# An Emissions Approach to SO 3 

# 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-1815Babcock & Wilcox Power Generation Group 1 

# An Emissions Approach to SO 3 

# 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 SO 3 , which form particulate and make up a portion of total particulate, must be controlled to even lower values. Thus, the selected acid gas control technolo

gies must be based on meeting the required emissions. This paper provides the results of investigations that have been performed and demonstrates achievable SO 3 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 SO 3 mitigation. Consideration of multiple SO 3 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.



### SO 3 

### emissions and total particulate When fuel is combusted in a utility boiler, the sulfur in the fuel combines with oxygen to form gaseous sulfur diox

ide (SO 2 ). Some of the SO 2 is further oxidized to SO 3 . The SO 3 hydrates to form H 2 SO 4vapor in the flue gas stream. Finally, the H 2 SO 4vapor 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 SO 3 formation as well as the equipment and technologies for SO 3 mitigation. SO 3 forms in two areas of a fossil fuel fired power plant, the boiler and across the catalyst on those units utilizing SCR for NO xreduction. Combustion of fuel liberates elemental sulfur, which oxides to form SO 2 . At typical combustion temperatures very little SO 2 is converted to SO 3 , approximately 0.1%, because the thermodynamic equilibrium at boiler combustion tempera

tures favor SO 2 formation. As heat is absorbed by the boiler surfaces and the flue gas temperature lowers, the equilibrium changes so that more SO 3 can be formed. The formation of SO 3 is dependent on the existence of atomic oxygen which is present at temperatures of 1500F (815C) and greater. SO 3 is therefore formed directly from SO 2 as long as there is suf

ficient atomic oxygen available. SO 3 formation is increased by catalytic effect of metal oxides on the boiler tube surfaces. The percent of SO 2 that is oxidized to SO 3 in the boiler fur

nace and convection pass is defined as the boiler SO 2 to SO 3 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 SO 2 conversion and alkaline ash constituents can react with SO 3 to lower the measured conversion rate.



### SCR effects on SO 3 

### formation When SCRs are installed in the typical high dust gas stream at the boiler exit, this NO xreduction technology2 Babcock & Wilcox Power Generation Group contributes additional SO 3 to the flue gas resulting in greater SO 3 that will contribute to total emissions and requires further SO 3 reduction. The SCR catalyst consists primarily of titanium dioxide (TiO 2 ), vanadium pentoxide (V 2 O 5 ) and tungsten trioxide (WO 3 ) or molybdenum oxide (MoO 3 ). Vanadium is one of the active catalyst constituents and is the primary constituent responsible for the conversion of SO 2 to SO 3 as the flue gas passes across the catalyst surface. The rate of SO 2 conversion will vary depending on the vanadium concentration; however, there is an offset on catalyst NO x reduction capability that also must be considered when selecting the catalyst chemistry. Thus a reduction in the catalyst SO 2 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 temper

ature 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 some

what offset by the lower flue gas temperature. Typical SO 2 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 SO 2 oxidation when the ammonia is not present. In summary, the SCR SO 2 conversion rate can vary considerably depending on catalyst chemistry and operating conditions. The total SO 3 concentration in the flue gas is dependent on these factors as well as the fuel sulfur con

tent. Fuel sulfur content becomes the dominant factor when evaluating the SO 3 effects on particulate emissions and the necessary mitigation requirements.



### Plant arrangements and mitigation technologies Other than the boiler and SCR which generate SO 3 , the typical power plant equipment in the downstream flue gas stream can affect the SO 3 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 com

mon 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 SO 3 present in the entering flue gas. This reduction in SO 3 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 SO 3 on the surface of the ash particles for optimum operation and particulate removal. SO 3 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 SO 3 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 SO 3 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 H 2 SO 4 . The Wet ESP operating principles are similar to the dry ESP with a couple of major differences. First, the Wet ESP oper

ates 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 SO 3 is present as H 2 SO 4 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 H 2 SO 4aerosol material. This location is also favorable to maximize the SO 3 reduction with sorbent injection ahead of the fabric filter. Under favorable conditions, SO 3 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 SO 3 con

centration 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 SO 3 than other technologies. The spray dryer reagent slurry reacts with the SO 3 /H 2 SO 4 in the flue gas to form particulate sulfate com

pounds and the temperature is reduced to well below acid dew point driving all remaining SO 3 to the H 2 SO 4aerosol. The highly efficient filter cake drives the fabric filter effluent H 2 SO 4concentration 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 SO 2 . 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 H 2 SO 4aerosol 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 H 2 SO 4 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 SO x . 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 SO 2 and SO 3 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 SO xreduction. In the case of high alkaline coal ash, the particulate collected by the fabric fil

ter 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 H 2 SO 4 , resulting in stack H 2 SO 4emissions 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 SO 3 /H 2 SO 4 . Most injection sorbents are injected dry, although not exclusively. With this technology the dry sorbent, frequently alkaline in nature, reacts with the SO 3 /H 2 SO 4vapor for collection as a particu

late. Popular sorbents for SO 3 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 suit

able 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 SO 3 in the flue gas is increased due to the catalyst oxidation of SO 2 . This technol

ogy can also be used on a new unit to achieve the low total particulate requirements at the stack which includes con

tribution from H 2 SO 4 . 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 SO 3 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 SO 3 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 ef

fects of SO 3 /H 2 SO 4 . The following provides stack emission results for total particulate and includes the filterable and condensable portions on a range of applications.

Table 1 SO 3 Reduction Across ESP with Trona Injection at AEP Gavin Unit 2 Injection Rate Moles Trona : Moles SO 3 SCR Out of Service 0 2.0 3.0 3.5
SO 3 Reduction, % 20 67 80 84

Injection Rate Moles Trona : Moles SO 3 SCR In Service 0.5 1.0 1.5 2.0
SO 3 Reduction, % 66 74 76 784 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 pro

vided 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 particu

late 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, SO 2 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 par

allel 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 202Babcock & 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 con

densable 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 SO xand particulate. New Brunswick Power’s decision to install Wet ESPs was to assure control of sulfuric acid emis

sions below 5 ppmvd @ 3% O 2 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 dur

ing 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 instal

lation 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, SO 3 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 SO 3 can react with ammonia present from the SCR or SNCR system resulting in potential fouling of the air heater and catalyst. SO 3 also impacts the activated carbon injection system’s ability to reduce mercury when the SO 3 competes with mercury for the active adsorption sites on carbon particles. Thus, removal of SO 3 can produce significant benefits for utility boilers. The acid dew point temperature is a function of the SO 3 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 SO 3 concentra

tions 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 SO 3 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. SO 3 and NH 3 react under certain conditions and locations to form ammonia salt deposits. If SO 3 is present in larger molar concentration than that of the molar concentration of NH 3 , 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. SO 3 has an impact on mercury absorption through the ash or via activated carbon. SO 3 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 2026 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 SO 3 can have a significant impact on the amount of carbon required to remove mercury and the selec

tion of the appropriate mercury mitigation technology.



### Economic considerations When a plant is considering the use of SO 3 mitigation technologies, several areas of the boiler island and air quality control system need to be investigated to optimize the SO 3 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 SO 2 to SO 3 and economizer outlet temperature. Both of these issues could substantially affect stack H 2 SO 4 emissions by increasing values. Air heater operation (temperature and operating conditions) has a large effect on the amount of SO 3 exiting the air heater and even the Dry ESP. Operating conditions and equipment sizing are important considerations in SO 3 mitigation. Wet FGDs do collect some H 2 SO 4but not to the levels that provide optimal stack condition on higher sulfur coals. Selection of a low SO 2 to SO 3 conversion catalyst could reduce both the cost of mitigation equipment as well as sorbent costs. Several sorbents are effective in removing H 2 SO 4from 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 SO 3 mitigation based on plant-specific conditions may reduce the overall cost of mitigation equipment.



### Conclusions

SO 3 emissions play an important role in total particulate emissions and contribute to stack opacity and blue plume issues. SO 3 formation is based on the combustion of sulfur laden fuels and is enhanced by ash constituents on tube sur

faces 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 SO 3 . There is operat

ing experience with stack test results demonstrating that low SO 3 /H 2 SO 4emissions are possible. However, the ultimate allowable SO 3 /H 2 SO 4emission is based on the allowed total particulate emission and the portion that is allowed from SO 3 /H 2 SO 4 . 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 SO 3 / H 2 SO 4technology 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 SO 3 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 SO 3 by Em

ploying Dry Sorbent Injection of Trona Upstream of the ESP,” presented to Air Quality 5 Conference, Baltimore, Maryland 2005. 3. Steam/its generation and use, 41 st Edition, The Bab

cock & 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 100 thAnnual 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 onMulti-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 filter

able 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.Copyright© 2008 by Babcock & Wilcox Power Generation Group, Inc. a Babcock & Wilcox company All rights reserved.

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