## SO 3 

## 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

SO 3 or sulfuric acid in flue gas is an issue for plants that fire medium - to high-sulfur coals, particularly those with SCR for NO X control, because of adverse effects such as duct corrosion, air heater plugging and elev ated plume opacity. EPRI has recently published an updated SO 3 Mitigation Guide that discusses the state of the art for measuring and controlling SO 3 emissions from coal-fired plants. Included in the guide are cost estimates for ten different SO 3 control technologies as applied to an example plant, and a cost estimating workbook that allows the report user to develop site sp ecific estimates for candidate cont rol 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 technolog ies for comparison. Sensitivity case estimates are also presented showing the effects of delivered reagent costs, SO 3 control system operating period (ozone season only versus year-round) , and new versus re trofit installations.



### INTRODUCTION

A wide range of SO 3 or sulfuric acid controls have been tested and/or applied for coal-fired power plants, such as low-sulfur-c oal switches, injecting alkaline sorbents at various locations in the furnace or ductwork, and insta lling wet ESPs. The costs of applying these technologies can vary over a wide range, and each has positive and ne gative attributes that could make it more or less favorable for application at a given power plant. This paper describes a number of

SO 3 /sulfuric acid control technol ogies and presents estimated costs for applying these technologies at an example plant that is being retrofitted with SCR for NO X control.

Figure 1 shows the flue gas path of a typical coal-fired power plant, and illustrates where a
number of candidate SO 3 /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 SO 2 content of the flue gas, which reduces the
concentration of SO 3 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 SO 2 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 SO 3 /Sulfuric Acid Control Options

Notwithstanding capital expenses that may be required, the economics of coal switching aredriven 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 thousa nd dollars or more.



### Fuel Additive

Omni Materials, Inc., of Mt. Carmel, Illinois has developed a proprietary fuel additive for coalbased applications, OmniClear TM . Based on information provided in company literature, the additive is apparently ground dol omite (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

SO 2 /MM Btu). An additive rate of approximately 0.5 to 1.0 wt% of th e coal feed rate reportedly
lowered SCR outlet SO 3 concentrations from 50 to 65 ppm to about 5 ppm at the ESP outlet. This equates to appr oximately 90 to 92% SO 3 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 SO 3 to produce magnesium sulfate solids. These solids are removed in the downstream par ticulate control device. Testin g co-funded by EPRI focused on the injection of magnesium hydroxide slurries in to coal-fired furnaces to achieve 90+% removal
of furnace-formed SO 3

. 2 For plants without SCR, furnace Mg injection is capable of high SO 3 - Byproduct Mg Injection

FGD Absorber To
Stack

Air Heater Economizer

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

Air Heater Economizer

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

Air Heater Economizer

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

conversion3 removal percentages, but SO 3 removal may be limited by the performance of downstream coldside ESPs. At high SO 3 removal percentages, the loss of su lfuric 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 SO 3 concentrations in the SCR inlet flue gas, which can allow SCR operation at lower load without capilla ry condensation of ammonium bisulfate in catalyst pores. However, furnace Mg injection does not appear to be effective at removing SO 3 formed across the SCR catalyst. 3

With or without SCR, furnace Mg injection shoul d 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 poten tial benefits of SO 3 removal upstream of the air heater on plant heat rate are mentioned several places in this paper, and warrant ex planation. Most coal-fired power plants have steam or glycol heaters to preh eat 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, th e air heater outlet flue gas temperature is typically controlled to minimize a dverse effects of sulfuric acid condensation, such as plugging and/or corrosion in the air heater, or dow nstream corrosion. Lowering the flue gas SO 3 concentration upstream of the air heater, such as by furnace Mg in jection, 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 co mbustion 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 inj ection technologies for downstream of the SCR and upstream of the air heater: MgO powder injec tion and sodium bisulfite/sulfite solution (SBS) injection. These
alkalis react with SO 3 to form salts that are removed in th e particulate control device. Since these technologies can remove SO 3 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 Mar tin Marietta, but othe r 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 SO 3 removal efficiency (>80%) with near stoichiometric amounts of MgO being injected. 4

The SBS Injection TM process is patented by Codan Deve lopment LLC and available by license. SBS solution, a byproduct from sodium-based FGD systems, or commercia lly available sodium
sulfite or bisulfite can be used as a feed ma terial. 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:SO 3 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 th e air heater outlet duct were evaluated in the economic comparison, hydrated lime injecti on 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 Ce nter (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, sodi um bicarbonate, or othe r dry alkaline powders into the ductwork between the air heater and pa rticulate control device, primarily a cold-side

ESP.

Ammonia injection has been tested by many a nd has been implemented at some plants for sulfuric acid control. Ammonia can be injected between the air heater and cold-side ESP at

NH 3 :SO 3 mole ratios in the range of 1.5:1 to 2:1 to achieve high sulfuric acid removal levels (upwards of 95%). The biggest i ssue for ammonia injection is its effect on fly ash disposal/reuse.



### Flue Gas Humidifica tion, With or Without Alkali Injection

In this technology, also tested by EPRI at th e ECTC, the flue gas is partially hu midified and cooled to below its acid dew point. The sulfuric acid appears to be re moved 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 se veral 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 tendenc y 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 near ly 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 c ontinuously, and the blow down can go to an FGD
system or to a separate system for treatment. To achieve high su lfuric acid removal efficiencies (>80%), the wet ESP could be installed downstream of the we t FGD absorber or could be
installed inside the absorber vessel as a replacement for the ch evron-style mist eliminator. For lower efficiencies (~60%) it is po ssible to convert the last field of a conventional dry ESP to wet operation. 75 By being installed at or near the end of the fl ue gas path, wet ESPs ty pically address only plume opacity and particulate emissi ons, and provide no upstream be nefits for air heater exit temperatures or duct corrosion.



### EXAMPLE PLANT FOR ECONOMIC STUDY

Cost estimates were prepared for applying a numbe r of sulfuric acid c ontrol technologies to a hypothetical or example power plan t. The plant consists of a single, 500-MW unit located in the Midwest, and firing a 3.5% sulfur bituminous co al. The plant is retrofitting an SCR system for

NO X control, and currently has a cold-side ESP fo r particulate control and a wet FGD system for

SO 2 control. The FGD system uses limestone r eagent and produces wallboard-grade gypsum, which is sold as a byproduct. The fly ash is ha ndled 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 materi al 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 10 6
Coal Sulfur Content (%) 3.5

Flue Gas SO 2 Content (ppmv wet at economizer outlet) 2790

Furnace Conversion of SO 2 to SO 3 (mole %) 1.0

Conversion of SO 2 to SO 3 Across SCR Catalyst (mole %) 0.75

Stack Sulfuric Acid C oncentration during SCR Operation (ppmv) 21

NO

x Season Duration (months/yr) 5 Target Stack Sulfuric Acid C oncentration (ppmv, dry basis):

For lower SO 3 removal percentage target 9.5 (return to pre-SCR conditions) For higher SO 3 removal percentage target 3.0 (assumed value corresponding to “clear” stack)

The plant has a wall-fired, pulverize d coal boiler that typically conve rts 1% of the coal sulfur to

SO 3 . The SCR catalyst guarantee is for no more than 0.75% conversion of SO 2 to SO 3 across the installed catalyst layers. Figure 2 summarizes the assumed baseline SO 3 /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 approximate ly 6 ppmv of SO 3 /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 SO 3 /Sulfuric Acid Concentrati ons 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 project ed value of 21 ppmv with the SCR in service. A sensitivity case also looked at costs for achieving a higher level of SO 3 control, down to 3 ppmv (dry basis) or less at the stack. This lower concentration should be ad equate to result in a clear stack, or low stack plume opacity (at leas t due to the sulfuric acid mist contribution to plume opacity) under most conditions. The SCR wa s assumed to operate only during the “ozone season,” from May 1 through September 30, and it was assumed the sulfur ic acid controls will only be required to operate during that time period as well. Other sensitivity cases considered both a new and retrofit plant in stallation where the SCR and SO 3 controls operate year-round.

As a first step in developing cost estimates for the various potential sulfuric acid controls, heat (enthalpy) and material bala nce calculations were conducted to estimate the expected SO 3 / sulfuric acid control performance of each tec hnology, 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 materi al balances are provided in the

EPRI SO 3 Mitigation Guide Update. 8

Cost estimates were not developed for ammonia injection at the lower SO 3 removal percentage.
When the NH 3 :H 2 SO 4 molar ratio is low, ammonia inj ection can cause operating problems via the formation of a sticky ammonium bisulfate.

Two technologies, byproduct Mg in jection and commercial Mg injec tion 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 ha ve operated or are planni ng to operate with a combination of furnace Mg injection and hydrated lime injection upstream of the ESP to achieve Air Heater Economizer

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/SCR7 relatively high control efficienci es. Consequently, this combina tion 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 t echnologies under consideration. Spr eadsheets 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 gene ral budgetary cost factors. A capital cost factor of $35/kW was used for a last-field dry ESP conversion for the lower SO 3 removal case, and a factor of $55/kW for sta ndalone 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 mate rials 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 technolog y can be very site specific.

The reagent and utility consumption estimates and the amortized capital cost estimates were combined to generate annual co st estimates for each of the tec hnologies. These estimates were
not “levelized” to reflect escalati on and discount rates, but instead represent first-year costs. Nor do they include operating labor, nor maintenance labor and ma terials. 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 averag e 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 “t ypical” values taken from previous economic evaluations conducted by URS for power plants east of the Mississippi River. The values for gypsum byproducts, fly ash byproduc t sales and incremen tal landfill disposal costs represent the nominal averages (rounded to the nearest whole do llar) 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 achievi ng 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 mes h, 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 so lids, assumed 50-mile delivery distance) 151

Commercial Mg(OH) 2 slurry, delivered from Mani stee, 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 Rive r, WY ($/dry ton available Na as Na 2 SO 3 ) 300 Ammonia, delivered from exis ting plant system ($/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

SO 3 /Sulfuric Acid Control Technol ogy for Achieving the Lower Removal Percentage Target

0 500 1000 1500 2000 2500

Fuel Ble

nd

Fue l Ad

d itive

B yp.

Mg Comm. Mg MgO SB S NH3

H umi

d.

/ L ime Hyd. Li

m

e

W et

ES

PAnnual Cost ($1000) Capital Recovery

Reagent and Utility Costs 2,7459 For the lower sulfuric acid control percentage pl ot, five control options had projected reagent, utility, and capital recovery costs in th e range of $460,000 to $670,000 annually. The five include the fuel additive, furnace injecti on of byproduct Mg, MgO powder injection, SBS Injection TM , and ammonia injection (at the higher removal level).

The differences between the projected costs of thes e four control options are not great relative to the level of uncertainty for th ese 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. Th is suggests that a more detailed analysis would be required to determine the most cost e ffective 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-su lfur 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 th is 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 lowe r 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, respectivel y. However, the wet ESP comparison is skewed by the assumption that the control technol ogies will only operate fi ve 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 technolog y, with projected first-year costs of $640,000, followed by the OmniClear TM fuel additive at $790,000 annually. Three other technologies, MgO powder injection, SBS injec tion and humidification with hydrated lime injection, show somewhat higher annual projected costs between $920,000 and $980,000. Again,

if these annual cost estimate s 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

SO 3 /Sulfuric Acid Control Technol ogy for Achieving the Higher Removal Percentage Target

Four other technologies show considerably hi gher 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 bl end injection alone. Note that the latter three technologies might adversely affect the base plant ESP performance due to th e 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 sy stem shows the highest first-year cost of over $4 million. However, as men tioned 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 SO 3 /sulfuric acid control technolog ies 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 SO 3 /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/injec tion technologies), months per year of control system operation, and new versus retrofit applications – impac t the relative economics of SO 3 control. Sensitivity cases for each of these pa rameters are presented and discussed below.

Of course, additional parameters impact the relative economics of SO 3 control, such as the size of the plant being controlled, what type of existin g control device is used for particulate control, 0 500 1000 1500 2000 2500

Fuel Bl

end Fuel A

dd

i t i ve Byp. Mg + Hyd. Lim e Comm. Mg + Hyd. L i me MgO SB S NH 3

Hum i d.

/Li

m

e

H

y d.

Li

me +

B

icar b We t E SPAnnual Cost ($1000) Capital Recovery

Reagent and Utility Costs 4,19111 whether the plant has an FGD system and what reag ent is used, whether or not the plant sells its fly ash and/or FGD byproduct, a nd many others. It is beyond th e scope of the guide and this paper to show cost sensitivities to all of these parameters, ev en though many of them can significantly impact SO 3 control economics. The reader can refer to the SO 3 control cost workbooks published in EPRI’s SO 3 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 re latively low (less than $10/kW). There is uncertainty in the delivered cost s of all of these sorbents. Since the sorbents are typically available at a disc rete 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 ba rge delivery is employed.

The f.o.b. price of the sorbents could also vary si gnificantly. The factors that drive the costs of several potential sorbents are described below:

OmniClear TM fuel additive – This sorbent/fuel additive is cu rrently 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 commercia lly, 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 st rongly influenced by market supply/demand

pressures.

SBS – Either sodium sulfite or s odium bisulfite, or a blend of the two, could be used as the reagent for this technology. Either reagent coul d 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 em ployed, 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 che micals used in high volumes in the U.S. The costs for these reagents are driven by suppl y and demand pressures, a nd by the price of raw materials, and can fluctu ate over a wide range.

Hydrated Lime – Hydrated lime is available from a numbe r 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 price12 of $75/ton was used as the basis for these cost estimates, quicklime can be purchased for about $50/ton and contains about 30% mo re alkali on a molar basis, maki ng 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 quick lime 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 cost s 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 ma jority of the injection technology costs, this could greatly influence the annual reagent, utility , and capital cost recove ry 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 ex cept ammonia injection and humidification with hydrated lime injection, sorbent delivered cost va riations 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 fi ve candidate sorbent inj ection technologies that
were estimated to have lo wer annual costs earlier in this paper, an increase in sorbent cost for
one coincident with a decrease for another coul d markedly change the ranking of injection technology costs.

Figure 5: Effect of Sorbent Delivered Price Variations on Control T echnology Cost Estimates (includes reagent, utility and capital recovery costs)

0 500 1000 1500 2000 2500 3000 3500

Fuel Addi t i v e Byp. Mg + H y d

.

Lime

Co

m

m.

Mg + H

y d

.

L ime MgO SBS NH3 Humid./ L ime

Hyd. Lime + BicarbAnnual Cost ($1000) -50% Reagent Cost
Estimated Reagent Cost
+50% Reagent Cost13 These results illustrates that, before selecting an SO 3 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 presente d earlier in this sec tion 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 opera te only during that period as well. However, some plants will have to opera te their SCR year-round, and/or will have to operate their SO 3 control technology year-round once installed. A ch ange to year-round operation will improve the
relative economics of tec hnologies whose costs are driven mos tly by capital recovery (e.g., wet ESP) and could erode the economic s 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 woul d be more complex if the SCR operated 5
months while the control technol ogy operated 12 months, as ther e would be different baseline

SO 3 concentrations and different SO 3 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 Fi gure 6 to show the effect of 12-month versus 5- month operation on the rela tive economics of the SO 3 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 estima ted at less than $1 million annua lly for 5-months operation,ammonia injection remains the lowest estimated cost option (notwithstanding other balance-ofplant issues) but the relative rankings of the othe r 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 lowe st (behind ammonia inj ection) for 12-months operation. Conversely, the fuel additive process go es from being the second least costly to the most costly of the five at 12-months operation.14 Figure 6: Comparison of Firs t-year Capital Recovery and Non-labor Operating Costs by

SO 3 /Sulfuric Acid Control Technolog y 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

SO 3 control technologies is the assumption that th e controls are being retrofit to an existing scrubbed plant. If it is instead a new plant, th ere are at least two impacts on the cost estimates. One is that a longer plant life would be assume d and hence a lower capital recovery factor would be applied. The second is that, for the wet E SP case, the wet ESP desi gn 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 a nnual cost estimates for candidate SO 3 control technologies for the higher SO 3 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 di scount rate, 20-year vers us 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 integr ated into the FGD module design. 10,11 0 1000 2000 3000 4000 5000 6000

Fuel Blend

F u el Additive

B

yp

. Mg + Hyd. L i me Comm. Mg + Hyd. Lime MgO S B S N H 3

H umid./L i me

Hyd. Lim e + B i carb

W et ESPAnnual Costs ($1000) 5-mos. Operation
12-mos. Operation15 Figure 7: Summary of First-year Capital Recovery and Non-labor Operating Costs by

SO 3 /Sulfuric Acid Control Technol ogy for Achieving the Higher Removal Percentage Target (New plant, 12-month operating period).

Figure 8 compares annual cost estimates for all three estimate base s (5-months operation, 12- months operation, and 12-months operation for a ne w 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, th e 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 particul ate 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, coul d vary significantly over the life of the plant.

On the other hand, the sorbent inj ection technologies that remove SO 3 from the flue gas upstream of the air heater could be expl oited to further improve the plan t 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 Addit i ve

Byp. M

g

+

Hyd. Lime

Com m

. Mg + Hyd. Lime MgO SBS N H3

H

u m

i d.

/ Li

me

H

y d.

Li

m

e

+

Bi

ca

r b Wet ESPAnnual Cost ($1000) Capital Recovery

Reagent and Utility Costs 564016 Figure 8: Comparison of Firs t-year Capital Recovery and Non-labor Operating Costs by

SO 3 /Sulfuric Acid Control Technol ogy for Achieving the Higher Removal Percentage Target



### SO 3 

### CONTROL PROCESS ECONOMICS WORKBOOK OVERVIEW

The example economics shown above illustra te that the most cost effective SO 3 control technology can be very site specific, dependi ng 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 co sts for implementing these technol ogies at the user’s coal-fired plant. The workbook is part of the EPRI SO 3 Mitigation Guide Update (TR-1004168). The purpose of the workbook is to allow the reader to calculate the approx imate capital and annual reagent and utility costs associated with each of the possible SO 3 control options for a particular plant. The control options that are covered by th is workbook include wet ESP, fuel blending, fuel additives, and a number of sorb ent injection technologies.

The workbook is oriented towards plants that fi re eastern bituminous coals, because eastern bituminous coals typically have higher sulfur c ontent than western coals and there is little data available for other coal types. The workbook c onsiders the effect of Powder River Basin subbituminous coal, but only as a low-sulfur blendi ng 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 SO 3 /sulfuric acid concentrations to cause pl ume opacity issues, as some could be considered medium- to high-sulfu r coals on the basis of pounds of SO 2 produced per million Btu of heat input. Consequently, the workbook also includes some calculati ons oriented towards Texas lignite. However, the user is cautioned that no data were ava ilable for evaluating SO 3 control technologies for Texas lign ite applications, so there are so me 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

F uel

Ble

nd Fuel Additive Byp. Mg + Hyd. Lime

Co

m m. Mg + Hyd. Lime M g O SBS NH3 Humid

. /Lime

Hyd

. L ime + Bicarb

W et

E SPAnnual Cost ($1000) 5-mos. Operation 12-mos. Operation 12-mos. Operation, New Plant17 Step 1: Enter specific da ta about plant operations.

Step 2: Estimate (or enter actual values for) flue gas flow rate, SO 3 profile across the flue gas path, and a target stack SO 3 concentration.

Step 3: Choose a control option and complete its corresponding worksheet. Sorbent injection technologies and fuel additives ar e 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 engineerin g 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 subs et 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 opti ons to make a final se lection of a control technology for implementation. Such an evalua tion should involve deve loping site-specific capital and delivered reagent cost estimates, and might involve appl ying 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 imp acts may preclude its use. OmniClear TM fuel additive, MgO injection and SBS injection appear to be cost competitive technolog ies at either control level, although more data are needed to support th e performance estimates us ed for the OmniClear TM
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 signifi cantly change the relative ranking of the cost
effectiveness of these SO 3 control technologies.

Byproduct Mg injection in the furnace can be a cost-effective technolog y 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 e ffective. Neither furnace injection technology was estimated to be capable of achieving the higher sulfuric acid removal per centage target. Although it would be possible to combine furnace injec tion 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 economic s look better if SO 3 control is required yea r-round rather than just during the ozone season. A longer capital recovery period and wet ESP in tegration with a new
wet scrubber also make the ec onomics for the wet ESP cases more competitive with the low capital cost, sorbent injection or additive alternatives.

The example economics presented here under line two important observations about SO 3 /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 dis posal 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 SO 3 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 SO 3 /sulfuric acid control technologies for which there is not adequate full-scale demons tration and test data to serve as a basis for power generators to evaluate control technologies with confid ence. For example, the fuel additive, MgO powder injection and humidifica tion/lime injection tec hnologies (combined or separately) show promise as be ing cost effective for some s ituations, but a well-documented,
full-scale demonstration of each of these technologies is needed.

Finally, it should be noted that the candidate SO 3 /sulfuric acid control t echnologies evaluated in
this section should not be considered an all-in clusive list; the technologie s 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 SO 3 /sulfuric acid controls, and has spawned the development of new processes. Some proce sses were not included in this evaluation because not enough information was av ailable to allow their costs to be estimated (e.g., condensing heat exchanger, and trona injec tion) 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 tr ioxide control.” Document provided by Omni Materials, Inc., Maysville, KY, 2003.

2. Blythe, G., R. McMillan, J. Davis, M. Lamis on, 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, Nati onal Energy Technology Laboratory, Pittsburgh, PA, TVA, Chattanooga, TN, American Electric Power, Co lumbus, OH, and FirstEnergy, Shippingport, PA, 1004165, 2002.

4. Martin Marietta Speci alty Chemicals promoti onal sheet for Utilimag 40.

5. Results of Full-Scale Testing of Sodium Bisulfite Injection for Fl ue Gas Sulfuric Acid Control. EPRI, 1004167, December 2002.

6. Peterson, J.R. A.F. Jones, F.B. Meserole, and R.G. Rhudy. “SO 3 Removal from Flue Gas by Sorbent Injection, EPRI HSTC Phase II Te st Results,” paper presented at the SO 2 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 Contr act WO3453-04. Palo Alto, CA. 1996.

8. SO 3 Mitigation Guide Update . EPRI, 1004168, March 2004.

9. Benson, L.B., K.J. Smith, and R.A. Roden. “Cont rol of Sulfur Dioxide and Sulfur Trioxide Using By-Product of a Magnesium-Enhanced L ime FGD System,” paper presented at the Institute of Clean Air Companies (ICAC) Fo rum 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 mu lti-pollutant control,” pa per presented at the Institute of Clean Air Companies (ICAC) Fo rum 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 Efficien cy Control of Fine Par ticulates and Sulfuric Acid Mist,” paper presented at the Institute of Clean Air Companies (ICAC) Forum 2003:
Multi-Pollutant Emission Controls & Stra tegies. Nashville, TN, 12-15 October 2003.