8 The Babcock & Wilcox Company 

# A System Approach to SO 3

# 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 SO 3

# Mitigation

Introduction
Over the past decade, efforts to remove nitrogen oxides (NO

x ) through the use of selective catalytic reduction (SCR) technology have resulted in increased sulfur trioxide (SO 3 ) 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 SO 2to
SO 3 conversion in the boiler. When flue gases containing as low as 10 ppmdv of SO 3 are treated in a wet flue gas desulfurization system (WFGD) the potential exists for a visible secondary plumeto 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.



## SO 3

## formation and sinks
When fuel is combusted in a utility boiler, the sulfur in the fuel combines with oxygen to form gaseous sulfur dioxide (SO 2 ). Some

of this is further oxidized to SO 3 . The SO 3 hydrates to form H 2 SO 4 vapor in the flue work. Finally, the H 2 SO 4 vapor condenses to form an aerosol. Along the flue gas path, SO 3 / H 2 SO 4is 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. SO 3 / H2 SO 4concentrations 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 PM 2.5 on new boiler permits and may eventually become regulated on the existing utility fossil fired fleet. To develop a cost effective solution for SO 3 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 SO 3 /H 2 SO 4 formation andcapture 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) H 2 SO 4capture in particulate removal devices, and 7) H 2 SO 4capture across the WFGD. This paper will examine capture of SO 3 / H 2 SO 4 in each of these areas and will suggest ways to minimize installed and operating costs when designing a SO 3 Mitigation System. An example will be presented.



## SO 3

## mitigation design criteria
boiler island SO 3

## formation

When establishing the design criteria for SO 3 mitigation systems, it is important to understand the factors that affect SO 3 formation in the boiler and also to have an understanding of where

H 2 SO 4is removed in the backend equipment of the boiler island.

SO 3 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 SO 2 . At typical combustion temperatures, very little SO 2 is

converted to SO 3 , approximately 0.1%, because thermodynamic equilibrium at these temperatures favors SO 2 formation. As the temperature drops 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 down to approximately 1500F. So

SO 3 is formed in a lower temperature window as long as there is atomic oxygen available. SO 3 formation is increased by catalytic effect of metal oxides on the boiler tubes or surfaces. The percent
of SO 2that is oxidized to SO 3 in the furnace and convection pass of

the boiler is defined as the boiler SO 2 to SO 3 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 sulfurlevels and the ash composition. Metal oxides in the ash can increase the conversion of SO 2 . 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 SO 3 in the boiler and economizer and lower the measured conversion. That is, approximately the same amount of SO 3 is

formed but it reacts with the alkali in the boiler. As the SO 3 concentration is measured at the economizer exit, the amount of SO 3 measured will be less than that formed. The conversion determined from the measurement is the apparent conversion which is less

than the actual.
The SO 3 in the flue gas begins to hydrolyze to form H 2 SO 4 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 H 2 SO 4 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 SO 2in the flue gas is oxidized to SO 3 . Firing fuels with high vanadium content, such as fuel oil or Orimulsion Æ , 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 SO 3 and alkali in the boiler. As a result, the SO 3 concentration in the flue gas is relatively lower with higher alkali flyash and the calculated conversion is lower. Boiler operation has an effect on SO 3 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.



## SO 3

## formation in the SCR
Selective catalytic reduction (SCR) technology contributes additional SO 3 to the flue gas and ultimately higher SO 3 emissions.

The rate of SO 2 to SO 3 oxidation is defined as the SCR conversion rate. The SCR catalyst consists primarily of vanadium pentoxide (V2 O 5 ), tungsten trioxide (WO 3 ) and titanium dioxide (TiO 2 ). Vanadium pentoxide is the active compound in the catalyst and is the ingredient responsible for the conversion of SO 2 to SO 3 . Catalystcomposition is carefully selected based on the operating conditions, the SO 2concentration, 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. Theconversion 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 SO 3 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 theboiler. 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 SO 3 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 SO 3 begins to hydrate to form H2 SO 4 . 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 risesas it traverses the hot duct generating a temperature gradient downstream of the air heaters. Some of the H2 SO 4captured in the air heater on the ìcoldî side of the duct re-volatizes on the ìhotî gasside of the duct, producing an acid concentration gradient that corresponds well to the temperature gradient. H 2 SO 4that 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 SO 3 condensed is dependent on the air heater leakage. Therefore, the amount of SO 3 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 SO 3 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 H 2 SO 4 aerosols, which can corrode flues, air heaters, and other equipment. H 2 SO 4condenses in low temperature areas such as near leaking precipitator doors, casing leaks, and cool duct surfaces caused by insulation

flaws. Once this H 2 SO 4is 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

SO 3 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 SO 3 . 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 H 2 SO 4aerosol 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 H 2 SO 4emissions at the ESP outlet resulting from the flyash having more affinity to adsorb H 2 SO 4 . 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 SO 3 removals, lower flue gas temperatures have been known to increase removal. The removal

of condensed SO 3 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 SO 3 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 SO 3 . 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% areachieved 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 H 2 SO 4vapor is quickly cooled below its dew point and now exists entirely as an

aerosol. The size of the H 2 SO 4aerosol 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 H 2 SO 4in 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 SO 3 for conditioning. The capture of SO 3 by ash and/or sorbent in the precipitator may also reduce the H 2 SO 4 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 H 2 SO 4in 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 H 2 SO 4removal in the wet scrubber are not fully understood. Although the resultant secondary (SO 3 / H 2 SO 4) plume can be quite visible, the actual concentration is very low, measured in parts per million. In cases where the WFGD technology is utilizedin 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 SO 3emissions 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 SO 3 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 longerresidence 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

SO 3 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 SO 3 emissions, but extreme care must be exercised in selecting the proper additive for a specific site. Due consideration should be given to: temperaturedistribution 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 ductworkand 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 SO 3 generated from both the boiler and SCR. Sorbents injected in the furnace can remove SO 3 before the SCR but there could still be a visible sulfuric acid plume
because of the SO 3 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 SO 3 formed in the boiler. The addition of sufficient excess alkali with furnace injection may continue to remove the SCR-generated SO 3 if the alkali is still present andreactive 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 SO 3 formed in both the boiler and the SCR and therefore reduces the existing SO 3 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 SO 3 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 SO 3 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 coldend temperature. Injection prior to the ESP will minimize the potential for a visible SO 3 plume, minimize ESP corrosion from higheracid 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 SO 3 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 SO 3 mitigation applications.4 The Babcock & Wilcox Company 

## Ammonia
Ammonia has generally been used as the reagent for NO

xcontrol in SCR systems and also for flue gas conditioning to enhance ESP performance. Ammonia can also be an effective means for SO 3 removal when lower concentrations of SO 3 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 SO 3 mitigation.

The use of ammonia for SO 3 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 H 2 SO 4issues. 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 SO 3 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 SO 3 .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

SO 3 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 SO 3 . 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 SO 3 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 matchthe 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 SO 3 . 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 maintenanceissues that have been reported related to nozzles, and duct deposition/ air heater fouling. Loss of atomization, even for a short amountof 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 SO 3 . 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. Drytrona is also relatively benign, minimizing safety concerns at individual sites. A side benefit of trona injection has reportedly beenimproved 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 / SO 3 reactants become molten (liquid). Material handling concerns for this dry sorbent are related to itscohesiveness, affinity for moisture, and its temperature sensitivities. Therefore, silo design, control of temperature and moisture Table 1 Typical Sorbents

LowñNH 3 already

in use w/SCR
Moderateñslurry

Low

Moderate

Low

Low Good for lower SO 3concentration

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 MaintenanceThe 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 SO 3 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 H 2 SO 4 emission to pre-retrofit levels.In the example, an analysis is performed to illustrate the estimated amount of SO 3 that formed in the boiler. Two different airheater temperatures (300F and 330F) will be evaluated and resulting impact on SO 3 /H 2 SO 4removal 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

SO 2 to SO 3 conversion catalyst and a normal conversion catalyst) is performed coupled with a WFGD and the resulting H 2 SO 4 concentration at the stack with no SO 3 mitigation technology will be presented. In the final part of this example, the use of a sorbent ispresented 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 SO 3 /H 2 SO 4concentrations 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 designinformation, 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 SO 2 is converted to SO 3 . Working through all the calculations, there will be approximately 379 lb/hr of SO 3 leaving the economizer. As the SO 3 passes through the air heater, two

events occur. The SO 3 is hydrolyzed to H 2 SO 4and a removal of the

SO 3 /H 2 SO 4combination occurs. As discussed in this paper, lowerair heater outlet temperatures correlate to higher removal efficiencies. At 300F, 25% of the SO 3 is removed and at 330F only approximately 20% is removed. For the 300F case the H 2 SO 4 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 outlettemperature cases, the removal through the dry ESP is approximately 25% and 20% respectively. Thus, for the 300F air heater outlet temperature case, the H 2 SO 4flow rate is 261 lb/hr or 14.7 ppmvd at the stack. For the 330F case, the H 2 SO 4is 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 SO 3 concentration changes as a result of the SCR catalyst oxidizing the SO 2 in the flue gas to SO 3 . 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 SO 2 to SO 3 , the SO 3 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 SO 3 flow rate entering the air heater increases to 754 lb/hr compared to the base case of 379 lb/hr. Using the same H 2 SO 4removal efficiency for the air heater and ESP as used in the base case, for the 300F case, the

H 2 SO 4flow 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 H 2 SO 4flow 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 H 2 SO 4enters the stack and when the catalyst is designed for 1% conversion, the H 2 SO 4 concentration entering the stack is 312 lb/hr or 17.8 ppmvd. For the

Entering Air Heater 379 lb/hr SO 3

Entering Air Heater 379 lb/hr SO 3 Entering ESP 348 lb/hr H 2 SO 4

Entering ESP 372 lb/hr H 2 SO 4 Entering Stack 261 lb/hr H 2 SO 4

14.7 ppmvd

Entering Stack 297 lb/hr H 2 SO 4

16.7 ppmvd 330F Air Heater Outlet Case 300F Air Heater Outlet Case Table 4
Base Condition CO 2 H 2 O SO 2 N 2 O 2 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
H 2 C
H 2 O
N 2 O 2 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 Used6 The Babcock & Wilcox Company Based on the above conditions, the use of a sorbent will now beevaluated. For this example, trona will be selected for the mitigation of H 2 SO 4 . Trona was selected due to the desire to condition theprecipitator 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 H 2 SO 4concentration, 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 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 H2 SO 4emissions 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 2to
SO 3 conversion catalyst could reduce both the cost of mitigation equipment as well as sorbent costs.

Several sorbents are effective in removing H2 SO 4from the fluegas 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 beconsidered 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 SO 3 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 SO 3 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 H2 SO4enters the stack and when the catalyst is designed for 1% conversion, the H 2 SO 4concentration 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 H 2 SO 4 Leaving SCR 566 lb/hr SO 3 Leaving DESP 390 lb/hr H 2 SO 4 Entering Stack 234 lb/hr H 2 SO 4

13.4 ppmvd

Leaving Air Heater 692 lb/hr H 2 SO 4 Leaving DESP 519 lb/hr H 2 SO 4 Entering Stack 312 lb/hr H 2 SO 4

17.8 ppmvd Leaving SCR 754 lb/hr SO 3

Leaving SCR 566 lb/hr SO 3 Leaving Air Heater 555 lb/hr H 2 SO 4 Leaving DESP 444 lb/hr H 2 SO 4 Entering Stack 266 lb/hr H 2 SO 4

15.1 ppmvd

Leaving SCR 754 lb/hr SO 3 Leaving Air Heater 738 lb/hr H 2 SO 4 Leaving DESP 591 lb/hr H 2 SO 4 Entering Stack 354 lb/hr H 2 SO 4

20.1 ppmvdThe Babcock & Wilcox Company 7 Copyright © 2006 by The Babcock & Wilcox Company All rights reserved.

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