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

Version 2010a

**1020636**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

Version 2010a

1020636 Technical Update, April 2010

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 **Fossil Energy Research Corporation**

**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**
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... SHAPING THE FUTURE OF ELECTRICITY are registered service marks of the Electric Power Research Institute, Inc. Copyright © 2010 Electric Power Research Institute, Inc. All rights reserved.

## CITATIONS This document was prepared by Fossil Energy Research Corporation 23342C South Pointe Laguna Hills, CA 92653 Principal Investigator J. Muncy This document describes research sponsored by the Electric Power Research Institute (EPRI). This publication is a corporate document that shoul d be cited in the lite rature in the following
manner: Estimating Total Sulfuric Acid Emissions from Stationary Power Plants: Version 2010a. EPRI, Palo Alto, CA: 2010. 1020636.

iii

## PRODUCT DESCRIPTION

This report provides a methodology to estimate su lfuric acid emissions from fossil-fuel-fired electrical power production facilities. The me thodology was developed by Southern Company Services (SCS) and modified by EPRI with perm ission from the developers. The calculations presented in this report allow owners of power plants to estimate the sulfuric acid manufactured during fuel combustion, removed by air pollution c ontrol equipment or flue gas treatment, and released to the environment in stack gases.
**Results and Findings** The power generation units considered in the repo rt 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 provi ded for estimating removal or production of sulfuric acid by pollution control devices and flue gas treatments. **Challenges and Objectives** Sulfuric acid releases from electri c 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 emissions. There is cu rrently no other published approach with a comparable amount of supporting measuremen ts. EPRI will continue to enhance the methodology by adding to the underl ying database and refining th e calculations to address new flue gas treatment approaches. **Approach** The manufacture and release of su lfuric acid from coal-, oil-, and natural gas-fired electrical generation units were estimated from field test data. Measurements from multiple facilities were used to develop sulfuric acid removal factors for various coal types and fa cility configurations. **Keywords** Sulfuric acid Toxics Release Inventory Air emissions

v

## ACKNOWLEDGEMENTS

The methodology described in this document was developed by Southern Company Services and modified, with permission, by EPRI. Individuals re sponsible for the development of the original Southern Company sulfuric acid model are Keith E. Harrison and Larry S. Monroe, Ph.D. of the Southern Company.

vii

## 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 airborne forms of a ny particle 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 ac id, and then cools and condenses to form small droplets of the acid. This document provides a methodology to estimate su lfuric acid emissions from fossil-fuel-fired electrical power production facilities. The met hodology 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 Southern Company Services to modify the SCS estimation method to include additional data and improvements, and to publish this method under EPRI sponsorship. The current 2010 version of this report contains several updates and changes to EPRI’s 2008 version (Report No. 1016384). The basic method for estimating sulfuric acid em issions 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 cont rol process selective catalytic reduction (SCR), and (3) flue gas conditioning (FGC), in which SO 3 is added to flue gas to improve particulate control device performance. Next, 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 proc ess of selective noncatalytic reduction (SNCR), and other types of FGC. This paper also provides a method to account for the impact of SO 3 /H 2 SO 4 removal technologies such as the addition of calciumbased, sodium-based, or other alkaline reagents , as described by Dombro wski (2004) and Weilert (2004).
The current estimation method is based on an ev er-growing database of measurements of SO 3 emissions from combustion systems, primarily coal -fired boilers. The 20 08 version of the model was based on data from over 40 coal-fired units , and the current 2010 version adds data from 13 new sources, representing vari ous boiler types and coal s ources. The estimates of SO 3 production from combustion of coal are consistent with theoretical predictions that approximately 1% of the sulfur in coal is converted to SO 3 , although a wide range of conversions from 0.2% to 1.6% is reported, depending on coal source a nd boiler type. Data are obtaine d from field tests, reporting the removal of SO 3 or H 2 SO 4 by air heaters, particulate control equipment such as electrostatic precipitators (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 estimate quantities released to the air.

ixThe 2010 version adds more than 10 new sources of measurement data of SO 3 emissions and introduces a new methodology for determining a Fuel Impact Factor (estimate of SO 2 conversion to SO 3 in the boiler) for eastern b ituminous coals. Several “technology factors”, used in the model to reflect sulfuric acid removal by pollution control devices , have been updated with new and re-evaluated measurement data. As with all estimation procedures, the methodol ogy described in this report and the factors developed from the available data wi ll not be applicable to every facility configuration or fuel type. Site-specific measurements of SO 3 or H 2 SO 4 emissions from a power facility, if available, should always be used in place of the estimates derived with this method.

x

## CONTENTS

**1 INTRODUCTION ..................................................................................................................**  **..1-1** Background..................................................................................................................... .....1-1 Objective ..............................................................................................................................1-2 Report Organization............................................................................................................ .1-2
**2**

**MEASUREMENT UNCERTAINTY .........................................................................................2-1** CCS Measurement Uncertainty ...........................................................................................2-1 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......................................................................................................3-3 Flue Gas Conditioning.......................................................................................................... 3-5
**4**

**ESTIMATING GUIDELINE: STEAM BOILERS .....................................................................4-1** Manufacture and Release from Combustion........................................................................4-1 Manufacture and Release from Flue Gas Conditioning (FGC) ..........................................4-12 Total Manufacture and Release for Source .......................................................................4-15 Total Release Calculation for Source s Employing Alkali Injection .....................................4-15 Technology Impact Factors (F2) ........................................................................................4-17
**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-8 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 CHANGES TO EPRI SULFURIC ACID ESTIMATION MODEL.......... B-1** 

xi

# 1 **INTRODUCTION**

**Background** Estimation of sulfuric acid emissions from power pl ants is a topic of increasing importance to the U.S. electric utility industry. Most signifi cantly, Section 313 of the Emergency Planning and Community Right-to-Know Act (EPCRA), also known as the Toxic Release Inventory (TRI), requires facilities that “manufact ure,” “process,” 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, the TRI reporting requirements are triggered if a facility “manufactures” or “processes” 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 ch emicals 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 “i nclud[ing] mists, vapors, gas, fog, and other airborne forms of any particle size.” Although in itially it appeared that only liquid droplets of sulfuric acid needed to be reported, the presen t method estimates the sulfuric acid emissions regardless of the physical state of the molecules. Beginning on July 1, 1999, certain coal- and oil-fire d electric power plants have been required to report annual releases of TRI chem icals that they manufacture, process or otherwise use above threshold amounts. Under EPA’s EPCRA § 313 regula tions, coal- and oil-fired electric utilities are deemed to “manufacture” sulfuric acid. Thus, electric utilities have to submit TRI reports on sulfuric acid releases if they “manufacture” more than 25,000 pounds of the chemical in a given reporting year (EPA, 1997).
Emissions of sulfuric acid have received consid erable attention in recent years with the broad application of selective catalytic reduction (SCR) NOx control technology. The use of SCR unavoidably contributes to producti on of sulfur trioxide (SO 3 ), the precursor of sulfuric acid. Several notable incidents have been witnessed wh ere an increase in sulfuric acid emissions, as manifested by an increase in stack plume visibilit y, was attributed to the addition of SCR process equipment to an existing power plant. The de ployment of approximately 115 GW of selective catalytic reduction (SCR) from 1997 through 2009 has prompted power plant owners to conduct extensive measurements documenting the fate of SO 3 and sulfuric acid in power plants. The methodology described in this report was deve loped by Southern Company Services (SCS). Between 2000 and 2005, SCS developed several ve rsions 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 emissions 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 publish this method under EPRI sponsorship. The 2008

1-1version of the model added the ability to estimate emissions based on a specified sulfuric acid flue gas concentration at the stack. This approach can be used when alkali injection is employed to reduce sulfuric acid emissions. The current methodology is largel y unchanged from the previous ve rsion of this model (EPRI, 2008), making use of correlation factors that relate coal type and power plant configuration to sulfuric acid emissions. The current version updates several of the “technology factors” (F2 factors, used to reflect the impact of pollution control devices) with new SO 3 measurements. The current version contains a modifi ed methodology to determine a Fuel Impact Factor (F1 factor, used to reflect the impact of coal type on conversion of SO 2 to SO 3 in the boiler) for eastern bituminous coals. Rather than presenting differe nt F1 factors for low-sulfur and high-sulfur eastern bituminous coals, the model now represents the F1 factor as a linear relationship between boiler SO 2 and the rate of conversion to SO 3 . The current report also corrects an error in a conversion factor for calculations of sulfuric acid releases during alkali injection, as documented in an errata sheet issued in April, 2009 (EPRI, 2008).
**Objective** The objective of this report is to present a methodology for estim ating sulfuric acid emissions from power generating facilities, for use in Toxics Release Inventor y reporting and other applications. The scope of units considered includ es coal- and oil-fired steam generating units, as well as simple cycle and combined cycle natural gas- and oil-fired combustion turbines. To date, the most authoritative and documen ted data describe sulfuric aci d emissions from coal-fired steam generators. The focus on this category of un its is due to the increased availability of measurements describing the fate of sulfuric ac id attributable to the retrofit of SCR process equipment on coal-fired steam generators.
**Report Organization** Section 2 of this report addresse s the uncertainty in measuring SO 3 concentration using the preferred controlled condensation system (CCS) method, and the accuracy and representativeness of the available data. Sect ion 3 outlines the general methodology adopted in this model while Section 4 describes the detail s of the methodology, focusing on data that can be used to predict sulfuric acid manufacture by combustion. This section also summarizes data describing the removal of sulfuric acid across air heaters, ESPs, and wet flue gas desulfurization (FGD) process equipment. Section 5 outlines ho w to conduct the calculation for steam boilers firing a mixture of fuels. Section 6 addresse s simple cycle and combined cycle combustion turbine applications. Example calculations for va rious power plant config urations are presented in Appendix A. A chronology of changes to the EPRI sulfuric acid model is presented in Appendix B.

1-2

# 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 addition, a large da tabase of measurements from many electric generating units (EGUs) is desired to obtain a ro bust predictive method. Both the size and the representativeness of the measur ement database are critical to the accuracy of a predictive method. The predictive correlations presented in this re port are based on data obtained from field tests conducted predominantly within the last 10 year s, with some estimates conducted in the1990s. The quality of the data is thought to vary widely . It was not possible to obtain quality control information for all of the available measurements; t hus, 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 data sources, but most measurements were conducted using the contro lled condensate system (CCS), a widely used technique 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 purpose, but that method has a known positive bias from oxidation of SO 2 to SO 3 in the impinger solution. **CCS Measurement Uncertainty** A series of field and laboratory trials conducte d by EPRI evaluated the measurement bias of the CCS technique by comparing results from both la boratory tests and field trials (EPRI, 2001). SO 3 /H 2 SO 4 measurements at similar gas compositions were compared in a 1) clean, ash-free laboratory environment; 2) simulated ash environm ent, 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 estimati on model. The results showed that, when fly ash was present in the flue gas stream, the tec hnique imposed a low bias (e.g., indicated lower SO 3 /H 2 SO 4 than measured in the ash-free laborator y environment), due to reactions of SO 3 or sulfuric acid with fly ash in the filter thim ble holder upstream of the CCS condenser. Conversely, the EPRI tests indicated that use of CCS downs tream of the particulate control device 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 desulfur ization outlet. Furthermore, the bias depended on the quantity of ash co llected, the alkalinity of the as h, and the coal sulfur content (e.g., SO 2 content in the sample gas). Measurement bias in the simulated ash environment was observed for both high sulfur coal and low sulf ur Powder River Basin (PRB) coal; however biasing in the PRB coal tests can generally be co nsidered non-significant in light of already low SO 3 concentrations and the expected absorption of sulfuric acid with the alkaline ash in actual field tests. Data for high sulf ur coal suggested a low bias of 20-25% could occur in measurement

2-1locations upstream of a particul ate control device with typica l ash loadings, and no significant bias downstream of the part iculate control device. The precision of the CCS data used in this estim ation model can be estimated 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 a precision of up to ± 20% is realistic for most conditions. The repeatabilit y of the CCS measurements depends on avoiding stratification within the gas stream (traversing is very difficult), maintaining correct temperatures in the sampling train, and having well trained samp ling personnel. Therefore, the precision of the entire data set used in this model, which incl udes data from older studies of unknown quality, is expected to be closer to ± 50%.
**Representativeness** The accuracy of the correlations presented in th is report depends on the representativeness of the constituent data points. For some power plan t configurations, only a few measurements are available, and the correlati ons provide only rough approximations of the flue gas SO 3 /H 2 SO 4 releases for similar units. The category with th e largest number of data points is dry-bottom boilers, firing low sulfur, eastern bitumi nous coal. In general, the number of SO 3 measurements for various power plant configurations are proport ional to the occurrence of those configurations among the total population of U.S. EGUs. The num ber of measurements in each power plant category should be considered when applying this model; factors based on one measurement have much higher uncertainty than f actors based on dozens of measurements. As a consequence of the uncertainty in SO 3 /H 2 SO 4 measurements and the limited number of data points that comprise the releva nt correlations, the predictive te chnique should be assumed to provide estimates within a ± 50% relative accuracy.

2-2

# 3 **BACKGROUND AND METHODOLOGY OVERVIEW** This section provides a brief overview of sulfur ic acid production mechanisms in power plants and presents the basic equations for estimating sulfuric acid rel eases. A detailed review of this topic has been provided by Srivastava ( 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 with in the flame zone of a boiler, the convective heat transfer sections, or environmental control components. 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 mechanis ms, including alkali-based sorbent injection, occurring at lower temperatures.
**Factors Affecting Manufacture and Release** The method estimates the manufact ure and the subsequent release of sulfuric acid from the power generation process. The manufacture of sulfuric acid is define d as any process step that increases the flue gas content of sulfuric acid, regardless of its ultimate fate. To estimate the release of sulfuric acid, the manufactur e estimate is corrected by a fact or 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 remaini ng steps in the power generation process reduce sulfuric acid. Therefore, the total sulfuric acid released is the cumulative sum of that manufactured, adjusted by sulfuric acid losses.
The manufacture of SO 3 , the precursor to sulfuric acid, is cal culated in this model as shown in Equation 3-1.
Equation 3-1 TSAM = EM Comb + EM SCR + E FGC where,
TSAM = Total manufacture of sulfuric acid
EM Comb = Manufacture of sulfuric acid through combustion
EM SCR = Manufacture of sulfuric acid from SCR
EM SCR = Manufacture of sulfuric acid from FGC

3-1The Total Sulfuric Acid Release (TSAR) fr om a combustion unit equipped with SCR/SNCR NOx control and FGC is re presented by Equation 3-2. Equation 3-2 TSAR = ER Comb + ER SCR/SNCR + ER FGC where,
TSAR = Total release of sulfuric acid
ER Comb = Sulfuric acid released through combustion
ER SCR/SNCR = Sulfuric acid released from SCR (or SNCR)
ER FGC = Sulfuric acid released from FGC

**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 util ity boiler, considering gas phase events only and ignoring catalytic effects. The results showed that insignificant SO 3 formed in the early st age of the flame, but SO 3 production increased as the gases exited the fl ame 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 conten t, 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, th e boiler or turbine combustion process comprises the only source of sulfuric acid. The sulfuric acid manufacture by th e combustion process (EM Comb ) is expressed as follows: Equation 3-3 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 4.

**Release** The release of sulfuric acid attributable to th e combustion process is de termined by adjusting the manufactured SO 3 by the removals in the following equipment: the air heater, electrostatic precipitator (ESP) or other partic ulate control device (PCD), and flue gas desulfurization (FGD) equipment. The release of sulfuric acid is calculated by applying Technology Impact Factors

3-2(F2) that describe the fraction of sulfuric acid that penetrates each downstream equipment component. The sulfuric acid released by combustion (ER Comb ) is described by the following: Equation 3-4 ER Comb = EM Comb ● F2 (all that apply) The development of Technology Impact Factor s (F2) for each downstream component is addressed in Section 4.

**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. 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 reducing th e content of vanadium pentoxide and compensating with other catalyst oxides such as tungsten or molybdenum, which offer improved selectivity (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 design ed for bituminous coals. If S CR is applied to extremely low sulfur, high alkalinity coal s such as PRB, higher SO 2 oxidation is acceptable. Depending on how the measurement of SO 2 oxidation is performed, the oxida tion can be 3% or higher. In many instances, owners and catalyst supplie rs prefer that measur ements to quantify SO 2 oxidation for the purpose of commer cial guarantees be conducted not with authentic flue gas but in a laboratory-scale test facility, 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 method 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 calcul ated laboratory-scale SO 3 values at the exit of an SCR reactor exceed measurements in the field has been witnesse d on numerous occasions . Specifically, Lindenhoff (2004) reported that the measured SO 2 oxidation rate for PRB-gene rated flue gas of 1.25% was below the 1.6% value predicted based on the boi ler and SCR catalyst specifications. Further, tests conducted by this catalyst manufact urer noted significant absorption of SO 3 generated within the SCR reactor prior to the air heater. Sufficient data was accumulated 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 an d the number of alkaline sites available in the flue gas stream.

3-3An alternative NOx control process, selectiv e 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. The following relationship describes the total H 2 SO 4 manufactured from an SCR equipped utility boiler or steam generator: Equation 3-5 EM SCR = K • S2 • f sops • E2 • F3 SCR Where K is a constant, S2 is the catalyst SO 2 oxidation rate, f sops is the fraction of the year in which flue gas is directed through the SCR, E2 is the annual rate of SO 2 production, and F3 SCR is the Technology Impact Factor for SCR used to adju st for the presence of alkaline fly ash. Further details of this relationship and the derivation of constants and other terms are presented in Section 4.

**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, a nd reducing the amount released. For an SCR, ammonia slip is expected to usua lly range between 0 and 2 parts per million (ppm) for bituminous coal cases. Higher values of am monia slip are possible if the unit has not been recently tuned, the boiler or SCR process operate s under upset, or as the catalyst ages. Higher ammonia slip may be tolerable in PRB coal appl ications, since ammonia is not readily absorbed by the highly alkaline PRB ash and adverse opera tional impacts (air preheater pluggage and ash contamination by ammonia) are avoided. Reac tions 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 fly ash. Any SO 3 or H 2 SO 4 that participates in th ese reactions is no longer chemically present as sulfuric ac id and is not required to be re ported 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 fu rnace zone (1,800 to 2,400°F, as compared to 700°F for SCR) do not require reduc tion catalyst so there is no additional manufacture of SO 3 or sulfuric acid. Typically, SNCR sy stems operate with higher levels of residual ammonia (5 to 10 ppm), so any sulfuric acid that is present fr om 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 reaction product is present is us ually determined by the stoichiometry, or the relative amount of each substan ce on a mole basis, that is present in the flue gas. When ammonia is present in an amount over tw ice the mole content of the sulfuric acid, the reaction product will always be th e ammonium sulfate. Conversely, wh en sulfuric acid is present

3-4in an amount on a mole basis greater than ammonia, 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 ammoni a slip. Accordingly, ammo nium bisulfate is the primary byproduct anticipated. For subbituminous, P RB, and lignite coals, any sulfuric acid produced is typically adsorbed by the ash and it is likely that residual ammonia will exceed sulfuric acid content on a mole basis. Under these conditions, ammonium sulfate is the likely product. For SNCR-equipped units, ammonia slip levels of 5 ppm and possibly higher will favor ammonium sulfate, particularly for western U.S. coals where the alkaline fly ash will reduce the SO 3 content. For eastern bituminous coals, which have generally higher su lfur content and lower ash alkalinity, ammonium bisulf ate will likely predominate. For the purpose of predicting sulfuric acid emissions, these distinctions are not important. A single molecule of sulfuric acid will capture a single molecule of ammonia, producing ammonium bisulfate. If additiona l ammonia is available, the amm onium bisulfate can react with another ammonia molecule to form ammonium sulfate. It can be assumed that all sulfuric acid forms ammonium bisulfate before any further r eaction to the ammonium sulfate form occurs. This assumption leads to the calculation strategy that ammonia captures all of the sulfuric acid it can as ammonium bisulfate, and since the bisulfate form is no longer reportable, the sulfuric acid disappears from the release calculation. Add itional ammonia reacting with the ammonium bisulfate is of no consequence to the sulfuric acid calculati on – although this issue will be important when estimating ammonia releases.
The sulfuric acid released from SCR or SNCR is determined by subtracting from the sulfuric acid manufactured the amount removed by the residua l ammonia, or ammonia slip. For SCR, the sulfuric acid released (ER SCR ) is estimated with the following relationship: Equation 3-6 ER SCR = [EM SCR – (K
s • B • f sreagent • S NH3 )] • F2
x Where K S is a constant, B is the coal burn in TBtu/yr, f sreagent is the fraction of SCR operation with reagent injection, S NH3 is the NH 3 slip for the SCR/SCNR and F2 are any applicable downstream, Technology Impact Factors. These cal culations and factors ar e described further in Section 4. For SNCR, as there is no sulfuric acid manufacture term, the sulfuric acid release estimate (ER SNCR ) is a negative term which, when included in the calculations, will result in an overall reduction of sulfuric acid emissions.
**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

3-5sulfurous 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 require s knowledge of the concentration of SO 3 injected and the associated oxygen content of the flue gas. Equation 3-7 presents an equation to estimate the ma nufacture of sulfuric acid from this source, where K e is a constant, B is the coal burn, f e is the FGC operating factor, and I s is the SO 3 injection rate. Further details and derivation of the constant are provided in Section 4. Equation 3-7 EM FGC = K
e • B • f
e • I
s **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. A ccordingly, FGC can manuf acture sulfuric acid, but can also remove sulfuric acid if NH 3 is injected alone or in quantities greater than the sulfuric acid. The following equation describes the relationshi p to determine the release of sulfuric acid attributed to FGC. Equation 3-8 ER FGC = [EM FGC – (K
e • B • f
e • I NH3 )] • F3 FGC • F2
Where F3 FGC is the Technology Impact Factor for FGC, used to adjust the releases based on the injection point of SO 3 . The Technology Impact Factors (F2) de scribe the fraction of sulfuric acid that penetrates the air heater (f or FGC that is introduced ahead of the air heater), and for the particulate control device and FGD (for FGC that is introduced afte r the air heater). The basis for the F2 factors and the detailed equations for quan tifying the manufacture a nd release of sulfuric acid are presented in Section 4. **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 some cases magnesium compounds, have been used with varying degrees of effectiveness 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 wi dely used reagent for control of SO 3 . SBS is introduced into the flue gas, usually at th e air heater exit, but in some un its 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 for 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 reagent that is used to control SO 3 . Trona can be injected at several locations within the boiler, but most app lications introduce trona at the air heater exit, prior to the particulate collector (Ritzenthaler, 2006). As with SBS, additional sodium introduced into flue gas is advantageous to compensate for the reduction in ESP performance.

3-6Several forms of calcium-based sorbents can be u tilized. These are injected at various locations in the flue gas, including the economizer inlet, economizer outlet (e.g., air heater inlet), and the air heater outlet. A survey of recent experien ce with lime-derived sorbents addressed the advantages of this approach (Benson, 2006a). H ydrated 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 performance, as the reduced SO 3 content in flue gas increases the electrical resistivity of the as h 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. 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. The alkali injection system usually is operated to reduce SO 3 emissions to between 5 and 15 ppm, an optimal range to prevent form ation of a visible plume.
In the 2008 version of the Sulfuric Acid Mode l, EPRI added a procedure to estimate SO 3 stack releases from EGUs that employ alkali injection for SO 3 control, using as an input to the model the measured or estimated stack gas SO 3 concentration. A procedure to convert measured sulfuric acid concentration in flue gas to a mass emission rate is summarized below and described in more detail in S ection 4. An example application of this method is provided in Appendix A. Equation 3-9 ER ALKINJ = K alkali • B • S SO3 • F2
x • F alkali Where K alkali is a constant, B is the coal burn, S SO3 is the measured SO 3 content with injection, F alkali is the fraction of time alkali injection is in operation, and F2 are any applicable downstream Technology Impact Factors.
To estimate SO 3 manufacture with alkali injectio n, plant owners should use the standard approaches given in Section 4 for the appropriate plant configuration. 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-approved test method for SO 3 (Method 8) has a significant positiv e 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.

3-7

# 4 **ESTIMATING GUIDELINE: STEAM BOILERS** This section describes an estimation procedure for calculating the manuf acture and release of sulfuric acid from coal-fired st eam generators. The topics addre ssed are (a) formation within the furnace; (b) the role of SCR, (c) flue gas conditi oning (FGC), and (d) alka li injection; and (e) the removal by downstream equipment such as air heater s, ESPs or other partic ulate control devices, and FGD process equipment. Each of the subse quent sections in this chapter provides the information to conduct 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 emi ssion monitoring system (CEMS) output. Units equipped with FGD equipment or other methods of SO 2 control are required to use either coal data or CEMS measurements from ahead of the 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 propose d 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 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 E2 = Sulfur dioxide (SO 2 ) emissions, either: (1) recorded by a continuous emissions monitor, tons/yr, or (2) cal culated from coal burn data, tons/yr.

4-1The Fuel Impact Factor (F1) is a numerical valu e or a mathematical relationship reflecting the conversion of SO 2 to SO 3 in the boiler for a specific coal ty pe and boiler type. In the derivation of Equation 4-1, the follow ing assumptions are made:

• SO 3 concentrations are proportional to SO 2 concentrations.

• The grade of coal being burned imp acts the rate of conversion from SO 2 to SO 3 .
• All SO 3 that forms is converted to H 2 SO 4 .
• The rate of SO 3 formation is independent of th e boiler firing rate (unit load). The estimates of sulfur dioxide emissions (E2) and F1 factors are further described in the following sections. Sulfur Dioxide (SO 2 ) Emissions from Combustion (E2) Estimating the sulfuric acid production from Equa tion 4-1 requires knowledge of the mass rate of SO 2 generated. This rate is designated as E2 in Equation 4-1. As noted pr eviously, the value of E2 can be estimated from either (a) the EPA CE MS 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 geomet ry in deriving E2. Specifically, if CEMS SO 2 data are used, the factor E2 is defined by the following equation

Equation 4-2a 

# ( ) ⎥ ⎦ ⎤ ⎢ ⎣ ⎡ +∗+∗

−= 100 321 12 2 CRCRC EE

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 verification tests, degrees In equation 4-2a, the factor C3 represents the wall effects bias factor, 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 geometries, a defau lt 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 recta ngular ducts that are equipped with flow monitors (E PA, 2009). This proposal has not b een finalized as of December, 2009, but some facilities may be allowed to appl y this approach as a conditional test method.

4-2As an alternative to using CEMS data, the follo wing 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 = Dry coal burn, tons/yr. The dry coal can be calculated from wet coal through the following relationship: Dry coal (tons/yr) = wet coal (tons/yr) • (1-moisture(%)/100%) S1 = Coal sulfur weighted average, %, dry K1 = Molecular weight and units conversion constant = (64.04)/(100 • 32.06) = 0.02 64.04 = molecular weight of SO 2 32.06 = molecular weight of S conversion of % S to a fraction - multiply 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. Data from a CEMS located after a flue gas desulfur ization system cannot be used. Fuel Impact Factor (F1 ). Figure 4-1 depict s the fraction of H 2 SO 4 produced as a function of flue gas SO 2 content for several coal sources and boile r types. The coal ranks and boiler types consist of (a) high sulfur (>2.5 %) eastern bituminous coal, fired in a dry bottom boiler (wallfired or cell-fired), (b) low sulfur eastern bitu minous coal, fired in a dry bottom boiler, (c) PRB coal, fired in both a cyclone and dry bottom boilers and (. Data are also shown for one unit that fires 75% lignite with the balance P RB and one unit that fires 100% lignite. 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, re gardless of boiler type, in that less than 1 ppm was observed. The previous version of the model (EPRI, 2008) separated eastern bituminous coal data for drybottom boilers into two distinct fuel groups, one for low-sulfur (<2.5% coal sulfur) coal and one for high-sulfur (>2.5% coal sulfur) coal. A uni que F1 factor was assigned to these two coal types that was the average SO 3 fraction produced for each type. However, that approach led to large fluctuations in estimated su lfuric acid releases for facilities with coal sulfur near the 2.5%

4-3division point. Therefore, the current model replaces the two eastern bituminous coal groups with a linear relationship. The re gression line for all eastern bitu minous, dry bottom boiler data is shown in Figure 4-1. The equation expressing this relationship is shown in Equation 4-3. This relationship is significant at the 95% confidence level, although the correlation coefficient (R 2 ) is low (0.13) due to scatter in th e data. The current model retain s F1 factors based on average fraction of SO 2 converted to SO 3 for all other coal types.

Eastern Bituminous y = 1.1163E-06x + 6.4877E-03 R 2 = 1.3004E-01

0.000 0.002 0.004 0.006 0.008 0.010 0.012 0.014 0.016 0.018 0.020

0 500 1000 1500 2000 2500 3000 3500 4000 Flue Gas SO 2 ContentBoiler SO3Production, F1 Factor High S East Bit, Dry Bottom Boiler Low S East Bit, Dry Bottom Boiler PRB Dry Bottom Boiler 75% Lignite 100% Lignite PRB Cyclone

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

Equation 4-3 F1 ebit = 1.1163E-6 • SO2 + 0.0064877 where, F1 ebit = Fuel Impact Factor for all Ea stern Bituminous coal s burned in a drybottom boiler SO 2 = Boiler SO 2 concentration (ppm), derived from fuel sulfur content (%) In order to use this approach, it is necessa ry to relate coal sulfur (%) to the SO 2 concentration in the boiler. Equation 4-4 is used to calculate that relationship:

4-4Equation 4-4 HV K 1SSO 1F 2 •=
where, SO 2 = Boiler SO 2 concentration (ppmvd, 3% O 2 , dry) derived from fuel sulfur content (%) S1 = Coal sulfur weighted average, %, dry K F1 = Conversion factor = 10,003,602 HV = Coal heating value, Btu/lb, dry The conversion factor K F1 considers all relevant constants to yield the result in ppm of SO 2 . The derivation of this constant is presented in Text Box A.

Text Box A: Derivation of Conversion Factor, K F1 . The U.S. Code of Federal Regulations 40, Part 60, Table 19-1 “F Factors for Various Fuels” states 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 3% O 2 on a dry basis (typical of the SO 2 measurement data used in the Fuel Impact Factors correlation) yields a volume of 11,419 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 20C (68°F), one pound mole occupies 385.5 standard cubic feet. The value 0.95 is the AP-42 (EPA, 1995b) K2 factor for sulfur conversion to SO 2 for a bituminous coal. Equation 4-4 above can then be expanded as follows:

S1% 0.95 385.5 scf S 1 lb mol S 1 MBtu 1 lb fuel 10 6 Btu 10 6 ppm 100% 1 lb mol S 32.06 lbs S 11,419 scf HV Btu 1 MBtu

Grouping terms,
SO 2 = S1 • 10,003,602 / HV Therefore, the value of K F1 is equal to 10,003,602 [ ppmvd SO 2 (3% O 2, dry) • Btu/lb]/%S.

4-5Table 4-1 summarizes the F1 factor s, noting any significant changes from the last version of the model (EPRI, 2008).

**Table 4-1 Summary of Fuel Impact Factors (F1) for Steam Generating Units** 

**Fuel Equipment**  **F1 Comment**  E. Bituminous (all) Dry Bottom Boiler Slope: 1.1163E-6 Intercept: 0.0064877 F1 = slope * SO 2 + intercept 32 data points*

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

W. Bituminous Dry Bottom Boiler 0.00111 One data point.

W. Bituminous Cyclone 0.0022 One data point. Subbituminous/PRB All Boilers 0.0019* Average of 8 units Lignite Dry Bottom Boiler 0.0044* Two data points.

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 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 EPRI, 2008

4-6**Sulfuric Acid Released from Combustion (ER Comb**  **)** For units that do not employ SCR or SNCR NOx control or FGC, the sulfuric acid released is the product of the amount manufactured and Technol ogy Impact Factors (F2) for all downstream equipment (the air heater, the particulate contro l device, the FGD, etc. – described later in Section 4). For these units, the total sulfuric acid emissions can be calculated from Equation 4-5.
Equation 4-5 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 B summarizes calculations for units equipped with an FGD process that employs partial flue gas bypass, which must account for the f act that the entire flue gas flow is not subject to sulfuric acid removal by the FGD process. Th is bypass factor is pertinent only to units that employ flue gas bypass.

Text Box B: 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 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. 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.

**Manufacture and Release from SCR and SNCR**  This section describes a method to estimate impact s of SCR or SNCR on sulfuric acid emissions. SCR can contribute to or reduce sulfuric ac id emissions, while SNCR will only reduce such emissions. As discussed in Section 3, SCR produces SO 3 (and ultimately sulfuric acid), while SNCR removes or reduces it due to the reaction with residual ammonia. The sulfuric acid manufactured by SCR is the net result of production by the cat alyst and removal by th e reaction of residual NH 3 from the SCR process. A key assumption in the calculation strategy is that residual amm onia from either SCR or SNCR captures all available sulfuric aci d in the (ammonium) bisulfate fo rm. 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 – a lthough this issue will be important when estimating ammonia releases.

4-7The 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 4-6 EM SCR = K • S2 • f sops • E2 • F3 SCR where,
EM SCR = Total H 2 SO 4 manufactured from SCR, lbs per year 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.

S2 = SCR catalyst SO 2 oxidation rate (specified as a fraction, typically from 0.001- 0.03)
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 shoul d reflect the hours the SCR reactor processed flue gas, which will be site-specific but can be approximated bygenerally 0.8 for year-round peaking operation, 0.98 for year-round baseloaded 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 4-6. Typically, the SO 2 oxidation rate from SCR catal ysts can range from as lo w 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 actu al field tests in commercial units – does not require adjustment and can be used as reported to predict sulfuric acid. The other method is based on laboratory tests of catalyst samples in the absence of ash and alkaline materials, and must be adjusted to account for th ese latter factors. 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 full-scale equipment. Thes e data – measured on commercial plants under

4-8actual operating conditions – are the most authentic in reflecting actual SO 3 content, as the impact of ash alkalinity is taken into acc ount. This approach reflects commercial process operation, and the resulting fractional oxidation rate can be used as the S2 value in Equation 4-6 without adjustment by the F3 SCR Technology Impact Factor. Laboratory Bench-Scale Tests . Some owners and process supplie rs prefer to specify and conduct guarantee measurements for SO 2 oxidation on laboratory-scale equipment using synthetic flue gases without fly ash. There are good reasons to select this methodol ogy; evidence suggests SO 3 measurements in the environment of the test la boratory 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 used, but must be adjusted for the role of ash alkalinity. This adjustment is provided 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.

**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 manufacture 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 removed by the residua l ammonia, or ammonia slip. For SCR, the sulfuric acid released (ER SCR ) is estimated with the following relationship: Equation 4-7 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 (See Text Box C) B = Coal burn in TBtu/yr

4-9f 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 4-6.
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 Factors, 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 C.

Text Box C: 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).

Equation 4-7 specifies the 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 4-8 a 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 concentration is quan tified 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 4-8b Ks (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 – 0)]
Ks = 2489

4-10Equation 4-8a can be used to calculate the value of K s at any condition used to define the concentration of residual NH 3 . The operating factor of the SCR describes the por tion of the coal burn that reflects the period of SCR operation, based on whether the unit operate s seasonally (0.43), annually in a base-load duty (0.98), or annually in peaking duty (0.80). The coal burn rate in TBtu/yr can be obtained from coal use record s, such as those reported to EIA in Form 767, or can be calculated from the annual coal burn (tons/yr) and the heating value of the coal, as described in the equation below: Equation 4-9 B = C1 • HV • K B

B where, B = Coal burn in TBtu/yr C1 = Dry coal burn, tons/yr. The dry coal can be calculated from wet coal through the following relationship: Dry coal (tons/yr) = wet coal (tons/yr) • (1-moisture(%)/100%) HV = Coal heating value, Btu/lb, dry K B = Conversion factor = 2E-9. The factor is calculated from the conversion of tons per year to pounds per ye ar and Btu to TBtu (2000/10 12 = 2E-9)
For SNCR, as there is no sulfuric acid manufacture term; the sulfuric acid release due to SNCR (ER SNCR ) is a negative amount which, when included in the calculations, will result in an overall reduction of sulfuric acid emissions. Accordingly, total sulfuric acid release (TSA R) for a generating unit equipped with SCR is estimated by the following equation: Equation 4-10 TSAR = ER Comb + ER SCR Total sulfuric acid release (TSAR) for a genera ting unit equipped with SNCR is estimated by the following equation:
Equation 4-11 TSAR = ER Comb + ER SNCR For units equipped with flue gas desulfurizati on bypass, a series of cal culations 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 D.

4-11Text 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 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. 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 SCR = [SB f + (1 – SB f ) • F2 s ] • [EM SCR – (K s • B • f s • S NH3 )] • 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.

**Manufacture and Release from Flue Gas Conditioning (FGC)** 
**Sulfuric Acid Manufactured from FGC** In order to moderate ash resistivity, most SO 3 –based FGC systems attempt 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 manuf actured during FGC use the setpoint of the FGC system as the key input. The FGC system is assu med to operate during most of the plant’s duty, except for perhaps startup and low load ope ration. The sulfuric acid manufactured by SO 3 -based FGC equipment (EM FGC ) is calculated as follows:
Equation 4-12 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 e quivalent to Ks, as described in Text Box C. B = Coal burn in TBtu/yr F e = Operating factor of FGC system, or the fraction of coal burn when the FGC system operates. This value is s ite-specific, 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 If the SO 3 injection rate (I S ) is known at conditions other than 6%O 2 and wet, Equation 4-8a can be used to calculate a new value K e at the new conditions.

4-12FGC equipment that employs both SO 3 and NH 3 must be reported to manuf acture sulfuric acid at the rate of SO 3 injection, regardless of whether ammonia 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 determines the sulfuric acid released by FGC, as discussed in the next section. **Sulfuric Acid Released from FGC (ER FGC**  **)** The subsequent release of sulfuric acid associat ed with flue gas conditioning can be estimated from the sulfuric acid quantity manufactured, adju sted by the amount that reacts with ammonia in any particulate control device installed downstream of the FGC. Equation 4-13 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, which is equivalent to Ks, as described in Text Box C 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 gas 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 e quipment after the ESP only, if no control equipment is installed after the ESP; F2 = 1.

**Table 4-3 F3**  **FGC – Technology Impact Factors 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.

4-13This 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 predicted removal within the air heater and ESP can differ. No mechanistic reason has been identified for these differences in removal – they emerge from the supporting data.
For SO 3 manufactured by combustion, SCR, or introdu ced as FGC ahead of the air preheater, the method predicts sulfuric acid removal of 75% (F3 FGC = 0.25) for eastern bituminous coals across an air preheater/cold-side ESP combination. Howeve r, as denoted in Table 4-3, a higher fraction of SO 3 or H 2 SO 4 (90%, F3 FGC = 0.10) is predicted to be removed for FGC if injected downstream of the air preheater. The difference in results is li kely attributable to the limited number of data points and uncertainty in the measurements . 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 (F3 FGC = 0.05) through the air heater and ESP. SO 3 is assumed to be 98% removed (F3 FGC = 0.02) when injected downstream of the air heater. As these western bituminous, subbituminous, and lignite coals feature si gnificant alkaline content of ash, any SO 3 injected for FGC will likely be captured by both physical deposition and chemical reaction. 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 ai r 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 desulfurizati on bypass, a series of cal culations 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 E.

Text Box E: 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/SN CR 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, 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**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. Theref ore, if a site burns coal and uses both SCR and FGC, the amount of sulfuric acid manufactured – by com bustion, SCR, and/or FGC – is added together to determine the total amount. Th e amount of sulfuric acid released is also calculated – again for combustion, SCR, and FG C – and summed to define the total. Both SCR and/or ammonia-based FGC may have a ne gative effect on sulfuric acid release, as the ammonia slip can combine with some or all of the sulfuric acid generated from combustion to form a non-reportable ammonia salt (ABS or AS ). Under these conditions, ammonia-based FGC can serve to only reduce the releas e of sulfuric acid. Since the re lease of sulfuric acid from combustion, SCR, and FGC are all additive, any ne gative values calculated as a result of these circumstances will need to be accounte d for in the total release equation. Accordingly, total sulfuric aci d manufacture (TSAM) and release (TSAR) is estimated for a generating unit equipped with SCR and flue gas conditioning by the following equations:
Equation 4-14a: Manufacture
TSAM = EM Comb + EM SCR/SNCR + EM FGC Equation 4-14b: 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 alkali injection to mitigate stack opacity or a visible plume will have access to field measurements describing SO 3 concentration in flue gas, most likely at the stack. The concentration of SO 3 measured at the stack can be converted to a mass emission rate using Equation 4-15 Equation 4-15 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 3,799, which is eq uivalent to Ks, as described in Text Box C. 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 operate d with alkali addition to remove SO 3

4-15F2 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 meas urement location. If the control device is an SO 2 scrubber, F2x is denoted as F2s, but is handled the same way. If the SO 3 content (S SO3 ) is known at conditions other than 6%O 2 and wet, Equation 4-8a can be used to calculate a new value K alkali at the new conditions. The Technology Impact Factors selected should represent the control 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 4-4, below) should be selected. If alkali injection is not utilized for the entire operating year (F alkali does not equal 1), then Equation 4-15 must be added to the fraction of th e total sulfuric acid release (TSAR) calculated from combustion, SCR/SNCR and/or FGC for the re mainder of the operating time. Furthermore, in the calculation of TSAR for pa rtial-year alkali injection, if SO 3 measurements also exist for operation without alkali injection, these data should be used with Equation 4-15 (without the F alkali term) instead of the standard estima tion equations to determine the term: ER Comb + ER SCR/SNCR + ER FGC , as shown below: Equation 4-16 ER NOINJ = K alkali • B • S SO3 • F2
x • (1-F alkali ) where,
ER NOINJ = Total H 2 SO 4 released from unit without al kali injection, lb s per year K alkali = Constant, equal to 3,799, which is eq uivalent to Ks, as described in Text Box C. B = Coal burn in TBtu/yr
S SO3 = SO 3 content without alka li injection, as measured in the stack or particulate collector exit, ppmv at 6% O 2 , wet
F alkali = fraction of time unit is operate d 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 meas urement location. If the control device is an SO 2 scrubber, F2x is denoted as F2s, but is handled the same way. Accordingly, total sulfuric acid release (TSAR) for a unit employing partia l-year alkali injection is estimated by one of the following equations: Equation 4-17a TSAR = ER ALKINJ + (ER Comb + ER SCR/SNCR + ER FGC ) • (1-F alkali )

4-16Equation 4-18b TSAR = ER ALKINJ + ER NOINJ **Technology Impact Factors (F2)** The sulfuric acid estimating methodology empl oys empirically-derived Technology Impact Factors (F2). These F2 factors de scribe sulfate removal observed over the air heater, the ESP or other particulate control devi ce, and FGD process equipment. Background information on these processes and the derivation of these F2 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 individual particles (a long 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 feas ibility of employing the air heater process environment in conjunction with limestone injection as a proa ctive sulfuric acid cont rol strategy (Hamel, 2003, and Bowes, 2006). Air heater surfaces follow a pattern of alternat ely heating and cooling as the heat exchange elements move from the relatively hot flue gas to the cooler combustion ai r. As reported during field tests of commercial equipment (Saranuc, 19 99), this temperature profile introduces a strong gradient in sulfuric acid concentration across th e exit plane of the air h eater. The cyclic thermal conditions as described by Hamel (2003) reveal thata significant portion of the air heater basket surface metal is exposed to flue gas temperat ure 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 4-2 presents data obtained from a survey of power plant operators and general literature sources describing SO 3 /H 2 SO 4 removal (and the corresponding F2 factors) across commercial, Ljungstrom-type air heaters. These data are presented as a function of SO 2 content of the flue gas for the host unit. Most data shown are for low sulfur eastern bituminous coal, for which air heater H 2 SO 4 removal varies significantly between 0% and 69%, averaging 50% as indicated by the horizontal line. Two high sulfur (>2.5%) east ern cases are shown, along with limited data for PRB coal. The data point showing 0% rem oval at approximately 600 ppm SO 2 is believed suspect, as an identical companion unit firing the same coal e xhibited sulfuric acid capture of 38%. This measurement was not included in the F2 calculation. Figure 4-2 presents two point s reported by Hamel (2003) based on a low sulfur eastern bituminous-fired unit where SO 3 was “spiked” into the flue ga s to elevate the concentration entering the air heater to 80 a nd 122 ppm. These two points are pl otted separately on Figure 4-2 versus an estimated flue gas SO 2 content that could generate such values (using the average SO 2 oxidation rate for high sulfur, easte rn bituminous coal in Figure 4-1). It should be noted these values measured for the “spiked” flue gas sign ificantly exceed those measured for the two high sulfur eastern coal cases.

4-170% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

0 500 1000 1500 2000 2500 3000 3500 Flue Gas SO 2 Content, ppmAir Heater H2SO4Removal, % 0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0Air Heater F2 Factor High S East Bit, Dry Bottom Boiler Low S East Bit, Dry Bottom Boiler Hamel Full-Scale Tests PRB Dry Bottom Boiler Series5

**Figure 4-2 Removal of Sulfuric Acid by Ljungstrom-Type Air Heaters**  The F2 factor for the air heater, calculated as [1 – Percent Removal], is estimated excluding the “spiked” SO 3 and suspect 0% removal measurement. The F2 factors for the air heater for low sulfur eastern bituminous, medium-high sulfur eastern bituminous, and PRB coals are shown in Table 4-3. Data are not currently available for othe r coal types. For those coals, the model user could consider adopting the F2 f actor for PRB if the ash is str ongly alkaline and the low sulfur, eastern bituminous value if the ash is acidic.

**Table 4-3 Summary of F2 Factors for Air Heater Removal of Sulfuric Acid** 

**Boiler Type**  **Fuel F2**  **Standard Deviation**  **Comment** All Boilers Low S Eastern Bit 0.50* 0.15 Average of measurements at 7 units.

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

All Boilers PRB 0.36* n/a Based on two data points. * Change in factor from EPRI, 2008.

4-18The standard deviation of the reported measuremen ts for low sulfur eastern bituminous coal is about one third of the average measurement. Th ere are not enough data to calculate a standard deviation for the F2 factors for the other fuels.
**Particulate and SO 3**  **Control Processes** This section discusses the av ailable data on removal of SO 3 by ESPs, FGDs, and alkali injection. ESPs and Baghouses An ESP provides extended residence time at relatively 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 contribut e 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 to 4 actual feet per second (0.6 – 1.2 meters per second), and the opportunity for heat loss at or near the walls, sulfuric acid condensation can be significant. Figure 4-3 plots sulfuric acid removal by the E SP and the corresponding F2 factors as a function of the SO 2 content of the flue gas for the host unit, fr om a survey of plant operators. Most data shown are for a cold–side ESP and low sulfur ea stern bituminous coal; three data points are shown 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 air heater, the 0% sulfuric acid removal at approximately 800 ppm SO 2 is suspect, as a companion unit at the same site firing the identical coal had 50% su lfuric acid removal. Accordingly, this “zero” removal datum, although shown in Figure 4-3, is not used in the analysis. The F2 factor for the cold-side ESP, calculated as [1- Percent Removal], is estimated using all data except the 0% removal point. The F2 fact ors for ESP capture for low sulfur eastern bituminous, medium-high sulfur eastern bituminous , and PRB coals are listed in Table 4-4. The F2 factor for the low sulfur eastern bituminous coal has been updated from a value of 0.49 in the 2008 version of the model to 0.63 du e to the reevaluation of measur ement data from one of the sources. Data are not currently available for othe r coal types. Facilities using coals not supported by the model should select a F2 factor for a coal with similar alkalinity in the ash: western subbituminous coals (e.g., non-PRB) could consider adopting the F2 factor 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. Data describing the reduced H 2 SO 4 penetration for one hot-side E SP (ESPh) is based on only a single test series It s hould be noted that although this F2 factor is used for all coals, the measurement is from a power plant burning a low-sulfur, eastern bituminous coal. Comparison of F2 factors for a cold-side ESP burning low a nd high sulfur eastern b ituminous coals show a significant difference between the two coal types. As a result, total H 2 SO 4 releases for hot-side ESP configurations may have a low bias; howev er there is insufficient data to recommend alternate values. Data for baghouses show high H 2 SO 4 removal based on very limited data from plants burning subbituminous coal. The average of two data points was 90% removal.

4-190% 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, % 0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0ESP F2 Factor High S East Bit
Low S East Bit
ESPh Low S EastBit PRB Dry Bottom Boiler

**Figure 4-3 Removal of Sulfuric Acid by**  **Cold-Side ESPs and One Hot-Side ESP**

**Table 4-4 Summary of F2 Factors for Particul**  **ate Control Devices (ESP, Baghouse)**

**Equipment Type**  **Coal Type F2**  **Factor Standard**  **Deviation Comment or Observation**  Cold-side ESP Low S Eastern Bit 0.63* 0.15 Average of measurements at 4 units.

Cold-side ESP High S Eastern Bit (>2.5%) 0.77 0.13 Average of measurements at 3 units.

Cold-side ESP Subbituminous (PRB) 0.72* n/a Based on one measurement at one unit.

Hot-side ESP All 0.63 n/a Based on one measurement at one unit. Baghouse Subbituminous coal 0.10 n/a Two data points. * Change in factor from EPRI, 2008. The standard deviation of the reported measuremen ts for low sulfur eastern bituminous coal is about one fourth of the average measurement, wh ile the standard deviatio n of the measurements

4-20for the high sulfur eastern bituminous coal is about one sixth of the average. Inadequate data prevent calculating a standard deviati on for F2 factors for the other fuels.
**FGD** FGD process equipment rapidly cools or quenches flue gas, condensing a significant portion of the sulfuric acid into submicron droplets that 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 thermodynami cally supersaturated. Buckley also projects sulfuric acid condensation on su rfaces where equipment walls are lower in temperature than the flue gas (common in commercial equipment). Ho wever, the thin laminar boundary layer at the wall limits mass transfer, and for FGD equipment this mechanism provides no appreciable removal. Ironically, it is the high saturation conditions in this lami nar layer near surfaces that are key to producing fine sulfuric acid mist. Srivastava (2004) suggests that the condensed su bmicron droplets, once formed, are sufficiently small so that they follow the flow streamlines and avoid contact with the remaining wetted walls, liquid sheets, and droplets in the flow path. Although some degree of sulfuric acid removal is observed in FGD equipment, the amount is highly variable and depends on the design of the system. Buckley (2002) estimates FGD equipmen t removes 40-70% of the sulfuric acid, and Srivastava an average of 50%. Figure 4-4 summarizes data reported in the public domain and from power company sources describing FGD removal (and corresponding F2 factors) of sulfuric acid. Th e 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 of about 50%. The shaded portion of Figure 4-4 represents the upper and lower bounds of the data reported by Buck ley (2002), while the solid horizontal line reflects the 50% average repor ted by Srivastava (2004). Table 4-5 summarizes the F2 factors for FGD pro cess equipment, including results for wet spray towers burning bituminous coal. Two results are av ailable for a wet scrubber at a unit burning a blend of PRB/lignite. Harrison (2005) calculated an average re moval of 60% for these units. Given the limited data, this value is assumed to apply to 100% firing of PRB or lignite. Data for a wet venturi-type combined part iculate/FGD process is also ava ilable, 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 described by that measured for bituminous coal. F2 factors for the use of magnesium-based additi ves in oil-fired boilers are also included in Table 4-5. These additives are used to control furnace 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 effect. 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.

4-214-22 **Figure 4-4 Removal of Sulfuric Acid by Flue Gas Desulf**  **urization Equipment: Various FGD Designs, Coals**

**Table 4-5 Summary of F2 Factors for Wet a**  **nd Dry FGD Equipment and Additives FGD Type Coal Type F2 Factor Standard**  **Deviation Comment or Observation** 

Wet: Spray Tower E. Bituminous 0.47 0.17 Seven data points. Wet: Spray Tower PRB or Lignite 0.40 n/a Two data points. Wet: Venturi Tower All coals 0.65 n/a Based on bituminous coal only; limited data from 2 units merit assigning same factor for other coals. Dry FGD and baghouse All coals 0.01 n/a Two data points. Mg-Ox mixed w/fuel oil All fuel 0.50 n/a One data point. Mg-Ox into furnace All fuel 0.50 n/a One data point.

# 5 **ESTIMATING GUIDELINE: MULTIPLE FUEL OR BLENDED FUEL BOILERS**  Estimating sulfuric acid production of steam boile rs 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 contribution of each source (combustion, SCR or SNCR NOx control, and FGC) for each different fuel, and adjusting fo r loss or removal. It is assumed for multiple fuel boilers that the contribution of each fuel can be separated and trea ted 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 se parate fuels in proportion 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 ab ility 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 available at present. Accordingly, the conservative approach is to presume an impact in direct proportion to the coal blend until a database can be developed. The sequence of calculations is performed for the first component of the blend, including calculations for SCR and FGC, if applicable. The sequence is repeated for each component. When complete, the total manufacture of sulf uric acid is calculated by adding all of the manufacture totals for all fuels from all proce sses. 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

5-1f. FGC release 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 would be summed t ogether and the releases summed also to give the final result. Example 5 in Appendix A details this calculation procedure.

5-2

# 6 **ESTIMATING GUIDELINE: COMBUSTION TURBINES** Natural gas-fired sources typically ha ve 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 un its will need to be included in the estimates for total sulfuric acid re lease for the site. The calculation described in this section can also be used to estimate sulf uric 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 onl y source of sulfuric acid is the sulfur in the fuel. The EPA AP-42 emissions factor suggests a value of 2000 grains of sulfur per million cubic feet of natural gas as a default sulfur content va lue. This value is equivalent to approximately 3.5 ppm of sulfur in th e 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 s imple cycle units, any sulfuric acid manufactured is released ; thus, the estimates of sulfuric acid are th e 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 reduction (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 (NG) 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 NG

6-1E2 NG = Sulfur dioxide (SO 2 ) emissions either: (1) recorded by a continuous emissions monitor, tons/yr, or (2) cal culated from fuel burn data, tons/yr.

SO 2 emissions can be obtained through a calcula tion using the heat i nput of natural gas.
Equation 6-2a E2 NG = K b • 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

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.

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

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).

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 million 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.

6-2Text 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)

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 temperat ure 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

6-3**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. For combustion, the manufacture of sulfuric acid for combined-cycle units is described by Equation 6-3.
Equation 6-3 EM CCcom = K • F1 • E2 NG where, EM CCcom = Total H 2 SO 4 released 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 NG (See Table 6-1) E2 NG = Sulfur dioxide (SO 2 ) emissions either: (1) recorded by a continuous emissions monitor, tons/yr, or (2) cal culated from fuel burn data, tons/yr. Equation 6-4 describes the manufacture of sulfur ic acid in an SCR. For the case of combined cycle combustion turbines, the SCR catalyst SO 2 oxidation rate (S2) wi ll be approximately 0.03. A more precise value can be obtained fr om 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. Equation 6-4 EM CCSCR = K • S2 • f sops • E2 • F3 SCR where,
EM CCSCR = Total H 2 SO 4 manufactured from SCR, lbs per year 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 S2 = SCR catalyst SO 2 oxidation rate (specified as a decimal, typically from 0.001- 0.03)
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

6-4NOx reduction or not. This value shoul d reflect the hours the SCR reactor processed flue gas, which will be site-specific but can be approximated bygenerally 0.8 for year-round peaking operation, 0.98 for year-round baseloaded operation, or 0.43 for seasonal operation
E2 = SO 2 produced, tons per year
F3 SCR = Technology Impact Factor, for SCR
The total sulfuric acid manufacture (TSAM) for a combined cycl e unit is estimated using the equation below: Equation 6-5 TSAM = EM CCcom + EM CCSCR **Sulfuric Acid Released** The sulfuric acid released by combustion in comb ined cycle units is estimated as follows: Equation 6-6 ER CCcom = EM CCcom • F2 CC where,
ER CCcom = Total H 2 SO 4 released from combustion, lbs/yr
F2 CC = Technology Impact Factor for the co mbined cycle heat exchanger, equal to a value of 0.5 The equation describing the sulf uric acid release from SCR equi pment on combined cycle units is estimated using a relationship similar to Equation 4-7, as follows: Equation 6-7 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 (see Text Box C) 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 comb ined cycle heat exchanger, equal to a value of 0.5.

6-5The total release of sulfuric acid from combined cycle units is then described by Equation 6-8, summing the sulfuric acid released by both combustion and SCR: Equation 6-8 TSAR = ER CCcom + ER CCSCR Example 7 of Appendix A illustrates a gas- fired combined cycle plant calculation.

6-6

# 7 **REFERENCES**

Benson, 2006a Benson, L. et al., “Use s of Lime for Controlling SO 3 Emissions,” Presentation to the 2006 DOE NETL 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 Tri oxide 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 Mist 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, August 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 Po llutant 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 Co mmunity 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, Meth od 2H- Determination of Stack Gas Velocity Taking into Account Veloc ity Decay Near the Stack Wall.

7-1EPA, 2009 Federal Register, Vol. 74, No. 163, Tuesday, August 25, 2009, 40 CFR Part 60 - Revisions to Test Method for Determining Stack Gas Velocity Taking Into Account Velocity Decay Near the Stack Walls. EPRI, 2001 EPRI Report 1004027, “Flue Gas Sulfuric Acid Measurement Improvements,” August, 2001. EPRI, 2008 Estimating Total Sulfuric Acid Emissions from Stationary Power Plants, EPRI, Palo Alto, CA: 2008. 1016384. (revised April, 2009) 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., Di smukes, E., Harrison, K., Monroe, L., Estimating Total Sulfuric Acid Emissi ons from Coal-Fired Power Plants. Revised Internal Report of Res earch & Environmental Affairs Department, Southern Company Services, February 1999.
Harrison, 2004 Harrison, K., et al., “Estimati ng Total Sulfuric Acid Emissions from Stationary Power Plants: Revision 3 ( 2004).” Revised Internal Report of Research & Environmental Affair s Department, Southern Company Services, December, 2004. Harrison, 2005 Harrison, K., et al., “Estimati ng Total Sulfuric Acid Emissions from Stationary Power Plants: Revision 4 ( 2005).” Revised Internal Report of Research & Environmental Affair s 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.

7-2Monroe, 2001 Monroe, L. and K. Harrison, “An Updated Method for Estimating Total Sulfuric Acid Emissions from Sta tionary 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, 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., “Emissi ons of Sulfur Trioxi de from Coal-Fired Power Plants,” Journal of the Ai r & 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-Sept ember 2, 2004, Washington, DC.

7-3

# A **EXAMPLE CALCULATIONS**

**Example 1: Conventional Coal -Fired Boiler with an ESP**  A 500 MW pulverized coal-fired (PC) boiler, equipped with a cold-s ide electrostatic precipitator, burns an Eastern bituminous coal. 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.
**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
F1 eastbit = 1.1163E-6 • SO2 + 0.0064876
ppm1667 000,12 602,003,10 0.2 HV K 1S2SO 1F = •=•=

F1 eastbit = 1.1163E-6 • 1667 + 0.0064876 = 0.0083
EM Comb = 3063 • 0.0083 • 42,824 = 1,088,710 lbs H 2 SO 4 /yr The 25,000 lbs/yr threshold has been exceeded; theref ore, a release estimate must be made and the result reporte d on Form R.
Released
ER comb = K • F1 • F2 • E2
ER comb = 3063 • 0.0083 • (0.50 • 0.63) • 42,824 = 342,943 lbs H 2 SO 4 /yr
Where F2 = Air Heater • Cold-Side ESP
F2 = 0.50 • 0.63 = 0. 315
**Example 2: SCR Added to Example 1** A 500 MW PC boiler, equipped with a cold-side electrostatic 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 o ccurred with the SCR operating. The SCR catalyst SO 2 oxidation rate specified in the design is 0.75%, and the ammonia slip is estimated to be 0.75

A-1ppmv. The coal used in the reporting year is 1,126,938 tons with a weig hted 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
F1 eastbit = 1.1163E-6 • SO2 + 0.0064877
ppm1667 000,12 602,003,10 0.2 HV K 1S2SO 1F = •=•=

F1 eastbit = 1.1163E-6 • 1667 + 0.0064877 = 0.0083
EM Comb = 3063 • 0.0083 • 42,824 = 1,088,710 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 = 1,088,710 + 423,023 lbs H 2 SO 4 /yr TSAM = 1,511,733 lbs H 2 SO 4 /yr The 25,000 lbs/yr threshold has been exceeded; theref ore, a release estimate must be made and the result reporte d on Form R.
Released
Combustion
ER Comb = K • F1 • F2 • E2
ER Comb = 3063 • 0.0083 • (0.50 • 0.63) • 42,824 = 342,943 lbs H 2 SO 4 /yr
Where F2 = Air Heater • Cold-Side ESP
F2 = 0.50 • 0.63 = 0.315

A-2SCR 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)] • 0.50 • 0.63
ER SCR = 122,812 lbs H 2 SO 4 /yr
Total
TSAR = ER comb + ER SCR TSAR = 342,943 + 122,812 lbs H 2 SO 4 /yr TSAR = 465,755 lbs H 2 SO 4 /yr
**Example 3: Alkali Injection Added to Example 1** A 500 MW PC boiler, equipped with a cold-side electrostatic 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 alka li 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 syst em 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
F1 eastbit = 1.1163E-6 • SO2 + 0.0064877

A-3ppm1667 000,12 602,003,10 0.2 HV K 1S2SO 1F = •=•=

F1 eastbit = 1.1163E-6 • 1667 + 0.0064877 = 0.0083
EM Comb = 3063 • 0.0083 • 42,824 = 1,088,710 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 = 1,088,710 + 423,023 lbs H 2 SO 4 /yr TSAM = 1,511,733 lbs H 2 SO 4 /yr The 25,000 lbs/yr threshold has been exceeded; theref ore, a release estimate must be made and the result reporte d 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 4-15
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 particulate 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 stack, there are no control technology components downstream of the measurement)
The conversion factor K alkali is equal to 3,799 (see Text Box C). This 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.

A-4However, the SO 3 concentration of 5 ppm in the stack is measured at slightly different conditions of excess O 2 and moisture (6.6% oxygen and 8.8% moisture and therefore, a new value of K alkali must be calculated:
K alkali (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 )]
K alkali (O 2 , H 2 O ) = 3799 (6% O 2 , 8.1% H 2 O) • [(100-8.1)/(100-8.8)]

• [(20.9 – 6.0)/(20.9 – 6.6)]
K alkali (6.6%, 8.8%) = 3799 • [1.0077) • [1.034]
K alkali (6.6%, 8.8%) =3958
Total sulfuric acid release is then calculated as follows:
ER ALKINJ = [3,958] • [27.05] • [5.0] • [1] • [1]
ER ALKINJ = 535,320 lbs/yr
TSAR = ER ALKINJ TSAR = 535,320 lbs/yr
**Example 4: 500 MW PRB-fired Boiler with ESP, SCR** A 500 MW PC boiler, equipped with a cold-side el ectrostatic precipitator, burns a PRB coal. The plant is equipped with an SCR process that oper ates 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 ammonia slip is estim ated to be 0.75 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 • 0.0019 • 9,692 = 56,404 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

A-5Total
TSAM = EM comb + EM SCR TSAM = 56,404 + 43,402 lbs H 2 SO 4 /yr TSAM = 99,806 lbs H 2 SO 4 /yr The 25,000 lbs/yr threshold has been exceeded; theref ore, a release estimate must be made and the result reporte d on Form R.
Released
Combustion
ER Comb = K • F1 • F2 • E2
ER Comb = 3063 • 0.0019 • (0.36 • 0.72) • 9,692 = 14,620 lbs H 2 SO 4 /yr
Where F2 = Air Heater • Cold-Side ESP
F2 = 0.36 • 0.72 = 0.26
SCR B = 1,384,552 tons/yr • 2000 lbs/ton • 8,500 Btu/lb • 1 TBtu/10 12 Btu B =23.54 TBtu/yr
ER SCR = [EM SCR – (K s • B • f s • S NH3 )] • F2 • F2
ER SCR = [43,402 – (3799 • 23.54 • 0.43 • 0.75)] • 0.36 • 0.72
ER SCR = 3,774 lbs H 2 SO 4 /yr
Total
TSAR = ER comb + ER SCR TSAR = 14,620 + 3,774 lbs H 2 SO 4 /yr TSAR = 18,394 lbs H 2 SO 4 /yr

**Example 5: FGC Added to Example 1** A 500 MW PC boiler, equipped with a cold-side electrostatic 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 estimated at 0.9. The coal used in the reporting year is 1,126,938 tons with a weighted average sulf ur concentration of 2.0% and a heating value of 12,000 Btu/lb.

A-6**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
F1 eastbit = 1.1163E-6 • SO2 + 0.0064877
ppm1667 000,12 602,003,10 0.2 HV K 1S2SO 1F = •=•=

F1 eastbit = 1.1163E-6 • 1667 + 0.0064877 = 0.0083
EM Comb = 3063 • 0.0083 • 42,824 = 1,088,710 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 /yr
Total
TSAM = EM Comb + EM FGC TSAM = 1,088,710 + 647,407 lbs H 2 SO 4 /yr TSAM = 1,736,117 lbs H 2 SO 4 /yr The 25,000 lbs/yr threshold has been exceeded; theref ore, a release estimate must be made and the result reporte d on Form R.
Released
Combustion
ER Comb = K • F1 • F2 • E2
ER Comb = 3063 • 0.0083 • (0.50 • 0.63) • 42,824 = 342,943 lbs H 2 SO 4 /yr
Where F2 = Air Heater • Cold-Side ESP
F2 = 0.50 • 0.63 = 0.315

A-7FGC 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 de vices after the ESP, then F2 = 1.0.
Total
ESAR = ER Comb + ER FGC ESAR = 342,943 + 92,487 lbs H 2 SO 4 /yr ESAR = 435,430 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 electrostatic 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 o ccurred with the SCR operating. The SCR catalyst SO 2 oxidation rate specified in the design is 0.75%, and the ammonia 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, except during startup and shutdown, with an operating factor estimated at 0.9. The coal used in the reporting year is 1,126,938 tons with a weighted average sulf ur 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= 1,088,711 + 423,023 + 647,407 lbs H 2 SO 4 /yr TSAM = 2,159,141 lbs H 2 SO 4 /yr The 25,000 lbs/yr threshold has been exceeded; theref ore, a release estimate must be made and the result reporte d on Form R.
Released

A-8Combustion
ER Comb = K • F1 • F2 • E2
ER Comb = 3063 • 0.0083 • (0.50 • 0.63) • 42,824 = 342,943 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)] • 0.50 • 0.63
ER SCR = 122,812 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 = 342,943 + 122,812 + 92,487 lbs H 2 SO 4 /yr TSAR = 558,242 lbs H 2 SO 4 /yr
**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 electrostatic 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 tons with a weighted average sulfur concentration of 2.0% and a heating value of 12,000 Bt u/lb. Natural gas is used as a startup fuel, with 0.5 TBtu per year. During st artup, 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 lo ad, it is burned while the SCR and FGC are both operating. The used oil has a sulfur content of 0.1% from analysis. **Solution** Coal fuel calculations Manufacture d from coal, from previous examples

A-9Total
TSAM = EM Comb + EM SCR + EM FGC TSAM= 1,088,711 + 423,023 + 647,407 lbs H 2 SO 4 /yr TSAM = 2,159,141 lbs H 2 SO 4 /yr
Released from coal, from previous examples
Total
TSAR = ER Comb + ER SCR + ER FGC TSAR = 342,943 + 122,812 + 92,487 lbs H 2 SO 4 /yr TSAR = 558,242 lbs H 2 SO 4 /yr Natural gas fuel calculations Manufactured from natural gas
Combustion
E2 NG = K b • 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 • 0.136
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 • 0.50 • 0.63 • 0.136
ER Comb = 1.31 lbs H 2 SO 4 released F2 is taken to be equal to 0.50 for the air heater and 0.63 for the ESP.
Used oil fuel calculations Manufactured from used oil

A-10Combustion
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 /yr
TSAM = 566 lbs H 2 SO 4 /yr
Released from used oil
Combustion
ER Comb = K • F1 • F2 • E2
ER Comb = 3063 • 0.0175 • 0.50 • 0.63 • 0.966
ER Comb = 16.3 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)] • 0.50 • 0.63
ER SCR = -9.6 lbs H 2 SO 4 /yr

A-11F2 is taken to be equal to 0.50 for the air heater and 0.63 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 = 16.3 – 9.6 + 70.3 lbs H 2 SO 4 /yr
TSAR= 77 lbs H 2 SO 4 /yr
Grand totals for all fuels Manufactured
TSAM = TSAM coal + TSAM NG + TSAM oil TSAM = 2,159,141 + 4.16 + 566 lbs H 2 SO 4 /yr TSAM = 2,159,211 lbs H 2 SO 4 /yr
Released
TSAR = TSAR coal + TSAR NG + TSAR oil TSAR = 558,242 + 1.31 + 77 lbs H 2 SO 4 /yr TSAR = 558,320 lbs H 2 SO 4 /yr
**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

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 the b ack-end tubes of the HRSG, like an air heater.)

A-12

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

EPRI, 2010 (EPRI Report 1020636)
Modification Description Fuel Impact Factor (F1) Combined low and high-sulfur eas tern bituminous coals into a single category with a linear curve fit. F1 factor based on fuel SO 2 content calculated from fuel sulfur content: F1 ebit = 1.1163E-6 •

 SO 2 + 0.0064877 Changed the following F1 factors based on additional data: Subbit/PRB – changed from 0.0018 to 0.0019 Lignite – changed from 0.0048 to 0.0044 Technology Factors (F2) Changed factors fo r APH and ESP due to addition and reevaluation of data: APH, low-sulfur east. bit. – changed from 0.49 to 0.50 APH, PRB – changed from 0.56 to 0.36 ESP, low-sulfur east. bit – changed from 0.49 to 0.63 ESP, PRB – changed from 0.73 to 0.72 Corrected placement of Srivastava and Buckley reference values in Figure 4-4. Alkali Injection Added a procedure to determine total releases from partial year injection. Incorporated correction to alka li injection conversion factor, K alkali Report Organization Moved F2 Factor s from Section 3 to Section 4 Examples Updated examples to account for new F1 and F2 factors

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. Errata page published to correct error in alkali injection conversion factor, K alkali

B-1Combustion 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 eac h 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 calcu lations 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), Dry 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 SCR

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