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 envir onmental laws, the agency strives to formulate and implement actions leading to a compatible balan ce between human activities and the ability of natural systems to support and nurture life. To meet this mandate, EPA's research prog ram is providing data and technical support for solving environmental pr oblems 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 Laborator y is the agency’s center for investigation of technological and management approaches for reduci ng 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 res ources, protection of water quality in public water systems; remediation of contaminated sites and gr oundwater; 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 sci entific and engineering information needed by EPA to support regulatory and policy decisions; and pr ovide technical support and information transfer to ensure effective implementation of environmental regulations and strategies.

This publication has been produced as part of the la boratory'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 (SO 2 ), nitrogen oxide (NO X ), 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: environmenta l control options (postcombustion controls), advanced power generati on options, and power plant upgrading and operating options. For each evaluated technology, the report includes background information, applicability, status of commercialization, any secondary environmental im pacts of the technologies, identification of primary process variables that impact performance relative to NO X , SO 2 , 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 SO 2 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 T echnology program, but have not been adopted by industry. Some of these technologies could become mo re cost-effective as environmental requirements evolve. Activated coke, electro-catalytic oxidation, EnviroScrub, and the combination of flue gas desulfurization with LoTOx or selective catalytic re duction exhibit the potential to significantly control (above 80 percent) all three pollutants (SO 2 , NO X , and Hg).

Although the report is limited to addressing technologi es with a certain level of maturity, the authors expect a rapid technological evolution in the development and commercia lization of several multiemission control technologies not addressed in this report.

ii

## Acknowledgments

ARCADIS would like to acknowledge the many contribut ors to this document without whose efforts this report would not be complete. In particular, we wi sh to acknowledge the technical guidance provided by Dr. Ravi Srivastava of EPA’s National Risk Manage ment 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.

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## 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 SO 2 Emissions from Coal-Fired Power Plants ...........................................................................2-2 2.2 NO X Emissions from Coal-Fired Power Plants ..........................................................................2-4 2.3 Mercury Emissions from Coal-Fired Power Plants ...................................................................2-8 2.4 CO 2 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 SO 2 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 SO 2 Sorbents .........................................................................................................3-19 3.2.1.2.3 Combined Mercury and SO 2 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 SO 2 and NO X 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 SNO X .........................................................................................................................3-45

iv3.2.2.4 SO X -NO X -Rox Box (SNRB) .....................................................................................3-49 3.2.2.5 THERMALONO X and FLU-ACE Process ...............................................................3-51 3.2.3 SO 2 , NO X , 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. SO 2 Emissions from Units with F GD Installed in 1990-1999..................................................2-4 Table 2-3. 1999 NO X Emissions for Title IV Affected Units ....................................................................2-6 Table 2-4. Mean Mercury Emission Reducti on 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 Injec tion 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 S upercritical 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 SO 2 and NO X emissions in 2001 and of me rcury emissions in 1998 ..........2-1 Figure 2-2. Annual SO 2 emissions for coal-fired units..............................................................................2-3 Figure 2-3. Annual NO X emissions for coal-fired units.............................................................................2-5 Figure 2-4. Annual CO 2 emissions for coal-fired units..............................................................................2-9 Figure 3-1. Mercury removal across spra y dryer and ESP-FF from ICR data...........................................3-5 Figure 3-2. Mercury removal versus activated car bon loading in a pilot scale ESP and baghouse.........3-16 Figure 3-3. E-Beam process schematic........................................................................................... .........3-39 Figure 3-4. NO X emissions from Cape Fear Unit 5: co mparison before and after ROFA.......................3-44 Figure 3-5. SNO X process schematic .......................................................................................................3-46 Figure 3-6. Activated coke process flow diagram ................................................................................ ...3-54 Figure 3-7. ECO pro cess flow diagram ........................................................................................... ........3-59 Figure 3-8. ECO power consumption versus NO X ..................................................................................3-62 Figure 3-8. Schematic diagram of LoTOx TM system ...............................................................................3-70 Figure 3-9. NO X 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 CO 2 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-SO X ESP enhanced for SO 2 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

viiLOI Loss-on-ignition
MM Million (10 6 ) MSW Municipal solid waste
MW Megawatt (electric) NAAQS National Ambient Air Quality Standards NO X 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 SO 2 Sulfur dioxide SRG SO 2 -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 10 6 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 10 12 Giga G 10 9 Mega M 10 6
Kilo k 10 3

Hecto h 10 2

Deka da 10 Deci d 10 -1
Centi c 10 -2

Milli m 10 -3
Micro μ 10 -6

ixx

## 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 (SO 2 ), oxides of nitrogen (NO X ), particulate matter (PM), and other pollutants, as driven by air po llution requirements. Control technologies that are capable of simultaneously reducing emissions of mul tiple 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 environm ental 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 Organiz ation of this Report

The intended use for this report is to provide the curre nt 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 St ates. For the purposes of this report, multi-emission control technologies are those capable of simultaneous ly controlling emissions of at least two of these three pollutants, NO X , SO 2 , and mercury, from electric utility sources. This evaluation includes background information, applicability, status of co mmercialization, any secondary environmental impacts of the technologies, identification of primary process variables that impact performance relative to NO X , SO 2 , 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 SO 2 , NO X , and mercury emissions, some technologies reviewed under this study promise to enable reduc tions of the carbon emissions that result from coalbased electricity production. Such capability is vi ewed as an additional benefit and discussed for each applicable technology, given that reducing carbon emissi ons would be advantageous to the fulfillment of U.S. commitments under the United Nations Framew ork 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 fi rst chapter provides genera l 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 u tility plants and 2,110 non-utility power plants are responsible for ensuring an adequate and reliable s ource 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 resu lt from emissions produced through the combustion of fossil fuels (coal, oil, and natural gas), which s upply 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 NO X and SO 2 . 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 (PM 2.5 ). 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 Policy 3 recommends the establishment of “mandatory reduction targets for emissions of three ma in 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 repor t focuses on emissions from coal-fired power plants since these plants generate about 50 percent of the el ectricity used in the United States. The coal-burning electric power industry is a major source of various air pollutant emissions including SO 2 , NO X , and mercury. In addition, the combustion of fossil fuels contributes to CO 2 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 approxima tely 25 percent and substa ntially 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 spit e of the progress made to date, the electric power industry is still a significant source of SO 2 , NO X , 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 SO 2 and NO X lead to the formation of fine particles (particles less than 2.5 micrometers). Most fine particles, namely sulfates and nitrates, are formed when SO 2 , NO X and volatile organic compounds and ammonia react in the air. Fine particl es 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 SO 2 emissions by 10 million tons below 1980 levels and a 2 million ton annual reduction in NO X 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 easter n 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 lim its imposed on these large, higher emitting plants and also set restrictions on smaller, cleaner plants fired by co al, oil, and gas, encompassing over 2,000 units in all.

1-2being deposited far away from where the emissions took place. Fine particles pose serious threats to public health because their size allows them to easily r each 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 NO X 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 Stat es and some urban areas including Los Angeles and Houston. Ozone can damage lung tissue, reduce lung f unction, and adversely sensitize the lungs to other irritants. Long-term exposures to ozone can cause rep eated 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 SO 2 and NO X 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 par ticles. Acid deposition lowers the pH of sensitive lakes and streams to toxic levels. Lower pH can im pact 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 calcium 2 in certain plants. In other cases, multiple pollutants such as ozone, SO 2 , and NO X can combine to weaken trees and make them vulnerable to other threat s, such as pests, that cause mortality.

Atmospheric deposition is a rapidly growing anthropogenic source of biologically available nitrogen in estuarine and near-coastal ecosys tems. Depending on the location, from 10 to 80 percent of new nitrogen inputs to coastal waters along the east and Gulf coast s 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 di versity, and degradation or loss of essential coastal ecosystem habitat (such as sea grass beds). These ecol ogical changes impact commercial and recreational fisheries and reduce our ability to use and enjoy coast al ecosystems. Recent studies also link atmospheric nitrogen deposition, coastal eutrophication, and ha rmful 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 h aze 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, whic h reduces the cold tolerance of individual trees, has contribute d 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.

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### 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 mercur y in the coal burned in power generation plants in 1999 was emitted to the atmosphere. 9 The percent contribution to tota l anthropogenic mercury emissions from power generation is expected to become even gr eater 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 me rcury 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 i onic 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 meth ylmercury 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 incl ude death, reduced reproductive success, impaired growth and development, a nd behavioral abnormalities.

While EPA has already taken action to reduce mercury emissions from other major sources such as municipal waste combustors, medical waste incine rators 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 technolog ies that have reached a stage of development beyond pilot scale. It includes those technologies that in tegrate in-situ or post-combustion controls of at least two of the SO 2 , NO X , and mercury pollutants, either in one process or a combination of coordinated and complementary processes. In addition, the repor t 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 CO 2 . 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 elect ric power industry in selecting emission control options for power plants. Information on environmental perfo rmance, cost, commercialization barriers, and other relevant factors on these technologies could enable power companies to choose less expensive air pollution compliance approaches, compared to cont rolling 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 em ission 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. Anthropogeni cally-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, Impact s 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" Nitr ogen 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 Mana gement Research Laboratory: Research Triangle Park, NC, Dec 2001.

1-51-6

## Chapter 2 Characterization of U.S. Power Plan ts 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 (SO 2 ), nitrogen oxides (NO X ), 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 SO 2 and NO X 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 SO 2 emitted and 22 percent of the NO X .

18% 9% 4%

69% <1%

Transportation

Industrial processing Fuelcombustionelectric utility Other stationary combustion Miscellaneous 22%

17%

5% 55% 1%

35%

42% 14% 4% 5% 2001 SO 2 Emissions

LEGEND 1998 Mercury Emissions 2001 NO X Emissions

Figure 2-1. Major sources of SO 2 and NO X emissions in 2001 and of mercury emissions in 1998.

2-1Since the majority of U.S. power plant capac ity is regulated under Title IV of the CAAA, 2,3 the data for
NO X , SO 2 , and CO 2 collected under this title provide a good repr esentation 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 a ffected a total of 2,638 units in 2001, from which 1,089 are considered coal-fired units based on burni ng over 50 percent coal as the primary fuel. Emissions data for Title IV affected units is availabl e at EPA Clean Air Market Division’s website. 4

Table 2-1 summarizes the 2001 total emissions data fo r 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 SO 2 emissions, 90 percent of NO X emissions, and 86 percent of CO 2 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 Units 5

Coal Non-Coal Total

SO 2 (Tons) 10,052,279 581,799 10,634,077

NO X (Tons) 4,235,104 464,770 4,699,874

CO 2 (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 pollu tion 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 u tility 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 SO 2 

### Emissions from Coal-Fired Power Plants

SO 2 emissions from coal-fired power plants increased slightly between 1996 an d 1997 by about 400,000 tons. Despite this emissions increase, a sharp decr ease 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

2-212.24 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 2001SO2Emissions (Million Tons)

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

Emissions of SO 2 are highly dependent on the sulfur content in the coal burned and the emissions control system employed. Emissions control systems are typica lly based on dry or wet flue gas desulfurization (FGD). FGD technologies are based on the use of sorbents to scrub SO 2 from the flue gas and are conventionally classified as throwaway and regenera ble 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 w ith moisture. In dry processes, dry waste material is produced and flue gas leaving the absorber is not saturated.

SO 2 emission rates for 60 units that had FGD technol ogies 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.

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

FGD Type Number of Units a Fuels Burned b Average SO 2 Emission (lb/MMBtu) Maximum SO 2 Emission (lb/MMBtu) Minimum SO 2 Emission (lb/MMBtu) Annual SO 2 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./petco ke 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. = bi tuminous coal; subbit. = subbitumin ous coal; petcoke = petroleum coke.



### 2.2 NO X 

### Emissions from Coal-Fired Power Plants

Annual NO X 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.

2-45.60 5.64 5.44

4.84 4.54 4.17

0 1 2 3 4 5 6 7

1996 1997 1998 1999 2000 2001NOxEmissions (Million Tons)

Figure 2-3. Annual NO X emissions for coal-fired units.

NO X is formed during most combustion processes by one or more of three chemical mechanisms: (1) “thermal” NO X resulting from oxidation of atmospheric molecular nitrogen, (2) “fuel” NO X resulting from oxidation of chemically bound nitrogen in the fuel, and (3) “prompt” NO X resulting from reaction between atmospheric molecular nitrogen and hydrocarbon radicals. In fuel-lean combustion of nitrogenfree fuels, thermal NO X is the primary component of NO X emissions. Thermal NO X 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 NO X contributes significantly to total NO X emissions, depending on the percentage of n itrogen in the fuel. Formation of fuel NO X depends on the availability of oxygen to react with the nitroge n during coal devolatilization and the initial stages of combustion. Under fuel-rich conditions, the formation of NO X may compete with the formation of molecular nitrogen (N 2 ) and may result in a reduction of NO X emissions. Prompt NO X contributes a relatively minor fraction of total NO X emissions for both nitrogen-free and nitrogen-containing fuels.

The factors described above that dictate NO X formation (devolatilization of fuel-bound nitrogen, oxygen concentration, and flame temperature) can all be adjust ed 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 NO X production. Combustion modification NO X controls utilize this combustion staging.

In general, NO X control technologies are categorized as being either primary control technologies or secondary control technologies . Primary control technologies reduce the formation of NO X in the primary combustion zone. In contrast, secondary control technologies destroy the NO X present in the flue gas from the primary combustion zone. Primary control techno logies being used in the United States are low NO X burner (LNB) and overfire air (OFA).

The secondary NO X 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 NO X reductions. The NO X

2-5reductions achieved, or projected, at these applications range from 20 to more than 80 percent. Table 2-3 summarizes the 1999 NO X emissions and emission rates for units regulated under Title IV. 10

Table 2-3. 1999 NO X Emissions for Title IV Affected Units

Boiler Type (Coal Units Only) Number of Units NO X Control Average NO X Emission (lb/MMBtu) Maximum NO X Emission

(lb/MMBtu) Minimum NO X Emission (lb/MMBtu) Annual NO X Emission

(tons)

Arch-fired 9 Uncontroll ed 0.74 0.91 0.25 11,170

Cell burner 2 Low NO X Burner Technology 0.62 0.71 0.52 39,125

3 Low NO X Burner Technology for Cell Burners 0.46 0.46 0.46 20,067

1 Low NO X 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 NO X Burner Technology 0.39 0.40 0.37 16,110

3 Low NO X 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 NO X 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)

2-6Table 2-3 (concluded)

Boiler Type (Coal Units Only) Number of Units NO X Control Average NO X Emission (lb/MMBtu) Maximum NO X Emission

(lb/MMBtu) Minimum NO X Emission (lb/MMBtu) Annual NO X Emission

(tons)

Dry bottom wallfired 153 Low NO X Burner Technology 0.43 0.81 0.18 848,965

41 Low NO X Burner Technology with Overfire Air (Dry Bottom Boilers Only) 0.45 0.71 0.30 182,191

1 Low NO X 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 NO X Burner Technology 0.34 0.45 0.13 202,120

31 Low NO X Burner Technology with Close-coupled and Separated OFA 0.36 0.63 0.16 146,046

40 Low NO X Burner Technology with Close-coupled OFA 0.37 0.67 0.17 181,774

26 Low NO X 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 NO X 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 NO X 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 oxi dized mercury, 26 tons of elementary mercury (Hg 0 ), and less than 1 ton of particulate-bound mercury. 12 This latter analysis also estimates the total amount of mercury in the fuel enteri ng these power plants at 75 tons in 1999.

The air pollution control technologies now used on pulv erized-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 co al 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 Hg 0 in the flue gas from combustion of these fuels. The average capture of Hg based on inle t measurements in pulverized coal (PC)-fired plants equipped with a cold-side electrostatic precipitator (ESP) is 35 per cent 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 Reduc tion 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-CS b 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 un it in ICR Phase III database.

b Refer to Acronyms, page vii for definitions.

2-8Units equipped with lime spray dryer absorber scr ubbers 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 Hg 0 in stack gas units that are fired with subbituminous coal and lignite results from low levels of Hg 0 oxidization.

The capture of Hg in units equipped with wet FGD scrubbers is dependent on the relative amount of Hg 2+ in the inlet flue gas and on the PM control tec hnology used. Average Hg captures in wet FGD scrubbers ranged from 23 percent for one PC-fired hot-side ES P (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 CO 2 

### 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 natura l 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 CO 2 emissions per kilowatt-hour of electricity.

Title IV does not require control of CO 2 emissions; it only requires that th ey be measured and reported. Figure 2-4 summarizes emissions from these units for 1996 to 2001. 4 Emissions of CO 2 from all Title IV affected units increased by 2.5 per cent from 1996 to 1997. In 1998, CO 2 emissions increased by 1.5 percent. The CO 2 emissions remained the same between 1998 and 1999, but in 2000, CO 2 emissions rose by 1.9 percent. In 2001, CO 2 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 2001CO2Emissions (Billion Tons)

Figure 2-4. Annual CO 2 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 Ra in Program Units, Including SO 2 , NO X , CO 2 , 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 SO 2 , NO X , CO 2 , 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 fro m 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 To tal 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 th e 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 c ontrols of at least two of the SO 2 , NO X ,, and mercury pollutants, either in one pro cess or a combination of coordinated and complementary (synergistic) processes.

There were no constraints set as to the percentage re duction 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-em ission control category. These technologies were included to emphasize that there are multiple optio ns 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 convent ional 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 plantworldwide 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 literatu re search was done (using technical papers from conferences, the internet, technical reports by orga nizations 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 SO 2 -mercury, SO 2 -NO X , and SO 2 -NO X -mercury emissions. Injection of activated carbon in front of el ectrostatic precipitators (ESPs) and fabric filters (FFs) was also included, because of the significant ro le 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 circul ating fluidized bed combustion (CFB), integrated gasification combined cycle (IGCC), pressurized fl uidized bed combustion (PFBC) and supercritical pulverized coal. In the category of plant upgrading and operating changes, the report includes: fuel

3-1blending or cofiring, plant upgrading and efficien cy 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 comb ined cycle unit burning na tural gas. Others, such as optimization, are strictly plant-operating adjustme nts. Most of these options are very site-specific, especially with regard to the potential emission reduc tion 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-sp ecific analyses are needed (b eyond 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, Ph oenix’s retrofit slagging combustor, ISCA’s Cl 2 injection, and BioDeNO X , which uses bacteria to reduce NO X 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 opti ons. Finally, there are technologies which were demonstrated in the past and for which recent inform ation is not available. These technologies, such as LIMB, NOXSO, or Milliken Clean Coal, are not discussed in this report.

For each technology, the following informa tion 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 sec tion is brief, but references are provided if the reader is interested in more detailed informati on. 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 est imates that are provided are based on the authors’ experience.

The costs reflect End of Year (EOY) 2000 US dolla rs, unless otherwise indicated. When the basis is different from EOY2000, the costs are adjusted us ing 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) wh en referring to the accuracy of estimates based on development stage of the technology and the design and cost basis.

3-2In addition to the costs, an attempt is made in the report to provide al so 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. Furthermor e, there are other factors that may affect costs equally or more than plant size. Some of these f actors 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 SO 2 

### 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 SO 2 and mercury) and is typically used in low- to medium-sulfur coal-fired power plants. “Dry” refers to the fact that the flue gas a nd the refuse (ash and solid reaction products) leaving the scrubber are not saturated with water vapor as in wet FGD (w et 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 gene ral, 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
SO 2 Reduction (%) 90 to 95
NO X 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 SO 2 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, alterna tively, pneumatic nozzles and injected into a vessel where it reacts with the SO 2 in the flue gas to produce calcium sulfate or sulfite products. The vessel must be appropriately sized to allow sufficient residen ce time (~ 10 seconds) for droplet evaporation and SO 2 capture to take place.

3-3In addition, spray dryers have been s hown to reduce mercury in the flue gas. 1-3 In this case, the more complex chemistry and speciation forms of the merc ury make it more difficult to fully understand the processes and reactions that take place. However, fl y 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 in clude a cylindrical vessel with conical bottom. The atomizer may be located either at the top or the bot tom and spraying into the moving flue gas flow. Flue gas exiting the spray dryer is directed to a downstrea m 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 fo r this application flexibility is mainly economic; spray dryers have lower costs and can achieve reasonable SO 2 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 ch ecked to make sure that the increase in particulate loading can be accommodated (the quantity of sorbent is proportional to the SO 2 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 ha ndle 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 typi cally referred to in terms of calcium-to-sulfur ratio or stoichiometry and ranges from about 1.0 to >2.0 for SO 2 removals of 75 to 95 percent. For 80 percent SO 2 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 tec hnology 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, subb ituminous, and lignite applications. Significant experience was gained in the United States through exte nsive testing programs such as those conducted at TVA's Shawnee Station, EPRI’s Environmental C ontrol 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 SO 2 reductions (up to 95 percent). Data from IEA’s coal research indicate SO 2 reductions from 70 to 96 percent with a median value of 90 percent, comparable to that of wet FGD technology. This performance reflects appli cations 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 SO 2 . However, a number of test programs as well as the recent EPA’s Mercury Inform ation 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, mercur y reductions are reported from the inlet to the spray

3-4dryer 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 pe rcent) 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 chlori ne content suggesting that spray dryers preferentially remove oxidized mercury. The wide range in the reduction values i ndicates 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 mercur y reductions from spray dryer-ESP-FF systems usingdifferent 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 reducti ons 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 Spra y 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%

3-5O&M Impacts O&M impacts include: 1. additional pressure loss associated with the spray drye r vessel and associated auxiliary power; 2. increased solids loading, wh ich 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 exis ting. 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 TAG 10 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, pri ces 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 range 11-13 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 unde rstand and predict mercury reduction performance. “Dedicated” mercury sorbents su ch as activated carbon should in crease 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 Merc ury Removal from Wet and Dry FGD. Proceedings of the U.S. EPA-DOE-EPRI Combined Power Pl ant 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 SO 2 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.

3-65. Guidelines for Particulate Control for Advanced SO 2 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 SO 2 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 C ontrol, Chicago, IL, Aug 20-23, 2001.

9. Martinelli, R. Dry Scrubber/fabric Filter Re trofit: 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 Sy stem 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 Maintena nce 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 Conferen ce on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001.

3-73.2.1.1.2 Advanced Dry Scrubbers

Advanced Dry FGD (CFB Absorbers) Summary

Status Pilot to Commercial

SO 2 Reduction, % 90 - 98

NO X 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 SO 2 -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 conventiona l 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 gene ric description is presented below, followed by brief descriptions of specific technologies offered by th e major vendors. They include Circulating Dry Scrubbing (CDS) offered by LURGI, Gas Suspen sion 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 th e system, or directly from the final particulate collection device (ESP or FF).

CDS – LURGI 1-3 This technology uses a circulating fluid bed to estab lish a zone of high partic le density. This bed is enhanced with activated carbon for mercury adsorpti on. Carbon utilization is enhanced due to the high residence time in the bed, while fine particles te nd to agglomerate through "collisions" in the bed, facilitating their subsequent capture in a conventiona l ESP or FF. The technology is used with hydrated lime injection for control of acid gases.

GSA – FLS Miljo 4,5 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 temperat ures [less than 11 °C (20 °F) approach to saturation

3-8temperatures]. Flue gas from the boiler flows directly into the bottom of the GSA vessel. Simultaneously, lime-slaked slurry is atomized into the reactor, flow ing upward with the flue gas. The lime content of the slurry is varied, depending on the SO 2 removal objectives.

GRAF – WULFF GmbH 6,7
The RCFB introduces an internal reflux within the ci rculating 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 SO 2 reduction via the amount of sorbent supply.

RAP - Beaumont 8,9 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 syst em. 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, th e four CFB-based technologies are commercial, with installations in the U.S. and abroad. The RAP t echnology has undergone pilot-scale tests and has been demonstrated at a facility in Ohio combined with a low temperature NO X removal system.

CDS - LURGI The first commercial installation in the U.S. was depl oyed 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 SO 2 control, respectively. T esting was carried out daily during a three-month period.

GSA – FLS Miljo FLS Miljo offers GSA commercially, with over 35 insta llations 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 SO 2 control exceeding 90 percent. 10

GRAF – WULFF GmbH WULFF GmbH commercially offers the RCFB. The t echnology is in full commercial use in plants ranging from 3 to 300 MW and firing various fuels for the simultaneous removal of SO 2 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 th e SRI’s combustion test facility. In addition, a fullscale demonstration program at the Medical Co llege of Ohio is currently proceeding.

3-9SO 2 and Mercury Emission Control Performance In general, the advanced scrubbe rs are capable of >90 percent SO 2 reduction. 12,13 With respect to mercury control, less information is available, but high remova l rates (such as in convent ional 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 SO 2 reduction in the CFB and ESP system, using coal with sulfur content varying from 0.2 percent to 1.2 percent. EPA-sponsored tests 14 at the Roanoke Valley unit in September of 2000 indi cated 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 wh en the CFB was injected with iodine-impregnated activated carbon (at 1000:1 AC-to-Hg ratio).

GSA – FLS Miljo 15 Results from the demonstration project at TVA under the CCT showed overall SO 2 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 SO 2 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), SO 2 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, SO 2 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 pe rcent. Mercury removal without activated carbon injection can reach up to 80 percent.

RAP - Beaumont The technology is currently being piloted at a com bustion test facility. Initial results were as high as 95 percent removal, but formal testing and demonstration on various coals and va rying conditions will be part of a continuing program. According to Beaumont, at the Medical College of Ohio, the test program will investigate SO 2 reductions from 70 to 95 percent and sorben t 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 sp ray 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 fa ll 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, SO 2 performance is well documented for th e 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 SO 2 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 SO 2 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 Circulati ng Fluid Bed Scrubber. Pr oceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant Control Symposium: The MEGA Symposium and The A&WMA Specialty Conferen ce on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001.

8. Gross, W. Advances in Semi-Dry Absorption for Mu ltipollutant Control. Proceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant Control Symposium: The MEGA

3-11Symposium and the A&WMA Specialty Conferen ce 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 SO 2 Reduction System LoTOx NO X 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. Advan ced, Large-capacity, Commercial Technology for Multipollutant Control. Proceedings of the Comb ined 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 SO 2 Control Symposium, Washington, DC, Dec 3-6, 1991.

13. Jozewicz, W.; Singer, C.; Srivastava, R. K.; Tsirigotis, P. E. Status of SO 2 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 Me rcury Testing, Test Report; Nov 6, 2000.

15. 10- MW Demonstration of Gas Suspension Absorp tion, Clean Coal Technology Demonstration Program, Program Update; U.S. Department of Energy: Washington, DC, Oct 1997.

16. Guidelines for Particulate Control for Advanced SO 2 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 C ontrol, Chicago, IL, Aug 20-23, 2001.

18. Weilert, C.V. Statistical Analyses of FGD Syst em 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 d esired reactions, whereas in sorbent injection, the reactions occur in the flue gas duct and the dow nstream 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 th e reactions to take place, through residence or “contact” time.

3-12Sorbent injection technologies can be characterized by th e 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 SO 2 control. Other differentiating feat ures may include details on sorbent preparation, injection approach, and integrati on with the particulate control device, etc.

Sorbent injection technologies received significant “atte ntion” in the US in the 1980’s, being developed as lower-cost and lower efficiency alternatives for SO 2 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 sever al sorbent injection processes usi ng different sorbents to achieve mercury or SO 2 reductions.

3.2.1.2.1 Activated Carbon with Particulate Controls

Activated Carbon with Particulate Controls Summary

Status Pilot to commercial

SO 2 Reduction None

NO X 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 activ ated 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 adso rption 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. Lowe r approach-to-saturation temperatures favor the

process.

A variation of this technology w as 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.

3-13The most commonly studied sorbent for mercury contro l 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 pr operties such as surface area, pore volume, and pore size. Activated carbon can be manufactured from a vari ety 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 atom s are vaporized, the desired highly porous activated carbon is produced. Commercially, activated carbon is ava ilable 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. Capac ity 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 dem onstrations 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, inves tigated several plant configurations, coals, and sorbents. This experience, combined with the experi ence gained in the 1980’s w ith sorbent injection for SO 2 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 Stati on – pilot scale ESP, FF, and COHPAC and TOXECON 5

 PSE&G Hudson Station – pilot scale COHPAC and TOXECON 6

 Alabama Power, Gaston Plant – full scale COHPAC and TOXECON 7

 WEPCO, Pleasant Prairie – full scale ESP 7

 PGE NEG, Salem Harbor Station – full scale ESP 7

 PGE NEG, Brayton Point Station – full scale dual ESPs 7

The other component of the technology – activated carbon – is a commercially available product widely used in industry. Another source of carbon-based sorb ent 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-e ffective 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 Hg 0 and Hg 2+ ) 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 (Hg p ) in the boiler flue gases. The degree to wh ich mercury can be adsorbed onto fly ash for subsequent capture in PM control is depende nt 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 adso rbed on the entrained fly ash upstream of the ESP. The gas-phase merc ury 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

3-14to which gaseous mercury adsorbs on the filter cak e typically depends on the speciation of gaseous mercury in the flue gas; in general, gaseous Hg 2+ is easier to adsorb than gaseous Hg 0 . 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 enhan ces 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 wi th FFs was much higher than for boilers equipped only with ESPs. ICR data reflected that plants wh ich 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 averag ed 90 percent while two similarly equipped units burning subbituminous coals displayed an average me rcury 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 efficien t collection of mercury when powdered activated carbon (PAC) is injected for additional mercury control upst ream of a FF as opposed to injection upstream of an ESP. New hybrid ESP-FF technologies, such as the Comb ined Hybrid Particle Collector (COHPAC), offer ways to cost-effectively retrofit ESP’s with FF a nd 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. Mercur y 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 predictions 14 for various configurations, sorbent characteristics, and operating conditions confirm this range of performan ce. If COHPAC is added to an existing ESP, in addition to the mercury reduction, particulates (including PM 2.5 ) are reduced, too. 15

Laboratory, pilot scale, and modeling programs 16-18 have indicated that the following parameters can affect the ultimate performance of the technology:

 sorbent type and properties,

 gas-phase mercury species (Hg 0 or HgCl 2 ),

 temperature,

 concentration of acid gases (HCl, SO 2 , NO, NO 2 ) 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 merc ury capture for the same sorbent loading.

Recent review and modeling 20 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 lo wer injection concentrations being necessary for a given level of mercury reduction than for PA C 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 carb on loading in a pilot scale ESP (open symbols) and baghouse (closed symbols). 19

O&M Impacts The major potential O&M impacts associated with th e 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 SO 3 dew point and, thus, intensifying corrosion and reducing bag life,

 auxiliary power for activated carbon injection, ev en 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 proper ties of the ash to require changes in its disposal. However, if the ash is utilized or sold for cons truction applications, the increased concentration of carbon may affect the ability of the utility to sell it.

3-16Capital Costs Capital costs will vary significantly for applications w ith 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 fo r 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 additiona l 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 iden tified. 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 NO X 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 Innov ation: Controlling Mercu ry 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 91 st 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 Remova l of Mercury Vapor from Simulated CoalCombustion Flue Gases. Presented at the A&WMA 93 rd 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 Injection3-17Pilot Scale Demonstration Flue Gas Using Sorbent Injection. Proceedings of the EPRI-DOE-EPA Combined Utility Air Pollutant Control Sy mposium, 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 So rbent 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.; Ma rtin, 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 Associ ation, 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.

3-1817. Miller, E. S.; Dunham, G. E.; Olson, E. S.; Brow n, 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.; Renninge r, S. Results of Activated Carbon Injection Upstream of ESP for Mercury Control. Proceedi ngs 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 92 nd 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 SO 2 Sorbents

SO 2 Sorbents Summary

Status Pilot scale to pre-commercial demonstration

SO 2 Reduction 40 – 85 %

NO X 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 fo r 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 SO 2 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 SO 2 reductions of 40 – 50 percent are a ppropriate. In this section, the focus is on technologies involving the injection of a cal cium- 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. SO 2 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 fr om the water injection. Low approach-to-saturation temperatures enhance the ensuing reactions, therefore maximizing the SO 2 reductions. Several different approaches to the technology have been de veloped 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 dire ct spraying of lime slurry into the ductwork between

3-19the 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 SO 2 removals than duct injection of dry hydrated lime.

Specialized processes and additives to improve the perfo rmance 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; Genera l Electric's In-Duct Scrubbing (IDS) process, an in-duct spray drying system based on a rotary atomizer; and EPA's E-SO X process, consisting of an array of spray nozzles fitted into a cavity created by rem oving the internals from the first field of an ESP.

Duct Injection - Dry Lime with Humidification The use of dry hydrated lime requires separate inj ection of water, upstream or downstream of the lime injection point, to activate the lime. The water is fi nely atomized to enhance evaporation and to avoid wetting the duct walls. As with lime slurry, a numbe r 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-SO 2 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 Sy stem injects hydrated lime and water between an ESP and a downstream FF

Duct Injection - Sodium Compounds The use of sodium-based processes not requiring wate r 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 extens ively during the mid 1980’s but never gained wide commercial acceptance. However, significant experien ce 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 Elec tric Muskingum River Station 3

E-SO X U.S. EPA Burger Station 4

3-20Table 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 Ca meo 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 Wash ington Unit No. 3 Port Washington, WI 12

Emission Control Performance The results from the various programs indicated SO 2 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 me rcury reduction from these programs.

O&M Impacts The major potential O&M impacts associated with SO 2 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 SO 3 dew point and, thus, intensifying corrosion and reducing bag life,

 impact on plume visibility from formation of NO 2 (for sodium-based sorbents),

 increased solid waste flow rate and associated a uxiliary 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.

3-21Capital 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 exp ected 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 drye rs (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 SO 2 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 complianc e strategies and increased use of low sulfur coals may make this technology an attractive option for sma ller 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 SO 2 Control Processes; EPRI TR-104594; Electric Power Research Institu te: 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-SO X 5-MW Pilot Demonstration. Proceedings of the 1990 SO 2 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 SO 2 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 SO 2 Control. React. Solids 1988

, 6 , 243.

8. Rhudy, R. G.; Carr, R. C. Pilot-Scale Evaluation of the HYPAS SO 2 and Particulate Matter Removal Process. Presented at the Sixth Annual Co al 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.

3-2210. 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 SO 2 and Simultaneous SO 2 /NO X 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 Desulfurizati on Using Dry Sodium Inj ection. Proceedings of the 1990 SO 2 Control Symposium, New Orleans, LA, May 8-11, 1990.

12. Coughlin, T.; Schumacher, P.; Hooper, A. R. Injec tion of Dry Sodium Bicarbonate to Trim Sulfur Dioxide Emissions. Proceedings of the 1990 SO 2 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 SO 2 Control Symposium, St. Louis, MO, Oct 25-28, 1988.

15. Smith, P. V. Dry Sorbent Injection and Acid Ra in Compliance. Presented at: Power-Gen ’90, Environmental Trends and Issues, Orlando, FL, Dec 4-6, 1990.

16. Weilert, C. V. Statistical Analyses of FGD Sy stem 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 Sorb ent 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 Ba sed 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.

3-233.2.1.2.3 Combined Mercury and SO 2 Sorbents

Combined Mercury and SO 2 Sorbents Summary

Status Pilot scale to commercial

SO 2 Reduction, % 40 – 85

NO X 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 fo r 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, th e basic technologies for sorbent injection involve the injection of a sorbent into the flue gas at temperatur es 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, multi pollutant-capability sorbents. In this section, a brief summary of combined and multipollutant sorbents is provided.

Commercial Readiness and Industry Experience Data from the mercury ICR 1-3 program demonstrated that dry scrubbers remove mercury and SO 2 , suggesting the ability of calcium-based sorbents to enhance mercury capture in addition to SO 2 . 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 SO 2 -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 baghouse 4 and into a specialized fluidized bed reactor. 6 Combining activated carbon with hydrated lime can reduce the amount of carbon required (for an equiva lent 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-b ased sorbents for mercury control 8,10 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 HgCl 2 from simulated flue gas at 100 °C (although less th an commercial activated carbon). Addition of SO 2 to

3-24the gas mixture decreased the sorption of HgCl 2 , suggesting that there is competition for the same alkaline sites between the two species. In contrast, the calci um-based sorbents showed little or no removal of Hg 0
in the absence of SO 2 . Addition of SO 2 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 calci um-based sorbents. More recently, hydrated lime and silicates have been evaluated for mercury, NO X , and SO 2 capture in benchscale tests. Oxidant-enhanced silicate sorbents i ndicated 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 al kaline 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 Station 4,7 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 ot her tests using sodium sesquicarbonate and sodium bicarbonate injection, SO 2 reduction was up to about 90 percent for the bicarbonate and about 20 percent for sesquicarbonate. In other test s at PSE&G’s Mercer Station, 6 injection of activated carbon and hydrated lime into a fluid bed reactor resulted in mercury re movals of up to 80 percen t with iodine-impregnated carbon at a ratio of 1000:1 and about 67 percent for non-impregnated carbon at a ratio of 2000:1. SO 2 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 SO 2 sorbent technologies, it is expected that combined pe rformance will be similar to that of the individual technologies, while the development of new sorbents ma y optimize the utilization and efficiency of future technology applications.

O&M Impacts The major potential O&M impacts associated with comb ined and multipollutant sorbent injection include the following:

 increased particulate loading to the ESP or FF,

 impact of reaction products on particulat e resistivity and associated ESP performance,

 low flue gas temperatures (if spray cooling is used) affecting SO 3 dew point and, thus, intensifying corrosion and reducing bag life,

 impact on plume visibility from formation of NO 2 (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 extrem e the combination of activated carbon and SO 2 sorbent injection technologies would cost no more (likely less) than th e 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.

3-25O&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 SO 2 Sorbent Injection; Future Outlook The same issues apply as for the application of the individual activated carbon and SO 2 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 Conferen ce 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 92 nd 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 Agglomerati on. 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. Pr eparation and Evaluation of Modified Lime and Silica-Lime Sorbents for Mercury Vapor Emissions Control. Proceedings of the U.S. EPRI-DOE3-26EPA 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 Conferen ce on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, Aug 20-23, 2001.

10. Ghorishi, S. B.; Sedman, C. B. Low Concentra tion 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 Sy stem 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 SO 2 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 sc rubbers have been shown to be efficient devices in capturing oxidized me rcury in the flue gas. 1-7 This fact has triggered a number of developments geared towards understanding and promoting the oxidation of el emental 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 oxida tion and reagent injection approaches for mercury oxidation. In addition, and as a result of developm ents in wet precipitator technology (WESP) and the compatibility of WESPs with wet scrubbers, the wet scrubber-WESP combination represents another system approach to combined SO 2 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 secti on 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 SO 2 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 coo ling and reaction with limestone slurry to produce amix 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 th rough 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 “mec hanical” 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 [a dipic acid or dibasic organic acid (DBA) used most often], which not only improve overall SO 2 capture but also help the settling characteristics of the waste

3-27products. Several commercial variations of the technol ogy 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 poten tially an excellent mercury control mechanism.

3.2.1.3.1 Wet Scrubbers with Mercury Oxidation Processes

Wet FGD with Mercury Ox idation Processes Summary

Status Under development, Pilot-scale testing

SO 2 Reduction, % 95

NO X 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 ar ea of mercury oxidation in the flue gas, upstream of wet scrubbers involve catalytic oxidation 5,7 and oxidation resulting from reagent injection. 6,8 One other approach injects chlorine into the flue gas to form HgCl 2 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 NO X control) to oxidize elemental mercury. While catalyst development and testing are at the laboratory scale, full-scale application would likely involve a conventi onal support structure (honeycomb) placed between the particulate control device and the wet scrubber. A num ber of catalyst materials have been investigated at several test sites including carbon, palladium, iron, and high carbon fly ash 8 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 r eagents 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 HgCl 2 ). The flue gas injection approach is expected to promote the conversion of HCl to Cl 2 in the flue gas, thereby providing a pathway for the formation of HgCl 2. The direct scrubber injection approach involves the addition of small amounts of a proprieta ry 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 pilo t-scale development. Laboratory- and pilot-scale tests funded by the DOE and EPRI have identified several cat alyst materials successful in oxidizing elemental mercury. Further testing of these catalysts has fo cused on two issues associated with the catalytic oxidation process: (1) catalyst life and (2) the app licability 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.

3-28Reagent-based Oxidation Reagent tests have been conducted for wet scr ubber 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 (l imestone forced oxidation system). Further tests of the technology at Zimmer Station (magnesium enhan ced lime) demonstrated av erage Hg removal across wet FGD of 51 percent. 10

Emission Control Performance Catalytic Oxidation In laboratory- and pilot-scale tests, several of the cat alysts tested exhibited levels of elemental mercury oxidation in the 70 to 95 percent range. In partic ular, 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 fi ve 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 propri etary reagents with no adverse effects on scrubber operation or SO 2 removal. This is in comparison to baselin e (no reagent) removal of mercury across the scrubber of about 72 percent. 10

O&M Impacts There is not sufficient information at present to asse ss 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 auxilia ry power consumption by up to 1.5-2.5 percent.

Capital Costs Wet scrubber: $160-273/kW; 11 as low as $103/kW reported 12 Catalytic oxidation: estimated for 400 MW plant to be about $5/kW 5 Reagent Injection: NA

O&M Costs Wet scrubber

 Fixed O&M: $1.2-14/kW-yr 13 (for a range of coal sulfur from 0.4 to about 3.5 percent)

 Variable O&M: 0.1-1 mill/kWh 13 (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 tes ting. Further testing of the potential for oxidation of other flue gas elements, including SO 2 and NO, should be carried out. Parallel research to characterize the stability and fate of mercury in the FGD sludge or gypsum is ongoing.

3-29Reagent-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 21 st 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 Sympos ium: The MEGA Symposium and The A&WMA Specialty Conference on Mercury Emissions: Fate, E ffects, 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 Cont rol 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 Conferen ce 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. Pro ceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant Control Sympos ium: The MEGA Symposium and The A&WMA Specialty Conference on Mercury Emissions: Fate, E ffects, and Control, Chicago, IL, Aug 20-23, 2001.

6. Milobowski, M. G. Wet FGD Enhanced Merc ury Control for Coal-Fired Utility Boilers. Proceedings of the U.S. EPA-DOE-EPRI Comb ined 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 Emissi ons 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 SO 2 Control Symposium, Miami, FL, March 28-31, 1995.

3-3012. Miller, M.; Webster, L.; Rader, P.; Bussell, C. Centralia WFGD System, State-of-the-art SO 2 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 C ontrol, Chicago, IL, Aug 20-23, 2001.

13. Weilert, C. V. Statistical Analyses of FGD Sy stem 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 Elemen tary 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

SO 2 Reduction, % 99

NO X 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 th e design and maintenance parameters. 1 While dry ESPs are typically limited to power levels of 100-500 watts per 0.47 m 3 /s (1,000 cfm), WESPs can handle power levels as high as 2,000 watts per 0.47 m 3 /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 coll ection 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 ga s flows in tubular or plate designs. Tubular designs offer smaller footprints and, in general, are more efficient than the plate type.

3-31WESP 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 optio n 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 wa ter 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 standa rd technology in abating the submicrometer particle SO 3 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 confi guration. 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 op eration 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 petr oleum 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 sulf ur 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 m 3 /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 SO 3 and PM 2.5 and stack flow with near-zero opacity. 7,8

Emission Control Performance When integrated with upstream technology, includin g 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, PM 2.5 , and metals. It achieved 78 percent removal of

mercury. 1,2 At a mining operation, a combined scrubber and WESP system achieved an SO 2 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 SO 2 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 Sout hern Research Institute, 9 a plate type WESP yielded the following removal results:

 SO 2 : 10 – 25 percent

 SO 3 : ~ 65 percent

 PM: 90 – 99 percent

 Hg: ~ 30 percent

3-32O&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 ra nges 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 desi gn configuration. If special alloys are necessary, due to acid gas concentrations, the costs could be considerably highe r. Non-metal materials are being investigated with the potential for cost reduction. Note that these costs refer to the WESP only, not the SO 2 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, a nd corona current suppression. Integration with wet scrubbers can offer significant advantages to wet scrubbe r 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 Demons trating Promise for Fine Particulate Control: Croll-Reynolds Clean Air Technologies. Power Eng . Jan 2001

.

2. Altman, R. Wet Electrostatic Precipitation Demons trating Multiple Pollutant Control in Industrial Applications Holds Promise for Coal-Fired Utility Emission Reduction of Acid Mist, PM 2.5 , and Mercury. Proceedings of the U.S. EPA-DOE-EPR I 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? Pro ceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant Control Sympos ium: The MEGA Symposium and The A&WMA Specialty Conference on Mercury Emissions: Fate, E ffects, 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 a nd 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.

3-338. Reynolds, J.; Buckley, W.; Ray, I. Advances in Wet Electrostatic Precipitation Technology at Fossil Fuel Power Plants for Multipollutant Cont rol. Presented at the ICAC Forum’03, Nashville, TN, Oct 2003.

9. Monroe, L. S. Testing of a Combined Dry and We t Electrostatic Precipitator for Control of Fine Particle Emissions from a Coal-Fired Boiler. Pr oceedings 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 Elect rostatic Precipitation/Demonstrating Multiple Pollutant Control in Industrial Applications Holds Promise for Coal-fired Utility Emission Reduction of Mist, PM 2.5 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

SO 2 Reduction, % (>90 with FGD)

NO X 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 demons trated 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 SO 2 , 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 PM 2.5 and SO 3 mist in a two-field electrical configuration 2 with the ESP after an FGD system. In addition, 40 percent removal of elemental mercury and greater than 70 percent removal of particulat e and oxidized mercury were achieved in a single electrical field configuration.

3-34The ability of Wet ESP to remove elemental mercury can be enhanced further through Plasma-Enhanced ESP (PEESP) technology. PEESP oxidizes vapor phase elemen tal 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 el emental mercury vapor to form oxidized mercury particles. These negatively charged particles are attr acted to the positively charged collecting electrode where they are collected. The mercuric oxide partic les 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 tes ting will commence later in 2004.

Emission Control Performance The supplier projects that up to 90 percent total merc ury removal can be achieved at pilot and full scale. Bench scale testing 3 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 t echnology is at an early stage of development.

Issues Associated with the Technology; Future Outlook There has been limited mercury removal experience wi th Wet ESPs. What has been reported shows some oxidation of elemental mercury and capture of particul ate and oxidized forms of mercury similar to that for PM 2.5
. 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-econom ic assessment to develop a more comprehensive picture of its cost-effectiveness. Additionally, furt her 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.

3-353. Montgomery, J. L.; Battelson, D. M.; Whitworth, C. G.; Ray, I.; Buckley, W.; Reynolds, J.; Altman, R. Plasma-Enhanced Electrostatic Preci pitation Technology for Control of Elemental Mercury. Presented at Power-Gen 2002, Orlando, FL, Dec 2002.

4. Wet Electrostatic Precipitation Demonstrati ng 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 Plas ma-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

SO 2 Reduction, % Existing scrubber

NO X 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) c oncept 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 fi eld 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 fa bricated to allow testing of full-length (10-foot long) plates. Table 3-5 summarizes the test conditions a nd results at the four sites. The sites included two PRB units, one equipped with an ESP (probe locat ed 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

3-36Table 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) SO 2 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 en abling 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 locat ed downstream of a 1 MW pilot wet absorber, which receives flue gas from Unit 1. 1

Additional tests will evaluate the ability to thermally re generate the gold-coated plates. The results of this study will provide data required for assessing the f easibility and estimating th e costs of a full-scale MerCAP process for flue gas mercury removal. Th e 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 ove r 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 per cent of mercury. In the tests conducted to date in flue gas derived from low rank fuels, this perfo rmance was achieved downstream of a spray dryerbaghouse. Similar results have recently been obtaine d 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 sorben t material that is cheaper or has higher mercury capacities than gold. Development work is needed to evaluate these op tions 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 H 2 O 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 percen t 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

3-37capital cost, $2.3 million is the gold media and its subs trate. 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 engin eering 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 merc ury 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 go ld for specific flue gas
conditions



### . 2

References

1. Control Technology Evaluation of MerCAP TM 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 Demonstrati on of Mercury Control by Adsorption Process (MerCAP TM ). Presented at the MEGA Symposium, Washington, DC, May 2003.



### 3.2.2 SO 2 

### and NO X 

### Control

3.2.2.1 Electron Beam Process
Electron Beam Process Summary

Status Early commercialization stage

SO 2 Reduction, % >95

NO X 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 SO 2 and NO X 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 af ter 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

3-38dry 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 chambe r where the flue gas is irradiated by a beam of high-energy electrons, while water is added to count eract the temperature rise. The irradiation also generates hydroxyl radicals and oxygen atoms, which oxidize the SO 2 and NO X . 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 amm onium 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 ES P-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 st age with a number of demonstration plants in operation, but no operating commercial applications. Eb ara International Corp. is actively promoting this technology, but others are preparing to offer relate d 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 SO 2 removal process only. Future market acceptance of this technology will depend on whether it is cheaper than the combination of individual SO 2 and NO X controls for the levels of SO 2 and NO X emissions required. Another major factor

3-39will be the price that can be obtained for the fer tilizer by-product. Should it be possible to sell the fertilizer by-product, this reve nue 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 Nm 3 /h) of the 200 MW boiler firing Australian coal. The emission reductions achieved were: 92 percent SO 2 and 60 percent NO X . After the successful operation of this plant, Chubu decided to install the E-beam process in the Nishi-Na goya 1 unit, which burns high-sulfur residual oil.

Also, the E-beam process was demonstrated at th e Chengdou Power Plant in Sichuan Province, China. The plant is 90- MW and has been operating since July 1997. SO 2 removals have been in the mid-80 percent range and NO X removal was between 15 and 20 percent using low-to-high-sulfur bituminous coal (600 – 2500 ppm inlet SO 2 ). 6

Emission Control Performance The E-beam process is capable of achieving SO 2 removals of 95 percent or greater and NO X removals of about 90 percent. High SO 2 removals require a minimal E-beam dose, generally much lower than the Ebeam dose necessary for NO X removal. Once the minimum E-beam dose is achieved, the primary factors affecting SO 2 removal are flue gas temperature and ammonia stoichiometry. The E-beam dosage required for 90 percent SO 2 removal is a minimum of 1.0 mrad.

The removal of NO X depends primarily on the E-beam dosage; temperature and SO 2 concentration are of secondary importance. Higher NO X removals require higher radiation dosages. A dose of about 0.3–0.6 mrad is required to achieve 50 percent NO X removal, and 90 percent NO X removal requires at least 2.7 mrad according to the data obtained to date. 7,8 Higher NO X removals are obtained at higher temperatures, contrary to SO 2 removal. Higher SO 2 concentrations also improve NO X removal, making the process better suited for high-sulfur applications. Furthermor e, additional particulates are removed in the new ESP or FF.

O&M Impacts The energy requirement for E-beam depends greatly on the NO X reduction being sought; when significant NO X 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 SO 2 removal of 80 percent and NO X removal of 10 percent. When NO X 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 po wer requirements and the ammonia injection. Early studies project that the total O&M costs are 11-15 mill s/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-produc ts. A concept has been pr oposed 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

3-40this 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 signi ficant amount of electricity, up to 5 percent of the plant output depending on the required NO X removal.

References

1. Hirano, S.; Aoki, S.; Izutsu, M.; Yuki, Y. Simultaneous SO 2 , SO 3 , and NO X 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 Appli cation Experience with Technology of SO 2 and NO X 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 Syst em. 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 G as 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 Technol ogy 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 SO 2 /NO X Removal by Electron-beam Processing. Presented at the 4 th Symposium on Integrated Environmental Control, Washington, DC, March 2-4, 1988.

3-413.2.2.2 ROFA-ROTAMIX (Mobotec)

ROFA-ROTAMIX Summary

Status ROFA and ROTAMIX commercially available for NO X reduction; ROTAMIX demonstr ated on a 150 MW coal-fired unit

SO 2 Reduction, % 69 with Trona, 64 with limestone

NO X 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 SO 2 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 wi th the injection of sorbents for SO 2 and Hg control have not been resolved.

Technology Description Mobotec offers three NO X 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 RO TAMIX. According to the vendor, these two technologies are generally designed as one system; theref ore, they are considered a multi-emission control option. The in-duct SCR is an independent NO X 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 opp osite 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 ai r 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 NO X , SO 2 , and heavy metals (including mercury). In addition to the ROFA ports, lances are provided to inject the ch emicals. So far, Mobotec has used urea and ammonia for NO X reduction, CaCO 3 for SO 2 control, and is considering ad sorbents 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.

3-42Commercial 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-bo ttom boilers burning coal, heavy fuel oil, wood wastes, and municipal waste). In the U.S., ROFA-R OTAMIX has been recently installed at Carolina Power & Light’s (CP&L) Cape Fear 5 and 6, T-fire d 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 SO 2 was achieved using CaCO 3
.
Emission Control Performance The 17 ROFA retrofits in Sweden (mainly stoker-fire d, fluidized-bed, and dry-bottom boilers burning coal, heavy fuel oil, wood wastes, and munici pal waste) achieved an average of 50 percent NO X reduction with ROFA, while maintaining CO emissions and reducing excess O 2
.
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 pow er, achieved 55 percent NO X 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 a nd increased auxiliary power due to the high-volume ROFA fan [820 kW (1100 HP)].

The combination of ROFA-ROTAMIX at Jordberg a (78 MW coal-fired stoker boiler in Sweden) achieved 40 percent NO X reduction and 90 percent SO 2 reduction. 1 The same performance (especially with regard to the SO 2 reduction) has not been confirmed in pul verized coal boilers, which operate at significantly higher temperatures than stokers.

The combination of ROFA-ROTAMIX has been insta lled in CP&L’s 154 MW coal-fired Unit 5 at the Cape Fear Generating Station for the multipollu tant technology evaluation program. The program included injection of CaCO 3 to determine the effect on SO 2 and Hg reduction and injection of trona to determine the effect on NO X , SO 2 , HCl, and Hg reduction. SO 2 reductions of 69 percent were achieved with trona and 64 percent with CaCO 3 . Mercury reductions of 89 per cent 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 whic h 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.

3-430 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

40 60 80 100 120 140 160 180NOXEmissions, lb/MMBtu



### Gross Electrical Power, MW e Before ROFA

After ROFA

Figure 3-4. NO X 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 bo iler 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-specifi c (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 in to 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 CaCO 3
.

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 insta llation. 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 projec ted to be lower for larger boilers.

3-44Issues Associated with the Technology; Future Outlook The performance of ROFA in large boilers may degrad e, as the boiler dimensions increase and either the air penetration will be less efficient or a more pow erful 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 1 72 MW scale. Slagging of the superheater by sorbent (CaCO 3 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 su ch sorbents on boiler tube erosion is not known.

References

1. Moberg, G.; Blid, J. O.; Wallin, S.; Fareid, T.; Ralston, J. Combined DeNO X /DeSO X and Additional NO X 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 Co mbined Combustion and Post Combustion NO X 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: NO X , SO 2 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 SNO X TM

SNO X Summary

Status Early commercial stage; two commercial plants in operation in Europe

SO 2 Reduction, % Above 90

NO X 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

3-45Technology Description As shown in Figure 3-5, the SNO X 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 SO 2 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 NO X is reduced with small quantities of ammonia in the first of two catalytic reactors where the NO X is converted to nitrogen and water vapor. If the heat available in the gas stream is not adequate, supplem ental heating maybe used (see preheat burner in front of the baghouse or the SO 3 reactor). The SO 2 is oxidized to SO 3 in a second catalytic converter (SO 3 Reactor). Then, the gas passes through a novel glass-tube condenser (WSA: W et gas S ulfuric A cid condenser) that allows the SO 3 to hydrolyze to concentrated sulfuric acid.

Because the SO 2 catalyst follows the NO X catalyst, any unreacted ammonia (slip) is oxidized in the SO 2 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. SNO X 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 operati on in 1999. Initially, the technology was tested at a pilot plant of Elsam (Danish utility) in a flue gas stream of 10,000 Nm 3 /h. From 1991 to 1993, the following demonstrations took place:

3-46 Gela (Italy) of Enichem SpA; Gas: 100,000 Nm 3 /h with 600-4,000 ppm SO 2 and 500 ppm NO X in the inlet

 Vodskov (Denmark) of ELSAM; Gas: 1,000,000 Nm 3 /h (approximately 305 MW) with 200-2,000 ppm SO 2 and 550 ppm NO X in the inlet

 Niles (USA) of Ohio Edison; Gas: 132,000 Nm 3 /h with 2,000 ppm SO 2 and 500-700 ppm NO X in the inlet

 Vresova (Czech Republic) of Sokolovs ka Uhelna A.G.; Gas: 54,000 Nm 3 /h with 2.4-3.6 H 2 S and 200 ppm NO X in the inlet

 Kawasaki plant (Japan) of Asahi Chemical Industry Ltd; Gas: 50,000 Nm 3 /h with 5.7 percent SO 2 and 100 ppm NO X in the inlet

The U.S. demonstration was conducted at Ohio Ed ison'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 ope rating 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
Nm 3 /h of flue gas from a petroleum-coke-fi ring facility having 2,380 - 4,600 ppm SO 2 and 330 ppm NO X in the inlet of the SNO X process. 3 The Gela plant is designed for 94 percent SO 2 removal and 90 percent NO X removal.

Emission Control Performance SO 2 and NO X removal efficiencies above 90 percent have been achieved. At Ohio Edison's Niles demonstration, SO 2 removal was approximately 94 percent with inlet concentrations averaging about 2,000 ppm SO 2 and NO X removal was 95 percent with inlet NO X in the 500 - 700 ppm range. 4 In addition, particulates are expected to be reduced, re lative to the original system with ESP.

SO 2 removal is controlled by the efficiency of the SO 2 -to-SO 3 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 cat alyst necessary at design flue gas flow conditions, and the gas and bed temperatures have to be high enough to activate the SO 2 oxidation reaction.

Particulates are very low, usually below 1 mg/Nm 3 . At Niles, air toxics were tested and showed high capture efficiency of some trace elements in the ba ghouse. 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 b een 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

3-47Costs Costs for retrofitting a 500 MW plant with the SNO X process are projected to be 305 $/kW (EOY 1995 dollars) resulting in 6.1 mills/kWh levelized costs 3 (over a 15-year period). Using the CEI (Chemical Engineering Annual Plant Index), the adjusted co st in EOY 2000 dollars is 315 $/kW. Presently, the supplier projects that the SNO X 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 technol ogy is its cost-effectiveness in reducing SO 2 and NO X relative to competing technologies.

References

1. Clean Coal Technology Demons tration Program: Update 2000 ; U.S. DOE, National Energy Technology Laboratory: Pittsbur gh, PA, April 2001; 5-74.

2. SNO X Flue Gas Cleaning Demonstration Project: A DOE Assessment; U.S. DOE/NETL2000/1125: Pittsburgh, PA, June 2000.

3. Bruno, L.; Ricci, R. Application of SNO X 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 C oal-fired Power Plant Utilizing the SNO X Innovative Clean Coal Technology Demonstr ation, Vols. 1 and 2; DOE/PC/93251-T3; U.S. DOE: Washington, DC, July 1994.

7. Andeasen, J.; Laursen, J. K.; Bendixen, O. R. SNO X 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 SNO X process for use in the boiler at 2.00 $/MMBtu

3-483.2.2.4 SO X -NO X -Rox Box (SNRB TM )

SNRB Summary

Status Pilot stage

SO 2 Reduction, % 80 – 90

NO X 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 SO 2 , NO X , and particulates in one unit - a high-temperature baghouse. 1,2 

### It o perates in the 425-455 °C (800-850 °F) temper ature range and is placed before the air heater. SO 2 removal is accomplished using either calcium- or sodium-based sorbent, sodium carbonate (Na 2 CO 3 ), and sodium bicarbonate (NaHCO 3 ), injected into the flue gas upstream of the baghouse. NO X removal is accomplished by injecting ammonia (NH 3 ) to selectively reduce NO X 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 pa rticulates, its primary design function.

Commercial Readiness and Industry Experience The SNRB technology requires further demonstration on a 50-100 MW scale. It has been demonstratedsuccessfully 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

 SO 2 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),

 SO 2 removal efficiency of 90 percent with sugar-h ydrated and lignosulfonate-hydrated lime at a Cato-S ratio of 2.0 and temperature of 425-455 °C (800 - 850 °F),

 SO 2 removal efficiency of 80 percent with s odium bicarbonate at a sodium-to-sulfur (Na 2 -to-S) molar ratio of 1.0 and temperature of 220 °C (425 °F),

 SO 2 emissions were reduced to less than 1.2 lb/MMBtu, 80-85% SO 2 reduction, with 3-4 percent sulfur coal with a Ca-to-S molar ratio as low as 1.5 and Na 2 -to-S ratio of 1.0,

 Injection of calcium-based sorbents directly ups tream of the baghouse at 440-480 °C (825-900 °F) resulted in higher overall SO 2 removal than injection farther upstream at temperatures up to 650 °C (1,200 °F),

 NO X reduction of 90 percent was achieved with an NH 3 -to-NO X 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 SO 2 removal, 90 percent NO X 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 ec onomics 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 NO X control, and their reliability is affected by both mechanical and thermal stresses due to cyclin g (changing operating c onditions) and cleanup of the bags. To address these concerns, a 3,800-hour durability test of three fabric filters was completed 2 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 conduc ted using 3M Company Nextel ceramic fiber filter bags or Owens Corning Fiberglas S-Glass filter ba gs. 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 temper ature 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 NO X emissions of 1.2 lb/MMBtu, 65 percent capacity factor, and 85 percent SO 2 and 90 percent NO X removal. Levelized cost over 15 years (constant U.S.$, 1994) is estimated to be 12.1 mills/kWh or equivalent to $553/ton of SO 2 plus NO X removed.

Issues Associated with the Technology; Future Outlook Considering that the technology has not been demons trated, 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 Demons tration Program: Update 2000; US DOE, National Energy Technology Laboratory: Pittsbur gh, PA, April 2001; 9-13.

2. Evans, A. P.; Kudlac, G. A.; Wolkinson, J. M.; Chang, R. SO X -NO X -Rox Box – High Temperature Baghouse Performance. Presented at the 10 th Particulate Control Symposium, Washington, DC, April 5-8, 1993.

3-503.2.2.5 THERMALONO X and FLU-ACE Process

THERMALONO X and FLU-ACE Process Summary

Status In demonstration

SO 2 Reduction, % Up to 95

NO X Reduction, % Up to 90 Hg Reduction, % NA

Cost

Capital ($/kW) THERMALONO X : $35/kW for 500 MW; FLU-ACE: Not available Fixed O&M ($/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 THERMALNO X process

Technology Description The THERMALONO X and FLU-ACE process is a two-step process. 1,2 The first step is the gas phase chemical reaction converting nitrogen m onoxide (NO) into nitrogen dioxide (NO 2 ). This is accomplished by direct phosphorus (P 4 ) liquid injection into the flue g as, which causes the release of ozone (O 3 ) that oxidizes NO into NO 2 . This NO to NO 2 conversion takes place in a specially designed reactor normally placed upstream of a wet scrubbing process.

The prevailing chemical reactions are:
P 4 + O 2 Æ P 4 O + O
P 4 O
n + O 2 Æ P 4 O n+1 + O, where n is 1 through 9 2NO + (O+O 3 ) Æ 2 NO 2 + O 2 2 NO 2 + H 2 O Æ NO 2 + NO 3 + H 2

In the second step the NO 2 is removed, as a water-soluble gas in the wet FGD process. In addition, as in the phosphoric acid manufacturing process, the solid P 4 O 10 particles that are formed in the duct from the first step, upon entering the wet FGD process are instan tly hydrated and hydrolyzed to form the dibasic phosphate (H 2 PO 4 - ) and the mono-basic phosphate (HPO 4 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 efficien cy by wet FGD and 98 percent by FLU-ACE. If the FGD cannot achieve the required NO X reduction, a FLU-ACE reactor can be added to boost the NO X reduction above 90 percent and remove other pollutants such as mercury, VOCs, and fine particulates.

The by-products of the THERMALONO X process are non-toxic nitrogen and phosphate compounds used as fertilizers and animal food additives.

The P 4 liquid is maintained at a constant temperature of 60 °C (140 °F) in the P 4 injection tank and is pumped continuously through a steam-traced closed piping circuit connecting the P 4 injection tank to the
P 4 atomization nozzle injection location in the flue gas duct. The P 4 injection rate is individually controlled to each nozzle via corresponding P 4 liquid flow control valves and atomizing steam pressure

3-51control valves to maintain optimum P 4 droplet size, physical dispersion, and chemical reaction in the duct. Atomization is done using steam, compressed air, or an aqueous emulsion of phosphorus.

When THERMALONO X is used, the existing wet FGD process mu st 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 NO 2 and SO 2 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 proj ect was suspended on Se ptember 27, 2001, during initial start-up. Tests were expected to last for 8-12 weeks with the target NO X reduction of 75 percent.

In parallel with the Conesville demonstration, Therma l Energy is carrying out an R&D program to test the THERMALONO X process with an existing FLU-A CE scrubber near Ottawa, Canada.

Emission Control Performance Thermal Energy projects 80-90 percent NO X removal for THERMALONO X with conventional FGD. 1 A combination of THERMALONO X and FLU-ACE is projected to achieve 98 percent NO X removal. In both cases, SO 2 removal is projected to be in the 90 – 95 percent range.

Key parameters affecting the THERMALONO X process are the flue gas temperature and oxygen concentration, which affect the reaction rate for converting NO to NO 2 , and therefore the reaction time required to achieve the desirable conversions (usual ly 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 NO X to P 4 ratio is projected by the supplier to be in the 3.0 - 4.0 range.

O&M Impacts Potential O&M impacts are associat ed with the ability to control the spontaneous reaction of the phosphorus and flue gas to produce ozon e. Also, if there is no market fo r the wastes, the ability to dispose of phosphate compounds needs to be assessed.

Costs Thermal Energy projects the cost of THERMALONO X 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 asso ciated 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 assess ed including the impact of phosphorus injection on by-product properties and economics.

3-52References

1. Hinke, T. V. Utility NO X 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 Mercur y 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 NO X 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 SO 2 

### , NO X 

### , and Mercury Control

3.2.3.1 Activated Coke

Activated Coke Summary

Status Commercial

SO 2 Reduction, % 90 – 98

NO X Reduction, % 15 – 80 (depends on SO 2 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 SO 2 -NO X -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 firs t 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 (NH 4 HSO 4 ); 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/Nm 3 (0.0124 grain/scf) when the inlet is kept below 200 mg/Nm 3 (0.0827 grain/scf).

In the second stage of the adsorption process, the activated coke acts as a catalyst in the decomposition of NO X 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.

3-53Activated 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 m 2 /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 (NH 4 HSO 4 ) 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 im plemented. After cooling, the activated coke passes through a vibrating screen to eliminate smaller partic les (fines) and then it is recycled back into the adsorber.

Cooling
water

Figure 3-6. Activated coke process flow diagram 7

SO 2 -rich gas can be reduced to H 2 S 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 adso rbed 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 requi red once every few years (1-3 years depending on the percentage sulfur and mercury in the coal). The c oke removed, representing approximately 1 percent of

3-54the 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 dispo sed of in a hazardous waste facility. Other methods of mercury removal or disposal are also considered, such as SO 2 -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-Forsc hung GmbH) and demonstrated at a 158,000 m 3 /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 a nd tested it in a pilot facility from 1981 to 1983. 4 Installations of the Mitsui activated coke process in Japan 5,6 and Germany include the following (designed for both SO 2 and NO X control unless otherwise indicated):

 31,775 Nm 3 /h at Mitsui’s power generating station (1984)

 236,000 Nm 3 /h at Idemitsu Kosan’s refinery on a residual fluidized bed catalytic cracking process (1987)

 451,000 and 659,000 Nm 3 /h boilers at EVO GmbH’s Arzberg power station in Germany (1987)

 323,000 Nm 3 /h at Hoechst AG’s power station in Frankfurt, Germany (1989)

 10,000 Nm 3 /h at Electric Power Development Corp.’ s (EPDC) Wakamatsu power station (1990)

 1,157,000 Nm 3 /h (350 MW) AFBC boiler at the Electric Power Development Corp. Takehara power station (1995), designed only for NO X reduction and achieved above 80 percent NO X reduction

Sumitomo of Japan has also developed its own ac tivated coke technology and provided a commercialsystem for the Electric Power Development Corp. Isogo station, a 600 MW power plant burning lowsulfur coal (flue gas flow rate of 1,806,000 Nm 3 /h). The activated coke process is designed for 95 percent SO 2 removal and 30% NO X reduction.

Sumitomo also has utilized this technology in si ntering plants of steel-making industry for SO 2 , NO X 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
[Nm 3 /h] Start up

A SO 2 900,000 1987

B SO 2 , NO X , Dust 1,300,000 1999

C Dioxin, Dust 1,552,000 2003

D SO 2 , NO X , Dust 1,300,000 2003

E SO 2 , NO X , Dust, Dioxin 1,350,000 2004

F SO 3 , NO X , Dust 1,650,000 2004

3-55Emission Control Performance SO 2 control efficiency has ranged from 90 to 98 percent and the NO X control efficiency from 15 to 80 percent. 1,5,6 NO X reduction is higher for lower SO 2 concentrations at the inlet of the adsorber. For example, 1000 ppm SO 2 concentration may result in NO X reduction in the 15 – 40 percent range, while 200 ppm SO 2 concentration will raise NO X reduction to above 70 percent. NO X reduction is also affected by the amount of ammonia injected (NH 3 -to-NO X ratio typically in 0.5-1.0 range results in above 70 percent NO X reduction), the oxygen concentration of the flue gas (lower excess O 2 results in lower NO X 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 proj ected. 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 we re not designed with mercury control in mind, but rather for SO 2 and NO X 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- NO X process, which means that either NO X emissions will be higher during start up or the ramp-up rate of the pl ant will be limited. Other O&M impacts are not known, mainly because of the lack of information and expe rience in the United States. Required auxiliary power is estimated to be 0.70 percent of the gross out put, 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: SO X 500 – 1,000 ppm, NO X 170 – 260 ppm and dust 140 – 200 mg/Nm 3 . 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, NH 3 , and fuel) are projected to be 1.3-2.1 mills/k Wh (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 le vel, 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-NO X system; so, NO X reduction in cycling units may suffer during start-up unless they ar e designed to utilize an external heat source to preheat the De-NO X 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 Denitr ification Technology for Coal-fired Power Plants; Brochure, May 2000.

3-563. Olson, D. G.; Tsuji, K.; Shiraishi, I. Th e 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 Desulfuriza tion, Denitrification, and Reduction of Air Toxics Using Activated Coke: 1. Activity of Activated Coke. Fuel 1997
, 75 , 549.

6. Tsuji, K.; Shiraishi, I. Combined Desulfuriza tion, Denitrification and Reduction of Air Toxics Using Activated Coke: 2. Process Applica tions 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 21 st Century – Multi-Pollutant Control Technology. Presented at the 28 th 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

SO 2 Reduction, % 98

NO X Reduction, % 90 Hg Reduction, % 90

CO 2 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.

3-57The 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 dischar ge reactor is the key component of the ECO process. Oxidation is accomplished through generation of a no n-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 temp eratures and pressures and have been widely used for commercial ozone (O 3 ) 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 applie d 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 spatia lly 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 wa ter and oxygen molecules present in the flue gas stream:

O 2 + e → O + O + e
H 2 O + e → OH + H + e
O + H 2 O → 2OH

In a flue gas stream, these radicals simultaneously oxidize NO X , SO 2 , and Hg to form nitric acid (HNO 3 ) and NO 2 , sulfuric acid (H 2 SO 4 ), and mercuric oxide (HgO), respectively. The above reactions leading to radical formation and the subsequent oxidation reac tions 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 para llel 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 pressu re drop across the reactor. Aerosols formed by the oxidation reactions, including HgO, HNO 3 , and H 2 SO 4 , exit the barrier discharge reactor in the flue gas stream. At this point the gas enters a condensing WE SP 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 n itric and sulfuric acids, which can be used in the industry for fertilizer and gypsum produ ction. Of course, the extent to which these by-products would be actually used depends on economics (supply and dema nd 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 Fi rst Energy’s R.E. Burger No. 5 unit 6,7 (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.

3-58Presently, 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 va riety 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 MW slipstream), the technology achieved the following emission reductions: 9

 90 percent NO X reduction,

 98 percent SO 2 reduction, and

 90 percent mercury reduction.

Solids Disposal and Dissolved MineralsDistillationUnit Dilute Acid

Figure 3-7. ECO process flow diagram.

It should be pointed out that these r esults were achieved with 337 ppm NO X in the inlet of the ECO system, approximately 40 percent higher than a similar installation with low-NO X burners.

3-59The early results from 50 MW demonstration (b y Powerspan Corp.) achieved the following:

 Greater than 90 percent NO X conversion in the reactor, total re duction of 65 percent, hindered by absorber performance

 Greater than 98 percent SO 2 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 NO X 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 th ese do not present any techni cal challenge, they will have some impact on the plant mass and energy balan ces, as well as the plant’s overall efficiency. At this point, there is not enough information to assess the magn itude of this impact, but it is not expected to be substantial.

The list of consumables and the by-produ cts 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 NO X reduction desired.

 Heat for the by-product crystallizer.

 Ammonia reagent – this can be estimated as roughly two moles of ammonia per mole of SO 2 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 th e balance of the amine for the conversion of NO X to ammonium nitrate and SO 2 to ammonium sulfate. These are estimated at around $150/ton of NO X removed and $15/ton of SO 2 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 NO X , 0.40 moles of ammonium nitrate are produced and for every mole of SO 2 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,

3-60Wheelabrator, The Andersons, and Powerspan perform ed 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 plan t modifications. It is the only comprehensive, fullscale cost analysis that has been ma de 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 determin ed by the molar ratio and specialty chemical costs are estimated at $150/ton of NO X removed and about $15/ton of SO 2 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 a nd ammonium nitrate fertilizer are widely traded commodity chemicals and their value will depend larg ely 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 react or is largely determined by the amount of NO oxidation needed and the gas flow. To increase the amount of NO X removed by the ECO process, it is necessary to increase reactor power. So, for a given percent of NO X reduction, the reactor power is roughly proportional to the NO X mass flow. Therefore, to achieve a low outlet NO X level while minimizing power demand, it is best to start with a low NO X level from the boiler. As a result, one would typically use an ECO system in combination with low NO X burners or other devices to minimize NO X 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•(NO X ) – 6.2431, where NO X is measured in lb/MMBtu. This is shown in Figure 3-8 below. Reactor power could poten tially be higher than 20 watts/scfm. However, this would likely be unattractive when compared to reducing NO X by other means such as low NO X burners. 10

Other power demands include fan power to overc ome 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 aux iliary 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 relativel y 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. Technolog y remains in the demonstration phase; therefore, performance and costs remain uncertain , especially for large-scale projects.

3-61Figure 3-8. ECO power consumption versus NO X .

References

1. McLarnon, C. R.; Jones, M. D. Pilot Testing and Scale-up of a Multipollutant Control Technology at FirstEnergy. Presented at the Po wer-Gen International Conference, Orlando, FL, Nov 15, 2000.

2. Kogelschatz, U.; Eliasson, B.; Egli, W. Dielectri c-Barrier Discharges Principle and Applications. Proceedings of the International Conference on Ph enomena in Ionized Gases, Toulouse, France, July 1997.

3. Penetrante, B.; Schultheis, S. Non-Therma l 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 NO X 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 NO X. 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 Fl ue Gas. Presented at the Conference on Air Quality II, McLean, VA, Sept 20, 2000.

8. Boyle, P.D., Operation of 50-MW ECO Commercia l 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 NO X ( lb/MMBTU )Power for 90 percent reduction,W/scfm



### NO X 

### (lb/MMBtu)

3-629. Boyle, P. D.; Steen, D.; Dovale, A. J. Commerc ial 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 SO 2 , NO X PM and Hg Removal from Coal-fired Boilers. Proceedings of the Combined Utility Air

SCR and Wet FGD

Status Commercial

SO 2 Reduction, % 95

NO X Re duction, % 90 – 95 Hg Red uction, % 40—90% dep ending on coal type

Cost

Capital ($/kW ) SCR: 50 -140; Wet FGD: 160-275 for a n ominal 400 MW plant Fixed O&M ($/kW-yr) S CR: 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

Issue s Need additional confirmation of merc ury oxidation levels in the SCR

Technology Description

elective Catalytic Reduction (SCR) – NO S X Control

CR technology 1 reduces NO X through a catalytically enhanced reaction of NO X 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 NO X to water and nitrogen “reactor” vessel. The reactor ensures that the flue g as determines the flue gas velocity. Typical catalyst ma terials 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 pr eheater, 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 reduc tion comes from the fact that SCRs have been

2-5 hown (also discussed in Section 3.2. 1.3) to oxidize elemental mercury. Thus, there is synergism with s

3-63wet scrubbers, which are effective in capturing oxi dized mercury. In fact, the SCR-wet scrubber

combination is conceptually similar to the appr oaches discussed in the wet scrubber section (catalytic and reagent-based mercury oxidation upstream of a wet scrubber).

Wet Scrubber As explained before in Section 3.2.1.3, the most commonly used we t scrubber technology uses a wet

mestone process with in-situ forced oxidation to remove SO 2 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 wi dely 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 leve ls rose from 81.9 to 94.1 percent. 2

esting catalyst may not be fully nderstood. Table 3-6, taken from Reference 3, summa rizes 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 ye ars 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 su ch as the addition of organic acids which not on improve overall SO 2 capture but also help the settling char acteristics 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 NO X 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&W 2,4 and EPRI 3 are 5,7 v

Emission Control Performance (Mercury Oxidation) SCR systems are widel

to Germany, mercury oxidation across the SCR increased HgCl 2 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 tests 3 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 ty pe and could range from 40 to 90 percent.

3-64Table 3-6. Selected SCR Test Results

Control Unit Co ntrol Unit Status Inlet Mercury Oxid ation (% 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 10 – 18 No ammonia 50

NH 3 injection sy stem 67 – 85 Normal 50 – 87

NH 3 injection sy stem 70 – 90 No ammonia 50 – 87

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 subseq uent 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 merc ury 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 th e 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

FSCR: $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 NO X and SO 2 reduction, this will result in a signi and inexpensive way to also control mercury emissions . Parallel research to ch aracterize the stability and fate of mercury in the FGD sludge or gypsum is ongoing.

References

1. Status Report on NO X Control Technologies and C NES

2. Milobowski, M.G. Wet FGD Enhanced Mercury Control for Coal-Fired Utility Boilers. Babcock & Wilcox Company. Proceedings of

3-65Air 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.

Richardson, C.; Machalek, T.; Miller, S.; Dene, C.; Chang, R. Effects of NO 3. s on Mercury Speciation in Utility Flue Gas. Proc eedings of the U.S. EPA-DOE-EPRI Combined

,

4. ski, G. T. How Low Can We Go? Pro ceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant Control Sympos ium: 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 Sympos ium: The MEGA Symposium and The A&WMA Specialty Conference on Mercury Emissions: Fate, E ffects, and Control, Chicago, IL, Aug 20-23 2001.

Bielaw

Specialty Conference on Mercury Emissions: Fate, E ffects, 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 Co mbined 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 NO X Controls for Coal-Fired Boilers

9. Bock, J.; Hocquel, M.; Hein, K. Mercury Oxid ation 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.

3-663.2.3.4 EnviroScrub Pahlman

EnviroScrub Summary

Status Pilot scale

SO 2 Reduction, % >99

NO X 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 NO X , SO X , 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 separ ation 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 (MnO 2 ) in the form of fine black powder. The sorbent is injected in a reactor, which opera tes at temperature between ambient and 320 °F. According to the supplier, different type of reactors are suitable including fluidized bed, baghouse, transport and cyclone. SO 2 and NO X react with the sorbent accord ing to the following reactions:

SO 2 + MnO 2 Æ MnSO 4 2 NO 2 + MnO 2 Æ Mn(NO 3 ) 2

Mercury vapor reacts with the Pahlmanite sorben t, which promotes oxidation to HgO followed by sorption by MnO 2
.
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, whic h dissolves the nitrate and sulfate salts of manganese. The chemical composition and opera ting 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 th e 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 me rcury compounds. These solutions may then be

3-67precipitated 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 wash ing and filtration system is sent to a chemical regeneration process to produce base and oxidizer ch emical 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 SO 2 and NO X .

 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 condu cted on the exhaust gas stream of Unit 1, a 75 MW boiler, which currently operates without any fo rm of back-end emission control systems for NO X and SO 2
.

 Potlatch Corp. Northwest Paper Division’s facility lo cated 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 NO X concentration output of approximately 133 ppm. 4

Emission Control Performance Results from Minnesota Power’s Boswell testing indica te that the technology achieved above 99 percent SO 2 reduction and 94-97 percent NO X reduction. 1 Also, the Hutsonville facility achieved over 99 percent SO 2 and 75 percent NO X reduction 4 on 1750 ppm SO 2 and 300 ppm NO X inlet.

According to the supplier, the technology also controls mercury and particulates (PM 2.5 ). 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 sp ecific 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 compre hensive picture of its cost-effectiveness. Also, removal efficiencies of mercury and pa rticulates 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 Duct s at Minnesota Power’s Boswell Energy Center in Cohasset, MN; Submitted to Minnesota Power, Dec 18, 2001.

3-682. Coal Plant Achieves 99% NO X and SO X 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)
SO 2 Reduction, % 95% due to the FGD which is part of the system
NO X Reduction, % 70-95% Hg Reduction, % Up to 90%
CO 2 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 NO X to higher oxides of nitrogen such as N 2 O 5 , and mercury to HgO. 1-7 Subsequently these compounds are removed in a wet FGD, because they are water-soluble. As Figure 3-8 8 shows, the LoTOx system consists of an in tegrated ozone-from-oxygen ge neration 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 sy stem, in response to the amount of NO X present in the flue gas generated by the combustion or process source. Upon in jection of the ozone in the flue gas (typically below 300 °F), oxidation occurs according to the following simplified reactions: 9-12

NO + O 3 → NO 2 + O 2 2NO 2 + O 3 → N 2 O 5 + O 2 Hg 0 + O 3 → HgO + O 2

N 2 O 5 and HgO are water soluble. In the presence of water, N 2 O 5 forms HNO 3 , which further reacts with alkali compounds or alkaline earth metals to form corresponding nitrates:

2HNO 3 + CaCO 3 → Ca(NO 3 ) 2 + CO 2 + H 2 O

The selection of wet FGD type (lime, limestone or ammonia) does not impact the performance of the LoTOx process because the solubility of N 2 O 5 is significantly higher than that of SO 2
.

3-69Theoretically, there is the potential for oxidation of SO 2 to SO 3 ; however, as proven in field testing, the reaction rates are very low compared to the predominant NO X reactions.

Fan 

### Economizer

Forced Draft Fan Induced Draft Stack 

### Boiler

Booster Fan

F G D Scrubber

LoTOx Reactor

Temperature Control Coldbox

Ozone Generator O 2

Cooling Water Vaporizer Air Purifier Air Compressor

Liquid Oxygen Cooling Water

Figure 3-8. Schematic diagram of LoTOx TM 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 appli cations. Also, LoTOx has been installed at a lead recovery furnace (25,000 scfm) which is operating presently. 14 LoTOx technology for NO X control is being considered by the refining industry to be used with wet SO 2 scrubbers and a number of commercial installations are expected to be operating by 200 5-07. 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 NO X reduction has been achieved and projected for large-scale applications. As Figure 3.9 shows, NO X outlet levels of less than 5 ppm have been achieved. Similar NO X reductions have been achieved in other facilities. For example, the 4,500 scfm metal pickling application achieved approximately 84 percent NO X reduction from 1100 ppm inlet, while th e natural gas-fired boiler of 8,000 scfm achieved nearly 98 percent NO X reduction (4 ppm outlet NO X emissions). Finally, LoTOx at the lead recovery furnace averaged 80 to 95 percent NO X reduction. 8,15

BOC normally recommends installati on of LoTOx alone when inlet NO X 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 NO X removal. By combining the two

3-70technologies, 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 SO 2 removal efficiency of the FGD by approximately 5 percent (depending on the FGD design) and has no impact on SO 3 emissions.

O&M Impacts O&M impacts are expected to be mi nimal since the LoTOx technology is injecting ozone in the flue gas. According to the supplier, auxiliary power requi rements 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 NO X level and unit size.

The supplier estimates the fixed O&M costs to be appr oximately 2.5 percent of the capital costs. In the electric utility industry, annualized costs are typically $1,200-2,200 per ton of NO X 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 Coals 8

Coal Type Typical Hg 2+ 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%

3-71Performance 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

: 0 0

: 0 0

0

: 52:00

1 : 4 4 :00

2

: 3 6

: 0 0

3

: 2 8

: 0 0

4

: 2 0

: 0 0

5

: 1 2 :00

6

: 0 4 :00

6

: 5 6

: 0 0

8

: 4 5

: 1 5

9

: 3 7

: 1 5 10:

2 9

: 1 5 11:

2 1 : 15 12:

1 3

: 1 5 13:

0 5

: 1 5 13:

5 7

: 1 5

1 4:

4 9

: 1 5 15:

4 1 : 15 16:

3 3

: 1 5 17:

2 5

: 1 5 18:

1 7

: 1 5

1 9:

0 9

: 1 5 20:

0 1 : 1 5 20:

5 3

: 1 5 21:

4 5

: 1 5 22:

3 7

: 1 5

2 3:

2 9

: 1 5

TimeNOx PPM

0 5000 10000 15000 20000 25000 30000 35000 40000Flue 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. NO X with LoTOx at MCO’s 25 MW-thermal gas and coal fired boiler. 13

References

1. Skelley, Authur P.; et al. Process for Removing NO X and SO X from Exhaust Gas. U.S. Patent 5,316,737, May 31, 1994.

2. Skelley, Authur P.; et al. Process for Removing NO X and SO X from Exhaust Gas. U.S. Patent 5,206,002, April, 27, 1993.

3. Skelley, Authur P.; et al. Low Temperature NO X / SO X Removal. U.S. Patent 4,999,167, May 12, 1991.

4. Saxena, Neeraj; et al. Removal of NO X and SO X 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 NO X 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 NO X Reduction. Adv. Env. Res

. 2000, 3 (4), 424-438.

3-728. Jarvis, J. B.; Day, A.;T.; Suchak, N. J. LoTOx TM 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 NO X , SO X , 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 NO X Emissions. Presented at ICAC Forum 02, Houston, TX, Feb 13, 2002.

11. Anderson, M. H. A Low Temperature Oxidation System for the Control of NO X 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. LoTO X System Demonstration for Coal-Fired Combustor. Presen ted 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 NO X 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 NO X Control. Presented at Power-Gen 2000, Orlando, FL, Nov 14, 2000.

16. Ellison, W. Chemical Process Design Alternatives to Gain Simultaneous NO X Removal in Scrubbers. Presented at the ICAC Forum’03, Nashville, TN, Oct 2003.

3-733.2.3.6 K-Fuel

K-Fuel Summary

Status Components of technology commercial

SO 2 Reduction, % Up to 30% (relative to raw PRB coal or lignite)

NO X 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 Description 1 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 th at improves the quality of the coal – including removing the mercury, moisture, ash, sulfur, and some of the fuel NO X 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 therefor e be reduced. Technology may be applicable to bituminous coal. However, the supplier has focused ex clusively 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 t echnology (PMR) is a two-step process, illustrated in Figure 3-10.

1. Physical Separation : A gravity separation process – either we t 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 pro cessed 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). Mi neral 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 merc ury is captured in a carbon-bed adsorption reactor. Water is recycled in the process. Mercury-laced activated carbon is disposed in a toxic landfill.

3-74Figure 3-10. K-Fuel PMR technology.

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

3-75Commercial 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 exp ected to be completed by the middle of 2004.

The K-Fuel has been tested in smaller scale facilities and a commerc ial 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 me rcury reduction; for example, testing by Rio Tinto Technical Services in Perth, Australia showed a 40 percent reduction 3 in fuel mercury due to thermal separation alone. Total mercury reduction at the En ergy & Environmental Research Laboratory of the University of North Dakota 4 and the Western Research Institute 5 were reportedly 66-67 percent. Also, NO X reduction up to 46 percent has been experienced in tests at Southern Research Institute 6 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 appr oximately 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 dis posal costs. Finally, more consistent coal quality with lower ash would have a positive impact on pl ant 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 st eam 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 pr ocess will be sold to the powe r plants rather than the power plants having to set-up their own PMR process f acility; 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 a nd 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 ma y be based on the price of competing coal on heating value basis plus credits for environmental benefits (lower SO 2 , NO X 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.

3-76Issues 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 SO 2 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 Th e 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 Generati on Technology Options

3.2.4.1 Circulating Fluidized Bed Technology

Circulating Fluidized-bed Technology Summary

Status Commercial up to 250 MW

SO 2 Reduction, % >95

NO X Reduction, % 30 – 70 depending on the coal [90 with SNCR (ammonia or urea)] Hg Reduction, % NA

CO 2 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 NO X burners, but without FGD.

Technology Description Circulating Fluidized Bed (CFB) combustion technolog y 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 applicat ions, 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 conve ntional PC boilers in many respects. The majority of boiler components are similar, and hence manufact uring of the furnace and the back-pass can be done in existing manufacturing facilities. In addition, a CF B 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 wher e subcritical operation is more cost-effective. As the technology is scaled up (above 400-500 MW), the supercritical d esign may be used depending on the site-specific environmental requirements or cost of fuel.

3-78Figure 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 SO 2 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 NO X and is the optimum temperature range for in-situ capture of SO 2. The injected limestone is converted to lime, a portion of which reacts with SO 2 to form calcium sulfate (CaSO 4 ), 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 recirc ulated back to the furnace to impr ove the overall limestone utilization. Limestone injection can remove from 90 to >95 percent of the sulfur in the coal 1 eliminating the need for flue gas desulfurization (FGD) downstream of the boiler. CFBs have NO X emissions 60-70 percent lower than conventional PC boilers with low NO X burners

CFB boilers can efficiently burn low reactivity an d 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.

3-79Commercial 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 supe r-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 (lar ger 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% H 2 O/0.6% S)

KEPCO, Kangwon-do Kangwon-do, South Korea KHI and ABB-CE 2 X 200 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 percent 1 of the sulfur in the coal without the need for flue gas desulfurization (FGD) downstream of the boiler. SO 2 removal is affected mainly by the bed temperature and by the Ca-to-S molar ratio. Th e 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 ra tio of 2.0 - 2.5 is typical for 90 - 95 percent SO 2 removal.

NO X emissions are 30 - 70 percent lower than conventional PCs with low NO X burners; 1 CFB boilers have achieved consistently 0.12-0.16 lbs/MMBtu NO X emissions, compared to pulverized coal plants which range from 0.2 to 0.5 lbs/MMBtu. Further NO X reduction can be achieved by installing an SNCR (ammonia or urea) injection system in the CFB furnace. NO X 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 NO X emissions are impacted by the bed temperature, the nitrogen and volatile matter in the coal, and the bed stoichiometry. Stoichiometr y, defined as a ratio of available air (weight) to theoretical air needed for complete combustion, is a ffected by the excess air and air distribution across the

3-80bed. The amount of ammonia or urea being injected (in case such system is available) also impacts the additional NO X 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 NO X and SO 2 controls, typically 34-38 percent (higher heat value basis). Therefore, no significant CO 2 reduction is expected. Superc ritical CFBs will have higher efficiency (38-40 percent) and proportionally lower CO 2 emissions.

O&M Impacts
None.

Capital Costs Capital costs of large CFB plants (between 150 an d 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 fi xed O&M and 2.0-5.5 mills /kWh for variable O&M costs depending on the O&M practices of the utility, la bor 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 a nd 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 th e 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, He lsinki, Finland, June 20-22, 2000.

3. Foster Wheeler Website – News Release 3/7/2003

. http://www.fwc.com/ (accessed Dec 1, 2004).

3-813.2.4.2 Integrated Gasification Combined Cycle

Integrated Gasification Combined Cycle Summary

Status Entrained and moving beds: commercial up to 500 MW; fluidized bed: in demonstration stage

SO 2 Reduction, % Up to 99

NO X Reduction, % 80-90 (compared to PC with low NO X burners) Hg Reduction, % Needs characterization via measurements

CO 2 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 bal ance 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 turbin e 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 opera te 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 th e gas enters the gas turbin e. Pressurized gasification also reduces the size of the gasifi er. Most gasification processes currently in use or planned for IGCC applications are oxygen blown; however, the Piñon Pi ne 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 dete rmined by the firing temperature of the gas turbine [typically: 1100 °C (2000 °F) or 1260 °C (2300 °F) fo r standard designs offered commercially] and by the frequency of the electricity produced. Typical net out put for single-train IGCC plants is approximately 275 MW for 60-Hz markets and 400 MW for 50-Hz market s. Plant net efficiency is typically 40 – 44 percent on a higher heating value (HHV) basis. Util ization 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 Puerto llano (Spain) are highly integrated designs with all the air for the air separation unit being taken as a bleed from the gas tu rbine compressor. In contr ast, the U.S. plants at Tampa and Wabash River are less integrated, and th e 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 consen sus among IGCC plant designers is to have the air

3-82separation 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 oper ation (three in the U.S and three in Europe) with three more IGCC plants utilizing refinery wastes in It aly. Table 3-9 shows these plants, as well as the first IGCC demonstration, Cool Water IGCC in Ba rstow, 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 applicab le 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; upgr ading 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 Loui siana: 670- MW IGCC utilizing petroleum coke.

Actual efficiencies of IGCC plants have been measu red in the 38-43.2 percent range (HHV-basis), mainly because their operation was designed in a conserva tive way to demonstrate the reliability of the technology and its ability to reduce acid rain pollutant s rather than to achieve the highest efficiency. Utilization of parts of existing plants in IGCC repower ing cases also contributed to keeping the efficiency on the low side. For example, the Wabash Rive r 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 percent 3 while Puertollano IGCC plant achieved 43.2 percent efficiency. 4

3-83Three types of gasification processes are available: mo ving-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 co al-water-slurry-fed processes, and Shell (Buggenum, Netherlands), Krupp-Uhde (Puertollano, Spain), G SP (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 an d has been used in many countries including China, the Czech Republic, German y, 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 IG CC 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 (sulfu r and nitrogen species and particulates) prior to combustion in the gas turbine, IGCC plants meet ex tremely stringent air emission standards. Sulfur emissions can be almost completely eliminated; SO 2 emissions are expected to be 0.03-0.1 lb/MMBtu, (40-115 mg/Nm 3 at 6 percent O 2 ). NO X emissions have been controlled to levels below 0.1 lb/MMBtu (125 mg/Nm 3 at 6 percent O 2 ) at two of the demonstrations usi ng steam or nitrogen dilution in the combustor and to half that level at two other sit es operating at lower combustion turbine temperatures. Recently, General Electric (GE) has claimed that they can meet a NO X level of 60 mg/Nm 3 even with
their 2300 ° F (1260 ° C) series FA gas turbine. Typical CO 2 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 turb ines. 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 SO 2 emissions. NO X emissions are affected by the design of th e gas turbine combustor and the environmental requirements of the plant site; most gas turbines utilize a dry low NO X combustor design and have achieved NO X emissions below 25 ppm(v) with the most recent turbine designs targeting below 10 ppm(v). 6 Assuming 25 ppm NO X emissions, this results in 80-90 percent reduction compared to pulverized coal boilers with low NO X 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 pulveri zed 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 aci d gas scrubbing loop, or is stripped from the amine

3-84solvent upon regeneration and partitions to the sulfur recovery unit. Some mercury, especially particulatephase and oxidized forms, may be removed in th e wet particulate scrubber and discharged with wastewater sludge. More testing is required to assess th e 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 sulf ur (usually in a Claus process) or sulfuric acid, as well as solid wastes in the form of inert slag, wh ich can be disposed of or sold for a variety of construction applications.

O&M Impacts The presence of toxic gases (CO and H 2 S) between the gasifier and the gas turbine requires some additional precautions. However, such precautions ar e common in other industries and can be addressed by installing CO and H 2 S sensors and appropriate design of the c ontrol system to manage plant start-up and especially transition from the start-up fuel to coal or coal-based syngas. Plan t 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 th e 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/kW 1 with the lower end of the range corresponding to IGCC plants with a minimum level of integration and, therefore, lower efficiency and th e 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 hi gher 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 obtai ned 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 ma in barrier to widespread utilization is the high capital costs relative to competing technologies. However, it should be pointed out that IGCC has much lower SO 2 , NO X , and CO 2 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 demonstr ate adequate reliability on a large scale (above 100 MW). The future of IGCC technology depe nds on the ability of the industry to reduce its costs and the environmental requirements associated with SO 2 , NO X , mercury, and CO 2 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.; Hoff mann, J. W.; Rameza, M. An Environmental Assessment of IGCC Power Systems. Presented at the 19 th Annual Pittsburgh Coal Conference, Pittsburgh, PA, Sept 2002.

3-854. 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 T echnology 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 Improvem ents 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

SO 2 Reduction, % Up to 98

NO X Reduction, % 30 – 70 depending on the coal [90 with SNCR (ammonia or urea)] Hg Reduction, % NA

CO 2 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 NO X burners but without FGD.

Technology Description Pressurized Fluidized-bed Combustion (PFBC) is sim ilar 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 g as, after particulate removal, is expanded through a gas turbine (GT) to drive the combustion air co mpressor and generate additional electric power.

The main advantages of PFBC are:

 pressurized conditions result in a more compact bo iler and therefore offers the potential to lower capital costs,

 utilization of the combined cycle concept incr eases 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 some what lower sorbent (Ca-to-S ratio) than AFBC.

3-86As 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 g as from the main combustor in a topping cycle to raise the turbine inlet gas temperature and increase the poweroutput 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 cr ucial to protecting the gas turbine and the successful demonstration of advanced PFBC.

Steam PFBC

HRSG Particulate Collector Water Coal & Sorbent

Steam Water To Stack A C

A ir GT Cyclone



# ∼

Figure 3-13. PFBC conceptual design.

Commercial Readiness and Industry Experience The technology is offered commercially up to 350 MW 3,4 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 experi ence obtained from these units will have a strong influence on the future of commercial PFBC technology.

3-87Ishikawajima-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 GT 140P 75- MW gas turbine and a 290- MW steam turbine. The boiler is designed for supercr itical 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

NO X 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 Ba bcock 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 (replace ment 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.

3-88Emission Control Performance SO 2 removal up to 98 percent is possible, especially with high-sulfur coals. SO 2 removal is affected by the bed temperature and by the Ca-to-S molar ratio. A Ca-t o-S molar ratio of approximately 1.5 is typical for an SO 2 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 disadvantag e and results in about the same waste volume compared to an AFBC. Furthermore, the absence of lime makes the solid wastes easier to handle.

NO X emissions are 30 – 70 percent lower than conventional PCs with low NO X burners. Further NO X reduction can be achieved by installing an SNCR or SCR system. NO X emissions in the 100 ppm (0.13 lbs/MMBtu) level without SNCR have been demonstrated. NO X 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. Co mpared 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 CO 2 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 r eached the 80-90 percent relia bility 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 determin ing the potential impacts on the various PFBC plant components.

Capital Costs Typical costs of` PFBC plants are expect ed 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

cost 1 depending on the O&M practices of the utility, labor costs, and cost of consumables (especially sorbent). The high estimates are more typical of th e 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 mate rials 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 conventio nal 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 Comme rcial 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

SO 2 Reduction, % 4 – 12

NO X Reduction, % 4 – 12 Hg Reduction, % 4 – 12

CO 2 Change, % 4 – 12 reduction

Cost

Capital ($/kW) Supercritical: 825 – 1080; Ult ra-supercritical: 1000 – 1150 (for 700 – 1000 MW plant size) Fixed O&M ($/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 NO X 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 pressu re, while supercritical plants are designed to operate from 23 to 35 MPa (3200 to 5000 psi). Also, s upercritical plants can be designed to operate at

3-90steam 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/1 000 °F/1050 °F), which is about 4.0 percent more efficient than the subcritical; and

3. Ultra-supercritical with double reheat: 31 MP a/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), whic h 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 tu rbine. 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, wa ter 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 Parameters 4

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 Countri es 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 pl ants 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

3-91Table 3-12. Equivalent Availability for S ubcritical and Supercritical Power Plants 4

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 developmen t of supercritical technol ogy. 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 util izing a standardized design for bituminous coal. 5 Also, China has ten supercritical units in ope ration and 10 more in the planning stage.

Emission Control Performance This technology is not an environmental control tech nology per se, but due to its higher efficiency it results in lower emissions prior to utilizing e nvironmental 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 doubl e reheat, the efficiency increases by about 8 percent relative to a similar subcritical plant. Further potentia l 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 subc ritical PC technology. Supercritical PC requires more attention to water chemistry (requirements are ti ghter 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 studies 1,6 have estimated the costs of supercritical vs subcritical PC technologies. The general consensus is that the capital costs of a superc ritical 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

3-92supercritical 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 su percritical 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 availa ble, and there are no issues associated with it. As more emphasis is placed on CO 2 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 re quires 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 Technol ogies. 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/supe rcritical/ppt_supercritical (accessed Dec 1, 2004).

5. Yoo, K. J.; Kim, M. H.; Moskal, J. J. Standard ization in the Design and Construction of 500 MW Coal-fired Power Plants in the Republic of Kor ea. Presented at the Powergen Americas, Orlando, FL, Dec 1996.

6. Sormani, G. F.; Monti, M. A.; Maffei, E. Co mparison 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

SO 2 Reduction Proportional to sulfur content of fuels; up to 100% reduction for switching from high- to low-sulfur coal or gas

NO X 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 signi ficant impact on both the thermal performance of the unit and the resulting emissions of SO 2 , NO X , Hg, and CO 2 . 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 fu el 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, bi omass, and municipal solid wastes.

Blending and cofiring generally constitute operating changes (even though orig inally 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 th e 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

3-94has been accomplished by mixing coals from two diffe rent 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 aver age quality characteristics (mainly sulfur content), as well as SO 2 measurements using continuous emission monitors. Blending could be used to affect emissions other than SO 2 (NO X 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 su bbituminous) is a common practice in the industry (again, mainly for sulfur control) and usually involv es hardware changes. Such changes are very sitespecific, but common areas, which are impacted by coal switching, are:

 Upgrading the coal crushing equipment and the pulve rizers to avoid potential de-rating of the unit due to limited coal throughput into boilers,

 Modifying the heating surface of the boiler (superheat er 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 handl e 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 impact s 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 na tural 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 g as 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 modi fied to maintain proper steam conditions, and

 Boiler backend modifications may be required, depend ing 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 to gether with the coal, but this limits the amount of

3-95cofired fuel to about 5 percent. In most case, separa te injection ports are added. Cyclones and fluidized bed boilers are better cofiring candidates than pulve rized 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 th at have been used extensively worldwide both for new plants and retrofit applications. Coal blending is also a common pr actice. 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 mon itoring 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 ch aracteristics of the coals, the design of the power plant, and the operating conditions. Sw itching from a high-sulfur (4 - 5 percent sulfur content) coal to a low-sulfur (0.5 - 0.8 percent su lfur content) coal reduces the SO 2 emissions up to 80 - 90 percent. The impact of coal blending on SO 2 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 NO X 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 CO 2 emissions mainly because of different moisture content of the coals, but also because of poten tially different auxiliary power requirements. For illustration purposes, if the mois ture content of the coal changes (as a result of switching or blending) from 8 to 20 percent, the imp act is an approximately 1.2 percent lower boiler efficiency, which corresponds to approximately a 3 percent or higher increase of CO 2
.
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 g as provided that the economics are favorable. In this case, SO 2 and mercury emissions may be eliminated. NO X emissions could be reduced by up to 70 - 80 percent. Finally, CO 2 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 CO 2 emission per fuel input is 200 lb/MMBtu for coal and 130 lb/MMBtu for natura l 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 SO 2 and mercury proportionally to its in put (typically up to 30 percent), NO X up to 50 - 70 percent, and CO 2 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 significan tly, but in general they are expected to reduce SO 2 and CO 2 proportionally to their inputs, and NO X 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 CO 2 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.

3-96O&M Impacts Changes in the fuel characteristics may have si gnificant impacts on unit performance and reliability. Table 3-14 summarizes the main impacts of unfavor able 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 pulverize rs, or other boiler-related systems. In most cases, these impacts can be mitigated by modifying the bo iler and other effected equipment. Other potential impacts include:

 Changes in the unburned carbon. This can be mitigat ed 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 impa ct 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 a nd may need to be modified to meet particulate emissions and opacity requirements.

 Reliability and operating flexibilit y 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 w ould 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).

3-97Table 3-14. Main O&M Impacts and Potential Mitigations

Impact on Emissions Coal Property SO 2 NO X Hg CO 2 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 SO 3 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 NO X controls for the increased baseline emissions

Volatile Matter X Potential impact on boiler heating surface performance Design or operation of NO X 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 SO 2 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 re gard 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 expens ive and may reach up to $200 - 300/kW. Cofiring capital costs may range from $30 to 200/kW. More specific examples 6 (End of Year 1991 U.S.$; 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.

3-98Issues Associated with the Technology; Future Outlook Fuel blending, switching, and cofiring are common indus try practices and are expected to continue. In the past, the main driving force has been economics, but th ey 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 c ontrol of emissions is required, all options are practical and commercially available.

Depending on site-specific constraints, not all opti ons 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 5 th International Conference, Kansas City, MO, May 20-22, 1997; EPRI TR-109340, Nov 1997.

2. Guidelines for Evaluating the Impact of Powder Ri ver 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 NO X Precursors During Rapid Pyrolysis. Energy Fuels 1993, 7 (6), 1013-1020.

4. Technology Assessment for Blending Western and Eastern Coals for SO 2 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 Wast e 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-D OE-EPRI Combined Power Plant Air Pollutant Control Symposium: The MEGA Symposium and The A&WMA Specialty Conference on Mercury Emissions: Fate, Effects, and C ontrol, 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.

3-9912. 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 (Upgradi ng, Newer Configurations, Technologies)

Plant Efficiency Improvements Summary

Status Commercial

SO 2 Reduction Heat rate improvement and upgrading: SO 2 reduction proportional to heat rate improvement; Repowering with gas: close to 100% SO 2 reduction

NO X Reduction Heat rate improvement and upgrading: NO X reduction proportional to heat rate improvement; Repowering with gas: up to 70 – 80% NO X reduction

Hg Reduction Heat rate improvement and upgrading: Hg reduction proportional to heat rate improvement; Repowering with natural gas: 100% Hg reduction

CO 2 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 plan t 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 op tions 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 pulve rizer 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 wa ter walls, superheat and reheat sections, as well as the condenser and the feed water h eaters 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. Exam ples 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 equipm ent due to condensation of sulfuric acid,

 replacement of steam turbine blades with new bl ades (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 favor able 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 ne w and more efficient tubes (with re gard to heat transfer), heating surface cleaning systems, and design modi fications 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 exis ting coal-fired power plant is to add a gas turbine and associated equipment and convert it to a combin ed cycle plant burning natural gas. There are a number of alternative approaches to repowering (fu ll 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 repowering 8 utilizes the existing boiler as a heat recovery device fo r the flue gas of the g as 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 turb ine 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.

3-101Commercial Readiness and Industry Experience All these options are commercially available, and th e 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 SO 2 , NO X , mercury, and CO 2 is proportional to the heat rate improvement achieved. Th ere 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 NO X emissions more than indicated by the proportional change.

Heat rate improvements may result in up to 1.5 per cent 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. CO 2 reduction is achieved due to better heat rate if less fuel is burned and th e fact that natural gas releases less CO 2 per unit heat input than coal. The end result from a repowering project may reach up to 50 percent CO 2 reduction, with parallel elimination of SO 2 and mercury.

O&M Impacts Upgrading and repowering projects do not have significan t 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 NO X emissions as much as possible through aggressive combustion staging (high overfire air flow rate) and lo w excess air, may affect heat rate adversely due to lower steam temperatures, high CO em issions, and high unburned carbon.

Costs Costs of heat rate improvements are typically lo w, 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 ava ilability of a reliable source of gas supply at a candidate plant location and cost di fferential 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 re duction 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 associ ated with heat rate improvements and plant upgrading relates to environmental requirements, which may apply in case the plant increases its output even marginally.

3-102References

1. Heat Rate Improvement Guidelines for Existing Fossil Plants; EPRI CS-4554; EPRI: Palo Alto, CA, May 1986.

2. MacDonald, J. Upgrading Older Power Plan ts 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 Mega watts, 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 Pa rallel 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

SO 2 Reduction, % Up to 1.5 at full load and up to 5 at low load

NO X 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

3-103Technology Description Power plant optimization generally involves the use of a software program that can determine the set of operating conditions which optimize an “objective f unction” such as “maximize plant efficiency,” “minimize NO X emissions,” or “maximize plant efficiency while maintaining NO X , CO, and unburned carbon below certain limits.” The so ftware 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 automati cally (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, th ere 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 st and-alone or one-time and advisory systems, because utilities wanted to gain experience and confirm thei r operation and reliability before putting them in automatic control. Presently, most of the optimiz ation 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 (P rocess Insights software), Praxis Engineers/GE (PECOS), ULTRAMA X , 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 NO X 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 NO X burner retrofit or a scheduled outage) are expected to achieve NO X and heat rate improvement in the low end of the above range. SO 2 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 conjunc tion 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 overfi re 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 ma intenance schedule is adjusted to avoid reliability problems.

3-104Costs 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 emissi on trading is expected to provide an additional impetus for more extensive use of optimization softwa re. There are no major issues associated with their application.

References

1. Retrofit NO X 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 NO X Using Advanced Empirical Optimization and Indi vidual Burner Instrumentation on a Boiler Operated in Load-Following Mode. Presented at EPRI’s 12 th Heat Rate Improvement Conference, Dallas, TX, Jan 30-Feb 1, 2001.

3. Romero, C. E.; Levy, E. K.; Sarunac, N. Imp acts of Combustion Optimization on Power Plant Heat Rate. Presented at EPRI’s 12 th 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 Comb ined 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 SO 2 emitted, and 22 percent of the NO X 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 po llutant 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 retrofitta ble emissions control technologies capable of simultaneously handling several pollutant s 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: NO X , SO 2 , and Hg.

The selection of control technologies was limited to th ose 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 rehabilita tion-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 sour ces of information including technology vendors, technical papers, expert consulta tions, reports published by the Department of Energy, and trade publications. The results of this review reveal the following:

 The number of technologies under development, demons tration, 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 ar e 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 SO 2, NO X , and mercury; most of these exhibit the potential to significantly control (above 80 percent) all three pollutants (SO 2 , NO X , and Hg).;

 Some technologies, such as SNO X , 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 in dustry. 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 r ecovery, Phoenix’s retrofit slagging combustor, ISCA’s Cl 2 injection, and BioDeNO X ), which were not evaluated in this report, may offer additional effective emission control of multiple pollutants in the near future.

4-14-2 For each evaluated technology, the report includes background i nformation, applicability, status of commercialization, any secondary environmental impacts of the technologies, identification of primary process variables that impact performance relative to NO X , SO 2 , 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 SO 2 -mercury, SO 2 -NO X , and SO 2 -NO X -mercury emissions. Injection of activated carbon upstream of electrostatic precipitators and bag filters was also included becau se of the significant role it may play in controlling mercury from existing power plants.

Advanced power generation technologies include circul ating flui dized bed combustion (CFB), integrated gasification combined cycle (IGCC), pressurized fl uidized 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 technologi es with a cert ain level of maturity, the authors expect a rapid technological evolution in the development and commercia lization 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 UnitsTechnologyStatusaEmissions ReductionsApplicabilityIssuesSO2and Mercury ControlDry scrubbersCSO2: 90-98%; NOX: NAb;Hg: 0- 95%Low-to-medium sulfur coalHg removal can vary significantly with coal type,operating conditionsSO2sorbentsP/CSO2: 40-85%; NOX: NA;Hg: NAUnits with ESP or FF forparticulate controlCalcium-based compounds not usedcommercially in coal fired plants. Wastedisposal issue with sodium-based compounds.Potential impacts on ESP or FFActivated carbon with SO2sorbent processesP/CSO2: 40-85%; NOX: NA;Hg: Up to 90%Units with ESP or FF forparticulate controlNot used commercially, potential impacts onESP or FFActivated carbon withparticulate controlsP/CHg: 50-90%Retrofit and new units with ESP orFFNot widely demonstrated at full scale, ashsalability, ESP and FF performance, impact ofcoal type (mercury speciation)Wet FGD with mercuryoxidation processesPSO2: 95%; NOX: NA;Hg: >80%Wet scrubber plantsFull scale demonstration underway, insufficientinformation at presentWet FGD with wet ESPC/PSO2: 99%; NOX: NA;Hg: Up to 80%Integration with wet scrubbers,retrofit dry ESPs, new unitsFew applications in power industry, potentiallyexpensive alloys requiredAdvanced dry FGDP/CSO2: 90-98%; NOX: NA;Hg: 0-95%SO2-Hg control for low-to- mediumsulfur coal (same as spray dryers)Hg removal may vary significantly with coaltype, operating conditions (similar to spraydryers)PEESPB/PSO2: >90% (with wet FGD);NOX: NA; Hg: Up to 98%New and retrofitEarly stage of development; demonstration andfurther assessment of the technology is neededMerCAPB/PSO2: NA: NOX: NA;Hg: >80%New and retrofit; scrubbed fluegasDid not perform well in unscrubbed gas; >80%for 10 ft long plates spaced 0.5 inches apartSO2and NOXControlE-BEAMC/DSO2: >95%; NOX: Up to 90%;Hg: NANew and retrofitDemonstration is required. High costs andauxiliary power requirementsROFA-ROTAMIXC/DSO2: 90%; NOX: 40-60%;Hg: 67% with Trona, 89% withCaCO3Existing plantsDemonstration phaseSNOXCSO2: >90%; NOX: >90%;Hg: 0%New and retrofitCost-effectivenessSNRBPSO2: 80-90%; NOX: 90%;Hg: NANew power plants and retrofitsRequires demonstrationTHERMALONOXwith wetFGD or FLU-ACEDSO2: Up to 95%; NOX: Up to90%;Hg: NANew and retrofitIn demonstration(continued)4-34-4(Table 4-1 concluded)TechnologyStatusaEmissions ReductionsApplicabilityIssuesSO2, NOX, and Mercury ControlActivated cokeCSO2: 90-98%; NOX: 15-80%;Hg: 90-99%New and retrofitDemonstration of the combined SO2-NOX-Hgcontrol is needed in the United StatesElectrocatalytic oxidation(ECO)DSO2: 98%; NOX: 90%;Hg: 90%New and retrofitDemonstration in progressWet FGD and SCRCSO2: 95%; NOX: 90-95%;Hg: 40-90% depending on coaltypePlants with SCR and wet scrubbertechnologiesNeed additional confirmation of mercuryoxidation levels in the SCREnviroScrubPSO2: >99%; NOX: 93-97%;Hg: Up to 67%New and retrofitDemonstration requiredLoTOXD/CSO2: 95%; NOX: 70-95%;Hg: Up to 90%New and retrofitDemonstration requiredK-FuelD/CSO2: Up to 30%; NOX: Up to45%;Hg: Up to 70%Mostly boilers burning PRB orligniteDemonstration required

Advanced Power Generation OptionsCirculating fluidized bedcombustionCSO2: >95%; NOX: 30-70%;Hg: NAMainly newSuccessful scale-up to 400-600 MW whilemaintaining its cost-effectiveness and emissionperformanceIntegrated gasificationcombined cycleC/DSO2: 99%; NOX: 80-90%;Hg: 90%NewHigh costs. Fluidized bed IGCC requiresdemonstrationPressurized fluidized bedcombustionCSO2: Up to 98%; NOX: 30-70%;Hg: NAMostly newSome reliability problems and high costs(relative to conventionalPCand FGD). Also,scale-up issues.Supercritical pulverized coalC/DSO2: 4-12%; NOX: 4-12%;Hg: 4-12%NewUltra-supercritical unit requires furtherdemonstration

Power Plant UpgradingFuel blending and cofiringCSO2: Up to 100%; NOX: 20-80%;Hg: flex%New and retrofitDevelopment of on-line coal quality monitoringis needed to enhance coal blendingPlant upgradingCDepends on choiceRetrofitImpact of environmental regulations pertainingto increased output of existing plantsPower plant optimizationCSO2: 1.5-5%; NOX: 5-35%;Hg: 1.5-5%New and retrofitNoneaStatus: B = Bench scale; P = pilot stage; C = commercial; D = demonstrationbNA = no removal reportedEnd of Document