TECHNICAL PAPER ISSN 1047.32891. Air & 1%’,irle Mimage. ASSOC. 54:750—762

c3M~,’1 2C’~4 :.j. a W~ ~~

Emissions of Sulfur Trioxide 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 of sulfur trioxide (SO3) are a key component of

plume opacity and acid deposition. Consequently, these

emisslon5 need to be low enough to not cause opacity

violations and 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 air pollution devices being used. It is well known that

the catalyst used in the selective catalytic reduction (SCR)

technology for nitrogen oxides control oxidizes a small

traction of sulfur dioxide in the flue gas to 503. The extent

of this oxidation depends on the catalyst formulation 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 opacity and undesirable

emissions. Recently, such effects have been observed at

plants firing high-S coal and equipped with 5CR systems

and wet scrubbers. This paper investigates the factors that

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 of coal-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 of effluents and trading

of emissions increase the direct monetary value of emis

sions control. The days when one must only r~onslder the

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 of sul

fur trioxide (S03)/sutfuric acid (H2S04), as highlighted by

the recent and well-publicized experiences of a power

plant In Ohio.2 Although not directly subject to emission

lImits, 503 Is important to consider during the design and

operation of coal-fired utility boilers for a number of

environmental and plant performance reasons.

The formation of SO3 will occur during the combus

tion of sulfur (S)-bearlng fuels such as coal and heavy fuel

oils. Virtually all of the 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 or changes 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

lead to plant operation-related problems and environmental

concerns. The emissions of SO3 from a boiler depend on a

number of Interacting complex factors including coal sulfur

content, combustion conditions, flue gas characteristics,

arid air pollution devices being used. Understanding the

paramenters leading to excessive generation of S0,1H2S04

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 paper is expected to be a state-of-the-art reference on

the subject for regulators, utility industry personnel, and

others stakeholders.

Pet. EX 181
‘4:75O..7~ Srtvastava, Miller, Erickson, and Jambhekar

concentration of sub-micron particles upon which the

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

is a function of water vapor and H3S04 concentration and

increases as both these variables increase.3 The curves In

Figure 1 determine the fraction of H2S04 in the vapor and

condensed phases for temperatures below the dew point.

For example, a 250 ~F flue gas with 10% water vapor and

8 ppm H2504 will have a vapor-phase acid gas concentra

tion of —2 ppm, with the remaining 6 ppm in the con

densed phase.

Iftemperatures at the stack are low enough and water

vapor and H2S04 concentrations are high enough, the

condensed-phase concentration of H2S04 can be at a level

that results in the formation of a visible plume 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 fly ash particles present In the stack gases. The size

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

f SUl~ tion, H2S04 concentration, and plume opacity Is shown

~d by in Figure 2 for flue gas with a sub-micron particle mode at

ower 0.15 ~m diameter.4’5 The gray area denotes 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 hjncticn of H2S04 concenlratlo’)

to- ddfe’ent watar vaPor c0ncentrations.~

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 stack of a 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 plume opacity of —35%. An opacity of 20%

can be achieved by reducing sub-micron PM concentra

tion to —1.6 mg/rn3 (i.e., —70% reduction) or by 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 unit with

I mg/rn3 of sub-micron particles in the stack gases is

predicted to experience doubling of plume opacity from

—5 to 10% when H2S04 concentrations Increase from 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 healthy adults. How

ever, there are studies that have shown 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 of exposure

1 10

Fine paitlcle concentration (rTlgfm~)

350

325

I

175—- ____ _____ __________

1500.1 1 10

142504 Concentration (ppm)

100

.t004 vo~sne ~ June 2004 Jcur,~I of me A~ 8 Waf~e R~nagenien~ Assoca~, 751
Sdvastava, Miller, Erickson, and Jambhekar

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.’° Once formed, SO3 reacts easily with the mois

ture in combustion flue gases to produce H2S04. Below its

dew point, H2S04 condenses and will collect in relatively

low-temperature areas of the flue gas path, such as the air

heater, and corrode the contacted metal components. The

dew point varies with H2S04 and water concentrations in

the flue gas (see Figure 1), but is typically between 200 and

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

ing or plugging of APH passages.12 Regular maintenance Is

conducted at plants to address the Impacts described. This

maintenance can include monitoring and replacement of

materials, washing of APH 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 flue gas may require reheating to ensure

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

Limit the combined sulfur dioxide (SO2) and SO3 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 as a hazardous air pollutant

(HAP) under Title III of the Clean Air Act Amendments of

l990.’~ Under Title 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

either emitted directly as a solid or liquid or are emitted as

a vapor but condense or react upon cooling and dilution

in the ambient air to form solid or liquid PM immediately

after discharge from the stack.” Secondary PM is com

posed of particles that form through chemical reactions in

the ambient air well after dilution and condensation have

occurred.’8 Under this definition, 503 or H2S04 that is in

the vapor phase in the furnace or stack and either reacts to

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 may be required to

control SO3 to maintain opacity standards. Even though

opacity measurements in the stack may be within regula

tory limits, the formation of a visible plume caused by the

presence of SO3 may result In plume opacities higher than

allowable levels and a need to control SO3 emissions.

Most states have a 20% opacity limit for stationary

sources, including coal-fired utility boilers, and many also

have provisions for higher opacity levels during unit

startup. There are some exceptions to the 20% lImit, with

a few states having opacity limits of 40% and at least one

(West Virginia) with a 10% opacity limit.

The formation of a detached plume Is indicated when

in-stack opacity measurement values are lower than those

in the downwind plume. While In-stack opacity measure

ments are made using Continuous emission monitors,

measurements of the downwind plume opacity are cov

ered under EPA Method 9~9 The increase in opacity from

in-stack measurements to downwind Is often caused by

the condensation of vapors 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, and Jambhekar

ssIon in regulatory violations and good neighbor policy con

d a cerns.

separate

FORMATION OF SO3

Formation In the Boiler

The S In coaL has InorganIc and organic components. The

inorganic component is predominantly pyrite, which can

exist both as distinct particles (excluded) and bound In

the coal matrix (included). The organic component Is part

of the various organic structures present In coal. The

fractions of included and excluded pyrite and organic

component delivered to a furnace are known to be depen

dent on the fineness to which the coal is ground. During

the combustion of coal, virtually all the S gets oxidized to

gaseous species such as SO2 and SO3, with SO2 being the

principal oxide. Although detailed chemical mechanisms

for oxidation of fuel S are not understood well at present.

It is believed that this oxidation proceeds through rapid

formation of SO2, occurring on a tiniescale comparable to

that of fuel 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

concentrations of oxygen (0) atoms. The consumption of

503 near flames occurs primarily via

SO3 + HO3 -, HOSO~ + 02

S03+O-’S02+02 (3)

A few other reactions are considered to result in formation

and destruction of 503 near the flame zone, but the effect

of these on SO3 concentrations Is relatively minor. Table

1 summarizeS the reactions Involving SO3 In the combus

tion zone.1°

To understand SO3 formation, calculations were

made using the S chemistry described previously with gas

compositions and temperature-time history characteristic

of a coal-fired boiler.20 This 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 provide the input composition for the

chemical kinetic calculations based on the S chemistry.

Note that the H2-02-carbon monoxide (CO) subset of the

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 of the boiler (see

Figures 3 and 4). SO3 production via gas-phase S kinetics

is complete before the flue gas enters the economizer. The

results also reflect that SO3 production Increases with coal

Table 1. The readio~s ~1vo1á19 503 in the ambustion zcne. The ate xnsimb

are laled in U~ f~m it = AT0 e~t(—EAIRT) with wits in mat-an-sec.

‘uded as

er ~

ollutant

lents of

stations

(9.09

tonnes)

dustzjal

and is

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ough

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and

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1750

1500

2

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10~

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250

0

2 4 5

Time (s)

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

~~kane54 Jun.2004 Journal of The A~ & Waste Managewit A~g~ ~
Srrb’astava, Miqe, E’ickson, and Jambhekar

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 of 503 via reaction 1. Finally. Figure 5 reflects

that SO2 conversion rate (i.e., S031S02 molar ratio) for the

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 range of 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.22 This 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 of 503 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 linearly with 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

plants to control emissions of oxides of nitrogen (NO,). In

the SCR process, NH3 is injected Into the flue gas within a

temperature range of —600—750 F (315—400 CC), up

stream of a catalyst. Subsequently, as the flue gas 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 commonly used 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 ,~vwy1aI o~ The ~ ~ Waste Managemei: Assocsation ~~3hsne 54 June 2004
Snvastava, MiIIe, Eñckson, and Jambhekar

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

technology oxidizes a small fraction of SO2 In the flue 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% of 502 in bitumi

nous and from 0.75 to 1.25% in Low-S sub-bituminous

coal applications. To examine what this oxidation means,

consider an SCR application with an SO2 oxidation guar

antee of 0.5%. Also assume that the concentrations of SO3

• and 503 in the flue gas at the inlet of the SCR reactor aye

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, for a given catalyst material experiencing

the same flue gas conditions, the oxidation rate of 502 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

implies that the conversion rate is proportional to catalyst

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 of the 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

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i

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and

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igher

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2004~

Time (s)

• .~
Sr~stava, F47Ie,~ Eiickson, and Jambhekar

A systematic study of oxidation of SO2 to 503 over hon

eyco~nb SCR catalysts has been reported in ref 31. The

findings of this 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 of oxidation 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 of variable 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 transfer heat from hot flue gas

exiting the economizer to combustion air flowing Into the

boiler. These APHs are available In rotary regenerative and

tubular designs, with the former used more widely. Typ

ically, the flue gas temperature at the APH inlet is between

600 and 700 °F (316 and 371 °C) and —300 ~F (149 0Q at

the exit. SO3 is hygroscopic and, therefore, absorbs vaporphase moisture at temperatures above its dew point to

form H2S04 vapor.22 This process occurs in the APH. The

extent of conversion of SO3 to H2S04 depends on the

temperature distribution in the APH and flue gas moisture

content. However, virtually all SO3 converts to H2S04 at

temperatures of 400 ~F or less. If local 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

odically exposed to hot flue gas and relatively cold incom

ing combustion air, evaporation of condensed H2S04 oc

curs on exposure to air. The rate of this evaporation is

dependent on the moisture content of air and metal sur

face temperature of the APH flow passage.3233

Results of an extensive field test program Indicate

that —40% of the 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 of the flue gas and combustion

air occurs. Therefore, the resultant H2S04 formed is not

removed by evaporation into the combustion air and

passes directly Out of the APH. Modeling of the acid con

densation phenomenon in tubular APHs is described In

ref 35.

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

Irliected as a reagent in the SCR process. A minor fraction

2—5 ppmv, of injected NH3 slips past the SCR catalyst and

does not react with NO,,. This fraction of NH3, known as

NH3 slip, reacts with SO3 downstream of the 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 passages become plugged and pressure loss across the

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

across the flow cross-section at the APH Inlet is enhanced

In the APH. As a result, strong transverse variations In gas

temperature and H2S04 vapor concentration can exist in

the gas leaving the APH. These variations can lead to

localized condensation of H2S04. Based on 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.

Fly Ash 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 of this adsorption depends on the temperattire of the flue gas, concentration of H2S04, and fly ash

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 and the PM control equipment. The adsorbed H2S04

gets removed with the fly ash in the PM Control device

(ESP or baghouse).

756 Journal of the Afr 8 Waste Mana~,erne,,t Asoctation V~jn~54 Jun.2004
Srtvastava, Miller, E’ickson, and Jambhekar

PM

gets

I ulp.

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 fly ash

properties and temperature, the majority of SO3 In flue

gas of a 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 of alkali content of fly ash and SO3 concentration at

the inlet of the APH. The alkali content of fly ash Is

defined as the molar sum of magnesium 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 of this 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 to be the 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) has been used

since the 1960s for the measurement of SO3 and H2S04 in

flue gas streams4’ .42 The general arrangements of the CCS

and thimble holder are shown In FIgures 7 and B, respec

tively. The measurement system consists of a quartz-lined

heated probe that draws gas through a quartz thimble for

the removal of PM. The probe and thimble are heated to

avoid condensation of SO3 vapor in the gas sample. The

gases enter a temperature-controlled condenser where the

SO3 is condensed on the wall to be collected ~nd mea

sured after the sample run via a deionized water rinse.

The measurement techniques for SO3 and H2S04 re

cently have been under review for accuracy and improve

ment for TRI reporting. Recently, a review and verification

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

of SO3

~s takes

NH3 I~

‘action,

~and

as

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us salt

ince If

ss the

it and

I

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~tOr In

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~ For

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e gas

can

70

60

— 50

j 40

6 3°

0

20

10•

0’

0 !10 20

• ‘.‘~

2004

FIgure 6. FIt, ash SO3 089km Tate ~eo( &an~.

~t*jiie54 June 2004

‘*1,

30 40 50 60 70 80 90 100

AIk.IUSQ3 Mal. RaUe

.Xjwnal of The Ah-8 Waste Manageiient~757
Srtvastava, Miller, E,ickson, and Jambhekar

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 for a variety of coals with a range

of S and fly ash chemical compositions. The study further

investigated the SO3 removal rates and efficiencies of the

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 of SO3 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

greater than 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 method system has been

used extensively In the United States on a variety of coals

with repeatable and reliable results.

MITIGATION OF SO3 EMISSIONS

The mitigation of SO3 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 for the 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 effective at the full scale.30.3~ However,

the method of delivery and 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 for the control of SCR catalyst arsenic poisoning has

been shown to be an effective method of furnace SO3

control. Recent commissioning data’6 have shown at least

Pm~ Houal~

for SOaIH2SO4

Condenser

High Temperature

Oven for P)Tex

Thimble Hcdder

Thermocouple to

Monitor E~dt Gas

Temperature

High-Temperature

Probe Uner

F Dryimpinger

3% H202

lmpmngers -.

V

Condenser Cooitrig

quor Inlet

• .9

Temperature

Sensor

Dual-Temperature

Controller for

Mathtah*ig Probe end

Oven Temperature (550?)

Temperature

Sensor

Condenser Coolleg

Liquor Outel /

&bnerslb)e Temperature

end Pump

Combination

140?Contrrjlled

Temperature Bath

Silos Gel

Desairant 4. Vacuum Une

OMoe

Temperature Bypass Valve

Sensors Vacuum

Gauge

Omifice

Magnehelic

Main

Valve

Dry Gas Meter Pump

788 Ja#neI ci the Air 5 Waste Management Assoclar,on Vo~rme 54 June 2004
Sn~sta~, Miller, Erickson, and Jambhekar

.

r

FIgure 8. ccs i~r~e holdo-.

a 50% reduction In furnace SO3 from limestone addition.

The injection of alkaline 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 activity are currently un

der investigation. To date, no studies have measured the

potential benefit of 5CR catalyst arsenic poisoning control

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 of other alkaline materials after the furnace/

economizer exit has been used for the control of SO3 for

both APH corrosion and stack emissions.’0 The primary

sorbents used are compounds such as hydrated lime, lime

stone, MgO, and sodium carbonate. The selection of a

sorbent for a given site will depend on economic factors,

such as availability and required 503 removal rates. Alkali

injection has successfully removed between 40 and 90%

of the SO3 in the flue gas at various plants depending on

the injected material and injection rate.’° The sorbents

are introduced into the flue gas as either a dry powder or

mixed with water to form slurry before injection. The

location of Injection in the flue gas stream varies. Plants

with APH cold-end corrosion problems may elect to 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

sorbent before the ESP must, however, Consider the effect

on particulate control The ESP will have higher inlet

mass loading, and the fly ash will have different 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 of NH3 after the APH and before the ~SP has

been shown to be <90% effectIve in the removal of 503 In

full-scale application.’0 This method of mitigation re

sults In the formation of (NH4)2S04 and NH4HSO4 salts in

the ESP, depending on the NH3 and 503 concentration

~,,snaI oThe A~ ~ kS~st~ ~nagement As~o~~ ise

Spring Attachment

Hooks

Stainless Steel

Retaining Spring

Thermocouple

Gas

Inlet

1819 Ball

Joint

Standard Taper

Pyrex 40150

Gas

Outlet

S

iearch

in the

differ

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)tions

pilot

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ilkajj

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2004 V~jne 54 June 2004
Snvastava, MiIIe,’ &ckson, and Jambhekar

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 before the ESP Is used for fly

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. The injection of NH3 results in the adsorption ofNH3

by the fly ash. Because the fly ash will contain most of the

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) of SO3 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

The firing of sub-bituminous coals typically results In low

SO3 formation and emission rates. Consequently, switch

ing from firing bituminous to sub-bituminous coals can

be a mitigation option. However, equipment and fuel cost

factors often make such a change impossible. Many boiler

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 for control

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 as well as the conversion of

502 to SO3 in the furnace 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 employ separate charging

and collection systems. However, the collecting surface in

WESPs Is cleaned with a liquid, In contrast to mechanical

cleaning in dry ESPs. Consequently, the two 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 to power levels of 100—500 W per 1000 cfm offlue

gas, WESPs can operate with power levels as high as 2000

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 WESP within the wet scrubber is

a design option with many attractive features including a

compact footprint; the ability to integrate the 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.

Tests at the Sherco Station (WESP retrofit to the outlet

section of the wet scrubber) allowed the scrubber to 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 greater than 95% removal of SO3 and

PM25 and stack flow with near 0 opacity.50

Changing the Operation of APR

Increasing the heat transfer (or cooling of the flue gas) in

the APH would appear to be a potentially viable strategy

for removing some of the S03/H2S04 in the APH. 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 of the Ar & Waste Management Assocsatim Vd~Jno54 June2004
Srtvastava, Miller, Erickson, and Jambhekar

RI~FERENCES

1. CoinbuStlOM

Inc.: New York, 1966. ~‘. r:: , L, Combustion Engineering

2.

3. VeihOff.

awthomeM

F.H.; Bancheto,

Plant SpeWtngAElØi3ouds

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 of Vapors; MinDs. EuWron.

1984, 18, 435.444.

£ Damle. AS.; Ensor, P.S.; Sparks, L.F.. Options for Controlling Conden.

satlon Aetosob to Meet Opacity Standards; I. Air Pollut. 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 of Subsnlcrometer Sulfuric Acid 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 of the Opacity of Emissions 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.L Ammossigun Sulfate and BuulftsteFonnution 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. 710-7 16.

14. MIller. C.A., U.S. Environmental Protection Agency. Personal commu

nication with J. Bock of Siemens AG, Redwttz, Germany, June 18.

2002.

15. Clean AirActA,nendments of 1990 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. Study of Hezerdmu Mr Pollut

ant Emissions (nun Electric Utility Steam 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. Air Quality Critu~v for 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 Sulfuric Acid 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 of SO~ to 50~ by Fly

Ash and the Capture of SO~ and SO3 by CaO and MgO; Thennachini.

Acta 1974, 8, 155-165.

24. Monroe, L. An Updated Method jfr Estimating Total Su4lnlc Acid Emit

sions giwn Stationer,’ 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 of a 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 Today 2000.56, 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: Molecular Structure-Reactivity Relation.

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, more frequent soot blowing

may be required to control this corrosion. These factors

would need to be considered when deciding to change the

APH operation to mitigate SO3 emissions. Data reflect that

—25% increase in H2S04 condensation may be possible by

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 of SO3 and subsequent formation of

H2S04 can assist in selections of practical control ap

proaches. Elevated SO3 concentrations can lead to corro

sion, the formation of sulfite 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 concentratiOns can lead to the forma

tion of visible plumes at the stack exit or shortly down

stream ofthe Stack, resulting in noncompliance with local

regulations.

SO3 can be formed In the boiler during the combus

tion of S-bearing fuels or downstream, 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 variety of methods. Injection of alkali materials into

the furnace, either with the fuel or In slurry form, has

resulted in reductions of up to 80%. Post-furnace injec

tion of alkali materials can achieve up to 90% reductIons

but can increase particle lOadIngs and ash resistivity char

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.

‘bber is

idinga

Ilingof

rubber

ik and

ie fine

ecause

fl On a

.‘ter, a

as the

WESP

lerally

an

0 Sta

more

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o

2004

54 June 2004 Journal ci the MrS 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 of Sulfur Trioxide In ~JdlIty Flue Gas Streams. Fistsburgh, PA, March 1998.

33. Sarunac, N.; Levy, E. Factors Affecting Sulfuric Acid Emissions from

Boilers. Presented at the EPRI/DO!1FJ’A Air Pollution Control Sympo

sium: The Mega Symposium, Atlanta, GA, August 16—20, 1999.

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About the Author,

R.K. Snvastava and CA. Miller are at the Office of Research

and Development, National Risk Management Research

Laboratory, Research Triangle Panic 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 of the Air & Waste Managen’ent Association

W&rne 54 June 2004