## 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, 2011iii 

### Table of Contents

Page

Executive Su mmary ....................................................................................... 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 Cont rol Altern atives ................................................................... 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) ......................................................................................... 13iv 

### 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 Conclu sions .................................................................................................... 15

Appendix A Technology Descriptionsv 

### 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 Desulfuriz ation (Spray dryer or circul ating fluidized bed scrubber)
FGDw Wet Flue Gas Desulfurization
HAP Hazardous Air Pollutant HCl Hydrochloric Acid HCN Hydrogen cyanide Hg Mercury ICI Industrial, Commer cial, and Institutional ICR Information Collection Request LOI Loss on Ignition MACT Maximum Achievable Control Technology
NESHAP National Emission Standard s for Hazardous Air Pollutants
NSR Normalized Stoichiometric Ratio
PM Particulate Matter
PRB Powder River Basin Coal RICE Reciprocating Inte rnal Combustion Engine
SBS Sodium Bisulfate SCR Selective Catalytic Reduction SOFA Separated Over-Fire Air
SO 3 Sulfur Trioxide TEF Toxic Equivalency Factor TEQ Toxicity Equivalent UPL Upper Prediction Limit ZWD Zero Water Discharge1 

### Executive Summary

This report 1 describes the results of an assessm ent conducted by URS Corporation (URS) to evaluate the availability of pollution contro l technologies to meet the requirements of the proposed National Emission Standards for Hazar dous Air Pollutants (NESHAP) for Utility Electric Generating Units (“EGUs”) (the “Toxic s 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 Envir onmental Protection Agency (EPA) has proposed, regardless of current configuration. URS iden tified proven, commercially available control technologies that will enable EGUs to achieve co mpliance 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 co ntrol equipment configurations present at existing EGUs. An assessment was performed to evaluate additional control technologies appropriate for those configuratio ns 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 contro l technologies and reviewed pub lished literature, conference proceedings, expert analysis and procurement in formation regarding the availability, cost and efficacy of numerous available control technologi es. 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 in stallations of the cont rol technologies. While special cases may exist, this analysis demonstrat es that the Toxics Rule emission limitations are generally achievable through the application of proven, commerci ally available technologies, regardless of the starting conf iguration 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 To xics Rule until three years after the effective date, or early 2015 – nearly four years after prop osal. 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 demons trated its ability to install a nd to operate these controls.

1 This report was prepared by URS Corporation for Exelon Corporation.2 The controls that will be most commonly need ed, such as activated carbon injection (for mercury control) or dry sorbent injection (for SO 3 control on bituminous fired plants and acid gas control at some western sub-bituminous fi red EGUs) typically requi re 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 capit al 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 a nd to file permit applications promptly to meet the 2015 compliance deadline. For those facilities f acing unique challenges in completing necessary upgrades by 2015, EPA has indicated that it will provide exte nsions of up to one year.3 

### 1.0 Introduction

In performing this assessment, URS consid ered the emissions limitations proposed by EPA in the Toxics Rule, reviewed relevant co mmercially available control technologies and evaluated seven hypothetical config urations of existing control e quipment to determine whether such facilities could be brought into compliance with the pr oposed Toxics Rule emission limitations. It was concluded that: 1) in ma ny instances, no additional controls would be required; 2) where additional c ontrols 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 t echnology 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 in tegrated gasification/ combined cycle (“IGCC”) sub-categories. Oil-fire d 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 particulat e 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 meta ls. 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 a nd 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 met hods. For example, coal-fired EGUs may use sulfur dioxide (“SO 2 ”) as a surrogate for acid gases in ce rtain circumstances, and may test for total non-mercury HAP metals or te n individual HAP metals in lieu of complying with the PM
limitation.

2.2 URS’ Technology Survey URS conducted a review of commercially-a vailable air quality control (“AQC”) technologies that may be employed by coal- a nd 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 defau lt emission limitations in the Toxics Rule for4 coal-fired EGUs and solid fuel oil-fired EGUs. 2 Although EPA proposed different emission limitations for liquid fuel oil-fired EGUs, the te chnologies available for controlling PM and HCl
at other EGUs would control total HAP metals a nd 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 info rmation from published literature and conference proceedings, discussions with technology experts, and procurement information associated with some technologies. For each pollu tant category, air quali ty control technologies were evaluated for their ability to achieve sufficient performa nce levels. Although costs were not a primary
factor in the selection of a ppropriate technologies, they were considered when comparing different technologies with similar expected perf ormance levels. The multi-pollutant nature of various technologies was also cons idered, as some processes woul d be expected to effectively remove pollutants from a number of potential HA P 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 possi ble technologies for cont rolling 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 ra nge of control technologi es available to EGUs requiring additional levels of control for mercur y, 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 cap ital retrofits that typicall y require less than eighteen months to install. Some technologies, such as wet or dry scrubbers, have longer inst allation 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 expect ed performance, cost, and schedule to construct at power plants of se veral 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 op erating scenarios, physical layout and balance of plant considerations, as well as economic a nd long-term planning considerations. For the purposes of this study, several common configurat ions 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, SO 2 or oxides of nitrogen (“NO x ”).

The most common PM control t echnologies are fabric filters (“FFs”) and electrostatic precipitators (“ESPs”). The most common SO 2 controls are flue gas desulfurization (“FGD”) systems (commonly called “scrubbers”), which ca n be either wet (“FGDw”) or dry (“FGDd”).
The most common NO x controls are selectiv e catalytic reduction (“SCR”) systems.

The potential need for additional controls to comply with the Toxics Rule was evaluated for seven different hypothetical configurati ons 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 instal led 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 te chnologies that may potentially be employed in order to lower emissions of the targeted HAP species for a give n plant configuration. The analysis took into account cost as well as the performance, maturi ty level, and number of existing commercial installations of each technology. Se lected technologies included di fferent control processes that could be implemented for different fuel type s, including opportunities for fuel switching. Additionally, the ability of certa in 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 ad ditional control for PM, HCl and mercury. Up to four different technologies we re identified for each scenario, each of which would provide the additional level of control requ ired. Those technologies were then ranked according to the
criteria described above. Table 2-1 lists seve ral 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 cond itions at that facility. As the table reflects, many facilities with existing PM and SO 2 controls may need no additi onal 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 ot her 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 thes e outlier plants in the discussion in Section 3.0.

In Table 2-1, configurations th at are unlikely to need additio nal controls to comply with the Toxics Rule are shaded in green. Those lik ely to require additional controls that can be
installed in no more than 24 m onths are shaded in blue. Th ose 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 c ontrols are not cumulative. Rather, EGU owners installing multiple control technologies would sc hedule installation of those controls, and any ancillary modifications to the pl ant, during the same planned outag e, or a coordina ted series of outages, provided all controls could be installe d prior to the deadline for compliance with the Toxics Rule. Nonetheless, if a pa rticular 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 discus sions of the rationale behind the various technology selections for each of the hypotheti cal configurations considered. For each configuration, the report provide s strategies for controlling PM, HCl and mercury. Appendix A presents further information on the technologies discussed in this report, incl uding each technology’s maturity; the number of commerci al installations, if known, the technology’s expected performance; capital and operating co sts; and the typical schedule for design, installation, and startup.7 Table 2-1. Pollution Control Options for Coal- and Oil-Fired Power Plants 4

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 SO 3 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 SO 3 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 SO 3 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 SO 3 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 SO 3 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 SO 3 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 SO 3 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, h ydrated lime, SBS and other reagents.8 

### 3.0 Analysis of Control Alternatives

3.1 Overview With adequate investment, it should be possibl e 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 fo llowing sections present seven typical air pollution control configur ations 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 meeti ng EPA’s proposed mercury a nd air toxic standards, as presented in Table 2-1. Technologies discusse d 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 acknowle dged that site specific factors will impact the ultimate performance of any AQC technology at a gi ven plant. Additional technologies in the developmental stages may be available and have not been included in the sc ope 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 a dditional 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 func tional fabric filter cap able of controlling PM emissions and with a sufficient additional marg in could adequately c ontrol emissions of HCl with the installation of a dry FGD system. FGDd would be ef fective for relatively high HCl content and, for this configura tion, 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, switchi ng to a western sub-bituminous coal would appreciably reduce HCl emissions. If coal s ubstitution alone does not achieve compliance for these plants, dry sorbent injection will be sufficien t 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 th an 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 contro l. FFs usually respond well to ACI for Hg removal, assuming the FF can handle the additiona l 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 c onfiguration, control of
SO 3 , which tends to hinder the effectiveness of AC I Hg removal, may be necessary for effective operation of ACI when burning high sulfur coal.

If mercury re-emissions from the wet FGD sy stem cause the EGU to exceed the Toxics Rule emission limitation, the use of scrubber add itives to reduce the re-emissions may be more
cost-effective than ACI.

If further Hg control is needed, using Low NO x Burners or increasing their NO x removal performance can lead to higher Loss on Ignition (LOI) to the fl y ash, and better Hg removal.

Some plants firing bituminous coal might be challenged to achieve Hg emission
limitations due to SO 3 interference with sorbent-based mercur y 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 bitumi nous coals this would be through decreasing flue gas SO 3 concentrations, and thus increasing the perf ormance 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 ad ditional margin, an act ivated carbon injection (ACI) system will provide adequate Hg contro l. FFs usually respond well to ACI for Hg removal, assuming the FF can handle the additiona l PM loading resulting from the operation of the ACI. However, SO 3 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 add itives may be able to reduce re-emission of mercury more cost-effectively than ACI.

Finally, although less effectiv e without a selective catalyt ic reduction (SCR) system, bromine addition could be sufficient for trimming em issions 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 unlikel y 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 unlikel y to require additional controls to meet the
HCl emission limitation in the Toxics Rule. Howe ver, 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 addi tional margin, an Activated Carbon Injection (ACI) system will provide adequate Hg contro l. FFs usually respond well to ACI for Hg removal, assuming the FF can handle the additiona l PM loading resulting from the operation of the ACI. However, SO 3 control may be necessary for effective operation of ACI when burning high sulfur coal.

Finally, although less effectiv e without a selective catalyt ic reduction (SCR) system, bromide addition could be sufficient for trimming em issions 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 ar e unlikely to require ad ditional controls to
meet the PM emission limitation in the Toxics Ru le. If additional control is required, a plant could upgrade either its FF or scrubber, or both, to achie ve the PM emission limitation.

3.5.2 Hydrochloric Acid (HCl) Plants equipped with SCR, FF and FGDd ar e unlikely to require ad ditional 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 sorben t 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 margi n, 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 resulti ng from the operation of the ACI. However,
SO 3 control may be necessary for effective opera tion 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 cont rol performance could be constrained by elevated SO 3 levels. A switch to Western sub-bituminous coal would imp rove the performance of the plant’s various mercury controls as well as yield acid gas emission reductions.

3.6 SCR-ESP-Wet FG D 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 opti on to provide additional control would be an upgrade of the ESP, the scrubber mist eliminat or, 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 th e 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 SO 3 control technology; some plants w ith 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 rem oval upstream of the FGD system, Toxecon with activated carbon injection would lik ely be the best control strategy. Under this configuration, scrubber re-emissi ons 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 insta lled. 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 SO 2 control is also desired.

3.7.2 Hydrochloric Acid (HCl) A dry FGD system will provide effective cont rol for relatively high HCl content, but may require installation of a fabric filter to control the additional pa rticulate 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 no t 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 co al 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 re quiring additional PM control or desiring Hg removal upstream of the FGD system, Toxecon w ith activated carbon inje ction would likely be the best control strategy. Altern atively, an ACI system using brominated sorbent may be used for plants burning western coals; however, me rcury removal under this option depends on ESP performance. Installation of a wet FGD may be a viable option for plants that desire additional
SO 2 control; using this strategy, bromide addition ma y also be an option for mercury control for EGUs firing western fuels.

The primary choice for a plant firing bitumi nous coal would likely be an ACI with
additional SO 3 control technology. However, plants firing bituminous coal will be challenged to achieve desired mercury reductions due to SO 3 interference. Plants fi ring lignite containing high mercury levels (e.g., Texas lignite) will require hi gh 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 pe rformance 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 opti on 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 th e 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 prim ary 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 SO 3 control technology may be necessary Under this configuration, sc rubber re-emission additives may be required to control Hg emissions in conjunction w ith other control technology, depending on mercury removal performance of the wet FGD.

3.9 Installation Schedule None of the typical confi gurations considered in this assessment included existing mercury controls, though many EG Us are presently equipped with ACI. Accordingly, this analysis concludes that every EGU configuratio n 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 impr oving 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-ranked15 technology for only two of the seven configurat ions evaluated. Dry FGD has the longest
installation time of th e top-ranked technologies.

These installation times are not cumulative; ra ther, 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 betw een 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 EP A in the Toxics Rule as its guide, URS examined the existing field of demonstrated, av ailable AQC technologies to determine whether these technologies would be sufficient to allow t ypical coal-fired and oil-fired EGUs to achieve
these emission limitations. URS co ncluded that the emission limita tions proposed in the Toxics Rule can be achieved by typical EGUs through th e application of successfully demonstrated, available AQC technologies. The controls consider ed in this analysis can typically be installed in 18 months (for ACI), 24 months (for ESP upgrad es), or 36 months (for FGDs) after detailed design and permitting is complete. If EGU owne rs make their technology choices and initiate the permitting process promptly, they should be ab le 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 tim es 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 separate ly from technologies not considered in the hypothetical configurations discusse d 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 lowe r costs due to site specific requirements. Additionally, cost estimates in clude equipment and operating co sts, where specified; planning and financing costs are not included. The es timated 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 informa tion available today, and the estimates provided here may be affected by future changes in pricing and scheduling demand.

A.1 Modifications to Exis ting AQC Systems at EGUs

A.1.1 Cold-side ESP Upgrades The use of electrostatic preci pitator (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 perf ormance can be upgraded to improve collection efficiency and reduce operating costs. Ofte n the performance can be increased through a thorough examination to insure that worn or br oken 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 SO 3 and/or ammonia injection (to the flue gas upstream of the ESP) to improve ash agglomeration. $2-10/kW

• Replace wire and weight systems, wide ning 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 ar ea served by each rapperA-2 • Increase the collecting surface area - severa l vendors report that many of the older ESPs in the US can be modified to incr ease the collecting surface area by 10-20% within their existing footprin t. Another option is to add an additional field. $30- 0/kW

• Reduce gas flow through the ESP by repair ing upstream leaks or upgrading air heaters to limit air in-leakage

• Add a Bipolar Agglomerator to th e 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 particular ly old or poorly performing, more repairs or modifications may be necessary. Some vendors cl aim 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 co sts for many of these modificati ons will not increase over the cost of previous operation, and in many cases th e operating costs will de crease due to gains in collection and power consumption efficien cy. The operating costs for injecting SO 3 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 manuf actured 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 th rough a series of alternating positive and negative parallel passages. The dust then enters a mi xing 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 appr oximately $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 awar d 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 em ission standards. If a plant is unable to meet emission standards w ith a fabric filter, the cause is mo st 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 inte rval between cleaning may be reduced and the life of the bags coul d be extended. Optimization of fabric filter performance may also be achieved by an evaluation of the maintena nce schedule. An analysis of process and maintenance data could lead to an un derstanding of how to an ticipate bag failure and replace them before the fa ilure actually occurs.

Another alternative to increase PM collection would be to re place the existing bags with different material such as a membrane bag. Diffe rent 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 additi onal 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 ad vantageous to maintain fly ash sales from the existing baghouse. Adding additional compartm ents 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 ba g 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 li mited by a phenomenon called “reemission” that results in a portion of the scrubbed Hg +2 being chemically reduced to Hg 0 in the FGD liquor. Once reduced, the insoluble Hg 0 is released back into th e flue gas. The re-emission process is not currently well understood, but is be lieved to occur by reacti on with bisulfite ions (dissolved SO 2 at lower Ph) in the FGD liquor, accord ing to the following overall reaction:A-4 Hg +2 + HSO 3 - + H 2 O ↔ Hg 0 + SO 4 = + 3 H +

The main pathway for this reaction is believe d to be through the formation of complexes between Hg +2 , sulfite, chloride, and possibly thiosulfate ions (present in i nhibited oxidation FGD systems). Even in forced oxidation FGD systems, there can be sufficient sulfite present for reemission reactions to occur. As more is unders tood, 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 precip itating oxidized mercury from the FGD liquor, so it will not react with other liquid-phase species such as sulf ite ions and be reduced to the elemental form. Most additives contain sulf ides, which produce a very insoluble salt with oxidized mercury.

The most straightforward method of adding sulfides to FGD systems might be to introduce H 2 S into the scrubbed gas upstream of the FGD absorber. However, H 2 S is extremely toxic and most utilities would not wa nt 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 H 2 S if they are exposed to low Ph, aqueous conditions. Four commercially available additives are discussed below: Degussa’s TMT-15, Nalc o’s additive 8034, Babcock & Wilcox’s sodium hydrosulfide (NaHS) additive, and Solucorp’s IF S-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 InterlockA-5 One operational issue that has not fully been addressed is the impact of re-emission additives on gypsum Hg content. Some owne rs of FGDw systems sell the gypsum that is produced as a byproduct of the scrubber. An in crease in the mercury c ontent of the gypsum byproduct could affect sales of the product. Cu rrently 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 pot entially no longer be salable. If this is the case, the effective cost of re-emission additive s would increase for those FGDw operators who are no longer able to sell the gypsum byproduct fo r $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, installa tion, and parametric testing.

o Outage Required: None.

A.1.4 Flue Gas Desulfur ization (FGD) Upgrades Existing FGD scrubber units can be modified to enhance SO 2 removal performance and improve unit operations and reliability. Such mo difications 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 ex tent of a given upgrade process is typically a function of the required performance levels, conf iguration and condition of the existing absorber, and other site-specific balanc e-of-plant requirements.

Upgrades to a scrubber can offer an appreciab le cost advantage over replacing an existing FGD unit with either a new unit or an alternative air quality control techno logy. This is achieved by salvaging as many structural components and e quipment associated with the existing unit as possible. This includes reuse of existing struct ural 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 SO 2 removal performance to leve ls 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 vari ous balance-of-plant equipment or processes. An example of a technology conve rsion could include modificatio ns to change a dual-alkali scrubber to a limestone forced-oxidation unit.A-6 Because of the large variation of activities a nd associated costs that are possible within the range of scrubber modifications that can be implemented, it is c onvenient to classify upgrades into three different ca tegories, as described below.

• Minor Upgrades: These consist of moderate changes to so me 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 installati on 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% SO 2 removal.

• Moderate Upgrades: These upgrades typica lly consist of major overhauls to the internals of a scrubbe r 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 com ponents are maintained. Modifications include installation of new a nd improved reagent spray he ader arrays and absorber trays.

• Major Upgrades: For some old FGD units, systems operating with lower-efficiency technologies and units that ha ve been out of commission fo r extended periods of time, major upgrades are required obtain desired le vels of performance. Such upgrades typically involve the same activities descri bed for moderate upgrades, but can also include additional replacemen t of some large equipment along with modifications or additions associated with balance-of-pla nt equipment. The latter can include additions of or modifications to reag ent preparation systems (e.g., ball mills), byproduct dewatering systems, and process slur ry 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 upgrad es are commensurate with the level of capital improvements or replacements required fo r a specific unit. The costs for minor upgrades typically range from $5 - $10/kW, whereas mode rate upgrades typically range from $15 - $25/kW. The costs for major upgrades can be qu ite 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 opera ting costs is determined by the nature of the modification(s). Changes in reagent preparat ion and process transport costs are impacted by the nature of the modifications made to prepar ation equipment, recirc ulation 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 im proved contactors within the absorber vessel may enable slurryA-7 liquid-to-gas ratios to be redu ced, thus having an opposite effect on costs. The addition of new processes associated with bypr oduct dewatering or water treatme nt would increase operating costs to varying degrees. A transition to a ze ro water discharge (ZWD) system could result in elimination of the need for a water treatment sy stem, 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 st ream 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 cost s 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 SO 2 : Upgraded FGD scrubbers have SO 2 removal rates of 92 – 99%.

o PM: High-efficiency FGD units can typically remove up to 70% of the particulate material entering th e 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 SO 2
.

• 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 desi gn, installation, and startup of FGD upgrades range from 12 – 36 months.

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

A.2 Additional AQC Technol ogies and Process Changes

A.2.1 Activated Car bon Injection (ACI) Activated carbon injection (AC I) 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 conve y the sorbent from the feeder to the flue gas duct. The sorbent is injected into the flue gas duct via a series of injectio n 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 temp erature, flue gas HCl concentration, concentrations of comp eting species in the flue gas (e.g., SO 3 ) 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 la nces is the promotion of mixing between the activated carbon and the flue gas. Be tter mixing can be achieved through nozzle design on the lances and careful lance placement. These parameters can be optimized with the help of computational flui d dynamics (CFD) modeling, in which the trajectory of the injected sorb ent particles is computed thr oughout 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 la rge ESPs, but quantification of the carryover is difficult. URS experience with ACI in front of one small ESP (SCA = 173 ft 2 /kacfm) (DOE project DE-FC26-03NT41987) showed that th e injected carbon adversely affected ESP sparking, due to carbon tracking on insu lators. Increased sparking could limit the amount of carbon that can be injected a nd hence the mercury capture that can be achieved.

• ACI performance is best at lowe r flue gas temperatures (<300 o F). Carbons are being developed for high temperature applications , such as Sorbent Technologies’ H-PAC. At temperatures below 650°F, H-PAC is re puted to have the same mercury removal performance as Sorbent Technologies’ standard brominated carbon B-PAC.A-9 • Activated carbon injectio n performs poorly in flue gas with high SO 3 concentrations, such as flue gas derived from eastern bituminous coals. The SO 3 competes with mercury for adsorption sites on the activated carbon. SO 3 tolerant sorbents (discussed below) and SO 3 mitigation technologies (discussed in a previous section) are possible means to make ACI more effec tive for bituminous flue gas.

• For low-halogen flue gas, brominated sorb ents can offer signifi cantly higher mercury removal than standard activated carbons. Brominated carbons have shown only a small advantage for high chloride flue gas, likely because SO 3 concentrations are high in these types of gases.

There are no data to pred ict the long-term effects of a permanent activated carbon injection process that is in operation for severa l 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 br eakthrough 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 cont rol is that the car bon 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 fl y ash competitively adsorbs the air-entraining admixtures (AEAs) that are a dded to concrete for air entrai nment and stabilization. This competition results in a larger volume of AEA being needed, and more significantly to readymix concrete manufacturers, it results in va riability 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, insta llation, and parametric testing.

o Outage Required: None.

A.2.2 Dry Sorbent Injection (“DSI”) Sorbent materials can be injected at various po ints along the flue gas path to control acid gases. The main target of this technology is SO 3 ; however additional acids may also be removed such as HCl, HF, and SO 2 . The removal of these additional gases depends on the amount and type of material added to the system. Sorbent reagen ts 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 mate rial to the injection poi nt. Sorbent injectionA-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 pa th including into the boiler, before an SCR, before the air heater, befo re the ESP or fabric filter, or before an FGD system. Table A-1 illustrates injection locati ons for each Sorbent material and includes the typical SO 3 removal rate at normalized stoichiome tric ratios (NSR) of reagent to SO 3 . Ammonia is currently used to condition fly ash for re moval in an ESP, and could be used for SO 3 control; however the stoichiometric ratio must be ca refully 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, SO 3 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 SO 3 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 technol ogy 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, ma intenance, water, and parasitic power costs. A majority of th e operating cost (~80%) consists of the reagent feed stock, thus making the overall operating cost dependent upon the normalized stoichiome tric ratio necessary to get the desired removal rate. The NSR listed in the table above is for SO 3 , additional reagent will be necessary to capture HCl and HF in some plant configurations. SO 2 capture is also possible by injecting excess reagent; however th e PM collection device must be capable of handling the increased PM load, which may be 50- 80% greater than the fl y 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 SO 3 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 SO 3 – 50 - 99% depending on reagent, in jection rate and configuration

o HCl, HF – up to +90%

o SO 2 – 40 - 90% possible

o Hg – enhances ACI performance by removing SO 3 especially in bituminous flue
gas

• Capital Costs: 5 - 10 $/kW

• Operating Costs: 2 - 8.6 $/kW-yr. (SO 3 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 mercur y emissions at coal fired power plants, there are several scenarios where coal switchi ng may be a cost-effective option for meeting emission limits, rather than the installation of po llution 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 Ligni te coal to a Powder River Basin (PRB) coal to meet HCl emissions limits.

• Switching from Lignite (Texas-derived in par ticular) to a PRB coal to meet mercury emissions limits.

For units switching from bituminous coal, it is recognized that th e feasibility would depend on the ability of a given plan t 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 emi ssion limits. Installation of a new FGD system or a significant overhaul of an existing FGD system would be capit al intensive project, and cost approximately $100/Kw or more. PRB coals have approximately 20-100 times less chloride andA-12 4-10 times less sulfur than eastern bituminous coal s. By switching to a PRB coal, it could be possible to meet

HCl emission limits by using a less expens ive HCl control technology like alkaline injection. For this switch to be economically fa vorable, the following w ould 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 cont rol technologies in place, or has a significantly under-performing HCl cont rol technology that would need a significant overhaul to m eet 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 plan t using lignite as its only fuel source would economically be able to meet a non-coal sp ecific mercury emission limit. Therefore, complete fuel switchi ng, or if significant pollution c ontrol equipment was already in place with high native capture (SCR, FF, FGD), fu el 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 fl y 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 ha ving elevated LOI values. 7

One research organization, G.E. Environmen tal 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 proj ect (DE-FC26-03NT41725) has employed coal “reburning” to optimize mercury capture, while the other (DE-FC26-05NT4 2310) 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 300 o F ESP inlet flue gas temperature. They reported up to 75% mercury removal at similar conditions, but with a lower, 270 o F ESP inlet temperature. In the second project on a 200 -MW tangentially-fired un it, 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 remova l with about 5% LOI in the fly ash at a 300 o F ESP inlet temperature. They reported a str ong 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 investig ating the effects of boiler combustion modifications on mercury emi ssions. 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 fi re some imported coals. In testing on a 250-MW tangentially fired boiler, they we re 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 prio r 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 test s without de-energizing the old ESP.

Combustion modification, to increase mercur y capture, will increase carbon content in the fly ash. If the ash is bei ng sold, increased carbon content c ould 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 liabili ty costing $5-20/ton to di spose 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 th e general efficiency in combustion of PRB coals, and that achieving an LOI of greater th an 1 wt% is difficult. Due to low SO 3 concentrations in the flue gas and the high ly 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 conj unction 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. Combusti on modification will be most effective if a baghouse is used for PM capture, as increased LOI w ill 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 NO x – 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 SO 2 emissions, but may also be used to accomplish removal of acid gases and selenium. Removal of these additional species may be nece ssary 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 alka line reagent and recycled solids for removal of SO 2 and acid gases. The alkaline reagent, typically lime, reacts with incoming pollutants to form calcium salts, such as calcium sulfate, calcium chloride, and calcium fluor ide. 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 su ch, does not generate a wastewat er purge stream as in a wet FGD, or limestone forced oxidation (LSFO) syst em. Spray dryers are limited in removal capabilities for higher su lfur coals compared to their wet FGD counterpart, and scrubber vessels are limited in size, generally treati ng up to 350 MW for a single vessel.

The spray dryer technology represents a ma ture technology that has over 30 years of operating experience, including opera tion at several of Exelon’s f acilities. Although spray dryers have traditionally been employed for SO 2 emissions reduction from co al-fired power plants, they have also been shown to effectively remove acid gases (HCl, HF), a nd 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 SO 2 at facilities that do not currently employ a scrubber syst em. 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 cont rol devices, relying on the spra y dryer’s downstream fabric filter for particulate contro l, 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 drye r 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 en gineering effort and f ootprint at the plant site. Capital costs will be affected by the type of fuel, the desired removal efficiency, specific site arrangement and existing equipment consider ations. 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, c onstruction, 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 typi cally around $50-80/kW-yr, again highly dependent upon site-specific f actors such as fuel type, syst em removal efficiency, reagent and disposal costs.

• Technology Maturity: mature; 30+ years operating experience

• Number of Commercial Installations: many

• Expected Performance:

o SO 2 – 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-upA-16 A.2.6 Halogen Injection In this technology, halogen-containing ch emicals are injected into the furnace to supplement the coal chlorine in its effect on mercury oxidation. Halogen salts added are typically calcium bromide (CaBr 2 ). These salts, added with the co al or injected into the furnace, decompose at furnace temperature to form HBr/Br 2 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 re moved by a downstream wet FGD system.

Full-scale tests of furnace hal ogen injection have been c onducted 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 lo w concentrations of br omine (20-200 ppm in the coal) can produce 50-90% oxidized mercury in the flue gas.

For example, calcium bromide injection test s 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 P RB and Texas Lignite. Baseline mercury removal at the unit ranges from 10 to 40% . Two two-week continuous inje ction tests were conducted at rates equivalent to 55 ppm and 113 pp m Br in the coal. At an inje ction 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 oxid ation of mercury at the FGD inlet was 85%, and the overall removal of mercury was 86%.

Parametric and long term testing at other site s have shown that bromide addition is most effective with coals that are low in chloride (PRB) and at plants th at 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 duration s have been sixty days, which is not long enough to evaluate corrosion eff ects. It is also not known if the increased concentration of bromine in the fly ash and scrubb er liquor/solids will impact the reuse of these byproducts.

Capital equipment to be inst alled for the furnace halogen in jection process is relatively simple, much like the equipment for activated carbon injection. The equipment consists of storage tanks for the halogen so lution, pumps and a metering system to convey the solution to the coal, and a process control system. The capita l 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 curren tly available at ~ $1/lb of 52 wt % solution. It should be noted that there have been several increases in the pr ice of calcium bromide ove r the last two years. Today’s price is more than double the 2004 price. It is unclear if such pr ice 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 patent 8 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, installa tion, 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 instal led downstream of an existing primary PM control device. The Toxec on 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 curren tly operate an FGD scrubber, Toxecon may be coupled with alka li injection upstream of the fabric filter to achieve acid gas control, for reduction of HCl, HF, and SO 2 . 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 tr ansport system will be required. Note that the capital cost of the DOE demonstr ation project at Wisconsin Energy’ s Presque Isle Power Plant in Michigan was $52.9MM treating approximately 2 70 MWe, indicating a capital cost of over $190/kW. However, costs for this demonstration proj ect 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 th is 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 in clude costs for powdered activated carbon, power associated with additional pressure drop acro ss the fabric filter, solids disposal, and fabric filter maintenance, including bag filter replacem ent. Operating costs are estimated to be $4-6/kW-yr.

• Technology Maturity: Commercial demonstration co mpleted; 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 SO 2 – 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 desulfurizat ion processes remove SO 2 from coal- and oil-combustion flue gas by reacting the gas with a re-circulating alka line reagent solution or slurry. The alkaline reagent, typically a limestone or lim e slurry, reacts with the incoming SO 2 in a spray tower to form calcium salts such as cal cium sulfate dihydrate (gypsum ) or calcium sulfite. Solid precipitation occurs in an inte grated reaction tank. The pr oduced byproduct solids are removed from the process by way of a slurry purge routed e ither to a solid filtration system or to a gravity settling pond. Removal of SO 2 across a wet FGD system is determined by the size and design of the scrubber unit, the gas-liqui d contact properties, and the scrubber operating parameters (i.e.,A-19 nature of the FGD process chemistry). High e fficiency FGD scrubbers are capable of removing 95 – 99% of the SO 2 present in the gas, depending on ma ny factors associated with unit design, operating conditions, and flue gas composition. Wet FGD systems have historically been able to achieve higher SO 2 removal levels than dry FGD systems and are generally more cost effective (than dry scrubbers) for the treatment of flue ga s derived from coal containing moderate to high sulfur levels (i.e., >2%).

Wet FGD is a mature technology that ha s over 40 years of co mmercial operating experience in the U.S and represents greater th an 80% of FGD technology installed on fossil fuel-fired power plants. The addi tion of wet FGD represents an a ppreciable cost to a utility due to high associated capital cost s but the technology is techni cally sound and operational risks associated with the technology have decrea sed with continued ope rating experience and technology development. Although wet FGD is typically employed for SO 2 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 un it. Furthermore, evaluation of coal and process data from the EPA ICR database indicates that plants configured with we t FGD achieve high levels of selenium removal from the flue gas.

A wet FGD system may be appr opriate for the removal of SO 2 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, par ticularly those employing SCR for NO x control, high levels (70 – 90%) of mercury removal might be expect ed across a wet FGD system. For units firing Western sub-bituminous coal that typically produ ce 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 natu ral tendency of fabric filters to oxidize mercury thus enhancing overall syst em removal; this effect is even greater when employing activated carbon injection upstream of the fabric filter resu lting in most of the mercury that is not removed across the fabric fi lter getting removed across the FGD absorber.

Despite being effective at removing oxidized fo rms of mercury from flue gas, some wet FGD absorbers have experienced mercury re-e missions 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 ga s. Mercury re-emissions are not well understood at this time but are believed to be imp acted 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 comple x 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; limest one 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; bypa ss 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 si gnificant engineering effort and appreciable footprint at the plant site. Capital costs will be affected by the size of the bo iler, type of fuel fired, required removal efficiency, solids dewatering appro ach, 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, c onstruction, and general facilities that are not accounted for in the above range. Fixed O&M costs can range from appr oximately $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 fact ors such as delivered reagent costs, byproduct transport and disposal costs, water and wastewater costs, a nd auxiliary power consumption costs; these costs can be offset by revenues asso ciated 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 SO 2 : High-performance FGD scrubbers can achieve 95 – 99% SO 2 removal.

o HCl: Most well-performing wet FGD units are able to achieve hydrogen halide removal rates equal to or gr eater than the respective SO 2 removal rate.

o PM: High-efficiency FGD units can t ypically remove up to 50-70% of the particulate material entering th e 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; elementa l 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, insta llation, 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 precipitat ors (WESPs) have been used in many industries for the effective control of sulfuric acid and PM for ove r 100 years. However, only in the past several years has the WESP been considered practical an d necessary for utility applications. WESPs have been considered and employed on the utili ty scale in order to reduce ultra-fine and condensable PM, including acid mist removal dow nstream of a wet scrubber. Although utility applications of WESP are fairly new, they ha ve been shown to achieve high levels of SO 3 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 opera tion at saturation temper ature, which promotes condensation of solubl e 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 de signed to ensure uniform water film over the entire collecting area and an integral part of th e WESP design is location of water spray nozzles to allow sufficient coverage ove r the collector plates. WESPs ge nerally 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 collect ing electrodes with fabric membranes that disperse water through cap illary action. The memb rane WESP has seen installation on non-utility applicatio ns up to approximately 185 MWe.

A WESP incurs higher capital costs than its dr y 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 ga s 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 pot entially offer 20-30% cost savings over its traditional counterpart.

Operational costs of the WESP include pressu re drop typically associated with a PM collector, energizing of the collect or plates, as well as water cons umption and water discharge. There are also potential water treatment costs; however they are not included in the costs presented here. In many cases the wastew ater is sent to the FGD reaction tank.

• Technology Maturity: mature; 100+ years of oper ating 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 uni t 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.