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Abatement of mercury emissions in the coal combustion process equippedwith a Fabric Filter Baghouse

Yan Cao a,*, Chin-Min Cheng a, Chien-Wei Chen a, Mingchong Liu a,b, Chiawei Wang a,b, Wei-Ping Pan a

a Institute for Combustion Science and Environmental Technology (ICSET), Western Kentucky University (WKU), 2413 Nashville Road, Bowling Green, KY 42101, USAb Mingchi University, Taipei, Taiwan

a r t i c l e i n f o

Article history:Received 27 November 2007Received in revised form 10 May 2008Accepted 16 May 2008Available online 12 June 2008

Keywords:CFBCPCMercury emissionFabric filter baghouseFly ash

a b s t r a c t

The purpose of this study was to investigate the dependence of mercury emissions on coal ranks and elec-tric utility boilers equipped with Fabric Filter Baghouses (FF). A comparison of mercury emission ratesand fly ash properties was made between a circulating Fluidized Bed Combustor (CFBC) with FF and a Pul-verized Coal (PC) combustor with FF during the burning of all three ranks of American coals. The datawere collected from the Environmental Protection Agency Information Collection Request (EPA ICR)and WKU ICSET’s mercury testing program. A statistical stepwise regression procedure was used to deter-mine significant factors such as coal rank and types of boilers equipped with FF on mercury emissionsduring coal combustion. The higher mercury emission rates were generally found in both CFB and PCunits when lignite was burned. The lower mercury emission rates were generally found in both CFBequipped with FF and PC units equipped with FF when bituminous coal was burned. There was a statis-tically significant lower mercury emission in the CFBC equipped with FF than that in the PC units whensub-bituminous coal was burned. Lower mercury emission rates in electric utility boilers equipped withFF are due to the active fly ash generated with a larger specific surface area and pore volume. Higher mer-cury emission rates observed during lignite-fired boilers may be due to their lower specific area of fly ash,which results from lower LOI, as well as the pore blockage by selenium (Se) for Texas lignite; and sodium(Na) and potassium (K) for North Dakota lignite. There is no significant mutual benefit for the mercurycaptured by the addition of Spray Dry Absorber (SDA) or selective non-catalytic reduction (SNCR) inthe CFBC system.

� 2008 Elsevier Ltd. All rights reserved.

1. Introduction

The United States (US) Environmental Protection Agency (EPA)promulgated the Clear Air Mercury Rule [21] to permanently capand reduce mercury emissions from coal-fired electric utilitiesboilers, because mercury is a persistent bio-accumulative toxinthat builds up in human body tissue [1]. The US EPA has also re-cently promulgated the Clean Air Interstate Rule (CAIR) to furtherreduce SO2 and NOx. This has led to additional installations of con-trol systems for Particulate Matter (PM), SO2 and NOx, which havebeen identified to also reduce mercury emissions without addi-tional cost [13,14,24]. Under Section 111 of the Clean Air Act(CAA), New Source Performance Standards (NSPS) on mercury havebeen established based on Best Demonstrated Technology (BDT)considering cost, non-air-quality health, environmental impacts,and energy requirements. However, on February 8, 2008 the US

Court of Appeals for the District of Columbia issued a unanimousdecision vacating the US Environmental Protection Agency’sClean Air Mercury Rule (CAMR) and the rule ‘‘de-listing” ElectricGenerating Units (EGUs) from the list of sources requiring regula-tion under the Clean Air Act Section 112. There is considerableuncertainty on the subject of regulators and regulated entities. Thisuncertainty is particularly acute when it pertains to the mercurymonitoring provisions of the rule, which will become effectiveby January 1, 2009 (No. 05-1097. United States Court of Appeals)[12].

Based on currently-available EPA Information CollectionRequest (ICR) data [8,20], a fabric filter baghouse (FF) can be moreeffective for particle-bound mercury capture than an electrostaticprecipitator (ESP). This is due to enhanced heterogeneous oxida-tion and adsorption of mercury by fly ash in FF. The combinationof Selective Catalytic Reduction (SCR) and Flue Gas Desulfurization(FGD) is another effective mercury control method. This is due tothe effective control of the oxidized mercury by FGD after the en-hanced elemental mercury oxidation by SCR. Thus, BDT of mercuryemissions in coal-fired electric utility boilers is considered to be

0016-2361/$ - see front matter � 2008 Elsevier Ltd. All rights reserved.doi:10.1016/j.fuel.2008.05.010

* Corresponding author. Tel.: +270 7790202; fax: +270 7452221.E-mail address: yan.cao@wku.edu (Y. Cao).

Fuel 87 (2008) 3322–3330

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either an FF, or an FGD or their combined utilization [6,10,11,18].However, the use of FF and SCR-FGD at US coal-fired powerplants is limited. There is only a 9.4% installation of FFs in compar-ison to an 85.8% installation of ESPs and only a 28.2% installationof FGDs in electric utility boilers for total generating capacity(MW).

Furthermore, the specific mercury removal performance of sug-gested BDT is largely varied, depending on coal properties and thecombustion process [6]. Based on the EPA ICR program, the achiev-able mercury control efficiencies by BDT are 86.7% for bituminouscoal-fired utility boilers. It is only 31.8% for sub-bituminous coal-fired boilers (mainly Powder River Basin (PRB) coal) and even aslow as 18.3% for lignite-fired utility boilers. The DOE Energy Infor-mation Administration (EIA) estimates that over 50% of the coal-re-serve base is bituminous coal, about 30% is sub-bituminous and 9%is lignite [22]. The most common sub-bituminous coal in the US islocated throughout Montana and Wyoming, and large deposits oflignite are located near North Dakota and Texas. Based on 1999survey results, 52% of the total tonnage of coal burned by the elec-tric utility industry is bituminous coal, approximately 36.5% is sub-bituminous and 6.5% is lignite [23].

There are over 1150 coal-fired electric utility boilers in the USbased on EPA ICR data. Although Pulverized Coal (PC) boilers areconsidered part of the older designs, PC boilers account for approx-imately 86% of the total number of units and make up around 90%of nationwide generating capacity [24]. Cyclone furnaces accountfor approximately 7.6% of both the total units and the nationwidegenerating capacity. For comparison, the most advanced coal com-bustion technologies, such as CFBC and Integrated GasificationCombined Cycle (IGCC) units, only account for about 3.7% and0.3% of the total units, respectively. They also account for about1.3% and less than 0.1% of the nationwide generating capacity,respectively. The United States strives for energy security bydeveloping advanced, environmentally-sound technologies andexploring a range of domestic energy sources. Coal will continueto prove itself a critical energy resource for the nation [9]. It isestimated that 159 new coal-fired units with about 70 gigawattsin total generating capacity will be built in the United States by2030. Approximately 15% of the new units will be CFBCs (22 newunits) in this resurgence, compared to the 3.7% presently availableCFBCs [23].

CFB combustor development has progressed since the mid-1960s because of its lower capital, operational, maintenance, andelectricity generation costs compared to IGCC [2,25]. The US Gov-ernment also recognized its potential as an efficient and environ-mentally friendly coal utilization technology. The technologyoffers a number of advantages. The long residence time of solidfuels in the CFBC system results in high combustion efficiency evenwith difficult-to-burn solid fuels. Low operating temperatures alsoeffectively control SOx and NOx emissions. Staging of second airinjection into the CFBC and Selective Non-catalytic Reduction(SNCR) technologies produces even lower NOx emissions [1,25].The Spray Dry Absorber (SDA) is followed by an FF for collectionof spent reagent and fly ash. Thus, SNCR and SDA with FF are gen-erally the standard Air Pollution Control Devices (APCDs) for theCFBC system under the new CAIR.

This study’s purpose was to screen out major factors on mer-cury emissions in all electric utility boilers by burning all ranksof coals. The evaluated data were collected from the EPA ICR pro-gram and WKU ICSET’s mercury field testing. We compared mer-cury emission rates and fly ash properties from CFBC boilers andconventional PC boilers equipped with FF during burning of allthree typical American coals. A statistical stepwise regression pro-cedure used to test the detailed investigations of mercury emissionrates among different set-ups of APCD (SNCR, SDA + FF) in twocommercial CFBC systems is also presented.

2. Methods

2.1. Data collection

Mercury emission data were collected from data bases of theEPA’s mercury ICR program and WKU ICSET mercury field testing.The EPA ICR data are from sampling activities, which were ob-tained based on ASTM D6784 Ontario Hydro Method (OHM). Be-sides ASTM OHM used, ICSET data were also from samplingactivities by the semi-continuous Mercury Monitor (SCEM) andEPA Appendix K method. The EPA ICR data were collected up-stream of the last air pollutant control device and the stack. The IC-SET data were collected from sampling activities, which have beenextended to varied APCD locations and boiler operation conditions.Thus, it could provide additional information about the depen-dence of mercury transformation at different locations and mer-cury emission rates on the boiler performance. Boilers equippedwith FF were selected in this study because FF was predicted tobe more efficient for mercury emission control than ESP. In the col-lected ICR data, there were 18 PC units, 1 cyclone unit, 9 CFBCunits, 3 Stoker-fired units and 2 IGCC units. Coals burned in theseunits included bituminous, sub-bituminous, lignite and theirblends. All ash characterization data were from the ICSET database.The mercury emission rate, which is commonly expressed as lb/TBtu, was not used in this study. It does not include informationon mercury input levels so that it is not accurate herein. In thisstudy, the new mercury emission rate (lg/NM3/(lg/g � Btu/lb)) isdefined as mercury emissions in the stack (Hgstack, lg/NM3), perthe mercury content (Hgcoal, lg/g) and also per heating value ofthe (BTUcoal, Btu/lb), see Eq. (1). This factor can be used to evaluatethe mercury emission rates, which are dependent on the mercurycontent of the coal (Hgcoal) and coal heating value (Btucoal). Wefound loss of information in ICR data (for example, a completeanalysis of coal) to calculate F-factor for every case and thus to cor-relate BTU and flue gas volume to make its unit have a simple

mercuryemissionrate ¼ Hgstack=½ðHgcoalÞðBtucoalÞ�: ð1Þ

2.2. Stepwise regression analysis

The collected data were subjected to the stepwise regressionto build up a statistics model of significant analysis of factorsaffecting mercury emission rates. Stepwise regression can removeand add variables into the regression model to identify a usefulsubset of the factors. The basic principle in this stepwise regres-sion is to calculate an F-statistic and p-value for each variablein the model. If the p-value for any variable is greater than Alphato remove (0.15), then the variable with the largest p-value is re-moved from the model. If no variable can be removed, the proce-dure attempts to add a variable, and the next step begins. Aftertrial and error calculations, the regression model will supply themost significant factors that fit the prediction. The selection ordefinition of the data’s subset is also dependent upon understand-ing mercury transformation in the coal-fired combustion process.In this study, SPSS statistics software was used to fulfill the step-wise regression analysis. We can keep variables in the modelregardless of their p-values. Because analysis procedures requirethat factor variables and their corresponding response variablesshould have an equal amount in data size, we compiled the databank into two groups (mercury emission rate and fly ash). Thefactor prediction on the mercury emission rate has 81 sets of data(54 sets from PC units and 27 sets from CFBC). Nine sets of datafrom stoker-fired units and 6 sets from IGCC data were excludedin the statistical analysis because little data was available andsome of the required information was not collected during testsin the EPA ICR program for those units that were IGCC and

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Stoker-fired. The fly ash characterization has 38 data sets (30from PC units and 8 from CFBC units).

2.3. Ash characterization by its physical structure

All fly ash samples in this study were collected in FF hoppers ofselected boilers during ICSET mercury field tests. The surface andelemental analyses of fly ashes were performed using a JEOL LSM-5400 Scanning Electron Microscope (SEM-EDX). The instrument’soperating parameters were as follows: the electron beam energy(15 keV), the working distance (30 mm) and the sample tilt angle(0�). In most cases, three magnifications at 200, 2000 and 10,000�were selected for analysis. Physical surface properties such as spe-cific surface area (BET model or BJH model), pore volume, and aver-age pore size of fly ashes were characterized by a Micromeritics’ASAP Accelerated Surface Area and Porosimetry instrument(Micromeritics Instrument Corp.). The specific surface area was cal-culated by the BET equation from the nitrogen adsorption data inthe relative pressure range of 0.05–0.2. The single point total porevolume was calculated from the amount of nitrogen adsorbed at arelative pressure of around 0.95. The micropore (pores 62 nm)[19] volume was obtained using the t-plots method; and the meso-pore (2–50 nm) volume was determined using the BJH method. Allof the calculations were performed with software provided byMicromeritics. The molecular sieve 13� provided by Micromeriticswas run periodically to check the reliability of this instrument.

3. Results and discussion

3.1. Factors affecting mercury emission rate

The mercury emission rates in boilers with different configura-tions and different coals are presented in Fig. 1. The mercury emis-

sion rate of Stoker-fired units was generally low, approximately1.0 � 10�3(lg/NM3/(lg/g � Btu/lb)). The PC boilers burning bitumi-nous coals were also low, approximately 9.0 � 10�4(lg/NM3/(lg/g � Btu/lb)). The mercury emission rate was increased in PC boilerswhen the coal was switched from bituminous coal to a blend ofbituminous coal and petroleum coke or sub-bituminous coal. PCboilers burning sub-bituminous coal showed an even higher mer-cury emission rate than those burning bituminous coal. Thisincreasing trend was at its greatest when lignite coal was burnedin the PC boilers – approximately 2.0 � 10�2 (lg/NM3/(lg/g � Btu/lb)). The cyclone-fired boiler burning bituminous coal showed avery high mercury emission rate, approximately 4.0 � 10�2 (lg/NM3/(lg/g � Btu/lb)) among all coal-fired combustion processes.However, there is only one such unit in the present study. The rea-son may be due to the higher combustion temperature, causingless ash to exit the cyclone boiler as fly ash. These conditions likelyresult in the lower reactivity and lower concentration of fly ashavailable for mercury capture with comparison to that of PC boil-ers. CFB boilers burning bituminous and sub-bituminous coalsshow very low mercury emission rates. Mercury emissions couldalso be efficiently controlled in a CFB boiler by burning their blen-dings. Compared to PC boilers burning lignite, a CFB boiler shows alower mercury emission rate of about 1.0 � 10�2 (lg/NM3/(lg/g � Btu/lb)). The coal gasification-based IGCC process appears tohave a higher mercury emission rate, around 6.0 � 10�3 (lg/NM3/(lg/g � Btu/lb)), than those of coal combustion-based boilersburning bituminous coal. From analysis, the mercury emission rateappears to be strongly related to the rank of coal and the type ofboiler.

Similarly shown in the Fig. 1, there is an apparent correlatedtrend of Hgash/Hgcoal and mercury emission rates. This may indi-cate that mercury adsorption by fly ash generated in boilers is amajor method for controlling mercury emissions in coal-fired

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Fig. 1. The dependence of mercury emission rates on boiler types with FF and coal ranks (B: Bituminous coal, P: Petcoke, SB: Sub-Bituminous coal, A: Anthracite coal, andL: Lignite).

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boilers equipped with FF. Mercury is present in the gas phase athigh temperatures during the coal combustion process. Mercuryadsorption by fly ash occurs when the flue gas temperature is de-creased downstream of the boiler. In this process, rank-related coalproperties (such as the chlorine, sulfur, moisture and pore struc-ture of fly ash), may influence mercury adsorption on the fly ash.An apparent decreasing trend of chlorine content in coals is foundwhen the rank of coals decreases. This is followed by an increasingtrend in mercury emission rates. This may imply that chlorine con-tent in the coal may be the factor affecting the mercury emissionrate. However, there is no significant correlation between the mer-cury emission rate and mercury speciation in the stack (Hg(0)/Hg(VT)stack, the ratio of the elemental mercury and the total gas-eous mercury), at least by available data shown in Fig. 1. The pos-sible explanation for this could be that the great change of mercuryspeciation by the interaction between gaseous mercury and fly ashoccurs after flue gas passes through the FF. The Loss On Ignition(LOI) content of the fly ash, which is relative to boiler type and coalrank, seemed to be correlated with the mercury emission ratebased on the limited data available, as shown in Fig. 1.

To more accurately predict the factors affecting mercury emis-sion rates, three trials by a stepwise regression analysis based ontwo available data banks were conducted. All three trials investi-gated the trends in mercury emission rates by different boilertypes burning different ranks of coals. In the first trial, factors in-cluded available data on boiler types, coal properties (such as coalrank, moisture (Mcoal), ash content (Acoal), sulfur content (Scoal),chlorine content (Clcoal), Hg content (Hgcoal) and heating value(Btucoal)). Four factors were finally chosen by the built-up regres-sion model based on their importance. The four factors could ex-plain 75.4% of the variation in mercury emission rates, as shownin Table 1. Among them, the most significant effects on mercuryemission rates are coal rank and boiler type with higher confidencelimits (very low statistical p-value). Other factors, based on adecreasing sequence of significance (in absolute line coefficient va-lue), were Scoal and Mcoal. According to the affecting trends, fourfactors can be categorized into a group of positive factors, whichinclude Scoal and Mcoal; and a group of negative factors, which in-clude coal rank and boiler type. An increase of Scoal and Mcoal leadsto an increase in the level of mercury emission rates. An increase inthe coal ranks (Level 1: lignite, Level 2: sub-bituminous, and Level

3: bituminous) and an increase in the boiler type level (Level 1: PCand Level 2: CFBC) lead to a decrease in the level of mercury emis-sion rates. Based on the definition of coal rank and levels of boilertypes, it was found that burning low rank coal or blending it withhigher rank coals in the conventional PC unit result in relativelyhigher mercury emission rates.

In order to increase the prediction accuracy by the regressionmodel, one more factor, mercury speciation in the flue gas(Hg(0)/Hg(VT)stack), was included in the model build-up in the sec-ond trial. All factors were able to explain 81.7% of the variation inthe mercury emission rate, as seen in Table 1. This is a slightimprovement over results achieved in the first trial. The most sig-nificant factors affecting mercury emission rates were still coalrank and boiler type. Other factors, which were found to be lesssignificant, were Btucoal, Scoal and Mcoal. The same trends of factorsappeared repeatedly in both trials. For the new factor, Hg(0)/Hg(VT)stack, it appeared that an increase in the Hg(0)/Hg(VT)stack le-vel leads to an increase in mercury emission rates. It is unusualthat the critical factor on mercury speciation, Clcoal, was not a sig-nificant factor in the regression model. Nevertheless, Scoal wasfound to be a factor in the regression model. It may be implied thatClcoal, which was found to be a critical factor affecting mercury spe-ciation, did not have a direct effect on mercury adsorption on thefly ash. Scoal may have a direct effect on mercury adsorption onthe fly ash [3,7,16]. An alternative possibility is that coal rank,which was positively correlated with Clcoal, may replace the func-tion of Clcoal in the regression model. The third trial by the stepwiseregression procedure was conducted to investigate the most signif-icant factors on the mercury emission rate. Two factors were cho-sen by the regression model, which are boiler type and coal rank.These are the most significant factors affecting the variation ofmercury emission rates in this study. Those two factors were ableto explain 71.6% of the variation in mercury emission rates withinthe confidence limits. The CFB burning higher rank coal can achievethe best mercury removal efficiency among all other boilers burn-ing the same rank of coal (temperature factor is not included in thisanalysis due to less and incomplete information found in the ICRdatabase. Discussion on impact of this factor on mercury emissionrates has been included in a reference [20]).

3.2. The correlation of fly ash properties with mercury emission rates

Fly ash is a key point in explaining the significance of lowermercury emission rates in CFBC units, as indicated in Fig. 1 and Ta-ble 1. The pore structure of fly ash from different coals is presentedin Fig. 2. The specific surface area of fly ash from the CFBC (approx-imately 15 m2/gram) is generally higher than those from other PCboilers (generally below 10 m2/gram based on collected data inthis study). The specific surface areas of fly ashes from the PC boil-ers show a larger scatter, depending on coal ranks. The fly ash fromthe lignite-fired PC boiler had the lowest specific surface area(approximately 1.0 m2/gram) among the three ranks of coal. Thepore volume of fly ash increased when the specific surface area in-creased. However, the pore size of fly ash did not show any signif-icant trend with different ranks of coals. In order to characterize flyash generated by different coal ranks and boiler types, the specificsurface area, pore volume and pore size of fly ash with boiler typeand coal rank were taken into the stepwise regression analysis.Two factors (boiler type and coal rank) explained the 82.2% varia-tion of the specific surface area of fly ash generated by differentboilers burning different ranks of coals, 75% variation of their porevolume and 57.9% variation of pore size. This implies that the spe-cific surface area of fly ash is a more significant parameter thanother physical properties of fly ash. An increase in the coal ranks(Level 1: lignite, Level 2: sub-bituminous, and Level 3: bituminous)leads to an increase of specific surface area. The same trend is

Table 1Stepwise statistical analysis on factors of mercury emission rates

Code Factor Linear coefficient p-value Adjusted-R2

1 Coal rank �0.005

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observed in the case of pore volume. The development of porestructure in the fly ash might play an important part in enhancingmercury adsorption on the fly ash in the FF, which is correlated tocoal ranks and boilers (Table 2).

Scanning electron microscopy (SEM) has been used directly instudies of morphological changes during coal combustion in boil-ers. Figs. 3, 4 and 5 show SEM morphologies of different fly ashesgenerated by PC boilers. Texas lignite usually generates a verysmooth and round fly ash in PC units. There are no interconnec-tions between the few pores found within these particles. Higher

combustion reactivity of low rank lignite results in lower LOI con-tent in its fly ash, and thus, not much carbon is left for developingthe pore structure in fly ash. Alternatively, Selenium (Se) is identi-fied in these particles by using EDX. Selenium may form a coatinglayer, which will block the pore structure of fly ash and prevent Hgfrom being adsorbed on the inner surface of the ash. This may beone of the reasons that the Texas lignite-fired boilers show lowmercury capture efficiency. There is also supporting evidence fromtwo other factors concerning Se plugging under lignite-fired fluegas atmosphere. First, Se was identified on the surface of the car-bon adsorbent of the Appendix K trap (EPA standard method onmercury measurement by carbon trap), as indicated in Fig. 3-2.The spot marked with a, b, and c on the surface of the carbon trapwas accumulated with pure Se compounds. This may explain whythe carbon trap loses its mercury capture capability in the flue gasatmosphere when Texas Lignite is burned. Second, SnCl2 is used asa commercial solid catalyst in the dry mercury CEM system to re-duce the oxidized mercury for mercury measurement purposes. Seis also on the surface of this catalyst to quickly deactivate underuse in the lignite atmosphere. Both solid samples (activated carbonand SnCl2) started to lose their adsorption capability or catalyst’sreactivity after having contacted with Texas lignite-fired flue gasfor just a half day. According to material balance from field testing,around 60% of the total Se in coal occurs in the gas phase whenburning blended Texas lignite and PRB, while 90% of the total Sein coal occurs in the flue gas burning Texas lignite only. The major-ity of coal Se is released in the flue gas during combustion, fol-lowed by its condensation on particles, such as fly ash, adsorbentand catalyst, under a typical temperature of FF in the downstreamof boilers which are burning Texas lignite.

Lignite also is produced in the North Dakota (ND) area in theUnited States. A serious deactivation was observed when SCRcatalysts were used when burning ND lignite-fired boilers [4].

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Table 2Stepwise statistical analysis on factors of fly ash properties

Code Factor Linear coefficient p-value Adjusted-R2

BET1 Boiler type 9.51

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The detailed study indicated that the activity loss of SCR catalystsmight be attributed to the pores of the SCR catalyst being pluggedby alkali oxides (Na and K) with a lower melting point [5,15,17]. Ahigh concentration of Na and K particles attaches to the surface ofthe SCR catalyst, filling its pores. Thus, Se for Texas lignite and Naand K for ND lignite may decrease the surface area of the fly ash.Together with lower LOI content in fly ash from lignite, a higher

occurrence of Se or Na and K in lignite may be some of the majorreasons for the lower mercury capture capability.

The development of fly ash pore structure from PC boilers burn-ing bituminous coals is presented in Fig. 4(a). Its surface was not assmooth as those from lower rank coals. Fly ash from PC boilersburning sub-bituminous coal shows a similar round shape, but amuch smaller particle size. Its irregular particle surface and a less

Fig. 3-1. SEM pictures of fly ash from Texas Lignite-fired and Sub-bituminous fired PC boilers.

Fig. 3-2. Selenium species on Appendix K trap’s carbon and catalyst from Texas Lignite-fired PC boilers.

Fig. 4. SEM pictures of fly ash from bituminous or sub-bituminous coal-fired PC unit.

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developed pore structure are presented in Fig. 4(b). In comparison,the shape of fly ash from CFBC units remains as it was originally inthe coal. The irregular shape is due to the lower temperature inCFBC and thus less likely to melt, see Fig. 5. The round shape offly ash, which was generally found in PC units, is not found in CFBCunits. The pore structure is the same as that found in fly ash fromPC units burning bituminous coals. However, CFBC boilers generatefly ash with a larger specific surface area and pore volume (seeFig. 2). The micro-phase structures of fly ash from CFBC units couldbe compared to that of the commercially available Hg sorbent(Darco LH), which is doped with the brominated species to en-hance its Hg capture capacity, as presented in Fig. 6. The surfacearea of Darco LH (approximately 300 m2/gram) has a much highersurface area than that of fly ash from the CFBC system (15 m2/gram). One still could expect good Hg capture performance of CFBCfly ash due to its higher content in the flue gas if the prevailinginjection rate of commercial Hg adsorbent (Darco LH) in the fluegas is considered (a 20 times smaller concentration of Draco LHin the flue gas).

3.3. The correlation of SDA or SNCR with mercury emission rates inCFBC

The addition of limestone and staged combustion technologiesto CFB boilers could largely control the emissions of SO2 and NOx.The pursuit of even lower NOx and SO2 emissions under the CleanAir Act could be achieved by the application of SNCR with the

injection of ammonia (NH3) to reduce NOx to N2. The use of anSDA with the injection of wet limestone or recirculation of hy-drated fly ash also could further reduce the emission of SOx. Theuse of SNCR technologies may also result in few ppm (below5 ppm required by US EPA) of NH3 slipping into the flue gas of aCFBC, where the NH3 will be adsorbed on the fly ash. A concernis raised regarding the adsorbed NH3 occupying the pore structureof fly ash. This condition may prevent Hg adsorption on the fly ash.In the SDA system, additional wet limestone or fly ash is injectedinto the duct, which may benefit enhanced Hg capture. This isdue to the increased content of solid particles in the flue gas.Two detailed investigations were conducted by the WKU ICSETteam in two selected CFBC units, which demonstrated the effectsof SNCR or SDA on the variation of mercury emission rates. Thedata are presented in Figs. 7 and 8.

In Fig. 7 the mercury emission rate from CFBC unit#1 variedslightly. The mercury emission rate was approximately1.5 � 10�3 (lg/NM3/(lg/g � Btu/lb)) on average in the first 3 daysduring the stable injection of NH3 in the SNCR system. When theNH3 injection rate decreased, the mercury emission rate decreasedto approximately 4.0 � 10�4 (lg/NM3/(lg/g � Btu/lb)) on the fourthday. However, it remained at approximately 4.0 � 10�4 (lg/NM3/(lg/g � Btu/lb)) when NH3 injection returned to a higher level. Thismay imply that the NH3 injection does not have any significant cor-relation between mercury emission rates of a CFBC with equippedSNCR. Results of mercury emission rates were confirmed by threemethods: SCEM, ASTM OHM and EPA Appendix K. The injectionof NH3 in SNCR in No. 2 CFBC without an SDA unit did not haveany significant effect on the variation of mercury emission rates,see Fig. 8. The average mercury emission rates were approximately1.0 � 10�4 (lg/NM3/(lg/g � Btu/lb)). The comparison of mercuryemission rates at both units indicated that there was no evidenceto show that the use of an SDA on mercury emission rates. Resultswere confirmed by both the SCEM and OHM in the stack.

4. Conclusion

Based on best available data collected from the EPA ICR pro-gram and WKU ICSET’s mercury testing program, a statistical step-wise regression procedure was used to determine significantfactors on mercury emissions during coal combustion. Investiga-tions on the dependence of mercury emissions on coal ranks andelectric utility boilers equipped with fabric filter baghouses (FF)indicate:

Fig. 5. SEM pictures of fly ash from Bituminous coal-fired CFBC units.

Fig. 6. SEM pictures of Hg Sorbent (Darco-LH).

3328 Y. Cao et al. / Fuel 87 (2008) 3322–3330

Author's personal copy

0

0.0005

0.001

0.0015

0.002

0.0025

11-27 11-28 11-29 11-30 12-1 12-2 12-3 12-4

Date

mer

cury

em

issi

on r

ate

by H

g(V

T)

or H

g(0)

,(

g/N

M3 /

(g/

g B

tu/lb

))

0

20

40

60

80

100

120

140

160

180

NH

3 in

ject

ion

rate

, lb/

hr

SCEM Hg(VT) SCEM Hg(0) OHM-Hg(VT) OHM-Hg(0) Appendix K NH3

Fig. 7. Mercury emission rate on stack of selected No. 1 CFBC unit.

0

0.0002

0.0004

0.0006

0.0008

0.001

0.0012

0.0014

11-29 12-4 12-9 12-14 12-19 12-24 12-29 1-3 1-8 1-13

Date

mer

cury

em

issi

on r

ate

by H

g(0)

or

Hg(

VT

) at

Sta

ck, (

g/N

M3 /

(g/

gB

tu/lb

))

SCEM-Hg(0) SCEM-Hg(VT) OHM-Hg(0) OHM-Hg(VT)

SNCR on (NH3 Injection) SNCR off

Fig. 8. Mercury emission rate on stack of selected No. 2 CFBC unit.

Y. Cao et al. / Fuel 87 (2008) 3322–3330 3329

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(1) Higher mercury emission rates were generally found in bothCFB and PC units when lignite was burned. Higher mercuryemission rates observed during lignite-fired boilers arelikely due to lower specific area of fly ash, which resultsfrom lower LOI, as well as the pore blockage by elementsof Selenium (Se) for Texas lignite; and Sodium (Na) andPotassium (K) for North Dakota lignite.

(2) Lower mercury emission rates were generally found in bothCFB equipped with FF and PC units equipped with FF whenbituminous coal was burned. There was a statistically signif-icant lower mercury emission in the CFBC equipped with FFthan that in the PC units when sub-bituminous coal wasburned. Lower mercury emission rates in electric utilityboilers equipped with FF are due to their active fly ash gen-erated with a larger specific surface area and pore volume.

(3) There is no significant mutual benefit for the mercury cap-tured by the addition of Spray Dry Absorber (SDA) or Selec-tive Non-Catalytic Reduction (SNCR) in the CFBC system.

Acknowledgements

We gratefully acknowledge mutual financial supports throughprojects by the United State Department of Energy (DE-FC26-03NT41840), Kentucky Office of Energy Policy (PO2 8550600002929 1) and USDA-ARS project (No. 6406-12630-002-02S).

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