Unit ed S t at es EPA-600/R-03-110 E n vironment al P r ot ect i on October 2003 A gency 

# Research and Development

Performance and Cost of Mercury and Multipollutant Emission Control Technology Applications on Electric Utility Boilers



# Prepared for

Office of Research and Development



# Prepared by National Risk Management Research Laboratory Research Triangle Park, NC 27711EPA-600/R-03/110 October 2003



# Performance and Cost of Mercury and Multipollutant Emission Control Technology Applications on Electric Utility Boilers

Prepared by:

Jam e s E. Staudt Andover Technology Partners 112 Tucker Farm Road North Andover, MA 01845
W o jciech Jozewicz ARCADIS Geraghty & Miller 4915 Prospectus Drive, Suite F Durham , NC 27713

EPA Contract No. 68-C-99-201, W o rk Assignm ent 4-028 EPA Project Officer: Ravi K. Srivastava National Risk Managem e nt Research Laboratory Research Triangle Park, NC 27711

U.S. Environm ental Protection Agency

Office of Research and Developm ent W a shington, DC 20460

## ABSTRACT

Under the Clean Air Act, as am ended, the Environm ental Protection Agency (EPA) ha s determ ined that m e rcury em issions from coal-f ired power plants should be regulated. Based on this determ ination, EPA is to propose Maxim um Achievable Control Technology Standards for these em issions by Decem ber 2003. To aid in this re gulatory effort, estim ates of the perform ance and cost of powdered activated carbon (PAC) injection-based m e rcury control technologies and
m

u ltipollutant c ont r o l t e chnologies that m ay be useful in controlling m e rcury em issions have been developed. This report presents these estim ates.

Estim ates cost range for PAC injection, based on currently available data, is 0.03-3.096
m ills/kWh. However, the higher costs are usually associated with the m i nority of plants using Spray Dryer Abs o rbers and Electrostatic Precipitators (SDAs plus ESPs) or the sm all num ber of plants using hot ESPs (ESPhs). Excluding the m i nority of plants using SDAs pl us ESPs or ESPhs, c u rrent cost estim ates are from 0.03 to 1.903 m ills/kWh. At the low end of these c o st ranges, 0.03 m ills/kWh, it is assum e d that no additional control technologie s a r e needed, but
m e rcury m onitoring will be necessary. In these cases, high m e rcury rem oval m ay be the result of the type of particulate m a tter, nitrogen oxide , and sulfur dioxide control m easures currently
em ployed, such as com b inations of ESP, selec tive catalytic reduction (S CR), and wet flue gas desulfurization (FGD) on bitum i nous coal-fired boilers.

Mul tipollutant control m e thods evaluated in this program that m ay provide cost effective
m e rcury control and control of other pollutant s include Electro Catalytic Oxidation (ECO), Advanced Dry FGD, and a coal beneficiation m e thod. ECO and Advanced Dry FGD are flue gas treatm e nt m e thods and are estim ated to have costs ranging from 3.28 to 12.33 m ills/kWhover a range of fuel types and conditions. A coal beneficiation m e thod called K-Fuel was shown to provide about 60% or greater reduction in m e rcury from Powder River Basin coal on a heating value basis. Based on this work, it is expected that f u ture ef f o rts in R&D are likely to f o cus on im proved understanding of m e rcury speciation across SCRs l eading to beneficial effects of com b inations of SCR wi t h we tFGD and developing sorbents that can im prove perform ance and cost of sorbent-based m e rcury control technologies. Multipollutant cont rol technologies, which are m o re c o s t l yth ans i ngl e
- pol l u t antme r c ury c ontr o l t echnologies but offer other envi r onme n t a l be ne fi t s , will be another area f o r f urther developm ent that could im prove the cost of reducing em issions from coal-fired power plants. Finally, rem ovi ng m e rcury from the coal, along with other fuel quality im provem e nts, m ay prove to be a very cost ef f ective approach f o r reducing em issions.

ii

## Foreword
The U.S. Environmental Protection Agen cy (EPA) is charged by Congress with protecting the Nation’s land, air, and wat e r resources. Under a mandate of national environmental laws, the Agency strives to formulate and im plement actions leading to a compatible balance between human activities and the ability of natur al systems to support and nurture life. To meet this mandate, EPA’s research program is providing data and technic a l s u pport for solving environment al problems today and building a science knowledge base necessary to manage our ec ological resources wisely, understand how pollutants affect our health, and prevent or reduce environmental risks in the future. The National Risk Management Research Laborat ory (NRMRL) is the Agency’s center for investigation of technological and management approaches for preventing and reducing risks from pollution that threat en human health and the environment. The focus of the Laboratory’s research program is on methods and their cost-effectiveness for prevention and control of pollution to air, land, water, and subsurface resources; protection of water quality in public water syst em s; rem ediation of contaminated sites, sediments, and ground water; prevention and control of indoor air pollution; and restoration of ecosystems. NRMRL collaborates with both pub lic and private sector partners to foster technologies that reduce the cost of co mplianc e and to anticipate emerging problems. NRMRL’s research provides solutions to environmental problems by: developing and promoting technologies t hat pr ot ect and im pr ove t he envir onm ent ; advancing scientific and engineering information to support regulatory and policy decisions; and providing the technical support and information transfer to ensure implementat ion of environmental regulations and strategies at the nat ional, state, and community levels. This publication has been produced as part of the Labor atory’s strategic long-term research plan. It is published and made ava ilable by EPA’s Office of Resear ch and Development to assist the user communityand to link researchers with their clients.

Hugh W. McKinnon, Director National Risk Management Research Laboratory

EPA REVIEW NOTICE
This report has been peer and administratively reviewed by the U.S. Environmental Protection Agency and approved for publ i c ati on. Menti on of trade names or commercial products does not constitute endorsement or recommendation for use. This document is available to the public through the National Te c h n i c a l Information Service, Springfield, Virginia 22161.

iii

## ACKNOWLEDGMENTS

The authors would like to acknowledge the m any c ontributors to this docum ent, without whose efforts this report would not be com p lete. In particular, we wish to acknowledge the technical guidance and insights provided by Dr. Ravi Sriv astava of EPA’s National Risk Managem e nt Research Laboratory, Office of Research and Developm ent. Th e authors also appreciate m a ny helpful discussions with vendors of control technologies discussed in this docum ent.

iv

## TABLE OF CONTENTS

Section Page Ab s tr a c t

................................................................ i i F o r e w o r d

.............................................................. i i i Acknowledgm ents ........................................................i v L i s t o f F i g ur e s

.......................................................... v i i L i s t o f T ab l e s

.......................................................... v i i i List of Acronym s and Abbreviations

.......................................... x

1.0 Introduction

....................................................... 1 2

. 0 M e r c ury S p e c i a t i o n an d C ap tur e

....................................... 5 3.0 Mercury Control with Existing Technologies

............................. 7 3

. 1 M e r c ury R e m o v a l i n P M E qu i p m e n t

.............................. 8 3.2 Im pacts of NO X C o n tr o l s o n M e r c ury S p e c i a t i o n an d C ap tur e

.......... 9 3.2.1 SCR Im pact on Mercury Speciation

........................ 9 3.2.2 Mercury Rem oval Though Com bustion NO X C o n tr o l s

......... 1 5 3.3 Mercury Rem oval in SO 2 C o n tr o l E qu i p m e n t

...................... 1 6 3.3.1 Mercury Rem oval in W e t FGD

........................... 1 6 3.3.2 Mercury Rem oval in SDA

............................... 1 7 3

. 4 M e r c ury R e m o v a l i n O th e r C o n tr o l D e v i c e s

....................... 1 8 3

. 5 M o d e l s o f M e r c ury R e m o v a l b y E x i s t i n g E qu i p m e n t

................ 1 8 4.0 Em erging Control Technologies

...................................... 2 1 4.1 PAC Injection-Based Technologies

.............................. 2 1 4.1.1 Mercury Rem oval Models

............................... 2 2 4.1.2 Mercury Reduction by PAC Injection

...................... 2 3 4.2 Em erging Control Technologies

................................ 2 5 4.2.1 Electro Catalytic Oxidation (ECO

......................... 2 6 4.2.2 Advanced Dry FGD

.................................... 3 2 4.2.3 K-Fuel

.............................................. 3 8 5.0 Technologies Currently under Developm ent

............................. 4 3 5.1 Oxidation Technologies

....................................... 4 3 5.2 Sorbent Technologies

........................................ 4 4

v5.3 Other Technologies

.......................................... 4 6 6

. 0 C o s t s o f R e d u c i n g M e r c ury E m i s s i o n s

................................. 4 9 6

. 1 M e r c ury an d M u l t i p o l l u t an t C o n tr o l C o s t M o d e l s

.................. 4 9 6

. 2 F u e l T yp e s , P l an t C h ar a c t e r i s t i c s , an d M o d e l P l an t C a s e s

............ 5 3 6

. 3 C o s t M o d e l R e s u l t s

.......................................... 5 7 6.3.1 High Sulfur Bitum i nous Coals (Model Plants 1-10, 26-28)

..... 5 7 6.3.2 Low Sulfur Bitum i nous Coals

............................ 6 6 6.3.3 Low Sulfur Subbitum i nous Coals including Powder River B a s i n C o a l s

.......................................... 7 1 6

. 4 C o s t I m p a c t s o f S e l e c t e d V ar i ab l e s

.............................. 8 0 6

. 5 S umm ary o f M e r c ury an d M u l t i p o l l u t an t C o n tr o l C o s t s

.............. 8 6 7

. 0 S umm ary
........................................................ 8 9 8

. 0 R e f e r e n c e s

....................................................... 9 1
Appendices

A Appendix A Description of Mercury and Multipollutant Control Perform ance
an d C o s t M o d e l

.................................................. A

- 1 B D escription of PAC Injection Algorithm s Used in the Mercury and M u l t i p o l l u t an t C o n tr o l P e r f o rm an c e an d C o s t M o d e l

..................... B

- 1 C S umm ary o f M e r c ury C o n tr o l C a s e s A n a l y z e d

.......................... C

- 1 D R e s u l t s o f M o d e l R un s

............................................. D

- 1

vi

## LIST OF FIGURES

Figure Page 1. Mercury oxidation without a catalyst as a function of residence tim e, gas t e m p e r a tur e , an d H C l c o n t e n t

........................................ 1 0 2. Mercury oxidation across SCR catal ysts and without SCR catalyst

........... 1 1 3

. O x i d a t i o n o f m e r c ury a c r o s s C

- 1 S C R c a t a l y s t i n P RB

- d e r i v e d f l u e g a s

....... 1 2 4. Effect of flue gas exposure tim e on C-1 SCR catalyst oxidation of elem ental

m e rcury at 700 °F and space velocity of 1,450 hr S 1

........................ 1 2 5

. L o c a t i o n o f E C O i n s t a l l a t i o n i n a p o w e r p l an t

........................... 2 6 6

. D e t a i l e d p r o c e s s f l o w d i a g r a m o f E C O

................................. 2 7 7. ECO power consum ption versus NO X .................................. 3 1 8

. F

. L

. S m i dth A i rt e c h A i r T e c h G a s - S o l i d s Ab s o r b e r ( G S A )

. ................. 3 3 9

. I n s t a l l a t i o n o f an a dv an c e d dry F G D u p s tr e a m o f an e x i s t i n g E S P

............ 3 3 1 0

. I n s t a l l a t i o n o f an a dv an c e d dry F G D d o w n s tr e a m o f an e x i s t i n g E S P

......... 3 4 11. Advanced dry scrubber SO 2 r e m o v a l p e r f o rm an c e

........................ 3 5 12 Advanced dry scrubber perform ance

................................... 3 5 1 3

. O v e r a l l s c h e m a t i c o f K

- F u e l p r o c e s s i n g p l an t

............................ 3 9 1 4

. K

- F u e l th e rm a l p r o c e s s i n g p l an t

...................................... 3 9 15. SO 2 and NO X e m i s s i o n s f r o m t e s t b urn s o f K

- F u e l an d un tr e a t e d f u e l s

........ 4 0 1 6

. E s t i m a t e d E f f e c t o f K

- F u e l C o s t o n G e n e r a t i o n C o s t

. ...................... 7 7 17. Cost of PAC Injection for 500 MW Coal Fired Boilers with existing E S P c o r F F

....................................................... 8 1 18. Cost of PAC Injection for 500 MW Coal Fired Boilers with Existing E S P c

— E f f e c t o f M e d i um V e r s u s H i g h P e r f o rm an c e P A C

.................. 8 2 19. Effect of Capital Cost on 90 Percent Mercury Control with PAC on Boiler

w i th E x i s t i n g E S P c an d R e tr o f i t o f D o w n s tr e a m P J F F

. .................... 8 3 20. Ef f ect of Fertilizer Value on Cost of Em issions Control with ECO on a 500 MW Bitum i nous Coal Boiler

..................................... 8 4 21. Effect of Power Value on Cost of Em issions Control with ECO on a 500 MW Bitum i nous Coal Boiler

..................................... 8 5 22. Effect of Reagent Cost on Cost of Em issions Control with Advanced Dry FGD on a 500 MW Boiler Firing Low Sulfur Bitum i nous Coal

.............. 8 5

vii

## LIST OF TABLES

Table Page 1. Average Mercury Capture by Existing Post-Com bustion Control C o n f i g ur a t i o n s U s e d f o r P C

- F i r e d B o i l e r s

............................... 7 2

. S umm ary o f R e s u l t s f r o m F u l l

- S c a l e S C R M e r c ury O x i d a t i o n T e s t s

.......... 1 4 3a. P aram eters Used for Equations 1 and 2 Wh ich Estim ate Mercury Rem oval b y E x i s t i n g E qu i p m e n t

.............................................. 1 9 3b. Param e ters Used for Equations 1 and 2 Wh ich Estim ate Percent of R e m a i n i n g M e r c ury i n G a s th a t I s E l e m e n t a l M e r c ury
..................... 2 0 4

. E C O P o l l u t an t R e m o v a l E f f i c i e n c i e s

................................... 3 0 5. Estim ated Cost of CFB-FGD System for a 500 MW Plant Burning PRB Coal

. . 38 6

. C o m p ar i s o n o f T yp i c a l P RB C o a l w i th K

- F u e l

........................... 4 1 7

. F u e l s U s e d I n M o d e l P l an t A n a l y s i s

................................... 5 4 8

. P o w e r P l an t C h ar a c t e r i s t i c s

.......................................... 5 5 9. Mercury Control Technology Applications and Co-benefits

................ 5 6 10a. H igh Sulfur Coal, ESP plus FGD W ithout SCR Co-benefit (Model Plants 1, 6)

. 5 9 10b. High Sulfur Coal, ESP plus FGD W ith SCR Co-benefit (Model Plants 1, 6)

.... 6 0 11a. H igh Sulfur Coal, ESPh plus FGD W ithout SCR Co-benefit (Model Plants 3, 8) 61 11b. High Sulfur Coal, ESPh plus FGD with SCR Co-benefit (Model Plants 3, 8)

. . . 61 12. Advanced Dry FGD on High Sulf ur Coal (Model Plants 4, 9), Sensitivity t o C ap i t a l C o s t

.................................................... 6 2 13. ESP and ECO on High Sulf ur Coal (Model Plants 5 and 10), Sensitivity t o C ap i t a l C o s t

.................................................... 6 3 14. High Sulfur Coal, 100 MW SDA, and ESPc (Model Plant 26)

............... 6 4 15. High Sulfur Coal, 100 MW SDA, and FF (Model Plant 27)

................. 6 5 16. High Sulfur Coal, 100 MW ESPh, and FGD (Model Plant 28)

............... 6 6 17. Low Sulfur Coal, ESPc, and No SO 2 C o n tr o l s ( M o d e l P l an t s 1 1 an d 2 9 )

...... 6 7 18. Low Sulfur Coal, FF, and No SO 2 C o n tr o l s ( M o d e l P l an t s 1 2 an d 3 0 )

......... 6 8 19. Low Sulfur Coal, ESPh, and No SO 2 C o n tr o l s ( M o d e l P l an t s 1 3 an d 3 1 )

...... 6 9 20. ECO Installed After Particulate Rem oval (Model Plants 14



### S 16, 32



### S 34), Sensitivity to Capital Cost

........................................... 7 0 21. Advanced Dry FGD (Model Plants 17



### S 19, 35



### S 37), Sensitivity to Capital Cost

. . 71

viii22. Low Sulfur Subbitum i nous Coals, ESPc, and No SO 2 Control (Model Plants 20, 38)

..................................................... 7 3 23. Low Sulfur Subbitum i nous Coals, FF, and No SO 2 Control (Model Plants 21, 39)

..................................................... 7 4 24. Low Sulfur Subbitum i nous Coals, ESPh, and No SO 2 Controls (Model Plants 22, 40)

..................................................... 7 5 25. Low Sulfur Subbitum i nous Coals with ECO (Model Plants 23



### S 25, 41



### S 43) Sensitivity to Capital Cost

........................................... 7 6 26. Com p arison of Estim ated Mercury Em issions from PRB and K-Fuel Boilers Equipped with Particulate Control and No Additional Mercury or SO 2 Controls

. 7 7 27. K-Fuel, ESPc and No SO 2 Control (Model Plants 44, 47)

.................. 7 8 28. K-Fuel, FF, and No SO 2 Control (Model Plants 45, 48)

.................... 7 9 29. K-Fuel, ESPh, and No SO 2 Controls (Model Plants 46, 49)

................. 8 0 3 0

. E s t i m a t e d C o s t o f M e r c ury C o n tr o l

— C urr e n t an d P o t e n t i a l C o s t E s t i m a t e s

.... 8 7 3 1

. E s t i m a t e d C o s t s o f M u l t i p o l l u t an t C o n tr o l s

............................. 8 8

ix

## LIST OF ACRONYMS AND ABBREVIATIONS

ACRONYM DEFINITION ADP acid dew point ATS approach to saturation CAAA Clean Air Act Am endm ents of 1990 CEMS continuous em ission m onitoring system COHPAC com p act hybrid particulate collector CRF capital recovery factor ECO e lectro catalytic oxidation EPA U .S. Environm ental Protection Agency ESP e lectrostatic precipitator ESPc cold-side electrostatic precipitator ESPh hot-side electrostatic precipitator FF f abric f ilter FGD f lue gas desulf urization GSA g as suspension absorber HCl hydrogen chloride Hg m e rcury HgCl 2 m e rcuric chloride Hg 0 elem ental m e rcury Hg ++ oxidized m e rcury Hg p particle-bound m e rcury Hg T total m e rcury HgO m ercury oxide ICR i nform a tion collection request IPM i ntegrated planning m odel kWh k ilowatt hour LOI l oss of ignition LNB l ow NO Xburner LSFO lim estone forced oxidation MACT m a xim um achievable control technology MEL m agnesium enhanced lim e MW m e gawatt MW Cs m unicipal waste com bustors NETL National Energy Technology Laboratory

x

## LIST OF ACRONYMS AND ABBREVIATIONS (continued)

ACRONYM DEFINITION NO X oxides of nitrogen OAR EPA’s Office of Air and Radiation OFA overfire air OH Ontario Hydro O&M operation and m a intenance PAC powdered activated carbon PC pulverized coal PFF polishing f abric f ilter PJFF pulse jet f abric f ilter PM particulate m a tter PPPP Pleasant Prairie Power Plant PRB P owder River basin PS particle scrubber RGFF reverse-gas f abric f ilter RAP r apid absorption process R&D r esearch and developm ent SC spray cooling SCR s elective catalytic reduction SDA s pray dryer absorber SNCR selective noncatalytic reduction SO 2 sulfur dioxide TCLP toxicity characteristic leaching procedure UBC unburned carbon W E SP wet electrostatic precipitator

xi

## 1.0 I NTRODUCTION

In the atm o sphere, m e rcury exists in two f o rm s: elem ental m e rcu r y

v a p o r ( H g 0 ) and ionic m e rcury (Hg ++ ). Hg 0 can circulate in the atm o sphere for up to one year and, consequently, can undergo dispersion ove rr e gi ona l and global scales. Hg ++ in the atm o sphere either is bound to airborne particles or exists in gaseous form . This form of m e rcury is readily rem oved from the atm o sphere by wet and dry deposition. After deposition, m e rcury is comm onl y r e -em itted back to the atm o sphere as either a gas or a constituent of particles and redeposited elsewhere. In this f a shion,

m e rcury cycles in the environm ent. 1

A num ber of hum an health and environm ental im p acts are associated with exposure to m e rcury. Mercury is known to bio-accum u late in fish and anim al tissue i n i t s m o st toxic form , m e thylm e rcury. Hum a n exposure to m e thylm e rcury has been associated wi th s e r i ous neurological and developm ental effects. Adults exposed to m e thylm e rcury show sym p tom s of trem ors, loss of coordination, and m e m o ry and sensory dif f i cu lties. Of f

s pring exposed during pregnancy show atrophy of the brain with delayed m e ntal developm ent. The incidence and extent of such effects depend on the level of exposure to m e thylm e rcury. Hg 0 is readily absorbed through lungs and, being fat-soluble, is rapidly distributed throughout the body. Subsequently, it slowly oxidizes to Hg ++ , which accum u lates in the brain an d can lead to trem o r s , m e m o ryd i s t ur

b an ces , s e n s o r ylo ss, and personality changes. Hg ++ i s ab s o r b e d through the digestive tract, accum u lates in the kidneys, and can lead to imm une-m ediated kidney toxicity. Adverse effects of m e rcury on fish, birds, and

m a mm a ls include reduced reproductive success, im paired grow th, behavioral abnorm a lities, and even death. Detail s of t h e risks associated w ith exposure to m e rcury are discussed in the literature. 1 A severe case of hum an exposure occurred in Minam a ta, Japan in the 1950s. 2

Under th e Clean Air Act as am ended the Envir onm ental Protection Agency (EPA) has determ ined that m e rcury em issions f r om coal-fir ed power plants should be regulated. 3 Based on this determ ination, EPA is to propose Maxim um Achievable Control Technology (MACT) Standards f o r these em issions by Decem ber 2003. To aid in this re gulatory effort, this report has been prepared as an update of a previ ous report (EPA 600/R-00-083) 4 that presented prelim inary estim ates of the perform ance and cost of prom ising m e rcury control technologies applicable to coal-fired electric utility boilers. Although m o st of these technologies are based on injection of powdered activated carbon (PAC) into boiler flue gas, additional technologies that offer prom ise in control of m e rcury and other pollutants are also discussed in this report.

1The report layout is as follows. First, the gene ral principles of m e rcury speciation and capture are discussed. Second, m e rcury rem o va l by e x i s t i ng e qui pme n ton c o a l

- f i r e d boi l e r s i s discussed. Third, pr omi s i ng me r c ury control technologies for coal-fired electric utility boilers are identified,

a nd t h e perform ance characteristics of thes e technologies are estim ated. These include characterization of m e rcury rem oval perform ance possible as a function of various param e ters. Fourth , m o d e l p l ants r e presenting the spectrum of retrof it possibilities are identif ied and a m a trix of

cases to be studied is developed. Next, costs of controlling m e rcury em issions f r om these m odel plants with the technologies of interest are exam ined. Finally, potential future im provem e nts in these costs are discussed. During discussion of cost and potential im provem e nts, research and developm ent (R&D) areas are identified for near-term em phasis.

Two m u ltipollutant air pollution control technol ogi e s we r ee v a l uat e d a s we l la s a c o a l be ne fi c i at i o n technology that offers pollution control advant ages. The two air pollution control technologies include electro cat al yt i c oxi dat i on (ECO) and advanced dry flue gas desulfurization (FGD). ECO is a unique technology w ithout any f u ll-scale co mm e rcial experience on utility boilers. However,

com m e rcial-scale dem onstrations are being built, and this technology has been studied extensively by the U.S. utility industry and the Departm e nt of Energy 5 . So, results are presented her e for ECO technology; however, they should be considered prelim inary. Advanced Dry FGD has extensive

e xpe r i e n c e i n wa s t e i n c i ne r a t i on a ppl i cations and som elimited com m e rcial experience on coal

- f i r e d boilers. Moreover, advanced dry FGD is sim ilar in m any respects to spray dryer absorber (SDA) technology—a well established sulfur dioxide (SO 2 ) control technology used on utility boilers. However, data regarding the control of m e rcury using this technology is lim ited, so the results presented here m ay be prelim inary with regard to m e rcury control but are expected to be m o re reliable with regard to control of SO 2 and particulate m a tter (PM) and with respect to cost. Coal beneficiation through the K-Fuel process has been dem onstrated on the pilot scale, and the first

comm e rcial plant f o r coal benef i ciation through the K

- Fuel process is planned. In addition to enhancing coal heating value for low-rank fuels, this process can reduce the content of m e rcury, sulf ur, and nitrogen in the c o a l , p r o v i d i n gm u ltipollutant benef its. The costs are estim ated in term s of increased fuel cost.
Use of sorbent injection technologies to contro l m e rcury em issions from electric power plants would result in m e rcury-im pregnated sorbent waste, which would need to be disposed of either by itself or in m i xture with flyash. One of the m o re com m only practiced solid waste disposal options is landfilling. However, there is lim ited inform ati on available on the stability of m e rcury in ash and sorbent residue. Therefore, it is unclear whether any potential exists for the release o f m e rcu r y back into the environm ent from landf illed m e rcury-im pregnated solid waste. Further research

2is needed on ash and sorbent residue to evaluate m e rcury retention and the potential for release back into the environm ent. Due to lack of in form ation, this report does not address any potential costs that m ay result if m e rcury has to be stabilized in sorbent waste.

34

## 2.0 M ERCURY SPECIATION AND CAPTURE

Mercury is volatilized and converted to H g 0in the high tem p erature regions of com bustion devices. As the flue gas cools, Hg 0 is oxidized to Hg ++ . The rate of oxi di z a t i on i s dependent on the tem p erature, f lue gas com position and properties, and am ount of flyash and any entrained sorbents. I n

c o al-fired com bustors, where the concentrati ons of hydroge n c h l o r i de ( H Cl ) ar e l o w, and whe r e equilibrium conditions are not achieved, H g 0 m ay be oxidized to m e rc ur ic oxide (HgO), m e rcuric sulfate (HgSO 4 ), m e rcuric chloride (HgCl 2 ), or som e other m e rcury com pound. 6 The oxidization of Hg 0 to HgCl 2 and t o othe r i oni c form s of mercury is abetted by catalytic reactions on the surface of flyash or sorbents and by other com pounds that m ay be present in the flue gas. Applications of nitrogen oxides (NO X ) control technologies such as selective catalytic reduction (SCR) can assist in oxidation of Hg 0

. Hg 0 , HgCl 2 , and HgO are prim arily in the vapor phase at flue gas cleaning tem p eratures. There f or e , each of these form s of m e rcury can potentially be adsorbed onto porous solids such as fl yash, PAC, and other sorbents for subsequent collection in a PM control device. These m e rcury form s m a y also be captured in carbon bed filters or other reactors containing appropriate sorbents.
Mercury rem oval with wet scrubbers also appears to be possible. H g C l 2 is water-soluble and reacts

r e a d i l y wi t h

a l ka l i me t a l oxi de s i n a

n

a c i d- ba s er e a c t i on; t h e r e f or e , conventional acid gas scrubbe r s used for SO 2 control can also effectively capture HgCl 2 . However, Hg 0 is insoluble in water and

m

u st be adsorbed onto a sorbent or converted to a soluble form of m e rcury that can be collected by wet scrubbing. HgO has low solubility and probably has to be collected by m e thods sim ilar to those used for Hg 0 . Therefore, the form of m e rcury that is m o st easily rem oved is HgCl 2, and t h i s f

o r

m

o f m e r c u r y

i s

m o s t r e a d i l y f

o r

m e d wh e n burning coals that are hi gher in chlorine content, such as Eastern bitum i nous coals. Furtherm ore, as will be described in Sections 3.1 and 3.2, the equipm ent on the boiler also plays an im portant role in determ ining m e rcury speciation. For this

r e a s on coal type, coal chlorine content, and th e boiler equipm ent all play a significantr o l e i n determ ining the ease with which m e rcury can be rem oved from co a l c o m bustion flue gas stream s.

The fol l o wi ng se c tions will describe m e rcury rem oval technol ogi e s pert i n e nt t o c o a l

- f i r e d boi l e r s

. For m any technologies described in the following sections, the coal properties and the existing equipm ent on the boiler will have an im pact on th e total m e rcury rem oval when that f acility is retrofitted with m e rcury rem oval equipm ent. This is because m e rcury speciation is im portant in

5determ ining the ease or difficulty of rem oving m e rcury from the exhaust gas. Additionally, fuel and the equipm ent used in the f acility play role in determ ining the m e rcury speciation.

6

## 3.0 M ERCURY CONTROL WITH EXISTING TECHNOLOGIES

Data derived from an EPA Inform ation Collecti on Request (ICR) showed that m e rcury released from coal com bustion m a y be partly rem oved from the exhaust gases by existing equipm ent without

a ddi t i ona l retrofit technology. 7 This chapter discusses the m e rcury control achieve d wi the xi s t i ng technologies utilized for control of PM, NO X , and SO 2 em issions at electric utility coal-f ired boilers.

Tabl e 1 shows t h e average re duction in total m e rcury (Hg T ) em issions fromICR data for coal-boilerc ont rol classes that burn pulverized coal (PC). Pl ants that em ploy only post-com bustion PM controls display class average Hg T em ission reductions ranging from 1 to 90 percent. Units with f abric f ilters (FFs) obtain the highest average levels of control. Decreasing average levels of control are generally observed for units equipped with a cold -side electrostatic precipitator (ESPc), hot-side ESP (ESPh), and particle scrubber (PS). For units equipped with dry scrubbers, the class average Hg T em ission reductions ranged from 2 to 98 percen t. The estim ated class average reductions for wet FGD scrubbers were sim ilar and ranged from 10 to 98 percent.

Table 1. Average Mercury Capture, in Percent, b y Existing Post-Combustion Control Configurations Used for PC-Fired Boilers. 8

Post-Combustion Control Strategy Post-Combustion Emission Control Device Configuration Coal Burned in PC-Fired Boiler Unit

Bituminous Subbituminous Lignite

PM Control Only ESPc 36 9 1 ESPh 14 7 not tested FF 90 72 not tested PS not tested 9 not tested
PM Control and SDA SDA+ESP not tested 43 not tested SDA+FF 98 25 2 SDA+FF+SCR 9 8 not tested not tested

PM Control and Wet FGD System a PS+FGD 1 2 1 0 not tested ESPc+FGD 81 29 48 ESPh+FGD 46 20 not tested FF+FGD 9 8 not tested not tested

a Estimated capture ac ross both control devices

7For PC-fired boi l e r s , the am ount of Hg capture d by a given control technology is greater for bitum i nous coal than for either subbitum i nous co al or lignite. For exam ple, the average capture of Hg, based on Ontario Hydro (O H ) inlet m easurem en ts in P C -f ired plants equipped with an ESPc, is 36 percent for bitum i nous coal, 9 percent for subbitum i nous coal, and 1 percent for lignite.



### 3.1 M ercuryRemoval in PM Control Equipment

Approxim a tely 77 percent of the coal-f ired utilityb o ile r s c ur r e ntly operating in the United States are equipped with only an ESP or an FF. Gaseous m e rcury (both Hg 0 and Hg ++ ) can potentially be adsorbed on fly ash and be collected in a downstream ESP or FF. The m odern ESPs and FFs that are now used on m o st coal-fired units achieve very high capture efficiencies for total PM. As a consequence, these PM control devices are also effective in capturing PM-bound m e rcury (Hg p ) in the boiler flue gases.
The degree to which m e rcury can be adsorbed onto fly ash for subsequent capture in PM control is dependent on the speciation of m e rcury, the fl ue gas concentration of fly ash, the properties of fly ash and the tem p erature of the f l ue gas in the PM control device. It is currently believed that m e rcury is prim arily adsorbed onto the unbur ned carbon in fly ash. Approxim ately 80 percent of the coal ash in PC-fir ed boilers is entrained with the f l ue gas as f l y ash. PC-f ired boilers with low-NO X burners have higher levels of carbon in the fly ash with a corres pondingly higher potential for m e rcury adsorption. Cyclone and stoker boilers tend to have high levels of carbon in the fly ash but have lower flue gas concentrations of fl y a s h than PC-fired boilers. Fly ash concentrations in fluidized-bed com bustors t e nd t o be higher than those in PC-fired boilers. Also, the carbon content of fluidized-bed com bustor fly ash is generally higher than that of PC-boiler fly ash.
Gas-phase m e rcury in units equipped with an ESP can be adsorbed on the entrained fly ash upstream of the ESP. The gas-phase m e rcury in units equi pped with a FF can be adsorbed by entrained fly ash or it can be adsorbed as the flue gas pa sses through the filter cake on the surface of the FF. The degree to which gaseous m e rcury adsorbs on the f ilter cake ty p i c a lly depends on the speciation of gaseous m e rcury in the flue gas; in general, gaseous Hg ++ is easier to adsorb than gaseous Hg 0

. The very intim ate contact between the gas and coll ected PM (which can act as a sorbent for the gas-phase m e rcury) that occurs in a FF signifi cantly enhances the gas-phase m e rcury collection efficiency of the FF over what is possible with an ESP. As i ndi c at e d i n Ta ble 1, the ICR data showed that, for both bitum i nous and subbitum i nous coals, m e rcury collection in boilers equipped only with FFs is m u ch higher than f o r boilers equippe d only with ESPs. As will be shown later in this

8docum ent, this effect also contributes to m u chm o re efficient collection of m e rcury when PAC is injected for additional m e rcury control upstream of a FF as opposed to injection upstream of an ESP. New hybr i d ESP-FF technologies, such as the Com b ined Hybrid Particle Collector (COHPAC), offer ways to cost-effectively retrof it ESP’s with FF and realize this benef it. The COHPAC approach also offers the benefit enab ling segregation of injected PAC from m u ch of the collected fly ash.
ICR data reflected that plants which em ploy only post-com bustion PM controls display average Hg em ission reductions ranging fr om 0 percent to 89 percent. 8 The highest levels of control were observe d for units with FFs. Decreasing levels of control were shown for units with ESPs, particulate scrubbers, and m echanical collectors. The average m e rcury reduction for two PC-fired units equipped with a FF baghouse and burning bitum i nous coal averaged 90 percent while two sim ilarly equipped units burning subbitum i nous co als displayed an average m e rcury reduction of 72 percent. The average capture of Hg for PC-fired plants equipped w ith an ESPc was 35 percent for bitum i nous coal, 3 percent for subbitum i nous coal, and near zero for lignite.



### 3.2 I mpacts of NO X 

### Controls on MercurySpeciation and Capture

Several NO Xcontrol technologies, including low NO Xburners (LNBs), overfire air (OFA), reburning, selective noncatalytic reduction (SNCR), and SCR, are em ployed at utility coal-fired boilers to control NO Xem issions. Of these control technologies, SCR ha s an im pact on the speciation of m e rcury in flue gas and, therefore, subsequent capture in wet FGD system s. Based on recent data, com bustion controls su ch as L N B s , O F A, and reburning m a y also have the potential to increase m e rcury capture in flyash. The eff ects of SCR and com bustion controls on m e rcury capture are described in the following sections.

3.2.1 S CR Impact on MercurySpeciation
The speciation of m e rcury is known to have a significant im pact on the ability of air pollution control equipm ent to capture it. In particular, the oxidized form of m e rcury, m e rcuric chloride (HgCl 2 ), is highly water-soluble and is, therefore, eas ier to capture in wet FGD system s than the elem ental form of m e rcury which is not water-soluble. SCR catal ys t s c a n a c t t o oxi di z ea s i gnificant portion of the elem ental m e rcury, which m a kes it easier to rem ove in downstream wet FGD.

9The results of studies have suggested that oxi dation of elem ental m e rcury by SCR catalyst m a y be affected by 9

S 12

• T he space velocity of the catalyst

• T he tem p erature of the reaction

• T he concentration of amm onia

• T he age of the catalyst

• T he concentration of Cl in the gas stream

Te s t s on a l a bor at or y c o mbus t o r ha s s hown t h at me r c ury oxidation without a catalyst was enha nc e d with higher Cl concentration (hi gher HCl at inlet) and that oxidation increased with residence tim e and at lower tem p eratures, as shown in Figure 1. 9 Reference 9 also describes the results of laboratory tests of oxidation of m e rcury across different types of SCR catalysts. The results of these tests, shown in Figure 2, dem onstrated th at the catalyst significantly increased the am ount of elem ental m e rcury that oxidized to m e rcuric chloride.

Figure 1. Mercury oxidation without a catalyst as a function of residence time, gas temperature, and HCl content. 9

10Figure 2. Mercury oxidation across SCR catalyst unit with and without catalyst. 9

Tests of m e rcury oxidation by S CR catalyst have been conducted using sim u lated flue gas and slip-stream s f r om actual units. 10 Results showed sim ilar trends for both sim u lated flue gas and sl i p - s t r eams fr om act ualun its with the exception that the effect of increasing space velocity appeared

som e what m o re s i g n if icant with the slip stream s. Multiple catalyst types were tested with sim ilar results obtained. According to Reference 10, it was determ ined that m e rcury oxidation was in the range of about 80



### S 90 percent for fresh catalyst and space velocities in the range of 1000 hr S 1

. However, the oxidation rate falls off with incr eased space velocity such that oxidation m i ght be in the range of 30



### S 80 percent at a space velocity of 4000 hr S 1 . Apparently, the wide range of oxi da t i on pe r f orm ance at a space velocity of 4000 hr S 1 is the result of the influence of other factors—tem p erature, amm onia, and possibly othe r effects. As shown in Figure 3, Reference 10 showed that oxidat i on of me r c ury a c r os s fr e s h SCR c a t a l ys twa s r e latively higher at tem p eratures in the vicinity of 700 °F and relatively lower in th e vicinity of 800 °F. This m ay be consistent with the fact that oxidation of m e rcury to m e rcuric chloride is greater at lower tem p eratures.
The presence of amm onia, which is the NO Xreducing reagent norm a lly used in SCR system s, appeared to inhibit the oxidation of elem ental m e rcury, as reported in Reference 10. This effect appeared to be m o st pronounced with catalyst that had been exposed to boiler exhaust gases for

a num ber of m onths. A s shown in Figure 4, m e rc ury oxidation without amm onia present rem a ined between 80 and 90 percent af ter 4200 hours (about si x m onths of continuous operation) of exposure

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

Figure 4. Effect of flue gas exposure time on C-1 SCR catalyst oxidation of elemental mercury at 700 °F and space velocity of 1,450 hrS 1

. 10

12to boiler gases at a space velocity of 1450 hr S 1 . W h en exposed to 300 ppm of am m onia, fresh catalyst continued to oxidize 80 to 90 percent of the elem ental m e rcury. However, after 4200 hours of exposure, no oxidation was m easured across the cat alyst when amm onia was present, suggesting that amm onia m ay play a role in suppressing m e rcury oxidation.

Oxidation of elem ental m e rcury to m e rcuric chlo ride across an SCR catalyst, therefore, m a y be a function of space velocity, t e m p erature, amm onia concentration, and catalyst life. Other factors, such as fly ash characteristics, are also believed to play a role.
Reference 11 describes the results of a program that evaluated m e rcury oxidation across full-scale utility boiler SCR system s. A summ ary of the re sults of the tests conducted in 2001 is shown in the f i rst f our entries in Table 2. Testing was pe rf orm e d at f our coal-f ired electric utility plants having catalyst age r a ngi ng from around 2500 hours to about 8000 hours. One plant fired subbitum i nous coal, and three other plants fired Eastern bitum i nous coal. T h e test results showed high levels of m e rcury oxidation in two of the three plants firing eastern bitum i nous coal and insignificant oxi da t i o n at the other two plants (one firing bitum i nous coal and the other subbitum i nous). However, it should be noted that for both of the plants wh ere little or no m e rcury oxidation was m easured (S1 and S3), over 85 percent of th e me r c ury at the particle control device inlet was already in the non-elem ental form . For the one bitum i nous coal-f ired plant with low

m e rcury oxidation (S3), over 50 percent of the m e rcur y at the SCR inlet was already in the oxidized form . At the plant firing subbitum i nous coal (S 1), m e rcury oxidation was fairly low. But , due to the high carbon in that plant’s fly ash, it is believed that the elem ental m e rcury was adsorbed onto the ash, resulting in high particulate m e rcury levels. Finally, in contrast with the findings of Reference 10, am m onia appeared to have little or no effect on m e rcury oxidation on the s e actual, f u ll-scale f acilities.
Subsequent tests on sister units at those plants and at other plants are shown in the second four entries in Table 2. All of the units fired bitum i nous coal and showed that m e rcury oxidation was generally enhanced to high levels of oxidized m e rcury at the SCR outlet. In each case where a scrubber was installed, the m e rcury rem oval was high. For the unit with an ESP and no scrubber,

m e rcury rem oval was not im proved by the SCR.

13Table 2.Summary of Results from Full-Scale SCR Mercury Oxidation Tests.13aPower PlantCatalystFlue Gas Hg++Content(SCR in/out)Flue Gas Hg++Content atPM Inletwithout:with SCRTotal Hg Removalacross PM+FGDwithout:with SCREffect ofNH3on HgOxidation(SCRin/out)TypeSpace Velocity(hrS1)AgeTypeSulfurb(%)Clb(ppm)S1:650 MWcCyclone, ESPHoneycomb18008000 hrPRB0.2<60(1 OH sample)8%/18% (Unit 2)(1 OH sample each)5%:8%(1 OH sample each)60%:65% (withinexperimental error)No effectS2:1360 MWcWall, ESP+FGD(MELd)Plate21253.5monthsOHbit.3.91640(2 OH samples)48%/91%no effect of alkaliinjection (Unit 1)(2 OH samples each)73%:97%(2 OH samples each)51%:88%FGD removed 94% ofHg++Not testedS3:750 MWcTangential, ESPHoneycombi39301 ozoneseasonPA bit.blend1.71150(2 OH samples)55%/65%(2 OH samples)35%/61% for 2ndcoal in sister unit77%:67% (possible filtereffect due to reactiveash)2ndcoal/sister unit nottested(2 OH samples each)16%:13% (withinexperimental error)2ndcoal/sister unit nottestedsmall neg.effect. Nottested in2ndcoal/sister unitS4:704 MWcCyclone, Lime Venturi ScrubberHoneycomb22751 ozoneseasonKY bit.2.9360(2 OH samples)9%/80%(2 OH samples each)56%:87%(2 OH samples each)46%:90%Smallnegativeeffect684 MWcWall,ESP+FGD“corregated”i3750?2monthsPA/WVbit.3.6470Oxidation to >80%(+38% net)Oxidation to 95%(+15%net) (using datafrom sister unit w/o SCR)Oxidation to >90%(+40% net)Not tested800 MWcTangential, ESPHoneycomb38002 seas.2 layersrepl.after 1stseas.KY/WVbit.11000Oxidation to >80%(+21% net)Oxidation to 89% (i0%net) (using data fromsister unit w/o SCR)No effect; actually lowerHg removal in ESP (-6%vs 23%)Not tested1360 MWcWall,ESP+FGD (MEL)Plate21252 ozoneseasonsOHbit.3.9520Oxidation to >80%(+33% net)Oxidation to >95% (didnot test w/o SCR)i85% Hg removal (didnot test w/o SCR)Not testedCyclone, LimeVenturi ScrubberHoneycomb22752 ozoneseasonsKY bit.3.1750bypass250w/SCROxidation to 60%(+20% net) (moreoxidation if 1 dataoutlier not used)Oxidation to >90%(+39% net) (Cl in coalchanged between tests)Oxidation to >90%(+47% net)Not testedCoal

14aNH3, Cl, SO3sampled at SCR outlet unless notedbBased on Energy EnvironmentalResearch Center’s analysescGross MWdMEL =magnesium-enhanced lime scrubberBench scale testing strongly suggests that HCl is an im portant exhaustgas constituent that is necessary for providing the chlorine for oxidation of Hg 0 to HgCl across the SCR catalyst. 12 This im portant result provides a scientific base for explaining the differences observed between coals in field-testing. Subbitum i nous coals tend to have lower chlorine levels and higher calcium in the ash than bitum i nous coals. Hence, they woul d be expected to produce exhaust gas with lower HCl concentrations than bitum i nous coals.
It is acknowledged that, at this point in tim e, the understanding of the effects of SCR catalyst on

m e rcury oxidation is not com p lete. There is a great d eal to learn with regard to the science of this phenom enon. However, apparently significant m e rcury oxidation by SCR catalyst occurs with bitum i nous coal, and oxidation is less certain with other coals. In this work, when evaluating this effect, it is assum e d that when bitum i nous coals are being used, 90 percent of the m e rcury after the SCR is in the non-elem ental form and is captu red by a downstream w e t F G D

. It is also assum e d that the SCR catalyst has no effect on m e rc ury oxidation when other coals are fired.

3.2.2 M ercuryRemoval Though Combustion NO XControls
The staged introduction of fuel and com bustion air is a comm on practice for reducing form ation of nitrogen oxides. This is often achieved with in the burner in LNBs and also t h r ough the use of OFA when deeper staging and greater NO Xreduction than afforded by LNBs alone is desired. Air staging reduces NO Xform ation by causing fuel-bound nitroge n to be released from the fuel at high-tem p e r a ture and fuel-rich conditions. The fuel subsequently burns out under lowertem p erature, oxygen-rich conditions to ensure high com bustion efficiency with low form ation of nitrogen oxide (N O ) . In the case of reburning (o r f u el staging), a secondary, fuel-rich com bustion zone is introduced af ter the initial com bustion zone to reduce the NO that wa s form ed in the initial

com bustion zone to nitrogen (N 2 ). A downstream burn-out zone—effectively an OFA zone after the reburn zone—provides com p lete com bustion of the reburning fuel under oxygen-rich conditions. Because all of these staged com bus tion m e thods used for m i nim i zing NO X f o rm ation result in delayed com bustion when com p ared with com bustion m e thods that do not try to m i nim i ze NO X form ation (and therefore burn the fuel only with m a xim um efficiency in m i nd), they also tend t or e duc e c o mbus t i on e ffi c i e n c y a

nd i n c r e a s e t

h e a m ount of unburned fuel—in the form of unbur ne d carbon (U B C ), also known as loss of ignition (LOI). The UBC ends up in the f l y ash that is collected in the PM control device. This carbon in the fly ash m ay act to adsorb Hg 0 and Hg ++ . Therefore, existing com bustion controls m i ght be expected to enhance rem oval of m e rcury from the exhaust gases by downstream PM collection devices.

15Com bustion of bitum i nous and low-rank (subbitum i nous and lignite) coals have been tested at pilot-scale under sim u lated air staging conditions. 14-16 In that effort, it was found that m e rcury
rem oval efficiencies by the downstream ESP im proved w ith air staging. Up to 90 percent m e rcury
rem oval was achieved with bitum i nous coals through air staging. W ith low- r ank coals, air staging im proved m e rcury rem oval f r om about 20 percent re m oval (without air staging) to about 40 percent

rem oval (with air staging). These tests c onfirm e d the expectation that com bustion NO Xcontrols can im prove the m e rcury capture by the PM control devices.



### 3.3 M ercuryRemoval in SO 2 

### Control Equipment

Both wet and dry flue gas desulfurization technol ogi e s a r e be i ng us e d i n t

h e Uni t e d St at e s t o control SO 2 em issions from coal-fired boilers. SDA is bei ng used at the m a jority of the plants em ploying dry FGD technologies. Available data reflects that som e m e rcury capture occurs in wet FGD and SDA system s.

3.3.1 M ercuryRemoval in Wet FGD
More than 20 percent of coal-fir ed utility boiler capacity in the Un ited States uses wet FGD systems to control SO 2 em issions. In such system s, a PM control device is installed upstream of the wet FGD scrubber. The PM control device used in com b ination with a wet FGD scrubber m ay be a PS, ESPc, ESPh, or a FF baghouse. W e t FGD system s rem ove gaseous SO 2 from fl ue g a s b y absorption. In wet scrubbers, gaseous species are m i xed with a liquid in which they are soluble. For SO 2 absorption, gaseous SO 2 is m i xed with a caustic slurry, typically water and lim estone or water and lim e.

Gaseous com pounds of Hg ++ are generally water-soluble and canabsorb in the aqueous slurry of a wet FGD system . However, gaseous Hg 0 is insoluble in water and therefore does not absorb in such slurries. Wh en gaseous com pounds of Hg ++ are absorbed in the liquid slurry of a wet FGD system , the dissolved species are believed to react with dissolved sulfides from the flue gas, such as H 2 S, to form m e rcuric sulfide (HgS); the HgS precipitates from the liquid solution as sludge. In the absence of sufficient sulf ides in the liquid solution, a com p eting reaction that reduces/converts dissolved H g ++ to Hg 0is believed to take place. W h en this conversion takes place, the newly form ed (insoluble) Hg 0 i s transferred to the flue gas passing through the wet FGD s y s t e m . The tr an s f e rr e d Hg 0 increases the concentration of Hg 0 in the flue gas passing through the wet FGD (since the incom i ng Hg 0 is not absorbed), thereby resulting in a higher concentration of gaseous Hg 0 in the

16f l u e g a s ex itin gth e w e t F G D co m p ared to th at ente ring. Transition m e tals in the slurry (o rig i n atin g from the flue gas) are believed to play an active role in the conversion reaction since they can act as catalysts and/or reactants for reducing oxidized species.
The capture of Hg in units equipped with wet FGD scrubbers is dependent on the relative am ount of Hg ++ in the inlet flue gas and on the PM contro l technology used. As described in Reference 8, ICR data reflected that average Hg captures in wet FGD scrubbers ranged from 23 percent for one P C -fired ESPh plus FGD unit burning subbitum i nous coal to 97 percent in a P C -f ired F F plus FGD unit burning bitum i nous coal. The high Hg cap ture in the FF plus FGD unit was attributed to increased oxidization and capture of Hg inthe FF followed by capture of any rem a ining Hg ++ in the wet scrubber.

3.3.2 M ercuryRemoval in SDA
More than 10 percent of coal-f ired utility boiler capacity in the United States uses SDA system s to control SO 2 em issions. 8 An SDA system operates by the sa m e principle as a wet FGD system using a lim e scrubbing agent, except that the flue gas is m i xed with a fine m i st of lim e slurry i n s t e a d of

a bulk liquid (as in w e t scrubbing). The SO 2 i s absorbed in the slurry and reacts with the hydrated lim e reagent to form solid calcium sulfite and calcium sulfate. The heat of the flue gas evaporates the water in the m i st leaving dry solid particles of calcium sulfite and calcium sulfate. Entrained particles (unreacted sorbent particles, reaction pr oducts, and fly ash) are captured in th e d o w n s tream PM control device (either an ESP or FF).
The perform ance of SDA system s in controlling SO 2 em issions is depende nt on the difference be t w e e n t h e SDA outlet tem p erature and the corresponding flue gas water vapor saturation tem p erature. SDA system s on coal-fired boilers typically operate about 20 °F (11 °C) above the saturation tem p erature (i.e., a 11 °C approach to saturation tem p erature). The relatively low flue gas tem p eratures afforded by SDA sys t e m s i n c r e a s e th e pot e nt i a l for m e rcury capture. The caking, or buildup, of m o ist fly ash deposits, which can plug the SDA reactor and coat downstream surfaces, dictates the m i nim um flue gas tem p eratures which can be em ployed at the outlet of SDAs.
Hg p is readily captured in SDA system s. Both Hg 0 and Hg ++ can potentially be adsorbed on fly ash, calcium sulf ite, or calcium sulf ate particles in the SDA. They can also be adsorbed and captured as the flue gas passes through the ESP or FF, whichever is used fo r PM control. In addition, gaseous Hg ++ m ay be absorbed in the slurry droplets and r eact with the calcium -based sorbents within the droplets. Nearly all of the Hg p can be captured in the downstream PM control device. If the PM

17control device is a FF, there is the potential f o r additional capture of gaseous m e rcury as the flue gas passes through the bag filter cake com posed of fly ash and dried slurry particles.

As de s c ribed in Reference 8, ICR data re fl e c t e d that units equipped with lim e spray dryer absorber scrubbers (SDA/ESP or SDA/ FF s y s t e m s ) e xhi bi t e d av e r a g e Hg c a p t

ur e s r angi ng fr om 98 percent for units burning bitum i nous coals to 3 percent for units burning subbitum i nous coal. The predom inance of Hg 0 in stack gas units that are fired with subbitum i nous coal and lignite resulted from low levels of Hg 0 oxidization.



### 3.4 M ercuryRemoval in Other Control Devices

Som e units use particulate scrubber system s, prim arily venturi scrubbers, to control PM em issions. Capture of Hg in these system s is lim ited to soluble Hg com pounds such as HgCl 2 . PS system s are typically poor collectors of fine PM, and capture of Hg p by such scrubbers m ay be poor if the Hg p in the f l ue gas is asso ciated with fine PM. Hg 0 is insoluble and will not typically be captured by the scrubber. It is possible to capture Hg ++ in the wet scrubbers, but the scrubber chem istry

an d th e m a nn e r in which the scrubber is operated will determ ine whether it is effectively rem oved,

or wh ether it is stripped, from the scr ubbing liquor. S tripping can occur if the H g ++is not adsorbed on the particles or reacted chem ically with liquid-phase reactants within the scrubber.
Mechanical collectors such as cy clones do a poor job of capturing f i ne PM, and, in general, m e rcury capture in these control devices s hould be lim ited to the capture of Hg p associated with particles larger than 10 μ m.


### 3.5 Models of MercuryRemoval byExisting Equipment

As noted in the preceding sections, t h er e are a num ber of param e ters that im pact the m e rcury
rem oval by existing equipm ent. Chlorine is wi dely acknowledged as having a role in m e rcury
rem oval. SO 2 is also expected to have a role as we ll. Fly ash characteristics and the tem p erature of t h e e x haust gas leaving the air preheater ex it have also dem onstrated a strong influence on

m e rcury rem oval. Of course, the equipm ent type plays an im portant role as well.
Expressions approxim a ting the effects of equi pm ent type, coal chlorine content, and SO 2 level

on m e rcury rem oval have been developed through statistical analysis of ICR data. 18 Data used by the Reference included equipm ent type, coal chlorine, and sulfur inform ation but not som e

18of the other param e ters expected to influence m e rcury rem oval from existing equipm ent. Since th e s e e xpressions do not include other effects expected to be significant, such as ash character i s t i c s and gas tem p erature, they should only be used for approxim a tions. These algorithm s are
Algorithm 1 (ESPc): f

existing equipm ent = C 1 × ln [(coal Cl, ppm )/(SO 2 , in lb/MMBtu)] + C 2 Eq. 1 Algorithm 2 (all other categories): f

existing equipm ent = C 1 × ln (coal Cl, ppm ) + C 2 Eq. 2

Wh e r e f existing equipm ent is the fraction of m e rcury rem oved by existing equipment. These sam e algorithm s were shown in Reference 18 to also provide a m eans to approxim a te the rem a ining

m e rcury that is in the elem ental form . There ar e mi ni mum and ma xi mum a l l ow abl e va l ue s tha t set the allowable range for the results of Equations 1 and 2. Tables 3a and 3b show values for C 1 and C 2 and m i nim um and m a xim um values to use in Equations 1 and 2 for estim ating fraction of m e rcury rem oved by existing equipm ent (Table 3a) and the fraction of rem a ining m e rcury that is elem ental (Table 3b).

Table 3a. Paramet e r s Used for Equations 1 and 2 Which Estimate Mercury Removal by Existing Equipment 18

Existing Equipment
ESPc ESPc + wet FGD ESPh ESPh + WET FGD FBC a + FF FF FF + wet FGD SDA + ESP SDA + FF C 1 C 2 Minimum (%) Maximum (%) 0.1233 -0.3885 0.0 55.0 0 .1157 -0.1438 24.0 70.0 0.0927 -0.4024 0.0 27.0 0 .2845 -1.3236 4.0 65.0 0.1394 0.1127 66.0 99.0 0.1816 -0.4287 40.0 85.0 0 .1943 -0.2385 79.0 96.0 -0.1087 0.6932 5.0 25.0 0.2854 -1.1302 0.0 99.0

a FBC = fluidized bed combustor

19Table 3b. Pa r a m e te r s Use d fo r Equations 1 and 2 Which Estimate Percent of Rema in in g M e r c u r y in Gas that Is Elemental Mercury 18

Existing Equipment
ESPc ESPc + wet FGD ESPh ESPh + WET FGD FBC a + FF FF FF + wet FGD SDA + ESP SDA + FF -0.1125 1.48 64.0 99.0 C 1 C 2 Minimum (%) Maximum (%) -0.1283 1.23 12.0 85.0

- 0.039 1.11 81.0 98.0 -0.1639 1.55 34.0 91.0

- 0.0945 1.45 80.0 99.0 -0.1198 1.2 44.0 68.0 -0.1182 0.88 30.0 33.0

- 0.426 3.1 45.0 84.0 -0.0355 1.13 91.0 98.0

a FBC = fluidized bed combustor

T h e correlations of Re f e rence 18 should be used only for m a king approxim a te estim ates. 19 Al t hough the algorithm will provide reasonable estim ates in m o st cases, Ref e rence 19 showed that f actors not addressed by these algorithm s , such as fly as h characteristics or gas tem p erature, can have a signif i cant ef f ect on the m e rcury capture in existing f acilities.
The capacity of PAC to adsorb m e rcury is large enough that it should not be lim iting except at tem p eratures of about 350 °F (177 °C) or m o re, wh ich is greater than the gas tem p erature at the exit of m o st air preheaters. So, with the possibl e exception of lignite coals, cooling usually has little or no benef i cial ef f ect on m e rcury absorpti on by PAC. However, the ability of f

l y ash and unburned carbon in the f l y ash to abso rb m e rcury is f ar less than that of P A C and m ay be enhanced by cooling. Therefore, although spray cooling m ay enhance m e rcury adsorption by fly ash and downstream c a p ture in the ESP or FF, it is not expected to enhance m e rcury capture by PAC except in the case where lignite coals are burned. Accord ing to Reference 8, over 90 percent of the coals burned i n t h e United States are bitum i nous, subbitum i nous, or blends of bitum i nous and subbitum i nous, which are not likely to use spray cooling with PAC injection. Therefore, spray cooling, which was evaluated in Reference 4, is not evaluated here.

20

## 4.0 E MERGING CONTROL TECHNOLOGIES

Based on published literature, 1,4,19-30 control technologies using injection of PAC into the flue gas appear to hold prom ise for reducing m e rcury em issions from utility boilers. These technologies have been applied successfully on m unicipal waste com bustors (MW C s ) . De spite differences between MW Cs and utility boilers (e.g., m e rcury c oncentration and speciation in the flue gas), full-scale and pilot-scale tests indicate that thes e technologies m ay be able to provide significant mercury removal f r om the f lue gas of coal-f ired utility boilers. Accordingly, this evaluation focused on the characterization of perform ance and costs of PAC injection-based technologies.
Other technologies have shown prom ise for contro l of m e rcury and other pollutants such as SO 2 , NO X , and PM . These m u ltipollutant control technologies m a y offer cost- e ffe c t i v e me r c ur y c ontr o l when considering the com b ined control of m e rcur y with control of other pollutants. Multipollutant control technologies evaluated in th i s e ffort i n c l ude ECO, a dvanced dry FGD, and a coal treatm ent technology known as K-Fuel.

T h is section begins w ith the description of P A C injection-based control technologies that can be retrof itted to existing boilers f o r control of m e rcury em issions, PAC injection estim ates f o r these technologies, m u ltipollutant control technologies that control m e rcury and other pollutants, and m odel plants used in this work. Subsequently, control technology applications on m odel plants used to develop cost estim ates are discussed. Fi nally, this section discusses ECO, advanced dry FGD, and K-Fuel.



### 4.1 P AC Injection-Based Technologies

Injection of PAC for m e rcury em issions control ha s been developed and tested at the full scale on coal-f ired utility boilers. Test program s ha ve been perf orm e d on a utility boiler f i ring subbitum i nous coal with a downst r e am c o l d

- s i d ee l e c t r o static precipitator (ESPc), on utility boilers firing bitum i nous coal with a downstream ESPc , and on a utility boiler firing bitum i nous coal with a Com p act Hybrid Particle Collector (COHPAC) arrangem e nt (upstream ESPh with downstream baghouse after the air preheater). 19,25

S 29 Using the data from these test program s and from pilot-scale testing, perform ance m odels we re developed for PAC injection based m e rcury control applications. 19,30T h ese m odels are in a f o rm wh ere th ey can be updated as new inform ation is developed on these applications and for other boiler applications.

214.1.1 M ercuryRemoval Models

If

f

equipm ent is equal to the fraction of m e rcury rem oved from the boiler gases by a specific piece of equipm ent, then (1 – f equipm ent ) equals the fraction of m e rcury rem a ining in the gases af ter that specific equipm ent. The fraction of m e rcury rem a ining after n pieces of equipm ent is equal to
[(1 – f equipm ent 1 ) × (1- f

equipm ent 2 ) × (1 – f equipm ent 3 ) × . . . × (1 – f equipm ent n )] Eq. 3
Therefore, the total m e rcury rem oval fraction, f Total , is
f

Total = 1 – [(1 – f equipm ent 1 ) × (1- f

equipm ent 2 ) × (1 – f equipm ent 3 ) × . . . × (1 – f equipm ent n )] Eq. 4
If one of the pieces of equipm ent is PAC injection, then the total m e rcury rem oval fraction is
f

Total = 1 – [(1 – f equipm ent 1 ) × (1- f

equipm ent 2 ) × (1 – f equipm ent 3 ) × . . . × (1 – f PA C inj ection ) × . . . × (1 – f equipm ent n )] Eq. 5

where f PA C inj ection is the fraction of m e rcury rem oved by PAC injection.

If

PAC injection is sim p ly added to existing e quipm ent and the rem oval effects of the existing equipm ent are com b ined into one term , then we can represent Equation 5 as
f

Total = 1 – [(1 – f existing equipm ent ) × (1 – f PA C inj ection )]
and, solving for f PA C inj ection

f PA C inj ection = 1 – [(1 - f Total )/ (1 – f existing equipm ent )] Eq. 6

where f existing equipm ent is the rem oval fraction associated with the existing equipm ent and m ay be approxim a ted by Equations 1 and 2 in Section 3.5 of this docum ent if the rem oval by existing equipm ent is not known. Given a total m e rcury reduction requirem e nt and knowing the reduction by existing equipm ent, it is possible to determ ine how m u ch additional reduction is necessary from PAC injection.
In this research, data from full-scale and pilot-scale tests of m e rcury reduction wer e us e dto form ulate m odels for m e rcury reduction from exis ting equipm ent and from PAC injection. Full-scale

22data f o r m e rcury rem oval by existing equipm ent are available f r om the ICR data. Full-scale testing results of m e rcury reduction from PAC injection are available from the Departm e nt of Energy’s fi e l d t e s t i ng program s at Southern Com p any’s Gaston Plant, W i scons i n El e c t r i c Powe r Compa ny’ s Pleasant Prairie Power Plant ( PPPP), and at PG&E Corp. Nati onal Generating Group’s Brayton Point and Salem Harbor Plants. 19

4.1.2 M ercuryReduction byPAC Injection
Reference 4 has algorithm s developed from pilot-scale data for m e rcury reduction on boilers equipped with PAC injection. The following m ode l im provem e nts, discussed in Reference 19, have been m a de:

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

m e rcury reduction from both PAC injection a nd existing equipm ent as afunc t i o n of PAC injection concentration. Wh en using the algorithm s of Reference 4, it is necessary to have a dif f e rent PA C injection algorithm f

o r each type of equipm ent conf iguration, including upstre am a

nd downs t r e am e qui pme nt

. The s e PAC i n j e c t i on a l gor ithm sm a y have to be updated as new inform ation regarding m e rcury contro l from existing equipm ent becom e s available. As described in Reference 19, the m e rcury re duction from PAC injection was isolated from that of the other equi pme n tin Equation 5. Th erefore, as m o re inform ation on reduction of

m e rcury from equipm ent other than PAC inj ection is developed, it should not be necessary to perf orm new regressions on the PAC injec tion m odels. Also, using Equation 5, it will also be possible to assess the fate of m e rcury in equipm ent that is either upstream or downstream of

the PAC injection system

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

m e rcury rem oval by injection of very high concen trations of PAC. As dem onstrated at a fulls c a l e de mons t r at i on at t

h e Pl e a s a nt

Pr a i r i e Power Plant, under som e circum stances t h e me r c ur y reduction by PAC injection can be lim ite d to som e thing well below 100 percent. 28 Therefore, the algor i t h

m for me r c ur y r e duc t i on fr om PAC i n j e ction was m odified as described in Reference 19 and in the following paragraphs to perm it an upper lim it to m e rcury rem oval that m ay be less than 100 percent.

3. Because the algorithm s of Reference 18 for m e rcury reduction from existing equipm ent are based on the full-scale ICR data, it is desirable to use them to characterize m e rcury reduction from existing equipm ent. However, it is not po ssible to integrate the algorithm s of Reference

234 into the approach used in Reference 18. By tre at i ng t h e me r c ur y r e duction from PAC injection independently from m e rcury reduction f r om other e q u i pm ent, it is possible to use the algorithm s of Reference 18 to characterize m e rcury reduction from existing equipm ent.

Because m e rcury reduction by PAC injection m ay be lim ited to a value well below 100 percent, as identified i n t h e s e c o nd point, the equation that is used in Reference 4 to characterize the relationship between m e rcury reduction and PAC injection

% reduction = 0 = 100 × f from PA C inj ection= 100-[A/(M+B) C ] E q. 7

where M is the m a ss injection rate of PAC (in lb/MMacf ) so that
M = {[A/(100 – 0 )] (1/C) } – B E q. 8

was m odified in Reference 19 to be
M = {[A/((100×D) – 0 )] (1/C) } – B E q. 9

where D is the fraction of m e rcury reduction that is asym ptotically approached.
A set of constants A, B, C, and D are specified for a given existing plant configuration, coal type (bitum i nous or subbitum i nous), PAC sorbent type, and retrofit configurati on (PAC alone or PAC plus retrof it fabric filter). Th ese constants are based upon f u ll-scale data wh ere available and based upon pilot-scale data or i nput from experts in this technology where f u ll-scale data are not available. Reference 19 showed that, for system s with FFs, a ll of the PAC-based sorbents appeared to offer

s i m ilar p e r f o r

m an c e in te r m s o f P A C injection concentration (in lb/MM a c f ) n e c e s s ar yf o r

a

g i v e n
m e rcury reduction. On the other hand, for units w ith ESPs and w ithout a f a

bric filter, PAC selection did have a significant effect on perform ance.
The constants A, B, C, and D are determ ined based upon a PAC injection m a tching key, which is a five-digit num ber com posed of the following elem ents:

• E xisting Particle Cont rol Equipm ent (10000, 20000, 30000 for FF, ESPc, ESPh, respectively) • T h e S O 2 control technology, if any (0, 1000, or 2000, or 3000, for none, FGD, SD, or advanced dry FGD, respectively)

24• T he fuel type: (100 for Bitum i nous or 200 for Subbitum i nous)

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

• T he PAC capacity (1 for high, 2 for m e di um , and 3 for low—In Reference 19, PAC selection appeared to m a ke a dif f e rence f o r f acilities with ESPs but not f o r f a cilities with FFs)

F o r exam ple, ESPc SD Bitum i nous FF m e d (Matching Key # 22112) indicates a Bitum i nous coalf i red boiler currently equipped with a spray drye r absorber and an ESPc that will retrof it PAC injection (m edium capacity) and a f abric f ilter. The list of constants used f o r Equation 9 in this work is shown in the Appendix 2. The m a tching ke y above will be used to determ ine the set of constants used for Equation 9 to estim ate the PAC injection concentration.
Equation 9 is used to determ ine PAC injection rate is the f o llowing m anner. If f

existing equipm ent is greater than or equal to f Total , then no additional m e rcury rem oval is necessary, and addition of PAC injection or any other technology to rem ove m e rcury is unnecessary. However, if f

existing equipm ent is less than f

Total , additional m e rcury rem oval is necessary through retrofit of another technology, in this case PAC injection. Using Equation 6, it is possible to determ ine the am ount of m e rcury reduction that m u st be perform e d by injection of PAC. Keeping in m i nd from Equation 7 that

0

= 100 × f from PA C inj ection , Equation 9 is then used to determ ine the injec tion concentration (M) of PAC (in lbs/MMacf). M is then m u ltiplied by the t o t a l ga s fl ow r a t e t o de term ine the injection rate of PAC (in lbs per hour).



### 4.2 Emerging Control Technologies

Certain em erging technologies appear to offer significant potential for the com b ined reduction of m e rcury and SO 2 , or of m e rcury, NO X , and SO 2 . The technologies of interest that are evaluated in this report include

• E lectro catalytic oxidation (ECO)

• A dvanced dry FGD

• K -Fuel

25These technologies generally have lim ited comm e rcial experience on coal-fired utility boilers, but experience with the technologies in other a pplications or experience with related technology

m ay be extensive. In the case of ECO, f o r ex am ple, this is a unique technology with lim ited experience beyond the developm ent and dem onstration efforts currently underway in the United States. Som e elem ents of the ECO proce ss—amm onia scrubbing and wet ESPs—are we llestablished technologies, h o w ev er. W e t E S P ’ s , wh ile n o t u s ed w i d e ly in the utility industry, have a large experience base in other industries. Adva nc e d dr y FGD ha s e xpe r i ence on other applications and is also closely related to spray dryer ab sorber technology, which has extensive experience on coal-fired utility boilers. K-Fuel is an approach f o r benef i ciating western fuels, especially Powder River B a s i n c o a l s

. K

- F u el rem oves m o isture (increasing heating value), nitrogen (reducing NO X ), sulfur (reducing SO 2 em issions), and m e rcury (reducing m e rcury em issions). K-Fuel has been tested on utility b o ilers an d a comm e rcial production plant is under construction. Therefore, each of these technologies appears to have prom ise, m ay be used in the near term , and can be analyzed with som e confidence. However, because of the lim ited experience with these technologies in coal utility applications, the results of the analys is shown here should be considered prelim inary.

4.2.1 E lectro Cataly tic Oxidation (ECO) 31

S 34
ECO technology has been developed by Powerspan. Itis expected that the ECO system would be installed downstream of the existing ESP or FF, as shown in Figure 5.

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

26This technology consists of

• Adielectric barrier discharge reactor that induces oxidation of pollutants

• A two-loop am m onia scrubber towe r t

h a t r e move s SO 2 and water-soluble oxidized form s of the pollutants

• Awet ESP that rem oves acid m i st and fine particles

• Aco-product (saleable fertilizer by-produc t) processing and m e rcury rem oval system that rem oves m e rcury with carbon filters and crystallizes the amm onium nitrate and

amm onium sulfate fertilizers from the scrubber tower.
In the dielectric barrier discharge reactor, the following happens:

• NO gas form s nitrogen dioxide (NO 2 ) gas and nitric acid (HNO 3 ) aerosol m i st. • S O 2 gas form s sulfur trioxide (SO 3 ), leading to the f o rm ation of sulf uric acid (H 2 SO 4 ) aerosol m i st. • H g 0 vapor form s HgO particles.
Figure 6 shows a detailed process flow diagram for an ECO application.

Figure 6. Detailed process flow diagram of ECO. 33

27The wa t e r - s oluble form s of the oxidized pollutants—HNO 3 and H 2 SO 4 —are rem oved in an a b s o r b e r tower that is equipped with a wet ESP. The absorber to w e r is a tw o-stage process with an absorption stage (at the top of the to w e r ) f o r

a

b s o r b ing the pollutants and a concentrating stage at the bottom

. An a que ousa mmoni a s o lu t i on i s us e d a st h e scrubbing agent to absorb SO 2and convert the absorbed SO 2 , nitric acid and sulfuric acid to amm onium nitrate and amm onium sulfate, respectively. NO 2 reacts with am m o n iu m

s u lf ite [ ( NH 4 ) 2 SO 3 ] , w h ich f o rm s in the scr ubbing liquor, to form am m onium sulfate [(NH 4 ) 2 SO 4 ] and N 2 . W ith 90 percent NO X r e duc t i o n, about 40 percent of the NO X becom e s ni tr a t e and about 50 percent becom e s NO 2 and ultim ately N 2 . Thus, som e of the NO Xis ultim ately converted to amm onium nitrate and the rem a inder is ultim ately converted to N 2 . All of the SO 2 r e m o v e d is u ltim ately rem oved in the f o rm of am m o n i u m

s u lf a

t e

. M e r c u r y

c o lle c t e d in th ea b s o r b e r tower water is rem oved from the liquid stream by an activated carbon filter. Acid m i st and fine particles rem oved in the wet ESP drain into th e absorber tower and are rem oved in the liqui d discharge of the lower loop. Due to chem istry consid erations of the absorber tower, the ECO process works best if the SO 2 to NO Xratio in the flue gas is equal to 3 or m o re on a m o lar basis.

The consum ables and the by-products of the ECO process include

Consum ables

• E lectric power for the barrier discharge reactor, pum ps and blowers. The power for the discharge reactor is related to the NO Xreduction desired. 33

• H eat for the by-product crystallizer. 33

• A mm onia reagent, which can be estim ated as roughly tw o m o les of amm onia per m o le of SO 2 rem oved. Additional am ine is provided by other chem icals discussed below.

• M ake-up water for the absorption tower— about 1 gal/m in per MW —no special quality specification. 33

• C arbon filters for m e rcury rem oval from the liquid discharge of the absorber. 33

• A dditional, proprietary chemicals that provide the balance of the amine for the conversion of NO Xto amm onium nitrate and SO 2 to amm onium sulfate. These are es tim ated at around $150/ton of NO Xrem oved and $15/ton of SO 2 rem oved. 33 By Products

• A mm onium nitrate and amm onium sulf ate crystals that can be sold as f e rtilizer. Typi c a lly, for 90 percent reduction for every m o le of inlet NO X , 0.40 mol e s of a mmoni um nitrate are produced, and one m o le of amm onium sulfate is produced for every m o le of SO 2 reduced. 33

• M ercury captured on the activated carbon (a wast e to be disposed of) at a cost of about $1000/lb of m e rcury captured. 33

28• Asm all am ount of coal fly ash that was not captured by the ESP is filtered out of the liquid stream to the f e rtilizer crystallizer. 33

• W ater vapor. 33
Experience The ECO technology has been dem onstrated in th e laboratory and on a 2000 scfm pilot at First Energy’s Burger Plant. The pilot has been operating since March 2002. A 50 MW comm e rcial dem onstration system is currently being built at Burger Station. The comm e rcial dem onstration unit at Burger Plant is designed to handle 110,000 scfm of gas flow. 34
Capital Cost Am erenUE, Sargent & Lundy, Whe e l a b r at o r , The Ande r s ons , and Powerspan perform e d a detailed cost estim ate of an ECO unit at Am erenUE’s Sioux plant. The capital cost of an ECO system for th i s 510 MW installation was estim ated at $114,500,000, inclusive of pr oc e s s e qui pme n t , ge ne r a l f acilities, owner’s costs, and contingencies. This also included the f e rtilizer plant and balance of plant m odifications. 35 It is the only com p rehensive, full-scale cost analysis that has been m a de available publicly. Therefore, a cost of $200/kW is a reasonable estim ate to use. Reference 33 conf irm e d this estim ate.
Operating Cost Variable operating cost is the cost of power and other consum ables. Amm onia consum ption is determ ined by the m o lar ratio described above unde r Consum ables. Specialty chem ical costs are estim ated at $150/ton of NO X rem oved and about $15/ton of SO 2 rem oved, based upon inf o rm ation fr om Re fe r e nc e 33. Reference 33 also provided inform ation on power cons umpt i on r e qui r e me nt s for both the ECO reactor and auxiliaries, describe d in the next section. Carbon filter replacem ent costs and the costs of disposal of used carbon filters are estim ated at $1000/lb of m e rcury rem oved. Fertilizer value, wh ich produces a revenue stream th at of f s ets a portion of the cost, is approxim ated at $110/ton of fertilizer produced. 33 The amm onium sulf ate and amm onium nitrate f e rtilizer are widely traded comm odity chem icals and their value will depend largely on m arket conditions at the tim e and transport costs.

F i xed O p erating Costs include an estim ated 1.5 per cent of process capital per year plus 3 operators and one m a intenance person per shift. 33 The m anpower needs are not e xpected to be a significant function of unit size. 33

29Pollutant Removal Efficiencies and Power Consumption Because ECO is a true m u ltipollutant process that can rem ove NO X , SO 2 , m e rcury, and fine particles, the effectiveness of the process can de pe nd upon several variables, and there m ay be som e interrelationships. Howe ve r , a typi c a l coal system would be designed for the rem oval efficiencies shown in Table 4. 33

Table 4. ECO Pollutant Removal Efficiencies 33, 35

Pollutant Removal Rate Conditions SO 2 98%-99% Any inlet condition NO X 90% Up to 250 ppm or up to about 0.450 lb/MMBtu a Hg 80%-90% Any inlet condition
Fine Particles 95% (Outlet to less than 0.004 lbm/MMBtu)

a At higher NO X levels, 90% reduction is achievable at higher ECO reactor power levels.

The ECO system tends to operate best whe n t

h e mol a r SO 2 to NO X ratio is 3.0 or greater. 33 Although ECO can operate at lower ratios, the reliability of both perf orm ance and cost predictions m ay be

som e what less.
The power for the dielectric barrier discharge reactor is largely determ ined by both the am ount of NO oxidation needed and the gas flow. To increase the am ount of NO Xrem oved by the ECO process, it is necessary to increase react or power. So, for a given percent of NO Xreduction, the reactor power is roughl y proportional to the NO X m a ss flow. Therefore, to achieve a low outlet NO Xlevel while m i nim i zing power dem and, it is best to start with a low NO Xlevel f r om the boiler. As a result, one would ty p i c a l ly use an ECO system in com b ination with low NO Xburners or other devices to m i nim i ze NO Xinto the ECO reactor. Based upon inform ation from Reference 33, this work assum e s that reactor power ( i n watts/scf m ) is equal to the lesser of 20 watts/scfm or 58.22 C (NO X ) – 6.2431 (see Figure 7), where NO Xis m easured in lb/MMBtu. Reactor power could potentially be higher than 20 watts/scfm ; however, this w ould likely be unattractive when com p ared to reducing NO Xby other m eans such as low NO Xburners.
Other power dem ands include fan power to overcom e about 9 inches of water total pressure drop (calculated as actual volum e flow tim es pressure dr op wi t h

a

n

a s s u me d fa n e ffi c i e n c y of 65 percent) and another estim ated 0.75 percent of plant output f o r auxiliary loads for the absorber and fertilizer

30plants. Although the fertilizer auxiliary co sts are m o re closely related to the SO 2 being rem oved, a single percentage is used for sim p licity. 33

Figure 7. ECO power consumption versus NO X . 33

Calculation M e thods Aw o rksheet titled EC O C o st and Perform ance was developed. Inputs for other calculations were largely taken from CUECost worksheets and the Plant Configuration Inputs and the Constants_CC worksheets. Inlet gas conditions are taken as the outlet of the air preheat er except f o r particle loading, which is reduced due to the ESP or FF. Relationships for m a ss balances were developed from the i n form ation provided above regardi ng consum ables, and relationships for power

consum ption were developed from inform ation discussed regarding power consum ption.
As noted earlier, the reliability of the algorithm s used f o r predicting ECO system perf orm ance and cost m a y be som e what reduced for m o lar SO 2 to NO X ratio sb e lo w 3

. 0. Therefore, the worksheet includes warnings when the inlet SO 2 to NO Xratio is below this value. Low SO 2 to NO Xdoes not m ean that the output is incorrect or that ECO cannot be us e d. It sim p ly m eans that the calculations are som e what less reliable, and it would be advisable to consult with the technology supplier for m o re inform ation.

314.2.2 A dvanced DryFGD 36-39,41-47
Dry FGD reacts hydrated lim e slurry with exhaust gases in an absorber vessel to capture SO 2 , SO 3 , HCl, and m e rcury that m ay be present in the exhaust gases. The exhaust gases are m a intained above saturation tem p erature to avoid condens ation. The by-product of dry scrubbing can usually be landf illed saf e ly or, in som e cases, reutilized f o r another purpose.
Advanced dry scrubbing is intended to im prove perform ance over conventional spray dryer absorbers. Advanced dry scrubbing utilizes a flui dized bed or a flash dryer for the reactor with recycle loops to enhance lim e utilization. Figure 8 s hows a diagram of the FLS AirTech Gas-Solid Abs o rber installed upstream of an ESP. Many system s use venturi m i xe r s t o i n tr oduc e th e s o r b e n t slurry

. T h e h i g hs o lid s loading in the reactor pr ovides high gas-solids interaction and high solidss o l i d s i nt e raction. The high solids-solids interaction allows reactive particle surface to continuousl y be exposed as the particles im pact one anothe r. The solids-solids interaction also causes som e agglom eration of f

i ne particles to f o rm larger particles that are easier to capture in downstream equipm ent. Because the reactions occur m o re effi ciently in the reactor and because the particles are larger, Advanced dry scrubbing doe s not r e qui r e a downstr eam fabric filter for the SO 2 rem oval reaction to be com p leted. Wh en a cyclone is used for recycle to produce a lower outlet particle concentration, a sm a l l e r downs t r eam particle collection device is needed. In this case, the technology can often be installed upstream of the existing ESP, as shown in Figure 9. W ithout the cyclone, it is likely that the existing ESP will require s o m e m o d i f i c ations to im prove collection ef f i ciency, or a new particle collection device m ay be nece ssary. However, in m any cases it is envisioned that the absorber will be installed downstream of the existing ESP so th at fly ash does not get contam inated and can continue to be sold. In th is case, an additional particle rem oval device will be necessary, as shown in Figure 10.

Som e fly ash is be ne fi c i a l t o me r c ury c ap tur e in the absorber, especially for subbitum i nous coal. 36 Reference 36 also indicated that 98 percent m e rc ury capture is possible for bitum i nous coal. The fly ash also helps to im prove the qualities of the solid by-product, m a king it m o re suitable for use as fill or for sale of cem ent-like products.

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

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

.

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

There are a num ber of com p anies that supply diffe rent versions of advanced dry FGD technology: L urg i L e ntjes, F.L. Sm idth AirTech’s Gas Suspension Absorber (GSA), RJM Beaum o nt ’s R a p i d Absorption Process (RAP), and WU LFF. The a dvanced dry scrubbing system s all use hydrated lim e slurry as the principal reagent to rem ove SO 2 and can rem ove m e rcury as well. Figure 11, which is the published perform a nce of three different advanced dry scrubber system s, 40,43,46 shows that the SO 2 rem oval efficiency is a strong function of stoichiom e tric ratio, approach-to-saturation (A T S , expressed in degrees Fahrenheit), and chlorine content. Data is shown for chlorine contents of 0.04 percent (400 ppm ) and 0.12 percent (1200 ppm ). Stoichiom e tric ratio is defined as m o les Ca/m olesSO 2 . As shown, ATS, fuel chlorine conten t and lim e stoichiom e try determ ine the SO 2 rem oval efficiency. For any given ATS, chlorine level, and stoichiom e tric ratio, all technologies offer sim ilar SO 2 rem oval. For exam ple, note that the GSA 18 deg and 1200 ppm Cl line, if continued, would closely follow the RAP 18 degree line. Since all versions of advanced dry FGD offered by the di ffe r e nt s uppliers rely on the sam echemistry, similar perform a nce would be expected for a specific set of conditions.
Although advanced dry FGD has not been as wide ly used as SDA technology, there is significant

o p e ratin gd ata on it for pulverized coal-fired applications. Moreover, the chem istry of S O 2 capture i s ve r y

s i mi l a r t o t h at of SDA technology. For the analysis of this report, algor i t hms we r e de ve l ope d to predict perf orm ance. To calculate lim e f eed necessary for a particular level of SO 2 reduction, Figure 11 was re- p lotted as stoichiom e try versus SO 2 reduction, and curves were fit based on ATS and chlorine content of the coal. The results are shown in Figure 12.

34Figure 11. Advanced dry scrubber SO 2 removal performance.

Figure 12. Advanced dry scrubber performance.
35At this tim e, som e suppliers of this technology lim it the gas-flows per reactor to an equivalent of around a 125-150 MW plant. 38 On the other hand, Lurgi has supplied single-reactor system s as large as 250 MW and expects to be able to supply single reactor system s as large as about 400 MW

. 39 WU LFF has supplied single-reactor system s as large as 300 MW

. 40 As a result, in som e (but not all) cases it m ay be necessary to have m o re absorber towers than for conventional spray dryers. For this reason, a design of a RAP system for a 500 MW boiler m ay require as m any as four reactors and a 250 MW system m a y require as m any as two reactors. 41 Som e other suppliers

m ay not require as m any reactors.

Lim ited experience has shown high m e rcury rem oval rates. Testing of m e rcury control from the Roanoke Valley Energy Facility showed that th e Lurgi-designed system provided in excess of 95 percent m e rcury rem oval from the 55 MW Unit #2 while firing eastern bitum i nous coal. 42 For subbitum i nous coals, where there is lower chlori ne content and a greater proportion of elem ental

m e rcury versus total m e rcury as com p ared to bitum i nous coals, lower capture efficiencies m ay be expected with norm a l lim e sorbent. However, activated carbon or other specialized sorbents

m a y offer the potential to capture m o re m e rcury. RJM-Beaum ont Environm ental System s offers oxidized calcium sorbent that they claim is effective in rem oval of SO 2 and m e rcury. 43

The consum ables and the by-products of the ECO process include

Consum ables

• E lectric power for the booster fan, pum ps, blowers, and reagent preparation

• L im e – norm a lly delivered as dry lim e and hydrated to hydrated lim e
• W ater – for producing hydrated lim e and for gas cooling

• C osts associated with downstream particle rem oval (energy, fabric filters, etc.)
The algorithm s of Figure 19 are used to calculate lim e feed necessary for a particular level of SO 2 reduction.
By Products

• C alcium sulfate, calcium sulfite, a sm all am ount of unreacted sorbent, ash and other solids collected in the downstream partic le collection device. Based upon review of pr oc e s s de s i gns fr om di ffe r e nt s uppl i e r s , t h ea pproxim a te am ount of this is 2.5-2.8 lbs / l b of sorbent injected. Most of ten the by-pr oducts are landfilled, but they can occasionally be re-used.

• W ater vapor that goes up the stack

36Experience This technology has been wi de l yus e d on i n c i ne r a t i on s y s t e m s and to a lesser degree on coal-fired boilers. Lurgi has supplied the technology to a 250 MW plant in Puerto Ri c o, to the 55 MW R o anoke V a lley facility in North Carolina, to th e B l ack H ills Pow e r & Light (G illette, WY ) plant, and to nine coal-fired plants in Europe. 44 WU LFF has supplied the technology for the 300 MW coal- and oil-fired Theiss plant in Austria. Th ere is significant comm e rcial experience on coal as a result of these installations. 40
Capital Cost Inform ation from technology providers suggests that the installed cost of a reactor and all m aterial handling equipm ent excluding any downstream particle control device (ESP, FF, or cyclone) is roughly $35/kW for 250 MW or 500 MW system s. 41,45 It m ay then be necessary to add the cost of the equipm ent and ins t a l l a tion of a FF or anESP, associated m a terial handling equipm ent, ductwork, fans, and other equipm ent, which coul d cost up to an additional $60/kW . Total cost

o f

p r o ces s cap ital, th eref o r e, is in the range of $100/kW . Additional costs associated w ith th e p r o j ect, such as e ngi ne ering and construction m anagem e nt, allowance for funds during construction, contingency, and general faciliti e s woul d i n c r e a se t

h e t o t a l c o st to above $100/kW . This is consistent with Reference 46, whi c h e s t i m a t e s th e c o s tof anF.L. Smi dthAi r T e c h Gas Suspension Absorber system at $149/kW (1990 dollars) for a 300 MW plan t. It is unclear from Reference 46 whether or not this cost includes the downstream ESP, but it does include the cost of the cyclone separator in the recycle system . Table 5 provides a cost estim ate for a Lurgi Lentjes CFB-FGD system at a 500 MW plant and shows a $150/kW cost estim ate. Therefore, a cost of about $150/kW appears to be consistent am ong several sources and will be used here.
Operating Costs The principal variable operating costs are for lim e reagent, water, power, and solid disposal. The preceding discussion described how lim e consum p tion is determ ined. W a ter consum ption (city water is considered adequate quality—dem i neralized water is not required) is determ ined by the slurry concentration. Booster fan power for the reactor and cyclone is estim ated from gas flow rate (actual cubic feet per m i nute) and pressure drop assum i ng a blower efficiency of 65 percent, and m a terial handling power is estim ated at 0.1144 hp/lb/h of lim e feed.

37Table 5. Estimated Cost of CFB-FGD System for a 500 MW Plant Burning PRB Coal

Subsystem Cost, U.S. $ $ /kW Reagent Feed Syatem 5,000,000 10.0 SO 2 Removal System 7,000,000 14.0 Particulate Collector 16,000,000 32.0 Flue Gas System 7,000,000 14.0 Waste Handling and Recycle System 7,000,000 14.0 General Support Equipment 4,000,000 8.0 Miscellaneous Equipment 6,000,000 12.0 Total Process Capital (TPC) 52,000,000 104 General Facilities (A, 5% of TPC) 2,600,000 5.2 Engineering and Construction Management (B) 5 ,200,000 10.4 Project Contingency (15% of TPC+A+B)) 8 ,970,000 17.9 Total Plant Cost (TC) 68,770,000 137.5 Allowance for Funds (3.2% of TC) 2 ,201,000 4.4 Owner’s Cost (5% of TC) 3 ,439,000 7.0 Total Plant Inv estment (TPI) 74,410,000 148.9 Inventory Capital (spare, 1 % of TPI) 744,000 1.5 Royalties 0 0 Total Capital Requirement 75,154,000 150

4.2.3 K -Fuel

K-Fuel is a beneficiated coal that is derived fr om western coal. The resulting fuel is lower in ash, higher in B t u value, and produces low e r pollutant em issions than untreated w e stern subbitum i nous or PRB coals. K-Fuel uses a pre-com bustion process that im proves the quality of the coal— including rem oving the m e rcury, m o isture, ash, sul f ur , a nd s o me of t h e fue lNO X precursors—before the coal is burned at the power plant. Because th ese const ituents are rem oved prior to com bustion, the need for post-com bustion controls m ay be reduced.

The K-Fuel Coal Beneficiation Process 48,49,50 The K-Fuel process em ploys both m echanical and therm a l m eans to increase the quality of the coal by rem oving m o isture, rock, sulfur, m e rcury, and other heavy m e tals. To begin the process, coal is delivered to the K-Fuel processing plant from the m i ne. The coal enters t h e fi r s tstage separator, developed using conventional coal cl eaning technology, where it is crushed and screened

38to rem ove the larg e r o c k a

n d r o c k m ate r i a l

. T h e p r o c e s sed coal is then passed on to an interm ediate storage f acility prior to being sent to the next stage in the process, as shown in Figure 13.

Figure 13. Overall schematic of K-Fuel processing plant. 48

From the interm ediate storage f acility the coal is se nt via a distribution system to the K-Fuel therm a l processing unit (Figure 14). This process em pl oys Lurgi Mark IV vessels under high pressure and tem p erature to place therm a l stress on the co al. The coal passes through pressure locks into the processors, and then steam at 460 °F (238 °C) and 485 psi is injected into the processors. Wh ile the coal is m a intained at these conditions, the m i neral inclusions are fractured under the therm a l stress, rem oving both the included rock (w hich c ontains som em e rcury) and sul f ur - f or

mi ng pyr i t e s

. The inherent m o isture of the coal is liberated as well.

Figure 14. K-Fuel thermal processing plant. 48

39Af ter it has been treated in the mai nprocessor, the processed coal is discharged into a second pressurized lock, which is then sealed off fromthe prim ary reactor. After sealing, the processor pressure is vented into a water condenser to re turn t h e processor to atm o spheric pressure, and to flash cool the coal to appr oxim a tely 200 °F (93 °C). The coal is then discharged onto a belt and f u

rther cooled by convection a nd indirect cooling. After cooling, the coal is sent on to a second stage separator for additional screeni ng t o r e move s u l f ur - and me r c ury-containing m i neral m atter which has been liberated by the therm a l process. Mercury that is released from the coal during therm a l treatm e nt is captured in a carbon filter. The carbon filter can then be disposed.

Pollutant Reduction Performance Test burns of coal treated with the K-Fuel Process showed reductions in NO Xand SO 2 em issions. Figure 15 shows SO 2 and NO Xem issions f o r tw o coals that w e re tested—w ith and without K

- F u el treatm e nt—and em issions from an eastern bitum i nous coal. 48

Figure 15. SO 2 and NO X fuels. emissions from test burns of K-Fuel and untreated

Because the K-Fuel process sim u l t aneousl yr e duces the m e rcury content of the coal and increases its Btu value, there is a signif i cant overall m e rcury em ission reduction on a heating value basis. Table 6 below com p ares the fuel analysis of a typi cal PRB coal used for the analysis of this report

40and a sim ilar analysis of K-Fuel that was assem b led from inform ation provided by KFx Corporation. 49 The table shows that m e rcury content of the K-Fuel derived from Cordero Mine is about 43 percent lower on a m a ss basis and about 60 percent lower on a Btu basis than the PRB coal used in this com p arison. This is consistent with the roughly 65 to 70 percent m e rcury reduction reported in Reference 48 for the K-Fuel process when applied to different PRB coals.

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

Contents Coal Type PRB K -Fuel Proximate Analysis (ASTM, as received) Volatile Matter (wt%) 30.79 40.20 Fixed Carbon (wt%) 32.41 45.50 100.00 99.62 Ultimate Analysis (ASTM, as received) Moisture (wt%) 30.40 7.50 Carbon (wt%) 47.85 66.70 Hydrogen (wt%) 3 .40 4 .80 Nitrogen (wt%) 0 .62 1 .00 Chlorine (wt%) 0 .03 0 .03 Sulfur (wt%) 0 .48 0 .38 Ash (wt%) 6 .40 6 .42 Oxygen (wt%) 10.82 13.20 Total (wt%) 100.00 100.03 Mercury (mg/kg) 0.07 0.04 Modified Mott Spooner HHV (Btu/lb) 8304. 11,718. Coal Ash Analysis (ASTM as received) SiO 2 (wt%) 31.60 28.40 Al 2 O 3 (wt%) 15.30 17.30 TiO 2 (wt%) 1 .10 1 .60 Fe 2 O 3 (wt%) 4 .60 6 .00 CaO (wt%) 22.80 23.50 MgO (wt%) 4 .70 4 .00 Na 2 O (wt%) 1 .30 1 .40 K 2 O (wt%) 0 .40 0 .27 P 2 O 5 (wt%) 0 .80 2 .43 SO 3 (wt%) 16.60 13.63 Other Unaccounted for (wt%) 0 .80 1 .47 Total (wt%) 100.00 100.00

41Experience The K-Fuel Process has been tested at the pilo t stage, and construction of a comm e rcial plant is planned for this year. 48,50 Lurgi is providing m u ch of the process reactor technology. The f i rst
c o mmercial plant is to be built at the Black Thunder m i ne in W r ight, W Y . Construction is cur r e nt l y scheduled to start in m i d-2003, with com p letion e xpected in the first half of 2004. The plant is expected to produce m o re than 700,000 tons per yearof K-Fuel Plus. This plant is intended to not only prove the comm e rcial value of the technol ogy but to also provide a basis for optim izing the technology, and thus, it is designed for the possibility of future expansion on site. 48,50
Technology Cost For the purpose of this program , the cost of the K-Fuel is going to be assessed on the basis of increm ental fuel cost. K-Fuel m ay be utilized on any facility where it can be econom ically transported to the site. 50 According to Reference 50, som e in terior eastern bitum i nous fuel-fired boilers m i ght consider K

- Fuel ove r PR B because K

- Fuel w ill avoid retrofits that m ay be necessary to avoid derates that m i ght otherwise occur wh en switching from bitum i nous coal to PRB coal. Reference 50 discusses possible delivered prices ranging from $20 to $32 per ton of coal. At this price range and a heating value of about 11,700 Btu /lb, the K

- F u el has an estim ated price of about $1.20-$1.36/MMBtu, which m a kes it com p etitively pr iced on a Btu basis with m a ny bitum i nous coals and som e what m o re expensive than PRB coals. $20/ton would equate to only about $0.85/MMBtu, which m akes it cost com p etitive with (and in s o m e cas es les s exp e n s iv e than) PRB coals according to the fuel cost inform ation in Reference 50. There is a chance that som e retrofit costs m i ght be incurred by switching from bitum i nous or PRB coals to K-Fuel, but these capital costs will be relatively sm all and will be dom inated by the f u el costs in m o st cases. As a result, the cost analysis perf orm e d here will f o cus on increm ental f u el cost as the m a jor cost of using K-Fuel. Increm ental costs of control m ay be in curred if m e rcury rem oval technologies, such as PAC injection, are retrofit to reduce m e rcury em issions further.

42

## 5.0 T ECHNOLOGIES CURRENTLY UNDER DEVELOPMENT

There are several m ultipollutant c ontrol technologies that are currently under developm ent or nearing

c o mme r c i a l s t a tus i nth e Uni t e d St a t e s . The s e , and other technologies, may e m e r ge i nar e l a t i v e l y short tim e depending on t h e results of on-going tests as well as the dem and for m e rcury and

m

u ltipollutant controls. Others m ay never reach comm e rcial stage either because of technical problem s or because of unfavorable econom ics relative to com p eting technologies.
For the purpose of this report, technologies currently under developm ent were divided into three groups: em ploying oxidation (other than SCR), utilizing sorbents, and other technologies.



### 5.1 O xidation Technologies

Oxidation technologies aim at oxidizing m e rcury inorder to facilitate its subsequent rem oval in wet FGD or wet ESP. Exam ples of these technologies include LoTOx, PEESP, and ESP

m odification discussed below.

LoTOx LoTOx is a gas phase low-tem p erature oxidation system which involves injection of ozone in the flue gas upstream of a wet FGD to oxidize NO Xto higher oxides of nitrogen such as N 2 O 5 , and m e rcury to HgO. Subsequently, these co m pounds are rem oved in a wet FGD because they are water soluble. The LoTOx system consists of an integrated oxygen/ozone ge neration unit

com p lete with ozone injection system either into the LoTOx reactor or directly into the exhaust ductpr i o r t o th e wet FGD (if sufficient residence tim e can be provided). Ozone is produced in-situ and on dem and by passing oxygen through a conventi onal industrial ozone generation system

. It is produced in response to the am ount of NO X present in the flue gas generated by th e com bustion or process source. Theoretically, ther e is the potential for oxidation of SO 2 to SO 3 ; however, as proven in field testing, the reaction rates ar e very low com p ared to the predom inant NO Xand Hg reactions.

PEESP Plasm a - E nhanc e d El e c tr o s t a t i c Pr e c i pi t a t o r s ( P EESP) technology offers the potential to enhance the ability of wet ESP to rem ove elem ental m e rcury. PEESP oxidizes vapor ph a s e elem ental m e rcury i n t o oxidized form and then rem oves it within the wet ESP process. This technology invol ve s injection of a reagent gas m i xture, through a corona discharge needle that is a t t a c h e d t o th e c e n tr a l

43ele c tr ode wi th i n an e l e c tr o s t at i c fi e l d. Injection into the area surrounding the sharp discharge point results in generation of hydroxyl radicals, ozone , and other reactive com pounds. These react with elem ental m e rcury vapor to form oxidized m e rcur y particles. These negatively charged particles are attracted to the positively ch arged collecting electrode where they are collected. The m e rcuric oxide particles an d o th e r a

b s o r b e d p o llutants ar e rem oved during the wash-down cycle of the wet ESP. PEESP can be incorporated in an existi ng wet ESP by m odifying the central electrode to inject the reagent gas. Greater than 80 percent total m e rcury rem oval is projected at pilot and f u ll scale; bench scale testing dem onstrated m e rcury rem oval of up to 83 percent.

ESP Modification for Me rcury Oxidation In this arrangem e nt, a catalyst, m o st likely in hone ycom b form , is inserted into the flue gas path upstream of the FGD system (last section of th e ESP). This placem ent provides for low velocity and a relatively particulate-free flue gas. As a result, a cl ose- pi t c hed catalyst can be used. Downstream of the catalyst, the oxi di z e dmercury is scrubbed in the FGD absorber, and coprecipitates with the calcium sulfite or gypsum byproduct. Prelim inary cost estim ates show that a catalytic process, if installe d upstream of a wet FGD system , should allow plants to achieve 90 percent overall m e rcury control at a cost that is 50 percent less than by injecting activated carbon. However, the cost of the process will depend largely on the catalyst lif e and required catalyst volum e. So far, only catalysts produced at a laboratory scale have been tested.



### 5.2 S orbent Technologies

Sorbent technologies utilize im proved dry sorbents to accom p lish m e rcury rem oval in system s without wet FGD. Additionally, im provem e nts in so rbents m ay help reduce the cost of controlling

m e rcury. Novel sorbents discussed here include Am ended Silicate, MerCAP, and Pahlm anite.

Amended Silicate Am ended silicate sorbents use a com m odity substrat e m a terial impregnated w ith a chemical additive that binds m e rcury to the surface of the particles. The sorbents have been prepared in a num ber of form ulations tailored to provide econom ic m e rcur y recovery in m u ltiple applications. In packedbed tests these sorbents showed m e rcury rem oval of several tim es that of activated carbon. Pilot plant tests dem onstrated 70



### S 96 percent m e rcury capture at injection rates of 1.6



### S 9.1 lb/MMacf, respectively. Out of the total rem oval, the inj ected am ended silicate rem oved 40 percent or m o re of the m e rcury in the first one second of contact tim e in the pilot tests. Good stability of captured

m e rcury on the sorbentwa s obs e rved. Wh en sam p les of sorbent m i xed with fly ash were collected

44from the pilot fabric filter hopper and subjected to Toxicity Characteristic Leaching Procedure (TCLP) tests; the leachate m e rcury levels were below the lim it of detection. Prelim inary process design and analysis indicate that amended silicates can be cost com p etitive with activated carbon for m e rcury control.

M e rcury Control Adsorption Process Mercury Control Adsorption Pr ocess (MerCAP) deploys a m e rcury adsorbing sorbent-coated cartridge placed in the flue gas duc t at tem p eratures of 400 °F (204 °C ) or less. Mercury is rem oved from the flue gas as it flows past the rigid struct ure. Once the cartridge is saturated with m e rcury, it can then be rem oved or regenerated in-situ. So rbent m a terials that have been considered for MerCAP configuration include activated carbon or m e tals which can am algam a te with m e rcury, such as gold and silver. Pilot scale experim e nts indicated that a MerCAP with gold coated plates approxim a tely 10 ftl o ng and spaced 0.5 inches apart was placed downstream of the spray dryer/f abric f ilter could rem ove m o re than 80 pe rcent of m e rcury f r om a low-rank f u el f l ue gas. In prelim inary tests, MerCAP did not perform as well in nonscrubbed flue gas.

Pahlman Process The Pahlm an Process is a dry sorbent system com p rised of two discrete steps. One step involves capturing target pollutants such as NO X , SO X , m e rcury, and partic ulates using Pahlm anite dry

m i neral sorbent com pounds. The othe r s t e p involves the regeneration of the spent or partially spent sorbent com pounds for r e us e and the separation and isolation of useful by-products such as nitrates and sulfates for use in fertilizers and industrial ch em icals. The Pahlm a nite sorbents are low-density oxides of m anganese (MnO 2 ) in the form of fine black powder. The sorbent is injected i na r e actor, which operates at tem p erature between am bient and 320 °F (160 °C). The technology is in pilot scale stage; a trailer-m ounted pilot plant is ava ilable which has been tested at a num ber of power plants using f l ue gas slipstream s. Testing indicated above 99 percent S O 2 , 93.6



### S 96.6 percent NO X , and up to 67 percent m e rcury reduction.

ROFA and ROTAM I X ROFA (rotating opposed fire air) is a com bus tion control technology that em ploys staged

com bustion to reduce NO X em issions. In the staged com bustion, fuel is initially burned in a fuel-rich zone for low NO Xgeneration. The fue l

- r i c hz one i s fol l o we d by an OFA system that induces rapid mixing of burn-out air with furnace gases in the upper furnace region using hi ghl y- t u

r bul e n t , r o t a t i n g flow to com p lete fuel com bust i on while mi nimi zing NO X form ation. W h en sorbent or NO X -reducing chem icals (such as amm onia or urea) are adde d to the OFA ports, the technology is referred to as ROTAMIX. The NO X -reducing chem icals reduce NO X through selective non-catalytic reduction

45reactions. The sorbent m ay be added for adsorption of SO 2 or m e rcury. Full-scale tests at Cape Fear Unit 5, firing eastern bitum i nous coal , showed that, in addition to the N O Xrem oval provided by the staged com bustion and the baseline m e rcury rem oval from the existing ESP, up to 89 pe r c e nt
rem oval of m e rcury, 64 percent rem oval of SO 2 and 4 percent rem oval of NO Xwas achieved by lim estone injection. Addition of Trona produced re sults of up to 67 percent rem oval of m e rcury, 69 pe r c e n t r e m oval of SO 2 and 11 percent rem oval of NO X . Slagging of the superheater by sorbent and ash was found to be a problem during the tests. However, it is believed that this problem m i ght be avoided in the future through selection of inj ection locations at a lower tem p erature where ash softening is not as great.



### 5.3 O ther Technologies

This group of technologies includes hybrid processe s that accom p lish m e rcury rem oval in a m odified baghouse (Prom o ted MB Felt), by a com b ined dry and w e t process (m ultipolluta nt control process), or in a regenerable sorbent bed (activated coke). These processes are presented below.

Promoted M B Felt T h is p r o cess is centered on a proprietary, low-pressure, m e rcury-capturing f ilter f a

b r ic ( P r o m o te d MB Felt) incorporated into a pulse-jet baghouse. The fabric is designed in a way that allows for

m e rcury capture to be segregated from particul at e c ontr o l , th ereby avoiding fly ash contam ination. Be nc h- sc a l e e xpe r i me nts at 185 °C dem onstrated approxim ately 75 m gHg/(g filter me di um) we r e captured. High m e rcury capture was later confirm e d in a pilot plant over the course of seven weeks.

M u ltipollutant Control Process This process involves sequential injection of dry sorbent and liquid oxidant to accom p lish SO 2 rem oval and oxidation/rem oval of NO X , and Hg in a m u ltipollutant control reactor. The reactor consists of three sequential tubular sections followed by a fabric filter. The first vertical section is a hum idif ier, which is f o llowed by two vertical sorption sections. Dry sorbent injection is located approxim a tely one third from the top of the f i rs t sorption section. Liquid oxidant is dispersed into the flue gas at the top of the sam e section. Prelim inary results from a 1 MW slipstream of a 300 MW low sulfur coal-fired boiler indicated SO 2 , NO X , and m e rcury rem ovals across the reactor of up to 92, 80, and 68 percent, respectively. The extent of oxi da t i on and subsequent rem oval of NO Xand m e rcury was a function of the type and am ount of oxidizer used.

46The Activated Coke Process This process involves three steps: adsorption, desorption, and (optional) by-product recovery. In the firs ts t e p ( a dsorption), flue gas passe s through a bed of activated coke slowly m oving downwards in a two-stage adsorber. The activated coke consists of carbon with large porous inner surface area. In the first stage, sulfur dioxide is rem oved by adso rption into the activated coke, where it form s sulfuric acid or amm onium hydrogen sulfate [NH 4 HSO 4 ]. Mercury can also be

rem oved by adsorption on the coke at a rate of up to 1.7 m g /g of activated coke at a tem p erature below 180 °C and condensation in the m i ddle of desorber where the coke is about to be heated for regeneration. Therefore, m e rcury can be rem oved by e x t r a c t i ng the coke in the m i ddle of desorber. O n e m e thod being considered f o r rem oving m e rcury is the use of a selenium f

ilter, which absorbs the m e rcur y fr om t h e flue ga sa nd for m s HgSe, a chemically stable com pound. The selenium f ilter is expected to have 98 percent Hg collection efficiency during the f ilter lif e (usually 4-5 years).

4748

## 6.0 C OSTS OF REDUCING MERCURY EMISSIONS

The costs of controlling any pollutant are com posed of capital costs associated with installation of the equipm ent and the operating costs associated with operating the equipm ent. In this report, these costs are estim ated and assessed on a m ills/kWh(or $/MWh) basis. In this ef f o rt, costs are determ ined on a constant dollar basis—that is to say that the costs are represented in 2003 dollars and the effects of general inflation are, therefor e, norm a lized. W e also assum e that the escalation of operating costs equa ls the general inflation rate. Therefore, inflation is assum e d to offset escalation so that the levelization factor for operating costs is equal to 1.0.
The approach to assess costs included the use of EPA’s CUECost m odel and additional worksheets that are specific to the technologies of interest . EPA’s CUECost m odel was used to estim ate flue gas conditions, establish basic economic param e ters, and per f or

m c o s t a

nd pe r f or

ma nc e c a l c ul a t ions for those technologies already integrated into CUEC ost. This approach was used to first estim ate the costs for m odel plants under specific conditions. Then, the costi mpac t s of som e selected variables are determ ined.



### 6.1 M ercuryand Multipollutant Control Cost Models

For this work, m e rcury rem oval is from existi ng air pollution control equipm ent as well as from additional equipm ent such as PAC injection. Thes e m odels were described in Sections 3.5 and 4.1, and the PAC injection rate algorithm constant s f o r each equipm ent conf iguration are provided in the Appendices.

Costs are com p rised of capital and operating costs. These costs are assessed to develop a total annual cost of pollution control expressed in m ills/kWhor $/MWh. a The total installed capital cost is annualized to produce an annual charge. Th is is done by m u ltiplying the total installed capital charge by a capital recovery factor (CRF). The CRF is a function of variables such as project life, cost of capital, tax rate, depreciation m e thods, and others. In this analysis, a CRF of 0.133 (or 13.3 percent) was chosen to be consistent with Reference 4. The annualized capital charge is then divided by the total power output of the plant for the year to determ ine the annual capital cost contribution to electric cost in m ills/kWh(or $/Mwh).

a Costs expressed in m ills/kWhand $/MWh are num erically equal.
49Operating costs are estim ated by determ ining the sum of the annual cost of consuma b l e s

— r e a g e n ts, power, water, etc. that contribute to variable operation and m a intenance (O&M) and the annual cost of additional operators, m a intenance, or parts (that contribute to fixed O&M) and dividing that sum by the total power outputof t h e pl a n t f o r the year to determ ine the operating cost contribution to electric cost in m ills/kWh(or $/MWh).
The total annual cost of pollution control (in m ills/kWh ) is determ ined by adding all of the cost

com ponents—annual capital cost, annual variable O&M, and annual fixed O&M.

I t

i s i m por t a

nt

t o not et h at t

h ec o s t s of t h e multipollutant control technologies are likely to be great e r than those for m e rcury control only. However, these technologies are prov iding additional pollution control benefits over and above m e rcury control.
In the tables that follow, estim ates of capital and total annual cost for m e rcury and m u ltipollutant control technology applications on m odel plants are shown. These estim a t e s were determ ined with the cost m odel discussed. It is noted that these estim ates are based on currently available data.

Wh ile developing the cost e s t i m a t e s for the m odel plant applications, the following specifications were used with the cost m odel.

1. Mercury concentration in the coal was taken to be 0.10 m g /kg for eastern bitum i nous coal and 0.07 m g /kg for subbitum i nous coal. These concentrations are in the range of

concentration reported f o r utility boilers in Ref e rence 72.

2. PAC injection rate correlations (see Section 4.1, Appendices and Refer e nc e 19) generally ref l ect that PAC injection require m e nts increase n o n lin early w ith an increase in

m e rcu r y

rem o v a l ef f i ciency. To characteri ze the im pact of this behavior, m odel plant cost estim ates were obtained for m e rcur y rem oval efficiencies of 50, 60, 70, 80, and 90 percent wherever possible. In som e cas es existing equipm ent provided in excess of 50 percent rem oval and PAC injection was not needed to achieve the specified level of reduction. For PAC injection with a downstream ESP, 90 percent reduction m ay not be possible with subbitum i nous coals w ithout retrofit of a downstream pulse jet f a

bric f ilter (PJFF). For bitum i nous coal f i red boilers w ith an ESP, 90 percent rem oval

m ay not be cost effective by PAC injection alone when com p ared to PAC injection and retrofit of a downstream PJFF to achieve 90 percent m e rcury rem oval.

503. Spray cooling was not used in any of th ese m odel runs because PAC has sufficiently high capacity for m o st tem p eratures of intere s t

— a ir preheater (APH) exit tem p erature under 350 °F— that any tem p erature effect is expected to be sm all. Moreover, spray cooling m ay have adverse effects on high-sulf ur fuel boilers [due to acid dew point (ADP) effects] and PRB fuel boilers (due to cem ent-like properties of the ash). However, at lignite coal-f ired plants, whic h are not evaluated here, spray cooling m i ght be used to im prove m e rcury rem oval. No data are currently available for recycling

o f

s o rb ent in technology applications utiliz ing PAC injectio n an d P J F F

. A cco rd in g l y , no sorbent recycle was used.

4. W e t FGD perform ance for m e rcury control is determ ined by Equation 2 if no SCR exists or 90 percent rem oval if the boiler fires bitum i nous coal and is equipped with an SCR. No oxidation (or co-benefit) by SCR is assum e d for subbitum i nous coals. If

P A C is added to provide additional reduc tion of m e rcury, then PAC is added upstream of the ESP or FF.

5. In each of the m odel plant cost determ inations, a plant capacity factor of 65 percent was used.

6. The cost of PAC was taken to be $1,000/ton of carbon.

7. In som e cases, it is assum e d that PAC is added upstream of the existing particulate control equipm ent. In others, particularly for high rem oval rates, it is assum e d that a downstream FF is added. In the case of spr ay dryer absorbers, it is assum e d that PAC is added upstream of the spray dryer, and a f abric f ilter m ay be added between the upstream PAC injection point and the downstr eam spray dryer. This is because the

rem oval of HCl by the spray dryer will advers ely af f ect the ability of PAC to achieve reasonable rem oval rates. This will require a larger f abric f ilter than if the f abric f ilter were installed downstream of the existing particulate control device because, in the upstream arrangem e nt, the f abric f ilter would need to be sized to capture all of the fly ash as well as the injected PAC.

8. The m u ltipollutant control technologies evaluated—ECO, advanced dry FGD, and K-Fuel—were designed to provide other be ne fits (e.g., reduction of NO Xor SO 2 em i s s i ons , i m pr ove me nt i nfue l he a t i ng va l u e ) besides m e rcury reduction. Therefore, the higher cost of these m u l t i pol lutant control approaches over control m e thods

51developed solely for m e rcury control should be considered with special attention to the greater environ-m e ntal and other benef its associated with m u ltipollutant control

appr oa c h es. For ECO, it was assum e d that 98 percent SO 2 rem oval and 90 percent NO X rem oval were provided in addition to 85 percent m e rcury reduction. For advanced dry FGD, it was assum e d that 90 percentSO 2 rem oval was achieved in addition to about 95 percent m e rcury reduction. For K Fu el, the reduction of em issions of other pollutants, especially SO 2 and NO X , will depend upon how the K-Fuel com p ares to the base fuel. For exam ple, the K-Fuel has 44 percent lower sulfur content o n a h e ating value basis than the base DOE PRB. Theref ore, the environm ental benefits of these

m e thods—over and above m e rcury reduction—can be very significant.

9. Costs include capital and operating costs associated with the retrofit and the expected cost of a continuous em ission m onitoring system (CEMS). The cost of existing technology is not included in the cost estim at e. However, the effect of existing technology is included in the total m e rcury rem oval perform ance. In som e cases, existing technology will provide ad eq u a te m e rcu r y

rem oval and no additional m e rcury rem oval technology is required. In these cases, a sm all cost associated with the expected cost of

the m e rcury CEMS will be shown.

10. In this ana l ys i s i twas assum e d that the percent m e rcury rem oval possible from additional controls was not affected by th e m e rcury rem oval from existing controls. While it is possible that there m ay be som e interaction, this is not expected to be a significant effect for the cases evaluated here.

11. In all of the cases evaluated here, the cost calculations assum e d that all collected fly ash is cu rren t ly sold. Therefore, calculations f o r PAC injection conf igurations in which f l y ash and PAC are collected together include increm ental costs to landf ill f l y ash at a cost of $30/ton. In m any cases these costs will not be increm ental because fly ash

m a y currently be landfilled or because fly ash may not be r e ndered com p letely unacceptable f o r re-use. The large m a jority of plants currently landf ill their f l yash, 30 and PAC injection would increase disposal costs only in proportion to P A C usage f o r them . A l so, i ns i tu a t i ons whe r e flyash is currently sold, fly ash contam ina t e d wi ths o me us e d PAC

m i ght still be beneficially reused depending upon the am ount of PAC added, the properties of the fly ash, and the intended use of the sold ash. According to ASTM St a ndard C618-03, coal fly ash with carbon contents as high as 6 percent m ay be acceptable as a concrete additive. 73 Ther e are other criteria that m ay determ ine

52acceptability of the fly ash as an additive to a buyer. However, the presence of sm all

am ounts of carbon in the fly ash will not nece ssarily render it unacceptable f o r benef i cial re-use. Disposal costs can be a signif i cant portion of total costs. As will be shown in a sensitivity analysis, elim ination, or at least a reduction, of disposal costs can significantly im prove economics of PAC injection from wha t i s pr e s e n t e d i n t

h i s section. The ash content of the coal ( on a heat i ng va lue basis) largely determ in e s th e m a g n itu d e of

this cost im pact. So, coals with highe r or lower ash contents will have higher or low e r ash disposal costs, respectively. Base d upon the characteristics of the f u els used in this program , the cost of landfilling fly ash at $30/ton is estim ated to be about 0.37

m ills/kWhfor the low sulfur bitum i nous cases with PAC injection. Sim ilarly, for the subbitum i nous and high-sulfur bitum i nous cases with PAC injection, the cost of landfilling fly ash at $30/ton is estim ated to be about 1.01 m ills/kWhand about 0.93

m ills/kWh, respectively. Because these costs, wh ic hm ayn o t a

p p l yin s o m e c a s e s , ar e included as increm ental costs in the resu lts shown whenever a PJFF is not added to segregate the fly ash from the injected PA C, the cost estim ates shown here should be regarded as likely to overestim ate the cost in this respect.



### 6.2 Fuel Ty pes, Plant Characteristics, and Model Plant Cases

Four different fuel types were evaluated for estim ating cos t s of me r c ury control options presented in the f o llowing chapter:

1. A high sulfur bitum i nous coal 2. A low sulfur bitum i nous coal 3. A PRB Coal 4. A special, subbitum i nous fuel from K-Fuel.

The first three fuels are taken from Reference 4, where the fuel inform ation was developed by NETL of the Departm e nt of Energy. The properties of these fuels are identified in Table 7 below.

53Table 7. Fuels Used In Model Plant Analysis

Contents Coal Type High Sulfur Bituminous Low Sulfur Bituminous PRB Subbituminous K-Fuel Proximate Analysis (ASTM, as received) Volatile Matter (wt%) 40.40 44.00 30.79 40.20 Fixed Carbon (wt%) 47.50 50.00 32.41 45.50 100.00 100.00 100.00 99.62 Ultimate Analysis (ASTM, as received) Moisture (wt%) 3 .10 2 .20 30.40 7.50 Carbon (wt%) 69.82 78.48 47.85 66.70 Hydrogen (wt%) 5 .00 5 .50 3 .40 4 .80 Nitrogen (wt%) 1 .26 1 .30 0 .62 1 .00 Chlorine (wt%) 0 .12 0 .12 0 .03 0 .03 Sulfur (wt%) 3 .00 0 .60 0 .48 0 .38 Ash (wt%) 9 .00 3 .80 6 .40 6 .42 Oxygen (wt%) 8 .70 8 .00 10.82 13.20 Total (wt%) 100.00 100.00 100.00 100.03 Mercury (mg/kg) 0.10 0.10 0.07 0.04 Modified Mott Spooner HHV (Btu/lb) 12,676. 14,175. 8304. 11,718. Coal Ash Analysis (ASTM, as received) SiO 2 (wt%) 29.00 51.00 31.60 28.40 Al 2 O 3 (wt%) 17.00 30.00 15.30 17.30 TiO 2 (wt%) 0 .74 1 .50 1 .10 1 .60 Fe 2 O 3 (wt%) 36.00 5.60 4.60 6.00 CaO (wt%) 6 .50 4 .20 22.80 23.50 MgO (wt%) 0 .83 0 .76 4 .70 4 .00 Na 2 O (wt%) 0 .20 1 .40 1 .30 1 .40 K 2 O (wt%) 1 .20 0 .40 0 .40 0 .27 P 2 O 5 (wt%) 0 .22 1 .80 0 .80 2 .43 SO 3 (wt%) 7 .30 2 .60 16.60 13.63 Other Unaccounted for (wt%) 1 .01 0 .74 0 .80 1 .47 Total (wt%) 100.00 100.00 100.00 100.00

Cost s for installing and operating the m e rcury control technologies described in previous sections are estim ated with model plants. Approximately 75 percent of the existing coal-f ired utility boilers in the United States are equipped with E S P s f o r th e co ntro l o f P M

. 8 The rem a ining boilers employ FFs, particulat es c r u

bbers, or other equipm ent for control of PM. Additionally, units firing m e dium

t o - h i gh s u l f ur

c o a l s may us e FGD technologies to m e e t th e i r SO 2 control requirem e nts. Generally,

54larger units firing high sulfur c oa l s e m pl oy wet FGD, and sm aller units firing m e dium sulfur coals

us e spray dryers. Wh ile developing the m odel plants, the s e PM and SO 2 control possibilities were taken into account.

Several m odel plants, with various flue gas cl eaning equipm ent configurations and firing either bitum i nous or subbitum i nous coal, were used in th is work. Table 7 exhibits fuels used in m odel plants. Power plant characteristics are given in Table 8, and m odel plants are shown in Table 9. Note that boiler sizes of 100 and 975 MW used in this work were selected to approxim a tely span the range of existing boiler sizes and to be consis tent with the size of th e m odel plants used in previous work. 4 It was also envisioned that use of S CR can enhance oxidation of m e rcury in flue g a s a n d r e sult in the “co-benef it” of increased m e rcury rem oval in wet FGD. S i n c eS C R is a c a p ita lintensive technology, generally its use is cost

- e ffe c t i ve on l ar ge r boi l e r s i z e s . Ac c o rdingly, in this work, the m e rcury co-benef it resulting f r om SCR use was evaluated f o r m odel plants utilizing large (975 MW ) boilers and wet FGD.

Table 8. Power Plant Characteristics

Characteristic Units V alue MW Equivalent of Flue Gas to Control System MW 100, 300, 500, 975 Net Plant Heat Rate Btu/kWh 10,500 Plant Capacity Factor % 6 5 Total Air Downstream of Economizer % 120 Air Heater Leakage % 1 2 Air Heater Outlet Gas Temperature ° F 300 Inlet Air Temperature ° F 8 0 Ambient Absolute Pressure in. of Hg 29.4 Pressure after Air Heater in. of H 2 O 1 2 Moisture in Air l b/lb dry air 0 .013 Ash Split Fly Ash % 80 Bottom Ash % 20 Seismic Zone integer 1 -

5556 Table 9. Mercury Control Technology Applications and Co-benefits

Model Plant Size (MW) Coal Existing Controls Additional Controls Co-benefit Case(s) with Type a % S 1 9 7 5 Bit 3 ESP+FGD PAC, PAC +PJFF S CR 2 9 7 5 Bit 3 FF+FGD PAC, PAC +PJFF S CR 3 9 7 5 Bit 3 ESPh +FGD PAC, PAC +PJFF S CR 4 9 7 5 Bit 3 ESP Ad v Dr y FGD 5 9 7 5 Bit 3 ESP ECO 6 3 0 0 Bit 3 ESP+FGD PAC, PAC +PJFF S CR 7 3 0 0 Bit 3 FF+FGD PAC, PAC +PJFF S CR 8 3 0 0 Bit 3 ESPh +FGD PAC, PAC +PJFF S CR 9 3 0 0 Bit 3 ESP Ad v Dr y FGD 1 0 3 0 0 Bit 3 ESP ECO 1 1 9 7 5 Bit 0 .6 ESP PAC, PAC +PJFF 1 2 9 7 5 Bit 0 .6 FF PAC, PAC +PJFF 1 3 9 7 5 Bit 0 .6 ESPh PAC +PJFF 1 4 9 7 5 Bit 0 .6 ESP ECO 15 975 B i t 0

. 6 FF E C O 1 6 9 7 5 Bit 0 .6 ESPh ECO 1 7 9 7 5 Bit 0 .6 ESP Ad v Dr y FGD 18 975 B it 0

. 6 FF A d v Dry FG D 1 9 9 7 5 Bit 0 .6 ESPh Ad v Dr y FGD 20 975 S ubbit 0

. 5 E S P P A C , P A C + P JFF 21 975 S ubbit 0

. 5 FF P A C , P A C + P JFF 22 975 Subbit 0 .5 ESPh PAC +PJFF 23 975 S ubbit 0. 5 E S P E C O 24 975 S ubbit 0

. 5 FF E C O 25 975 Subbit 0 .5 ESPh ECO 2 6 1 0 0 Bit 3 SD+ESP PAC, PAC +PJFF 2 7 1 0 0 Bit 3 SD+FF PAC, PAC +PJFF 2 8 1 0 0 Bit 3 ESPh +FGD PAC +PJFF 2 9 1 0 0 Bit 0 .6 ESP PAC, PAC +PJFF 3 0 1 0 0 Bit 0 .6 FF PAC, PAC +PJFF 3 1 1 0 0 Bit 0 .6 ESPh PAC +PJFF 3 2 1 0 0 Bit 0 .6 ESP ECO 33 100 B i t 0

. 6 FF E C O 3 4 1 0 0 Bit 0 .6 ESPh ECO 3 5 1 0 0 Bit 0 .6 ESP Ad v Dr y FGD 36 100 B it 0

. 6 FF A d v Dry FG D 3 7 1 0 0 Bit 0 .6 ESPh Ad v Dr y FGD 38 100 S ubbit 0

. 5 E S P P A C , P A C + P JFF 39 100 S ubbit 0

. 5 FF P A C , P A C + P JFF 40 100 Subbit 0 .5 ESPh PAC +PJFF 41 100 S ubbit 0. 5 E S P E C O 42 100 S ubbit 0

. 5 FF E C O 43 100 Subbit 0 .5 ESPh ECO 4 4 9 7 5 K- Fu e l 0 .4 ESP PAC, PAC +PJFF 45 975 K -Fuel 0. 4 F F P A C , P A C + P JFF 4 6 9 7 5 K- Fu e l 0 .4 ESPh PAC +PJFF 4 7 1 0 0 K- Fu e l 0 .4 ESP PAC, PAC +PJFF 48 100 K -Fuel 0. 4 F F P A C , P A C + P JFF 4 9 1 0 0 K- Fu e l 0 .4 ESPh PAC +PJFF

a B i t = bit u minous coal; S ubbit = subbit u minous coal

### 6.3 C ost Model Results

Three costs are typically shown in the f o llo w i n g tables. O n e is the capital cost expressed in $/kW

. This is the one-tim e capit a l c h a r ge for the equipm ent, installation, start-up, and such. Total annualized cost (Total Cost in the tables) and the Variable Cost, both expressed in m ills/kWh , are also shown. Total Cost includes the annualized capital cost as well as a nnual variable and fixed operating cost. The Variable Cost is only the portion of th e Total Cost that is attributable to variable operating and m a intenance costs. In the f o llowing tables and discussion, the Model Plant num bers are noted so that m o re detailed cost inform ation can be reviewed in the m odel plant tabl es of Appendix 4.

For those appl i c a t i ons, part i c ul ar l yPAC injection, in which m u ltiple m e rcury control levels we r e evaluated (i.e., 50 through 90 percent), several co lumn s are shown in the tables presented. Each

c o l umn i ndi c a t e s th e e s t i m a t e d c ap i t a l c o st ( $ /kW) and total annual cost (m ills/kWh ) for the pla n t size indicated and whether or not a PJFF was a dded. In som e cases, existing controls provided adequate m e rcury reduction, so the onl y i t e msa dde d we r e m e rcury emissions m onitoring equipm ent (no PAC injection or PJFF). Estim ated m e rcury em issions on m g /kWhbasis are also indicated in the tables. This estim ated m e rcury em issions num ber m ay be useful for estim ating total m e rcury
m a ss em issions for particular configurations.
Only one level of m e rcury rem oval is shown f o r ECO and advanced dry FGD. Multiple column s and costs are estim ated f o r sensitivity to dif f e rent variables, such as capital cost.

6.3.1 H igh Sulfur Bituminous Coals (Model Plants 1



### S 10, 26



### S 28)

For all of the m odel plants in which high sulfur bitum i nous coal is fired, it was assum e d that the boi l e r wa se qui pped with an FGD technology that mi ght include lim estone forced oxidation (LSFO) , SDA, ECO, or advanced dry FGD. In the case of boilers equipped withwet FGD (LSFO), it was

assum e d a ny necessary additional m e rcury control was perform e d through injection of PAC upstream of the existing particulate rem oval device or between the existing particulate rem oval device and a new downstream PJFF. The co-benef it of SCR was also evaluated assum i ng that the com b ination of SCR with LSFO would result in the greater of 90 percent m e rcury rem oval or the am ount of m e rcury rem oval from the existing particle rem oval equipm ent and LSFO.

57For high sulf ur units in which the co-benef it of SCR with LSFO (or wet FGD) is evaluated, the size range chose n wa s 300 MW to 975 MW . The reason 300 MW rather than 100 MW was selected as the low end of the size range is that SCR plus LSFO is a capital-intens ive approach f o r com b ined SO 2 and NO Xcontrol. Therefore, it would be unlikely to be selected over other approaches for SO 2 and NO Xcontrol on a unit as sm all as 100 MW . For ECO and advanced dry FGD, the sam e size range was evaluated for consistency with the LSFO cases. On the other hand, SDA was not assessed f o r large, high-sulf ur f u el boilers because it would rarely be econom ical f o r SO 2 rem oval on such large boilers when com p ared to LSFO.
High Sulfur Coal ESP plus FGD (Model Plants 1, 6) As s hown i n Ta bl e s 10a and 10b, existing e qui pme nt ( E SPc and we t FGD) ar e e xpe c t e d t o pr ovi de 68 percent m e rcury rem oval under the conditions of Model plant #1. Mercury rem oval by PAC injection is necessary for higher m e rcury rem ova l. Under these conditions, to achieve 90 percent

m e rcury rem oval, a PJFF downstream of the ESP and PAC injection wil l pe rm i t m o re econom ical

rem oval through PAC injection. W ith the SCR, PA C injection is not expected to be necessary for achieving over 90 percent rem oval of m e rcury, butPAC i n j e c t i on may be ne c e s s aryfor higher than 90 percent m e rcury rem oval.

High Sulfur Coal FF plus FGD (Model Plants 2, 7) Wh en a f acility is equipped with a f a

bric f ilter and an FGD sy s t e m , it is expected that no additional

m e rcury rem oval will be necessary because 96 percent m e rcury rem o v a l is e xp e c t e d f

r o m e x is tin g equipm ent. In this case SCR co-benefit is not significant because m e rcury rem oval is expected to be high already.

58Table 10a. High Sulfur Coal, ESP plus FGD Without SCR Co-benefit (Model Plants 1, 6) a

Parameter Specified Hg Reduction (%) 50 60 70 80 90 Hg Reduction of Existing Equipment (%) 67.7 67.7 67.7 67.7 67.7 Hg Reduction by PAC (%) none none 7.3 38.2 69.1 Total Outlet Hg (mg/MWh) 12.2 12.2 11.3 7 .5 3.8 975 MW and No PJFF b Retrofit PJFF? b no no no no no Capital Cost ($/kW) $0.094 $0.094 $1.601 $2.437 $4.304 Variable Cost (mills/kWh) 0 .000 0.000 1.195 1.447 2.175 Total Cost b (mills/kWh) 0 .003 0.003 1.242 1.520 2.303 975 MW w i th PJFF Retrofit PJFF? no no yes y es yes Capital Cost ($/kW) $0.094 $0.094 $36.216 $36.322 $36.538 Variable Cost (mills/kWh) 0 .000 0.000 0.215 0.234 0.278 Total Cost (mills/kWh) 0 .003 0.003 1.122 1.144 1.195 300 MW and No PJFF b Retrofit PJFF? b no no no no no Capital Cost ($/kW) $0.126 $0.126 $2.370 $3.600 $6.330 Variable Cost (mills/kWh) 0 .000 0.000 1.195 1.447 2.175 Total Cost b (mills/kWh) 0 .004 0.004 1.265 1.554 2.363 300 MW w i th PJFF Retrofit PJFF? no no yes y es yes Capital Cost ($/kW) $0.126 $0.126 $45.989 $45.147 $46.467 Variable Cost (mills/kWh) 0 .000 0.000 0.215 0.234 0.278 Total Cost (mills/kWh) 0 .004 0.004 1.352 1.376 1.430

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices. b The calculations performed to generate t he results in this table assumed t hat all collected fly ash is currently sold, which is the situation with t he most conservative assumption. T herefore, these ca lculations include costs to landfill fly ash with an impact to total cost of around 0.93 mills/kW h . In many cases these costs will not apply because either ash may cu rrently be landfilled or it may not be rendered completely unacceptable for re-use.

59Table 10b. High Sulfur Coal, ESP plus FGD With SCR Co-benefit (Model Plants 1, 6) a

Parameter Specified Hg Reduction (%) 50 60 70 80 90 Hg Reduction of Existing Equipment (%) 90. 90. 90. 90. 90. Hg Reduction by PAC (%) none none none none none Total Outlet Hg (mg/MWh) 3 .8 3.8 3 .8 3.8 3 .8 975 MW Retrofit PJFF? no no no no no Capital Cost ($/kW) $0.094 $0.094 $0.094 $0.094 $0.094 Variable Cost (mills/kWh) 0 .000 0.000 0.000 0.000 0.000 Total Cost (mills/kWh) 0 .003 0.003 0.003 0.003 0.003 300 MW Retrofit PJFF? no no no no no Capital Cost ($/kW) $0.126 $0.126 $0.126 $0.126 $0.126 Variable Cost (mills/kWh) 0 .000 0.000 0.000 0.000 0.000 Total Cost (mills/kWh) 0 .004 0.004 0.004 0.004 0.004

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices.

High Sulfur Coal ESPh plus FGD (Model Plants 3, 8) If

an ESPh is used in com b ination with FGD, it is a s s u m e d th at a low tem p erature PJFF will f o llow the ESP and air preheater. Tables 11a and 11b showthe results of cost estim ates. As shown, the co-benefit of SCR has substantia l cost im pacts because, without SCR, PAC m u st be added with a downstream PJFF.

60Table 11a. High Sulfur Coal, ESPh plus FGD Without SCR Co-benefit (Model Plants 3, 8) a

Parameter Specified Hg Reduction (%) 50 60 70 80 90 Hg Reduction of Existing Equipment (%) 65.0 65.0 65.0 65.0 65.0 Hg Reduction by PAC (%) none none 14.3 42.9 71.4 Total Outlet Hg (mg/MWh) 13.2 13.2 11.3 7 .5 3.8 975 MW Retrofit PJFF? no no yes y es yes Capital Cost ($/kW) $0.094 $0.094 $36.236 $36.345 $36.566 Variable Cost (mills/kWh) 0 .000 0.000 0.218 0.239 0.284 Total Cost (mills/kWh) 0 .003 0.003 1.126 1.149 1.201 300 MW Retrofit PJFF? no no yes y es yes Capital Cost ($/kW) $0.126 $0.126 $46.018 $46.180 $46.508 Variable Cost (mills/kWh) 0 .000 0.000 0.218 0.239 0.284 Total Cost (mills/kWh) 0 .004 0.004 1.357 1.382 1.437

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices.

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

Parameter Specified Hg Reduction (%) 50 60 70 80 90 Hg Reduction of Existing Equipment (%) 90. 90. 90. 90. 90. Hg Reduction by PAC (%) none none none none none Total Outlet Hg (mg/MWh) 3 .8 3.8 3 .8 3.8 3 .8 975 MW Retrofit PJFF? no no no no no Capital Cost ($/kW) $0.094 $0.094 $0.094 $0.094 $0.094 Variable Cost (mills/kWh) 0 .000 0.000 0.000 0.000 0.000 Total Cost (mills/kWh) 0 .003 0.003 0.003 0.003 0.003 300 MW Retrofit PJFF? no no no no no Capital Cost ($/kW) $0.126 $0.126 $0.126 $0.126 $0.126 Variable Cost (mills/kWh) 0 .000 0.000 0.000 0.000 0.000 Total Cost (mills/kWh) 0 .004 0.004 0.004 0.004 0.004

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices.

61ESP plus AdvDry FGD (Model Plants 4, 9) Because of the high lev e ls of m e rcury reduction th at are assum e d to occur with advanced dry FGD on bitum i nous coals (over 95 percent m e rcury re m oval was m easured at the Roanoke facility), 42 additional m e rcury rem oval by PAC injection is not necessary. As will be shown later, this technology is m o re cost effective on low sulfur coals than on high sulfur coals as shown here. It should also be kept in m i nd that this technol ogy, while m o re costly than PAC injection, provides SO 2 rem oval. An SO 2 rem oval of 90 percent was assum e d for each of these cases.

Due to the lim ited experience with this technology on utility plants in the United Ststes, capital cost estim ates m ay be uncertain. Sensitivity of the total cost with respect to capital cost is shown in Table 12. The base estim ated cost for the size range is shown in bold on Table 12. Sensitivity analysis in a later section of this report and th e appendices also show cost sensitivity with respect to reagent price.

Table 12. Advanced Dry FGD on High Sulfur Coal (Model Plants 4, 9), S ensitivity to Capital Cost a

Parameter Capital Cost Category b -20% -10% Projected + 10% +20% Hg Reduction of Existing Equipment (%) 29.4 29.4 29.4 29.4 29.4 Hg Reduction of Advanced Dry FGD c (%) 95.0 95.0 95.0 95.0 95.0 Total Hg Removal (%) 96.5 96.5 96.5 96.5 96.5 Total Outlet Hg (mg/MWh) 1 .327 1.327 1.327 1.327 1.327 975 MW Capital Cost ($/kW) $115.46 $129.80 $144.23 $158.65 $173.07 Variable Cost (mills/kWh) 5 .323 5.323 5.323 5.323 5.323 Total Cost (mills/kWh) 7 .940 8.265 8.592 8.919 9.246 300 MW Capital Cost ($/kW) $127.47 $143.30 $159.23 $175.15 $191.07 Variable Cost (mills/kWh) 5 .323 5.323 5.323 5.323 5.323 Total Cost (mills/kWh) 8 .212 8.571 8.932 9.293 9.654

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices.
b Capital Cost (115.28

S 173.07 $/kW for a 975 MW plant and 127.47

S 191.07 $/kW for a 300 MW plant) is the variable.

c Advanced dry FGD is a technology developed primarily for SO 2 mercury control for bituminous coal. removal; however, it can also provide

62ESP plus ECO (Model Plants 5 and 10) ECO is an em erging technology that appears to be capable of high pollution reduction. Because it is an em erging techn o logy, the sensitivity of tota l cost to capital cost was assessed and is shown in Table 13. The econom ics rely, in part, on the revenue from fertilizer product sales and on the value of power. Sensitivity analyses for the eff ect of fertilizer product value and for power cost are shown in a later section of this report and in the appendices. For high sulf ur coals, a high am ount of fertilizer product is possible, wh ich m akes the econom ics of th e process appear m o re favorable than f o r lower sulf ur applications.

Table 13. ESP and ECO on High Sulfur Coal (Model Plants 5 and 10), S ensitivity to Capital Cost a

Parameter Capital Cost Category b -20% -10% Projected + 10% +20% Hg Reduction of Existing Equipment (%) 29.4 29.4 29.4 29.4 29.4 85.0 85.0 85.0 85.0 89.4 89.4 89.4 89.4 ECO Hg Reduction FGD c (%) 85.0 Total Hg Reduction (%) 89.4 Total Outlet Hg (mg/MWh) 3 .98 3 .98 3 .98 3 .98 3 .98 975 MW Capital Cost ($/kW) $150.28 $169.05 $187.83 $206.60 $225.38 Variable Cost d (mills/kWh)

- 0.820 -0.820 -0.820 -0.820 -0.820 Total Cost (mills/kWh) 3 .276 3.764 4.252 4.740 5.228 300 MW Capital Cost ($/kW) $190.23 $214.00 $237.76 $261.53 $285.29 Variable Cost d (mills/kWh)

- 0.820 -0.820 -0.820 -0.820 -0.820 Total Cost (mills/kWh) 4 .741 5.359 5.977 6.595 7.212

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices. b Capital Cost (150.28

S 225.38 $/kW for a 975 MW plant and 190.23

S 285.29 $/kW for a 300 MW plant) is the variable. ECO is a technology developed primarily for NO X and SO 2 removal; however, it can also provide mercury control. d Variable Cost includes a credit for fertilizer by-pr oduct sale. Negative numbers imply a net credit. Variable Cost also includes the cost of power for the barri er discharge reactor—estima ted at about 4.8% of plant output for this case.

63 c100 M W SDA and ESPc (Model Plant 26) For high sulfur fuels, a SDA with a downstream ESP is not expected to be very effective for me r c ury
rem oval. Therefore, m o st of the m e rcury rem ova l must be perform e d by additional PAC i n j e c t i on. In this case, a PJFF m ay be installed upstream of the S D Aand m u st be sized f o r collection of the f u ll ash loading plus the P A C injection. Altern atively, a sm aller polishi ng PJF F m a y be installed downstream of the existing ESP. As will be shown later, a SDA with a

d o w n s tr e a m

PJFF is expected to achieve relatively high m e rcury rem oval and will only require m oder a te PAC injection to achieve the additional reduction necessary for 90 percent rem oval. Therefore, it m ay be m o re econom ical to install a polishing PJFF downstream of the ESP ( C OHPAC conversion) and still inject the PAC upstream of the SDA than to install a PJFF sized for collection of the full ash loading plus the PAC injection. However, because data is not available on m e rcury rem oval from an SDA with a downstream COHPAC, it is uncertain if an SDA with a downstream COHPAC arrangem e nt would be as effective in rem oving m e rcury as an SDA with downstream PJFF.

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

Parameter Specified Hg Reduction (%) 50 60 70 80 90 Hg Reduction of Existing Equipment (%) 5 .0 5.0 5 .0 5.0 5 .0 Hg Reduction by PAC (%) 47.4 57.9 68.4 78.9 89.5 Total Outlet Hg (mg/MWh) 16.8 13.5 10.1 6 .7 3.4 100 MW no PJFF Retrofit PJFF? no no no no no Capital Cost ($/kW) $6.014 $7.235 $8.996 $11.818 $17.266 Variable Cost (mills/kWh) 0 .659 0.877 1.226 1.861 3.309 Total Cost (mills/kWh) 0 .838 1.092 1.493 2.211 3.821 100 MW and Full Size PJFF Retrofit PJFF? yes y es yes y es yes Capital Cost ($/kW) $110.342 $110.891 $111.094 $111.413 $112.065 Variable Cost (mills/kWh) 0 .242 0.255 0.275 0.308 0.383 Total Cost (mills/kWh) 2 .907 2.934 2.960 3.002 3.096 100 MW w i th PJFF (COHPAC conv ersion) Retrofit PJFF? yes y es yes y es yes Capital Cost ($/kW) $57.612 $57.970 $58.174 $58.495 $59.149 Variable Cost (mills/kWh) 0 .243 0.257 0.277 0.310 0.385 Total Cost (mills/kWh) 1 .657 1.680 1.706 1.749 1.843

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices.

64100 M W SDA and FF (Model Plant 27) As shown in Table 15, a SDA with a downstream f

a

br ic f i lter is expected to provide high m e rcury
rem oval, approaching 90 percent. A sm all am ount of PAC m i ght be adde d upstream of the SDA to provide som e m o re m e rcury reduction at a relatively low cost.

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

Parameter Specified Hg Reduction (%) 50 60 70 80 90 Hg Reduction of Existing Equipment (%) 89.3 89.3 89.3 89.3 89.3 Hg Reduction by PAC (%) none none none none 6.3 Total Outlet Hg (mg/MWh) 4 .0 4.0 4 .0 4.0 3 .8 100 MW, no PJFF Retrofit PJFF? no no no no no Capital Cost ($/kW) $0.165 $0.165 $0.165 $0.165 $3.388 Variable Cost (mills/kWh) 0 .000 0.000 0.000 0.000 0.270 Total Cost (mills/kWh) 0 .005 0.005 0.005 0.005 0.370

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices.

65100 M W ESPh and FGD (Model Plant 28) In this case, the ESPh fol l o wed by a wet F GD (LSFO) will provide about 65 percent m e rcury
rem oval, and additional m e rcury rem oval will, ther efore, be necessary to achieve 90 percent. As shown in Table 16, it is m o re econom ical for 90 percent m e rcury rem oval to install a polishing f abric f ilter af ter the air preheater and upstream of the f l ue gas desulf urization than to only inject PAC without the fabric filter. But for 70 percen t rem oval, it m ay be m o st econom ical to inject PAC in the ductwork between the air preheater and the FGD.

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

Parameter Specified Hg Reduction (%) 50 60 70 80 90 Hg Reduction of Existing Equipment (%) 89.3 89.3 89.3 89.3 89.3 Hg Reduction by PAC (%) none none none none 6.3 Total Outlet Hg (mg/MWh) 4 .0 4.0 4 .0 4.0 3 .8 100 MW w i thout PJFF Retrofit PJFF? no no no no no Capital Cost ($/kW) $0.165 $0.165 $3.751 $5.595 $9.657 Variable Cost (mills/kWh) 0 .000 0.000 1.236 1.510 2.287 Total Cost (mills/kWh) 0 .005 0.005 1.347 1.675 2.573 100 MW w i th PJFF Retrofit PJFF? no no yes y es yes Capital Cost ($/kW) $0.165 $0.165 $57.533 $57.767 $58.241 Variable Cost (mills/kWh) 0 .000 0.000 0.217 0.237 0.282 Total Cost (mills/kWh) 0 .005 0.005 1.627 1.654 1.714

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices.

6.3.2 Low Sulfur Bituminous Coals These coals are represented by Model Plants 11



### S 19 and 29



### S 37 in Table 9 and have a 0.6 wt% sulphur content as shown in Table 7. The existing controls on these plants are either a cold- or hot-side ESP or FF. Plants with ESPc or FF woul d need additional controls that consist of PAC, PAC with a PJFF, ECO, or advanced dry FGD. Plants with an ESPh would need PAC with a PJFF, ECO, or FF.

66With ESPc and No SO 2 controls (Model Plants 11 and 29) For these cases, PAC injection is expected to be necessary for m e rcury reduction in excess of 50 percent. As shown in Table 17, addition of a PJFF for the 975 MW plant case im proves overall

econom ics f o r rem oval in excess of 70 percent. Ho wever, for a sm aller 100 MW plant, the addition of a polishing PJFF is m o re econom ical only for the 90 percent m e rcury rem oval case.

Table 17. Low Sulfur Coal, ESPc, and No SO 2 Controls (Model Plants 11 and 29) a

Parameter Specified Hg Reduction (%) 50 60 70 80 90 Hg Reduction of Existing Equipment (%) 50.6 50.6 50.6 50.6 50.6 Hg Reduction by PAC (%) none 19.0 39.2 59.5 79.7 Total Outlet Hg (mg/MWh) 16.601 13.452 10.089 6.726 3.363 975 MW and No PJFF b Retrofit PJFF? b no no no no no Capital Cost ($/kW) $0.094 $1.855 $2.467 $3.490 $5.711 Variable Cost (mills/kWh) 0 .000 0.709 0.901 1.277 2.282 Total Cost b (mills/kWh) 0 .003 0.764 0.974 1.381 2.451 975 MW w i th PJFF Retrofit PJFF? no yes y es yes y es Capital Cost ($/kW) $0.094 $36.248 $36.324 $36.445 $36.690 Variable Cost (mills/kWh) 0 .000 0.220 0.234 0.258 0.311 Total Cost (mills/kWh) 0 .003 1.128 1.144 1.171 1.233 100 MW and No PJFF b Retrofit PJFF? b no no no no no Capital Cost ($/kW) $0.165 $3.791 $5.271 $7.430 $12.057 Variable Cost (mills/kWh) 0 .000 0.709 0.901 1.277 2.282 Total Cost b (mills/kWh) 0 .005 0.827 1.057 1.497 2.639 100 MW w i th PJFF Retrofit PJFF? no yes y es yes y es Capital Cost ($/kW) $0.165 $57.563 $57.729 $57.989 $58.518 Variable Cost (mills/kWh) 0 .000 0.220 0.234 0.258 0.311 Total Cost (mills/kWh) 0 .005 1.631 1.650 1.682 1.751

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KWh. For a more comprehensive breakdown of costs, please see the model plant tables in the appendices. b The calculations performed to generate the results in this table assumed that all collected fly ash is currently sold, which is the situation with the most conservative assumption. Therefore, these calculations include costs to landfill fly ash with an impact to total cost of around 0.93 mills/kWh. In many cases these costs will not apply because either ash may currently be landfilled or it may not be rendered completely unacceptable for re-use.

67With FF and No SO 2 controls (Model Plants 12 and 30) D u e to the high m e rcury rem oval expected from existing equipm ent in these cases, PAC injection is only expected to be necessary for m e rcury reduc tion in excess of 85 percent. As shown i nTabl e 18, installation of a PJFF is expected to be ec onom ically beneficial for neither the 975 nor the 100 MW plant cases.

Table 18. Low Sulfur Coal, FF, and No SO 2 Controls (Model Plants 12 and 30) a

Parameter Specified Hg Reduction (%) 50 60 70 80 90 Hg Reduction of Existing Equipment (%) 85.0 85.0 85.0 85.0 85.0 Hg Reduction by PAC (%) none none none none 33.3 Total Outlet Hg (mg/MWh) 5 .0 5.0 5 .0 5.0 3 .4 975 MW and No PJFF b Retrofit PJFF? b no no no no no Capital Cost ($/kW) $0.094 $0.094 $0.094 $0.094 $0.821 Variable Cost (mills/kWh) 0 .000 0.000 0.000 0.000 0.458 Total Cost b (mills/kWh) 0 .003 0.003 0.003 0.003 0.482 975 MW w i th PJFF Retrofit PJFF? no no no no yes Capital Cost ($/kW) $0.094 $0.094 $0.094 $0.094 $36.299 Variable Cost (mills/kWh) 0 .000 0.000 0.000 0.000 0.229 Total Cost (mills/kWh) 0 .003 0.003 0.003 0.003 1.139 100 MW and No PJFF b Retrofit PJFF? b no no no no no Capital Cost ($/kW) $0.165 $0.165 $0.165 $0.165 $1.752 Variable Cost (mills/kWh) 0 .000 0.000 0.000 0.000 0.458 Total Cost b (mills/kWh) 0 .005 0.005 0.005 0.005 0.510 100 MW w i th PJFF Retrofit PJFF? no no no no yes Capital Cost ($/kW) $0.165 $0.165 $0.165 $0.165 $57.674 Variable Cost (mills/kWh) 0 .000 0.000 0.000 0.000 0.229 Total Cost (mills/kWh) 0 .005 0.005 0.005 0.005 1.644

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices. b The calculations performed to generate t he results in this table assumed t hat all collected fly ash is currently sold, which is the situation with t he most conservative assumption. T herefore, these ca lculations include costs to landfill fly ash with an impact to total cost of around 0.93 mills/kW h . In many cases these costs will not apply because either ash may cu rrently be landfilled or it may not be rendered completely unacceptable for re-use.

68With ESPh and No SO 2 Controls (Model Plants 13 and 31) Due to the low m e rcury rem oval possible f r om existing equipm ent in these cases, PAC injection is expected to be necessary for all of the conditions, and a polishing PJFF m u st be added because PAC injection would norm a lly be added downst r e am of t h e ESPh a nd a i r preheater. Table 19 shows the econom ics of this type of installation for 975 MW and 100 MW plants.

Table 19. Low Sulfur Coal, ESPh, and No SO 2 Controls (Model Plants 13 and 31) a

Parameter Specified Hg Reduction (%) 50 60 70 80 90 Hg Reduction of Existing Equipment (%) 25.5 25.5 25.5 25.5 25.5 Hg Reduction by PAC (%) 32.9 46.3 59.7 73.2 86.6 Total Outlet Hg (mg/MWh) 16.8 13.5 10.1 6 .7 3.4 975 MW Retrofit PJFF? yes y es yes y es yes Capital Cost ($/kW) $36.162 $36.360 $36.447 $36.584 $36.865 Variable Cost (mills/kWh) 0 .229 0.241 0.258 0.287 0.353 Total Cost (mills/kWh) 1 .135 1.152 1.172 1.205 1.280 100 MW Retrofit PJFF? yes y es yes y es yes Capital Cost ($/kW) $57.458 $57.805 $57.994 $58.290 $58.893 Variable Cost (mills/kWh) 0 .229 0.241 0.258 0.287 0.353 Total Cost (mills/kWh) 1 .638 1.659 1.682 1.720 1.804

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices.

69ECO Installed after Particulate Removal (Model Plants 14



### S16, 32



### S 34) Since the m o st comm on location for installation of ECO is likely to be after an ESPc and because the econom ics are sim ilar regardless of the exis ting PM rem oval equipm ent, only the results of analysis for ECO installed after an ESPc are shown in Table 20. ECO is a capital-intensive technology, and there rem a ins som e uncertainty re garding its actual capital cost because it is an

em erging technology. Therefore, the cost was evaluated for a range of capital costs plus or m i nus 20 percent of the projected cost for the size un it. The sensitivity analysis of Section 6.4 shows estim ated ECO econom ics while varying the fertili zer product value and the power cost for a 500 MW plant. Additional inf o rm ation is available in the Model Runs in the appendices. For a given coal, unit size, and cost of consum ables, the econom ics of ECO are estim ated to be roughly the

sam e regardless of the type of upstream particulate control device.

Table 20. ECO Installed After Particulate Removal (Model Plants 14



### S 16, 32



### S 34), Sensitivity to Capital Cost a

Parameter Capital Cost Category b -20% -10% Projected + 10% +20% Hg Reduction of Existing Equipment (%) 50.6 50.6 50.6 50.6 50.6 ECO Hg Reduction FGD c (%) 85.0 85.0 85.0 85.0 85.0 Total Hg Reduction (%) 92.6 92.6 92.6 92.6 92.6 Total Outlet Hg (mg/MWh) 2 .49 2 .49 2 .49 2 .49 2 .49 975 MW Capital Cost ($/kW) $150.28 $169.05 $187.83 $206.60 $225.38 Variable Cost d (mills/kWh) 1 .243 1.243 1.243 1.243 1.243 Total Cost (mills/kWh) 5 .340 5.828 6.316 6.804 7.292 100 MW Capital Cost ($/kW) $236.99 $266.59 $296.20 $325.80 $355.41 Variable Cost d (mills/kWh) 1 .243 1.243 1.243 1.243 1.243 Total Cost (mills/kWh) 9 .521 10.021 10.790 11.560 12.329

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices. b Capital Cost (150.28

S 225.38 $/kW for a 975 MW plant and 236.99

S 355.41 $/kW for a 100 MW plant) is the variable. ECO is a technology developed primarily for NO X and SO 2 removal; however, it can also provide mercury control. Data shown is for retrofit on a boiler with existing ESPc. For boilers with existing ESPh or FF, costs would be very similar, but outlet mercury would diffe r somewhat from what is shown here. See appendices for details d Variable Cost includes a credit for fertilizer by-pr oduct sale. Negative numbers imply a net credit. Variable Cost also includes the cost of power for the barri er discharge reactor—estima ted at about 4.8% of plant output for this case.

70 cAdvanced Dry FGD (Model Plants 17



### S19, 35



### S 37) Advanced Dry FGD is another technology that is som e what capital intensive and controls SO 2 and m e rcury. Like ECO, the econom ics are a strong function of capital cost and sulfur level and less affected by the type of upstream particul ate control technology. Shown in Table 21 are the results of analysis for advanced dry FGD downstream of an existing ESPc.

Table 21. Advanced Dry FGD (Model Plants 17

S 19, 35

S 37), Sensitiv ity to Capital Cost a

Parameter Capital Cost Category b -20% -10% Projected + 10% +20% Hg Reduction of Existing Equipment (%) 50.6 50.6 50.6 50.6 50.6 95.0 95.0 95.0 95.0 97.5 97.5 97.5 97.5

0.830 0.830 0.830 0.830 Hg Reduction of Advanced Dry FGD c (%) 95.0 Total Hg Removal (%) 97.5 Total Outlet Hg (mg/MWh) 0 .830 975 MW Capital Cost ($/kW) $115.46 $129.80 $144.23 $158.65 $173.07 Variable Cost (mills/kWh) 1 .071 1.071 1.071 1.071 1.071 Total Cost (mills/kWh) 3 .688 4.013 4.340 4.667 4.994 100 MW Capital Cost ($/kW) $162.17 $182.31 $202.57 $222.82 $243.08 Variable Cost (mills/kWh) 1 .071 1.071 1.071 1.071 1.071 Total Cost (mills/kWh) 4 .747 5.203 5.662 6.122 6.581

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices. b Capital Cost (115.28

S 173.07 $/kW for a 975 MW plant and 162.17

S 243.08 $/kW for a 100 MW plant) is the variable. Advanced dry FGD is a technology developed primarily for SO 2 removal; however, it can also provide mercury control for bituminous coal. Data shown is fo r retrofit on a boiler with existing ESPc. For boilers with existing ESPh or FF, costs would be very similar, but outlet mercury may differ somewhat from what is shown here. See appendices for details.

6.3.3 Low Sulfur Subbituminous Coals Including Pow d er River Basin Coals
Mercury rem oval with existing equipm entis typically lower for subbitum i nous coals than for bitum i nous coals. As a result, m e rcury reducti on is m o re dependent on PAC injection for high l e vels of m e rcury rem oval. In the case of bo ilers currently equipped with ESPs, it m a y notbe p o s s i ble to achieve 80 or 90 percent reduction w ithout addition of a downstream P J F F as in d i cated in Model Plant s 20



### S 22 and 38



### S 40. ECO is exam ined on Model Plants 23



### S 25 and 41



### S 43. The effectiveness and cost of K-Fuel as a m e rcur y control technology is exam ined in Model Plants 44



### S49. The K-fuel process is prim arily designed to im prove fuel-heating value, but i t

a l s o provides

som e SO 2 reduction, m ay provide NO Xreduction, and provides m e rcury reduction.

71 cBoilers with Particulate Control and No SO 2 Control (Model Plants 20



### S 22, 38



### S 40) As shown in Table 22 for the cases without a downstream PJFF, estim ates for 80 or 90 percent

me r c ur y r e duc t i on s how hi gh c o s t s due t o hi gh pr e d i c t e d i n j e c tion rates. It is recognized t h a t , de s p i t e the high injection rates, the specified Hg reduction ma y not be achievable without addition of

aPJ FF a f t e r th e ESP. Howe ve r , it should be noted tha t th e a l gor i th ms us e d for PAC i n j e c t i on he r e (Equation 9 a nd t h e a s s o ciated constants for this case) were developed from test results at the Pleasant Prairie Power Plant, which had a coal chlorine content of only 15 ppm , which is lower than typically expected for this type of fuel. 19 So, it is possible that other PRB fueled boilers m ay be easier to control with PAC than those shown here.

For m e rcury reduction from boilers firing subb itum i nous coals and equipped with a downstream FF, PAC injection is necessary for greater than about 60 percent m e rcury reduction. Addition of a downstream PJFF provides the benefit of m u ch lower waste disposal costs because fly ash is not contam inated. Therefore, although the cost of sorbent is sim ilar regardless of whether or not a PJFF is added, the additional cost of waste dis posal roughly com p ensates for the cost of the PJFF for the 975 MW case as shown in Table 23.
In the case where an ESPh is currently installe d, it is necessary to install a downstream PJFF f o r
m e rcury rem oval by PAC injection. As shown in Table 24, this can generally be perform e d at a cost of below 2 m ills/kWh

. PRB Coals with ECO (Model Plants 23



### S 25, 41



### S 43) Since the m o st comm on installation for an ECO is likely to be after an ESPc and the econom ics are sim ilar regardless of existing particle rem oval equipm ent, only the ECO after an ESPc is shown in Table 25. ECO is a capital-inte nsive technology, and there rem a in s som e uncertainty regarding its cap ital cost because it is an em erging technol ogy. Theref o r e, th e co st w a s ev alu ated f

o r a ran g e of

capital costs within 20 percent of the projected cost for the si ze unit. The m odel runs in the appendices show estim ated ECO econom ics for various fertilizer product value and power value for 975 MW and 100 MW plants equipped w ith E S P c , F F , or E S P h. T h e low e r N O X level associated with PRB coals helps to reduce the power dem and of the ECO ba rr i e r di s c har g e r e a c t or c o mpar e d to the power dem a nd of the ECO barrie r di s c har g e r e a c tor when firing bitum i nous coals. However, because of the low fertilizer product re ve nue (due to low NO Xand SO 2 levels f o r PRB coals),

econom ics of ECO on this application are estim ated to be less favorable than for the bitum i nous coals that have higher NO Xand SO 2 levels.

72Table 22. Low Sulfur Subbituminous Coals, ESPc, and No SO 2 Control (Model Plants 20, 38) a

Parameter Specified Hg Reduction (%) 50 60 70 80 90 Hg Reduction of Existing Equipment (%) 29.7 29.7 29.7 29.7 29.7 Desired Hg Reduction by PAC (%) 28.9 43.1 57.3 71.5 85.8 Actual Hg Reduction by PAC (%) without PJFF b 28.9 43.1 57.3 69.3 69.3
Total Actual Hg Reduction without PJFF b 50.0 60.0 70.0 78.5 78.5 975 MW w i th ESPc and No PJFF c Retrofit PJFF? c no no no no no Capital Cost ($/kW) $0.401 $1.238 $3.232 $27.744 $27.744 Variable Cost (mills/kWh) 1 .027 1.181 1.811 20.102 20.102 Total Cost c(mills/kWh) 1 .039 1.218 1.907 20.924 20.924 Total Outlet Hg (mg/MWh) 20.1 16.1 12.1 8 .7 8.7 975 MW w i th ESPc and PJFF Retrofit PJFF? yes y es yes y es yes Capital Cost ($/kW) $35.998 $36.258 $36.422 $36.666 $37.139 Variable Cost (mills/kWh) 0 .209 0.231 0.262 0.315 0.435 Total Cost c(mills/kWh) 1 .111 1.139 1.176 1.236 1.369 Total Outlet Hg (mg/MWh) 20.1 16.1 12.1 8 .0 4.0 100 MW w i th ESPc and No PJFF c Retrofit PJFF? c no no no no no Capital Cost ($/kW) $0.840 $2.651 $6.887 $55.806 $55.806 Variable Cost (mills/kWh) 1 .027 1.181 1.811 20.102 20.102 Total Cost c(mills/kWh) 1 .052 1.259 2.015 21.756 21.756 Total Outlet Hg (mg/MWh) 20.1 16.1 12.1 8 .7 8.7 100 MW w i th ESPc and PJFF Retrofit PJFF? yes y es yes y es yes Capital Cost ($/kW) $57.102 $57.585 $57.939 $58.466 $59.479 Variable Cost (mills/kWh) 0 .209 0.231 0.262 0.315 0.435 Total Cost c(mills/kWh) 1 .608 1.643 1.685 1.753 1.903 Total Outlet Hg (mg/MWh) 20.1 16.1 12.1 8 .0 4.0

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices. b W i th PAC injection on subbituminous coals without a dow nstream fabric filter, Hg reduction at very high levels is not expected to be possible. Additi onal PAC injection will not improve Hg reduction.

c The calculations performed to generate t he results in this table assumed t hat all collected fly ash is currently sold, which is the most conservative situation. Therefore, these calculations include costs to landfill fly ash with an impact to total cost of around 1.01 mills/kW h

. In many cases these costs will not apply because ash may currently be landfilled or because ash may not be rendered completely unacceptable for re-use.

73Table 23. Low Sulfur Subbituminous Coals, FF, and No SO 2 Control (Model Plants 21, 39) a

Parameter Specified Hg Reduction (%) 50 60 70 80 90 Hg Reduction of Existing Equipment (%) 60.7 60.7 60.7 60.7 60.7 Hg Reduction by PAC (%) none none 23.6 49.1 74.5 Total Outlet Hg (mg/MWh) 15.8 15.8 12.1 8 .0 4.0 975 MW w i th FF and No PJFF b Retrofit PJFF? b no no no no no Capital Cost ($/kW) $0.094 $0.094 $0.616 $0.842 $1.259 Variable Cost (mills/kWh) 0 .000 0.000 1.057 1.097 1.186 Total Cost b (mills/kWh) 0 .003 0.003 1.075 1.122 1.223 975 MW w i th FF and PJFF Retrofit PJFF? no no yes y es yes Capital Cost ($/kW) $0.094 $0.094 $36.094 $36.320 $37.737 Variable Cost (mills/kWh) 0 .000 0.000 0.203 0.243 0.332 Total Cost c(mills/kWh) 0 .003 0.003 1.106 1.153 1.254 100 MW w i th FF and No PJFF b Retrofit PJFF? b no no no no no Capital Cost ($/kW) $0.165 $0.165 $1.308 $1.799 $2.696 Variable Cost (mills/kWh) 0 .000 0.000 1.057 1.097 1.186 Total Cost c(mills/kWh) 0 .005 0.005 1.096 1.150 1.266 100 MW w i th FF and PJFF Retrofit PJFF? no no yes y es yes Capital Cost ($/kW) $0.165 $0.165 $57.230 $57.721 $58.618 Variable Cost (mills/kWh) 0 .000 0.000 0.203 0.243 0.332 Total Cost c(mills/kWh) 0 .005 0.005 1.604 1.659 1.774

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices. b The calculations performed to generate t he results in this table assumed t hat all collected fly ash is currently sold, which is the most conservative situation. Therefore, these calculations include costs to landfill fly ash with an impact to total cost of around 1.01 mills/kW h

. In many cases these costs will not apply because ash may currently be landfilled or because ash may not be rendered completely unacceptable for re-use.

74Table 24. Low Sulfur Subbituminous Coals, ESPh, and No SO 2 Controls (Model Plants 22, 40) a

Parameter Specified Hg Reduction (%) 50 60 70 80 90 Hg Reduction of Existing Equipment (%) 12.6 12.6 12.6 12.6 12.6 Hg Reduction by PAC (%) 42.8 54.2 65.7 77.1 88.6 Total Outlet Hg (mg/MWh) 20.1 16.1 12.1 8 .0 4.0 975 MW w i th ESPh and PJFF Retrofit PJFF? yes y es yes y es yes Capital Cost ($/kW) $36.119 $36.381 $36.550 $36.806 $37.305 Variable Cost (mills/kWh) 0 .230 0.254 0.289 0.348 0.482 Total Cost (mills/kWh) 1 .135 1.166 1.206 1.273 1.421 100 MW w i th ESPh and PJFF Retrofit PJFF? tes y es yes y es yes Capital Cost ($/kW) $57.365 $57.852 $58.217 $58.766 $59.834 Variable Cost (mills/kWh) 0 .230 0.254 0.289 0.348 0.482 Total Cost c(mills/kWh) 1 .637 1.674 1.720 1.795 1.960

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices.

75Table 25. Low Sulfur Subbituminous Coals with ECO (Model Plants 23



### S 25, 41



### S 43) Sensitivity to Capital Cost a

Parameter Capital Cost Category b -20% -10% Projected + 10% +20% Hg Reduction of Existing Equipment (%) 29.7 29.7 29.7 29.7 29.7 ECO Hg Reduction FGD c (%) 85.0 85.0 85.0 85.0 85.0 Total Hg Reduction (%) 89.5 89.5 89.5 89.5 89.5 Total Outlet Hg (mg/MWh) 4 .24 4 .24 4 .24 4 .24 4 .24 975 MW w i th ESPc Capital Cost ($/kW) $150.28 $169.05 $187.83 $206.60 $225.38 Variable Cost d (mills/kWh) 0 .442 0.442 0.442 0.442 0.442 Total Cost (mills/kWh) 4 .539 5.027 5.515 6.003 6.491 100 MW w i th ESPc Capital Cost ($/kW) $236.99 $266.59 $296.20 $325.80 $355.41 Variable Cost d (mills/kWh) 0 .442 0.442 0.442 0.442 0.442 Total Cost (mills/kWh) 8 .451 9.220 9.990 10.759 11.529

a This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices. b Capital Cost (150.28

S 225.38 $/kW for a 975 MW plant and 236.99

S 355.41 $/kW for a 100 MW plant) is the variable. ECO is a technology developed primarily for NO X and SO 2 removal; however, it can also provide mercury control. Data shown is for retrofit on a boiler with existing ESPc. For boilers with existing ESPh or FF, costs would be very similar, but outlet mercury would diffe r somewhat from what is shown here. See appendices for details d Variable Cost includes a credit for fertilizer by-pr oduct sale. Negative numbers imply a net credit. Variable Cost also includes the cost of power for the barri er discharge reactor—estima ted at about 4.8% of plant output for this case.

Beneficiated Western Coals—K-Fuel Table 26 com p ares the estim ated m e rcury em issions on a m g /MWhbasis for the base PRB coal versus the K-Fuel beneficiated coal. The K-Fu el has about 60 percent less m e rcury than PRB on a unit of heating value basis. Mercury rem oval rates for the particulate rem oval equipm ent are
s i m ila r, with the K-Fuel estim ated to have a slightly higher rem oval with an ESPc due to the slightly lower sulfur level in th e fuel. It is also im portant to note that K-Fuel provides a 44 percent reduction in SO 2 em issions from the base PRB fuel.
Figure 16 shows the econom ics of K-Fuel assum i ng th at all of the increm ental costs of using the fuel are born in an increased fuel cost over PRB fuel.

76 cTabl e 26. C o m p arison of Estim ated Mercury Em issions from P R B and K

- F u el a Boilers Equipped with Particulate Control and No Additional Mercury or SO 2 Controls

Characteristic PRB K -Fuel PRB K -Fuel PRB K -Fuel Particulate Control System ESPc ESPc FF FF ESPh ESPh Hg Reduction with Existing Equipment (%) 29.7 36.8 60.7 60.7 12.6 12.6 Hg from Coal (mg/MWh) 40.2 16.3 40.2 16.3 40.2 16.3 Total Outlet Hg (mg/MWh) 28.2 10.3 15.8 6 .4 35.1 14.2

a The K-fuel process is primarily designed to impr ove fuel-heating value, but it may provide NO X reduction, provides some SO 2 reduction, and provides Hg reduction.

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

Model runs were perform e d for PAC injection on boilers equipped w ith K-Fuel. These are m odel runs 44 through 49, and Tables 27



### S 29 summ arize the results of these m odel runs. The econom ics of

PAC injection f o r K-Fuel are sim ilar to thos e f o r PAC injection f o r PRB, except that it m ay be appropriate to add to t h ese costs the increm ental cost of the K-Fuel over PRB. The m a jor difference is that lower em issions rates are possibl e with K-Fuel than with PRB due to the lower initial m e rcury level.

77Table 27. K-Fuel a , ESPc and No SO 2 Control (Model Plants 44, 47) b

Parameter Specified Hg Reduction (%) 50 60 70 80 90 Hg Reduction of Existing Equipment (%) 36.8 36.8 36.8 36.8 36.8 Desired Hg Reduction by PAC (%) 20.9 36.7 52.5 68.3 84.2 Actual Hg Reduction by PAC (%) without PJFF c 20.9 36.7 52.5 68.3 69.3
Total Actual Hg Reduction without PJFF c 50.0 60.0 70.0 80.0 80.6 975 MW w i th ESPc and No PJFF d Retrofit PJFF? d no no no no no Capital Cost ($/kW) $0.391 $0.673 $2.240 $14.462 $26.735 Variable Cost (mills/kWh) 0 .745 0.785 1.180 8.237 18.846 Total Cost d (mills/kWh) 0 .756 0.805 1.247 8.666 19.638 Total Outlet Hg (mg/MWh) 8 .1 6.5 4 .9 3.3 3 .2 975 MW w i th ESPc and PJFF Retrofit PJFF? yes y es yes y es yes Capital Cost ($/kW) $35.922 $36.177 $36.333 $36.565 $37.009 Variable Cost (mills/kWh) 0 .190 0.209 0.238 0.285 0.393 Total Cost d (mills/kWh) 1 .089 1.115 1.148 1.203 1.323 Total Outlet Hg (mg/MWh) 8 .1 6.5 4 .9 3.3 1 .6 100 MW w i th ESPc and No PJFF d Retrofit PJFF? d no no no no no Capital Cost ($/kW) $0.817 $1.431 $4.792 $29.800 $53.860 Variable Cost (mills/kWh) 0 .745 0.785 1.180 8.237 18.846 Total Cost d (mills/kWh) 0 .769 0.828 1.322 9.120 20.441 Total Outlet Hg (mg/MWh) 8 .1 6.5 4 .9 3.3 3 .2 100 MW w i th ESPc and PJFF Retrofit PJFF? yes y es yes y es yes Capital Cost ($/kW) $56.936 $57.409 $57.748 $58.248 $59.202 Variable Cost (mills/kWh) 0 .190 0.209 0.238 0.285 0.393 Total Cost d (mills/kWh) 1 .584 1.616 1.654 1.717 1.853 Total Outlet Hg (mg/MWh) 8 .1 6.5 4 .9 3.3 1 .6

a The K-fuel process is primarily designed to impr ove fuel-heating value, but it may provide NO X reduction, provides some SO 2 reduction, and provides Hg reduction. b This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices.

c W i th PAC injection on subbituminous coals without a dow nstream fabric filter, Hg reduction at very high levels is not expected to be possible. Additi onal PAC injection will not improve Hg reduction. d The calculations performed to generate t he results in this table assumed t hat all collected fly ash is currently sold, which is the most conservative situation. Therefore, these calculations include costs to landfill fly ash with an impact to total cost of around 1.01 mills/kW h

. In many cases these costs will not apply because ash may currently be landfilled or because ash may not be rendered completely unacceptable for re-use.

78Table 28. K-Fuel a , FF, and No SO 2 Control (Model Plants 45, 48) b

Parameter Specified Hg Reduction (%) 50 60 70 80 90 Hg Reduction of Existing Equipment (%) 60.7 60.7 60.7 60.7 60.7 Hg Reduction by PAC (%) none none 23.6 49.1 74.5 Total Outlet Hg (mg/MWh) 6 .4 6.4 4 .9 3.3 1 .6 975 MW w i th FF and No PJFF c Retrofit PJFF? c no no no no no Capital Cost ($/kW) $0.094 $0.094 $0.598 $0.817 $1.219 Variable Cost (mills/kWh) 0 .000 0.000 0.773 0.811 0.895 Total Cost c(mills/kWh) 0 .003 0.003 0.791 0.835 0.931 975 MW w i th FF and PJFF Retrofit PJFF? no no yes y es yes Capital Cost ($/kW) $0.094 $0.094 $36.076 $36.295 $36.697 Variable Cost (mills/kWh) 0 .000 0.000 0.193 0.230 0.315 Total Cost c(mills/kWh) 0 .003 0.003 1.096 1.140 1.236 100 MW w i th FF and No PJFF c Retrofit PJFF? c no no no no no Capital Cost ($/kW) $0.165 $0.165 $1.269 $1.744 $2.611 Variable Cost (mills/kWh) 0 .000 0.000 0.773 0.811 0.895 Total Cost d (mills/kWh) 0 .005 0.005 0.811 0.862 0.973 100 MW w i th FF and PJFF Retrofit PJFF? no no yes y es yes Capital Cost ($/kW) $0.165 $0.165 $57.191 $57.666 $58.533 Variable Cost (mills/kWh) 0 .000 0.000 0.193 0.230 0.315 Total Cost c(mills/kWh) 0 .005 0.005 1.593 1.645 1.755

a The K-fuel process is primarily designed to impr ove fuel-heating value, but it may provide NO X reduction, provides some SO 2 reduction, and provides Hg reduction. b This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices. The calculations performed to generate t he results in this table assumed t hat all collected fly ash is currently sold, which is the most conservative situation. Therefore, these calculations include costs to landfill fly ash with an impact to total cost of around 1.01 mills/kW h

. In many cases these costs will not apply because ash may currently be landfilled or because ash may not be rendered completely unacceptable for re-use.

79 cTable 29. K-Fuel a , ESPh, and No SO 2 Controls (Model Plants 46, 49) b

Parameter Specified Hg Reduction (%) 50 60 70 80 90 Hg Reduction of Existing Equipment (%) 12.6 12.6 12.6 12.6 12.6 Hg Reduction by PAC (%) 42.8 54.2 65.7 77.1 88.6 Total Outlet Hg (mg/MWh) 8 .1 6.5 4 .9 3.3 1 .6 975 MW w i th ESPh and PJFF Retrofit PJFF? yes y es yes y es yes Capital Cost ($/kW) $36.096 $36.353 $36.517 $36.764 $37.246 Variable Cost (mills/kWh) 0 .219 0.242 0.275 0.331 0.457 Total Cost (mills/kWh) 1 .123 1.153 1.191 1.254 1.395 100 MW w i th FF and PJFF Retrofit PJFF? yes y es yes y es yes Capital Cost ($/kW) $57.315 $57.792 $58.145 $58.676 $59.707 Variable Cost (mills/kWh) 0 .219 0.242 0.275 0.331 0.457 Total Cost (mills/kWh) 1 .624 1.660 1.7.03 1.775 1.932

a The K-fuel process is primarily designed to impr ove fuel-heating value, but it may provide NO X reduction, provides some SO 2 reduction, and provides Hg reduction. b This table shows Total Cost and the portion of Total Cost that is variable (Variable Cost), both in mills/KW h

. For a more comprehensive breakdown of costs, pl ease see the model plant tables in the appendices.



### 6.4 C ost Impacts of Selected Variables

Sensitivity analysis was performed for certain variables of interest on specific m odel plants. These included the effects of new sorbents, capital cost on PAC injection, fertilizer cost/power cost on ECO, and lim e cost on Advanced Dry FGD.
Effect of New Sorbents on Cost of Hg Control In the future, cost of controlling m e rcury could be reduced by new sorbe nt s , which could potentially elim inate disposal costs for spent sorbent/fly as h m i xtures. To assess the effects of elim ination of ash and sorbent disposal cost, Figure 17 wa s developed. Figure 17 shows the results of cost estim ates com p aring m e rcury control cost for 500 MW plants with and without disposal costs. For each configuration, the sorbent and fly ash are collected together in an existing FF or ESPc. As shown, the elim ination of disposal costs can be quite significant, especially for the PRB fuels. Low sulfur bitum i nous coal, with a low ash le vel and high Btu content, has a lower com ponent of ash disposal cost of the total cost, but it is nevertheless quite significant at about 0.38 m ills /kWh (this is just for the fly ash; the sorbent contribut es to additional disposal cost). The PRB fuel has

80Figure 17. Cost of PAC Injection for 500 MW Coal Fired Boilers with existing ESPc or FF.
a higher ash loading and lower Btu content, causi ng ash levels to be m u ch higher and disposal

c o st s for contam inated ash m u ch higher (about 1.0 m ill/kWhfor th e a s h a l one )

. The e x a c tsa vi ngs in disposal cost for any particular application will depend upon the actual ash content and Btu value of the particular f u el being used. So, f ac ilities with f u el having dif f e rent ash content or Btu value will see a dif f e rent im pact on ash disposal costs.

It is also notable that the im pact of disposal cost s, as a percent of total cost, is m u ch greater for f acilities with FFs than f o r f acilities that capture the PAC and f l y ash in ESPs. This is because th e m u c hlower PAC injection rate f o r FF-equipped f acilities m ak e s a s hd i s p o s a l c o s t a

v e r ylar g e fraction of the total cost. Figure 17 shows that ifdisposal costs can be avoided by use of costeffective sorbents other than PAC, or by other m eans, then the cost of controlling m e rcury can be reduced by 75 to 80 percent in som e cases (PAC injection upstream of existing FF).
There is extensive research ongoing in the field of im proved sorbents for m e rcury control that

m ay be m o re efficient in capturing m e rcury and potentially at a lower cost than PAC. 59,74,75 These im provem e nts in sorbents m a y contribut e t o ove r a l l r e duc t i onsi n s o r b e n t c o nsum ption, contributing to reduced costs for disposal, sorbents, and cap ital equipm ent. Im proved sorbents could enable

81users to avoid installation of f

abric f ilters a nd will also reduce the sorbent storage and m a terial handing equipm ent on site.

For exam ple, Ref e rence 19 show ed that PAC usage f o r f acilities that capture PAC sorbent in downstream ESPs was m u ch m o re af f ected by selection of th e ty p e of PAC sorbent than f acilities that captured the PAC sorbent in a FF. Reference 19 cited the results of several f u ll-scale tests using different PAC m a terial sa v a i l a bl e fr om ma nufa c t ur e r s

. Re fe r e nc e 19 developed three different perform ance curves for each of the two cases with downstream ESPs (one case with bitum i nous coal and the other case with a PRB subbitum i nous coal). The three di ffe r e nt curves were characterized as high, m e dium , and low perform an ce. Figure 18 shows estim ates of total cost for PAC inje c t i on ( i nc l u s i ve of disposal costs) for the m e dium perform a nce sorbents used in this study versus higher perform ance sorbents tested in fi eld trials. The estim ates assum e that the higher perform ance PAC sorbents are ava ilable at the sam e price (the higher perform ance sorbents are PAC with som e different physical characteristic s—no additional chem icals). As shown in Figure

Figure 18. Cost of PAC Injection for 500 MW Coal Fired Boilers with Existing ESPc—Effect of Medium Versus High Performance PAC.

8218, cost reduction of 20 percent is estim ated for th e bitum i nous coal fired facility when using the higher perform a nce PAC. Because the sorbents used in the calculations to generate Figure 18 are conventional PAC sorbent s , e v e ngr eater cost im provem e nts are likely if other im proved sorbents are considered.
Effect of Capital Cost for PAC Injection For f acilities with ESPcs that m a y retrof it PAC in jection and a PJFF downstr eam of the ESP, capital cost is a m a jor contributor to control cost. As shown in Figure 19, for boilers firing either PRB or low sulfur bitum i nous coal, the total cost of control is expected to vary from about 1.2 to about 1.8 m ills/kWhover the range of expected total capital costs.

Figure 19. Effect of Capital Cost on 90 Percent Mercury Control with PAC on Boiler with Existing ESPc and Retrofit of Downstream PJFF.

Effect of Fertilizer Value and Power Cost on ECO Figure 20 shows the estim ated eff ect of the value of fertilizer product on the econom ics of ECO for a 500 MW plant firing either lo w sulfur or high sulfur bitum i nous coal. For a high sulfur coal

83fired boiler, t h e im pact of fertilizer value in reducing cost is greater because m o re fertilizer is produced from a high sulfur coal boiler. Also, for th e high sulf ur coal boiler, the net cost is lower due to the higher f e rtilizer revenues. Figure 21 s hows the ef f ects of the value of power needed by the ECO on the cost of controlling with ECO on a 500 MW plant firing either low sulfur or high sulfur bitum i nous coal. For a PRB coal fired boiler or a boiler with lower initial NO X , the effect of power on total cost is less because power consum ption is closely related to NO Xlevels.

Figure 20. Effect of Fertilizer Value on Cost of Emissions Control with ECO on a 500 MW Bituminous Coal Boiler.

Effect of Lime Cost on Advanced Dry FGD Figure 22 shows the effects of the cost of lim e reagent, an im portant cost factor, on the total cost of control for advanced dry FGD

. A s s h o wn , th ere is roughly !0.19 m ills/kWheffect, or a roughly !4 percent effect on the total cost of control over the range evaluated.

84Figure 21. Effect of Power Value on Cost of Emissions Control with ECO on a 500 MW Bituminous Coal Boiler.

Figure 22. Effect of Reagent Cost on Cost of Emissions Control with Advanced Dry FGD on a 500 MW Boiler Firing Low Sulfur Bituminous Coal.

85

### 6.5 S ummaryof Mercuryand Multipollutant Control Costs

Table 30 shows expected costs for control of m e rc ury from coal-fired boilers. Listed are control costs for at least 80 percent and up to 90 per cent reduction. The following assum p tions were used in m a king the current and potential cost estim ates.

• F or situations where one approach seem ed to be m o re attractive than another (such as PAC injection alone versus PA C injection plus a PJFF), it was assum e d that the f acility owner would norm a lly select the m o re econom ically attractive approach.

• A n approach that is not considered in th e results of Table 27 is changing of fuels to lower m e rcury c ont e n tfuels (such as conversion from PRB to K-Fuel, as described earlier). However, depending upon the increm enta l cost of these fuels relative to the current fuel, they could be m o re cost effective in the application than the additional controls shown.

• T he Current Cost Estim ates use PAC sorbent injection levels that have been m e asured in f i eld tests or in pilot tests using currently available PAC sorbents 19,30 assum e that all cases used PAC and that all fly ash that com e s in contact with used PAC m u st be disposed of. As discussed earlier, the assum p ti on that all f l y ash currently is sold is a

m o st conservative assum p tion. For the m a jorityof plants that currently landfill their fly a s h, the increm ental costs of PAC injection are estim ated to be from 0.37 m ills/kWh to about 1.0 m ills/kW h

less than show n in Ta ble 30. Moreover, current research program s of

f e r the potential to reduce operating costs in one of two ways: (1) reduction of sorbent costs by developm ent of less expensive sorben ts, or sorbents that are m o re efficient in m e rcury capture than existing PAC sorbents or (2) reduction or elim ination of disposal costs by utilizing sorbent m a terials that can be benef i cially reused in the sam e m a nner
a s f l y

a s h th at m a y

b e captured with it. Sensitivity analysis s h o w e d th at , if d i s p o s a lc o s t s caused by PAC injection could be avoided, th e cost of control could be reduced by 15 to 17 percent f o r f acilities where sorbent is collected in downstream ESPc’s and by about 80 percent for facilities where sorbent is c o l l e c t e d i n downstr e am FFs. The reason the im pact is greater for FFs than for ESPs is because PAC injection rates tend to be

m

u ch lower for FFs, and the im pact of ash di sposal cost on total cost is therefore m u ch greater.

86Table 30. Estimated Cost of Mercury Control—Current and Potential Cost Estimates

Coal Type S (% )

Bitt 3
Bit 3 Bit 3 Bit 3 Bit 3 Bit 3 Bit 3
Bit 0 .6
Bit 0 .6 Bit 0 .6
PRB 0 .5
PRB 0 .5 PRB 0 .5 Existing Controls

ESP + FGD SCR + ESP + FGD FF + FGD SCR + FF + FGD

ESPh + FGD SDA + ESP SDA + FF ESP
FF ESPh ESP
FF ESPh Additional Controls Cost Estimates of Additional Controls (mills/kWh) PAC + PJFF + CEMS PAC + CEMS 1.144

S 1.430 C EMS 0 .03

S 0.04 C EMS 0 .03

S 0.04 C EMS 0 .03

S 0.04 PAC + PJFF + CEMS 1.149

S 1.437 PAC + (PJFF) + CEMS a 2.211

S 3.096 a PAC + CEMS 0.05

S 0.370 PAC + PJFF + CEMS PAC + CEMS b 1.171

S 1.751 PAC + CEMS b 0.003

S 0.510 PAC + PJFF + CEMS 1.205

S 1.804 PAC + PJFF + CEMS PAC + CEMS b 1.236

S 1.903 PAC + CEMS b 1.122

S 1.266 PAC + PJFF + CEMS 1.273

S 1.960

a For 80 percent control assumes no PJFF. For 90 percent control, assumes full-size PJFF (sized for full ash loading and much more expensive than if sized for downstream of an ESP or FF) being necessary for 90 percent control. b The calculations performed to generate t he results in this table assumed t hat all collected fly ash is currently sold, which is the most conservative situation. Therefore, these calculations include costs to landfill fly ash with an impact to total cost of around 0.37 mills/kW h for the low sulfur bituminous coal and around 1.01 mills/kW h for the low sulfur bituminous coal. In many cases these costs will not apply because ash may currently be landfilled or because ash may not be rendered completely unacceptable for re-use.

In this w o r k , tw o m u ltipollutant controls were also evaluated: ECO and advanced dry FGD. ECO is an em erging technology, and adva nced dry FGD is a technology thatis being introduced to the United States by several suppliers. There currentlyis n o c o mm e rcial experience with ECO at this tim e. There is lim ited comm e rcial experience with advanced dry FGD on coal-fired boilers in the United States; however, there is m o re expe rience with the technology in Europe. Therefore, the c os t i n form ation presented in Table 31 should be regarded as prelim inary, especially for ECO. However, it should be kept in m i nd, when consid er i ng t h e hi gher costs associated with m u ltipollutant controls over controls that rem ove onl y me r c ur y, th at othe r e nvironm ental benefits, such as SO 2 or NO Xcontrol, are realized in addition to m e rcury reduction.

The universe of m u ltipollutant controls is not lim ited to the technologies presented in this work. Therefore, other technologies that could offer lo wer control costs m ay beco m e available to users.

87Table 31. Estimated Costs of Multipollutant Controls

Coal Existing Controls Type S (% )

Bit 3 ESP Bit 3 ESP Bit 0 .6 ESP Bit 0 .6 ESP PRB 0 .5 ESP PRB 0 .5 ESP Additional Controls Cost Estimates of Additional Controls (mills/kWh) ECO + CEMS 3.28

S 7.21 Adv Dry FGD + CEMS 7.94

S 9.65 ECO + CEMS 5.34

S 12.33 Adv Dry FGD + CEMS 3.69

S 6.58 ECO + CEMS 4.54

S 11.53 Adv Dry FGD a + CEMS 3.89

S 6.79 a

a Mercury control with advanced dry FGD on PRB fuels may be uncertain

K-Fuel, which is developed from low rank wester n fue l s, was also evaluated. It was shown in this work that K-Fuel offers roughly 60 percen t, som e tim es m o re, reduction of m e rcury in the fuel (on a heating va l u e ba s i s). This is achieved by sim u ltaneously reducing the m e rcury concentration in the f u el while in creasing the fuel’s heating value. K-Fuel m a y also of f e r the f acility other environm ental or operating benefits be sides m e rcury reduction. Moreover, it was shown that m e rcury reductions beyond the 60 percent provi ded by K-Fuel (versus PRB ) can be achieved with PAC injection. As the first comme r c i a l K- Fuel plant will be built soon, there is no com m e rcial experience with this technology at this tim e. Cost s ar e e v a l uat e d based on cost prem ium for K-Fuel over a f acility’s existing f u el. For exam ple, if K- Fuel were available at an increm ental cost of $0.12/MMB tu over a base f u el, then the increm ental cost w ould be appr oxim ately 1.26 m ills/kWh

.

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## 7.0 S UMMARY

Cost esti ma t e s of PAC i n j e c t i on- ba se d me r c ury c o ntrol technologies for coal-fired electric utility boilers have been determ ined. These estim ates include those based on currently available data as well as projections for future appli c at i ons of mor ee ffective sorbent. Estim ates based on currently available data range f r om 0.03-3.096 m ills/kWh. Howe ver, the higher costs are usually associated with the m i nority of plants using SDAs plus E SPs or the sm all num ber of plants using ESPhs. Potential costs, developed assum i ng im provem e nts in sorbent technology for m e rcury rem oval, range from 0.03-1.69 m ills/kWhexcluding applications with SDAs plus ESPs or with ESPhs. At the low end of these cost ranges, 0.03 m ills/kWh, it is assum e d that no additional control technologies are needed but that m e rcury m onitoring w ill be necessa ry. In these cases, high m e rcury
rem oval m ay be the result of the type of NO Xand SO 2 control m easures currently em ployed.

The estim ates based on currently available data m ay be conservative for the following reasons: (1) They assum e that prior to add ition of controls all fly ash is so ld, and after addition of controls, any fly ash that is com b ined with spent PAC m u st be disposed of; (2) The estim ates of PAC injection rates for PRB-fired boilers with PAC collected by downstream ESP are based upon experience at Pleasant Prairie Power Plant, which fires a fuel with a lower chlorine content coal than is typical for a PRB fuel; (3) A 65 percent cap acity factor is assum e d for all cases. The first

assum p tion is conservative because m o st plants do not currently sell their fly ash; furtherm ore, fly ash sales m i ght be possible even wi t h s m a l l a m ounts of PAC present. The im pact of this assumption was estim ated to be in the range from 0.37 m ills/kWhto about 1.0 m ills/kWh , depending upon fuel characteristics. Thus, for plants that do not currently sell their fly ash (m ost plants), the actual increm ental cost of control would be lower t h an what we have estim ated. Moreover, im proved sorbents available in the f uturem a y elim inate, or at least m itigate, any im pact of sorbent injection on disposal costs. The s econd estim ate is conservative because, at the PPPP tests, m e rcury reduction by PAC injection was lim ited to around 70 percent. This is believed to b e d u e , a t l e a s t in part, to PPPP’s unusually low chlorine content—m u ch lowe r th anfo r mo s tPRB fuels. Therefore, other PRB fueled boilers withchlorine contents typical of a PRB coal, and equipped with a downstream ESP, m a y be m o re e ffectively controlled th a n

what was de mo n s t r at e d at PPPP. The final assum p tion is conservative partic ularly for larger plants that are likely to be base loaded with higher capacity factors.
Results of sensitivity analyses conducted on total annual cost of m e rcury controls reflect that: (1) Elim ination of disposal costs could reduce co sts by 80 percent for som e cases (PAC injection upstream of an existing FF) and by 17 percent in others (PAC injection upstream of an existing
89ESP); (2) Using a m o re effective PAC sorbent m i ght reduce costs by 20 percent; (3) The cost of a retrofit PJFF has a significant im pact on contro l costs and, over the expected cost range, m a y cause cost to vary from about 1.2 m ills/kWhto about 1.8 m ills/kWh ; (4) Fertilizer product value and the value of process power requirem e nt have a very significant im pact on the cost of ECO, with fertilizer product value being m o st significan t for high sulfur fuel applications; and (5) As expected, lim e reagent cost has a large im pact on the total cost of using advanced dry FGD.
Based on this work, it is expected that f u ture ef f o rts in R&D are likely to f o cus on im proved understanding of both m e rcury speciation across S C R s and the benef i cial effects of com b inations of SCR with wet FGD, and on deve l o ping sorbents that can im prove perform ance and cost of sorbent-based m e rcury control technologies. Mu ltipollutant control technologies, which are m o re costly than single-pollutant m e rcury control tec hnologies but offer other environm ental benef its, will be another area f o r f urther developm ent that could im prove the cost of reducing em issions f r om coal-f ired power plants. Finally, rem oving m e rcury f r om the coa l , a l o n gwith other f u el quality im provem e nts, m ay prove to be a cost effective approach for reducing em issions.

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