An Emissions Approach to SO3

Mitigation

Authors:

D.P. Tonn

A.L. Moretti

R.E. Snyder

Babcock & Wilcox

Power Generation Group, Inc.

Barberton, Ohio, U.S.A.

A. Lau

AES Deepwater Inc.

Pasadena, Texas, U.S.A.

Presented to:

Seventh Power Plant Air 

Pollutant Control “Mega” 

Symposium

Date:

August 25-28, 2008

Location:

Baltimore, Maryland, U.S.A.

Technical Paper

BR-1815
Babcock & Wilcox Power Generation Group 1

An Emissions Approach to SO3 Mitigation

Presented at:

Seventh Power Plant Air Pollutant Control “Mega” Symposium

Baltimore, Maryland, U.S.A.

August 25-28, 2008

BR-1815

D.P. Tonn, A.L. Moretti and R.E. Snyder

Babcock & Wilcox Power Generation Group, Inc.

Barberton, Ohio, U.S.A.

A. Lau

AES Deepwater Inc.

Pasadena, Texas, U.S.A.

Abstract/Introduction

Total particulate emissions are being set near detection 

limits on new or revised power plant operating permits. Acid 

gas emissions, such as SO3, which form particulate and make 

up a portion of total particulate, must be controlled to even 

lower values. Thus, the selected acid gas control technologies must be based on meeting the required emissions. This 

paper provides the results of investigations that have been 

performed and demonstrates achievable SO3 emissions 

utilizing an emissions control system approach for a range 

of fuel sulfur contents. Available total particulate emission 

results on both high and low sulfur fuels with multiple 

control technologies are presented as demonstration of 

SO3 mitigation. Consideration of multiple SO3 mitigation 

technologies and reagents is included. The conclusions of 

this analysis can be utilized in the economic selection of the 

proper control technologies for the selected primary fuel and 

sulfur content to achieve the total particulate emissions.

SO3 emissions and total particulate

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

the fuel combines with oxygen to form gaseous sulfur dioxide (SO2). Some of the SO2 is further oxidized to SO3. The 

SO3 hydrates to form H2SO4 vapor in the flue gas stream. 

Finally, the H2SO4 vapor condenses to form a sub-micron 

aerosol. The acid aerosols that avoid capture or collection 

in the downstream flue gas path (air heaters) and in the air 

pollution control equipment (electrostatic precipitators, 

baghouses and FGD systems) exit the stack and contribute 

to total particulate emissions. 

When establishing or selecting the required technologies 

to achieve the total particulate emissions, it is important to 

understand SO3 formation as well as the equipment and 

technologies for SO3 mitigation. SO3 forms in two areas 

of a fossil fuel fired power plant, the boiler and across the 

catalyst on those units utilizing SCR for NOx reduction. 

Combustion of fuel liberates elemental sulfur, which oxides 

to form SO2. At typical combustion temperatures very little 

SO2 is converted to SO3, approximately 0.1%, because the 

thermodynamic equilibrium at boiler combustion temperatures favor SO2 formation. As heat is absorbed by the boiler 

surfaces and the flue gas temperature lowers, 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 at temperatures of 1500F (815C) and greater. SO3

is therefore formed directly from SO2 as long as there is sufficient atomic oxygen available. SO3 formation is increased 

by catalytic effect of metal oxides on the boiler tube surfaces. 

The percent of SO2 that is oxidized to SO3 in the boiler furnace and convection pass is defined as the boiler SO2 to SO3

conversion rate. Furnace geometry (surface area), oxygen 

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

levels and ash composition all have an effect on the boiler 

conversion rate. Metal oxides in the ash can increase SO2

conversion and alkaline ash constituents can react with SO3

to lower the measured conversion rate. 

SCR effects on SO3 formation

When SCRs are installed in the typical high dust gas 

stream at the boiler exit, this NOx reduction technology 
2 Babcock & Wilcox Power Generation Group

contributes additional SO3 to the flue gas resulting in greater 

SO3 that will contribute to total emissions and requires 

further SO3 reduction. The SCR catalyst consists primarily 

of titanium dioxide (TiO2), vanadium pentoxide (V2O5) and 

tungsten trioxide (WO3) or molybdenum oxide (MoO3). 

Vanadium is one of the active catalyst constituents and is the 

primary constituent responsible for the conversion of SO2 to 

SO3 as the flue gas passes across the catalyst surface. The 

rate of SO2 conversion will vary depending on the vanadium 

concentration; however, there is an offset on catalyst NOx

reduction capability that also must be considered when 

selecting the catalyst chemistry. Thus a reduction in the 

catalyst SO2 conversion rate results in a requirement to 

increase catalyst volume. 

Catalyst conversion rate is also dependent on flue gas 

temperature and boiler load. The greater the flue gas temperature the greater the conversion rate. A greater temperature 

than normal or typical will occur as the boiler convections 

pass heating surfaces season or become fouled with an ash 

layer. At lower loads and reduced gas velocities there is also 

an increase in conversion rate due to the greater exposure 

time to the catalyst surface although this increase is somewhat offset by the lower flue gas temperature. Typical SO2

conversion rates across the catalyst can vary from less than 

0.5% to greater than 2% in a reactor with multiple catalyst 

layers and with the ammonia injection system in service. 

For those units that do not have an SCR bypass and utilize 

the SCR only during the summer ozone season, there will 

be an increase in SO2 oxidation when the ammonia is not 

present. In summary, the SCR SO2 conversion rate can vary 

considerably depending on catalyst chemistry and operating 

conditions. The total SO3 concentration in the flue gas is 

dependent on these factors as well as the fuel sulfur content. Fuel sulfur content becomes the dominant factor when 

evaluating the SO3 effects on particulate emissions and the 

necessary mitigation requirements. 

Plant arrangements and mitigation 

technologies

Other than the boiler and SCR which generate SO3, the 

typical power plant equipment in the downstream flue gas 

stream can affect the SO3 content in the flue gas and the 

resulting particulate emissions at the stack. Refer to Figure 1 

for the most typical power plant equipment arrangements. 

Air heaters The air heater is typically the first piece 

of equipment the flue gas passes after the SCR and is common to all utility power plants. While the air heater exit gas 

temperature will be above the acid dew point, the surfaces 

within the air heater will expose the flue gas to temperatures 

below the acid dew point. This results in the collection or 

capture of a portion of the SO3 present in the entering flue 

gas. This reduction in SO3 will vary from almost no reduction 

to as great as 50% depending on many variables including 

operating gas temperatures, fuel type, ash characteristics 

and cold end metal temperatures.

Electrostatic precipitators The dry electrostatic 

precipitator (ESP) remains the most common high efficiency 

particulate collection device in use today. When installed 

after the air heater the ESP depends on the presence of SO3

on the surface of the ash particles for optimum operation 

and particulate removal. SO3 conditioning of the ash is 

utilized on some units burning lower sulfur coals to reduce 

the ash resistivity to optimize particulate collection. ESPs 

installed ahead of the air heater (hot side ESPs) are in a gas 

temperature zone where the SO3 is all vapor and does not 

attach to the ash particles; therefore the hot side ESP depends 

on bulk ash resistivity for effective particulate collection. 

Thus, ESPs installed after the air heater result in some SO3

reduction in the flue gas. This reduction may vary from 20% 

to 80% and is enhanced to the upper end of the range by the 

injection of sorbent materials ahead of the ESP, being careful 

to not upset the basic ash resistivity in a negative manner 

and cause a reduction in particulate collection.

Wet electrostatic precipitators (Wet ESPs) are effective 

collectors of both ash particles and acid mists such as H2SO4. 

The Wet ESP operating principles are similar to the dry ESP 

with a couple of major differences. First, the Wet ESP operates at or near saturated flue gas conditions so that moisture 

plays an important role in the Wet ESP operation. At these 

conditions all of the SO3 is present as H2SO4 in aerosol 

form for ease of collection. The second major difference is 

the cleaning of internal surfaces where the Wet ESP utilizes 

water sprays instead of rapping systems. This difference 

is critical in the elimination of particulate re-entrainment 

by the Wet ESP. Wet ESPs can be designed to collect over 

Fig. 1 Typical power plant arrangements.
Babcock & Wilcox Power Generation Group 3

90% of the aerosol fine particulate as well as the fine ash 

particulate with outlet emissions at the detection limits of 

current test methods.

Fabric filters The fabric filter is another primary high 

efficiency particulate collector. It can be installed either at 

the air heater outlet to collect flyash or in combination with 

the spray dryer FGD to collect reagent products in addition 

to flyash. The primary collection mechanism for the fabric 

filter is the dust cake on the filter bags.

Thus at the air heater outlet location the fabric filter is a 

very efficient collector of the H2SO4 aerosol material. This 

location is also favorable to maximize the SO3 reduction with 

sorbent injection ahead of the fabric filter. Under favorable 

conditions, SO3 reduction of the air heater effluent in excess 

of 90% is easily achieved. Air heater exit gas temperature 

and bag materials must be synchronized for the SO3 concentration and for greatest bag longevity. 

When used in combination with spray dryer FGD, the 

fabric filter is installed downstream of the FGD module 

and results in an even greater reduction of SO3 than other 

technologies. The spray dryer reagent slurry reacts with the 

SO3/H2SO4 in the flue gas to form particulate sulfate compounds and the temperature is reduced to well below acid 

dew point driving all remaining SO3 to the H2SO4 aerosol. 

The highly efficient filter cake drives the fabric filter effluent 

H2SO4 concentration to detection limits. This combination of 

technologies is most applicable to the lower sulfur fuels. 

Wet FGD The primary purpose of the Wet Flue Gas 

Desulfurization (Wet FGD) system is the capture of SO2. The 

Wet FGD will collect some particulate as the flue gas passes 

through. The intimate contact between a flue gas stream and 

the scrubber liquid will transfer some particulate in the flue 

gas to the liquid in removal from the gas stream. Particulate 

collection efficiency in the Wet FGD is dependent on the 

particle size with the finer particulate being more difficult 

to remove. Therefore, since the H2SO4 aerosol is present in 

the flue gas only as a fine particulate, the Wet FGD has a 

limited ability to be an efficient collector of this material. 

The measured and reported capture of H2SO4 across the 

Wet FGD varies from 30% to greater than 50% with limited 

knowledge of how to maximize the removal. 

Dry FGD The spray dryer FGD (Dry FGD) technology 

injects lime slurry into the flue gas stream downstream of 

the air heater for environmental control of SOx. The slurry 

brings the flue gas temperature down to a temperature that 

is approximately 25F (14C) above saturation and allows the 

lime to react with SO2 and SO3 forming particulate calcium 

compounds. Dry FGD systems are installed in combination 

with a high efficiency particulate collector which is typically 

a fabric filter for greatest SOx reduction. In the case of high 

alkaline coal ash, the particulate collected by the fabric filter is recycled for injection with the lime slurry for greater 

utilization of the ash and lime alkalinity. Due to the reduced 

temperature operating conditions and the slurry alkalinity, 

this combination of technologies is very effective in the 

capture of H2SO4, resulting in stack H2SO4 emissions of 1 

ppm or less when burning a low sulfur PRB coal. 

Injection sorbents As referenced in both the dry ESP 

and fabric filter sections above, injection sorbents can be 

used to enhance the capture of SO3/H2SO4. Most injection 

sorbents are injected dry, although not exclusively. With this 

technology the dry sorbent, frequently alkaline in nature, 

reacts with the SO3/H2SO4 vapor for collection as a particulate. Popular sorbents for SO3 capture include magnesium 

hydroxide, hydrated lime, high surface area lime, Trona, 

sodium bi-sulfite, ammonia and other proprietary products. 

Considerations on sorbent usage and injection include suitable gas temperature for optimum reaction, effects on ash 

resistivity and ESP performance, available residence time 

for drying and reaction, affects on ash sales and disposal, air 

heater fouling, and reagent storage and handling issues. 

This technology is suited for existing units that may have 

a tendency for a visible or blue plume, particularly after a 

SCR system is added and the level of SO3 in the flue gas is 

increased due to the catalyst oxidation of SO2. This technology can also be used on a new unit to achieve the low total 

particulate requirements at the stack which includes contribution from H2SO4. It may be logical to install a sorbent 

injection system and avoid the use of a Wet ESP depending 

on fuel sulfur content. Sorbents for SO3 may be required 

to enable the use of injection technologies for mercury 

capture. An example of sorbent technology operating data 

for the Gavin plant with Trona injection is given in Table 1. 

The Gavin plant burns high sulfur coals and demonstrates 

the high capture rates of SO3 by dry sorbent technologies. 

These capture rates can be used in the determination of total 

particulate emissions. 

Investigations and studies

One purpose of this paper is to assemble a sampling of 

the demonstrated and available technologies which have 

achieved low particulate stack emissions including the effects of SO3/H2SO4. The following provides stack emission 

results for total particulate and includes the filterable and 

condensable portions on a range of applications.

Table 1

SO3 Reduction Across ESP with Trona Injection

at AEP Gavin Unit 2

Injection Rate

Moles Trona : Moles SO3

SCR Out of Service 0 2.0 3.0 3.5

SO3 Reduction, % 20 67 80 84

Injection Rate

Moles Trona : Moles SO3

SCR In Service 0.5 1.0 1.5 2.0

SO3 Reduction, % 66 74 76 78
4 Babcock & Wilcox Power Generation Group

Low sulfur coals

Hawthorn Kansas City Power & Light’s Hawthorn Unit 

5 is a nominal 550 MW PC fired boiler burning PRB coals. 

The equipment train at Hawthorn includes the opposed wall 

fired boiler, the two reactor SCR system, the air heaters, the 

two module dry FGD system, the ten compartment pulse jet 

fabric filter and the ID fans. Total particulate emission test 

results for two different fabric filter bag materials are provided in Table 2. This data indicates that the total particulate 

emission is consistently at a very low emission value and 

that the condensable portion typically makes up less than 

half of the total with some dependability on type of fabric 

filter bag. The available data indicates the inorganic portion 

of the condensable catch ranges from 25% to 85%. 

600 MW Unit The flue gas train for this operating 

project includes the boiler, SCR, air heater, fabric filter 

and Wet FGD. This unit burns PRB coals. Particulate test 

data results for this unit are provided in Table 3. While not 

achieving as low total particulate emissions, this data also 

demonstrates the small condensable portion but consisting 

of a high portion of inorganic material. 

550 MW Unit This operating PRB coal fired project has 

a flue gas train that includes the boiler, air heater, fabric filter 

and Wet FGD. Particulate test data results for this unit are 

provided in Table 4. This data indicates a low total particulate emission level with the condensables about equal to the 

filterable emissions and with the condensables consisting of 

about 50% inorganic material. 

Medium and high sulfur coals

500 MW Unit The flue gas train for this operating unit 

includes the boiler, SCR, air heater, dry ESP and Wet FGD. 

The boiler burns a 3.3% sulfur coal. This data, Table 5, 

represents a low total particulate emissions with over half 

consisting of the condensable portion. Further lab testing 

indicated the condensable particulate consisted mostly of 

sulfates in the inorganic portion. 

Petroleum coke/heavy oil

Deepwater AES Deepwater is a petroleum coke 

fired cogeneration plant located in Pasadena, Texas on the 

Houston Ship Channel in a non-attainment area. This plant 

is designed to burn petroleum coke with a sulfur value up 

to 6% content. To limit the emissions of flyash, SO2 and 

sulfuric acid mist, the plant chose a three-stage flue gas 

cleaning system consisting of 1) dry electrostatic precipitator 

for particulate capture, 2) limestone sorbent-based wet flue 

gas desulfurization (FGD) system, and 3) wet electrostatic 

precipitator for removal of sulfuric acid mist and residual 

particulate fines.

The Deepwater unit has been in commercial operation 

since 1986 and added an SCR system in 2007. Upgrades 

to the Wet ESP modules were initiated in 1999 and 2005 

and modifications to the collection surface and discharge 

electrodes have been completed in six of the twelve parallel flow modules. These modifications have resulted in 

improved performance compared to the original Wet ESP 

system performance (without SCR) which had successfully 

met the design stack particulate emissions of 0.005 grains/

Table 2

Hawthorn Particulate Emissions on PRB Coal

Unit 

Load Particulate Emissions – gr/acf

Stack 

Opacity

Test MW Total Filterable Condensable %

Needle Felt Bags

Nov. 2001 585 0.00638 0.00443 0.00195 NA

Aug. 2002 NA 0.00426 0.00345 0.00082 NA

Apr. 2003 515 0.00438 0.00299 0.00138 1.25

May 2004 545 0.00555 0.00346 0.00210 1.16

Membrane Bags

May 2005 515 0.00545 0.00080 0.00465 2.10

Apr. 2006 530 0.00433 0.00093 0.00341 1.54

Test 

Method

Method 

5B

Method 

202

Table 3

Low Sulfur PRB Coal Application A

Particulate Emissions

Particulate Emissions – lb/million Btu

Test ID Total Filterable Condensable Inorganic/

Organic %

1 0.0406 0.0351 0.0055 91.8/8.2

2 0.0480 0.0387 0.0099 93.0/7.0

3 0.0124 0.00389 0.0085 94.1/5.9

Avg.

Results 0.0337 0.0259 0.0080 93.0/7.0

Test 

Method

Method 

5B

Method 

202

Table 4

Low Sulfur PRB Coal Application B

Particulate Emissions

Particulate Emissions – lb/million Btu

Test ID Total Filterable Condensable Inorganic/

Organic %

1 0.0019 0.00076 0.0012 42.4/57.6

2 0.0019 0.00113 0.0008 57.7/42.3

3 0.0010 0.00069 NA 0/100

Avg.

Results 0.0016 0.00086 0.0010 50.0/50.0

Test 

Method

Method 

5B

Method 

202
Babcock & Wilcox Power Generation Group 5

scfd for the combined filterable flyash and sulfuric acid mist 

concentrations. 

Recent emissions data is presented in Table 6. The condensable particulate is made up of virtually all sulfate as 

indicated in the inorganic portion. 

Colson Cove In 2004 New Brunswick Power placed 

high efficiency Wet ESPs into service following two new 

limestone-based Wet FGD scrubbers at their 1050 MW 

Coleson Cove station. This was part of a plant wide effort 

to reduce the cost of electricity generation by switching to 

lower cost fuels and to upgrade emission controls to reduce 

SOx and particulate. New Brunswick Power’s decision to 

install Wet ESPs was to assure control of sulfuric acid emissions below 5 ppmvd @ 3% O2 and limit flyash particulates 

below 0.015 lb/million Btu. To achieve this level of control 

of sulfuric acid at all times, design collection efficiency 

exceeded 90%. 

The Wet ESP consists of a three field upflow design 

constructed in an upward extension of each of the two Wet 

FGD modules. Thus the Wet ESPs were installed within 

the circular absorber module. Scrubbed gas enters the close 

coupled inlet field of the Wet ESP after exiting the Wet FGD 

mist eliminator. The gas exits the top of the third field of 

the Wet ESP through a final mist eliminator section which 

captures any re-entrained droplets that may be present during flushing cycles. This design simplifies the arrangement. 

Materials of construction for the inlet field of the Wet ESP 

collecting plates are C-276. Stainless steel made of 6% Mo 

was utilized for the high voltage system and the balance of 

the collection plates. 

This application again demonstrates the successful installation and operation of Wet ESP technology in the utility 

atmosphere to control the total particulate emissions from 

a high sulfur fuel.

Impact on plant equipment

Aside from stack opacity/particulate issues, SO3 can have 

a major impact on the operation of the plant equipment. 

These impacts include such items as an increase in the acid 

dew point temperature which can limit heat recovery from 

the air heater and cause backend corrosion. The SO3 can 

react with ammonia present from the SCR or SNCR system 

resulting in potential fouling of the air heater and catalyst. 

SO3 also impacts the activated carbon injection system’s 

ability to reduce mercury when the SO3 competes with 

mercury for the active adsorption sites on carbon particles. 

Thus, removal of SO3 can produce significant benefits for 

utility boilers. 

The acid dew point temperature is a function of the SO3

concentration and moisture content of the flue gas. The acid 

dew point temperature is the temperature at which acid 

will condense at or below this temperature. When the SCR 

is placed in service, the acid dew point temperature can 

substantially increase due to the increase in SO3 concentrations leaving the SCR. If the air heater outlet temperature is 

not selected appropriately for new units or is not analyzed 

properly for SCR retrofits, there is an increased risk of acid 

corrosion on the downstream equipment. However, when 

the air heater outlet temperature is increased, the heat rate 

of the boiler is negatively affected. 

Air heater fouling is an issue when acid condensation 

occurs. The ash combines with the sulfuric acid under 

certain conditions and forms a moist and sticky deposit. 

SCRs increase the SO3 concentration. However, even if the 

temperature leaving the air heater is increased to maintain 

a similar margin as existed prior to SCR installation, some 

units will experience increased air heater fouling due to a 

change in the cohesiveness of the material.

SO3 and NH3 react under certain conditions and locations 

to form ammonia salt deposits. If SO3 is present in larger 

molar concentration than that of the molar concentration 

of NH3, Ammonium Bisulfate (ABS) will form. ABS is a 

sticky substance which can foul the air heater which results 

in increased pressure drop through the air heater, and over 

time the air heater will require an outage for cleaning. Air 

heater surface profile design, basket depth, number of basket 

sections and cleaning devices can be utilized to minimize 

ABS effects.

SO3 has an impact on mercury absorption through the ash 

or via activated carbon. SO3 competes with mercury for the 

active adsorption sites on the flyash/carbon. This reduces the 

Table 5

High Sulfur Coal Application C

Particulate Emissions

Particulate Emissions – lb/million Btu

Test ID Total Filterable Condensable Inorganic/

Organic %

1 0.0084 0.00191 0.0065 89.5/10.5

2 0.0073 0.00242 0.0048 77.4/22.6

3 0.0123 0.00243 0.0099 92.1/7.9

Avg.

Results 0.0093 0.00225 0.0070 86.3/13.7

Test 

Method

Method 

5B

Method 

202

Table 6

AES Deepwater Petcoke

Particulate Emissions

Particulate Emissions – gr/dscf

Test ID Total Filterable Condensable Inorganic/

Organic %

1 0.0078 0.0016 0.0062 81/19

2 0.0057 0.0005 0.0052 100/0

(as reported)

3 0.0047 0.0004 0.0043 100/0

(as reported)

Avg.

Results 0.0061 0.0008 0.0052

Test 

Method

Method 

5B

Method 

202
6 Babcock & Wilcox Power Generation Group

capability of the ash to capture mercury. The same effect is 

true when using activated carbon to capture mercury. Thus, 

the presence of SO3 can have a significant impact on the 

amount of carbon required to remove mercury and the selection of the appropriate mercury mitigation technology.

Economic considerations

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 summary, the approach to SO3 mitigation 

based on plant-specific conditions may reduce the overall 

cost of mitigation equipment.

Conclusions

SO3 emissions play an important role in total particulate 

emissions and contribute to stack opacity and blue plume 

issues. SO3 formation is based on the combustion of sulfur 

laden fuels and is enhanced by ash constituents on tube surfaces and by the addition of SCR catalyst. Multiple pieces 

of typical power plant equipment downstream of the boiler 

contribute to the capture or reduction of SO3. There is operating experience with stack test results demonstrating that low 

SO3/H2SO4 emissions are possible. However, the ultimate 

allowable SO3/H2SO4 emission is based on the allowed total 

particulate emission and the portion that is allowed from 

SO3/H2SO4. Based on the findings of this paper, this portion 

is dependent on the fuel sulfur content and ash constituents as 

well as the selection of back end equipment and any sorbent 

injection needs. For the determination of the selected SO3/

H2SO4 technology to achieve the final allowable emission, 

some economic evaluation of the optimum technology (for 

instance sorbent injection vs. Wet ESP) will be required for 

the higher sulfur fuels. 

1. Moretti A. and Triscori R. The Babcock & Wilcox 

Company, Ritzenthaler D. American Electric Power, “A 

System Approach to SO3 Mitigation,” presented to EPRIDOE-EPA-AWMA Combined Power Plant Air Pollutant 

Control Mega Symposium, August 28 – 31, 2006 Baltimore, 

Maryland.

2. Maziuk J., “Successful Mitigation of SO3 by Employing Dry Sorbent Injection of Trona Upstream of the 

ESP,” presented to Air Quality 5 Conference, Baltimore, 

Maryland 2005. 

3. Steam/its generation and use, 41st Edition, The Babcock & Wilcox Company, Editors: John B. Kitto and Steven 

C. Stultz, Copyright 2005.

4. Triscori R. and Kumur S. The Babcock & Wilcox 

Company, Lau A. and Niznik K. AES Deepwater Inc. 

“Performance Evaluation of Wet electrostatic Precipitator 

at AES Deepwater,” presented to Air & Waste Management 

Association 100th Annual Conference June 26 – 29, 2007 

Pittsburgh, Pennsylvania. 

References

5. Snyder R. and Redinger K. The Babcock & Wilcox 

Company, McMenus M. Kansas City Power & Light, 

“Impact of Fabric Filter Media and SDA Operations on 

Multi-Pollutant Emissions,” presented to EPRI-DOE-EPAAWMA Combined Power Plant Air Pollutant Control Mega 

Symposium, August 28 – 31, 2006 Baltimore, Maryland.

6. Private internal test reports for measurement of filterable and condensable particulate, The Babcock & Wilcox 

Company.

7. Staehle R., Triscori R. and Kumar S. The Babcock & 

Wilcox Company, Ross G. New Brunswick Power, Pasternak 

E. AES Deepwater Inc. “The Past, Present and Future of Wet 

Electrostatic Precipitators in Power Plant Applications,” 

presented to Combined Power Plant Air Pollutant Control 

Mega Symposium, May 19 – 22, 2003, Washington, DC.
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