ELECTRIC POWER RESEARCH INSTITUTE 3420 Hillview Avenue, Palo Alto, California 94304-1338 ▪ PO Box 10412, Palo Alto, California 94303-0813 ▪ USA 800.313.3774 ▪ 650.855.2121 ▪ askepri@epri.com ▪ www.epri.com 

## Estimating Total Sulfuric Acid Emissions **from Stationary Power Plants**

**1016384**

Effective February 7, 2008 , this report has been made publicly available in accordance with Section 734.3(b)(3) and published in accordance with Se ction 734.7 of the U.S. Export Administration Regulations. As a result of this publication, this r eport is subject to only copyright protection and does not require any license agreement from EPRI. This notice supersedes the ex port control restrictions and any proprietary licensed material notices embedded in the document prior to publicationELECTRIC POWER RESEARCH INSTITUTE 3420 Hillview Avenue, Palo Alto, California 94304-1338 ▪ PO Box 10412, Palo Alto, California 94303-0813 ▪ USA 800.313.3774 ▪ 650.855.2121 ▪ askepri@epri.com ▪ www.epri.com 

## Estimating Total Sulfuric Acid Emissions from Stationary Power Plants

1016384
Technical Update, March 2008

EPRI Project Manager

Naomi Goodman**DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES** 

THIS DOCUMENT WAS PREPARED BY THE ORGANI ZATION(S) NAMED BELOW AS AN ACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTR IC POWER RESEARCH INST ITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE ORGANIZATION(S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM:
(A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED, (I) WITH RESPECT TO THE USE OF ANY INFORMATION, APPAR ATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT, INCLUDING ME RCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, OR (II) THAT SUCH USE DOES NOT INFR INGE ON OR INTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY'S INTELLECTUAL PROPERTY, OR (III) THAT THIS DOCUMENT IS SUITABLE TO ANY PARTICULAR USER'S CIRCUMSTANCE; OR
(B) ASSUMES RESPONSIBILITY FOR ANY DAMAGE S OR OTHER LIABILITY WHATSOEVER (INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRI OR ANY EPRI REPRESENTATIVE HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES) RESULTING FROM YOUR SELECTION OR USE OF THIS DOCUMENT OR ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT.
ORGANIZATION(S) THAT PREPARED THIS DOCUMENT
**J. E. Cichanowicz, Inc.**

**This is an EPRI Technical Update report. A Technical Update report is intended as an informal report of continuing research, a meeting,**  **or a topical study. It is not a final EPRI technical report.**

**NOTE**

For further information about EPRI, call the EPRI Cust omer Assistance Center at 800.313.3774 or e-mail askepri@epri.com.

Electric Power Research In stitute, EPRI, and TOGETHER

... SHAPING THE FUTURE OF ELECTRICITY are registered service marks of the Electric Power Research Institute, Inc.
Copyright © 2008 Electric Power Research Institute, Inc. All rights reserved.iii 

## CITATIONS
This document was prepared by
J.E Cichanowicz, Inc. P.O. Box 905 Saratoga, CA 95071 Principal Investigator E. Cichanowicz This document describes research sponsored by the Electric Power Research Institute (EPRI). This publication is a corporate doc ument that should be cited in the literature in the following

manner: Estimating Total Sulfuric Acid Emis sions from Stationary Power Plants, EPRI, Palo Alto, CA: 2008. 1016384.v 

## PRODUCT DESCRIPTION

This report provides a methodolog y to estimate sulfuric acid e missions from fossil-fuel-fired electrical power production faci lities. The methodology was de veloped by Southern Company Services (SCS) and modified by EPRI with permission from the developers. The calculations presented in this report allow owners of power pl ants to estimate the sulfuric acid manufactured during fuel combustion, removed by air pollution control equipment or flue gas treatment, and released to the environment in stack gases.

**Results and Findings** The power generation units considered in the re port include coal- and oil-fired steam generating units as well as simple-cycle and combined-cycle natural gas- and oil-fired combustion turbines. Calculation procedures are pr ovided for estimating removal or production of sulfuric acid by pollution control devices and flue gas treatments.

**Challenges and Objectives** Sulfuric acid releases from electric power generating units must be reported to EPA on an annual basis if the amounts manufactured, processed, or otherwise used exceed the limits set by the EPA’s Toxics Release Inventory (TRI) program.
**Applications, Value, and Use** This report will be useful to environmental sta ff of power generation facilities responsible for TRI reporting.
**EPRI Perspective** The methodology presented in this report is used by many power generation facility owners to estimate sulfuric acid emissi ons. There is currently no other published approach with a comparable amount of supporting measurement s. EPRI will continue to enhance the methodology by adding to the underlying database and refining the calculations to address new flue gas treatment approaches.
**Approach** The manufacture and release of sulfuric acid from coal-, oil-, and natural gas-fired electrical generation units were estimated from field test data. Measurements from mult iple facilities were used to develop sulfuric acid removal factors for va rious coal types and fac ility configurations.
**Keywords** Sulfuric acid Toxics Release Inventory Air emissionsvii 

## ACKNOWLEDGEMENTS

The methodology described in this document wa s developed by Southern Company Services and modified, with permission, by EPRI. Individuals r esponsible for the devel opment of the original Southern Company sulfuric acid model are Keith E. Harrison and Larry S. Monroe, Ph.D. of the Southern Company. April Freeman of Southern Company also provided review and input into this version of the model.ix 

## EXECUTIVE SUMMARY

The U. S. Environmental Protection Agency’s (EPA’s) Toxic Release Inventory (TRI) reporting system requires that, beginning in 1998, electric utilities estimate thei r emissions of over 600 chemicals. Sulfuric acid (H 2 SO 4 ) is one of the chemicals included in the TRI reporting requirement, when it is present in an aerosol form. The EPA defines sulfuric acid aerosols as “includ[ing] mists, vapors, gas, fog, and other air borne forms of any partic le size.” Sulfuric acid aerosol is formed during combustion of fossil fuels when sulfur trioxide (SO 3 ) in hot combustion gases combines with water to form sulfuric acid, and then cools and condenses to form small droplets of the acid. This document provides a methodology to estimate sulfuric acid emission s from fossil-fuel-fired electrical power production facilities. The method ology described in this report was developed by Southern Company Services (SCS). Between 2000 and 2005, SCS developed several versions of the estimation methodology and released draft reports on request. The SCS model is widely used in the electrical power ge neration industry for TRI reporting and other emissions estimation purposes. In 2007, EPRI received permission from S outhern Company Services to modify the SCS estimation method to include additional data and improvements, and to publish this method under EPRI sponsorship. The 2008 version of this report contains several updates from EPRI’s 2007 version. The basic method for estimating sulfuric acid emi ssions remains unchanged from that described by SCS (2005). First, the method estimates manufacture of SO 3 and sulfuric acid from three sources: (1) combustion of fuel, (2) the NOx c ontrol process selective ca talytic reduction (SCR), and (3) flue gas conditioning (FGC), in which SO 3 is added to flue gas to improve particulate control device performance. Ne xt, the actual release of SO 3 or H 2 SO 4 is calculated by adjusting the manufacturing estimate to account for processes known to remove SO 3 and H 2 SO 4 . These include a byproduct reaction of SCR, as well as the NOx control process of selective noncatalytic reduction (SNCR), and othe r types of FGC. This paper does not currently consider other developing SO 3 /H 2 SO 4 removal technologies such as the various types of sorbent-based approaches that employ calcium-based, sodiu m-based, or other reagents, as described by Dombrowski (2004) and Weilert (2004).

The current estimation method is based on an ever-growing database of measurements of SO 3 emissions from combustion systems, primarily coal-fired boilers. The 2008 version of the model is based on data from over 40 coal-fired units, representing various boiler types and coal sources. The estimates of SO 3 production from combustion of coal are consistent with theoretical predictions that approximat ely 1% of the sulfur in coal is converted to SO 3 , although a wide range of conversions from 0.2% to 1.6% is re ported, depending on coal source and boiler type. Data are obtained from field t ests, reporting the removal of SO 3 or H 2 SO 4 by air heaters, particulate control equipment such as electrostatic pr ecipitators (ESPs) and fabric filters, and SO 2 control equipment. The removal data are used to develop “technology factors” that represent the amount of sulfuric acid that passes through, but is not captured by, each pollution control device. The technology factors are used to estimat e quantities released to the air.x The current update does not incorporate any new measurement data of SO 3 emissions. However, this version adds the capability to account for alkali injection, an expanding technique to control SO 3 emissions. As with all estimation procedures, the methodo logy described in this report and the factors developed from the current database will not be appli cable to every facility configuration or fuel type. Site-specific measurements of SO 3 or H 2 SO 4 emissions from a power facility, when available, should always be used in place of the estimates derived with this method.xi 

## ERRATA

Please make the following corrections to the text: Page 4-14
Equation 1-12 ER ALKINJ = K alkali • B • S SO3 • F2

x • F alkali K alkali = Constant, equal to 3,799

The conversion factor K alkali , equal to 3,799, considers all relevant constants to yield the result in pounds per year of sulfuric acid.
**Page 4-15**

Text Box E: Derivation of Conversion Factor, K alkali . The U.S. Code of Federal Regulations 40, Part 60, Table 19-1 “F Factors for Various Fuels” lists that 1 million Btu of heat input for bituminous or subbituminous coal will produce 10,640 wet standard cubic feet of flue gas, defined at 0% oxygen and on a wet basis at 20oC and 760 mm Hg. Correcting this volume to 6% O 2 (typical at ESP conditions) yields a volume of 14,925 scf. The standard volume of one pound mole of any gas is 359 scf, defined at 0oC and 760 mm Hg. Converting this to the English units standard of 20oC (68°F), one pound mole occupies 385 standard cubic feet. Using these in the equation above,
(K alkali • B • S SO3 ) = lbs H 2 SO 4 per yr =

B TBtu S SO3 scf SO 3 1 lb mol H 2 SO 4 98 lbs H 2 SO 4 10 6 MBtu 14,925 scf flue gas
year 10 6 scf flue gas 385 scf H 2 SO 4 1 lb mol H 2 SO 4 1 TBtu 1 MBtu

Grouping terms,

= B • S SO3 • 3,799
Therefore, the value of K alkali is equal to 3,799 lbs H 2 SO 4 /(TBtu • ppmv SO 3 @ 6% O 2 and wet).
If the value of SO 3 is known in wet flue gas at an O 2 content other than 6%, or an H 2 O content other than 8.1%, first convert the SO 3 concentration to a 6% O 2 , 8.1% H 2 O wet flue gas basis. The conversion of SO 3 at any flue gas O 2 content to the value at 6% O 2 and 8.1% H 2 O wet basis uses the following formula:
SO 3 (6% O 2 , 8.1% H 2 O)

= S SO3 (measured O 2 , H 2 O) • [(100-8.1)/(100-measured H 2 O)] • [(20.9 – 6.0)/(20.9 – measured O 2 )]xii Page A-4 The 25,000 lbs/yr threshold has been exceeded; ther efore, a release estimate must be made and the result reported on Form R.

Released

The total sulfuric acid released is based on the maximum value allowed by alkali injection, as measured in the stack, and the volume flow rate of combustion products processed.

The concentration of SO 3 measured at the stack can be converted to a mass emission rate, as described by Equation 4-12

ER ALKINJ = K alkali • B • S SO3 • F alkali • F2

x where,

ER ALKINJ = Total H 2 SO 4 released from unit equipped with alkali injection, lbs per year

K alkali = Constant, equal to 3,799, with units of lbs H 2 SO 4 /(TBtu ppmv SO 3 ) (SO 3 measured at @ 6% O 2 and 8.1% H 2 O) B = 27.05 TBtu/yr, for the specific case of Example 1

S SO3 = SO 3 content as measured in the stack or pa rticulate collector exit, corrected to a concentration basis of ppmv at 6% O 2 , 8.1% moisture

F alkali = fraction of operation with alkali addition to remove SO 3 . F2

x = 1 (as the SO 3 measurement is in the stac k, there are no control technology components downstream of the measurement)

The conversion factor K alkali is equal to 3,799 (see Text Box E). Th is constant is derived for the case where flue gas SO 3 is reported in terms of 6% oxygen and wet flue gas at 8.1% H 2 O.

The SO 3 concentration of 5 ppm in the stack is measure d at slightly different conditions of excess O 2 and moisture, compared to the reference conditions of 6% O 2 , at 8.1% H 2 O.

S SO3 (6% O 2 , 8.1% H 2 O) = S SO3 (measured O 2 , H 2 O) • [(100-8.1)/(100-measured H 2 O)] • [(20.9 – 6.0)/(20.9 – measured O 2 )]

S SO3 (6% O 2 , 8.1% H 2 O) = 5 • [1.0077) • [1.034]

S SO3 (6% O 2 , 8.1% H 2 O) = 5.2 ppm The coal burn rate in TBtu/yr is obtained from coal use records.

ER ALKINJ = [3,799] • [27.05] • [5.2] • [1] • [1]

ER ALKINJ = 534,367 lbs/yr

TSAR = ER ALKINJ TSAR = 534,367 lbs/yrxiii 

## CONTENTS

**1 INTRODUCTION ..................................................................................................................** 

**.. 1-1**  Background.....................................................................................................................

..... 1-1 Objective ......................................................................................................................

........ 1-1

**2**

**MEASUREMENT UNCERTAINTY ......................................................................................... 2-1**  SO 3 /H 2 sO 4 Measurement Accuracy...................................................................................... 2-1 Correlation Representativeness........................................................................................... 2-2

**3**

**BACKGROUND AND METHODOLOGY OVERVIEW........................................................... 3-1**  Factors Affecting Manufacture and Release........................................................................ 3-1 Combustion Process............................................................................................................ 3-2 SCR/SNCR NOx Control...................................................................................................... 3-2 Flue Gas Conditioning.......................................................................................................... 3-5 Technology Impact Factors (F2) .......................................................................................... 3-5

**4**

**ESTIMATING GUIDELINE: STEAM BOILERS ..................................................................... 4-1**  Manufacture and Release from Combustion........................................................................ 4-1 Manufacture and Release from Flue Gas Conditioning (FGC) .......................................... 4-10 Total Manufacture and Release for Source ....................................................................... 4-13 Total Release Calculation for Sour ces Employing Alkali Injection ..................................... 4-13

**5**

**ESTIMATING GUIDELINE: MULTIPLE FUEL OR BLENDED FUEL BOILERS................... 5-1** 

**6**

**ESTIMATING GUIDELINE: COMBUSTION TURBINES ....................................................... 6-1**  Simple Cycle Units.............................................................................................................

.. 6-1 Combined Cycle Units.......................................................................................................... 6-4

**7**

**REFERENCES ....................................................................................................................**

**... 7-1** 

**A EXAMPLE CALCULATIONS................................................................................................**  **A-1** Example 1: Conventional Coal-Fired Boiler with an ESP................................................... A-1 Example 2: SCR Added to Example 1 ............................................................................... A-1 Example 3: Alkali Injection Added to Example 1................................................................ A-3 Example 4: 500 MW PRB-fired Boiler with ESP, SCR....................................................... A-5 Example 5: FGC Added to Example 1 ............................................................................... A-6 Example 6: SCR and FGC Added to Example 1................................................................ A-7 Example 7: Coal-Fired Boiler with FGC, NG Startup Fuel, and Used Oil Co-Firing........... A-9 Example 8: Natural Gas Combined Cycle Plant .............................................................. A-12

**B**

**CHRONOLOGY OF CHANG ES TO EPRI SULFURIC ACID ESTIMATION MODEL........**  **B-13**1-1 

# 1
**INTRODUCTION**

**Background** The ability to estimate sulfuric acid emissions from power plants is a topic of increasing importance to the U.S. utility industry. Most significantly, Section 313 of the Emergency Planning and Community Right-to-Know Act (EPCRA), also known as the Toxic Release Inventory (TRI), requires facilit ies that “manufacture,” “proc ess,” or “otherwise use” a listed chemical above certain threshold amounts to report their annual releases of the chemical to EPA and state agencies. For sulfuric acid in general, the TRI reporting requireme nts are triggered if a facility “manufactures” or “proce sses” more than 25,000 pounds of this chemical or “otherwise uses” more than 10,000 pounds of it in a given calendar year.

Sulfuric acid is a listed TRI chemical. In June 1995, the U. S. Environmental Protection Agency (EPA) modified the list of chem icals subject to the EPCRA § 313 reporting requirements so that only aerosol forms of sulfuric acid would be s ubject to the TRI reporting requirements (EPA, 1995a). EPA defines sulfuric acid aerosols as “inc lud[ing] mists, vapors, gas, fog, and other airborne forms of any particle size.” Although initia lly it appeared that only liquid droplets of sulfuric acid needed to be reported, the presen t method estimates the su lfuric acid emissions regardless of the physical state of the molecules. As of July 1, 1999, certain coal- and oil-fired electric power plan ts are required to report annual releases of TRI chemicals that they manufacture, process or otherwise use above threshold amounts. Under EPA’s EPCRA § 313 regulations, coa l- and oil-fired electric utilities are deemed to “manufacture” sulfuric acid. Thus, electric utili ties have to submit TRI reports on sulfuric acid releases if they “manufactur e” more than 25,000 pounds of the ch emical in a given reporting year (EPA, 1997). Significantly, emissions of sulfuric acid have receiv ed considerable attenti on in recent years with the broad application of selec tive catalytic reduction (SCR) NOx control technology. The use of SCR unavoidably contributes to production of sulfur trioxide (SO 3 ), the key precursor of sulfuric acid. Several notable incidents have been witnessed where an increase in sulfuric acid emissions, as manifested by an increase in stack plume visib ility, was attributed to the presence of newly retrofit SCR process equipment. The deployment of approximately 105 GW of selective catalytic reduction (SCR) from 1997 through 2006 has prompted power plant owners to conduct extensive measurements documenting the fate of SO 3 and sulfuric acid.

**Objective** The objective of this document is to present a methodology for estimating su lfuric acid emissions from power generating facilities. Th e scope of units considered in cludes coal- and oil-fired steam generating units, as well as simple cycle and co mbined cycle natural gas- and oil-fired combustion turbines. To date, the most authorit ative and documented data describe sulfuric acid emissions from coal-fired steam generators. The fo cus on this category of units is due to the1-2 increased availability of measure ments describing the fate of sulfu ric acid attributable to the retrofit of SCR process equipment on coal-fired steam generators. The methodology described in this report was de veloped by Southern Company Services (SCS). Between 2000 and 2005, SCS developed several versions of the estimation methodology and released draft reports informally (Har dman, 1998; Hardman, 1999; Monroe, 2001, Harrison, 2004, and Harrison, 2005 ) . The SCS model is widely used in the electrical power generation industry for TRI reporting and other emissi ons estimation purposes. In 2007, EPRI received permission from Southern Company Services to modify the SCS estimation method to include additional data and improvements, and to pub lish this method under EPRI sponsorship. The current (2008) version of the model adds the ab ility to estimate emissi ons based on a specified sulfuric acid flue gas concentration at the stack. This approach can be used when alkali injection is employed to reduce su lfuric acid emissions. In its basic approach, the methodology employed by this predictive technique is unchanged from the previous version (EPRI, 2007). Section 2 of this report addresses the uncertainty in measuring SO 3 concentration using the controlled condensation system (CCS), and the accuracy and representa tiveness of the data. Section 3 outlines the general methodology adopted in this model and summarizes data describing the removal of sulfuric acid across ai r heaters, ESPs, and wet flue gas desulfurization (FGD) process equipment. Section 4 describes the details of the methodology, focusing on data that predict manufacture by combustion, and outlines the calcula tion for including the role of the air heater and emissions control equipment. Sect ion 5 outlines how to conduct the calculation for steam boilers firing a mixture of fuels. Section 6 addresses both simple cycle and combined cycle combustion turbine applications. Example calculations for ma ny cases are presented in Appendix A.2-1 

# 2
**MEASUREMENT UNCERTAINTY**
A predictive method for sulfuric acid emissions requires knowle dge of sulfuric acid production and the fate of emissions from specific boilers and combustion turbines, to an acceptable degree of measurement accuracy. In a ddition, a large database of units is desired to generalize a correlation reflecting the broad population of genera ting units. Both of these factors are key to developing a usable predictive method. The predictive correlations presented in this re port are based on data obtained from field tests conducted predominantly in the last 1-2 years, with some estimates conducted 5-7 years ago. The quality of the information is believed to vary widely. It was not possible to obtain quality control information for all data sets; thus , it was not possible to critically review all data used in this model. The technique used to measure SO 3 /H 2 SO 4 is not known for all sources, but most measurements were conducted using the CCS, a widely used tec hnique that is generally considered the most accurate method for measuring SO 3 /H 2 SO 4 in stack gases from stationary combustion sources. EPA Method 8 is sometimes used for this purpo se, but that method h as a known positive bias from oxidation of SO 2 to SO 3 in the impinger solution.
**SO 3**  **/H 2**  **sO 4**  **Measurement Accuracy** A recent series of field and laboratory trials conducted by EPRI evaluated the measurement bias of the CCS technique by compari ng results from both la boratory tests and fie ld trials (EPRI, 2001). SO 3 /H 2 SO 4 measurements at similar gas compositi ons were compared in a 1) clean, ashfree laboratory environment; 2) simulated ash env ironment, and 3) actual field duty. The findings of the EPRI tests conducted under high-ash conditions are applicable to much of the field data used to derive removal factors in the current estim ation model. The results showed that, when fly ash was present in the flue gas stream, the technique imposed a low bias (e.g., indicated lower SO 3 /H 2 SO 4 than actual), due to reactions of SO 3 or sulfuric acid with fly ash in the filter thimble holder upstream of the CCS conde nser. Conversely, the EPRI tests indicated that use of CCS downstream of the particulate control devi ce produces unbiased measurements, as long as appropriate procedures are followed.

The extent of bias observed in the EPRI st udy depended on the sampling location, which could be the air heater inlet, air heater outlet, or flue gas desulfurization outlet. Further, the bias depended on the quantity of ash collected, the alka linity of the ash, and th e coal sulfur content (e.g., SO 2 content in the sample gas). Measurement bias was observed for both high sulfur coal and low sulfur PRB coal. The magnitude of the bias varied widely; data for high sulfur coal suggested a low bias of up to 40% could occur, although most measurements indicated lower bias values. A 20% low bias was noted for low su lfur, Power River Basin subbituminous coal. The accuracy of the CCS data used in this esti mation model can be estima ted from the variability among duplicate measurements believed to be conducted under the same process conditions. Data from recent field trials with experienced test crews suggest an accuracy of ± 20% is realistic for most conditions. The accuracy of the CCS measurements depends on avoiding stratification2-2 within the gas stream (traversi ng is very difficult), maintaining correct temperatures in the sampling train, and having well tr ained sampling personnel. The accu racy of the entire data set used in this model, which includes data from olde r studies, is expected to be closer to ± 50%.

**Correlation Representativeness** The accuracy of the correlations presented in th is report depends on the representativeness of the constituent data points. For some power plant co nfigurations, there are only a few data points, and the correlations provide only rough approximations of the flue gas SO 3 /H 2 SO 4 for similar units. The category with the largest number of data points is dry-bottom boilers firing low sulfur, eastern bituminous coal. In general, the plant con figurations from which the data are derived are considered to be representative of the utility industry generating popula tion. The number of data points in each category should be considered wh en applying the results of these correlations. As a consequence of the uncertainty in SO 3 /H 2 SO 4 measurement accuracy and the limited number of data points that comprise the relevant corr elations, the predictive technique should be assumed to provide estimates within a ± 50% relative accuracy.3-1 

# 3
**BACKGROUND AND METHODOLOGY OVERVIEW**
This section provides a brief overview of sulfuric acid production mechanisms. A detailed review of this topic has been provided by S rivastava (2004) and more recently by Monroe (2006). The production or manufacture of SO 3 , and ultimately sulfuric acid, is determined initially by processes occurring directly within the flame zone of a boiler, the convective heat transfer sections, or environmental control component s. These production or manufacturing processes can be gas phase or can be induced by catalysis on the surface of fly ash particles or heat removal surfaces.

Mechanisms that remove sulfuric acid from the flue gas also can occur both in the gas phase and on heat transfer surfaces, usually promoted by ash-derived deposits. The amount of sulfuric acid released from the stack is the aggregate result of production mechanisms, generally occurring at temperatures above 650°F, and removal mechan isms occurring at lower temperatures.

Recent research activities have been directed to the use of alkali-based sorbents to capture SO 3 at various points in the power generation process. As of the end of 2007, more than 25,000 MW of coal-fired generating capacity wi ll be equipped with some type of sorbent injection method for SO 3 control. New in this version of the report is a method to calculate su lfuric acid releases for units that inject alkali for SO 3 reduction.

**Factors Affecting Manufacture and Release**
The method will estimate the manu facture and the subsequent re lease of sulfuric acid from the power generation process. The manufacture of sulfuric acid is defined as any process step that increases the flue gas content of su lfuric acid, regardless of its ultimate fate. To estimate the release of sulfuric acid, the manufacture estimate is co rrected by a factor or series of factors to account for sulfuric acid re moval within the system. Three process steps ultimately lead to the manuf acture of sulfuric acid in a fossil fuel-fired electricity generation unit: the combustion process, selective catalytic reduction (SCR) for NOx control, and flue gas conditioning. All remaining steps in the power generation process reduce sulfuric acid. Therefore, the total sulfuric acid released is the cu mulative sum of that manufactured, adjusted by sulfuric acid losses.

The manufacture of SO 3 , the precursor to sulfuric acid, is denoted in this model as follows: for the combustion process by EM Comb ; for SCR by EM SCR ; and for flue gas conditioning (FGC) by EM FGC . The Total Sulfuric Acid Manufactured (TSA M) from a combustion unit equipped with SCR NOx control and FGC is represented by Equation 3-1.

Equation 3-1 TSAM = EM Comb + EM SCR + E FGC3-2 **Combustion Process**

**Manufacture** A detailed analytical study by Seni or (2002) explored details of SO 2 oxidation to SO 3 . Specifically, the author modeled the relevant reaction sets employing the temperature-time history of a typical utility boiler, considering g as phase events only and ignoring catalytic effects. The results showed that insignificant SO 3 formed in the early stage of the flame, but SO 3 production increased as the gases exited the flam e zone and cooled. The author reported production of SO 3 to be essentially complete prior to flue gas entering the economizer section. The observation that most SO 3 forms during cooling from post-flame temperatures (2,900- 3,100°F) to temperatures typical of the economizer entrance was also noted by Buckley (2002). Senior further quantified the relationship betw een coal sulfur content, excess air, and SO 3 production that has been empirica lly observed by previous investig ators. Specifically, the results showed that after four se conds of residence time, SO 3 production could range from between 0.3 - 0.6% of the flue gas SO 2 concentration. In the absence of SCR NOx control or FGC, the boiler or turbine combustion process comprises the only source of sulfuric acid. The sulfuric acid manufacture by the combustion process (EM Comb ) is expressed as follows: Equation 3-2 EM Comb = K • F1 • E2
Where K is a constant, F1 is the Fuel Impact Factor describing the SO 3 production associated with combustion for a specific fuel type, and E2 is the annual rate of SO 2 production. Further details of this relationship and the derivation of constants and other terms are presented in Section 3.

**Release**
The release of sulfuric acid attributable to th e combustion process is determined by adjusting the manufactured SO 3 by the removals in the following equipment: the air heater, electrostatic precipitator (ESP) or other par ticulate control device (PCD), a nd flue gas desulfurization (FGD) equipment. The release of sulfu ric acid is calculated by a pplying Technology Impact Factors (F2) that describe the fraction of sulfuric ac id that penetrates each downstream equipment component. The sulfuric acid released by combustion (ER Comb ) is described by the following: Equation 3-3 ER Comb = EM Comb ● F2 (all that apply) The development of Technology Impact Factor s (F2) for each downs tream component is addressed later in this section.

**SCR/SNCR NOx Control**

**Manufacture** The SCR process increases the production of SO 3, and therefore, H 2 SO 4 , as a percentage of SO 2 . SO 3 production can range from as low as 0.3%, for the most recent catalyst technology, to as high as 3% of the SO 2 concentration.3-3 The production of SO 3 from SO 2 is a well-known consequence of SCR, and the degree of SO 2 oxidation is a performance variable that should be part of catalys t procurement specifications. To a degree, SO 3 production can be mitigated by substituting for vanadium pentoxide or other catalyst oxides such as tungsten or molybdenum, which offer improved se lectivity (e.g., lower SO 2 oxidation) but also lower activity for NOx removal. Alternatively, advanced catalyst formulations can be used that concentrate the vanadium-containing active ingredients on the catalyst surface and minimize content within the substrate, lowering SO 2 oxidation. To achieve an equivalent level of NOx and residual ammonia slip, a low SO 2 oxidation catalyst may require a larger volume of catalyst than one for which SO 2 conversion is not constrained. In general, the degree of SO 2 oxidation ranges from about 0.2% to 1.5% for most SCR process reactors designed for bituminous coals. If SCR is applied to extr emely low sulfur, high alkalinity coals such as PRB, higher SO 2 oxidation is acceptable. Depending on how the measurement of SO 2 oxidation is performed, the oxidation can be 3% or higher. In many instances, owners and catalyst supplie rs prefer that measurements to quantify SO 2 oxidation for the purpose of commercial guarantees be conducted not with authentic flue gas but in a laboratory-scale test faci lity, without fly ash present. This approach has the advantage of improved accuracy and repeatability of the SO 3 concentration. The measurements are generally conducted using CCS. However, particularly fo r PRB coals, this me thod will over-predict SO 3 manufactured by the SCR, as the mitigating role of high fly ash alkalinity is not considered. Consequently, the role of fly ash alkalin ity must be considered in predicting SO 3 manufactured by SCR.

The observation that calculated SO 3 values at the exit of an SCR reactor exceed measurements in the field has been witnessed on numerous occas ions. Specifically, Lindenhoff (2004) reported that the measured SO 2 oxidation rate for PRB-generated flue gas of 1.25% was below the 1.6% value predicted based on the boiler and SCR catalyst specifications. Further, tests conducted by this catalyst manufacturer noted significant absorption of SO 3 generated within the SCR reactor prior to the air heater. Sufficient data was accumu lated to derive both a mathematical model and to project a graphical relationship describing SO 3 removal within an SCR reactor as a function of both ash content and the number of alkaline sites available in the flue gas stream. An alternative NOx control process, selective non-catalytic reduction (SNCR), does not use a catalyst and does not promote the oxidation of SO 2 to SO 3 . Accordingly, there is no manufacture of sulfuric acid attributable to SNCR.

**Release** Both SCR and SNCR can introduce residual ammonia (NH 3 ), also called ammonia slip, into the flue gas. This residual ammonia can react with SO 3 or sulfuric acid to form ammonium sulfate and/or ammonium bisulfate, thereby rem oving from the flue gas some of the SO 3 that is a precursor to sulfuric acid, and reducing the amount released. For an SCR, ammonia slip is expected to usua lly range between 0 and 2 ppm for bituminous coal cases. Higher values of ammonia slip are possibl e if the unit has not been recently tuned, the boiler or SCR process operates under upset, or as the catalyst ages. Higher ammonia slip may be tolerable in PRB coal applications, since ammoni a is not readily absorbed by the highly alkaline PRB ash and adverse operational impacts (air preheater pluggage and ash contamination by ammonia) are avoided. Reactions between the residual ammonia and SO 3 or H 2 SO 4 occur in the air preheater and result in a solid product that may deposit or accumulate on the surface of the fly3-4 ash. Any SO 3 or H 2 SO 4 that participates in these reactions is no longer chemically present as sulfuric acid and is not required to be reporte d to the EPA TRI program as a release of sulfuric acid. SNCR employs ammonia or urea injection in the upper furnace for NOx reduction. The higher temperatures characteristic of the upper furnace zone (1,800 to 2,400°F, as compared to 700°F for SCR) do not require reduction catalyst so there is no additional manufacture of SO 3 or sulfuric acid. Typically, SNCR syst ems operate with higher levels of residual ammonia (5 to 10 ppm), so any sulfuric acid that is present from combustion is reduced through reaction with the ammonia. Consequently, SNCR systems will always reduce the overall amount of sulfuric acid released, while SCR systems can reduce but will likely increase the amount of sulfuric acid released.

The reactions between SO 3 and/or H 2 SO 4 and ammonia produce ammonium sulfate [(NH 4 ) 2 SO 4 ] and/or ammonium bisulfate (NH 4 HSO 4 ). While both chemicals are solids, the bisulfate pairs one molecule of ammonia with one of sulfuric acid, while the sulfate requires two ammonia molecules for each sulfuric acid. Which reactio n product is present is usually determined by the stoichiometry, or the relative amount of each substance on a mole basi s, that is present in the flue gas. When ammonia is present in an amount over twice the mole content of the sulfuric acid, the reaction product will always be the ammonium su lfate. Conversely, when sulfuric acid is present in an amount on a mole basis greater than ammo nia, the product will be ammonium bisulfate. Between these two extremes, a mixture of a mmonium sulfate and bisulfate is produced. An SCR-equipped unit firing bituminous coals with low-to-medium sulfur content will always produce an excess of sulfuric acid over ammonia slip. Accordingly, ammonium bisulfate is the primary byproduct anticipated. For subbituminous, PRB, and lignite coals, any sulfuric acid produced is typically adsorbed by the ash and it is likely that resi dual ammonia will exceed sulfuric acid content on a mole basis. Under these conditions, a mmonium sulfate is the likely product. For SNCR-equipped units, ammonia slip levels of 5 ppm and possibly higher will favor producing ammonium sulfate, particularly for wester n U.S. coals where the alkaline fly ash will reduce the SO 3 content. For eastern bituminous coals, wh ich have generally higher sulfur content and lower ash alkalinity, ammonium bisulfate will likely predominate. For the purpose of predicting sulfuric acid emissi ons, these distinctions are not important. A single molecule of sulfuric acid will capture a single molecule of ammonia, producing ammonium bisulfate. If additional ammonia is ava ilable, the ammonium bisulfate can react with another ammonia molecule to fo rm ammonium sulfate. It can be assumed that all sulfuric acid forms ammonium bisulfate before any further reaction to the ammonium sulfate form occurs. This assumption leads to the calcula tion strategy that ammonia captur es all of the sulfuric acid it can as ammonium bisulfate, and si nce the bisulfate form is no l onger reportable, the sulfuric acid disappears from the release cal culation. Additional ammonia r eacting with the ammonium bisulfate is of no consequence to the sulfuric acid calculation – although this issue will be important when estimating ammonia releases.

Further details of the calculations used in this model to predict sulfuric acid manufacture and release by SCR and SNCR are presented in Section 4.3-5 **Flue Gas Conditioning**

**Manufacture** Flue gas conditioning (FGC) is a process that is typically used in power plants to assist in particulate control in an ESP or baghouse. The conditioning additives can be any of the following: SO 3 , SO 3 plus NH 3 , or NH 3 alone. In SO 3 -based FGC, SO 3 is introduced into the flue gas either preceding or following the air heater. The SO 3 is typically prod uced on-site from sulfurous fuel that is burned to produce SO 2 , which is then catalytically oxidized to SO 3 with a conversion rate typically exceeding 95%. Wh en injected into the flue gas, the SO 3 immediately reacts with water vapor to create sulfuric acid, thus resulting in the manufacture of sulfuric acid. Estimating the manufacture source requires knowledge of the concentration of SO 3 injected and the associated O 2 content of the flue gas. Section 4 presents an equation to estimate the manufacture of sulfuric acid from this source.

**Release**
The release of sulfuric acid attributable to FGC requires adjusting for the reaction with NH 3 that may be introduced as part of a flue gas conditioni ng scheme, either with or without sulfuric acid. Analogous to the case of SCR and SNCR, the concentration of NH 3 and the associated O 2 content of the flue gas must be estimated. Accordingly, FGC can manufacture sulfuric acid, but can also remove sulfuric acid if NH 3 is injected alone or in quantiti es greater than the sulfuric acid. The relevant relationships are presented in Section 4. The Technology Impact Factor s (F2) describe the fraction of sulfu ric acid that penetrates the air heater (for FGC that is introduced ahead of the ai r heater), and for the particulate control device and FGD (for FGC that is introduced after the a ir heater). The basis for the F2 factors is presented in the subsequent section, and the deta iled equations for quantifying the manufacture and release of sulfuric acid are presented in Section 4.

**Technology Impact Factors (F2)** The sulfuric acid estimating methodology employ s empirically-derived Technology Impact Factors (F2). These F2 factors d escribe sulfate removal observed over the air heater, the ESP or other particulate control device, and FGD pr ocess equipment. Relevant background and the derivation of these factors are addressed in this section.

**Air Heater**
The removal of SO 3 and/or H 2 SO 4 within the air heater is due to the condensation of sulfuric acid and its removal as discrete indivi dual particles (along with the fly ash) on the surface of this heat exchanger. The conventional Ljungstrom-type ai r heater has been documented to provide a removal sink for sulfuric acid (Saranuc, 1999). In fact, the largest supp lier of Ljungstrom air heaters has evaluated the feasibility of em ploying the air heater process environment in conjunction with limestone injection as a proa ctive sulfuric acid con trol strategy (Hamel, 2003, and Bowes, 2006). Air heater surfaces follow a pattern of altern ately heating and cooling as the heat exchange elements move from the relatively hot flue gas to the cooler combustion air. As reported during field tests of commercial equipment (Saranuc, 19 99), this temperature profile introduces a strong3-6 gradient in sulfuric acid concen tration across the exit pl ane of the air heater. The cyclic thermal conditions as described by Hamel (2003) reveal that a significant portion of the air heater basket surface metal is exposed to flue gas temperature below the sulfuric acid dewpoint. This phenomenon may promote sulfuric acid depositi on on the heat exchanger metal surface, compared to a tube-type heat exchanger in wh ich the metal temperature is always above the sulfuric acid dewpoint. Figure 3-1 presents data obtained from a survey of utility operators and general literature sources describing SO 3 /H 2 SO 4 removal across commercial, Ljungstro m-type air heaters. These data are presented as a function of SO 2 content of the flue gas for the ho st unit. Most data shown are for low sulfur eastern bituminous co al, for which air heater H 2 SO 4 removal varies significantly between 0% and 69%, averaging 45% as indicat ed by the horizontal line. Two high sulfur (>2.5%) eastern cases are shown, along with limited data for PRB coal. The data point showing 0% remo val at approximately 600 ppm SO 2 is believed suspect, as an identical companion unit firing the same coal exhibited sulfuric ac id capture of 38%. Figure 3-1 presents two points reported by Ha mel (2003) based on a low sulfur eastern bituminous-fired unit where SO 3 was “spiked” into the flue g as to elevate the concentration entering the air heater to 80 and 122 ppm. These tw o points are plotted separately on Figure 3-1 versus an estimated flue gas SO 2 content that could generate such values (using the average SO 2 oxidation rate for high sulfur eastern bituminous co al in Figure 4-1). It should be noted these values measured for the “spiked ” flue gas significantly exceed those measured for the two high sulfur eastern coal cases.
The F2 factor for the air heater, calculated as [1 – Collection Efficiency], is estimated excluding the “spiked” SO 3 and suspect 0% removal measurement. Th e F2 factors for the air heater for low sulfur eastern bituminous, medium-high sulfur ea stern bituminous, and PRB coals are shown in Table 3-1. Data are not currently available fo r other coal types. Western subbituminous coals (e.g., non-PRB) could consider adopting the F2 f actor for PRB if the ash is strongly alkaline; western coals with acidic ash (e.g., bituminous) may consider adopting the low sulfur, eastern bituminous value.3-7 0% 10% 20% 30% 40% 50% 60% 70% 80%

0 500 1000 1500 2000 2500 3000 3500
Flue Gas SO 2 Content, ppmAir Heater H2SO4Removal, % Low S East Bit, Dry Bottom Boiler High S East Bit, Dry Bottom Boiler Hamel Full-Scale Tests PRB Dry Bottom Boiler

**Figure 3-1 Removal of Sulfuric Acid by Ljungstrom-Type Air Heaters** 

**Table 3-1 Summary of F2 Factors for Air He**  **ater Removal of Sulfuric Acid**

**Boiler Type**  **Fuel F2**  **Standard Deviation**  **Comment**

All Boilers Low S Eastern Bit 0.49 0.16 Average of measurements at 7 units.

All Boilers Med-High S Eastern Bit (S >2.5%) 0.85 n/a Two data points only.

All Boilers PRB 0.56* n/a Based on one data point.

* Change in factor from Harrison (2005)

Table 3-1 reports the standard deviation of th e reported measurements for the low sulfur eastern bituminous coal is about one third the value of the measurement. Inadequate data prevent calculating a standard deviation for F2 factors for the other fuels.3-8 **Particulate and SO 3**  **Control Processes**
This section discusses the available data on removal of SO 3 by ESPs, FGDs, and alkali injection.

ESP An ESP provides extended residence time at re latively low temperatures, allowing contact between sulfuric acid and fly ash particles, as well as having collecting plates that can retain sulfuric acid particles. These features contribute to the removal of sulfuric acid. The ESP is the flue gas contacting device with perhaps the l ongest residence time; for large units, usually 10 seconds and in some cases up to 15 seconds. Given the low flue gas velocities of 2-4 aft/s, and the opportunity for heat loss at or near the wall s, sulfuric acid condensation can be significant. Figure 3-2 plots sulfuric acid remova l by the ESP as a function of the SO 2 content of the flue gas for the host unit, from a survey of plant opera tors. Most data shown are for a cold–side ESP and low sulfur eastern bituminous coal ; three data points are show n for high sulfur coal (>2.5%). Also shown is a single data point for a hot-side ESP and four data points for low sulfur eastern bituminous coal. Similar to the case for the a ir heater, the 0% sulfu ric acid removal at approximately 800 ppm SO 2 is suspect, as a companion unit at the same site firing the identical coal had 50% sulfuric acid rem oval. Accordingly, this “zero” datum, although shown in Figure 3-2, is not used in the analysis.

**Figure 3-2 Removal of Sulfuric Acid by**  **Cold-Side and One Hot-Side ESP** 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

0 500 1000 1500 2000 2500 3000 3500
Flue Gas SO 2 , ppmESP Flue Gas H2SO4Removal, % Low S East Bit, Dry Bottom Boiler High S East Bit ESPh Low S EastBit PRB Dry Bottom Boiler3-9 The F2 factor for the cold-side ESP, calculated as [1- Collection Efficiency], is estimated using all data except the 0% removal point. The F2 factors for ESP capture for low sulfur eastern bituminous, medium-high sulfur eastern bituminous, a nd PRB coals are listed in Table 3-2. Data are not currently available for other coal t ypes. Western subbitumi nous coals (e.g., non-PRB) could consider adopting the F2 factor for PRB if the ash is strongly alkali ne; western coals with acidic ash (e.g., bituminous) may co nsider adopting the low sulfur, eastern bituminous value. Data describing the reduced H 2 SO 4 penetration for one hot-side ESP is the result of a methodical and carefully executed test program, and is adopt ed even though it is inco nsistent with earlier projections. The standard deviati ons of the ESP data were not calculated due to the small number of data points. Data for baghouses would reside at the extreme point on the chart, corresponding to 90% H 2 SO 4 removal.

**Table 3-2 Summary of F2 Factors for Particul**  **ate Control Devices (ESP, Baghouse)**

**Equipment Type**  **Coal Type F2 Factor**  **Comment or Observation** Cold-side ESP Low S Eastern Bit 0.49 Average of measurements at 4 units. Cold-side ESP High S Eastern Bit (>2.5%) 0.77 Average of measurements at 3 units. Cold-side ESP Subbituminous (PRB) 0.73 Based on one measurement at one unit.

Hot-side ESP All 0.63 Based on one measurement at one unit. Baghouse Subbituminous coal 0.10 Two data points.

**FGD** FGD process equipment rapidly cools or quenche s flue gas, condensing a significant portion of the sulfuric acid into submicron droplets th at can escape the process environment, confounding capture. Buckley (2002) notes that for condensation to occur, sulfuric acid generally must be supersaturated. However, fly ash particles can provide a nucleus for condensation of sulfuric acid, even at conditions that are not thermodynamic ally supersaturated. Bu ckley also projects sulfuric acid condensation on surfaces where equipm ent walls are lower in temperature than the flue gas (common in comme rcial equipment). However, the th in laminar boundary layer at the wall limits mass transfer, and for FGD equipm ent this mechanism provides no appreciable removal. Ironically, it is the high saturation conditions in this lamin ar layer near surfaces that are key to producing fine su lfuric acid mist. Srivastava (2004) suggests that the condensed submicron drople ts, once formed, are sufficiently small so that they follow the flow streamlines a nd avoid contact with the remaining wetted walls, liquid sheets, and droplets in the flow path. Alth ough some degree of sulfu ric acid removal is observed in FGD equipment, the amount is highly variable and depends on the design of the system. Buckley (2002) estimates FGD equipment removes 40-70% of the sulfuric acid, and Srivastava an average of 50%. Figure 3-3 summarizes data reported in the publ ic domain and from utility-specific tests describing FGD removal of sulfuric acid. The percent of sulfuric acid removal is depicted as a function of FGD inlet SO 2 concentration. Removals range from 22% to 78%, with an average of3-10 about 50%. The shaded portion of Figure 3-3 repr esents the upper and lower bounds of the data reported by Buckley (2002), while the solid ho rizontal line reflects the average reported by Srivastava (2004).

0% 10% 20% 30% 40% 50% 60% 70% 80%

1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 FGD Inlet SO 2 , ppmFGD H2SO4Removal, %

Venturi LimestoneTower PRB/Lignite Buckley, 2002 Srivastava, 2004

**Figure 3-3 Removal of Sulfuric Acid by Flue Gas Desulf**  **urization Equipment: Various FGD Designs, Coals**

Table 3-3 summarizes the F2 factors for FGD pr ocess equipment, including results for a wet spray tower burning bituminous coal, and also one burning a blend of PRB/lignite. Given the limited data, the latter is assumed to serve as the basis of an F2 -factor for 100% firing of PRB or lignite. Data for a wet venturi-type combined pa rticulate/FGD process is also available, but only for a bituminous coal. Similar to the case for a wet spray tower, the lack of data merits assuming sulfuric acid removal for all coals is desc ribed by that measured for bituminous coal. F2 factors for the use of magnesium-based additiv es in oil-fired boilers are also included in Table 3-3. These additives are used to control furn ace slagging caused by the vanadium in the oil or to control sulfuric acid emissions or bot h. The fuel oil vanadium can also catalyze SO 2 to SO 3 oxidation, but the additive, when added to the oi l, tends to effectively bind up the vanadium, partially reducing its catalytic ef fect. Addition of magnesium-based additives in the fuel oil tend to be less effective in controlling the emissions of sulfuric acid than the same additive sprayed into the furnace downstream of the flame zone.3-11 **Table 3-3 Summary of F2 Factors for Wet, Dry FGD Equipment and Additives** 
**FGD Type Coal Type F2 Factor Comment or Observation** Wet: Spray Tower E. Bituminous 0.47 Seven data points. Wet: Spray Tower PRB or Lignite 0.40 Two data points. Wet: Venturi Tower All coals 0.65 Based on bituminous coal only; limited data merit assigning same factor for other coals. Dry FGD and baghouse All coals 0.01 Two data points. Mg-Ox mixed w/fuel oil All fuel 0.50 One data point. Mg-Ox into furnace All fuel 0.50 One data point.

**Alkali Injection** Many utility operators inject alkali into the flue gas to control SO 3 . A wide variety of alkali materials based on calcium, sodium, or in so me cases magnesium compounds, have been used with varying degrees of e ffectiveness to remove SO 3 . These alkali materials include sodium bisulfate, trona, and various types of lime (conve ntional, hydrated, and magnesium enhanced). Sodium bisulfate (SBS) is the most widely used reagent for control of SO 3 . SBS is introduced into the flue gas, usually at the air heater exit, but in some unit s at the air heater inlet, to maximize residence time and improve SO 3 removal. SBS can be highly effective in removing SO 3 . Additional sodium can be added to the flue gas to compensate fo r any compromise in ESP performance due to increased ash resistivity associated with SO 3 reduction. A detailed summary of experience with the SBS concept has recently been published (Moser, 2007). Trona is another sodium-containing reagen t that is being used to control SO 3 . Trona can be injected at several locations within the boiler, but most applications introduce trona at the air heater exit, prior to the parti culate collector (Ritzenthaler, 2006). As with SBS, additional sodium introduced into flue g as is advantageous to compensate for the reduction in ESP performance.

Several forms of calcium-based sorbents can be u tilized. These are injected at various locations in the flue gas, including the economizer inlet, econo mizer outlet (e.g., air h eater inlet), and the air heater outlet. A survey of recent experie nce with lime-derived sorbents addressed the advantages of this approach (Benson, 2006a). Hydr ated lime has been shown to be an effective calcium-based reagent for SO 3 control (Gale, 2006), as has li me supplemented with magnesium hydroxide (Benson, 2006b). Calcium–based sorbents can be very effective in reducing SO 3 , but may compromise ESP performan ce, as the reduced SO 3 content in flue gas increases the electrical resistivity of the ash on the collecting plate. For th is reason, some operators have proposed using both calcium- and sodium-based sorbents, the latter to both augment SO 3 removal and promote ESP performance. In summary, any of several alkali materials can be used to control SO 3 , with the least cost solution depending on the plant and access to low cost sorbent.3-12 Plant units that deploy alkali injection will have conducted field tests to determine the resulting SO 3 concentration in flue gas. In most cases, th e tests will be conducted at the stack. In most cases, the alkali injection syst em is operated to reduce SO 3 emissions to between 5 and 15 ppm, which is the general range targeted for SO 3 mitigating measures.
In the 2008 version of the Sulfuric Acid Model, EPRI has added a procedure to estimate SO 3 stack releases from generating units that employ alkali injection for SO 3 control, using measured or estimated stack gas SO 3 concentrations. A procedure to convert measured sulfuric acid concentration in flue gas to a mass emission rate is summarized in Section 4, and an example application of this method is provided in Appendix A.

To estimate SO 3 manufacture with alkali injecti on, plant owners should use the standard approaches given in Section 4 fo r the appropriate plant configur ation. At this time, EPRI does not have sufficient information to estimate the impact on SO 3 formation of adding alkali at various points in the fuel combustion and stack gas treatment process. Assuming that there is no reduction of SO 3 formation is conservative for a threshold determination for TRI reporting purposes. Users of this approach should be cautioned th at the current EPA-appr oved test method for SO 3 (Method 8) has a significant positive bias, and that corrections for this bias may be needed to accurately assess flue gas concentrations. A more accurate method is the controlled condensate system, although this method is not curre ntly approved by EPA for this purpose.4-1 

# 4
**ESTIMATING GUIDELINE: STEAM BOILERS**
This section describes an estimation procedure fo r calculating the manufacture and release of sulfuric acid from coal-fired steam generators. The topics addressed are (a ) formation within the furnace; (b) the role of SCR; and (c) the rem oval by downstream equipment such as air heaters, ESPs or other particulate control de vices, and FGD process equipment. Each of the subsequent sections in this chapter provides the in formation to conduc t this stepwise calculation.

**Manufacture and Release from Combustion**  The premise of the methodology is that the amount of sulfuric acid manufactured by the boiler is a function of the amount of SO 2 released – determined either from coal usage (amount burned and sulfur content) or from continuous emis sion monitoring system (CEMS) output. Units equipped with FGD equipmen t or other methods of SO 2 control are required to use either coal data or CEMS measurements from ahead of th e scrubber. As described below, it may be necessary to correct CEMS SO 2 data for non-ideal stack flow conditions.
**Sulfuric Acid Manufactured by Combustion (EM Comb**  **)** The following relationship is proposed to estimate the sulfuric acid manufactured from combustion in utility sources:

**Equation 4-1 EM Comb**  **= K** • **F1** • **E2** where,

EM Comb = total H 2 SO 4 manufactured from combustion, lbs/yr K = Molecular weight and units conversio n constant, equal to 3,063. This value is derived as follows: 98.07/64.04 • 2000 = 3,063. Here, 98.07 is the molecular weight of H 2 SO 4 ; 64.04 is the molecular weight of SO 2 ; conversion from tons per year to pounds per year requires multiplying by 2000. F1 = Fuel Impact Factor E2 = Sulfur dioxide (SO 2 ) emissions, either: (1) recorded by a continuous emissions monitor, tons/yr, or (2) calculated from coal burn data, tons/yr. In the derivation of Equation 4-1, the following assumptions are made:

• SO 3 concentrations are proportional to SO 2 concentrations.

• The grade of coal being burned impac ts the rate of conversion from SO 2 to SO 3 .

• All SO 3 that forms is converted to H 2 SO 4 .4-2 • The rate of SO 3 formation is independent of the boiler firing rate (unit load). The fuel impact factor (F1) and estimates of sulf ur dioxide emissions (E2) are further described in the following sections. Fuel Impact Factor (F1 ). Figure 4-1 depicts the Fuel Impac t Factor (F1) as a function of flue gas SO 2 content, for several coal sources and boiler types. Figure 4-1 depicts a total of 30 data points, derived from 21 different units. The coal ranks and boiler types consist of (a) high sulfur (>2.5%) eastern bituminous coal, fired in a dry bottom boiler, (b) low sulfur eastern bituminous coal, fired in a dry bottom boiler, (c) PRB coal, fire d in both a cyclone (1 reference) and two dry bottom boilers (4 references), and (d) high sulfu r eastern bituminous coal , fired in a cell-fired boiler. Data are also shown for units that fire predominantly (75%) lignite (with the balance PRB) and PRB alone.

**Figure 4-1 Relationship between Boiler SO**  **3 Production and Flue Gas SO**  **2 (corrected to 3% O**  **2 )** 

Figure 4-1 shows that a wide range in SO 3 production is observed for all coals and boiler types. This range exceeds the theoretical predictions by Seni or (2002), suggesting that the role of ash in either catalyzing SO 3 production or absorbing/neutralizing SO 3 is not fully accounted for. The only consistent results in Figure 4-1 are for SO 3 from PRB-fired units, regardless of boiler type, 0.000 0.002 0.004 0.006 0.008 0.010 0.012 0.014 0.016 0.018 0.020

0 1000 2000 3000 4000
Flue Gas SO 2 ContentBoiler H2SO4Production, F1 Factor High S East Bit, Dry Bottom Boiler Low S East Bit, Dry Bottom Boiler High S East Bit, Cell-fired Boiler PRB Dry Bottom Boiler 75% Lignite4-3 in that less than 1 ppm was observed. Even for the low sulfur eastern bituminous coals, a significant range of SO 3 content is observed. Attempts at co rrelating the F1 factor with flue gas SO 2 content provided unacceptable correlation coeffi cients (R-squared values); thus, correlations are not proposed.

Table 4-1 summarizes the basis of the F1 factors used in this model, denoting any significant changes from the most recent guideline publ ished (Harrison, 2005). For two categories of equipment for which the most data points ex ist – dry-bottom boilers firing low sulfur eastern bituminous coal, and dry bottom boilers firing medi um-high sulfur coal – a standard deviation is included for all of the data. Sulfur Dioxide (SO 2 ) Emissions from Combustion (E2)

. Estimating the sulfuric acid production from Equation 4-1 requires knowle dge of the mass rate of SO 2 generated. This rate is designated as E2 in Equation 4-1. As noted previously, the va lue of E2 can be estimated from either (a) the EPA CEMS data, or (b) calculated from the coal burn data (EPA, 1995a). CEMS can directly quantify the annual SO 2 production rate, in tons/year of SO 2 . However, it may be necessary to correct for stack geometry in deriving E2. Specifically, if CEMS SO 2 data are used, the factor E2 is defined by the following equation

**Equation 4-2a** 

# ( ) ⎥ ⎦ ⎤ ⎢ ⎣ ⎡ + ∗ + ∗

− = 100 3 2 1 1 2 2 C R C R C E E

where,
E2 = Corrected SO 2 mass rate, tons per year
E = CEMS-derived SO 2 mass rate, tons per year C1 = 0.0264 (non-axial flow bias factor) C2 = 0.183 (non-axial flow bias factor) C3 = 1.5 (wall effects bias factor) – default value for cylindrical stacks R = Stack/duct average resultant angle (or swirl angle) from site veri fication tests, degrees

In equation 4-2a, the factor C3 re presents the wall effects bias fact or which is used to specify the non-axial properties of flow w ithin the stack, as measured by EPA Method 1 (EPA, 1991). This value, which will vary with each site, can be determined using EPA Method 2H (EPA, 1999). For most cylindrical stack geom etries, a default value of 1.5 can be used; however the R value for each stack can be different and should be determined using the appropriate EPA method. EPA has also proposed a wall effects correction for stacks with rectangular ducts that are equipped with flow monitors (EPA, 2006). This proposal has not been finalized as of March 2007, but some facilities may be allowed to a pply this approach as a conditional test method.4-4 **Table 4-1 Summary of Fuel Impact Factors (F1) for Steam Generating Units** 

**Fuel Equipment**  **F1 Standard**  **Deviation Comment**  Med-High S Eastern Bituminous (>2.5%) Dry Bottom Boiler 0.011 0.0041 Seven data points.

Med-High S Eastern Bituminous (>2.5%) Cyclone 0.016 One data point.

Low S Eastern Bit. Dry Bottom Boiler 0.0082* 0.0021 Average of measurements at 16 units; slight increase in penetration compared to Harrison (2005). W. Bituminous Dry Bottom Boiler 0.00111 One data point.

W. Bituminous Cyclone 0.0022 One data point. Subbituminous/PRB All Boilers 0.0018* Average of 7 units; an increase in penetration compared to Harrison (2005). Lignite Dry Bottom Boiler 0.0048 One data point.

Lignite Cyclone 0.00112 One data point. Petroleum coke Boiler 0.04 One data point. Natural gas Boiler 0.01
#2 Fuel oil Boiler 0.01
#6 Fuel oil Boiler 0.025
Used oil Boiler 0.0175 Natural gas CT See Table 6-1
#2 Fuel oil CT See Table 6-1 Natural gas CC 0.0555 #2 Fuel oil CC 0.0555* New category in 2007. Other Alternative Fuels Any 0.04 Other Alternative Fuels, co-fired w/coal, >75% heat throughput NA Use Coal F1, in absence of any applicable data.

* Change in factor from Harrison (2005)4-5 As an alternative to using CEMS data, the following relationship based on coal burn data can be used to estimate the rate of SO 2 emissions:
Equation 4-2b E2 = K1 • K2 • C1 • S1
where,
E2 = SO 2 mass rate, tons/yr C1 = Coal burn, tons/yr S1 = Coal sulfur weighted average, % K1 = Molecular weight and units conversion co nstant, equal to 0.02. This value is derived from (64.04)/(100 • 32.06) = 0.02. Here, 64.04 is the molecular weight of SO 2 ; 32.06 is the molecular weight of S; and conversion of % S to a fraction requires multiplying by 100.
K2 = Sulfur conversion to SO 2 , implicit from EPA AP-42 (EPA, 1995b)
= 0.95 for bituminous coals
= 0.875 for subbituminous coals = 0.55 to 0.85 for lignite, based on the Na content
= 1.0 for oil

When any source uses FGD equipment or another technology to control SO 2 emissions, either the fuel basis must be used for the manufacturing and rele ase calculations, or CEMS data can be used but only when the CEMS precedes the FGD or SO 2 control equipment. CEMS data after a flue gas desulfurization system cannot be used.
**Sulfuric Acid Released from Combustion (ER Comb**  **)**
For units that do not employ SCR or SNCR NOx c ontrol or FGC, the sulfu ric acid released is the product of the amount manufactured and the Tec hnology Impact Factors (F 2) for all downstream equipment (the air heater, the particulate control device, the FGD, etc.). For these units, the total sulfuric acid emissions can be calculated from Equation 4-3.

Equation 4-3 ER Comb = EM Comb • F2 (all that apply)

Units that do employ SCR or SNCR, and/or flue gas c onditioning, must consider these additional sources as described in the following sections.

Text Box A summarizes calculations for units equipped with an FGD process that employs partial flue gas bypass, which must account for the fact that the entire flue gas flow is not subject to sulfuric acid removal by the FGD process. This bypass factor is pertinent only to units that employ flue gas bypass.4-6 **Manufacture and Release from SCR and SNCR** 
This section describes a method to estimate how SCR can contribute to or reduce sulfuric acid emissions, while SNCR will only reduce such emissions.
As discussed in Section 3, SO 3 (and ultimately sulfuric acid) is produced by SCR, but can only be removed or reduced by SNCR due to the reac tion with residual ammonia. The sulfuric acid manufactured by SCR is the net result of produc tion by the catalyst and removal by the reaction of residual NH 3 from the SCR process. A key assumption in the calculation strategy is th at residual ammonia from either SCR or SNCR captures all available sulfuric acid as the (ammonium) bisulfate form. The bisulfate form is not reportable under the TRI reporting requirement and thus is not part of the manufacture calculation. If any additional ammonia reacts with the bisulfate, it is of no consequence to the sulfuric acid calculation – alt hough this issue will be importa nt when estimating ammonia releases.

The calculations for the manufacture of sulfuric acid by SCR and the release of sulfuric acid by SCR and SNCR are described in the following sections.
**Sulfuric Acid Manufacture by SCR (EM SCR**  **)** The following relationship estimates the total H 2 SO 4 manufactured from an SCR equipped utility boiler or steam generator:
Equation 4-4 EM SCR = K • S2 • f sops • E2 • F3 SCR where,

EM SCR = Total H 2 SO 4 manufactured from SCR, lbs per year

K = Conversion factor = 3063 S2 = SCR catalyst SO 2 oxidation rate (specified as a decimal, typically from 0.001- 0.03) Text Box A: Flue Gas Desulfurization Bypass Calculation

. Those units equipped with scrubbers where some of the flue gas bypasses the scrubber should take this into account in their combus tion release calculations. No credit for sulfuric acid removal should be taken for the fraction of the flue gas that bypasses the scrubber. Therefore, this amount of the flue gas should not be multiplied by the F2 factor for the scrubber. However, the flue gas volume should still be multiplied by the F2 factors for the other control devices. A modified equation considering partial scrubber bypass is given below and should be used where appropriate.

ER COMB = [SB f + (1 – SB f ) • F2

s ] • K • F1 • E2 • F2

x where, SB f = fraction of scrubber bypass, as a decimal
F2

s = F2 for scrubber
F2

x = All other applicable F2 factors except for scrubber.4-7 f

sops = Operating factor of SCR system, or the fraction of coal burn when the flue gas is directed through the SCR, whether NH 3 reagent is injected to derive NOx reduction or not. This value should reflect the hours the SCR reactor processed flue gas, which will be site-specific but can be approximated by generally 0.8 for year-round peaking operation, 0.98 for yea r-round base-loaded operation, or 0.43 for seasonal operation

E2 = SO 2 produced, tons per year

F3 SCR = Technology Impact Factor, for SCR The Technology Impact Factor for SCR (F3 SCR ) is required to adjust SO 3 content for the presence of alkaline fly ash, as described in Section 3, unless direct measurements exist for the subject unit documenting SO 3 increase across the SCR reactor. It is important to select the correct SO 2 oxidation rate for use in Equation 4-4. Typically, the SO 2 oxidation rate from SCR catalysts can range from as low as 0.3% of flue gas SO 2 content, up to 3% for low sulfur, highly alkaline coals (e.g., PRB). There are two means by which SO 2 oxidation is specified and measured for SCR process equipment, and each has significantly different implications for SO 3 produced. One method – based on act ual field tests in commercial units – does not require adjustment and can be us ed as reported to predict sulfuric acid. The other method is based on laboratory tests of catalys t samples in the absen ce of ash and alkaline materials, and must be adjusted to account for these latter factor s. The consequences of each of these methods on estimates of sulfuric acid emissions are described as follows: Full-Scale Catalyst Performance Tests. Ideally, SO 2 conversion data will be determined with commercial testing of fu ll-scale equipment. These data – measured on commercial plants under actual operating conditions – are the most authentic in re flecting actual SO 3 content, as the impact of ash alkalinity is taken into account . This approach reflects commercial process operation, and the resulting fractio nal oxidation rate can be used as the S2 value in Equation 4-4 without adjustment by the F3 SCR Technology Impact Factor. Laboratory Bench-Scale Tests . Some owners and process suppliers prefer to specify and conduct guarantee measurements for SO 2 oxidation on laboratory-scale e quipment using synthetic flue gases without fly ash. There are good reasons to select this methodology; evidence suggests SO 3 measurements in the environment of the test labo ratory are more accurate and reproducible than field tests. However, this method does not expose the catalyst being tested to ash, so there is no alkaline component to mitigate or absorb any SO 3 generated. Accordingly, SO 2 oxidation reported by this method exceeds that measured in commercial practice, particularly for PRB coals. SO 2 oxidation data from bench-scale tests can be u sed, but must be adjusted for the role of ash alkalinity. This adjustment is pr ovided by the Technology Impact factor F3 SCR . An F3 SCR factor for PRB coals is shown in Table 4-2. This factor is derived from measurements at two PRB-fired units. SO 3 emitted from these units was lower than specified in the catalyst guarantee, which was based on laboratory test data . At present, there are no data to support F3 SCR factors for other coals, so a factor of 1 (full penetration) is recommended.4-8 **Table 4-2 F3**  **SCR Technology Impact Factors for SCR** 

**Coal Type** F3 SCR PRB 0.17
Other Coals 1 (no data available)

SNCR will not result in the manufa cture of sulfuric acid, thus EM SNCR is by definition zero.

**Sulfuric Acid Released from SCR and SNCR**
The sulfuric acid released from SCR or SNCR is determined by subtracting from the sulfuric acid manufactured the amount remo ved by the residual ammonia, or ammonia slip. For SCR, the sulfuric acid released (ER SCR ) is estimated with the following relationship:
Equation 4-5 ER SCR = [EM SCR – (K

s • B • f sreagent • S NH3 )] • F2

x where,

ER SCR = Total H 2 SO 4 released from SCR, lbs per year

EM SCR = Total H 2 SO 4 manufactured from SCR, lbs per year

K

s = Conversion factor = 3799 B = Coal burn in TBtu/yr

f

sreagent = fraction of SCR operation with reagent injection, when residual NH 3 is produced that will remove SO 3 . The value of f sreagent will be similar to, but slightly less than, the value of f sops , defined for Equation 4-4.

S NH3 = NH 3 slip from SCR/SNCR, ppmv at 6% O 2 , wet:

• SCR averages 0.75 ppmv over catalyst guarantee period

• SNCR averages 5 ppmv

• Note: actual NH 3 slip data should be used if available F2

x = Technology Impact Fact ors, all that apply

The conversion factor K

s , equal to 3799, considers all relevant constants to yield the result in pounds per year of sulfuric acid. The derivation of this constant , for the case where residual NH 3 is reported in terms of 6% oxyge n and “wet” flue gas at 8.1% H 2 O, is presented in Text Box B. The coal burn rate in TBtu/yr is obtained from co al use records, such as those reported to EIA in Form 767. The operating factor of the SCR describes the portion of the coal burn that reflects the period of SCR operation, based on whether th e unit operates seasonally (0.43), annually in a base-load duty (0.98), or a nnually in peaking duty (0.80).4-9 Equation 4-6a specifies th e concentration of NH 3 in flue gas (S NH3 ) in terms of ppmv at 6% O 2 , wet flue gas basis. If the concentration of NH 3 is reported at different conditions, the value of the constant K

s will change. The following formula is used to adjust the value of the constant K

s :
Equation 4-6a **Ks (O 2**  **, H 2**  **O ) = 3799 (6% O 2**  **, 8.1% H 2**  **O)** • **[(100-8.1)/(100-new H 2**  **O)]**

• **[(20.9 – 6.0)/(20.9 – new O 2**  **)]** For example, if the ammonia concen tration is quantified at a value (in ppm) that is defined at 0% oxygen and a dry basis, the value of K

s that should be used is:

Equation 4-6b **K**
**s (O**  **2 , H**  **2 O) = 3799 (6% O**  **2 , 8.1% H**  **2 O)**  • **[(100-8.1)/(100-0)]**

• **[(20.9 – 6.0)/(20.9 – new O 2**  **)]**

**= 2489 lbs H 2**  **SO 4**  **/(TBtu** • **ppmv NH 3**  **@ 0% O 2**  **and dry).** This formula (Equation 4-6b) is us ed to calculate the value of K

s at any condition used to define the concentration of residual NH 3 . For SNCR, as there is no sulfuric acid manufact ure term, the sulfuric ac id release estimate (ER SNCR ) is a negative term which, when included in the calculations, will result in an overall reduction of sulfuric acid emissions.

Text Box B: Derivation of Conversion Factor, K S . The U.S. Code of Federal Regulations 40, Part 60, Table 19-1 “F Factors for Various Fuels” lists that 1 million Btu of heat input for bituminous or subbituminous coal will produce 10,640 wet standard cubic feet of flue gas, defined at 0% oxygen and on a wet basis at 20C and 760 mm Hg. Correcting this volume to 6% O 2 (typical at ESP conditions) yields a volume of 14,925 scf. The standard volume of one pound mole of any gas is 359 scf, defined at 0C and 760 mm Hg. Converting this to the English units standard of 20C (68°F), one pound mole occupies 385 standard cubic feet. Using these in the equation above,
(K

s • B • f

s • S NH3 ) = lbs H 2 SO 4 per yr =

B TBtu S NH3 scf NH 3 1 lb mol NH 3 1 lb mol H 2 SO 4 98 lbs H 2 SO 4 14925 scf fg 10 6 MBtu year 10 6 scf flue gas 385 scf NH 3 1 lb mol NH 3 1 lb mol H 2 SO 4 1 MBtu TBtu

Grouping terms,

= B • f

s • S NH3 • 3799
Therefore, the value of K

s is equal to 3799 lbs H 2 SO 4 /(TBtu • ppmv NH 3 @ 6% O 2 and wet).
If the value of NH 3 is known in wet flue gas at an O 2 content other than 6%, first convert the NH 3 concentration to a 6% wet flue gas basis in order to use th e preceding formula. The conversion of NH 3 at any flue gas O 2 content to the value at 6% O 2 wet basis uses the following formula:

NH 3 @ 6% = (NH 3 content at X%)*(15)/(21-X)
Where: NH 3 content at X% represents that measured at an O 2 concentration of X4-10 Accordingly, total sulfuric acid release (TSAR) is estimated for a generating unit equipped with SCR by the following equation:

**Equation 4-7** TSAR = ER Comb + ER SCR Or in the case of SNCR,

Equation 4-8 TSAR = ER Comb + ER SNCR For units equipped with flue gas desulfurization bypass, a series of calculations analogous to those described in the previous section for co mbustion-derived sulfuric acid are required. The calculations for SCR or SNCR ar e described in Text Box C.

**Manufacture and Release from Flue Gas Conditioning (FGC)** 

**Sulfuric Acid Manufactured from FGC**
Most SO 3 –based FGC systems, in order to moderate ash resistivity, strive to maintain a fixed concentration of SO 3 in the flue gas, typically between 5 and 7 ppm by volume (ppmv). Calculations to estimate the sulfuric acid manufact ured use the setpoint of the FGC system as the key input. The FGC system is assumed to opera te during most of the plant’s duty, except for perhaps startup and low load operation. The sulfuric acid manufactured by SO 3 -based FGC equipment (EM FGC ) is calculated as follows:

Equation 4-9 EM FGC = K e • B • f e • I s where,
EM FGC = Total H 2 SO 4 manufactured from FGC, lbs per year
K

e = Conversion factor = 3799, which is equivalent to Ks, as described in Text Box B. B = Coal burn in TBtu/yr Text Box C: Special Provision for Flue Gas Desulfurization Bypass

. Those units equipped with scrubbers where some of the flue gas bypasses the scrubber should take this into account in their SCR/SNCR release calculations also, as in the combustion release calculations. No credit for sulfuric acid removal should be taken for the fraction of the flue gas that bypasses the scrubber. Therefore, this amount of the flue gas should not be multiplied by the F2 factor for the scrubber. Howe ver, it should still be multiplied by the F2 factors for the other control devices. A modified equation considering partial scrubber bypass is given below and should be used where appropriate.

ER SCR = [SB f + (1 – SB f ) • F2

s ] • [EM SCR – (K

s • B • f

s • S NH3 )] • F2

x where, SB f = fraction of scrubb er bypass, as a decimal
F2

s = F2 factor for scrubber

F2

x = All other applicable F2 factors except for scrubber.4-11 F

e = Operating factor of FGC system, or the fraction of coal burn when the FGC system operates. This value is site-speci fic, must be determined for each unit, but generally will be about 0.8.
I

s = SO 3 injection rate in ppmv at 6% O 2 , wet; generally, = 7 ppmv if before the APH = 5 ppmv if after the APH
The conversion of SO 3 from measured conditions to 6% O 2 and wet basis is conducted using Equation 4-6a. FGC equipment that employs both SO 3 and NH 3 must be reported to ma nufacture sulfuric acid at the rate of SO 3 injection, regardless of whether ammoni a is used or not. FGC equipment that employs NH 3 alone does not manufacture sulfuric acid, and any ammonia will reduce the release of sulfuric acid by reacting with SO 3 or the resultant H 2 SO 4 . The reduction in flue gas sulfuric acid by reaction with ammonia de termines the sulfuric acid rel eased by FGC, discussed in the next section.
**Sulfuric Acid Released from FGC (ER FGC**  **)** The subsequent release of that portion of sulfuric acid associated with flue gas conditioning can be estimated from the sulfuric acid quantity ma nufactured, adjusted by the amount that reacts with ammonia in the particulate control device installed downstream of the FGC.
Equation 4-10 ER FGC = [EM FGC – (K e • B • f e • I NH3 )] • F3 FGC • F2
where,
ER FGC = Total H 2 SO 4 released from FGC, lbs per year
EM FGC = Total H 2 SO 4 manufactured from FGC, lbs per year
K

e = Conversion factor = 3799 B = Coal burn in TBtu/yr
F

e = Operating factor of FGC system, or the fraction of fuel burn when the FGC system operates. This value will be the same as F

e described previously and in many cases can be approximated by 0.8.
I NH3 = NH 3 injection for dual flue g as conditioning, ppmv at 6% O 2 , wet; generally 3 ppmv NH 3 if operating, or zero (0) if no ammonia is used.
F3 FGC = Technology Impact Fact ors for FGC, see Table 4-3 F2 = Technology Impact Factors for equipment after the ESP only, if no control equipment is installed after the ESP; F2 = 1.4-12 **Table 4-3 F3**  **FGC – Technology Impact Factor**  **s for FGC with Cold-Side ESP**

**Location Coals F3 FGC**  Upstream of APH Bituminous 0.25 Upstream of APH W. bituminous, subbituminous, & lignite 0.05
Downstream of APH Bituminous 0.10 Downstream of APH W. bituminous, subbituminous, & lignite 0.02 For other fuels, use F3 = 0.5 for startup fuel and F3 = coal factor for fuels co-fired as a minor fraction (<25%) with coal.

This approach leads to a possible co ntradiction in the behavior of SO 3 /H 2 SO 4 depending on the place in which the SO 3 /H 2 SO 4 enters the system. Depending on the source of the SO 3 , and for FGC where it is injected, the pr edicted removal within the air heater and ESP can differ. No mechanistic reason has been identified for the se differences – they emerge from the supporting data. The following passage describes this apparent anomaly.

For SO 3 manufactured by combustion, SCR, or intr oduced as FGC ahead of the air preheater, the method predicts sulfuric acid removal of 75% for eastern bituminous coals across an air preheater/cold-side ESP combination. However, a higher fraction of SO 3 or H 2 SO 4 is predicted to be removed for FGC if injected downstream of the air preheater. Specifically, as denoted in Table 4-3, 90% will be removed in a cold-side ESP for the eastern bituminous coal. Thus, for bituminous coals, the F3 factor for FGC intr oduced upstream of the a ir heater mirrors the behavior of SO 3 manufactured from combustion or SCR; th e method predicts th e same result for a molecule of SO 3 found ahead of the air preheater, regard less of its origin. However, for the same eastern bituminous coal, the F3 factor fo r FGC introduced downstream of the air heater yields a higher SO 3 removal (90%) than for SO 3 introduced ahead of the air heater. The difference in results is likely attributable to the limited number of data points, and uncertainty in the measurement. It is recommended that the methodology be executed as described, and future versions will attempt to resolve this difference.
For western or low-rank fuels, SO 3 injected ahead of the air heater as FGC is assumed to be 95% removed through the air heater and ESP. SO 3 is assumed to be 98% removed when injected downstream of the air heater. As these western bituminous, su bbituminous, and lignite coals feature significant alkaline content of ash, any SO 3 injected for FGC will likely be captured by both physical deposition and chemical reacti on. Accordingly, it is reasonable that SO 3 /H 2 SO 4 removal assumed for these coals be higher than for eastern bituminous coals. Further, as the injection of SO 3 on the cold-side of the air preheater is typically below the acid dewpoint, it can be expected that any injected SO 3 will condense on fly ash more readily compared to the slower cooling of the flue gas through the air preheater. For units equipped with flue gas desulfurization bypass, a series of calculations analogous to those described in the previous sections for combustion- and SCR-derived sulfuric acid are required. These calculations for FGC are described in Text Box D.4-13 **Total Manufacture and Release for Source** For any given source, the total manufacture and release of sulfuric acid is the sum of the individual manufacture or release estimates. Ther efore, if a site burns coal and uses both SCR and FGC, the amount of sulfuric acid manufac tured – by combustion, SCR, and/or FGC – is added together to determine the total amount. The amount of sulfuric aci d released is also calculated – again for combustion, SCR, and FGC – and summed to define the total. Both SCR and/or FGC may contribute a negative e ffect on sulfuric acid re lease, as the ammonia in the system can remove some or all of the sulfuric acid generated from co mbustion. Under these conditions, ammonia-based FGC can serve to only reduce the release of sulfuric acid. Since the release of sulfuric acid from combustion, SCR, and FGC are al l additive, any negative values calculated as a result of these circumstances will be accounted for in the total release equation. Accordingly, total sulfuric acid manufacture (T SAM) and release (TSAR) is estimated for a generating unit equipped with SCR and flue gas conditioning by the following equations:

Equation 4-11a: Manufacture

TSAM = EM Comb + EM SCR/SNCR + EM FGC Equation 4-11b: Release

TSAR = ER Comb + ER SCR/SNCR + ER FGC

Examples 1 through 4 in Appendix A de tail the use of these calculations.

**Total Release Calculation for S ources Employing Alkali Injection**  As described in Section 3, sources that employ al kali injection to mitigate stack opacity or a visible plume will have access to field measurements describing SO 3 concentration in flue gas,

Text Box D: Special Provision for Flue Gas Desulfurization Bypass

. Those units equipped with scrubbers where some of the flue gas bypasses the scrubber should take this into account in their FGC release calculations also, as in the combustion and SCR/SNCR release calculations. No cr edit for sulfuric acid removal should be taken for the fraction of the flue gas that bypasses the scrubber. Therefore, this amount of the flue gas should not be multiplied by the F2 factor for the scrubber. However, it should still be multiplied by the F2 factors for the other control devices. A modified equation considering partial scrubber bypass is given below and should be used where appropriate.

ER FGC = [SB f + (1 – SB f ) • F2

s ] • [EM FGC – (K

e • B • f

e • I NH3 )] • F3 FGC • F2

x

where, SB f = fraction of scrubber bypass, as a decimal
F2

s = F2 factor for scrubber
F2

x = All other applicable F2 factors except for scrubber.4-14 most likely at the stack. The concentration of SO 3 measured at the stack can be converted to a mass emission rate using Equation 4-12
Equation 4-12 ER ALKINJ = K alkali • B • S SO3 • F2

x • F alkali where,

ER ALKINJ = Total H 2 SO 4 released from unit equipped with alkali injection, lbs per year

K alkali = Constant, equal to 1.46 B = Coal burn in TBtu/yr

S SO3 = SO 3 content, as measured in the stack or particulate collector exit, ppmv at 6% O 2 , wet

F alkali = fraction of time unit is operated with alkali addition to remove SO 3 F2

x = Technology Impact Factors, to be applied only if SO 3 measurements are conducted at a location preceding the stack. The value of F2

x is 1 if measurements are conducted at th e stack, and there are no control components downstream of the measuremen t location. If the control device is an SO 2 scrubber, F2x is denoted as F2s, but is handled the same way. The Technology Impact Factors sele cted should represent the c ontrol equipment between the point of SO 3 measurement and the stack. For example, if a unit is equipped with only an ESP, and the SO 3 measurement is conducted at the ESP inlet, then the F2 factor for an ESP (Table 3-2) should be selected.

The conversion factor K alkali , equal to 1.46, considers all relevant constants to yield the result in pounds per year of sulfuric acid. The derivation of this constant , for the case where flue gas SO 3 is reported in terms of 6% oxyge n and “wet” flue gas at 8.1% H 2 O, is presented in Text Box E. The coal burn rate in TBtu/yr is obtained from co al use records, such as those reported to EIA in Form 767, for coal analysis on either on a wet or dry basis provides the same result.4-15 Text Box E: Derivation of Conversion Factor, K alkali . The U.S. Code of Federal Regulations 40, Part 60, Table 19-1 “F Factors for Various Fuels” lists that 1 million Btu of heat input for bituminous or subbituminous coal will produce 10,640 wet standard cubic feet of flue gas, defined at 0% oxygen and on a wet basis at 20oC and 760 mm Hg. Correcting this volume to 6% O 2 (typical at ESP conditions) yields a volume of 14,925 scf. The standard volume of one pound mole of any gas is 359 scf, defined at 0oC and 760 mm Hg. Converting this to the English units standard of 20oC (68°F), one pound mole occupies 385 standard cubic feet. Using these in the equation above,
(K alkali • B • S SO3 ) = lbs H 2 SO 4 per yr =

B TBtu S SO3 scf SO 3 98 lbs H 2 SO 4 14925 scf flue gas
year 10 6 scf flue gas 1 lb mol H 2 SO 4 1 MBtu

Grouping terms,

= B • S SO3 • 1.46
Therefore, the value of K alkali is equal to 1.46 lbs H 2 SO 4 /(TBtu • ppmv SO 3 @ 6% O 2 and wet).
If the value of SO 3 is known in wet flue gas at an O 2 content other than 6%, or an H 2 O content other than 8.1%, first convert the SO 3 concentration to a 6% O 2 , 8.1% H 2 O wet flue gas basis. The conversion of SO 3 at any flue gas O 2 content to the value at 6% O 2 and 8.1% H 2 O wet basis uses the following formula:
SO 3 (6% O 2 , 8.1% H 2 O)

= S SO3 (measured O 2 , H 2 O) • [(100-8.1)/(100-measured H 2 O)] • [(20.9 – 6.0)/(20.9 – measured O 2 )]5-1 

# 5
**ESTIMATING GUIDELINE: MULTIPLE FUEL OR BLENDED FUEL BOILERS** 
Estimating sulfuric acid production of steam boilers firing multiple or blended fuels – such as natural gas, fuel oil, and perhaps coal – uses th e same approach as for single fuels. This will consist of determining the cont ribution of each source (combustion, SCR or SNCR NOx control, and FGC) for each different fuel, and adjusting for loss or removal. It is assumed for multiple fuel boilers that the contribution of each fuel can be separated and treat ed individually. The same approach is to be used for boilers that fire a blended coal. This assumption is particularly important when considering blends of PRB with low or high sulfur eastern bituminous coal, as this approach accounts for the role of alkalinity in PRB ash in mitigating SO 3 . This approach of treating blends of coal as separate fuels in propor tion to the mass burn rate is believed to be conservative with regard to SO 3 emissions when considering PRB coal, in that it will likely project H 2 SO 4 emissions higher than actual. The ability of PRB coal to neutralize SO 3 by an amount that is greater th an a direct proportion of the coal blend is due to the extremely high content of alkaline material, particularly CaO. However, data to quantify this impact with any reasonable degree of confidence are not avai lable at present. Accordingly, the conservative approach is to presume an impact in direct pr oportion to the coal blend until a database can be developed. The sequence of calculations is performed fo r the first component of the blend, including calculations for SCR and FGC, if applicable. Th e sequence is repeated for each component. When complete, the total manufacture of sulf uric acid is calculate d by adding all of the manufacture totals for all fu els from all processes. Likewise, the release is summed over all processes and fuels. As an example, if a unit with an SCR and FGC bu rns mostly coal, but uses natural gas in a NOx reburn process and also disposes of used oil by combustion in the furnace, then the following sequence of calculations would be required:

1. Coal fuel

a. Combustion manufacture b. Combustion release

c. SCR manufacture d. SCR release

e. FGC manufacture f. FGC release 2. Natural gas

a. Combustion manufacture b. Combustion release

c. SCR manufacture d. SCR release

e. FGC manufacture f. FGC release5-2 3. Used oil

a. Combustion manufacture b. Combustion release

c. SCR manufacture d. SCR release

e. FGC manufacture f. FGC release 4. Sum manufacture and releases

a. Manufacture = 1a + 1c + 1e + 2a + 2c + 2e + 3a + 3c + 3e
b. Release = 1b + 1d + 1f + 2b + 2d + 2f + 3b + 3d + 3f

All of the manufactured results w ould be summed together and the releases summed also to give the final result. Example 5 in Appendix A details this calculation procedure.6-1 

# 6
**ESTIMATING GUIDELINE: COMBUSTION TURBINES**
Natural gas-fired sources typically have negligible content of sulfur in the fuel, thus sulfuric acid production is negligible. Facilities that burn only natural gas are not required to participate in the TRI reporting program. However, sources that are co-located with coal units will need to be included in the estimates for total sulfuric acid release for the site. The calculation described in this section can also be used to estimate sulfuric acid emissions for Prevention of Significant Deterioration (PSD) review of new natural gas-fired generation sites. The calculations for gas-fired units are structured very much the same as for coal- and oil-fired sources. For simple cycle combustion turbines, the only source of sulfuric acid is the sulfur in the fuel. The EPA AP-42 emissions factor suggests a va lue of 2000 grains of sulfur per million cubic feet of natural gas as a default su lfur content value. This value is equivalent to approximately 3.5 ppm of sulfur in the raw natural gas. A methodology to estimate manufacture and rele ase of sulfuric acid for simple cycle and combined cycle units is provided below.

**Simple Cycle Units** Given the current configuration of si mple cycle units, any sulfuric acid manufactured is released ; thus, the estimates of sulfuric acid are the same. This is because there is no equipment located following the simple cycle arrangement that removes sulfuric acid. Even though simple cycle units can be equipped with SCR, and th e use of SCR with sulfur-containing fuels will manufacture SO 3 , the exit gas temperature is t oo high to allow condensation of SO 3 or reaction with ammonia slip. Selective non-catalytic reducti on (SNCR) is not applied to simple cycle or combined cycle combustion turbines; therefore, no estimation procedure is provided for that configuration. Accordingly, the equations for formation of sulfuric acid from natural gas combustion are:

Equation 6-1 EM SC = K • F1 • E2 NG

where,
EM SC = total H 2 SO 4 manufactured from combustion, lbs/yr K = Molecular weight and units conversion
constant = 98.07 / 64.04 • 2000 = 3,063 98.07 = Molecular weight of H 2 SO 4 64.04 = Molecular weight of SO 2 Conversion from tons per year to pounds per year – multiply by 2000. F1 = Fuel Impact Factor for NG6-2 E2 NG = Sulfur dioxide (SO 2 ) emissions either: (1) recorded by a c ontinuous emissions monitor, tons/yr, or (2) calculated from fuel burn data, tons/yr.

SO 2 emissions can be obtained through a calcula tion using the heat input of natural gas.

Equation 6-2a E2 NG = K b • B NG • S
where,
E2 NG = Total SO 2 production from NG combustion, tons/yr
K

b = Molecular weight and units conversion constant = 0.0001359
B NG = Burn of NG in TBtu/yr S = Sulfur content of natural gas, in grains per million standard cubic feet (Mscf), typically 2000 gr/10 6 scf per EPA AP-42.

The derivation of constant K b is presented in Text Box F.

The SO 2 emissions can also be calculated fr om the volume of natural gas burned:
Equation 6-2b E2 NG = K NG • N1 • S where,
E2 NG = total SO 2 production from NG combustion, tons/yr

K NG = Molecular weight and units conversion constant = 1.427 • 10 -7
N1 = NG burn in million standard cubic feet (Mscf) per year S = NG sulfur content in grains per mil lion standard cubic feet, use EPA’s value of 2000 gr/10 6 scf as default

The derivation of constant K NG is presented in Text Box G

Text Box F: Derivation of Molecular Weight and Units Conversion Constant, K b K b is determined from the following equation.
(K b • B NG • S) = tons SO 2 per yr =
B NG TBtu S gr S 1 scf nat gas 10 12 Btu lb S 1 ton S 1 ton mol S 1 ton mole SO 2 64 tons SO 2

Year 10 6 scf nat gas 1050 Btu TBtu 7000 gr S 2000 lbs S 32 tons S 1 ton mol S 1 ton mole SO 2 Grouping terms,
= (B NG • S) • 64 / (1050 • 32 • 14) = (B NG • S) • 0.0001359
Therefore, the value of K b is equal to 0.0001359 tons SO 2 /(TBtu • grains S/million SCF NG).6-3 Table 6-1 presents the F1 factors for simple cycl e units as a function of stack temperature, as sulfuric acid vapor is related to the temperatur e of the exhaust. As simple cycle combustion turbines (CT) exhaust is usually around 1000°F, and TRI rules require the reporting of sulfuric acid (not of SO 3 ), the amount manufactured and released depends on stack temperature. Table 6-1 combines the temperature-based SO 3 to H 2 SO 4 conversion with the SO 2 to SO 3 conversion to give the Fuel Impact Factor, F1.

**Table 6-1 F1 – Fuel Factors for a Simple CT** 

**Stack T, °F F1**

300 0.055
400 0.055
500 0.047

600 0.022
700 0.0055
750 0.0027

800 0.0013
850 0.00071

900 0.00039
950 0.00022

1000 0.00013
1050 0.00008
1100 0.00005
1150 0.00003

1200 0.00002 Text Box G: Derivation of Molecular Weight and Units Conversion Constant, K NG (K NG • N1 • S) = tons SO 2 per yr =
N1 10 6 scf S gr S lb S 1 ton S 1 ton mol S 1 ton mole SO 2 64 tons SO 2

Year 10 6 scf nat gas 7000 gr S 2000 lbs S 32 tons S 1 ton mol S 1 ton mole SO 2

Grouping terms,
(N1 • S) • 64 / (7000 • 2000 • 32) = (N1 • S) • 1.427 • 10 -7

Therefore, the value of K NG is equal to 1.427 • 10 -7 tons SO 2 /(grains S)6-4 **Combined Cycle Units**

**Sulfuric Acid Manufactured** For the case of combined cycle units, the manufacture of sulfuric acid is due to both combustion and SCR NOx control. The manufacture due to combustion is estimated using an equation similar to Equation 4-11a, but accounting for only combustion and SCR sources.
For combustion, the manufacture of sulfuric acid for combined-cycle units is described by Equation 6-3.

Equation 6-3 EM CC = K • F1 • E2 NG where,
EM CC = total H 2 SO 4 released from combustion, lbs/yr K = Molecular weight and un its conversion constant = 98.07/64.04 • 2000 = 3,063 98.07 = Molecular weight of H 2 SO 4 ; 64.04 = Molecular weight of SO 2 ; Conversion from tons per year to pounds per year – multiply by 2000. F1= Fuel Impact Factor for NG (See Table 6-1)
E2 NG = Sulfur dioxide (SO 2 ) emissions either: (1) recorded by a continuous emissions monitor, tons/yr, or (2) calculated from fuel burn data, tons/yr. Equation 4-4 describes the manufacture of sulfuri c acid in an SCR. For the case of combined cycle combustion turbines, the SCR catalyst SO 2 oxidation rate will be approximately 0.03. A more precise value can be obtained fro m either field test reports of SO 2 oxidation, or from the vendor’s specification of the SCR catalyst or pr ocess. The Technology Impact Factor for SCR, F3 SCR , will be 1.0.

**Sulfuric Acid Released**
The total release of sulfuric acid from combined cy cle units is described by Equation 6-4, summing the sulfuric acid released by both combustion and SCR: Equation 6-4 TSAR = ER CCcom + ER CCSCR The sulfuric acid released by combustion in combin ed cycle units is estimated using an equation analogous to that for simple cycle units.
Equation 6-5 ER CCcom = EM CCcom • F2 CC The Technology Impact Factor fo r combined cycle units, F2 CC , accounts for removal in the heat exchanger. At present a value of 0.5 is assigned to this factor. The equation describing the sulfuric acid releas e from SCR equipment on combined cycle units is estimated using a relationship similar to Equation 4-5, as follows:6-5 Equation 6-6 ER CCSCR = [EM CCSCR – (K

s • B • f sreagent • S NH3 )] • F2

cc where,

ER CCSCR = Total H 2 SO 4 released from SCR, lbs per year

EM CCSCR = Total H 2 SO 4 manufactured from SCR, lbs per year

K

s = Conversion factor = 3799 B = Fuel burn in TBtu/yr

f

sreagent = Fraction of SCR operation with r eagent injection, when residual NH 3 is produced that will remove SO 3 . S NH3 = NH 3 slip from SCR, ppmv at 6% O 2 , wet (averages 0.75 ppmv over catalyst guarantee period. Actual NH 3 slip data should be used if available)

F2 CC = Technology Impact Factor for the combined cycle heat exchanger, equal to a value of 0.5. Example 7 of Appendix A illustrates a gas- fired combined cycle plant calculation.7-1 

# 7
**REFERENCES**

Benson, 2006a Benson, L. et al., “U ses of Lime for Controlling SO 3 Emissions,” Presentation to the 2006 DOE N ETL Environmental Controls Conference, May, 2006, Pittsburgh, PA. Benson, 2006b Benson, L., “Use of Magnesi um Hydroxide for Reduction of SO 3 Emissions from Coal-Fired Power Pl ants,” Presentation to the 2006 DOE NETL Environmental Controls C onference, May, 2006, Pittsburgh, PA.
Bowes, 2006 Bowes, E., et al., “Sulfur T rioxide Reduction Strategy Demonstrated At Dominion Energy’s Chesterfield St ation,” Proceedings of the 2006 Mega-Symposium, August, 2006, Baltimore, MD. Buckley, 2002 Buckley, W., et al., “Acid Mi st Causes Problems for FGD Systems,” Power Engineering, November, 2002.
Dahlin, 1991 Dahlin, R., et al., “Control of Acid Mist Emissions From FGD Systems,” paper presented to the EPRI-EPA-DOE 1991 SO 2 Control Symposium, Washington, DC, December, 1991.
Dombrowski, 2004 Dombrowski, K. et al., “SO 3 Mitigation Guide and Cost-Estimating Workbook,” Proceedings of the Combined Power Plant Air Pollution Control Mega-Symposium, Augus t 30-September 2, 2004, Washington, DC. EPA, 1991 EPA Code of Federal Regulations 40, Part 60, Appendix A, Method 1, Section 2.5, 1991 Edition. EPA, 1995a EPA, “Sulfuric Acid: Toxic Chemical Release Reporting: Community Right-To-Know.” Final Rule. 60 FR 34182. June 30, 1995. EPA, 1995b EPA, “Compilation of Air Pollu tant Emission Factors AP-42, Fifth Edition, Volume I: Stationary Point and Area Sources.” http://www.epa.gov/ttnchie1/ap42pdf/c01s01.pdf

. EPA, 1997 EPA, Emergency Planning and Community Right-to-Know Act - Section 313. Guidance for Reporting Sulfuric Ac id (acid aerosols including mists vapors, gas, fog, and other airborne forms of any particle size). EPA-745- R-97-007, November 1997. EPA, 1999 40 CFR Part 60, Appendix A, Metho d 2H- Determination of Stack Gas Velocity Taking into Account Veloc ity Decay Near the Stack Wall.7-2 EPA, 2006 Federal Register, August 22, 2006. 40 CFR Parts 72 and 75, Revisions to the Continuous Emissions Monitoring Rule for the Acid Rain Program and the NO

x Budget Trading Program, [OAR-2005-0132].
EPRI, 2001 EPRI Report 1004027, “Flue G as Sulfuric Acid Measurement Improvements,” August, 2001.
Gale, 2006 Gale. T., et al ., “Hydrated Lime for SO 3 Removal,” Proceedings of the Power Plant Air Pollutant Control “Mega Symposium”, Baltimore, MD, August, 2006.
Hamel, 2003 Hamel, B., “The Role of the Combustion Air Preheater in an Effective Multipollutant Control Strategy,” Proceedings of the Combined Power Plant Air Pollutant Control Mega Symposium, Washington, DC, May, 2003. Hardman, 1998 Hardman, R., Stacy R., Dismukes, E., Estimating Total Sulfuric Acid Emissions from Coal-Fired Power Plants. Internal Report of Research & Environmental Affairs Department, Southern Company Services, March 1998. Hardman, 1999 Hardman, R., Stacy, R., Dismukes, E., Harrison, K., Monroe, L., Estimating Total Sulfuric Acid Emissi ons from Coal-Fired Power Plants. Revised Internal Report of R esearch & Environmental Affairs Department, Southern Company Services, February 1999.
Harrison, 2004 Harrison, K., et al., “Estimating Total Sulfuric Acid Emissions from Stationary Power Plants: Revision 3 ( 2004).” Revised Internal Report of Research & Environmental Affairs Department, Southern Company Services, December, 2004. Harrison, 2005 Harrison, K., et al., “Estimating Total Sulfuric Acid Emissions from Stationary Power Plants: Revision 4 ( 2005).” Revised Internal Report of Research & Environmental Affairs Department, Southern Company Services, October, 2005.
Lindenhoff, 2004 Lindenhoff, Peter, “S CR Catalyst Developments: SO 2 Oxidation,” presentation to the EPRI 2004 Workshop on Selective Catalytic Reduction, November, 2004, Pittsburgh, PA.
Monroe, 2001 Monroe, L. and K. Harrison, “An Updated Method for Estimating Total Sulfuric Acid Emissions from Statio nary Power Plants: Revision 1,” White Paper Issued by Southern Company Services, March, 2001.
Monroe, 2006 Monroe, L., et al., “A Review of Sulfuric Acid Formation and Behavior in Coal-Fired Power Plants,” Proc eedings of the 2006 Mega-Symposium, August, 2006, Baltimore, MD.
Moser, 2007 Moser, R., “SO 3 ’s Impact on Plant O&M: Part III,” Power Magazine,7-3 April, 2007. Ritzenthaler, 2006 Ritzenthaler, D. et al., “A System Approach to SO 3 Mitigation With Trona,” Proceedings of the Power Plant Air Pollutant Control “Mega Symposium”, Baltimore, MD, August, 2006.
Saranuc, 1999 Saranuc, N., et al., “Factors Affecting Sulfuric Acid Emissions From Boilers,” Proceedings of the Combined Power Plant Air Pollutant Control Mega Symposium, Atlanta, GA, August, 1999.
Senior, 2002 Senior, C.L., et al., “Simulation of SO 3 Production,” Fuel Processing Technology, 2000, 63, 197-213.
Srivastava, 2004 Srivastava, R., et al., “Emis sions of Sulfur Trioxide from Coal-Fired Power Plants,” Journal of the A ir & Waste Management Association, Volume 54, June 2004.
Weilert, 2004 C. Weilert, “Wet ESPs vs. Sorbent Injection for SO 3 Control,”Proceedings of the Combined Power Plant Air Pollution Control MegaSymposium, August 30-September 2, 2004, Washington, DC.A-1 

# A
**EXAMPLE CALCULATIONS**

**Example 1: Conventional Coal -Fired Boiler with an ESP**  A 500 MW pulverized coal-fired (PC) boiler, equipped with a cold-side electro static precipitator, burns an Eastern bituminous coal. The coal u sed in the reporting year is 1,126,938 tons with a weighted average sulfur con centration of 2.0% and a hea ting value of 12,000 Btu/lb.

**Solution** Manufactured

E2 = K1 • K2 • C1 • S1

E2 = 0.02 • 0.95 • 1,126,938 • 2.0 = 42,824 tons SO 2 /yr

EM Comb = K • F1 • E2

EM Comb = 3063 • 0.008 • 42,824 = 1,049,359 lbs H 2 SO 4 /yr The 25,000 lbs/yr threshold has been exceeded; ther efore, a release estimate must be made and the result reported on Form R.

Released

ER comb = K • F1 • F2 • E2

ER comb = 3063 • 0.008 • (0.49 • 0.49) • 42,824 = 259,951 lbs H 2 SO 4 /yr

Where F2 = Air Heater • Cold-Side ESP

F2 = 0.49 • 0.49 = 0.24

**Example 2: SCR Added to Example 1** A 500 MW PC boiler, equipped with a cold-side el ectrostatic precipitato r, burns an Eastern bituminous coal. The plant is equipped with an SCR process that operates during the ozone season only, so that 0.43 of the coal burn occu rred with the SCR operating. The SCR catalyst SO 2 oxidation rate specified in th e design is 0.75%, and the ammoni a slip is estimated to be 0.75 ppmv. The coal used in the reporting year is 1,126,938 tons with a weighted average sulfur concentration of 2.0% and a h eating value of 12,000 Btu/lb.A-2 **Solution** Manufactured

E2 = K1 • K2 • C1 • S1

E2 = 0.02 • 0.95 • 1,126,938 • 2.0 = 42,824 tons SO 2 /yr

Combustion

EM comb = K • F1 • E2

EM comb = 3063 • 0.008 • 42,824 = 1,049,359 lbs H 2 SO 4 /yr

SCR

EM SCR = K • S2 • f

s • E2

EM SCR = 3063 • 0.0075 • 0.43 • 42,824 = 423,023 lbs H 2 SO 4 /yr

Total

TSAM = EM comb + EM SCR TSAM = 1,049,359 + 423,023 lbs H 2 SO 4 /yr
TSAM = 1,472,382 lbs H 2 SO 4 /yr The 25,000 lbs/yr threshold has been exceeded; ther efore, a release estimate must be made and the result reported on Form R.

Released

Combustion

ER Comb = K • F1 • F2 • E2

ER Comb = 3063 • 0.008 • (0.49 • 0.49) • 42,824 = 251,951 lbs H 2 SO 4 /yr

Where F2 = Air Heater • Cold-Side ESP

F2 = 0.49 • 0.49 = 0.24

SCR
B = 1,126,938 tons/yr • 2000 lbs/ton • 12,000 Btu/lb • 1 TBtu/10 12 Btu B = 27.05 TBtu/yr

ER SCR = [EM SCR – (K

s • B • f

s • S NH3 )] • F2 • F2

ER SCR = [423,023 – (3799 • 27.05 • 0.43 • 0.75)] • 0.49 • 0.49

ER SCR = 93,611 lbs H 2 SO 4 /yr

TotalA-3 TSAR = E1’ comb + E1’ SCR TSAR = 251,951 + 93,611 lbs H 2 SO 4 /yr
TSAR = 345,562 lbs H 2 SO 4 /yr

**Example 3: Alkali Injection Added to Example 1** A 500 MW PC boiler, equipped with a cold-side el ectrostatic precipitato r, burns an Eastern bituminous coal. The plant employs injection of alkali material (e.g., lime, sodium bicarbonate, sodium bisulfate, etc.) to control SO 3 emissions at the stack. The plant operator has conducted a series of field tests to determine the amount of al kali material that must be injected to limit flue gas SO 3 concentration at the stack. The test contract or has issued a report defining the amount of alkali that should be added to limit the stack SO 3 to 5 ppm, as measured in the flue gas at 6.6% O 2 , and 8.8% moisture. The alkali injection system will be operated throughout the entire year, so that no more than 5 ppm of SO 3 at the stated conditions of excess O 2 and moisture exist in the stack. The coal burn rate in the reporting year is 1,126,938 tons, with a weighted average sulfur concentration of 2.0%, and a heating value of 12,000 Btu/lb.

The calculation of manufactured sulfuric acid is the same as Example 1, and is repeated here:

**Solution** Manufactured

E2 = K1 • K2 • C1 • S1

E2 = 0.02 • 0.95 • 1,126,938 • 2.0 = 42,824 tons SO 2 /yr

Combustion

EM comb = K • F1 • E2

EM comb = 3063 • 0.008 • 42,824 = 1,049,359 lbs H 2 SO 4 /yr

SCR

EM SCR = K • S2 • f

s • E2

EM SCR = 3063 • 0.0075 • 0.43 • 42,824 = 423,023 lbs H 2 SO 4 /yr

Total

TSAM = EM comb + EM SCR TSAM = 1,049,359 + 423,023 lbs H 2 SO 4 /yr
TSAM = 1,472,382 lbs H 2 SO 4 /yr The 25,000 lbs/yr threshold has been exceeded; ther efore, a release estimate must be made and the result reported on Form R.A-4 Released

The total sulfuric acid released is based on the maximum value allowed by alkali injection, as measured in the stack, and the volume flow rate of combustion products processed.

The concentration of SO 3 measured at the stack can be converted to a mass emission rate, as described by Equation 4-12

ER ALKINJ = K alkali • B • S SO3 • F alkali • F2

x where,

ER ALKINJ = Total H 2 SO 4 released from unit equipped with alkali injection, lbs per year

K alkali = Constant, equal to 1.46, with units of lbs H 2 SO 4 /(TBtu ppmv SO 3 ) (SO 3 measured at @ 6% O 2 and 8.1% H 2 O) B = 27.05 TBtu/yr, for the specific case of Example 1

S SO3 = SO 3 content as measured in the stack or pa rticulate collector exit, corrected to a concentration basis of ppmv at 6% O 2 , 8.1% moisture

F alkali = fraction of operation with alkali addition to remove SO 3 . F2

x = 1 (as the SO 3 measurement is in the stac k, there are no control technology components downstream of the measurement)

The conversion factor K alkali is equal to 1.46 (see Text Box E). Th is constant is derived for the case where flue gas SO 3 is reported in terms of 6% oxygen and wet flue gas at 8.1% H 2 O.

The SO 3 concentration of 5 ppm in the stack is measure d at slightly different conditions of excess O 2 and moisture, compared to the reference conditions of 5% O 2 , at 8.1% H 2 O.

S SO3 (6% O 2 , 8.1% H 2 O) = S SO3 (measured O 2 , H 2 O) • [(100-8.1)/(100-measured H 2 O)] • [(20.9 – 6.0)/(20.9 – measured O 2 )]

S SO3 (6% O 2 , 8.1% H 2 O) = 5 • [1.0077) • [1.034]

S SO3 (6% O 2 , 8.1% H 2 O) = 5.2 ppm

The coal burn rate in TBtu/yr is obtained from coal use records.

ER ALKINJ = [1.46] • [27.05] • [5.2] • [1] • [1]

ER ALKINJ = 205.9 lbs/yr

TSAR = ER ALKINJ TSAR = 205.9 lbs/yrA-5 **Example 4: 500 MW PRB-fired Boiler with ESP, SCR** A 500 MW PC boiler, equipped with a cold-side elect rostatic precipitator, burns a PRB coal. The plant is equipped with an SCR process that op erates during the ozone season only, so that 0.43 of the coal burn occurred with the SCR operating. The SCR catalyst SO 2 oxidation rate specified in the design is 2%, and the ammoni a slip is estimated to be 0.7 5 ppmv. The coal used in the reporting year is 1,384,552 tons with a weighted average sulfur concentration of 0.40% and a heating value of 8,500 Btu/lb.

**Solution** Manufactured

E2 = K1 • K2 • C1 • S1

E2 = 0.02 • 0.875 • 1,384,552 • 0.40 = 9,692 tons SO 2 /yr

Combustion

EM comb = K • F1 • E2

EM comb = 3063 • 0.0018 • 9,692 = 53,435 lbs H 2 SO 4 /yr

SCR

EM SCR = K • S2 • f

s • f 3SCR • E2

EM SCR = 3063 • 0.020 • 0.43 • 0.17 • 9,692 = 43,402 lbs H 2 SO 4 /yr

Total

TSAM = EM comb + EM SCR TSAM = 53,435 + 43,402 lbs H 2 SO 4 /yr
TSAM = 96,837 lbs H 2 SO 4 /yr The 25,000 lbs/yr threshold has been exceeded; ther efore, a release estimate must be made and the result reported on Form R.

Released

Combustion

ER Comb = K • F1 • F2 • E2

ER Comb = 3063 • 0.008 • (0.56 • 0.73) • 9,692 = 97,087 lbs H 2 SO 4 /yr

Where F2 = Air Heater • Cold-Side ESP

F2 = 0.56 • 0.73 = 0.41A-6 SCR
B = 47,118 tons/yr • 2000 lbs/ton • 8,500 Btu/lb • 1 TBtu/10 12 Btu B = 0.80 TBtu/yr

ER SCR = [EM SCR – (K

s • B • f

s • S NH3 )] • F2 • F2

ER SCR = [43,402 – (3799 • 0.80 • 0.43 • 0.75)] • 0.56 • 0.73

ER SCR = 17,342 lbs H 2 SO 4 /yr

Total

TSAR = E1’ comb + E1’ SCR TSAR = 97,087 + 17,342 lbs H 2 SO 4 /yr
TSAR = 114,429 lbs H 2 SO 4 /yr

**Example 5: FGC Added to Example 1** A 500 MW PC boiler, equipped with a cold-side el ectrostatic precipitato r, burns an Eastern bituminous coal. The plant is equipped with a FGC process that injects both SO 3 and NH 3 , with the SO 3 injected upstream of the air preheater. The SO 3 is injected at 7 ppmv at 6% O 2 wet, and the ammonia at 3 ppmv also at 6% O 2 wet. The FGC system operates whenever the plant is on, except during startup and shutdown, with an operating factor estimat ed at 0.9. The coal used in the reporting year is 1,126,938 tons with a weight ed average sulfur concentration of 2.0% and a heating value of 12,000 Btu/lb.

**Solution** Manufactured

E2 = K1 • K2 • C1 • S1

E2 = 0.02 • 0.95 • 1,126,938 • 2.0 = 42,824 tons SO 2 /yr

Combustion

EM Comb = K • F1 • E2

EM Comb = 3063 • 0.008 • 42,824 = 1,049,359 lbs H 2 SO 4 /yr

FGC
B = 1,126,938 tons/yr • 2000 lbs/ton • 12000 Btu/lb • 1 TBtu/10 12 Btu B = 27.05 TBtu/yr

EM FGC = K

e • B • f

e • I

s EM FGC = 3799 • 27.05 • 0.9 • 7 = 647,407 lbs H 2 SO 4 /yrA-7 Total

TSAM = EM Comb + EM FGC TSAM = 1,049,359 + 647,407 lbs H 2 SO 4 /yr
TSAM = 1,696,766 lbs H 2 SO 4 /yr The 25,000 lbs/yr threshold has been exceeded; ther efore, a release estimate must be made and the result reported on Form R.

Released

Combustion

ER Comb = K • F1 • F2 • E2

ER Comb = 3063 • 0.008 • (0.49 • 0.49) • 42,824 = 251,951 lbs H 2 SO 4 /yr

Where F2 = Air Heater • Cold-Side ESP

F2 = 0.49 • 0.49 = 0.24

FGC
B = 1,126,938 tons/yr • 2000 lbs/ton • 12000 Btu/lb • 1 TBtu/10 12 Btu B = 27.05 TBtu/yr

ER FGC = [EM FGC – (K

e • B • f

e • I NH3 )] • F3 • F2

ER FGC = [647,407 – (3799 • 27.05 • 0.9 • 3.0)] • 0.25 • 1.0

ER FGC = 92,487 lbs H 2 SO 4 /yr

Since there are no other control devices after the ESP, then F2 = 1.0.

Total

ESAR = ER Comb + ER FGC ESAR = 251,951 + 92,487 lbs H 2 SO 4 /yr
ESAR = 344,438 lbs H 2 SO 4 /yr

**Example 6: SCR and FGC Added to Example 1** A 500 MW PC boiler, equipped with a cold-side el ectrostatic precipitato r, burns an Eastern bituminous coal. The plant is equipped with an SCR process that operates during the ozone season only, so that 0.43 of the coal burn occu rred with the SCR operating. The SCR catalyst SO 2 oxidation rate specified in th e design is 0.75%, and the ammoni a slip is estimated to be 0.75 ppmv. The plant is also equipped with a FGC process that injects both SO 3 and NH 3 , with the SO 3 injected upstream of the air preheater. The SO 3 is injected at 7 ppmv at 6% O 2 wet, and the ammonia at 3 ppmv also at 6% O 2 wet. The FGC system operates whenever the plant is on,A-8 except during startup and shutdown, with an operating factor estimat ed at 0.9. The coal used in the reporting year is 1,126,938 tons with a weight ed average sulfur concentration of 2.0% and a heating value of 12,000 Btu/lb.

**Solution** From previous examples: Manufactured

Tota l

TSAM = EM Comb + EM SCR + EM FGC TSAM= 1,049,359 + 423,023 + 647,407 lbs H 2 SO 4 /yr
TSAM = 2,119,789 lbs H 2 SO 4 /yr The 25,000 lbs/yr threshold has been exceeded; ther efore, a release estimate must be made and the result reported on Form R.

Released

Combustion

ER Comb = K • F1 • F2 • E2

ER Comb = 3063 • 0.008 • (0.49 • 0.49) • 42,824 = 251,951 lbs H 2 SO 4 /yr

SCR

ER SCR = [EM SCR – (K

s • B • f

s • S NH3 )] • F2 • F2

ER SCR = [423,023 – (3799 • 27.05 • 0.43 • 0.75)] • 0.49 • 0.49

ER SCR = 93,611 lbs H 2 SO 4 /yr

FGC

ER FGC = [EM FGC – (K E • B • f E • I NH3 )] • F3 • F2

ER FGC = [647,407 – (3799 • 27.05 • 0.9 • 3.0)] • 0.25 • 1.0

ER FGC = 92,487 lbs H 2 SO 4 /yr

Total

TSAR = ER Comb + ER SCR + ER FGC TSAR = 251,951 + 93,611 + 92,487 lbs H 2 SO 4 /yr
TSAR = 438,049 lbs H 2 SO 4 /yrA-9 **Example 7: Coal-Fired Boiler with FGC, NG Startup Fuel, and Used Oil Co-Firing**  A 500 MW PC boiler, equipped with a cold-side el ectrostatic precipitato r, burns an Eastern bituminous coal as the main fuel. The plant is e quipped with an SCR process that operates during the ozone season only, so that 0.43 of the coal burn occurred with the SCR operating. The ammonia slip is estimated to be 0.75 ppmv. The pl ant is also equipped with a FGC process that injects both SO 3 and NH 3 , with the SO 3 injected upstream of the air preheater. The SO 3 is injected at 7 ppmv at 6% O 2 wet, and the ammonia at 3 ppmv also at 6% O 2 wet. The FGC system operates whenever the plant is on, except during startup and shutdown, with an operating factor estimated at 0.9. The coal used in the reporting year is 1,126,938 t ons with a weighted average sulfur concentration of 2.0% and a heating va lue of 12,000 Btu/lb. Natural gas is used as a startup fuel, with 0.5 TBtu per year. During start up, neither the SCR nor the FGC system is used. Used oil is also burned, with 483.2 tons burned ( 0.0185 TBtu/yr) in the year. Since the used oil is burned when the unit is at full load, it is bur ned while the SCR and FGC are both operating. The used oil has a sulfur cont ent of 0.1% from analysis.
**Solution** Coal fuel calculations Manufacture d from coal, from previous examples

Total

TSAM = EM Comb + EM SCR + EM FGC TSAM = 1,049,359 + 423,023 + 647,407 lbs H 2 SO 4 /yr
TSAM = 2,119,789 lbs H 2 SO 4 /yr

Released from coal, from previous examples

Total

TSAR = ER Comb + ER SCR + ER FGC TSAR = 251,951 + 93,611 + 92,487 lbs H 2 SO 4 /yr
TSAR = 438,049 lbs H 2 SO 4 /yr Natural gas fuel calculations Manufactured from natural gas

Combustion

E2 NG = K b • B NG • S

E2 NG = 0.0001359 • 0.5 TBtu/yr • 2000 gr/10 6 scf

E2 NG = 0.136 tons SO 2 /year

EM Comb = K • F1 • E2 NG EM Comb = 3063 • 0.01 • 0.136A-10 EM Comb = 4.16 lbs H 2 SO 4 manufactured

No sulfuric acid is manufactured in either the SCR or FGC.

Released from natural gas

Combustion

ER Comb = K • F1 • F2 • E2 NG ER Comb = 3063 • 0.01 • 0.49 • 0.49 • 0.136

ER Comb = 1.00 lbs H 2 SO 4 released F2 is taken to be equal to 0.49 fo r the air heater and 0.49 for the ESP.

Used oil fuel calculations Manufactured from used oil

Combustion

E2 = K1 • K2 • C1 • S1

E2 = 0.02 • 1.0 • 483.2 • 0.1

E2 = 0.966 tons SO 2 /year

EM Comb = K • F1 • E2

EM Comb = 3063 • 0.0175 • 0.966

EM Comb = 51.8 lbs H 2 SO 4 manufactured

SCR

EM SCR = K • S2 • f

s • E2

EM SCR = 3063 • 0.0075 • 1.0 • 0.966

EM SCR = 22.2 lbs H 2 SO 4 manufactured

FGC

EM FGC = K

e • B • f

e • I

s EM FGC = 3799 • 0.0185 • 1.0 • 7.0

EM FGC = 492 lbs H 2 SO 4 manufactured

Total

TSAM = EM Comb + EM SCR + EM FGC TSAM = 51.8 + 22.2 + 492 lbs H 2 SO 4 /yrA-11 TSAM = 566 lbs H 2 SO 4 /yr

Released from used oil

Combustion

ER Comb = K • F1 • F2 • E2

ER Comb = 3063 • 0.0175 • 0.49 • 0.49 • 0.966

ER Comb = 12.43 lbs H 2 SO 4 released

SCR

ER SCR = [EM SCR – (K

s • B • f

s • S NH3 )] • F2 • F2

ER SCR = [22.2 – (3799 • 0.0185 • 1.0 • 0.75)] • 0.49 • 0.49

ER SCR = -7.33 lbs H 2 SO 4 /yr F2 is taken to be equal to 0.49 fo r the air heater and 0.49 for the ESP.

FGC

ER FGC = [EM FGC – (K

e • B • f

e • I NH3 )] • F3 • F2

ER FGC = [492 – (3799 • 0.0185 • 1.0 • 3.0)] • 0.25 • 1.0

ER FGC = 70.3 lbs H 2 SO 4 /yr

Total

TSAR = ER Comb + ER SCR + ER FGC TSAR = 12.43 – 7.33 + 70.3 lbs H 2 SO 4 /yr

TSAR= 75.4 lbs H 2 SO 4 /yr

Grand totals for all fuels Manufactured

TSAM = TSAM coal + TSAM NG + TSAM oil TSAM = 2,119,789 + 4.16 + 566 lbs H 2 SO 4 /yr
TSAM = 2,120,359 lbs H 2 SO 4 /yr

Released

TSAR = TSAR coal + TSAR NG + TSAR oil TSAR = 438,049 + 1.00 + 75.4 lbs H 2 SO 4 /yr
TSAR = 438,125 lbs H 2 SO 4 /yrA-12 **Example 8: Natural G as Combined Cycle Plant**  A natural gas-fired combined-cycle unit uses 12.3 TB tu of natural gas, with the standard sulfur content.

**Solution** Manufactured

E2 NG = K b • B NG • S = 0.0001359 • 12.3 • 2000 = 3.343 tons SO 2 /yr EM CC = K • F1 • E2 NG = 3063 • 0.0555 • 3.343 = 568 lbs H 2 SO 4 manufactured

Released

ER CC = K • F1 • F2 • E2 NG = 3063 • 0.0555 • 0.5 • 3.343 = 284.5 lbs H 2 SO 4 released (F2 = 0.5 because of the low temperature of th e back-end tubes of the HRSG, like an air heater.)B-1 

# B
**CHRONOLOGY OF CHANGES TO EPRI SULFURIC ACID ESTIMATION MODEL** 

EPRI, 2008 (EPRI Report 1016384 )

Modification Description Alkali Injection Added a procedure to estima te a stack release using a measured or specified stack gas SO 3 concentration, to support estimates on units with alkali injection. Combustion Turbines Clarified procedures for estimating emissions from simple and combined cycle CTs. Blended Coals New method calculates SO 3 manufacture by calculating the SO 3 emission rate separately for each of the component coals, and proportioning the contribution of SO 3 from each. The prior method assumed the SO 3 production was the same as that of the major coal component. Examples Provided new example calcul ations for alkali injection and blended coal.
EPRI, 2007 (Report 1014773 ) changes from Harrison, 2005.

Modification Description Formatting Adapted Southern Company paper (Harrison, 2005) to EPRI format. Fuel (F1) Factors Changed the followi ng F1 factors based on additional data: Low S E. Bit, Dry Boiler – from 0.0080 to 0.0082 Subbit. (including PRB), Dr y Boiler – from 0.0014 to 0.0018 Subbit. (including PRB), Cyclone – from 0.003 to 0.0018
Technology (F2) Factors A dded new F2 Factors: Air Preheater, PRB fuel - 0.56 Cold-side ESP, PRB fuel – 0.73
SCR Added a Technology Impact Factor for SCR, F3 SCRElectric Power Research Institute • 3412 H illview Avenue, Palo Alto, California 94304 • PO Box 10412, Palo Alto, California 9 4303 • USA 800.313.3774 • 650.855.2121 • askepri@epri.com • www.epri.com **Export Control Restrictions** Access to and use of EPRI Intellectual Property is granted with the specific understanding and requirement that responsibility for ensuring full compliance with all applicable U.S. and foreign export laws and regulations is being undertaken by you and your company. This include s an obligation to ensure that any individual receiving access hereunder who is not a U.S. citizen or permanent U.S. resident is permitted access under applicable U.S. and foreign export laws and regulations. In the event you are uncertain whether you or your company may lawfully obtain access to this EPRI Intellectual Property, you acknowledge that it is your obligation to consult with your company’s legal counsel to determine whether this access is lawful. Although EPRI may make available on a case-by-case basis an informal assessment of the applicable U.S. export classification for specific EPRI Intellectual Property, you and your company acknowledge that th is assessment is solely for informational purposes and not for reliance purposes. You and your company acknowledge that it is still the obligation of you and your company to make your own assessment of the applicable U.S. export classification and ensure compliance accordingly. You and your company understand and acknowledge your obligations to make a prompt report to EPRI and the appropriate authorities regarding any access to or use of EPRI Intellectual Property hereunder that may be in violation of applicable U.S. or foreign export laws or regulations. **The Electric Power Research Institute (EPRI)** The Electric Power Research Institute (EPRI), with major locations in Palo Alto , California, and Charlotte, North Carolina, was established in 1973 as an independent, nonprofit center for public interest energy and environmental research. EPRI brings together members, participants, the Institute’s scientists and engineers, and other leading experts to work collaboratively on solutions to the challenges of electric power. These solutions span nearly every area of electricity generation, delivery, and use, including health, safety, and environment. EPRI’s members represent over 90% of the electricity generated in the United States. International participation represents nearly 15% of EPRI’s total research, development, and demonstration program.
Together...Shaping the Future of Electricity

© 2008 Electric Power Research Institute (EPRI), Inc. All rights reserved. Electric Power Research Institute and EPRI are registered service marks of the Electric Power Research Institute, Inc.
Printed on recycled paper in the United States of America 101638 4