TECHNICAL PAPER ISSN 1047.32891. Air& 1%’,irle Mimage. ASSOC. 54:750—762 c3M~,’1 2C’~4 :.j.a W~

~ ~ 

# Emissions of SulfurTrioxide from Coal-Fired Power Plants

R.K. Srivastava and CA. Miller Office of Research and Development, National Risk Management Research Laborator,’, Air Poflution Prevention and Control Division, U.S. Environmental Protection Agency, Research Triangle Park, North 

### Carolina

C. Erickson and R. Janibhekar Babcock Borsig Power, Inc., Worcester, Massachusetts

ABSTRACT Emissions ofsulfurtrioxide (SO3) 

### area key componentof plume opacity and acid deposition. Consequently, these emisslon5 need to be low enough to not cause opacity violationsand acid deposition. Generally, a small fraction of sulfur (5) in coal is converted to SO3 in coal-fired combustion devices such as electric utility boilers. The emissions of SO3 from such a boiler depend on coal S content, combustion conditions, flue gas characteristics, and airpollution devices being used. It iswell known that thecatalyst used in the selectivecatalytic reduction (SCR) technology for nitrogen oxides control oxidizes a small traction ofsulfurdioxide in the fluegas to503. Theextent ofthisoxidation dependson thecatalystformulation and SCR operating conditIons. Gas-phase 503 and sulfuric acid, on being quenched in plant equipment (e.g., air preheater and wet scrubber), result in fine acidic mist, which can cause increased plume opacityand undesirable emissions. Recently, such effects have been observed at plants firing high-S coal and equipped with 5CR systems andwet scrubbers. This paper investigates the factorsthat affect acidic mist production In coal-fired electric utility

750

~ crh~A~asre-ge~ASsoa: boilers and discusses approaches for mitIgating emission of this mist.

INTRODUCTION As understanding of the adverse effects of air pollution has grown, so also has the complexity ofcoal-fired power plant design and operation, especially with regard to air pollution control systems. Control of air pollutant emis sions is not only a legal requirement but also is becoming
a financial necessity, as salability ofeffluents and trading of emissions increase the direct monetary value of emis sions control. The dayswhen one must only r~onslderthe nuisance value of fly ash are long past.1 As plant complexity has increased, so have unex pected consequences of changing segments of the total chemical process that occurs between fuel preparation and ultimate emissions. One of the more discernible ad
verse consequences Is the formation and emission ofsul fur trioxide (S03)/sutfuricacid (H2S04), as highlighted by the recent and well-publicized experiences of a power plant In Ohio.2 Although not directlysubjectto emission lImits, 503 Isimportanttoconsiderduring thedesign and operation of coal-fired utility boilers for a number of environmental and plant performance reasons. The formation ofSO3 will occur during the combus tion ofsulfur (S)-bearlngfuels such as coal and heavyfuel oils. Virtually all ofthe SO3 converts to H2504 as flue gas Is cooled in the air preheater (APH). Relatively high con centrations of S03/H2S04 in the boiler, stack, or plume
can cause adverse impacts to plant equipment and to the environment. Impacts on plant equipment can include corrosion, fouling, and plugging and may require addi tional hardware orchanges in operation to minimize S03,1 H2SO4 concentrations and the resulting adverse Impacts.

Health and Environmental Effects Formation of visible H2S04 droplets depends upon the concentration and dew point of H~SO4 and the

~ Jun. 2CWld IMPLICATIONS Fomiation and emissions of S05/H2S04 can potentially leadto plantoperation-related problemsand environmental
concerns. The emissions of SO3from a boilerdepend on a numberof Interacting complexfactors including coal sulfur content, combustion conditions, flue gas characteristics, arid air pollution devices being used. Understanding the paramentersleadingtoexcessivegeneration ofS0,1H2S04 emissions can assist In selection of practical control ap proaches. This paper investigates the factors that affect S03/1’(2SO4 emissions ftorn coal-fired electric utility boilers and discusses approaches for mitigating these emissions. The paperisexpected to be astate-of-the-art reference on the subject for regulators, utility industry personnel, and others stakeholders.



### Pet. EX 181‘4:75O..7~ 

### Srtvastava, Miller, Erickson, andJambhekar

concentration of sub-micron particles upon which the



# . acid can condense. As seen in Figure 1, H2S04 dew point

is afunction ofwatervaporand H3S04 concentration and increases as both these variables increase.3 The curves In Figure 1 determinethefraction of H2S04 in thevaporand condensed phases for temperatures below the dew point. For example, a 250 ~F flue gas with 10% watervaporand 8 ppm H2504 will have avapor-phase acid gas concentra tion of —2 ppm, with the remaining 6 ppm in the con densed phase. Iftemperatures atthe stackare lowenough and water vapor and H2S04 concentrations are high enough, the condensed-phase concentration of H2S04can beata level that results in the formation ofavisibleplume attached to the stack. Once the gases leave the stack, the rate of ~lssIon cooling and subsequent H2S04 condensation competes

with the plume dilution by entrainment of ambient air into the plume. Even in cases where stack conditions are such that the H~SO4 Is completely in the vapor phase at -lUtlOfl the stack exit, a detached plume may still form shortly power do~wjnd as temperatures drop below the dew point. to air In most cases, and particularly in the case where ernis- H2S04, water, and sub-micron soLid particles are present, ~mIng condensation is the dominant formation mechanism. rading The opacity of these plumes is most strongly influenced cm,s- by the concentrations of condensing species and sub
e micron flyash particles present In thestackgases. Thesize distribution of the sub-micron fly ash also can have a ‘flex- noticeable effect on plume opacity at low to moderate

tOt& fj2~(34 concentrations, because these particles act as con ation densatlon sites for the condensing vapor-phase H2S04. !e ad- The relationship between sub-micron particle conceritra fSUl~ tion, H2S04 concentration, and plume opacity Is shown ~d by in Figure2 forfluegaswith asub-micron particle modeat
ower 0.15 ~m diameter.4’5The grayareadenotes a typical range ~Sion sand
-:r of

.bus fuel gas :on iime the ude ~di -03/ ~cts.

FIgure 1. D€w point of H3804 as a hjncticnof H2S04 concenlratlo’)

to-ddfe’ent watarvaPorc0ncentrations.~ Figure 2. Iso-opacity piot calciiated 4cr a bmocfal disbibution ot
coarse and sub-micron particles. The sub-macn particle mode is at 0.15 pm diarneter.~ The gray area represer~s typical sub-micron mass corcentratu,s in the stackofa coal-firad ut~ty bdler.5

of sub-micron particle concentrations downstream of an electrostatic precipitator (ESP).6 The curves In Figure 2 Illustrate that H3504 concen tration can have a strong impact on opacity when fine particle concentrations are present at realistic levels. Be
cause the condensing acid particles can nucleate to form particles even at very low levels of pre.existing submicron particles, further reduction of sub-mlc~on solid particles may not significantly reduce plume opacity. As
an example, a unit emitting 16 ppm of vapor-phase H2S04 and 5 mg/rn3 of sub-micron particles is predicted to result In a plumeopacityof —35%. An opacity of 20%
can be achieved by reducing sub-micron PM concentra tion to —1.6 mg/rn3 (i.e., —70% reduction) orby reducing H2S04 to —8 ppm (a 50% reduction). For units with limited ability to further reduce PM emissions, control of SO3 (and, subsequently, 112S04) may be the only viable option for meeting plume-opacity requirements. Because essentially all the SO3 is converted to H2S04 at or below stack temperatures, Figure 2 also Illustrates the impact of increases in SO3 formation on plume opacity. A unitwith I mg/rn3 of sub-micron particles in the stack gases is predicted to experience doubling of plume opacity from —5 to 10%when H2S04concentrations Increasefrom 5 to 10 ppm. Data on direct adverse effects on human health are Inconsistent, but studies indicate that aqueous acidic aerosols at typical and even elevated ambient concentra tions generally have minimal effects on Symptoms and mechanical lung function In young healthyadults. How ever, there are studies that haveshown changes in muco ciliary clearance and modest bronchoconstriction in asth matics exposed to elevated concentrations of 400 ~.g/m3
or morey.B Of more concern than the effects ofexposure 1 10 Fine paitlcle concentration (rTlgfm~)

350
325

I

175—-

____ _____ __________ 150 0.1 1 10

142504 Concentration (ppm) 100

.t004 vo~sne

~ June 2004 Jcur,~I of meA~ 8 Waf~e R~nagenien~ Assoca~, 751

### Sdvastava, Miller, Erickson, andJambhekar

to typical ambient levels of SO3/H~SO4 aerosol atone is exposure to this aerosol mixed with other ambient PM constituents, including elemental carbon and metals.’ In situations where 503/H2504 aerosol combines with a sinking plume, the ambient concentrations near the stack can reach significantly higher levels than those normally experienced. In such cases where meteorologi cal and operating conditions combine to form a nearstack acidic fog, damage to property and vegetation can
occur If the conditions are sustained for an extended period. Anecdotal evidence of adverse health impacts, such as burning eyes, sore throats, and headaches, has also been reported In such cases.2

Impacts on Plant Hardware The most common problem associated with elevated con centrations of SO3 is low-temperature (<300 ~F 

### 1150 ~Cj) Corrosion.’°Onceformed, SO3 reactseasilywith the mois ture in combustion flue gasesto produce H2S04. Below its dew point, H2S04 condenses and will collect in relatively low-temperatureareas ofthe flue gas path, such as the air heater, and corrodethe contacted metal components. The dew point varieswith H2S04 and waterconcentrations in thefluegas (see Figure 1), butistypicallybetween200and 300 °F(95 and 150~C, respectively), corresponding to low (8%) moIsture, low (0.1 ppm) L-12S04 conditions and high (15%) moisture, high (20 ppm) H2504 conditions, respec tively. At higher temperatures (above 1000 F [540 AC)), SO3 can cause corrosion In superheaters and reheaters.11 These high-temperature reactions are less common than the low-temperature condensation and corrosion reac tions. in addition to forming corrosive H2S04, SO3 reacts to form sulfate (S042) particles, especially ammonlum sulfate [(NH4)2S04] and ammonium bisulfate (NH4HSO4), In boilers using ammonia (NH3), which.can lead to foul ingorplugging ofAPH passages.12 Regularmaintenance Is conducted atplantstoaddressthe Impactsdescribed. This maintenance can include monitoring and replacementof materials, washing ofAPH passages, and other activities. In some cases, modification or addition of hardware may be required to minimize corrosion or plugging. At plants using wet flue gas desuifurizatlon (FGD) systems. the reduction In flue gas temperature can result in in creased H2S04 condensation and subsequent corrosion. In such cases, the fluegas may require reheating toensure It remains above the dew poInt, thereby resulting in in creased operation costs.13

ItEGULATORY OVERVIEW There are currently no U.S. regulations that directly limit emissions of S03!H2S04 aerosols from utility boilers. Other regulatory programs may. however, require SO3 control, as discussed later. German emission standards Limitthe combined sulfurdioxide (SO2) andSO3 emission concentrations to a daily average of 50 mg/Nm3 and a 30-mm average of 200 mg!Nm3. There is no separate emission limit for SO3 alone.14 In the United States, SO3 emissions are included as part of limits on opacity and particulate matter (PM) emissions, and l-12S04 is listed asa hazardousairpollutant (HAP) underTitle III ofthe Clean AirAct Amendmentsof l990.’~ UnderTitle Ill, electric utility generating stations
are exempt from the mass emission limits of 10 ((9.09 tonnes) per year of any single HAP or 25 t (22.7 tonnes) per year of combined HAPs set for other industrial
sources. Thus, although H2S04 is a listed HAP and is emitted in significant quantities by coal-fired utility gen erating stations,16 there is no regulatory requirement to control these emissions as HAPs. They must, however, be reported to the U.S. Environmental Protection Agency (EPA) under the Toxlcs Release Inventory (TRI) require ments. The H2S04 is typically measured and reported as equivalent 503. EPA has defined primary PM as particles that are eitheremitted directlyasasolidor liquid orareemitted as avapor but condense or react upon cooling and dilution in the ambientairtoform solid or liquid PM immediately after discharge from the stack.” Secondary PM is com posed ofparticlesthatform through chemical reactions in theambientairwell afterdilution and condensation have occurred.’8 Under this definition, 503 or H2S04 that is in thevaporphase in thefurnaceorstackand eitherreactsto form SO42— particles or condenses to form liquid H2S04 immediately after leaving the stack is considered part of primary PM emissions arid is therefore subject to PM emission limits. In some states or localities, plants maybe required to control SO3 to maintain opacity standards. Even though opacity measurements in the stack maybe within regula torylimits, the formation ofavisible plumecaused bythe presenceofSO3 may result In plumeopacities higherthan allowable levels and a need to control SO3 emissions. Most states have a 20% opacity limit for stationary sources, including coal-fired utilityboilers, and manyalso have provisions for higher opacity levels during unit startup. There are some exceptions to the 20%lImit, with
a few states having opacity limits of40% and at least one (West Virginia) with a 10% opacity limit. Theformation ofadetached plume Isindicatedwhen in-stackopacity measurementvaluesare lowerthan those in the downwind plume. While In-stackopacity measure ments are made using Continuous emission monitors, measurements of the downwind plume opacity are cov ered under EPA Method 9~9The increase in opacityfrom in-stack measurements to downwind Is often caused by the condensation ofvapors such as H2S04 and can result

182 ..IOur..a’ 01 the A.~ 8 Vle,sle .~1anagen,en: Asoc~at,c~, Vc.wje 54 June 2004

### Snvastava, MiIIe,~ Eiickson, andJambhekar

ssIon in regulatory violations and good neighbor policy con d a cerns. separate 

### FORMATION OF SO3 Formation In the Boiler TheS In coaL has InorganIcand organiccomponents.The inorganiccomponent is predominantly pyrite, which can exist both as distinct particles (excluded) and bound In the coal matrix(included). Theorganiccomponent Ispart of the various organic structures present In coal. The fractions of included and excluded pyrite and organic componentdelivered toafurnaceare known to be depen dent on the fineness to which the coal is ground. During the combustion ofcoal, virtuallyall the S gets oxidized to gaseous species such as 

### SO2 and SO3, with SO2 being the principal oxide. Although detailed chemical mechanisms foroxidation offuel S are not understood well at present. It is believed that this oxidation proceeds through rapid formation ofSO2, occurringon a tiniescalecomparableto that offuel oxidation reactions. Because SO2 formation Is
so rapid, Its concentration can be estimated using equi lIbrium calculations. The primary reaction that results in SO3 formation in flames is

SO2 + 0 + M

-, SO3 + M

This recombination reaction proceeds rapidly near the combustion zone in the presence of super-equilibrium concentrationsofoxygen (0) atoms. The consumptionof 503 near flames occurs primarilyvia

SO3 + HO3

-, HOSO~ + 02

S03+O-’S02+02 (3)

Afewotherreactionsareconsideredto result in formation and destruction of503 neartheflame zone, butthe effect ofthese on SO3 concentrations Is relatively minor. Table 1 summarizeSthe reactions Involving

### SO3 In the combus tion zone.1° To understand SO3 formation, calculations were made usingthe S chemistry described previouslywith gas compositionsand temperature-time history characteristic ofa coal-fired boiler.20This history is shown In FIgure 3. Initial gas-phase composItions are assumed to result from complete combustion (with 10 and 30% excess air) of a Montana sub-bituminous and a Western Kentucky bitu minous coal. The sub-bituminous coal Is composed of 53.26% (by weight) carbon (C), 3.35% hydrogen (H). Reaction A p E,JR

SO3 + H

= HO5O +0 2.5e05 2.92 25.300 503÷0

= SO2 +

### 03 2.0012 0 10.000 503+50=503+503 1.0012 0 5000 S02+0+M=503+M 9.2e10 0 1200 

### 503 4-01

=

### 503 + H~~• 4.9e02 2.69 12000 HOS03

= S03 + H 1.4e18 —2.91 27,600 HOSO3+0=S03+OH 5.0012 0 0 R)S02-fOH=S03+H20 1.0012 0 0 HOSO2 

### +03

=

### 503+1103 7.8e11 0 330

0.87% nitrogen (N), 0.78% 5, 9.34% ash. 21.23% water, and 11.16% 0. The bituminous coal contains69.79% C, 4.79% H. 1.34% N, 2.95% S, 

### 7.47% ash, 5% water, and 

### 8.65% 0. The initial compositions resulting from com plete combustion of the coals are then equilibrated at 1647 ‘C (1900 K) to providethe inputcomposition forthe chemical kinetic calculations based on the S chemistry. Note that the H2-02-carbon monoxide (CO) subset ofthe hydrocarbon mechanism given In ref 21 is used in these calculations. This subset Includes 25 reactions involving (1) 11 species.

FIgures 4 and 5 plot SO3 mole fraction and the ratio SO3 mole fraction/SO2 mole fraction versus time, respec tively. Because reaction 1 Is exothermic, little SO3 is formed Initially at high temperatures in the furnace. As the flue gas cools, SO3 Is produced, and the rate of pro duction Is high in the convective region ofthe boiler (see Figures 3 and 4). SO3 production via gas-phase S kinetics is completebeforethefluegasenterstheeconomizer. The resultsalso reflectthatSO3 production Increaseswith coal Table 1. The readio~s~1vo1á19503intheambustionzcne.The atexnsimb

are laledin U~ f~m it

= AT0 e~t(—EAIRT)withwits in mat-an-sec.

‘uded as er ~ ollutant lentsof stations (9.09 tonnes) dustzjal and is tygen. :ient to -ver, be ‘agency equire rted as

tat are ttedas .lutlon .tiately
corn
n ye
tt is in .lctSto ~I3504 art of



### ~ PM

-ed to ough~gu1aythe than -ions. mary also unit with
one
;hen hose: ~iire tots, 

# •~:

-suit

2004’

~ and (2)

~a0

1750

1500 2

~ 1250

10~

I—

~

5%

250

0 2 4 5

Time (s)

FIgure 3. Temperata,e-timehistomy tom-a coal-fred pa~io- piont~

~~kane54 Jun.2004 JournalofTheA~& Waste ManagewitA~g~

~

### Srrb’astava, Miqe, E’ickson, andJambhekar

6E-06

5E-06

4E-06

3E.06

2E-06

S content and furnace excess air level. This is because increases irvthe S content of coal or furnace excess air level result in a corresponding increase in the concentra tion of 503 andlor 0, which, in turn, results In greater production of503via reaction 1. Finally. Figure 5 reflects thatSO2conversion rate(i.e., S031S02 molarratio) forthe modeled coals ranges between 0.1 and 0.65%, approxi. mately, and is relatively independent of coal type at a specific excess air level. Because boilers are operated with between 10 and 30% excess air, a 0.65% conversIon of coal S to 503 should provide a conservative estimate of SO3 production in the furnace. In addition to the SO3 formation in the furnace dis cussed above, additional formation takes place in the temperature rangeof 1100—800 ~F (593—427 ~C) found in the economizer region of the boiler. This formation re sults from oxidation of 502 via molecular oxygen (02) catalyzed by iron oxides present in both ash and tube surfaces.22This oxidation mechanism depends on several operating and design parameters, including SO2 concen tration, ash content and composition, convective pass surface area, gas and tube surface temperature distribu tions, and excess air level. Because the impact of these parameters depends on site-specific factors (e.g., cleanli
ness of tube surfaces), it is difficult to characterize the extent of503 formation caused by catalytic oxidation of SO2. A laboratory study found that conversion of SO2 to SO3 in the presence of fly ash ranged between —10 and 27% for temperatures between 500 and 700 ~C, and es sentially Increased linearlywith the iron oxide content of the ash.23 These conversion rates are substantially higher than those found In coal-fired boilers, for which data suggest furnace/economizer conversion to be —0.8 to 1.6% for bituminous and 0.05—0.1% for Sub-bituminous coals.24 The above laboratory study results indicate that temperatures and residence times greater than, and car bon ash contents lower than, those typically found In coal-flied utility boilers are required to achieve high oxi dation rates.

Formation of SO3 in SCR Reactors The SCR technology is increasingly being used at power plantstocontrol emissionsofoxidesofnitrogen (NO,). In theSCRprocess, NH3 is injected Into thefluegas within a temperature range of —600—750 F (315—400 CC), up stream ofa catalyst. Subsequently, as thefluegas contacts the SCR catalyst, N0~, which predominantly is nitric ox ide (NO) in combustion devices, is chemically reduced to molecular nitrogen (N2). In the most commonlyused SCR 1.3E.05

1.2E.05

1.1 E-05

1 E-05

9E.O6 1900

1800

8E.06

7E-06 0 

# I 1600

/ 3 ~0 0

0

— 1400

1300

1200

1100

1000

900

800

700

1 E-06

FIgure 4. 803 pr0c~.JCe(j dimng coal C04T~uStion 600

500

754 ,~vwy1aIo~The

~ ~ Waste Managemei: Assocsation ~~3hsne 54 June 2004

### Snvastava, MiIIe, Eñckson, andJambhekar

FigUreS. SO3 cOmeieofl casing coal cocnbusbon.

process layout, known as hot-side SCR, 

### the catalyst is located between the economizer and the APH. It Is well known that the catalyst used In the SCR technologyoxidizes asmall fraction ofSO2 In theflue gas to SO3:~-29

SO2 + 

### 1⁄2 O~ —“SO3

The extent of this oxidation depends on the catalyst for mulation and SCR operating conditions. Generally, this oxidation can range from 0.25 to 0.5% of502 in bitumi
nous and from 0.75 to 1.25% in Low-S sub-bituminous coal applications. To examinewhatthisoxidation means, consideran SCR application with an SO2 oxidation guar anteeof0.5%. AlsoassumethattheconcentrationsofSO3

•and 503 in theflue gas atthe inletofthe SCR reactoraye 2000 and 20 ppm, respectively. Then, based on oxidation
across the catalyst, theconcentratiom of SO3 and SO3 at the exit of the 5CR reactor Will be 0.995 X 2000 1990 ppm and 2000

— 1990 +20 =30 ppm, respectively. mus, the SO3 loading in the flue gas at ‘the exit of the SCR reactor will be 5096 more than that at the Inlet. 

### ‘rbls

WA~1~54 .juno 2004 example illustrates that the level of oxidation across the catalyst can have a significant impact on SO3 concentra tion.In general, fora given catalyst material experiencing the same flue gas conditions, the oxidation rate of502 to 503 (or conversion rate) Is inversely proportional to area (4) velocIty (AV), which Is simply the ratio of flue gas volu metric flow rate to geometric catalyst surface area. This impliesthattheconversion rate is proportionaltocatalyst volume (and, hence, geometric surface area) and gas res idence time in the catalyst. Thus, the conversion rate, ~c, can be expressed as

K = K/AV (5)

where the constant of proportionality, K, is a function of catalyst material and design as well as flue gas proper. ties;3° that is.

K

= f(catalyst material, catalyst design,

flue gas properties) (6)

Journal ofthe Al’

### a Waste Management

~ 75~ 1900

1800 0.008
0.0075
0.007
0.0065

0.006 0 0.0055

~ 0.005 E 0.0045

0.0035

0.003
0.0025
0.002
0.0015
0.001
0.0005
0 C

I i

‘02 to and id es ~ntof igher data .8 to

nous that
car .d in oxi

‘wer

i. in in a up. acts

2004~ 

### Time (s)

• .~

### Sr~stava, F47Ie,~ Eiickson, andJambhekar

A systematic study of oxidation ofSO2 to 503 over hon eyco~nb SCR catalysts has been reported in ref 31. The findings ofthis study are as follows: (1) The Conversion rate depends primarily on the vanadium content of the catalyst and, therefore,
can be Controlled by adjusting this content; (2) The oxidation reaction is considerably slower than diffusion of SO2 within the pores of the catalyst. Therefore, the entire volume of the cat alyst Is active in oxidation of SO2 to SO3 in con trast to reduction of NO,, to N2, which, being diffusion-limited, occurs mainly at the catalyst surface. The rate ofoxidation Is Linearly propor tional to catalyst wall thickness. Accordingly, re ducing the wall thickness should not affect NO,, reduction but should reduce 502 to SO3 conver sion; (3) The reaction rate is ofvariable order in SO2 con centration, Increases with temperature, is inde pendent of concentrations of 02 and water In practical applications, is strongly inhibited by NH3 and is slightly enhanced by NO,,.

SO3 DEPLETION OR CONVERSION TO H2S04

Processes in APHs Utility boilers use APHs to transferheat from hot flue gas exitingtheeconomizertocombustion airflowing Intothe boiler.TheseAPHsareavailable In rotary regenerativeand tubular designs, with the former used more widely. Typ ically, theflue gastemperatureattheAPH inlet isbetween 600 and 700 °F (316 and 371 °C) and —300 ~F (149

### 0Q at the exit. SO3 is hygroscopic and, therefore, absorbsvaporphase moisture at temperatures above its dew point to form H2S04 vapor.22This process occurs in the APH. The extent of conversion of SO3 to H2S04 depends on the temperaturedistribution in theAPH and fluegas moisture content. However, virtually all SO3 converts to H2S04 at temperatures of400 ~F or less. Iflocal metal temperatures in the APH flow passages drop below the acid dew point,
some H2504 condenses on these surfaces as liquid drop lets (aerosol). This rate of condensation is dependent on the wall temperature and 112504 concentration in the flue gas. In a regenerative APH, where flow passages are peri odicallyexposedto hot fluegasand relativelycold incom ing combustion air, evaporation ofcondensed H2S04 oc curs on exposure to air. The rate of this evaporation is dependent on the moisture content ofair and metal sur face temperature of the APH flow passage.3233 Results of an extensive field test program Indicate that —40% ofthe flue gas 503 present at the regenerative APH inlet is removed in the APH by the condensationevaporation mechanism discussed above.3~ The tubular APH design does not have surfaces that are periodically exposed to combustion air; except for small leakages in welds and seal, no mixing ofthe fluegas and combustion air occurs. Therefore, the resultant H2S04 formed is not removed by evaporation into the combustion air and passes directly Out ofthe APH. Modeling of the acid con densation phenomenon in tubular APHs is described In ref35. In addition to the condensation-evaporation of SO3 discussed above, an additional conversion process takes place In boilers using SCR. In such applications, NH3 is Irliectedasa reagent in theSCRprocess. A minorfraction 2—5 ppmv, ofinjected NH3 slips past the SCRcatalystand does not react with NO,,. This fraction of NH3, known as NH3 slip, reacts with SO3 downstream ofthe SCR reactor and forms (NH4)2S04 and NH4HSO4 salts and, thereby, results in removal of S0~ from the flue gas.12 This salt formation can be detrimental to the APH performance if APH passagesbecomeplugged and pressurelossacrossthe APH results in forcing offline washing. The amount and type of salt formed will depend on the amount of NH3 slip; based on typical concentrations of SO3 and H20 in flue gas, the amount of NH3 slip is the limiting factor in salt-formation reactions.

Localized Condensation of U2S04 La the Duct between API! and PM Control Condensation of H2S04 also can take place in the duct between the APH and the PM control device.3S.36 For example, because of the rotating heat transfer element employed in the regenerative APH, gas flow stratification
acrossthe flow cross-section attheAPH Inlet isenhanced In the APH. As a result, strong transversevariations In gas temperature and H2S04 vapor concentration can exist in the gas leaving the APH. These variations can lead to localized condensation ofH2S04. Basedon operating con ditions, localized condensation also can occur in units using tubular APHs. For a given combination of flue gas H2S04 concentration and moisture content, Figure 1 can be used to determine if condensation is occurring.
FlyAsh Adsorption and Removal of H2S04 in PM

Control Equipment In addition to the processes described, some H2S04 gets adsorbed on fly ash in the APH and downstream equip ment. The rate ofthis adsorption dependson the temperattire ofthe flue gas, concentration of H2S04, and flyash properties, In particular alkalinity.22.37 The adsorption may Increase rapidly as the flue gas reaches the cold end of the APH and may continue in the duct between the APH andthe PM control equipment. Theadsorbed H2S04 gets removed with the fly ash in the PM Control device (ESP or baghouse).

756 Journal oftheAfr8 Waste Mana~,erne,,tAsoctation V~jn~54 Jun.2004

### Srtvastava, Miller, E’ickson, andJambhekar

PM

gets

Iulp. iper ash ~tion end the



# . The firing of sub-bituminous coals, which generally

have £ contents on the order of 0.5%, results In fly ash with a relatively high amount of alkali (20—30% by weight). Such alkaline ash adsorbs virtually all H2S04 in the flue gas.38 In such cases, SO3 Injection is required for Improving ESP performance. In contrast, based on flyash properties and temperature, the majority of SO3 In flue gas ofa bituminous Coal-fired boiler may or may not be adsorbed In fly ash.30 Finally, hot-side ESPs operate.at high-enough temperatures where lIttle adsorption of H2S04 occurs. As mentioned above, adsorption of H2S04 on fly ash depends on the alkalinity of the fly ash and the concen tration of H2S04. Figure 6 illustrates the general adsorp tion characteristics of fly ash as a function of the molar ratio ofalkali contentofflyash and SO3 concentration at the inlet of the APH. The alkali content of fly ash Is defined as the molarsum ofmagnesium oxide (MgO) and calcium oxide (CaO) in the ash. This figure represents a correlation of data from Babcock Borsig Power field-test ing programs concerning SO3 production and capture in flue gas systems.

Aerosol Fornwtlon In Wet FGD Systems As the H2S04 vapor-containing flue gas passes through a wet FGD system, it Is rapidly cooled below the acid dew point. Because the rate ofthis cooling Is greater than the rate of absorption of H2S04 vapor In the scrubber solu tion, the dew-point crossover results in H2S04 mist with sub-micron droplets.3O’39 in a wet scrubber, generally, the
mass transfer between ~his mist and the scrubbing liquid
occurs through inertial Impaction, gravitational settling, Brownian diffusion, diffusiophoresis. and thermophoresis. For sub-micron mist droplets with diameters less than —0.05 ~m, Brownlan diffusion is known tobethe primary component of mass transfer.4° In practical situations, de pending on the relative velocity between the sub-micron mist droplets and the collecting liquid form (droplets, wetted walls, liquid sheets, and bubbles), the Brownian motion-induced mass transfer is often not adequate to result in high-efficiency,capture of sub-micron droplets. Therefore, generally, larger droplets in the mist can be removed in the scrubber, but a significant portion of the sub-micron droplets are not removed and are emitted from the stack. This explains why wet FGD systems are relatively inefficient in removing S03/1-l2S04. In general, —50% of the H2S04 entering the scrubber may be re moved in the scrubber.

M~AStiREMENT OF SO3 The controlled condensation system (CCS) hasbeen used since the 1960s forthe measurementofSO3 and H2S04 in fluegas streams4’ .42ThegeneralarrangementsoftheCCS and thimble holderare shown In FIgures 7 and B, respec tively. The measurementsystemconsists ofaquartz-lined heated probe that draws gasthrough a quartzthimble for the removal of PM. The probe and thimble are heated to avoid condensation of SO3 vapor in the gas sample. The gases entera temperature-controlled condenserwherethe SO3 is condensed on the wall to be collected ~nd mea sured after the sample run via a deionizedwater rinse. The measurement techniques for SO3 and H2S04 re centlyhave been under reviewforaccuracyand improve mentforTRI reporting. Recently, a reviewandverification project has been undertaken by EPRJ to qualify the CCS method and compare field data with availabLe ically __sin.. tion i Is not air and :id con ibed in

ofSO3
~s takes NH3 I~ ‘action,

~ and

as ‘eactor ‘ereby,
us salt ince If
ssthe

it and I
‘20 in
~tOr In

duct

~ For ment .ation inced
n gas 1st in .~d to
conunits
e gas
can 70

60

— 50 

# j

40 6 3° 0 20

10•
0’ 0 !10 20

• ‘.‘ ~

2004 FIgure 6. FIt, ash SO3 089kmTate ~eo( &an~.

~t*jiie54 June 2004
‘*1, 30 40 50 60 70 80 90 100
AIk.IUSQ3 Mal. RaUe

.Xjwnal ofTheAh-8 Waste Manageiient

~ 757

### Srtvastava, Miller, E,ickson, andJambhekar

FIgure 7. 

## ccs samptng tram.
prediction methods used to estimate SO3 emissions for TRI reporting.37 The EPRI project compared laboratory data with field test data fora varietyofcoals with a range ofS and flyash chemical compositions. The study further investigated the SO3 removal rates and efficiencies ofthe plant equipment used for field verification. The EPRI project has concluded that alkaline ash will produce a bias In the SO3 measurement. The bias is a result ofSO3 removal In the thimble holder by the alka line ash collected on the quartz thimble. This bias Is seen as significant for low-S high-alkaline ash fuels (Powder River Basin coals). The CCS was found to have a bias of 20—25% Low readings for high S, acIdic ash fuels and greaterthan 40% for Powder River Basin coals. A possible solution to the bias is utilized in Europe.’3 The test method uses a system similar to the CCS; however, the quartz thimble is replaced with a small tubular ESP. The tubular ESP removes the ash to the sidewalls away from the gas stream; in Contrast, the quartz thimble filters the flue gas through the collected ash. Furthermore, the Eu ropean system can distinguish between gaseous and aero sol 503 using deionized water procedures on various col lection plates. The European SO3 methodsystem has been used extensively In the United States on a varietyofcoals with repeatable and reliable results. MITIGATION OF SO3 EMISSIONS The mitigation ofSO3 has been an active area of research for many years.’3~23~’4’5 This research has resulted in the development, refinement, and Implementation of differ ent techniques and methods forthe successful mitigation of 503 in the flue gases of fossil-fuel—flied boilers. Re. cently, a guide that summarizes 50~ mitIgation options and their respective success in either full-scale or pilot testing has been written.’0 The mitigation options are described below.

Alkali Addition Into the Furnace The Injection of alkali In the flue gas stream has been a method of SO3 mitigation for almost 30 years.’4 The lo cation in the flue gas stream and the delivery method of the alkali have been studied and tested depending on operating and site conditIons. The addition of alkalI Into the furnace recently has been proven to be effectiveatthefull scale.30.3~ However, the method ofdeliveryand the effectiveness of the alkali used varies from site to site depending on specific condi tions. The addition of limestone to coal before pulveriza tion forthe control ofSCR catalystarsenic poisoning has been shown to be an effective method of furnace SO3 control. Recentcommissioningdata’6 have shownatleast Pm~ Houal~ forSOaIH2SO4 Condenser HighTemperature Oven forP)Tex Thimble Hcdder Thermocoupleto MonitorE~dtGas Temperature

High-Temperature Probe Uner 

### F Dryimpinger 3% H202 lmpmngers

-.



### V CondenserCooitrig quor Inlet

• .9 Temperature Sensor

Dual-Temperature Controllerfor Mathtah*ig Probeend OvenTemperature (550?) Temperature Sensor

CondenserCoolleg LiquorOutel 

# / &bnerslb)eTemperature end Pump Combination 140?Contrrjlled TemperatureBath Silos Gel Desairant 

### 4. Vacuum

Une

OMoe Temperature BypassValve

Sensors Vacuum Gauge

Omifice Magnehelic Main Valve DryGas Meter Pump

788 Ja#neI ci theAir 5 Waste ManagementAssoclar,on Vo~rme 54 June 2004

## Sn~sta~, Miller, Erickson, andJambhekar



# . r

FIgure 8. 

## ccs i~r~e holdo-.

a 50% reduction In furnace SO3 from limestone addition. The injection ofalkaline sorbents (Ca-and Mg-based slurdes) has been shown to be elfective at controlling SO3 emissions of the furnace.39 The sluny injection method has successfully obtained SO3 furnace conversion reduc tions of 40—80% but has been found to be sensitive to injection location and elevation. The effects of the MgO sorbent slurries on SCR catalyst activityare currently un der investigation. To date, no studies have measured the potential benefitof5CRcatalyst arsenicpoisoningcontrol by MgO sorbent injection. The addition or injection of alkali In the furnace does not influence the conversion rate of the SCR catalyst.

Alkali Injection after the furnace The injection ofotheralkaline materialsafterthe furnace/ economizer exit has been used forthe control of SO3for both APH corrosion and stack emissions.’0 The primary sorbentsusedarecompoundssuch as hydrated lime, lime stone, MgO, and sodium carbonate. The selection of a sorbent fora given sitewill depend on economicfactors, such as availabilityand required 503 removal rates. Alkali injection has successfully removed between 40 and 90% of the SO3 in the flue gas atvarious plants depending on the injected material and injection rate.’° The sorbents
are introduced into the flue gas as eithera dry powderor mixed with water to form slurry before injection. The location of Injection in the flue gas stream varies. Plants with APH cold-endcorrosion problemsmayelectto inject the sorbent before the APH; however, adequate APH cleaning equipment is required with this configuration. In general, the common injection location for SO3 con trol is between the APH and the E5P. The Injection of sorbentbefore the ESP must, however, Considerthe effect
on particulate control The ESP will have higher inlet
mass loading, andtheflyashwill havedifferent resIstivity characteristics. It has been reported that dry Injection of hydrated lime has resulted in strong sparking and lower operating currents in the ESP during pilot-scale testing.’c

Ammonia Injection before the ESP The injection ofNH3aftertheAPH andbeforethe ~SPhas been shown to be <90%effectIve intheremoval of503 In full-scale application.’0 This method of mitigation re sults Intheformation of(NH4)2S04 and NH4HSO4salts in the ESP, depending on the NH3 and 503 concentration

~,,snaIoThe A~

~ kS~st~ ~nagementAs~o~~ ise SpringAttachment Hooks
Stainless Steel

Retaining Spring

Thermocouple

Gas Inlet 1819 Ball Joint

Standard Taper Pyrex40150 Gas Outlet

S

iearch in the differ .~adon

S. Re )tions pilot is are

~en a me lo )d of g on

has ever, ilkajj ndi 

# a

~east

2004 V~jne 54 June 2004

### Snvastava, MiIIe,’ &ckson, andJambhekar

ratios. The formation of NH4HSO4 is expected when NH3 to SO3 molar ratios are less than 1; this formation tends to decrease the ESP particle loading caused by fly ash agglomeration. NH3 injection beforetheESP Is usedforfly ash conditioning to increase ESP performance caused by the agglomeration effects. With NH3 to SO3 molar ratios between I and 2, Increased formation of (NH4)2S04 is expected, with an increase in the particle loading of the ESP.Theinjection ofNH3 results in the adsorption ofNH3 bytheflyash. Because the flyash will contain most ofthe injected NH3, the concentration may exceed acceptance limits for ash salability. Additional treatment of fly ash holding ponds and basins may be required If large amounts (—30 ppmv) ofSO3 are being removed. The use of NH3 for SO3 mitigation is practical on units equipped with SCRs, because NH3 is used as the reagent and is readily available on site.

Fuel Switching and Blending Thefiring ofsub-bituminous coals typically results In low SO3 formation and emission rates. Consequently, switch ing from firing bituminous to sub-bituminous coals can bea mitigation option. However, equipment and fuelcost factorsoften makesuch achange impossible. Manyboiler systems do not have the capacity and the equipment to accommodate the firing of sub-bituminous coal without major modifications that make fuel switch economically unacceptable. Coal availability and costs also can con strain fuel switching. One possible solution is the blend ing of bituminous and sub-bituminous coals to create a blend that has fuel and ash characteristics favorable for SO3 emissions. This strategy is currently used forcontrol ling SO2 emissions. When sub-bituminous coals are blended with bituminous coals, the overall S content of the fuel is reduced, resulting In a reduction of the SO~ concentration in the flue gas aswell as the conversion of
502 toSO3 in thefurnace and SCR and, thereby, resulting in an overall reduction in SO3. Also, the sub-bituminous coal ash contains large percentages of allcaline materials that further assist in the capture of SO3 in the APH and ESP.

Wet ESPs Similar to day ESPs, wet ESPs (WESPs) operate in a threestep process involving (1) charging of the entering parti des; (2) collection of the particles on the surface of an oppositeiy charged surface; and (3) cleaning the collec tion surface. Both technologies employseparate charging and collection systems. However, thecollectingsurfacein WESPs Is cleaned with a liquid, In contrast to mechanical cleaning in dry ESPs. Consequently, thetwo technologies differ In the nature of particles that can be removed, the overall efficiency of removal, and the design and maintenance parameters.” While day ESPs are typically limited topowerlevelsof 100—500W per 1000cfm offlue gas, WESPs can operatewith power levels as high as2000 W per 1000 cfm. Because of wet cleansing of the collec tion system, PM does not accumulate in the collection electrodes; this mitigates particle re-entrainment. Based

on these factors, WESPs can collect sub-micron particles and acid mist very efficiently. WESPs can be configured for vertical or horizontal gas flows in tubular or plate designs. Tubular designs offer smaller footprints and, in general, are more efficient than the plate type. WESPs can be integrated easily with a wet scrubber. In fact, integration ofthe WESPwithin thewetscrubberis
adesign option with many attractive features including a compactfootprint; theabilityto integratethe handling of the wash water and solids from the WESP with scrubber slurry, thereby avoiding the need for separate tank and blowdown system; and the ability to coüect the fine F12S04 mist, which typically escapes the scrubber because of its very small droplet size.” In 1986, the first commercial WESP application on a U.S. power plant took place when AES Deepwater, a 15$-MW cogeneration plant firing petroleum coke as the primary fuel, was equipped with a WESP. With the WESP in operation, the plume opacity at the plant is generally 10% or less.’8 Recently, an upflow tubular design WE.~P has been retrofit at Northern States Power Company’s Sherco Sta tion in a wet scrubber/WESP configuration. Two more power plant applications are underway presently: (1) a 5000-cfm slipstream at Bruce Mansfield Station; and (2) a plate-type WESP for integration with Powerspan’s ECO technology to be demonstrated at First Energy’s RE. Burger plant. TestsattheShercoStation (WESP retrofittotheoutlet section ofthewet scrubber) allowedthe scrubberto main tain a 70% SO2 reduction while keeping particulate emis sions at 0.01 lb/iC’ Btu and opacity under 10%. Full conversion of all scrubber modules at the plant with WESPs is now underway.’9 The WESP at the Mansfield Station is achieving greaterthan 95% removal ofSO3 and PM25 and stackflow with near 0 opacity.50
Changing the Operation ofAPR Increasing the heat transfer (or cooling oftheflue gas) in the APH would appearto be a potentiallyviable strategy for removing some ofthe S03/H2S04 in theAPH. This, in turn, would lead to increased condensation of fl2S04 in the APH and also to improved plant efficiency. However, the dew point at the APH outlet is —230 ‘F (110 ‘C), thereby limiting the SO3 removal to —9096.30 On the other hand, the potential for corrosion In the APH and downstream duct would increase with increased H2S04

780 .~canaI oftheAr& Waste ManagementAssocsatim Vd~Jno54 June2004

### Srtvastava, Miller, Erickson, andJambhekar

RI~FERENCES
1. CoinbuStlOM Inc.: New York, 1966. ~‘. r::

, L, Combustion Engineering 2. awthomeM PlantSpeWtngAElØi3ouds

~
3. VeihOff. F.H.; Bancheto, J.T~

~ c:’sem. En,. prog. 1974, 70 ~ Points of Flue Gases; 4. Damie, AS.; Ensor, D.S.; Sparks. LF.. Prediction of the Opacity of Detached Ptumee Formed by Condensation ofVapors; MinDs. EuWron. 1984, 18, 435.444. £ Damle. AS.; Ensor, P.S.; Sparks, L.F.. OptionsforControlling Conden. satlon Aetosob to Meet OpacityStandards; I. AirPollut. ConUoI A.ssoc. 1987, 37, 925.933. 6. Markowskl. G.R.; Ensot, Di; Hooper~ R.G.; Cart. R.C. A Submicron Aerosol Mode in Rue Gas from a Pulverized Coal Utility Boiler; Ema ron. Sri. Technol. 1980, 34(11), 1400-1402. 7. lelbul. GD.: Spektor, D.M.; Albert, R.E.; iipprnann. M. Dose. Dependent Effects ofSubsnlcrometerSulfuricAcid Aerosol on Particle Clearance from Ciliated Human Lung Airways; Am. md. H~. Assoc. I. 1984, 45. 285.292. 8. Utell. Mj.; Fzampton. M.W.; Morrow. P.1. Mr PoUutlon and Asthma: CUnical Studies with Sulfuric Add Aerosols; Allergy Proc. 1991, 12. 385-388. 9. Method 9—Visual Detgrmination ofthe Opacity ofEmissions from Sra. tionaly Sowces; 40 CFR 60, Appendix A, Government Printing Office: Washington. DC, 1996. AvaIlable at: www.epa.govlttniemcl promgateim-09.pdf (accessed April2004). 10. Peterson, J.; Jones, A.F. SO~ Mitigation Guide; EPRI Report Number TR-104424; EPRI: Palo Alto, CA, October 1994. 11. SInger. J.G. Combustion—Fossil Power Systems, 3rd ed.; Combustion Engineering Inc.: New York, 1981. 12. Burke,J.M.: )oh~son. IC.LAmmossigunSulfateandBuulftsteFonnution in AirPrehsatns; EPA-60017-82.025a; Industrial Environmental Research Laboratory. U.S. Environmental Protection Agency: Research Triangle Park, NC. 1982. 13. ZetlmeIsl, Mj.; McCarthy, 1(4.; Laurence, OF. investigation of Some Factors Affecting Nonfiame Generation and Suppression of SO3; In dust. Es~. Chem. Pi-od. Res. Des. 1983,22. 710-716. 14. MIller. C.A., U.S. Environmental ProtectionAgency. Personal commu nication with J. Bock of Siemens AG, Redwttz, Germany, June 18. 2002. 15. Clean AirActA,nendments of1990 Public law 101-549; Government Printing Of8ce: Washington. DC, November 15, 1990. Available at: www.epa.gov/epahornellaws.hem (accessed AprIl 2004). 16. U.S. Environmental Protection Agency. StudyofHezerdmu Mr Pollut ant Emissions (nun Electric UtilitySteam Genensting Units—Final ReporL Volume 1; EPA-4531R.98-049 Office of Mr Quality Planning and Standards: Research Triangle Park. NC, 1998. 17. US. Environmental Protection Agency. AirQualityCritu~vfor Pamen. late Maitre; EPA-6001P-95/OOi (NTIS P896—168224); National Center for Environmental Assessment: Research Triangle Park, NC, April 1996. 18. US. Environmental Protection Agency. Consolidated Emissions Re porting; Fed, keg. 2002, 67, 39602.39616. 19. Aizueta. M.U.; BIibao. P..; Glarboig, P. InhibItion and Sensitization of Fuel Oxidation by SOS, CombusL flame 2001, 127, 2234.2251. 20. SenIor, C.L; Sarofim, A.F.; Zeng; T.; Helble, 14.; Mamani-Paco, P.. Fuel Process. Technot. 2000, 63, 197.213. 21. Wamatz.J.; Mass, U.: Dibble. R.W. Combustion; Sprlnger.Verlag: New York. 1996; pp 67-71. 22. Hardman, P..; Stacy. P..; Dlsmukes. 1. Estimating SulfuricAcid Aerosol Emissions from Coal-Fired Power Plants. Presented at the DOE.FETC Conference on Formation, Distribution, Impact, and Fate of Sulfur Trioxide in Utility Flue Gas Streams. Pittsburgh, PA, March 1998. 23. Matter, P.; Dibbs, H.P. The Catalytic Conversion ofSO~ to 50~ by Fly Ash and the Capture ofSO~ and SO3 by CaO and MgO; Thennachini. Acta 1974, 8, 155-165. 24. Monroe, L. An Updated MethodjfrEstimating Total Su4lnlcAcid Emit sionsgiwnStationer,’ Power Plants Research and Environmental Affairs Department. Southern Company Generation and Electricity Market ing: Birmingham, AL, 2001. 25. Nova, 1.; dall’Acqua, L; Lietti, L; Glamello, 1.; l’orzattj, P. Study of Thermal Deactivation ofa De-NO~ Commercial Catalyst; AppI. Catal. B: Etwinm. 2001. 35. 3142. 26. Forzattl. P.; Nova, I.; Beretta. A. Catalytic Properties In DeNO~ and S02.SO3 Reactions; Catat Today2000.56, 431-441. 27. Dunn. j.; ltoppula, PL; Stenger, H.G.; Wachs, I. OXid~do~ of SulIu, Dioxide to Sulfur Thoxide over Supported Vanadla Catalysts; AppI. Cato.l. B: Environ. 1998, 19, 103.117. 28. Dunn. j.; Stenger, H.G.; Wachs. 1. Oxidation of Sulfur Dioxide over Supported Vanadla Catalysts: MolecularStructure-ReactivityRelation. ships and Reaction Kinetics; Catat Today 1999, 51, 301-318. 29. Dunn. J.; Stenger, H.G.; Wadis. I. Molecular Stnscture—_iteactivity RelatIonshIps for the Oxidation of Sulfur Dioxide over Supported Metal Oxide Catalysts; CataLTaday 1999, 53, 543-556. 30. Gutberlet, H.; Hartenstein, H.; Ucata, A. SO~ Corsve~tJon Rate of DeNO. Catalysts—Effects on Downstream Plant Components and Remedial Measures. Presented at PowerGen 1999, New Orleans, LA, 1999. 31. Svachula. J.; Alemany. 1.4.; Ferlazzo. N.; Forzattl. P.; Tronconl, 1.; Bregani. F. Oxidation of SO2 to SO~ aver Honeycomb DeNOxing Catalysts; hid. En,. Che,n. Ret. 1993. 32,826-834. condensation. Consequently, morefrequentsootblowing may be required to control this corrosion. These factors would need tobeconsideredwhen decidingtochangethe APH operation to mitigateSO3emissions. Data reflectthat —25% increase in H2S04condensation maybepossibleby lowering the flue gas temperature at the APH exit by -‘40 ~F (22 CC).

SUMMARY Formation and emissions of S03/H2S04 potentially can lead to plant operation-related problems and environ mental concerns. The formation of SO5 is complex, de pending upon fuel, operating parameters, and plant con figuration, and understanding the parameters leading to excessive generation ofSO3 and subsequentformation of H2S04 can assist in selections of practical control ap proaches. Elevated SO3 concentrations can lead to corro sion, the formation ofsulfite scale, and fouling and plug ging of low-temperature plant cornponents~ and can add to the particle loading to control equipment. In sonic cases, elevated SO3 concentratiOnscan lead tothe forma tion ofvisible plumes at the stack exit or shortly down stream oftheStack, resulting in noncompliancewith local regulations. SO3 can be formed In the boiler during the combus tion ofS-bearingfuels ordownstream, particularly In SCR reactors. SOIH2SO4 can condense on low-temperature components and gets adsorbed by fly ash. Adsorption is much greater In the high alkaline ashes resulting from sub-bituminous coal firing. S031H2S04 traditionally has been measured using extractive controlled condensation methods. If needed, S03/H2S04 emission can be mitigated us ing a varietyofmethods. Injection ofalkali materials into the furnace, either with the fuel or In slurry form, has resulted in reductions of up to 80%. Post-furnace injec tion ofalkali materials can achieve up to 90% reductIons but can increase particle lOadIngs and ash resistivitychar acteristics. NH3 Injection can also reduce S031H2S04 by <90%and may result In increased particle loading to the downstream collection systems. In plants with adequate operational and equipment flexibility, fuel switching and blending can be used to reduce formation and emissions of 

## so3. WESPs are also an option for control of 503/ H2SO~, and a variety of designs have been successfully demonstrated fOr colleêtlon of acid mists and opacity contrOl. ically fflue
as 2000 collec Ilection Based articles lfigured
sr plate :ind, in

rubber. ‘bberis idinga Ilingof rubber ik and ie fine

ecause

fl On a .‘ter, a as the WESP lerally 

# an

0 Sta

more (1) a I (2) a ECO R.E.
)utlet -nain eflhls

• Full with sfield and

s) in stegy is, in

14 in !ver, 

# o

.504

2004 54 June 2004 Journal citheMrS Waste Manapeene’ir~4s~o~ 761

### Sni.asta~, Mffier Erickson, and Jambhekar

32. Levy, EK. Effect of Boiler Operations on Sulfuric Acid Emissions. Presented at the DOE-FElt Conference on Formation, Distribution. Impact, and Fate ofSulfurTrioxide In ~JdlIty Flue Gas Streams. Fistsburgh, PA, March 1998. 33. Sarunac, N.; Levy, E. Factors Affecting Sulfuric Acid Emissions from Boilers. Presented atthe EPRI/DO!1FJ’AAir Pollution Control Sympo sium: The Mega Symposium, Atlanta, GA, August 16—20, 1999. 34. Devlto, M.S.; Oda, R.L Flue Gas SO~ Stratification at ESP Inlets. Pre sented at the DOE-FETC Conferenceon Formation, Distribution, Im pact, and Face of Sulfur Trioxide In Utility Flue Gas Streams, Pitts burgh. PA, March 1998. 35. Yllmaz, A.; Pecjsulls, M.; O’Agostisul, M.D.; Levy. L; Saninac, N.; Maust, P. Cold End Acid Condensation In TubularAir Preheasers. In Pmcudinp of 1995 Joint Power Generation Conference, PWR-VoL 28: American Societyof Mechanical Engineers: NewYork, NY, 1995; Vol. 3. pp 473-480. 36. D’Agostinl, M.; Levy, E.; Wilson, B. A Method for Calculating Add Deposition Rates In RegenerativeAlePreheaters. In HeatTransferfquip. meetFundamentals, DesignApplicationandOperating Problems; Sath, R.. Ed.; ASME-HTD: New York, NY, 1990; VoL 108, pp 78-87. 37. Blythe, 0.; Galloway, C.; Rhudy, R. Flue Gas Sulfuric Acid Measure. ment Method Improvements. Presented at the U.S. EPAIDOJJEPRI Combined Power Plant Air Pollution Control Symposium: TheMega Symposium; Chicago. IL, August 20-23, 2001. 38. Gutbedet, H. Pleasant Prairie Power PlantSO~ Meannrmenrs atDlffei’mr TestLocations; Riley Power inc. Internal Report by E. On Englneering~ Report Number01-01.100962; RIley Power: Worcester, MA, January 2002. 39. Blythe, 0.; McMlllan, R.; Davis,J.; Lanilson, M.; Beeghly, J.; Benson. L; Goetz, E.; Rt,udy, R. Furnace Inlection of Alkaline’ Sorbents for SulfuricAcid Control. PreSented at the U.S. EPAII)OE/EPRI Comhlnesi PowerPlant Air Pollution Control SymposIum: The MegaSymposium, Chicago, IL August 20-23, 2001. 40. AIr & Waste Management Association, Air Pollution Engineering Man ual, Ed. 2; DavIs. W., Ed.; Wiley & Sons: NewYork, NY, 2000. 41. Lisle, ES.; Sensenbaugh, J.D. The DetermInation 01 Sulfur Trioxide and Add Dew Point In Flue Gases; Combustion 1965, 36~ 12-16. 42. fllsmukes, LB. Conditioning ofFlyAsh with Sulfur Tn oxideandAmmo nia; EPA-600!2-75.015 (NflS P8-247231); U.S. Environmental Protec tion Agency, Office of Energy, Minerals, and Industry Research Tri angle Park, NC, 1975. 43. Erickson, C., BabcockBotsig Power Inc. Personal communicationwith HGutberlet of E. On Engineering, Gelsenkrlchen. Germany~ July 7,

44. Reese. J.t; Jonakirs, J.; Catacristi, Vi. Prevention of Residual Oil Combustion Problems by Use of Low Excess Air and Magnesium Addltlve;J. Eng. Power 1965, Transactions ofASI.fE. Series A, 8~ 229- 236. 45. Radway, J.E.; Ealey, LM. A Practical Reviewofthe Cause and Control ofCold End Corrosion andAddicStackEmissions In Oil-Fired Boilers. Presented atthe Winter Meetingofthe ASME, Atlanta, GA. December 6—10, 1975. 46. Hutcheson, L; Martin, M.; Ake, T.; Erickson, CA.; Nystedt, P.; Mclar. land. L; Favor, C. SelectiveCatalytic Reduction System Performanceat Duke Energy’s ClIffslde Unit S Power Station. Presented at the EPRJ 2002 Workshop on Selective Catalytic Reduction, Atlanta, GA, Octo. bet22—23, 2002. 47. Altman, R.; Offen, G.; Buckley, W.; Ray, I. Wet Electrostatic Precipita tion Demonstrating Promise for Fine Particulate Control-Pan I; Power Eng. 2001 Jan, 37.39. 48. Kumar, K.5.; Mansour, A. Wet ESPforControlling SulfuricAcid Plume Following an 5CR System. Presented at the ICAC Fonsrn 2002. Hates. ton. TX, February 12—13, 2002. 49. Altman, R. Wet Electrostatic Precipitation Demonstrating Multiple Pollutant Control In Industrial Applications Holds Promise for Coal. Fired Utility EmIssion ReductIon of Acid Mist, PM25. and Mercuty. i’resented at tIre U.S. EPAIDOEIEPRI Combined Power Plant AIr P01. lutlon Control SymposIum: The Mega Symposium; Chkago, IL, Au gust 20—23, 2001. 50. Srlvastava, R., U.S. Environmental Protection Agency. Personal com munication withJ. ReynoldsofCroll-Reynolds Co. inc., Westfield, NJ, August 8,2002.

About the Author, R.K. Snvastava and CA. MillerareattheOfficeof Research and Development, National Risk Management Research Laboratory, Research TrianglePanic NC. C. Erickson and R. Jarnbhekar are at Babcock Borsig Power, Inc., Worcester, MA. Address correspondence to: R.K. Srivastava, Office of Research and Development, National Risk Management Research Laboratory, Air Pollution Prevention alid Control DMslon, U.S. Environmental Protection agency, Research Triangle Panic, NC, 27711; fax: (919) 541-0554; e-mail: Shvastavaravf@epa.gov.

702 ,A~csrssi ofthe Air & Waste Managen’entAssociation W&rne54 June 2004