United States EPA-600/R-03-110

Environmental Protection 

Agency October 2003

Research and

Development

Performance and Cost of Mercury and 

Multipollutant Emission Control 

Technology Applications on Electric 

Utility Boilers 

Prepared for

Office of Research and Development

Prepared by 

National Risk Management

Research Laboratory

Research Triangle Park, NC 27711
EPA-600/R-03/110 

October 2003 

Performance and Cost of Mercury and

Multipollutant Emission Control

Technology Applications on

Electric Utility Boilers

Prepared by:

James E. Staudt

Andover Technology Partners

112 Tucker Farm Road

North Andover, MA 01845

Wojciech Jozewicz

ARCADIS Geraghty & Miller

4915 Prospectus Drive, Suite F

Durham, NC 27713

EPA Contract No. 68-C-99-201, Work Assignment 4-028

EPA Project Officer: Ravi K. Srivastava

National Risk Management Research Laboratory

Research Triangle Park, NC 27711

U.S. Environmental Protection Agency

Office of Research and Development

Washington, DC 20460
ABSTRACT

Under the Clean Air Act, as amended, the Environmental Protection Agency (EPA) has 

determined that mercury emissions from coal-fired power plants should be regulated. Based on 

this determination, EPA is to propose Maximum Achievable Control Technology Standards for 

these emissions by December 2003. To aid in this regulatory effort, estimates of the performance 

and cost of powdered activated carbon (PAC) injection-based mercury control technologies and 

multipollutant control technologies that may be useful in controlling mercury emissions have 

been developed. This report presents these estimates. 

Estimates cost range for PAC injection, based on currently available data, is 0.03-3.096 

mills/kWh. However, the higher costs are usually associated with the minority of plants using 

Spray Dryer Absorbers and Electrostatic Precipitators (SDAs plus ESPs) or the small number 

of plants using hot ESPs (ESPhs). Excluding the minority of plants using SDAs plus ESPs or 

ESPhs, current cost estimates are from 0.03 to 1.903 mills/kWh. At the low end of these cost 

ranges, 0.03 mills/kWh, it is assumed that no additional control technologies are needed, but 

mercury monitoring will be necessary. In these cases, high mercury removal may be the result 

of the type of particulate matter, nitrogen oxide, and sulfur dioxide control measures currently 

employed, such as combinations of ESP, selective catalytic reduction (SCR), and wet flue gas 

desulfurization (FGD) on bituminous coal-fired boilers. 

Multipollutant control methods evaluated in this program that may provide cost effective 

mercury control and control of other pollutants include Electro Catalytic Oxidation (ECO), 

Advanced Dry FGD, and a coal beneficiation method. ECO and Advanced Dry FGD are flue gas 

treatment methods and are estimated to have costs ranging from 3.28 to 12.33 mills/kWh over 

a range of fuel types and conditions. A coal beneficiation method called K-Fuel was shown to 

provide about 60% or greater reduction in mercury from Powder River Basin coal on a heating 

value basis. 

Based on this work, it is expected that future efforts in R&D are likely to focus on improved 

understanding of mercury speciation across SCRs leading to beneficial effects of combinations 

of SCR with wet FGD and developing sorbents that can improve performance and cost of 

sorbent-based mercury control technologies. Multipollutant control technologies, which are more 

costly than single-pollutant mercury control technologies but offer other environmental benefits, 

will be another area for further development that could improve the cost of reducing emissions 

from coal-fired power plants. Finally, removing mercury from the coal, along with other fuel 

quality improvements, may prove to be a very cost effective approach for reducing emissions. 

ii 
Foreword 

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

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

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

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

and nurture life. To meet this mandate, EPA’s research program is providing data and 

technical support for solving environmental problems today and building a science 

knowledge base necessary to manage our ecological resources wisely, understand how 

pollutants affect our health, and prevent or reduce environmental risks in the future. 

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

for investigation of technological and management approaches for preventing and 

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

of the Laboratory’s research program is on methods and their cost-effectiveness for 

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

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

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

ecosystems. NRMRL collaborates with both public and private sector partners to foster 

technologies that reduce the cost of compliance and to anticipate emerging problems. 

NRMRL’s research provides solutions to environmental problems by: developing and 

promoting technologies that protect and improve the environment; advancing scientific and 

engineering information to support regulatory and policy decisions; and providing the 

technical support and information transfer to ensure implementation of environmental 

regulations and strategies at the national, state, and community levels. 

This publication has been produced as part of the Laboratory’s strategic long-term 

research plan. It is published and made available by EPA’s Office of Research and 

Development to assist the user community and to link researchers with their clients. 

Hugh W. McKinnon, 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. 

iii 
ACKNOWLEDGMENTS

The authors would like to acknowledge the many contributors to this document, without whose 

efforts this report would not be complete. In particular, we wish to acknowledge the technical 

guidance and insights provided by Dr. Ravi Srivastava of EPA’s National Risk Management 

Research Laboratory, Office of Research and Development. The authors also appreciate many 

helpful discussions with vendors of control technologies discussed in this document. 

iv 
TABLE OF CONTENTS

Section Page 

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

Foreword .............................................................. iii

Acknowledgments ........................................................iv

List of Figures .......................................................... vii

List of Tables .......................................................... viii

List of Acronyms and Abbreviations .......................................... x

1.0 Introduction ....................................................... 1

2.0 Mercury Speciation and Capture ....................................... 5

3.0 Mercury Control with Existing Technologies ............................. 7

3.1 Mercury Removal in PM Equipment .............................. 8

3.2 Impacts of NOX Controls on Mercury Speciation and Capture .......... 9

3.2.1 SCR Impact on Mercury Speciation ........................ 9

3.2.2 Mercury Removal Though Combustion NOX Controls ......... 15

3.3 Mercury Removal in SO2 Control Equipment ...................... 16

3.3.1 Mercury Removal in Wet FGD ........................... 16

3.3.2 Mercury Removal in SDA ............................... 17

3.4 Mercury Removal in Other Control Devices ....................... 18

3.5 Models of Mercury Removal by Existing Equipment ................ 18

4.0 Emerging Control Technologies ...................................... 21

4.1 PAC Injection-Based Technologies .............................. 21

4.1.1 Mercury Removal Models ............................... 22

4.1.2 Mercury Reduction by PAC Injection ...................... 23

4.2 Emerging Control Technologies ................................ 25

4.2.1 Electro Catalytic Oxidation (ECO ......................... 26

4.2.2 Advanced Dry FGD .................................... 32

4.2.3 K-Fuel .............................................. 38

5.0 Technologies Currently under Development ............................. 43

5.1 Oxidation Technologies ....................................... 43

5.2 Sorbent Technologies ........................................ 44

v 
5.3 Other Technologies .......................................... 46

6.0 Costs of Reducing Mercury Emissions ................................. 49

6.1 Mercury and Multipollutant Control Cost Models .................. 49

6.2 Fuel Types, Plant Characteristics, and Model Plant Cases ............ 53

6.3 Cost Model Results .......................................... 57

6.3.1 High Sulfur Bituminous Coals (Model Plants 1-10, 26-28) ..... 57

6.3.2 Low Sulfur Bituminous Coals ............................ 66

6.3.3 Low Sulfur Subbituminous Coals including Powder River

Basin Coals .......................................... 71

6.4 Cost Impacts of Selected Variables .............................. 80

6.5 Summary of Mercury and Multipollutant Control Costs .............. 86

7.0 Summary ........................................................ 89

8.0 References ....................................................... 91

Appendices 

A Appendix A Description of Mercury and Multipollutant Control Performance

and Cost Model .................................................. A-1

B Description of PAC Injection Algorithms Used in the Mercury and

Multipollutant Control Performance and Cost Model ..................... B-1

C Summary of Mercury Control Cases Analyzed .......................... C-1

D Results of Model Runs ............................................. D-1

vi 
LIST OF FIGURES

Figure Page 

1. Mercury oxidation without a catalyst as a function of residence time, gas

temperature, and HCl content ........................................ 10

2. Mercury oxidation across SCR catalysts and without SCR catalyst ........... 11

3. Oxidation of mercury across C-1 SCR catalyst in PRB-derived flue gas ....... 12

4. Effect of flue gas exposure time on C-1 SCR catalyst oxidation of elemental

mercury at 700 °F and space velocity of 1,450 hrS1 ........................ 12

5. Location of ECO installation in a power plant ........................... 26

6. Detailed process flow diagram of ECO ................................. 27

7. ECO power consumption versus NOX .................................. 31

8. F.L. Smidth Airtech AirTech Gas-Solids Absorber (GSA). ................. 33

9. Installation of an advanced dry FGD upstream of an existing ESP ............ 33

10. Installation of an advanced dry FGD downstream of an existing ESP ......... 34

11. Advanced dry scrubber SO2 removal performance ........................ 35

12 Advanced dry scrubber performance ................................... 35

13. Overall schematic of K-Fuel processing plant ............................ 39

14. K-Fuel thermal processing plant ...................................... 39

15. SO2 and NOX emissions from test burns of K-Fuel and untreated fuels ........ 40

16. Estimated Effect of K-Fuel Cost on Generation Cost. ...................... 77

17. Cost of PAC Injection for 500 MW Coal Fired Boilers with existing

ESPc or FF ....................................................... 81

18. Cost of PAC Injection for 500 MW Coal Fired Boilers with Existing

ESPc—Effect of Medium Versus High Performance PAC .................. 82

19. Effect of Capital Cost on 90 Percent Mercury Control with PAC on Boiler

with Existing ESPc and Retrofit of Downstream PJFF. .................... 83

20. Effect of Fertilizer Value on Cost of Emissions Control with ECO on a

500 MW Bituminous Coal Boiler ..................................... 84

21. Effect of Power Value on Cost of Emissions Control with ECO on a

500 MW Bituminous Coal Boiler ..................................... 85

22. Effect of Reagent Cost on Cost of Emissions Control with Advanced Dry

FGD on a 500 MW Boiler Firing Low Sulfur Bituminous Coal .............. 85

vii 
LIST OF TABLES

Table Page 

1. Average Mercury Capture by Existing Post-Combustion Control

Configurations Used for PC-Fired Boilers ............................... 7

2. Summary of Results from Full-Scale SCR Mercury Oxidation Tests .......... 14

3a. Parameters Used for Equations 1 and 2 Which Estimate Mercury Removal

by Existing Equipment .............................................. 19

3b. Parameters Used for Equations 1 and 2 Which Estimate Percent of

Remaining Mercury in Gas that Is Elemental Mercury ..................... 20

4. ECO Pollutant Removal Efficiencies ................................... 30

5. Estimated Cost of CFB-FGD System for a 500 MW Plant Burning PRB Coal . . 38

6. Comparison of Typical PRB Coal with K-Fuel ........................... 41

7. Fuels Used In Model Plant Analysis ................................... 54

8. Power Plant Characteristics .......................................... 55

9. Mercury Control Technology Applications and Co-benefits ................ 56

10a. High Sulfur Coal, ESP plus FGD Without SCR Co-benefit (Model Plants 1, 6) . 59

10b. High Sulfur Coal, ESP plus FGD With SCR Co-benefit (Model Plants 1, 6) .... 60

11a. High Sulfur Coal, ESPh plus FGD Without SCR Co-benefit (Model Plants 3, 8) 61

11b. High Sulfur Coal, ESPh plus FGD with SCR Co-benefit (Model Plants 3, 8) . . . 61

12. Advanced Dry FGD on High Sulfur Coal (Model Plants 4, 9), Sensitivity

to Capital Cost .................................................... 62

13. ESP and ECO on High Sulfur Coal (Model Plants 5 and 10), Sensitivity

to Capital Cost .................................................... 63

14. High Sulfur Coal, 100 MW SDA, and ESPc (Model Plant 26) ............... 64

15. High Sulfur Coal, 100 MW SDA, and FF (Model Plant 27) ................. 65

16. High Sulfur Coal, 100 MW ESPh, and FGD (Model Plant 28) ............... 66

17. Low Sulfur Coal, ESPc, and No SO2 Controls (Model Plants 11 and 29) ...... 67

18. Low Sulfur Coal, FF, and No SO2 Controls (Model Plants 12 and 30) ......... 68

19. Low Sulfur Coal, ESPh, and No SO2 Controls (Model Plants 13 and 31) ...... 69

20. ECO Installed After Particulate Removal (Model Plants 14S16, 32S34),

Sensitivity to Capital Cost ........................................... 70

21. Advanced Dry FGD (Model Plants 17S19, 35S37), Sensitivity to Capital Cost . . 71

viii 
22. Low Sulfur Subbituminous Coals, ESPc, and No SO2 Control (Model

Plants 20, 38) ..................................................... 73

23. Low Sulfur Subbituminous Coals, FF, and No SO2 Control (Model

Plants 21, 39) ..................................................... 74

24. Low Sulfur Subbituminous Coals, ESPh, and No SO2 Controls (Model

Plants 22, 40) ..................................................... 75

25. Low Sulfur Subbituminous Coals with ECO (Model Plants 23S25, 41S43)

Sensitivity to Capital Cost ........................................... 76

26. Comparison of Estimated Mercury Emissions from PRB and K-Fuel Boilers

Equipped with Particulate Control and No Additional Mercury or SO2 Controls . 77

27. K-Fuel, ESPc and No SO2 Control (Model Plants 44, 47) .................. 78

28. K-Fuel, FF, and No SO2 Control (Model Plants 45, 48) .................... 79

29. K-Fuel, ESPh, and No SO2 Controls (Model Plants 46, 49) ................. 80

30. Estimated Cost of Mercury Control—Current and Potential Cost Estimates .... 87

31. Estimated Costs of Multipollutant Controls ............................. 88

ix
LIST OF ACRONYMS AND ABBREVIATIONS 

ACRONYM DEFINITION

ADP acid dew point

ATS approach to saturation

CAAA Clean Air Act Amendments of 1990

CEMS continuous emission monitoring system

COHPAC compact hybrid particulate collector

CRF capital recovery factor

ECO electro catalytic oxidation

EPA U.S. Environmental Protection Agency

ESP electrostatic precipitator

ESPc cold-side electrostatic precipitator

ESPh hot-side electrostatic precipitator

FF fabric filter

FGD flue gas desulfurization

GSA gas suspension absorber

HCl hydrogen chloride

Hg mercury

HgCl2 mercuric chloride

Hg0 elemental mercury

Hg++ oxidized mercury

Hgp particle-bound mercury

HgT total mercury

HgO mercury oxide

ICR information collection request

IPM integrated planning model

kWh kilowatt hour

LOI loss of ignition

LNB low NOX burner

LSFO limestone forced oxidation

MACT maximum achievable control technology

MEL magnesium enhanced lime

MW megawatt

MWCs municipal waste combustors

NETL National Energy Technology Laboratory

x 
LIST OF ACRONYMS AND ABBREVIATIONS 

(continued) 

ACRONYM DEFINITION

NOX oxides of nitrogen

OAR EPA’s Office of Air and Radiation

OFA overfire air

OH Ontario Hydro

O&M operation and maintenance

PAC powdered activated carbon

PC pulverized coal

PFF polishing fabric filter

PJFF pulse jet fabric filter

PM particulate matter

PPPP Pleasant Prairie Power Plant

PRB Powder River basin

PS particle scrubber

RGFF reverse-gas fabric filter

RAP rapid absorption process

R&D research and development

SC spray cooling

SCR selective catalytic reduction

SDA spray dryer absorber

SNCR selective noncatalytic reduction

SO2 sulfur dioxide

TCLP toxicity characteristic leaching procedure

UBC unburned carbon

WESP wet electrostatic precipitator

xi 
1.0 INTRODUCTION 

In the atmosphere, mercury exists in two forms: elemental mercury vapor (Hg0) and ionic mercury 

(Hg++). Hg0

 can circulate in the atmosphere for up to one year and, consequently, can undergo 

dispersion over regional and global scales. Hg++ in the atmosphere either is bound to airborne 

particles or exists in gaseous form. This form of mercury is readily removed from the atmosphere 

by wet and dry deposition. After deposition, mercury is commonly re-emitted back to the 

atmosphere as either a gas or a constituent of particles and redeposited elsewhere. In this fashion, 

mercury cycles in the environment.1 

A number of human health and environmental impacts are associated with exposure to mercury. 

Mercury is known to bio-accumulate in fish and animal tissue in its most toxic form, 

methylmercury. Human exposure to methylmercury has been associated with serious neurological 

and developmental effects. Adults exposed to methylmercury show symptoms of tremors, loss 

of coordination, and memory and sensory difficulties. Offspring exposed during pregnancy show 

atrophy of the brain with delayed mental development. The incidence and extent of such effects 

depend on the level of exposure to methylmercury. Hg0 is readily absorbed through lungs and, 

being fat-soluble, is rapidly distributed throughout the body. Subsequently, it slowly oxidizes to 

Hg++, which accumulates in the brain and can lead to tremors, memory disturbances, sensory loss, 

and personality changes. Hg++ is absorbed through the digestive tract, accumulates in the kidneys, 

and can lead to immune-mediated kidney toxicity. Adverse effects of mercury on fish, birds, and 

mammals include reduced reproductive success, impaired growth, behavioral abnormalities, and 

even death. Details of the risks associated with exposure to mercury are discussed in the 

literature.1

 A severe case of human exposure occurred in Minamata, Japan in the 1950s.2 

Under the Clean Air Act as amended the Environmental Protection Agency (EPA) has determined 

that mercury emissions from coal-fired power plants should be regulated.3 Based on this determination, EPA is to propose Maximum Achievable Control Technology (MACT) Standards for 

these emissions by December 2003. To aid in this regulatory effort, this report has been prepared 

as an update of a previous report (EPA 600/R-00-083)4 that presented preliminary estimates of 

the performance and cost of promising mercury control technologies applicable to coal-fired 

electric utility boilers. Although most of these technologies are based on injection of powdered 

activated carbon (PAC) into boiler flue gas, additional technologies that offer promise in control 

of mercury and other pollutants are also discussed in this report. 

1
The report layout is as follows. First, the general principles of mercury speciation and capture 

are discussed. Second, mercury removal by existing equipment on coal-fired boilers is discussed. 

Third, promising mercury control technologies for coal-fired electric utility boilers are identified, 

and the performance characteristics of these technologies are estimated. These include 

characterization of mercury removal performance possible as a function of various parameters. 

Fourth, model plants representing the spectrum of retrofit possibilities are identified and a matrix 

of cases to be studied is developed. Next, costs of controlling mercury emissions from these model 

plants with the technologies of interest are examined. Finally, potential future improvements in 

these costs are discussed. During discussion of cost and potential improvements, research and 

development (R&D) areas are identified for near-term emphasis. 

Two multipollutant air pollution control technologies were evaluated as well as a coal beneficiation 

technology that offers pollution control advantages. The two air pollution control technologies 

include electro catalytic oxidation (ECO) and advanced dry flue gas desulfurization (FGD). ECO 

is a unique technology without any full-scale commercial experience on utility boilers. However, 

commercial-scale demonstrations are being built, and this technology has been studied extensively 

by the U.S. utility industry and the Department of Energy5

. So, results are presented here for ECO 

technology; however, they should be considered preliminary. Advanced Dry FGD has extensive 

experience in waste incineration applications and some limited commercial experience on coal-fired 

boilers. Moreover, advanced dry FGD is similar in many respects to spray dryer absorber (SDA) 

technology—a well established sulfur dioxide (SO2) control technology used on utility boilers. 

However, data regarding the control of mercury using this technology is limited, so the results 

presented here may be preliminary with regard to mercury control but are expected to be more 

reliable with regard to control of SO2 and particulate matter (PM) and with respect to cost. Coal 

beneficiation through the K-Fuel process has been demonstrated on the pilot scale, and the first 

commercial plant for coal beneficiation through the K-Fuel process is planned. In addition to 

enhancing coal heating value for low-rank fuels, this process can reduce the content of mercury, 

sulfur, and nitrogen in the coal, providing multipollutant benefits. The costs are estimated in terms 

of increased fuel cost. 

Use of sorbent injection technologies to control mercury emissions from electric power plants 

would result in mercury-impregnated sorbent waste, which would need to be disposed of either 

by itself or in mixture with flyash. One of the more commonly practiced solid waste disposal options 

is landfilling. However, there is limited information available on the stability of mercury in ash 

and sorbent residue. Therefore, it is unclear whether any potential exists for the release of mercury 

back into the environment from landfilled mercury-impregnated solid waste. Further research 

2
is needed on ash and sorbent residue to evaluate mercury retention and the potential for release 

back into the environment. Due to lack of information, this report does not address any potential 

costs that may result if mercury has to be stabilized in sorbent waste. 

3
4
2.0 MERCURY SPECIATION AND CAPTURE 

Mercury is volatilized and converted to Hg0 in the high temperature regions of combustion devices. 

As the flue gas cools, Hg0

 is oxidized to Hg++. The rate of oxidization is dependent on the 

temperature, flue gas composition and properties, and amount of flyash and any entrained sorbents. 

In coal-fired combustors, where the concentrations of hydrogen chloride (HCl) are low, and where 

equilibrium conditions are not achieved, Hg0 may be oxidized to mercuric oxide (HgO), mercuric 

sulfate (HgSO4), mercuric chloride (HgCl2), or some other mercury compound.6 The oxidization 

of Hg0

 to HgCl2 and to other ionic forms of mercury is abetted by catalytic reactions on the surface 

of flyash or sorbents and by other compounds that may be present in the flue gas. Applications 

of nitrogen oxides (NOX) control technologies such as selective catalytic reduction (SCR) can 

assist in oxidation of Hg0. 

Hg0, HgCl2, and HgO are primarily in the vapor phase at flue gas cleaning temperatures. Therefore, 

each of these forms of mercury can potentially be adsorbed onto porous solids such as flyash, PAC, 

and other sorbents for subsequent collection in a PM control device. These mercury forms may 

also be captured in carbon bed filters or other reactors containing appropriate sorbents. 

Mercury removal with wet scrubbers also appears to be possible. HgCl2 is water-soluble and reacts 

readily with alkali metal oxides in an acid-base reaction; therefore, conventional acid gas scrubbers 

used for SO2 control can also effectively capture HgCl2. However, Hg0 is insoluble in water and 

must be adsorbed onto a sorbent or converted to a soluble form of mercury that can be collected 

by wet scrubbing. HgO has low solubility and probably has to be collected by methods similar 

to those used for Hg0. Therefore, the form of mercury that is most easily removed is HgCl2, and 

this form of mercury is most readily formed when burning coals that are higher in chlorine content, 

such as Eastern bituminous coals. Furthermore, as will be described in Sections 3.1 and 3.2, the 

equipment on the boiler also plays an important role in determining mercury speciation. For this 

reason coal type, coal chlorine content, and the boiler equipment all play a significant role in 

determining the ease with which mercury can be removed from coal combustion flue gas streams. 

The following sections will describe mercury removal technologies pertinent to coal-fired boilers. 

For many technologies described in the following sections, the coal properties and the existing 

equipment on the boiler will have an impact on the total mercury removal when that facility is 

retrofitted with mercury removal equipment. This is because mercury speciation is important in 

5
determining the ease or difficulty of removing mercury from the exhaust gas. Additionally, fuel 

and the equipment used in the facility play role in determining the mercury speciation. 

6
3.0 MERCURY CONTROL WITH EXISTING TECHNOLOGIES 

Data derived from an EPA Information Collection Request (ICR) showed that mercury released 

from coal combustion may be partly removed from the exhaust gases by existing equipment without 

additional retrofit technology.7

 This chapter discusses the mercury control achieved with existing 

technologies utilized for control of PM, NOX, and SO2 emissions at electric utility coal-fired boilers. 

Table 1 shows the average reduction in total mercury (HgT) emissions from ICR data for coal-boilercontrol classes that burn pulverized coal (PC). Plants that employ only post-combustion PM controls 

display class average HgT emission reductions ranging from 1 to 90 percent. Units with fabric 

filters (FFs) obtain the highest average levels of control. Decreasing average levels of control are 

generally observed for units equipped with a cold-side electrostatic precipitator (ESPc), hot-side 

ESP (ESPh), and particle scrubber (PS). For units equipped with dry scrubbers, the class average 

HgT emission reductions ranged from 2 to 98 percent. The estimated class average reductions for 

wet FGD scrubbers were similar and ranged from 10 to 98 percent. 

Table 1. Average Mercury Capture, in Percent, by Existing Post-Combustion Control 

Configurations Used for PC-Fired Boilers.8 

Post-Combustion 

Control Strategy 

Post-Combustion 

Emission Control 

Device 

Configuration 

Coal Burned in PC-Fired Boiler Unit 

Bituminous Subbituminous Lignite 

PM Control Only 

ESPc 36 9 1 

ESPh 14 7 not tested 

FF 90 72 not tested 

PS not tested 9 not tested 

PM Control and 

SDA 

SDA+ESP not tested 43 not tested 

SDA+FF 98 25 2 

SDA+FF+SCR 98 not tested not tested 

PM Control and 

Wet FGD Systema 

PS+FGD 12 10 not tested 

ESPc+FGD 81 29 48 

ESPh+FGD 46 20 not tested 

FF+FGD 98 not tested not tested a

 Estimated capture across both control devices 

7
For PC-fired boilers, the amount of Hg captured by a given control technology is greater for 

bituminous coal than for either subbituminous coal or lignite. For example, the average capture 

of Hg, based on Ontario Hydro (OH) inlet measurements in PC-fired plants equipped with an ESPc, 

is 36 percent for bituminous coal, 9 percent for subbituminous coal, and 1 percent for lignite. 

3.1 Mercury Removal in PM Control Equipment 

Approximately 77 percent of the coal-fired utility boilers currently operating in the United States 

are equipped with only an ESP or an FF. Gaseous mercury (both Hg0 and Hg++) can potentially 

be adsorbed on fly ash and be collected in a downstream ESP or FF. The modern ESPs and 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 PM-bound mercury 

(Hgp

) in the boiler flue gases. 

The degree to which mercury can be adsorbed onto fly ash for subsequent capture in PM control 

is dependent on the speciation of mercury, the flue gas concentration of fly ash, the properties 

of fly ash and the temperature of the flue gas in the PM control device. It is currently believed 

that mercury is primarily adsorbed onto the unburned carbon in fly ash. Approximately 80 percent 

of the coal ash in PC-fired boilers is entrained with the flue gas as fly ash. PC-fired boilers with 

low-NOX burners have higher levels of carbon in the fly ash with a correspondingly higher potential 

for mercury adsorption. Cyclone and stoker boilers tend to have high levels of carbon in the fly 

ash but have lower flue gas concentrations of fly ash than PC-fired boilers. Fly ash concentrations 

in fluidized-bed combustors tend to be higher than those in PC-fired boilers. Also, the carbon 

content of fluidized-bed combustor fly ash is generally higher than that of PC-boiler fly ash. 

Gas-phase mercury in units equipped with an ESP can be adsorbed on the entrained fly ash upstream 

of the ESP. The gas-phase mercury in units equipped with a FF can be adsorbed by entrained fly 

ash or it can be adsorbed as the flue gas passes through the filter cake on the surface of the FF. 

The degree to which gaseous mercury adsorbs on the filter cake typically depends on the speciation 

of gaseous mercury in the flue gas; in general, gaseous Hg++ is easier to adsorb than gaseous Hg0

. 

The very intimate contact between the gas and collected PM (which can act as a sorbent for the 

gas-phase mercury) that occurs in a FF significantly enhances the gas-phase mercury collection 

efficiency of the FF over what is possible with an ESP. As indicated in Table 1, the ICR data showed 

that, for both bituminous and subbituminous coals, mercury collection in boilers equipped only 

with FFs is much higher than for boilers equipped only with ESPs. As will be shown later in this 

8
document, this effect also contributes to much more efficient collection of mercury when PAC 

is injected for additional mercury control upstream of a FF as opposed to injection upstream of 

an ESP. New hybrid ESP-FF technologies, such as the Combined Hybrid Particle Collector 

(COHPAC), offer ways to cost-effectively retrofit ESP’s with FF and realize this benefit. The 

COHPAC approach also offers the benefit enabling segregation of injected PAC from much of 

the collected fly ash. 

ICR data reflected that plants which employ only post-combustion PM controls display average 

Hg emission reductions ranging from 0 percent to 89 percent.8

 The highest levels of control were 

observed for units with FFs. Decreasing levels of control were shown for units with ESPs, 

particulate scrubbers, and mechanical collectors. The average mercury reduction for two PC-fired 

units equipped with a FF baghouse and burning bituminous coal averaged 90 percent while two 

similarly equipped units burning subbituminous coals displayed an average mercury reduction 

of 72 percent. The average capture of Hg for PC-fired plants equipped with an ESPc was 35 percent 

for bituminous coal, 3 percent for subbituminous coal, and near zero for lignite. 

3.2 Impacts of NOX Controls on Mercury Speciation and Capture 

Several NOX control technologies, including low NOX burners (LNBs), overfire air (OFA), 

reburning, selective noncatalytic reduction (SNCR), and SCR, are employed at utility coal-fired 

boilers to control NOX emissions. Of these control technologies, SCR has an impact on the 

speciation of mercury in flue gas and, therefore, subsequent capture in wet FGD systems. Based 

on recent data, combustion controls such as LNBs, OFA, and reburning may also have the potential 

to increase mercury capture in flyash. The effects of SCR and combustion controls on mercury 

capture are described in the following sections. 

3.2.1 SCR Impact on Mercury Speciation 

The speciation of mercury is known to have a significant impact on the ability of air pollution 

control equipment to capture it. In particular, the oxidized form of mercury, mercuric chloride 

(HgCl2), is highly water-soluble and is, therefore, easier to capture in wet FGD systems than the 

elemental form of mercury which is not water-soluble. SCR catalysts can act to oxidize a significant 

portion of the elemental mercury, which makes it easier to remove in downstream wet FGD. 

9
The results of studies have suggested that oxidation of elemental mercury by SCR catalyst may 

be affected by9S12 

• The space velocity of the catalyst 

• The temperature of the reaction 

• The concentration of ammonia 

• The age of the catalyst 

• The concentration of Cl in the gas stream 

Tests on a laboratory combustor has shown that mercury oxidation without a catalyst was enhanced 

with higher Cl concentration (higher HCl at inlet) and that oxidation increased with residence 

time and at lower temperatures, as shown in Figure 1.9

 Reference 9 also describes the results of 

laboratory tests of oxidation of mercury across different types of SCR catalysts. The results of 

these tests, shown in Figure 2, demonstrated that the catalyst significantly increased the amount 

of elemental mercury that oxidized to mercuric chloride. 

Figure 1. Mercury oxidation without a catalyst as a function of residence 

time, gas temperature, and HCl content.9 

10
Figure 2. Mercury oxidation across SCR catalyst unit with and without 

catalyst.9 

Tests of mercury oxidation by SCR catalyst have been conducted using simulated flue gas and 

slip-streams from actual units.10 Results showed similar trends for both simulated flue gas and 

slip-streams from actual units with the exception that the effect of increasing space velocity appeared 

somewhat more significant with the slip streams. Multiple catalyst types were tested with similar 

results obtained. According to Reference 10, it was determined that mercury oxidation was in 

the range of about 80S90 percent for fresh catalyst and space velocities in the range of 1000 hrS1

. 

However, the oxidation rate falls off with increased space velocity such that oxidation might be 

in the range of 30S80 percent at a space velocity of 4000 hrS1. Apparently, the wide range of 

oxidation performance at a space velocity of 4000 hrS1

 is the result of the influence of other 

factors—temperature, ammonia, and possibly other effects. As shown in Figure 3, Reference 10 

showed that oxidation of mercury across fresh SCR catalyst was relatively higher at temperatures 

in the vicinity of 700 °F and relatively lower in the vicinity of 800 °F. This may be consistent with 

the fact that oxidation of mercury to mercuric chloride is greater at lower temperatures. 

The presence of ammonia, which is the NOX reducing reagent normally used in SCR systems, 

appeared to inhibit the oxidation of elemental mercury, as reported in Reference 10. This effect 

appeared to be most pronounced with catalyst that had been exposed to boiler exhaust gases for 

a number of months. As shown in Figure 4, mercury oxidation without ammonia present remained 

between 80 and 90 percent after 4200 hours (about six months of continuous operation) of exposure 

11
Figure 3. Oxidation of mercury across C-1 SCR catalyst in PRBderived flue gas.10 

Figure 4. Effect of flue gas exposure time on C-1 SCR catalyst oxidation of

elemental mercury at 700 °F and space velocity of 1,450 hrS1

.

10

12
to boiler gases at a space velocity of 1450 hrS1

. When exposed to 300 ppm of ammonia, fresh catalyst 

continued to oxidize 80 to 90 percent of the elemental mercury. However, after 4200 hours of 

exposure, no oxidation was measured across the catalyst when ammonia was present, suggesting 

that ammonia may play a role in suppressing mercury oxidation. 

Oxidation of elemental mercury to mercuric chloride across an SCR catalyst, therefore, may be 

a function of space velocity, temperature, ammonia concentration, and catalyst life. Other factors, 

such as fly ash characteristics, are also believed to play a role. 

Reference 11 describes the results of a programthat evaluated mercury oxidation across full-scale 

utility boiler SCR systems. A summary of the results of the tests conducted in 2001 is shown in 

the first four entries in Table 2. Testing was performed at four coal-fired electric utility plants 

having catalyst age ranging from around 2500 hours to about 8000 hours. One plant fired 

subbituminous coal, and three other plants fired Eastern bituminous coal. The test results showed 

high levels of mercury oxidation in two of the three plants firing eastern bituminous coal and 

insignificant oxidation at the other two plants (one firing bituminous coal and the other 

subbituminous). However, it should be noted that for both of the plants where little or no mercury 

oxidation was measured (S1 and S3), over 85 percent of the mercury at the particle control device 

inlet was already in the non-elemental form. For the one bituminous coal-fired plant with low 

mercury oxidation (S3), over 50 percent of the mercury at the SCR inlet was already in the oxidized 

form. At the plant firing subbituminous coal (S1), mercury oxidation was fairly low. But, due 

to the high carbon in that plant’s fly ash, it is believed that the elemental mercury was adsorbed 

onto the ash, resulting in high particulate mercury levels. Finally, in contrast with the findings 

of Reference 10, ammonia appeared to have little or no effect on mercury oxidation on these actual, 

full-scale facilities. 

Subsequent tests on sister units at those plants and at other plants are shown in the second four 

entries in Table 2. All of the units fired bituminous coal and showed that mercury oxidation was 

generally enhanced to high levels of oxidized mercury at the SCR outlet. In each case where a 

scrubber was installed, the mercury removal was high. For the unit with an ESP and no scrubber, 

mercury removal was not improved by the SCR. 

13
Table 2. Summary of Results from Full-Scale SCR Mercury Oxidation Tests.13 a 

Power Plant 

Catalyst Flue Gas Hg++ 

Content 

(SCR in/out) 

Flue Gas Hg++ Content at 

PM Inlet 

without:with SCR 

Total Hg 

across P

without:w

Type 

Space Velocity 

(hrS1) 

Age Type Sulfurb (%) Clb (ppm) 

S1: 650 MWc 

Cyclone, ESP 

Honeycomb 

1800 

8000 hr PRB 0.2 <60 (1 OH sample) 

8%/18% (Unit 2) 

(1 OH sample each) 

5%:8% 

(1 OH sam

60%:65% 

experime

S2: 1360 MWc 

Wall, ESP+FGD (MELd) 

Plate 

2125 

3.5 

months 

OH 

bit. 

3.9 1640 (2 OH samples) 

48%/91% 

no effect of alkali 

injection (Unit 1) 

(2 OH samples each) 

73%:97% 

(2 OH sam

51%

FGD remo

H

S3: 750 MWc 

Tangential, ESP 

Honeycomb 

i3930 

1 ozone 

season 

PA bit. 

blend 

1.7 1150 (2 OH samples) 

55%/65% 

(2 OH samples) 

35%/61% for 2nd 

coal in sister unit 

77%:67% (possible filter 

effect due to reactive 

ash) 

2nd coal/sister unit not 

tested 

(2 OH sam

16%:13% 

experime

2nd coal/sis

tes

S4: 704 MWc Cyclone, Lime Venturi Scrubber Honeycomb 2275 1 ozone season KY bit. 2.9 360 (2 OH samples) 9%/80% (2 OH samples each) 56%:87% (2 OH sam

46%

684 MWc Wall, 

ESP+FGD 

“corregated” 

i3750? 

2 

months 

PA/ WV 

bit. 

3.6 470 Oxidation to >80% 

(+38% net) 

Oxidation to 95% 

(+15%net) (using data 

from sister unit w/o SCR) 

Oxidation 

(+40% 

800 MWc 

Tangential, ESP 

Honeycomb 

3800 

2 seas. 

2 layers 

repl. 

after 1st 

seas. 

KY/ WV 

bit. 

1 1000 Oxidation to >80% 

(+21% net) 

Oxidation to 89% (i0% 

net) (using data from 

sister unit w/o SCR) 

No effect; a

Hg removal 

vs 2

1360 MWc Wall, 

ESP+FGD (MEL) 

Plate 

2125 

2 ozone 

seasons 

OH 

bit. 

3.9 520 Oxidation to >80% 

(+33% net) 

Oxidation to >95% (did 

not test w/o SCR) 

i85% Hg r

not test w

Cyclone, Lime Venturi Scrubber 

Honeycomb 

2275 

2 ozone 

seasons 

KY bit. 3.1 750 

bypass 

250 

w/SCR 

Oxidation to 60% 

(+20% net) (more 

oxidation if 1 data 

outlier not used) 

Oxidation to >90% 

(+39% net) (Cl in coal 

changed between tests) 

Oxidation 

(+47% 

Coal 

14

a NH3, Cl, SO3 sampled at SCR outlet unless noted b Based on Energy Environmental Research Center’s analysesc Gross MWd MEL = magnesium-enhanced lime scrubber
Bench scale testing strongly suggests that HCl is an important exhaust gas constituent that is 

necessary for providing the chlorine for oxidation of Hg0

 to HgCl across the SCR catalyst.12 This 

important result provides a scientific base for explaining the differences observed between coals 

in field-testing. Subbituminous coals tend to have lower chlorine levels and higher calcium in 

the ash than bituminous coals. Hence, they would be expected to produce exhaust gas with lower 

HCl concentrations than bituminous coals. 

It is acknowledged that, at this point in time, the understanding of the effects of SCR catalyst on 

mercury oxidation is not complete. There is a great deal to learn with regard to the science of this 

phenomenon. However, apparently significant mercury oxidation by SCR catalyst occurs with 

bituminous coal, and oxidation is less certain with other coals. In this work, when evaluating this 

effect, it is assumed that when bituminous coals are being used, 90 percent of the mercury after 

the SCR is in the non-elemental form and is captured by a downstream wet FGD. It is also assumed 

that the SCR catalyst has no effect on mercury oxidation when other coals are fired. 

3.2.2 Mercury Removal Though Combustion NOX Controls 

The staged introduction of fuel and combustion air is a common practice for reducing formation 

of nitrogen oxides. This is often achieved within the burner in LNBs and also through the use 

of OFA when deeper staging and greater NOX reduction than afforded by LNBs alone is desired. 

Air staging reduces NOX formation by causing fuel-bound nitrogen to be released from the fuel 

at high-temperature and fuel-rich conditions. The fuel subsequently burns out under lowertemperature, oxygen-rich conditions to ensure high combustion efficiency with low formation 

of nitrogen oxide (NO). In the case of reburning (or fuel staging), a secondary, fuel-rich combustion 

zone is introduced after the initial combustion zone to reduce the NO that was formed in the initial 

combustion zone to nitrogen (N2). A downstream burn-out zone—effectively an OFA zone after 

the reburn zone—provides complete combustion of the reburning fuel under oxygen-rich conditions. 

Because all of these staged combustion methods used for minimizing NOX formation result in 

delayed combustion when compared with combustion methods that do not try to minimize NOX 

formation (and therefore burn the fuel only with maximum efficiency in mind), they also tend 

to reduce combustion efficiency and increase the amount of unburned fuel—in the form of unburned 

carbon (UBC), also known as loss of ignition (LOI). The UBC ends up in the fly ash that is collected 

in the PM control device. This carbon in the fly ash may act to adsorb Hg0 and Hg++. Therefore, 

existing combustion controls might be expected to enhance removal of mercury from the exhaust 

gases by downstream PM collection devices. 

15
Combustion of bituminous and low-rank (subbituminous and lignite) coals have been tested at 

pilot-scale under simulated air staging conditions.14-16 In that effort, it was found that mercury 

removal efficiencies by the downstream ESP improved with air staging. Up to 90 percent mercury 

removal was achieved with bituminous coals through air staging. With low-rank coals, air staging 

improved mercury removal from about 20 percent removal (without air staging) to about 40 percent 

removal (with air staging). These tests confirmed the expectation that combustion NOX controls 

can improve the mercury capture by the PM control devices. 

3.3 Mercury Removal in SO2 Control Equipment 

Both wet and dry flue gas desulfurization technologies are being used in the United States to control 

SO2 emissions from coal-fired boilers. SDA is being used at the majority of the plants employing 

dry FGD technologies. Available data reflects that some mercury capture occurs in wet FGD and 

SDA systems. 

3.3.1 Mercury Removal in Wet FGD 

More than 20 percent of coal-fired utility boiler capacity in the United States uses wet FGD systems 

to control SO2 emissions. In such systems, a PM control device is installed upstream of the wet 

FGD scrubber. The PM control device used in combination with a wet FGD scrubber may be a 

PS, ESPc, ESPh, or a FF baghouse. Wet FGD systems remove gaseous SO2 from flue gas by 

absorption. In wet scrubbers, gaseous species are mixed with a liquid in which they are soluble. 

For SO2 absorption, gaseous SO2 is mixed with a caustic slurry, typically water and limestone 

or water and lime. 

Gaseous compounds of Hg++ are generally water-soluble and can absorb in the aqueous slurry 

of a wet FGD system. However, gaseous Hg0

 is insoluble in water and therefore does not absorb 

in such slurries. When gaseous compounds of Hg++ are absorbed in the liquid slurry of a wet FGD 

system, the dissolved species are believed to react with dissolved sulfides from the flue gas, such 

as H2S, to form mercuric sulfide (HgS); the HgS precipitates from the liquid solution as sludge. 

In the absence of sufficient sulfides in the liquid solution, a competing reaction that reduces/converts 

dissolved Hg++ to Hg0

 is believed to take place. When this conversion takes place, the newly formed 

(insoluble) Hg0

 is transferred to the flue gas passing through the wet FGD system. The transferred 

Hg0

 increases the concentration of Hg0 in the flue gas passing through the wet FGD (since the 

incoming Hg0

 is not absorbed), thereby resulting in a higher concentration of gaseous Hg0 in the 

16
flue gas exiting the wet FGD compared to that entering. Transition metals in the slurry (originating 

from the flue gas) are believed to play an active role in the conversion reaction since they can act 

as catalysts and/or reactants for reducing oxidized species. 

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

of Hg++ in the inlet flue gas and on the PM control technology used. As described in Reference 

8, ICR data reflected that average Hg captures in wet FGD scrubbers ranged from 23 percent for 

one PC-fired ESPh plus FGD unit burning subbituminous coal to 97 percent in a PC-fired FF plus 

FGD unit burning bituminous coal. The high Hg capture in the FF plus FGD unit was attributed 

to increased oxidization and capture of Hg in the FF followed by capture of any remaining Hg++ 

in the wet scrubber. 

3.3.2 Mercury Removal in SDA 

More than 10 percent of coal-fired utility boiler capacity in the United States uses SDA systems 

to control SO2 emissions.8 An SDA system operates by the same principle as a wet FGD system 

using a lime scrubbing agent, except that the flue gas is mixed with a fine mist of lime slurry instead 

of a bulk liquid (as in wet scrubbing). The SO2 is absorbed in the slurry and reacts with the hydrated 

lime reagent to form solid calciumsulfite and calcium sulfate. The heat of the flue gas evaporates 

the water in the mist leaving dry solid particles of calcium sulfite and calcium sulfate. Entrained 

particles (unreacted sorbent particles, reaction products, and fly ash) are captured in the downstream 

PM control device (either an ESP or FF). 

The performance of SDA systems in controlling SO2 emissions is dependent on the difference 

between the SDA outlet temperature and the corresponding flue gas water vapor saturation 

temperature. SDA systems on coal-fired boilers typically operate about 20 °F (11 °C) above the 

saturation temperature (i.e., a 11 °C approach to saturation temperature). The relatively low flue 

gas temperatures afforded by SDA systems increase the potential for mercury capture. The caking, 

or buildup, of moist fly ash deposits, which can plug the SDA reactor and coat downstream surfaces, 

dictates the minimum flue gas temperatures which can be employed at the outlet of SDAs. 

Hgp

 is readily captured in SDA systems. Both Hg0 and Hg++ can potentially be adsorbed on fly 

ash, calcium sulfite, or calcium sulfate particles in the SDA. They can also be adsorbed and captured 

as the flue gas passes through the ESP or FF, whichever is used for PM control. In addition, gaseous 

Hg++ may be absorbed in the slurry droplets and react with the calcium-based sorbents within the 

droplets. Nearly all of the Hgp

 can be captured in the downstream PM control device. If the PM 

17
control device is a FF, there is the potential for additional capture of gaseous mercury as the flue 

gas passes through the bag filter cake composed of fly ash and dried slurry particles. 

As described in Reference 8, ICR data reflected that units equipped with lime spray dryer absorber 

scrubbers (SDA/ESP or SDA/FF systems) exhibited average Hg captures ranging from 98 percent 

for units burning bituminous coals to 3 percent for units burning subbituminous coal. The 

predominance of Hg0

 in stack gas units that are fired with subbituminous coal and lignite resulted 

from low levels of Hg0 oxidization. 

3.4 Mercury Removal in Other Control Devices 

Some units use particulate scrubber systems, primarily venturi scrubbers, to control PM emissions. 

Capture of Hg in these systems is limited to soluble Hg compounds such as HgCl2. PS systems 

are typically poor collectors of fine PM, and capture of Hgp by such scrubbers may be poor if the 

Hgp

 in the flue gas is associated with fine PM. Hg0 is insoluble and will not typically be captured 

by the scrubber. It is possible to capture Hg++ in the wet scrubbers, but the scrubber chemistry 

and the manner in which the scrubber is operated will determine whether it is effectively removed, 

or whether it is stripped, from the scrubbing liquor. Stripping can occur if the Hg++ is not adsorbed 

on the particles or reacted chemically with liquid-phase reactants within the scrubber. 

Mechanical collectors such as cyclones do a poor job of capturing fine PM, and, in general, mercury 

capture in these control devices should be limited to the capture of Hgp

 associated with particles 

larger than 10 μm. 

3.5 Models of Mercury Removal by Existing Equipment 

As noted in the preceding sections, there are a number of parameters that impact the mercury 

removal by existing equipment. Chlorine is widely acknowledged as having a role in mercury 

removal. SO2 is also expected to have a role as well. Fly ash characteristics and the temperature 

of the exhaust gas leaving the air preheater exit have also demonstrated a strong influence on 

mercury removal. Of course, the equipment type plays an important role as well. 

Expressions approximating the effects of equipment type, coal chlorine content, and SO2 level 

on mercury removal have been developed through statistical analysis of ICR data.18 Data used 

by the Reference included equipment type, coal chlorine, and sulfur information but not some 

18
of the other parameters expected to influence mercury removal from existing equipment. Since 

these expressions do not include other effects expected to be significant, such as ash characteristics 

and gas temperature, they should only be used for approximations. These algorithms are 

Algorithm 1 (ESPc): 

fexisting equipment = C1 × ln [(coal Cl, ppm)/(SO2, in lb/MMBtu)] + C2 Eq. 1 

Algorithm 2 (all other categories): 

fexisting equipment = C1 × ln (coal Cl, ppm) + C2 Eq. 2 

Where fexisting equipment is the fraction of mercury removed by existing equipment. These same 

algorithms were shown in Reference 18 to also provide a means to approximate the remaining 

mercury that is in the elemental form. There are minimum and maximum allowable values that 

set the allowable range for the results of Equations 1 and 2. Tables 3a and 3b show values for 

C1 and C2 and minimum and maximum values to use in Equations 1 and 2 for estimating fraction 

of mercury removed by existing equipment (Table 3a) and the fraction of remaining mercury that 

is elemental (Table 3b). 

Table 3a. Parameters Used for Equations 1 and 2 Which Estimate Mercury Removal by Existing 

Equipment18 

Existing Equipment 

ESPc 

ESPc + wet FGD 

ESPh 

ESPh + WET FGD 

FBCa

 + FF 

FF 

FF + wet FGD 

SDA + ESP 

SDA + FF 

C1 C2 

Minimum 

(%) 

Maximum 

(%) 

0.1233 -0.3885 0.0 55.0 

0.1157 -0.1438 24.0 70.0 

0.0927 -0.4024 0.0 27.0 

0.2845 -1.3236 4.0 65.0 

0.1394 0.1127 66.0 99.0 

0.1816 -0.4287 40.0 85.0 

0.1943 -0.2385 79.0 96.0 

-0.1087 0.6932 5.0 25.0 

0.2854 -1.1302 0.0 99.0 

a

 FBC = fluidized bed combustor 

19
Table 3b. Parameters Used for Equations 1 and 2 Which Estimate Percent of Remaining Mercury 

in Gas that Is Elemental Mercury18 

Existing Equipment 

ESPc 

ESPc + wet FGD 

ESPh 

ESPh + WET FGD 

FBCa

 + FF 

FF 

FF + wet FGD 

SDA + ESP 

SDA + FF -0.1125 1.48 64.0 99.0 

C1 C2 

Minimum 

(%) 

Maximum 

(%) 

-0.1283 1.23 12.0 85.0 

-0.039 1.11 81.0 98.0 

-0.1639 1.55 34.0 91.0 

-0.0945 1.45 80.0 99.0 

-0.1198 1.2 44.0 68.0 

-0.1182 0.88 30.0 33.0 

-0.426 3.1 45.0 84.0 

-0.0355 1.13 91.0 98.0 

a

 FBC = fluidized bed combustor 

The correlations of Reference 18 should be used only for making approximate estimates.19 Although 

the algorithm will provide reasonable estimates in most cases, Reference 19 showed that factors 

not addressed by these algorithms, such as fly ash characteristics or gas temperature, can have 

a significant effect on the mercury capture in existing facilities. 

The capacity of PAC to adsorb mercury is large enough that it should not be limiting except at 

temperatures of about 350 °F (177 °C) or more, which is greater than the gas temperature at the 

exit of most air preheaters. So, with the possible exception of lignite coals, cooling usually has 

little or no beneficial effect on mercury absorption by PAC. However, the ability of fly ash and 

unburned carbon in the fly ash to absorb mercury is far less than that of PAC and may be enhanced 

by cooling. Therefore, although spray cooling may enhance mercury adsorption by fly ash and 

downstream capture in the ESP or FF, it is not expected to enhance mercury capture by PAC except 

in the case where lignite coals are burned. According to Reference 8, over 90 percent of the coals 

burned in the United States are bituminous, subbituminous, or blends of bituminous and 

subbituminous, which are not likely to use spray cooling with PAC injection. Therefore, spray 

cooling, which was evaluated in Reference 4, is not evaluated here. 

20
4.0 EMERGING CONTROL TECHNOLOGIES 

Based on published literature,1,4,19-30 control technologies using injection of PAC into the flue gas 

appear to hold promise for reducing mercury emissions from utility boilers. These technologies 

have been applied successfully on municipal waste combustors (MWCs). Despite differences 

between MWCs and utility boilers (e.g., mercury concentration and speciation in the flue gas), 

full-scale and pilot-scale tests indicate that these technologies may be able to provide significant 

mercury removal from the flue gas of coal-fired utility boilers. Accordingly, this evaluation focused 

on the characterization of performance and costs of PAC injection-based technologies. 

Other technologies have shown promise for control of mercury and other pollutants such as SO2, 

NOX, and PM. These multipollutant control technologies may offer cost-effective mercury control 

when considering the combined control of mercury with control of other pollutants. Multipollutant 

control technologies evaluated in this effort include ECO, advanced dry FGD, and a coal treatment 

technology known as K-Fuel. 

This section begins with the description of PAC injection-based control technologies that can 

be retrofitted to existing boilers for control of mercury emissions, PAC injection estimates for 

these technologies, multipollutant control technologies that control mercury and other pollutants, 

and model plants used in this work. Subsequently, control technology applications on model plants 

used to develop cost estimates are discussed. Finally, this section discusses ECO, advanced dry 

FGD, and K-Fuel. 

4.1 PAC Injection-Based Technologies 

Injection of PAC for mercury emissions control has been developed and tested at the full scale 

on coal-fired utility boilers. Test programs have been performed on a utility boiler firing 

subbituminous coal with a downstream cold-side electrostatic precipitator (ESPc), on utility boilers 

firing bituminous coal with a downstream ESPc, and on a utility boiler firing bituminous coal 

with a Compact Hybrid Particle Collector (COHPAC) arrangement (upstream ESPh with 

downstream baghouse after the air preheater).19,25S29 Using the data from these test programs and 

from pilot-scale testing, performance models were developed for PAC injection based mercury 

control applications.19,30 These models are in a form where they can be updated as new information 

is developed on these applications and for other boiler applications. 

21
4.1.1 Mercury Removal Models 

If fequipment is equal to the fraction of mercury removed from the boiler gases by a specific piece 

of equipment, then (1 – fequipment) equals the fraction of mercury remaining in the gases after that 

specific equipment. The fraction of mercury remaining after n pieces of equipment is equal to 

[(1 – fequipment 1) × (1-fequipment 2) × (1 – fequipment 3) × . . . × (1 – fequipment n)] Eq. 3 

Therefore, the total mercury removal fraction, fTotal, is 

fTotal = 1 – [(1 – fequipment 1) × (1-fequipment 2) × (1 – fequipment 3) × . . . × (1 – fequipment n)] Eq. 4 

If one of the pieces of equipment is PAC injection, then the total mercury removal fraction is 

fTotal = 1 – [(1 – fequipment 1) × (1-fequipment 2) × (1 – fequipment 3) × . . . × (1 – f PAC injection) × . . . 

× (1 – fequipment n)] Eq. 5 

where f PAC injection is the fraction of mercury removed by PAC injection. 

If PAC injection is simply added to existing equipment and the removal effects of the existing 

equipment are combined into one term, then we can represent Equation 5 as 

fTotal = 1 – [(1 – fexisting equipment) × (1 – f PAC injection)] 

and, solving for f PAC injection 

f PAC injection = 1 – [(1 - fTotal)/ (1 – fexisting equipment)] Eq. 6 

where f existing equipment is the removal fraction associated with the existing equipment and may be 

approximated by Equations 1 and 2 in Section 3.5 of this document if the removal by existing 

equipment is not known. Given a total mercury reduction requirement and knowing the reduction 

by existing equipment, it is possible to determine how much additional reduction is necessary 

from PAC injection. 

In this research, data from full-scale and pilot-scale tests of mercury reduction were used to 

formulate models for mercury reduction from existing equipment and from PAC injection. Full-scale 

22
data for mercury removal by existing equipment are available from the ICR data. Full-scale testing 

results of mercury reduction from PAC injection are available from the Department of Energy’s 

field testing programs at Southern Company’s Gaston Plant, Wisconsin Electric Power Company’s 

Pleasant Prairie Power Plant (PPPP), and at PG&E Corp. National Generating Group’s Brayton 

Point and Salem Harbor Plants.19 

4.1.2 Mercury Reduction by PAC Injection 

Reference 4 has algorithms developed from pilot-scale data for mercury reduction on boilers 

equipped with PAC injection. The following model improvements, discussed in Reference 19, 

have been made: 

1. The algorithms of Reference 4 were developed from pilot-scale tests and characterize total 

mercury reduction from both PAC injection and existing equipment as a function of PAC 

injection concentration. When using the algorithms of Reference 4, it is necessary to have 

a different PAC injection algorithm for each type of equipment configuration, including 

upstream and downstream equipment. These PAC injection algorithms may have to be updated 

as new information regarding mercury control from existing equipment becomes available. 

As described in Reference 19, the mercury reduction from PAC injection was isolated from 

that of the other equipment in Equation 5. Therefore, as more information on reduction of 

mercury from equipment other than PAC injection is developed, it should not be necessary 

to perform new regressions on the PAC injection models. Also, using Equation 5, it will also 

be possible to assess the fate of mercury in equipment that is either upstream or downstream 

of the PAC injection system. 

2. The algorithms of Reference 4 are of a form in which it is possible to approach 100 percent 

mercury removal by injection of very high concentrations of PAC. As demonstrated at a fullscale demonstration at the Pleasant Prairie Power Plant, under some circumstances the mercury 

reduction by PAC injection can be limited to something well below 100 percent.28 Therefore, 

the algorithm for mercury reduction from PAC injection was modified as described in Reference 

19 and in the following paragraphs to permit an upper limit to mercury removal that may be 

less than 100 percent. 

3. Because the algorithms of Reference 18 for mercury reduction from existing equipment are 

based on the full-scale ICR data, it is desirable to use them to characterize mercury reduction 

from existing equipment. However, it is not possible to integrate the algorithms of Reference 

23
4 into the approach used in Reference 18. By treating the mercury reduction from PAC injection 

independently from mercury reduction from other equipment, it is possible to use the algorithms 

of Reference 18 to characterize mercury reduction from existing equipment. 

Because mercury reduction by PAC injection may be limited to a value well below 100 percent, 

as identified in the second point, the equation that is used in Reference 4 to characterize the 

relationship between mercury reduction and PAC injection 

% reduction = 0 = 100 × ffrom PAC injection = 100-[A/(M+B)C

] Eq. 7 

where M is the mass injection rate of PAC (in lb/MMacf) so that 

M = {[A/(100 – 0)](1/C)} – B Eq. 8 

was modified in Reference 19 to be 

M = {[A/((100×D) – 0)](1/C)} – B Eq. 9 

where D is the fraction of mercury reduction that is asymptotically approached. 

A set of constants A, B, C, and D are specified for a given existing plant configuration, coal type 

(bituminous or subbituminous), PAC sorbent type, and retrofit configuration (PAC alone or PAC 

plus retrofit fabric filter). These constants are based upon full-scale data where available and based 

upon pilot-scale data or input from experts in this technology where full-scale data are not available. 

Reference 19 showed that, for systems with FFs, all of the PAC-based sorbents appeared to offer 

similar performance in terms of PAC injection concentration (in lb/MMacf) necessary for a given 

mercury reduction. On the other hand, for units with ESPs and without a fabric filter, PAC selection 

did have a significant effect on performance. 

The constants A, B, C, and D are determined based upon a PAC injection matching key, which 

is a five-digit number composed of the following elements: 

• Existing Particle Control Equipment (10000, 20000, 30000 for FF, ESPc, ESPh, 

respectively) 

• The O S 2 control technology, if any (0, 1000, or 2000, or 3000, for none, FGD, SD, or 

advanced dry FGD, respectively) 

24
• The fuel type: (100 for Bituminous or 200 for Subbituminous) 

• Whether an additional FF will be retrofit (0 or 10 for none or FF, respectively) 

• The PAC capacity (1 for high, 2 for medium, and 3 for low—In Reference 19, PAC 

selection appeared to make a difference for facilities with ESPs but not for facilities 

with FFs) 

For example, ESPc SD Bituminous FF med (Matching Key # 22112) indicates a Bituminous coalfired boiler currently equipped with a spray dryer absorber and an ESPc that will retrofit PAC 

injection (medium capacity) and a fabric filter. The list of constants used for Equation 9 in this 

work is shown in the Appendix 2. The matching key above will be used to determine the set of 

constants used for Equation 9 to estimate the PAC injection concentration. 

Equation 9 is used to determine PAC injection rate is the following manner. If fexisting equipment is 

greater than or equal to fTotal, then no additional mercury removal is necessary, and addition of 

PAC injection or any other technology to remove mercury is unnecessary. However, if fexisting equipment 

is less than fTotal, additional mercury removal is necessary through retrofit of another technology, 

in this case PAC injection. Using Equation 6, it is possible to determine the amount of mercury 

reduction that must be performed by injection of PAC. Keeping in mind from Equation 7 that 

0 = 100 × ffrom PAC injection, 

Equation 9 is then used to determine the injection concentration (M) of PAC (in lbs/MMacf). M 

is then multiplied by the total gas flow rate to determine the injection rate of PAC (in lbs per hour). 

4.2 Emerging Control Technologies 

Certain emerging technologies appear to offer significant potential for the combined reduction 

of mercury and SO2, or of mercury, NOX, and SO2. The technologies of interest that are evaluated 

in this report include 

• Electro catalytic oxidation (ECO) 

• Advanced dry FGD 

• K-Fuel 

25
These technologies generally have limited commercial experience on coal-fired utility boilers, 

but experience with the technologies in other applications or experience with related technology 

may be extensive. In the case of ECO, for example, this is a unique technology with limited 

experience beyond the development and demonstration efforts currently underway in the United 

States. Some elements of the ECO process—ammonia scrubbing and wet ESPs—are wellestablished technologies, however. Wet ESP’s, while not used widely in the utility industry, have 

a large experience base in other industries. Advanced dry FGD has experience on other applications 

and is also closely related to spray dryer absorber technology, which has extensive experience 

on coal-fired utility boilers. K-Fuel is an approach for beneficiating western fuels, especially Powder 

River Basin coals. K-Fuel removes moisture (increasing heating value), nitrogen (reducing NOX), 

sulfur (reducing SO2 emissions), and mercury (reducing mercury emissions). K-Fuel has been 

tested on utility boilers and a commercial production plant is under construction. Therefore, each 

of these technologies appears to have promise, may be used in the near term, and can be analyzed 

with some confidence. However, because of the limited experience with these technologies in 

coal utility applications, the results of the analysis shown here should be considered preliminary. 

4.2.1 Electro Catalytic Oxidation (ECO)31S34 

ECO technology has been developed by Powerspan. It is expected that the ECO system would 

be installed downstream of the existing ESP or FF, as shown in Figure 5. 

Figure 5. Location of ECO installation in a power plant.31 

26
This technology consists of 

• A dielectric barrier discharge reactor that induces oxidation of pollutants 

• A two-loop ammonia scrubber tower that removes SO2 and water-soluble oxidized forms 

of the pollutants 

• A wet ESP that removes acid mist and fine particles 

• A co-product (saleable fertilizer by-product) processing and mercury removal system 

that removes mercury with carbon filters and crystallizes the ammonium nitrate and 

ammonium sulfate fertilizers from the scrubber tower. 

In the dielectric barrier discharge reactor, the following happens: 

• NO gas forms nitrogen dioxide (NO2) gas and nitric acid (HNO3) aerosol mist. 

• SO2 gas forms sulfur trioxide (SO3), leading to the formation of sulfuric acid (H2SO4) 

aerosol mist. 

• Hg0 vapor forms HgO particles. 

Figure 6 shows a detailed process flow diagram for an ECO application. 

Figure 6. Detailed process flow diagram of ECO.33 

27
The water-soluble forms of the oxidized pollutants—HNO3 and H2SO4—are removed in an absorber 

tower that is equipped with a wet ESP. The absorber tower is a two-stage process with an absorption 

stage (at the top of the tower) for absorbing the pollutants and a concentrating stage at the bottom. 

An aqueous ammonia solution is used as the scrubbing agent to absorb SO2 and convert the absorbed 

SO2, nitric acid and sulfuric acid to ammoniumnitrate and ammonium sulfate, respectively. NO2 

reacts with ammonium sulfite [(NH4)2SO3], which forms in the scrubbing liquor, to form ammonium 

sulfate [(NH4)2SO4] and N2. With 90 percent NOX reduction, about 40 percent of the NOX becomes 

nitrate and about 50 percent becomes NO2 and ultimately N2. Thus, some of the NOX is ultimately 

converted to ammonium nitrate and the remainder is ultimately converted to N2. All of the SO2 

removed is ultimately removed in the form of ammonium sulfate. Mercury collected in the absorber 

tower water is removed from the liquid stream by an activated carbon filter. Acid mist and fine 

particles removed in the wet ESP drain into the absorber tower and are removed in the liquid 

discharge of the lower loop. Due to chemistry considerations of the absorber tower, the ECO process 

works best if the SO2 to NOX ratio in the flue gas is equal to 3 or more on a molar basis. 

The consumables and the by-products of the ECO process include 

Consumables 

• Electric power for the barrier discharge reactor, pumps and blowers. The power for 

the discharge reactor is related to the NOX reduction desired.33 

• Heat for the by-product crystallizer.33 

• Ammonia reagent, which can be estimated as roughly two moles of ammonia per mole 

of SO2 removed. Additional amine is provided by other chemicals discussed below. 

• Make-up water for the absorption tower—about 1 gal/min per MW—no special quality 

specification.33 

• Carbon filters for mercury removal from the liquid discharge of the absorber.33 

• Additional, proprietary chemicals that provide the balance of the amine for the conversion 

of NOX to ammonium nitrate and SO2 to ammonium sulfate. These are estimated at 

around $150/ton of NOX removed and $15/ton of SO2 removed.33 

By Products 

• Ammonium nitrate and ammonium sulfate crystals that can be sold as fertilizer. 

Typically, for 90 percent reduction for every mole of inlet NOX, 0.40 moles of ammonium 

nitrate are produced, and one mole of ammonium sulfate is produced for every mole 

of SO2 reduced.33 

• Mercury captured on the activated carbon (a waste to be disposed of) at a cost of about 

$1000/lb of mercury captured.33 

28
• 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.33 

• Water vapor.33 

Experience 

The ECO technology has been demonstrated in the laboratory and on a 2000 scfm pilot at First 

Energy’s Burger Plant. The pilot has been operating since March 2002. A 50 MW commercial 

demonstration system is currently being built at Burger Station. The commercial demonstration 

unit at Burger Plant is designed to handle 110,000 scfm of gas flow.34 

Capital Cost 

AmerenUE, Sargent & Lundy, Wheelabrator, The Andersons, and Powerspan performed a detailed 

cost estimate of an ECO unit at AmerenUE’s Sioux plant. The capital cost of an ECO system for 

this 510 MW installation was estimated at $114,500,000, inclusive of process equipment, general 

facilities, owner’s costs, and contingencies. This also included the fertilizer plant and balance 

of plant modifications.35 It is the only comprehensive, full-scale cost analysis that has been made 

available publicly. Therefore, a cost of $200/kW is a reasonable estimate to use. Reference 33 

confirmed this estimate. 

Operating Cost 

Variable operating cost is the cost of power and other consumables. Ammonia consumption is 

determined by the molar ratio described above under Consumables. Specialty chemical costs are 

estimated at $150/ton of NOX removed and about $15/ton of SO2 removed, based upon information 

from Reference 33. Reference 33 also provided information on power consumption requirements 

for both the ECO reactor and auxiliaries, described in the next section. 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.33 The ammonium sulfate and ammonium nitrate fertilizer are 

widely traded commodity chemicals and their value will depend largely on market conditions at 

the time and transport costs. 

Fixed Operating Costs include an estimated 1.5 percent of process capital per year plus 3 operators 

and one maintenance person per shift.33 The manpower needs are not expected to be a significant 

function of unit size.33 

29
Pollutant Removal Efficiencies and Power Consumption

Because ECO is a true multipollutant process that can remove NOX, SO2, mercury, and fine particles,

the effectiveness of the process can depend upon several variables, and there may be some

interrelationships. However, a typical coal system would be designed for the removal efficiencies

shown in Table 4.33

Table 4. ECO Pollutant Removal Efficiencies33,35 

Pollutant Removal Rate Conditions 

SO2 98%-99% Any inlet condition 

NOX 90% Up to 250 ppm or up to about 0.450 lb/MMBtua 

Hg 80%-90% Any inlet condition 

Fine Particles 95% (Outlet to less than 0.004 lbm/MMBtu) 

a

 At higher NOX levels, 90% reduction is achievable at higher ECO reactor power levels. 

The ECO system tends to operate best when the molar SO2 to NOX ratio is 3.0 or greater.33 Although 

ECO can operate at lower ratios, the reliability of both performance and cost predictions may be 

somewhat less. 

The power for the dielectric barrier discharge reactor is largely determined by both the amount 

of NO oxidation needed and the gas flow. To increase the amount of NOX removed by the ECO 

process, it is necessary to increase reactor power. So, for a given percent of NOX reduction, the 

reactor power is roughly proportional to the NOX mass flow. Therefore, to achieve a low outlet 

NOX level while minimizing power demand, it is best to start with a low NOX level from the boiler. 

As a result, one would typically use an ECO system in combination with low NOX burners or other 

devices to minimize NOX into the ECO reactor. Based upon information from Reference 33, this 

work assumes that reactor power (in watts/scfm) is equal to the lesser of 20 watts/scfm or 

58.22C(NOX) – 6.2431 (see Figure 7), where NOX is measured in lb/MMBtu. Reactor power could 

potentially be higher than 20 watts/scfm; however, this would likely be unattractive when compared 

to reducing NOX by other means such as low NOX burners. 

Other power demands include fan power to overcome about 9 inches of water total pressure drop 

(calculated as actual volume flow times pressure drop with an assumed fan efficiency of 65 percent) 

and another estimated 0.75 percent of plant output for auxiliary loads for the absorber and fertilizer 

30
plants. Although the fertilizer auxiliary costs are more closely related to the SO2 being removed, 

a single percentage is used for simplicity.33 

Figure 7. ECO power consumption versus NOX.

33 

Calculation Methods 

A worksheet titled ECO Cost and Performance was developed. Inputs for other calculations were 

largely taken from CUECost worksheets and the Plant Configuration Inputs and the Constants_CC 

worksheets. Inlet gas conditions are taken as the outlet of the air preheater except for particle 

loading, which is reduced due to the ESP or FF. Relationships for mass balances were developed 

from the information provided above regarding consumables, and relationships for power 

consumption were developed from information discussed regarding power consumption. 

As noted earlier, the reliability of the algorithms used for predicting ECO system performance 

and cost may be somewhat reduced for molar SO2 to NOX ratios below 3.0. Therefore, the worksheet 

includes warnings when the inlet SO2 to NOX ratio is below this value. Low SO2 to NOX does 

not mean that the output is incorrect or that ECO cannot be used. It simply means that the 

calculations are somewhat less reliable, and it would be advisable to consult with the technology 

supplier for more information. 

31
4.2.2 Advanced Dry FGD36-39,41-47 

Dry FGD reacts hydrated lime slurry with exhaust gases in an absorber vessel to capture SO2, SO3, 

HCl, and mercury that may be present in the exhaust gases. The exhaust gases are maintained 

above saturation temperature to avoid condensation. The by-product of dry scrubbing can usually 

be landfilled safely or, in some cases, reutilized for another purpose. 

Advanced dry scrubbing is intended to improve performance over conventional spray dryer 

absorbers. Advanced dry scrubbing utilizes a fluidized bed or a flash dryer for the reactor with 

recycle loops to enhance lime utilization. Figure 8 shows a diagram of the FLS AirTech Gas-Solid 

Absorber installed upstream of an ESP. Many systems use venturi mixers to introduce the sorbent 

slurry. The high solids loading in the reactor provides high gas-solids interaction and high solidssolids interaction. The high solids-solids interaction allows reactive particle surface to continuously 

be exposed as the particles impact one another. The solids-solids interaction also causes some 

agglomeration of fine particles to form larger particles that are easier to capture in downstream 

equipment. Because the reactions occur more efficiently in the reactor and because the particles 

are larger, Advanced dry scrubbing does not require a downstream fabric filter for the SO2 removal 

reaction to be completed. When a cyclone is used for recycle to produce a lower outlet particle 

concentration, a smaller downstream particle collection device is needed. In this case, the technology 

can often be installed upstream of the existing ESP, as shown in Figure 9. Without the cyclone, 

it is likely that the existing ESP will require some modifications to improve collection efficiency, 

or a new particle collection device may be necessary. However, in many cases it is envisioned 

that the absorber will be installed downstream of the existing ESP so that fly ash does not get 

contaminated and can continue to be sold. In this case, an additional particle removal device will 

be necessary, as shown in Figure 10. 

Some fly ash is beneficial to mercury capture in the absorber, especially for subbituminous coal.36 

Reference 36 also indicated that 98 percent mercury capture is possible for bituminous coal. The 

fly ash also helps to improve the qualities of the solid by-product, making it more suitable for 

use as fill or for sale of cement-like products. 

32
Figure 8. F.L. Smidth AirTech Gas-Solids Absorber (GSA).37 

Figure 9. Installation of an advanced dry FGD upstream of an existing ESP. 

33
Figure 10. Installation of an advanced dry FGD downstream of an existing ESP. 

There are a number of companies that supply different versions of advanced dry FGD technology: 

Lurgi Lentjes, F.L. Smidth AirTech’s Gas Suspension Absorber (GSA), RJM Beaumont’s Rapid 

Absorption Process (RAP), and WULFF. The advanced dry scrubbing systems all use hydrated 

lime slurry as the principal reagent to remove SO2 and can remove mercury as well. Figure 11, 

which is the published performance of three different advanced dry scrubber systems,40,43,46 shows 

that the SO2 removal efficiency is a strong function ofstoichiometric ratio, approach-to-saturation 

(ATS, expressed in degrees Fahrenheit), and chlorine content. Data is shown for chlorine contents 

of 0.04 percent (400 ppm) and 0.12 percent (1200 ppm). Stoichiometric ratio is defined as moles 

Ca/molesSO2. As shown, ATS, fuel chlorine content and lime stoichiometry determine the SO2 

removal efficiency. For any given ATS, chlorine level, and stoichiometric ratio, all technologies 

offer similar SO2 removal. For example, note that the GSA 18 deg and 1200 ppm Cl line, if 

continued, would closely follow the RAP 18 degree line. Since all versions of advanced dry FGD 

offered by the different suppliers rely on the same chemistry, similar performance would be expected 

for a specific set of conditions. 

Although advanced dry FGD has not been as widely used as SDA technology, there is significant 

operating data on it for pulverized coal-fired applications. Moreover, the chemistry of SO2 capture 

is very similar to that of SDA technology. For the analysis of this report, algorithms were developed 

to predict performance. To calculate lime feed necessary for a particular level of SO2 reduction, 

Figure 11 was re-plotted as stoichiometry versus SO2 reduction, and curves were fit based on ATS 

and chlorine content of the coal. The results are shown in Figure 12. 

34
Figure 11. Advanced dry scrubber SO2 removal performance. 

Figure 12. Advanced dry scrubber performance. 

35
At this time, some suppliers of this technology limit the gas-flows per reactor to an equivalent 

of around a 125-150 MW plant.38 On the other hand, Lurgi has supplied single-reactor systems 

as large as 250 MW and expects to be able to supply single reactor systems as large as about 400 

MW.

39 WULFF has supplied single-reactor systems as large as 300 MW.40 As a result, in some 

(but not all) cases it may be necessary to have more absorber towers than for conventional spray 

dryers. For this reason, a design of a RAP system for a 500 MW boiler may require as many as 

four reactors and a 250 MW system may require as many as two reactors.41 Some other suppliers 

may not require as many reactors. 

Limited experience has shown high mercury removal rates. Testing of mercury control from the 

Roanoke Valley Energy Facility showed that the Lurgi-designed system provided in excess of 

95 percent mercury removal from the 55 MW Unit #2 while firing eastern bituminous coal.42 For 

subbituminous coals, where there is lower chlorine content and a greater proportion of elemental 

mercury versus total mercury as compared to bituminous coals, lower capture efficiencies may 

be expected with normal lime sorbent. However, activated carbon or other specialized sorbents 

may offer the potential to capture more mercury. RJM-Beaumont Environmental Systems offers 

oxidized calcium sorbent that they claim is effective in removal of SO2 and mercury.43 

The consumables and the by-products of the ECO process include 

Consumables 

• Electric power for the booster fan, pumps, blowers, and reagent preparation 

• Lime – normally delivered as dry lime and hydrated to hydrated lime 

• Water – for producing hydrated lime and for gas cooling 

• Costs associated with downstream particle removal (energy, fabric filters, etc.) 

The algorithms of Figure 19 are used to calculate lime feed necessary for a particular level of SO2 

reduction. 

By Products 

• Calcium sulfate, calcium sulfite, a small amount of unreacted sorbent, ash and other 

solids collected in the downstream particle collection device. Based upon review of 

process designs from different suppliers, the approximate amount of this is 2.5-2.8 lbs/lb 

of sorbent injected. Most often the by-products are landfilled, but they can occasionally 

be re-used. 

• Water vapor that goes up the stack 

36
Experience 

This technology has been widely used on incineration systems and to a lesser degree on coal-fired 

boilers. Lurgi has supplied the technology to a 250 MW plant in Puerto Rico, to the 55 MW 

Roanoke Valley facility in North Carolina, to the Black Hills Power & Light (Gillette, WY) plant, 

and to nine coal-fired plants in Europe.44 WULFF has supplied the technology for the 300 MW 

coal- and oil-fired Theiss plant in Austria. There is significant commercial experience on coal 

as a result of these installations.40 

Capital Cost 

Information from technology providers suggests that the installed cost of a reactor and all material 

handling equipment excluding any downstream particle control device (ESP, FF, or cyclone) is 

roughly $35/kW for 250 MW or 500 MW systems.41,45 It may then be necessary to add the cost 

of the equipment and installation of a FF or an ESP, associated material handling equipment, 

ductwork, fans, and other equipment, which could cost up to an additional $60/kW. Total cost 

of process capital, therefore, is in the range of $100/kW. Additional costs associated with the project, 

such as engineering and construction management, allowance for funds during construction, 

contingency, and general facilities would increase the total cost to above $100/kW. This is consistent 

with Reference 46, which estimates the cost of an F.L. Smidth AirTech Gas Suspension Absorber 

system at $149/kW (1990 dollars) for a 300 MW plant. It is unclear from Reference 46 whether 

or not this cost includes the downstream ESP, but it does include the cost of the cyclone separator 

in the recycle system. Table 5 provides a cost estimate for a Lurgi Lentjes CFB-FGD system at 

a 500 MW plant and shows a $150/kW cost estimate. Therefore, a cost of about $150/kW appears 

to be consistent among several sources and will be used here. 

Operating Costs 

The principal variable operating costs are for lime reagent, water, power, and solid disposal. The 

preceding discussion described how lime consumption is determined. Water consumption (city 

water is considered adequate quality—demineralized water is not required) is determined by the 

slurry concentration. Booster fan power for the reactor and cyclone is estimated from gas flow 

rate (actual cubic feet per minute) and pressure drop assuming a blower efficiency of 65 percent, 

and material handling power is estimated at 0.1144 hp/lb/h of lime feed. 

37
Table 5. Estimated Cost of CFB-FGD System for a 500 MW Plant Burning PRB Coal 

Subsystem Cost, U.S. $ $/kW 

Reagent Feed Syatem 5,000,000 10.0 

SO2 Removal System 7,000,000 14.0 

Particulate Collector 16,000,000 32.0 

Flue Gas System 7,000,000 14.0 

Waste Handling and Recycle System 7,000,000 14.0 

General Support Equipment 4,000,000 8.0 

Miscellaneous Equipment 6,000,000 12.0 

Total Process Capital (TPC) 52,000,000 104 

General Facilities (A, 5% of TPC) 2,600,000 5.2 

Engineering and Construction Management (B) 5,200,000 10.4 

Project Contingency (15% of TPC+A+B)) 8,970,000 17.9 

Total Plant Cost (TC) 68,770,000 137.5 

Allowance for Funds (3.2% of TC) 2,201,000 4.4 

Owner’s Cost (5% of TC) 3,439,000 7.0 

Total Plant Investment (TPI) 74,410,000 148.9 

Inventory Capital (spare, 1 % of TPI) 744,000 1.5 

Royalties 0 0 

Total Capital Requirement 75,154,000 150 

4.2.3 K-Fuel 

K-Fuel is a beneficiated coal that is derived from western coal. The resulting fuel is lower in ash,

higher in Btu value, and produces lower pollutant emissions than untreated western subbituminous

or PRB coals. K-Fuel uses a pre-combustion process that improves the quality of the coal—

including removing the mercury, moisture, ash, sulfur, and some of the fuel NOX precursors—before

the coal is burned at the power plant. Because these constituents are removed prior to combustion,

the need for post-combustion controls may be reduced.

The K-Fuel Coal Beneficiation Process48,49,50

The K-Fuel process employs both mechanical and thermal means to increase the quality of the

coal by removing moisture, rock, sulfur, mercury, and other heavy metals. To begin the process,

coal is delivered to the K-Fuel processing plant from the mine. The coal enters the first stage

separator, developed using conventional coal cleaning technology, where it is crushed and screened

38
to remove the large rock and rock material. The processed coal is then passed on to an intermediate 

storage facility prior to being sent to the next stage in the process, as shown in Figure 13. 

Figure 13. Overall schematic of K-Fuel processing plant.48 

From the intermediate storage facility the coal is sent via a distribution system to the K-Fuel thermal 

processing unit (Figure 14). This process employs Lurgi Mark IV vessels under high pressure 

and temperature to place thermal stress on the coal. The coal passes through pressure locks into 

the processors, and then steam at 460 °F (238 °C) and 485 psi is injected into the processors. While 

the coal is maintained at these conditions, the mineral inclusions are fractured under the thermal 

stress, removing both the included rock (which contains some mercury) and sulfur-forming pyrites. 

The inherent moisture of the coal is liberated as well. 

Figure 14. K-Fuel thermal processing plant.48 

39
After it has been treated in the main processor, the processed coal is discharged into a second

pressurized lock, which is then sealed off from the primary reactor. After sealing, the processor

pressure is vented into a water condenser to return the processor to atmospheric pressure, and

to flash cool the coal to approximately 200 °F (93 °C). The coal is then discharged onto a belt

and further cooled by convection and indirect cooling. After cooling, the coal is sent on to a second

stage separator for additional screening to remove sulfur- and mercury-containing mineral matter

which has been liberated by the thermal process. Mercury that is released from the coal during

thermal treatment is captured in a carbon filter. The carbon filter can then be disposed.

Pollutant Reduction Performance

Test burns of coal treated with the K-Fuel Process showed reductions in NOX and SO2 emissions.

Figure 15 shows SO2 and NOX emissions for two coals that were tested—with and without K-Fuel

treatment—and emissions from an eastern bituminous coal.48

Figure 15. SO2 and NOX

fuels. 

emissions from test burns of K-Fuel and untreated 

Because the K-Fuel process simultaneously reduces the mercury content of the coal and increases 

its Btu value, there is a significant overall mercury emission reduction on a heating value basis. 

Table 6 below compares the fuel analysis of a typical PRB coal used for the analysis of this report 

40
and a similar analysis of K-Fuel that was assembled from information provided by KFx 

Corporation.49 The table shows that mercury content of the K-Fuel derived from Cordero Mine 

is about 43 percent lower on a mass basis and about 60 percent lower on a Btu basis than the PRB 

coal used in this comparison. This is consistent with the roughly 65 to 70 percent mercury reduction 

reported in Reference 48 for the K-Fuel process when applied to different PRB coals. 

Table 6. Comparison of Typical PRB Coal with K-Fuel 

Contents Coal Type 

PRB K-Fuel 

Proximate Analysis (ASTM, as received) 

Volatile Matter (wt%) 30.79 40.20 

Fixed Carbon (wt%) 32.41 45.50 

100.00 99.62 

Ultimate Analysis (ASTM, as received) 

Moisture (wt%) 30.40 7.50 

Carbon (wt%) 47.85 66.70 

Hydrogen (wt%) 3.40 4.80 

Nitrogen (wt%) 0.62 1.00 

Chlorine (wt%) 0.03 0.03 

Sulfur (wt%) 0.48 0.38 

Ash (wt%) 6.40 6.42 

Oxygen (wt%) 10.82 13.20 

Total (wt%) 100.00 100.03 

Mercury (mg/kg) 0.07 0.04 

Modified Mott Spooner HHV (Btu/lb) 8304. 11,718. 

Coal Ash Analysis (ASTM as received) 

SiO2 (wt%) 31.60 28.40 

Al2O3 (wt%) 15.30 17.30 

TiO2 (wt%) 1.10 1.60 

Fe2O3 (wt%) 4.60 6.00 

CaO (wt%) 22.80 23.50 

MgO (wt%) 4.70 4.00 

Na2O (wt%) 1.30 1.40 

K2O (wt%) 0.40 0.27 

P2O5 (wt%) 0.80 2.43 

SO3 (wt%) 16.60 13.63 

Other Unaccounted for (wt%) 0.80 1.47 

Total (wt%) 100.00 100.00 

41
Experience 

The K-Fuel Process has been tested at the pilot stage, and construction of a commercial plant is 

planned for this year.48,50 Lurgi is providing much of the process reactor technology. The first 

commercial plant is to be built at the Black Thunder mine in Wright, WY. Construction is currently 

scheduled to start in mid-2003, with completion expected in the first half of 2004. The plant is 

expected to produce more than 700,000 tons per year of K-Fuel Plus. This plant is intended to 

not only prove the commercial value of the technology but to also provide a basis for optimizing 

the technology, and thus, it is designed for the possibility of future expansion on site.48,50 

Technology Cost 

For the purpose of this program, the cost of the K-Fuel is going to be assessed on the basis of 

incremental fuel cost. K-Fuel may be utilized on any facility where it can be economically 

transported to the site.50 According to Reference 50, some interior eastern bituminous fuel-fired 

boilers might consider K-Fuel over PRB because K-Fuel will avoid retrofits that may be necessary 

to avoid derates that might otherwise occur when switching from bituminous coal to PRB coal. 

Reference 50 discusses possible delivered prices ranging from $20 to $32 per ton of coal. At this 

price range and a heating value of about 11,700 Btu/lb, the K-Fuel has an estimated price of about 

$1.20-$1.36/MMBtu, which makes it competitively priced on a Btu basis with many bituminous 

coals and somewhat more expensive than PRB coals. $20/ton would equate to only about 

$0.85/MMBtu, which makes it cost competitive with (and in some cases less expensive than) PRB 

coals according to the fuel cost information in Reference 50. There is a chance that some retrofit 

costs might be incurred by switching from bituminous or PRB coals to K-Fuel, but these capital 

costs will be relatively small and will be dominated by the fuel costs in most cases. As a result, 

the cost analysis performed here will focus on incremental fuel cost as the major cost of using 

K-Fuel. Incremental costs of control may be incurred if mercury removal technologies, such as 

PAC injection, are retrofit to reduce mercury emissions further. 

42
5.0 TECHNOLOGIES CURRENTLY UNDER DEVELOPMENT 

There are several multipollutant control technologies that are currently under development or nearing 

commercial status in the United States. These, and other technologies, may emerge in a relatively 

short time depending on the results of on-going tests as well as the demand for mercury and 

multipollutant controls. Others may never reach commercial stage either because of technical 

problems or because of unfavorable economics relative to competing technologies. 

For the purpose of this report, technologies currently under development were divided into three 

groups: employing oxidation (other than SCR), utilizing sorbents, and other technologies. 

5.1 Oxidation Technologies 

Oxidation technologies aim at oxidizing mercury in order to facilitate its subsequent removal in 

wet FGD or wet ESP. Examples of these technologies include LoTOx, PEESP, and ESP 

modification discussed below. 

LoTOx 

LoTOx is a gas phase low-temperature oxidation system which involves injection of ozone in 

the flue gas upstream of a wet FGD to oxidize NOX to higher oxides of nitrogen such as N2O5, 

and mercury to HgO. Subsequently, these compounds are removed in a wet FGD because they 

are water soluble. The LoTOx system consists of an integrated oxygen/ozone generation unit 

complete with ozone injection system either into the LoTOx reactor or directly into the exhaust 

duct prior to the wet FGD (if sufficient residence time can be provided). Ozone is produced in-situ 

and on demand by passing oxygen through a conventional industrial ozone generation system. 

It is produced in response to the amount of NOX present in the flue gas generated by the combustion 

or process source. Theoretically, there is the potential for oxidation of SO2 to SO3; however, as 

proven in field testing, the reaction rates are very low compared to the predominant NOX and Hg 

reactions. 

PEESP 

Plasma-Enhanced Electrostatic Precipitators (PEESP) technology offers the potential to enhance 

the ability of wet ESP to remove elemental mercury. PEESP oxidizes vapor phase elemental mercury 

into oxidized form and then removes it within the wet ESP process. This technology involves 

injection of a reagent gas mixture, through a corona discharge needle that is attached to the central 

43
electrode within an electrostatic field. Injection into the area surrounding the sharp discharge point 

results in generation of hydroxyl radicals, ozone, and other reactive compounds. These react with 

elemental mercury vapor to form oxidized mercury particles. These negatively charged particles 

are attracted to the positively charged collecting electrode where they are collected. The mercuric 

oxide particles and other absorbed pollutants are removed during the wash-down cycle of the wet 

ESP. PEESP can be incorporated in an existing wet ESP by modifying the central electrode to 

inject the reagent gas. Greater than 80 percent total mercury removal is projected at pilot and full 

scale; bench scale testing demonstrated mercury removal of up to 83 percent. 

ESP Modification for Mercury Oxidation 

In this arrangement, a catalyst, most likely in honeycomb form, is inserted into the flue gas path 

upstream of the FGD system (last section of the ESP). This placement provides for low velocity 

and a relatively particulate-free flue gas. As a result, a close-pitched catalyst can be used. 

Downstream of the catalyst, the oxidized mercury is scrubbed in the FGD absorber, and coprecipitates with the calcium sulfite or gypsum byproduct. Preliminary cost estimates show that 

a catalytic process, if installed upstream of a wet FGD system, should allow plants to achieve 90 

percent overall mercury control at a cost that is 50 percent less than by injecting activated carbon. 

However, the cost of the process will depend largely on the catalyst life and required catalyst 

volume. So far, only catalysts produced at a laboratory scale have been tested. 

5.2 Sorbent Technologies 

Sorbent technologies utilize improved dry sorbents to accomplish mercury removal in systems 

without wet FGD. Additionally, improvements in sorbents may help reduce the cost of controlling 

mercury. Novel sorbents discussed here include Amended Silicate, MerCAP, and Pahlmanite. 

Amended Silicate 

Amended silicate sorbents use a commodity substrate material impregnated with a chemical additive 

that binds mercury to the surface of the particles. The sorbents have been prepared in a number 

of formulations tailored to provide economic mercury recovery in multiple applications. In packedbed tests these sorbents showed mercury removal of several times that of activated carbon. Pilot 

plant tests demonstrated 70S96 percent mercury capture at injection rates of 1.6S9.1 lb/MMacf, 

respectively. Out of the total removal, the injected amended silicate removed 40 percent or more 

of the mercury in the first one second of contact time in the pilot tests. Good stability of captured 

mercury on the sorbent was observed. When samples of sorbent mixed with fly ash were collected 

44
from the pilot fabric filter hopper and subjected to Toxicity Characteristic Leaching Procedure 

(TCLP) tests; the leachate mercury levels were below the limit of detection. Preliminary process 

design and analysis indicate that amended silicates can be cost competitive with activated carbon 

for mercury control. 

Mercury Control Adsorption Process 

Mercury Control Adsorption Process (MerCAP) deploys a mercury adsorbing sorbent-coated 

cartridge placed in the flue gas duct at temperatures of 400 °F (204 °C) or less. Mercury is removed 

from the flue gas as it flows past the rigid structure. Once the cartridge is saturated with mercury, 

it can then be removed or regenerated in-situ. Sorbent materials that have been considered for 

MerCAP configuration include activated carbon or metals which can amalgamate with mercury, 

such as gold and silver. Pilot scale experiments indicated that a MerCAP with gold coated plates 

approximately 10 ft long and spaced 0.5 inches apart was placed downstream of the spray 

dryer/fabric filter could remove more than 80 percent of mercury from a low-rank fuel flue gas. 

In preliminary tests, MerCAP did not perform as well in nonscrubbed flue gas. 

Pahlman Process 

The Pahlman Process is a dry sorbent system comprised of two discrete steps. One step involves 

capturing target pollutants such as NOX, SOX, mercury, and particulates using Pahlmanite dry 

mineral sorbent compounds. The other step involves the regeneration of the spent or partially spent 

sorbent compounds for reuse and the separation and isolation of useful by-products such as nitrates 

and sulfates for use in fertilizers and industrial chemicals. The Pahlmanite sorbents are low-density 

oxides of manganese (MnO2) in the form of fine black powder. The sorbent is injected in a reactor, 

which operates at temperature between ambient and 320 °F (160 °C). 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. Testing indicated above 99 percent SO2, 93.6S96.6 percent NOX, 

and up to 67 percent mercury reduction. 

ROFA and ROTAMIX 

ROFA (rotating opposed fire air) is a combustion control technology that employs staged 

combustion to reduce NOX emissions. In the staged combustion, fuel is initially burned in a fuel-rich 

zone for low NOX generation. The fuel-rich zone is followed by an OFA system that induces rapid 

mixing of burn-out air with furnace gases in the upper furnace region using highly-turbulent, rotating 

flow to complete fuel combustion while minimizing NOX formation. When sorbent or NOX-reducing 

chemicals (such as ammonia or urea) are added to the OFA ports, the technology is referred to 

as ROTAMIX. The NOX-reducing chemicals reduce NOX through selective non-catalytic reduction 

45
reactions. The sorbent may be added for adsorption of SO2 or mercury. Full-scale tests at Cape 

Fear Unit 5, firing eastern bituminous coal, showed that, in addition to the NOX removal provided 

by the staged combustion and the baseline mercury removal from the existing ESP, up to 89 percent 

removal of mercury, 64 percent removal of SO2 and 4 percent removal of NOX was achieved by 

limestone injection. Addition of Trona produced results of up to 67 percent removal of mercury, 

69 percent removal of SO2 and 11 percent removal of NOX. Slagging of the superheater by sorbent 

and ash was found to be a problem during the tests. However, it is believed that this problem might 

be avoided in the future through selection of injection locations at a lower temperature where ash 

softening is not as great. 

5.3 Other Technologies 

This group of technologies includes hybrid processes that accomplish mercury removal in a modified 

baghouse (Promoted MB Felt), by a combined dry and wet process (multipollutant control process), 

or in a regenerable sorbent bed (activated coke). These processes are presented below. 

Promoted MB Felt 

This process is centered on a proprietary, low-pressure, mercury-capturing filter fabric (Promoted

MB Felt) incorporated into a pulse-jet baghouse. The fabric is designed in a way that allows for

mercury capture to be segregated from particulate control, thereby avoiding fly ash contamination.

Bench-scale experiments at 185 °C demonstrated approximately 75 mg Hg/(g filter medium) were

captured. High mercury capture was later confirmed in a pilot plant over the course of seven weeks.

Multipollutant Control Process

This process involves sequential injection of dry sorbent and liquid oxidant to accomplish SO2

removal and oxidation/removal of NOX, and Hg in a multipollutant control reactor. The reactor

consists of three sequential tubular sections followed by a fabric filter. The first vertical section

is a humidifier, which is followed by two vertical sorption sections. Dry sorbent injection is located

approximately one third from the top of the first sorption section. Liquid oxidant is dispersed into

the flue gas at the top of the same section. Preliminary results from a 1 MW slipstream of a 300

MW low sulfur coal-fired boiler indicated SO2, NOX, and mercury removals across the reactor

of up to 92, 80, and 68 percent, respectively. The extent of oxidation and subsequent removal

of NOX and mercury was a function of the type and amount of oxidizer used.

46
The Activated Coke Process 

This process involves three steps: adsorption, desorption, and (optional) by-product recovery. 

In the first step (adsorption), flue gas passes through a bed of activated coke slowly moving 

downwards in a two-stage adsorber. The activated coke consists of carbon with large porous inner 

surface area. In the first stage, sulfur dioxide is removed by adsorption into the activated coke, 

where it forms sulfuric acid or ammonium hydrogen sulfate [NH4HSO4]. Mercury can also be 

removed by adsorption on the coke at a rate of up to 1.7 mg/g of activated coke at a temperature 

below 180 °C and condensation in the middle of desorber where the coke is about to be heated 

for regeneration. Therefore, mercury can be removed by extracting the coke in the middle of 

desorber. One method being considered for removing mercury is the use of a selenium filter, which 

absorbs the mercury from the flue gas and forms HgSe, a chemically stable compound. The selenium 

filter is expected to have 98 percent Hg collection efficiency during the filter life (usually 4-5 years). 

47
48
6.0 COSTS OF REDUCING MERCURY EMISSIONS 

The costs of controlling any pollutant are composed of capital costs associated with installation 

of the equipment and the operating costs associated with operating the equipment. In this report, 

these costs are estimated and assessed on a mills/kWh (or $/MWh) basis. In this effort, costs are 

determined on a constant dollar basis—that is to say that the costs are represented in 2003 dollars 

and the effects of general inflation are, therefore, normalized. We also assume that the escalation 

of operating costs equals the general inflation rate. Therefore, inflation is assumed to offset 

escalation so that the levelization factor for operating costs is equal to 1.0. 

The approach to assess costs included the use of EPA’s CUECost model and additional worksheets 

that are specific to the technologies of interest. EPA’s CUECost model was used to estimate flue 

gas conditions, establish basic economic parameters, and perform cost and performance calculations 

for those technologies already integrated into CUECost. This approach was used to first estimate 

the costs for model plants under specific conditions. Then, the cost impacts of some selected 

variables are determined. 

6.1 Mercury and Multipollutant Control Cost Models 

For this work, mercury removal is from existing air pollution control equipment as well as from 

additional equipment such as PAC injection. These models were described in Sections 3.5 and 

4.1, and the PAC injection rate algorithm constants for each equipment configuration are provided 

in the Appendices. 

Costs are comprised of capital and operating costs. These costs are assessed to develop a total 

annual cost of pollution control expressed in mills/kWh or $/MWh.a

 The total installed capital 

cost is annualized to produce an annual charge. This is done by multiplying the total installed capital 

charge by a capital recovery factor (CRF). The CRF is a function of variables such as project life, 

cost of capital, tax rate, depreciation methods, and others. In this analysis, a CRF of 0.133 (or 

13.3 percent) was chosen to be consistent with Reference 4. The annualized capital charge is then 

divided by the total power output of the plant for the year to determine the annual capital cost 

contribution to electric cost in mills/kWh (or $/Mwh). 

a

Costs expressed in mills/kWh and $/MWh are numerically equal. 

49 
Operating costs are estimated by determining the sum of the annual cost of consumables—reagents, 

power, water, etc. that contribute to variable operation and maintenance (O&M) and the annual 

cost of additional operators, maintenance, or parts (that contribute to fixed O&M) and dividing 

that sum by the total power output of the plant for the year to determine the operating cost 

contribution to electric cost in mills/kWh (or $/MWh). 

The total annual cost of pollution control (in mills/kWh) is determined by adding all of the cost 

components—annual capital cost, annual variable O&M, and annual fixed O&M. 

It is important to note that the costs of the multipollutant control technologies are likely to be greater 

than those for mercury control only. However, these technologies are providing additional pollution 

control benefits over and above mercury control. 

In the tables that follow, estimates of capital and total annual cost for mercury and multipollutant 

control technology applications on model plants are shown. These estimates were determined 

with the cost model discussed. It is noted that these estimates are based on currently available 

data. 

While developing the cost estimates for the model plant applications, the following specifications 

were used with the cost model. 

1. Mercury concentration in the coal was taken to be 0.10 mg/kg for eastern bituminous 

coal and 0.07 mg/kg for subbituminous coal. These concentrations are in the range 

of concentration reported for utility boilers in Reference 72. 

2. PAC injection rate correlations (see Section 4.1, Appendices and Reference 19) 

generally reflect that PAC injection requirements increase nonlinearly with an increase 

in mercury removal efficiency. To characterize the impact of this behavior, model plant 

cost estimates were obtained for mercury removal efficiencies of 50, 60, 70, 80, and 

90 percent wherever possible. In some cases existing equipment provided in excess 

of 50 percent removal and PAC injection was not needed to achieve the specified level 

of reduction. For PAC injection with a downstream ESP, 90 percent reduction may 

not be possible with subbituminous coals without retrofit of a downstream pulse jet 

fabric filter (PJFF). For bituminous coal fired boilers with an ESP, 90 percent removal 

may not be cost effective by PAC injection alone when compared to PAC injection 

and retrofit of a downstream PJFF to achieve 90 percent mercury removal. 

50
3. Spray cooling was not used in any of these model runs because PAC has sufficiently 

high capacity for most temperatures of interest—air preheater (APH) exit temperature 

under 350 °F— that any temperature effect is expected to be small. Moreover, spray 

cooling may have adverse effects on high-sulfur fuel boilers [due to acid dew point 

(ADP) effects] and PRB fuel boilers (due to cement-like properties of the ash). 

However, at lignite coal-fired plants, which are not evaluated here, spray cooling might 

be used to improve mercury removal. No data are currently available for recycling 

of sorbent in technology applications utilizing PAC injection and PJFF. Accordingly, 

no sorbent recycle was used. 

4. Wet FGD performance for mercury control is determined by Equation 2 if no SCR 

exists or 90 percent removal if the boiler fires bituminous coal and is equipped with 

an SCR. No oxidation (or co-benefit) by SCR is assumed for subbituminous coals. 

If PAC is added to provide additional reduction of mercury, then PAC is added upstream 

of the ESP or FF. 

5. In each of the model plant cost determinations, a plant capacity factor of 65 percent 

was used. 

6. The cost of PAC was taken to be $1,000/ton of carbon. 

7. In some cases, it is assumed that PAC is added upstream of the existing particulate 

control equipment. In others, particularly for high removal rates, it is assumed that 

a downstream FF is added. In the case of spray dryer absorbers, it is assumed that PAC 

is added upstream of the spray dryer, and a fabric filter may be added between the 

upstream PAC injection point and the downstream spray dryer. This is because the 

removal of HCl by the spray dryer will adversely affect the ability of PAC to achieve 

reasonable removal rates. This will require a larger fabric filter than if the fabric filter 

were installed downstream of the existing particulate control device because, in the 

upstream arrangement, the fabric filter would need to be sized to capture all of the 

fly ash as well as the injected PAC. 

8. The multipollutant control technologies evaluated—ECO, advanced dry FGD, and 

K-Fuel—were designed to provide other benefits (e.g., reduction of NOX or SO2 

emissions, improvement in fuel heating value) besides mercury reduction. Therefore, 

the higher cost of these multipollutant control approaches over control methods 

51
developed solely for mercury control should be considered with special attention to 

the greater environ-mental and other benefits associated with multipollutant control 

approaches. For ECO, it was assumed that 98 percent SO2 removal and 90 percent 

NOX removal were provided in addition to 85 percent mercury reduction. For advanced 

dry FGD, it was assumed that 90 percent SO2 removal was achieved in addition to 

about 95 percent mercury reduction. For K Fuel, the reduction of emissions of other 

pollutants, especially SO2 and NOX, will depend upon how the K-Fuel compares to 

the base fuel. For example, the K-Fuel has 44 percent lower sulfur content on a heating 

value basis than the base DOE PRB. Therefore, the environmental benefits of these 

methods—over and above mercury reduction—can be very significant. 

9. Costs include capital and operating costs associated with the retrofit and the expected 

cost of a continuous emission monitoring system (CEMS). The cost of existing 

technology is not included in the cost estimate. However, the effect of existing technology is included in the total mercury removal performance. In some cases, existing 

technology will provide adequate mercury removal and no additional mercury removal 

technology is required. In these cases, a small cost associated with the expected cost 

of the mercury CEMS will be shown. 

10. In this analysis it was assumed that the percent mercury removal possible from 

additional controls was not affected by the mercury removal from existing controls. 

While it is possible that there may be some interaction, this is not expected to be a 

significant effect for the cases evaluated here. 

11. In all of the cases evaluated here, the cost calculations assumed that all collected fly 

ash is currently sold. Therefore, calculations for PAC injection configurations in which 

fly ash and PAC are collected together include incremental costs to landfill fly ash 

at a cost of $30/ton. In many cases these costs will not be incremental because fly ash 

may currently be landfilled or because fly ash may not be rendered completely unacceptable for re-use. The large majority of plants currently landfill their flyash,30 and PAC 

injection would increase disposal costs only in proportion to PAC usage for them. Also, 

in situations where flyash is currently sold, fly ash contaminated with some used PAC 

might still be beneficially reused depending upon the amount of PAC added, the 

properties of the fly ash, and the intended use of the sold ash. According to ASTM 

Standard C618-03, coal fly ash with carbon contents as high as 6 percent may be 

acceptable as a concrete additive.73 There are other criteria that may determine 

52
acceptability of the fly ash as an additive to a buyer. However, the presence of small 

amounts of carbon in the fly ash will not necessarily render it unacceptable for beneficial 

re-use. Disposal costs can be a significant portion of total costs. As will be shown in 

a sensitivity analysis, elimination, or at least a reduction, of disposal costs can 

significantly improve economics of PAC injection from what is presented in this section. 

The ash content of the coal (on a heating value basis) largely determines the magnitude 

of this cost impact. So, coals with higher or lower ash contents will have higher or 

lower ash disposal costs, respectively. Based upon the characteristics of the fuels used 

in this program, the cost of landfilling fly ash at $30/ton is estimated to be about 0.37 

mills/kWh for the low sulfur bituminous cases with PAC injection. Similarly, for the 

subbituminous and high-sulfur bituminous cases with PAC injection, the cost of 

landfilling fly ash at $30/ton is estimated to be about 1.01 mills/kWh and about 0.93 

mills/kWh, respectively. Because these costs, which may not apply in some cases, are 

included as incremental costs in the results shown whenever a PJFF is not added to 

segregate the fly ash from the injected PAC, the cost estimates shown here should be 

regarded as likely to overestimate the cost in this respect. 

6.2 Fuel Types, Plant Characteristics, and Model Plant Cases 

Four different fuel types were evaluated for estimating costs of mercury control options presented 

in the following chapter: 

1. A high sulfur bituminous coal 

2. A low sulfur bituminous coal 

3. A PRB Coal 

4. A special, subbituminous fuel from K-Fuel. 

The first three fuels are taken from Reference 4, where the fuel information was developed by 

NETL of the Department of Energy. The properties of these fuels are identified in Table 7 below. 

53
Table 7. Fuels Used In Model Plant Analysis 

Contents 

Coal Type 

High Sulfur 

Bituminous 

Low Sulfur 

Bituminous 

PRB 

Subbituminous K-Fuel

Proximate Analysis (ASTM, as received) 

Volatile Matter (wt%) 40.40 44.00 30.79 40.20 

Fixed Carbon (wt%) 47.50 50.00 32.41 45.50 

100.00 100.00 100.00 99.62 

Ultimate Analysis (ASTM, as received) 

Moisture (wt%) 3.10 2.20 30.40 7.50 

Carbon (wt%) 69.82 78.48 47.85 66.70 

Hydrogen (wt%) 5.00 5.50 3.40 4.80 

Nitrogen (wt%) 1.26 1.30 0.62 1.00 

Chlorine (wt%) 0.12 0.12 0.03 0.03 

Sulfur (wt%) 3.00 0.60 0.48 0.38 

Ash (wt%) 9.00 3.80 6.40 6.42 

Oxygen (wt%) 8.70 8.00 10.82 13.20 

Total (wt%) 100.00 100.00 100.00 100.03 

Mercury (mg/kg) 0.10 0.10 0.07 0.04 

Modified Mott Spooner HHV (Btu/lb) 12,676. 14,175. 8304. 11,718. 

Coal Ash Analysis (ASTM, as received) 

SiO2 (wt%) 29.00 51.00 31.60 28.40 

Al2O3 (wt%) 17.00 30.00 15.30 17.30 

TiO2 (wt%) 0.74 1.50 1.10 1.60 

Fe2O3 (wt%) 36.00 5.60 4.60 6.00 

CaO (wt%) 6.50 4.20 22.80 23.50 

MgO (wt%) 0.83 0.76 4.70 4.00 

Na2O (wt%) 0.20 1.40 1.30 1.40 

K2O (wt%) 1.20 0.40 0.40 0.27 

P2O5 (wt%) 0.22 1.80 0.80 2.43 

SO3 (wt%) 7.30 2.60 16.60 13.63 

Other Unaccounted for (wt%) 1.01 0.74 0.80 1.47 

Total (wt%) 100.00 100.00 100.00 100.00 

Costs for installing and operating the mercury control technologies described in previous sections 

are estimated with model plants. Approximately 75 percent of the existing coal-fired utility boilers 

in the United States are equipped with ESPs for the control of PM.

8

 The remaining boilers employ 

FFs, particulate scrubbers, or other equipment for control of PM. Additionally, units firing mediumto-high sulfur coals may use FGD technologies to meet their SO2 control requirements. Generally, 

54
larger units firing high sulfur coals employ wet FGD, and smaller units firing medium sulfur coals 

use spray dryers. While developing the model plants, these PM and SO2 control possibilities were 

taken into account. 

Several model plants, with various flue gas cleaning equipment configurations and firing either 

bituminous or subbituminous coal, were used in this work. Table 7 exhibits fuels used in model 

plants. Power plant characteristics are given in Table 8, and model plants are shown in Table 9. 

Note that boiler sizes of 100 and 975 MW used in this work were selected to approximately span 

the range of existing boiler sizes and to be consistent with the size of the model plants used in 

previous work.4

 It was also envisioned that use of SCR can enhance oxidation of mercury in flue 

gas and result in the “co-benefit” of increased mercury removal in wet FGD. Since SCR is a capitalintensive technology, generally its use is cost-effective on larger boiler sizes. Accordingly, in this 

work, the mercury co-benefit resulting from SCR use was evaluated for model plants utilizing 

large (975 MW) boilers and wet FGD. 

Table 8. Power Plant Characteristics 

Characteristic Units Value 

MW Equivalent of Flue Gas to Control System MW 100, 300, 500, 975 

Net Plant Heat Rate Btu/kWh 10,500 

Plant Capacity Factor % 65 

Total Air Downstream of Economizer % 120 

Air Heater Leakage % 12 

Air Heater Outlet Gas Temperature °F 300 

Inlet Air Temperature °F 80 

Ambient Absolute Pressure in. of Hg 29.4 

Pressure after Air Heater in. of H2O 12 

Moisture in Air lb/lb dry air 0.013 

Ash Split 

Fly Ash % 80 

Bottom Ash % 20 

Seismic Zone integer 1 

-

55
56

Table 9. Mercury Control Technology Applications and Co-benefits

Model

Plant

Size

(MW)

Coal Existing Controls Additional Controls Co-benefit

Typea % S Case(s) with

1 975 Bit 3 ESP+FGD PAC, PAC +PJFF SCR

2 975 Bit 3 FF+FGD PAC, PAC +PJFF SCR

3 975 Bit 3 ESPh+FGD PAC, PAC +PJFF SCR

4 975 Bit 3 ESP Adv Dry FGD

5 975 Bit 3 ESP ECO

6 300 Bit 3 ESP+FGD PAC, PAC +PJFF SCR

7 300 Bit 3 FF+FGD PAC, PAC +PJFF SCR

8 300 Bit 3 ESPh+FGD PAC, PAC +PJFF SCR

9 300 Bit 3 ESP Adv Dry FGD

10 300 Bit 3 ESP ECO

11 975 Bit 0.6 ESP PAC, PAC +PJFF

12 975 Bit 0.6 FF PAC, PAC +PJFF

13 975 Bit 0.6 ESPh PAC +PJFF

14 975 Bit 0.6 ESP ECO

15 975 Bit 0.6 FF ECO

16 975 Bit 0.6 ESPh ECO

17 975 Bit 0.6 ESP Adv Dry FGD

18 975 Bit 0.6 FF Adv Dry FGD

19 975 Bit 0.6 ESPh Adv Dry FGD

20 975 Subbit 0.5 ESP PAC, PAC +PJFF

21 975 Subbit 0.5 FF PAC, PAC +PJFF

22 975 Subbit 0.5 ESPh PAC +PJFF

23 975 Subbit 0.5 ESP ECO

24 975 Subbit 0.5 FF ECO

25 975 Subbit 0.5 ESPh ECO

26 100 Bit 3 SD+ESP PAC, PAC +PJFF

27 100 Bit 3 SD+FF PAC, PAC +PJFF

28 100 Bit 3 ESPh+FGD PAC +PJFF

29 100 Bit 0.6 ESP PAC, PAC +PJFF

30 100 Bit 0.6 FF PAC, PAC +PJFF

31 100 Bit 0.6 ESPh PAC +PJFF

32 100 Bit 0.6 ESP ECO

33 100 Bit 0.6 FF ECO

34 100 Bit 0.6 ESPh ECO

35 100 Bit 0.6 ESP Adv Dry FGD

36 100 Bit 0.6 FF Adv Dry FGD

37 100 Bit 0.6 ESPh Adv Dry FGD

38 100 Subbit 0.5 ESP PAC, PAC +PJFF

39 100 Subbit 0.5 FF PAC, PAC +PJFF

40 100 Subbit 0.5 ESPh PAC +PJFF

41 100 Subbit 0.5 ESP ECO

42 100 Subbit 0.5 FF ECO

43 100 Subbit 0.5 ESPh ECO

44 975 K-Fuel 0.4 ESP PAC, PAC +PJFF

45 975 K-Fuel 0.4 FF PAC, PAC +PJFF

46 975 K-Fuel 0.4 ESPh PAC +PJFF

47 100 K-Fuel 0.4 ESP PAC, PAC +PJFF

48 100 K-Fuel 0.4 FF PAC, PAC +PJFF

49 100 K-Fuel 0.4 ESPh PAC +PJFF a

 Bit = bituminous coal; Subbit = subbituminous coal
6.3 Cost Model Results 

Three costs are typically shown in the following tables. One is the capital cost expressed in $/kW. 

This is the one-time capital charge for the equipment, installation, start-up, and such. Total 

annualized cost (Total Cost in the tables) and the Variable Cost, both expressed in mills/kWh, 

are also shown. Total Cost includes the annualized capital cost as well as annual variable and fixed 

operating cost. The Variable Cost is only the portion of the Total Cost that is attributable to variable 

operating and maintenance costs. In the following tables and discussion, the Model Plant numbers 

are noted so that more detailed cost information can be reviewed in the model plant tables of 

Appendix 4. 

For those applications, particularly PAC injection, in which multiple mercury control levels were 

evaluated (i.e., 50 through 90 percent), several columns are shown in the tables presented. Each 

column indicates the estimated capital cost ($/kW) and total annual cost (mills/kWh) for the plant 

size indicated and whether or not a PJFF was added. In some cases, existing controls provided 

adequate mercury reduction, so the only items added were mercury emissions monitoring equipment 

(no PAC injection or PJFF). Estimated mercury emissions on mg/kWh basis are also indicated 

in the tables. This estimated mercury emissions number may be useful for estimating total mercury 

mass emissions for particular configurations. 

Only one level of mercury removal is shown for ECO and advanced dry FGD. Multiple columns 

and costs are estimated for sensitivity to different variables, such as capital cost. 

6.3.1 High Sulfur Bituminous Coals (Model Plants 1S10, 26S28) 

For all of the model plants in which high sulfur bituminous coal is fired, it was assumed that the 

boiler was equipped with an FGD technology that might include limestone forced oxidation (LSFO), 

SDA, ECO, or advanced dry FGD. In the case of boilers equipped with wet FGD (LSFO), it was 

assumed any necessary additional mercury control was performed through injection of PAC 

upstream of the existing particulate removal device or between the existing particulate removal 

device and a new downstream PJFF. The co-benefit of SCR was also evaluated assuming that 

the combination of SCR with LSFO would result in the greater of 90 percent mercury removal 

or the amount of mercury removal from the existing particle removal equipment and LSFO. 

57
For high sulfur units in which the co-benefit of SCR with LSFO (or wet FGD) is evaluated, the 

size range chosen was 300 MW to 975 MW. The reason 300 MW rather than 100 MW was selected 

as the low end of the size range is that SCR plus LSFO is a capital-intensive approach for combined 

SO2 and NOX control. Therefore, it would be unlikely to be selected over other approaches for 

SO2 and NOX control on a unit as small as 100 MW. For ECO and advanced dry FGD, the same 

size range was evaluated for consistency with the LSFO cases. On the other hand, SDA was not 

assessed for large, high-sulfur fuel boilers because it would rarely be economical for SO2 removal 

on such large boilers when compared to LSFO. 

High Sulfur Coal ESP plus FGD (Model Plants 1, 6) 

As shown in Tables 10a and 10b, existing equipment (ESPc and wet FGD) are expected to provide 

68 percent mercury removal under the conditions of Model plant #1. Mercury removal by PAC 

injection is necessary for higher mercury removal. Under these conditions, to achieve 90 percent 

mercury removal, a PJFF downstream of the ESP and PAC injection will permit more economical 

removal through PAC injection. With the SCR, PAC injection is not expected to be necessary 

for achieving over 90 percent removal of mercury, but PAC injection may be necessary for higher 

than 90 percent mercury removal. 

High Sulfur Coal FF plus FGD (Model Plants 2, 7) 

When a facility is equipped with a fabric filter and an FGD system, it is expected that no additional 

mercury removal will be necessary because 96 percent mercury removal is expected from existing 

equipment. In this case SCR co-benefit is not significant because mercury removal is expected 

to be high already. 

58
Table 10a. High Sulfur Coal, ESP plus FGD Without SCR Co-benefit (Model Plants 1, 6)a 

Parameter Specified Hg Reduction (%) 

50 60 70 80 90 

Hg Reduction of Existing Equipment (%) 67.7 67.7 67.7 67.7 67.7 

Hg Reduction by PAC (%) none none 7.3 38.2 69.1 

Total Outlet Hg (mg/MWh) 12.2 12.2 11.3 7.5 3.8 

975 MW and No PJFFb 

Retrofit PJFF?b no no no no no 

Capital Cost ($/kW) $0.094 $0.094 $1.601 $2.437 $4.304 

Variable Cost (mills/kWh) 0.000 0.000 1.195 1.447 2.175 

Total Costb

 (mills/kWh) 0.003 0.003 1.242 1.520 2.303 

975 MW with PJFF 

Retrofit PJFF? no no yes yes yes 

Capital Cost ($/kW) $0.094 $0.094 $36.216 $36.322 $36.538 

Variable Cost (mills/kWh) 0.000 0.000 0.215 0.234 0.278 

Total Cost (mills/kWh) 0.003 0.003 1.122 1.144 1.195 

300 MW and No PJFFb 

Retrofit PJFF?b no no no no no 

Capital Cost ($/kW) $0.126 $0.126 $2.370 $3.600 $6.330 

Variable Cost (mills/kWh) 0.000 0.000 1.195 1.447 2.175 

Total Costb

 (mills/kWh) 0.004 0.004 1.265 1.554 2.363 

300 MW with PJFF 

Retrofit PJFF? no no yes yes yes 

Capital Cost ($/kW) $0.126 $0.126 $45.989 $45.147 $46.467 

Variable Cost (mills/kWh) 0.000 0.000 0.215 0.234 0.278 

Total Cost (mills/kWh) 0.004 0.004 1.352 1.376 1.430 a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. b The calculations performed to generate the results in this table assumed that all collected fly ash is currently 

sold, which is the situation with the most conservative assumption. Therefore, these calculations include 

costs to landfill fly ash with an impact to total cost of around 0.93 mills/kWh. In many cases these costs will 

not apply because either ash may currently be landfilled or it may not be rendered completely unacceptable 

for re-use. 

59
Table 10b. High Sulfur Coal, ESP plus FGD With SCR Co-benefit (Model Plants 1, 6)a 

Parameter Specified Hg Reduction (%) 

50 60 70 80 90 

Hg Reduction of Existing Equipment (%) 90. 90. 90. 90. 90. 

Hg Reduction by PAC (%) none none none none none 

Total Outlet Hg (mg/MWh) 3.8 3.8 3.8 3.8 3.8 

975 MW 

Retrofit PJFF? no no no no no 

Capital Cost ($/kW) $0.094 $0.094 $0.094 $0.094 $0.094 

Variable Cost (mills/kWh) 0.000 0.000 0.000 0.000 0.000 

Total Cost (mills/kWh) 0.003 0.003 0.003 0.003 0.003 

300 MW 

Retrofit PJFF? no no no no no 

Capital Cost ($/kW) $0.126 $0.126 $0.126 $0.126 $0.126 

Variable Cost (mills/kWh) 0.000 0.000 0.000 0.000 0.000 

Total Cost (mills/kWh) 0.004 0.004 0.004 0.004 0.004 a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. 

High Sulfur Coal ESPh plus FGD (Model Plants 3, 8) 

If an ESPh is used in combination with FGD, it is assumed that a low temperature PJFF will follow 

the ESP and air preheater. Tables 11a and 11b show the results of cost estimates. As shown, the 

co-benefit of SCR has substantial cost impacts because, without SCR, PAC must be added with 

a downstream PJFF. 

60
Table 11a. High Sulfur Coal, ESPh plus FGD Without SCR Co-benefit (Model Plants 3, 8)a 

Parameter Specified Hg Reduction (%) 

50 60 70 80 90 

Hg Reduction of Existing Equipment (%) 65.0 65.0 65.0 65.0 65.0 

Hg Reduction by PAC (%) none none 14.3 42.9 71.4 

Total Outlet Hg (mg/MWh) 13.2 13.2 11.3 7.5 3.8 

975 MW 

Retrofit PJFF? no no yes yes yes 

Capital Cost ($/kW) $0.094 $0.094 $36.236 $36.345 $36.566 

Variable Cost (mills/kWh) 0.000 0.000 0.218 0.239 0.284 

Total Cost (mills/kWh) 0.003 0.003 1.126 1.149 1.201 

300 MW 

Retrofit PJFF? no no yes yes yes 

Capital Cost ($/kW) $0.126 $0.126 $46.018 $46.180 $46.508 

Variable Cost (mills/kWh) 0.000 0.000 0.218 0.239 0.284 

Total Cost (mills/kWh) 0.004 0.004 1.357 1.382 1.437 a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. 

Table 11b. High Sulfur Coal, ESPh plus FGD with SCR Co-benefit (Model Plants 3, 8)a 

Parameter Specified Hg Reduction (%) 

50 60 70 80 90 

Hg Reduction of Existing Equipment (%) 90. 90. 90. 90. 90. 

Hg Reduction by PAC (%) none none none none none 

Total Outlet Hg (mg/MWh) 3.8 3.8 3.8 3.8 3.8 

975 MW 

Retrofit PJFF? no no no no no 

Capital Cost ($/kW) $0.094 $0.094 $0.094 $0.094 $0.094 

Variable Cost (mills/kWh) 0.000 0.000 0.000 0.000 0.000 

Total Cost (mills/kWh) 0.003 0.003 0.003 0.003 0.003 

300 MW 

Retrofit PJFF? no no no no no 

Capital Cost ($/kW) $0.126 $0.126 $0.126 $0.126 $0.126 

Variable Cost (mills/kWh) 0.000 0.000 0.000 0.000 0.000 

Total Cost (mills/kWh) 0.004 0.004 0.004 0.004 0.004 a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. 

61
ESP plus AdvDry FGD (Model Plants 4, 9) 

Because of the high levels of mercury reduction that are assumed to occur with advanced dry FGD 

on bituminous coals (over 95 percent mercury removal was measured at the Roanoke facility),42 

additional mercury removal by PAC injection is not necessary. As will be shown later, this 

technology is more cost effective on low sulfur coals than on high sulfur coals as shown here. 

It should also be kept in mind that this technology, while more costly than PAC injection, provides 

SO2 removal. An SO2 removal of 90 percent was assumed for each of these cases. 

Due to the limited experience with this technology on utility plants in the United Ststes, capital 

cost estimates may be uncertain. Sensitivity of the total cost with respect to capital cost is shown 

in Table 12. The base estimated cost for the size range is shown in bold on Table 12. Sensitivity 

analysis in a later section of this report and the appendices also show cost sensitivity with respect 

to reagent price. 

Table 12. Advanced Dry FGD on High Sulfur Coal (Model Plants 4, 9), Sensitivity to Capital 

Costa 

Parameter Capital Cost Categoryb 

-20% -10% Projected +10% +20% 

Hg Reduction of Existing Equipment (%) 29.4 29.4 29.4 29.4 29.4 

Hg Reduction of Advanced Dry FGDc

(%) 95.0 95.0 95.0 95.0 95.0 

Total Hg Removal (%) 96.5 96.5 96.5 96.5 96.5 

Total Outlet Hg (mg/MWh) 1.327 1.327 1.327 1.327 1.327 

975 MW 

Capital Cost ($/kW) $115.46 $129.80 $144.23 $158.65 $173.07 

Variable Cost (mills/kWh) 5.323 5.323 5.323 5.323 5.323 

Total Cost (mills/kWh) 7.940 8.265 8.592 8.919 9.246 

300 MW 

Capital Cost ($/kW) $127.47 $143.30 $159.23 $175.15 $191.07 

Variable Cost (mills/kWh) 5.323 5.323 5.323 5.323 5.323 

Total Cost (mills/kWh) 8.212 8.571 8.932 9.293 9.654 a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. b Capital Cost (115.28S173.07 $/kW for a 975 MW plant and 127.47S191.07 $/kW for a 300 MW plant) is the 

variable. c Advanced dry FGD is a technology developed primarily for SO2

mercury control for bituminous coal. 

removal; however, it can also provide 

62
ESP plus ECO (Model Plants 5 and 10) 

ECO is an emerging technology that appears to be capable of high pollution reduction. Because 

it is an emerging technology, the sensitivity of total cost to capital cost was assessed and is shown 

in Table 13. The economics rely, in part, on the revenue from fertilizer product sales and on the 

value of power. Sensitivity analyses for the effect of fertilizer product value and for power cost 

are shown in a later section of this report and in the appendices. For high sulfur coals, a high amount 

of fertilizer product is possible, which makes the economics of the process appear more favorable 

than for lower sulfur applications. 

Table 13. ESP and ECO on High Sulfur Coal (Model Plants 5 and 10), Sensitivity to Capital 

Costa 

Parameter Capital Cost Categoryb 

-20% -10% Projected +10% +20% 

Hg Reduction of Existing Equipment (%) 29.4 29.4 29.4 29.4 29.4 

85.0 85.0 85.0 85.0 

89.4 89.4 89.4 89.4 

ECO Hg Reduction FGDc

(%) 85.0 

Total Hg Reduction (%) 89.4 

Total Outlet Hg (mg/MWh) 3.98 3.98 3.98 3.98 3.98 

975 MW 

Capital Cost ($/kW) $150.28 $169.05 $187.83 $206.60 $225.38 

Variable Costd

 (mills/kWh) -0.820 -0.820 -0.820 -0.820 -0.820 

Total Cost (mills/kWh) 3.276 3.764 4.252 4.740 5.228 

300 MW 

Capital Cost ($/kW) $190.23 $214.00 $237.76 $261.53 $285.29 

Variable Costd

 (mills/kWh) -0.820 -0.820 -0.820 -0.820 -0.820 

Total Cost (mills/kWh) 4.741 5.359 5.977 6.595 7.212 a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. b Capital Cost (150.28S225.38 $/kW for a 975 MW plant and 190.23S285.29 $/kW for a 300 MW plant) is the 

variable. 

ECO is a technology developed primarily for NOX and SO2 removal; however, it can also provide mercury 

control. d Variable Cost includes a credit for fertilizer by-product sale. Negative numbers imply a net credit. Variable 

Cost also includes the cost of power for the barrier discharge reactor—estimated at about 4.8% of plant 

output for this case. 

63

c 
100 MW SDA and ESPc (Model Plant 26) 

For high sulfur fuels, a SDA with a downstream ESP is not expected to be very effective for mercury 

removal. Therefore, most of the mercury removal must be performed by additional PAC injection. 

In this case, a PJFF may be installed upstream of the SDA and must be sized for collection of 

the full ash loading plus the PAC injection. Alternatively, a smaller polishing PJFF may be installed 

downstream of the existing ESP. As will be shown later, a SDA with a downstream PJFF is expected 

to achieve relatively high mercury removal and will only require moderate PAC injection to achieve 

the additional reduction necessary for 90 percent removal. Therefore, it may be more economical 

to install a polishing PJFF downstream of the ESP (COHPAC conversion) and still inject the PAC 

upstream of the SDA than to install a PJFF sized for collection of the full ash loading plus the 

PAC injection. However, because data is not available on mercury removal from an SDA with 

a downstream COHPAC, it is uncertain if an SDA with a downstream COHPAC arrangement 

would be as effective in removing mercury as an SDA with downstream PJFF. 

Table 14. High Sulfur Coal, 100 MW SDA, and ESPc (Model Plant 26)a 

Parameter Specified Hg Reduction (%) 

50 60 70 80 90 

Hg Reduction of Existing Equipment (%) 5.0 5.0 5.0 5.0 5.0 

Hg Reduction by PAC (%) 47.4 57.9 68.4 78.9 89.5 

Total Outlet Hg (mg/MWh) 16.8 13.5 10.1 6.7 3.4 

100 MW no PJFF 

Retrofit PJFF? no no no no no 

Capital Cost ($/kW) $6.014 $7.235 $8.996 $11.818 $17.266 

Variable Cost (mills/kWh) 0.659 0.877 1.226 1.861 3.309 

Total Cost (mills/kWh) 0.838 1.092 1.493 2.211 3.821 

100 MW and Full Size PJFF 

Retrofit PJFF? yes yes yes yes yes 

Capital Cost ($/kW) $110.342 $110.891 $111.094 $111.413 $112.065 

Variable Cost (mills/kWh) 0.242 0.255 0.275 0.308 0.383 

Total Cost (mills/kWh) 2.907 2.934 2.960 3.002 3.096 

100 MW with PJFF (COHPAC conversion) 

Retrofit PJFF? yes yes yes yes yes 

Capital Cost ($/kW) $57.612 $57.970 $58.174 $58.495 $59.149 

Variable Cost (mills/kWh) 0.243 0.257 0.277 0.310 0.385 

Total Cost (mills/kWh) 1.657 1.680 1.706 1.749 1.843 a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. 

64
100 MW SDA and FF (Model Plant 27) 

As shown in Table 15, a SDA with a downstream fabric filter is expected to provide high mercury 

removal, approaching 90 percent. A small amount of PAC might be added upstream of the SDA 

to provide some more mercury reduction at a relatively low cost. 

Table 15. High Sulfur Coal, 100 MW SDA, and FF (Model Plant 27)a 

Parameter Specified Hg Reduction (%) 

50 60 70 80 90 

Hg Reduction of Existing Equipment (%) 89.3 89.3 89.3 89.3 89.3 

Hg Reduction by PAC (%) none none none none 6.3 

Total Outlet Hg (mg/MWh) 4.0 4.0 4.0 4.0 3.8 

100 MW, no PJFF 

Retrofit PJFF? no no no no no 

Capital Cost ($/kW) $0.165 $0.165 $0.165 $0.165 $3.388 

Variable Cost (mills/kWh) 0.000 0.000 0.000 0.000 0.270 

Total Cost (mills/kWh) 0.005 0.005 0.005 0.005 0.370 a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. 

65
100 MW ESPh and FGD (Model Plant 28) 

In this case, the ESPh followed by a wet FGD (LSFO) will provide about 65 percent mercury 

removal, and additional mercury removal will, therefore, be necessary to achieve 90 percent. As 

shown in Table 16, it is more economical for 90 percent mercury removal to install a polishing 

fabric filter after the air preheater and upstream of the flue gas desulfurization than to only inject 

PAC without the fabric filter. But for 70 percent removal, it may be most economical to inject 

PAC in the ductwork between the air preheater and the FGD. 

Table 16. High Sulfur Coal, 100 MW ESPh, and FGD (Model Plant 28)a 

Parameter Specified Hg Reduction (%) 

50 60 70 80 90 

Hg Reduction of Existing Equipment (%) 89.3 89.3 89.3 89.3 89.3 

Hg Reduction by PAC (%) none none none none 6.3 

Total Outlet Hg (mg/MWh) 4.0 4.0 4.0 4.0 3.8 

100 MW without PJFF 

Retrofit PJFF? no no no no no 

Capital Cost ($/kW) $0.165 $0.165 $3.751 $5.595 $9.657 

Variable Cost (mills/kWh) 0.000 0.000 1.236 1.510 2.287 

Total Cost (mills/kWh) 0.005 0.005 1.347 1.675 2.573 

100 MW with PJFF 

Retrofit PJFF? no no yes yes yes 

Capital Cost ($/kW) $0.165 $0.165 $57.533 $57.767 $58.241 

Variable Cost (mills/kWh) 0.000 0.000 0.217 0.237 0.282 

Total Cost (mills/kWh) 0.005 0.005 1.627 1.654 1.714 a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. 

6.3.2 Low Sulfur Bituminous Coals 

These coals are represented by Model Plants 11S19 and 29S37 in Table 9 and have a 0.6 wt%

sulphur content as shown in Table 7. The existing controls on these plants are either a cold- or

hot-side ESP or FF. Plants with ESPc or FF would need additional controls that consist of PAC,

PAC with a PJFF, ECO, or advanced dry FGD. Plants with an ESPh would need PAC with a PJFF,

ECO, or FF.

66
With ESPc and No SO2 controls (Model Plants 11 and 29)

For these cases, PAC injection is expected to be necessary for mercury reduction in excess of 50

percent. As shown in Table 17, addition of a PJFF for the 975 MW plant case improves overall

economics for removal in excess of 70 percent. However, for a smaller 100 MW plant, the addition

of a polishing PJFF is more economical only for the 90 percent mercury removal case.

Table 17. Low Sulfur Coal, ESPc, and No SO2 Controls (Model Plants 11 and 29)a 

Parameter Specified Hg Reduction (%) 

50 60 70 80 90 

Hg Reduction of Existing Equipment (%) 50.6 50.6 50.6 50.6 50.6 

Hg Reduction by PAC (%) none 19.0 39.2 59.5 79.7 

Total Outlet Hg (mg/MWh) 16.601 13.452 10.089 6.726 3.363 

975 MW and No PJFFb 

Retrofit PJFF?b no no no no no 

Capital Cost ($/kW) $0.094 $1.855 $2.467 $3.490 $5.711 

Variable Cost (mills/kWh) 0.000 0.709 0.901 1.277 2.282 

Total Costb

 (mills/kWh) 0.003 0.764 0.974 1.381 2.451 

975 MW with PJFF 

Retrofit PJFF? no yes yes yes yes 

Capital Cost ($/kW) $0.094 $36.248 $36.324 $36.445 $36.690 

Variable Cost (mills/kWh) 0.000 0.220 0.234 0.258 0.311 

Total Cost (mills/kWh) 0.003 1.128 1.144 1.171 1.233 

100 MW and No PJFFb 

Retrofit PJFF?b no no no no no 

Capital Cost ($/kW) $0.165 $3.791 $5.271 $7.430 $12.057 

Variable Cost (mills/kWh) 0.000 0.709 0.901 1.277 2.282 

Total Costb

 (mills/kWh) 0.005 0.827 1.057 1.497 2.639 

100 MW with PJFF 

Retrofit PJFF? no yes yes yes yes 

Capital Cost ($/kW) $0.165 $57.563 $57.729 $57.989 $58.518 

Variable Cost (mills/kWh) 0.000 0.220 0.234 0.258 0.311 

Total Cost (mills/kWh) 0.005 1.631 1.650 1.682 1.751 

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in 

mills/KWh. For a more comprehensive breakdown of costs, please see the model plant tables in 

the appendices. b The calculations performed to generate the results in this table assumed that all collected fly ash is 

currently sold, which is the situation with the most conservative assumption. Therefore, these 

calculations include costs to landfill fly ash with an impact to total cost of around 0.93 mills/kWh. In 

many cases these costs will not apply because either ash may currently be landfilled or it may not 

be rendered completely unacceptable for re-use. 

67
With FF and No SO2 controls (Model Plants 12 and 30)

Due to the high mercury removal expected fromexisting equipment in these cases, PAC injection

is only expected to be necessary for mercury reduction in excess of 85 percent. As shown in Table

18, installation of a PJFF is expected to be economically beneficial for neither the 975 nor the

100 MW plant cases.

Table 18. Low Sulfur Coal, FF, and No SO2 Controls (Model Plants 12 and 30)a 

Parameter Specified Hg Reduction (%) 

50 60 70 80 90 

Hg Reduction of Existing Equipment (%) 85.0 85.0 85.0 85.0 85.0 

Hg Reduction by PAC (%) none none none none 33.3 

Total Outlet Hg (mg/MWh) 5.0 5.0 5.0 5.0 3.4 

975 MW and No PJFFb 

Retrofit PJFF?b no no no no no 

Capital Cost ($/kW) $0.094 $0.094 $0.094 $0.094 $0.821 

Variable Cost (mills/kWh) 0.000 0.000 0.000 0.000 0.458 

Total Costb

 (mills/kWh) 0.003 0.003 0.003 0.003 0.482 

975 MW with PJFF 

Retrofit PJFF? no no no no yes 

Capital Cost ($/kW) $0.094 $0.094 $0.094 $0.094 $36.299 

Variable Cost (mills/kWh) 0.000 0.000 0.000 0.000 0.229 

Total Cost (mills/kWh) 0.003 0.003 0.003 0.003 1.139 

100 MW and No PJFFb 

Retrofit PJFF?b no no no no no 

Capital Cost ($/kW) $0.165 $0.165 $0.165 $0.165 $1.752 

Variable Cost (mills/kWh) 0.000 0.000 0.000 0.000 0.458 

Total Costb

 (mills/kWh) 0.005 0.005 0.005 0.005 0.510 

100 MW with PJFF 

Retrofit PJFF? no no no no yes 

Capital Cost ($/kW) $0.165 $0.165 $0.165 $0.165 $57.674 

Variable Cost (mills/kWh) 0.000 0.000 0.000 0.000 0.229 

Total Cost (mills/kWh) 0.005 0.005 0.005 0.005 1.644 a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. b The calculations performed to generate the results in this table assumed that all collected fly ash is currently 

sold, which is the situation with the most conservative assumption. Therefore, these calculations include 

costs to landfill fly ash with an impact to total cost of around 0.93 mills/kWh. In many cases these costs will 

not apply because either ash may currently be landfilled or it may not be rendered completely unacceptable 

for re-use. 

68
With ESPh and No SO2 Controls (Model Plants 13 and 31)

Due to the low mercury removal possible from existing equipment in these cases, PAC injection

is expected to be necessary for all of the conditions, and a polishing PJFF must be added because

PAC injection would normally be added downstream of the ESPh and air preheater. Table 19 shows

the economics of this type of installation for 975 MW and 100 MW plants.

Table 19. Low Sulfur Coal, ESPh, and No SO2 Controls (Model Plants 13 and 31)a 

Parameter Specified Hg Reduction (%) 

50 60 70 80 90 

Hg Reduction of Existing Equipment (%) 25.5 25.5 25.5 25.5 25.5 

Hg Reduction by PAC (%) 32.9 46.3 59.7 73.2 86.6 

Total Outlet Hg (mg/MWh) 16.8 13.5 10.1 6.7 3.4 

975 MW 

Retrofit PJFF? yes yes yes yes yes 

Capital Cost ($/kW) $36.162 $36.360 $36.447 $36.584 $36.865 

Variable Cost (mills/kWh) 0.229 0.241 0.258 0.287 0.353 

Total Cost (mills/kWh) 1.135 1.152 1.172 1.205 1.280 

100 MW 

Retrofit PJFF? yes yes yes yes yes 

Capital Cost ($/kW) $57.458 $57.805 $57.994 $58.290 $58.893 

Variable Cost (mills/kWh) 0.229 0.241 0.258 0.287 0.353 

Total Cost (mills/kWh) 1.638 1.659 1.682 1.720 1.804 a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. 

69
ECO Installed after Particulate Removal (Model Plants 14S16, 32S34) 

Since the most common location for installation of ECO is likely to be after an ESPc and because 

the economics are similar regardless of the existing PM removal equipment, only the results of 

analysis for ECO installed after an ESPc are shown in Table 20. ECO is a capital-intensive 

technology, and there remains some uncertainty regarding its actual capital cost because it is an 

emerging technology. Therefore, the cost was evaluated for a range of capital costs plus or minus 

20 percent of the projected cost for the size unit. The sensitivity analysis of Section 6.4 shows 

estimated ECO economics while varying the fertilizer product value and the power cost for a 500 

MW plant. Additional information is available in the Model Runs in the appendices. For a given 

coal, unit size, and cost of consumables, the economics of ECO are estimated to be roughly the 

same regardless of the type of upstream particulate control device. 

Table 20. ECO Installed After Particulate Removal (Model Plants 14S16, 32S34), Sensitivity to 

Capital Costa 

Parameter Capital Cost Categoryb 

-20% -10% Projected +10% +20% 

Hg Reduction of Existing Equipment (%) 50.6 50.6 50.6 50.6 50.6 

ECO Hg Reduction FGDc

(%) 85.0 85.0 85.0 85.0 85.0 

Total Hg Reduction (%) 92.6 92.6 92.6 92.6 92.6 

Total Outlet Hg (mg/MWh) 2.49 2.49 2.49 2.49 2.49 

975 MW 

Capital Cost ($/kW) $150.28 $169.05 $187.83 $206.60 $225.38 

Variable Costd

 (mills/kWh) 1.243 1.243 1.243 1.243 1.243 

Total Cost (mills/kWh) 5.340 5.828 6.316 6.804 7.292 

100 MW 

Capital Cost ($/kW) $236.99 $266.59 $296.20 $325.80 $355.41 

Variable Costd

 (mills/kWh) 1.243 1.243 1.243 1.243 1.243 

Total Cost (mills/kWh) 9.521 10.021 10.790 11.560 12.329 a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. b Capital Cost (150.28S225.38 $/kW for a 975 MW plant and 236.99S355.41 $/kW for a 100 MW plant) is the 

variable. 

ECO is a technology developed primarily for NOX and SO2 removal; however, it can also provide mercury 

control. Data shown is for retrofit on a boiler with existing ESPc. For boilers with existing ESPh or FF, costs 

would be very similar, but outlet mercury would differ somewhat from what is shown here. See appendices 

for details d Variable Cost includes a credit for fertilizer by-product sale. Negative numbers imply a net credit. Variable 

Cost also includes the cost of power for the barrier discharge reactor—estimated at about 4.8% of plant 

output for this case. 

70

c 
Advanced Dry FGD (Model Plants 17S19, 35S37)

Advanced Dry FGD is another technology that is somewhat capital intensive and controls SO2

and mercury. Like ECO, the economics are a strong function of capital cost and sulfur level and

less affected by the type of upstream particulate control technology. Shown in Table 21 are the

results of analysis for advanced dry FGD downstream of an existing ESPc.

Table 21. Advanced Dry FGD (Model Plants 17S19, 35S37), Sensitivity to Capital Costa 

Parameter Capital Cost Categoryb 

-20% -10% Projected +10% +20% 

Hg Reduction of Existing Equipment (%) 50.6 50.6 50.6 50.6 50.6 

95.0 95.0 95.0 95.0 

97.5 97.5 97.5 97.5 

0.830 0.830 0.830 0.830 

Hg Reduction of Advanced Dry FGDc

(%) 95.0 

Total Hg Removal (%) 97.5 

Total Outlet Hg (mg/MWh) 0.830 

975 MW 

Capital Cost ($/kW) $115.46 $129.80 $144.23 $158.65 $173.07 

Variable Cost (mills/kWh) 1.071 1.071 1.071 1.071 1.071 

Total Cost (mills/kWh) 3.688 4.013 4.340 4.667 4.994 

100 MW 

Capital Cost ($/kW) $162.17 $182.31 $202.57 $222.82 $243.08 

Variable Cost (mills/kWh) 1.071 1.071 1.071 1.071 1.071 

Total Cost (mills/kWh) 4.747 5.203 5.662 6.122 6.581 a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. b Capital Cost (115.28S173.07 $/kW for a 975 MW plant and 162.17S243.08 $/kW for a 100 MW plant) is the 

variable. 

Advanced dry FGD is a technology developed primarily for SO2 removal; however, it can also provide 

mercury control for bituminous coal. Data shown is for retrofit on a boiler with existing ESPc. For boilers with 

existing ESPh or FF, costs would be very similar, but outlet mercury may differ somewhat from what is 

shown here. See appendices for details. 

6.3.3 Low Sulfur Subbituminous Coals Including Powder River Basin Coals 

Mercury removal with existing equipment is typically lower for subbituminous coals than for 

bituminous coals. As a result, mercury reduction is more dependent on PAC injection for high 

levels of mercury removal. In the case of boilers currently equipped with ESPs, it may not be 

possible to achieve 80 or 90 percent reduction without addition of a downstream PJFF as indicated 

in Model Plants 20S22 and 38S40. ECO is examined on Model Plants 23S25 and 41S43. The 

effectiveness and cost of K-Fuel as a mercury control technology is examined in Model Plants 

44S49. The K-fuel process is primarily designed to improve fuel-heating value, but it also provides 

some SO2 reduction, may provide NOX reduction, and provides mercury reduction. 

71

c 
Boilers with Particulate Control and No SO2 Control (Model Plants 20S22, 38S40) 

As shown in Table 22 for the cases without a downstream PJFF, estimates for 80 or 90 percent 

mercury reduction show high costs due to high predicted injection rates. It is recognized that, despite 

the high injection rates, the specified Hg reduction may not be achievable without addition of 

a PJFF after the ESP. However, it should be noted that the algorithms used for PAC injection here 

(Equation 9 and the associated constants for this case) were developed from test results at the 

Pleasant Prairie Power Plant, which had a coal chlorine content of only 15 ppm, which is lower 

than typically expected for this type of fuel.19 So, it is possible that other PRB fueled boilers may 

be easier to control with PAC than those shown here. 

For mercury reduction from boilers firing subbituminous coals and equipped with a downstream 

FF, PAC injection is necessary for greater than about 60 percent mercury reduction. Addition of 

a downstream PJFF provides the benefit of much lower waste disposal costs because fly ash is 

not contaminated. Therefore, although the cost of sorbent is similar regardless of whether or not 

a PJFF is added, the additional cost of waste disposal roughly compensates for the cost of the PJFF 

for the 975 MW case as shown in Table 23. 

In the case where an ESPh is currently installed, it is necessary to install a downstream PJFF for 

mercury removal by PAC injection. As shown in Table 24, this can generally be performed at 

a cost of below 2 mills/kWh. 

PRB Coals with ECO (Model Plants 23S25, 41S43) 

Since the most common installation for an ECO is likely to be after an ESPc and the economics 

are similar regardless of existing particle removal equipment, only the ECO after an ESPc is shown 

in Table 25. ECO is a capital-intensive technology, and there remains some uncertainty regarding 

its capital cost because it is an emerging technology. Therefore, the cost was evaluated for a range 

of capital costs within 20 percent of the projected cost for the size unit. The model runs in the 

appendices show estimated ECO economics for various fertilizer product value and power value 

for 975 MW and 100 MW plants equipped with ESPc, FF, or ESPh. The lower NOX level associated 

with PRB coals helps to reduce the power demand of the ECO barrier discharge reactor compared 

to the power demand of the ECO barrier discharge reactor when firing bituminous coals. However, 

because of the low fertilizer product revenue (due to low NOX and SO2 levels for PRB coals), 

economics of ECO on this application are estimated to be less favorable than for the bituminous 

coals that have higher NOX and SO2 levels. 

72
Table 22. Low Sulfur Subbituminous Coals, ESPc, and No SO2 Control (Model Plants 20, 38)a 

Parameter Specified Hg Reduction (%) 

50 60 70 80 90 

Hg Reduction of Existing Equipment (%) 29.7 29.7 29.7 29.7 29.7 

Desired Hg Reduction by PAC (%) 28.9 43.1 57.3 71.5 85.8 

Actual Hg Reduction by PAC (%) without 

PJFFb 

28.9 43.1 57.3 69.3 69.3 

Total Actual Hg Reduction without PJFFb 50.0 60.0 70.0 78.5 78.5 

975 MW with ESPc and No PJFFc 

Retrofit PJFF?c no no no no no 

Capital Cost ($/kW) $0.401 $1.238 $3.232 $27.744 $27.744 

Variable Cost (mills/kWh) 1.027 1.181 1.811 20.102 20.102 

Total Costc

 (mills/kWh) 1.039 1.218 1.907 20.924 20.924 

Total Outlet Hg (mg/MWh) 20.1 16.1 12.1 8.7 8.7 

975 MW with ESPc and PJFF 

Retrofit PJFF? yes yes yes yes yes 

Capital Cost ($/kW) $35.998 $36.258 $36.422 $36.666 $37.139 

Variable Cost (mills/kWh) 0.209 0.231 0.262 0.315 0.435 

Total Costc

 (mills/kWh) 1.111 1.139 1.176 1.236 1.369 

Total Outlet Hg (mg/MWh) 20.1 16.1 12.1 8.0 4.0 

100 MW with ESPc and No PJFFc 

Retrofit PJFF?c no no no no no 

Capital Cost ($/kW) $0.840 $2.651 $6.887 $55.806 $55.806 

Variable Cost (mills/kWh) 1.027 1.181 1.811 20.102 20.102 

Total Costc

 (mills/kWh) 1.052 1.259 2.015 21.756 21.756 

Total Outlet Hg (mg/MWh) 20.1 16.1 12.1 8.7 8.7 

100 MW with ESPc and PJFF 

Retrofit PJFF? yes yes yes yes yes 

Capital Cost ($/kW) $57.102 $57.585 $57.939 $58.466 $59.479 

Variable Cost (mills/kWh) 0.209 0.231 0.262 0.315 0.435 

Total Costc

 (mills/kWh) 1.608 1.643 1.685 1.753 1.903 

Total Outlet Hg (mg/MWh) 20.1 16.1 12.1 8.0 4.0 a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. b With PAC injection on subbituminous coals without a downstream fabric filter, Hg reduction at very high 

levels is not expected to be possible. Additional PAC injection will not improve Hg reduction. c The calculations performed to generate the results in this table assumed that all collected fly ash is currently 

sold, which is the most conservative situation. Therefore, these calculations include costs to landfill fly ash 

with an impact to total cost of around 1.01 mills/kWh. In many cases these costs will not apply because ash 

may currently be landfilled or because ash may not be rendered completely unacceptable for re-use. 

73
Table 23. Low Sulfur Subbituminous Coals, FF, and No SO2 Control (Model Plants 21, 39)a 

Parameter Specified Hg Reduction (%) 

50 60 70 80 90 

Hg Reduction of Existing Equipment (%) 60.7 60.7 60.7 60.7 60.7 

Hg Reduction by PAC (%) none none 23.6 49.1 74.5 

Total Outlet Hg (mg/MWh) 15.8 15.8 12.1 8.0 4.0 

975 MW with FF and No PJFFb 

Retrofit PJFF?b no no no no no 

Capital Cost ($/kW) $0.094 $0.094 $0.616 $0.842 $1.259 

Variable Cost (mills/kWh) 0.000 0.000 1.057 1.097 1.186 

Total Costb

 (mills/kWh) 0.003 0.003 1.075 1.122 1.223 

975 MW with FF and PJFF 

Retrofit PJFF? no no yes yes yes 

Capital Cost ($/kW) $0.094 $0.094 $36.094 $36.320 $37.737 

Variable Cost (mills/kWh) 0.000 0.000 0.203 0.243 0.332 

Total Costc

 (mills/kWh) 0.003 0.003 1.106 1.153 1.254 

100 MW with FF and No PJFFb 

Retrofit PJFF?b no no no no no 

Capital Cost ($/kW) $0.165 $0.165 $1.308 $1.799 $2.696 

Variable Cost (mills/kWh) 0.000 0.000 1.057 1.097 1.186 

Total Costc

 (mills/kWh) 0.005 0.005 1.096 1.150 1.266 

100 MW with FF and PJFF 

Retrofit PJFF? no no yes yes yes 

Capital Cost ($/kW) $0.165 $0.165 $57.230 $57.721 $58.618 

Variable Cost (mills/kWh) 0.000 0.000 0.203 0.243 0.332 

Total Costc

 (mills/kWh) 0.005 0.005 1.604 1.659 1.774 a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. b The calculations performed to generate the results in this table assumed that all collected fly ash is currently 

sold, which is the most conservative situation. Therefore, these calculations include costs to landfill fly ash 

with an impact to total cost of around 1.01 mills/kWh. In many cases these costs will not apply because ash 

may currently be landfilled or because ash may not be rendered completely unacceptable for re-use. 

74
Table 24. Low Sulfur Subbituminous Coals, ESPh, and No SO2 Controls (Model Plants 22, 40)a 

Parameter Specified Hg Reduction (%) 

50 60 70 80 90 

Hg Reduction of Existing Equipment (%) 12.6 12.6 12.6 12.6 12.6 

Hg Reduction by PAC (%) 42.8 54.2 65.7 77.1 88.6 

Total Outlet Hg (mg/MWh) 20.1 16.1 12.1 8.0 4.0 

975 MW with ESPh and PJFF 

Retrofit PJFF? yes yes yes yes yes 

Capital Cost ($/kW) $36.119 $36.381 $36.550 $36.806 $37.305 

Variable Cost (mills/kWh) 0.230 0.254 0.289 0.348 0.482 

Total Cost (mills/kWh) 1.135 1.166 1.206 1.273 1.421 

100 MW with ESPh and PJFF 

Retrofit PJFF? tes yes yes yes yes 

Capital Cost ($/kW) $57.365 $57.852 $58.217 $58.766 $59.834 

Variable Cost (mills/kWh) 0.230 0.254 0.289 0.348 0.482 

Total Costc

 (mills/kWh) 1.637 1.674 1.720 1.795 1.960 a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. 

75
Table 25. Low Sulfur Subbituminous Coals with ECO (Model Plants 23S25, 41S43) Sensitivity 

to Capital Costa 

Parameter Capital Cost Categoryb 

-20% -10% Projected +10% +20% 

Hg Reduction of Existing Equipment (%) 29.7 29.7 29.7 29.7 29.7 

ECO Hg Reduction FGDc

(%) 85.0 85.0 85.0 85.0 85.0 

Total Hg Reduction (%) 89.5 89.5 89.5 89.5 89.5 

Total Outlet Hg (mg/MWh) 4.24 4.24 4.24 4.24 4.24 

975 MW with ESPc 

Capital Cost ($/kW) $150.28 $169.05 $187.83 $206.60 $225.38 

Variable Costd

 (mills/kWh) 0.442 0.442 0.442 0.442 0.442 

Total Cost (mills/kWh) 4.539 5.027 5.515 6.003 6.491 

100 MW with ESPc 

Capital Cost ($/kW) $236.99 $266.59 $296.20 $325.80 $355.41 

Variable Costd

 (mills/kWh) 0.442 0.442 0.442 0.442 0.442 

Total Cost (mills/kWh) 8.451 9.220 9.990 10.759 11.529 a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. b Capital Cost (150.28S225.38 $/kW for a 975 MW plant and 236.99S355.41 $/kW for a 100 MW plant) is the 

variable. 

ECO is a technology developed primarily for NOX and SO2 removal; however, it can also provide mercury 

control. Data shown is for retrofit on a boiler with existing ESPc. For boilers with existing ESPh or FF, costs 

would be very similar, but outlet mercury would differ somewhat from what is shown here. See appendices 

for details d Variable Cost includes a credit for fertilizer by-product sale. Negative numbers imply a net credit. Variable 

Cost also includes the cost of power for the barrier discharge reactor—estimated at about 4.8% of plant 

output for this case. 

Beneficiated Western Coals—K-Fuel 

Table 26 compares the estimated mercury emissions on a mg/MWh basis for the base PRB coal 

versus the K-Fuel beneficiated coal. The K-Fuel has about 60 percent less mercury than PRB on 

a unit of heating value basis. Mercury removal rates for the particulate removal equipment are 

similar, with the K-Fuel estimated to have a slightly higher removal with an ESPc due to the slightly 

lower sulfur level in the fuel. It is also important to note that K-Fuel provides a 44 percent reduction 

in SO2 emissions from the base PRB fuel. 

Figure 16 shows the economics of K-Fuel assuming that all of the incremental costs of using the 

fuel are born in an increased fuel cost over PRB fuel. 

76

c 
Table 26. Comparison of Estimated Mercury Emissions from PRB and K-Fuela

 Boilers Equipped 

with Particulate Control and No Additional Mercury or SO2 Controls 

Characteristic PRB K-Fuel PRB K-Fuel PRB K-Fuel 

Particulate Control System ESPc ESPc FF FF ESPh ESPh 

Hg Reduction with Existing Equipment 

(%) 

29.7 36.8 60.7 60.7 12.6 12.6 

Hg from Coal (mg/MWh) 40.2 16.3 40.2 16.3 40.2 16.3 

Total Outlet Hg (mg/MWh) 28.2 10.3 15.8 6.4 35.1 14.2 a The K-fuel process is primarily designed to improve fuel-heating value, but it may provide NOX reduction, 

provides some SO2 reduction, and provides Hg reduction. 

Figure 16. Estimated Effect of K-Fuel Cost on Generation Cost. 

Model runs were performed for PAC injection on boilers equipped with K-Fuel. These are model 

runs 44 through 49, and Tables 27S29 summarize the results of these model runs. The economics 

of PAC injection for K-Fuel are similar to those for PAC injection for PRB, except that it may 

be appropriate to add to these costs the incremental cost of the K-Fuel over PRB. The major 

difference is that lower emissions rates are possible with K-Fuel than with PRB due to the lower 

initial mercury level. 

77
Table 27. K-Fuela

, ESPc and No SO2 Control (Model Plants 44, 47)b 

Parameter Specified Hg Reduction (%) 

50 60 70 80 90 

Hg Reduction of Existing Equipment (%) 36.8 36.8 36.8 36.8 36.8 

Desired Hg Reduction by PAC (%) 20.9 36.7 52.5 68.3 84.2 

Actual Hg Reduction by PAC (%) without 

PJFFc 

20.9 36.7 52.5 68.3 69.3 

Total Actual Hg Reduction without PJFFc 50.0 60.0 70.0 80.0 80.6 

975 MW with ESPc and No PJFFd 

Retrofit PJFF?d no no no no no 

Capital Cost ($/kW) $0.391 $0.673 $2.240 $14.462 $26.735 

Variable Cost (mills/kWh) 0.745 0.785 1.180 8.237 18.846 

Total Costd

 (mills/kWh) 0.756 0.805 1.247 8.666 19.638 

Total Outlet Hg (mg/MWh) 8.1 6.5 4.9 3.3 3.2 

975 MW with ESPc and PJFF 

Retrofit PJFF? yes yes yes yes yes 

Capital Cost ($/kW) $35.922 $36.177 $36.333 $36.565 $37.009 

Variable Cost (mills/kWh) 0.190 0.209 0.238 0.285 0.393 

Total Costd

 (mills/kWh) 1.089 1.115 1.148 1.203 1.323 

Total Outlet Hg (mg/MWh) 8.1 6.5 4.9 3.3 1.6 

100 MW with ESPc and No PJFFd 

Retrofit PJFF?d no no no no no 

Capital Cost ($/kW) $0.817 $1.431 $4.792 $29.800 $53.860 

Variable Cost (mills/kWh) 0.745 0.785 1.180 8.237 18.846 

Total Costd

 (mills/kWh) 0.769 0.828 1.322 9.120 20.441 

Total Outlet Hg (mg/MWh) 8.1 6.5 4.9 3.3 3.2 

100 MW with ESPc and PJFF 

Retrofit PJFF? yes yes yes yes yes 

Capital Cost ($/kW) $56.936 $57.409 $57.748 $58.248 $59.202 

Variable Cost (mills/kWh) 0.190 0.209 0.238 0.285 0.393 

Total Costd

 (mills/kWh) 1.584 1.616 1.654 1.717 1.853 

Total Outlet Hg (mg/MWh) 8.1 6.5 4.9 3.3 1.6 a The K-fuel process is primarily designed to improve fuel-heating value, but it may provide NOX reduction, 

provides some SO2 reduction, and provides Hg reduction. b This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. c With PAC injection on subbituminous coals without a downstream fabric filter, Hg reduction at very high 

levels is not expected to be possible. Additional PAC injection will not improve Hg reduction. d The calculations performed to generate the results in this table assumed that all collected fly ash is currently 

sold, which is the most conservative situation. Therefore, these calculations include costs to landfill fly ash 

with an impact to total cost of around 1.01 mills/kWh. In many cases these costs will not apply because ash 

may currently be landfilled or because ash may not be rendered completely unacceptable for re-use. 

78
Table 28. K-Fuela

, FF, and No SO2 Control (Model Plants 45, 48)b 

Parameter Specified Hg Reduction (%) 

50 60 70 80 90 

Hg Reduction of Existing Equipment (%) 60.7 60.7 60.7 60.7 60.7 

Hg Reduction by PAC (%) none none 23.6 49.1 74.5 

Total Outlet Hg (mg/MWh) 6.4 6.4 4.9 3.3 1.6 

975 MW with FF and No PJFFc 

Retrofit PJFF?c no no no no no 

Capital Cost ($/kW) $0.094 $0.094 $0.598 $0.817 $1.219 

Variable Cost (mills/kWh) 0.000 0.000 0.773 0.811 0.895 

Total Costc

 (mills/kWh) 0.003 0.003 0.791 0.835 0.931 

975 MW with FF and PJFF 

Retrofit PJFF? no no yes yes yes 

Capital Cost ($/kW) $0.094 $0.094 $36.076 $36.295 $36.697 

Variable Cost (mills/kWh) 0.000 0.000 0.193 0.230 0.315 

Total Costc

 (mills/kWh) 0.003 0.003 1.096 1.140 1.236 

100 MW with FF and No PJFFc 

Retrofit PJFF?c no no no no no 

Capital Cost ($/kW) $0.165 $0.165 $1.269 $1.744 $2.611 

Variable Cost (mills/kWh) 0.000 0.000 0.773 0.811 0.895 

Total Costd

 (mills/kWh) 0.005 0.005 0.811 0.862 0.973 

100 MW with FF and PJFF 

Retrofit PJFF? no no yes yes yes 

Capital Cost ($/kW) $0.165 $0.165 $57.191 $57.666 $58.533 

Variable Cost (mills/kWh) 0.000 0.000 0.193 0.230 0.315 

Total Costc

 (mills/kWh) 0.005 0.005 1.593 1.645 1.755 a The K-fuel process is primarily designed to improve fuel-heating value, but it may provide NOX reduction, 

provides some SO2 reduction, and provides Hg reduction. b This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. 

The calculations performed to generate the results in this table assumed that all collected fly ash is currently 

sold, which is the most conservative situation. Therefore, these calculations include costs to landfill fly ash 

with an impact to total cost of around 1.01 mills/kWh. In many cases these costs will not apply because ash 

may currently be landfilled or because ash may not be rendered completely unacceptable for re-use. 

79

c 
Table 29. K-Fuela

, ESPh, and No SO2 Controls (Model Plants 46, 49)b 

Parameter Specified Hg Reduction (%) 

50 60 70 80 90 

Hg Reduction of Existing Equipment (%) 12.6 12.6 12.6 12.6 12.6 

Hg Reduction by PAC (%) 42.8 54.2 65.7 77.1 88.6 

Total Outlet Hg (mg/MWh) 8.1 6.5 4.9 3.3 1.6 

975 MW with ESPh and PJFF 

Retrofit PJFF? yes yes yes yes yes 

Capital Cost ($/kW) $36.096 $36.353 $36.517 $36.764 $37.246 

Variable Cost (mills/kWh) 0.219 0.242 0.275 0.331 0.457 

Total Cost (mills/kWh) 1.123 1.153 1.191 1.254 1.395 

100 MW with FF and PJFF 

Retrofit PJFF? yes yes yes yes yes 

Capital Cost ($/kW) $57.315 $57.792 $58.145 $58.676 $59.707 

Variable Cost (mills/kWh) 0.219 0.242 0.275 0.331 0.457 

Total Cost (mills/kWh) 1.624 1.660 1.7.03 1.775 1.932 a The K-fuel process is primarily designed to improve fuel-heating value, but it may provide NOX reduction, 

provides some SO2 reduction, and provides Hg reduction. b This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. 

For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. 

6.4 Cost Impacts of Selected Variables 

Sensitivity analysis was performed for certain variables of interest on specific model plants. These 

included the effects of new sorbents, capital cost on PAC injection, fertilizer cost/power cost on 

ECO, and lime cost on Advanced Dry FGD. 

Effect of New Sorbents on Cost of Hg Control 

In the future, cost of controlling mercury could be reduced by new sorbents, which could potentially 

eliminate disposal costs for spent sorbent/fly ash mixtures. To assess the effects of elimination 

of ash and sorbent disposal cost, Figure 17 was developed. Figure 17 shows the results of cost 

estimates comparing mercury control cost for 500 MW plants with and without disposal costs. 

For each configuration, the sorbent and fly ash are collected together in an existing FF or ESPc. 

As shown, the elimination of disposal costs can be quite significant, especially for the PRB fuels. 

Low sulfur bituminous coal, with a low ash level and high Btu content, has a lower component 

of ash disposal cost of the total cost, but it is nevertheless quite significant at about 0.38 mills/kWh 

(this is just for the fly ash; the sorbent contributes to additional disposal cost). The PRB fuel has 

80
Figure 17. Cost of PAC Injection for 500 MW Coal Fired Boilers with existing ESPc or FF. 

a higher ash loading and lower Btu content, causing ash levels to be much higher and disposal 

costs for contaminated ash much higher (about 1.0 mill/kWh for the ash alone). The exact savings 

in disposal cost for any particular application will depend upon the actual ash content and Btu 

value of the particular fuel being used. So, facilities with fuel having different ash content or Btu 

value will see a different impact on ash disposal costs. 

It is also notable that the impact of disposal costs, as a percent of total cost, is much greater for 

facilities with FFs than for facilities that capture the PAC and fly ash in ESPs. This is because 

the much lower PAC injection rate for FF-equipped facilities makes ash disposal cost a very large 

fraction of the total cost. Figure 17 shows that if disposal costs can be avoided by use of costeffective sorbents other than PAC, or by other means, then the cost of controlling mercury can 

be reduced by 75 to 80 percent in some cases (PAC injection upstream of existing FF). 

There is extensive research ongoing in the field of improved sorbents for mercury control that 

may be more efficient in capturing mercury and potentially at a lower cost than PAC.59,74,75 These 

improvements in sorbents may contribute to overall reductions in sorbent consumption, contributing 

to reduced costs for disposal, sorbents, and capital equipment. Improved sorbents could enable 

81
users to avoid installation of fabric filters and will also reduce the sorbent storage and material 

handing equipment on site. 

For example, Reference 19 showed that PAC usage for facilities that capture PAC sorbent in 

downstream ESPs was much more affected by selection of the type of PAC sorbent than facilities 

that captured the PAC sorbent in a FF. Reference 19 cited the results of several full-scale tests 

using different PAC materials available from manufacturers. Reference 19 developed three different 

performance curves for each of the two cases with downstream ESPs (one case with bituminous 

coal and the other case with a PRB subbituminous coal). The three different curves were 

characterized as high, medium, and low performance. Figure 18 shows estimates of total cost for 

PAC injection (inclusive of disposal costs) for the medium performance sorbents used in this study 

versus higher performance sorbents tested in field trials. The estimates assume that the higher 

performance PAC sorbents are available at the same price (the higher performance sorbents are 

PAC with some different physical characteristics—no additional chemicals). As shown in Figure 

Figure 18. Cost of PAC Injection for 500 MW Coal Fired Boilers with Existing 

ESPc—Effect of Medium Versus High Performance PAC. 

82
18, cost reduction of 20 percent is estimated for the bituminous coal fired facility when using the 

higher performance PAC. Because the sorbents used in the calculations to generate Figure 18 are 

conventional PAC sorbents, even greater cost improvements are likely if other improved sorbents 

are considered. 

Effect of Capital Cost for PAC Injection 

For facilities with ESPcs that may retrofit PAC injection and a PJFF downstream of the ESP, capital 

cost is a major contributor to control cost. As shown in Figure 19, for boilers firing either PRB 

or low sulfur bituminous coal, the total cost of control is expected to vary from about 1.2 to about 

1.8 mills/kWh over the range of expected total capital costs. 

Figure 19. Effect of Capital Cost on 90 Percent Mercury Control with PAC on Boiler with 

Existing ESPc and Retrofit of Downstream PJFF. 

Effect of Fertilizer Value and Power Cost on ECO 

Figure 20 shows the estimated effect of the value of fertilizer product on the economics of ECO 

for a 500 MW plant firing either low sulfur or high sulfur bituminous coal. For a high sulfur coal 

83
fired boiler, the impact of fertilizer value in reducing cost is greater because more fertilizer is 

produced from a high sulfur coal boiler. Also, for the high sulfur coal boiler, the net cost is lower 

due to the higher fertilizer revenues. Figure 21 shows the effects of the value of power needed 

by the ECO on the cost of controlling with ECO on a 500 MW plant firing either low sulfur or 

high sulfur bituminous coal. For a PRB coal fired boiler or a boiler with lower initial NOX, the 

effect of power on total cost is less because power consumption is closely related to NOX levels. 

Figure 20. Effect of Fertilizer Value on Cost of Emissions Control with ECO on a 

500 MW Bituminous Coal Boiler. 

Effect of Lime Cost on Advanced Dry FGD 

Figure 22 shows the effects of the cost of lime reagent, an important cost factor, on the total cost 

of control for advanced dry FGD. As shown, there is roughly !0.19 mills/kWh effect, or a roughly 

!4 percent effect on the total cost of control over the range evaluated. 

84
Figure 21. Effect of Power Value on Cost of Emissions Control with ECO on a 

500 MW Bituminous Coal Boiler. 

Figure 22. Effect of Reagent Cost on Cost of Emissions Control with Advanced 

Dry FGD on a 500 MW Boiler Firing Low Sulfur Bituminous Coal. 

85
6.5 Summary of Mercury and Multipollutant Control Costs 

Table 30 shows expected costs for control of mercury from coal-fired boilers. Listed are control 

costs for at least 80 percent and up to 90 percent reduction. The following assumptions were used 

in making the current and potential cost estimates. 

• For situations where one approach seemed to be more attractive than another (such as 

PAC injection alone versus PAC injection plus a PJFF), it was assumed that the facility 

owner would normally select the more economically attractive approach. 

• An approach that is not considered in the results of Table 27 is changing of fuels to 

lower mercury content fuels (such as conversion from PRB to K-Fuel, as described 

earlier). However, depending upon the incremental cost of these fuels relative to the 

current fuel, they could be more cost effective in the application than the additional 

controls shown. 

• The Current Cost Estimates use PAC sorbent injection levels that have been measured 

in field tests or in pilot tests using currently available PAC sorbents19,30 assume that 

all cases used PAC and that all fly ash that comes in contact with used PAC must be 

disposed of. As discussed earlier, the assumption that all fly ash currently is sold is a 

most conservative assumption. For the majority of plants that currently landfill their 

fly ash, the incremental costs of PAC injection are estimated to be from 0.37 mills/kWh 

to about 1.0 mills/kWh less than shown in Table 30. Moreover, current research programs 

offer the potential to reduce operating costs in one of two ways: (1) reduction of sorbent 

costs by development of less expensive sorbents, or sorbents that are more efficient 

in mercury capture than existing PAC sorbents or (2) reduction or elimination of disposal 

costs by utilizing sorbent materials that can be beneficially reused in the same manner 

as fly ash that may be captured with it. Sensitivity analysis showed that, if disposal costs 

caused by PAC injection could be avoided, the cost of control could be reduced by 15 

to 17 percent for facilities where sorbent is collected in downstream ESPc’s and by 

about 80 percent for facilities where sorbent is collected in downstream FFs. The reason 

the impact is greater for FFs than for ESPs is because PAC injection rates tend to be 

much lower for FFs, and the impact of ash disposal cost on total cost is therefore much 

greater. 

86
Table 30. Estimated Cost of Mercury Control—Current and Potential Cost Estimates 

Coal 

Type S (%) 

Bitt 3 

Bit 3 

Bit 3 

Bit 3 

Bit 3 

Bit 3 

Bit 3 

Bit 0.6 

Bit 0.6 

Bit 0.6 

PRB 0.5 

PRB 0.5 

PRB 0.5 

Existing Controls 

ESP + FGD 

SCR + ESP + FGD 

FF + FGD 

SCR + FF + FGD 

ESPh + FGD 

SDA + ESP 

SDA + FF 

ESP 

FF 

ESPh 

ESP 

FF 

ESPh 

Additional Controls 

Cost Estimates of 

Additional Controls 

(mills/kWh) 

PAC + PJFF + CEMS 

PAC + CEMS 1.144S1.430 

CEMS 0.03S0.04 

CEMS 0.03S0.04 

CEMS 0.03S0.04 

PAC + PJFF + CEMS 1.149S1.437 

PAC + (PJFF) + CEMSa 2.211S3.096a 

PAC + CEMS 0.05S0.370 

PAC + PJFF + CEMS 

PAC + CEMSb 1.171S1.751 

PAC + CEMSb 0.003S0.510 

PAC + PJFF + CEMS 1.205S1.804 

PAC + PJFF + CEMS 

PAC + CEMSb 1.236S1.903 

PAC + CEMSb 1.122S1.266 

PAC + PJFF + CEMS 1.273S1.960 a For 80 percent control assumes no PJFF. For 90 percent control, assumes full-size PJFF (sized for full ash 

loading and much more expensive than if sized for downstream of an ESP or FF) being necessary for 90 

percent control. b The calculations performed to generate the results in this table assumed that all collected fly ash is currently 

sold, which is the most conservative situation. Therefore, these calculations include costs to landfill fly ash 

with an impact to total cost of around 0.37 mills/kWh for the low sulfur bituminous coal and around 1.01 

mills/kWh for the low sulfur bituminous coal. In many cases these costs will not apply because ash may 

currently be landfilled or because ash may not be rendered completely unacceptable for re-use. 

In this work, two multipollutant controls were also evaluated: ECO and advanced dry FGD. ECO 

is an emerging technology, and advanced dry FGD is a technology that is being introduced to the 

United States by several suppliers. There currently is no commercial experience with ECO at this 

time. There is limited commercial experience with advanced dry FGD on coal-fired boilers in 

the United States; however, there is more experience with the technology in Europe. Therefore, 

the cost information presented in Table 31 should be regarded as preliminary, especially for ECO. 

However, it should be kept in mind, when considering the higher costs associated with multipollutant controls over controls that remove only mercury, that other environmental benefits, such 

as SO2 or NOX control, are realized in addition to mercury reduction. 

The universe of multipollutant controls is not limited to the technologies presented in this work. 

Therefore, other technologies that could offer lower control costs may become available to users. 

87
Table 31. Estimated Costs of Multipollutant Controls 

Coal 

Existing Controls 

Type S (%) 

Bit 3 ESP 

Bit 3 ESP 

Bit 0.6 ESP 

Bit 0.6 ESP 

PRB 0.5 ESP 

PRB 0.5 ESP 

Additional Controls 

Cost Estimates of 

Additional Controls 

(mills/kWh) 

ECO + CEMS 3.28S7.21 

Adv Dry FGD + CEMS 7.94S9.65 

ECO + CEMS 5.34S12.33 

Adv Dry FGD + CEMS 3.69S6.58 

ECO + CEMS 4.54S11.53 

Adv Dry FGDa

 + CEMS 3.89S6.79a 

a Mercury control with advanced dry FGD on PRB fuels may be uncertain 

K-Fuel, which is developed from low rank western fuels, was also evaluated. It was shown in 

this work that K-Fuel offers roughly 60 percent, sometimes more, reduction of mercury in the 

fuel (on a heating value basis). This is achieved by simultaneously reducing the mercury 

concentration in the fuel while increasing the fuel’s heating value. K-Fuel may also offer the facility 

other environmental or operating benefits besides mercury reduction. Moreover, it was shown 

that mercury reductions beyond the 60 percent provided by K-Fuel (versus PRB) can be achieved 

with PAC injection. As the first commercial K-Fuel plant will be built soon, there is no commercial 

experience with this technology at this time. Costs are evaluated based on cost premium for K-Fuel 

over a facility’s existing fuel. For example, if K-Fuel were available at an incremental cost of 

$0.12/MMBtu over a base fuel, then the incremental cost would be approximately 1.26 mills/kWh. 

88
7.0 SUMMARY 

Cost estimates of PAC injection-based mercury control technologies for coal-fired electric utility 

boilers have been determined. These estimates include those based on currently available data 

as well as projections for future applications of more effective sorbent. Estimates based on currently 

available data range from 0.03-3.096 mills/kWh. However, the higher costs are usually associated 

with the minority of plants using SDAs plus ESPs or the small number of plants using ESPhs. 

Potential costs, developed assuming improvements in sorbent technology for mercury removal, 

range from 0.03-1.69 mills/kWh excluding applications with SDAs plus ESPs or with ESPhs. 

At the low end of these cost ranges, 0.03 mills/kWh, it is assumed that no additional control 

technologies are needed but that mercury monitoring will be necessary. In these cases, high mercury 

removal may be the result of the type of NOX and SO2 control measures currently employed. 

The estimates based on currently available data may be conservative for the following reasons: 

(1) They assume that prior to addition of controls all fly ash is sold, and after addition of controls, 

any fly ash that is combined with spent PAC must be disposed of; (2) The estimates of PAC 

injection rates for PRB-fired boilers with PAC collected by downstream ESP are based upon 

experience at Pleasant Prairie Power Plant, which fires a fuel with a lower chlorine content coal 

than is typical for a PRB fuel; (3) A 65 percent capacity factor is assumed for all cases. The first 

assumption is conservative because most plants do not currently sell their fly ash; furthermore, 

fly ash sales might be possible even with small amounts of PAC present. The impact of this 

assumption was estimated to be in the range from 0.37 mills/kWh to about 1.0 mills/kWh, 

depending upon fuel characteristics. Thus, for plants that do not currently sell their fly ash (most 

plants), the actual incremental cost of control would be lower than what we have estimated. 

Moreover, improved sorbents available in the future may eliminate, or at least mitigate, any impact 

of sorbent injection on disposal costs. The second estimate is conservative because, at the PPPP 

tests, mercury reduction by PAC injection was limited to around 70 percent. This is believed to 

be due, at least in part, to PPPP’s unusually low chlorine content—much lower than for most PRB 

fuels. Therefore, other PRB fueled boilers with chlorine contents typical of a PRB coal, and 

equipped with a downstream ESP, may be more effectively controlled than what was demonstrated 

at PPPP. The final assumption is conservative particularly for larger plants that are likely to be 

base loaded with higher capacity factors. 

Results of sensitivity analyses conducted on total annual cost of mercury controls reflect that: 

(1) Elimination of disposal costs could reduce costs by 80 percent for some cases (PAC injection 

upstream of an existing FF) and by 17 percent in others (PAC injection upstream of an existing 

89
ESP); (2) Using a more effective PAC sorbent might reduce costs by 20 percent; (3) The cost of 

a retrofit PJFF has a significant impact on control costs and, over the expected cost range, may 

cause cost to vary from about 1.2 mills/kWh to about 1.8 mills/kWh; (4) Fertilizer product value 

and the value of process power requirement have a very significant impact on the cost of ECO, 

with fertilizer product value being most significant for high sulfur fuel applications; and (5) As 

expected, lime reagent cost has a large impact on the total cost of using advanced dry FGD. 

Based on this work, it is expected that future efforts in R&D are likely to focus on improved 

understanding of both mercury speciation across SCRs and the beneficial effects of combinations 

of SCR with wet FGD, and on developing sorbents that can improve performance and cost of 

sorbent-based mercury control technologies. Multipollutant control technologies, which are more 

costly than single-pollutant mercury control technologies but offer other environmental benefits, 

will be another area for further development that could improve the cost of reducing emissions 

from coal-fired power plants. Finally, removing mercury from the coal, along with other fuel quality 

improvements, may prove to be a cost effective approach for reducing emissions. 

90
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