Estimating Total Sulfuric Acid Emissions from 

Stationary Power Plants

1023790

EPRI Project Manager

N. Goodman

ELECTRIC POWER RESEARCH INSTITUTE

3420 Hillview Avenue, Palo Alto, California 94304-1338 ... PO Box 10412, Palo Alto, California 94303-0813 ... USA

800.313.3774 ... 650.855.2121 ... askepri@epri.com ... www.epri.com

Estimating Total Sulfuric Acid Emissions from 

Stationary Power Plants

1023790

Technical Update, March 2012
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Fossil Energy Research Corporation

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Estimating Total Sulfuric Acid Emissions from Stationary Power Plants. EPRI, Palo Alto, CA:

2012. 1023790.

iii

ACKNOWLEDGMENTS

The following organization, under contract to the Electric Power Research Institute (EPRI), 

prepared this report:

Fossil Energy Research Corporation

23342C South Pointe

Laguna Hills, Ca 92653

Principal Investigator

J. Muncy

This report describes research sponsored by EPRI.

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.

v

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

vii

EXECUTIVE SUMMARY

The U. S. Environmental Protection Agency’s (EPA’s) Toxics Release Inventory (TRI) program 

requires electric utilities to estimate and report annual emissions of 682 chemicals and chemical 

categories. 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 

originally by Southern Company Services (SCS). The SCS model was 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 model 

to include additional data and improvements, and to publish this method under EPRI 

sponsorship. EPRI has continued to maintain and improve the methodology, and publishes 

updates on an as-needed basis. The current report provides clarifications and minor corrections to 

the previous (2010) version, adds several new technology factors, and incorporates additional 

sulfuric acid removal measurements. A chronology of changes to the EPRI/SCS model since 

2007 is provided in an appendix to this report.

The method for estimating sulfuric acid emissions considers 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. These sources are then summed and ammonia 

slip from SCR, selective noncatalytic reduction (SNCR), or FGC is subtracted from the total SO3

to account for ammonium bisulfate (ABS) formation, which is not reportable. Removal through 

control devices is then accounted for through the use of Technology Factors (F2) which describe 

SO3 removals across downstream devices such as the air preheater (APH), electrostatic 

precipitator (ESP), baghouse or other particulate control devices. In previous versions of this 

model, these sources were treated independently and each source was adjusted to account for 

removal processes; however, this approach sometimes produced negative SO3 releases for the 

individual SO3 sources, due to reactions with ammonia slip from SCR/SNCR that were estimated 

to remove more SO3 than was manufactured. Therefore, the current method first sums the 

sources and then applies the removal processes in a manner that is more consistent with the 

actual flue gas flow through the plants’ control devices. This version of the report changes the 

approach to estimating releases when FGC is employed. It also introduces new guidelines for 

SO3 mitigation from sorbent injection, a combined cycle carbon monoxide (CO) catalyst 

oxidation factor, and a wet ESP technology impact factor. 

The SCS/EPRI estimation method is an empirical model, i.e., emissions are predicted from 

sulfuric acid measurements at full-scale power plants. Data are obtained from field tests that 

measured production of SO3 from fuel sulfur in various types of combustion equipment, as well 

as the removal of SO3 or H2SO4 from the flue gas stream by air heaters, particulate control 

devices such as electrostatic precipitators (ESPs) and fabric filters, and sulfur dioxide control 

equipment. The removal data are used to develop “technology factors” that represent the amount 
viii

of sulfuric acid that passes through and is not captured by each pollution control device. The 

technology factors are used to estimate the amount of sulfuric acid aerosol released to the air. 

The 2012 database of measurements of SO3 emissions from combustion systems includes data 

from 64 sources, an increase of 14 from the previous version. As mentioned, data are obtained 

from field tests, and new sources are defined as a new series of test data from a plant during a 

defined time period. The new data were used to improve estimates for changes in sulfuric acid 

emissions due to SO3 mitigation, CO catalyst oxidation and use of a wet ESP. 

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 generally be used in place of the estimates derived with this method.
ix

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

Description of General Methodology ..................................................................................3-1

Sulfuric Acid Manufacture from Combustion.................................................................3-2

SCR/SNCR NOx Control ..............................................................................................3-3

Flue Gas Conditioning ..................................................................................................3-4

Methodology to Estimate Release......................................................................................3-4

SCR/SNCR NOx Control ..............................................................................................3-5

Flue Gas Conditioning ..................................................................................................3-7

Estimating Release with Alkali Injection........................................................................3-8

4 ESTIMATING GUIDELINE: STEAM BOILERS ....................................................................4-1

Sulfuric Acid Manufacture...................................................................................................4-1

Sulfuric Acid Manufactured by Combustion (EMComb) ....................................................4-1

Sulfuric Acid Manufactured from SCR (EMSCR) .............................................................4-7

Sulfuric Acid Manufactured from FGC (EMFGC) .............................................................4-8

Total Manufacture from All Sources............................................................................4-11

Sulfuric Acid Release .......................................................................................................4-11

Ammonia Slip from SCR and SNCR (NH3SCR)............................................................4-12

Ammonia Injection from FGC (NH3FGC).......................................................................4-14

Total Release Calculation for Sources Employing Alkali Injection...............................4-14

Technology Impact Factors (F2).......................................................................................4-16

Air Heater...................................................................................................................4-16

Particulate and SO3 Control Processes ......................................................................4-19

FGD ...........................................................................................................................4-21

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

6 ESTIMATING GUIDELINE: COMBUSTION TURBINES ......................................................6-1

Manufacture and Release for Simple Cycle Units...............................................................6-1

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

Sulfuric Acid Manufactured...........................................................................................6-4

7 REFERENCES .....................................................................................................................7-1

A EXAMPLE CALCULATIONS..............................................................................................A-1
x 

Example 1: Conventional Coal-Fired Boiler with an ESP...................................................A- 1

Solution .......................................................................................................................A- 1

Example 2: SCR Added to Example 1...............................................................................A- 2

Solution .......................................................................................................................A- 2

Example 3: Alkali Injection Added to Example 1................................................................ A-4

Solution ....................................................................................................................... A-4

Example 4: 500 MW PRB-fired Boiler with ESP, SCR....................................................... A-6

Solution ....................................................................................................................... A-6

Example 5: FGC Added to Example 1............................................................................... A-8

Solution ....................................................................................................................... A-8

Example 6: SCR and FGC Added to Example 1.............................................................. A-10

Solution ..................................................................................................................... A-10

Example 7: SCR and Downstream FGC Added to Example 1......................................... A-11

Solution ..................................................................................................................... A-11

Example 8: Coal-Fired Boiler with FGC, NG Startup Fuel, and Used Oil Co-Firing.......... A-12

Solution ..................................................................................................................... A-12

Example 9: Natural Gas Combined Cycle Plant .............................................................. A-15

Solution ..................................................................................................................... A-15

Example 10: SCR and CO catalyst added to Example 9 ................................................. A-16

Solution ..................................................................................................................... A-16

B CHRONOLOGY OF CHANGES TO EPRI SULFURIC ACID ESTIMATION MODEL .......... B-1
xi

LIST OF FIGURES

Figure 3-1 Schematic of Methodology Used to Estimate Sulfuric Acid Releases..................... 3-6

Figure 4-1 Relationship between Boiler SO3 Production and Flue Gas SO2 (corrected to 3% 

O2).......................................................................................................................................... 4-4

Figure 4-2 Removal of Sulfuric Acid by Ljungstrom-Type Air Heaters ................................... 4-18

Figure 4-3 Removal of Sulfuric Acid by Cold-Side ESPs and One Hot-Side ESP.................. 4-20

Figure 4-4 Removal of Sulfuric Acid by Flue Gas Desulfurization Equipment: Various FGD 

Designs, Coals...................................................................................................................... 4-22

xiii

LIST OF TABLES

Table 4-1 Summary of Fuel Impact (F1) Factors for Steam Generating Units ......................... 4-6

Table 4-2 F3SCR Technology Impact Factors for SCR.............................................................. 4-8

Table 4-3 Summary of F2 Factors for Air Heater Removal of Sulfuric Acid ........................... 4-18

Table 4-4 Summary of F2 Factors for Particulate Control Devices (ESP, Baghouse)............ 4-20

Table 4-5 Summary of F2 Factors for Wet and Dry FGD Equipment and Additives............... 4-22

Table 6-1 Fuel Impact (F1) Factors for a Simple CT............................................................... 6-3

1-1

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 Toxics 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. 

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 aerosol 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 was 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 

version of the model added the ability to estimate emissions based on a specified sulfuric acid 
1-2 

flue gas concentration at the stack, which can be used when alkali injection is employed to 

reduce sulfuric acid emissions. The 2010 version updated several of the “technology factors” (F2 

factors, used to reflect the impact of pollution control devices) with new SO3 measurements. 

The current version of the model makes minor changes to the calculation procedure to more 

accurately represent flow through from the boiler and control devices. This version also changes 

the approach used to account for sulfuric acid from flue gas conditioning (FGC). Finally, the 

revision makes several corrections and clarifications to technology factors, introduces a new 

technology factor for units with a wet electrostatic precipitator (ESP), and adds a new sulfuric 

acid source: oxidation of sulfur dioxide across a carbon monoxide catalyst in combined cycle 

units. 

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 sulfuric acid model is presented in Appendix B. 
2-1

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 the 1990s. 

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 

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

bias downstream of the particulate control device. 
2-2

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.
3-1

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. 

Description of General Methodology

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 Total Sulfuric Acid Manufacture (TSAM) of SO3, the precursor to sulfuric acid, is 

calculated in this model as shown in Equation 3-1. 

TSAM = EMComb + EMSCR + EMFGC Equation 3-1

where,

TSAM = Total manufacture of sulfuric acid 

EMComb = Manufacture of sulfuric acid through combustion

EMSCR = Manufacture of sulfuric acid from SCR

EMFGC = Manufacture of sulfuric acid from FGC
3-2

The Total Sulfuric Acid Release (TSAR) from a combustion unit equipped with SCR or selective 

noncatalytic reduction (SNCR) NOx control and FGC is represented in a simplified form in 

Equation 3-2, and explained in further detail in Section 4.

TSAR = {[(EMComb + EMSCR/SNCR + EMFGC_before APH) – NH3Slip] • F2APH + 

(EMFGC_afterAPH – NH3Slip) } • F2x Equation 3-2

where,

TSAR = Total sulfuric acid released

EMComb = Sulfuric acid manufactured through combustion

EMSCR/SNCR = Sulfuric acid manufactured from SCR or SNCR

EMFGC_beforeAPH = Sulfuric acid manufactured from FGC injected upstream of the air 

preheater (APH)

EMFGC_afterAPH = Sulfuric acid manufactured from FGC injected downstream of the APH

NH3Slip = Calculated ammonia slip that reacts with H2SO4 to form ammonium 

bisulfate (ABS) from SCR/SNCR and/or FGC

F2APH = Technology Impact Factor for APH

F2x = Technology Impact Factors, all that apply (downstream of APH)

Sulfuric Acid Manufacture from Combustion

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:

EMComb = K • F1 • E2 Equation 3-3

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.
3-3

SCR/SNCR NOx Control

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.

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:

EMSCR = K • S2 • fsops • E2 • F3SCR Equation 3-4

Where K is a constant, S2 is the catalyst SO2 oxidation rate, fsops is the fraction of the coal burn 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 
3-4

details of this relationship and the derivation of constants and other terms are presented in 

Section 4.

Flue Gas Conditioning

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 

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 3-5 estimates the manufacture of sulfuric acid from FGC, where Ke is a constant, B is 

the coal burn, fe is the FGC operating factor, and Is is the SO3 injection rate. F3FGC is the 

Technology Impact Factor for FGC, and has been added to the manufacture equation in the 

current version of the model, to adjust for the presence of alkaline fly ash in PRB coals. It should 

be noted that the F3FGC factor has been updated to new values, and in the current version is now 

applied to the manufacture equation, whereas in previous versions of the model it was applied to 

the release equations. Further details and derivation of the constant are provided in Section 4. 

EMFGC = Ke • B • fe • Is • F3FGC Equation 3-5

Methodology to Estimate Release

Sources of sulfuric acid manufactured upstream of the air preheater are calculated separately, 

then summed. The combined SO3 is modified to reflect reactions of SO3 with residual NH3 slip 

from SCR/SNCR equipment and/or FGC ammonia injection, and then adjusted by removal in 

applicable downstream equipment such as the air preheater, electrostatic precipitator or other 

particulate control device (PCD) and flue gas desulfurization (FGD) equipment. The adjustments 

are made through the use of Technology Impact Factors (F2) which describe the fraction of 

sulfuric acid that penetrates each component. 

The methodology employs the follow steps, combined into a single release equation, which is 

shown in Equation 3-6, and illustrated schematically in Figure 3-1:

1. Sum the sources of sulfuric acid upstream of the APH from combustion, SCR and FGC 

2. Calculate residual ammonia slip from the SCR/SNCR and FGC and subtract this 

ammonia from the sum of the sources upstream of the APH to account for ABS 

formation which is not reportable

3. If the result of Steps 1) and 2) is a positive value, apply the technology factor for APH 

removal of SO3

4. Add downstream sources of sulfuric acid (from FGC, if injected downstream), and 

subtract downstream ammonia injection (from FGC if injected downstream) to account 

for ABS, which is not reportable

5. Apply all relevant downstream technology factors 
3-5

In equation form, the methodology is expressed as shown in Equation 3-6.

TSAR = {[(EMComb + EMSCR/SNCR + EMFGC_beforeAPH ) – (NH3SCR + NH3FGC_beforeAPH)] •

F2APH + (EMFGC_afterAPH – NH3FGC_afterAPH)} • F2x Equation 3-6

This approach is a change from the 2010 Sulfuric Acid Emissions model, which applied the 

Technology Factors independently to each source of sulfuric acid manufacture, then summed the 

calculated SO3 releases to obtain the total release for the unit. The former approach sometimes 

produced negative SO3 releases for the individual SO3 sources, due to reactions with ammonia 

slip from SCR/SNCR that were estimated to remove more SO3 than was manufactured. 

SCR/SNCR NOx Control

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 

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.
3-6

Figure 3-1

Schematic of Methodology Used to Estimate Sulfuric Acid Releases
3-7

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 sulfuric acid, the 

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

A 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 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 reaction is 

important when estimating ammonia releases.

The total sulfuric acid released is reduced by the residual ammonia, or ammonia slip, from SCR 

or SNCR. This ammonia slip is calculated as follows, and is added to any ammonia injection 

from FGC before it is subtracted from the sum of the sulfuric acid manufactured.

NH3SCR = Ks • B • fsreagent • SNH3 Equation 3-7

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

reagent injection, and SNH3 is the NH3 slip for the SCR/SCNR. This calculation and factors are 

described further in Section 4.

Flue Gas Conditioning

Flue gas conditioning may involve injection of NH3 alone or NH3 with SO3. Thus, FGC can result 

in sulfuric acid manufacture or may result in sulfuric acid removal, if NH3 is injected alone or in 

quantities greater than the sulfuric acid. The following equation describes the calculation of 

ammonia that is used to reduce sulfuric acid. If ammonia is injected upstream of the APH, this 

value would be added to the residual ammonia from SCR/SNCR. If added downstream of the 

APH, the value would be subtracted from any downstream SO3 injection introduced by FGC.
3-8

NH3FGC = Ke • B • fe • INH3 Equation 3-8

Where Ke is a constant, B is the coal burn in TBtu/yr, fe is the fraction of coal burn with FGC 

operation, and INH3 is the NH3 injected. This calculation and factors are described further in 

Section 4.

Estimating Release with 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 SBS usage 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.

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 generally have conducted field tests to determine the 

SO3 concentration in flue gas for a specified sorbent injection rate. In most cases, these 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. 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 

procedure is provided in Appendix A. 

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

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. 
3-9

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

(EPA 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 (CCS). Although no general-purpose, EPA-approved CCS method is 

currently available, it is widely used by stack test contractors for sulfuric acid measurement and 

is more accurate than Method 8, if performed correctly. 

Some units will not have measured stack emissions. This version of the model adds an alternate 

approach to estimate releases with alkali injection if stack SO3 measurements are not available.

Instead of using Equation 3-9 for ERALKINJ, the total sulfuric acid release is calculated by 

estimating total releases using Equation 3-6. An alkali injection factor, F3ALKINJ, is then applied to 

the total release as shown in Equation 3-10. This F3ALKINJ is either the expected fractional 

reduction in SO3 (generally as guaranteed by the vendor) or a default of 0.2. The basis of the 0.2 

value is test results indicating that 80% removal is easily achievable (EPRI, 2010b). This method 

is explained in further detail in Section 4.

TSARALKINJ = (TSARComb+SCR+FGC) • F3ALKINJ Equation 3-10

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.

4-1

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) 

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.

Sulfuric Acid Manufacture 

Sulfuric Acid Manufactured by Combustion (EMComb)

The premise of the methodology is that the amount of sulfuric acid manufactured by the boiler is 

a function of the amount of SO2 produced – which may be 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 

estimate emissions either from coal data or from the output of a CEMS positioned ahead of the 

scrubber. As described below, it may be necessary to correct SO2 CEMS data for non-ideal stack 

flow conditions.

The following relationship is used to estimate the sulfuric acid manufactured from combustion in 

utility sources:

EMComb = K • F1 • E2 Equation 4-1

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

2000 = Conversion from tons per year to pounds per year.

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.

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.
4-2

• 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. The user should check with their 

CEMS operator, as the bias corrections may already be taken care of in the instrument software. 

If CEMS SO2 data are used, the factor E2 is defined by the following equation:

( )





 



 • + • + = − 100

1 2 3 2 1

2 C R C R C E E Equation 4-2

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 4-2, 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 March, 

2012, but some facilities may be allowed to apply this approach as a conditional test method.
4-3 

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:

E2 = K1 • K2 • C1 • S1 Equation 4-3 

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 

 100 = conversion of % S to a fraction 

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, because the measured SO2 has 

already been decreased by the control equipment, and therefore is not an accurate predictor of the 

SO3 emissions rate.

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 (wall-fired 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. 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. 
4-4 

The current model uses a linear relationship to estimate SO3 production for all eastern 

bituminous, dry bottom boiler data, as shown in Figure 4-1. The equation expressing this 

relationship is shown in Equation 4-4. 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. 

Figure 4-1 

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

F1ebit = 1.12E-6 • SO2 + 0.0065 Equation 4-4 

where,

F1ebit = Fuel Impact Factor for all Eastern Bituminous coals burned in a dry-bottom 

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 4-5 is used to calculate that relationship:

HV

K SSO F1

2 1•= Equation 4-5 

Eastern Bituminous

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

R2 = 1.3004E-01

0.000

0.005

0.010

0.015

0.020

0 1000 2000 3000 4000

Boiler SO3 Production, F1 Factor

Flue Gas SO2 Content

High S East Bit, Dry Bottom Boiler

Low S East Bit, Dry Bottom Boiler

PRB Dry Bottom Boiler

75% Lignite

100% Lignite

PRB Cyclone
4-5 

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. 

Table 4-1 summarizes the F1 factors. There are no changes to these factors from the previous 

version of the model (EPRI, 2010a). 

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.
4-6

Table 4-1

Summary of Fuel Impact (F1) Factors for Steam Generating Units

Fuel Equipment F1 Comment

E. Bituminous (all)1 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.

1

For eastern bituminous coal, a linear relationship between SO2 and SO3 is used instead of an 

average F1 factor. 
4-7

Sulfuric Acid Manufactured from SCR (EMSCR)

This section describes a method to estimate impacts of SCR on sulfuric acid 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. As such, only the SCR process will be 

addressed in this section. The removal equations will be discussed in subsequent sections, and 

will address both SCR and SCNR, as residual ammonia from either process contributes to 

sulfuric acid removal.

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

boiler or steam generator:

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

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

2000 = Conversion from tons per year to pounds per year.

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, S2, 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 
4-8

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 

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.

Table 4-2 shows the F3SCR factors. It should be noted that the 0.17 factor for PRB coals when 

using laboratory-scale SO2 conversion (S2) data without fly ash is based on 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. Additionally, if full-scale catalyst 

performance SO2 conversion data is used, the F3SCR factor is 1 for all coal types.

Table 4-2

F3SCR Technology Impact Factors for SCR

Coal Type F3SCR

Using Laboratory-Scale SO2 Conversion Data (S2), Without Fly Ash

PRB 0.17 (n = 2)

Other Coals 1 (no data available)

Using Full-Scale Catalyst Performance SO2 Conversion Data (S2)

All Coals 1

SNCR does not result in the manufacture of sulfuric acid; thus, EMSNCR for SNCR is by 

definition zero.

Sulfuric Acid Manufactured from FGC (EMFGC)

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:
4-9

EMFGC = Ke • B • fe • Is • F3FGC Equation 4-7

where,

EMFGC = Total H2SO4 manufactured from FGC, lbs per year, either upstream of APH ( 

EMFGC_beforeAPH) and/or downstream of APH (EMFGC_afterAPH)

Ke = Conversion factor = 3,799, see Text Box B.

B = Coal burn in TBtu/yr

fe = Operating factor of FGC system: 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

F3FGC = Technology Impact Factor for FGC

= 0.17 for PRB coal

= 1 for all other coals

A Technology Impact Factor for FGC (F3FGC) is used to adjust the flue gas SO3 manufacture 

from FGC injection to account for the presence of alkaline fly ash. The principle is the same as 

for the F3SCR factor, that is used to adjust the flue gas SO3 produced by SO2 oxidation rate on the 

SCR catalyst.

The current F3FGC factor is applied differently than in previous versions of the model. In the 

EPRI (2010) model and all earlier versions, the F3FGC factors were substituted for Technology 

Impact Factors (F2) for the APH and/or ESP when FGC was used. The old F3FGC factors were 

used to account for both SO3 reductions from adsorption to alkaline fly ash and differential 

behavior when FGC was injected before and after the APH. However, this approach led different 

estimated sulfuric acid releases depending on the source of the SO3 (e.g., from combustion or 

FGC). Additionally, as new test measurements were added to the database and used to update the 

F2 factors, the historical F3FGC factors became obsolete, as they were based on theoretical 

understanding of SO3 behavior rather than empirical data.

The new method first reduces the SO3 that is injected into a PRB-fired boiler using a new F3FGC

factor to account for sorption by the alkaline fly ash. Subsequently, SO3 from FGC is treated the 

same as all other sources of sulfuric acid with respect to ABS formation or reduction through 

control devices. The new F3FGC factor (0.17) is assumed to be equal to the F3SCR factor. A F3SCR

of 1.0 is used for eastern bituminous coals (zero reduction), as those coals produce an acidic ash 

that does not adsorb appreciable amounts of SO3.
4-10

The conversion factor Ke, equal to 3,799, 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 SO3

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

Equation 4-7 specifies the concentration of SO3 in flue gas (IS) in terms of ppmv at 6% O2, wet 

flue gas basis. If the concentration of SO3 is reported at different conditions, the value of the 

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

Ke (O2, H2O ) = 3,799 (6% O2, 8.1% H2O) • [(100-8.1)/(100-new H2O)] 

• [(20.9 – 6.0)/(20.9 – new O2)] Equation 4-8 

For example, if the SO3 concentration is quantified at a value (in ppm) that is defined at 0% 

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

Ke (O2, H2O) = 3,799 (6% O2, 8.1% H2O) • [(100-8.1)/(100-0)] • [(20.9 – 6.0)/(20.9 – 0)]

Ke = 2,489

The sulfuric acid manufacture from FGC should be noted as either upstream of the APH, 

EMFGC_beforeAPH, or downstream of the APH, EMFGC_afterAPH. These values must be kept separate for 

the release equations.

FGC equipment that employs NH3 injection alone does not manufacture sulfuric acid and 

therefore this amount, EMFGC, would be zero. However, the injected NH3 will reduce the total 

Text Box B: Derivation of Conversion Factor, Ke. 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 20°C 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 0°C and 760 mm Hg. Converting this to the English 

units standard of 20°C (68°F), one pound mole occupies 385 standard cubic feet. Using these in the equation 

above,

(Ke • B • fe • IS) = lbs H2SO4 per yr =

B TBtu IS(SNH3) scf 

NH3

1 lb mol SO3 1 lb mol H2SO4 98 lbs H2SO4 14925 scf fg 106 MBtu

year 106 scf flue gas 385 scf SO3 1 lb mol NH3 1 lb mol H2SO4 1 MBtu TBtu

Grouping terms,

= B • fe • IS • 3,799

Therefore, the value of Ke is equal to 3,799 lbs H2SO4/(TBtu • ppmv SO3 @ 6% O2 and wet).
4-11

release of sulfuric acid by reacting with SO3 or the resultant H2SO4, and therefore should be used 

in the release equation, as discussed in subsequent sections. 

Total Manufacture from All Sources

The total manufacture of sulfuric acid is the sum of the individual manufacture 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 summed to determine the total amount. 

Accordingly, total sulfuric acid manufacture (TSAM) is estimated for a generating unit equipped 

with SCR and flue gas conditioning by the following equation: 

Total Sulfuric Acid Manufacture (TSAM) is described by the following equation: 

TSAM = EMComb + EMSCR + (EMFGC_beforeAPH + EMFGC_afterAPH) Equation 4-9 

Sulfuric Acid Release

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. Therefore, sources of ammonia are 

calculated and summed in relation to the APH, and used to adjust the sulfuric acid manufactured. 

Once adjusted by ammonia, the remaining sulfuric acid is then adjusted by the removals in 

applicable downstream equipment such as the APH, ESP or other particulate control device and 

FGD equipment through the use of Technology Impact Factors (F2) which describe the fraction 

of sulfuric acid that penetrates each component. 

Total Sulfuric Acid Release (TSAR) is described by the following equation: 

TSAR = {[(EMComb + EMSCR + EMFGC_beforeAPH ) – (NH3SCR + NH3FGC_beforeAPH)] • 

F2APH + (EMFGC_afterAPH – NH3FGC_afterAPH)} • F2x Equation 4-10

where,

TSAR = Total Sulfuric Acid Release, lbs per year

EMComb = Total sulfuric acid manufactured from combusted, lbs per year 

EMSCR = Total sulfuric acid manufactured from SCR, lbs per year 

EMFGC_beforeAPH = Total sulfuric acid manufactured from FGC upstream of the APH 

EMFGC_afterAPH = Total sulfuric acid manufactured from FGC downstream of the APH 

NH3SCR = Total ammonia slip produced from SCR/SNCR, lbs per year 

NH3FGC_beforeAPH = Total ammonia produced from FGC upstream of the APH, lbs per 

year

NH3FGC_afterAPH = Total ammonia produced from FGC downstream of the APH, lbs per 

year
4-12

F2APH = Technology Impact Factor for APH, applied only if subtotal for 

releases upstream of the APH is non-negative 

F2x = Technology Impact Factors for processes downstream of the APH, 

all that apply

Examples in Appendix A detail the use of these calculations. Ammonia produced from 

SCR/SNCR and FGC are calculated using equations from the sections below. 

It should be noted that the F2 factor for the APH (F2APH) should only be applied if the subtotal of 

the sum of the sulfuric acid manufactured minus the ammonia slip upstream of the APH 

[(EMComb + EMSCR + EMFGC_beforeAPH ) – (NH3SCR + NH3FGC_beforeAPH)] is a positive value. If this 

subtotal is negative, this would indicate that excess ammonia slip is still present after all the 

sulfuric acid from combustion, SCR and FGC has been consumed to form ABS. In this instance, 

the resulting ammonia slip should not be reduced by the F2APH factor, as all the ammonia is 

expected to penetrate the APH. This negative ammonia slip value can then be added to any 

downstream FGC injection, as summarized in the equation below: 

TSARExcessNH3 = {[(EMComb + EMSCR + EMFGC_beforeAPH ) – (NH3SCR + NH3FGC_beforeAPH)] + 

(EMFGC_afterAPH – NH3FGC_afterAPH)} • F2x Equation 4-11

Text Box C summarizes calculations for a unit equipped with a FGD process that employs partial 

flue gas bypass, to 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. 

Ammonia Slip from SCR and SNCR (NH3SCR) 

A key assumption in the calculation methodology is that residual ammonia from either a SCR or 

SNCR captures all available sulfuric acid in the (ammonium) bisulfate form. The bisulfate form 

is not reportable under the Toxics Release Inventory rules and thus is not part of the manufacture 

calculation. If any additional ammonia reacts with bisulfate to form ammonium sulfate, that 

reaction is of no consequence to the sulfuric acid calculation – although it needs to be taken into 

account when estimating ammonia releases. 

Text Box C: 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 total 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.

Modified equations considering partial scrubber bypass are given below and should be used where 

appropriate.

TSARbypass = {[(EMComb + EMSCR/SNCR + EMFGC_beforeAPH ) – (NH3SCR + NH3FGC_beforeAPH)] • F2APH + 

(EMFGC_afterAPH – NH3FGC_afterAPH)} • F2x

TSAR = [SBf + (1 – SBf

) • F2s] • TSARbypass 

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

F2s = F2 for scrubber

F2x = All other applicable F2 factors except for scrubber.
4-13

The total sulfuric acid released from combustion, SCR, and FGC is determined by subtracting 

from the sulfuric acid manufactured the amount removed by the residual ammonia, or ammonia 

slip. For SCR/SNCR, the ammonia slip is calculated using the following:

NH3SCR = Ks • B • fsreagent • SNH3 Equation 4-12

where,

NH3SCR = Total ammonia slip produced from SCR/SNCR, lbs per year

Ks = Conversion factor = 3799, which is equivalent to Ke (See Text Box B)

B = Coal burn in TBtu/yr

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 

The conversion factor Ks, equal to 3,799, is equivalent to the factor Ke used for SO3 injected from 

FGC, and considers all relevant constants to yield the result in pounds per year of ammonia. The 

derivation of this constant, in the form of Ke, was presented previously in Text Box B.

Equation 4-12 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. As with Ke, Equation 4-8, described previously and repeated again 

below for reference, is used to adjust the value of the constant Ks:

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

• [(20.9 – 6.0)/(20.9 – new O2)] Equation 4-8

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:

B = C1 • HV • KB Equation 4-13

where,

B = Coal burn in TBtu/yr
4-14

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)

Ammonia Injection from FGC (NH3FGC)

Similar to reactions with ammonia slip from SCR or SNCR, any ammonia injected from FGC 

will react with sulfuric acid manufactured to form ABS. The following equation is used to 

calculate ammonia from FGC. Care must be taken to note the location of the ammonia injection, 

upstream or downstream of the APH, such that the ammonia can be utilized correctly in the 

release equation.

NH3FGC = Ke • B • fe • INH3 Equation 4-14

where,

NH3FGC = Ammonia produced from FGC, lbs per year, either upstream of APH, 

NH3FGD_beforeAPH, or downstream of APH, NH3FGC_afterAPH

Ke = Conversion factor = 3,799, as described in Text Box B

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.

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 typically 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.

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

where,

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

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

B.

B = Coal burn in TBtu/yr
4-15

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

6% O2, wet

Falkali = Operating factor for the alkali injection system, fraction of coal burn when

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. 

If the SO3 content (SSO3) is known at conditions other than 6% O2 and wet, Equation 4-8 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 4-5, 

below) should be selected.

If the utility employing alkali injection does not have access to measured data, the total sulfuric 

acid releases may be calculated as described by Equation 4-10 (i.e., by estimating and summing 

the manufacture and applying the technology Impact Factors), and an alkali injection factor, 

F3ALKINJ, is then applied to the total release. This F3ALKINJ is either the expected fractional 

reduction in SO3 (generally as guaranteed by the vendor), a default value of 0.2, as available data 

indicates 80% removal is easily achievable (EPRI, 2010b). 

ERALKINJ = (TSARComb+SCR+FGC) • Falkali F3ALKINJ Equation 4-16

where,

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

per year 

TSARComb+SCR+FGC = Total H2SO4 released from combustion, SCR and FGC, as 

calculated using Equation 4-10.

Falkali = Operating factor for the alkali injection system, fraction of coal 

burn when unit is operated with alkali addition to remove SO3

F3ALKINJ = Technology Impact Factor for alkali injection:; the expected 

fractional reduction in SO3 (generally as guaranteed by the 

vender). If no vendor information is available, use a default value 

of 0.2.
4-16

Partial Year Injection

If alkali injection is not utilized for the entire operating year (Falkali does not equal 1), then 

Equation 4-15 (or Equation 4-16) 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 (Equation 4-10). 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 instead of the standard estimation equations, as shown below:

ERNOINJ = Kalkali • B • SSO3 • F2x• (1-Falkali) Equation 4-17

where,

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

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

B.

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 = Operating factor for the alkali injection system, fraction of coal burn when 

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:

TSAR = ERALKINJ + (TSARComb+SCR+FGC) • (1-Falkali) Equation 4-18

TSAR = ERALKINJ + ERNOINJ Equation 4-19

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 
4-17

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.
4-18

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 4-4. Data are not currently available for other coal types. For those coals, as well as fuel 

oils, 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.

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

about one third of the average measurement. Inadequate data prevent calculating a standard 

deviation for F2 factors for the other fuels. 

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

0% 1.0

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0 500 1000 1500 2000 2500 3000 3500

Air Heater H

Air Heater F2 Factor

2SO4 Removal, %

Flue Gas SO2 Content, ppm

High S East Bit, Dry Bottom Boiler

Low S East Bit, Dry Bottom Boiler

Hamel Full-Scale Tests

PRB Dry Bottom Boiler

Series5
4-19

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 4-5. Data 

are not currently available for other coal types. 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. 

This guidance also applies to for fuel oils or any other coal that is not listed in the table.

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.

The current model adds a F2 factor of 0.12 for a wet ESP, as shown in Table 4-5. Wet ESP’s 

operate in much the same manner as a traditional ESP; however, due to the lower operating 

temperature and saturated environment, higher power levels are achievable, resulting in higher 

collection efficiency for sulfuric acid mists. The new F2 factor is based on two sets of paired 

measurements, both of which demonstrated 88% sulfuric acid removal across the wet ESP. One 

data point was from a high sulfur, eastern bituminous, coal-fired boiler and the other from a 

petroleum-coke fired boiler. Flue gas SO2 was not reported for these tests; therefore, the data 

points are not included in Figure 4-3. Until further data are available, EPRI recommends using a 

wet ESP F2 factor of 0.12 for all fuels.

Baghouses show high H2SO4 removal based on very limited data. The average of two data points 

is 90% removal.
4-20

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.

Wet ESP All 0.12* n/a Average of measurements at two units

Baghouse Subbituminous coal 0.10 n/a Two data points.

* Change in factor from EPRI, 2010a. n/a – not applicable – too few points to calculate.

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 

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. 

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

0% 1.0

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0 500 1000 1500 2000 2500 3000 3500

ESP F2 Factor

ESP Flue Gas H2SO4 Removal, %

Flue Gas SO2, ppm

High S East Bit

Low S East Bit

ESPh Low S EastBit

PRB Dry Bottom Boiler
4-21

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 utility-specific tests 

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 

14% 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 average reported by Srivastava (2004). 

Table 4-6 summarizes the F2 factors for FGD process equipment, including results for a wet 

spray tower burning bituminous coal, and also one burning a blend of PRB/lignite. Given the 

limited data, the latter is assumed to serve as the basis of an F2-factor for 100% firing of PRB or 

lignite. Data for a wet venturi -type combined 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 4-6. 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. Previous versions of the report had inadvertently 

changed the factor for injection into the furnace to a value of 0.5; thus, the current version 

corrects the value back to 0.25.
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 0.73* 0.13 Four data points from three units,

bituminous coal only; limited data 

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 0.25** n/a One data point.

* Changes from 2010 version due to new data

**Correction from previous versions (see text)
5-1

5

ESTIMATING GUIDELINE: MULTIPLE FUEL OR 

BLENDED FUEL BOILERS

Estimating sulfuric acid production of steam boilers firing multiple or blended fuels – such as 

natural gas, fuel oil, and perhaps coal – uses 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
5-2

e. FGC manufacture

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 8 in Appendix A details this calculation procedure.
6-1

6

ESTIMATING GUIDELINE: COMBUSTION TURBINES

Natural gas-fired sources typically have negligible content of sulfur in the fuel, thus sulfuric acid 

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

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

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

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

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

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

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

fuel. The EPA AP-42 emissions factor suggests a 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.

Manufacture and Release for 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 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:

EMSC = K • F1 • E2NG Equation 6-1

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

2,000 = Conversion from tons per year to pounds per year.

F1 = Fuel Impact Factor for NG
6-2 

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. 

E2NG = Kb • BNG • S Equation 6-2 

where,

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

Kb = Molecular weight and units conversion constant = 0.0001359 

BNG = 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 D. 

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

E2NG = KNG • N1 • S Equation 6-3 

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 E. 

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

Kb is determined from the following equation.

(Kb • BNG • S) = tons SO2 per yr =

BNG

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).
6-3 

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 

Fuel Impact (F1) Factors for a Simple CT

Stack T, °F F1

300 0.055

400 0.055

500 0.047

600 0.022

700 0.0055

750 0.0027

800 0.0013

850 0.00071

900 0.00039

950 0.00022

1000 0.00013

1050 0.00008

1100 0.00005

1150 0.00003

1200 0.00002

Text Box E: 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)
6-4 

Combined Cycle Units

Sulfuric Acid Manufactured

For combined cycle units, sources of manufacture of sulfuric acid are combustion, oxidation of 

SO2 across catalyst used for NOx control and recently, oxidation of SO2 across catalyst used for 

CO control. 

For combustion, the manufacture of sulfuric acid for combined-cycle units is described by 

Equation 6-4. 

EMCCcom = K • F1 • E2NG Equation 6-4 

where,

EMCCcom = 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; 

 2,000 = Conversion from tons per year to pounds per year. 

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. 

Recently, it has been shown that CO catalysts in combined cycle units can oxidize SO2 to SO3 in 

a manner similar to SCRs. Equation 6-5 describes the manufacture of sulfuric acid across the CO 

catalyst. For the case of combined cycle combustion turbines, the CO catalyst SO2 oxidation rate 

(S3) will be approximately 0.1. This value is an estimate based on data from a prominent catalyst 

vendor. A more accurate value can be obtained from field measurements of SO2 oxidation, or 

from the vendor’s specification of the CO catalyst. 

EMCC_CO = K • S3 • fCOops • E2 Equation 6-5 

where,

EMCC_CO = Total H2SO4 manufactured from the CO catalyst, 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

 2000 = Conversion from tons per year to pounds per year 
6-5

S3 = CO catalyst SO2 oxidation rate (specified as a decimal, typically from 

0.1-0.6)

fCOops = Operating factor of CO catalyst system, or the fraction of fuel burn when 

the flue gas is directed through the CO catalyst. This value should reflect 

the fraction of hours that the CO catalyst processed flue gas. This value 

will be site-specific but can be approximated as 0.8 for year-round 

peaking operation, 0.98 for year-round base-loaded operation, or 0.43 

for seasonal operation.

E2 = SO2 produced, tons per year

Equation 6-6 describes the manufacture of sulfuric acid in an SCR. The amount of sulfuric acid 

manufactured due to SO2 oxidation across the CO catalyst (EMCC_CO) must be subtracted from the 

total amount of SO2 produced (E2), because the CO catalyst will reduce the amount available for 

conversion by the SCR catalyst. 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.

EMCCSCR = [(K • E2) - EMCC-CO] • fsops • S2 • F3SCR Equation 6-6

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;

2,000 = Conversion from tons per year to pounds per year 

E2 = SO2 produced, tons per year

EMCC_CO = Total H2SO4 manufactured from the CO catalyst, lbs per year 

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 

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

F3SCR = Technology Impact Factor, for SCR (equal to 1.0, refer to Table 4-2)
6-6

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

equation below:

TSAMCC = EMCCcom + EMCC_CO + EMCCSCR Equation 6-7

Sulfuric Acid Released

The sulfuric acid released by all sources in combined cycle units is estimated as shown in 

Equation 6-8. This equation takes into account the reducing effect of ammonia slip from the SCR 

equipment in a similar method as described in Section 4.: 

TSARCC = [TSAMCC – (Ks • B • fsreagent • SNH3)] • F2cc Equation 6-8

where,

TSARCC = Total H2SO4 released, lbs per year 

TSAMCC = Total H2SO4 manufactured from all sources, lbs per year

Ks = Conversion factor = 3,799 (see Text Box B)

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. 

Examples 9 and 10 of Appendix A illustrates a gas-fired combined cycle plant calculation.
7-1

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. 
7-2

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

EPRI, 2010a

EPRI, 2010b

Estimating Total Sulfuric Acid Emissions from Stationary Power Plants, 

EPRI, Palo Alto, CA: 2008. 1016384. (revised April, 2009)

Estimating Total Sulfuric Acid Emissions from Stationary Power Plants, 

EPRI, Palo Alto, CA: 2010. 1020636.

Operation and Maintenance Guidelines for Selective Catalytic 

Reduction: 2010 Update. EPRI, Palo Alto, CA: 2010. 1019707.

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.

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

Sulfuric Acid Emissions from Stationary Power Plants: Revision 1,” 
7-3

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.

A-1 

A 

EXAMPLE CALCULATIONS

Example 1: Conventional Coal-Fired Boiler with an ESP 

A 500 MW pulverized coal-fired (PC) boiler, equipped with a cold-side 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 

ppm HV

K SSO F 1667

000,12

602,003,10 0.21 1

2 •=•= =

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

TSAR = EMComb • F2APH • F2ESP

TSAR = 1,088,710 • 0.50 • 0.63 = 342,944 lbs H2SO4/yr 
A-2

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 

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

ppm HV

K SO S F 1667

12,000

10,003,602 1 2.0 1

2 = • = • =

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

Coal Burn

B = C1 • HV • KB
A-3

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

B = 27.05 Tbtu/yr

Ammonia Slip

NH3SCR = Ks • B • fsreagent • SNH3

NH3SCR = 3799 • 27.05 • 0.43 • 0.75 = 33,141 lbs NH3/yr

Total Releases

TSAR = [(EMComb + EMSCR/SNCR ) – (NH3SCR)] • F2APH • F2ESP

TSAR = [(1,088,710 + 423,023) – (33,141)] • 0.50 • 0.63

TSAR = 465,756 lbs H2SO4/yr
A-4 

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 

ppm1667 000,12

602,003,10 0.2

HV

K SO 1S2 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. 
A-5

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 B). 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.

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
A-6 

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 = 56,405 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 

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

Coal Burn

B = C1 • HV • KB 

B = 1,384,552 tons/yr • 2000 lbs/ton • 8,500 Btu/lb • 1 Tbtu/1012 Btu

 B =23.54 Tbtu/yr 

Ammonia Slip

NH3SCR = Ks • B • fsreagent • SNH3

NH3SCR = 3799 • 23.54 • 0.43 • 0.75 = 28,841 lbs NH3/yr 
A-7

Total Releases

TSAR = [(EMComb + EMSCR/SNCR ) – (NH3SCR)] • F2APH • F2ESP

TSAR = [(56,404 + 43,402) – (28,841)] • 0.36 • 0.72

TSAR = 18,394 lbs H2SO4/yr
A-8

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

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

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

ppm HV

K SO S F 1667

12,000

10,003,602 1 2.0 1

2 = • = • =

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 • F3FGC

EMFGC = 3799 • 27.05 • 0.9 • 7 • 1 = 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.
A-9

Released

Coal Burn

B = C1 • HV • KB

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

B = 27.05 Tbtu/yr

FGC Ammonia Injection 

NH3FGC = Ke • B • fe • INH3

NH3FGC = 3799 • 27.05 • 0.9 • 3.0 = 277,460 lbs NH3/yr

Total Releases

TSAR = [(EMComb + EMFGC ) – (NH3FGC)] • F2APH • F2ESP

TSAR = [(1,088,710 + 647,407) – (277,460)] • 0.50 • 0.63

TSAR = 459,477 lbs H2SO4/yr
A-10

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 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

Manufactured

Total (from previous examples)

TSAM = EMComb + EMSCR + EMFGC

TSAM= 1,088,710 + 423,023 + 647,407 lbs H2SO4/yr

TSAM = 2,159,140 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

Total Releases (from previous examples)

TSAR = [(EMComb + EMSCR + EMFGC ) – (NH3SCR + NH3FGC)] • F2APH • F2ESP

TSAR = [(1,088,710 + 423,023 + 647,407) – (33,141 + 277,460)] • 0.50 • 0.63

TSAR = 582,290 lbs H2SO4/yr
A-11

Example 7: SCR and Downstream 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 downstream

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

Manufactured

Total (from previous examples)

TSAM = EMComb + EMSCR + EMFGC

TSAM= 1,088,710 + 423,023 + 647,407 lbs H2SO4/yr

TSAM = 2,159,140 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

Total Releases (from previous examples)

TSAR = {[(EMComb + EMSCR ) – NH3SCR] • F2APH + (EMFGC_afterAPH – NH3FGC_afterAPH)} • F2ESP

Check that subtotal from upstream sources is positive:

TSARupstream = [(1,088,710 + 423,023) – 33,141] = 1,478,592 > 0

TSAR = [(1,088,710 + 423,023) – 33,141] • 0.50 + (647,407 – 277,460)} • 0.63

TSAR = 698,823 lbs H2SO4/yr
A-12

Example 8: 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 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

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

Total (from previous examples)

TSAM = EMComb + EMSCR + EMFGC

TSAM= 1,088,710 + 423,023 + 647,407 lbs H2SO4/yr 

 TSAM = 2,159,140 lbs H2SO4/yr 

Released from coal

Total Releases (from previous examples)

TSARcoal = 582,290 lbs H2SO4/yr 

Natural gas fuel calculations

Manufactured from natural gas

Combustion

E2NG = Kb • BNG • 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 = 4.17 lbs H2SO4 manufactured
A-13

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

Released from natural gas

Total Releases

TSARNG = EMComb • F2APH • F2ESP

TSARNG = 4.17 • 0.50 • 0.63 

TSARNG = 1.31 lbs H2SO4/yr 

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 

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• F3FGC

EMFGC = 3799 • 0.0185 • 1.0 • 7.0 • 1 

EMFGC = 492 lbs H2SO4 manufactured

Total Manufactured

TSAM = EMComb + EMSCR + EMFGC

 TSAM = 51.8 + 22.2 + 492 lbs H2SO4/yr 

 TSAM = 566 lbs H2SO4/yr 
A-14

Released from used oil 

Ammonia Slip

NH3SCR = Ks • B • fsreagent • SNH3

NH3SCR = 3799 • 0.0185 • 1.0 • 0.75 = 52.7 lbs NH3/yr 

FGC Ammonia Injection 

NH3FGC = Ke • B • fe • INH3

NH3FGC = 3799 • 0.0185 • 1.0 • 3.0 = 211 lbs NH3/yr 

Total Releases

TSARoil = [(EMComb + EMSCR + EMFGC ) – (NH3SCR + NH3FGC)] • F2APH • F2ESP

TSARoil = [(51.8 + 22.2 + 492) – (52.7 + 211)] • 0.5 • 0.63 

TSARoil = 95 lbs H2SO4/yr 

F2 is taken to be equal to 0.50 for the air heater and 0.63 for the ESP 

Grand totals for all fuels

Manufactured 

TSAM = TSAMcoal + TSAMNG + TSAMoil

TSAM = 2,159,140 + 4.17 + 566 lbs H2SO4/yr 

 TSAM = 2,159,710 lbs H2SO4/yr 

Released 

TSAR = TSARcoal + TSARNG + TSARoil

TSAR = 582,290 + 1.31 + 95 lbs H2SO4/yr 

 TSAR = 582,386 lbs H2SO4/yr 
A-15

Example 9: Natural Gas Combined Cycle Plant

A natural gas-fired combined-cycle unit uses 12.3 Tbtu/yr. of natural gas, with the standard 

sulfur content. 

Solution

Manufactured

E2NG = Kb • BNG • S 

E2NG = 0.0001359 • 12.3 • 2000 

E2NG = 3.343 tons SO2/yr

Combustion

EMCC = K • F1 • E2NG 

EMCC = 3063 • 0.0555 • 3.343 

EMCC = 568 lbs H2SO4/yr 

Released

TSARNG = EMComb • F2CC

TSARNG = 568 • 0.5

TSARNG = 284.5 lbs H2SO4/yr

F2CC = 0.5 because the low temperature of the back-end tubes of the HRSG act like an air heater.
A-16

Example 10: SCR and CO catalyst added to Example 9

A natural gas-fired combined-cycle unit uses 12.3 Tbtu/yr. of natural gas, with the standard 

sulfur content. The plant is equipped with an SCR process that operates continually (operating 

factor of 1.0). The SCR catalyst SO2 oxidation rate specified in the design is 2.0%, and the 

ammonia slip is estimated to be 0.75 ppmv. The plant is also equipped with a CO catalyst, which 

also is in continuous operation, and has an estimated SO2 oxidation rate of 10%.

Solution

Manufactured

E2NG = Kb • BNG • S 

E2NG = 0.0001359 • 12.3 • 2000 

E2NG = 3.343 tons SO2/yr

Combustion

EMCC = K • F1 • E2NG 

EMCC = 3063 • 0.0555 • 3.343 

EMCC = 568 lbs H2SO4/yr

CO Catalyst

EMCC_CO = K • S3 • fCOops • E2

EMCC_CO = 3063 • 0.1 • 1.0 • 3.343

EMCC_CO = 1024 lbs H2SO4/yr

SCR

EMCCSCR = [(K • E2) - EMCC-CO] • fsops • S2 • F3SCR

EMCCSCR = [(3063 • 3.343) – 1024] • 1.0 • 0.02 • 1.0

EMCCSCR = 184 lbs H2SO4/yr

Total

TSAMCC= EMComb + EMCC_CO + EMSCR

TSAMCC = 568 + 1024 + 184

TSAMCC = 1776 lbs H2SO4/yr

Released

TSARCC = [TSAM – (Ks • B • fsreagent • SNH3)] • F2cc

TSARCC = [1776 – (3799 • 12.3 • 1.0 • 0.75)] • 0.5

TSARCC = -16,635 = 0 lbs H2SO4/yr
A-17

The total releases are zero because the actual result is a negative value, indicating that the 

ammonia slip is greater than the sulfuric acid, thereby forming ABS, which is not reportable. 

F2CC = 0.5 because the low temperature of the back-end tubes of the HRSG act like an air heater.

B-1

B

CHRONOLOGY OF CHANGES TO EPRI SULFURIC 

ACID ESTIMATION MODEL

EPRI, 2012 (EPRI Report 1023790)

Modification Description

SCR Factor (F3SCR) Changes made to Table 4-2 to clarify proper use of the F3SCR

factor

Alkali Injection Changed description of Falkali such that it is fraction of coal burn 

instead of fraction of operating year, to be consistent with other 

operating factors

Added alternate approach for calculating releases with alkali 

injection to be used if the utility does not have measured data.

F3ALKINJ factor is introduced.

Total Sulfuric Acid Release 

Methodology (TSAR)

Reorganized release equations such that sources are summed 

upstream of the APH and ammonia from SCR/SNCR is applied to 

reduce releases based on ABS formation, then the F2 factor for 

the APH is applied. Then, any downstream source of SO3 or 

ammonia from downstream FGC is added, followed by 

application of all remaining F2 factors.

FGC Factor (F3FGC) Corrected the F3FGC factor. The F3FGC factor was introduced in the 

2001 version of the report, but as actual data has become 

available to update the F2 factors, the F3FGC factor has become 

outdated. F3FGC will now account only for alkalinity in PRB coal, 

and be applied directly to the manufacture equation.

Combined Cycle Introduced a potential third source of sulfuric acid manufacture 

and release from oxidation across CO catalysts

Technology Factors (F2) Added Wet ESP, all fuels: 0.1

Changed FGD, venturi, all coals from 0.65 to 0.73 (2 new data 

points)

Updated and corrected Figure 4-4 to reflect two new data points, 

change the shaded area to reflect the proper data range, and 

deleted an inaccurate PRB/lignite data point

Changed the F2 factor in Table 4-6 for Mg-Ox into furnace from 

0.5 to 0.25 to rectify an error introduced in the 2004 version of 

the report

Examples Updated examples to account for new release equation 

methodology
B-2 

EPRI, 2010a (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 + 0.0065 

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

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

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.
B-3

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


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1023790