SO3 Mitigation Guide and Cost Estimating Workbook 

Paper #34 

Katherine Dombrowski, Gary Blythe

URS Corporation, P.O Box 201088, Austin, TX 78720 

Richard Rhudy

EPRI, 3412 Hillview Avenue, Palo Alto, CA 94304 

ABSTRACT 

SO3 or sulfuric acid in flue gas is an issue for plants that fire medium- to high-sulfur coals, 

particularly those with SCR for NOX control, because of adverse effects such as duct corrosion, 

air heater plugging and elevated plume opacity. EPRI has recently published an updated SO3

Mitigation Guide that discusses the state of the art for measuring and controlling SO3 emissions 

from coal-fired plants. Included in the guide are cost estimates for ten different SO3 control 

technologies as applied to an example plant, and a cost estimating workbook that allows the 

report user to develop site specific estimates for candidate control technologies. This paper 

presents and discusses the cost estimate data for the example plant. Capital, reagent, and utilities 

costs are presented for each of ten technologies for comparison. Sensitivity case estimates are 

also presented showing the effects of delivered reagent costs, SO3 control system operating 

period (ozone season only versus year-round), and new versus retrofit installations. 

INTRODUCTION 

A wide range of SO3 or sulfuric acid controls have been tested and/or applied for coal-fired 

power plants, such as low-sulfur-coal switches, injecting alkaline sorbents at various locations in 

the furnace or ductwork, and installing wet ESPs. The costs of applying these technologies can 

vary over a wide range, and each has positive and negative attributes that could make it more or 

less favorable for application at a given power plant. This paper describes a number of 

SO3/sulfuric acid control technologies and presents estimated costs for applying these 

technologies at an example plant that is being retrofitted with SCR for NOX control. 

Figure 1 shows the flue gas path of a typical coal-fired power plant, and illustrates where a 

number of candidate SO3/sulfuric acid control technologies might typically be applied. The 

following paragraphs briefly discuss each of the potential control technologies illustrated. 

Fuel Switch/Blending 

Low-sulfur coal blending or switching lowers the SO2 content of the flue gas, which reduces the 

concentration of SO3 produced in the furnace and across an SCR catalyst. The ability to 

implement this option and its cost effectiveness can be very site specific. If low-sulfur-coal firing 

is feasible, it can result in other benefits such as making more SO2 allowance tons available and 

allowing lower air heater outlet flue gas temperatures, the latter of which can result in plant heat 

rate improvements. 
2

Figure 1: Illustration of Potential SO3/Sulfuric Acid Control Options 

Notwithstanding capital expenses that may be required, the economics of coal switching are 

driven almost entirely by the delivered cost differential between the current coal and the lowsulfur coal. Changes in the delivered fuel price of a few cents per million Btu can change the 

annual costs for this control option by several hundred thousand dollars or more. 

Fuel Additive 

Omni Materials, Inc., of Mt. Carmel, Illinois has developed a proprietary fuel additive for coalbased applications, OmniClearTM. Based on information provided in company literature, the 

additive is apparently ground dolomite (75% minus 200 mesh) that is partially calcined, then 

treated with a coating that helps prevent dead burning.1

 The company literature reports the 

results of a full-scale test on a plant with an SCR and firing approximately a 3% sulfur coal (5 lb 

SO2/MM Btu). An additive rate of approximately 0.5 to 1.0 wt% of the coal feed rate reportedly 

lowered SCR outlet SO3 concentrations from 50 to 65 ppm to about 5 ppm at the ESP outlet. 

This equates to approximately 90 to 92% SO3 removal. However, since no ESP outlet 

concentration data were reported for without the additive, it is not clear what percentage of the 

reported removal was attributable to the additive (i.e., some removal would be expected across 

the air heater and ESP without the additive). 

Furnace Injection of Magnesium-based Alkalis 

This technology involves injecting magnesium hydroxide (Mg(OH)2) aqueous slurry into the 

upper furnace, where it reacts with SO3 to produce magnesium sulfate solids. These solids are 

removed in the downstream particulate control device. Testing co-funded by EPRI focused on 

the injection of magnesium hydroxide slurries into coal-fired furnaces to achieve 90+% removal 

of furnace-formed SO3.

2

 For plants without SCR, furnace Mg injection is capable of high SO3

- Byproduct 

Mg Injection

FGD Absorber

To 

Stack

Economizer Air Heater

Outlet

SCR

- MgO Injection

- SBS Injection

- SBS Injection

- Hydrated Lime Injection

- Ammonia Injection

- Humidification with Alkali Injection

ID/Booster Fans

ESP

Wet ESP

- Fuel 

Switch

- Fuel 

Additive

- Commercial 

Mg Injection

Wet ESP 

conversion

- Byproduct 

Mg Injection

FGD Absorber

To 

Stack

Economizer Air Heater

Outlet

SCR

- MgO Injection

- SBS Injection

- SBS Injection

- Hydrated Lime Injection

- Ammonia Injection

- Humidification with Alkali Injection

ID/Booster Fans

ESP

Wet ESP

- Fuel 

Switch

- Fuel 

Additive

- Commercial 

Mg Injection

- Byproduct 

Mg Injection

FGD Absorber

To 

Stack

Economizer Air Heater

Outlet

SCR

- MgO Injection

- SBS Injection

- SBS Injection

- Hydrated Lime Injection

- Ammonia Injection

- Humidification with Alkali Injection

ID/Booster Fans

ESP

Wet ESP

- Fuel 

Switch

- Fuel 

Additive

- Commercial 

Mg Injection

Wet ESP 

conversion
3

removal percentages, but SO3 removal may be limited by the performance of downstream coldside ESPs. At high SO3 removal percentages, the loss of sulfuric acid conditioning of fly ash 

particles appears to cause high resistivity conditions that limit ESP performance.3

 For plants 

with SCR, furnace injection can lower SO3 concentrations in the SCR inlet flue gas, which can 

allow SCR operation at lower load without capillary condensation of ammonium bisulfate in 

catalyst pores. However, furnace Mg injection does not appear to be effective at removing SO3

formed across the SCR catalyst.3

With or without SCR, furnace Mg injection should lower the flue gas acid dew point, which may 

allow the plant to operate at lower air heater outlet flue gas temperatures and realize heat rate 

improvements. The potential benefits of SO3 removal upstream of the air heater on plant heat 

rate are mentioned several places in this paper, and warrant explanation. Most coal-fired power 

plants have steam or glycol heaters to preheat the ambient combustion air going to the air 

heaters. The amount of preheat is adjusted to control the air heater outlet air and flue gas 

temperatures. On bituminous coal-fired plants, the air heater outlet flue gas temperature is 

typically controlled to minimize adverse effects of sulfuric acid condensation, such as plugging 

and/or corrosion in the air heater, or downstream corrosion. Lowering the flue gas SO3

concentration upstream of the air heater, such as by furnace Mg injection, may allow the plant to 

lower the air heater outlet temperature. This is typically implemented by reducing the amount of 

steam used to preheat the combustion air to the air heater (or to heat the glycol solution). 

Reduced steam consumption for combustion air preheat can improve the overall plant heat rate. 

For this evaluation, cost estimates have been developed for both an FGD byproduct Mg(OH)2

slurry (byproduct Mg) and commercial Mg(OH)2 slurry (commercial Mg). 

Alkali Injection into the SCR Outlet Duct 

Costs were estimated for two injection technologies for downstream of the SCR and upstream of 

the air heater: MgO powder injection and sodium bisulfite/sulfite solution (SBS) injection. These 

alkalis react with SO3 to form salts that are removed in the particulate control device. Since these 

technologies can remove SO3 upstream of the air heater, they offer a potential for lower air 

heater gas exit temperatures, with corresponding plant heat rate improvements. They may also 

reduce corrosion in the air heater and downstream equipment. 

The reactive MgO powder is marketed by Martin Marietta, but other vendors may provide 

similar products. Relatively few performance data are available in the literature for the MgO duct 

injection process. Martin Marietta literature cites examples of high SO3 removal efficiency 

(>80%) with near stoichiometric amounts of MgO being injected.4

The SBS InjectionTM process is patented by Codan Development LLC and available by license. 

SBS solution, a byproduct from sodium-based FGD systems, or commercially available sodium 

sulfite or bisulfite can be used as a feed material. SBS process performance data are available 

from full-scale testing at Vectren Corporation’s A.B. Brown Station.5

 High sulfuric acid removal 

levels are possible (greater than 90%, or down to less than 2 ppmv at the ESP outlet) when 

injecting at Na:SO3 mole ratios in the range of 1.5:1 to 2:1. 
4

Alkali Injection into the Air Heater Outlet Duct 

Two technologies involving alkali injection into the air heater outlet duct were evaluated in the 

economic comparison, hydrated lime injection and ammonia injection. These, and all 

technologies applied downstream of the air heater, offer no potential benefits to SCR low-load 

turn down or plant heat rate. 

EPRI evaluated duct injection of alkali powders such as hydrated lime at pilot scale at their 

Environmental Control Technology Center (ECTC) in the early 1990s.6 Alkaline powders react 

with flue gas sulfuric acid to form sulfate salts that are collected with the fly ash in the 

particulate control device. EPRI found it was possible to achieve high sulfuric acid removal 

percentages when injecting hydrated lime, sodium bicarbonate, or other dry alkaline powders 

into the ductwork between the air heater and particulate control device, primarily a cold-side 

ESP. 

Ammonia injection has been tested by many and has been implemented at some plants for 

sulfuric acid control. Ammonia can be injected between the air heater and cold-side ESP at 

NH3:SO3 mole ratios in the range of 1.5:1 to 2:1 to achieve high sulfuric acid removal levels 

(upwards of 95%). The biggest issue for ammonia injection is its effect on fly ash disposal/reuse. 

Flue Gas Humidification, With or Without Alkali Injection 

In this technology, also tested by EPRI at the ECTC, the flue gas is partially humidified and 

cooled to below its acid dew point. The sulfuric acid appears to be removed by condensing onto 

existing fly ash particles, which can be collected in a cold-side ESP or wet scrubber. Alkali can 

also be injected, and serves several apparent purposes. One is to neutralize the sulfuric acid 

droplets formed, so they are less corrosive to ductwork, ESP collecting plates, etc. Another 

reason is to control the fly ash resistivity. When injecting upstream of a cold-side ESP, EPRI 

found that humidification can result in low fly ash resistivity and a tendency for increased ash reentrainment emissions, which could be avoided by also injecting a calcium-based alkali. Of the 

various possible configurations, humidification with separate hydrated lime powder injection 

upstream of the ESP was selected for evaluation in the EPRI guide. 

Wet ESP 

Wet ESP technology has been in existence for nearly a century, but sulfuric acid control on coalfired power plants represents a relatively new application in the U.S. In this control technique, 

sulfuric acid mist is collected by electrostatic forces in a wetted-plate ESP. The collected mist is 

washed from the plates either periodically or continuously, and the blow down can go to an FGD 

system or to a separate system for treatment. To achieve high sulfuric acid removal efficiencies 

(>80%), the wet ESP could be installed downstream of the wet FGD absorber or could be 

installed inside the absorber vessel as a replacement for the chevron-style mist eliminator. For 

lower efficiencies (~60%) it is possible to convert the last field of a conventional dry ESP to wet 

operation.7
5

By being installed at or near the end of the flue gas path, wet ESPs typically address only plume 

opacity and particulate emissions, and provide no upstream benefits for air heater exit 

temperatures or duct corrosion. 

EXAMPLE PLANT FOR ECONOMIC STUDY 

Cost estimates were prepared for applying a number of sulfuric acid control technologies to a 

hypothetical or example power plant. The plant consists of a single, 500-MW unit located in the 

Midwest, and firing a 3.5% sulfur bituminous coal. The plant is retrofitting an SCR system for 

NOX control, and currently has a cold-side ESP for particulate control and a wet FGD system for 

SO2 control. The FGD system uses limestone reagent and produces wallboard-grade gypsum, 

which is sold as a byproduct. The fly ash is handled dry, and either sold as a byproduct or 

disposed in a landfill. During the “ozone season,” all of the fly ash is typically sold. Table 1 

summarizes the assumptions made for the hypothetical plant. 

Table 1. Assumptions made for heat and material balances for hypothetical plant.

Parameter Value 

Unit Load (gross MW) 500 

Gross Plant Heat Rate (Btu/hr/KW ) 9200 

Capacity Factor (%) 85 

Flue Gas Flow Rate (acfm at economizer outlet) 2.07 x 106 

Coal Sulfur Content (%) 3.5 

Flue Gas SO2 Content (ppmv wet at economizer 

outlet) 

2790 

Furnace Conversion of SO2 to SO3 (mole %) 1.0 

Conversion of SO2 to SO3 Across SCR Catalyst 

(mole %) 

0.75 

Stack Sulfuric Acid Concentration during SCR 

Operation (ppmv) 

21 

NOx Season Duration (months/yr) 5 

Target Stack Sulfuric Acid Concentration (ppmv, dry basis): 

 For lower SO3 removal percentage target 9.5 (return to pre-SCR conditions) 

 For higher SO3 removal percentage target 3.0 (assumed value corresponding to “clear” stack) 

The plant has a wall-fired, pulverized coal boiler that typically converts 1% of the coal sulfur to 

SO3. The SCR catalyst guarantee is for no more than 0.75% conversion of SO2 to SO3 across the 

installed catalyst layers. Figure 2 summarizes the assumed baseline SO3/sulfuric acid 

concentrations at various locations in the flue gas path, both with and without the SCR in line. 

The concentrations in the figure assume approximately 6 ppmv of SO3/sulfuric acid removal 

each across the air heater and ESP and 50% removal of sulfuric acid mist across the FGD 

absorber for both cases. 
6

Figure 2: Baseline and Post-SCR SO3/Sulfuric Acid Concentrations for Hypothetical Plant 

METHODOLOGY FOR ECONOMIC CALCULATIONS 

The objective of applying controls was to restore the stack sulfuric acid concentration to the preSCR value of 9.5 ppmv (dry basis) from the projected value of 21 ppmv with the SCR in service. 

A sensitivity case also looked at costs for achieving a higher level of SO3 control, down to 3 

ppmv (dry basis) or less at the stack. This lower concentration should be adequate to result in a 

clear stack, or low stack plume opacity (at least due to the sulfuric acid mist contribution to 

plume opacity) under most conditions. The SCR was assumed to operate only during the “ozone 

season,” from May 1 through September 30, and it was assumed the sulfuric acid controls will 

only be required to operate during that time period as well. Other sensitivity cases considered 

both a new and retrofit plant installation where the SCR and SO3 controls operate year-round. 

As a first step in developing cost estimates for the various potential sulfuric acid controls, heat 

(enthalpy) and material balance calculations were conducted to estimate the expected SO3/ 

sulfuric acid control performance of each technology, and to estimate reagent and utility 

consumption rates. Performance information for each technology was taken from data supplied 

either by the vendor or by EPRI. The details of the heat and material balances are provided in the 

EPRI SO3 Mitigation Guide Update.8

Cost estimates were not developed for ammonia injection at the lower SO3 removal percentage. 

When the NH3:H2SO4 molar ratio is low, ammonia injection can cause operating problems via 

the formation of a sticky ammonium bisulfate. 

Two technologies, byproduct Mg injection and commercial Mg injection in the furnace, were not 

estimated to be able to achieve the higher sulfuric acid removal percentage (down to 3 ppmv at 

the stack) independently. Two U.S. power plants have operated or are planning to operate with a 

combination of furnace Mg injection and hydrated lime injection upstream of the ESP to achieve 

Economizer Air Heater

Outlet ESP

SCR

Absorber

Stack

ID/Booster Fans

31 ppm 53 ppm w/SCR

25 ppm baseline

48 ppm w/SCR

9.5 ppm baseline

21 ppm w/SCR

19 ppm baseline

42 ppm w/SCR
7

relatively high control efficiencies. Consequently, this combination of control technologies was 

included for the economic evaluation for the higher removal percentage case.9

The performance estimates and heat and material balances formed the basis for the capital cost 

estimates for eight of the ten technologies under consideration. Spreadsheets were then used to 

develop an overall project cost estimate. 

The two not estimated in this manner were wet ESP and fuel switch. Capital cost estimates were 

developed for the wet ESP cases but were based solely on general budgetary cost factors. A 

capital cost factor of $35/kW was used for a last-field dry ESP conversion for the lower SO3

removal case, and a factor of $55/kW for standalone wet ESP retrofit downstream of the wet 

FGD absorber for the higher removal percentage. The capital costs for a wet ESP retrofit can be 

very site specific, depending on the difficulty of the retrofit and materials of construction 

selection, and could vary by ±50% or greater. No capital cost estimates were made for fuel 

switching because the capital cost requirements for this technology can be very site specific. 

The reagent and utility consumption estimates and the amortized capital cost estimates were 

combined to generate annual cost estimates for each of the technologies. These estimates were 

not “levelized” to reflect escalation and discount rates, but instead represent first-year costs. Nor 

do they include operating labor, nor maintenance labor and materials. For most of the 

technologies, there is not a good experience basis for estimating these values, so such an estimate 

would be based on a percentage of capital, reagent, and/or utility costs, and would not help 

differentiate the projected costs of the technologies. 

The factors used to develop costs are shown in Table 2. The reagent costs are based either on 

f.o.b. quotes from vendors and an assumed shipping distance at an average shipping cost, as 

shown in the table, or typical delivered costs for the Midwest. Plant water, softened water, 

auxiliary power and fuel costs are also “typical” values taken from previous economic 

evaluations conducted by URS for power plants east of the Mississippi River. The values for 

gypsum byproducts, fly ash byproduct sales and incremental landfill disposal costs represent the 

nominal averages (rounded to the nearest whole dollar) for power plants with medium- and highsulfur coal limestone forced oxidation FGD systems, as reported on their 2001 Form EIA-767. 

Capital cost recovery values are based on an annual recovery factor of 0.15, which nominally 

represents an 8% discount rate and a 10-year book life. 

BASELINE CASE ECONOMIC RESULTS 

The first year cost estimates are summarized in Figure 3 for the lower removal target. Because 

the cost estimated for ammonia injection was relatively low, ammonia injection was included in 

Figure 3 even though it was estimated for achieving the higher removal percentage target. 
8

Table 2. Factors used to generate annual reagent and utility costs. 

Factor Value Used 

OmniClearTM fuel additive, 75% minus 200 mesh, delivered from Omni Materials ($/ton) 100 

Byproduct Mg(OH)2 slurry, delivered from Midwest supplier ($/dry ton of pure Mg(OH)2, 

shipped at 18% solids, 65% purity in solids, assumed 50-mile delivery distance) 

151 

Commercial Mg(OH)2 slurry, delivered from Manistee, MI ($/dry ton Mg(OH)2, shipped at 

58 wt% solids, 100% purity in solids, assumed 600-mile delivery distance) 

334 

Utilimag 40 MgO powder, delivered from Manistee, MI ($/dry ton MgO, assumed 600-

mile delivery distance) 

472 

Sodium Sulfite, delivered from Green River, WY ($/dry ton available Na as Na2SO3) 300 

Ammonia, delivered from existing plant system ($/ton) 300 

Hydrated Lime, delivered from Midwest location ($/ton) 75 

Truck Transit Costs ($/ton-mile) 0.12 

Plant Water Cost ($/1000 gal) 0.40 

Plant Softened Water Cost ($/1000 gal) 2.30 

Plant Auxiliary Power ($/kwh) 0.032 

Plant Fuel Costs ($/MM Btu) 1.04 

Plant Low-sulfur Fuel Cost ($/MM Btu) 1.24 

Gypsum Byproduct Value ($/wet ton, f.o.b. plant) 5.00 

Fly Ash Sales Value ($/ton, f.o.b. plant) 3. 00 

Incremental Landfill Disposal Costs ($/ ton) 4. 00 

Annual Capital Recovery Factor 0.15 

Figure 3: Summary of First-year Capital Recovery and Non-labor Operating Costs by 

SO3/Sulfuric Acid Control Technology for Achieving the Lower Removal Percentage Target 

0

500

1000

1500

2000

2500

Fuel Blend

Fuel Additive

Byp. Mg

Comm. Mg

MgO

SBS

NH3

Humid./Lime

Hyd. Lime

Wet ESP

Annual Cost ($1000)

Capital Recovery

Reagent and Utility Costs

2,745
9

For the lower sulfuric acid control percentage plot, five control options had projected reagent, 

utility, and capital recovery costs in the range of $460,000 to $670,000 annually. The five 

include the fuel additive, furnace injection of byproduct Mg, MgO powder injection, SBS 

InjectionTM, and ammonia injection (at the higher removal level). 

The differences between the projected costs of these four control options are not great relative to 

the level of uncertainty for these estimates. For example, if these annual cost estimates are 

assumed to have an uncertainty of 25%, the “error bars” (not shown in Figure 3) for these five 

lower cost options would substantially overlap. This suggests that a more detailed analysis would 

be required to determine the most cost effective control option for this application. 

Three other control options were estimated to be somewhat more expensive, in the range of 

$760,000 to $820,000 annually. These include low-sulfur coal blending, commercial Mg 

injection in the furnace, and humidification with hydrated lime injection between the air heater 

and ESP. Recall that the costs for fuel blending with low-sulfur coal disregard any potential 

capital modifications that may be required by the plant. Significant capital modification 

requirements could make this option less attractive. Also, its ranking is based almost entirely on 

an assumed value for the fuel cost differential. This cost differential could vary widely from the 

assumed value of $0.20/MM Btu. 

The remaining technologies for which costs were developed at the lower removal percentage 

include dry hydrated lime powder injection upstream of the ESP and a wet ESP retrofit to the last 

field of the existing dry ESP. These two options appear to be less cost effective, with annual 

costs projected at $1.0 and $2.8 million, respectively. However, the wet ESP comparison is 

skewed by the assumption that the control technologies will only operate five months out of the 

year, and the relatively high capital recovery factor (10-year recovery). Both of these 

assumptions favor low capital cost control options such as fuel blending or sorbent injection. 

This effect is further discussed below. 

The estimated costs for the higher sulfuric acid removal percentage are shown in Figure 4. These 

estimates show ammonia injection as a potentially low cost technology, with projected first-year 

costs of $640,000, followed by the OmniClearTM fuel additive at $790,000 annually. Three other 

technologies, MgO powder injection, SBS injection and humidification with hydrated lime 

injection, show somewhat higher annual projected costs between $920,000 and $980,000. Again, 

if these annual cost estimates have an uncertainty of 25%, the error bars for these five 

technologies would overlap. 
10

Figure 4: Summary of First-year Capital Recovery and Non-labor Operating Costs by 

SO3/Sulfuric Acid Control Technology for Achieving the Higher Removal Percentage Target 

Four other technologies show considerably higher first-year operating costs of $1.9 to $2.4 

million. These include fuel switching; the two furnace injection technologies, which were 

combined with hydrated lime injection between the air heater and ESP for this estimate; and 

hydrated lime/sodium bicarbonate blend injection alone. Note that the latter three technologies 

might adversely affect the base plant ESP performance due to the addition of relatively large 

quantities (17 to 21% of the base fly ash loading) of particulate matter to the ESP inlet flue gas. 

The wet ESP retrofit downstream of the wet FGD system shows the highest first-year cost of 

over $4 million. However, as mentioned above, the wet ESP comparison is skewed by the 

assumption that the control technologies will only operate five months out of the year and the 

relatively high capital recovery factor (10-year recovery). 

COST ESTIMATE SENSITIVITY CASES 

The relative cost effectiveness of SO3/sulfuric acid control technologies is impacted by a number 

of parameters. Comparison of the cost estimates presented in Figure 3 with those in Figure 4 

illustrates the effect of one parameter, the required SO3/sulfuric acid removal percentage. 

However, many of the assumptions made to develop these cost estimates also impact the results. 

This subsection presents the results of sensitivity cases run to show how three parameters – 

delivered sorbent costs (for sorbent additive/injection technologies), months per year of control 

system operation, and new versus retrofit applications – impact the relative economics of SO3

control. Sensitivity cases for each of these parameters are presented and discussed below. 

Of course, additional parameters impact the relative economics of SO3 control, such as the size 

of the plant being controlled, what type of existing control device is used for particulate control, 

0

500

1000

1500

2000

2500

Fuel Blend

Fuel Additive

Byp. Mg + Hyd. Lime

Comm. Mg + Hyd. Lime

MgO

SBS

NH3

Humid./Lime

Hyd. Lime + Bicarb

Wet ESP

Annual Cost ($1000)

Capital Recovery

Reagent and Utility Costs

4,191
11

whether the plant has an FGD system and what reagent is used, whether or not the plant sells its 

fly ash and/or FGD byproduct, and many others. It is beyond the scope of the guide and this 

paper to show cost sensitivities to all of these parameters, even though many of them can 

significantly impact SO3 control economics. The reader can refer to the SO3 control cost 

workbooks published in EPRI’s SO3 Mitigation Guide Update (Report 1004168) to develop 

initial cost estimates that are more specific to a particular plant’s circumstances. 

Effect of Delivered Reagent Cost 

The estimated costs for most of the additive or injection technologies are largely driven by 

delivered sorbent cost, as the capital costs for these technologies are relatively low (less than 

$10/kW). There is uncertainty in the delivered costs of all of these sorbents. Since the sorbents 

are typically available at a discrete number of locations and the distance between those locations 

and the candidate plant could vary over a wide range, transportation costs could be quite 

variable. Furthermore, transportation costs on a ton-mile basis will vary significantly depending 

on whether truck, rail or barge delivery is employed. 

The f.o.b. price of the sorbents could also vary significantly. The factors that drive the costs of 

several potential sorbents are described below: 

OmniClearTM fuel additive – This sorbent/fuel additive is currently supplied by only one vendor. 

The f.o.b. price of this additive can therefore be influenced by market supply/demand pressures. 

Byproduct Mg – This material is not sold commercially, so the market price per ton is not 

established. Some plants would be able to produce this material internally from their FGD 

byproduct, but many would have to purchase this material from a third party. Carmeuse has 

estimated the production cost at $67/ton of pure magnesium hydroxide,9 but this does not include 

capital recovery or any profit. 

MgO Powder – The Utilimag 40 sorbent used as the basis for this evaluation is supplied by only 

one vendor. The f.o.b. price can therefore be strongly influenced by market supply/demand 

pressures. 

SBS – Either sodium sulfite or sodium bisulfite, or a blend of the two, could be used as the 

reagent for this technology. Either reagent could be procured as a byproduct or as a technical 

grade chemical. This reagent could be shipped as a concentrated solution or as a dried powder. 

Depending on which reagent source and form is employed, the f.o.b. and delivered cost of this 

reagent could vary by hundreds of dollars per ton. 

Ammonia – Both ammonia and urea are commodity chemicals used in high volumes in the U.S. 

The costs for these reagents are driven by supply and demand pressures, and by the price of raw 

materials, and can fluctuate over a wide range. 

Hydrated Lime – Hydrated lime is available from a number of suppliers throughout the Midwest. 

Depending on the plant size and hydrated lime requirements, and distances from suppliers, it 

may be more cost effective to purchase quicklime and hydrate it on site. While a delivered price 
12

of $75/ton was used as the basis for these cost estimates, quicklime can be purchased for about 

$50/ton and contains about 30% more alkali on a molar basis, making it about half the cost of 

hydrated lime on a molar basis. Plants that use lime or magnesium-enhanced lime as an FGD 

reagent on site already may have a long-term contract for quicklime and have presumably 

negotiated a competitive delivered price. However, using quicklime to produce hydrated lime on 

site requires additional capital investment and operating and maintenance labor, which will offset 

some of the savings. 

Given these issues, it is quite possible that the costs of any of the sorbents considered could vary 

over a range of 50% from the values used as the basis for the cost estimates presented in 

Figures 3 and 4. Since sorbent costs represent a majority of the injection technology costs, this 

could greatly influence the annual reagent, utility, and capital cost recovery estimates. Figure 5 

illustrates the effects of delivered sorbent cost, over the range of 50% of the values presented in 

Table 2, for the higher sulfuric acid removal percentage case. 

For all of the sorbent injection technologies except ammonia injection and humidification with 

hydrated lime injection, sorbent delivered cost variations produce a wide range in the technology 

cost estimates. The ammonia injection costs are mostly driven by the assumption of lost fly ash 

sales, and the humidification with lime injection costs are mostly driven by capital costs. 

The results in Figure 5 show that among the five candidate sorbent injection technologies that 

were estimated to have lower annual costs earlier in this paper, an increase in sorbent cost for 

one coincident with a decrease for another could markedly change the ranking of injection 

technology costs. 

Figure 5: Effect of Sorbent Delivered Price Variations on Control Technology Cost Estimates 

(includes reagent, utility and capital recovery costs) 

0

500

1000

1500

2000

2500

3000

3500

Fuel Additive

Byp. Mg + Hyd. Lime

Comm. Mg + Hyd. Lime

MgO

SBS

NH3

Humid./Lime

Hyd. Lime + Bicarb

Annual Cost ($1000)

-50% Reagent Cost

Estimated Reagent Cost

+50% Reagent Cost
13

These results illustrates that, before selecting an SO3 control technology for a particular plant, it 

would be best to have the delivered sorbent cost established to a relatively high confidence level. 

Effect of Control Technology Operating Period 

The control technology cost estimates presented earlier in this section were based on the 

assumption that the SCR on the example plant would operate only during the 5-month ozone 

season, and that the control technology would operate only during that period as well. However, 

some plants will have to operate their SCR year-round, and/or will have to operate their SO3

control technology year-round once installed. A change to year-round operation will improve the 

relative economics of technologies whose costs are driven mostly by capital recovery (e.g., wet 

ESP) and could erode the economics of technologies whose costs are driven mostly by reagent 

and/or utility costs (e.g., fuel switch/blend or fuel additive). 

Two simplifying assumptions were made in generating the 12-month per year costs. One is that 

the SCR operates year-round. The analysis would be more complex if the SCR operated 5 

months while the control technology operated 12 months, as there would be different baseline 

SO3 concentrations and different SO3 removal percentage requirements for the two periods of the 

year. The second simplifying assumption was that the plant’s fly ash is sold year-round. Again, 

the analysis would be more complex if the ash is only sold for part of the year, particularly for 

the ammonia injection case where the cost estimate is largely driven by the impacts of lost fly 

ash sales. 

The results from Figure 4 are incorporated into Figure 6 to show the effect of 12-month versus 5-

month operation on the relative economics of the SO3 control technologies at the higher removal 

percentage. As expected, the relative ranking of the fuel switch/blend case erodes for 12-months 

operation and the relative ranking of the wet ESP case improves. For the five injection 

technologies that were estimated at less than $1 million annually for 5-months operation, 

ammonia injection remains the lowest estimated cost option (notwithstanding other balance-ofplant issues) but the relative rankings of the other four technologies reverse. For example, the 

more capital intensive humidification with lime injection process goes from being the most 

costly of the five to being the second lowest (behind ammonia injection) for 12-months 

operation. Conversely, the fuel additive process goes from being the second least costly to the 

most costly of the five at 12-months operation. 

 
14

Figure 6: Comparison of First-year Capital Recovery and Non-labor Operating Costs by 

SO3/Sulfuric Acid Control Technology for Achieving the Higher Removal Percentage Target (5-

month vs. 12-month operating period) 

 

Effects of New Versus Retrofit Installation 

Another assumption used for this evaluation that impacts the relative economics of the candidate 

SO3 control technologies is the assumption that the controls are being retrofit to an existing 

scrubbed plant. If it is instead a new plant, there are at least two impacts on the cost estimates. 

One is that a longer plant life would be assumed and hence a lower capital recovery factor would 

be applied. The second is that, for the wet ESP case, the wet ESP design and implementation 

could be integrated with the wet FGD absorber, possibly lowering the capital cost. For the other 

technologies, the capital costs would not likely change as significantly for a new plant. 

Figure 7 illustrates first-year annual cost estimates for candidate SO3 control technologies for the 

higher SO3 removal percentage and for 12-months operation (the most likely scenario for a new 

plant) with two changes from the estimates shown in Figure 4. One is that the capital recovery 

factor has been lowered to 0.10 from 0.15 (same discount rate, 20-year versus 10-year recovery 

period), and the capital costs for the wet ESP case have been reduced to $35/kW from $55/kW, 

reflecting the wet ESP being integrated into the FGD module design. 10,11 

0

1000

2000

3000

4000

5000

6000

Fuel Blend

Fuel Additive

Byp. Mg + Hyd. Lime

Comm. Mg + Hyd. Lime

MgO

SBS

NH3

Humid./Lime

Hyd. Lime + Bicarb

Wet ESP

Annual Costs ($1000)

5-mos. Operation

12-mos. Operation
15

Figure 7: Summary of First-year Capital Recovery and Non-labor Operating Costs by 

SO3/Sulfuric Acid Control Technology for Achieving the Higher Removal Percentage Target 

(New plant, 12-month operating period). 

Figure 8 compares annual cost estimates for all three estimate bases (5-months operation, 12-

months operation, and 12-months operation for a new plant). The estimates illustrated in Figures 

7 and 8 show that the relative economics of the wet ESP case greatly improve relative to the 

sorbent injection technologies. Furthermore, the wet ESP offers two advantages relative to 

sorbent injection. One is that the wet ESP can also lower the emissions of trace metals (e.g., 

beryllium, lead) present in the fine particulate emitted from the dry ESP or baghouse, which 

could help in the permitting of the new coal plant. The second is that the primary cost driver for 

the wet ESP case, capital recovery, would be fixed at the outset whereas the primary cost driver 

for sorbent injection, delivered sorbent costs, could vary significantly over the life of the plant. 

On the other hand, the sorbent injection technologies that remove SO3 from the flue gas upstream 

of the air heater could be exploited to further improve the plant heat rate and to lower costs 

associated with corrosion repair in the back end of the plant. Neither of these factors has been 

considered here. 

 

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

Fuel Blend

Fuel Additive

Byp. Mg + Hyd. Lime

Comm. Mg + Hyd. Lime

MgO

SBS

NH3

Humid./Lime

Hyd. Lime + Bicarb

Wet ESP

Annual Cost ($1000)

Capital Recovery

Reagent and Utility Costs

5640
16

Figure 8: Comparison of First-year Capital Recovery and Non-labor Operating Costs by 

SO3/Sulfuric Acid Control Technology for Achieving the Higher Removal Percentage Target 

SO3 CONTROL PROCESS ECONOMICS WORKBOOK OVERVIEW 

The example economics shown above illustrate that the most cost effective SO3 control 

technology can be very site specific, depending on the plant location, existing environmental 

controls, disposal or reuse practices for coal combustion byproducts, utility-specific capital 

recovery factors, etc. A workbook was designed to enable the user to perform a simplified, 

preliminary investigation of the costs for implementing these technologies at the user’s coal-fired 

plant. The workbook is part of the EPRI SO3 Mitigation Guide Update (TR-1004168). The 

purpose of the workbook is to allow the reader to calculate the approximate capital and annual 

reagent and utility costs associated with each of the possible SO3 control options for a particular 

plant. The control options that are covered by this workbook include wet ESP, fuel blending, fuel 

additives, and a number of sorbent injection technologies. 

The workbook is oriented towards plants that fire eastern bituminous coals, because eastern 

bituminous coals typically have higher sulfur content than western coals and there is little data 

available for other coal types. The workbook considers the effect of Powder River Basin 

subbituminous coal, but only as a low-sulfur blending coal, in the context of being implemented 

as a mitigation technology. It is possible that some plants that fire Texas lignite could have high 

enough flue gas SO3/sulfuric acid concentrations to cause plume opacity issues, as some could be 

considered medium- to high-sulfur coals on the basis of pounds of SO2 produced per million Btu 

of heat input. Consequently, the workbook also includes some calculations oriented towards 

Texas lignite. However, the user is cautioned that no data were available for evaluating SO3

control technologies for Texas lignite applications, so there are some technical risks associated 

with using the workbook for a Texas-lignite-fired plant. 

Completion of the workbook involves three main steps: 

0

1000

2000

3000

4000

5000

6000

Fuel Blend

Fuel Additive

Byp. Mg + Hyd. Lime

Comm. Mg + Hyd. Lime

MgO

SBS

NH3

Humid./Lime

Hyd. Lime + Bicarb

Wet ESP

Annual Cost ($1000)

5-mos. Operation

12-mos. Operation

12-mos. Operation, New Plant
17

Step 1: Enter specific data about plant operations. 

Step 2: Estimate (or enter actual values for) flue gas flow rate, SO3 profile across the flue gas 

path, and a target stack SO3 concentration. 

Step 3: Choose a control option and complete its corresponding worksheet. Sorbent injection 

technologies and fuel additives are covered by one worksheet, fuel switching by another, and wet 

ESP by a third worksheet. Completing the specified worksheet will estimate capital and 

operating costs for the selected technology. 

Note that the calculations in the worksheets have been simplified from those used to generate the 

relative economics presented in this paper. Even the calculations in this paper do not include all 

of the details that should be considered in a site-specific engineering evaluation of control 

technologies. The results from these worksheets are meant to develop a relative ranking of 

control options for a particular plant, based on a limited set of variables that have been identified 

as significantly impacting control costs. The initial estimates developed using these worksheets 

should be useful for selecting a subset of control options that appear to be more cost effective for 

a particular plant. 

The use of these worksheets to develop initial estimates does not preclude the need to conduct a 

thorough engineering evaluation of control options to make a final selection of a control 

technology for implementation. Such an evaluation should involve developing site-specific 

capital and delivered reagent cost estimates, and might involve applying risk factors based on the 

extent of full-scale, commercial experience for each technology considered and potential sorbent 

cost volatility. 

CONCLUSIONS 

The example economics presented show that ammonia injection was projected to be a low cost 

technology, but balance-of-plant impacts may preclude its use. OmniClearTM fuel additive, MgO 

injection and SBS injection appear to be cost competitive technologies at either control level, 

although more data are needed to support the performance estimates used for the OmniClearTM

additive and MgO powder injection at high control efficiencies. Humidification combined with 

lime injection may also be a cost-competitive control approach, particularly if the two steps can 

be combined by injecting lime or limestone slurry. Variations in delivered sorbent cost from 

those assumed for this evaluation could significantly change the relative ranking of the cost 

effectiveness of these SO3 control technologies. 

Byproduct Mg injection in the furnace can be a cost-effective technology for restoring stack 

sulfuric acid mist concentrations to pre-SCR levels. For the example plant, commercial Mg 

injection in the furnace was slightly less cost effective. Neither furnace injection technology was 

estimated to be capable of achieving the higher sulfuric acid removal percentage target. Although 

it would be possible to combine furnace injection with another technology downstream to 

achieve less than 3 ppmv of sulfuric acid mist at the stack, the economics of installing two 

control technologies in series did not appear to be attractive for the set of assumptions made in 

this study. 
18

Fuel switching or blending with low-sulfur coal could be cost effective depending on the cost 

differential between the current and low-sulfur coal, and assuming only minimal capital cost 

implications. Finally, although wet ESP technology was evaluated at the highest cost in this 

comparison, its economics look better if SO3 control is required year-round rather than just 

during the ozone season. A longer capital recovery period and wet ESP integration with a new 

wet scrubber also make the economics for the wet ESP cases more competitive with the low 

capital cost, sorbent injection or additive alternatives. 

The example economics presented here underline two important observations about SO3/sulfuric 

acid controls. One is that there is no one “best” control option available. The cost effectiveness 

of the various options depend on site specifics such as the location of the plant relative to reagent 

sources, coal combustion byproduct reuse and disposal practices, the sulfuric acid mist control 

level required, and the extent to which other particulate matter contributes to plume opacity. 

Depending on these specifics, one technology may be favored over the others for a particular 

plant situation. The cost estimating workbook associated with EPRI’s SO3 Mitigation Guide 

Update provides the user with the ability to estimate relative costs for a specific plant’s 

circumstances. 

The second observation is that there are several candidate SO3/sulfuric acid control technologies 

for which there is not adequate full-scale demonstration and test data to serve as a basis for 

power generators to evaluate control technologies with confidence. For example, the fuel 

additive, MgO powder injection and humidification/lime injection technologies (combined or 

separately) show promise as being cost effective for some situations, but a well-documented, 

full-scale demonstration of each of these technologies is needed. 

Finally, it should be noted that the candidate SO3/sulfuric acid control technologies evaluated in 

this section should not be considered an all-inclusive list; the technologies evaluated here were 

limited to those for which the authors had performance and cost data available. The retrofit of 

SCR to plants that fire high-sulfur coal has created a need for retrofit SO3/sulfuric acid controls, 

and has spawned the development of new processes. Some processes were not included in this 

evaluation because not enough information was available to allow their costs to be estimated 

(e.g., condensing heat exchanger, and trona injection) and there may be others that were not 

included merely because the authors of this report are not yet aware of them. 

REFERENCES 

1. “OmniClear, A new alternative for sulfur trioxide control.” Document provided by Omni 

Materials, Inc., Maysville, KY, 2003. 

2. Blythe, G., R. McMillan, J. Davis, M. Lamison, R. Rhudy, J. Beeghly, L. Benson, and E. 

Goetz. “Furnace Injection of Alkaline Sorbents for Sulfuric Acid Control,” paper presented at 

the US EPA/DOE/EPRI Combined Power Plant Air Pollutant Control Symposium, The Mega 

Symposium, Chicago, IL, 20-23 August 2001. 
19

3. Sulfuric Acid Removal Process Evaluation: Long-term Results. EPRI, Palo Alto, CA, U.S. 

Department of Energy, National Energy Technology Laboratory, Pittsburgh, PA, TVA, 

Chattanooga, TN, American Electric Power, Columbus, OH, and FirstEnergy, Shippingport, 

PA, 1004165, 2002. 

4. Martin Marietta Specialty Chemicals promotional sheet for Utilimag 40. 

5. Results of Full-Scale Testing of Sodium Bisulfite Injection for Flue Gas Sulfuric Acid Control. 

EPRI, 1004167, December 2002. 

6. Peterson, J.R. A.F. Jones, F.B. Meserole, and R.G. Rhudy. “SO3 Removal from Flue Gas by 

Sorbent Injection, EPRI HSTC Phase II Test Results,” paper presented at the SO2 Control 

Symposium, Boston, MA, 24-27 August 1993. 

7. Monroe, L.S. and K.M. Cushing. Wet Electrostatic Precipitator Addition to the Outlet of a 

Marginal Dry ESP. Final Report for EPRI Contract WO3453-04. Palo Alto, CA. 1996. 

8. SO3 Mitigation Guide Update. EPRI, 1004168, March 2004. 

9. Benson, L.B., K.J. Smith, and R.A. Roden. “Control of Sulfur Dioxide and Sulfur Trioxide 

Using By-Product of a Magnesium-Enhanced Lime FGD System,” paper presented at the 

Institute of Clean Air Companies (ICAC) Forum 2003: Multi-Pollutant Emission Controls & 

Strategies. Nashville, TN, 12-15 October 2003. 

10. Reynolds, J., W. Buckley, and I. Ray. “Advances in wet electrostatic precipitation 

technology at fossil fuel power plants for multi-pollutant control,” paper presented at the 

Institute of Clean Air Companies (ICAC) Forum 2003: Multi-Pollutant Emission Controls & 

Strategies. Nashville, TN, 12-15 October 2003. 

11. Staehle, Richard C., Ronald J. Triscori, K. Sampath Kumar, Gary Ross, and Randy Cothron. 

“Wet Electrostatic Precipitators for High Efficiency Control of Fine Particulates and Sulfuric 

Acid Mist,” paper presented at the Institute of Clean Air Companies (ICAC) Forum 2003: 

Multi-Pollutant Emission Controls & Strategies. Nashville, TN, 12-15 October 2003.