-

Efforts by B&W2,4 and EPRI3

 are

5,7 v

Emission Control Performance (Mercury Oxidation) 

SCR systems are widel

to

Germany, mercury oxidation across the SCR increased HgCl2

percent.5

Results from tests at B&W indicated that oxidized mercury increased from 50.9 to 93.4 percent in th

presence 

te

Joint pilot- and full-scale tests3

 by URS and EPRI showed a significant variation in results, sugg

that the fundamental mechanisms of mercury oxidation across the SCR

u

oxidation is highly depended on the coal type and could range from 40 to 90 percent. 

3-64 
Table 3-6. Selected SCR Test Results 

Control Unit Control Unit Status Inlet Mercury Oxidation 

(% of total) 

Outlet Mercury 

Oxidation 

(% of total) 

Pilot SCR No ammonia 8 – 12 2 – 10 

Full scale SCR Normal 10 – 18 4 – 7 

Full scale SCR No ammonia 10 – 18 50 

NH3 injection system Normal 50 – 87 67 – 85 

NH3 injection system No ammonia 50 – 87 70 – 90 

O

o impacts are expected from the natural oxidation of elemental mercury across the SCR catalyst. Of 

ourse, as mentioned in the section on wet FGD, the FGDs and SCRs themselves have O&M impacts 

sed auxiliary power and potential air preheater fouling due to ammonium bisulfate. 

ation 

f elemental mercury on the catalyst and the subsequent capture in the scrubber. SCR costs are highly 

ite-specific factors and range from about $50 to 140/kW.8

 Capital costs for wet scrubbers 

ixed O&M: 

yr (based on 1 percent of capital costs).1

et scrubber: $1.2-14/kW-yr (for a range of coal sulfur from 0.4 to about 3.5 percent). 

ir preheater 

ashes. 

-1 mill/kWh (for a range of coal sulfur from 0.4 to about 3.5 percent). 

sociated with the Technology; Future Outlook 

et FGD 

chnology. Further testing on the speciation of mercury must be conducted to gain a better understanding 

 fundamental mechanisms. As SCR and wet 

ficant 

ost Effectiveness for Utility Boilers;

CAUM Report, Boston, MA, June 1998. 

 The 

the U.S. EPA-DOE-EPRI Combined Power Plant 

&M Impacts 

N

c

including increa

Capital Costs 

No additional costs to the SCR-wet scrubber system are associated with the naturally occurring oxid

o

dependent on s

were provided in Section 3.2.1.3 and were in the range of $160-275/kW. 

O&M Costs 

F

SCR: $0.5-1.4/kWW

Variable O&M: 

SCR: 0.75-4 mills /kWh.8

 Wide range based on catalyst rate of replacement, number of a

w

Wet scrubber: 0.1

Issues As

Studying mercury oxidation has become a focus in efforts to enhance SCR, and in turn, w

te

of oxidation potential, oxidation vs catalyst age, as well as

FGD technologies are increasingly combined for NOX and SO2 reduction, this will result in a signi

and inexpensive way to also control mercury emissions. Parallel research to characterize the stability and 

fate of mercury in the FGD sludge or gypsum is ongoing. 

References 

1. Status Report on NOX Control Technologies and C

NES

2. Milobowski, M.G. Wet FGD Enhanced Mercury Control for Coal-Fired Utility Boilers.

Babcock & Wilcox Company. Proceedings of 

3-65 
Air Pollutant Control Symposium: The MEGA Symposium and The A&WMA Specialty 

Conference on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001. 

3. Richardson, C.; Machalek, T.; Miller, S.; Dene, C.; Chang, R. Effects of NO s 

on Mercury Speciation in Utility Flue Gas. Proceedings of the U.S. EPA-DOE-EPRI Combined 

, 

4. ski, G. T. How Low Can We Go? Proceedings of the U.S. EPA-DOE-EPRI Combined 

Power Plant Air Pollutant Control Symposium: The MEGA Symposium and The A&WMA 

3, 

5. , J.; Bursik, A. Impact of the State-of-the-Art of Flue Gas Cleaning on Mercury Species 

Emissions from Coal-Fired Steam Generators. Water, Air, Soil Pollut.1995, 80, 209-215. 

6. l 

Equipment in the Next Five Years. http://www.mcilvainecompany.com

X Control Processe

Power Plant Air Pollutant Control Symposium: The MEGA Symposium and The A&WMA 

Specialty Conference on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23

2001. 

Bielaw

Specialty Conference on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-2

2001. 

Fahlke

McIlvaine Company. U.S. Power Plants Will Commit $12 Billion for Air Pollution Contro

 (accessed Dec 1, 2004). 

7.

Coal Research: London, England, Aug 1995. 

8. – 2000 Update; EPRI: Palo Alto, CA, Dec 2000. 

Varying HCl Concentrations. Proceedings of the Combined Utility Air Pollutant Control 

10. oeckner, B.; 

Anderson, H.; Morris, E. Proceedings of the Combined Utility Air Pollutant Control Symposium: 

11. pson, J.; Wocken, C. Impact of 

SCR on Mercury Speciation for Coal-fired Boilers. Proceedings of the Combined Utility Air 

Sloss, L. Mercury Emissions and Effects – the Role of Coal; IEAPER/19; IEA Perspectives, IEA

Retrofit NOX Controls for Coal-Fired Boilers 

9. Bock, J.; Hocquel, M.; Hein, K. Mercury Oxidation Across SCR Catalysts of Flue Gas with 

Symposium: The MEGA Symposium, Washington, DC, May 19-21, 2003. 

Machalek, T.; Ramavajjala, M.; Richardson, M.; Richardson, C.; Dene, C.; G

The MEGA Symposium, Washington, DC, May 19-21, 2003. 

Brickett, L.; Chu, P.; Lee, C.; Srivastava, R.; Laudal, D.; Thom

Pollutant Control Symposium: The MEGA Symposium, Washington, DC, May 19-21, 2003. 

3-66 
3.2.3.4 EnviroScrub Pahlman 

EnviroScrub Summary 

Status Pilot scale 

SO2 Reduction, % >99 

NOX Reduction, % 93-97 

Hg Reduction, % Up to 67 

Cost 

Capital ($/kW) 150 for 500 MW plant 

Fixed O&M ($/kW-yr) NA 

Variable O&M (mills/kWh) 1.45 

Applicability Both new and retrofit applications 

Issues Early stage of development; demonstration and further 

assessment of the technology is needed. 

Technology Description 

EnviroScrub’s Pahlman Process is a “closed-loop” dry sorbent system comprised of two discrete steps. 

One step involves capturing the target pollutants, such as NOX, SOX, mercury and particulates, using 

Pahlmanite dry mineral sorbent compounds. The other step involves the regeneration of the spent or 

partially spent sorbent compounds for reuse and separation and isolation of useful by-products such as 

nitrates and sulfates for use in fertilizers and industrial chemicals. 

The Pahlmanite sorbents are low-density oxides of manganese (MnO2) in the form of fine black powder. 

The sorbent is injected in a reactor, which operates at temperature between ambient and 320 °F. 

According to the supplier, different type of reactors are suitable including fluidized bed, baghouse, 

transport and cyclone. SO2 and NOX react with the sorbent according to the following reactions: 

SO2 + MnO2 Æ MnSO4

2 NO2 + MnO2 Æ Mn(NO3)2

Mercury vapor reacts with the Pahlmanite sorbent, which promotes oxidation to HgO followed by 

sorption by MnO2. 

Sorbent regeneration is a wet chemical process, which involves the following steps:3

1. Reacted (“loaded”) sorbent is transported into a regeneration vessel where it comes in contact 

with a hot, oxidizing, aqueous solution, which dissolves the nitrate and sulfate salts of 

manganese. The chemical composition and operating conditions of the regeneration vessel are 

controlled so that the dissolved manganese is precipitated to form fresh sorbent; also, the 

remaining solid sorbent is re-oxidized and re-activated. 

2. The slurry consisting of nitrates and sulfates is transported from the regeneration vessel to a 

washing and filtration process, which separates the solids from the liquid fraction. The solids are 

subsequently dried and returned to the reactor for reuse. 

3. The liquid fraction is separated by membrane technology or other means into concentrated 

solutions containing sulfate, nitrate and mercury compounds. These solutions may then be 

3-67 
precipitated or evaporated to be converted to a solid form for either disposal or by-products. 

Excess water is returned to the regeneration vessel. 

4. Some of the sulfate-containing liquid from the washing and filtration system is sent to a chemical 

regeneration process to produce base and oxidizer chemical which can be used in the Pahlmanite 

sorbent regenerator. 

Commercial Readiness and Industry Experience 

The technology is in pilot scale stage; a trailer-mounted pilot plant is available which has been tested at a 

number of power plants using flue gas slipstreams (1,000 scfm): 

 Ameren Energy’s Hutsonville Power Station in Hutsonville, Illinois, which burns high-sulfur Eastern 

Bituminous coal, without the use of an emissions control system for SO2 and NOX. 

 Minnesota Power’s Boswell Energy Center located in Cohasset, Minnesota, which consists of four 

coal-fired steam boilers (total: 1000 MW) burning PRB (Powder River Basin) coal. The 

demonstration of the EnviroScrub process was conducted on the exhaust gas stream of Unit 1, a 75 

MW boiler, which currently operates without any form of back-end emission control systems for NOX

and SO2. 

 Potlatch Corp. Northwest Paper Division’s facility located in Brainerd, Minnesota. The demonstration 

of the EnviroScrub process was conducted on boiler #1, a Zurn Industries 75,000 lb/hr steam boiler, 

operating exclusively on natural gas with NOX concentration output of approximately 133 ppm.4

Emission Control Performance 

Results from Minnesota Power’s Boswell testing indicate that the technology achieved above 99 percent 

SO2 reduction and 94-97 percent NOX reduction.1

 Also, the Hutsonville facility achieved over 99 percent 

SO2 and 75 percent NOX reduction4

 on 1750 ppm SO2 and 300 ppm NOX inlet. 

According to the supplier, the technology also controls mercury and particulates (PM2.5). Testing at 

Boswell indicated mercury removal up to 67 percent.4

O&M Impacts 

O&M impacts are not known, mainly because of the lack of information. At least auxiliary power is 

expected to increase, but no specific estimates are available. 

Capital Costs 

According to the supplier, capital costs for a 500 MW plant are projected to be in $150/kW.2

O&M Costs 

Variable O&M costs are projected by the supplier to be approximately 1.45 mills/kWh.2

Issues Associated with the Technology; Future Outlook 

The technology is still at an early development stage (pilot plant) and requires further demonstration and 

techno-economic assessment to develop a more comprehensive picture of its cost-effectiveness. Also, 

removal efficiencies of mercury and particulates need to be demonstrated. 

References 

1. Interpoll Laboratories Inc. Results of the Nov 8, 2001 Air Emission Monitoring on EnviroScrub 

Technologies; Mobile Demonstration Pilot Scrubber Ducts at Minnesota Power’s Boswell Energy 

Center in Cohasset, MN; Submitted to Minnesota Power, Dec 18, 2001. 

3-68 
2. Coal Plant Achieves 99% NOX and SOX Removal with Multi-pollutant Technology. Power Eng. 

Magazine May 2002.

3. PahlmanTM Process Overview; Brochure; Enviroscrub. 

http://www.enviroscrub.com/lit/ScrubBro.pdf (accessed Dec 1, 2004). 

4. Modern Power Systems. Can Enviroscrub Clean Up in the Multi-pollutant Control Business?

Nov 2002. 

3.2.3.5 LoTOx 

LoTOx Summary 

Status Early commercial (commercial in metal industry) 

SO2 Reduction, % 95% due to the FGD which is part of the system 

NOX Reduction, % 70-95% 

Hg Reduction, % Up to 90% 

CO2 Change, % NA (1-2.5% increase due to auxiliary power requirements) 

Cost 

Capital ($/kW) $35-70/kW (for LoTOx only; not including FGD) 

Fixed O&M ($/kW-yr) NA 

Variable O&M 

(mills/kWh) NA 

Applicability Both new and retrofit applications 

Issues Further demonstration is needed at utility scale. 

Technology Description 

LoTOx is a gas phase low temperature oxidation system, which involves injection of ozone in the flue gas 

upstream of a wet FGD to oxidize NOX to higher oxides of nitrogen such as N2O5, and mercury to HgO.1-7

Subsequently these compounds are removed in a wet FGD, because they are water-soluble. As Figure 

3-88

 shows, the LoTOx system consists of an integrated ozone-from-oxygen generation unit complete 

with ozone injection system into the LoTOx. 

Ozone is injected into the reactor or directly into the exhaust duct prior to the wet FGD (if sufficient 

residence time can be provided). Ozone is produced in-situ and on demand by passing oxygen through a 

conventional industrial ozone generation system, in response to the amount of NOX present in the flue gas 

generated by the combustion or process source. Upon injection of the ozone in the flue gas (typically 

below 300 °F), oxidation occurs according to the following simplified reactions:9-12

NO + O3 → NO2 + O2

2NO2 + O3 → N2O5 + O2

Hg0 + O3 → HgO + O2

N2O5 and HgO are water soluble. In the presence of water, N2O5 forms HNO3, which further reacts with 

alkali compounds or alkaline earth metals to form corresponding nitrates: 

2HNO3 + CaCO3 → Ca(NO3)2 + CO2 + H2O 

The selection of wet FGD type (lime, limestone or ammonia) does not impact the performance of the 

LoTOx process because the solubility of N2O5 is significantly higher than that of SO2. 

3-69 
Theoretically, there is the potential for oxidation of SO2 to SO3; however, as proven in field testing, the 

reaction rates are very low compared to the predominant NOX reactions. 

Fan

Economizer

Forced Draft Fan Induced Draft Stack

Boiler

Booster

Fan

F G D

Scrubber

LoTOx

Reactor

Temperature

Control

Coldbox

Ozone

Generator

O2

Cooling Water

Vaporizer

Air Purifier Air Compressor

Liquid Oxygen

Cooling

Water

Figure 3-8. Schematic diagram of LoTOxTM system.8

Commercial Readiness and Industry Experience 

The technology has been demonstrated up to a scale of 25 MW, at boiler #4 of the Medical College of 

Ohio (MCO) capable of burning high-sulfur Ohio coal.13 Commercial experience was also gained in the 

steel industry prior to the MCO demonstration. For example: a 4,500 scfm metal pickling process and a 

natural gas-fired boiler of 8,000 scfm are on-going applications. Also, LoTOx has been installed at a lead 

recovery furnace (25,000 scfm) which is operating presently.14 LoTOx technology for NOX control is 

being considered by the refining industry to be used with wet SO2 scrubbers and a number of commercial 

installations are expected to be operating by 2005-07. Based on these developments, the supplier (BOC) 

is prepared to provide the technology for commercial use with appropriate guarantees. 

Emission Control Performance 

Up to 95 percent NOX reduction has been achieved and projected for large-scale applications. As Figure 

3.9 shows, NOX outlet levels of less than 5 ppm have been achieved. Similar NOX reductions have been 

achieved in other facilities. For example, the 4,500 scfm metal pickling application achieved 

approximately 84 percent NOX reduction from 1100 ppm inlet, while the natural gas-fired boiler of 8,000 

scfm achieved nearly 98 percent NOX reduction (4 ppm outlet NOX emissions). Finally, LoTOx at the 

lead recovery furnace averaged 80 to 95 percent NOX reduction.8,15

BOC normally recommends installation of LoTOx alone when inlet NOX is below 0.3 lb/MMBtu. Above 

0.3 lb/MMBtu, LoTOx is recommended as part of an integrated control approach operating in series with 

an alternate control process that is capable of moderate NOX removal. By combining the two 

3-70 
technologies, users may be able to avoid installing an SCR system, which is expected to have higher 

capital investment and operating costs. 

Oxidized mercury species are removed in a forced oxidation wet FGD, which is downstream of the 

LoTOx system, and removal rates depend primarily on the coal characteristics. As the Table 3-7 shows, 

LoTOx is reported to have enhanced the mercury removal of FGD for all coals, especially subbituminous 

coal and lignite.16

According to the supplier, LoTOx enhances the SO2 removal efficiency of the FGD by approximately 

5 percent (depending on the FGD design) and has no impact on SO3 emissions. 

O&M Impacts 

O&M impacts are expected to be minimal since the LoTOx technology is injecting ozone in the flue gas. 

According to the supplier, auxiliary power requirements for a 500 MW plant are projected to be 

approximately 5.0 – 12.5 MWs or 1-2.5 percent of the gross power output. 

Also, cooling water is required; which for a 500 MW plant is estimated at 4,500 gal/min and assumed 

available at 70 °F. 

Costs 

Capital costs are estimated (by the supplier) to be in the $35 to 70 per kW range depending on inlet NOX

level and unit size. 

The supplier estimates the fixed O&M costs to be approximately 2.5 percent of the capital costs. In the 

electric utility industry, annualized costs are typically $1,200-2,200 per ton of NOX removed, inclusive of 

mercury removal. 

Issues Associated with the Technology; Future Outlook 

The technology has yet to be demonstrated at a utility scale plant based on which the performance and 

cost projections could be verified. 

Table 3-7. Mercury Data for Various Coals8

Coal Type Typical Hg2+ as % 

of Total Hg 

Hg Removal with 

FGD Alone 

Hg removal with 

LoTOx and FDG 

Bituminous 70-85% 76% 94% 

Sub-Bituminous 15-45% 33% 92% 

Lignite 10-30% 19% 91% 

3-71 
Performance of LoTOx System at MCO

December 6, 2001

Outlet NOx Setpoint = 5 PPM Changed to 10 PPM

0

10

20

30

40

50

60

70

80

0:00:00

0:52:00

1:44:00

2:36:00

3:28:00

4:20:00

5:12:00

6:04:00

6:56:00

8:45:15

9:37:15

10:29:15

11:21:15

12:13:15

13:05:15

13:57:15

14:49:15

15:41:15

16:33:15

17:25:15

18:17:15

19:09:15

20:01:15

20:53:15

21:45:15

22:37:15

23:29:15

Time

NOx PPM

0

5000

10000

15000

20000

25000

30000

35000

40000

Flue Gas Flow, ACFM

60 Min Avg Inlet NOx PPM 60 Min Avg Outlet NOx PPM 60 Min Avg Flue Gas Flow ACFM

Flue Gas Temp = 179 - 234 F

Scrubber Temp = 75 - 100 F

Inlet SOx = 74 - 178 ppm

Inlet CO = 150 - 300 ppm

Figure 3-9. NOX with LoTOx at MCO’s 25 MW-thermal gas and coal fired boiler.13

References 

1. Skelley, Authur P.; et al. Process for Removing NOX and SOX from Exhaust Gas. U.S. Patent 

5,316,737, May 31, 1994. 

2. Skelley, Authur P.; et al. Process for Removing NOX and SOX from Exhaust Gas. U.S. Patent 

5,206,002, April, 27, 1993. 

3. Skelley, Authur P.; et al. Low Temperature NOX/ SOX Removal. U.S. Patent 4,999,167, May 12, 

1991. 

4. Saxena, Neeraj; et al. Removal of NOX and SOX Emissions from Pickling Lines of Metal 

Treatment. U.S. Patent 5,985,223, Nov 16, 1999. 

5. LTO System Performance Test, Alta Dena Dairy; South Coast Air Quality Management District 

Report, Feb 13, 1998. 

6. Ferrell, R. Controlling NOX Emissions: A Cooler Alternative. Pollut. Eng. April 2000. 

7. Fu, Y.; Diwekar, U. M.; Suchak, N.J. Optimization Framework for Modeling the Low 

Temperature Oxidation Process for NOX Reduction. Adv. Env. Res. 2000, 3(4), 424-438. 

3-72 
8. Jarvis, J. B.; Day, A.;T.; Suchak, N. J. LoTOxTM Process Flexibility and Multi-pollutant Control 

Capability. Proceedings of the Combined Power Plant Air Pollutant Control MEGA Symposium, 

Washington DC, May 19-22, 2003. 

9. Goss, W. L.; Lutwen, R. C.; Ferrell, R.; Suchak, N.; Hwang, S. C. A Report of the Startup of a 

Multi-Pollutant Removal System for NOX, SOX, and Particulate Control Using a Low 

Temperature Oxidation System on a 25 MW Coal Fired Boiler. Presented at Power-Gen 2001, 

Las Vegas, NV, Dec 12, 2001. 

10. Ferrell, R.; Suchak, N.; Hwang, S.C.; Tseng, J.; Kelton, R.; Goss, W.; Lutwen, R. A Report on 

the Application of Low Temperature Oxidation for Control of NOX Emissions. Presented at 

ICAC Forum 02, Houston, TX, Feb 13, 2002. 

11. Anderson, M. H. A Low Temperature Oxidation System for the Control of NOX Emissions Using 

Ozone Injection. Presented at the ICAC Forum’98, Durham, NC, March 1998. 

12. Ferrell, R.; Anderson, M.; Suchak, N.; Kelton, R.; Cuddeback, B.; Hwang, S. C. LoTOX System 

Demonstration for Coal-Fired Combustor. Presented at ICAC Forum’00, Arlington, VA, March 

2000. 

13. Goss, W. L. Multi-pollutant Control System Installation at Medical College of Ohio; Technical 

Transfer Paper; June 28, 2002. 

14. Ferrell, R.; Suchak, N.; Kelton, R.; Hine, H.; Nadkarmi, S. Application of Low Temperature 

Oxidation for NOX Emissions Control on a Lead Recovery Furnace. Presented at the Annual 

A&WMA Meeting and Exhibition, San Diego, CA, June 2003. 

15. Ferrell, R.; Anderson, M. H.; Hwang, S. C.; Suchak, N. J.; Kelton, R.; Tseng, J. T. Applications 

and Economics of Low Temperature Oxidation NOX Control. Presented at Power-Gen 2000, 

Orlando, FL, Nov 14, 2000. 

16. Ellison, W. Chemical Process Design Alternatives to Gain Simultaneous NOX Removal in 

Scrubbers. Presented at the ICAC Forum’03, Nashville, TN, Oct 2003. 

3-73 
3.2.3.6 K-Fuel 

K-Fuel Summary 

Status Components of technology commercial 

SO2 Reduction, % Up to 30% (relative to raw PRB coal or lignite) 

NOX Reduction, % Up to 45% (relative to raw PRB coal or lignite) 

Hg Reduction, % Up to 70% (relative to raw PRB coal or lignite) 

Cost Indicative prices: $20 per ton for K-Fuel vs $6.50 ton PRB, both FOB 

in Wyoming 

Capital ($/kW) NA 

Fixed O&M ($/kW-yr) NA 

Variable O&M 

(mills/kWh) NA 

Applicability 

The supplier is focusing on boilers burning subbituminous and lignite 

because the process is effective for coals with high ash and 

moisture. K-Fuel could apply to boilers burning bituminous coal too, 

but significant boiler modifications may be required as is the case of 

switching from bituminous to PRB. 

Issues 

A plant-specific evaluation is required to assess the cost 

effectiveness of a switch to K-fuel, especially when the overall 

benefit of the emission reductions is taken into consideration. 

Technology Description1

K-Fuel is a beneficiated coal that is derived from PRB coal or lignite coal. The resulting fuel is lower in 

ash, higher in Btu value and produces lower pollutant emissions than untreated western subbituminous or 

PRB coals. K-Fuel uses a pre-combustion process that improves the quality of the coal – including 

removing the mercury, moisture, ash, sulfur, and some of the fuel NOX precursors – before the coal is 

burned at the power plant. Because these constituents are removed prior to burning the coal at the plant, 

the need for post-combustion controls may therefore be reduced. Technology may be applicable to 

bituminous coal. However, the supplier has focused exclusively on PRB and lignite applications, because 

the K-Fuel is a moisture and ash reduction process, which PRB and lignites are high in. 

The K-Fuel pre-combustion multi-pollutant reduction technology (PMR) is a two-step process, illustrated 

in Figure 3-10. 

1. Physical Separation: A gravity separation process – either wet or dry – is used to remove ash 

along with other pollutants (sulfur and mercury). This involves crushing and screening to remove 

the larger particles. Also, high-energy magnetic separation can be used, especially for coals with 

a higher percentage of fine particles. The processed coal is then passed on to an intermediary 

storage facility prior to being sent to the next step of the process. Wastes from physical cleaning 

are returned to the coal mine. 

2. Thermal Processing, which follows, employs Lurgi Mark IV vessels operating under high 

temperature and pressure (460 °F and 485 psi). Mineral matter of the coal under thermal stress 

fractures in these vessels liberating moisture, as well as sulfur and mercury. Figure 3-11 shows 

the main components of the thermal processing unit. 

The water and mercury vapors are condensed, and mercury is captured in a carbon-bed adsorption reactor. 

Water is recycled in the process. Mercury-laced activated carbon is disposed in a toxic landfill. 

3-74 
Figure 3-10. K-Fuel PMR technology. 

Figure 3-11. K-Fuel thermal separation unit. 

3-75 
Commercial Readiness and Industry Experience 

The components of the PMR process are proven commercially. Physical cleaning is a well-proven 

technology and thermal separation is used worldwide, with Lurgi having approximately 160 thermal 

separation units in operation. In the U.S., thermal processing has been used since 1984.2

 The first 

commercial plant, 700,000 tons per year, is expected to be completed by the middle of 2004. 

The K-Fuel has been tested in smaller scale facilities and a commercial plant, including Southern 

Research Institute (SRI) and at American Electric Power’s (AEP) Clifty Creek Station in Indiana. 

Emission Control Performance 

According to KFx, the developer of K-Fuel, physical separation studies on a number of low rank coals, 

exhibited ash reduction in the 10-30 percent range, 10-36 percent sulfur reduction, and 28-66 percent 

mercury reduction. Thermal separation adds more mercury reduction; for example, testing by Rio Tinto 

Technical Services in Perth, Australia showed a 40 percent reduction3

 in fuel mercury due to thermal 

separation alone. Total mercury reduction at the Energy & Environmental Research Laboratory of the 

University of North Dakota4

 and the Western Research Institute5 were reportedly 66-67 percent. Also, 

NOX reduction up to 46 percent has been experienced in tests at Southern Research Institute6

 and 40 

percent at AEP’s Clifty Creek Station. All emission reductions are relative to similar type raw coal (PRB 

or lignite). 

Finally, reduced moisture in the coal is expected to improve boiler efficiency. For a typical Wyoming 

coal, moisture is reduced from 20-30 percent to approximately 6 percent. Such a change may improve 

boiler efficiency by up to 2.0 percent. 

O&M Impacts 

Most O&M impacts are expected to be positive including reduced auxiliary power and O&M costs 

associated with the coal handling equipment, pulverizers, particulate collection, and ash handling 

equipment. Also, less ash reduces transportation and disposal costs. Finally, more consistent coal quality 

with lower ash would have a positive impact on plant reliability. However, there is inadequate 

information to quantify such impacts. 

While the supplier is targeting mainly boilers burning PRB coal or lignites for this technology, K-Fuel 

could be used in boilers designed for bituminous coal, too. However, in the case of bituminous coal, the 

O&M impacts could be significant including lower steam temperatures, higher unburned carbon, slagging 

and potential de-rating (reduced output). Such impacts could be eliminated through boiler modifications, 

but some investment would be required. 

Costs 

It is envisioned that the coal produced by the PMR process will be sold to the power plants rather than the 

power plants having to set-up their own PMR process facility; if so, the price of the processed coal is the 

important parameter. Presently, there is no adequate information to estimate the price of the processed 

coal, but it would need to reflect the costs of selective mining, capital and operating costs of all 

components (physical and thermal separations and carbon bed absorber for mercury removal) and 

disposal costs of mercury and other wastes. Also, the price will have to be competitive with other coal; in 

other words, the price for K-Fuel may be based on the price of competing coal on heating value basis plus 

credits for environmental benefits (lower SO2, NOX and Hg reductions). Preliminary estimates suggest 

that K-Fuel may be available in the $20-25 per ton range FOB Wyoming. Presently, this compares to raw 

Wyoming coal of $6.50 per ton FOB Wyoming. However, the K-Fuel may also compete against Eastern 

bituminous coal. 

3-76 
Issues Associated with the Technology; Future Outlook 

The technology is suitable mainly for western coals. Also, not adequate information is available to assess 

its cost-effectiveness. With the operation of the Black Thunder plant by mid-2004 more information is 

expected to become available. 

References 

1. Black & Veatch. Effective Mercury Reduction Strategy for Western Coal/K-Fuel Technology; 

Report to the U.S. EPA, March 2003. 

2. Ness, M. Improving Power Plant Performance and Reducing Emissions through Coal 

Beneficiation. Presented at the Energy Generation Conference, Bismarck, ND, Jan, 2002. 

3. Davies, M. Technical Report – Revised K-Fuel Process; Rio Tinto Technical Services: Perth, 

Nov 30, 2000. 

4. Gunderson, J. R. Combustion testing of K-Fuel for Heartland Fuels; Energy & Environmental 

Research Center, Nov, 1993; 59. 

5. Vesperman, K. Utility SO2 Compliance with a Long-range Forecast. Presented at the Low-rank 

Fuels Symposium, St. Louis, MO, May 10-13, 1993. 

6. Monroe, L. S. Testing K-Fuel Synthetic Coal In The Southern Research and Southern Company 

Combustion Research Facility; Southern Research Institute, Aug 1998. 

7. Janssen, K. E. Lignite-to-gas Plant Reveals Numerous Innovations. Power May/June 1997, 

79-82. 

8. Alderman, J. K. Western Coal Preparation – Meeting the Demands for Clean Energy. Coal Age 

March 2003, 107 (3), 24-30. 

3-77 
3.2.4 Advanced Power Generation Technology Options 

3.2.4.1 Circulating Fluidized Bed Technology 

Circulating Fluidized-bed Technology Summary 

Status Commercial up to 250 MW 

SO2 Reduction, % >95 

NOX Reduction, % 30 – 70 depending on the coal [90 with SNCR (ammonia or 

urea)] 

Hg Reduction, % NA 

CO2 Change, % Negligible 

Cost 

Capital ($/kW) 850 – 1100 (for a new CFB plant In the 100 – 250 MW 

range) 

Fixed O&M ($/kW-yr) 30 – 37 

Variable O&M (mills/kWh) 2.0 – 5.5 

Applicability 

Mainly new power plants; also for replacement of old boilers 

while utilizing the existing turbine and balance of plant 

(BOP) 

Issues Successful scale-up to 400 – 600 MW while maintaining its 

cost-effectiveness and emission performance 

Note: Emission reduction is based on comparison of this technology to a similar size subcritical 

pulverized coal boiler with low NOX burners, but without FGD.

Technology Description 

Circulating Fluidized Bed (CFB) combustion technology is one of the two variations of Atmospheric 

Fluidized Bed Combustion (AFBC), the other one being the bubbling AFBC. CFB has been the 

predominant design used in coal-fired power applications, especially in large-scale plants above 100 MW. 

Bubbling AFBC is used too, but the most recent plants are small, 10-50 MW, burning biomass and 

municipal solid wastes. CFB technology is described in this section because of its applicability for large 

power applications. 

 

CFB boilers (see Figure 3-12) are very similar to conventional PC boilers in many respects. The majority 

of boiler components are similar, and hence manufacturing of the furnace and the back-pass can be done 

in existing manufacturing facilities. In addition, a CFB boiler utilizes the Rankine steam cycle with steam 

temperatures and pressures similar to PC boilers. CFB boilers can be designed for either subcritical or 

supercritical conditions. Most CFB boilers utilized so far are of the subcritical type mainly because the 

technology has been utilized in sizes up to 250 MW where subcritical operation is more cost-effective. As 

the technology is scaled up (above 400-500 MW), the supercritical design may be used depending on the 

site-specific environmental requirements or cost of fuel. 

3-78 
Figure 3-12. CFB process schematic. 

The difference of CFB relative to PC boiler stems from the lower operating temperature and the injection 

of limestone in the furnace to capture SO2 emissions. Typical maximum furnace temperature in a CFB 

boiler are in the 1500-1600 °F (820–870 °C) range, while conventional PC boilers operate at 2200-2700 

°F (1200–1500 °C). This low combustion temperature limits the formation of NOX and is the optimum 

temperature range for in-situ capture of SO2. The injected limestone is converted to lime, a portion of 

which reacts with SO2 to form calcium sulfate (CaSO4), a dry solid, which is removed in the particulate 

collection equipment (either ESP or FF). A cyclone is located between the furnace and the convection 

pass to capture unreacted lime and limestone present in the flue gases exiting the furnace. The solids 

collected in the cyclone are recirculated back to the furnace to improve the overall limestone utilization. 

Limestone injection can remove from 90 to >95 percent of the sulfur in the coal1

 eliminating the need for 

flue gas desulfurization (FGD) downstream of the boiler. CFBs have NOX emissions 60-70 percent lower 

than conventional PC boilers with low NOX burners 

CFB boilers can efficiently burn low reactivity and low-grade fuels, which may not be burned in 

conventional PCs. Such fuels include anthracite, coal cleaning wastes, and industrial and municipal solid 

wastes. High-ash fuels, such as lignite, are particularly suitable for CFB technology. 

3-79 
Commercial Readiness and Industry Experience 

Commercial applications of this technology exist in sizes up to 265 MW net (~300 MW gross) unit size, 

as demonstrated by hundreds of boilers operating throughout the world (Australia, China, Czech 

Republic, Finland, France, Germany, India, Japan, Poland, South Korea, Sweden, Thailand, and United 

States). Vendors are now offering boiler sizes for plants well over 300 MW in sizes. Foster Wheeler has 

signed a contract to supply a 460 MW boiler with super-critical steam conditions at the Lagisza plant in 

Poland.3

 This plant is scheduled to be started up by the end of 2005. In 1996, EPRI estimated that there 

are approximately 300 CFB units (larger than 22 tons/hr of steam capacity each) in operation worldwide. 

Since then (1996), the number of CFB operating units has increased further. Experience from these units 

has confirmed performance and emissions targets, high reliability, and the ability to burn a variety of low 

quality fuels. 

The most recent CFB projects on a scale larger than 200 MW are shown in Table 3-8. 

Table 3-8. CFB Units larger than 200 MW 

Company, 

Plant Name Location Supplier Net MW 

Startup Fuel Type 

EDF, 

Gardanne 

Provence, 

France Stein (Lurgi) 232 1996 Subbituminous Coal (30% ash/4% S) 

Turow Power 

Co., Turow 

Station 

Silesia, 

Poland 

Foster 

Wheeler 2 x 230 1999 Brown Coal (23% ash/44% H2O/0.6% S) 

KEPCO, 

Kangwon-do 

Kangwon-do, 

South Korea 

KHI and 

ABB-CE 2X200 1998 Korean Anthracite 

AES, 

Warrior Run 

Warrior Run, 

Maryland, USA 

ABB-CE and 

Lurgi 2 x 200 1999 Bituminous Coal 

JEA, 

Jacksonville 

Jacksonville, 

Florida, USA 

Foster 

Wheeler 265 2002 Bituminous Coal, Petroleum Coke 

Sithe/Tractabel 

Red Hills 

Red Hills, 

Mississippi, USA Alstom (Stein) 2 x 220 2001 Lignite 

Emission Control Performance 

CFBs have demonstrated that they can remove up to 90 - 95 percent1

 of the sulfur in the coal without the 

need for flue gas desulfurization (FGD) downstream of the boiler. SO2 removal is affected mainly by the 

bed temperature and by the Ca-to-S molar ratio. The bed temperature is designed for optimum sulfur 

capture [1500-1600 °F (820 - 870 °C)]. Ca-to-S molar ratio depends on the amount of CaO and MgO in 

the ash, as well as their reactivity. A Ca-to-S molar ratio of 2.0 - 2.5 is typical for 90 - 95 percent SO2

removal. 

NOX emissions are 30 - 70 percent lower than conventional PCs with low NOX burners;1

 CFB boilers 

have achieved consistently 0.12-0.16 lbs/MMBtu NOX emissions, compared to pulverized coal plants 

which range from 0.2 to 0.5 lbs/MMBtu. Further NOX reduction can be achieved by installing an SNCR 

(ammonia or urea) injection system in the CFB furnace. NOX emissions in the 100 ppm level without 

ammonia or urea injection and below 20 ppm (0.027 lbs/MMBtu) with ammonia or urea injection have 

been demonstrated.1

 NOX emissions are impacted by the bed temperature, the nitrogen and volatile matter 

in the coal, and the bed stoichiometry. Stoichiometry, defined as a ratio of available air (weight) to 

theoretical air needed for complete combustion, is affected by the excess air and air distribution across the 

3-80 
bed. The amount of ammonia or urea being injected (in case such system is available) also impacts the 

additional NOX removed as a result of such an injection. 

It is not clear whether CFB controls mercury, too. CFB plant efficiency is similar to new subcritical 

pulverized coal plants equipped with NOX and SO2 controls, typically 34-38 percent (higher heat value 

basis). Therefore, no significant CO2 reduction is expected. Supercritical CFBs will have higher 

efficiency (38-40 percent) and proportionally lower CO2 emissions. 

O&M Impacts 

None. 

Capital Costs 

Capital costs of large CFB plants (between 150 and 250 MW) range from $850 to 1100/kW, similar to or 

slightly above the costs of pulverized coal plants with FGD, which range from $800 to 1000/kW.1

O&M Costs 

O&M costs are projected to be $30-37/kW-yr for fixed O&M and 2.0-5.5 mills/kWh for variable O&M 

costs depending on the O&M practices of the utility, labor costs, and cost of consumables (especially 

sorbent).1

Issues Associated with the Technology; Future Outlook 

The main barrier to widespread utilization of the technology is scale-up to larger sizes (present focus on 

400 - 500 MW) while maintaining its cost-effectiveness and emission control performance. This barrier is 

expected to be overcome in the next 2-3 years as indicated by a number of studies and demonstration 

projects being planned.2

 One such effort is led by Electricite de France (EdF), which sponsored a study to 

develop a 600 MW CFB design. Participating in this study are Alstom and Foster Wheeler, two of the 

leading CFB vendors. 

Presently, CFBs are being built worldwide, especially for solid fuels difficult to burn in a pulverized coal 

boiler such as anthracite, lignite, brown coal, and coal wastes. Also, industrial and municipal solid wastes, 

petroleum coke, and other waste fuels are being burned in most cases as supplemental fuels. CFB 

technology is expected to be used widely in the future, mainly in new power plant applications. 

References 

1. Tavoulareas, S. Financing Clean Coal Technologies; World Bank: Washington, DC, July 2001. 

2. Dyr, R. A.; Hebb, J. L.; Darling, S. L. The JEA CFB Demonstration Project: An Update. 

Presented at the PowerGen-Europe, Helsinki, Finland, June 20-22, 2000. 

3. Foster Wheeler Website – News Release 3/7/2003. http://www.fwc.com/ (accessed Dec 1, 2004). 

3-81 
3.2.4.2 Integrated Gasification Combined Cycle 

Integrated Gasification Combined Cycle Summary 

Status Entrained and moving beds: commercial up to 500 MW; 

fluidized bed: in demonstration stage 

SO2 Reduction, % Up to 99 

NOX Reduction, % 80-90 (compared to PC with low NOX burners) 

Hg Reduction, % Needs characterization via measurements 

CO2 Change, % 10 to 20% potential reduction over a comparablysized PC plant with FGD 

Cost 

Capital ($/kW) 1200 – 1600 (for new plant of 400 MW size) 

Fixed O&M ($/kW-yr) 30 – 45 

Variable O&M (mills/kWh) 0.5 – 2.0 

Applicability New power plants or retrofits utilizing existing plant steam 

turbine-generators and balance of plant equipment 

Issues 

High costs are the main barrier to widespread utilization of 

entrained and moving bed IGCC. Fluidized bed IGCC 

requires demonstration. 

Technology Description 

The integrated gasification combined cycle (IGCC) involves gasification of coal with either oxygen or air, 

with the resulting syngas (an abbreviation for synthetic gas) cooled, cleaned, and fired in a gas turbine. 

The hot exhaust from the gas turbine passes to a heat recovery steam generator (HRSG) where it produces 

steam that drives a steam turbine.1,2 Power is produced from both the gas and steam turbines; hence, 

combined cycle (CC). 

The gasification plant could be designed to operate under atmospheric or pressurized conditions. 

Pressurized gasification is preferred to avoid large auxiliary power losses for compression of the syngas, 

which is required in an atmospheric IGCC, before the gas enters the gas turbine. Pressurized gasification 

also reduces the size of the gasifier. Most gasification processes currently in use or planned for IGCC 

applications are oxygen blown; however, the Piñon Pine Plant in the U.S. uses an air-blown fluid bed 

process [developed by Kellogg Rust Westinghouse (KRW)]. 

The electric output of an IGCC plant is mainly determined by the firing temperature of the gas turbine 

[typically: 1100 °C (2000 °F) or 1260 °C (2300 °F) for standard designs offered commercially] and by the 

frequency of the electricity produced. Typical net output for single-train IGCC plants is approximately 

275 MW for 60-Hz markets and 400 MW for 50-Hz markets. Plant net efficiency is typically 40 – 44 

percent on a higher heating value (HHV) basis. Utilization of the new gas turbines (G- and H-class) 

would increase the overall plant efficiency to 46 – 48 percent (HHV basis) with an output of 400-450 

MW (in 60-Hz markets) and 500 - 550 MW in 50-Hz markets. 

The IGCC design varies, especially in the degree of integration. For example, some IGCC plants such as 

the Buggenum (Netherlands) and Puertollano (Spain) are highly integrated designs with all the air for the 

air separation unit being taken as a bleed from the gas turbine compressor. In contrast, the U.S. plants at 

Tampa and Wabash River are less integrated, and the air separation units have their own separate air 

compressors. The more highly integrated design has higher plant efficiency, but lower plant availability 

and operating flexibility. Presently, the general consensus among IGCC plant designers is to have the air 

3-82 
separation unit derive part of its air supply from the gas turbine compressor and the remainder from a 

separate dedicated compressor. 

Commercial Readiness and Industry Experience 

In general, IGCC technology has been demonstrated up to 500 MW in size and offered commercially, but 

higher costs (relative to the conventional PC with FGD) limit its widespread utilization. Presently, there 

are six coal-based IGCC demonstration plants in operation (three in the U.S and three in Europe) with 

three more IGCC plants utilizing refinery wastes in Italy. Table 3-9 shows these plants, as well as the first 

IGCC demonstration, Cool Water IGCC in Barstow, CA, which operated from 1984 to 1989. 

In addition, there are approximately 160 gasification facilities in 28 countries being utilized by the 

petrochemical industry. These are mainly gasifiers using heavy oil, petroleum bottoms, or petroleum 

coke. While this experience is not directly applicable to coal-fired IGCCs, it is clearly helpful because 

some of the technical problems and operating issues have been addressed. 

Table 3-9. Commercial-Size IGCC Power Plants 

Project name and location Gasification 

Technology 

 MW 

(gross) Startup Date 

Cool Water, Mojave, CA, US Texaco 120 1984 

SEP-Demkolec, Buggenum, 

The Netherlands Shell 253 1994 

Wabash River, West Terre Haute, IN, US Destec 296 1995 

Tampa Electric, FL, US Texaco 312 1996 

Sierra Pacific Piñon Pine, NV, US KRW fluid bed 107 1998 

ELCOGAS, Puertollano, Spain Krupp-Uhde Prenflo 335 1997 

Schwartze Pumpe, Schwartze Pumpe, Germany Lurgi moving bed 75 1999 

ISAB Energy, Sicily, Italy Texaco 512 2001 

Sarlux, Sardinia, Italy Texaco 548 2000 

API Energia, Falconara, Italy Texaco 280 2001 

Note: Above gasifiers are of entrained type, unless otherwise indicated. 

Samples of additional projects in the planning stage include: 

 Vresova, Czech Republic: 385 MW lignite-firing; upgrading of existing facility and increase of plant 

output; 

 Port Arthur, TX: 6,985 tonnes/day (7,700 U.S. ton/day) petroleum coke gasification plant; and 

 Citgo’s refinery at Lake Charles in Louisiana: 670- MW IGCC utilizing petroleum coke. 

Actual efficiencies of IGCC plants have been measured in the 38-43.2 percent range (HHV-basis), mainly 

because their operation was designed in a conservative way to demonstrate the reliability of the 

technology and its ability to reduce acid rain pollutants rather than to achieve the highest efficiency. 

Utilization of parts of existing plants in IGCC repowering cases also contributed to keeping the efficiency 

on the low side. For example, the Wabash River IGCC repowering project achieved 39.7 percent 

efficiency (this was 20 percent higher than the plant’s efficiency prior to repowering). Similarly, the 

Tampa (Polk) IGCC plant achieved 38 percent3

 while Puertollano IGCC plant achieved 43.2 percent 

efficiency.4

3-83 
Three types of gasification processes are available: moving-bed, fluidized-bed, and entrained-bed, each of 

them at a different stage of development. 

Entrained-flow gasifiers operate at high temperatures (between 1300 and 1500 °C) where the ash is 

melted and removed from the bottom of the gasifier as slag. This type of gasification is suitable for lowash coals (less then 10 – 15 percent ash) and is the most widely used IGCC process. The main suppliers 

are: Texaco (Tampa and Cool Water plants in the U.S., and three refinery waste IGCC plants in Italy) and 

Destec (Wabash plant in the U.S.) offering coal-water-slurry-fed processes, and Shell (Buggenum, 

Netherlands), Krupp-Uhde (Puertollano, Spain), GSP (Schwarze Pumpe, Germany), and Mitsubishi 

(Nakoso, Japan) offering a dry-coal-fed process. 

In moving-bed dry ash gasifiers, steam is injected along with the oxygen to keep the coal ash well below 

its ash fusion temperature. This type of gasifier is offered mainly by Lurgi and has been used in many 

countries including China, the Czech Republic, Germany, South Africa, and the United States. Also, a 

slagging version of the Lurgi gasifier has been developed, and a commercial-sized unit based on this 

technology has been commissioned at Schwarze Pumpe in Germany.

Fluidized-bed gasification, which is more suitable for high-ash coals, is still in the demonstration stage. A 

number of small atmospheric-pressure Winkler gasifiers have been built in Germany, India, and Turkey. 

Also, the U-Gas gasifier developed by the Institute of Gas Technology (IGT) in the U.S. is utilized in the 

Shanghai Coking and Chemical plant in China. A high-temperature Winkler gasifier has been developed 

by Rheinbraun and used in Germany and Finland for methanol and ammonia manufacture. The same 

process is expected to be used in the Vresova IGCC plant in the Czech Republic. Presently, the largest 

plant is the 100- MW Piñon Pine in Reno, NV, utilizing the KRW fluid-bed process, but it is experiencing 

operating problems and is still in an extended commissioned program. 

Emission Control Performance 

By removing the emission-forming constituents (sulfur and nitrogen species and particulates) prior to 

combustion in the gas turbine, IGCC plants meet extremely stringent air emission standards. Sulfur 

emissions can be almost completely eliminated; SO2 emissions are expected to be 0.03-0.1 lb/MMBtu, 

(40-115 mg/Nm3

 at 6 percent O2). NOX emissions have been controlled to levels below 0.1 lb/MMBtu 

(125 mg/Nm3

 at 6 percent O2) at two of the demonstrations using steam or nitrogen dilution in the 

combustor and to half that level at two other sites operating at lower combustion turbine temperatures. 

Recently, General Electric (GE) has claimed that they can meet a NOX level of 60 mg/Nm3

 even with 

their 2300 °F (1260 °C) series FA gas turbine. Typical CO2 emissions will be 12 – 15 percent lower than 

a comparably-sized PC plant with FGD, with further reduction possible with the utilization of the higher 

efficiency (G- and H-class) gas turbines. There are indications that IGCC plants equipped with carbon bed 

adsorption systems may be able to achieve 90 percent mercury removal.5

Emissions are affected mainly by the requirements of the gas turbine to maintain low particulates and SO2

emissions. NOX emissions are affected by the design of the gas turbine combustor and the environmental 

requirements of the plant site; most gas turbines utilize a dry low NOX combustor design and have 

achieved NOX emissions below 25 ppm(v) with the most recent turbine designs targeting below 10 

ppm(v).6

 Assuming 25 ppm NOX emissions, this results in 80-90 percent reduction compared to 

pulverized coal boilers with low NOX burners which experience 0.20-0.50 lbs/MMBtu. 

Limited data available (mainly from Wabash River, Polk, and the Louisiana IGCC plants) suggest that 

mercury emissions at the stack are similar to pulverized coal-fired plants, ranging from 1.5 to 5 lb/trillion 

Btu. While the mass balance closure in these plants was not good, there is good evidence that mercury is 

removed by the amine solvent, accumulates in the acid gas scrubbing loop, or is stripped from the amine 

3-84 
solvent upon regeneration and partitions to the sulfur recovery unit. Some mercury, especially particulatephase and oxidized forms, may be removed in the wet particulate scrubber and discharged with 

wastewater sludge. More testing is required to assess the level of mercury emissions from IGCC plants. It 

is also important to find out the fate of the mercury in IGCC wastes. 

By-products of IGCC include production of elemental sulfur (usually in a Claus process) or sulfuric acid, 

as well as solid wastes in the form of inert slag, which can be disposed of or sold for a variety of 

construction applications. 

O&M Impacts 

The presence of toxic gases (CO and H2S) between the gasifier and the gas turbine requires some 

additional precautions. However, such precautions are common in other industries and can be addressed 

by installing CO and H2S sensors and appropriate design of the control system to manage plant start-up 

and especially transition from the start-up fuel to coal or coal-based syngas. Plant availability continues to 

be an issue especially during early start-up of most IGCC plants, as they experience operating problems. 

However, after the commissioning period, most IGCC plants have achieved high reliability (in the 75 – 

95 percent range). 

Capital Costs 

While significant progress has been made in reducing the capital costs of IGCC plants, they remain more 

expensive than conventional PC with FGD. The typical range of IGCC capital costs of a 400 MW plant is 

$1200 - 1600/kW1

 with the lower end of the range corresponding to IGCC plants with a minimum level of 

integration and, therefore, lower efficiency and the high end for maximum integration. The capital costs 

are projected to decline, as the industry gains more experience with IGCC technology and technological 

developments are incorporated (especially in higher efficiency gas turbines and hot gas clean-up 

technologies), but the timing and impact of these developments are uncertain. 

O&M Costs 

For a 400 MW IGCC, fixed O&M costs are projected to be in the $30-45/kW-yr range. Variable O&M 

costs depend on whether some revenue can be obtained from by-product sales. Assuming no sales of byproducts, the variable O&M costs are projected to be in the 0.5 - 2.0 mills/kWh range.1

Issues Associated with the Technology; Future Outlook 

For the entrained and moving bed IGCC processes, the main barrier to widespread utilization is the high 

capital costs relative to competing technologies. However, it should be pointed out that IGCC has much 

lower SO2, NOX, and CO2 emissions than the conventional (subcritical) PC with FGD; furthermore, 

because they are more efficient, they have lower fuel costs. The fluidized-bed gasification process 

requires further development and demonstration. It has yet to demonstrate adequate reliability on a large 

scale (above 100 MW). The future of IGCC technology depends on the ability of the industry to reduce its 

costs and the environmental requirements associated with SO2, NOX, mercury, and CO2 emissions.7

References 

1. Tavoulareas, S. Financing Clean Coal Technologies; World Bank: Washington, DC, July 2001. 

2. Technology Assessment of Clean Coal Technologies for China. Electric Power Production;

World Bank ESMAP and AESEG Technical Paper 011, May 2001. 

3. Ratafia-Brown, J. A.; Manfredo, L. M.; Hoffmann, J. W.; Rameza, M. An Environmental 

Assessment of IGCC Power Systems. Presented at the 19th Annual Pittsburgh Coal Conference, 

Pittsburgh, PA, Sept 2002. 

3-85 
4. Study on Clean Coal IGCC Technology for China; TA No. 2792 PRC; Asian Development Bank, 

Sept 1998. 

5. Klett, M. G.; Rutkowski, M. D. The Cost of Mercury Removal in an IGCC Plant; U.S. 

Department of Energy, National Energy Technology Laboratory: Pittsburgh, PA, Jan 2001. 

6. First H System Gas Turbine Planned for Baglan. Modern Power Systems May 1999, 37-42. 

7. Todd, D. IGCC Experience and Technology Improvements Spreading to Other Process/Power 

Plants; General Electric, July 1999. 

3.2.4.3 Pressurized Fluidized Bed Combustion (PFBC) 

PFBC Summary 

Status Commercially available up to 350 MW 

SO2 Reduction, % Up to 98 

NOX Reduction, % 30 – 70 depending on the coal [90 with SNCR (ammonia or 

urea)] 

Hg Reduction, % NA 

CO2 Change, % Reduction up to 12 

Cost 

Capital ($/kW) 1000 – 1300 (for new plants of 250 MW size) 

Fixed O&M ($/kW-yr) 40 – 70 

Variable O&M (mills/kWh) 2.0 – 4.0 

Applicability Mostly new power plants– also applicable to retrofit 

applications 

Issues 

Some reliability problems and high costs (relative to 

conventional PC and FGD) limit its short-term acceptance. 

Also, scaling-up the technology to larger size (above 350 

MW) has experience problems which are not clear how they 

will be overcome 

Note: Emission reduction is based on comparison of this technology to a similar size subcritical 

pulverized coal boiler with low NOX burners but without FGD. 

Technology Description 

Pressurized Fluidized-bed Combustion (PFBC) is similar to AFBC in that it utilizes the fluidized bed 

technology, but the PFBC boiler operates under pressure (typically 1.2–1.6 MPa).1,2 Also, it is a combined 

cycle plant (see Figure 3-13), as pressurized hot flue gas, after particulate removal, is expanded through a 

gas turbine (GT) to drive the combustion air compressor and generate additional electric power. 

The main advantages of PFBC are: 

 pressurized conditions result in a more compact boiler and therefore offers the potential to lower 

capital costs, 

 utilization of the combined cycle concept increases the overall plant efficiency and will take 

advantage of future technological progress in gas turbine technology, and 

 PFBC is able to accomplish sulfur removal at somewhat lower sorbent (Ca-to-S ratio) than AFBC. 

3-86 
As in the case of AFBC, there are two types of PFBCs, the bubbling and circulating. Also, an “advanced 

PFBC” design has been developed with a pyrolyzer added upstream of the PFBC combustor. The fuel gas 

generated in the pyrolyzer is burned with the flue gas from the main combustor in a topping cycle to raise 

the turbine inlet gas temperature and increase the power output and efficiency of the turbine. The char 

from the pyrolyzer is burned in the main combustor. Sorbent is added to both the pyrolyzer and the main 

combustor. The successful development of hot gas cleanup (HGCU) technology using ceramic particle 

filters and alkali vapor removal is crucial to protecting the gas turbine and the successful demonstration of 

advanced PFBC. 

Steam

PFBC

HRSG ParticulateCollector

Water

Coal &

Sorbent

Steam Water

To Stack

AC

Air

GT

Cyclone

∼

Figure 3-13. PFBC conceptual design. 

Commercial Readiness and Industry Experience 

The technology is offered commercially up to 350 MW3,4 but there are a number of technical issues still 

unresolved (see Issues below). As shown in Table 3-10,1

 six commercial-scale bubbling PFBC units (five 

plants, one with two units) have been put into service around the world. Most of these boilers are 

demonstration units, with financial support from government or international agencies, and all but one are 

less than 100 MW. A 360- MW supercritical unit (based on the ABB technology) and a 250- MW 

subcritical unit (based on the Hitachi technology) have been constructed in Japan at Karita for Kyushu 

Electric Power Company (KyEPCO) and at Osaki for Chugoku Electric, respectively. Both were 

commissioned in mid-2000. The operating experience obtained from these units will have a strong 

influence on the future of commercial PFBC technology. 

3-87 
Ishikawajima-Harima Heavy Industries (IHI), which recently obtained a worldwide license from ABB, 

Mitsubishi Heavy Industries (MHI), and Hitachi Ltd., are the main suppliers of bubbling PFBC. Five of 

the six operating PFBC units listed in Table 3-10 are based on ABB’s P 200 PFBC module, designed for 

about 80 MW. The sixth unit, an 85- MW module designed by MHI, started up in early 1996. 

The Karita PFBC plant, a 360- MW PFBC, replaces an old, conventional coal-fired power plant. It 

consists of one novel ABB P 800 module with a GT140P 75- MW gas turbine and a 290- MW steam 

turbine. The boiler is designed for supercritical steam conditions of 24.1 MPa/565 °C/593 °C. A wide 

range of coal qualities, from lignite to anthracite, will be used at this plant, and the fuel and sulfur sorbent 

mixture will be fed as paste. The order for the plant was placed with ABB Carbon’s licensee, IHI, which 

has undertaken the engineering, manufacturing, erection, and commissioning of the plant. The GT140P 

turbine was supplied by ABB STAL and the steam turbine was supplied by Toshiba. 

Table 3-10. PFBC Plants and Operating Experience 

Technology ABB ABB ABB ABB MHI 

Facility Name Escatron, 

Spain Vartan, Sweden Tidd, USA Wakamatsu, Japan 

Tomatoh-Atsuma, 

Japan 

Gross Output, MW 79 135 plus 

224 MW 73 71 85 

Units 1 2 1 1 1 

Coal Type Lignite Polish 

Bituminous 

Ohio 

Bituminous Australian Various 

Coal Sulfur, % 7 0.65 4 0.4 0.9 

Coal Ash, % 36 15 10 10 Not Available 

Coal Feed Dry Paste Paste Paste Dry 

Sorbent Feed Dry Paste Dry or Paste Paste Dry 

Sorbent Limestone Dolomite or 

Limestone Dolomite Limestone Limestone 

NOX Control None SNCR and SCR None SCR SCR 

Cyclones 9 x 2 7 x 2 7 x 2 7 x 1 2 x 1 

Hot Filter 1/9 

Slipstream None 1/7 Slipstream Full Gas Flow (part time) Full Gas Flow 

Steam Pressure, bar 90 130 90 102 166 

Steam Temperature, 

°C 510 530 496 593/593 566/538 

Lurgi Lentjes Babcock (LLB, the Lurgi-Deutsche Babcock partnership) and Foster Wheeler (now 

incorporating Ahlstrom Pyropower) have been developing circulating PFBC. To date, development has 

been mainly on a pilot plant scale. However, a 137 MW circulating PFBC plant is under construction at 

the McIntosh plant of the City of Lakeland, FL. 

PFBC technology is applicable for both retrofit (replacement of an existing boiler and utilization of the 

remaining equipment, especially the steam turbine and balance of plant) and new applications. However, 

most PFBC projects in the future are expected to be new applications. 

3-88 
Emission Control Performance 

SO2 removal up to 98 percent is possible, especially with high-sulfur coals. SO2 removal is affected by the 

bed temperature and by the Ca-to-S molar ratio. A Ca-to-S molar ratio of approximately 1.5 is typical for 

an SO2 removal of 90 – 95 percent. The excess sorbent is not calcined. While this increases the volume of 

solid wastes compared to an AFBC with the same Ca-to-S molar ratio, PFBC requires a lower Ca-to-S 

molar ratio, which counterbalances this disadvantage and results in about the same waste volume 

compared to an AFBC. Furthermore, the absence of lime makes the solid wastes easier to handle. 

NOX emissions are 30 – 70 percent lower than conventional PCs with low NOX burners. Further NOX

reduction can be achieved by installing an SNCR or SCR system. NOX emissions in the 100 ppm (0.13 

lbs/MMBtu) level without SNCR have been demonstrated. NOX emissions are impacted by the bed 

temperature, the nitrogen and volatile matter in the coal, and the bed stoichiometry, which is affected by 

the excess air and air distribution across the bed. 

It is not clear whether PFBC controls mercury, too. 

Typical PFBC design plant efficiency ranges from 38 to 46 percent (HHV basis) depending on the coal 

type, coal feed method, and steam cycle conditions. Compared to new subcritical pulverized coal plants, 

which typically have efficiency in the range of 34 to 38 percent, PFBC can potentially result (as these 

efficiencies indicate) in up to 10 - 12 percent lower CO2 emissions. 

O&M Impacts 

Reliability problems have been experienced by the most recent demonstration plants, but eventually have 

been resolved. For example, Vartan and Wakamatsu reached the 80-90 percent reliability level, but others 

had lower reliability. The impact of small particulates and alkali on the gas turbine was one of the issues. 

ABB is offering a “ruggedized” gas turbine design, which is expected to improve reliability. The 

properties of the ash are critical in determining the potential impacts on the various PFBC plant 

components. 

Capital Costs 

Typical costs of` PFBC plants are expected to be in the $1000 - 1300/kW range.1

O&M Costs 

O&M costs are projected to be: $40 - 70/kW-yr fixed O&M cost and 2.0 - 4.0 mills/kWh variable O&M 

cost1

 depending on the O&M practices of the utility, labor costs, and cost of consumables (especially 

sorbent). The high estimates are more typical of the 80 MW PFBC, while the lower estimates are for the 

350 MW design. 

Issues Associated with the Technology; Future Outlook 

The PFBC plants in operation experienced a number of problems but, for the most part, they have been 

satisfactorily addressed. However, some uncertainty still remains in the following areas: 

 Coal feed. Wet feed systems need proper size distribution and a better indicator of proper 

consistency; dry feed systems need designs that address erosion in transport pipes at high pressure 

and redundant systems for high availability. 

 Gas turbine lifetime. High-cycle fatigue damage and erosion are on-going problems being addressed 

by the suppliers. 

 Gas filter performance. Development continues on thermal shock–resistant ceramic candle filters. 

Development of this component is critical for achieving higher plant efficiencies and the wider 

acceptance of the technology. 

3-89 
 Coal and sorbent distribution in the bed. Fuel and sorbent distribution need to be optimized to achieve 

maximum sorbent utilization and uniform bed temperatures. 

 Cyclone liner life. Proper application of select materials or unlined austenitic stainless steel cyclones 

may resolve this issue. 

In conclusion, PFBC technology has been demonstrated and is commercially available up to a 350 MW 

plant size, but higher than conventional technology costs limit its widespread utilization, at least in the 

short term. 

References 

1. Tavoulareas, S. Financing Clean Coal Technologies; World Bank: Washington, DC, July 2001. 

2. Technology Assessment of Clean Coal Technologies for China. Electric Power Production;

World Bank ESMAP and AESEG Technical Paper 011, May 2001. 

3. Jansson, S.; Anderson, J. Progress of ABB’s PFBC Projects. Presented at the 15th FBC 

Conference, Savannah, GA, May 1999. 

4. Anderson, J.; Anderson, L. Technical and Commercial Trends in PFBC. Presented at the PowerGen Europe, Frankfurt, Germany, June 1999. 

3.2.4.4 Supercritical Pulverized Coal Plant 

Supercritical Pulverized Coal Plant Summary 

Status Supercritical: commercial; ultra- supercritical: needs 

demonstration 

SO2 Reduction, % 4 – 12 

NOX Reduction, % 4 – 12 

Hg Reduction, % 4 – 12 

CO2 Change, % 4 – 12 reduction 

Cost 

Capital ($/kW) Supercritical: 825 – 1080; Ultra-supercritical: 1000 – 1150 

(for 700 – 1000 MW plant size) 

Fixed O&M ($/kW-yr) Supercritical: 25 – 32; Ultra-supercritical: 30 – 35 

Variable O&M (mills/kWh) 3.0 – 5.0 

Applicability New power plants 

Issues Ultra-supercritical requires further demonstration 

Note: Emission reduction is based on comparison of this technology to a similar size subcritical 

pulverized coal boiler with low NOX burners, but without FGD. 

Technology Description 

Supercritical pulverized coal technology is similar to subcritical in terms of the conceptual plant design, 

but may operate at higher steam temperatures and higher pressures.1

 Subcritical plants operate below 

approximately 18 MPa (2600 psi) maximum steam pressure, while supercritical plants are designed to 

operate from 23 to 35 MPa (3200 to 5000 psi). Also, supercritical plants can be designed to operate at 

3-90 
steam temperatures (superheat and reheat) up to 650 °C (1200 °F) compared to 538 °C (1000 °F), which 

is the typical temperature in subcritical plants. 

Typical pulverized plant designs used presently and their steam parameters are given below: 

1. Subcritical: 16.7 MPa/538 °C/538 °C (2400 psi/1000 °F/1000 °F); 

2. Supercritical: 24.2 MPa/538 °C/565 °C (3500 psi/1000 °F/1050 °F), which is about 4.0 percent 

more efficient than the subcritical; and 

3. Ultra-supercritical with double reheat: 31 MPa/600 °C/600 °C/600 °C (4500 psi/1100 °F/1100 

°F/1100 °F), which is about 8 percent more efficient than the subcritical design; or 35 MPa/650 

°C/650 °C/650 °C (3500 psi/1200 °F/1200 °F), which would produce an efficiency gain of about 

11 percent relative to the subcritical unit. Both these options are under development. 

The high steam pressures and temperatures require higher grade materials for the furnace water walls, 

superheat and reheat sections of the boiler, headers, steam piping between boiler and turbine, and first 

stages of the superheat and reheat sections of the turbine. Availability of materials such as 11⁄4Cr-1⁄2Mo, 

21⁄4Cr-1Mo, and 9–12 percent Cr class steels (T91 and T23) are critical for designing and manufacturing 

supercritical plants. In addition to materials, water chemistry (corrosion protection) and power plant 

controls are some of the most important aspects of supercritical plant design and operation. However, 

appropriate design and O&M practices have proven adequate to ensure reliable operation. 

Commercial Readiness and Industry Experience 

Supercritical plants are commercially available in many countries including China, Denmark, Germany, 

Italy, Japan, Russia, South Korea, and the United States.1,2,3 The ultra-supercritical unit is in the 

demonstration stage. Supercritical pulverized coal technology is commercial with approximately 462 

units operating worldwide (see Table 3-11). There are at least 12 boiler manufacturers and 11 steam 

turbine suppliers that offer supercritical plant components. 

Table 3-11. Power Plants with Supercritical Design Parameters4

Country or Region Number of Units Total Units (%) Capacity, MW Total Capacity (%) 

Japan 108 23.4 67,900 25.2 

USA 149 32.3 106,454 39.6 

West European Countries 53 11.5 29,310 10.9 

East European Countries 123 26.5 51,810 19.3 

Other Countries 29 6.3 13,520 5.0 

Total 462 100.0 268,994 100.0 

The U.S. has the largest number of supercritical plants in operation, but all these plants were installed in 

the 1960s and 1970s. In recent years, no supercritical plants have been built in the U.S. This is mainly 

attributable to the perception that supercritical plants have lower reliability and the relatively low costs of 

fuels in the U.S., which make low-cost but also low efficiency options (in this case subcritical PC) 

economically more attractive. Indeed, there were some reliability problems experienced by the first 

supercritical plants built in the U.S., but, as Table 3-12 shows, the reliability (expressed as equivalent 

availability) of these plants improved significantly to the same level of subcritical plants. Similar 

experience is documented by VGB in Germany.4

3-91 
Table 3-12. Equivalent Availability for Subcritical and Supercritical Power Plants4

U.S. Supercritical Plants 

Size Range ( MW) 300-399 400-499 500-599 600-799 >800 

Subcritical 76.5 77.4 76.3 78.5 77.2 

Supercritical 64.4 74.6 73.8 74.2 75.6 

Germany’s Supercritical Plants 

Year 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 

Subcritical 84.2 82.5 84.1 84.9 84.5 82.0 83.8 83.7 86.6 88.5 

Supercritical 80.2 74.9 84.2 85.2 87.1 89.8 83.0 84.7 79.5 90.3 

Japan is one of the countries leading the development of supercritical technology. Until the early 1990s, 

most Japanese plants had steam conditions of 3500 psi/1000 °F/1050 °F (24.6 MPa/538 °C/566 °C), but 

starting in 1993 the steam temperatures of new plants are in the ultra-supercritical range, approaching 

1100 °F (600 °C). 

Also, there are about 53 supercritical units in Europe, especially in Germany, Italy (mostly oil fired), and 

Denmark. The most recent European units (most of them coal-fired with one oil-biomass unit) utilize 

ultra-supercritical steam conditions. 

Korea has built sixteen 500 MW supercritical units utilizing a standardized design for bituminous coal.5

Also, China has ten supercritical units in operation and 10 more in the planning stage. 

Emission Control Performance 

This technology is not an environmental control technology per se, but due to its higher efficiency it 

results in lower emissions prior to utilizing environmental controls such as SCR and FGD. The 

supercritical design improves plant efficiency by 4.0 percent relative to a similar subcritical plant. 

If the ultra-supercritical design is used with double reheat, the efficiency increases by about 8 percent 

relative to a similar subcritical plant. Further potential exists (projected to increase efficiency by 10 - 12 

percent) utilizing higher steam conditions, such as 35 MPa/650 °C/650 °C/650 °C (3500 psi/1200 °F/1200 

°F), but this technology remains to be demonstrated. 

O&M Impacts 

There are no significant O&M impacts relative to subcritical PC technology. Supercritical PC requires 

more attention to water chemistry (requirements are tighter than for subcritical plants) and operation, 

especially during start-up and load following. However, power plant controls can be designed to include 

all the precautions and safeguards needed for safe and reliable operation. 

Capital Costs 

Many recent studies1,6 have estimated the costs of supercritical vs subcritical PC technologies. The 

general consensus is that the capital costs of a supercritical plant are equal to or up to 8 percent higher 

than a similar size subcritical plant. So, considering that the latter is projected to cost $800 - 1000/kW, the 

3-92 
supercritical unit is projected to cost $825 - 1080/kW and the ultra- supercritical unit $1000 - 1150/kW 

(in all cases, the PC is equipped with FGD, but not SCR).1,6

Is should be noted also that supercritical plants are usually competitive in large sizes, above 500 MW. 

However, recently power plant suppliers have been developing smaller supercritical plants (in the 350 - 

500 MW range) to address cases with high cost fuels and limited demand growth.1

O&M Costs 

Fixed O&M costs range from $25 to 32/kW-yr for supercritical units and $30 to 35/kW-yr for ultrasupercritical units. Variable O&M costs range from 3 to 5 mills/kWh.1

Issues Associated with the Technology; Future Outlook 

The supercritical PC technology is commercially available, and there are no issues associated with it. As 

more emphasis is placed on CO2 emission reduction, it provides a proven technology (therefore low-risk 

option) to achieve significant plant efficiency improvement relative to conventional (subcritical) 

pulverized coal plants. An ultra-supercritical unit requires further demonstration, mainly to prove the 

reliability of new alloy materials. 

References 

1. Tavoulareas, S. Financing Clean Coal Technologies; World Bank: Washington, DC, July 2001. 

2. Torrens, I. M.; Stenzel, W. C. Increasing the Efficiency of Coal-fired Power Generation/State of 

the Technology: Reality and Perceptions; International Energy Agency/CIAB: London, England, 

March 1997. 

3. Slettehaugh, R. A.; Dittus, M. H.; Voss, R. A. Lignite Power Generation in North Dakota- Cost, 

Performance, and Emissions of Viable Technologies. Presented at the PowerGen Conference, 

Orlando, FL, Nov 14-16, 2000. 

4. Supercritical Power Plants/Evaluation of Design Parameters (March 17, 1999). http://www. 

worldbank.org/html/fpd/em/supercritical/ppt_supercritical (accessed Dec 1, 2004). 

5. Yoo, K. J.; Kim, M. H.; Moskal, J. J. Standardization in the Design and Construction of 500 MW 

Coal-fired Power Plants in the Republic of Korea. Presented at the Powergen Americas, Orlando, 

FL, Dec 1996. 

6. Sormani, G. F.; Monti, M. A.; Maffei, E. Comparison Between Cost of Electricity Generated 

from Coal by Ultra-supercritical Steam Plants and IGCC. Presented at the Powergen Americas, 

Orlando, FL, Dec 1996. 

3-93 
3.2.5 Power Plant Upgrading and Operating Options 

3.2.5.1 Fuel Blending and Cofiring 

Fuel Blending and Cofiring Summary 

Status Commercial except for fuel blending requiring on-line 

continuous control of emissions 

SO2 Reduction Proportional to sulfur content of fuels; up to 100% reduction 

for switching from high- to low-sulfur coal or gas 

NOX Reduction 

Up to 20 – 30% due to switching from bituminous to 

subbituminous coal or biomass cofiring. 50 – 80% due to 

gas cofiring and reburn or switching from coal to gas 

Hg Reduction Proportional to mercury content of fuels, as well as other 

fuel properties 

Cost 

Capital ($/kW) Coal blending: 20 – 100; Fuel switching: Up to 200 – 300; 

Cofiring: 30 – 200 

Fixed O&M ($/kW-yr) Project-specific 

Variable O&M (mills/kWh) Project-specific 

Applicability Both new and retrofit applications 

Issues Development of on-line coal quality monitoring is needed to 

enhance coal blending 

Technology Description 

The ability to alter the fuel characteristics has a significant impact on both the thermal performance of the 

unit and the resulting emissions of SO2, NOX, Hg, and CO2. Table 3-14 lists the key fuel properties, which 

affect emissions. Therefore, altering the characteristics of the fuel by blending or cofiring could be 

viewed as a multi-emission control option. 

While the feasibility and attractiveness of changing the fuel characteristics are very site-specific (affected 

significantly by plant design and fuel properties), in general the following options are available while 

maintaining the basic configuration and design of the plant: 

 Blending with a fuel of the same type with different properties (blending coal of the same 

classification such as two eastern bituminous coals) or different classifications (eastern bituminous 

coal with subbituminous coal), 

 Switching to a fuel of the same type; for example, switching from eastern bituminous to 

subbituminous coal, 

 Switching to a fuel of different type; for example, switching from coal to natural gas, and 

 Cofiring coal with fuels such as gas, biomass, and municipal solid wastes. 

Blending and cofiring generally constitute operating changes (even though originally some hardware 

modifications may be necessary or required to mitigate O&M impacts), while switching to another fuel is 

a permanent change (at least until the decision is reversed) and includes hardware modifications. 

Blending coals is very common in the utility industry worldwide with the primary focus being control of 

sulfur content.1-5 The plant operator either mixes the coals in the coal yard or loads the coal silos partly 

with the one coal and then with the other with mixing occurring inside the silo. In some cases, blending 

3-94 
has been accomplished by mixing coals from two different conveyors on to a common one. The ability to 

monitor and control coal quality (beyond just sulfur) is very limited. Monitoring is based on periodic 

sampling of the coal and rough estimation of the average quality characteristics (mainly sulfur content), as 

well as SO2 measurements using continuous emission monitors. Blending could be used to affect 

emissions other than SO2 (NOX and mercury). However, the exact coal quality resulting from such 

blending cannot be predicted; only an approximation of the average is possible with present technologies. 

More detailed fine-tuning of the coal analysis through blending needs on-line coal quality monitoring 

technologies, which are still under development. 

Switching to another coal (from bituminous to subbituminous) is a common practice in the industry 

(again, mainly for sulfur control) and usually involves hardware changes. Such changes are very sitespecific, but common areas, which are impacted by coal switching, are: 

 Upgrading the coal crushing equipment and the pulverizers to avoid potential de-rating of the unit due 

to limited coal throughput into boilers, 

 Modifying the heating surface of the boiler (superheater and reheat sections) to maintain the steam 

outlet temperatures over the load range without exceeding operating limitations set by materials 

(maximum metal temperatures or gas velocities to avoid excessive erosion), 

 Replacing or modifying the soot blowing system to accommodate higher slagging or fouling, 

 Incorporation of a flue gas conditioning system to modify the resistivity of the sub-bituminous, lowsulfur coal ash and make it suitable for collection in an existing precipitator originally designed for 

high-sulfur coal ash, 

 Modification of the ash handling system to handle quick-setting characteristics of sub-bituminous 

coal ash, and 

 Modification of the coal storage and conveying systems to meet the special handling characteristics of 

sub-bituminous coal. 

On the positive side, coal switching may provide an opportunity to improve performance (plant 

efficiency) or at least minimize the adverse impacts on efficiency. For example, modifications in the 

economizer, air heater, and feed water heaters may increase plant efficiency or mitigate boiler efficiency 

reduction due to higher moisture of the new coal. 

Switching from coal to a different fuel type such as natural gas is also possible. Hardware modifications 

may be required depending on the design of the existing plant. The types of changes required are as 

follows: 

 The plant needs to be connected to a natural gas pipeline, in case gas is not available on site, 

 The burners need to be modified to accommodate natural gas, 

 The boiler heating surfaces may need to be modified to maintain proper steam conditions, and 

 Boiler backend modifications may be required, depending on whether the plant elects to dismantle the 

existing pollution controls, bypass these controls and leave them in place, or continue to pass flue 

gases through the non-operating controls. 

Cofiring involves utilization of more than one fuel, which represents a relatively small percentage 

(usually 5 - 15 percent) of the total heat input.6,7 Typically, fuels which have been cofired with coal are: 

natural gas, biomass, and municipal solid wastes (MSW).8,9 Depending mainly on the physical properties 

of the secondary fuel, it may be introduced in the boiler through a separate burner or injection port or 

mixed with the coal. Solid fuels may be pulverized together with the coal, but this limits the amount of 

3-95 
cofired fuel to about 5 percent. In most case, separate injection ports are added. Cyclones and fluidized 

bed boilers are better cofiring candidates than pulverized coal boilers, even though the latter have 

demonstrated adequate performance and reliability. Cofiring natural gas requires separate burners or ports 

within the existing coal burners.10

Commercial Readiness and Industry Experience 

Fuel switching and cofiring are commercial options that have been used extensively worldwide both for 

new plants and retrofit applications. Coal blending is also a common practice. In cases, where the average 

coal quality needs to be adjusted to an approximate level or below a set level, coal blending is a welldemonstrated option. However, if on-line continuous monitoring and control of coal quality is needed, 

presently there is no available technology except monitoring of sulfur content. On-line coal quality 

monitoring technologies are under demonstration and have not achieved the level of reliability needed for 

widespread application. 

Emission Control Performance 

Blending of coals or switching to another coal clearly impacts all emissions, even though the impact at 

each plant is very site-specific and depends on the characteristics of the coals, the design of the power 

plant, and the operating conditions. Switching from a high-sulfur (4 - 5 percent sulfur content) coal to a 

low-sulfur (0.5 - 0.8 percent sulfur content) coal reduces the SO2 emissions up to 80 - 90 percent. The 

impact of coal blending on SO2 would be lower than this level and proportional to the percent of the lowsulfur coal being used. Switching from bituminous to subbituminous coal or blending also reduces NOX

emissions by up to 20-50 percent as demonstrated in a number of well-documented utility sites such as 

Arapahoe 4 of Public Service of Colorado,5

 Genoa 3 of Dairyland, and Gibson 3 of PSI Energy.2 Coal 

switching and blending is expected to have an impact on mercury emissions as each coal contains a 

different level of mercury. Also, changes in chlorine content resulting from coal blending may affect the 

speciation of mercury. Additonally, the ash composition and unburned carbon content may play a 

catalytic role affecting mercury speciation. Presently, no adequate data exist to predict such impact. 

Finally, coal switching and blending are expected to affect plant efficiency and CO2 emissions mainly 

because of different moisture content of the coals, but also because of potentially different auxiliary 

power requirements. For illustration purposes, if the moisture content of the coal changes (as a result of 

switching or blending) from 8 to 20 percent, the impact is an approximately 1.2 percent lower boiler 

efficiency, which corresponds to approximately a 3 percent or higher increase of CO2. 

Switching from coal to another fuel has more drastic consequences to the performance and emissions. The 

most common fuel switch is from coal to natural gas provided that the economics are favorable. In this 

case, SO2 and mercury emissions may be eliminated. NOX emissions could be reduced by up to 70 - 80 

percent. Finally, CO2 is reduced by approximately 30 percent as a result of switching from coal to natural 

gas fuel. Boiler efficiency for natural gas is usually 2-3 percentage points lower than bituminous coal. 

Due to the high percentage of hydrogen in the natural gas, the CO2 emission per fuel input is 200 

lb/MMBtu for coal and 130 lb/MMBtu for natural gas based strictly on fuel carbon conversion. 

The impact of cofiring on emissions is very site specific and depends on the characteristics of the fuels 

being cofired, the plant design, and the design of the cofiring system. Cofiring of gas in a coal-fired plant 

reduces SO2 and mercury proportionally to its input (typically up to 30 percent), NOX up to 50 - 70 

percent, and CO2 by up to 7 percent (assuming maximum heat input due to natural gas of 20 percent).11-14

The characteristics of biomass and MSW vary significantly, but in general they are expected to reduce 

SO2 and CO2 proportionally to their inputs, and NOX by up to 20 percent. It should be noted that these 

fuels are considered renewable energy sources, so any substitution of coal results in a proportional 

reduction of CO2 emissions. However, some of the fuels contain a significant amount of moisture (wood 

wastes and wet MSW may contain 40 - 60 percent moisture), which reduces the plant efficiency and may 

counterbalance the benefit of using a renewable energy resource. 

3-96 
O&M Impacts 

Changes in the fuel characteristics may have significant impacts on unit performance and reliability. 

Table 3-14 summarizes the main impacts of unfavorable changes in the values of the key fuel 

characteristics, as well as potential mitigation options. 

In general, load reduction (de-rating) may be necessary to avoid high steam and metal temperatures or to 

accommodate lower steam temperatures at the steam turbine inlet. Also, load may be limited by the 

capacity of the existing fuel handling system pulverizers, or other boiler-related systems. In most cases, 

these impacts can be mitigated by modifying the boiler and other effected equipment. Other potential 

impacts include: 

 Changes in the unburned carbon. This can be mitigated by design enhancements of the pulverizers 

(addition of dynamic classifiers) and the firing system (new burners). 

 Increase or reduction of furnace slagging and fouling. In most cases, this can be mitigated through 

increased soot blowing, but in some cases de-rating may be needed. 

 Depending on the fuel characteristics, pulverizer wear and reliability, as well as corrosion and erosion 

of boiler heating surfaces, may be affected. The impact of blending coals of different hardness on the 

final size distribution and compositional distribution of the pulverized coal is still not fully 

understood. Blending hard and soft coals may cause difficulties in pulverizing the blend, as the 

grinding requirements may not always be proportional to the mix of the two coals. In most cases, the 

characteristics of the poor coal dominate the blend. 

 Very often fuel changes impact the performance of the ESP and may result in higher particulate 

emissions and opacity. If the ESP size is conservative, it may not require any modifications. 

However, many older plants represent tight designs and may need to be modified to meet particulate 

emissions and opacity requirements. 

 Reliability and operating flexibility may be impacted, usually adversely because biomass and MSW 

are difficult fuels to handle. Also, some coals may be harder to grind (pulverize) or more corrosive. 

Of course, natural gas is easier to handle and would be expected to improve plant reliability and 

operating flexibility. 

 Other impacts requiring consideration on a case-by-case basis include potential changes in the 

required excess air (which impacts plant efficiency), CO emissions, and unit turndown rate (speed at 

which the operator can change unit output). 

3-97 
Table 3-14. Main O&M Impacts and Potential Mitigations 

Impact on Emissions Coal Property SO2 NOX Hg CO2

Potential Plant Equipment 

and O&M Impacts Potential Mitigation 

Coal Type X X X X 

Potential de-rating, lower 

reliability, and lower 

efficiency 

De-rating may be avoided through 

hardware modifications, especially 

in the mills and boiler heating 

surfaces 

% Sulfur X ESP performance and FGD 

system performance 

ESP upgrading or SO3 flue gas 

conditioning and upgrading of the 

FGD system or increased reagent 

use 

% Ash X 

ESP performance, ash 

handling system impacts, 

and erosion of mills and 

boiler surfaces 

ESP upgrading, upgrading or more 

frequent operation of the ash 

handling system and more active 

maintenance of mills and boiler 

surfaces 

Ash fusion 

temperature X Furnace slagging and backpass fouling Sootblowing and fuel additives 

% Nitrogen X 

Design or operation of NOX controls 

for the increased baseline 

emissions 

Volatile Matter X Potential impact on boiler 

heating surface performance 

Design or operation of NOX controls 

for the increased baseline 

emissions and boiler heating 

surface modification 

% Moisture X X X X 

Mill throughput, boiler 

efficiency, primary air 

system performance, and 

increased combustion air 

and flue gas volumes 

Mill and primary air system 

upgrading, design or operation of 

pollution controls for the increased 

baseline emissions, and operation 

of draft fans at higher capacities 

% Mercury X Depends on whether mercury 

controls would be present 

% CaO or MgO X Increased reagent use, if SO2

controls are present 

Grindability X Mill throughput Mill upgrading 

Costs 

The costs, both capital and O&M, are very site specific. The following estimates are for illustration 

purposes only. 

Coal blending is the least expensive option with regard to costs, which may range from $20 to 100/kW 

depending on the amount of cofired coal, its characteristics, and the design of the existing power plant. 

Switching to another fuel is usually more expensive and may reach up to $200 - 300/kW. Cofiring capital 

costs may range from $30 to 200/kW. More specific examples6

 (End of Year 1991 U.S.$; however, 

capital costs of power plant equipment have been reduced significantly since then and it is expected that 

the same costs reflect FY2000 conditions): 

 Wood cofiring: $104/kW, 

 Refuse Derived Fuel cofiring: $128/kW, and 

 Tire-derived fuel cofiring: $37/kW. 

3-98 
Issues Associated with the Technology; Future Outlook 

Fuel blending, switching, and cofiring are common industry practices and are expected to continue. In the 

past, the main driving force has been economics, but they have a role to play in emission control too, as 

emissions become commodities and emission control becomes an operating cost. The key technological 

barrier, especially with regard to coal blending, is the absence of reliable and commercially available online continuous coal quality monitors. However, if only a not-very-accurate control of emissions is 

required, all options are practical and commercially available. 

Depending on site-specific constraints, not all options may be available to all power plants. Such 

constraints may include: lack of natural gas in the proximity of the plant, very high transportation and 

processing costs for biomass and waste fuels, and constraining power plant design with tight fuel 

specification requirements (cyclone and wet bottom boilers). 

References 

1. In Effects of Coal Quality on Power Plants; Proceedings of 5th International Conference, Kansas 

City, MO, May 20-22, 1997; EPRI TR-109340, Nov 1997. 

2. Guidelines for Evaluating the Impact of Powder River Basin (PRB) Coal Blends on Power Plant 

Performance and Emissions;EPRI TR-106340; EPRI: Palo Alto, CA, March 1996. 

3. Kambara, S.; Takarada, T.; Yamamoto, Y.; Kato, K. Relation Between Functional Forms of Coal 

Nitrogen and Formation of NOX Precursors During Rapid Pyrolysis. Energy Fuels 1993, 7 (6), 

1013-1020. 

4. Technology Assessment for Blending Western and Eastern Coals for SO2 Compliance; EPRI 

TR-105748; EPRI: Palo Alto, CA, May 1996. 

5. Smith, R. A. Arapahoe 4/Powder River Basin Coal Test Burn; U.S. DOE report: Washington, 

DC, April 1996. 

6. Strategic Analysis of Biomass and Waste Fuels for Electric Power Generation; EPRI TR-102773; 

EPRI: Palo Alto, CA, Dec 1993. 

7. Costello, R. Biomass Cofiring Offers Cleaner Future for Coal Plants. Power Eng. 1999, 45. 

8. Kouvo, P.; Korelin, T.; Savola, T. Mercury Emissions and Removal During Cofiring of Coal, 

Wood and Wastes. Proceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant 

Control Symposium: The MEGA Symposium and The A&WMA Specialty Conference on 

Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001. 

9. Davidson, R. Experience of Cofiring Waste with Coal; International Energy Agency/Coal 

Research Center: London, England, Nov 1998. 

10. Pratapas, J. M.; Stenzil, W.; Mazurek, J. The Natural Gas Cofiring/Reburning Module for 

Pulverized Coal Fired Plant Evaluations and Planning. Presented at the American Power 

Conference, Chicago, IL, April 9-11, 1996. 

11. Morrison, G. Cofiring of Coal and Waste – an International Perspective. Presented at the 

Powergen Conference, Orlando, FL, Dec 1996. 

3-99 
12. Guidelines for Cofiring Refuse-derived Fuel in Electric Utility Boilers; EPRI RP-1861; EPRI, 

March 1998. 

13. Hecklinger, R. S.; Rehm, F. R. Coal Refuse-derived Fuel Cofiring Project, Milwaukee County, 

Wisconsin; EPA/600/2-85/136 (NTIS PB86-135381); U.S. EPA, Hazardous Waste Engineering 

Research Laboratory: Cincinnati, OH, Nov 1985. 

14. Proceedings: Municipal Solid Waste as a Utility Fuel; EPRI CS-4900-SR: Palo Alto, CA, Nov 

1986. 

3.2.5.2 Plant Efficiency Improvements (Upgrading, Newer Configurations, Technologies) 

Plant Efficiency Improvements Summary 

Status Commercial 

SO2 Reduction 

Heat rate improvement and upgrading: SO2 reduction 

proportional to heat rate improvement; Repowering with 

gas: close to 100% SO2 reduction 

NOX Reduction 

Heat rate improvement and upgrading: NOX reduction 

proportional to heat rate improvement; Repowering with gas: 

up to 70 – 80% NOX reduction 

Hg Reduction 

Heat rate improvement and upgrading: Hg reduction 

proportional to heat rate improvement; Repowering with 

natural gas: 100% Hg reduction 

CO2 Change 

Heat rate improvement: Up to 1.5% reduction at full load (up 

to 5% at low loads); Upgrading: up to 8% reduction; 

Repowering with natural gas: up to 50% reduction 

Cost 

Capital ($/kW) Heat rate improvement: <20 – 40; Upgrading: 20 – 50; 

Repowering with natural gas: 100 – 400 

Fixed O&M ($/kW-yr) Project-specific 

Variable O&M (mills/kWh) Project-specific 

Applicability Retrofit applications 

Issues Impact of environmental regulations pertaining to increased 

output of existing plants 

Technology Description 

Upgrading and efficiency improvement in a power plant are geared towards increasing the plant output or 

achieving higher efficiency. In the latter case, the same output can be produced utilizing less fuel and, in 

most cases, proportionally less emissions. Most options affecting plant output and efficiency are 

interrelated, but for simplicity they will be described separately in this document, grouped into three 

categories: (1) efficiency improvement, (2) plant upgrading and (3) power plant repowering. The third 

option involves significant changes in the plant design, usually by adding a gas turbine and converting the 

plant to a combined cycle. 

Efficiency Improvements

Efficiency improvements can be achieved by both operating changes and minor hardware modifications,1

such as: 

3-100 
 adjustment and tuning of the pulverizer to improve coal fineness for better combustion efficiency, 

resulting in lower CO and unburned carbon, 

 reduction in excess air; this is accomplished by closer monitoring of excess air (usually by installing a 

CO monitor in the stack), combustion system tuning (adjustments of air registers and coal-air flow 

balancing), and pulverizer tuning, 

 reduction in air leakage into the boiler, air heater, and pollution control equipment, 

 reduction in water and steam leaks in valves and piping of the balance of plant, and 

 cleaning of heating surfaces such as the boiler water walls, superheat and reheat sections, as well as 

the condenser and the feed water heaters to improve heat transfer. 

Power Plant Upgrading

Usually upgrading is geared towards increased plant output,2,3 or increased plant remaining life, but 

invariably it improves plant efficiency, too. Examples of measures included in this category are: 

 pulverizer upgrades including a dynamic classifier and increased capacity of the exhaust fans, 

 replacement of the economizer or the air heater, resulting in lower stack temperature and better plant 

efficiency; this is usually a desirable option when the plant switches from high-sulfur to low-sulfur 

coal (either by coal switching or blending) and can afford to lower the stack temperature without 

concern about corrosion in the backend equipment due to condensation of sulfuric acid, 

 replacement of steam turbine blades with new blades (usually improved three-dimensional profile) 

taking advantage of technological improvements in blade design and materials; this applies to all 

sections of the steam turbine (high, intermediate, and low pressure), but especially in the high 

pressure section where the economics are more favorable and more technological improvements have 

been made,4-6

 more efficient modifications of feed water heaters and addition of low-pressure preheating,7

 refurbishment of condenser with new and more efficient tubes (with regard to heat transfer), heating 

surface cleaning systems, and design modifications to reduce air in-leakage, 

 installation of variable-speed drives on the main rotating equipment (forced- and induced-draft fans, 

boiler-feed pumps, and circulating water pumps) to reduce the plant auxiliary power consumption, 

and 

 replacement of outdated controls with a state-of-the-art digital control system to improve overall plant 

operation and efficiency. 

Power Plant Repowering

The general principle followed in repowering an existing coal-fired power plant is to add a gas turbine 

and associated equipment and convert it to a combined cycle plant burning natural gas. There are a 

number of alternative approaches to repowering (full repowering, topping or windbox repowering, and 

parallel repowering),8-12 but they differ only by the degree to which the existing equipment is used. 

Topping or windbox repowering involves use of the flue gas from a new gas turbine as hot combustion air 

into the burners of the existing boiler and may increase plant output up to 40 percent. Parallel repowering8

utilizes the existing boiler as a heat recovery device for the flue gas of the gas turbine, but because the 

resulting outlet steam temperatures are lower, a new heat recovery steam generator is needed to ensure 

that the plant output is maintained. Full repowering utilizes mainly the existing steam turbine and balance 

of plant along with a new gas turbine and associated equipment to form a combined cycle. Power output 

of the plant may increase up to 200 percent as a result of full repowering. 

3-101 
Commercial Readiness and Industry Experience 

All these options are commercially available, and the industry (both the utilities and the boiler vendors) 

has significant experience with such projects. 

Emission Control Performance 

In the case of heat rate improvement and upgrading, reduction of SO2, NOX, mercury, and CO2 is 

proportional to the heat rate improvement achieved. There are some exceptions where the change may not 

be exactly proportional, but it is not significantly different. An example of such cases is the reduction of 

excess air, which benefits plant efficiency, but may benefit NOX emissions more than indicated by the 

proportional change. 

Heat rate improvements may result in up to 1.5 percent heat rate improvement at full load and up to 5 

percent at low loads. Upgrading projects may achieve higher efficiency than heat rate improvements, but 

they are very site-specific. 

In the case of repowering, there is a change in fuel from coal to natural gas, which results in significant 

changes in the emissions. In general, topping or windbox repowering improves plant heat rate by 5 – 10 

percent. Full repowering may increase the plant efficiency of an old coal-fired power plant (in most cases: 

28 – 34 percent efficient on an HHV-basis) to 45 – 50 percent. CO2 reduction is achieved due to better 

heat rate if less fuel is burned and the fact that natural gas releases less CO2 per unit heat input than coal. 

The end result from a repowering project may reach up to 50 percent CO2 reduction, with parallel 

elimination of SO2 and mercury. 

O&M Impacts 

Upgrading and repowering projects do not have significant adverse O&M impacts. In fact, the changes in 

plant design and operation are usually beneficial to both performance and reliability of the plant. There 

are cases, however, with heat rate improvements where a trade-off between emissions and heat rate may 

be involved. For example, an attempt to reduce NOX emissions as much as possible through aggressive 

combustion staging (high overfire air flow rate) and low excess air, may affect heat rate adversely due to 

lower steam temperatures, high CO emissions, and high unburned carbon. 

Costs 

Costs of heat rate improvements are typically low, below $20-40/kW. Upgrading and repowering costs 

are very site-specific, but they are typically in the following ranges: 

 $20 - 50/kW for upgrading and 

 $100 - 400/kW for repowering.12

Issues Associated with the Technology; Future Outlook 

Repowering applications depend greatly on the availability of a reliable source of gas supply at a 

candidate plant location and cost differential between coal and gas. Considering that gas prices continue 

to be significantly above those of coal for most locations in the U.S., the attractiveness of repowering 

options is limited. Another reason is the significant reduction of prices of new natural gas combined cycle 

power plants (ranging from $400 to 550/kW), which can achieve higher performance than repowered 

plants. However, if emission requirements are imposed on existing power plants, the cost-effectiveness of 

repowering will likely improve. The main issue associated with heat rate improvements and plant 

upgrading relates to environmental requirements, which may apply in case the plant increases its output 

even marginally. 

3-102 
References 

1. Heat Rate Improvement Guidelines for Existing Fossil Plants; EPRI CS-4554; EPRI: Palo Alto, 

CA, May 1986. 

2. MacDonald, J. Upgrading Older Power Plants to Improve Their Competitiveness. Gas Turbine 

World March-April 2001. 

3. Smith, D. J. Plant Upgrades Add Capacity at Less Cost. Power Eng. April 2001. 

4. Daniels, D. Turbine Deposits Rob Megawatts, But You Can Catch the Thief. Power Magazine

March/April 1999. 

5. Giovando, C. Explore Opportunities from Today’s Steam Turbines. Power Magazine July/August 

1998. 

6. Chambers, A. Partial Rotor Rebuilds Save Time and Money. Power Eng. June 1998. 

7. Brummel, H. Upgrades Give Power Plans New Lease of Life. Siemens Power J. Jan 1998. 

8. Bauer, G.; Joyce, J. S. The Benefits of Parallel Repowering Existing Steam Turbines with Gas 

Turbines. Presented at the CEA Electricity ’96, Montreal, Canada, April 30, 1996. 

9. Farber, M.A. Economic Evaluation of Plant Upgrading Investments/Case Studies; EPRI 

EA-3890, Vol. 2; EPRI: Palo Alto, CA, Feb 1985. 

10. Makansi, J. Rehabilitation. Power Magazine May/June 1999, Special Report. 

11. Repowering as a Competitive Strategy. EPRI J. Sept/Oct 1995. 

12. Stoll, H. G.; Smith, R. W.; Tomlinson, L. O. Performance and Economic Considerations of 

Repowering Steam Power Plants; GER-3644D; GE Industrial and Power Systems. 

3.2.5.3 Power Plant Optimization 

Power Plant Optimization Summary 

Status Commercial 

SO2 Reduction, % Up to 1.5 at full load and up to 5 at low load 

NOX Reduction, % 5 – 35 

Hg Reduction, % Up to 1.5 at full load and up to 5 at low load 

Cost 

Capital 

Stand-alone or one-time: $25,000 – 50,000 

Advisory: $100,000 – 250,000 

Closed loop: $150 – 300,000 

Fixed O&M ($/yr) $10,000 – 20,000 

Variable O&M (mills/kWh) None 

Applicability Both new and retrofit applications 

Issues None 

3-103 
Technology Description 

Power plant optimization generally involves the use of a software program that can determine the set of 

operating conditions which optimize an “objective function” such as “maximize plant efficiency,” 

“minimize NOX emissions,” or “maximize plant efficiency while maintaining NOX, CO, and unburned 

carbon below certain limits.” The software resides in a separate personal computer, which is linked 

directly to the existing Data Acquisition System (DAS) of the power plant to monitor plant performance. 

With the data obtained from the DAS, it establishes a model of how the process works (usually by 

employing neural network-based technology) and then identifies the optimum operating conditions. 

The optimum advice could be implemented automatically (without any action from the plant operator) 

through a direct link into the power plant control system (“closed-loop” system). Alternately, it could be 

shown on a computer screen in the control room and be left to the power plant operator to decide whether 

and how to implement it (“advisory” system). A third variation of the power plant optimization system is 

“stand-alone” or “one-time” optimization, in which case the software is linked temporarily to the DAS 

(usually a few weeks), optimum settings are identified, and the existing control system (mainly the 

“control set-points”) is adjusted to take advantage of the optimum settings. After the completion of the 

stand-alone or one-time optimization, the software may be removed from the plant or left on site so that 

optimization can be repeated in the future. 

Commercial Readiness and Industry Experience 

The technology is commercially available. Presently, there are more than 250 boilers with power plant 

optimization systems in operation or planned to be installed in the U.S.1

 More than 95 percent of these 

boilers are coal-fired, but there are a few gas- and oil-fired boilers, too. When the first optimization 

systems were installed (1993 - 95), most were stand-alone or one-time and advisory systems, because 

utilities wanted to gain experience and confirm their operation and reliability before putting them in 

automatic control. Presently, most of the optimization systems are of the “closed loop” type. 

Optimization software is offered by a number of organizations such as: NeuCo (ProcessLink), Pegasus 

Technologies Corp. (offering NeuSIGHT), Pavillion (Process Insights software), Praxis Engineers/GE 

(PECOS), ULTRAMAX,

2,3 and URS (formerly Radian Corp. offering GNOCIS).4

 Also, Lehigh 

University offers BoilerOP software,5

 but this software is geared more for optimization through 

parametric testing. 

Emission Control Performance 

Industry experience has demonstrated that optimization can achieve 5-35 percent NOX reduction, along 

with heat rate improvement (up to 1.5 percent at full load and up to 4 percent at low loads). Boilers that 

have more operating variables, have not been tuned recently, or have not been tuned with the objective to 

reduce emissions, fall in the middle to the high end of the 5-35 percent range. Boilers that have been 

recently tuned (following a low NOX burner retrofit or a scheduled outage) are expected to achieve NOX

and heat rate improvement in the low end of the above range. SO2 and mercury emissions are expected to 

be reduced proportionally to the heat rate improvement. 

O&M Impacts 

Significant O&M impacts are not expected in conjunction with power plant optimization. However, the 

right precautions need to be taken to avoid O&M impacts, especially long-term impacts which are 

difficult to monitor and quantify. Examples of such impacts are potential waterwall corrosion, which may 

be caused by aggressive combustion staging (high overfire air flow rate) and low excess air. Also, if the 

optimization program shows preference in using one specific pulverizer more than others, then 

precautions need to be taken so that pulverizer maintenance schedule is adjusted to avoid reliability 

problems. 

3-104 
Costs 

Typical capital costs,1

 including installation but not including the time contributed by utility staff, are: 

 For stand-alone or one-time optimization: $25,000-50,000 

 For advisory optimization: $100,000-250,000 

 For closed loop optimization: $150,000-300,000 

In most cases, O&M costs are limited to a small license agreement (up to $10-20,000 per year) with the 

software supplier to provide technical support on an as-needed basis, as well as revised versions of the 

software. 

Issues Associated with the Technology; Future Outlook 

Increased competition due to deregulation and emission trading is expected to provide an additional 

impetus for more extensive use of optimization software. There are no major issues associated with their 

application. 

References 

1. Retrofit NOX Controls for Coal-fired Utility Boilers-2000 Update Addendum; EPRI TR-102906; 

EPRI: Palo Alto, CA, Dec 2000. 

2. Payson, E. P.; Brown, R.; Earley, D.; Moreno, C. Obtaining Improved Boiler Efficiency and NOX

Using Advanced Empirical Optimization and Individual Burner Instrumentation on a Boiler 

Operated in Load-Following Mode. Presented at EPRI’s 12th Heat Rate Improvement Conference, 

Dallas, TX, Jan 30-Feb 1, 2001. 

3. Romero, C. E.; Levy, E. K.; Sarunac, N. Impacts of Combustion Optimization on Power Plant 

Heat Rate. Presented at EPRI’s 12th Heat Rate Improvement Conference, Dallas, TX, Jan 30-Feb 

1, 2001. 

4. Warriner, G.; Logan, S.; Pascoe, S. Full-scale Implementation of Results for GNOCIS TM Plus. 

Proceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant Control 

Symposium: The MEGA Symposium and The A&WMA Specialty Conference on Mercury 

Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001. 

5. Sarunac, N.; Romero, C. E.; Levy, E. K.; Weston, W. C. Anatomy of a Successful Optimization 

Project. Proceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant Control 

Symposium: The MEGA Symposium and The A&WMA Specialty Conference on Mercury 

Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001. 

3-105 
Chapter 4

Summary 

During 2001, fuel combustion-electric utilities contributed 69 percent of the total SO2 emitted, and 22 

percent of the NOX emitted in the United States. As demand for electricity generation and the need to 

address emissions of multiple pollutants grow, new emissions control technologies are emerging. In the 

past, these technologies have mainly addressed one pollutant at a time in harmony with individual 

environmental requirements. In light of the need to address emissions of multiple pollutants, the 

development of cost-effective and easily retrofittable emissions control technologies capable of 

simultaneously handling several pollutants is increasingly becoming necessary. 

This report presents and analyzes various existing and novel control technologies designed to achieve 

multi-emission reductions. It provides an evaluation of multi-emission control technologies and options 

that are available for coal-fired power plants with a capacity of 25 MW or larger in the United States. The 

report addresses technologies and options that are capable of simultaneously controlling at least two of 

the following three pollutants: NOX, SO2, and Hg. 

The selection of control technologies was limited to those for which at least one installation, no lower 

than 5 MW or equivalent, was in operation in a power plant worldwide as of July 1, 2001. Advanced 

power generation technologies, power plant rehabilitation-upgrading options, fuel switching or blending, 

and power plant optimization were also included due to their ability to reduce multiple emissions. 

The technology reviews are based on several sources of information including technology vendors, 

technical papers, expert consultations, reports published by the Department of Energy, and trade 

publications. The results of this review reveal the following: 

 The number of technologies under development, demonstration, or already commercially available is 

significant; most of them have been used already in power plants or industrial applications; 

 Fifteen out of the 27 evaluated technologies are in commercial or early commercial stage; 

 A couple of technologies (Activated Coke and E-BEAM), which are not commonly used in the 

United States, are already in use in other countries; 

 Six of the evaluated control technologies (Activated Coke, ECO, wet FGD with SCR, EnviroScrub, 

LoTOx and K-Fuel) are capable of achieving reductions of SO2, NOX, and mercury; most of these 

exhibit the potential to significantly control (above 80 percent) all three pollutants (SO2, NOX, and 

Hg).; 

 Some technologies, such as SNOX, SNRB, ADVACATE, and CZD, have been tested either in pilot or 

demonstration scale in the early phase of the U.S. Department of Energy’s Clean Coal Technology 

(CCT) program, but have not been adopted by industry. Some of these technologies could become 

more cost-effective as environmental requirements evolve. 

 A number of technologies under early development (Pioneer Technologies’ Non-thermal Plasma Arc 

technology, Consummator’s plasma arc by-product recovery, Phoenix’s retrofit slagging combustor, 

ISCA’s Cl2 injection, and BioDeNOX), which were not evaluated in this report, may offer additional 

effective emission control of multiple pollutants in the near future. 

4-1 
4-2 

For each evaluated technology, the report includes background information, applicability, status of 

commercialization, any secondary environmental impacts of the technologies, identification of primary 

process variables that impact performance relative to NOX, SO2, and mercury, as well as capital and 

operation and maintenance (O&M) costs. Table 4-1 includes summary descriptions of 27 technologies 

identified as multi-emission control technologies, which have reached a stage of development beyond 

pilot scale. These technologies can broadly be divided into: 

 Environmental control (post-combustion controls), 

 Advanced power generation, and 

 Power plant upgrading and operating options. 

For the purposes of this report, environmental controls include those processes that control SO2-mercury, 

SO2-NOX, and SO2-NOX-mercury emissions. Injection of activated carbon upstream of electrostatic 

precipitators and bag filters was also included because of the significant role it may play in controlling 

mercury from existing power plants. 

Advanced power generation technologies include circulating fluidized bed combustion (CFB), integrated 

gasification combined cycle (IGCC), pressurized fluidized bed combustion (PFBC), and supercritical 

pulverized coal. Plant upgrading and operating changes include fuel blending and cofiring, plant 

upgrading and efficiency improvements, and plant optimization. 

Although the report is limited to addressing technologies with a certain level of maturity, the authors 

expect a rapid technological evolution in the development and commercialization of several multiemission control technologies not necessarily addressed in this report. 
Table 4-1. Summary Descriptions of 27 Multi-emission Control Technologies for Coal-fired Units 

Technology Statusa Emissions Reductions Applicability Issues SO2 and Mercury ControlDry scrubbers C SO2: 90-98%; NOX: NAb; 

Hg: 0- 95% 

Low-to-medium sulfur coal Hg removal can vary 

operating conditions 

SO2 sorbents P/C SO2: 40-85%; NOX: NA; 

Hg: NA 

Units with ESP or FF for particulate control 

Calcium-based compcommercially in coal fdisposal issue with soPotential impacts on E

Activated carbon with SO2

sorbent processes 

P/C SO2: 40-85%; NOX: NA; 

Hg: Up to 90% 

Units with ESP or FF for particulate control 

Not used commercialESP or FF 

Activated carbon with particulate controls 

P/C Hg: 50-90% Retrofit and new units with ESP or 

FF 

Not widely demonstrasalability, ESP and FF coal type (mercury sp

Wet FGD with mercury oxidation processes 

P SO2: 95%; NOX: NA; 

Hg: >80% 

Wet scrubber plants Full scale demonstrat

information at presen

Wet FGD with wet ESP C/P SO2: 99%; NOX: NA; 

Hg: Up to 80% 

Integration with wet scrubbers, retrofit dry ESPs, new units 

Few applications in poexpensive alloys requ

Advanced dry FGD P/C SO2: 90-98%; NOX: NA; 

Hg: 0-95% 

SO2-Hg control for low-to- medium 

sulfur coal (same as spray dryers) 

Hg removal may vary type, operating conditdryers) 

PEESP B/P SO2: >90% (with wet FGD); 

NOX: NA; Hg: Up to 98% 

New and retrofit Early stage of develop

further assessment of 

MerCAP B/P SO2: NA: NOX: NA; 

Hg: >80% 

New and retrofit; scrubbed flue gas 

Did not perform well ifor 10 ft long plates sp

SO2 and NOX ControlE-BEAM C/D SO2: >95%; NOX: Up to 90%; 

Hg: NA New and retrofit Demonstration is requ

auxiliary power requir

ROFA-ROTAMIX C/D SO2: 90%; NOX: 40-60%; 

Hg: 67% with Trona, 89% with CaCO3

Existing plants 

Demonstration phase 

SNOX C SO2: >90%; NOX: >90%; 

Hg: 0% New and retrofit Cost-effectiveness 

SNRB P SO2: 80-90%; NOX: 90%; 

Hg: NA New power plants and retrofits Requires demonstrati

THERMALONOX with wet FGD or FLU-ACE 

D SO2: Up to 95%; NOX: Up to 

90%; Hg: NA 

New and retrofit In demonstration 

4-3 
4-4 

(Table 4-1 concluded) 

Technology Statusa Emissions Reductions Applicability Issues SO2, NOX, and Mercury ControlActivated coke C SO2: 90-98%; NOX: 15-80%; 

Hg: 90-99% 

New and retrofit Demonstration of the 

control is needed in th

Electrocatalytic oxidation (ECO) 

D SO2: 98%; NOX: 90%; 

Hg: 90% 

New and retrofit Demonstration in prog

Wet FGD and SCR C SO2: 95%; NOX: 90-95%; 

Hg: 40-90% depending on coal type 

Plants with SCR and wet scrubber technologies 

Need additional confioxidation levels in the 

EnviroScrub P SO2: >99%; NOX: 93-97%; 

Hg: Up to 67% 

New and retrofit Demonstration require

LoTOX D/C SO2: 95%; NOX: 70-95%; 

Hg: Up to 90% 

New and retrofit Demonstration require

K-Fuel D/C SO2: Up to 30%; NOX: Up to 

45%; Hg: Up to 70% 

Mostly boilers burning PRB or lignite 

Demonstration require

Advanced Power Generation OptionsCirculating fluidized bed combustion 

C SO2: >95%; NOX: 30-70%; 

Hg: NA 

Mainly new Successful scale-up t

maintaining its cost-ef

performance 

Integrated gasification combined cycle 

C/D SO2: 99%; NOX: 80-90%; 

Hg: 90% 

New High costs. Fluidized 

demonstration 

Pressurized fluidized bed combustion 

C SO2: Up to 98%; NOX: 30-

70%; Hg: NA 

Mostly new Some reliability proble

(relative to convention

scale-up issues. 

Supercritical pulverized coal C/D SO2: 4-12%; NOX: 4-12%; 

Hg: 4-12% 

New Ultra-supercritical uni

demonstration 

Power Plant UpgradingFuel blending and cofiring C SO2: Up to 100%; NOX: 20-

80%; Hg: flex% 

New and retrofit Development of on-lin

is needed to enhance 

Plant upgrading C Depends on choice Retrofit Impact of environmen

to increased output of 

Power plant optimization C SO2: 1.5-5%; NOX: 5-35%; 

Hg: 1.5-5% 

New and retrofit None 

a Status: B = Bench scale; P = pilot stage; C = commercial; D = demonstration b NA = no removal reported
End of Document