## Wet ESP vs. Sorbent Injection for SO3 Control

Paper # 107
Carl V. Weilert
Bums & McDonnell Engineering Company, 9400 Ward Parkway, Kansas City, MO 64114
ABSTRACT Sulfuric acid (H2S04) is formed from sulfurtrioxide (SO3) created in the boiler and in selective catalytic reduction (SCR) systems by oxidation ofsulfur dioxide (SO2) that results when sulfurbearing fuels are combusted. Once emitted from the stack, H2SO4 vapor condenses to an aerosol that can lead to significant increases in plume opacity and create public concern. For units equipped with wet flue gas desulfurization (FGD) systems, the H2SO4 aerosol is formed when the gas is quenched atthe inlet ofthe SO2 absorber. Wet scrubbers typically remove less than 50% ofthis H2S04 aerosol. For high sulfurfuels, this can still leave significant amounts ofH2SO4 mist exiting the stack. Consequently, owners ofexisting units firing highsulfur coal that are being retrofitwith SCR systems for NO~ reduction and/orwith wet FGD systems for SO2 control will need to take into accountthe effects ofthe increased level ofH2SO4 emissions, and consider control alternatives.
There are two primary alternatives for control ofSO3 / H2SO4 from existing units equipped with awet scrubber. The H2SO4 aerosol can be captured downstream ofthe FGD system in awet electrostatic precipitator (WESP) orthe SO3 / H2S04vapor can be captured by injecting a sorbent upstream ofthe particulate collection device. This paper compares and contraststhese two alternatives for H2SO4 control and identifies the situations favoring one overthe other.
INTRODUCTION The problems associated with emissions ofsulfuric acid aerosol from electric utility power plants firing high sulfurfuels have received considerable attention in the past fewyears. Although the “blue plume” phenomenon caused bythe light scattering effects ofsulfuric acid aerosols that form when sulfuric acid vapor condenses in wet FGD systems has been known for manyyears, the magnitude ofthe problem has recently been heightened bythe sudden increases in sulfuric acid aerosol concentrations that have occurred when SCR systems were retrofitto high sulfur coal fired boilers firing which had previously been retrofitwith wet FGD systems. The examples receiving the most media attention have been AEP’s Gavin Station and Cinergy’s Gibson Station. However, the phenomenon is occurring to some extent at many high sulfur coal-fired plants in the U.S. with the SCR/wet FGD combination.
The degree ofconversion of SO2 to SO3 thattypically occurs in the furnace ofa coal-fired boiler ranges from about 0.5% to 1.5%. Butthe degree ofSO2 to SO3 oxidation occurring acrossthe catalyst ofan SCR system can be within the same range. This means thatthe retrofit ofan SCR system can result in an approximate doubling ofthe SO3 concentration entering the air heater. This explains why the magnitude ofthe visible effect on the stack plume opacity can be so dramatic.
1At typical air heater exit flue gas temperatures, virtually all ofthe SO3 vaporwill have combined

with watervaporto form H2S04 vapor. However, it is common fortheterm “SO3” to be used to describethe sulfuric acid species present in the flue gas at all points in the gas path, even in the stackdischarge. In this paper, “SO3”, “H2S04” and “sulfuric acid” will be used interchangeably exceptwhere clarification is necessary.
While it is not correctto describethe “blue plume” phenomenon associated with SCR retrofits or FGD retrofits as “unexpected”, it is certainlytrue thatthe effect is an “unintended” consequence ofthe retrofit ofthese airpollution control technologies. It is ironicthatthe expenditure of hundreds ofmillions ofdollars forsystems to significantly reduce emissions ofthe criteria pollutants (SO2 and NOR) has led to the unintended consequence ofplume opacity increases and the attendant public outcry caused by a pollutant (SO3) which is emitted at concentrations of50 ppm or less.
The effect on plume opacity and the public outcry it generates are not going to fade away. Utilities retrofitting SCRto units having FGD, orvice versa, will be well advised to carefully considerthe long-term alternatives for reduction ofSO3 emissions. This paper compares the two principal alternatives available for SO3 control: wet ESP and sorbent injection. Factors that would favor one overthe other are described.
The considerations for control ofSO3 emissions from existing units are significantly different than those forthe configuration ofair pollution control equipment for new units. Therefore, the paper is divided into two main sections. The first covers alternative for SO3 control for existing units, with focus on those which are (or soon will be) equipped with wet FGD systems. The second covers considerations for sulfuric acid mist emissions control for new units.


### ALTERNATiVES FOR SO3 CONTROL FOR EXISTING UNITS There are two main technology-based alternatives for control ofSO3 emissions from existing units. Other approaches thatwould reduce SO3 emissions include switching to lower sulfurcoal and/orwashed coal to reduce the sulfur content ofthe fuel as fired. These options will not be covered in this paper. The alternatives described herein are retrofit ofawet ESP for control of sulfuric acid aerosol and sorbent injection for control ofSO3 in conjunction with an ESP or fabric filter (baghouse) downstream.


### Wet ESP Retrofit The first alternative for consideration is the retrofit ofawet electrostatic precipitator (wet ESP) downstream ofthe existing FGD system. Ifthe unit currently does not have an FGD system but is anticipating the retrofit ofawet FGD, the retrofit ofawet ESP can be incorporated into the design ofthe wet FGD system. Applicability Wet ESP technology has been applied to the control ofsulfuric acid aerosols for many years in sulfuric acid production plants. In general, wet ESPs have been applied in various industrial air pollution control applications forthe collection offine particles ordusts that are not conducive to collection in dry ESPs orfabric filter baghouses.

2Experience

A few examples offull-scale wet ESP installations exist for electric utility boilers. However, none ofthese current installations are serving units firing high sulfurcoal. Installations ofwet ESPs in North America on utility boilers are limited to thosetabulated below:
Table 1. Full-scale WESP Installations on Utility Boilers in North America. Facifity Unit size Fuel Fired Number ofWESP WESP Flow

(MW) Modules Configuration Deepwater 155 Pet Coke 12 (external to FGD) Vertical plate 3-field Sherco 1 & 2 750 ea. PRB Coal 12 per unit (retrofit Vertical tube into each existing wet 2-field scrubber absorber) Dalhousie 1 & 2 315 total Orimulsion 1 (retrofit into existing Vertical tube FGD absorbertower) Single field Dakota 420 equiv. Waste liquids 1 (external to existing Horizontal Gasification from coal FGD absorbertower) plate gasification 3-field process Coleson Cove 3 x 350 No. 6 Oil 2 (integral to each of2 Vertical plate retrofit FGD absorber 3-field towers)
It should be noted that a pilot-scale slipstream WESP has been operated at First Energy’s Bruce Mansfield Unit 2. This pilot WESP treats flue gas from a high-sulfurcoal-fired unit. Also, a WESP section is included in the FGD absorberforthe 50 MW (equivalent) slipstream commercial demonstration unit for Powerspan’s Electro-Catalytic Oxidation (ECO) system at First Energy’s R. E. Burger Station. This WESP also treats flue gas from a relatively high sulfur coal. Capability Removal efficiency for sulfuric acid mist in wet ESPs is dependent on the collection area. However, removal efficiency of90% orgreater can be achieved with proper design. Ifthe wet ESP is intended solely for control ofSO3 emissions, the design ofthe wet ESP can be fine-tuned to provide the degree ofcontrol needed to eliminate the visible plume problem.
FeasibilityforRetrofit As shown in Table 1, wet ESPs can be configured in the horizontal flow orvertical flow arrangement, and may be integral to the FGD absorber orexternal to it. The vertical flow arrangement is capable ofretrofit into the top ofan existing FGD absorbertower, but, in practice this may be problematic. For example, the retrofit ofavertical flow WESP section to the existing FGD absorbertower at NB Power’s Dalhousie Station allowed space only fora single field. This is believed to have contributed to relatively poor performance ofthe WESP in terms ofSO3 reduction efficiency. Additional feasibility issues may result ifthe existing FGD system has numerous absorber modules, because each module would need to be retrofitwith its own 3WESP section. An alternative is to retrofit an external 

### WESP, such as was accomplished at

Dakota Gasification. However, many existing FGD systems may be configured such thatthe space required for retrofit ofan external WESP is not available.
Ifthe existing boiler unit is to receive afuture FGD retrofit for compliance with SO2 emission reduction requirements, it should be feasible to design avertical flow WESP section into the FGD absorbertower(s). This will minimize the plot space required forthe WESP and allowthe waterbalance forthe FGD system to incorporate consideration ofthe WESP wash water. Incorporation ofa WESP module(s) external to the retrofit FGD absorber(s) may also be technically feasible ifthe additional plot space required is available close to the absorber.
Benefits In addition to controlling SO3 emissions and stackplume opacity, awet ESP will reduce other forms offine particulate, and may provide significant control ofmercury emissions as well. For example, test results from the pilotWESP at Bruce Mansfield indicate that oxidized mercury (Hg~2) was removed at an efficiency ranging from 76% to 86% and that elemental mercury (Hg°) was removed at an efficiency ranging from 18% to 44%. Because all existing coal-fired utility boilers are expected to become subjectto mercury control regulations in the nearfuture, this beneficial aspect ofWESP performance may be an important consideration forthe long term. Costs Costs ofWESP retrofits are expected to be site specific. One vendor has indicated thatthe total installed cost ofavertical flow WESP integrated into the top ofa retrofitFGD absorbertower will range from 20 $/kWto 40 $/kW depending on the design SO3 collection efficiency. The cost ofthe external horizontal flow WESP at Dakota Gasification has been reported to be approximately $90/kW.
Concerns In addition to the retrofit feasibility issues noted above, there are additional concerns with the large-scale application ofWESP technology to boilers firing high-sulfur coal. These concerns have notyet been addressed in the full-scale installations to date. As noted previously, none of these installations involved the treatment offlue gas from firing high-sulfur coal. More significantly, perhaps, none ofthe fuels fired in the utility boilers forwhich WESPs are currently operating atfull scale have had significant chlorine content. The corrosion potential ofthe acidic environmentthat exists in the WESP system can be expected to be greatly enhanced when the high chloride concentrations typical ofFGD systems on units firing eastern bituminous coal are introduced via carryover ofliquorfrom the FGD absorber into the WESP.
This lackofexperience with regard to the corrosion effects ofthe WESP in high-chloride applications is worrisome, especially in light ofthe currenttrend toward fewer and larger FGD absorber modules. Based on the current level offield experience, it is unclearwhatthe appropriate material ofconstruction for WESPs on high-chloride coal will be. Ifthe WESP materials selection in a particular case proves inadequate, problems with FGD absorber availability could result. The needto move to increasingly corrosion-resistant materials of construction may cause the installed cost ofWESPs to escalate significantly beyond currentestimates. As with FGD developments in the 1970s, it can reasonably be expected thatthere will

be some initial failures as the industry moves along the learning curve.



### Sorbent Injection The second alternative for control ofSO3 emissions from existing units is sorbent injection. Sorbent injection for SO3 control will typically be applied by injection ofa sorbent into the flue gas at a point upstream ofthe particulate collection device. The sorbentwill react with the SO3 to form a solid which can be collected in the ESP orfabric filter baghouse. Applicability Sorbent injection technology has been applied to the control ofSO3 emissions from coal-fired and oil-fired utility boilers for manyyears. The technology is readily available.
Alternative Sorbents Sorbents that may be used for control ofSO3 emissions include, but are not limited to, the following:

• Ammonia

• Hydrated lime

• Magnesium compounds (oxide or hydroxide)

• Sodium compounds (carbonate orbicarbonate)

• Sodium bisulfite (SBS) solution Experience Virtually all ofthe U.S. utility coal-fired boiler experience with SO3 control has been acquired at units burning high sulfur coal and utilizing dry ESPs for particulate control. In general, there are few, ifany, large electric utility units operating in the U.S. that burn high-sulfur coal and utilize fabric filters (baghouses) forparticulate control without an SO~ removal system upstream. That is, except for units utilizing lime-based semi-dry FGD systems or limestone-based fluidized bed combustors in which the SO2 and SO3 concentrations are effectively reduced priorto the particulate collector, no large U.S. utility boilers firing high-sulfur coal are currently using baghouses. This situation is likely to change, as several high-sulfur coal-fired units are currently being retrofitwith fabric filter baghouses. Nevertheless, the experience summaries presented below are universally based on experience with ESPs.
EPRI reports that ammonia injection for SO3 control atfull-scale coal-fired utility powerplants has been demonstratedto result in SO3 removal efficiencies of95% or better. Hydrated lime has been tested at full scale at several facilities, including AEP’s Gavin Station. These full-scale tests confirmed what had been observed in several pilot-scale tests, such as those conducted by EPRI atthe High SulfurTest Center. That is, hydrated lime injection forpurposes ofSO3 control resulted in significant degradation ofESP performance. Magnesium compounds have been used extensively for SO3 control in oil-fired boilers. MgO has been used as a fuel additive for oil-fired units for manyyears. Butthe use ofmagnesium

5compounds for SO3 control in coal-fired boilers is primarily limited to some DOE-sponsored

demonstration programs. In one such program, magnesium oxide and magnesium hydroxide were injected into the furnace both as a dry powder and in slurry form. Long term tests ofthis sorbent injection option were conducted at First Energy’s Bruce Mansfield Unit 3 and atAEP’s Gavin Unit 1.
Sodium carbonate (in the form oftrona) was successfully used at AEP’s Gavin Station during 2003 to control plume opacitythat had become elevated due to increased oxidation of SO2 to SO3 across the SCR catalyst. The sodium-based sorbent did not exhibitthe ESP performance degradation effect thatwas found with hydrated lime. In fact, ESP performance actually improved due to the ash conditioning effect ofthe sodium compounds.
Sodium bisulfite (SBS) solution has been applied commercially forpurposes ofSO3 control. Using atechnology patented by Codan Development LLC, SBS solution has been injected into the flue gas ductworkat locations upstream and downstream ofthe air heater on coal-fired boilers. This technology has been specifically applied to reduce plume opacity due to high SO3 concentrations resulting from operation ofSCR systems on high-sulfur coal-fired units equipped with wet FGD systems. Capability Pilot scale and full-scale testing has confirmed that up to 90% orgreater SO3 control efficiency is possible with several different sorbents, including ammonia and SBS. Control efficiency performance with the other sorbents was reportedly somewhat lower. In most cases, control efficiencies of70% to 90% will be requiredto appreciably reduce, or completely eliminate, the plume opacity effect ofthe increased SO3 concentrations due to oxidation ofSO2 to SO3 across the SCR catalyst. FeasibilityforRetrofit Sorbent injection for SO3 control is generally feasible for retrofitto most coal-fired boilers. Especially fortechnologies based on injection ofliquids (such as SBS) or slurries, the duct configuration at and immediately downstream ofthe injection location should provide at least one second ofresidencetime. In these casesthe ductwork immediately downstream from the injection location should have a minimum ofinternal braces. It may be necessary in some cases to make modifications to the ductwork internals to ensure that this condition can be achieved. Considering that SCR systems usually are provided with a source ofammonia, avery straightforward application ofsorbent injection for SO3 control would be to inject ammonia downstream from the air heater. Because the ammonia could be injected as avapor, there would be no concerns regarding solids fallout or potential wetting ofthe ductwalls. There are other concerns with this approach, however, as described below.
Benefits In addition to serving the primary function ofplume opacity reduction, sorbent injection for SO3 control effectively reduces the acid dewpoint ofthe flue gas. This means that at all locations in the ductwork downstream ofthe sorbent injection pointthe potential for corrosion will be significantly reduced. This is in sharp contrastto the situation that exists with WESP

6applications downstream ofawet FGD system, in which the acid mist is removedjust before the

flue gas enters the stack, and there is no benefitwith regard to reduced corrosion at any point upstream ofthe 

### WESP.
Costs The capital cost ofsorbent injection systems such as those used forcontrol ofSO3 emissions has been reported to be approximately $5/kWto S101kW, depending on the specifictechnology used.
Concerns One ofthe principal concerns with regard to the use ofsorbent injection for 503 control is the adverse effectthat some sorbents have on the performance ofdry ESPs. The presence ofthe sorbent can modify the resistivity ofthe ash to an extentthat particulate removal efficiency performance ofthe ESP tends to suffer overtime. Hydrated lime is especially prone to this effect. Sodium compounds are generally not. Forthe sorbents such as SBS that are based on introduction ofa liquid into the ductwork, there is a concern that improper atomization will result in wetting ofthe duct surfaces, leading to corrosion and formation ofdeposits on these surfaces. Another concern with regard to sorbent injection is the effect ofthe collected sorbent on the salability ofthe fly ash. Ammoniatends to be adsorbed readily on the fly ash from high sulfur coals, and could substantially modifythe range ofpotential commercial uses forthe ash. The sodium-based sorbents produce compounds from reactions with SO3 that are soluble in waterand may pose a concern with regard to increased potential for leaching ofsoluble salts from the ash in landfills. 

### Comparative Analysis For existing units with plume opacity problems caused by excessive SO3 emissions, the choice between control alternatives is likelyto be based on a number offactors.
Conditions Favoring WESPRetrofit The following conditions are generally expected to favorthe selection ofthe WESP retrofit option:

• Requirements for SO3 control efficiencies of90% and above.

• Need to achieve significant reductions in mercury emissions.

• Plans to retrofit FGD systems in the nearfuture.

• Ability to employ vertical flowWESP integrated into the FGD absorbertower.

• Current and future fly ash sales potential.

• No severe problems with acid dewpoint corrosion in the flue gas ductwork.Conditions Favoring Sorbent Injection

The following conditions are generally expected to favorthe selection ofthe sorbent injection option:

• Requirements for SO3 control efficiencies of70% or less.

• Little or no need for additional mercury emission control.

• Existing FGD system that represents a difficult retrofit foraWESP.

• Existing FGD system with multiple absorber modules.

• Lack ofadequate space for retrofit ofa WESP external to the existing FGD.

• No current orfuture potential for sale offly ash.

• Significantproblems with acid dewpoint corrosion in ductwork.

SO3 CONTROL CONSIDERATIONS FOR NEW UNITS Owners proposing the construction ofnew units are required to apply for and receive Prevention ofSignificant Deterioration (PSD) permits priorto commencing construction. The PSD regulations require that best available control technology (BACT) be applied to those pollutants which will be emitted from the proposed unit in excess ofthe “significance levels” identified in the regulations. For sulfuric acid mist, any level ofpotential emissions that exceeds 7.0 tons per yearwill require a BACT analysis. Itwill be virtually impossible for large, new units firing high-sulfurcoal to have potential emissions ofsulfuric acid mist belowthis “de minimis” threshold value. That means that any new unitfiring high sulfurcoal will likely be subjectto BACT requirements. This will dictate consideration ofan emission rate for sulfuric acid mist that corresponds to application ofthe “top” level ofcontrol, in accordance with U.S. EPA guidelines forthe “Top Down” BACT.
The “top” level ofcontrol must be applied as BACT and reflected in the permit unless it can be eliminated from further consideration due to technical infeasibility, or ifthe case-specific economic, energy or environmental impacts warrant its rejection. In performing a BACT analysis for sulfuric acid mist, recent determinations ofBACT must be considered in the identification ofthe candidates forthe “top” level ofcontrol. Table 2 provides information on recent BACT determinations for H2504 mist as reflected in draft or final PSD construction permits for proposed new pulverized coal-fired electric utility units firing high-sulfurcoal.
Table 2. Recent H2S04 BACT determinations for proposed new units firing high-sulfur coal. Proposed Unit size Coal Proposed H2S04 Control BACT H2S04 Facifity (MW) to be Fired Technology Emission Rate lb/mmBtu Elm Road 2 x 615 Pittsburgh #8 FF /WFGD /WESP 0.01 Thoroughbred 2 x 750 West KY bit. ESP /WFGD /WESP 0.00497 Prairie State 2 x 750 Southern IL bit. ESP /WFGD /WESP 0.005 (draft) Longview Power 600 2.5%S WV bit. DSI / FF /WFGD 0.0075Review ofTable 2 indicatesthat WESP technology is reflected in the permits for several ofthe

proposed new high-sulfur coal-fired power plants in the U.S. as the control technique for reduction ofemissions ofH2SO4 mist. However, in two cases the control technology lineup also presumes that fabric filters will be used. In one case the control technique cited forsulfuric acid mist consists ofdry sorbent injection (DSI) upstream ofa fabric filter. In each case listed in Table 2, the NO~ control technologyto be applied includes SCR. Current H2S04 emission levels representing BACT are approximately 0.005 lb/mmBtu.

CONCLUSIONS Active control ofemissions ofSO3 (aka sulfuric acid mist) from existing coal-fired boilers equipped with SCR systems and wet FGD systems is likely to become more common in the near future due to the public.awareness created by the extreme “SO3 plume” episodes that have occurred in the industrywithin the pastfewyears. Two primary technology-based control alternatives exist: retrofit ofwet electrostatic precipitators (WESPs) or use ofsorbent injection upstream ofthe particulate control device. Each ofthese options has been proven to a limited extent in previous full-scale applications to electric utility boilers firing high sulfurcoal. In some cases there are unanswered questions regarding the technical feasibility and cost ofthese options.
The technology favored for reduction ofSO3 emissions from high-sulfur coal-fired units will depend on a number offactors including the degree ofemission control requiredto eliminate the objectionable visible plume effects, the configuration ofthe existing air pollution control equipment, the need for coincident removal ofmercury, the current and future plans forfly ash sales, and the extentto which acid dewpoint corrosion is a critical problem at a given plant. Depending on the individual situation at each plantwith regard to these factors, one control alternative is likelyto be favored overthe other. For existing plants, where the need for SO3 emission reduction are driven more by public relations considerations than by regulatory limitations, the overall cost ofthe controls may determine the solution to be applied, ifany. BACT considerations for new units firing high-sulfurcoal will require overall control efficiencies of90% or more. The use ofWESPs is proposed for several ofthe new units recently permitted, but sorbent injection upstream ofa fabric filter baghouse has also been identified as the control technique in at least one case. This drive toward very low stack emissions ofsulfuric acid mist will force these technologies to mature within the next fewyears. Itwould not be surprising ifsome setbacks occur along the path to full implementation ofthese technologies.

Key Words:
Wet ESP Sorbent injection SO3 Sulfuric acid mist 

### BACT