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 

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Estimating Total Sulfuric Acid Emissions 

from Stationary Power Plants 

Version 2010a 

1020636 

Technical Update, April 2010 

EPRI Project Manager 

Naomi Goodman 
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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 should be cited in the literature 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 sulfuric acid emissions from fossil-fuel-fired 

electrical power production facilities. The methodology was developed by Southern Company 

Services (SCS) and modified by EPRI with permission 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 control equipment or flue gas treatment, and 

released to the environment in stack gases. 

Results and Findings 

The power generation units considered in the report 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 provided for estimating removal or production of sulfuric acid by 

pollution control devices and flue gas treatments. 

Challenges and Objectives 

Sulfuric acid releases from electric power generating units must be reported to EPA on an annual 

basis if the amounts manufactured, processed, or otherwise used exceed the limits set by the 

EPA’s Toxics Release Inventory (TRI) program. 

Applications, Value, and Use 

This report will be useful to environmental staff 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 currently no other published approach with a 

comparable amount of supporting measurements. EPRI will continue to enhance the 

methodology by adding to the underlying database and refining the calculations to address new 

flue gas treatment approaches. 

Approach 

The manufacture and release of sulfuric acid from coal-, oil-, and natural gas-fired electrical 

generation units were estimated from field test data. Measurements from multiple facilities were 

used to develop sulfuric acid removal factors for various coal types and facility 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 responsible 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 their emissions of over 600 

chemicals. Sulfuric acid (H2SO4) 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 any particle size.” Sulfuric acid 

aerosol is formed during combustion of fossil fuels when sulfur trioxide (SO3) in hot combustion 

gases combines with water to form sulfuric acid, and then cools and condenses to form small 

droplets of the acid. 

This document provides a methodology to estimate sulfuric acid emissions from fossil-fuel-fired 

electrical power production facilities. The methodology 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 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 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 emissions remains unchanged from that described 

by SCS (2005). First, the method estimates manufacture of SO3 and sulfuric acid from three 

sources: (1) combustion of fuel, (2) the NOx control process selective catalytic reduction (SCR), 

and (3) flue gas conditioning (FGC), in which SO3 is added to flue gas to improve particulate 

control device performance. Next, the actual release of SO3 or H2SO4 is calculated by adjusting 

the manufacturing estimate to account for processes known to remove SO3 and H2SO4. These 

include a byproduct reaction of SCR, as well as the NOx control process of selective noncatalytic reduction (SNCR), and other types of FGC. This paper also provides a method to 

account for the impact of SO3/H2SO4 removal technologies such as the addition of calciumbased, sodium-based, or other alkaline reagents, as described by Dombrowski (2004) and Weilert 

(2004). 

The current estimation method is based on an ever-growing database of measurements of SO3

emissions from combustion systems, primarily coal-fired boilers. The 2008 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 various boiler types and coal sources. The estimates of SO3 production 

from combustion of coal are consistent with theoretical predictions that approximately 1% of the 

sulfur in coal is converted to SO3, although a wide range of conversions from 0.2% to 1.6% is 

reported, depending on coal source and boiler type. Data are obtained from field tests, reporting 

the removal of SO3 or H2SO4 by air heaters, particulate control equipment such as electrostatic 

precipitators (ESPs) and fabric filters, and SO2 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. 

ix 
 

The 2010 version adds more than 10 new sources of measurement data of SO3 emissions and 

introduces a new methodology for determining a Fuel Impact Factor (estimate of SO2 conversion 

to SO3 in the boiler) for eastern bituminous 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 methodology described in this report and the factors 

developed from the available data will not be applicable to every facility configuration or fuel 

type. Site-specific measurements of SO3 or H2SO4 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 Sources 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 plants is a topic of increasing importance to the 

U.S. electric utility industry. Most significantly, Section 313 of the Emergency Planning and 

Community Right-to-Know Act (EPCRA), also known as the Toxic Release Inventory (TRI), 

requires facilities that “manufacture,” “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 chemicals subject to the EPCRA § 313 reporting requirements so that 

only aerosol forms of sulfuric acid would be subject to the TRI reporting requirements (EPA, 

1995a). EPA defines sulfuric acid aerosols as “includ[ing] mists, vapors, gas, fog, and other 

airborne forms of any particle size.” Although initially it appeared that only liquid droplets of 

sulfuric acid needed to be reported, the present method estimates the sulfuric acid emissions 

regardless of the physical state of the molecules. 

Beginning on July 1, 1999, certain coal- and oil-fired electric power plants have been required to 

report annual releases of TRI chemicals that they manufacture, process or otherwise use above 

threshold amounts. Under EPA’s EPCRA § 313 regulations, 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 considerable attention in recent years with the broad 

application of selective catalytic reduction (SCR) NOx control technology. The use of SCR 

unavoidably contributes to production of sulfur trioxide (SO3), the precursor of sulfuric acid. 

Several notable incidents have been witnessed where an increase in sulfuric acid emissions, as 

manifested by an increase in stack plume visibility, was attributed to the addition of SCR process 

equipment to an existing power plant. The deployment 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 SO3 and sulfuric acid in power plants. 

The methodology 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 informally (Hardman, 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 

1-1 
version 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 largely unchanged from the previous version 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 SO3 measurements. The 

current version contains a modified methodology to determine a Fuel Impact Factor (F1 factor, 

used to reflect the impact of coal type on conversion of SO2 to SO3 in the boiler) for eastern 

bituminous coals. Rather than presenting different F1 factors for low-sulfur and high-sulfur 

eastern bituminous coals, the model now represents the F1 factor as a linear relationship between 

boiler SO2 and the rate of conversion to SO3. 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 estimating sulfuric acid emissions 

from power generating facilities, for use in Toxics Release Inventory reporting and other 

applications. The scope of units considered includes 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 documented data describe sulfuric acid emissions from coal-fired 

steam generators. The focus on this category of units is due to the increased availability of 

measurements describing the fate of sulfuric acid attributable to the retrofit of SCR process 

equipment on coal-fired steam generators. 

Report Organization 

Section 2 of this report addresses the uncertainty in measuring SO3 concentration using the 

preferred controlled condensation system (CCS) method, and the accuracy and 

representativeness of the available data. Section 3 outlines the general methodology adopted in 

this model while Section 4 describes the details 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 how to conduct the calculation for steam boilers 

firing a mixture of fuels. Section 6 addresses simple cycle and combined cycle combustion 

turbine applications. Example calculations for various power plant configurations 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 knowledge 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 database of measurements from many electric 

generating units (EGUs) is desired to obtain a robust predictive method. Both the size and the 

representativeness of the measurement database are critical to the accuracy of a predictive 

method. 

The predictive correlations presented in this report are based on data obtained from field tests 

conducted predominantly within the last 10 years, 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; thus, it was not possible to critically review all 

data used in this model. 

The technique used to measure SO3/H2SO4 is not known for all data sources, but most 

measurements were conducted using the controlled condensate system (CCS), a widely used 

technique that is generally considered the most accurate method for measuring SO3/H2SO4 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 SO2 to SO3 in the impinger 

solution. 

CCS Measurement Uncertainty

A series of field and laboratory trials conducted by EPRI evaluated the measurement bias of the 

CCS technique by comparing results from both laboratory tests and field trials (EPRI, 2001). 

SO3/H2SO4 measurements at similar gas compositions were compared in a 1) clean, ash-free 

laboratory environment; 2) simulated ash environment, 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 estimation model. The results showed that, when fly ash 

was present in the flue gas stream, the technique imposed a low bias (e.g., indicated lower 

SO3/H2SO4 than measured in the ash-free laboratory environment), due to reactions of SO3 or 

sulfuric acid with fly ash in the filter thimble holder upstream of the CCS condenser. Conversely, 

the EPRI tests indicated that use of CCS downstream of the particulate control device produces 

unbiased measurements, as long as appropriate procedures are followed. 

The extent of bias observed in the EPRI study depended on the sampling location, which could 

be the air heater inlet, air heater outlet, or flue gas desulfurization outlet. Furthermore, the bias 

depended on the quantity of ash collected, the alkalinity of the ash, and the coal sulfur content 

(e.g., SO2 content in the sample gas). Measurement bias in the simulated ash environment was 

observed for both high sulfur coal and low sulfur Powder River Basin (PRB) coal; however 

biasing in the PRB coal tests can generally be considered non-significant in light of already low 

SO3 concentrations and the expected absorption of sulfuric acid with the alkaline ash in actual 

field tests. Data for high sulfur coal suggested a low bias of 20-25% could occur in measurement 

2-1 
locations upstream of a particulate control device with typical ash loadings, and no significant 

bias downstream of the particulate control device. 

The precision of the CCS data used in this estimation 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 repeatability 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 sampling personnel. Therefore, the precision of the 

entire data set used in this model, which includes data from older studies of unknown quality, is 

expected to be closer to ± 50%. 

Representativeness 

The accuracy of the correlations presented in this report depends on the representativeness of the 

constituent data points. For some power plant configurations, only a few measurements are 

available, and the correlations provide only rough approximations of the flue gas SO3/H2SO4

releases for similar units. The category with the largest number of data points is dry-bottom 

boilers, firing low sulfur, eastern bituminous coal. In general, the number of SO3 measurements 

for various power plant configurations are proportional to the occurrence of those configurations 

among the total population of U.S. EGUs. The number of measurements in each power plant 

category should be considered when applying this model; factors based on one measurement 

have much higher uncertainty than factors based on dozens of measurements. 

As a consequence of the uncertainty in SO3/H2SO4 measurements and the limited number of data 

points that comprise the relevant correlations, the predictive technique 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 sulfuric acid production mechanisms in power plants 

and presents the basic equations for estimating sulfuric acid releases. A detailed review of this 

topic has been provided by Srivastava (2004) and more recently by Monroe (2006). 

The production or manufacture of SO3, and ultimately sulfuric acid, is determined initially by 

processes occurring directly within the flame zone of a boiler, the convective heat transfer 

sections, or environmental control 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 mechanisms, including alkali-based sorbent injection, 

occurring at lower temperatures. 

Factors Affecting Manufacture and Release 

The method estimates the manufacture and the subsequent release of sulfuric acid from the 

power generation process. The manufacture of sulfuric acid is defined as any process step that 

increases the flue gas content of sulfuric acid, regardless of its ultimate fate. To estimate the 

release of sulfuric acid, the manufacture estimate is corrected by a factor or series of factors to 

account for sulfuric acid removal within the system. 

Three process steps ultimately lead to the manufacture of sulfuric acid in a fossil fuel-fired 

electricity generation unit: the combustion process, selective catalytic reduction (SCR) for NOx 

control, and flue gas conditioning. All remaining steps in the power generation process reduce 

sulfuric acid. Therefore, the total sulfuric acid released is the cumulative sum of that 

manufactured, adjusted by sulfuric acid losses. 

The manufacture of SO3, the precursor to sulfuric acid, is calculated in this model as shown in 

Equation 3-1. 

Equation 3-1 TSAM = EMComb + EMSCR + EFGC 

where, 

 TSAM = Total manufacture of sulfuric acid 

EMComb = Manufacture of sulfuric acid through combustion 

EMSCR = Manufacture of sulfuric acid from SCR 

EMSCR = Manufacture of sulfuric acid from FGC 

3-1 
The Total Sulfuric Acid Release (TSAR) from a combustion unit equipped with SCR/SNCR 

NOx control and FGC is represented by Equation 3-2. 

Equation 3-2 TSAR = ERComb + ERSCR/SNCR + ERFGC 

where, 

 TSAR = Total release of sulfuric acid 

ERComb = Sulfuric acid released through combustion 

ERSCR/SNCR = Sulfuric acid released from SCR (or SNCR) 

ERFGC = Sulfuric acid released from FGC 

Combustion Process 

Manufacture 

A detailed analytical study by Senior (2002) explored details of SO2 oxidation to SO3. 

Specifically, the author modeled the relevant reaction sets employing the temperature-time 

history of a typical utility boiler, considering gas phase events only and ignoring catalytic effects. 

The results showed that insignificant SO3 formed in the early stage of the flame, but SO3

production increased as the gases exited the flame zone and cooled. The author reported 

production of SO3 to be essentially complete prior to flue gas entering the economizer section. 

The observation that most SO3 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 between coal sulfur content, excess air, and SO3

production that has been empirically observed by previous investigators. Specifically, the results 

showed that after four seconds of residence time, SO3 production could range from between 0.3 - 

0.6% of the flue gas SO2 concentration. 

In the absence of SCR NOx control or FGC, the boiler or turbine combustion process comprises 

the only source of sulfuric acid. The sulfuric acid manufacture by the combustion process 

(EMComb) is expressed as follows: 

Equation 3-3 EMComb = K ● F1 • E2 

Where K is a constant, F1 is the Fuel Impact Factor describing the SO3 production associated 

with combustion for a specific fuel type, and E2 is the annual rate of SO2 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 the combustion process is determined by adjusting the 

manufactured SO3 by the removals in the following equipment: the air heater, electrostatic 

precipitator (ESP) or other particulate 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 (ERComb) is described by the following: 

Equation 3-4 ERComb = EMComb ● F2 (all that apply) 

The development of Technology Impact Factors (F2) for each downstream component is 

addressed in Section 4. 

SCR/SNCR NOx Control 

Manufacture 

The SCR process increases the production of SO3, and therefore, H2SO4, as a percentage of SO2. 

SO3 production can range from as low as 0.3%, for the most recent catalyst technology, to as 

high as 3% of the SO2 concentration. 

The production of SO3 from SO2 is a well-known consequence of SCR, and the degree of SO2

oxidation is a performance variable that should be part of catalyst procurement specifications. To 

a degree, SO3 production can be mitigated by reducing the content of vanadium pentoxide and 

compensating with other catalyst oxides such as tungsten or molybdenum, which offer improved 

selectivity (e.g., lower SO2 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 SO2

oxidation. To achieve an equivalent level of NOx and residual ammonia slip, a low SO2

oxidation catalyst may require a larger volume of catalyst than one for which SO2 conversion is 

not constrained. In general, the degree of SO2 oxidation ranges from about 0.2% to 1.5% for 

most SCR process reactors designed for bituminous coals. If SCR is applied to extremely low 

sulfur, high alkalinity coals such as PRB, higher SO2 oxidation is acceptable. Depending on how 

the measurement of SO2 oxidation is performed, the oxidation can be 3% or higher. 

In many instances, owners and catalyst suppliers prefer that measurements to quantify SO2

oxidation for the purpose of commercial 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 SO3 concentration. The measurements are generally 

conducted using CCS. However, particularly for PRB coals, this method will over-predict SO3

manufactured by the SCR, as the mitigating role of high fly ash alkalinity is not considered. 

Consequently, the role of fly ash alkalinity must be considered in predicting SO3 manufactured 

by SCR. 

The observation that calculated laboratory-scale SO3 values at the exit of an SCR reactor exceed 

measurements in the field has been witnessed on numerous occasions. Specifically, Lindenhoff 

(2004) reported that the measured SO2 oxidation rate for PRB-generated flue gas of 1.25% was 

below the 1.6% value predicted based on the boiler and SCR catalyst specifications. Further, 

tests conducted by this catalyst manufacturer noted significant absorption of SO3 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 SO3 removal within an 

SCR reactor as a function of both ash content and the number of alkaline sites available in the 

flue gas stream. 

3-3 
An alternative NOx control process, selective non-catalytic reduction (SNCR), does not use a 

catalyst and does not promote the oxidation of SO2 to SO3. Accordingly, there is no manufacture 

of sulfuric acid attributable to SNCR. 

The following relationship describes the total H2SO4 manufactured from an SCR equipped utility 

boiler or steam generator: 

Equation 3-5 EMSCR = K • S2 • fsops • E2• F3SCR 

Where K is a constant, S2 is the catalyst SO2 oxidation rate, fsops is the fraction of the year in 

which flue gas is directed through the SCR, E2 is the annual rate of SO2 production, and F3SCR is 

the Technology Impact Factor for SCR used to adjust 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 (NH3), also called ammonia slip, into the 

flue gas. This residual ammonia can react with SO3 or sulfuric acid to form ammonium sulfate 

and/or ammonium bisulfate, thereby removing from the flue gas some of the SO3 that is a 

precursor to sulfuric acid, and reducing the amount released. 

For an SCR, ammonia slip is expected to usually range between 0 and 2 parts per million (ppm) 

for bituminous coal cases. Higher values of ammonia slip are possible if the unit has not been 

recently tuned, the boiler or SCR process operates under upset, or as the catalyst ages. Higher 

ammonia slip may be tolerable in PRB coal applications, since ammonia is not readily absorbed 

by the highly alkaline PRB ash and adverse operational impacts (air preheater pluggage and ash 

contamination by ammonia) are avoided. Reactions between the residual ammonia and SO3 or 

H2SO4 occur in the air preheater and result in a solid product that may deposit or accumulate on 

the surface of the fly ash. Any SO3 or H2SO4 that participates in these reactions is no longer 

chemically present as sulfuric acid and is not required to be reported to the EPA TRI program as 

a release of sulfuric acid. 

SNCR employs ammonia or urea injection in the upper furnace for NOx reduction. The higher 

temperatures characteristic of the upper furnace zone (1,800 to 2,400°F, as compared to 700°F 

for SCR) do not require reduction catalyst so there is no additional manufacture of SO3 or 

sulfuric acid. Typically, SNCR systems operate with higher levels of residual ammonia (5 to 10 

ppm), so any sulfuric acid that is present from combustion is reduced through reaction with the 

ammonia. Consequently, SNCR systems will always reduce the overall amount of sulfuric acid 

released, while SCR systems can reduce but will likely increase the amount of sulfuric acid 

released. 

The reactions between SO3 and/or H2SO4 and ammonia produce ammonium sulfate [(NH4)2SO4] 

and/or ammonium bisulfate (NH4HSO4). 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 usually determined by the 

stoichiometry, or the relative amount of each substance on a mole basis, that is present in the flue 

gas. When ammonia is present in an amount over twice the mole content of the sulfuric acid, the 

reaction product will always be the ammonium sulfate. Conversely, when sulfuric acid is present 

3-4 
in an amount on a mole basis greater than ammonia, the product will be ammonium bisulfate. 

Between these two extremes, a mixture of ammonium sulfate and bisulfate is produced. 

An SCR-equipped unit firing bituminous coals with low-to-medium sulfur content will always 

produce an excess of sulfuric acid over ammonia slip. Accordingly, ammonium bisulfate is the 

primary byproduct anticipated. For subbituminous, PRB, and lignite coals, any sulfuric acid 

produced is typically adsorbed by the ash and it is likely that 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 

SO3 content. For eastern bituminous coals, which have generally higher sulfur content and lower 

ash alkalinity, ammonium bisulfate 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 additional ammonia is available, the ammonium 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 reaction 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. Additional ammonia reacting with the ammonium 

bisulfate is of no consequence to the sulfuric acid calculation – 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 residual ammonia, or ammonia slip. For SCR, the 

sulfuric acid released (ERSCR) is estimated with the following relationship: 

Equation 3-6 ERSCR = [EMSCR – (Ks • B • fsreagent• SNH3)] • F2x

Where KS is a constant, B is the coal burn in TBtu/yr, fsreagent is the fraction of SCR operation 

with reagent injection, SNH3 is the NH3 slip for the SCR/SCNR and F2 are any applicable 

downstream, Technology Impact Factors. These calculations and factors are described further in 

Section 4. 

For SNCR, as there is no sulfuric acid manufacture term, the sulfuric acid release estimate 

(ERSNCR) 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: SO3, SO3 plus NH3, or NH3 alone. In SO3-based FGC, SO3 is introduced into the flue 

gas either preceding or following the air heater. The SO3 is typically produced on-site from 

3-5 
sulfurous fuel that is burned to produce SO2, which is then catalytically oxidized to SO3 with a 

conversion rate typically exceeding 95%. When injected into the flue gas, the SO3 immediately 

reacts with water vapor to create sulfuric acid, thus resulting in the manufacture of sulfuric acid. 

Estimating the manufacture source requires knowledge of the concentration of SO3 injected and 

the associated oxygen content of the flue gas. 

Equation 3-7 presents an equation to estimate the manufacture of sulfuric acid from this source, 

where Ke is a constant, B is the coal burn, fe is the FGC operating factor, and Isis the SO3

injection rate. Further details and derivation of the constant are provided in Section 4. 

Equation 3-7 EMFGC = Ke • B • fe • Is

Release 

The release of sulfuric acid attributable to FGC requires adjusting for the reaction with NH3 that 

may be introduced as part of a flue gas conditioning scheme, either with or without sulfuric acid. 

Analogous to the case of SCR and SNCR, the concentration of NH3 and the associated O2

content of the flue gas must be estimated. Accordingly, FGC can manufacture sulfuric acid, but 

can also remove sulfuric acid if NH3 is injected alone or in quantities greater than the sulfuric 

acid. The following equation describes the relationship to determine the release of sulfuric acid 

attributed to FGC. 

Equation 3-8 ERFGC = [EMFGC – (Ke • B • fe • INH3)] • F3FGC • F2 

Where F3FGC is the Technology Impact Factor for FGC, used to adjust the releases based on the 

injection point of SO3. The Technology Impact Factors (F2) describe the fraction of sulfuric acid 

that penetrates the air heater (for FGC that is introduced ahead of the air heater), and for the 

particulate control device and FGD (for FGC that is introduced after the air heater). The basis for 

the F2 factors and the detailed equations for quantifying the manufacture and release of sulfuric 

acid are presented in Section 4. 

Alkali Injection 

Many utility operators inject alkali into the flue gas to control SO3. 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 SO3. These alkali materials include sodium 

bisulfate, trona, and various types of lime (conventional, hydrated, and magnesium enhanced). 

Sodium bisulfate (SBS) is the most widely used reagent for control of SO3. SBS is introduced 

into the flue gas, usually at the air heater exit, but in some units at the air heater inlet, to 

maximize residence time and improve SO3 removal. SBS can be highly effective in removing 

SO3. Additional sodium can be added to the flue gas to compensate for any compromise in ESP 

performance due to increased ash resistivity associated with SO3 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 SO3. Trona can be injected at 

several locations within the boiler, but most applications 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. 

3-6 
Several forms of calcium-based sorbents can be utilized. 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 experience with lime-derived sorbents addressed the 

advantages of this approach (Benson, 2006a). Hydrated lime has been shown to be an effective 

calcium-based reagent for SO3 control (Gale, 2006), as has lime supplemented with magnesium 

hydroxide (Benson, 2006b). Calcium–based sorbents can be very effective in reducing SO3, but 

may compromise ESP performance, as the reduced SO3 content in flue gas increases the 

electrical resistivity of the ash on the collecting plate. For this reason, some operators have 

proposed using both calcium- and sodium-based sorbents, the latter to both augment SO3

removal and promote ESP performance. 

In summary, any of several alkali materials can be used to control SO3, 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 

SO3 concentration in flue gas. In most cases, the tests will be conducted at the stack. The alkali 

injection system usually is operated to reduce SO3 emissions to between 5 and 15 ppm, an 

optimal range to prevent formation of a visible plume. 

In the 2008 version of the Sulfuric Acid Model, EPRI added a procedure to estimate SO3 stack 

releases from EGUs that employ alkali injection for SO3 control, using as an input to the model 

the measured or estimated stack gas SO3 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 Section 4. An example application of this method is provided in 

Appendix A. 

Equation 3-9 ERALKINJ = Kalkali • B • SSO3 • F2x• Falkali

Where Kalkali is a constant, B is the coal burn, SSO3 is the measured SO3 content with injection, 

Falkali is the fraction of time alkali injection is in operation, and F2 are any applicable 

downstream Technology Impact Factors. 

To estimate SO3 manufacture with alkali injection, 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 SO3 formation of adding alkali at 

various points in the fuel combustion and stack gas treatment process. Assuming that there is no 

reduction of SO3 formation is conservative for a threshold determination for TRI reporting 

purposes. 

Users of this approach should be cautioned that the current EPA-approved test method for SO3

(Method 8) has a significant positive bias, and that corrections for this bias may be needed to 

accurately assess flue gas concentrations. A more accurate method is the controlled condensate 

system, although this method is not currently approved by EPA for this purpose. 

3-7 

4

ESTIMATING GUIDELINE: STEAM BOILERS 

This section describes an estimation procedure for calculating the manufacture and release of 

sulfuric acid from coal-fired steam generators. The topics addressed are (a) formation within the 

furnace; (b) the role of SCR, (c) flue gas conditioning (FGC), and (d) alkali injection; and (e) the 

removal by downstream equipment such as air heaters, ESPs or other particulate control devices, 

and FGD process equipment. Each of the subsequent 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 SO2 released – determined either from coal usage (amount burned 

and sulfur content) or from continuous emission monitoring system (CEMS) output. Units 

equipped with FGD equipment or other methods of SO2 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 SO2 data for non-ideal stack flow conditions. 

Sulfuric Acid Manufactured by Combustion (EMComb)

The following relationship is proposed to estimate the sulfuric acid manufactured from 

combustion in utility sources: 

Equation 4-1 EMComb = K • F1 • E2 

where, 

EMComb= total H2SO4 manufactured from combustion, lbs/yr 

K = Molecular weight and units conversion constant 

= 98.07 / 64.04 • 2000 = 3,063 

 98.07 = Molecular weight of H2SO4 

 64.04 = Molecular weight of SO2

 Conversion from tons per year to pounds per year – multiply by 2000. 

F1 = Fuel Impact Factor 

E2 = Sulfur dioxide (SO2) emissions, either: (1) recorded by a continuous 

emissions monitor, tons/yr, or (2) calculated from coal burn data, tons/yr. 

4-1 
The Fuel Impact Factor (F1) is a numerical value or a mathematical relationship reflecting the 

conversion of SO2 to SO3 in the boiler for a specific coal type and boiler type. In the derivation 

of Equation 4-1, the following assumptions are made: 

• SO3 concentrations are proportional to SO2 concentrations. 

• The grade of coal being burned impacts the rate of conversion from SO2 to SO3. 

• All SO3 that forms is converted to H2SO4. 

• The rate of SO3 formation is independent of the boiler firing rate (unit load). 

The estimates of sulfur dioxide emissions (E2) and F1 factors are further described in the 

following sections. 

Sulfur Dioxide (SO2) Emissions from Combustion (E2) 

Estimating the sulfuric acid production from Equation 4-1 requires knowledge of the mass rate of 

SO2 generated. This rate is designated as E2 in Equation 4-1. As noted previously, the value of 

E2 can be estimated from either (a) the EPA CEMS data, or (b) calculated from the coal burn 

data (EPA, 1995a). 

CEMS can directly quantify the annual SO2 production rate, in tons/year of SO2. However, it 

may be necessary to correct for stack geometry in deriving E2. Specifically, if CEMS SO2 data 

are used, the factor E2 is defined by the following equation 

Equation 4-2a ( )

⎥

⎦

⎤ ⎢

⎣

⎡ +∗+∗ −= 100

321 12

2 CRCRC EE 

where, 

E2 = Corrected SO2 mass rate, tons per year 

E = CEMS-derived SO2 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 within 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 default value of 1.5 can be used; however the R value 

for each stack can be different and should be determined using the appropriate EPA method. 

EPA has also proposed a wall effects correction for stacks with rectangular ducts that are 

equipped with flow monitors (EPA, 2009). This proposal has not been finalized as of December, 

2009, but some facilities may be allowed to apply this approach as a conditional test method. 

4-2 
As an alternative to using CEMS data, the following relationship based on coal burn data can be 

used to estimate the rate of SO2 emissions: 

Equation 4-2b E2 = K1 • K2 • C1 • S1 

where, 

E2 = SO2 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 SO2 

32.06 = molecular weight of S 

conversion of % S to a fraction - multiply by 100 

K2 = Sulfur conversion to SO2, 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 SO2 emissions, either 

the fuel basis must be used for the manufacturing and release calculations, or CEMS data can be 

used, but only when the CEMS precedes the FGD or SO2 control equipment. Data from a CEMS 

located after a flue gas desulfurization system cannot be used.

Fuel Impact Factor (F1). Figure 4-1 depicts the fraction of H2SO4 produced as a function of 

flue gas SO2 content for several coal sources and boiler 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 bituminous 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 PRB and one unit that fires 100% lignite. 

Figure 4-1 shows that a wide range in SO3 production is observed for all coals and boiler types. 

This range exceeds the theoretical predictions by Senior (2002), suggesting that the role of ash in 

either catalyzing SO3 production or absorbing/neutralizing SO3 is not fully accounted for. The 

only consistent results in Figure 4-1 are for SO3 from PRB-fired units, regardless 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 unique F1 factor was assigned to these two coal 

types that was the average SO3 fraction produced for each type. However, that approach led to 

large fluctuations in estimated sulfuric acid releases for facilities with coal sulfur near the 2.5% 

4-3 
division point. Therefore, the current model replaces the two eastern bituminous coal groups 

with a linear relationship. The regression line for all eastern bituminous, 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 (R2) is 

low (0.13) due to scatter in the data. The current model retains F1 factors based on average 

fraction of SO2 converted to SO3 for all other coal types. 

Eastern Bituminous

y = 1.1163E-06x + 6.4877E-03

R2

 = 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 SO2 Content

Boiler SO3 Production, 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 SO3 Production and Flue Gas SO2 (corrected to 3% O2) 

Equation 4-3 F1ebit = 1.1163E-6 • SO2 + 0.0064877 

where, 

F1ebit = Fuel Impact Factor for all Eastern Bituminous coals burned in a drybottom boiler 

SO2 = Boiler SO2 concentration (ppm), derived from fuel sulfur content (%) 

In order to use this approach, it is necessary to relate coal sulfur (%) to the SO2 concentration in 

the boiler. Equation 4-4 is used to calculate that relationship: 

4-4 
Equation 4-4 HV

K 1SSO 1F

2 •=

where, 

SO2 = Boiler SO2 concentration (ppmvd, 3% O2, dry) derived from fuel sulfur 

content (%) 

S1 = Coal sulfur weighted average, %, dry 

KF1 = Conversion factor = 10,003,602 

HV = Coal heating value, Btu/lb, dry 

The conversion factor KF1 considers all relevant constants to yield the result in ppm of SO2. The 

derivation of this constant is presented in Text Box A. 

Text Box A: Derivation of Conversion Factor, KF1. 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% O2 on a dry basis (typical of the SO2 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 

SO2 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 106 Btu 106

 ppm 

100% 1 lb mol S 32.06 lbs S 11,419 scf HV Btu 1 MBtu 

Grouping terms, 

SO2 = S1 • 10,003,602 / HV 

Therefore, the value of KF1 is equal to 10,003,602 [ ppmvd SO2 (3% O2, dry) • Btu/lb]/%S. 

4-5 
Table 4-1 summarizes the F1 factors, 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 * SO2 + 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 (ERComb) 

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 Technology Impact Factors (F2) for all downstream 

equipment (the air heater, the particulate control 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 ERComb = EMComb • F2 (all that apply)

Units that do employ SCR or SNCR, and/or flue gas conditioning, 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 fact that the entire flue gas flow is not subject 

to sulfuric acid removal by the FGD process. This bypass factor is pertinent only to units that 

employ flue gas bypass. 

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. 

ERCOMB = [SBf + (1 – SBf) • F2s] • K • F1 • E2 • F2x

where, SBf = fraction of scrubber bypass, as a decimal 

 F2s = F2 for scrubber 

 F2x = All other applicable F2 factors except for scrubber. 

Manufacture and Release from SCR and SNCR 

This section describes a method to estimate impacts of SCR or SNCR on sulfuric acid emissions. 

SCR can contribute to or reduce sulfuric acid emissions, while SNCR will only reduce such 

emissions. 

As discussed in Section 3, SCR produces SO3 (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 catalyst and removal by the reaction of residual 

NH3 from the SCR process. 

A key assumption in the calculation strategy is that residual ammonia from either SCR or SNCR 

captures all available sulfuric acid in the (ammonium) bisulfate form. The bisulfate form is not 

reportable under the TRI reporting requirement and thus is not part of the manufacture 

calculation. If any additional ammonia reacts with the bisulfate, it is of no consequence to the 

sulfuric acid calculation – although this issue will be important when estimating ammonia 

releases. 

4-7 
The calculations for the manufacture of sulfuric acid by SCR and the release of sulfuric acid by 

SCR and SNCR are described in the following sections. 

Sulfuric Acid Manufacture by SCR (EMSCR) 

The following relationship estimates the total H2SO4 manufactured from an SCR equipped utility 

boiler or steam generator: 

Equation 4-6 EMSCR = K • S2 • fsops • E2• F3SCR 

where, 

EMSCR = Total H2SO4 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 H2SO4 

 64.04 = Molecular weight of SO2

 Conversion from tons per year to pounds per year – multiply by 2000. 

S2 = SCR catalyst SO2 oxidation rate (specified as a fraction, typically from 

0.001- 0.03) 

fsops = Operating factor of SCR system, or the fraction of coal burn when the flue 

gas is directed through the SCR, whether NH3 reagent is injected to derive 

NOx reduction or not. This value should reflect the hours the SCR reactor 

processed flue gas, which will be site-specific but can be approximated by 

generally 0.8 for year-round peaking operation, 0.98 for year-round baseloaded operation, or 0.43 for seasonal operation 

E2 = SO2 produced, tons per year 

F3SCR = Technology Impact Factor, for SCR 

The Technology Impact Factor for SCR (F3SCR) is required to adjust SO3 content for the 

presence of alkaline fly ash, as described in Section 3, unless direct measurements exist for the 

subject unit documenting SO3 increase across the SCR reactor. 

It is important to select the correct SO2 oxidation rate for use in Equation 4-6. Typically, the SO2

oxidation rate from SCR catalysts can range from as low as 0.3% of flue gas SO2 content, up to 

3% for low sulfur, highly alkaline coals (e.g., PRB). There are two means by which SO2

oxidation is specified and measured for SCR process equipment, and each has significantly 

different implications for SO3 produced. One method – based on actual 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 these 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, SO2 conversion data will be determined with 

commercial testing of full-scale equipment. These data – measured on commercial plants under 

4-8 
actual operating conditions – are the most authentic in reflecting actual SO3 content, as the 

impact of ash alkalinity is taken into account. 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 F3SCR Technology Impact Factor. 

Laboratory Bench-Scale Tests. Some owners and process suppliers prefer to specify and conduct 

guarantee measurements for SO2 oxidation on laboratory-scale equipment using synthetic flue 

gases without fly ash. There are good reasons to select this methodology; evidence suggests SO3

measurements in the environment of the test laboratory 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 SO3 generated. Accordingly, SO2 oxidation 

reported by this method exceeds that measured in commercial practice, particularly for PRB 

coals. SO2 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 F3SCR. 

An F3SCR factor for PRB coals is shown in Table 4-2. This factor is derived from measurements 

at two PRB-fired units. SO3 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 F3SCR

factors for other coals, so a factor of 1 (full penetration) is recommended. 

Table 4-2 

F3SCR Technology Impact Factors for SCR 

Coal Type F3SCR

PRB 0.17 

Other Coals 1 (no data available) 

SNCR will not result in the manufacture of sulfuric acid, thus EMSNCR 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 residual ammonia, or ammonia slip. For SCR, the 

sulfuric acid released (ERSCR) is estimated with the following relationship: 

Equation 4-7 ERSCR = [EMSCR – (Ks • B • fsreagent• SNH3)] • F2x

where, 

ERSCR = Total H2SO4 released from SCR, lbs per year 

EMSCR = Total H2SO4 manufactured from SCR, lbs per year 

Ks = Conversion factor = 3799 (See Text Box C) 

B = Coal burn in TBtu/yr 

4-9 
fsreagent = fraction of SCR operation with reagent injection, when residual NH3 is 

produced that will remove SO3. The value of fsreagent will be similar to, but 

slightly less than, the value of fsops, defined for Equation 4-6. 

SNH3 = NH3 slip from SCR/SNCR, ppmv at 6% O2, wet: 

• SCR averages 0.75 ppmv over catalyst guarantee period 

• SNCR averages 5 ppmv 

• Note: actual NH3 slip data should be used if available 

F2x = Technology Impact Factors, all that apply 

The conversion factor Ks, 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 NH3

is reported in terms of 6% oxygen and “wet” flue gas at 8.1% H2O, is presented in Text Box C. 

Text Box C: Derivation of Conversion Factor, KS. 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% O2 (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,

(Ks • B • fs • SNH3) = lbs H2SO4 per yr = 

B TBtu SNH3 scf NH3 1 lb mol NH3 1 lb mol H2SO4 98 lbs H2SO4 14925 scf fg 106

 MBtu 

year 106 scf flue gas 385 scf NH3 1 lb mol NH3 1 lb mol H2SO4 1 MBtu TBtu 

Grouping terms, 

= B • fs • SNH3 • 3799 

Therefore, the value of Ks is equal to 3799 lbs H2SO4/(TBtu • ppmv NH3 @ 6% O2 and wet). 

Equation 4-7 specifies the concentration of NH3 in flue gas (SNH3) in terms of ppmv at 6% O2, 

wet flue gas basis. If the concentration of NH3 is reported at different conditions, the value of the 

constant Ks will change. The following formula is used to adjust the value of the constant Ks: 

Equation 4-8a Ks (O2

, H2O ) = 3799 (6% O2, 8.1% H2O) • [(100-8.1)/(100-new H2O)] 

• [(20.9 – 6.0)/(20.9 – new O2)] 

For example, if the ammonia concentration is quantified at a value (in ppm) that is defined at 0% 

oxygen and a dry basis, the value of Ks that should be used is: 

Equation 4-8b Ks (O2

, H2O) = 3799 (6% O2, 8.1% H2O) • [(100-8.1)/(100-0)] 

 • [(20.9 – 6.0)/(20.9 – 0)] 

 Ks = 2489 

4-10 
Equation 4-8a can be used to calculate the value of Ks at any condition used to define the 

concentration of residual NH3. 

The operating factor of the SCR describes the portion of the coal burn that reflects the period of 

SCR operation, based on whether the unit operates 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 records, 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 • KBB

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 

KB = Conversion factor = 2E-9. The factor is calculated from the conversion of 

tons per year to pounds per year and Btu to TBtu (2000/1012 = 2E-9) 

For SNCR, as there is no sulfuric acid manufacture term; the sulfuric acid release due to SNCR 

(ERSNCR) 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 (TSAR) for a generating unit equipped with SCR is 

estimated by the following equation: 

Equation 4-10 TSAR = ERComb + ERSCR

Total sulfuric acid release (TSAR) for a generating unit equipped with SNCR is estimated by the 

following equation: 

Equation 4-11 TSAR = ERComb + ERSNCR

For units equipped with flue gas desulfurization bypass, a series of calculations analogous to 

those described in the previous section for combustion-derived sulfuric acid are required. The 

calculations for SCR or SNCR are described in Text Box D. 

4-11 
Text Box D: Special Provision for Flue Gas Desulfurization Bypass. Those units equipped with scrubbers 

where some of the flue gas bypasses the scrubber should take this into account in their 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. 

ERSCR = [SBf + (1 – SBf) • F2s] • [EMSCR – (Ks • B • fs • SNH3)] • F2x

where, 

SBf = fraction of scrubber bypass, as a decimal 

F2s = F2 factor for scrubber 

F2x = 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 SO3–based FGC systems attempt to maintain a fixed 

concentration of SO3 in the flue gas, typically between 5 and 7 ppm by volume (ppmv). 

Calculations to estimate the sulfuric acid manufactured during FGC use the setpoint of the FGC 

system as the key input. The FGC system is assumed to operate during most of the plant’s duty, 

except for perhaps startup and low load operation. The sulfuric acid manufactured by SO3-based 

FGC equipment (EMFGC) is calculated as follows: 

Equation 4-12 EMFGC = Ke • B • fe • Is

 where, 

EMFGC = Total H2SO4 manufactured from FGC, lbs per year 

Ke = Conversion factor = 3799, which is equivalent to Ks, as described in Text 

Box C. 

B = Coal burn in TBtu/yr 

Fe = Operating factor of FGC system, or the fraction of coal burn when the 

FGC system operates. This value is site-specific, must be determined for 

each unit, but generally will be about 0.8. 

Is = SO3 injection rate in ppmv at 6% O2, wet; generally, 

 = 7 ppmv if before the APH 

= 5 ppmv if after the APH 

If the SO3 injection rate (IS) is known at conditions other than 6%O2 and wet, Equation 4-8a can 

be used to calculate a new value Ke at the new conditions. 

4-12 
FGC equipment that employs both SO3 and NH3 must be reported to manufacture sulfuric acid at 

the rate of SO3 injection, regardless of whether ammonia is used or not. FGC equipment that 

employs NH3 alone does not manufacture sulfuric acid, and any ammonia will reduce the release 

of sulfuric acid by reacting with SO3 or the resultant H2SO4. 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 (ERFGC) 

The subsequent release of sulfuric acid associated with flue gas conditioning can be estimated 

from the sulfuric acid quantity manufactured, adjusted by the amount that reacts with ammonia 

in any particulate control device installed downstream of the FGC. 

Equation 4-13 ERFGC = [EMFGC – (Ke • B • fe • INH3)] • F3FGC • F2 

 where, 

ERFGC = Total H2SO4 released from FGC, lbs per year 

EMFGC = Total H2SO4 manufactured from FGC, lbs per year 

Ke = Conversion factor = 3799, which is equivalent to Ks, as described in Text 

Box C 

B = Coal burn in TBtu/yr 

Fe = Operating factor of FGC system, or the fraction of fuel burn when the FGC 

system operates. This value will be the same as Fe described previously and 

in many cases can be approximated by 0.8. 

INH3 = NH3 injection for dual flue gas conditioning, ppmv at 6% O2, wet; 

generally 3 ppmv NH3 if operating, or zero (0) if no ammonia is used. 

F3FGC = Technology Impact Factors for FGC, see Table 4-3 

F2 = Technology Impact Factors for equipment after the ESP only, if no control 

equipment is installed after the ESP; F2 = 1. 

Table 4-3 

F3FGC – Technology Impact Factors for FGC with Cold-Side ESP 

Location Coals F3FGC

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. 

4-13 
This approach leads to a possible contradiction in the behavior of SO3/H2SO4 depending on the 

place in which the SO3/H2SO4 enters the system. Depending on the source of the SO3, 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 SO3 manufactured by combustion, SCR, or introduced as FGC ahead of the air preheater, the 

method predicts sulfuric acid removal of 75% (F3FGC = 0.25) for eastern bituminous coals across 

an air preheater/cold-side ESP combination. However, as denoted in Table 4-3, a higher fraction 

of SO3 or H2SO4 (90%, F3FGC = 0.10) is predicted to be removed for FGC if injected downstream 

of the air preheater. The difference in results is likely 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, SO3 injected ahead of the air heater as FGC is assumed to be 95% 

removed (F3FGC = 0.05) through the air heater and ESP. SO3 is assumed to be 98% removed 

(F3FGC = 0.02) when injected downstream of the air heater. As these western bituminous, 

subbituminous, and lignite coals feature significant alkaline content of ash, any SO3 injected for 

FGC will likely be captured by both physical deposition and chemical reaction. Accordingly, it is 

reasonable that SO3/H2SO4 removal assumed for these coals be higher than for eastern 

bituminous coals. Further, as the injection of SO3 on the cold-side of the air preheater is typically 

below the acid dewpoint, it can be expected that any injected SO3 will condense on fly ash more 

readily compared to the slower cooling of the flue gas through the air preheater. 

For units equipped with flue gas desulfurization bypass, a series of calculations analogous to 

those described in the previous sections for combustion- and SCR-derived sulfuric acid are 

required. These calculations for FGC are described in Text Box 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/SNCR 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. 

ERFGC = [SBf + (1 – SBf) • F2s] • [EMFGC – (Ke • B • fe • INH3)] • F3FGC • F2x

where, 

SBf = fraction of scrubber bypass, as a decimal 

 F2s = F2 factor for scrubber 

 F2x = 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. Therefore, if a site burns coal and uses both SCR 

and FGC, the amount of sulfuric acid manufactured – by combustion, SCR, and/or FGC – is 

added together to determine the total amount. The amount of sulfuric acid released is also 

calculated – again for combustion, SCR, and FGC – and summed to define the total. 

Both SCR and/or ammonia-based FGC may have a negative 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 release of sulfuric acid. Since the release of sulfuric acid from 

combustion, SCR, and FGC are all additive, any negative values calculated as a result of these 

circumstances will need to be accounted for in the total release equation. 

Accordingly, total sulfuric acid 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 = EMComb + EMSCR/SNCR + EMFGC 

Equation 4-14b: Release 

 TSAR = ERComb + ERSCR/SNCR + ERFGC

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

Total Release Calculation for Sources 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 SO3 concentration in flue gas, 

most likely at the stack. The concentration of SO3 measured at the stack can be converted to a 

mass emission rate using Equation 4-15 

Equation 4-15 ERALKINJ = Kalkali • B • SSO3 • F2x• Falkali

where, 

ERALKINJ = Total H2SO4 released from unit equipped with alkali injection, lbs per year 

Kalkali = Constant, equal to 3,799, which is equivalent to Ks, as described in Text 

Box C. 

B = Coal burn in TBtu/yr 

SSO3 = SO3 content, as measured in the stack or particulate collector exit, ppmv at 

6% O2, wet 

Falkali = fraction of time unit is operated with alkali addition to remove SO3

4-15 
F2x = Technology Impact Factors, to be applied only if SO3 measurements are 

conducted at a location preceding the stack. The value of F2x is 1 if 

measurements are conducted at the stack, and there are no control 

components downstream of the measurement location. If the control 

device is an SO2 scrubber, F2x is denoted as F2s, but is handled the same 

way. 

If the SO3 content (SSO3) is known at conditions other than 6%O2 and wet, Equation 4-8a can be 

used to calculate a new value Kalkali at the new conditions. 

The Technology Impact Factors selected should represent the control equipment between the 

point of SO3 measurement and the stack. For example, if a unit is equipped with only an ESP, 

and the SO3 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 (Falkali does not equal 1), then 

Equation 4-15 must be added to the fraction of the total sulfuric acid release (TSAR) calculated 

from combustion, SCR/SNCR and/or FGC for the remainder of the operating time. Furthermore, 

in the calculation of TSAR for partial-year alkali injection, if SO3 measurements also exist for 

operation without alkali injection, these data should be used with Equation 4-15 (without the 

Falkali term) instead of the standard estimation equations to determine the term: ERComb + 

ERSCR/SNCR + ERFGC, as shown below: 

Equation 4-16 ERNOINJ = Kalkali • B • SSO3 • F2x• (1-Falkali) 

where, 

ERNOINJ = Total H2SO4 released from unit without alkali injection, lbs per year 

Kalkali = Constant, equal to 3,799, which is equivalent to Ks, as described in Text 

Box C. 

B = Coal burn in TBtu/yr 

SSO3 = SO3 content without alkali injection, as measured in the stack or 

particulate collector exit, ppmv at 6% O2, wet 

Falkali = fraction of time unit is operated with alkali addition to remove SO3

F2x = Technology Impact Factors, to be applied only if SO3 measurements are 

conducted at a location preceding the stack. The value of F2x is 1 if 

measurements are conducted at the stack, and there are no control 

components downstream of the measurement location. If the control 

device is an SO2 scrubber, F2x is denoted as F2s, but is handled the same 

way. 

Accordingly, total sulfuric acid release (TSAR) for a unit employing partial-year alkali injection 

is estimated by one of the following equations: 

Equation 4-17a TSAR = ERALKINJ + (ERComb + ERSCR/SNCR + ERFGC) • (1-Falkali) 

4-16 
Equation 4-18b TSAR = ERALKINJ + ERNOINJ

Technology Impact Factors (F2) 

The sulfuric acid estimating methodology employs empirically-derived Technology Impact 

Factors (F2). These F2 factors describe sulfate removal observed over the air heater, the ESP or 

other particulate control device, 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 SO3 and/or H2SO4 within the air heater is due to the condensation of sulfuric acid 

and its removal as discrete individual particles (along with the fly ash) on the surface of this heat 

exchanger. The conventional Ljungstrom-type air heater has been documented to provide a 

removal sink for sulfuric acid (Saranuc, 1999). In fact, the largest supplier of Ljungstrom air 

heaters has evaluated the feasibility of employing the air heater process environment in 

conjunction with limestone injection as a proactive sulfuric acid control strategy (Hamel, 2003, 

and Bowes, 2006). 

Air heater surfaces follow a pattern of alternately heating and cooling as the heat exchange 

elements move from the relatively hot flue gas to the cooler combustion air. As reported during 

field tests of commercial equipment (Saranuc, 1999), this temperature profile introduces a strong 

gradient in sulfuric acid concentration across the exit plane of the air heater. The cyclic thermal 

conditions as described by Hamel (2003) reveal that a significant portion of the air heater basket 

surface metal is exposed to flue gas temperature below the sulfuric acid dewpoint. This 

phenomenon may promote sulfuric acid deposition on the heat exchanger metal surface, 

compared to a tube-type heat exchanger in which 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 SO3/H2SO4 removal (and the corresponding F2 factors) across commercial, 

Ljungstrom-type air heaters. These data are presented as a function of SO2 content of the flue gas 

for the host unit. Most data shown are for low sulfur eastern bituminous coal, for which air 

heater H2SO4 removal varies significantly between 0% and 69%, averaging 50% as indicated by 

the horizontal line. Two high sulfur (>2.5%) eastern cases are shown, along with limited data for 

PRB coal. 

The data point showing 0% removal at approximately 600 ppm SO2 is believed suspect, as an 

identical companion unit firing the same coal exhibited sulfuric acid capture of 38%. This 

measurement was not included in the F2 calculation. 

Figure 4-2 presents two points reported by Hamel (2003) based on a low sulfur eastern 

bituminous-fired unit where SO3 was “spiked” into the flue gas to elevate the concentration 

entering the air heater to 80 and 122 ppm. These two points are plotted separately on Figure 4-2 

versus an estimated flue gas SO2 content that could generate such values (using the average SO2

oxidation rate for high sulfur, eastern bituminous coal in Figure 4-1). It should be noted these 

values measured for the “spiked” flue gas significantly exceed those measured for the two high 

sulfur eastern coal cases. 

4-17 
0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0 500 1000 1500 2000 2500 3000 3500

Flue Gas SO2 Content, ppm

Air Heater H2SO4 Removal, %

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

Air 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” SO3 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 other coal types. For those coals, the model user 

could consider adopting the F2 factor for PRB if the ash is strongly 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. 

4-18 
The standard deviation of the reported measurements for low sulfur eastern bituminous coal is 

about one third of the average measurement. There are not enough data to calculate a standard 

deviation for the F2 factors for the other fuels. 

Particulate and SO3 Control Processes 

This section discusses the available data on removal of SO3 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 contribute to the removal of sulfuric acid. The ESP is the 

flue gas contacting device with perhaps the longest 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 ESP and the corresponding F2 factors as a function 

of the SO2 content of the flue gas for the host unit, from a survey of plant operators. Most data 

shown are for a cold–side ESP and low sulfur eastern 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 SO2 is suspect, as a companion unit at the 

same site firing the identical coal had 50% sulfuric 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 factors 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 due to the reevaluation of measurement data from one of the 

sources. Data are not currently available for other 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 H2SO4 penetration for one hot-side ESP (ESPh) is based on only a 

single test series It should 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 and high sulfur eastern bituminous coals show a 

significant difference between the two coal types. As a result, total H2SO4 releases for hot-side 

ESP configurations may have a low bias; however there is insufficient data to recommend 

alternate values. 

Data for baghouses show high H2SO4 removal based on very limited data from plants burning 

subbituminous coal. The average of two data points was 90% removal. 

4-19 
0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0 500 1000 1500 2000 2500 3000 3500

Flue Gas SO2, ppm

ESP Flue Gas H2SO4 Removal, %

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

ESP 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 Particulate 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 measurements for low sulfur eastern bituminous coal is 

about one fourth of the average measurement, while the standard deviation of the measurements 

4-20 
for the high sulfur eastern bituminous coal is about one sixth of the average. Inadequate data 

prevent calculating a standard deviation 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 thermodynamically supersaturated. Buckley also projects 

sulfuric acid condensation on surfaces where equipment walls are lower in temperature than the 

flue gas (common in commercial equipment). However, 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 laminar layer near surfaces that are 

key to producing fine sulfuric acid mist. 

Srivastava (2004) suggests that the condensed submicron 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 equipment 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. The percent of sulfuric 

acid removal is depicted as a function of FGD inlet SO2 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 Buckley (2002), while the solid horizontal line 

reflects the 50% average reported by Srivastava (2004). 

Table 4-5 summarizes the F2 factors for FGD process equipment, including results for wet spray 

towers burning bituminous coal. Two results are available for a wet scrubber at a unit burning a 

blend of PRB/lignite. Harrison (2005) calculated an average removal 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 particulate/FGD process is also available, but only for a bituminous 

coal. Similar to the case for a wet spray tower, the lack of data merits assuming sulfuric acid 

removal for all coals is described by that measured for bituminous coal. 

F2 factors for the use of magnesium-based additives 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 both. The fuel oil vanadium can also catalyze SO2 to SO3

oxidation, but the additive, when added to the oil, 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. 

4-21 
4-22 

Figure 4-4 

Removal of Sulfuric Acid by Flue Gas Desulfurization Equipment: Various FGD Designs, Coals 

Table 4-5 

Summary of F2 Factors for Wet and 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 boilers firing multiple or blended fuels – such as 

natural gas, fuel oil, and perhaps coal – uses the 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 for loss or removal. It is assumed for multiple 

fuel boilers that the contribution of each fuel can be separated and treated 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 SO3. 

This approach of treating blends of coal as separate fuels in proportion to the mass burn rate is 

believed to be conservative with regard to SO3 emissions when considering PRB coal, in that it 

will likely project H2SO4 emissions higher than actual. The ability of PRB coal to neutralize SO3

by an amount that is greater than 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 sulfuric acid is calculated by adding all of the 

manufacture totals for all fuels from all processes. Likewise, the release is summed over all 

processes and fuels. 

As an example, if a unit with an SCR and FGC burns 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 

5-1 
f. 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 together 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 have negligible content of sulfur in the fuel, thus sulfuric acid 

production is negligible. Facilities that burn only natural gas are not required to participate in the 

TRI reporting program. However, sources that are co-located with coal units will need to be 

included in the estimates for total sulfuric acid release for the site. The calculation described in 

this section can also be used to estimate sulfuric acid emissions for Prevention of Significant 

Deterioration (PSD) review of new natural gas-fired generation sites. 

The calculations for gas-fired units are structured very much the same as for coal- and oil-fired 

sources. For simple cycle combustion turbines, the only source of sulfuric acid is the sulfur in the 

fuel. The EPA AP-42 emissions factor suggests a value of 2000 grains of sulfur per million cubic 

feet of natural gas as a default sulfur content value. This value is equivalent to approximately 3.5 

ppm of sulfur in the raw natural gas. 

A methodology to estimate manufacture and release of sulfuric acid for simple cycle and 

combined cycle units is provided below. 

Simple Cycle Units 

Given the current configuration of simple cycle units, any sulfuric acid manufactured is 

released; thus, the estimates of sulfuric acid are the same. This is because there is no equipment 

located following the simple cycle arrangement that removes sulfuric acid. Even though simple 

cycle units can be equipped with SCR, and the use of SCR with sulfur-containing fuels will 

manufacture SO3, the exit gas temperature is too high to allow condensation of SO3 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 EMSC = K • F1 • E2NG 

where, 

EMSC = total H2SO4 manufactured from combustion, lbs/yr 

K = Molecular weight and units conversion constant 

= 98.07 / 64.04 • 2000 = 3,063 

 98.07 = Molecular weight of H2SO4 

 64.04 = Molecular weight of SO2

 Conversion from tons per year to pounds per year – multiply by 2000. 

F1 = Fuel Impact Factor for NG 

6-1 
E2NG = Sulfur dioxide (SO2) emissions either: (1) recorded by a continuous 

emissions monitor, tons/yr, or (2) calculated from fuel burn data, tons/yr. 

SO2 emissions can be obtained through a calculation using the heat input of natural gas. 

Equation 6-2a E2NG = Kb • BB

NG • S

where, 

E2NG = Total SO2 production from NG combustion, tons/yr 

Kb = Molecular weight and units conversion constant = 0.0001359 

BB

NG = Burn of NG in TBtu/yr 

S = Sulfur content of natural gas, in grains per million standard cubic feet 

(Mscf), typically 2000 gr/106 scf per EPA AP-42. 

The derivation of constant Kb is presented in Text Box F. 

Text Box F: Derivation of Molecular Weight and Units Conversion Constant, Kb

Kb is determined from the following equation. 

(Kb • BNG • S) = tons SO2 per yr = 

BB

NG

TBtu S gr S 

1 scf nat 

gas 1012 Btu lb S 1 ton S 1 ton mol S 

1 ton mole 

SO2 64 tons SO2

Year 

106 scf 

nat gas 1050 Btu TBtu 

7000 gr 

S 2000 lbs S 32 tons S 1 ton mol S 

1 ton mole 

SO2

Grouping terms, 

= (BNG • S) • 64 / (1050 • 32 • 14) = (BNG • S) • 0.0001359 

Therefore, the value of Kb is equal to 0.0001359 tons SO2/(TBtu • grains S/million SCF NG). 

The SO2 emissions can also be calculated from the volume of natural gas burned: 

Equation 6-2b E2NG = KNG • N1 • S 

where, 

E2NG = total SO2 production from NG combustion, tons/yr 

KNG = 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/106 scf as default 

The derivation of constant KNG is presented in Text Box G. 

6-2 
Text Box G: Derivation of Molecular Weight and Units Conversion Constant, KNG

(KNG • N1 • S) = tons SO2 per yr = 

N1 106

 scf S gr S lb S 1 ton S 1 ton mol S 1 ton mole SO2 64 tons SO2

Year 106 scf nat gas 7000 gr S 2000 lbs S 32 tons S 1 ton mol S 1 ton mole SO2

Grouping terms, 

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

Therefore, the value of KNG is equal to 1.427 • 10-7 tons SO2/(grains S) 

Table 6-1 presents the F1 factors for simple cycle units as a function of stack temperature, as 

sulfuric acid vapor is related to the temperature 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 SO3), the amount manufactured and released depends on stack temperature. Table 

6-1 combines the temperature-based SO3 to H2SO4 conversion with the SO2 to SO3 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 EMCCcom = K • F1 • E2NG 

where, 

EMCCcom= Total H2SO4 released from combustion, lbs/yr 

K = Molecular weight and units conversion constant 

= 98.07/64.04 • 2000 = 3,063 

 98.07 = Molecular weight of H2SO4; 

 64.04 = Molecular weight of SO2; 

 Conversion from tons per year to pounds per year – multiply by 2000. 

F1= Fuel Impact Factor for NG (See Table 6-1) 

E2NG= Sulfur dioxide (SO2) emissions either: (1) recorded by a continuous 

emissions monitor, tons/yr, or (2) calculated from fuel burn data, tons/yr. 

Equation 6-4 describes the manufacture of sulfuric acid in an SCR. For the case of combined 

cycle combustion turbines, the SCR catalyst SO2 oxidation rate (S2) will be approximately 0.03. 

A more precise value can be obtained from either field test reports of SO2 oxidation, or from the 

vendor’s specification of the SCR catalyst or process. The Technology Impact Factor for SCR, 

F3SCR, will be 1.0. 

Equation 6-4 EMCCSCR = K • S2 • fsops • E2• F3SCR 

where, 

EMCCSCR = Total H2SO4 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 H2SO4; 

 64.04 = Molecular weight of SO2; 

 Conversion from tons per year to pounds per year – multiply by 2000 

S2 = SCR catalyst SO2 oxidation rate (specified as a decimal, typically from 

0.001- 0.03) 

fsops = Operating factor of SCR system, or the fraction of coal burn when the flue 

gas is directed through the SCR, whether NH3 reagent is injected to derive 

6-4 
NOx reduction or not. This value should reflect the hours the SCR reactor 

processed flue gas, which will be site-specific but can be approximated by 

generally 0.8 for year-round peaking operation, 0.98 for year-round baseloaded operation, or 0.43 for seasonal operation 

E2 = SO2 produced, tons per year 

F3SCR = Technology Impact Factor, for SCR 

The total sulfuric acid manufacture (TSAM) for a combined cycle unit is estimated using the 

equation below: 

Equation 6-5 TSAM = EMCCcom + EMCCSCR 

Sulfuric Acid Released 

The sulfuric acid released by combustion in combined cycle units is estimated as follows: 

Equation 6-6 ERCCcom = EMCCcom • F2CC 

where, 

ERCCcom = Total H2SO4 released from combustion, lbs/yr 

F2CC = Technology Impact Factor for the combined cycle heat exchanger, equal 

to a value of 0.5

The equation describing the sulfuric acid release from SCR equipment on combined cycle units 

is estimated using a relationship similar to Equation 4-7, as follows: 

Equation 6-7 ERCCSCR = [EMCCSCR – (Ks • B • fsreagent• SNH3)] • F2cc

where, 

ERCCSCR = Total H2SO4 released from SCR, lbs per year 

EMCCSCR = Total H2SO4 manufactured from SCR, lbs per year 

Ks = Conversion factor = 3799 (see Text Box C) 

B = Fuel burn in TBtu/yr 

fsreagent = Fraction of SCR operation with reagent injection, when residual NH3 is 

produced that will remove SO3. 

SNH3 = NH3 slip from SCR, ppmv at 6% O2, wet (averages 0.75 ppmv over catalyst 

guarantee period. Actual NH3 slip data should be used if available) 

F2CC = Technology Impact Factor for the combined cycle heat exchanger, equal to 

a value of 0.5. 

6-5 
The 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 = ERCCcom + ERCCSCR

Example 7 of Appendix A illustrates a gas-fired combined cycle plant calculation. 

6-6 
7

REFERENCES 

Benson, 2006a Benson, L. et al., “Uses of Lime for Controlling SO3 Emissions,” 

Presentation to the 2006 DOE NETL Environmental Controls 

Conference, May, 2006, Pittsburgh, PA. 

Benson, 2006b Benson, L., “Use of Magnesium Hydroxide for Reduction of SO3

Emissions from Coal-Fired Power Plants,” Presentation to the 2006 DOE 

NETL Environmental Controls Conference, May, 2006, Pittsburgh, PA. 

Bowes, 2006 Bowes, E., et al., “Sulfur Trioxide Reduction Strategy Demonstrated At 

Dominion Energy’s Chesterfield Station,” 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 SO2 Control Symposium, 

Washington, DC, December, 1991. 

Dombrowski, 

2004 

Dombrowski, K. et al., “SO3 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 Pollutant Emission Factors AP-42, Fifth 

Edition, Volume I: Stationary Point and Area Sources.” 

http://www.epa.gov/ttnchie1/ap42pdf/c01s01.pdf. 

EPA, 1997 EPA, Emergency Planning and Community Right-to-Know Act - Section 

313. Guidance for Reporting Sulfuric Acid (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, Method 2H- Determination of Stack Gas 

Velocity Taking into Account Velocity Decay Near the Stack Wall. 

7-1 
EPA, 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 SO3 Removal,” Proceedings of the 

Power Plant Air Pollutant Control “Mega Symposium”, Baltimore, MD, 

August, 2006. 

Hamel, 2003 Hamel, B., “The Role of the Combustion Air Preheater in an Effective 

Multipollutant Control Strategy,” Proceedings of the Combined Power 

Plant Air Pollutant Control Mega Symposium, Washington, DC, May, 

2003. 

Hardman, 1998 Hardman, R., Stacy R., Dismukes, E., Estimating Total Sulfuric Acid 

Emissions from Coal-Fired Power Plants. Internal Report of Research & 

Environmental Affairs Department, Southern Company Services, March 

1998. 

Hardman, 1999 Hardman, R., Stacy, R., Dismukes, E., Harrison, K., Monroe, L., 

Estimating Total Sulfuric Acid Emissions from Coal-Fired Power Plants. 

Revised Internal Report of Research & Environmental Affairs 

Department, Southern Company Services, February 1999. 

Harrison, 2004 Harrison, K., et al., “Estimating Total Sulfuric Acid Emissions from 

Stationary Power Plants: Revision 3 (2004).” Revised Internal Report of 

Research & Environmental Affairs Department, Southern Company 

Services, December, 2004. 

Harrison, 2005 Harrison, K., et al., “Estimating Total Sulfuric Acid Emissions from 

Stationary Power Plants: Revision 4 (2005).” Revised Internal Report of 

Research & Environmental Affairs Department, Southern Company 

Services, October, 2005. 

Lindenhoff, 2004 Lindenhoff, Peter, “SCR Catalyst Developments: SO2 Oxidation,” 

presentation to the EPRI 2004 Workshop on Selective Catalytic 

Reduction, November, 2004, Pittsburgh, PA. 

7-2 
Monroe, 2001 Monroe, L. and K. Harrison, “An Updated Method for Estimating Total 

Sulfuric Acid Emissions from Stationary 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,” Proceedings of the 2006 Mega-Symposium, 

August, 2006, Baltimore, MD. 

Moser, 2007 Moser, R., “SO3’s Impact on Plant O&M: Part III,” Power Magazine, 

April, 2007. 

Ritzenthaler, 2006 Ritzenthaler, D. et al., “A System Approach to SO3 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 SO3 Production,” Fuel Processing 

Technology, 2000, 63, 197-213. 

Srivastava, 2004 Srivastava, R., et al., “Emissions of Sulfur Trioxide from Coal-Fired 

Power Plants,” Journal of the Air & Waste Management Association, 

Volume 54, June 2004. 

Weilert, 2004 C. Weilert, “Wet ESPs vs. Sorbent Injection for SO3 Control,” 

Proceedings of the Combined Power Plant Air Pollution Control MegaSymposium, August 30-September 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-side 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 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 SO2/yr 

 EMComb = K • F1 • E2 

 F1eastbit = 1.1163E-6 • SO2 + 0.0064876 

 ppm1667 000,12

602,003,10 0.2

HV

K 1S2SO 1F •=•= =

 F1eastbit = 1.1163E-6 • 1667 + 0.0064876 = 0.0083 

 EMComb = 3063 • 0.0083 • 42,824 = 1,088,710 lbs H2SO4/yr 

The 25,000 lbs/yr threshold has been exceeded; therefore, a release estimate must be made and 

the result reported on Form R. 

Released 

 ERcomb = K • F1 • F2 • E2 

 ERcomb = 3063 • 0.0083 • (0.50 • 0.63) • 42,824 = 342,943 lbs H2SO4/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 precipitator, 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 occurred with the SCR operating. The SCR catalyst 

SO2 oxidation rate specified in the design is 0.75%, and the ammonia slip is estimated to be 0.75 

A-1
ppmv. 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 Btu/lb. 

Solution 

Manufactured 

 E2 = K1 • K2 • C1 • S1 

 E2 = 0.02 • 0.95 • 1,126,938 • 2.0 = 42,824 tons SO2/yr 

 Combustion

 EMcomb = K • F1 • E2 

 F1eastbit = 1.1163E-6 • SO2 + 0.0064877 

 ppm1667 000,12

602,003,10 0.2

HV

K 1S2SO 1F •=•= =

 F1eastbit = 1.1163E-6 • 1667 + 0.0064877 = 0.0083 

 EMComb = 3063 • 0.0083 • 42,824 = 1,088,710 lbs H2SO4/yr 

 SCR

 EMSCR = K • S2 • fs • E2 

 EMSCR = 3063 • 0.0075 • 0.43 • 42,824 = 423,023 lbs H2SO4/yr 

 Total

 TSAM = EMcomb + EMSCR

 TSAM = 1,088,710 + 423,023 lbs H2SO4/yr 

 TSAM = 1,511,733 lbs H2SO4/yr 

The 25,000 lbs/yr threshold has been exceeded; therefore, a release estimate must be made and 

the result reported on Form R. 

Released 

 Combustion

 ERComb = K • F1 • F2 • E2 

 ERComb = 3063 • 0.0083 • (0.50 • 0.63) • 42,824 = 342,943 lbs H2SO4/yr 

 Where F2 = Air Heater • Cold-Side ESP 

 F2 = 0.50 • 0.63 = 0.315 

A-2
 SCR

 B = 1,126,938 tons/yr • 2000 lbs/ton • 12,000 Btu/lb • 1 TBtu/1012 Btu 

 B = 27.05 TBtu/yr 

 ERSCR = [EMSCR – (Ks • B • fs • SNH3)] • F2 • F2 

 ERSCR = [423,023 – (3799 • 27.05 • 0.43 • 0.75)] • 0.50 • 0.63 

 ERSCR = 122,812 lbs H2SO4/yr 

 Total

 TSAR = ERcomb + ERSCR

 TSAR = 342,943 + 122,812 lbs H2SO4/yr 

 TSAR = 465,755 lbs H2SO4/yr 

Example 3: Alkali Injection Added to Example 1 

A 500 MW PC boiler, equipped with a cold-side electrostatic precipitator, burns an Eastern 

bituminous coal. The plant employs injection of alkali material (e.g., lime, sodium bicarbonate, 

sodium bisulfate, etc.) to control SO3 emissions at the stack. The plant operator has conducted a 

series of field tests to determine the amount of alkali material that must be injected to limit flue 

gas SO3 concentration at the stack. The test contractor has issued a report defining the amount of 

alkali that should be added to limit the stack SO3 to 5 ppm, as measured in the flue gas at 6.6% 

O2, and 8.8% moisture. The alkali injection system will be operated throughout the entire year, 

so that no more than 5 ppm of SO3 at the stated conditions of excess O2 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 SO2/yr 

 Combustion

 EMcomb = K • F1 • E2 

 F1eastbit = 1.1163E-6 • SO2 + 0.0064877 

A-3
 ppm1667 000,12

602,003,10 0.2

HV

K 1S2SO 1F •=•= =

 F1eastbit = 1.1163E-6 • 1667 + 0.0064877 = 0.0083 

 EMComb = 3063 • 0.0083 • 42,824 = 1,088,710 lbs H2SO4/yr 

 SCR

 EMSCR = K • S2 • fs • E2 

 EMSCR = 3063 • 0.0075 • 0.43 • 42,824 = 423,023 lbs H2SO4/yr 

 Total

 TSAM = EMcomb + EMSCR

 TSAM = 1,088,710 + 423,023 lbs H2SO4/yr 

 TSAM = 1,511,733 lbs H2SO4/yr 

The 25,000 lbs/yr threshold has been exceeded; therefore, a release estimate must be made and 

the result reported on Form R. 

Released 

The total sulfuric acid released is based on the maximum value allowed by alkali injection, as 

measured in the stack, and the volume flow rate of combustion products processed. 

The concentration of SO3 measured at the stack can be converted to a mass emission rate, as 

described by Equation 4-15 

 ERALKINJ = Kalkali • B • SSO3 • Falkali • F2x

where, 

ERALKINJ = Total H2SO4 released from unit equipped with alkali injection, lbs per year 

Kalkali = Constant, equal to 3,799, with units of lbs H2SO4/(TBtu ppmv SO3) (SO3

measured at @ 6% O2 and 8.1% H2O) 

B = 27.05 TBtu/yr, for the specific case of Example 1 

SSO3 = SO3 content as measured in the stack or particulate collector exit, corrected to 

a concentration basis of ppmv at 6% O2, 8.1% moisture 

Falkali = fraction of operation with alkali addition to remove SO3. 

F2x = 1 (as the SO3 measurement is in the stack, there are no control technology 

components downstream of the measurement) 

The conversion factor Kalkali is equal to 3,799 (see Text Box C). This constant is derived for the 

case where flue gas SO3 is reported in terms of 6% oxygen and wet flue gas at 8.1% H2O. 

A-4
However, the SO3 concentration of 5 ppm in the stack is measured at slightly different conditions 

of excess O2 and moisture (6.6% oxygen and 8.8% moisture and therefore, a new value of Kalkali

must be calculated: 

Kalkali (O2, H2O ) = 3799 (6% O2, 8.1% H2O) • [(100-8.1)/(100-new H2O)] 

• [(20.9 – 6.0)/(20.9 – new O2)] 

Kalkali (O2, H2O ) = 3799 (6% O2, 8.1% H2O) • [(100-8.1)/(100-8.8)] 

• [(20.9 – 6.0)/(20.9 – 6.6)] 

Kalkali (6.6%, 8.8%) = 3799 • [1.0077)• [1.034] 

Kalkali (6.6%, 8.8%) =3958 

Total sulfuric acid release is then calculated as follows: 

 ERALKINJ = [3,958] • [27.05] •[5.0] • [1] • [1] 

ERALKINJ = 535,320 lbs/yr 

TSAR = ERALKINJ 

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 electrostatic precipitator, burns a PRB coal. The 

plant is equipped 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 SCR catalyst SO2 oxidation rate specified in 

the design is 2%, and the ammonia slip is estimated 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 SO2/yr 

 Combustion

 EMcomb = K • F1 • E2 

 EMcomb = 3063 • 0.0019 • 9,692 = 56,404 lbs H2SO4/yr 

 SCR

 EMSCR = K • S2 • fs • f3SCR • E2 

 EMSCR = 3063 • 0.020 • 0.43 • 0.17 • 9,692 = 43,402 lbs H2SO4/yr 

A-5
 Total

 TSAM = EMcomb + EMSCR

 TSAM = 56,404 + 43,402 lbs H2SO4/yr 

 TSAM = 99,806 lbs H2SO4/yr 

The 25,000 lbs/yr threshold has been exceeded; therefore, a release estimate must be made and 

the result reported on Form R. 

Released 

 Combustion

 ERComb = K • F1 • F2 • E2 

 ERComb = 3063 • 0.0019 • (0.36 • 0.72) • 9,692 = 14,620 lbs H2SO4/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/1012 Btu 

 B =23.54 TBtu/yr 

 ERSCR = [EMSCR – (Ks • B • fs • SNH3)] • F2 • F2 

 ERSCR = [43,402 – (3799 • 23.54 • 0.43 • 0.75)] • 0.36 • 0.72 

 ERSCR = 3,774 lbs H2SO4/yr 

 Total

 TSAR = ERcomb + ERSCR

 TSAR = 14,620 + 3,774 lbs H2SO4/yr 

 TSAR = 18,394 lbs H2SO4/yr 

Example 5: FGC Added to Example 1 

A 500 MW PC boiler, equipped with a cold-side electrostatic precipitator, burns an Eastern 

bituminous coal. The plant is equipped with a FGC process that injects both SO3 and NH3, with 

the SO3 injected upstream of the air preheater. The SO3 is injected at 7 ppmv at 6% O2 wet, and 

the ammonia at 3 ppmv also at 6% O2 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 Btu/lb. 

A-6
Solution 

 Manufactured 

 E2 = K1 • K2 • C1 • S1 

 E2 = 0.02 • 0.95 • 1,126,938 • 2.0 = 42,824 tons SO2/yr 

 Combustion

 EMComb = K • F1 • E2 

 F1eastbit = 1.1163E-6 • SO2 + 0.0064877 

 ppm1667 000,12

602,003,10 0.2

HV

K 1S2SO 1F •=•= =

 F1eastbit = 1.1163E-6 • 1667 + 0.0064877 = 0.0083 

 EMComb = 3063 • 0.0083 • 42,824 = 1,088,710 lbs H2SO4/yr 

 FGC

 B = 1,126,938 tons/yr • 2000 lbs/ton • 12000 Btu/lb • 1 TBtu/1012 Btu 

 B = 27.05 TBtu/yr 

 EMFGC = Ke • B • fe • Is

 EMFGC = 3799 • 27.05 • 0.9 • 7 = 647,407 lbs H2SO4/yr 

 Total

 TSAM = EMComb + EMFGC

 TSAM = 1,088,710 + 647,407 lbs H2SO4/yr 

 TSAM = 1,736,117 lbs H2SO4/yr 

The 25,000 lbs/yr threshold has been exceeded; therefore, a release estimate must be made and 

the result reported on Form R. 

Released 

 Combustion

 ERComb = K • F1 • F2 • E2 

 ERComb = 3063 • 0.0083 • (0.50 • 0.63) • 42,824 = 342,943 lbs H2SO4/yr 

 Where F2 = Air Heater • Cold-Side ESP 

 F2 = 0.50 • 0.63 = 0.315 

A-7
 FGC

 B = 1,126,938 tons/yr • 2000 lbs/ton • 12000 Btu/lb • 1 TBtu/1012 Btu 

 B = 27.05 TBtu/yr 

 ERFGC = [EMFGC – (Ke • B • fe • INH3)] • F3 • F2 

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

 ERFGC = 92,487 lbs H2SO4/yr 

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

 Total

 ESAR = ERComb + ERFGC

 ESAR = 342,943 + 92,487 lbs H2SO4/yr 

 ESAR = 435,430 lbs H2SO4/yr 

Example 6: SCR and FGC Added to Example 1 

A 500 MW PC boiler, equipped with a cold-side electrostatic precipitator, 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 occurred with the SCR operating. The SCR catalyst 

SO2 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 SO3 and NH3, with the 

SO3 injected upstream of the air preheater. The SO3 is injected at 7 ppmv at 6% O2 wet, and the 

ammonia at 3 ppmv also at 6% O2 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 Btu/lb. 

Solution 

From previous examples: 

Manufactured 

 Total 

 TSAM = EMComb + EMSCR + EMFGC

 TSAM= 1,088,711 + 423,023 + 647,407 lbs H2SO4/yr 

 TSAM = 2,159,141 lbs H2SO4/yr 

The 25,000 lbs/yr threshold has been exceeded; therefore, a release estimate must be made and 

the result reported on Form R. 

Released 

A-8
 Combustion

 ERComb = K • F1 • F2 • E2 

 ERComb = 3063 • 0.0083 • (0.50 • 0.63) • 42,824 = 342,943 lbs H2SO4/yr 

 SCR

 ERSCR = [EMSCR – (Ks • B • fs • SNH3)] • F2 • F2 

 ERSCR = [423,023 – (3799 • 27.05 • 0.43 • 0.75)] • 0.50 • 0.63 

 ERSCR = 122,812 lbs H2SO4/yr 

 FGC

 ERFGC = [EMFGC – (KE • B • fE • INH3)] • F3 • F2 

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

 ERFGC = 92,487 lbs H2SO4/yr 

 Total

 TSAR = ERComb + ERSCR + ERFGC

 TSAR = 342,943 + 122,812 + 92,487 lbs H2SO4/yr 

 TSAR = 558,242 lbs H2SO4/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 precipitator, burns an Eastern 

bituminous coal as the main fuel. The plant is equipped 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 plant is also equipped with a FGC process that 

injects both SO3 and NH3, with the SO3 injected upstream of the air preheater. The SO3 is 

injected at 7 ppmv at 6% O2 wet, and the ammonia at 3 ppmv also at 6% O2 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 Btu/lb. Natural gas is used as 

a startup fuel, with 0.5 TBtu per year. During startup, neither the SCR nor the FGC system is 

used. Used oil is also burned, with 483.2 tons burned (0.0185 TBtu/yr) in the year. Since the 

used oil is burned when the unit is at full load, it is 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

Manufactured from coal, from previous examples 

A-9
 Total

 TSAM = EMComb + EMSCR + EMFGC

 TSAM= 1,088,711 + 423,023 + 647,407 lbs H2SO4/yr 

 TSAM = 2,159,141 lbs H2SO4/yr 

Released from coal, from previous examples 

 Total

 TSAR = ERComb + ERSCR + ERFGC

 TSAR = 342,943 + 122,812 + 92,487 lbs H2SO4/yr 

 TSAR = 558,242 lbs H2SO4/yr 

Natural gas fuel calculations

Manufactured from natural gas 

 Combustion

 E2NG = Kb • BB

NG • S 

 E2NG = 0.0001359 • 0.5 TBtu/yr • 2000 gr/106 scf 

 E2NG = 0.136 tons SO2/year 

 EMComb = K • F1 • E2NG 

 EMComb = 3063 • 0.01 • 0.136 

 EMComb = 4.16 lbs H2SO4 manufactured 

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

Released from natural gas 

 Combustion

 ERComb = K • F1 • F2 • E2NG 

 ERComb = 3063 • 0.01• 0.50 • 0.63 • 0.136 

 ERComb = 1.31 lbs H2SO4 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-10
 Combustion

 E2 = K1 • K2 • C1 • S1 

 E2 = 0.02 • 1.0 • 483.2 • 0.1 

 E2 = 0.966 tons SO2/year 

 EMComb = K • F1 • E2 

 EMComb = 3063 • 0.0175 • 0.966 

 EMComb = 51.8 lbs H2SO4 manufactured 

 SCR

 EMSCR = K • S2 • fs • E2 

 EMSCR = 3063 • 0.0075 • 1.0 • 0.966 

 EMSCR = 22.2 lbs H2SO4 manufactured 

 FGC

 EMFGC = Ke • B • fe • Is

 EMFGC = 3799 • 0.0185 • 1.0 • 7.0 

 EMFGC = 492 lbs H2SO4 manufactured 

 Total

 TSAM = EMComb + EMSCR + EMFGC

 TSAM = 51.8 + 22.2 + 492 lbs H2SO4/yr 

 TSAM = 566 lbs H2SO4/yr 

Released from used oil 

 Combustion

 ERComb = K • F1 • F2 • E2 

 ERComb = 3063 • 0.0175 • 0.50 • 0.63 • 0.966 

 ERComb = 16.3 lbs H2SO4 released 

SCR

 ERSCR = [EMSCR – (Ks • B • fs • SNH3)] • F2 • F2 

 ERSCR = [22.2 – (3799 • 0.0185 • 1.0 • 0.75)] • 0.50 • 0.63 

 ERSCR = -9.6 lbs H2SO4/yr 

A-11
 F2 is taken to be equal to 0.50 for the air heater and 0.63 for the ESP. 

 FGC

 ERFGC = [EMFGC – (Ke • B • fe • INH3)] • F3 • F2 

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

 ERFGC = 70.3 lbs H2SO4/yr 

 Total

 TSAR = ERComb + ERSCR + ERFGC

 TSAR = 16.3 – 9.6 + 70.3 lbs H2SO4/yr 

 TSAR= 77 lbs H2SO4/yr 

Grand totals for all fuels

Manufactured 

 TSAM = TSAMcoal + TSAMNG + TSAMoil

 TSAM = 2,159,141 + 4.16 + 566 lbs H2SO4/yr 

 TSAM = 2,159,211 lbs H2SO4/yr 

Released 

 TSAR = TSARcoal + TSARNG + TSARoil

 TSAR = 558,242 + 1.31 + 77 lbs H2SO4/yr 

 TSAR = 558,320 lbs H2SO4/yr 

Example 8: Natural Gas Combined Cycle Plant 

A natural gas-fired combined-cycle unit uses 12.3 TBtu of natural gas, with the standard sulfur 

content. 

Solution 

 Manufactured 

 E2NG = Kb • BB

NG • S = 0.0001359 • 12.3 • 2000 = 3.343 tons SO2/yr 

EMCC = K • F1 • E2NG = 3063 • 0.0555 • 3.343 = 568 lbs H2SO4 manufactured 

Released 

 ERCC = K • F1 • F2 • E2NG = 3063 • 0.0555 • 0.5 • 3.343 = 284.5 lbs H2SO4 released 

(F2 = 0.5 because of the low temperature of the back-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 eastern bituminous coals into a 

single category with a linear curve fit. F1 factor based on fuel 

SO2 content calculated from fuel sulfur content: 

 F1ebit = 1.1163E-6 • SO2 + 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 for 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 alkali injection conversion factor, 

Kalkali

Report Organization Moved F2 Factors 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 estimate a stack release using a measured or 

specified stack gas SO3 concentration, to support estimates on 

units with alkali injection. 

Errata page published to correct error in alkali injection 

conversion factor, Kalkali

B-1
Combustion Turbines Clarified procedures for estimating emissions from simple and 

combined cycle CTs. 

Blended Coals New method calculates SO3 manufacture by calculating the SO3

emission rate separately for each of the component coals, and 

proportioning the contribution of SO3 from each. The prior 

method assumed the SO3 production was the same as that of the 

major coal component. 

Examples Provided new example calculations 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 following 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 Added new F2 Factors: 

 Air Preheater, PRB fuel - 0.56 

 Cold-side ESP, PRB fuel – 0.73 

SCR Added a Technology Impact Factor for SCR, F3SCR

B-2

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1020636