8 The Babcock & Wilcox Company

A System Approach to SO3 Mitigation

BR-1781

Technical Paper

A.L. Moretti and R.J. Triscori

The Babcock & Wilcox Company

Barberton, Ohio, U.S.A.

D.P. Ritzenthaler

American Electric Power

Columbus, Ohio, U.S.A.

Presented to:

EPRI-DOE-EPA-AWMA

Combined Power Plant Air Pollutant Control

Mega Symposium

August 28-31, 2006

Baltimore, Maryland, U.S.A.
A System Approach to SO3

 Mitigation

Introduction

Over the past decade, efforts to remove nitrogen oxides (NOx)

through the use of selective catalytic reduction (SCR) technology

have resulted in increased sulfur trioxide (SO3) concentrations in

the flue gas stream of utility boilers that fire fossil fuels or other

specialty fuels. This same problem has been encountered when

firing fuels with high vanadium content which increase the SO2 to

SO3 conversion in the boiler. When flue gases containing as low as

10 ppmdv of SO3 are treated in a wet flue gas desulfurization

system (WFGD) the potential exists for a visible secondary plume

to occur. The primary plume is due to water droplets which dissipate readily. The secondary plume is less visible and typically

only becomes apparent after the primary plume has dissipated.

The secondary plume is caused by aerosols, primarily sulfuric acid

but also ammonium bisulfate and other compounds. The color of

the secondary plume is typically blue, but brown and other colors

have been noted depending upon meteorological conditions, angle

of the sun, other compounds, etc.

SO3 formation and sinks

When fuel is combusted in a utility boiler, the sulfur in the fuel

combines with oxygen to form gaseous sulfur dioxide (SO2). Some

of this is further oxidized to SO3. The SO3 hydrates to form H2SO4

vapor in the flue work. Finally, the H2SO4 vapor condenses to

form an aerosol. Along the flue gas path, SO3/ H2SO4 is removed in

sinks such as the air heaters, electrostatic precipitators (ESPs),

baghouses and FGD systems. The acid aerosols that avoid collection in the pollution control equipment exit the stack and contribute to a visible trailing plume (typically blue).

Even a very low concentration can cause a readily visible secondary plume because of the inherent light scattering properties of

the sub-micron (aerosol) particulates. SO3/ H2SO4 concentrations

as low as 6 to 10 ppm dry volume have been known to cause a

visible plume under certain atmospheric conditions. Acid mist is

considered PM2.5 on new boiler permits and may eventually become regulated on the existing utility fossil fired fleet.

To develop a cost effective solution for SO3 mitigation in a

BR-1781

utility application, an overall system approach is necessary to

optimize the size and cost of such systems. When determining the

design requirements, consideration of SO3/H2SO4 formation and

capture should include concurrent evaluation of the following areas: 1) fuel selection, 2) boiler operation, 3) selection of SCR catalyst, 4) optimizing air heater design and operation, 5) utilization of

sorbent injection technology, 6) H2SO4 capture in particulate removal devices, and 7) H2SO4 capture across the WFGD. This paper will examine capture of SO3/ H2

SO4 in each of these areas and

will suggest ways to minimize installed and operating costs when

designing a SO3 Mitigation System. An example will be presented.

SO3 mitigation design criteria

boiler island SO3 formation

When establishing the design criteria for SO3 mitigation systems, it is important to understand the factors that affect SO3

formation in the boiler and also to have an understanding of where

H2SO4 is removed in the backend equipment of the boiler island.

SO3 forms in two areas of a fossil fuel fired power plant, the boiler

proper and across the SCR catalyst.

Combustion of fuel liberates elemental sulfur, which oxidizes to

form SO2. At typical combustion temperatures, very little SO2 is

converted to SO3, approximately 0.1%, because thermodynamic

equilibrium at these temperatures favors SO2 formation. As the

temperature drops the equilibrium changes so that more SO3 can be

formed. The formation of SO3 is dependent on the existence of

atomic oxygen which is present down to approximately 1500F. So

SO3 is formed in a lower temperature window as long as there is

atomic oxygen available. SO3 formation is increased by catalytic

effect of metal oxides on the boiler tubes or surfaces. The percent

of SO2

 that is oxidized to SO3 in the furnace and convection pass of

the boiler is defined as the boiler SO2 to SO3 conversion rate, or the

boiler conversion rate. The boiler conversion rate is dependent

upon many variables including: furnace geometry (surface area),

oxygen concentration (excess air), fuel vanadium levels, fuel sulfur

levels and the ash composition. Metal oxides in the ash can increase the conversion of SO2. Ash with high alkalinity will react

Albert L. Moretti and Ronald J. Triscori

The Babcock & Wilcox Company

Barberton, Ohio, U.S.A.

Douglas P. Ritzenthaler

American Electric Power

Columbus, Ohio, U.S.A.
2 The Babcock & Wilcox Company

with SO3 in the boiler and economizer and lower the measured

conversion. That is, approximately the same amount of SO3 is

formed but it reacts with the alkali in the boiler. As the SO3

 concentration is measured at the economizer exit, the amount of SO3

measured will be less than that formed. The conversion determined

from the measurement is the apparent conversion which is less

than the actual.

The SO3 in the flue gas begins to hydrolyze to form H2SO4

vapor as the temperature drops below about 1000F. This reaction

is complete at gas temperatures between about 350 and 400F. The

bulk of the reaction is taking place within the air heater. The H2SO4

can condense out on cold end surfaces, which can be below the acid

due point. Acid aerosols can also form if local gas temperatures

drop below the dew point due to air in-leakage or damage to the

insulation.

For a coal fired boiler, typically 0.5 to 1.5% of the SO2 in the

flue gas is oxidized to SO3. Firing fuels with high vanadium content, such as fuel oil or OrimulsionÆ, results in higher boiler conversion rates due to the catalytic effect of the vanadium. Conversion

measurements when firing fuels with high alkali content (sodium,

potassium, calcium in the ash) indicate relatively lower apparent

conversions. The actual conversion is unknown because of the

reaction of the SO3 and alkali in the boiler. As a result, the SO3

concentration in the flue gas is relatively lower with higher alkali

flyash and the calculated conversion is lower.

Boiler operation has an effect on SO3 formation. Operating the

unit with higher excess air can provide additional oxygen radicals

for oxidizing SO2. However, lowering the excess air level must be

balanced against higher unburned carbon levels in the ash.

SO3 formation in the SCR

Selective catalytic reduction (SCR) technology contributes additional SO3 to the flue gas and ultimately higher SO3 emissions.

The rate of SO2 to SO3 oxidation is defined as the SCR conversion

rate. The SCR catalyst consists primarily of vanadium pentoxide

(V2O5), tungsten trioxide (WO3) and titanium dioxide (TiO2). Vanadium pentoxide is the active compound in the catalyst and is the

ingredient responsible for the conversion of SO2 to SO3. Catalyst

composition is carefully selected based on the operating conditions, the SO2 concentration, the ammonia slip and the target ammonium bisulfate concentration. SCR catalysts can be designed for

a range of conversions, about 0.20% to 0.8% per layer. This results

in conversions of 0.60% to 2.4% with 3 layers of catalyst. The

conversion rate varies greatly with catalyst temperature. The combination of catalyst operating temperature and the baseline catalyst

conversion rate results in significant variability from site to site.

Thus, when selecting an SCR catalyst it is important to evaluate

both the benefits of using a low conversion catalyst and providing

means to lower economizer outlet (SCR inlet) temperature. Selecting a low conversion rate catalyst or lowering the catalyst operating

temperature can substantially reduce the SO3 content after the SCR

and can reduce the cost of the mitigation equipment if required.

For a given boiler that was originally designed for a low sulfur

fuel but will burn higher sulfur fuels in conjunction with the use of

a WFGD system, the potential exists for increased slagging in the

boiler. As a result, a higher economizer exit (SCR inlet) temperature may occur. As this temperature increases, the SCR conversion

rate increases, resulting in a higher SO3 concentration at the SCR

outlet. Some units minimize this increase in flue gas temperature at

the economizer outlet by employing water cannons and/or

sootblowers.

Removal in air heater

As the flue gas passes through the air heater the SO3 begins to

hydrate to form H2SO4. Some of the acid condenses and impinges

the colder surfaces of the air heater causing a portion to be caught in

the air heater baskets and on the ash. The basket temperature rises

as it traverses the hot duct generating a temperature gradient downstream of the air heaters. Some of the H2SO4 captured in the air

heater on the ìcoldî side of the duct re-volatizes on the ìhotî gas

side of the duct, producing an acid concentration gradient that corresponds well to the temperature gradient. H2SO4 that remains on

the air heater basket elements can be volatized as the elements

traverse the primary air duct. This liberated acid passes through

the pulverizers and is destroyed in the burner flame.

The amount of condensation and removal within the air heater

baskets depends upon the design of the air heater and the cold end

metal temperature. Among other things, this temperature will change

as a function of operating conditions, coal composition and the

cleanliness of the boiler surfaces and the air heater. In addition, the

amount of SO3 condensed is dependent on the air heater leakage.

Therefore, the amount of SO3 captured in the air heater changes

with time for each unit and is also different for different units and

operating set points. Usually, the removal in an air heater is 20 to

30%.

The presence of ammonia and SO3 in the flue gas can also result

in the formation of sticky ammonium bisulfate (ABS), which can

foul the air heater if present in sufficient amounts. The reduced

temperature after the air heater can result in H2SO4 aerosols, which

can corrode flues, air heaters, and other equipment. H2SO4 condenses in low temperature areas such as near leaking precipitator

doors, casing leaks, and cool duct surfaces caused by insulation

flaws. Once this H2SO4 is condensed, it does not all evaporate at

typical flue gas temperatures because there is insufficient heat in

the gas to overcome the heat of vaporization of the acid. Thus, an

SO3 mitigation system can also provide the added benefit of reduced corrosion problems.

Removal in particulate control equipment

Particulate removal equipment such as the electrostatic precipitator (ESP) or the baghouse plays a role in removing SO3. There are

many factors that affect the removal efficiency such as the type of

particulate removal device (i.e. hot or cold side ESP or baghouse),

the alkalinity in the ash, size of the H2SO4 aerosol particle size and

flue gas temperature. For a given coal, as the temperature leaving

the air heater approaches the acid dew point, studies have indicated

that the resistivity of the flyash decreases. Also as the temperature

decreases, the gas volume decreases. These factors result in higher

power consumption of the ESP which equates to higher collection

efficiencies. This improvement in collection efficiency correlates

to lower H2SO4 emissions at the ESP outlet resulting from the

flyash having more affinity to adsorb H2SO4.

The ESP has been the industry standard for particulate capture

on units burning medium to high sulfur fuels. The ESP allows for

lower air heater outlet temperatures which equates to greater boiler

efficiencies. In terms of maximizing SO3 removals, lower flue gas

temperatures have been known to increase removal. The removal

of condensed SO3 is also dependant on overall particulate removal

efficiency of the ESP as well as the alkalinity in the ash. Test data

indicates that the ESP is less effective at capturing SO3 when compared to a fabric filter.

The fabric filter (baghouse) is the industry standard on low

sulfur fuels. It is well suited for Powder River Basin (PRB) fuels.
The Babcock & Wilcox Company 3

Similar to the ESP, the fabric filter can also remove SO3. However,

there is a major difference that makes a fabric filter more efficient

than an ESP. The ESP captures ash that has adsorbed some acid.

The same thing occurs in the fabric filter. However, as ash is

removed in the fabric filter, a cake builds up on the bag. As the acid

passes through the cake it is exposed to more ash, so the adsorption

of the acid is increased over that occurring naturally in the flue gas.

This enhanced removal does not require additional alkalinity in the

ash. If there is additional alkalinity in the ash, such as when firing

PRB coals, additional removal will occur. Tests have indicated that

removals as high as 40% can be achieved in a fabric filter when

firing eastern bituminous coals. Acid removals above 90% are

achieved when firing PRB fuels. Flue gas temperature, fabric material, acid dew point and alkalinity in the ash, all play a key role in

the performance of the fabric filter.

Removal in WFGD

A WFGD provides the ideal conditions for aerosol formation.

As the flue gas enters the scrubber quench zone, the H2SO4 vapor is

quickly cooled below its dew point and now exists entirely as an

aerosol. The size of the H2SO4 aerosol particle is dependent on

how fast it is condensed. The rapid condensation that takes place

in the scrubber results in ultra-fine (sub-micron) aerosols. The

overall removal of the acid in the scrubber increases as the aerosol

particle size increases. Therefore, the removal of H2SO4 in the wet

scrubber can be enhanced by forming larger particles.

Precipitator design and operation also play a role in the removal

of acid in the scrubber.

Ash loading to the FGD may increase due to ash carryover from

an ESP with high resistivity ash, i.e., ash with little to no SO3 for

conditioning. The capture of SO3 by ash and/or sorbent in the

precipitator may also reduce the H2SO4 loading to the FGD. Limited data with lowering the inlet loading to the FGD has shown a

reduction in FGD acid aerosol capture rate.

The capture of H2SO4 in the WFGD system ranges from below

30% to 75%. Most test data indicates good repeatability at the

same unit and operating conditions. However, there are units for

which the test data is highly variable even at seemingly identical

operating conditions. The parameters controlling the H2SO4 removal in the wet scrubber are not fully understood.

Although the resultant secondary (SO3/ H2SO4) plume can be

quite visible, the actual concentration is very low, measured in

parts per million. In cases where the WFGD technology is utilized

in conjunction with SCRs on high sulfur coals or with high vanadium petroleum fuels, the sulfuric acid aerosols at the stack exit can

be as low as 6 to 10 ppm dry volume, yet are readily visible under

the right meteorological conditions.

Sorbent technologies

There are several sorbents that can be utilized to control the SO3

emissions from a combustion source. These sorbent control methods include injecting chemicals in either the fuel or in the flue gas.

These sorbents react in the flue gas to form a solid compound that

can be removed in the particulate collection device such as an ESP

or baghouse.

Sorbent injection technologies for the mitigation of SO3 typically utilize alkaline-based reagents that contain calcium, magnesium, sodium or ammonia. Depending on the reagent used, these

reagents can be injected dry or wet, either in aqueous or slurry

form. Dry injection typically uses pneumatic conveying equipment to transport dry solids from a storage silo to the flue gas.

Injection of solutions and slurries has some disadvantages when

compared to dry injection. Wet injection generally requires longer

residence times since the reaction typically occurs after evaporation. Also, poor atomization can result in agglomeration of ash on

internal supports or other boiler island equipment depending on

injection location.

Several chemicals have been found to be successful at reducing

SO3 concentrations when added downstream of the boiler furnace

(i.e., upstream or downstream of the air heater), SCR, ESP or scrubber. These chemicals include magnesium oxide, calcium hydroxide,

sodium bisulfate, ammonia, and sodium sesquicarbonate (Trona).

Each of these chemicals is effective in reducing SO3 emissions, but

extreme care must be exercised in selecting the proper additive for a

specific site. Due consideration should be given to: temperature

distribution across flues, characteristics of the additives and resulting salt formation, available residence time, amount and availability

of additive, physical limitations of ductwork, internal structural

supports, particle size of additive, flow distribution in ductwork

and potential impacts on flyash sales as well as reagent cost. Sorbents that are injected downstream of the SCR have an advantage in

the fact that the sorbent removes the SO3 generated from both the

boiler and SCR. Sorbents injected in the furnace can remove SO3

before the SCR but there could still be a visible sulfuric acid plume

because of the SO3 generated across the SCR, especially with a high

conversion catalyst.

Injection in the furnace and/or in the ductwork before an SCR is

assumed to only remove the SO3 formed in the boiler. The addition

of sufficient excess alkali with furnace injection may continue to

remove the SCR-generated SO3 if the alkali is still present and

reactive before and after the SCR. For example, some magnesiumbased sorbents injected into the furnace become unreactive before

the SCR. Furthermore, it is important with this option to select a

sorbent that will not poison the SCR catalyst.

Injection in the ductwork after the SCR reduces the total SO3

formed in both the boiler and the SCR and therefore reduces the

existing SO3 to the air heater. This minimizes the impact of ammonium bisulfate formation and other means for pluggage. This injection location also reduces the impact, such as corrosion, from operating near the dew point temperature. By reducing the SO3 concentration prior to the air heater, the average cold end temperature can

be reduced to achieve greater boiler efficiency (improved heat rate).

Alkali injection either before or after the ESP provides effective

control of SO3 plume at either location. These injection locations

do not address the potential for ammonium bisulfate deposition in

the air heater or the potential to lower the air heaterís average cold

end temperature. Injection prior to the ESP will minimize the potential for a visible SO3 plume, minimize ESP corrosion from higher

acid dew point, but can possibly degrade ESP performance depending on the sorbent and its effect on ash resistivity. Injection

after the ESP will also minimize the potential for a visible SO3

plume and provide downstream corrosion protection. However,

there is a potential regulatory issue with injecting a sorbent that

reacts to form a solid downstream of the particulate collection

device.

Typical sorbents

Table 1 summarizes the various sorbents typically employed in

power plant SO3 mitigation applications.
4 The Babcock & Wilcox Company

Ammonia

Ammonia has generally been used as the reagent for NOx control

in SCR systems and also for flue gas conditioning to enhance ESP

performance. Ammonia can also be an effective means for SO3 removal when lower concentrations of SO3 are present in the flue gas.

It is typically injected downstream of the air heater and upstream

of the ESP to form ammonium bisulfate and/or ammonium sulfate.

High removal efficiencies can be achieved if injected in front of the

air heater but ABS formation can produce a sticky ash that fouls the

air heater basket elements. Ammonia has minimal capital and O&M

costs compared with other technologies. Many plants with an SCR

system already have ammonia on site that could be utilized for SO3

mitigation.

The use of ammonia for SO3 mitigation can impact flyash sales

due to high ammonia content in the ash. Ammonia off-gassing from

flyash is another concern. Sites that stabilize scrubber sludge by

mixing it with flyash and lime could experience odor problems.

Additionally, ammonium bisulfate formation may cause buildup in

the air heater and flues, and cause ESP operational problems from

ammonia salts which may cause solid particulate related opacity

issues rather than H2SO4 issues. There is also a risk of increased

ammonia slip.

Magnesium Hydroxide

Magnesium based sorbents are primarily injected in the furnace.

Magnesium hydroxide is effective at capturing SO3 formed during

the combustion process in the furnace. This sorbent can also have

a beneficial impact in reducing slag formation on furnace surfaces.

Two different forms can be used. One is a byproduct of a MagLime

WFGD and the second is a commercially available product which is

delivered in slurry form at about 50% solids. It is typically injected

into the furnace as a slurry with about 15% solids.

This option has a relatively high O&M cost associated with it

due primarily to high sorbent cost coupled with the need for a high

molar ratio for it to be effective in reducing the formation of SO3.

Other O&M factors include nozzle maintenance and the wear associated with pumping an abrasive slurry. Capital costs must include

the slurry preparation equipment needed, and if winter operation is

required, heat trace and insulation of slurry pipes. The magnesium

based sorbents have not been shown to be effective in controlling

SO3 formed from the catalyst. Therefore, magnesium hydroxide is

typically used in conjunction with another technology.

Hydrated lime and high surface lime

Hydrated lime, Ca(OH)2, has been successfully utilized as a

means to mitigate SO3. It is injected on a dry basis after the air

heater and ahead of the ESP. This technology has relatively low

O&M and capital costs. Depending on site location, the sorbent is

readily available and inexpensive. The injection system is simple

compared to slurry injection, keeping capital costs to a minimum.

However, hydrated lime injection has been known to reduce performance of the ESP. Some sites have used hydrated lime with no

ESP performance issues while others with marginally sized ESPs

have reported a reduction in ash collection from calcium buildup

and increased resistivity (in addition to increased particle loading

entering the ESP basis). Humidification improves SO3 removal performance of hydrated lime; proper flow distribution and mixing is

important to achieving high removal efficiencies. With the inherent

temperature gradients leaving the air heater, it is important to match

the sorbent injection with the acid stratification to achieve optimum removal. Also, longer residence time is important for maximum removal.

Test data indicates that high surface area lime hydrate provides

improved performance and creates less maintenance issues than

lower surface area. Depending on the compatibility of the current

FGD system, if present, the cost of adding lime hydrate ahead of

the FGD can be partially offset by reduced lime addition to the

FGD system.

SBS

Sodium bisulfate (SBS) is very effective at removing SO3. It can

be purchased commercially or the byproduct of a dual alkali FGD

system can be used. It is typically injected as a liquid. It is

reported that this technology has relatively high O&M costs and

moderate relative capital costs. There are numerous maintenance

issues that have been reported related to nozzles, and duct deposition/ air heater fouling. Loss of atomization, even for a short amount

of time, can result in wetting of the fluework and huge agglomeration of ash. Increased residence time is required to evaporate the

moisture to avoid duct deposition even in ideal circumstances. A

significant amount of compressed air is required for atomization.

Field tests have shown some improvement in ESP removal efficiency.

Trona

Like other sodium sorbents, trona is very reactive and effective

in removing SO3. Trona is injected in dry form, which minimizes

the capital investment needed to deliver the sorbent to the flue gas

and minimizes the sorbent preparation equipment required. Dry

trona is also relatively benign, minimizing safety concerns at individual sites. A side benefit of trona injection has reportedly been

improved ESP performance. Sorbent cost is low, but transportation costs from the mine located in Wyoming are high. O&M costs

are minimal relative to other sorbent technologies. Nozzle and

lance design are imperative for reliable operation, therefore due

consideration should be given to their design. Flue gas temperature

is an important consideration in preventing deposition in the

ductwork. Deposition could occur if the trona / SO3 reactants

become molten (liquid).

Material handling concerns for this dry sorbent are related to its

cohesiveness, affinity for moisture, and its temperature sensitivities. Therefore, silo design, control of temperature and moisture

Table 1

Typical Sorbents

LowñNH3 already

in use w/SCR

Moderateñslurry

Low

Moderate

Low

Low

Good for lower

SO3 concentration

Goodñfurnace

injection

Goodñlimited by

ESP performance

Excellent

Good to

excellent

Excellent

Ammonia

Magnesium

Hydroxide

Hydrated

Lime

SBS

High Surface

Area Lime

Trona

Low

High

Low

High

Low

Low

Low

Moderate

Moderate

to low

High

Moderate

ESP concerns

Low

Sorbent Effectiveness

Relative

O&M

Costs

Relative

Capital

Costs

Relative

Maintenance
The Babcock & Wilcox Company 5

are important considerations to maintain a reactive material that

does not bridge or rat hole, and freely flows.

Example

In this section of the paper, an example is presented for a boiler

system that will retrofit a future SCR and WFGD system. As a

result, the SO3 levels will potentially increase and since the stack

will now become a wet stack as a result of the saturated flue gas

leaving the WFGD there will be the potential for a visible blue

plume to occur. With this retrofit, the plantís goal will be to use

some type of mitigation equipment to reduce the stack H2SO4

emission to pre-retrofit levels.

In the example, an analysis is performed to illustrate the estimated amount of SO3

 that formed in the boiler. Two different air

heater temperatures (300F and 330F) will be evaluated and resulting impact on SO3/H2SO4 removal in the air heater and dry ESP will

be examined. This will be considered the base case or pre-SCR and

WFGD case. Further analysis of two different SCR designs (a low

SO2 to SO3 conversion catalyst and a normal conversion catalyst)

is performed coupled with a WFGD and the resulting H2SO4 concentration at the stack with no SO3 mitigation technology will be

presented. In the final part of this example, the use of a sorbent is

presented for each of two SCR design cases and air heater temperatures. The estimated amount of consumable sorbent will be presented along with the economic findings. A stack concentration of

5 ppm will be the basis for sizing of the sorbent injection system.

Basis of design for example

This example is based on a typical 600 MW utility fired boiler.

For the purpose of this example a mid to high sulfur coal was

selected (3.1% S) to demonstrate SO3/H2SO4 concentrations and

sorbent consumption rates that are in line with coals used in actual

operating plants. Table 2 lists the coal analysis and heat input that

will be used for the basis of this example. Based on this design

information, Table 3 shows the flue gas flow rates from the products of combustion.

For this particular boiler design it is estimated that approximately 1.0% of the SO2 is converted to SO3. Working through all

the calculations, there will be approximately 379 lb/hr of SO3 leaving the economizer. As the SO3 passes through the air heater, two

events occur. The SO3 is hydrolyzed to H2SO4 and a removal of the

SO3/H2SO4 combination occurs. As discussed in this paper, lower

air heater outlet temperatures correlate to higher removal efficiencies. At 300F, 25% of the SO3 is removed and at 330F only approximately 20% is removed. For the 300F case the H2SO4 concentration is 348 lb/hr and for the 330F case, the concentration is 371

lb/hr. After the flue gas leaves the air heater and enters the dry ESP,

further removal occurs. For the 300F and 330F air heater outlet

temperature cases, the removal through the dry ESP is approximately 25% and 20% respectively. Thus, for the 300F air heater

outlet temperature case, the H2SO4 flow rate is 261 lb/hr or 14.7

ppmvd at the stack. For the 330F case, the H2SO4 is 297 lb/hr or

16.7 ppmvd at the stack. Table 4 summarizes this base condition.

After the retrofit of the SCR and WFGD system, the SO3 concentration changes as a result of the SCR catalyst oxidizing the SO2

in the flue gas to SO3. For this example, two different conversion

rates for the SCR are examined, 0.5% and 1.0% at both the 300F

and 330F air heater outlet temperatures.

When the air heater is designed for an outlet temperature of

300F and an SCR catalyst is designed for 0.5% conversion of SO2

to SO3, the SO3 flow rate entering the air heater is 566 lb/hr compared to the base case of 379 lb/hr (with no SCR). If a catalyst

designed for 1% conversion is selected, the SO3 flow rate entering

the air heater increases to 754 lb/hr compared to the base case of

379 lb/hr. Using the same H2SO4 removal efficiency for the air

heater and ESP as used in the base case, for the 300F case, the

H2SO4 flow rate entering the WFGD for the 0.5% and 1% case is

390 lb/hr and 519 lb/hr respectively. When the air heater design

outlet temperature is increased to 330F, the H2SO4 flow rate entering the WFGD increases to 444 lb/hr for the 0.5% conversion case

and 591 lb/hr for the 1% conversion case. For this example, 40%

removal across the WFGD will be used. For the 300F air heater

outlet design, when the catalyst is designed for 0.5% conversion, a

concentration 234 lb/hr or 13.4 ppmvd of H2SO4 enters the stack

and when the catalyst is designed for 1% conversion, the H2SO4

concentration entering the stack is 312 lb/hr or 17.8 ppmvd. For the

Entering Air Heater

379 lb/hr SO3

Entering Air Heater

379 lb/hr SO3

Entering ESP

 348 lb/hr H2SO4

Entering ESP

 372 lb/hr H2SO4

Entering Stack

261 lb/hr H2SO4

14.7 ppmvd

Entering Stack

297 lb/hr H2

SO4

16.7 ppmvd

330F Air Heater Outlet Case

300F Air Heater Outlet Case

Table 4

Base Condition

CO2

H2O

SO2

N2

O2

HCl

Total

1,151,349

290,706

30,297

3,960,526

198,420

402

5,631,700

Component Flue Gas Flow Rate (lb/hr)

Table 3

Flue Gas Flow Rates

Ash

S

H2

C

H2O

N2

O2

Cl

Total

Fuel input (MBtu)

HHV (Btu/lb)

17.61

3.10

4.13

64.24

5.5

1.15

4.19

0.08

100.00

5625.3

11,500

Ultimate Analysis %

Table 2

Coal Analysis and Heat Input Used
6 The Babcock & Wilcox Company

Based on the above conditions, the use of a sorbent will now be

evaluated. For this example, trona will be selected for the mitigation of H2SO4. Trona was selected due to the desire to condition the

precipitator with a sodium-based sorbent, combined with the desire to inject a dry sorbent into the duct. Using 5 ppm at the stack

as the design basis for the target H2

SO4 concentration, for the 300F

air heater outlet temperature case, with an SCR catalyst designed

for 0.5% and 1.0% conversion, the required trona flow rates are 572

lb/hr and 651 lb/hr respectively. For the 330F air heater outlet

temperature case with an SCR catalyst designed for 0.5% and 1.0%

conversion, the required trona flow rates are 572 lb/hr and 651 lb/hr

respectively. If 0.5% conversion catalyst is used with an air heater

outlet of 300F compared to using a 1.0% conversion catalyst at a

temperature of 330F, a savings of 123 lb/hr in the required amount

of trona will be realized. This equates to a savings of about

U.S.$75,000 per year for a single boiler unit. The savings will

propagate for plants with multiple boilers. Table 6 summarizes

this discussion.

Conclusions

When a plant is considering the use of SO3 mitigation technologies, several areas of the boiler island and air quality control system

need to be investigated to optimize the SO3

 mitigation philosophy

employed. For example, most users plan to use higher sulfur coals

after the retrofit of a Wet FGD system. This can impact boiler

conversion of SO2 to SO3 and economizer outlet temperature. Both

of these issues could substantially affect stack H2SO4 emissions by

increasing values. Air heater operation (temperature and operating

conditions) has a large effect on the amount of SO3

 exiting the air

heater and even the Dry ESP. Operating conditions and equipment

sizing are important considerations in SO3 mitigation. Wet FGDs

do collect some H2SO4 but not to the levels that provide optimal

stack condition on higher sulfur coals. Selection of a low SO2 to

SO3 conversion catalyst could reduce both the cost of mitigation

equipment as well as sorbent costs.

Several sorbents are effective in removing H2SO4 from the flue

gas stream but careful consideration is required on location of injection, cost and reliability of the handling and injection system and

sorbent costs. In some cases, use of alternate sorbents should be

considered in design of the sorbent handling system allowing flexibility to switch to a different sorbent if supply interruptions occur and/or price increases occur. In conclusion, a system approach

to SO3 mitigation based on plant-specific conditions may reduce

the overall cost of mitigation equipment.

References

1. Erickson, Clayton A. and Jambhekar Rajaram, ìCurrent work

on the impacts and control of SO3 emissions from Selective Catalytic Reduction systems,î 2002 Conference on SCR and SNCR for

NOx Control, Pittsburgh, Pennsylvania, May 2002.

2. Damle, A. S., Ensor, D. S., Sparks, L. E., ìPrediction of the

opacity of detached plumes formed by condensation of vapors,î

Atmospheric Environment, Volume 18, No. 2, (1984).

3. Maziuk, John, ìSuccessful Mitigation of SO3 by Employing Dry Srobent Injection of Trona Upstream of the ESP,î Air

Quality 5 Conference, Baltimore, Maryland, 2005.

4. White, Harry J., Industrial Electrostatic Precipitation,

Addison-Wesley Publishing Company, Boston, Massachusetts,

1963.

Trona Flow Rates

 300F A/H Outlet Temp, 0.5% Conversion Catalyst 572 lb/hr

 300F A/H Outlet Temp, 1.0% Conversion Catalyst 651 lb/hr

 330F A/H Outlet Temp, 0.5% Conversion Catalyst 605 lb/hr

 330F A/H Outlet Temp, 1.0% Conversion Catalyst 695 lb/hr

Table 6

Trona Evaluation

330F air heater outlet design, when the catalyst is designed for

0.5% conversion, a concentration 266 lb/hr or 15.1 ppmvd of H2SO4

enters the stack and when the catalyst is designed for 1% conversion, the H2SO4 concentration entering the stack is 354 lb/hr or 20.1

ppmvd. Table 5 summarizes the above discussion.

Table 5

Test Case Results

300F Air Heater Outlet Case, 0.5% Conversion Catalyst

300F Air Heater Outlet Case, 1.0% Conversion Catalyst

330F Air Heater Outlet Case, 0.5% Conversion Catalyst

330F Air Heater Outlet Case, 1.0% Conversion Catalyst

Leaving Air Heater

520 lb/hr H2SO4

Leaving SCR

566 lb/hr SO3

Leaving DESP

390 lb/hr H2SO4

Entering Stack

234 lb/hr H2SO4

13.4 ppmvd

Leaving Air Heater

692 lb/hr H2SO4

Leaving DESP

519 lb/hr H2SO4

Entering Stack

312 lb/hr H2

SO4

17.8 ppmvd

Leaving SCR

754 lb/hr SO3

Leaving SCR

566 lb/hr SO3

Leaving Air Heater

555 lb/hr H2SO4

Leaving DESP

444 lb/hr H2SO4

Entering Stack

266 lb/hr H2SO4

15.1 ppmvd

Leaving SCR

754 lb/hr SO3

Leaving Air Heater

738 lb/hr H2SO4

Leaving DESP

591 lb/hr H2

SO4

Entering Stack

354 lb/hr H2SO4

20.1 ppmvd
The Babcock & Wilcox Company 7

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