Assessment of Technology Options 

Available to Achieve Reductions 

of Hazardous Air Pollutants

Prepared by:

u

April 5, 2011
Assessment of Technology Options 

Available to Achieve Reductions 

of Hazardous Air Pollutants 

Prepared by: 

George Lipinski, P.E. 

Jean Leonard 

Carl Richardson, Ph.D. 

URS Corporation 

9400 Amberglen Boulevard (78729) 

P.O. Box 201088 

Austin, TX 78729-1088 

April 5, 2011 

iii 

Table of Contents 

Page 

 Executive Summary ....................................................................................... 1 

1.0 Introduction ..................................................................................................... 3 

2.0 Technology Survey ........................................................................................ 3 

 2.1 EPA’s Proposed Emission Limitations .............................................................. 3 

 2.2 URS’ Technology Survey .................................................................................. 3 

 2.3 Assumptions Regarding Existing Sources ......................................................... 4 

 2.4 Summary of Survey Results............................................................................... 5 

3.0 Analysis of Control Alternatives ................................................................... 8 

 3.1 Overview ............................................................................................................ 8 

 3.2 Fabric Filter Configuration ................................................................................ 8 

 3.2.1 Particulate Matter (PM) ........................................................................... 8 

 3.2.2 Hydrochloric Acid (HCl) ......................................................................... 8 

 3.2.3 Mercury (Hg) ......................................................................................... 9 

 3.3 Fabric Filter and Wet FGD Configuration ......................................................... 10 

 3.3.1 Particulate Matter (PM) ........................................................................... 10 

 3.3.2 Hydrochloric Acid (HCl) ......................................................................... 10 

 3.3.3 Mercury (Hg) ......................................................................................... 10 

 3.4 Fabric Filter-Dry FGD Configuration ................................................................ 10 

 3.4.1 Particulate Matter (PM) ........................................................................... 10 

 3.4.2 Hydrochloric Acid (HCl) ......................................................................... 11 

 3.4.3 Mercury (Hg) ......................................................................................... 11 

 3.5 SCR-FGDd-FF Configuration ........................................................................... 11 

 3.5.1 Particulate Matter (PM) ........................................................................... 11 

 3.5.2 Hydrochloric Acid (HCl) ......................................................................... 11 

 3.5.3 Mercury (Hg) ......................................................................................... 11 

 3.6 SCR-ESP-Wet FGD Configuration ................................................................... 12 

 3.6.1 Particulate Matter (PM) ........................................................................... 12 

 3.6.2 Hydrochloric Acid (HCl) ......................................................................... 12 

 3.6.3 Mercury (Hg) ......................................................................................... 12 

 3.7 ESP Only Configuration .................................................................................... 13 

 3.7.1 Particulate Matter (PM) ........................................................................... 13 

 3.7.2 Hydrochloric Acid (HCl) ......................................................................... 13 

 3.7.3 Mercury (Hg) ......................................................................................... 13 
iv 

Table of Contents 

Page 

 3.8 ESP-FGDw Configuration ................................................................................. 14 

 3.8.1 Particulate Matter (PM) ........................................................................... 14 

 3.8.2 Hydrochloric Acid (HCl) ......................................................................... 14 

 3.8.3 Mercury (Hg) ......................................................................................... 14 

 3.9 Installation Schedule .......................................................................................... 14 

4.0 Conclusions .................................................................................................... 15 

Appendix A Technology Descriptions 
v 

Index of Acronyms

ACI Activated Carbon Injection 

AH Air Heater 

AQC Air Quality Control 

CAA Clean Air Act 

CFB Circulating Fluidized Bed 

CO Carbon monoxide 

COHPAC Compact Hybrid Particulate Collector 

DSI Dry Sorbent Injection 

EMPC Estimated Maximum Possible Concentration

ESP Electrostatic Precipitator 

FF Fabric Filter 

FGD Flue Gas Desulfurization 

FGDd Dry Flue Gas Desulfurization (Spray dryer or circulating fluidized bed scrubber) 

FGDw Wet Flue Gas Desulfurization 

HAP Hazardous Air Pollutant 

HCl Hydrochloric Acid 

HCN Hydrogen cyanide 

Hg Mercury 

ICI Industrial, Commercial, and Institutional 

ICR Information Collection Request 

LOI Loss on Ignition 

MACT Maximum Achievable Control Technology 

NESHAP National Emission Standards for Hazardous Air Pollutants 

NSR Normalized Stoichiometric Ratio 

PM Particulate Matter 

PRB Powder River Basin Coal 

RICE Reciprocating Internal Combustion Engine 

SBS Sodium Bisulfate 

SCR Selective Catalytic Reduction 

SOFA Separated Over-Fire Air 

SO3 Sulfur Trioxide

TEF Toxic Equivalency Factor

TEQ Toxicity Equivalent 

UPL Upper Prediction Limit 

ZWD Zero Water Discharge 
1 

Executive Summary 

This report1 describes the results of an assessment conducted by URS Corporation (URS) 

to evaluate the availability of pollution control technologies to meet the requirements of the 

proposed National Emission Standards for Hazardous Air Pollutants (NESHAP) for Utility 

Electric Generating Units (“EGUs”) (the “Toxics Rule”). This assessment was designed to 

answer the ultimate question of whether control technologies are available that will equip EGUs 

to meet the emission limitations the Environmental Protection Agency (EPA) has proposed, 

regardless of current configuration. URS identified proven, commercially available control 

technologies that will enable EGUs to achieve compliance with the Toxics Rule, given adequate 

investment by the owners. In the event that an EGU requires the installation or upgrade of 

control equipment, the technologies available typically require less than three years to install 

after detailed design and permitting is complete. 

To begin, URS identified a number of typical control equipment configurations present at 

existing EGUs. An assessment was performed to evaluate additional control technologies 

appropriate for those configurations that would enable EGUs to comply with the Toxics Rule 

emission limitations on hazardous air pollutants (“HAP”). URS consulted its own experience 

and database of pollution control technologies and reviewed published literature, conference 

proceedings, expert analysis and procurement information regarding the availability, cost and 

efficacy of numerous available control technologies. URS applied this information and its own 

experience to evaluate the menu of control options that would be available to EGUs of different 

configurations, and to rank those options. This analysis took into account the performance, 

maturity and number of existing commercial installations of the control technologies. While 

special cases may exist, this analysis demonstrates that the Toxics Rule emission limitations are 

generally achievable through the application of proven, commercially available technologies, 

regardless of the starting configuration of the facility. 

Assuming EPA signs the final Toxics Rule as scheduled on November 16, 2011, the rule 

will not be effective until early 2012, or 60 days after it is published in the Federal Register. 

EGUs will not be required to comply with the Toxics Rule until three years after the effective 

date, or early 2015 – nearly four years after proposal. To the extent that existing facilities 

require additional control technology to comply with the Toxics Rule, the technology is known, 

available and the industry has demonstrated its ability to install and to operate these controls. 

 

1

 This report was prepared by URS Corporation for Exelon Corporation. 
2 

The controls that will be most commonly needed, such as activated carbon injection (for 

mercury control) or dry sorbent injection (for SO3 control on bituminous fired plants and acid 

gas control at some western sub-bituminous fired EGUs) typically require less than eighteen 

months to install once permitting is completed. Barring unreasonable permitting or supply chain 

delays, EGU owners who act promptly will be able to complete such low capital upgrades by the 

compliance date. Facilities requiring high capital upgrades such as the addition of wet FGDs 

will face longer installation times. Owners of EGUs requiring such additions will need to select 

technologies and contractors and to file permit applications promptly to meet the 2015 

compliance deadline. For those facilities facing unique challenges in completing necessary 

upgrades by 2015, EPA has indicated that it will provide extensions of up to one year. 
3 

1.0 Introduction 

In performing this assessment, URS considered the emissions limitations proposed by 

EPA in the Toxics Rule, reviewed relevant commercially available control technologies and 

evaluated seven hypothetical configurations of existing control equipment to determine whether 

such facilities could be brought into compliance with the proposed Toxics Rule emission 

limitations. It was concluded that: 1) in many instances, no additional controls would be 

required; 2) where additional controls would be necessary, the most common top-ranked control 

technologies can typically be installed in less than 24 months; and 3) in all other instances 

considered in this assessment, the top-ranked control technology can typically be installed in less 

than 36 months after detailed design and permitting is complete. 

2.0 Technology Survey 

2.1 EPA’s Proposed Emission Limitations 

In the Toxics Rule, EPA proposes emissions limitations for five different sub-categories 

of EGUs. Coal-fired EGUs are divided into lignite, non-lignite and integrated gasification/ 

combined cycle (“IGCC”) sub-categories. Oil-fired EGUs are divided into solid fuel (petroleum 

coke) and liquid fuel sub-categories. EPA has proposed emission limitations for mercury, 

hydrogen chloride (“HCl”) and total particulate matter (“PM”) for all coal-fired EGU subcategories and the solid fuel oil sub-category, with HCl being a surrogate for all acid gases and 

PM being a surrogate for non-mercury HAP metals. For liquid oil-fired EGUs, EPA has 

proposed limits on total HAP metals (including mercury), HCl and hydrogen fluoride (“HF”). 

EPA has proposed to regulate dioxins/furans and other organic HAPs for all sub-categories 

through work practice standards rather than numerical emission limitations. EPA has also 

proposed a number of alternative compliance methods. For example, coal-fired EGUs may use 

sulfur dioxide (“SO2”) as a surrogate for acid gases in certain circumstances, and may test for 

total non-mercury HAP metals or ten individual HAP metals in lieu of complying with the PM 

limitation. 

2.2 URS’ Technology Survey 

URS conducted a review of commercially-available air quality control (“AQC”) 

technologies that may be employed by coal- and oil-fired EGUs in order to meet emission 

limitations proposed by EPA in the Toxics Rule. This technology survey presents control 

technologies for Mercury, HCl, and PM, the default emission limitations in the Toxics Rule for 
4 

coal-fired EGUs and solid fuel oil-fired EGUs.2 Although EPA proposed different emission 

limitations for liquid fuel oil-fired EGUs, the technologies available for controlling PM and HCl 

at other EGUs would control total HAP metals and HF (as well as HCl) at liquid fuel oil-fired 

EGUs. 

To conduct the control technology assessment, URS utilized internal information on air 

quality control technologies, as well as information from published literature and conference 

proceedings, discussions with technology experts, and procurement information associated with 

some technologies. For each pollutant category, air quality control technologies were evaluated 

for their ability to achieve sufficient performance levels. Although costs were not a primary 

factor in the selection of appropriate technologies, they were considered when comparing 

different technologies with similar expected performance levels. The multi-pollutant nature of 

various technologies was also considered, as some processes would be expected to effectively 

remove pollutants from a number of potential HAP categories, allowing a holistic approach to 

achieving compliance with the Toxics Rule. Through this analysis, a ranking of available control 

technologies was developed that takes into account cost, maturity and the ability to treat multiple 

HAPs. This assessment did not consider possible technologies for controlling dioxin/ furan 

emissions or organic HAPs. Under the proposed Toxics Rule, these HAPs are to be controlled 

through work practice standards. 

The analysis demonstrates that there is a range of control technologies available to EGUs 

requiring additional levels of control for mercury, HCl or PM. These technologies are proven 

and mature, and in fact are already installed at many EGUs. Many of the available technologies 

involve relatively low capital retrofits that typically require less than eighteen months to install. 

Some technologies, such as wet or dry scrubbers, have longer installation times and EGU owners 

requiring such additions will need to move more rapidly to meet the 2015 compliance deadline. 

2.3 Assumptions Regarding Existing Sources 

URS assessed AQC technologies for expected performance, cost, and schedule to 

construct at power plants of several different configurations. It should be noted that for any 

particular facility, technology assessments must be conducted on a site-specific basis, taking into 

account the plant’s existing equipment, current operating scenarios, physical layout and balance 

of plant considerations, as well as economic and long-term planning considerations. For the 

purposes of this study, several common configurations of AQC technology already in place at 

 

2

 URS did not specifically address the applicability of any particular technology to IGCC units. 
5 

existing fossil-fuel fired facilities were identified to address expected need for additional controls 

to reduce the emissions of toxic air pollutants. These hypothetical configurations consist of one 

or a combination of control technologies for PM, SO2 or oxides of nitrogen (“NOx”). 

The most common PM control technologies are fabric filters (“FFs”) and electrostatic 

precipitators (“ESPs”). The most common SO2 controls are flue gas desulfurization (“FGD”) 

systems (commonly called “scrubbers”), which can be either wet (“FGDw”) or dry (“FGDd”). 

The most common NOx controls are selective catalytic reduction (“SCR”) systems. 

The potential need for additional controls to comply with the Toxics Rule was evaluated 

for seven different hypothetical configurations of AQC technology at existing EGUs, as 

presented in Table 2-1. The objective of the assessment was to present the most plausible 

technologies for each plant configuration to achieve the HAP emission limitations. This analysis 

does not indicate that all plant configurations will need additional controls; nor does it imply that 

any particular controls installed at a specific plant will unequivocally meet the emission 

limitations proposed in the Toxics Rule. The analysis is intended as an overview of 

commercially available, proven technologies that may potentially be employed in order to lower 

emissions of the targeted HAP species for a given plant configuration. The analysis took into 

account cost as well as the performance, maturity level, and number of existing commercial 

installations of each technology. Selected technologies included different control processes that 

could be implemented for different fuel types, including opportunities for fuel switching. 

Additionally, the ability of certain technologies to control multiple HAPs was considered when 

making final selections. 

2.4 Summary of Survey Results 

URS identified several alternative control strategies that could be deployed where these 

hypothetical configurations will likely require additional control for PM, HCl and mercury. Up 

to four different technologies were identified for each scenario, each of which would provide the 

additional level of control required. Those technologies were then ranked according to the 

criteria described above. Table 2-1 lists several alternatives for each configuration requiring 

additional control. Each facility would choose one of these alternatives to achieve compliance 

with the Toxics Rule, based on the site-specific conditions at that facility. As the table reflects, 

many facilities with existing PM and SO2 controls may need no additional controls to meet the 

PM and HCl limits in the Toxics Rule, respectively.3

 However, if the controls at such facilities 

 

3

 These configurations are noted in the table as “no additional control needed.” 
6 

are already at their maximum capacity or face other operational challenges, these facilities may 

indeed need additional controls for PM or HCl as well. Suggestions are provided for upgrades 

and add-on controls for these outlier plants in the discussion in Section 3.0. 

In Table 2-1, configurations that are unlikely to need additional controls to comply with 

the Toxics Rule are shaded in green. Those likely to require additional controls that can be 

installed in no more than 24 months are shaded in blue. Those likely to require additional 

controls that can be typically installed in 36 months (but require more than 24 months) are 

shaded in yellow. Installation times for new controls are not cumulative. Rather, EGU owners 

installing multiple control technologies would schedule installation of those controls, and any 

ancillary modifications to the plant, during the same planned outage, or a coordinated series of 

outages, provided all controls could be installed prior to the deadline for compliance with the 

Toxics Rule. Nonetheless, if a particular control cannot be installed prior to this deadline, it is 

probable that controls necessary for other HAPs would be installed separately, because these 

control technologies are not, by and large, interdependent. 

Section 3.0 of this report provides brief discussions of the rationale behind the various 

technology selections for each of the hypothetical configurations considered. For each 

configuration, the report provides strategies for controlling PM, HCl and mercury. Appendix A 

presents further information on the technologies discussed in this report, including each 

technology’s maturity; the number of commercial installations, if known, the technology’s 

expected performance; capital and operating costs; and the typical schedule for design, 

installation, and startup. 
7 

Table 2-1. Pollution Control Options for Coal- and Oil-Fired Power Plants4

Existing 

Configuration 

Control Options to Achieve Toxics Rule Emission Limitations 

PM HCl Hg 

Fabric Filter only (§ 3.2) No additional control 

needed 

1) FGDd; or 

2) FGDw; or 

3) Dry Sorbent Injection;5 or 

4) Coal switch 

1) ACI with SO3 control; or 

2) FGDw with re-emission 

additives; or 

3) Combustion 

Modification; or 

4) Coal switch 

Fabric Filter with Wet Flue 

Gas Desulfurization (§ 3.3) 

No additional control 

needed 

No additional control 

needed 

1) ACI with SO3 control; or 

2) FGD additives; or 

3) Bromide addition 

Fabric Filter with Dry Flue 

Gas Desulfurization (§ 3.4) 

No additional control 

needed 

No additional control 

needed 

1) ACI with SO3 control; or 

2) Bromide addition 

Fabric Filter with Dry Flue 

Gas Desulfurization and 

Selective Catalytic 

Reduction (§ 3.5) 

No additional control 

needed 

No additional control 

needed 

1) ACI with SO3 control; or 

2) Bromide addition; or 

3) Coal switch 

Electrostatic Precipitator 

with Wet Flue Gas 

Desulfurization and 

Selective Catalytic 

Reduction (§ 3.6) 

1) ESP upgrade; or 

2) Scrubber upgrade; or 

3) Toxecon; or 

4) Wet ESP 

No additional control 

needed 

1) ACI with SO3 control; or 

2) Bromide addition; or 

3) FGDw re-emission 

additives; or 

4) Toxecon 

Electrostatic Precipitator 

only (§ 3.7) 

1) ESP upgrade; or 

2) Toxecon; or 

3) Wet ESP; or 

4) FGDw 

1) FGDd/FF; or 

2) Toxecon w/ Dry Sorbent 

Injection; or 

3) Coal switch; or 

4) FGDw 

1) Toxecon; or 

2) ACI with SO3 control; or 

3) FGDw + Bromide; or 

4) Coal switch 

Electrostatic Precipitator 

with Wet Flue Gas 

Desulfurization (§ 3.8) 

1) ESP upgrade; or 

2) FGDw upgrade; or 

3) Toxecon 

No additional control 

needed 

1) ACI with SO3 control; or 

2) Bromide addition; or 

3) FGDw re-emission 

additives; or 

4) Toxecon 

 

4

 Green highlighting indicates that additional controls are unlikely to be necessary to achieve Toxics Rule emission 

limitations. Blue highlighting indicates that the top-ranked control technology has installation times of 24 months 

or less, after permitting. Yellow highlighting indicates that the top-ranked control technology has typical 

installation times of more than 24 months but less than 36 months, after permitting. 

5

 Dry sorbent injection includes Trona, hydrated lime, SBS and other reagents. 
8 

3.0 Analysis of Control Alternatives 

3.1 Overview 

With adequate investment, it should be possible for virtually any EGU to comply with all 

emission limits under the Toxics Rule, but the required strategy for meeting these limits will 

depend on each plant’s existing control configuration. The following sections present seven 

typical air pollution control configurations at fossil-fuel fired power plants, as listed in Table 2-1. 

Each regulated HAP (or surrogate) is discussed in terms of the plant configuration and likely 

controls that may be necessary or useful in achieving EPA’s proposed mercury and air toxics 

limits. Through the reasoning that is presented in the sections below, technologies have been 

selected as the most likely to assist in meeting EPA’s proposed mercury and air toxic standards, 

as presented in Table 2-1. Technologies discussed in this section are all commercially available 

technologies with a history of demonstrated performance, and each is capable of achieving 

compliance with the Toxics Rule. It is acknowledged that site specific factors will impact the 

ultimate performance of any AQC technology at a given plant. Additional technologies in the 

developmental stages may be available and have not been included in the scope of this survey. 

For further detail on these technologies see Appendix A. 

3.2 Fabric Filter Configuration 

3.2.1 Particulate Matter (PM) 

A properly sized and functional FF should provide adequate PM control to comply with 

the Toxics Rule. If a facility is in need of additional removal, one option would be to add a wet 

scrubber after the baghouse to remove additional PM as well as HCl. Toxecon could also be 

added (downstream carbon injection and baghouse) if multi-pollutant control is desired, as this 

system provides not only additional PM control, but mercury control as well. 

3.2.2 Hydrochloric Acid (HCl) 

Plants equipped with a properly sized and functional fabric filter capable of controlling 

PM emissions and with a sufficient additional margin could adequately control emissions of HCl 

with the installation of a dry FGD system. FGDd would be effective for relatively high HCl 

content and, for this configuration, would be less costly than FGDw. However, additional PM 

emissions can be expected with the operation of an FGDd system; therefore, for units with a FF 

that is not capable of controlling additional PM loadings, a wet FGD would be an effective way 

to control both HCl and PM. 
9 

For plants burning bituminous coal, switching to a western sub-bituminous coal would 

appreciably reduce HCl emissions. If coal substitution alone does not achieve compliance for 

these plants, dry sorbent injection will be sufficient to treat the reduced load of HCl. For plants 

already burning PRB coal and configured with an efficient FF, dry sorbent injection can be 

expected to reduce HCl emissions sufficiently to meet the Toxics Rule emission standard, and 

will be significantly less costly than a wet or dry scrubber. 

3.2.3 Mercury (Hg) 

For plants equipped with a properly sized and functional fabric filter capable of 

controlling PM emissions and with a sufficient additional margin, an activated carbon injection 

(ACI) system will provide adequate Hg control. FFs usually respond well to ACI for Hg 

removal, assuming the FF can handle the additional PM loading resulting from the operation of 

the ACI. However, fly ash sales may be impacted by ACI installation upstream of the FF due to 

increased carbon levels in the collected fly ash. Additionally, under this configuration, control of 

SO3, which tends to hinder the effectiveness of ACI Hg removal, may be necessary for effective 

operation of ACI when burning high sulfur coal. 

If mercury re-emissions from the wet FGD system cause the EGU to exceed the Toxics 

Rule emission limitation, the use of scrubber additives to reduce the re-emissions may be more 

cost-effective than ACI. 

If further Hg control is needed, using Low NOx Burners or increasing their NOx removal 

performance can lead to higher Loss on Ignition (LOI) to the fly ash, and better Hg removal. 

Some plants firing bituminous coal might be challenged to achieve Hg emission 

limitations due to SO3 interference with sorbent-based mercury control processes. Plants firing 

lignite (particularly Texas lignite) will require high levels of removal in order to comply with the 

Toxics Rule. However, in both cases, a switch to western sub-bituminous coal could appreciably 

lower mercury emissions. In the case of bituminous coals this would be through decreasing flue 

gas SO3 concentrations, and thus increasing the performance of ACI for Hg control. For Texas 

lignite coals, Hg emissions would likely be lowered due to significantly lower fuel Hg 

concentrations, as well as moderate improvement in ACI performance. 
10 

3.3 Fabric Filter and Wet FGD Configuration 

3.3.1 Particulate Matter (PM) 

 Plants equipped with FF and FGDw are unlikely to require additional controls to meet the 

PM emission limitation in the Toxics Rule. If additional control is required, a plant could 

upgrade either its fabric filter or scrubber, or both, to achieve the PM emission limitation. 

3.3.2 Hydrochloric Acid (HCl) 

 Plants equipped with FF and FGDw are unlikely to require additional controls to meet the 

HCl emission limitation in the Toxics Rule. 

3.3.3 Mercury (Hg) 

 For plants equipped with a properly sized and functional fabric filter capable of 

controlling PM emissions with a sufficient additional margin, an activated carbon injection 

(ACI) system will provide adequate Hg control. FFs usually respond well to ACI for Hg 

removal, assuming the FF can handle the additional PM loading resulting from the operation of 

the ACI. However, SO3 control may be necessary for effective operation of ACI when burning 

high sulfur coal. 

 If mercury re-emissions from the wet FGD system cause the EGU to exceed the Toxics 

Rule emission limitation, the use of scrubber additives may be able to reduce re-emission of 

mercury more cost-effectively than ACI. 

 Finally, although less effective without a selective catalytic reduction (SCR) system, 

bromine addition could be sufficient for trimming emissions at EGUs firing low sulfur coal if the 

Hg emission rate needs only small incremental improvement. 

3.4 Fabric Filter-Dry FGD Configuration 

3.4.1 Particulate Matter (PM) 

 Plants equipped with FF and FGDd are unlikely to require additional controls to meet the 

PM emission limitation in the Toxics Rule. If additional control is required, a plant could 

upgrade either its fabric filter or scrubber, or both, to achieve the PM emission limitation. 
11 

3.4.2 Hydrochloric Acid (HCl) 

 Plants equipped with FF and FGDd are unlikely to require additional controls to meet the 

HCl emission limitation in the Toxics Rule. However, if needed, a dry sorbent injection system 

would provide a low capital option to trim emissions. 

3.4.3 Mercury (Hg) 

 For plants equipped with a properly sized and functional fabric filter capable of 

controlling PM emissions with a sufficient additional margin, an Activated Carbon Injection 

(ACI) system will provide adequate Hg control. FFs usually respond well to ACI for Hg 

removal, assuming the FF can handle the additional PM loading resulting from the operation of 

the ACI. However, SO3 control may be necessary for effective operation of ACI when burning 

high sulfur coal. 

 Finally, although less effective without a selective catalytic reduction (SCR) system, 

bromide addition could be sufficient for trimming emissions at EGUs firing low sulfur coal if the 

Hg emission rate needs only small incremental improvement. 

3.5 SCR-FGDd-FF Configuration 

3.5.1 Particulate Matter (PM) 

 Plants equipped with SCR, FF and FGDd are unlikely to require additional controls to 

meet the PM emission limitation in the Toxics Rule. If additional control is required, a plant 

could upgrade either its FF or scrubber, or both, to achieve the PM emission limitation. 

3.5.2 Hydrochloric Acid (HCl) 

 Plants equipped with SCR, FF and FGDd are unlikely to require additional controls to 

meet the HCl emission limitation in the Toxics Rule. If necessary, removal rates would be 

improved by either upgrading the scrubber or installing a dry sorbent injection system. 

3.5.3 Mercury (Hg) 

 For plants equipped with a properly sized and functional fabric filter capable of 

controlling PM emissions with a sufficient margin, an activated carbon injection (ACI) system 

will provide adequate Hg control. FFs usually respond well to ACI for Hg removal, assuming 

the FF can handle the additional PM loading resulting from the operation of the ACI. However, 

SO3 control may be necessary for effective operation of ACI when burning high sulfur coal. 
12 

 Removal rates of Hg from bromide addition are high in combination with the SCR, 

especially for PRB coal, and could also provide polishing capability for bituminous coals that 

require only incremental improvements in removal. However, the SCR, FGDd, FF configuration 

is not typical for plants firing bituminous coal. If installed on a bituminous coal plant, it is 

possible that mercury control performance could be constrained by elevated SO3 levels. A 

switch to Western sub-bituminous coal would improve the performance of the plant’s various 

mercury controls as well as yield acid gas emission reductions. 

3.6 SCR-ESP-Wet FGD Configuration 

3.6.1 Particulate Matter (PM) 

 The compliance strategy for PM under this configuration will depend on the performance 

of existing controls. Assuming the existing ESP does not provide adequate control to meet the 

Toxics Rule emission limitation, the first option to provide additional control would be an 

upgrade of the ESP, the scrubber mist eliminator, or both. Alternatively, a wet ESP may be 

installed. Toxecon could also be added downstream of the existing ESP if multi-pollutant 

control is desired. 

3.6.2 Hydrochloric Acid (HCl) 

 Plants equipped with a high-efficiency wet FGD system are unlikely to require additional 

controls to meet the HCl emission limitation in the Toxics Rule. If additional removal is needed, 

removal efficiencies could be improved by one or more of the FGD upgrades described in 

Appendix A.

3.6.3 Mercury (Hg) 

 The Hg control strategy under this configuration would depend on the fuel being fired. 

The primary choice for plants firing bituminous coal would likely be ACI with additional SO3

control technology; some plants with this configuration might not require any additional mercury 

control. For plants firing low-sulfur fuels, the primary choice would likely be bromine addition. 

For plants requiring additional PM control, or desiring Hg removal upstream of the FGD system, 

Toxecon with activated carbon injection would likely be the best control strategy. Under this 

configuration, scrubber re-emissions additives may be required to control Hg emissions in 

conjunction with other control technology, depending on mercury removal performance of the 

wet FGD. 
13 

3.7 ESP Only Configuration 

3.7.1 Particulate Matter (PM) 

 The compliance strategy for PM under this configuration will depend on the performance 

of existing controls. Assuming the existing ESP does not provide adequate control to meet the 

Toxics Rule emission limitation, the first option for additional control would be an upgrade of 

the ESP. Alternatively, a wet ESP may be installed. Toxecon could also be added downstream 

of the existing ESP if multi-pollutant control is desired. In some cases, particularly plants 

burning bituminous fuels, a wet FGD may be installed if additional SO2 control is also desired. 

3.7.2 Hydrochloric Acid (HCl) 

 A dry FGD system will provide effective control for relatively high HCl content, but may 

require installation of a fabric filter to control the additional particulate loadings dry FGD would 

add. A dry FGD system is likely to be more cost effective than a wet FGD, if switching to a FF 

to handle the additional particulate loading is not necessary. Toxecon used in conjunction with 

sorbent injection would be a viable control option if multi-pollutant control is desired. For plants 

firing bituminous coal, a switch to a western coal would reduce the HCl loading on the ESP, 

likely enabling dry sorbent injection alone to achieve the Toxics Rule emission limitation. 

3.7.3 Mercury (Hg) 

 The Hg control strategy under this configuration would depend on the fuel being fired. 

For plants burning western coals, or those requiring additional PM control or desiring Hg 

removal upstream of the FGD system, Toxecon with activated carbon injection would likely be 

the best control strategy. Alternatively, an ACI system using brominated sorbent may be used 

for plants burning western coals; however, mercury removal under this option depends on ESP 

performance. Installation of a wet FGD may be a viable option for plants that desire additional 

SO2 control; using this strategy, bromide addition may also be an option for mercury control for 

EGUs firing western fuels. 

 The primary choice for a plant firing bituminous coal would likely be an ACI with 

additional SO3 control technology. However, plants firing bituminous coal will be challenged to 

achieve desired mercury reductions due to SO3 interference. Plants firing lignite containing high 

mercury levels (e.g., Texas lignite) will require high levels of removal which are difficult to 

obtain across an ESP. In both cases, a switch to a low-sulfur sub-bituminous coal would lower 

mercury emissions via better mercury control performance and, for Texas lignite fired EGUs, 

lower coal mercury levels. 
14 

3.8 ESP-FGDw Configuration 

3.8.1 Particulate Matter (PM) 

 The compliance strategy for PM under this configuration will depend on the performance 

of existing controls. Assuming the existing ESP does not provide adequate control to meet the 

Toxics Rule emission limitation, the first option to provide additional control would be an 

upgrade of the ESP, the scrubber mist eliminator, or both. Alternatively, Toxecon could also be 

added downstream of the existing ESP if multi-pollutant control is desired. 

3.8.2 Hydrochloric Acid (HCl) 

 Plants equipped with a high-efficiency wet FGD system are unlikely to require additional 

controls to meet the HCl emission limitation in the Toxics Rule. If additional removal is needed, 

removal efficiencies could be improved by one or more of the FGD upgrades described in 

Appendix A or by or a dry sorbent injection system. 

3.8.3 Mercury (Hg) 

 The Hg control strategy under this configuration would depend on the fuel being fired. 

For plants requiring additional PM control or desiring Hg removal upstream of the FGD system, 

Toxecon with activated carbon injection would likely be the best control strategy. Bromine 

addition would likely be the primary control strategy for plants burning low-sulfur fuels. 

Alternatively, for plants burning low-sulfur fuel, ACI is another control option. ACI would also 

be an option for plants firing bituminous coal, but SO3 control technology may be necessary 

Under this configuration, scrubber re-emission additives may be required to control Hg 

emissions in conjunction with other control technology, depending on mercury removal 

performance of the wet FGD. 

3.9 Installation Schedule 

 None of the typical configurations considered in this assessment included existing 

mercury controls, though many EGUs are presently equipped with ACI. Accordingly, this 

analysis concludes that every EGU configuration would require mercury control, and identifies 

ACI as the technology of choice for six of the seven configurations considered. ACI has a 

typical installation time of 12 to 18 months after permitting. As URS assumes fabric filters to 

provide adequate PM control to comply with the Toxics Rule PM emission limitation, ESP 

upgrades are the top-ranked alternative for improving PM control from EGUs. Depending on the 

scope of the upgrade, installation times for ESP upgrades typically run from six months for the 

simpler upgrades to twenty-four months for the most comprehensive upgrades. Dry FGD 

technology, with a typical installation time of 24 to 36 months, was identified as the top-ranked 
15 

technology for only two of the seven configurations evaluated. Dry FGD has the longest 

installation time of the top-ranked technologies. 

 These installation times are not cumulative; rather, plants installing multiple technologies 

would typically coordinate installation so that all controls for mercury, HCl and PM would be 

installed during the same outage, although some additional outage time may be necessary to coordinate simultaneous installation. With nearly four years between the proposal of the Toxics 

Rule and the date EGUs must come into compliance, these improvements can be accomplished 

on-time, provided EGU owners move quickly to initiate these upgrades in response to the 

proposed rule, and no unreasonable delays occur in the permitting process or supply chain.6 

4.0 Conclusion 

Using the emission limitations proposed by EPA in the Toxics Rule as its guide, URS 

examined the existing field of demonstrated, available AQC technologies to determine whether 

these technologies would be sufficient to allow typical coal-fired and oil-fired EGUs to achieve 

these emission limitations. URS concluded that the emission limitations proposed in the Toxics 

Rule can be achieved by typical EGUs through the application of successfully demonstrated, 

available AQC technologies. The controls considered in this analysis can typically be installed 

in 18 months (for ACI), 24 months (for ESP upgrades), or 36 months (for FGDs) after detailed 

design and permitting is complete. If EGU owners make their technology choices and initiate 

the permitting process promptly, they should be able to comply with the Toxics Rule emission 

limits by the deadline of early 2015 (almost 48 months after proposal of the rule). Plants facing 

extreme delays in permitting or the supply chain, or with atypically complex upgrade 

requirements, have an opportunity to request an additional year to come into compliance with the 

Toxics Rule. 

 

6

 Potential delays associated with heavy equipment lead times have not been included in this analysis because it is 

not possible to predict at this time whether any particular delay will occur. 
A-1 

APPENDIX A 

A.0 Technology Descriptions 

This section provides a high-level overview of each add-on control technology that has 

been presented in the main body of this report. Because some of these technologies treat 

multiple HAPs, they cannot easily be categorized by the pollutant they treat. However, several 

of the technologies described are upgrades or modifications to AQC systems present at existing 

EGUs. These modifications are grouped separately from technologies not considered in the 

hypothetical configurations discussed in Section 3.0 of the report. 

Equipment costs provided in the following technology descriptions are typical; site 

specific circumstances may lead to higher or lower costs due to site specific requirements. 

Additionally, cost estimates include equipment and operating costs, where specified; planning 

and financing costs are not included. The estimated schedules for implementation of the 

technologies represent time from the placement of the equipment order to installation. This 

assessment is based on cost and schedule information available today, and the estimates provided 

here may be affected by future changes in pricing and scheduling demand. 

A.1 Modifications to Existing AQC Systems at EGUs 

A.1.1 Cold-side ESP Upgrades 

The use of electrostatic precipitator (ESP) technology for the removal of PM is well 

established and has been implemented for over 100 years. Decades old, or poorly performing 

ESPs that were designed for lower emission performance can be upgraded to improve collection 

efficiency and reduce operating costs. Often the performance can be increased through a 

thorough examination to insure that worn or broken components are replaced, and insuring that 

the gas flow distribution through the system is uniform. Other ESP modifications and upgrades 

may include: 

• Upgrade of control systems such as power controlled rapping (PCR). $0.27/kW 

• Upgrade of ESP power supplies. $1/kW 

• Add SO3 and/or ammonia injection (to the flue gas upstream of the ESP) to improve 

ash agglomeration. $2-10/kW 

• Replace wire and weight systems, widening the gas passages and adding rigid 

discharge electrodes. This will improve the mechanical integrity of the electrodes 

and can improve performance with existing TR sets. 

• Increase the number of electrical bus sections. 

• Add rappers to decrease the amount of collecting surface area served by each rapper 
A-2 

• Increase the collecting surface area - several vendors report that many of the older 

ESPs in the US can be modified to increase the collecting surface area by 10-20% 

within their existing footprint. Another option is to add an additional field. $30-

0/kW 

• Reduce gas flow through the ESP by repairing upstream leaks or upgrading air 

heaters to limit air in-leakage 

• Add a Bipolar Agglomerator to the inlet of the ESP. $25-40/kW. 

The capital costs associated with these upgrades will depend on the extent to which the 

ESP is modified. If the unit is particularly old or poorly performing, more repairs or 

modifications may be necessary. Some vendors claim that modifications such as upgrading the 

power supplies and controls will pay for themselves within one to two years due to savings in 

power consumption. Operating costs for many of these modifications will not increase over the 

cost of previous operation, and in many cases the operating costs will decrease due to gains in 

collection and power consumption efficiency. The operating costs for injecting SO3 and/or 

ammonia for ash conditioning will be approximately 2-4 $/kW-yr. 

Another method to improve the performance of an ESP would be to add a Bipolar 

Agglomerator to the ESP inlet duct. An agglomerator manufactured by Indigo Technologies 

uses a bipolar charging zone to charge part of the dust positively and part of the dust negatively. 

This is accomplished by passing the flue gas through a series of alternating positive and negative 

parallel passages. The dust then enters a mixing zone where the oppositely charged particles are 

attracted to each other and form a larger agglomerated particle that can be more easily removed 

in the ESP. The agglomerator is similar to an ESP without collection plates. This technology is 

relatively new with only 45 commercial installations at power plants, mostly outside the U.S. 

Reductions in opacity are reported to be 40% to 70%, with some units burning sub-bituminous 

and bituminous fuels reporting reductions in opacity of approximately 50%. The cost to add an 

agglomerator to an existing system is approximately $25-40/kW. The operating costs are 

approximately $0.02/kW-yr and consist primarily of the power required to operate the unit. 

• ESP UpgradeTechnology Maturity: mature 

• Number of Units Upgraded: hundreds 

• Expected Performance: 

o PM: +99% 

• Capital Costs: 0.27 - 20 $/kW 

• Operating Costs: .02- 4 $/kW-yr. 

• Installation Schedule: 6-12 months from award of design to operation for low capital 

options; 12-24 months for implementation of higher capital cost modifications / 

additions 

o Outage Required: 0-7 days if no plate/electrode modification. 2-4 weeks with 

plate/electrode modification. 
A-3 

A.1.2 Fabric Filter Upgrades 

A typical fabric filter should be able to meet MACT PM emission standards. If a plant is 

unable to meet emission standards with a fabric filter, the cause is most likely due to bag failures. 

To minimize bag failures it may be possible to optimize the cleaning process to minimize these 

problems. On a pulse jet baghouse this may include adjusting the pulse pressure and duration to 

more thoroughly clean the bags. By cleaning more thoroughly, the interval between cleaning 

may be reduced and the life of the bags could be extended. Optimization of fabric filter 

performance may also be achieved by an evaluation of the maintenance schedule. An analysis of 

process and maintenance data could lead to an understanding of how to anticipate bag failure and 

replace them before the failure actually occurs. 

Another alternative to increase PM collection would be to replace the existing bags with 

different material such as a membrane bag. Different bag materials will have different pressure 

drop characteristics and it will be necessary to determine whether the plant has existing fan 

capacity to handle the upgrade. 

An additional solution would be to add additional compartments to the existing baghouse 

to increase the collection surface, or add a COHPAC system. The Toxecon could be necessary if 

a multi-pollutant strategy is desired and it is advantageous to maintain fly ash sales from the 

existing baghouse. Adding additional compartments or a Toxecon system are both capital 

intensive solutions and may not be practical for plants that have restricted space available for 

retrofit. 

• Technology Maturity: mature (fabric filter)

• Number of Commercial Installations: many

• Expected Performance: 

o PM: +99% 

• Costs for Optimizing Fabric Filter Performance: $200K - $500K, excluding 

projects where complete bag replacement is required 

• Schedule: 3-6 months for performance optimization 

• Costs for Adding Compartments or Toxecon: 75-130 $/kW 

• Schedule: 12-24 months from detailed design to startup 

o Outage Required: 7-10 days. (3-4 weeks if a new fan is required) 

A.1.3 FGDw Additives 

As discussed in Section 1.2.8, wet scrubbers can remove acid gases, PM and mercury. 

However, removal of Hg+2 by wet FGD systems can be limited by a phenomenon called “reemission” that results in a portion of the scrubbed Hg+2 being chemically reduced to Hg0

 in the 

FGD liquor. Once reduced, the insoluble Hg0

 is released back into the flue gas. The re-emission 

process is not currently well understood, but is believed to occur by reaction with bisulfite ions 

(dissolved SO2 at lower Ph) in the FGD liquor, according to the following overall reaction: 
A-4 

Hg+2 + HSO3

-

 + H2O ↔ Hg0 + SO4

=

 + 3 H+

The main pathway for this reaction is believed to be through the formation of complexes 

between Hg+2, sulfite, chloride, and possibly thiosulfate ions (present in inhibited oxidation FGD 

systems). Even in forced oxidation FGD systems, there can be sufficient sulfite present for reemission reactions to occur. As more is understood, it may be possible to control FGD chemistry 

to minimize re-emission (e.g., by controlling forced oxidation air rates and/or liquor chloride 

concentrations). However, a near-term solution may be the use of FGD additives to precipitate 

Hg+2 out of the liquid phase before it undergoes reduction reactions. 

Additives generally work by rapidly precipitating oxidized mercury from the FGD liquor, 

so it will not react with other liquid-phase species such as sulfite ions and be reduced to the 

elemental form. Most additives contain sulfides, which produce a very insoluble salt with 

oxidized mercury. 

The most straightforward method of adding sulfides to FGD systems might be to 

introduce H2S into the scrubbed gas upstream of the FGD absorber. However, H2S is extremely 

toxic and most utilities would not want to handle this gas at their plants. Another approach is to 

add sulfide-containing salts to the FGD liquor. However, some of these salts can release H2S if 

they are exposed to low Ph, aqueous conditions. Four commercially available additives are 

discussed below: Degussa’s TMT-15, Nalco’s additive 8034, Babcock & Wilcox’s sodium 

hydrosulfide (NaHS) additive, and Solucorp’s IFS-2C additive. Figure A-1 shows a schematic 

for a sample TMT-15 addition system. 

Figure A-1. TMT-15 Additive System for FGD Absorber with One Recycle Pump 

TIC

FGD 

Absorber

To Stack

Fan Recycle Pump

TMT-15 

Storage 

Tank

Metering Pump

Metering Pump Motor Run 

Interlock

TIC

FGD 

Absorber

To Stack

Fan Recycle Pump

TMT-15 

Storage 

Tank

Metering Pump

Metering Pump Motor Run 

Interlock
A-5 

One operational issue that has not fully been addressed is the impact of re-emission 

additives on gypsum Hg content. Some owners of FGDw systems sell the gypsum that is 

produced as a byproduct of the scrubber. An increase in the mercury content of the gypsum 

byproduct could affect sales of the product. Currently there are few if any specifications on 

gypsum Hg content, but re-emission additives that precipitate mercury could increase gypsum 

Hg content to the point where the gypsum would potentially no longer be salable. If this is the 

case, the effective cost of re-emission additives would increase for those FGDw operators who 

are no longer able to sell the gypsum byproduct for $5-10/ton, but rather a liability costing $5-

20/ton to dispose of in a landfill. 

• Technology Maturity: Testing 3 years of experience 

• Number of Commercial Installations: Several, in Europe

• Expected Performance:

o Hg – An additional 10-50% above native capture 

• Capital Costs: 0.75-1.5 $/Kw 

• Operating Costs: 0.2-0.5 $/Kw-yr. 

• Installation Schedule: 6-9 months for design, installation, and parametric testing. 

o Outage Required: None. 

A.1.4 Flue Gas Desulfurization (FGD) Upgrades 

Existing FGD scrubber units can be modified to enhance SO2 removal performance and 

improve unit operations and reliability. Such modifications are applicable to older FGD units, 

units currently not being operated (i.e., moth-balled units) or units originally designed for lower 

removals than now required or desired. The extent of a given upgrade process is typically a 

function of the required performance levels, configuration and condition of the existing absorber, 

and other site-specific balance-of-plant requirements. 

Upgrades to a scrubber can offer an appreciable cost advantage over replacing an existing 

FGD unit with either a new unit or an alternative air quality control technology. This is achieved 

by salvaging as many structural components and equipment associated with the existing unit as 

possible. This includes reuse of existing structural steel and absorber shells as well as highcapital process equipment such as pumps and compressors (where applicable). 

Upgrades have been performed on a large number of FGD units over the past 15 years 

and have resulted in increased SO2 removal performance to levels ranging from 92 – 99%. 

These have ranged from minor modifications to the internal components of a given unit, to 

enhance gas-liquid contact, to conversion of some units from one FGD technology to another 

coupled with the addition or modification of various balance-of-plant equipment or processes. 

An example of a technology conversion could include modifications to change a dual-alkali 

scrubber to a limestone forced-oxidation unit. 
A-6 

Because of the large variation of activities and associated costs that are possible within 

the range of scrubber modifications that can be implemented, it is convenient to classify 

upgrades into three different categories, as described below. 

• Minor Upgrades: These consist of moderate changes to some of the internals of a 

scrubber module, reusing most of existing process and structural components. The 

primary focus is enhancement of gas/liquid contacting within the absorber. Examples 

of applicable modifications include installation of absorber trays or wall rings as well 

as modifications to the configuration or type of reagent spray headers used (to 

improve overall reagent coverage and overlap within the absorber). Typical minor 

upgrades have been used to boost FGD performance to 92 – 97% SO2 removal. 

• Moderate Upgrades: These upgrades typically consist of major overhauls to the 

internals of a scrubber module to replace poor performing or failing components. In 

many cases, the existing internal process and structural components are removed; the 

absorber shell and large equipment components are maintained. Modifications 

include installation of new and improved reagent spray header arrays and absorber 

trays. 

• Major Upgrades: For some old FGD units, systems operating with lower-efficiency 

technologies and units that have been out of commission for extended periods of time, 

major upgrades are required obtain desired levels of performance. Such upgrades 

typically involve the same activities described for moderate upgrades, but can also 

include additional replacement of some large equipment along with modifications or 

additions associated with balance-of-plant equipment. The latter can include 

additions of or modifications to reagent preparation systems (e.g., ball mills), 

byproduct dewatering systems, and process slurry recirculation systems. In some 

cases, enhancements are made to existing mist eliminators to reduce carry-over of 

particulate material from the scrubber. Conversions from one FGD technology to 

another may include demolition of old or unneeded process components and/or 

addition of new ones. 

The costs associated with FGD system upgrades are commensurate with the level of 

capital improvements or replacements required for a specific unit. The costs for minor upgrades 

typically range from $5 - $10/kW, whereas moderate upgrades typically range from $15 - 

$25/kW. The costs for major upgrades can be quite variable, depending on the nature of upgrade 

and extent of balance-of-plant modifications made; these upgrades typically range from $50 to 

no more than $100/kW. The pending EPA MACT rule coupled with the multi-pollutant control 

nature of wet FGD scrubbers should ensure that scrubber upgrades continue to be a feasible 

option for many plants to enhance emission reductions. 

The impact of a scrubber upgrade on unit operating costs is determined by the nature of 

the modification(s). Changes in reagent preparation and process transport costs are impacted by 

the nature of the modifications made to preparation equipment, recirculation lines, and spray 

headers. For example, increased pressure-drop across the reagent slurry recirculation system 

(i.e., due to increased number of spray headers) would result in increased energy costs to operate 

the process. The addition of improved contactors within the absorber vessel may enable slurry 
A-7 

liquid-to-gas ratios to be reduced, thus having an opposite effect on costs. The addition of new 

processes associated with byproduct dewatering or water treatment would increase operating 

costs to varying degrees. A transition to a zero water discharge (ZWD) system could result in 

elimination of the need for a water treatment system, thus having the opposite effect; however, 

this benefit would be off-set by higher capital cost and energy usage required for the ZWD 

scheme. Furthermore, the conversion to an FGD process that produces a marketable gypsum 

byproduct could result in an appreciable revenue stream for the plant if local market conditions 

are favorable. Thus, operating cost impacts of scrubber upgrades can vary substantially from 

plant to plant, ranging from actually reducing operating costs to significantly increasing 

operating costs, depending on the nature of the existing and modified units. 

• Technology Maturity: FGD scrubber upgrades have been conducted over 15 years. 

• Number of Commercial Installations: Approximately 50 FGD units have been 

upgraded to enhance performance or lower overall operating costs. 

• Expected Performance:

o SO2: Upgraded FGD scrubbers have SO2 removal rates of 92 – 99%. 

o PM: High-efficiency FGD units can typically remove up to 70% of the 

particulate material entering the absorber in the flue gas. 

o HCl: Most well-performing wet FGD units are able to achieve greater than 90% 

removal of hydrogen halides. HCl would be expected to be removed across a wet 

FGD unit at a similar or higher efficiency than SO2. 

• Capital Costs:

o Minor Upgrades: $5 - $10/kW 

o Moderate Upgrades: $15 - $25/kW 

o Major Upgrades: $50 - $100/kW 

• Operating Costs: 

o Variable (see discussion above) 

• Installation Schedule: Typical schedules for the design, installation, and startup of 

FGD upgrades range from 12 – 36 months. 

o Outage Required: 4-8 weeks, in two parts. 

A.2 Additional AQC Technologies and Process Changes 

A.2.1 Activated Carbon Injection (ACI) 

Activated carbon injection (ACI) is the most demonstrated of the add-on mercury control 

technologies considered. Figure A-2 illustrates how ACI would be implemented upstream of a 

cold-side ESP (injection upstream of a FF baghouse would look similar, except for exchanging a 

baghouse for the ESP). Sorbent is metered from a storage silo with a weigh belt or volumetric 

feeder. A blower provides the motive force to convey the sorbent from the feeder to the flue gas 

duct. The sorbent is injected into the flue gas duct via a series of injection lances. The lances are 

placed upstream of the PM control device (PCD) or in rare cases upstream of the air heater. 
A-8 

Figure A-2. Simplified Schematic of ACI Installation. 

Truck

Unloading

Air Heater

ESP

LIC Storage

Silo

Weigh Belt

Filter Blower Ratio

Controller

Unit Load

Driflow Solids Pump

or Equivalent

M

To ID Fan, Stack

Truck

Unloading

Air Heater

ESP

LIC Storage

Silo

Weigh Belt

Filter Blower Ratio

Controller

Unit Load

Driflow Solids Pump

or Equivalent

M

Air Heater

ESP

LIC Storage

Silo

Weigh Belt

Filter Blower Ratio

Controller

Unit Load

Driflow Solids Pump

or Equivalent

M

To ID Fan, Stack

The performance of ACI for mercury control can be very site specific. Factors such as 

duct residence time, mixing effectiveness, PCD size and type, flue gas temperature, flue gas HCl 

concentration, concentrations of competing species in the flue gas (e.g., SO3) and other factors 

make it difficult to use full-scale performance data from one site to predict performance at 

another. Each of these parameters is explored below in somewhat more detail. 

• The more important design factor for the lances is the promotion of mixing between 

the activated carbon and the flue gas. Better mixing can be achieved through nozzle 

design on the lances and careful lance placement. These parameters can be optimized 

with the help of computational fluid dynamics (CFD) modeling, in which the 

trajectory of the injected sorbent particles is computed throughout the flue gas path. 

• PCD size can be important because carbon/ash carryover from small PCDs can limit 

the injection rate. Carbon carryover has been visually observed on PM filters placed 

at the outlet of small and large ESPs, but quantification of the carryover is difficult. 

URS experience with ACI in front of one small ESP (SCA = 173 ft2

/kacfm) (DOE 

project DE-FC26-03NT41987) showed that the injected carbon adversely affected 

ESP sparking, due to carbon tracking on insulators. Increased sparking could limit the 

amount of carbon that can be injected and hence the mercury capture that can be 

achieved. 

• ACI performance is best at lower flue gas temperatures (<300o

F). Carbons are being 

developed for high temperature applications, such as Sorbent Technologies’ H-PAC. 

At temperatures below 650°F, H-PAC is reputed to have the same mercury removal 

performance as Sorbent Technologies’ standard brominated carbon B-PAC. 
A-9 

• Activated carbon injection performs poorly in flue gas with high SO3 concentrations, 

such as flue gas derived from eastern bituminous coals. The SO3 competes with 

mercury for adsorption sites on the activated carbon. SO3 tolerant sorbents (discussed 

below) and SO3 mitigation technologies (discussed in a previous section) are possible 

means to make ACI more effective for bituminous flue gas. 

• For low-halogen flue gas, brominated sorbents can offer significantly higher mercury 

removal than standard activated carbons. Brominated carbons have shown only a 

small advantage for high chloride flue gas, likely because SO3 concentrations are high 

in these types of gases. 

There are no data to predict the long-term effects of a permanent activated carbon 

injection process that is in operation for several years. As noted above, increased sparking has 

been observed on small ESPs. Carbon breakthrough has been observed on both small and large 

ESPs. Carbon breakthrough may compromise gypsum quality for units that are equipped with 

wet FGDs downstream of the ESP. Carbon breakthrough may also trigger New Source Review 

for units that do not have additional PM controls downstream of the ESP. 

A disadvantage of using ACI for mercury control is that the carbon in the fly ash can 

adversely affect the air entrainment capabilities of concretes made using fly ash to replace some 

of the cement. The carbon sorbent in the fly ash competitively adsorbs the air-entraining 

admixtures (AEAs) that are added to concrete for air entrainment and stabilization. This 

competition results in a larger volume of AEA being needed, and more significantly to readymix concrete manufacturers, it results in variability in the amount of AEA needed. 

• Technology Maturity: Testing & Full Scale Operation; ~10 & 2 years of experience 

• Number of Commercial Installations: 50+

• Expected Performance:

o Hg – An additional 10-90% above native capture 

• Capital Costs: 2-10 $/kW (depending upon unit size) 

• Operating Costs: 2-20 $/kW-yr. 

• Installation Schedule: 12-18 months for design, installation, and parametric testing. 

o Outage Required: None. 

A.2.2 Dry Sorbent Injection (“DSI”) 

Sorbent materials can be injected at various points along the flue gas path to control acid 

gases. The main target of this technology is SO3; however additional acids may also be removed 

such as HCl, HF, and SO2. The removal of these additional gases depends on the amount and 

type of material added to the system. Sorbent reagents can be injected either as slurry or as a dry 

material. Slurry is typically injected using dual fluid nozzles where the water evaporates upon 

injection leaving dry sorbent material to react with the acid gases in the flue gas. Dry material is 

injected using pneumatic conveyors to carry the material to the injection point. Sorbent injection 
A-10 

is a mature technology with approximately 90 units currently being treated with one of five main 

reagents: 

• Trona – (22 units) dry injection of a mined mineral consisting of sodium bicarbonate 

and sodium carbonate 

• SBS – (20 units) liquid injection of soda ash or sodium bisulfite 

• Hydrated Lime – (28-34 units) dry injection 

• Magnesium Hydroxide – (1 unit) slurry 

• Ammonia – (8 units) anhydrous or aqueous 

Sorbents can be injected at several locations along the flue gas path including into the 

boiler, before an SCR, before the air heater, before the ESP or fabric filter, or before an FGD 

system. Table A-1 illustrates injection locations for each Sorbent material and includes the 

typical SO3 removal rate at normalized stoichiometric ratios (NSR) of reagent to SO3. Ammonia 

is currently used to condition fly ash for removal in an ESP, and could be used for SO3 control; 

however the stoichiometric ratio must be carefully regulated to prevent excess ammonia 

emissions. This may be an attractive option for plants with an existing SCR and infrastructure 

for ammonia storage on site. 

Table A-1. Injection Locations, SO3 Removal, and Required Stoichiometric Ratio 

Typical Injection Location Trona SBS 

Injection 

Hydrated 

Lime 

Magnesium 

Hydroxide Ammonia 

Boiler ● 

Before SCR ● 

Before AH ● ● ● 

Before ESP/FF ● ● ●

Before FGD ● 

Typical SO3 Removal 70-90% 95-99% 50-80% 50-90% 80-95% 

Typical NSR 2-3 1-1.5 3-5 2-4 1.5-2 

The typical capital cost for this technology is about $10/kW with the exception of 

ammonia injection that is approximately $5/kW. This includes pumps, spray nozzles, and 

control equipment. The operating costs consist of the reagent, maintenance, water, and parasitic 

power costs. A majority of the operating cost (~80%) consists of the reagent feed stock, thus 

making the overall operating cost dependent upon the normalized stoichiometric ratio necessary 

to get the desired removal rate. The NSR listed in the table above is for SO3, additional reagent 

will be necessary to capture HCl and HF in some plant configurations. SO2 capture is also 

possible by injecting excess reagent; however the PM collection device must be capable of 

handling the increased PM load, which may be 50-80% greater than the fly ash alone. Table A-2 

contains a summary of conceptual capital and approximate costs. 
A-11 

Table A-2. Capital and Operating Costs for Dry Sorbent Injection 

Trona SBS 

Injection 

Hydrated 

Lime 

Magnesium 

Hydroxide Ammonia 

Capital Cost ($/kW) 10 10 10 10 5 

Reagent Cost ($/ton) 180 275 125 500 600 

Approx. Operating Costs for SO3

and HCl capture ($/kW-yr.) 3.4 - 5 2 - 2.75 2 – 3 5.1 - 8.6 2.2 - 3.5 

• Technology Maturity: mature; 7+ years of operating experience 

• Number of Commercial Installations: 90

• Expected Performance: 

o SO3 – 50 - 99% depending on reagent, injection rate and configuration 

o HCl, HF – up to +90% 

o SO2 – 40 - 90% possible 

o Hg – enhances ACI performance by removing SO3 especially in bituminous flue 

gas 

• Capital Costs: 5 - 10 $/kW 

• Operating Costs: 2 - 8.6 $/kW-yr. (SO3 only) 

• Installation Schedule: 9-12 months from award to commercial operation 

o Outage Required: None. 

A.2.3 Coal Switching 

With upcoming MACT limits on HCl and mercury emissions at coal fired power plants, 

there are several scenarios where coal switching may be a cost-effective option for meeting 

emission limits, rather than the installation of pollution control devices. There are likely to be 

two dominant cases where coal switching is a viable option for meeting the upcoming MACT 

standards: 

• Switching from an Eastern bituminous or Lignite coal to a Powder River Basin (PRB) 

coal to meet HCl emissions limits. 

• Switching from Lignite (Texas-derived in particular) to a PRB coal to meet mercury 

emissions limits. 

For units switching from bituminous coal, it is recognized that the feasibility would 

depend on the ability of a given plant to operate either with higher coal flow (and associated flue 

gas volume) or at a de-rated capacity. 

Without some form of scrubber (wet or dry) it is unlikely that a plant burning eastern 

bituminous coal could meet the potential HCl emission limits. Installation of a new FGD system 

or a significant overhaul of an existing FGD system would be capital intensive project, and cost 

approximately $100/Kw or more. PRB coals have approximately 20-100 times less chloride and 
A-12 

4-10 times less sulfur than eastern bituminous coals. By switching to a PRB coal, it could be 

possible to meet 

HCl emission limits by using a less expensive HCl control technology like alkaline 

injection. For this switch to be economically favorable, the following would have to be true: 

• The site burns eastern bituminous or a lignite coal with significant chloride and sulfur 

content. 

o The site does not have any HCl control technologies in place, or has a 

significantly under-performing HCl control technology that would need a 

significant overhaul to meet HCl emissions limits. 

o The site has a FF or ESP that can handle additional PM loading from alkaline 

injection for HCl removal. A FF would be more effective in removing HCl with 

alkaline injection than an ESP, and would also likely be more able to meet PM 

emissions limits even with the additional PM load. 

Due to the high content of mercury in lignite, it is unlikely that a plant using lignite as its 

only fuel source would economically be able to meet a non-coal specific mercury emission limit. 

Therefore, complete fuel switching, or if significant pollution control equipment was already in 

place with high native capture (SCR, FF, FGD), fuel blending would be necessary to meet the 

emissions limits. Due to similar energy content, availability, and relatively low cost, the most 

likely candidate for an alternate fuel is PRB coal. 

A.2.4 Combustion Modifications 

Boiler combustion modifications may be used to optimize mercury capture by unburned 

carbon, which is subsequently collected along with fly ash in the ESP. It has been observed in 

limited field testing reports that for bituminous coal fired plants significant mercury control 

percentages (up to 75%) can be achieved with fly ash having elevated LOI values.7

 

One research organization, G.E. Environmental Services, has conducted full-scale tests 

on using combustion modifications to optimize this effect. The full-scale tests were co-funded by 

the U.S. Department of Energy. One project (DE-FC26-03NT41725) has employed coal “reburning” to optimize mercury capture, while the other (DE-FC26-05NT42310) is investigating 

air staging using (separated over-fire air [SOFA]). 

In the first demonstration project, GE reported up to 60% mercury removal with 

optimized re-burning and 10-15% LOI in the fly ash at a 300o

F ESP inlet flue gas temperature. 

They reported up to 75% mercury removal at similar conditions, but with a lower, 270oF ESP 

inlet temperature. In the second project on a 200-MW tangentially-fired unit, GE reports that 

 

7

 Lissianski, Vitali. “Mercury Control Using Combustion Staging”. Presented at DOE-NETL Mercury Control 

Technology R&D Program Review. Pittsburgh, PA. July 13, 2005. 
A-13 

optimized SOFA achieved up to 65% mercury removal with about 5% LOI in the fly ash at a 

300o

F ESP inlet temperature. They reported a strong effect of flue gas temperature on mercury 

capture by LOI, and tested duct humidification as a means of lowering the ESP inlet flue gas 

temperature. 

The Lehigh University Energy Research Center also has been investigating the effects of 

boiler combustion modifications on mercury emissions. They have developed a predictive 

model, and have conducted full-scale tests at three eastern-bituminous-coal-fired units, ranging 

from 108- to 650-MW in size. Two sites also fire some imported coals. In testing on a 250-MW 

tangentially fired boiler, they were able to enhance capture of mercury with the fly ash from a 

baseline level of about 6% to about 60% with “optimum” low mercury settings and a mid-level 

excess oxygen value. Variables optimized included excess oxygen, coal mills in service, mill 

classifier setting, separated over-fire air (SOFA) percentages, burner and SOFA tilt, air heater 

exit temperatures, and flue gas residence time prior to PM removal. The latter was accomplished 

by de-energizing an old ESP upstream of a new, larger ESP. However, the 60% mercury 

reduction level was achieved in some tests without de-energizing the old ESP. 

Combustion modification, to increase mercury capture, will increase carbon content in 

the fly ash. If the ash is being sold, increased carbon content could either reduce the value or 

render the ash unsalable. Such costs can be significant when ash goes from being a commodity 

worth $5-20/ton to a liability costing $5-20/ton to dispose of in a landfill. 

There are not many studies available on combustion modification and its impact on 

mercury removal on PRB coal fired power plants. Part of this is due to the general efficiency in 

combustion of PRB coals, and that achieving an LOI of greater than 1 wt% is difficult. Due to 

low SO3 concentrations in the flue gas and the highly alkaline ash, even small increases in LOI 

have been shown to increase Hg capture. 

Based on the evidence at hand, combustion modification may possibly be used for 

mercury control either in conjunction with another mercury control technology when native 

capture is low, or as a way of increasing a high native removal such that no other mercury 

control technologies are necessary. Combustion modification will be most effective if a 

baghouse is used for PM capture, as increased LOI will be more effective with fabric filters than 

with ESPs. 

• Technology Maturity: Testing; ~10 years of operating experience 

• Number of Commercial Installations: few operating

• Expected Performance:

o NOx – 0-20% additional removal 

o Hg – An additional 10-50% above native capture 

• Capital Costs: 0.5-1 $/kW (Study necessary to “tune”) 

• Operating Costs: 0.2-1 $/kW-yr. (http://www.epa.gov/airmarkets/progsregs/epaipm/docs/v410/Chapter5.pdf) 
A-14 

• Installation Schedule: 3-6 months for experimental design and “tuning” of the 

combustion tests. 

o Outage Required: None. 

A.2.5 Dry Flue Gas Desulfurization 

Dry FGD (also referred to as a “spray dryer”) is typically employed for the removal of 

SO2 emissions, but may also be used to accomplish removal of acid gases and selenium. 

Removal of these additional species may be necessary to achieve anticipated emissions standards 

under the Toxics Rule. In a spray dryer absorber vessel, flue gas comes in contact with an 

atomized slurry of alkaline reagent and recycled solids for removal of SO2 and acid gases. The 

alkaline reagent, typically lime, reacts with incoming pollutants to form calcium salts, such as 

calcium sulfate, calcium chloride, and calcium fluoride. Solids from the scrubber are captured in 

a downstream fabric filter. A portion of the reaction products and fly ash are recycled to the 

reagent slurry feed and the remaining are transported to landfill for disposal. The spray dryer 

technology, a type of dry flue gas desulfurization (dry FGD), operates at 20-30° F above 

saturation temperature, and as such, does not generate a wastewater purge stream as in a wet 

FGD, or limestone forced oxidation (LSFO) system. Spray dryers are limited in removal 

capabilities for higher sulfur coals compared to their wet FGD counterpart, and scrubber vessels 

are limited in size, generally treating up to 350 MW for a single vessel. 

The spray dryer technology represents a mature technology that has over 30 years of 

operating experience, including operation at several of Exelon’s facilities. Although spray dryers 

have traditionally been employed for SO2 emissions reduction from coal-fired power plants, they 

have also been shown to effectively remove acid gases (HCl, HF), and particulate with the 

downstream fabric filter, to meet anticipated MACT limits. 

The lime spray dyer may be appropriate for removal of particulate, acid gases, and 

selenium and SO2 at facilities that do not currently employ a scrubber system. Facilities with an 

existing electrostatic precipitator (ESP) or fabric filter (FF) may choose to continue operation of 

the existing particulate control device in order to maintain flyash sales or they may opt to 

abandon existing particulate control devices, relying on the spray dryer’s downstream fabric 

filter for particulate control, and disposing of all fly ash and FGD solid byproduct. 

A general process flow diagram of the lime spray dryer is shown in Figure A-3. Major 

capital cost components of a lime spray dryer system include the following systems: 

• Lime reagent supply and handling equipment, 

• Absorber vessel and associated pumps and tanks, 

• Flue gas handling systems (duct work and ID fans), and 

• Waste/byproduct handling systems. 
A-15 

Figure A-3. Lime Spray Dryer FGD System 

Spray Dryer

Fabric Filter

Solids

Disposal

Bin

Pug Mill

Recycle Solids

Tank

Lime Feed

Tank

ID Fan

Flue Gas from

Air Heater

Flue Gas

to Stack

Recycle

Solids

Bin

FGD Solids

Solids to 

Disposal

FGD Solids

Lime Receiving

Lime

Storage

Silo

Lime

Feed

Bin

Ball Mill

Slaker Lime Slurry

Feed Tank

Water

The spray dryer system requires a significant engineering effort and footprint at the plant 

site. Capital costs will be affected by the type of fuel, the desired removal efficiency, specific 

site arrangement and existing equipment considerations. Typical capital costs for a lime spray 

dryer system would likely be in the range of $220-260/kW. Additional project costs will be 

incurred including engineering, construction, and general facilities that are not accounted for in 

the above range. Operating costs for the lime spray dyer include lime reagent, water use, 

maintenance, parasitic power, and solids disposal costs. Lime reagent is a major operating cost, 

generally on the order of $100+/ton. Operating costs are typically around $50-80/kW-yr, again 

highly dependent upon site-specific factors such as fuel type, system removal efficiency, reagent 

and disposal costs. 

• Technology Maturity: mature; 30+ years operating experience 

• Number of Commercial Installations: many

• Expected Performance: 

o SO2 – 95%, dependent on fuel sulfur content 

o Acid Gases – up to 95% HCl, 45-95% HF, depending on coal properties 

o Hg – up to 90% when combined with carbon injection 

• Capital Costs: Dependent upon unit size, site-specific factors 

• Operating Costs: 30-50 $/kW-yr 

• Installation Schedule: 24-36 months from detailed design to start-up 
A-16 

A.2.6 Halogen Injection 

In this technology, halogen-containing chemicals are injected into the furnace to 

supplement the coal chlorine in its effect on mercury oxidation. Halogen salts added are 

typically calcium bromide (CaBr2). These salts, added with the coal or injected into the furnace, 

decompose at furnace temperature to form HBr/Br2 in the flue gas. These vapor-phase halogen 

acids react with elemental mercury in the back pass of the furnace as the flue gas cools, to 

produce oxidized mercury that can be removed by a downstream wet FGD system. 

Full-scale tests of furnace halogen injection have been conducted on a number of coalfired units that fire Powder River Basin coal, Texas lignite, and North Dakota lignite. Results 

from these parametric tests have shown that low concentrations of bromine (20-200 ppm in the 

coal) can produce 50-90% oxidized mercury in the flue gas. 

For example, calcium bromide injection tests were conducted at TXU’s Monticello Steam 

Electric Station Unit 3, which is equipped with a cold-side ESP and a limestone forced oxidation 

scrubber. Monticello fires a 50/50 blend of PRB and Texas Lignite. Baseline mercury removal 

at the unit ranges from 10 to 40%. Two two-week continuous injection tests were conducted at 

rates equivalent to 55 ppm and 113 ppm Br in the coal. At an injection rate equivalent to 55 ppm 

Br in the coal, the oxidation of mercury at the FGD inlet was 67%, and the removal of mercury 

was 65% (computed from coal and FGD outlet gas Hg concentrations). At an injection rate 

equivalent to 113 ppm Br in the coal, the oxidation of mercury at the FGD inlet was 85%, and 

the overall removal of mercury was 86%. 

Parametric and long term testing at other sites have shown that bromide addition is most 

effective with coals that are low in chloride (PRB) and at plants that have an SCR. The SCR, in 

conjunction with the bromine, act to oxidize the elemental mercury better than either 

individually. 

The long-term effects of bromine injection on FGD chemistry and FGD or boiler 

materials of construction are not known. To date, the longest test durations have been sixty days, 

which is not long enough to evaluate corrosion effects. It is also not known if the increased 

concentration of bromine in the fly ash and scrubber liquor/solids will impact the reuse of these 

byproducts. 

Capital equipment to be installed for the furnace halogen injection process is relatively 

simple, much like the equipment for activated carbon injection. The equipment consists of 

storage tanks for the halogen solution, pumps and a metering system to convey the solution to 

the coal, and a process control system. The capital cost of installation is estimated as $3/kW. 

The largest component of the operating cost for the process is the calcium bromide 

solution. This solution is currently available at ~ $1/lb of 52 wt% solution. It should be noted 

that there have been several increases in the price of calcium bromide over the last two years. 

Today’s price is more than double the 2004 price. It is unclear if such price increases should be 

expected in the future. The primary consumer of calcium bromide is the oil industry, which uses 

it as an operational fluid for offshore oil wells. 
A-17 

An existing patent8 on the use of bromine to oxidize mercury may require royalty 

payments to the patent holder. The amount of the royalty payment is not known at this time. 

• Technology Maturity: Testing 5 years of experience 

• Number of Commercial Installations: None

• Expected Performance:

o Hg – An additional 10-78% above native capture, with downstream FGD system 

• Capital Costs: 2.5-3.5 $/kW 

• Operating Costs: 0.25-2.5 $/kW-yr. (Chemical cost only, no royalties) 

• Installation Schedule: 6-12 months for design, installation, and parametric testing. 

o Outage Required: None. 

A.2.7 Toxecon 

Toxecon is an EPRI developed technology that involves the injection of dry sorbent, such 

as powdered activated carbon into a compact pulsed-jet fabric filter installed downstream of an 

existing primary PM control device. The Toxecon system has been demonstrated to achieve 

90%+ removal of mercury from the flue gas and offers additional reduction of PM with the 

installation of the baghouse. In facilities that do not currently operate an FGD scrubber, 

Toxecon may be coupled with alkali injection upstream of the fabric filter to achieve acid gas 

control, for reduction of HCl, HF, and SO2. In general, this technology may be an attractive 

control option for facilities operating a hot-side ESP with no FGD system. 

A generic process flow diagram of the system is shown in Figure A-4. A new pulsed-jet 

fabric filter is installed downstream of an existing PM control device, and a pneumatic 

conveying system and storage silo are included for sorbent injection. If additional alkali 

injection is included, a second storage silo and transport system will be required. Note that the 

capital cost of the DOE demonstration project at Wisconsin Energy’s Presque Isle Power Plant in 

Michigan was $52.9MM treating approximately 270 MWe, indicating a capital cost of over 

$190/kW. However, costs for this demonstration project were likely inflated due to the nature of 

the demonstration/first-of-its-kind installation. Additionally, a capital cost saving configuration 

of Toxecon may be employed whereby the last fields of the ESP are converted to a fabric filter 

PM collector (Toxecon 1.5). In this case, the sorbent injection point would be just downstream 

of the ESP fields, and upstream of the converted fields. Elimination of the new fabric filter 

housing from the system configuration would be expected to reduce the capital costs by 50-60% 

in comparison with the full Toxecon system. 

 

8

 Vosteen, B. US Patent 6878358. 
A-18 

Figure A-4. Toxecon System 

Boiler 

Carbon 

Injection

Existing 

ESP 

Powdered 

Activated Carbon 

Storage Silo 

Flue Gas to 

Existing ID fan 

and Scrubber or 

Stack 

Pulsed-Jet FF

Operating costs of the Toxecon system include costs for powdered activated carbon, 

power associated with additional pressure drop across the fabric filter, solids disposal, and fabric 

filter maintenance, including bag filter replacement. Operating costs are estimated to be 

$4-6/kW-yr. 

• Technology Maturity: Commercial demonstration completed; sorbent injection and 

fabric filter are proven technologies. 

• Number of Installations: ~5 

• Expected Performance: 

o Hg – 90%+ 

o Acid Gases – up to 90% HCl, HF with alkali injection 

o SO2 – 40-70% with alkali injection 

o Se – up to 90% with alkali injection 

• Total Project Costs: Demonstration project cost $190/kW) 

• Operating Costs: 4-6 $/kW-yr. 

• Installation Schedule: 12-24 months from detailed design to start-up 

o Outage Rrequired: 5-10 days. 

A.2.8 Wet Flue Gas Desulfurization (FGDw) 

Wet flue gas desulfurization processes remove SO2 from coal- and oil-combustion flue 

gas by reacting the gas with a re-circulating alkaline reagent solution or slurry. The alkaline 

reagent, typically a limestone or lime slurry, reacts with the incoming SO2 in a spray tower to 

form calcium salts such as calcium sulfate dihydrate (gypsum) or calcium sulfite. Solid 

precipitation occurs in an integrated reaction tank. The produced byproduct solids are removed 

from the process by way of a slurry purge routed either to a solid filtration system or to a gravity 

settling pond. Removal of SO2 across a wet FGD system is determined by the size and design of 

the scrubber unit, the gas-liquid contact properties, and the scrubber operating parameters (i.e., 
A-19 

nature of the FGD process chemistry). High efficiency FGD scrubbers are capable of removing 

95 – 99% of the SO2 present in the gas, depending on many factors associated with unit design, 

operating conditions, and flue gas composition. Wet FGD systems have historically been able to 

achieve higher SO2 removal levels than dry FGD systems and are generally more cost effective 

(than dry scrubbers) for the treatment of flue gas derived from coal containing moderate to high 

sulfur levels (i.e., >2%). 

Wet FGD is a mature technology that has over 40 years of commercial operating 

experience in the U.S and represents greater than 80% of FGD technology installed on fossil 

fuel-fired power plants. The addition of wet FGD represents an appreciable cost to a utility due 

to high associated capital costs but the technology is technically sound and operational risks 

associated with the technology have decreased with continued operating experience and 

technology development. Although wet FGD is typically employed for SO2 removal, it is also 

effective at removing acid gases, such as HCl and HF, from flue gas; wet FGD absorbers can 

also remove up to 50 – 70% of the particulate matter present in the gas, depending on the gasliquid contact properties of the unit. Furthermore, evaluation of coal and process data from the 

EPA ICR database indicates that plants configured with wet FGD achieve high levels of 

selenium removal from the flue gas. 

A wet FGD system may be appropriate for the removal of SO2 and acid gases at plants 

that do not currently employ a scrubber system. Furthermore, the wet FGD absorber would be 

expected to provide additional removal (50-70%) of particulate matter penetrating the upstream 

electrostatic precipitator (ESP) or fabric filter (FF). Wet FGD processes are also effective at 

removing oxidized forms of mercury from flue gas. Thus, for bituminous coal fired plants with 

high flue gas mercury oxidation, particularly those employing SCR for NOx control, high levels 

(70 – 90%) of mercury removal might be expected across a wet FGD system. For units firing 

Western sub-bituminous coal that typically produce flue gas mercury mainly in the elemental 

form, wet FGD provides the option for a plant to employ a mercury oxidation technology, such 

as boiler halogen (salt) addition, to decrease mercury emissions. For units configured with FF or 

Toxecon, wet FGD provides for the ability to take advantage of the natural tendency of fabric 

filters to oxidize mercury thus enhancing overall system removal; this effect is even greater when 

employing activated carbon injection upstream of the fabric filter resulting in most of the 

mercury that is not removed across the fabric filter getting removed across the FGD absorber. 

Despite being effective at removing oxidized forms of mercury from flue gas, some wet 

FGD absorbers have experienced mercury re-emissions from the process. Here, mercury 

captured by the FGD unit is chemically reduced back to volatile elemental mercury that 

subsequently exits the absorber with the flue gas. Mercury re-emissions are not well understood 

at this time but are believed to be impacted by a number of FGD operating parameters 

(associated with the process chemistry). The re-emissions can be controlled using chemical 

additives added to the process to complex or precipitate the captured mercury. 

Figure A-5 illustrates the primary components of a wet FGD process. The process can be 

operated under forced-, inhibited-, and natural oxidation modes. A number of reagents can be 

used to provide alkalinity to the process; limestone and lime represent to most common used. 
A-20 

Figure A-5. Illustration of Wet FGD Process; Example shows LSFO Process 

For a typical limestone forced oxidation FGD process, the major cost components are 

associated with the following process systems: 

• Flue gas handling (ductwork; bypass dampers, motive force, etc.) 

• Absorber unit 

• Reaction tank 

• Reagent preparation 

• Solids dewatering and handling 

• Oxidation air 

• Mist elimination 

• Gas reheat (for units operating dry stacks) 

• Control systems 

• Wastewater treatment 

• Chimney (e.g., modification from dry to wet stack) 
A-21 

Operating and maintenance cost categories include: 

• Feed materials and chemicals 

• Labor and supervision 

• Waste disposal 

• Maintenance, materials, and other costs 

• Auxiliary power costs 

• Water/water treatment costs 

A wet FGD system requires a significant engineering effort and appreciable footprint at 

the plant site. Capital costs will be affected by the size of the boiler, type of fuel fired, required 

removal efficiency, solids dewatering approach, specific site arrangement, and existing 

equipment considerations. Capital costs for a wet FGD system can range from roughly $300 - 

$600/kW, depending on a large number of factors; additional project costs will be incurred 

including engineering, construction, and general facilities that are not accounted for in the above 

range. Fixed O&M costs can range from approximately $9 - $19/kW-yr, depending on the size 

of the unit, and variable O&M costs can range from $15 - $38/kW-yr. The latter is impacted by 

plant size and site specific factors such as delivered reagent costs, byproduct transport and 

disposal costs, water and wastewater costs, and auxiliary power consumption costs; these costs 

can be offset by revenues associated with byproduct sales. 

• Technology Maturity: Over 40 years of commercial operation. 

• Number of Commercial Installations: Wet FGD is installed on many plants 

representing roughly one-third of the coal-derived electric generation (i.e., >100 GW) 

in the U.S. 

• Expected Performance:

o SO2: High-performance FGD scrubbers can achieve 95 – 99% SO2 removal. 

o HCl: Most well-performing wet FGD units are able to achieve hydrogen halide 

removal rates equal to or greater than the respective SO2 removal rate. 

o PM: High-efficiency FGD units can typically remove up to 50-70% of the 

particulate material entering the absorber in the flue gas. 

o Mercury: Wet FGD units can typically remove 85-90% of the oxidized mercury 

present in the incoming flue gas; elemental mercury removal is typically less than 

10%. Overall mercury removal is impacted by the extent of mercury re-emissions 

experienced by a given absorber unit. 

• Capital Costs:

o $300 - $600/kW 

• Operating Costs: 

o Fixed O&M costs can range from $9 - $19/kW-yr while variable O&M costs can 

range from $15 - $38/kW-yr. 
A-22 

• Installation Schedule: 

o Typical schedules for the design, installation, and startup of new FGDs range 

from 24 – 44 months. 

• Outage Required: 

o 4 – 8 weeks. 

A.2.9 Wet Electrostatic Precipitator (WESP) 

Wet electrostatic precipitators (WESPs) have been used in many industries for the 

effective control of sulfuric acid and PM for over 100 years. However, only in the past several 

years has the WESP been considered practical and necessary for utility applications. WESPs 

have been considered and employed on the utility scale in order to reduce ultra-fine and 

condensable PM, including acid mist removal downstream of a wet scrubber. Although utility 

applications of WESP are fairly new, they have been shown to achieve high levels of SO3

removal (> 80%) when used in combination with a wet FGD system. The collection of 

submicron PM is improved in the WESP over the dry ESP due to the ability of a WESP to 

achieve higher corona power levels, and the operation at saturation temperature, which promotes 

condensation of soluble acid aerosols. 

A WESP is configured much like a dry ESP, using multiple collecting and electrode 

fields. It is designed for large gas volumes, high PM inlet loading rates, and low outlet 

emissions. The parallel collecting fields are arranged in series and housed in a single enclosure. 

Collecting plates in a WESP are specifically designed to ensure uniform water film over the 

entire collecting area and an integral part of the WESP design is location of water spray nozzles 

to allow sufficient coverage over the collector plates. WESPs generally employ special alloys in 

order to avoid corrosion. One vendor has touted their membrane WESP as offering 20-30% cost 

savings over the conventional WESP by replacing solid sheet/tube collecting electrodes with 

fabric membranes that disperse water through capillary action. The membrane WESP has seen 

installation on non-utility applications up to approximately 185 MWe. 

A WESP incurs higher capital costs than its dry counterpart, mainly due to the materials 

of construction required in order to avoid corrosion problems. Because the cost of the system is 

highly dependent on incoming flue gas and wash water content, which will vary from site-to-site, 

capital costs may fall in range of $75- 200/kW, depending upon unit size. As stated above, the 

commercial membrane WESP may potentially offer 20-30% cost savings over its traditional 

counterpart. 

Operational costs of the WESP include pressure drop typically associated with a PM 

collector, energizing of the collector plates, as well as water consumption and water discharge. 

There are also potential water treatment costs; however they are not included in the costs 

presented here. In many cases the wastewater is sent to the FGD reaction tank. 

• Technology Maturity: mature; 100+ years of operating experience on industrial 

applications; 

• Number of Commercial Installations: several at the utility-scale; 
A-23 

• Expected Performance: 

o PM – 99%+ 

o HCl – not quantified; 90% expected 

o Hg – potentially 95% with wet scrubber 

• Capital Costs: $75-200/kW, dependent upon unit size and configuration 

• Operating Costs: $3-4/kW-yr. 

• Installation Schedule: 12-24 months from detailed design to start-up

o Outage Required: 5-10 days.