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 sulfur trioxide (SO3) created in the boiler and in selective

catalytic reduction (SCR) systems by oxidation of sulfur 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 at the inlet ofthe SO2 absorber. Wet scrubbers typically

remove less than 50% ofthis H2S04 aerosol. For high sulfur fuels, this can still leave significant

amounts of H2SO4 mist exiting the stack. Consequently, owners of existing units firing highsulfur coal that are being retrofit with SCR systems for NO~ reduction and/or with wet FGD

systems for SO2 control will need to take into account the effects ofthe increased level of H2SO4

emissions, and consider control alternatives.

There are two primary alternatives for control of SO3 / H2SO4 from existing units equipped with

a wet scrubber. The H2SO4 aerosol can be captured downstream ofthe FGD system in a wet

electrostatic precipitator (WESP) or the SO3 / H2S04 vapor can be captured by injecting a

sorbent upstream ofthe particulate collection device. This paper compares and contrasts these

two alternatives for H2SO4 control and identifies the situations favoring one over the other.

INTRODUCTION

The problems associated with emissions of sulfuric acid aerosol from electric utility power plants

firing high sulfur fuels have received considerable attention in the past few years. Although the

“blue plume” phenomenon caused by the light scattering effects of sulfuric acid aerosols that

form when sulfuric acid vapor condenses in wet FGD systems has been known for many years,

the magnitude of the problem has recently been heightened by the sudden increases in sulfuric

acid aerosol concentrations that have occurred when SCR systems were retrofit to high sulfur

coal fired boilers firing which had previously been retrofit with 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 of conversion of SO2 to SO3 that typically occurs in the furnace of a coal-fired boiler

ranges from about 0.5% to 1.5%. But the degree of SO2 to SO3 oxidation occurring across the

catalyst of an SCR system can be within the same range. This means that the retrofit of an 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.

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At typical air heater exit flue gas temperatures, virtually all ofthe SO3 vapor will have combined

with water vapor to form H2S04 vapor. However, it is common for the term “SO3” to be used to

describe the sulfuric acid species present in the flue gas at all points in the gas path, even in the

stack discharge. In this paper, “SO3”, “H2S04” and “sulfuric acid” will be used interchangeably

except where clarification is necessary.

While it is not correct to describe the “blue plume” phenomenon associated with SCR retrofits or

FGD retrofits as “unexpected”, it is certainly true that the effect is an “unintended” consequence

ofthe retrofit ofthese air pollution control technologies. It is ironic that the expenditure of

hundreds of millions of dollars for systems to significantly reduce emissions ofthe criteria

pollutants (SO2 and NOR) has led to the unintended consequence of plume opacity increases and

the attendant public outcry caused by a pollutant (SO3) which is emitted at concentrations of 50

ppm or less.

The effect on plume opacity and the public outcry it generates are not going to fade away.

Utilities retrofitting SCR to units having FGD, or vice versa, will be well advised to carefully

consider the long-term alternatives for reduction of SO3 emissions. This paper compares the two

principal alternatives available for SO3 control: wet ESP and sorbent injection. Factors that

would favor one over the other are described.

The considerations for control of SO3 emissions from existing units are significantly different

than those for the configuration of air 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 of SO3 emissions from existing

units. Other approaches that would reduce SO3 emissions include switching to lower sulfur coal

and/or washed 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 of a wet ESP for control of

sulfuric acid aerosol and sorbent injection for control of SO3 in conjunction with an ESP or

fabric filter (baghouse) downstream.

Wet ESP Retrofit

The first alternative for consideration is the retrofit of a wet electrostatic precipitator (wet ESP)

downstream ofthe existing FGD system. Ifthe unit currently does not have an FGD system but

is anticipating the retrofit of a wet FGD, the retrofit of a wet ESP can be incorporated into the

design ofthe wet FGD system.

Applicability

Wet ESP technology has been applied to the control of sulfuric acid aerosols for many years in

sulfuric acid production plants. In general, wet ESPs have been applied in various industrial air

pollution control applications for the collection of fine particles or dusts that are not conducive to

collection in dry ESPs or fabric filter baghouses.

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Experience

A few examples of full-scale wet ESP installations exist for electric utility boilers. However,

none ofthese current installations are serving units firing high sulfur coal. Installations of wet

ESPs in North America on utility boilers are limited to those tabulated below:

Table 1. Full-scale WESP Installations on Utility Boilers in North America.

Facifity Unit size Fuel Fired Number of WESP 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 absorber tower) Single field

Dakota 420 equiv. Waste liquids 1 (external to existing Horizontal

Gasification from coal FGD absorber tower) plate

gasification 3-field

process

Coleson Cove 3 x 350 No. 6 Oil 2 (integral to each of 2 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-sulfur coal-fired unit. Also, a

WESP section is included in the FGD absorber for the 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 of 90% or greater can be achieved with proper design. Ifthe wet

ESP is intended solely for control of SO3 emissions, the design of the wet ESP can be fine-tuned

to provide the degree of control needed to eliminate the visible plume problem.

Feasibilityfor Retrofit

As shown in Table 1, wet ESPs can be configured in the horizontal flow or vertical flow

arrangement, and may be integral to the FGD absorber or external to it. The vertical flow

arrangement is capable ofretrofit into the top of an existing FGD absorber tower, but, in practice

this may be problematic. For example, the retrofit of a vertical flow WESP section to the

existing FGD absorber tower at NB Power’s Dalhousie Station allowed space only for a single

field. This is believed to have contributed to relatively poor performance of the WESP in terms

of SO3 reduction efficiency. Additional feasibility issues may result ifthe existing FGD system

has numerous absorber modules, because each module would need to be retrofit with its own

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WESP 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 that the

space required for retrofit of an external WESP is not available.

Ifthe existing boiler unit is to receive a future FGD retrofit for compliance with SO2 emission

reduction requirements, it should be feasible to design a vertical flow WESP section into the

FGD absorber tower(s). This will minimize the plot space required for the WESP and allow the

water balance for the FGD system to incorporate consideration ofthe WESP wash water.

Incorporation of a 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 stack plume opacity, a wet ESP will reduce other

forms of fine particulate, and may provide significant control of mercury emissions as well. For

example, test results from the pilot WESP 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 subject to mercury control regulations in the near future, this

beneficial aspect of WESP performance may be an important consideration for the long term.

Costs

Costs of WESP retrofits are expected to be site specific. One vendor has indicated that the total

installed cost of a vertical flow WESP integrated into the top of a retrofit FGD absorber tower

will range from 20 $/kW to 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 of WESP technology to boilers firing high-sulfur coal. These concerns

have not yet been addressed in the full-scale installations to date. As noted previously, none of

these installations involved the treatment of flue gas from firing high-sulfur coal. More

significantly, perhaps, none ofthe fuels fired in the utility boilers for which WESPs are currently

operating at full scale have had significant chlorine content. The corrosion potential ofthe acidic

environment that exists in the WESP system can be expected to be greatly enhanced when the

high chloride concentrations typical of FGD systems on units firing eastern bituminous coal are

introduced via carryover of liquor from the FGD absorber into the WESP.

This lack of experience with regard to the corrosion effects ofthe WESP in high-chloride

applications is worrisome, especially in light ofthe current trend toward fewer and larger FGD

absorber modules. Based on the current level of field experience, it is unclear what the

appropriate material of construction 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 need to move to increasingly corrosion-resistant materials of

construction may cause the installed cost of WESPs to escalate significantly beyond current
estimates. As with FGD developments in the 1 970s, it can reasonably be expected that there will

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

Sorbent Injection

The second alternative for control of SO3 emissions from existing units is sorbent injection.

Sorbent injection for SO3 control will typically be applied by injection of a sorbent into the flue

gas at a point upstream ofthe particulate collection device. The sorbent will react with the SO3

to form a solid which can be collected in the ESP or fabric filter baghouse.

Applicability

Sorbent injection technology has been applied to the control of SO3 emissions from coal-fired

and oil-fired utility boilers for many years. The technology is readily available.

Alternative Sorbents

Sorbents that may be used for control of SO3 emissions include, but are not limited to, the

following:

• Ammonia

• Hydrated lime

• Magnesium compounds (oxide or hydroxide)

• Sodium compounds (carbonate or bicarbonate)

• 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, if any, large electric utility units operating in the U.S. that burn high-sulfur coal and utilize

fabric filters (baghouses) for particulate 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 prior to 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 retrofit with fabric filter baghouses. Nevertheless, the experience summaries presented

below are universally based on experience with ESPs.

EPRI reports that ammonia injection for SO3 control at full-scale coal-fired utility power plants

has been demonstrated to result in SO3 removal efficiencies of 95% 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 at the High Sulfur Test Center. That is, hydrated lime injection for purposes

of SO3 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 many years. But the use of magnesium

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compounds 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 at AEP’s

Gavin Unit 1.

Sodium carbonate (in the form oftrona) was successfully used at AEP’s Gavin Station during

2003 to control plume opacity that had become elevated due to increased oxidation of SO2 to

SO3 across the SCR catalyst. The sodium-based sorbent did not exhibit the ESP performance

degradation effect that was 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 for purposes of SO3 control.

Using a technology patented by Codan Development LLC, SBS solution has been injected into

the flue gas ductwork at 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 of SCR 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% or greater 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 of 70% to 90% will be required to appreciably reduce, or completely eliminate, the

plume opacity effect ofthe increased SO3 concentrations due to oxidation of SO2 to SO3 across

the SCR catalyst.

Feasibilityfor Retrofit

Sorbent injection for SO3 control is generally feasible for retrofit to most coal-fired boilers.

Especially for technologies based on injection of liquids (such as SBS) or slurries, the duct

configuration at and immediately downstream ofthe injection location should provide at least

one second ofresidence time. In these cases the ductwork immediately downstream from the

injection location should have a minimum of internal 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 of ammonia, a very

straightforward application of sorbent injection for SO3 control would be to inject ammonia

downstream from the air heater. Because the ammonia could be injected as a vapor, there would

be no concerns regarding solids fallout or potential wetting ofthe duct walls. There are other

concerns with this approach, however, as described below.

Benefits

In addition to serving the primary function of plume 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 point the potential for corrosion will be

significantly reduced. This is in sharp contrast to the situation that exists with WESP

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applications downstream of a wet FGD system, in which the acid mist is removed just before the

flue gas enters the stack, and there is no benefit with regard to reduced corrosion at any point

upstream ofthe WESP.

Costs

The capital cost of sorbent injection systems such as those used for control of SO3 emissions has

been reported to be approximately $5/kW to S 101kW, depending on the specific technology used.

Concerns

One of the principal concerns with regard to the use of sorbent injection for 503 control is the

adverse effect that some sorbents have on the performance of dry ESPs. The presence ofthe

sorbent can modify the resistivity ofthe ash to an extent that particulate removal efficiency

performance ofthe ESP tends to suffer over time. Hydrated lime is especially prone to this

effect. Sodium compounds are generally not.

For the sorbents such as SBS that are based on introduction of a liquid into the ductwork, there is

a concern that improper atomization will result in wetting ofthe duct surfaces, leading to

corrosion and formation of deposits on these surfaces.

Another concern with regard to sorbent injection is the effect ofthe collected sorbent on the

salability ofthe fly ash. Ammonia tends to be adsorbed readily on the fly ash from high sulfur

coals, and could substantially modify the range of potential commercial uses for the ash. The

sodium-based sorbents produce compounds from reactions with SO3 that are soluble in water and

may pose a concern with regard to increased potential for leaching of soluble 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 likely to be based on a number of factors.

Conditions Favoring WESP Retrofit

The following conditions are generally expected to favor the selection ofthe WESP retrofit

option:

• Requirements for SO3 control efficiencies of 90% and above.

• Need to achieve significant reductions in mercury emissions.

• Plans to retrofit FGD systems in the near future.

• Ability to employ vertical flow WESP integrated into the FGD absorber tower.

• 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 favor the selection ofthe sorbent injection

option:

• Requirements for SO3 control efficiencies of 70% or less.

• Little or no need for additional mercury emission control.

• Existing FGD system that represents a difficult retrofit for a WESP.

• Existing FGD system with multiple absorber modules.

• Lack of adequate space for retrofit of a WESP external to the existing FGD.

• No current or future potential for sale of fly ash.

• Significant problems with acid dewpoint corrosion in ductwork.

SO3 CONTROL CONSIDERATIONS FOR NEW UNITS

Owners proposing the construction of new units are required to apply for and receive Prevention

of Significant Deterioration (PSD) permits prior to 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 of potential emissions that exceeds 7.0 tons per

year will require a BACT analysis. It will be virtually impossible for large, new units firing

high-sulfur coal to have potential emissions of sulfuric acid mist below this “de minimis”

threshold value. That means that any new unit firing high sulfur coal will likely be subject to

BACT requirements. This will dictate consideration of an emission rate for sulfuric acid mist

that corresponds to application of the “top” level of control, in accordance with U.S. EPA

guidelines for the “Top Down” BACT.

The “top” level of control 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 for the “top” level of control. 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-sulfur coal.

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 0.0075
Review of Table 2 indicates that 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 of emissions of H2SO4 mist. However, in two cases the control technology lineup also

presumes that fabric filters will be used. In one case the control technique cited for sulfuric acid

mist consists of dry sorbent injection (DSI) upstream of a fabric filter. In each case listed in

Table 2, the NO~ control technology to be applied includes SCR. Current H2S04 emission levels

representing BACT are approximately 0.005 lb/mmBtu.

CONCLUSIONS

Active control of emissions of SO3 (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 industry within the past few years. Two primary technology-based control

alternatives exist: retrofit of wet electrostatic precipitators (WESPs) or use of sorbent 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 sulfur coal. In some

cases there are unanswered questions regarding the technical feasibility and cost ofthese options.

The technology favored for reduction of SO3 emissions from high-sulfur coal-fired units will

depend on a number of factors including the degree of emission control required to eliminate the

objectionable visible plume effects, the configuration ofthe existing air pollution control

equipment, the need for coincident removal of mercury, the current and future plans for fly ash

sales, and the extent to which acid dewpoint corrosion is a critical problem at a given plant.

Depending on the individual situation at each plant with regard to these factors, one control

alternative is likely to be favored over the 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, if any.

BACT considerations for new units firing high-sulfur coal will require overall control

efficiencies of 90% or more. The use of WESPs is proposed for several ofthe new units recently

permitted, but sorbent injection upstream of a fabric filter baghouse has also been identified as

the control technique in at least one case. This drive toward very low stack emissions of sulfuric

acid mist will force these technologies to mature within the next few years. It would not be

surprising if some setbacks occur along the path to full implementation ofthese technologies.

Key Words:

Wet ESP

Sorbent injection

SO3

Sulfuric acid mist

BACT